REGULATORY ANALYSIS 

for Proposed Revisions to 

Colorado Air Quality Control Commission 

Regulation Numbers 3, 6 and 7 

(5 CCR 1001-5, 5 CCR 1001-8, and CCR 1001-9) 

February 11, 2014 

Colorado Department of Public Health and Environment 

Air Pollution Control Division 

4300 Cherry Creek Drive South 

Denver, CO 80246 

 
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Table of Contents

1 EXECUTIVE SUMMARY ........................................................................................ 1

2 INTRODUCTION ...................................................................................................... 1

3 ANALYSIS ................................................................................................................. 3

3.1 Regulation Number 6 ........................................................................................... 3

3.1.1 Proposed Revisions ....................................................................................... 3

3.1.2 Class of Persons Affected ............................................................................. 4

3.1.3 Quantitative and Qualitative Impacts ............................................................ 4

3.1.4 Probable Agency Costs ................................................................................. 5

3.1.5 Comparison to Inaction ................................................................................. 5

3.1.6 Less Costly Methods/Less Intrusive Methods .............................................. 6

3.1.7 Alternative Methods...................................................................................... 6

3.1.8 Quantification of Data ................................................................................... 6

3.2 Regulation Number 3 ........................................................................................... 6

3.2.1 Proposed Revisions ....................................................................................... 6

3.2.2 Class of Persons Affected ............................................................................. 7

3.2.3 Quantitative and Qualitative Impacts ............................................................ 7

3.2.4 Probable Agency Costs ................................................................................. 9

3.2.5 Comparison to Inaction ............................................................................... 10

3.2.6 Less Costly Methods/Less Intrusive Methods ............................................ 11

3.2.7 Alternative Methods.................................................................................... 13

3.2.8 Quantification of Data ................................................................................. 13

3.3 Regulation Number 7 ......................................................................................... 16

3.3.1 Discussion of Proposed Revisions .............................................................. 16

3.3.2 Class of Persons Affected ........................................................................... 17

3.3.3 Quantitative and Qualitative Impacts .......................................................... 18

3.3.4 Probable Agency Costs ............................................................................... 21

3.3.5 Comparison to Inaction ............................................................................... 22

3.3.6 Less Costly Methods/Less Intrusive Methods ............................................ 23

3.3.7 Alternative Methods.................................................................................... 24

3.3.8 Quantification of Data ................................................................................. 27

4 CLOSING SUMMARY............................................................................................ 57
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1 EXECUTIVE SUMMARY

The Colorado Air Pollution Control Division’s (“Division’s”) proposed revisions to the Air 

Quality Control Commission’s (“Commission’s”) Regulation Numbers 3, 6, and 7, collectively 

expand the air emission control requirements on oil and gas facilities in Colorado. They were 

developed after the Division’s extensive, year-long stakeholder process leading up to the 

Commission’s rulemaking hearing, including input from diverse industry, environmental and 

governmental stakeholders. The proposal has received the support of several industry and 

environmental leaders, including Anadarko Petroleum, Noble Energy, Encana Oil and Gas, and 

the Environmental Defense Fund. The proposal affects not only the oil and gas industry and 

supporting businesses in Colorado, but the Regulation Number 3 revisions broadly affect all 

businesses in Colorado. Further, the proposal broadly benefits all persons in Colorado, 

especially those who live and work in the proximity of oil and gas operations, given the 

anticipated emissions reductions that will be achieved and the reasonable associated cost of 

implementation. The Division estimates that the proposed strategies will result in substantial 

reductions of hydrocarbon emissions from the oil and gas industry. More specifically, the 

Division estimates the proposed strategies will reduce volatile organic compound (VOC) 

emissions by 93,500 tons per year, and methane/ethane emissions by 64,000 tons per year. The 

Division conservatively estimates that the annual net costs to industry of the Division’s proposal 

will be $42.4 million per year. This translates to approximately $453 per ton of VOC reduced, 

which is very reasonable when compared to other air pollution reduction strategies adopted by 

the Colorado Commission and the U.S. Environmental Protection Agency (EPA). In prehearing 

submittals to the Commission, the supporters of the proposal have concluded that the Division’s 

costs estimates methodology and cost estimates are reasonable. Some opponents of the proposal 

have asserted that the costs may be much higher. The Commission will consider the Division’s 

proposal and any alternate proposals at the rulemaking hearing commencing February 19, 2014. 

2 INTRODUCTION

On December 13, 2013, interested parties, stakeholders, and state representatives filed eleven 

separate requests for both a Cost Benefit Analysis and a Regulatory Analysis (“Requests”) with 

the Division, per C.R.S. §24-4-103(2.5), C.R.S. §24-4-103(4.5) and the Commission’s 

Procedural Rules, 5 CCR 1001-1, §V.E.13. This document satisfies the requirements for a 

Regulatory Analysis, and is separate from the related Cost-Benefit Analysis. Similarly, this 

Regulatory Analysis is different from, but related to, the required Economic Impact Analysis, 

C.R.S. §25-7-110.5(4). The Requests were specific to proposed revisions to the Commission’s 

Regulation Numbers 3, Parts A, B, and C (“Regulation 3”); Regulation 6, Part A (“Regulation 

6”); and Regulation Number 7 (“Regulation 7”). 
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The Colorado Administrative Procedure Act (“APA”)1

 serves as the legal authority for this 

rulemaking process, and sets forth requirements for both cost-benefit and regulatory analyses. 

Under the APA, any person may request an agency engaged in a rulemaking to prepare a 

regulatory analysis.2

 The regulatory analysis must include: 

 A description of the classes of persons who will be affected by the proposed rule, 

including classes that will bear the costs of the proposed rule and classes that will benefit 

from the proposed rule; 

 To the extent practicable, a description of the probable quantitative and qualitative impact 

of the proposed rule, economic or otherwise, upon affected classes of persons; 

 The probable costs to the agency and to any other agency of the implementation and 

enforcement of the proposed rule and any anticipated effect on state revenues; 

 A comparison of the probable costs and benefits of the proposed rule to the probable 

costs and benefits of inaction; 

 A determination of whether there are less costly methods or less intrusive methods for 

achieving the purpose of the proposed rule; and 

 A description of any alternative methods for achieving the purpose of the proposed rule 

that were seriously considered by the agency and the reasons why they were rejected in 

favor of the proposed rule. 

 To the extent practicable, a quantification of the data used in the analysis; the analysis 

must take into account both short-term and long-term consequences.3

 

So long as the regulatory analysis is undertaken in good faith, it satisfies the APA.4 

This Regulatory Analysis evaluates the Division’s November 15, 2013 proposed revisions to 

Regulations 3, 6, and 7, as amended on January 30, 2014, using information gathered through the 

Division’s Cost Benefit Analysis, and Economic Impact Analyses, and other documents 

associated with the administrative record for the February 19-23, 2014 Commission Hearing. 

The Division’s proposed revisions to Regulation 3, 6, and 7 are part of an overall effort to fully 

adopt federal Standards of Performance for Crude Oil and Natural Gas Production, 

Transmission, and Distribution found in 40 C.F.R. Part 60, Subpart OOOO (“NSPS OOOO”), by 

incorporating them into Regulation Number 6, Part A, and making the corresponding revisions to 

the Regulation Number 3 catch-all provisions to address barriers that prevented full adoption of 

NSPS OOOO. The proposal also revises Regulation Number 7 to address differences and 

overlaps between NSPS OOOO and Regulation Number 7 oil and gas control requirements, and 

to further reduce hydrocarbon emissions and leaks from oil and gas facilities. These revisions 

include: 

1. Expanding Colorado’s adoption of NSPS OOOO, such that it is adopted in full 

(Regulation 6); 

2. Removing “catch-all” provisions (Regulation 3); 

 

1 See C.R.S. § 24-4-101 et. seq. 2 Id. at § 24-4-103(4.5) 3 Id.

4

 Id. at § 24-4-103(2.5)(d) & § 24-4-103(4.5)(d). 
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3. Removing crude oil storage tank permitting exemptions (Regulation 3); 

4. Expanding condensate tank control requirements state-wide, including establishing 

storage tank emission monitoring (“STEM”) requirements (Regulation 7); 

5. Expanding dehydration unit (“dehy”) control requirements state-wide (Regulation 7); 

6. Establishing leak detection and repair (“LDAR”) requirements for components at well 

production facilities and natural gas compressor stations state-wide (Regulation 7); 

7. Establishing well maintenance and liquids unloading requirements state-wide (Regulation 

7); and 

8. Expanding pneumatic controller requirements state-wide (Regulation 7). 

In addition to these more prominent revisions, these proposals also correct minor administrative 

errors, and make typographical, grammatical, and formatting changes in Regulation 3, 6, and 7. 

This Regulatory Analysis focuses on the more significant revisions and does not address 

typographical, grammatical, and formatting changes. 

This analysis represents information gathered from various stakeholders in an effort to generate 

the most complete and accurate assessment of the costs and benefits of the proposed strategies. 

Where data was not reasonably available, the Division utilized assumptions that are set forth in 

this analysis.

3 ANALYSIS		

3.1 Regulation Number 6

3.1.1 Proposed Revisions

The proposed revisions to Regulation 6 fully incorporate by reference the federal NSPS OOOO 

into Regulation Number 6, Part A, including the provisions not incorporated during the 

Commission’s partial adoption. In late 2012, the Commission partially adopted the Standards of 

Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution found in 

40 C.F.R. Part 60, Subpart OOOO (“NSPS OOOO”), such that Colorado currently administers 

NSPS OOOO, for all affected facilities under NSPS OOOO including centrifugal compressors, 

reciprocating compressors, pneumatic controllers, storage vessels, process unit equipment, and 

sweetening units, except for natural gas wells (well completion requirements) and equipment that 

emits less than current reporting and permitting thresholds. At that time, the Commission 

directed the Division to consider full adoption of NSPS OOOO, as well as other improvements to 

Colorado’s oil and gas emission regulations. 

It appears that all parties to the Commission rulemaking support the proposed revisions to 

Regulation 6. 
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3.1.2 Class of Persons Affected

“A description of the classes of persons who will be affected by the proposed rule, including 

classes that will bear the costs of the proposed rule and classes that will benefit from the 

proposed rule.” 

There is limited impact associated with this proposal, in that NSPS OOOO is already in effect on 

a federal level and the Commission has already partially adopted NSPS OOOO for Colorado. 

The classes of persons affected by the proposed full adoption of NSPS OOOO include oil and 

gas companies operating in Colorado, and businesses that support the oil and gas industry in 

Colorado. Also, citizens statewide are impacted by the proposal. In all cases, it is simpler and 

less confusing to no longer have to deal with federal and state agencies administering the same 

requirements. 

Full adoption of NSPS OOOO does not have an additional cost impact on any affected classes of 

persons because this rule is currently in effect and federally enforceable. Full adoption of NSPS 

OOOO does not provide additional health or economic benefits to classes of persons affected by 

the proposal because NSPS OOOO is currently in effect and federally enforceable. However, 

affected classes of persons will benefit from the proposed full adoption of NSPS OOOO due to 

having Colorado implement and enforce NSPS OOOO for all sources subject to NSPS OOOO in 

Colorado. 

Further, full adoption of NSPS OOOO benefits the United States Environmental Protection 

Agency (“EPA”) by relieving the agency of the primary responsibility to implement and enforce 

NSPS OOOO in Colorado. 

The Colorado Oil and Gas Conservation Commission (“COGCC”) does have well completion 

requirements that are different but similar to NSPS OOOO requirements. However this proposal 

to fully adopt NSPS OOOO does not change the fact that there are two different requirements 

that may apply to natural gas wells. The Division continues to work with the COGCC to address 

this issue and coordinate implementation of these rules. 

3.1.3 Quantitative and Qualitative Impacts			

“To the extent practicable, a description of the probable quantitative and qualitative impact of 

the proposed rule, economic or otherwise, upon affected classes of persons.” 

There are few if any additional quantitative impacts of the Regulation 6 proposal because these 

rules are already in effect on a federal level. The qualitative impact of the proposed rule upon 

affected classes of persons includes Colorado’s implementation and enforcement of NSPS 

OOOO, using Division staff much more familiar with Colorado’s oil and gas issues than EPA 

staff. Full adoption of NSPS OOOO does not provide any other additional costs or benefits 

beyond those affected by NSPS OOOO. 
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3.1.4 Probable Agency Costs

“The probable costs to the agency and to any other agency of the implementation and 

enforcement of the proposed rule and any anticipated effect on state revenues.” 

The probable costs to the Division of implementing and enforcing the NSPS OOOO 

requirements for affected facilities below current Air Pollutant Emission Notice (“APEN”) 

reporting and minor source permitting thresholds, as well as implementing and enforcing the 

NSPS OOOO well completion requirements, are unknown at this time. These sources are not 

currently subject to Colorado’s reporting and permitting requirements. 

The Division will largely implement the provisions of its proposal through its oil and gas 

inspection team. This team currently consists of nine full time inspectors and four term limited 

inspectors. In 2012, in response to the growth in the oil and gas industry in Colorado, the 

legislature approved increasing the size of the inspection team from six inspectors to nine. In 

2013, the legislature appropriated additional funds to hire four term limited inspectors to conduct 

IR camera inspections at well production facilities in Colorado. The term for these positions 

runs through June of 2015, but could be extended by the legislature if warranted. The additional 

inspectors provided during the 2012 and 2013 legislative sessions has significantly expanded the 

capabilities of the oil and gas inspection team, which will further enable the Division to 

implement and enforce the proposed requirements if the Commission chooses to adopt the 

Division’s proposal. The total projected annual cost to the Division for the oil and gas inspection 

team in fiscal year 2013-14 is $1,305,304, which includes salary costs, fringe benefits, operating 

costs (including vehicles, field equipment, and office equipment), travel training and indirect 

costs. 

There is no anticipated effect on state revenues because the proposal does not assess any 

additional emissions reporting or permitting fees than those that already apply. 

3.1.5 Comparison to Inaction

“A comparison of the probable costs and benefits of the proposed rule to the probable costs and 

benefits of inaction.” 

If the Commission does not fully adopt NSPS OOOO, EPA and the Division will continue to 

share the implementation and enforcement responsibilities for NSPS OOOO. However, 

regardless of partial or full adoption, NSPS OOOO remains effective and federally enforceable. 

Importantly, the Division does not advocate full adoption of NSPS OOOO without removing the 

catch-all provisions in Regulation Number 3 due to the reporting and permitting impacts on both 

the regulated community and the Division. 
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3.1.6 Less Costly Methods/Less Intrusive Methods		

“A determination of whether there are less costly methods or less intrusive methods for 

achieving the purpose of the proposed rule.” 

There are no less costly or intrusive methods for achieving full adoption of NSPS OOOO. 

Retaining partial adoption of NSPS OOOO will not resolve the issue of shared implementation 

responsibilities between EPA and the Division. 

3.1.7 Alternative Methods		

“A description of any alternative methods for achieving the purpose of the proposed rule that 

were seriously considered by the agency and the reasons why they were rejected in favor of the 

proposed rule.” 

The Division did not consider any alternative methods for achieving full adoption of NSPS 

OOOO. 

3.1.8 Quantification of Data		

“To the extent practicable, a quantification of the data used in the analysis; the analysis must 

take into account both short-term and long-term consequences.” 

The short and long term consequences of the full adoption of NSPS OOOO are full 

implementation and enforcement by Colorado, instead of split implementation and enforcement 

between EPA and Colorado. The Division did not further quantify the short- or long-term 

consequences of the Regulation 6 proposal to fully adopt NSPS OOOO beyond what was already 

performed by EPA. 

3.2 Regulation Number 3

3.2.1 Proposed Revisions

The Division is proposing revisions to Regulation 3’s reporting and permitting requirements in 

order to improve the efficiency of Colorado’s air quality reporting and permitting system. 

The proposed revisions remove the requirement for sources subject to either a federal New 

Source Performance Standard (“NSPS”) or federal National Emission Standards for Hazardous 

Air Pollutant (“NESHAP”)/Maximum Available Control Technology (“MACT”) adopted into 

Regulation Number 6, Part A or Number 8, Parts A, C, D, and E to file an APEN and obtain a 

minor source permit regardless of whether their emissions exceed the reporting or permitting 

thresholds (“catch-all provisions”). As a result, sources subject to a NSPS incorporated into 

Regulation Number 6, Part A or a NESHAP/MACT incorporated into Regulation Number 8, 
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Parts A, C, D, or E are subject to APEN reporting and permitting only if their emissions exceed 

the applicable APEN and permitting thresholds. 

In addition, the proposed revisions simplify the Appendix A non-criteria reportable pollutant de 

minimis determination to 250 pounds per year of any individual non-criteria reportable pollutant. 

The proposed revisions also remove the crude oil storage tank permitting exemptions. 

 Finally, the proposed revisions correct an inadvertent error to the minor source permitting 

exemption for crude oil and condensate truck loading equipment. This revision is administrative 

in nature, as the Division currently implements the provision as it was originally intended. 

It appears that all parties to the Commission rulemaking support the proposed revisions to 

Regulation 3, and some parties have submitted alternative proposals requesting additional 

revisions (see Section 3.2.7 in this Regulatory Analysis). 

3.2.2 Class of Persons Affected

“A description of the classes of persons who will be affected by the proposed rule, including 

classes that will bear the costs of the proposed rule and classes that will benefit from the 

proposed rule.” 

The classes of persons affected by the proposed revisions to Regulation 3 are broad. Revisions 

to the catch-all provisions affect any stationary source subject to an NSPS adopted into 

Regulation Number 6 or NESHAP/MACT adopted into Regulation Number 8 that has emissions 

below the APEN reporting and minor source permitting thresholds. To demonstrate the breadth 

of impact, some examples of business and industry that are affected include dry cleaners, 

aggregate mining operations, grain elevators, natural gas compressor stations, surface coating 

operations, and power plants. Those activities subject to an NSPS or NESHAP/MACT, whose 

emissions fall below current reporting and permitting thresholds, will no longer have to report 

emissions and obtain minor source permits. 

The proposed revisions to the non-criteria reportable pollutant de minimis threshold will affect 

stationary sources with emissions of non-criteria reportable pollutants greater than 250 pounds 

per year. This revision also has a broad impact, as most sources emit some degree of hazardous 

air pollutants or other non-criteria reportable pollutants. 

Further, the revisions to the crude oil storage tank permit exemptions affect owners and operators 

of crude oil storage tanks with capacities of 40,000 gallons or less. The correction to the minor 

source permitting exemption for crude oil and condensate truck loading equipment is 

administrative in nature and affects oil and natural gas operations. 

3.2.3 Quantitative and Qualitative Impacts		

“To the extent practicable, a description of the probable quantitative and qualitative impact of 

the proposed rule, economic or otherwise, upon affected classes of persons.” 
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Quantitative and qualitative consequences for each revision are discussed below. Short- and 

long-term consequences include the continued delay in adopting NSPS OOOO in full, as well as 

other federal NSPS and NESHAP/MACT that apply to small sources in Colorado. There are 

minimal if any costs to the regulated community due to these revisions, and in some cases, cost 

savings are anticipated. Further, the Division anticipates that there will be no significant 

environmental impact associated with the proposal. 

3.2.3.1 		Catch‐all Provisions

There are no anticipated costs to either the regulated community or the government associated 

with these proposed revisions. Removal of the catchall provisions will actually reduce reporting, 

permitting, and associated cost burdens for the regulated community. By reducing reporting and 

permitting activities, the proposed revision will also reduce costs to the Division associated with 

these activities. 

The Division conducted a permit tracking project from February, 2013 to September, 2013 to 

understand the impact of this proposal. All pre-construction permits issued were evaluated to 

determine if they would have required an APEN and permit under this proposal. The Division’s 

permit tracking project indicated that 7% (167 of 2,355) permits processed required permits 

solely due to the catch-all provision, accounting for approximately 0.03% of the total 

uncontrolled actual criteria pollutant emissions and 0.003% of statewide uncontrolled actual 

criteria pollutant emissions. The total hourly permit processing fees for these permits was 

approximately $50,000.5

 This cost estimate does not include the time saved by the sources by no 

longer having to complete and submit an APEN or minor source permit application. 

The environmental impacts of revising the catch-all provisions are minimal. Further, no 

emissions increases are anticipated from these sources that would no longer require a permit 

because these revisions will not exempt them from having to comply with the requirements of an 

applicable NSPS or NESHAP/MACT. 

3.2.3.2 			Non‐criteria Reportable Pollutants

Some stationary sources affected by the proposed revisions to the non-criteria reportable 

pollutant thresholds may have new costs related to reporting emissions previously below 

reporting thresholds, including filing and annual fees. Revision of the threshold for non-criteria 

reportable pollutants could result in ether cost savings or additional costs to the regulated 

community depending on the source. Sources that are required to report hazardous air pollutants 

(a subset of non-criteria reportable pollutants) must pay an emission fee of $152.90 per ton. 

Currently Regulation Number 3 contains a complex reporting formula involving multiple and 

different thresholds, some of which are above and some of which are below the proposed 250 

pound threshold. Accordingly, changing the threshold will reduce costs for some sources, while 

increasing costs for other sources. Based on an analysis of reported emissions, the proposed 

threshold change will reduce industry fees paid to the Division by $47,702 per year. Because the 

emissions from sources that are not currently reporting is unknown it is not possible to calculate 

 

5

 Permit cost savings were calculated using an average of 4 hours spent per permit, as determined by the time spent 

on permits processed due to the catch-all provisions in the Division’s permit tracking project, multiplied by the 

Division billing rate of $76.45 an hour. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 9 

 

the additional costs to sources that will be required to report for the first time under the new 

proposed threshold. Based on the relative prevalence of different emissions, however, the 

Division believes that there will be a small net savings to the regulated community. 

Additionally, beyond the actual emission fees, the current reporting system is very complex 

resulting in numerous hours being spent by both the regulated community and Division staff in 

determining whether reporting is required. Simplifying the reporting system will eliminate the 

costs associated with this analysis. 

Some stationary sources affected by the proposed revisions would benefit because they would no 

longer be required to report their non-criteria reportable pollutant emissions, thus saving filing 

and possibly annual fees. The revised threshold of 250 pounds per year preserves at least 96% of 

the Division’s current inventory of non-criteria reportable pollutants. Other sources may have 

new costs related to having to report emissions that were previously below reporting thresholds, 

including filing and annual fees. This impact is unknown at this time because these sources are 

not currently subject to Colorado’s reporting and permitting requirements. While EPA does not 

require States to report hazardous air pollutant emissions, EPA utilizes this data to annually 

populate the National Emissions Inventory. Accordingly, Colorado will continue to provide a 

robust set of data while also serving an important regulatory streamlining purpose. 

3.2.3.3 		Crude Oil Storage Tanks

Owners and operators of crude oil storage tanks may have new costs related to obtaining permits 

for previously permit-exempt equipment. There are minimal direct costs projected for the 

affected businesses and industrial sector associated with the removal of the crude oil storage tank 

permitting exemption. Stationary sources with crude oil storage tanks whose uncontrolled actual 

emissions exceed the minor source or operating permit thresholds would be required to obtain a 

permit. In 2008, the Commission removed the reporting exemption for crude oil storage tanks to 

improve the inventory of uncontrolled actual emissions. While the Division believes there are 

many crude oil storage tanks in Colorado, the Division’s APEN inventory only identifies 64 

crude oil storage tanks with a design capacity of 40,000 gallons or less in Colorado. Removal of 

the crude oil storage tank minor source permitting exemption would require these tanks to obtain 

minor source permits at a cost of approximately $19,500. 

3.2.3.4 Minor Source Permitting Correction

No practical impact is anticipated as a result of this revision, as the Division continues to 

implement the provision as was originally intended. 

3.2.4 Probable Agency Costs

“The probable costs to the agency and to any other agency of the implementation and 

enforcement of the proposed rule and any anticipated effect on state revenues.” 

The Division does not anticipate any negative effect on state revenues. Any potential Full Time 

Equivalent (“FTE”) personnel savings will be redirected to addressing the current permitting 

backlog. Any loss in permitting fees, will be offset by the processing of backlog permits. In 
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addition, the crude oil storage tank permitting exemption revisions will slightly increase the 

submission of permitting fees. Similarly, the Division anticipates the reduction in filing and 

annual fees due to the approximately 4% reduction in current non-criteria reportable pollutant 

reporting to be offset by the increased reporting and associated fees by stationary sources with 

non-criteria reportable pollutant emissions greater than 250 pounds per year. 

3.2.4.1 		Catch‐all Provisions

The revisions to the catch-all provisions will reduce the administrative burden on both the 

Division and the regulated community. The Division estimated through the permit tracking 

project that the staffing of approximately 0.6 FTE would be saved due to the revisions. 

However, revising the catch-all provisions does not change the applicability or enforcement of 

the NSPS or NESHAP/MACT. 

3.2.4.2 			Non‐criteria Reportable Pollutants

The revisions to the non-criteria reportable pollutant threshold establish a simplified, standard 

reporting threshold of 250 pounds per year for all non-criteria reportable pollutants. This 

eliminates the complicated matrix system and streamlines the process for sources, and for the 

Division, both in explaining the process to sources and reviewing reported emissions. The work 

associated with any increased reporting will be absorbed by existing Division staff or potentially 

offset by the approximately 4% reduction in current non-criteria reportable pollutant reporting. 

3.2.4.3 		Crude Oil Storage Tanks

The Division’s APEN inventory currently identifies 64 crude oil storage tanks with a design 

capacity of 40,000 gallons or less. The work associated with permitting and inspecting these, 

and potentially more, sources will be absorbed by existing Division staff. 

3.2.4.4 		Minor Source Permitting Correction

There are no additional agency costs incurred as a result of this revision, as the Division 

continues to implement the provision as was originally intended. 

3.2.5 Comparison to Inaction

“A comparison of the probable costs and benefits of the proposed rule to the probable costs and 

benefits of inaction.” 

If the Commission does not adopt at least the proposed revisions to the catchall provisions, the 

Division would not recommend full adoption of NSPS OOOO. Further, absent adoption of the 

proposed revisions to the catchall provisions, the Division’s permitting backlog will be 

negatively impacted. Finally, the public, regulated community, and other agencies will continue 

to experience the complexity and confusion of the APEN reporting thresholds and Appendix A 

de minimis levels applicability determinations. If the Commission does not adopt the proposed 

crude oil storage tank exemption revisions, a potentially significant source of emissions will 

continue to be exempt from permitting requirements. If the Commission does not make the 

minor source permitting correction, the provision will not align with the Commission’s intent at 

the time of adoption nor the Division’s current implementation of the provision. The purposes of 

the proposed revisions to Regulation 3 include allowing full adoption of NSPS OOOO, 
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streamlining and clarifying reporting and permitting, and requiring permits for a potentially 

significant source of emissions. 

3.2.5.1 		Catch‐all Provisions

The revisions to the catch-all provisions reduce reporting and permitting costs. If the 

Commission does not adopt the proposed revisions, the regulated community and the Division 

will retain those reporting and permitting costs. Further, if the Commission adopts NSPS 

OOOO, and other NSPS and NESHAP/MACT similarly affecting very small sources, in full 

without removing the catch-all provisions, the increase in APEN reporting and minor source 

permitting would overwhelm both the Division and the regulated community. 

3.2.5.2 			Non‐criteria Reportable Pollutants

The revisions to the non-criteria reportable pollutant thresholds may reduce costs for some 

sources and increase costs for other sources. However, all sources will benefit from the 

increased clarity of the de minimis reporting determination. If the Commission does not adopt 

the proposed revisions, the public, regulated community, and the Division will continue to deal 

with a complex and confusing reporting determination. 

3.2.5.3 		Crude Oil Storage Tanks

The costs of the proposed revisions to the crude oil storage tank permit exemptions include the 

costs to the regulated community of obtaining permits and the costs to the Division of permitting 

and inspecting subject tanks. Removing the permitting exemptions also increases the 

consistency of Colorado’s regulations with NSPS OOOO by requiring these sources to also be 

subject to Colorado’s notification, recordkeeping, and control requirements. If the Commission 

does not adopt the proposed crude oil storage tank exemption revisions, there will not be costs 

associated with permitting but a potentially significant source of emissions will continue to be 

exempt from permitting requirements. 

3.2.5.4 		Minor Source Permitting Correction

No costs are anticipated with the proposed revisions, as the Division will continue to implement 

the provision as was originally intended. 

3.2.6 Less Costly Methods/Less Intrusive Methods		

“A determination of whether there are less costly methods or less intrusive methods for 

achieving the purpose of the proposed rule.” 

The Division does not believe that there are less costly or less intrusive methods to fully adopt 

NSPS OOOO than the Division’s proposal. 

3.2.6.1 		Catchall Provisions

The Division believes that the revisions to the catch-all provisions are necessary to adopt NSPS 

OOOO, and other NSPS and NESHAP/MACT similarly affecting very small sources, due to the 

anticipated extensive number of APENs and minor source permit applications that would be 

required. Consider how the current catch-all provisions would apply if the Commission adopts 

MACT JJJJJJ, which applies to a multitude of small boilers. Under the catch-all provisions, 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 12 

 

every boiler providing electricity, steam, or hot water in a hotel, restaurant, laundry, medical 

center, research center, institution of higher education, or manufacturing, processing, mining, or 

refining facility would be required to file an APEN and obtain a minor source permit, even if the 

source had emissions less than the reporting and permitting thresholds. Other examples of rules 

similarly affecting very small sources include NSPS JJJJ, which applies to numerous stationary 

spark ignition internal combustion engines; MACT M, which applies to all perchloroethylene dry 

cleaning facilities; MACT HHHHHH, which applies to paint stripping and spray applications of 

greater than three motor vehicles or mobile equipment; and MACT SSSSSS, which applies to all 

glass manufacturing facilities. Under the current catch-all provisions, all of these facilities 

would require APENs and minor source permits, even if emissions are below the reporting and 

permitting thresholds. 

If NSPS OOOO is adopted in full without the corresponding adoption of the proposed revisions 

to the catch-all provisions, the regulated community will be required to file APENs and obtain 

minor source permits for every NSPS OOOO affected facility. In turn, the Division’s permitting 

backlog will likely grow and industry’s ability to obtain timely permits will be negatively 

impacted. In comparison, if NSPS OOOO is adopted in full along with the proposed revisions to 

the catch-all provisions, only NSPS OOOO affected facilities with emissions greater than the 

reporting and minor source permitting thresholds will be required to report emissions and obtain 

minor source permits. This is currently how the partial adoption of NSPS OOOO is 

implemented. Thus, the Division does not believe there are less costly or intrusive methods than 

the proposed catch-all provisions revisions to reduce the administrative impact of full adoption 

of NSPS OOOO. 

Similarly, the Division does not believe there are less costly or intrusive methods than the 

proposed catch-all provisions revisions to improve the efficiency of Colorado’s reporting and 

permitting system for NSPS or NESHAP/MACT subject sources with emissions below the 

reporting and permitting thresholds, especially since these revisions will save costs for both the 

Division and the regulated community. 

3.2.6.2 		Appendix A

The purpose of the revisions to the non-criteria reportable pollutant thresholds is to simplify a 

complex and confusing reporting determination. 

The Division cannot quantify the costs of unknown non-criteria reportable pollutants but 

considers the true cost savings of the proposed revision to the non-criteria reportable pollutant 

threshold the savings in time and effort of the public and regulated community in determining 

applicability under the revised Appendix A. While some sources non-criteria reportable 

pollutant reporting will increase, the Division does not believe there is a less costly or intrusive 

method to streamline the non-criteria reportable pollutant reporting determination while still 

maintaining a robust non-criteria reportable pollutant inventory. 

3.2.6.3 		Crude Oil Tank Permit Exemption

Requiring permits for crude oil storage tanks, a potentially significant source of emissions, 

cannot be accomplished in any less costly or less intrusive method. Further, some sources will 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 13 

 

want enforceable permit limits on their crude oil storage tanks so as to be exempt from NSPS 

OOOO storage vessel requirements. 

3.2.6.4 		Minor Source Permitting Correction

There are no less costly or no less intrusive methods, as the Division will continue to implement 

the provision as was originally intended. 

3.2.7 Alternative Methods		

“A description of any alternative methods for achieving the purpose of the proposed rule that 

were seriously considered by the agency and the reasons why they were rejected in favor of the 

proposed rule.” 

In addition to the Division’s proposal, various parties to the rulemaking have submitted different 

alternative proposals for the Commission to consider. Some of these proposals request that the 

Commission adopt additional requirements, increasing APEN reporting and permitting 

thresholds, as well as change how emissions are reported to the Division. 

The Division considered revising the APEN and minor source permitting thresholds to further 

simplify and clarify APEN reporting and minor source permitting. However, the Division 

decided not to pursue revising the APEN and minor source permitting thresholds at this time, in 

order to avoid diverting focus from the important emission reductions associated with the 

proposed revisions to Regulation Number 7, and provide additional time to work with EPA on 

the potential development of a sufficient noninterference demonstration for such revisions. 

Further, the Division considered alternative thresholds for the proposed revisions to the noncriteria reportable threshold. The Division selected the 250 pound per year threshold due to 

concerns about higher thresholds and the retention of approximately 96% of the Division’s 

current non-criteria reportable pollutant inventory under the proposed revision. 

The Division did not consider any alternatives concerning the proposed revisions to the crude oil 

storage tank permitting exemptions or the minor source permitting correction. 

3.2.8 Quantification of Data		

“To the extent practicable, a quantification of the data used in the analysis; the analysis must 

take into account both short-term and long-term consequences.” 

The Division quantified the short-term consequences and used them to project long-term 

consequences of the Regulation 3 proposal. 

3.2.8.1 		Catch‐all Provisions

The Division tracked all pre-construction permits, which includes permits processed for point 

sources at both major stationary sources and minor sources, between mid-February and 

September, 2013. The permit tracking project indicates that 7% (167 of 2,355) of those permits 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 14 

 

processed required permits because of the catch-all provision. In addition, the potentially 

eliminated emissions in comparison to statewide emissions are all much less than 1%, as 

illustrated in Table 1 below. 

Table 1: Emissions from Sources Potentially No Longer Requiring Permits 

 due to the Catch-all Revisions (State-wide) 

Pollutant Uncontrolled actual 

emissions of potentially 

eliminated permits during 

tracking project (tpy, % 

of statewide emissions) 

Uncontrolled actual 

emissions statewide6

 (tpy) 

CO 45 (0.05%) 99,929 

NOx 110 (0.07%) 165,192 

Total PM7 32 (0.0004%) 7,385,720 

SO2 0.2 (0.0002%) 115,715 

VOC 24 (0.005%) 469,396 

TOTAL 211.2 (0.003%) 8,235,952 

Further, 4% (87 of 2,355) of the permits processed that required permits because of the catch-all 

provision are in the nonattainment area (“NAA”). The potentially eliminated emissions in 

comparison to NAA emissions are also much less than 1%, as illustrated in Table 2 below. 

Table 2: Emissions from Sources Potentially No Longer Requiring Permits 

due to the Catch-all Revisions (8-Hour Ozone NAA) 

Pollutant Uncontrolled actual 

emissions of potentially 

eliminated permits during 

tracking project in the 

NAA (tpy, % of NAA 

emissions) 

NAA uncontrolled actual 

emissions8

 (tpy) 

CO 19 (0.1%) 19,110 

NOx 90 (0.24%) 37,831 

Total PM9 15 (0.003%) 441,084 

SO2 0.1 (0.0004%) 23,994 

VOC 5 (0.004%) 140,463 

TOTAL 129.1 (0.02%) 662,482 

Importantly, these tables represent point source emissions, and do not include mobile source or 

area source emissions. Therefore, the percentage of emissions potentially eliminated from 

 

6

 January-November, 2013, total emissions. 

7

 Includes PM, PM10, and PM2.5. 

8

 January-November, 2013, total emissions. 

9

 Includes PM, PM10, and PM2.5. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 15 

 

permitting due to the removal of the catch-all provisions is even less, if the total emissions 

inventory, including point, mobile and area source emissions, were used. 

The revisions to the catch-all provisions reduce costs to affected classes of persons, due to fewer 

sources being required to file APENs and obtain minor source permits. The Division’s permit 

tracking project shows that 7% (167 of 2,355) of the permits processed between mid-February 

and September, 2013, were permitted due to the catch-all provision. The total hourly permit 

processing fees for these permits was approximately $50,00010. This cost estimate does not 

include the time saved by the sources by no longer having to complete and submit an APEN or 

minor source permit application. 

The environmental impacts of revising the catch-all provisions are minimal and no emissions 

increases are anticipated because these revisions will not exempt any source from complying 

with the requirements of an applicable NSPS or NESHAP/MACT. The Division’s permit 

tracking project shows that the 7% of permits processed between mid-February 14, and 

September 30, 2013, accounted for approximately 0.03% of the total uncontrolled actual criteria 

pollutant emissions during the tracking project and 0.003% of statewide uncontrolled actual 

criteria pollutant emissions.11 

3.2.8.2 		Appendix A

There are potential increased costs to the affected classes of persons associated with the revisions 

to Appendix A, however the full extent is unknown. This revision may increase the reporting 

requirements for a currently unknown quantity of Bin B and Bin C non-criteria reportable 

pollutants because the revised threshold is lower than the current lowest de minimis reporting 

thresholds of 500 and 1,000 pounds per year, respectively. This revision may also decrease the 

reporting requirements for some Bin A pollutants because the revised threshold is higher than the 

current lowest de minimis reporting threshold of 50 pounds per year. Sources will save emission 

fees of $152.90 per ton of non-criteria reportable pollutant no longer required to report, not 

including the time saved by the sources due to not collecting the emissions data for and 

submitting APENs. 

The environmental impacts of revising the catch-all provisions are minimal and no emissions 

increases are anticipated because these revisions will not exempt any source from complying 

with applicable requirements. In addition, the Division estimates that the proposed reporting 

thresholds of 250 pounds per year will retain at least 96% of the Division’s current non-criteria 

reportable pollutant tracking for inventory purposes, which will continue to provide data to the 

EPA for the National Emissions Inventory, as well as to external custormers such as 

environmental groups and the public. In addition, because the proposed reporting threshold is 

less than the current thresholds for many of the current scenarios, the revision will result in 

additional emissions of Bin B and Bin C pollutants being reported. 

 

10 Permit cost savings were calculated using an average of 4 hours spent per permit, as determined by the time spent 

on permits processed due to the catch-all provisions in the Division’s permit tracking project, multiplied by the 

Division billing rate of $76.45 an hour. 

11 See the Division’s January 29, 2014, CAA § 110(l) Noninterference Demonstration for a more detailed discussion 

of noninterference with the NAAQS. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 16 

 

3.2.8.3 		Crude Oil Tank Permit Exemption

There are anticipated costs to the affected classes of persons associated with the removal of the 

crude oil storage tank permitting exemptions. The Division’s APEN inventory currently only 

identifies 64 crude oil storage tanks with a design capacity of 40,000 gallons or less in Colorado. 

Removal of the crude oil storage tank minor source permitting exemption would requires these 

tanks to obtain minor source permits at a cost of approximately $19,500. 

The emissions from crude oil storage tanks can be significant and permitting exemptions are 

meant to be limited to emission points with negligible impacts on air quality. The environmental 

impacts of revising the crude oil storage tank permitting exemptions may be significant, 

however, due to data limitations that impact is known. 

The short term consequences of the proposed catch-all revisions include allowing the 

Commission to fully adopt NSPS OOOO. The long term consequences of the proposed catch-all 

revisions include potentially allowing the Commission to adopt other NSPS and 

NESHAP/MACT similarly affecting very small sources. 

The short term consequences of the proposed revisions to the non-criteria reportable pollutant 

threshold include simplifying the non-criteria reportable pollutant reporting determinations for 

both the Division and the regulated community and reducing the Division’s current non-criteria 

reportable pollutant inventory by approximately 4%. The long term consequences of the 

proposed revisions to the non-criteria reportable pollutant threshold are unknown. 

The short-term consequences of the proposed crude oil storage tank permit exemptions include 

requiring existing crude oil storage tanks with a capacity of 40,000 gallons or less to obtain 

permits. The long term consequences of the proposed crude oil storage tank permit exemptions 

include requiring new crude oil storage tanks to obtain permits. 

3.2.8.4 		Minor Source Permitting Correction

Short- and long-term consequences of the proposed correction include aligning the provision 

with the Commission’s original intent. No data was quantified relating to this revision. 

3.3 Regulation Number 7

3.3.1 Discussion of Proposed Revisions

The Regulation 7 rulemaking package proposes revisions that expand existing oil and gas control 

requirements and establish additional monitoring, recordkeeping and reporting requirements. 

These proposed revisions include the following: 

1) Enhancing the existing control program for petroleum storage tanks by: 

a. Lowering the control requirement threshold for condensate storage tanks from 20 

to 6 tons per year of uncontrolled actual volatile organic compound (VOC) 

emissions; 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 17 

 

b. Requiring controls for crude oil and produced water storage tanks with 

uncontrolled actual VOC emissions that are equal or greater than 6 tons per year; 

and 

c. Expanding NAA requirements for tank controls during the first 90 days of 

production to the rest of the state; 

2) Establishing requirements to ensure that emissions from controlled storage tanks are 

captured and routed to the control device; 

3) Enhancing the existing control program for dehys by: 

a. Increasing the control requirements from 90% to 95%; 

b. Increasing designed destruction efficiency requirements from 95% to 98%; 

c. Establising more stringent requirements for individual dehys located in proximity 

to a building unit or designated outside activity area; 

4) Establishing LDAR requirements for compressor stations and well production facilities, 

including requirements to reduce emissions from compressor seals and open ended lines 

consistent with current federal requirements; 

5) Expanding the existing 8-hour ozone NAA requirements for auto-igniters on flare devices 

to the rest of the state; 

6) Expanding the existing NAA requirements for low bleed pneumatic devices to the rest of 

the state and where feasible requiring no-bleed pneumatic devices; and 

7) Requiring that the gas stream at newly constructed well production facilities either be 

connected to a pipeline or routed to a control device from the date of first production. 

If adopted, these proposed revisions will result in substantial reduction of hydrocarbon emissions 

including volatile organic compounds (VOCs) and methane. 

Several industry and environmental parties fully support the Division’s proposed revisions to 

Regulation 7. Conversely, some parties request that the Commission adopt additional 

requirements that go beyond the Division’s proposal, while other alternatives request that the 

Commission limit aspects of the Division’s proposed revisions. See Section 3.3.7 of this 

Regulatory Analysis for details on the parties’ alternative proposals. 

3.3.2 Class of Persons Affected

“A description of the classes of persons who will be affected by the proposed rule, including 

classes that will bear the costs of the proposed rule and classes that will benefit from the 

proposed rule.” 

The proposal affects the oil and gas industry and supporting businesses in Colorado. Further, the 

proposal broadly benefits all persons in Colorado, especially those who live and work in the 

proximity of oil and gas operations. Companies that will bear the costs of this rule change include 

the oil and gas companies operating, drilling, recompleting or otherwise stimulating wells in the 

NAA, as well as well production facilities, compressor stations and dehys. Revisions to 

Regulation 7 may require installation of controls to reduce hydrocarbon emissions from storage 

tanks, dehys, and separators on newly constructed, hydraulically fractured or recompleted wells. 

Typically flares are used as control equipment, but vapor recovery units (“VRUs”) and other 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 18 

 

Division-approved pollution prevention devices may be used. Use of best management 

practices or controls may also be required for well maintenance and liquids unloading activities. 

Regulation 7 revisions may also require installation of auto-igniters on combustion devices and 

installation of low- or no-bleed pneumatic controllers. In addition, compressor stations and well 

production facilities may be required to monitor components for emissions and repair leaks. 

Owners and operators of well production facilities or compressor stations that include 

compressor seals and open-ended lines may have to comply with additional work practice 

standards. 

The proposed Regulation 7 will benefit those companies that manufacture and/or distribute flare 

control devices, VRUs, auto-igniters or low- and no-bleed pneumatic controllers. Companies 

that manufacture hydrocarbon monitoring equipment, including infra-red (“IR”) cameras, photoionization detectors, flame ionization detectors and other Division-approved monitoring 

methods, as well as those companies that provide or support monitoring services may also 

benefit from these proposed revisions. 

Given that VOCs are precursors to ozone, the citizens in the NAA will benefit from the proposed 

rule through reduced ozone precursor emissions. State-wide, persons living or working in 

proximity to storage tanks, dehys, wells, well production facilities or compressor stations will 

benefit from reduced air emissions. See Section 3.3.3 of this Regulatory Analysis for a more 

comprehensive review of public health impacts. 

Thus, all persons in the State benefit from the proposed revisions. 

3.3.3 Quantitative and Qualitative Impacts			

“To the extent practicable, a description of the probable quantitative and qualitative impact of 

the proposed rule, economic or otherwise, upon affected classes of persons.” 

The proposed changes to Regulation Number 7 are projected to result in substantial reductions of 

hydrocarbon emissions (including both VOCs and methane/ethane) from the oil and gas industry. 

The Division estimates approximately 93,500 tons per year VOC, or 257 tons per day, and 

approximately 64,000 tons per year methane/ethane will be reduced. 

Qualitative impacts of this Regulation 7 proposal are closely related to Colorado’s air quality and 

economy. During the past ten years, Colorado has been a leader in developing and implementing 

requirements to reduce air emissions from the oil and gas sector. As a result of these efforts, 

Colorado now has in place a series of cost-effective requirements that significantly reduce air 

emissions from Colorado oil and gas facilities. Despite this success, however, the tremendous 

growth of oil and gas production in Colorado continues to threaten the air quality gains that we 

have achieved. Since 2004 gas production in Colorado has increased by 50% while oil 

production has more than doubled. While this growth has provided important economic benefits 

for Colorado, increased air emissions can have a negative impact on Colorado’s public health 

and environment. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 19 

 

Specifically, VOC emissions contribute to the formation of ground level ozone. Ozone is 

photochemical oxidant and known respiratory irritant. Ground level ozone is a secondary 

pollutant produced through the reaction of VOCs, nitrogen oxides and sunlight. Elevated levels 

of ground level ozone have been linked to a variety of adverse health effects including decreased 

lung function, increased respiratory symptoms, serious indicators of respiratory morbidity 

including emergency visits and hospital admissions, as well as total non-accidental and cardiorespiratory mortality. According to EPA, ground-level ozone also damages vegetation and 

ecosystems. It leads to reduced agricultural crop and commercial forest yields, reduced growth 

and survivability of tree seedlings, and increased susceptibility to diseases, pests and other 

stresses such as harsh weather. In the United States alone, ground-level ozone is responsible for 

an estimated $500 million in reduced crop production each year. Ground-level ozone also 

damages the foliage of trees and other plants, affecting the landscape of cities, national parks and 

forests, and recreation areas.12

The U.S. EPA has set the current National Ambient Air Quality Standards (“NAAQS”) for 

ground level ozone at 75 parts per billion (ppb) averaged over an 8-hour period. Based on a 

review of the then current health literature, the Clean Air Scientific Advisory Committee 

concluded in 2008 that the 75 ppb standard was not sufficiently protective of public health, and 

recommended that the standard be set at between 60 ppb and 70 ppb. EPA is in the process of 

considering whether to lower the ozone standard. 

Currently, the Denver Metro/North Front Range area is out of attainment with federal healthbased ground level ozone standards. This includes much of the Denver/Julesberg oil field. 

Other areas of the state have also experienced elevated ozone levels recently, with one monitor in 

Western Colorado showing concentrations above 75 ppb and a number of other monitors 

showing levels between 60 ppb and 75 ppb. 

Addressing oil and gas emissions is a critical component of Colorado’s efforts to lower ozone 

levels since this sector represents the largest source of VOC emissions in the state. Based on the 

most recent inventory (2011), 54% of the anthropogenic VOC emissions in the state come from 

the oil and gas sector, which is roughly triple the amount of emissions from the next largest 

source. Moreover, because of the ongoing growth in the oil and gas industry and the projected 

decline in VOC emissions from other sectors, the share of VOC emissions attributable to the oil 

and gas sector will likely increase over the foreseeable future. The proposed emission reduction 

strategies will further enhance existing public health and environment protections on both a local 

and regional scale. 

In addition to VOC emissions, oil and gas operations are a large source of methane. Methane is 

a potent greenhouse gas, which contributes to global climate change. In addition to reducing 

VOCs that contribute to regional ozone pollution, the Division’s proposed strategies will reduce 

methane, and thereby play a role in Colorado’s overall efforts to reduce greenhouse gas 

emissions. Finally, the proposed strategies will reduce the exposure of people that live and work 

 

12 See EPA website, “Ozone – Good Up High Bad Nearby.” http://www.epa.gov/oar/aqps/gooduphigh/bad.html. 

February 11, 2014. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 20 

 

near oil and gas production sites to VOC emissions. Methane is also a valuable natural resource 

(natural gas), and reducing leaks will benefit Colorado’s environment and economy. 

The Division assesses the direct and indirect costs to the regulated community for each of the 

proposed strategies in Regulation Number 7 in Section 3.3.8 of this Regulatory Analysis. 

Equipment costs, labor costs, maintenance costs, supervision costs, travel costs, and costs 

associated with recordkeeping and reporting are all evaluated. The Division estimates that the 

total annual costs to the regulated community as a result of the proposed strategies will be 

approximately $59.2 million. Further, the proposed strategies are expected to result in the 

capture of additional product worth approximately $16.8 million, for a total net cost of $42.4 per 

year. In addition to these direct costs, implementation of the proposed strategies could result in 

the shut-in of certain marginally producing wells, resulting in indirect costs in the form of lost 

revenues to oil and gas companies, loss of jobs associated with these facilities, lost royalty 

payments, and lost severance taxes. Based on available information the Division cannot 

reasonably calculate the amount of additional oil and gas that would be shut-in due to the 

proposed rules, but believes that the amount is likely to be very small due to the low costs 

attributable to small, marginally producing facilities.13 An analysis by an economist hired by 

certain industry parties has suggested that these indirect costs could be quite large.14 This 

information will be considered by the Commission as part of the rulemaking hearing. 

The Division recognizes that the oil and gas industry plays an important role in Colorado’s 

economy in the evaluation of qualitative impacts of the Regulation 7 proposal. The industry is a 

significant employer of highly skilled and well-paid employees. The industry generates large 

revenues and pays significant taxes in the state. It produces valuable domestic resources that help 

keep prices low while adding to national stability and security. At the same time, emissions from 

the oil and gas industry represent a significant portion of the total VOC emissions both in the 

NAA and throughout the rest of the state. The Division’s proposal is intended to achieve 

significant reductions in air emissions without imposing unreasonable costs that could stifle 

economic activity. 

As discussed above, the Division’s proposal is projected to result in a net annual cost to the 

industry of approximately $42.4 million. As with any increase in costs, the costs associated with 

the Division’s proposal could have some adverse impact on economic activity associated with the 

oil and gas industry in Colorado. However, over the past decade Colorado’s oil and gas industry 

has experienced unprecedented growth, even as Colorado has enacted regulatory measures to 

ensure that development continues in a protective and responsible manner. Moreover, given the 

relative size of the costs of the current proposal to the overall size of the industry, the total impact 

of these costs will likely be minimal. In 2012, for example, oil and gas producers in Colorado 

sold 48,450,717 barrels of oil and 1,661,073,176 MCF of natural gas. 

Based on the current price of oil, $96 per barrel, and assuming a price for natural gas of 

 

13 See discussion in Section 3.3.8 of this Regulatory Analysis. 14 See Attached Exhibit A. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 21 

 

$3.5/MCF15, annual revenue from the sale of oil and gas in Colorado based on 2012 production 

levels is approximately $10.5 billion. Accordingly, the net cost of the Division’s proposal is 

approximately 0.4% of the annual revenues. Given this small percentage, the Division’s proposal 

is unlikely to have any appreciable impact on the economic competitiveness of the industry as a 

whole. This conclusion is bolstered by the fact that several of the largest oil and gas companies 

in the state (Anadarko Petroleum Corp., Noble Energy, Inc., Encana Oil and Gas USA, and DCP 

Midstream) fully support the Division’s proposed revisions. Collectively, the Division estimates 

that these companies will bear approximately 75% of the total annual cost of the proposed rules. 

While it is unlikely that the costs associated with the proposed revisions will have any 

meaningfully adverse impacts on the competitiveness of the industry as a whole in Colorado, 

the costs could incrementally add to the current costs associated with operating marginally 

producing wells. This could potentially lead to some wells being shut in and the resultant 

economic consequences of these shut-ins including lost production revenue, lost royalties, lost 

severance taxes and potentially lost jobs. To mitigate against this possibility, the Division’s has 

crafted a tiered proposal that triggers requirements based on emission thresholds that are 

directly tied to production. Based on this, the truly small facilities are subject to less 

requirements and less costs; for example, only a one-time instrument-based leak inspection, 

which the Division estimates will cost approximately $712. 

Finally, it does not appear that the costs associated with the Division’s proposal will have any 

meaningful negative impact on the general public or small businesses that purchase natural gas 

and other petroleum products. Oil and natural gas are sold on international and national 

markets, making it extremely unlikely that any increase in production costs in Colorado will be 

reflected in prices for Colorado consumers. 

3.3.4 Probable Agency Costs

“The probable costs to the agency and to any other agency of the implementation and 

enforcement of the proposed rule and any anticipated effect on state revenues.” 

The Division will largely implement the provisions of its proposal through its oil and gas 

inspection team. This team currently consists of nine full time inspectors and four term limited 

inspectors. In 2012, in response to the growth in the oil and gas industry in Colorado, the 

legislature approved increasing the size of the inspection team from six inspectors to nine. In 

2013, the legislature appropriated additional funds to hire four term limited inspectors to conduct 

IR camera inspections at well production facilities in Colorado. The term for these positions 

runs through June of 2015, but could be extended by the legislature if warranted. The additional 

inspectors provided during the 2012 and 2013 legislative sessions has significantly expanded the 

capabilities of the oil and gas inspection team, which will further enable the Division to 

implement and enforce the proposed requirements if the Commission chooses to adopt the 

Division’s proposal. The total projected annual cost to the Division for the oil and gas inspection 

 

15 The Division assumed a price per MCF of $3.50 throughout its analysis; however, natural gas prices are currently 

around $5 per MCF, suggesting that the Division has underestimated the value of gas saved by the proposal. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 22 

 

team in fiscal year 2013-14 is $1,305,304, which includes salary costs, fringe benefits, operating 

costs (including vehicles, field equipment, and office equipment), travel training and indirect 

costs. 

The Division does not anticipate state revenues to be affected because the proposal does not assess 

any additional emissions reporting or permitting fees beyond those that already apply. However, 

state revenues could potentially be affected by implementation of the proposed strategies, in that they 

could potentially result in the shut-in of a few marginally producing wells, resulting in indirect costs 

in the form of lost revenues to oil and gas companies, loss of jobs associated with these facilities, lost 

royalty payments, and lost severance taxes. Based on available information the Division cannot 

reasonably calculate the amount of oil and gas that could be shut-in due to the proposed rules, but 

believes that the amount is likely to be very small due to the low costs attributable to small, 

marginally producing facilities. 

3.3.5 Comparison to Inaction

“A comparison of the probable costs and benefits of the proposed rule to the probable costs and 

benefits of inaction.” 

The Division estimates the proposed strategies will reduce volatile organic compound (VOC) 

emissions by 93,500 tons per year, and methane/ethane emissions by 64,000 tons per year. The 

Division conservatively estimates that the annual net costs to industry of the Division’s proposal will 

be $42.4 million per year. This translates to approximately $453 per ton of VOC reduced. Costs and 

benefits of the proposed Regulation 7 revisions are detailed in Section 3.3.8. 

Conversely, inaction would mean that the above emissions reductions are not realized, that the 

associated captured methane (natural gas), a valuable natural resource, is lost to the ambient air 

and that the estimated cost savings in captured product that can be sold at a profit is not realized. 

Further, emissions from this sector are projected to grow substantially, especially in shale gas/oil 

development.16 

The forecast growth in shale gas/oil development will result in increased emissions of VOC and 

other hydrocarbons including greenhouse gases, unless additional controls are implemented. 

This could result in increases in ozone formation and the development of additional State 

Implementation Plan requirements to meet current and future NAAQS requirements. According 

to EPA, attaining the current ozone standard throughout the nation will result in between $6.9 

billion and $18 billion in annual health benefits. For lower standards the health benefits are even 

greater. For example, EPA projects that achieve a 70 ppb standard will result in between $13 

billion and $37 billion in annual health benefits, and for a 65 ppb standard the benefits will 

increase to between $22 billion and $61 billion per year. EPA does not report these health 

benefits by state, but since the population of the Denver Metropolitan Area/North Front Range 

NAA accounts for approximately 2.5% of the total national population living in areas that are in 

 

16 U. S. Energy Information Administration. “Annual Energy Outlook 2013”. April 15-May 2, 2013. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 23 

 

violation of the current NAAQS, the health benefits attributable to Colorado are likely to be 

substantial. 

The proposed rules will also produce substantial benefits associated with reducing greenhouse 

gases. As part of this rulemaking the Environmental Defense Fund has engaged an expert to 

analyze the benefits of the rulemaking based on the social cost of carbon. Based on this analysis, 

EDF projects that the total annual benefit from the projected methane reductions is between $104 

million and $318 million in 2016 and between $132 million and $404 million in 2025.17

In addition to the benefits associated with reductions of VOCs and methane, the proposed rules 

will produce additional economic benefits in the form increased product capture and the creation 

of new jobs associated with the implementation of the new requirements. 

3.3.6 Less Costly Methods/Less Intrusive Methods		

“A determination of whether there are less costly methods or less intrusive methods for 

achieving the purpose of the proposed rule.” 

In 2004, 2006 and again in 2008, the Commission established oil and gas industry specific 

emissions control requirements in an effort to reduce VOC emissions in the 8-hour ozone NAA. 

The tremendous growth of oil and gas production in Colorado and the associated emissions 

continue to threaten the air quality gains that have been achieved. Since 2004 gas production in 

Colorado has increased by 50% while oil production has more than doubled. Since then, the oil 

and gas industry has grown significantly (more than predicted), and changes in drilling 

technologies and other advancements have further supported growth in this industry. The oil and 

gas industry continues to be the largest VOC emitter in Colorado (illustrated in Figure 1, below). 

Several industry alternative proposals identify less costly and/or less intrusive methods to reduce 

emissions (see Section 3.3.7 of this Regulatory Analysis). The Division made several 

clarifications based on these alternatives, but did not substantially revise the Division’s 

Regulation 7 proposal. The Division believes the Regulation 7 proposal secures more emissions 

reductions than those alternatives, and those additional emission reductions are cost effective. 

Moreover, several parties have proposed more costly and/or more intrusive methods to reduce 

emissions. The Division believes that its proposal strikes a proper balance and achieves 

substantial emissions reductions in a cost effective manner. 

 

17 See Attached Exhibit B.
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 24 

 

Figure 1 - Colorado Statewide Anthropogenic VOC Emissions (2011) 

3.3.7 Alternative Methods		

“A description of any alternative methods for achieving the purpose of the proposed rule that 

were seriously considered by the agency and the reasons why they were rejected in favor of the 

proposed rule.” 

In addition to the Division’s proposal, various parties to the rulemaking have submitted 6 

different alternative proposals for the Commission to consider. Some of these proposals request 

that the Commission adopt additional requirements that go beyond the Division’s proposal, while 

other alternatives request that the Commission limit aspects of the Division’s proposed revisions. 

In some cases, the parties submitting the proposals included analyses estimating the costs and 

benefits associated with their proposals. Copies of each of these proposals along with any 

economic impact analysis that the parties submitted identifying the projected costs and benefits 

of their particular proposals are attached to this Regulatory Analysis as exhibits. Upon evaluation 

of these proposals, and other parties’ comments, the Division made several clarifications to but 

did not substantially revise the Division’s Regulation 7 proposal. The Division believes the 

Regulation 7 proposal strikes an appropriate balance between the various alternatives. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 25 

 

The section below identifies each of the submitted proposals, discusses how the proposals differ 

from the Division’s proposal, and addresses the projected costs and benefits of each proposal.18

 

3.3.7.1 		Joint Industry Work Group

A collection of oil and gas companies and industry trade groups have submitted an alternative 

proposal seeking to limit the requirements set forth in the Division’s proposal.19 Specifically, the 

Joint Industry Work Group request that the Commission limit the Division’s proposal in the 

following respects: 1) restrict all proposed requirements to the Denver Metropolitan Area/North 

Front Range 8-hour ozone NAA; 2) reduce the required frequency proposed for leak inspection 

and repair; 3) eliminate the proposed requirements for dehydrators; 4) limit proposed 

requirements for compressor seals and open-ended lines to compressor stations; and 5) eliminate 

proposed requirements related to well maintenance and liquids unloading. In addition to these 

proposed limitations, the Joint Industry Work Group have proposed a number of additional 

changes, which could have some minimal additional impacts on the costs and benefits of the 

proposal. 

Since the Joint Industry Group did not submit an economic analysis detailing the projected costs 

and benefits of their alternative proposal,20 the Division has conducted an analysis of the Joint 

Industry Work Group alternative proposal utilizing the same methodologies and assumptions 

detailed in Section 3.3.8 of this Regulatory Analysis. Based on this analysis, the Division 

estimates that the Joint Industry Work Group alternative proposal would have a net cost21 to the 

regulated community of approximately $32.2 million, and would reduce emissions of VOCs by 

56,525 tons per year and methane/ethane by 33,058 tons per year. The decrease in net costs 

should have some positive impact on the indirect costs associated with potential well shut-ins, 

but the Division is unable to reasonably calculate this impact. The decrease in costs relative to 

the Division’s proposal includes a decrease in the number of facility inspections, which would 

result in fewer new inspector jobs attributable to the proposal. Finally, because the Joint 

Industry Work Group proposal would result in less VOC and methane emission reductions, the 

economic benefits associated with these reductions discussed in Section 3.3.8 of this Regulatory 

Analysis would be reduced. 

 

18 In instances where a party submitted an analysis of the costs and benefits associated with their proposal such 

analysis is attached. Where parties submitted proposal without an analysis of their own proposal the Division has 

endeavored to analyze the costs and benefits of these proposals using the same methodologies used to analyze the 

costs and benefits of the Division’s proposal. 

19 A copy of this alternative proposal is attached to this Regulatory Analysis as Exhibit C. 20 The group did submit an analysis of the Division’s proposal showing substantially higher costs than reflected in 

the Division’s analysis. A copy of this analysis is attached hereto as Exhibit A. It should be noted that while the 

Joint Industry Work Group predicts much higher costs from the Division’s proposals, Anadarko Petroleum 

Corporation, Noble Energy, Inc. and Encana Oil and Gas USA have submitted information during the rulemaking 

supporting the reasonableness of the Division’s cost and benefit calculations. Submissions from these companies 

can be found at the following link: 

ftp://ft.dphe.state.co.us/apc/aqcc/REBUTTAL%20STATEMENTS,%20EXHIBITS%20%26%20ALT%20PROPOS

AL%20REVISIONS/

21 Net cost reflects the cost of implementing the proposed strategy less the value of the additional product captured 

as a result of the proposed strategies. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 26 

 

3.3.7.2 		WPX Energy

WPX is the largest natural gas producer in the state. In the current rulemaking WPX has offered 

an alternative proposal that would decrease the total number of leak inspections by allowing well 

production facilities with low leak rates during two consecutive inspections to reduce inspection 

frequency from monthly to quarterly, or from quarterly to annually depending on the size of the 

facility.22 While it is difficult to predict in advance how many facilities would be able to take 

advantage of this reduced inspection rate, for the purposes of this Regulatory Analysis the 

Division assumes that one half of the facilities would be able to utilize the reduced frequency. 

Based on this assumption, adoption of WPX’s alternative proposal would reduce the total net 

annual cost of the proposed revisions from approximately $42.4 million to approximately $36.8 

million. This change would also decrease the amount of emission reductions from the Division’s 

proposal by 1,845 tons per year of VOC and 2,757 tons per year of methane/ethane. 

The decrease in net costs should have some positive impact on the indirect costs associated with 

potential well shut-ins, but the Division is unable to reasonably calculate this impact. Given the 

relatively small difference in net costs between the two proposals, any positive impact should be 

fairly small. The decrease in costs relative to the Division’s proposal includes a decrease in the 

number of facility inspections, which would result in fewer new inspector jobs attributable to the 

proposal. Based on the number of inspection hours for each proposal, the number of new 

inspector jobs would decrease. Finally, because the WPX proposal would result in less VOC and 

methane emission reductions, the economic benefits associated with these reductions discussed 

in Section 3.3.8 of this Regulatory Analysis would be reduced. 

3.3.7.3 		Conservation Groups

As part of the rulemaking a number of conservation groups have submitted an alternative 

proposal requiring additional leak detection inspections for well production facilities and 

compressor stations relative to the Division’s proposal. In addition, the Conservation Groups’ 

alternative proposal increases the number of pneumatic devices that would need to be retrofitted. 

A copy of the Conservation Groups’ alternative proposal is attached as Exhibit D. Additionally, 

their analysis of the costs and benefits associated with their alternative proposal is attached as 

Exhibit E. 

3.3.7.4 		Local Community Organizations

A group of local community organizations have submitted an alternative proposal aimed at 

increasing the stringency of the Division’s proposal for facilities that are located within 1,320 

feet of a building unit or designated outdoor activity area. Specifically, for such facilities the 

Local Community Organizations’ alternative proposal would decrease the threshold for controls 

from petroleum storage tanks from 6 tons per year (as proposed by the Division) to two tons per 

year. Additionally, facilities located within 1,320 feet of these designated areas would be subject 

to a more stringent leak inspection schedule. Copies of the Local Community Organizations’ 

 

22 In addition to this change, WPX has proposed a limited number of additional changes and clarifications that do 

not impact the cost and benefit calculations conducted for the Division’s proposal. A copy of WPX’s alternative 

proposal is attached as Exhibit F. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 27 

 

alternative proposal and their assessment of costs and emission reduction benefits are attached as 

Exhibits G and H. 

3.3.7.5 		Local Government Coalition

The Local Government Coalition consists of a number of county and city governments including 

Adams County, Boulder County, La Plata County, Pitkin County and San Miguel County, Fort 

Collins, the City of Boulder, and the City and County of Denver. In their alternative proposal, 

the Local Government Coalition seeks to increase the number of leak detection inspections for 

compressor stations and well production facilities relative to the Division’s proposal. The Local 

Government Coalition also seeks to require that well production facilities be tied in to a gas 

gathering line within 90 days after the date of first production, unless the Division approves an 

extension of this deadline. Copies of the Local Government Coalition’s alternative proposal and 

documents assessing the costs and benefits of that proposal are attached hereto as Exhibits I 

through M. 

3.3.7.6 		Worldwide Liquid Solutions, LLC

Worldwide Liquid Solutions (WLS) is a manufacturer of emission reduction technology 

designed to control VOC emissions from petroleum storage tanks. According to WLS, their 

emission reduction technology cannot control methane and ethane and therefore cannot meet the 

control standards for tanks reflected in the Division proposal. To address this, WLS has 

submitted an alternative proposal that would only require reductions of VOCs from tanks and not 

methane/ethane. As an alternative to their alternative, WLS has proposed rejecting all of the 

proposed changes to Regulation No. 7 set forth in the Division’s proposal. Copies of WLS’ 

alternative proposal and their assessment of costs and emission reduction benefits are attached as 

Exhibits N and O. 

3.3.8 Quantification of Data		

“To the extent practicable, a quantification of the data used in the analysis; the analysis must 

take into account both short-term and long-term consequences.” 

As set forth below, the Division has assessed the direct and indirect costs to the regulated 

community for each of the proposed strategies in Regulation Number 7. The Division estimates 

revisions to Regulation 7 will reduce VOC emissions by 93,500 tons per year, and methane/ethane 

emissions by 64,000 tons per year. The Division conservatively estimates that the annual net costs to 

industry of the Division’s proposal will be $42.4 million per year. This translates to approximately 

$453 per ton of VOC reduced, which is very reasonable when compared to other air pollution 

reduction strategies adopted by the Colorado Commission and the EPA. The Division estimates 

that the total annual costs to the regulated community as a result of the proposed strategies will 

be approximately $59.2 million. Further, the proposed strategies are expected to result in the 

capture of additional product worth approximately $16.8 million, for a total net cost of $42.4 

million per year. In addition to these direct costs, implementation of the proposed strategies 

could potentially result in the shut-in of certain marginally producing wells, resulting in indirect 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 28 

 

costs in the form of lost revenues to oil and gas companies, loss of jobs associated with these 

facilities, lost royalty payments, and lost severance taxes. Based on available information the 

Division cannot reasonably calculate the amount of oil and gas that could be shut-in due to the 

proposed rules, but believes that the amount is likely to be very small due to the low costs 

attributable to small, marginally producing facilities. To mitigate against this possibility, the 

Division’s has crafted a tiered proposal that triggers requirements based on emission thresholds that 

are directly tied to production. Based on this, the truly small facilities are subject to less requirements 

and less costs; for example, only a one-time instrument-based leak inspection, which the Division 

estimates will cost approximately $712. An analysis by an economist hired by certain industry 

parties has suggested that these indirect costs could be quite large.23 This information will be 

considered by the Commission as part of the rulemaking hearing. 

The detailed discussions below largely focus on short-term consequences of the proposal. Long 

term consequences potentially include having to establish greater and potentially more extreme 

control measures in the future to address the current mass of emissions and anticipated growth in 

emissions. The oil and gas industry is expected to continue to grow significantly, especially in 

shale gas/oil development.24 

This continued growth in shale gas/oil development will result in increased emissions of VOC 

and other hydrocarbons including methane and ethane, unless additional controls are 

implemented. This could result in increases in ozone formation and additional State 

Implementation Plan requirements to meet current and future NAAQS requirements. According 

to EPA, attaining the current ozone standard throughout the nation will result in between $6.9 

billion and $18 billion in annual health benefits. For lower standards the health benefits are even 

greater. For example, EPA projects that achieving a 70 ppb standard will result in between $13 

billion and $37 billion in annual health benefits, and for a 65 ppb standard the benefits will 

increase to between $22 billion and $61 billion per year. EPA does not report these health 

benefits by state, but since the population of the Denver Metropolitan Area/North Front Range 

NAA accounts for approximately 2.5% of the total national population living in areas that are in 

violation of the current NAAQS, the health benefits attributable to Colorado are likely to be 

substantial. 

3.3.8.1 		Control Requirements for Petroleum Storage Tanks

Commencing in 2004 the Commission has adopted a series of requirements aimed at reducing 

emissions from petroleum storage tanks at well production facilities, compressor stations and gas 

processing plants. Currently, condensate tanks with uncontrolled actual emissions of 20 tons per 

year or greater of VOC must be equipped with a control device that has a control efficiency of at 

least 95%. Additionally, with certain exceptions, operators in the NAA must achieve a 90% 

system-wide reduction of VOC emissions from condensate tanks during the period from May 1 

through September 30, and 70% during the period from October 1 through April 30. These 

current requirements only apply to tanks that store condensate, which is defined in the 

Commission’s Common Provisions regulation as “hydrocarbon liquids . . . with an API gravity 

 

23 See Attached Exhibit A. 24 U. S. Energy Information Administration. “Annual Energy Outlook 2013”. April 15-May 2, 2013. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 29 

 

of 40 degrees or greater.” While most of the petroleum liquid produced in Colorado qualifies as 

condensate, there are heavier hydrocarbon liquids, typically referred to as crude oil, with an API 

gravity below 40 degrees that are not subject to the current control requirements. Additionally, 

there are a number of high volume produced water tanks that have VOC emissions above 6 tons 

per year that are not currently regulated under the existing requirements. 

While Colorado has achieved considerable success in controlling emissions from condensate 

tanks since 2004, petroleum storage tanks at oil and gas production and midstream facilities 

continue to be the most significant source of VOC emissions from this sector. To address this 

emission source the Division is proposing the following strategies: 1) reducing the control 

threshold from 20 tons per year VOC to 6 tons per year; 2) eliminating the distinction between 

condensate and other liquids and requiring controls strictly based on emission levels; and 3) 

extending the current requirement that all condensate tanks in the NAA be controlled during the 

first 90 days of production to storage tanks throughout the state. In order to meet each of these 

three strategies, the Division assumes that owners and operators will equip tanks with enclosed 

flares, as is the typical practice under the existing tank control requirements. The estimated costs 

associated with installing and maintaining an enclosed flare are set forth in subsection 3.3.8.1.1 

of this Regulatory Analysis. Utilizing the calculated flare costs, the estimated costs and benefits 

for each of the three tank control strategies are discussed in subsections 3.3.8.1.2 – 3.3.8.1.4 of 

this Regulatory Analysis. 

3.3.8.1.1 General	Cost	Estimates	for	Flares	 	

The estimated cost for a flare control device is based on identified costs from a 2008 oil and gas 

cost study25 adjusted for inflation. Based on this data, the estimated annualized cost of a flare 

control device with auto-igniter26 is about $6,287.27 

 

 

25 See “Oil & Gas Emissions Reduction Strategies Cost Analysis and Control Efficiency Determination,” Lesair 

Environmental, Inc., June 2008. Information from this study was previously submitted to the Commission as part of 

the 2008 Ozone Action Plan process. For reference or background purposes, the Division has cited herein certain 

information that has been submitted to the Commission as part of the rulemaking; however, it is not necessarily 

included with this Regulatory Analysis as an exhibit. 

26 Currently only flares in the NAA are required to have auto-igniters. Under the current proposal, the auto-igniter 

requirement would be extended statewide. For the purposes of this cost analysis, it is assumed that auto-igniters will 

be required statewide. The cost and benefits associated with equipping existing flares outside the non-attainment 

with auto-igniters are discussed below in Section 3.3.8.1.7. 

27 Certain parties to the rulemaking have asserted that the actual cost per combustion device is higher based on 

EPA’s cost analysis conducted in accordance with NSPS OOOO. Based on a review of EPA’s analysis it appears 

that additional costs were included for surveillance systems that are not applicable to the proposed rule. 

Additionally, unlike the analysis in NSPS OOOO, the costs that the Division has identified are based on a Colorado 

specific cost analysis. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 30 

 

Table 1: Flare Control Device with Auto Igniter – Annualized Cost Analysis* 

Item Capital Costs 

(one time) 

Non-Recurring 

Costs (one time) 

O&M Costs 

(recurring) 

Annualized 

Total Costs 

Flare $18,169 

Freight/Engineering $1,648 

Flare Installation $6,980 

Auto Igniter $1,648 

Pilot Fuel** $768 

Maintenance $2,197 

Subtotal Costs $19,817 $8,628 $2,965 

Annualized Costs*** $2,747 $575 $2,965 $6,287

*Control cost evaluation based on 2008 Ozone Rulemaking cost survey and producer data. Control device costs 

were developed based on an oil and gas cost study and information submitted by industry in 2008. However, those 

costs were escalated by 9.85% to reflect CPI-U increases that have occurred since 2008.28

** Pilot fuel costs $3.41/MMBtu (Henry Hub Spot Price - Aug. 2013) 

*** Annualized over 15 years at 5% ROR 

3.3.8.1.2 Lowering	Statewide	Condensate	Tank	Control	Threshold	(from	20	tpy	to	6	tpy)	

The Division is proposing to lower the uncontrolled VOC emission control threshold from 20 tpy 

down to 6 tpy on condensate storage tanks statewide. Based on an analysis of the Air Pollution 

Emissions Notice (APEN) database, the Division estimates that statewide there are 588 

uncontrolled condensate tank batteries with VOC emissions over six tons per year. Of these 588 

tanks, 396 are outside the NAA and the remaining 192 are within the current NAA. 

Table 2: Condensate Tank Battery Analysis

Tank Battery Type Ozone NAA 

[count] 

Outside 

NAA [count] 

Cancelled 

Tanks [count] 

Total Statewide 

Tanks [count] 

Controlled Tanks 4,971 490 5,461 

Uncontrolled Tanks 1,451 1,132 36 2,619 

All Tanks 6,422 1,622 36 8,080 

 

Uncontrolled Tanks (≥ 6 tpy) 192 396 588 

Based on the reported uncontrolled actual VOC emissions for these 588 tanks, and assuming 

both that 75% of the VOC emissions are captured and sent to the flare,29 and that the flare has a 

95% destruction efficiency, the total VOC emission reduction associated with lowering the 

condensate tank threshold statewide is 5,162 tons per year. 

 

28 It has been suggested that the Division should have used the Producer Price Index to calculate an escalation from 

2008 to 2013 costs. From 2008 to 2013, however, the Producer Price Index for the oil and gas field equipment 

sector grew at a slower rate than the CPI. Accordingly, the Division’s analysis may actually overstate the increase 

in cost from 2008 to 2013. 

29 The costs and benefits associated with improving the capture percentage for controlled storage tanks are discussed 

below in Section 3.3.8.1.5. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 31 

 

Table 3: Condensate Tank Battery Emissions Analysis for Lowering Statewide Threshold

Tank Battery Type 

Uncontrolled 

VOC Emissions 

[tons/year] 

Controlled 

VOC 

Emissions 

[tons/year] 

VOC 

Emission 

Reduction 

[tons/year] 

NAA Uncontrolled Tanks (≥6 tpy) 2,355 677* 1,678 

Outside NAA Uncontrolled Tanks (≥6 tpy) 4,890 1,406* 3,484 

Totals: 7,245 2,083 5,162 

*Emission reduction estimated by accounting for 75% capture and 95% destruction efficiency. 

The annualized cost of installing 588 flare control devices is about $3.7 million dollars with an

average cost effectiveness of about $716 per ton of VOC reduced. For the smallest individual 

tank battery subject to controls (6 tons/year), the flare cost effectiveness is estimated at $1,471 

per ton of VOC reduced. 

Table 4: Tanks over 6 tpy – Control Cost Estimates for Flare Control Devices

Affected Tanks 

[count] 

Each Flare 

Annualized Cost 

Total Annualized 

Costs 

VOC Reduction 

[tons/year] 

Control Costs

[$/ton] 

588 $6,286.8 $3,696,638 5,162 $716

In addition to VOC reductions, this strategy will significantly reduce methane and ethane 

emissions from currently uncontrolled tanks. To calculate methane and ethane emission 

reductions, the Division determined the relative proportion of VOCs to methane and ethane 

based on reported average values from 30 natural gas liquid analyses submitted to the Division. 

Based on these analyses, methane/ethane emissions from condensate storage tanks are about 

38% of the VOC emissions by weight. Accordingly, projected methane/ethane emission 

reductions from this proposed strategy are 1,963 tons per year or $1,884 per ton of 

methane/ethane reduced. 

3.3.8.1.3 Requiring	Controls	for	Produced	Water	and	Crude	Oil	Tanks	

As discussed above, the Division is proposing to eliminate the distinction between condensate 

tanks and other storage tanks. If the Commission adopts this proposal, crude oil tanks and 

produced water tanks with uncontrolled actual VOC emissions of six tons per year or greater will 

require controls. Because produced water and crude oil tanks are identified separately in the 

Division’s APEN data base, the costs and benefits for these two types of storage tanks are broken 

out separately. 

The Division is proposing that all statewide produced water tanks with uncontrolled VOC 

emissions over 6 tons/year be required to install emission controls. Some uncontrolled produced 

water tanks could be co-located at sites with condensate or crude oil tanks that have flare 

controls, but pressure and flow differences may require the installation of a separate flare control 

device for the water tank. Consequently, the control costs are based on the assumption that each 

water tank battery will install a new flare control device. Based on an analysis of the APEN 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 32 

 

database, the Division estimates that statewide there are 52 uncontrolled produced water tank 

batteries with VOC emissions over 6 tons/year. 

Table 5: Produced Water Tank Battery Analysis

Tank Battery Type Total Statewide Water Tanks 

Controlled Water Tanks: 338 

Uncontrolled Water Tanks: 530 

Total: 868 

Uncontrolled Tanks (≥6 tpy) 52 

Based on the reported uncontrolled actual emissions, the Division estimates that the total VOC 

emission reduction associated with controlling these produced water tanks statewide is 457 tons 

per year. 

Table 6: Produced Water Tank Battery – Emissions Analysis

Tank Battery Type 

Uncontrolled 

VOC Emissions 

[tons/year] 

Controlled 

VOC 

Emissions 

[tons/year] 

VOC 

Emission 

Reduction 

[tons/year] 

Uncontrolled Tanks (≥6tpy) 641.4 184.4* 457 

*Emission reduction estimated by accounting for 75% capture and 95% destruction efficiency. 

The annualized cost of installing 52 flare control devices is about $327,000, with an average cost 

effectiveness of about $715 per ton of VOC reduced. For the smallest individual tank battery (6 

tons/year), the flare cost effectiveness is estimated at $1,471 per ton of VOC reduced. 

Table 7: Produced Water Tanks – Control Cost Estimates for Flare Control Devices

Tank Size 

Affected 

Tanks 

[count] 

Each Flare 

Annualized 

Cost 

Total 

Annualized 

Costs 

VOC 

Reduction 

[tons/year] 

Control 

Costs 

[$/ton] 

≥ 6tpy 52 $6,286.8 $326,914 457 $715 

The Division is proposing that all statewide hydrocarbon liquid storage tanks with VOC 

emissions over six tons/year must install emission controls. Based on a recent analysis of 2013 

APEN data, there are 67 reported crude oil tanks batteries statewide. Thirty seven of the tank 

batteries are already equipped with controls. Of the remaining thirty, eight are over the proposed 

six tons/year threshold. Given that approximately 5% of the total wells in the state report crude 

oil production to the Colorado Oil and Gas Conservation Commission (COGCC),30 it appears 

 

30 Based on an analysis of 2010 COGCC data. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 33 

 

likely that the Division’s APEN database may be undercounting crude oil tanks, either because 

these tanks have not been reported or because they are being reported as condensate tanks.31

Table 8: Crude Oil Tank Battery Analysis

Tank Battery Type Total Statewide Crude Oil Tanks 

Controlled Crude Oil Tanks 36 

Uncontrolled Crude Oil Tanks 29 

Total: 65 

 

Uncontrolled Tanks (≥6 tpy) 8 

The total VOC emission reduction associated with controlling these 8 crude oil tanks statewide is 

118 tons per year. 

Table 9: Crude Oil Tank Battery – Emissions Analysis

Tank Battery Type 

Uncontrolled VOC 

Emissions 

[tons/year] 

Controlled 

VOC Emissions 

[tons/year] 

VOC Emission 

Reduction 

[tons/year] 

Uncontrolled Tanks (≥6tpy) 165.2 47.5* 117.7 

*Emission reduction estimated by accounting for 75% capture and 95% destruction efficiency. 

The annualized cost of installing eight flare control devices is about $50,294 dollars with an 

average cost effectiveness of about $427 per ton of VOC reduced. For the smallest individual 

tank battery (6 tons/year), the flare cost effectiveness is estimated at $1,471 per ton of VOC 

reduced. 

Table 10: Crude Oil Tanks – Control Cost Estimates for Flare Control Devices

Tank Size 

Affected 

Tanks 

[count] 

Each Flare 

Annualized 

Cost 

Total 

Annualized 

Costs 

VOC 

Reduction 

[tons/year] 

Control 

Costs 

[$/ton] 

≥ 6tpy 8 $6,286.8 $50,294.4 117.7 $427 

3.3.8.1.4 Requiring	Controls	During	the	First	90	Days	of	Production	Statewide	

Under current requirements owners and operators of new and modified storage tanks outside the 

NAA have 90 days after the date of first production to determine if emissions from the tank 

trigger the requirement to install a control. Because production is typically at its highest during 

this initial period, significant emissions can occur before controls are installed. To address this 

 

31 Prior to 2008 crude oil storage tanks were exempt from APEN reporting requirements, which may explain in part 

the small numbers of tanks identified in the system. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 34 

 

issue in the NAA, the Commission mandated in the 2008 Ozone Action Plan that all condensate 

tanks be controlled during the first 90 days. The Division is now proposing to expand this 

requirement to storage tanks throughout the state. 

To calculate the cost effectiveness of this strategy, the Division first determined the number of 

new and modified storage tanks outside the NAA based on reported APEN data for the period of 

2010-2012. Based on this APEN data, there are on average 141 new and modified tanks each 

year, with yearly reported uncontrolled actual emissions of 7,370 tons VOC. Assuming that 

emissions during the first 90 days equal 1/4th of the annual reported emissions,32 total 

uncontrolled actual VOC emissions from these tanks during the first 90 days is 1,842.5 tons. 

Assuming enhanced capture efficiency for these new tanks (see subsection 3.3.8.1.5 of this 

Regulatory Analysis) the flare control efficiency is 95%, and thus the calculated benefit from 

expanding the first 90 day control requirement to tanks outside the NAA will be 1,750.4 tons per 

year. 

While the Division estimates that there are 141 new and modified storage tanks outside the NAA 

each year, the majority of these, 84, will require control devices regardless of this strategy since 

their uncontrolled actual emissions are over six tpy. For these 84 tanks, the cost of operating a 

flare during the first 90 days will be approximately 25% of the total annualized cost, or 

$1,571.70 per tank. For the remaining 57 tanks with emissions less than six tons/year, because 

controls for these tanks will only need to be in place for 90 days, the Division assumes that each 

flare can control 3 tanks per year, which means that 19 new flares are required to comply with 

this proposed strategy. For other applications, the annualized cost of a flare is estimated to be 

$6,287. Since flares required for this application will be relocated three times a year, the 

Division assumes an additional $3,000 in annual relocation costs, for a total annualized cost of 

about $9,287 per flare. Based on the emission reductions calculated above, the total cost 

effectiveness of this requirement is $176/ton of VOC reduction. 

 

Table 11: Control Cost Estimates for Flare Control Devices Required During the First 90 

Days of Production 

Storage 

Tank 

Threshold 

[tpy] 

Number of 

New 

Storage 

Tanks 

Number 

of New 

Flares 

Annualized 

Cost Each 

Flare 

Total Flare 

Cost 

Total VOC 

Reduction 

[tons/year] 

VOC 

Control 

Cost 

[$/ton] 

<6 57 19 $9,286.8 $176,449.2 44.7 $3,947 

≥6 84 84 $1,571.7 $132,022.8 1,705.7 $77 

 141 $308,472 1,750.4 $176 

Using the methodology discussed in subsection 3.3.8.1.2 of this Regulatory Analysis, the 

projected methane/ethane emission reductions from this strategy is 665.5 tons per year or $464 

per ton of methane/ethane reduced. 

 

32 Because reported emissions typically are based on a calculation assuming a standard rate of production decline 

after the first 90 days, actual emissions during the first 90 days could be much higher. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 35 

 

3.3.8.1.5 Emission	Capture	Requirements	for	Controlled	Petroleum	Storage	Tanks	

In order for storage tank control requirements to be effective, emissions from the tank must be 

routed to the control device. Historically the Division has assumed that 100% of a tank’s 

emissions will be captured and routed to the control device, typically a flare, resulting in a 95% 

reduction of emissions. Field observations using IR cameras and other methodologies indicate 

that in actuality emissions from controlled storage tanks often escape through the thief hatches 

and pressure relief valves (PRV) and therefore are not being combusted in the flare. This occurs 

when the tank cannot adequately contain the flashing emissions that occur when pressurized 

liquids from the separator are dumped into the atmospheric tank. To address this issue, the 

Division is proposing new regulatory language clarifying that all emissions from controlled 

storage tanks must be routed to the control device and that these tanks must be operated without 

venting emissions from thief hatches, PRVs and other openings, except when venting is 

reasonably necessary for maintenance, gauging, or safety of personnel and equipment. 

To assure compliance with these capture standards, the Division’s proposal requires that owners 

and operators of controlled storage tanks implement a STEM plan. Pursuant to the STEM plan, 

owners and operators must evaluate and employ appropriate control technologies and/or 

operational practices designed to meet the proposed capture requirements, and certify that these 

technologies and/or operational practices are designed to minimize emissions from the tank. The 

Division’s STEM proposal also requires implementation of a two-pronged monitoring strategy 

involving a weekly33 auditory, visual, and olfactory (AVO) inspection for all controlled tanks, 

and a periodic instrument based monitoring for tanks using EPA Reference Method 21, an IR 

camera or other Division approved monitoring device or method. As proposed, the frequency of 

this instrument based monitoring will depend on the level of uncontrolled actual emissions from 

the tank. 

Table 12: Proposed Tiering for Instrument Based Tank Inspections

Tank Uncontrolled Actual VOC Emissions Inspection Frequency 

≥ 6 tpy to ≤ 12 tpy Annually 

> 12 tpy to ≤ 50 tpy Quarterly 

> 50 tpy Monthly 

In assessing the cost effectiveness of the proposed requirements, the Division first calculated the 

costs associated with implementing technological and/or operational changes at controlled tanks. 

For the purposes of this analysis the Division assumed that all tanks with uncontrolled actual 

emissions greater than or equal to 6 tons per year would need to be controlled consistent with the 

Division’s proposal discussed in Section 3.3.1 of this Regulatory Analysis. Based on reported 

data, there are currently 5,310 storage tanks statewide with emissions greater than or equal to 6 

tons per year. While the Division’s proposal does not specify the type of technology or 

operational practices that operators will use, for the purposes of this analysis the Division 

 

33 There is an exception for the weekly inspection requirement where the operator loads out liquids from the storage 

tank on less than a weekly basis. In these circumstances the operator must conduct the inspection whenever liquids 

are loaded out, but no less often than every 30 days. Typically liquids are loaded out multiple times in a given week, 

meaning that for the majority of the tanks AVO inspections will be required weekly. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 36 

 

assumed that buffer bottle technology would be installed on each of the subject tanks.34 The 

buffer bottle technology utilizes a small tank that is installed after the separator which allows for 

a secondary flash of pressurized liquids prior to dumping into the storage tank. The second-stage 

flash reduces the pressure of the liquids going to the tank and thereby helps to ensure that the 

tank can adequately handle the flashing emissions that occur when the liquids are brought to 

atmospheric pressure. Based on industry provided information, the estimated annual cost of a 

buffer bottle is set forth in Table 13.35

Table 13: Annualized Cost Analysis for Buffer Bottle 

Item Capital Costs 

(one time) 

Non-Recurring 

Costs (one time) 

O&M Costs 

(recurring) 

Annualized 

Total Costs 

Buffer Bottle $11,500 

Freight/Engr $600 

Installation $2,280 

Maintenance $2,500 

Subtotal Costs $11,500 $2,880 $2,500 

Annualized Costs* $1,593.8 $192 $2,500 $4,285.8

* Annualized over 15 years at 5% ROR 

The Division also calculated the costs associated with conducting enhanced inspections. Based 

on the proposed tiering, operators will need to conduct 24,840 tank inspections per year.36

Assuming that each inspection takes two hours and utilizing a $103/hour 37 in-house inspection 

cost and a $134/hour contractor inspection cost (30% profit added to in-house rate), the total 

annual cost associated with conducting enhanced inspections under the proposed rule is 

$5,392,010, which equates to $1,015.4 per year for each tank that will be subject to STEM. 

 

 

34 Based on discussions with industry representatives during the stakeholder process there may be other less costly 

technologies and operational practices that could be used to ensure good emission capture from tanks such as 

replacing seals, more frequent maintenance, changing the size of piping going to the storage tank, and timing well 

dumps to avoid overloading the separator. There may also be other options for new facilities that allow for the 

capture and sale of additional gas such as the installation of high-low pressure separators or utilizing a liquids 

gathering system that eliminates atmospheric storage tanks at well sites. 

35 For this Regulatory Analysis, the Division increased the capital and maintenance costs for buffer bottles based on 

input from industry stakeholders. 

36 In practice, many operators are already conducting IR camera inspections at storage tanks, however, the Division 

does not have information regarding how many inspections are currently occurring. 

37 The hourly inspection cost is discussed below in Table 20. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 37 

 

Table 14: Instrument Based Tank Inspections Based on Proposed Tiering 

Tank Uncontrolled 

Actual VOC 

Emissions 

Inspection 

Type/Hourly Rate Number 

of Tanks 

Inspection 

Frequency 

Number of 

Inspections 

STEM 

Inspection 

Costs 

>6 tpy to ≤ 12 tpy In-House/$103 1,085 Annually 1,085 $223,510 

>12 tpy to ≤ 50 tpy In-House/$103 2,595 Quarterly 10,380 $2,138,280 

> 50 tpy In-House/$103 745 Monthly 8,940 $1,841,640 

Subtotal: 4,425 20,405 $4,203,430 

 

>6 tpy to ≤ 12 tpy Contractor/$134 323 Annually 323 $86,564 

>12 tpy to ≤ 50 tpy Contractor/$134 329 Quarterly 1,316 $352,688 

> 50 tpy Contractor/$134 233 Monthly 2,796 $749,328 

Subtotal: 885 4,435 $1,188,580 

 

 Total: 5,310 24,840 $5,392,010 

The Division also considered whether additional costs should be included for conducting 

periodic AVO inspections. Because these activities are already required for controlled storage 

tanks under existing regulation, the Division did not include these costs in determining the total 

cost of the proposed capture requirements. The Division also did not include costs associated 

with certifying that selected technologies and/or operational practices are designed to minimize 

emissions, since costs for certifying capture efficiency are already included in the annualized 

cost of required flares.38 Accordingly, the total projected annual cost of the proposed capture 

requirements based on the use of a buffer bottle and enhanced monitoring requirements is 

$5,301.2 per tank. 

To calculate the projected emissions reduction from the proposed capture requirements, the 

Division assumed a current capture rate of 75% for controlled tanks based on analytical work 

that the Division, EPA and others have performed. Based on this capture rate, the Division 

calculated the emissions reduction that would occur if the capture rate were increased to 100% 

using the following equation: 

Emission reduction = [uncontrolled VOC*(1-(0.75*0.95))] – [uncontrolled VOC *(1-0.95)], 

Using this equation as applied to the reported uncontrolled actual emissions from the 5,310 

storage tanks statewide with emissions greater than or equal to six tons per day, the projected 

emission reduction from the proposed capture requirements is 53,386 tons per year. Included in 

the total are 33 existing crude oil tanks with flare controls (>6 tpy) and 8 crude oil tanks that 

would need flare controls (>6 tpy). 

 

 

38 See “Oil & Gas Emissions Reduction Strategies Cost Analysis and Control Efficiency Determination,” Lesair 

Environmental, Inc., June 2008, at pg. 8. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 38 

 

Table 15: STEM Emission Control Analysis (Statewide) 

Number of 

Tanks ≥6 tpy 

Uncontrolled 

VOC 

[tons/year] 

Controlled VOC (@ 

71.25% Control) 

[tons/year] 

Controlled VOC (@ 

95% Control) 

[tons/year] 

VOC 

Reduction 

[tons/year] 

5,269 221,569 63,701 11,078 52,623

41 3,213 924 161 763

5,310 224,782 64,625 11,239 53,386

Applying this reduction to the costs calculated above, the cost effectiveness of these proposed 

requirements is $527/ton of VOC. 

Table 16: STEM Control Cost Estimates (Statewide)

Type of 

Technology 

Number 

of Tanks 

Each Device 

Annualized 

Costs [$/year] 

Total 

Annualized 

Costs 

VOC 

Reduction 

[tons/year] 

Control 

Costs 

[$/ton] 

Buffer Bottle 5,310 $5,301.2 $28,149,372 53,386 $527.3 

Using the average ratio of VOC to methane/ethane emissions from storage tanks, the projected 

methane/ethane reduction from this strategy is 20,287 tons per year, which equates to $1,388 per 

ton of methane/ethane reduced. 

During the Division’s stakeholder process leading up to the Commission’s rulemaking hearing, 

certain parties have raised questions about the Division’s assumption that currently controlled 

tanks have a 75% capture efficiency. In light of this the Division has also calculated cost 

effectiveness based on the assumption that current capture efficiency is 50% and 95%. For the 

50% case, current controlled emissions would be 118,011 tpy VOC. Accordingly, the emission 

reduction benefit from increasing capture to 100% would be 106,772 tons per year (118,011-

11,239) and the cost effectiveness would be $264/ton VOC39. For the 95% capture scenario, 

current controlled emissions would be 21,916 tons per year VOC and the emission reduction 

would be 10,677 tons per year (21,916-11,239). Under this scenario, the cost effectiveness 

would be $2,636/ton VOC40. 

While the buffer bottle technology offers a good alternative in a retrofit situation for reducing 

pressures to the tank and increasing emission capture, for new facilities, installation of a highlow pressure (HLP) separator to satisfy STEM may prove to be a better performing option. This 

equipment allows for two stages of separation of the gas and the liquids instead of the single 

stage separation accomplished in traditional separators. By adding a second stage of separation, 

the pressure of the liquids sent to the tank is significantly reduced, thereby helping to ensure 

 

39 This may overestimate the cost effectiveness given that if the current capture rate were only 50% additional costs 

could be required to increase the capture rate to 100%. 

40 This is a conservative calculation given that if the current capture rate were 95% it is likely that the control costs 

to increase the capture rate to 100% would be significantly less. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 39 

 

complete capture of flashing emissions instead of venting a portion of the emission stream 

through the thief hatch or PRV. Additionally, rather than being routed to the flare, as in the case 

of the buffer bottle technology, gas from the second stage of separation can be sent to a vapor 

recovery unit (VRU), recompressed and sent to the sales line, resulting in increased product 

recovery. Based on information provided from industry, the Division has calculated that the 

annual cost of a HLP separator w/VRU is about $19,341. 

Table 17: Annualized Cost Analysis for HLP Separator 

Item Capital Costs 

(one time) 

Non-Recurring 

Costs (one time) 

O&M Costs 

(recurring) 

Annualized 

Total Costs 

HLP/VRU $90,000 

Freight/Engr $1,648 

HLP/VRU Installation $11,154 

Maintenance $9,396 

VRU Recovered NG * $(3,382) 

Subtotal Costs $90,000 $12,802 $6,014 

Annualized Costs** $12,474 $853 $6,014 $19,341

* Recovered NG fuel costs $3.5/MCF (Henry Hub Spot Price - Aug. 2013) and average tank battery size of 63.2 tpy 

– based on 3-yr average of APEN data on storage tanks ≥6 tpy (uncontrolled VOC). 

** Annualized over 15 years at 5% ROR 

Unlike the retrofit situation analyzed above where the emission controls are already in place, it is 

appropriate in new installations to aggregate the cost of the HLP separator w/VRU with the costs 

of the control unit (flare) to determine the overall cost of controlling emissions from the tank. 

Based on the $6,286.8 annual cost of a flare and annual instrument based monitoring costs of 

$1,015.4 per tank, the total annual control costs for a new tank will be $26,643 per year. 

Based on an analysis of reported data for new tanks during the past three years, the average 

uncontrolled actual emissions of a new tank is 63.2 tpy. Assuming a 95% overall control 

efficiency, equipping a tank with an HLP separator and a flare will reduce the emissions from an 

average new tank by 60 tpy. This yields a cost effectiveness of $444 per ton VOC reduced. If 

instead, the highest cost scenario (using a six tpy tank) is assumed, the cost effectiveness is 

$4,674 per ton VOC. For methane ethane the cost per ton is $1,168 per ton reduced on average. 

3.3.8.1.6 LDAR	Requirements	for	Compressor	Stations	and	Well	Production	Facilities	

Commission Regulation Number 7 requires owners and operators of gas processing plants in 

Colorado to implement LDAR programs to identify and repair fugitive emission leaks from 

components at these facilities. Under this requirement, owners and operators must conduct 

periodic inspections using EPA Reference Method 2141 and repair leaks within a prescribed time 

frame. 

 

 

41 While EPA Reference Method 21 sets performance standards for inspection equipment rather than specifying 

technology, typically Method 21 inspections utilize photo ionization detectors (PIDs) to assess leak levels. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 40 

 

Although component leaks at compressor stations and well production facilities in Colorado are 

also a significant source of VOC and methane emissions, Regulation No. 7 does not currently 

include LDAR requirements for these facilities.42 To address these emissions, the Division is 

proposing regulatory changes that would establish LDAR requirements for compressor stations 

and well production facilities. Pursuant to this proposal, owners and operators of compressor 

stations and well production facilities will be required to conduct periodic leak inspections, and 

repair identified leaks. As specified, required inspections may be done either in accordance with 

EPA Reference Method 21 or utilizing an IR camera. The proposed language also allows the 

Division to approve other inspection methods as new leak detection technologies are 

demonstrated to be effective. 

The proposed regulation establishes a tiered system to determine inspection frequency. For 

compressor stations the tiering is based on the uncontrolled actual leak emissions at the facility 

as follows: 

Table 18: Proposed Tiering for Leak Inspections at Compressor Stations 

Component Leak Uncontrolled Actual VOC 

Emissions Inspection Frequency 

≤ 12 tpy Annually 

>12 tpy to ≤ 50 tpy Quarterly 

> 50 tpy Monthly 

For well production facilities the proposed tiering is based on uncontrolled actual emissions from 

the largest emitting storage tank at the facility as set forth in Table 19. The tiering is based on 

tank emissions rather than uncontrolled actual leak emissions in order to create an EPA 

Reference Method 21/IR camera monitoring schedule that is consistent with the monitoring 

schedule proposed as part of STEM emission capture requirements.43

 

 

42 Although leak detection is not currently required at most of these facilities, some operators currently conduct 

voluntary leak detection and repair programs. Additionally, the Division has issued a limited number of permits that 

include some leak detection requirements. For the purposes of this analysis, however, the Division assumes that 

there is no leak detection occurring at well production facilities and compressor stations. Accordingly the actual 

additional costs that operators may incur may be less than the costs calculated in this analysis. 

43 Because there may be a limited number of instances where well production facilities don’t have storage tanks, the 

proposal also provides that for tank-less facilities, the inspection schedule will be based on the facility’s total VOC 

emissions. This provision is intended to apply to large facilities that utilize a liquids gathering system for 

transporting petroleum liquids to a centralized facility. These facilities are not included in the facility count used in 

this Regulatory Analysis, but because the number of these facilities in Colorado is extremely small this exclusion 

should have a negligible impact on the overall costs and emission reduction benefits of the proposed LDAR 

requirement. Additionally, because the costs and benefits from the proposed LDAR program increase at roughly the 

same rate, the cost effectiveness of the program for these facilities should mirror the cost effectiveness of the 

program as applied to facilities with tanks. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 41 

 

Table 19: Proposed Tiering for Leak Inspections at Well Production Facilities

Tank Uncontrolled Actual VOC Emissions Inspection Frequency 

< 6 tpy One Time (and Monthly AVO) 

≥ 6 tpy to ≤ 12 tpy Annually 

>12 tpy to ≤ 50 tpy Quarterly 

> 50 tpy Monthly 

The Division utilized a multi-step process to calculate the estimated costs and benefits associated 

with the proposed LDAR requirements. First, the Division calculated an hourly inspection rate 

based on the total annual cost for each inspector divided by an assumed 1,880 annual work 

hours.44 To calculate the total annual cost for each inspector, the Division included salary and 

fringe benefits for each inspector, annualized equipment and vehicle costs, and add-ons to 

account for supervision, overhead, travel, record keeping, and reporting. Based on the 

assumptions set forth in Table 20 below, the total annual cost for each inspector will be 

$193,629, which equates to an hourly inspection rate of $103. 

Table 20: LDAR Inspector – Annualized Cost Analysis 

Item Capital Costs 

(one time) 

Annual Costs Annualized Total 

Costs 

FLIR Camera $122,000

FLIR Camera 

Maintenance/Repair 

$7,500

Photo Ionization Detector $5,000

Vehicle (4x4 Truck) $22,000

Inspection Staff $75,000

Supervision (@ 20%) $15,000

Overhead (@10%) $7,500

Travel (@15%) $11,250

Recordkeeping (@10%) $7,500

Reporting (@10%) $7,500

Fringe (@30%) $22,500

Subtotal Costs $149,000 $153,750

Annualized Costs* $39,879 $153,750 $193,629

*over 5 years at 6% ROR Annualized Hourly Rate $103

Initially, the Division assumed that conducting inspections in-house would be the lowest cost 

option since it would not involve additional profit to be paid to a contractor. For smaller 

companies that cannot fully utilize an IR camera, however, conducting inspections in-house may 

not be the most cost effective option. To account for this in this Regulatory Analysis, the 

Division assumed a 30% profit margin for contractors, which it added to the calculated hourly 

rate in instances where it appeared that contractors would be used to conduct the inspection 

($134 per hour). 

 

44 This assumes a 40 hour work week with ten holidays, two weeks of vacation, and one week of sick leave. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 42 

 

Second, the Division calculated the average amount of time that it would take to conduct an EPA 

Reference Method 21 inspection at compressor stations and well production facilities based on 

the number of components to be inspected and assuming that a component could be inspected 

every 30 seconds. The proposed rule also allows owners and operators to use IR cameras either 

as the sole inspection tool, or as a screening tool to identify potential leaking components 

followed by a Method 21 inspection. An IR camera inspection or IR Camera/Method 21 hybrid 

inspection can be conducted more quickly than a Method 21 inspection of each component. 

While the Division does not currently have actual data regarding how much faster an inspection 

could be completed using an IR camera, for the purpose of this analysis the Division assumed 

that an IR camera based inspection would take 50% of the time required for a Method 21 

inspection.45

 

For compressor stations, the Division used reported component counts for compressor stations 

within each of the tiers identified in Table 18 above. Based on these counts, and the inspection 

times per component discussed above, the Division calculated that the total inspection time per 

compressor station facility tier are as follows: 

Table 21: Calculated Inspection Time Compressor Station Leak Inspections 

Component Leak Uncontrolled 

Actual VOC Emissions Method 21 Inspection IR Camera/ Hybrid Inspection 

≤ 12 tpy 21.2 hours 10.6 hours 

>12 tpy to ≤ 50 tpy 56.2 hours 28.1 hours 

> 50 tpy* 

* there are currently no compressor stations in Colorado with calculated leaks at this level

For well production facilities, the Division has limited data on the number of components per 

facility. Based on this limitation, the Division did not attempt to calculate a separate inspection 

time for each of the proposed facility tiers, and instead used the overall average component 

count. Based on the limited available data, however, there does appear to be a distinction 

between component numbers at well production facilities in the NAA and well production 

facilities outside the NAA. Accordingly, the Division calculated separate inspection times for 

well production facilities by area as set forth in Table 22. 

Table 22: Calculated Inspection Times for Well Production Facility Leak Inspections 

Area Method 21 Inspection IR Camera/ Hybrid 

Inspection 

NAA 12.2 hours 6.1 hours 

Rest of the State 6.8 hours 3.4 hours 

 

45 Based on the Division’s own IR camera inspections, and reports from various parties during the stakeholder and 

prehearing process it appears that the Division’s assumption may significantly overstate the actual time needed to 

conduct an IR camera inspection. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 43 

 

 

In addition to the travel costs that are built into the hourly inspection rate as set forth in Table 20, 

for the purposes of this Regulatory Analysis the Division also assumed an additional three hours 

in travel time for each inspection outside the NAA. This assumption reflects the fact that certain 

well sites in basins outside the NAA may be remote, requiring additional travel. 

Next, the Division calculated the projected inspection costs for both compressor stations and well 

production facilities. To make this calculation the Division used industry reported emission data 

to determine the number of facilities that will be subject to annual, quarterly and monthly 

inspections to determine the total number of inspections for each tier, and multiplied these 

inspections by the calculated inspection time and projected hourly inspection rate. For 

compressor stations the Division assumed that all inspections would be conducted by 3rd party 

contractors. For well production facilities, the Division assumed that any company with 500 or 

more inspections per year would conduct inspections in-house, and that companies with less than 

500 inspections per year would use contractors.46 Because the proposed rule also requires 

owners and operators of well production facilities that are not subject to monthly instrument 

monitoring to conduct monthly AVO inspections the Division considered whether additional 

costs should be included for these inspections. Based on information provided during the 

Division’s stakeholder process leading up to the Commission’s rulemaking hearing it appears 

that operators already routinely conduct such inspections and repair leaks identified during these 

AVO inspections. Additionally, while the proposed rule may impose recordkeeping and 

reporting requirements associated with these AVO inspections, given the relatively small number 

of leaks that are expected to be identified, and the fact that any recordkeeping can be readily 

included in existing inspection and maintenance records the Division believes that any additional 

recordkeeping and reporting costs will be nominal relative to the overall cost of the LDAR 

program. 

In its Initial EIA, the Division did not include the cost to repair leaking components or remonitor these components post-repair to verify that the repair was effective, assuming that the 

cost to repair and re-monitor would be offset by the cost savings from capturing additional 

product as a result of repairs. Based on information that the Conservation Groups submitted as 

part of their Pre-Hearing Statement to the Commission, it appears that the Division’s assumption 

in the Initial EIA was reasonable. See Exhibit A to CG-PHS, Testimony of David McCabe at pg. 

8. Nevertheless, for this Regulatory Analysis, the Division has included both repair costs and 

estimated product savings from conducting leak detection activities. To calculate repair costs, 

the Division used EPA information regarding leaking component rates, component repair times, 

and hourly repair rates. Specifically, the Division assumed a $66.24 hourly rate to repair 

components, and an average repair time of between 0.17 hours and 16 hours, depending on the 

both type of component and the complexity of the repair.47 To calculate the number of leaking 

components the Division used industry reported component counts and assumed a 1.18% leaking 

 

46 Based on this assumption, 3,545 inspections per year will be conducted using 3rd party contractors. 47 See “Equipment Leak Emission Reduction and Cost Analysis for Well Pads, Gathering and Boosting Stations, and 

Transmission and Storage Facilities Using Emission and Cost Data From the Uniform Standards,” Bradley Nelson 

and Heather Brown, April 17, 2012; “Analysis of Emissions Reduction Techniques for Equipment Leaks,” Cindy 

Hancy, December 21, 2011. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 44 

 

component rate for facilities subject to annual inspections.48 To account for the projected 

additional emission reductions from quarterly and monthly inspection schedules the Division 

used annual leaking component rates of 1.77% for facilities with quarterly inspection schedules 

and 2.36% for facilities with monthly inspection schedules. To calculate the value of the 

additional product captured, the Division converted the amount of VOC and methane/ethane 

reduced to MCF of natural gas, with a price of $3.50/MCF. With respect to re-monitoring, the 

Division determined that because of the small number of components that will require repair and 

the fact that re-monitoring can be undertaken at the same time as repair, any additional costs 

associated with re-monitoring are negligible. 

 

Based on this methodology, the calculated annual inspection costs for compressor stations are set 

forth in Table 23. 

Table 23: Compressor Station Leak Inspection Costs Using IR Camera/Method 21 Hybrid 

Compressor 

Station Fugitive 

VOC Tier [tpy] 

Number of 

Compressor 

Stations 

Annual 

Inspection 

Frequency

Time per 

IR Camera 

Inspection 

[hours] 

Total Annual 

Inspection 

Time 

[hours] 

Total Annual 

Inspection Cost 

≤ 12 tpy 147 1 10.6 1,558.2 $208,799 

>12 to ≤ 50 tpy 53 4 28.1 5,957.2 $798,265 

≥ 50 tpy 0 12 

Total: 200 7,515.4 $1,007,064 

Repair costs associated with these inspections are set forth in Table 24 and fuel savings 

associated with these repairs are set forth in Table 25. 

Table 24: Compressor Station Leak Repair Costs 

Compressor 

Station Fugitive 

VOC Tier [tpy] 

Number of 

Compressor 

Stations 

Leak Repair 

Rate [$/hr] 

Number of 

Leaks per 

Compressor 

Station 

Total Leak 

Repair Time 

per CS 

[hours] 

Total Annual 

Repair Cost 

≤ 12 tpy 147 $66.24 30.1 23.0 $223,957.4 

>12 to ≤ 50 tpy 53 $66.24 119.4 85.2 $299,113.3 

≥ 50 tpy 0 $66.24 - - - 

Total: 200 $523,071 

 

 

48 This leaking component rate is consistent with the rate that the Louis Berger Group used in their Initial Economic 

Impact Analysis for Industry’s Proposed Revisions to Colorado’s Air Quality Control Commission Regulation No. 7 

(DGS-PHS Ex. C), and is based on the leak rate utilized by Nelson and Brown in their analysis of leak reduction 

costs and benefits (See footnote 41). 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 45 

 

Table 25: Compressor Station Recovered Natural Gas Value from Leak Repairs 

Compressor 

Station Fugitive 

VOC Tier [tpy] 

Number of 

Compressor 

Stations 

Total 

Recovered 

Natural Gas 

per CS 

[tons/year] 

Value of 

Natural 

Gas 

[$/MCF] 

Conversion 

Factor 

[MCF/ton] 

Total Annual 

Value of 

Recovered 

Natural Gas 

≤ 12 tpy 147 10.2 $3.5 35.8 $187,875 

>12 to ≤ 50 tpy 53 36.4 $3.5 35.8 $241,729 

≥ 50 tpy 0 $3.5 35.8 - 

Total: 200 $429,604 

The total net costs for compressor station LDAR are set forth in Table 26. 

Table 26: Compressor Station Net Leak Inspection and Repair Costs 

Compressor 

Station Fugitive 

VOC Tier [tpy] 

Number of 

Compressor 

Stations 

Total Annual 

Inspection 

Cost 

Total 

Annual 

Repair Cost 

Total 

Annual 

Value of 

Recovered 

Natural 

Gas 

Net Annual 

Leak 

Inspection and 

Repair Costs 

≤ 12 tpy 147 $208,799 $223,957.4 $187,875 $244,882

>12 to ≤ 50 tpy 53 $798,265 $299,113.3 $241,729 $855,650

≥ 50 tpy 0 - - -

Total: 200 $1,007,064 $523,071 $429,604 $1,100,531

For well production facilities the estimated annual inspection costs are set forth in Table 27. 

 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 46 

 

Table 27: Well Production Facility Leak Inspection Costs Using IR Camera/Method 21 

Hybrid 

Uncontrolled 

VOC at 

Storage Tank 

Battery Tier 

[tpy] 

O&G 

Basin* 

Number 

of 

Facilities 

Annual 

Inspection 

Frequency 

Total 

Number of 

Inspections 

Inspection 

Time Per 

Inspection 

[hours] 

Total Annual 

Inspection 

Cost 

In-House Inspections at $103/hour 

> 6 to ≤12 DJ/NAA 945 1 945 6.1 $593,744

> 12 to ≤ 50 DJ/NAA 2,447 4 9,788 6.1 $6,149,800

> 50 DJ/NAA 693 12 8,316 6.1 $5,224,943

Subtotal: 4,085 19,049 $11,968,487

 

In-House Inspections at $103/hour 

> 6 to ≤12 ROS 173 1 173 6.4** $114,042

> 12 to ≤ 50 ROS 176 4 704 6.4 $464,077

> 50 ROS 115 12 1,380 6.4 $909,696

Subtotal: 464 2,257 $1,487,815

 

Contract Inspections at $134/hour 

> 6 to ≤12 DJ/NAA 150 1 150 6.1 $122,610

> 12 to ≤ 50 DJ/NAA 153 4 612 6.1 $500,249

> 50 DJ/NAA 118 12 1,416 6.1 $1,157,438

Subtotal: 421 2,178 $1,780,297

 

Contractor Inspections at $134/hour 

> 6 to ≤12 ROS 140 1 140 6.4** $120,064

> 12 to ≤ 50 ROS 148 4 592 6.4 $507,699

> 50 ROS 52 12 624 6.4 $535,142

Subtotal: 340 1,356 $1,162,905

 

Total: 5,310 24,840 $16,399,504

* ROS = Remainder of State 

** ROS inspection time includes additional 3 hours for travel time 

Repair costs associated with these inspections are set forth in Table 28 and fuel savings 

associated with these repairs are set forth in Table 29. 

 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 47 

 

Table 28: Well Production Facility Leak Repair Costs 

Uncontrolled 

VOC at 

Storage Tank 

Battery Tier 

[tpy] 

O&G 

Basin 

Number of 

Facilities 

Number of 

Leaks per 

Tank 

Total Leak 

Repair Time 

per Tank 

[hours] 

Total Annual 

Repair Cost 

> 6 to ≤12 DJ/NAA 1,095 17.0 11.8 $855,887 

> 12 to ≤ 50 DJ/NAA 2,600 25.5 17.7 $3,048,365 

> 50 DJ/NAA 811 34.1 23.6 $1,267,807 

Subtotal: 4,506 $5,172,059 

 

> 6 to ≤12 ROS 313 9.7 7.7 $159,645 

> 12 to ≤ 50 ROS 324 14.5 11.6 $248,956 

> 50 ROS 167 19.4 15.4 $170,356 

Subtotal: 804 $578,957 

 

Total: 5,310 $5,751,016 

Table 29: Well Production Facility Recovered Natural Gas Value from Leak Repairs 

Uncontrolled 

VOC at 

Storage 

Tank Battery 

Tier [tpy] 

O&G 

Basin 

Number 

of 

Facilities 

Total 

Recovered 

Natural 

Gas per 

tank 

[tons/year]

Value of 

Natural 

Gas 

[$/MCF]

Conversion 

Factor 

[MCF/ton] 

Total Annual 

Value of 

Recovered 

Natural Gas 

> 6 to ≤12 DJ/NAA 1,095 4.6 $3.5 35.8 $631,136 

> 12 to ≤ 50 DJ/NAA 2,600 7.0 $3.5 35.8 $2,280,460 

> 50 DJ/NAA 811 9.3 $3.5 35.8 $945,050 

Subtotal: 4,506 $3,856,646 

 

> 6 to ≤12 ROS 313 4.6 $3.5 35.8 $180,407 

> 12 to ≤ 50 ROS 324 6.8 $3.5 35.8 $276,061 

> 50 ROS 167 9.1 $3.5 35.8 $190,418 

Subtotal: 804 $646,886 

 

Total: 5,310 $4,503,532 

The total net costs for well production facility station LDAR are set forth in Table 30. 

 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 48 

 

Table 30: Well Production Facility –Net Leak Inspection and Repair Costs 

Uncont. 

VOC at 

Storage 

Tank 

Battery Tier 

[tpy] 

O&G 

Basin 

Total Annual Inspection 

Cost Total 

Annual 

Repair 

Cost 

Total 

Annual 

Value of 

Recovered 

Natural Gas 

Net Annual 

Leak 

Inspection 

and Repair 

Costs 

In-House Contractor 

> 6 to ≤12 DJ/NAA $593,744 $122,610 $855,887 $631,136 $941,105

> 12 to ≤ 50 DJ/NAA $6,149,800 $500,249 $3,048,365 $2,280,460 $7,417,954

> 50 DJ/NAA $5,224,943 $1,157,438 $1,267,807 $945,050 $6,705,138

Subtotal: $11,968,487 $1,780,297 $5,172,059 $3,856,646 $15,064,197

 

> 6 to ≤12 ROS $114,042 $120,064 $159,645 $180,407 $213,344

> 12 to ≤ 50 ROS $464,077 $507,699 $248,956 $276,061 $944,671

> 50 ROS $909,696 $535,142 $170,356 $190,418 $1,424,776

Subtotal: $1,487,815 $1,162,905 $578,957 $646,886 $2,582,791

 

Total: $13,456,302 $2,943,202 $5,751,016 $4,503,532 $17,646,988

Additionally, based on information in the Division’s APEN reporting system, there are 2,799 

well production facilities with uncontrolled actual storage tank emissions less than or equal to 6 

tons per year that will be subject to a one-time instrument based inspection. The one-time cost 

for inspecting these facilities is estimated to be $1,639,239.49

Table 31: Well Production Facility Leak Inspection Costs Using IR Camera/Method 21 Hybrid 

Uncontrolled 

VOC at 

Storage 

Tank Battery 

Tier [tpy] 

O&G 

Basin 

Number of 

Facilities and 

Inspections 

Inspection 

Time Per 

Inspection 

[hours] 

Inspection 

Type/Hourly Rate 

Total Annual 

Inspection Cost 

≤ 6 DJ/NAA 1,598 6.1 In-House/$103 $1,004,023

≤ 6 ROS 500 3.4 In-House/$103 $175,100

 Subtotal: 2,098 $1,179,123

 

≤ 6 DJ/NAA 389 6.1 Contractor/$134 $317,969

≤ 6 ROS 312 3.4 Contractor/$134 $142,147

 Subtotal: 701 $460,116

 

Total: 2,799 $1,639,239

 

49 To calculate these costs the Division used the same methodology applicable to periodic inspection costs, except 

that it did not include additional travel time for facilities outside the NAA based on the assumption that companies 

could coordinate these one-time inspections with visits to the facilities for other purposes. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 49 

 

The Division recognizes that there are likely additional facilities not included in the APEN 

database that will be subject to this one-time inspection requirement, thereby increasing the 

overall cost of the one-time inspection requirement. Roughly speaking the additional cost for 

one-time inspections will be proportional to the number of additional facilities, so that if there 

are twice the number of facilities, the overall cost will be approximately double. However, 

because the expected emission reduction benefit will increase roughly at the same rate as the cost 

of inspections the overall cost-effectiveness of the one-time inspection requirement should 

remain approximately the same regardless of the number of facilities. 

Finally, the Division calculated the cost effectiveness of the proposed LDAR requirements based 

on the costs identified above and the projected emission reductions. To determine emission 

reductions the Division first calculated pre-inspection program VOC and methane emissions 

based on the reported component counts, standard emission factors for these components, and 

the average fraction of VOC and non-VOC emissions (methane/ethane). Based on EPA reported 

information, the Division calculated a 40% reduction for annual inspections, a 60% reduction for 

quarterly inspections, and an 80% reduction for monthly inspections. 

Using this information the Division calculated that the total emission reductions from leaks at 

compressor stations will be 1,107 tpy VOC and 2,321 tons per year methane/ethane. 

Table 32: Compressor Station Leak Inspection Emission Reductions 

Comp. 

Station 

Fugitive 

VOC Tier 

[tpy] 

Number 

of Comp 

Stations 

LDAR 

Program 

Reduction 

% 

Fugitive 

VOC 

Emissions 

for each CS 

tier [tpy] 

Total 

VOC 

Reduction 

[tpy] 

Fugitive 

Methane-Ethane 

Emissions for 

each CS tier 

[tpy] 

Total 

MethaneEthane 

Reduction 

[tpy] 

≤ 12 147 40% 10.1 588.0 15.5 911.4 

> 12 to ≤ 50 53 60% 16.4 519.4 44.3 1,409.8 

> 50 80% 

 200 1,107.4 2,321.1 

Based on these reductions, the cost effectiveness of conducting leak inspections at compressor 

stations is estimated to be $994/ton VOC and $474/ton methane/ethane. 

 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 50 

 

Table 33: Compressor Station Leak Inspection Cost Effectiveness using IR Camera/Method 21 

Comp. 

Station 

Fugitive 

VOC Tier 

[tpy] 

Number 

of Comp 

Stations 

Total Net 

Annual 

Inspection 

& Repair 

Cost 

LDAR 

Program 

Reduction 

% 

Total 

VOC 

Reduction 

[tpy] 

VOC 

Control 

Cost 

[$/ton] 

Total 

MethaneEthane 

Reduction 

[tpy] 

Methane

-Ethane 

Control 

Cost 

[$/ton] 

≤ 12 147 $244,882 40% 588.0 $416 911.4 $269 

> 12 to ≤ 50 53 $855,650 60% 519.4 $1,647 1,409.8 $607 

> 50 80% 

 200 $1,100,531 1,107.4 $994 2,321.2 $474 

For well production facilities the total emission reductions is estimated to be 14,015 tpy VOC 

and 21,927 tpy methane/ethane. 

Table 34: Well Production Facility Leak Inspection Emission Reductions 

Uncontrolled 

VOC at 

Tank Battery 

Tier [tpy] 

Number 

of 

Facilities 

LDAR 

Program 

Reduction 

% 

Fugitive 

VOC 

Emissions 

for each 

Tank 

Battery [tpy]

Total VOC 

Reduction 

[tpy] 

Fugitive 

MethaneEthane 

Emissions for 

each Tank 

Battery [tpy] 

Total 

MethaneEthane 

Reduction 

[tpy] 

DJ/NAA 

> 6 to ≤ 12 1,095 40% 4.6 1,971.0 7.0 3,066.0 

> 12 to ≤ 50 2,600 60% 4.6 7,280.0 7.0 10,920.0 

> 50 811 80% 4.6 3,000.7 7.0 4,541.6 

Subtotal: 4,506 12,251.7 18,527.6 

 

Remainder of State 

> 6 to ≤ 12 313 40% 3.9 500.8 7.5 939.0 

> 12 to ≤ 50 324 60% 3.9 745.2 7.5 1,458.0 

> 50 167 80% 3.9 517.7 7.5 1,002.0 

Subtotal: 804 1,763.7 3,399.0 

 

Total: 5,310 14,015.4 21,926.6 

Based on these reductions, the cost effectiveness of conducting ongoing instrument based 

inspections at well production facilities is estimated to be $1,259/ton VOC and $805/ton 

methane/ethane. 

 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 51 

 

Table 35: Well Production Facility Leak Cost-Effectiveness Using IR Camera/Method 21 

Uncont. 

VOC at Tank 

Battery Tier 

[tpy] 

Number 

of Tanks 

Total Net 

Annual Leak 

Inspection & 

Repair Cost 

LDAR 

Program 

Reduction 

% 

Total 

VOC 

Reduction 

[tpy] 

VOC 

Control 

Cost 

[$/ton] 

Total 

MethaneEthane 

Reduction 

[tpy] 

Methane

-Ethane 

Control 

Cost 

[$/ton] 

DJ/NAA 

> 6 to ≤ 12 1,095 $941,105 40% 1,971.0 $477 3,066.0 $307 

> 12 to ≤ 50 2,600 $7,417,954 60% 7,280.0 $1,019 10,920.0 $679 

> 50 811 $6,705,138 80% 3,000.7 $2,235 4,541.6 $1,476 

Subtotal: 4,506 $15,064,197 12,251.7 $1,230 18,527.6 $813 

 

ROS 

> 6 to ≤ 12 313 $213,344 40% 500.8 $426 939.0 $227 

> 12 to ≤ 50 324 $944,671 60% 745.2 $1,268 1,458.0 $648 

> 50 167 $1,424,776 80% 517.7 $2,752 1,002.0 $1,422 

Subtotal: 804 $2,582,791 1,763.7 $1,464 3,399.0 $760 

 

Total: 5,310 $17,646,988 14,015.4 $1,259 21,926.6 $805 

Additionally, for the 2,799 well production facilities with uncontrolled actual storage tank 

emissions equal to or less than 6 tons per year that will be subject to a one-time instrument based 

inspection, the calculated one-time benefit is 4,876 tons VOC and 8,000 tons methane/ethane, 

assuming a 40% reduction. Based on these reductions, for the one-time inspections of well 

production facilities with tanks that are less than six tons per year the cost effectiveness of the 

proposed rule is calculated to be $409/ton VOC and $249/ton methane/ethane. 

In addition to the component LDAR requirements for compressor stations and well production 

facilities, the Division’s proposal includes additional requirements designed to reduce leaks from 

open ended lines and valves, reciprocating compressors, and wet seal centrifugal compressors. 

These requirements mirror existing cost-effective requirements set forth in NSPS OOOO and 

other federal rules. 

For open ended valves and lines at well production facilities and compressor stations, the 

proposal requires that each such valve or line be equipped with a cap, blind flange, plug or 

second valve commencing January 1, 2015. Alternatively, the Division’s proposal allows 

operators to treat open-ended lines and valves as components and monitor them in accordance 

with the proposed LDAR requirements. As part of its LDAR cost effectiveness analysis detailed 

above, the Division included the costs of inspecting and repairing open ended lines and valves in 

its overall calculation. While the Division has not identified specific information regarding the 

costs and emission reduction benefits from equipping open ended lines with a cap, blind flange, 

plug or second valve it notes that the requirement has been included in a multitude of federal air 

quality rules, including NSPS VV, NSPS VVa, MACT H, MACT CC, MACT TT, MACT YY, 

MACT GGG, MACT III, and MACT MMM, dating back as far as 1983. Based on this 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 52 

 

widespread prevalence in federal rules the Division believes that the proposal represents a simple 

and cost-effective strategy to reduce emissions from open-ended lines and valves. However, to 

the extent that it is not cost effective in a specific case operators can employ the monitoring 

option allowed for under the proposed rule. 

For centrifugal compressors, the Division’s proposal requires that hydrocarbon emissions from 

wet seal fluid degassing systems be reduced by 95% beginning January 1, 2015. In its updated 

technical support document for NSPS OOOO, EPA analyzed the cost-effectiveness of this 

strategy and found that accounting revenues from the capture of additional product, 

implementation of this strategy would on a per unit basis reduce VOC emissions by 19.5 tpy, 

methane emissions by 216.2 tpy, and result in a net cost savings of $46,974.50

With respect to reciprocating compressors, the Division’s proposal requires that commencing 

January 1, 2015, the rod packing for reciprocating compressors located at compressor stations be 

replaced every 26,000 hours of operation or every 36 months. As with the requirement for 

centrifugal compressors, EPA analyzed this proposed strategy as part of the adoption of NSPS 

OOOO and found that it was a cost-effective way to reduce VOC and methane emissions. 

Specifically, EPA found that per compressor the strategy reduces VOC emissions by 1.9 tons per 

year and methane emissions by 6.8 tons per year, at a net cost of $43 per ton of VOC reduced 

and $12 per ton of methane reduced.51

3.3.8.1.7 Auto	Igniter	Requirements	on	Existing	Flare	Control	Devices	Outside	the	NAA	

Unlike the NAA, flares used to control emissions at condensate tank batteries and glycol 

dehydration units outside the NAA are not required to have auto-igniters. The Division is 

proposing that all flares used to control emissions at condensate tank batteries and glycol 

dehydration units statewide should have auto igniters. Based on an analysis of the APEN 

database, the Division estimates the statewide number of existing flare control devices without 

auto-igniters on condensate tank batteries, glycol dehydration, produced water tanks, and crude 

oil tanks is 796. The reported uncontrolled actual emissions from these units are 53,101.1 tons 

per year VOC. 

The estimated annualized cost for an auto-igniter is $475 based on information that the industry 

provided to the Division in 2008, adjusted for inflation.52 

 

 

 

50 See APCD-PHS Ex. HHHH pp. 6-1—6-3 51 See initial technical support document for NSPS OOOO (submitted as DGS-PHS Ex. NN) at pp. 6-12—6-17. 52 See “Oil & Gas Emissions Reduction Strategies Cost Analysis and Control Efficiency Determination,” Lesair 

Environmental, Inc., June 2008. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 53 

 

Table 36: Auto Igniter Control Device – Retrofit Cost Analysis 

Item Capital Costs 

(one time) 

Non-Recurring 

Costs (one time) 

O&M Costs 

(recurring) 

Annualized 

Total Costs 

Auto Igniter $1,648 

Freight/Engineering $200 

Flare Installation $500 

Maintenance $200 

Subtotal Costs $1,648 $700 $200 

Annualized Costs* $228.4 $46.7 $200 $475

 * Annualized over 15 years at 5% ROR 

The Division estimates that a flare without an auto-igniter could experience about 3% pilot light 

downtime (262.8 hours) over a one year period. During the downtime period, any VOC 

emissions routed to the flare control device are uncontrolled. Based on the total uncontrolled 

actual emissions of 53,101.1tons per year VOC from units equipped with flares without autoigniters, the emissions during this downtime period will be 1,593.1 tons of VOC. The Division 

assumes that as a result of the installation of an auto-igniter, the amount of downtime can be 

eliminated, for a total emission reduction of 1,251.7 tons/year. Given that the annualized cost of 

installing 796 auto-igniters is about $378,100 the estimated cost effectiveness of this strategy is 

about $302 per ton of VOC reduced. 

Table 37: Auto Igniter Emission Reduction Estimates 

Source Type for Existing 

Flare Controls 

Number of 

Auto 

Igniters 

Uncontrolled 

VOC [tpy] 

Uncontrolled VOC 

Using 3% 

Downtime [tpy] 

Total VOC 

Reduction 

[tpy] 

Condensate Tanks 490 31,170.6 935.1 666.3 

Dehydrators 131 16,372.0 491.2 466.6 

Produced Water Tanks 172 4,842.2 145.3 103.5 

Crude Oil Tanks 3 716.3 21.5 15.3 

 796 53,101.1 1,593.1 1251.7 

* Dehydrator flares assumed to have 100% capture and 95% destruction – thus 95% control. Tank flares are 

assumed to have 75% capture and 95% destruction – thus 71.25% control.

Table 38: Auto Igniter Control Cost Estimates (Outside NAA)

Number Each Auto-Igniter 

Annualized Costs 

Total Annualized 

Costs 

VOC Reduction* 

[tons/year] 

Control Costs 

[$/ton] 

796 $475 $378,100 1,251.7 $302 

 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 54 

 

3.3.8.2 		Expanding Low Bleed Pneumatics Requirements Statewide		

As part of the 2008 Ozone Action Plan the Commission adopted regulatory requirements 

mandating the use of low bleed pneumatic controllers in the NAA. The current proposal would 

expand this requirement statewide. 

To estimate the costs and benefits of this proposed strategy, the Division estimated the number of 

high-bleed pneumatic devices based on Independent Petroleum Association of the Mountain 

States (IPAMS) survey data from 2006, which identified the average number of such devices per 

well. The Division then scaled this number up based on 2012 COGCC well count data. Based on 

this methodology, there are 9,877 high-bleed pneumatic devices outside the NAA. Assuming a 

95% replacement rate, the proposed rule will result in the replacement of 9,384 high bleed 

devices with low bleed devices. Based on this count, and the average emission reductions per 

device replaced identified in the IPAMS survey, the projected benefit from the proposed 

expansion of the current NAA low bleed pneumatic rule will be approximately 14,921 tons per 

year VOC (40.9 tons per day). Based on this information and assuming an 80/20 ratio of 

methane/ethane to VOC by volume, the estimated methane/ethane reduction from this strategy is 

17,100 tons per year. 

 

The average retrofit cost of a high-bleed pneumatic device is based on costs from the 2008 cost 

study53 adjusted for inflation. Utilizing this methodology, the annualized cost for each replaced 

device is $169. However, because the reduced bleed rate results in more natural gas being sold, 

operators will receive additional revenue as a result of the installation of a low bleed device. 

Based on the emission reduction data from the IPAMS survey and August 2013 spot prices for 

natural gas, the estimated average value of the recovered gas will be $1,268 for each device 

replaced. As a result, the net annual gain is $1,084 per replaced device. Based on this projected 

net gain, this strategy will pay for itself in approximately one year and two months. 

 

Table 39: Replace High-Bleed Pneumatics with Low-Bleed Pneumatics – Annualized Cost 

Analysis* 

Item Capital Costs 

(one time) 

Non-Recurring 

Costs (one time) 

O&M Costs 

(recurring) 

Annualized 

Total Costs 

Low/No Bleed 

Device* 

$1,033 

Labor $387 

Value of NG Saved** $(1,268) 

Maintenance $16 

Subtotal Costs $1,033 $387 $(1,253) 

Annualized Costs*** $143 $26 $(1,253) $(1,084)

* Control device costs were developed based on an Oil and Gas Cost Study and information submitted by industry 

in 2008. However, those costs were escalated by 9.85% to reflect CPI-U increases that have occurred since 2008. 

** Recovered NG fuel costs $3.5/MCF (Henry Hub Spot Price - Aug. 2013) 

*** Annualized over 15 years at 5% ROR

 

53 See “Oil & Gas Emissions Reduction Strategies Cost Analysis and Control Efficiency Determination,” Lesair 

Environmental, Inc., June 2008. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 55 

 

Assuming 9,384 total devices replaced, adoption of this strategy will result in $10,169,441 in 

annual cost savings. 

Table 40: Low Bleed Pneumatic Control Cost Estimates (Outside NAA)

Number Each Device 

Annualized Costs 

Total Annualized 

Costs 

VOC Reduction 

[tons/year] 

Control Costs 

[$/ton] 

9,384 $(1,084) $(10,169,441) 14,921 NA 

The proposed rule also requires the use of no-bleed pneumatic devices if it is technically and 

economically feasible and where on-site electrical grid power is being used. Use of no-bleed 

pneumatic devices will further reduce emissions relative to the use of low bleed devices. Since 

the Division does not have information indicating the number of no-bleed pneumatic devices that 

could be required, it is not possible to calculate the cost effectiveness of this particular provision. 

However, because the proposed requirement expressly provides that use of no-bleed pneumatics 

is only required where economically feasible the Division assumes that any use of no-bleed 

pneumatic devices pursuant to the proposed rule will be cost effective. 

  

3.3.8.3 		Require Newly Constructed Gas Wells be Connected to a Pipeline or Route

Emissions to a Control Device

Currently in Colorado, natural gas produced at oil and gas sites is typically routed to a 

transmission pipeline. With the advent of new drilling technologies, additional areas of the state 

without established pipeline infrastructure may experience oil and gas exploration and 

production. This can lead to instances where produced gas is vented or flared instead of being 

put into a transmission line. To date the Division has identified 61 instances in Colorado where 

this is occurring. To address this, the proposed regulation provides that for newly constructed, 

hydraulically fractured, or recompleted wells, the gas stream must either be connected to a 

pipeline or routed to a control device achieving 95% control efficiency. Currently all of the sites 

that are not routed to a pipeline are flaring their gas. Additionally, because venting the gas at 

such sites would create a safety issue, the Division assumes that in the limited future instances 

where the gas stream is not routed to a pipeline, operators will route the emissions to a flare or 

other control device. Accordingly, adoption of this portion of the proposed regulation will likely 

not result in any additional costs. 

3.3.8.4 		Control Requirements for Glycol Dehydrators

The Division is proposing to revise the control requirements applicable to glycol natural gas 

dehydrators statewide. Currently any glycol natural gas dehydrator with uncontrolled actual 

VOC emissions of 2 tons per year or greater that is located at a facility where the sum of 

uncontrolled actual emissions from all of the dehydrators at the facility is greater than 15 tons per 

year, must be equipped with a control device that reduces emissions by at least 90%. Under the 

Division’s proposal, all existing dehydrators with uncontrolled actual emissions of 6 tons per 

year or greater VOC must be controlled with air pollution control equipment achieving at least 

95% reduction. The proposal also provides that existing dehydrators with uncontrolled actual 

emissions of two tons per year or greater VOC must be controlled if they are located within 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 56 

 

1,320 feet of a building unit or designated outside activity area. Finally, the proposal requires 

that all new dehydrators with uncontrolled actual emissions of two tons per year or greater VOC 

be controlled. The Division assumes that newly subject glycol dehydrators will be controlled 

using flares that achieve a 95% destruction efficiency. The annual cost for these units is 

$6,286.80 per unit. 

Based on industry reported APEN data, there are currently 433 uncontrolled dehydrators at sites 

with total dehydrator uncontrolled actual VOC emissions below 15 tpy. Of these, 217 have 

uncontrolled actual emissions greater than or equal to two tons per year. The total uncontrolled 

actual emissions for these 217 dehydrators are 1,827.5 tpy VOC. There are 148 dehydrators with 

uncontrolled actual VOC emissions greater than or equal to 6 tons per year. The total 

uncontrolled actual emissions for these 148 dehydrators are 1,549.7 tpy VOC. Currently, the 

Division does not have information regarding the location of these uncontrolled dehydrators 

relative to a building unit or designated outside activity area. Assuming, however, that all of the 

2 to 6 ton dehydrators are located within 1,320 feet of a building unit or designated outside 

activity area and thus will require a control, the proposed requirement will reduce 1,736 tpy of 

VOC at a cost effectiveness of $786/ton VOC. For the smallest dehydrator subject to the 

proposed rule (2 ton/year) the cost effectiveness is estimated to be $3309 per ton of VOC 

reduced. 

Table 41: Dehydrator Control Cost Estimates (2 TPY Control Threshold)

Number Each Device 

Annualized Costs 

Total Annualized 

Costs 

VOC Reduction 

[tons/year] 

Control Costs 

[$/ton] 

217 $6,286.8 $1,364,236 1,736 $786 

Conversely, if it is assumed that none of the 2 to 6 ton existing dehydrators will require controls 

the proposed requirement will reduce 1,472 tpy of VOC at a cost effectiveness of $632/ton VOC. 

 

Table 42: Dehydrator Control Cost Estimates (6 TPY Control Threshold)

Number Each Device 

Annualized Costs 

Total Annualized 

Costs 

VOC Reduction 

[tons/year] 

Control Costs 

[$/ton] 

148 $6,286.8 $930,446 1,472 $632 

3.3.8.5 		Control Requirements for Downhole Well Maintenance and Liquids Unloading

Events

Historically, Colorado has not regulated air emissions from temporary activities such as well 

completions and well maintenance at well production sites. Recently, however, EPA, Colorado 

and other jurisdictions have identified these activities as potentially large sources of emissions 

from the oil and gas sector. In recognition of this, the Colorado Oil and Gas Conservation 

Commission and more recently EPA have adopted requirements for green completions to reduce 

hydrocarbon emissions during well completion activities. The Division is now proposing 

additional regulatory requirements designed to reduce emissions during well maintenance. 
2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 57 

 

Well maintenance is required when, over time, liquids build up inside the well and reduce gas 

and oil flow out of the well. To remove these liquids and improve flow, the liquids are blown 

out of the well under pressure. This process is typically referred to as liquids load-out or well 

blow-down. Historically emissions from well blow-downs are vented to the atmosphere. EPA 

has established emission factors for liquid unloading based on fluid equilibrium calculations to 

calculate the amount of gas needed to blow down a column of fluids blocking a well and Natural 

Gas STAR partner data on the amount of additional venting after a blow-down. Based on its 

calculations, EPA estimated that in the United States the combined methane emissions for liquid 

unloading and well completions in 2009, was 217 billion cubic feet, and that liquid unloading 

may account for 33% of the uncontrolled methane emissions from the natural gas industry.54 For 

Colorado, the Division has calculated that emissions from well blow-downs in 2008 were 

approximately 9,306 tons of VOC per year. 

To address these emissions, the Division is proposing a two pronged requirement aimed at 

reducing the number of required liquids unloading events and reducing the amount of emissions 

vented to the atmosphere during these events. Under the Division’s proposal operators shall use 

best management practices to minimize the need for venting associated with downhole 

maintenance and liquids unloading. For example, EPA’s Gas Star program advocates the use of 

a plunger lift system to reduce the need for liquids unloading. According to EPA, use of a 

plunger lift will on average pay for itself in less than one year through the capture of additional 

product. The Division’s proposal also provides that emissions during well maintenance and 

liquids unloading shall be captured or controlled using best management practices to limit 

venting during well blow-downs to the maximum extent practicable. Based on information 

provided by Environmental Defense Fund, application of these requirements could result in 

annual VOC reductions of 2,881 tons and methane reductions of 19,207 tons per year. Given the 

wide variety of practices that this could entail, the Division currently does not have information 

about the precise cost-effectiveness of this provision. Given the fact that the proposal only 

requires use of best management practices, which takes into account the cost of the practices in a 

given situation, the Division assumes that the proposed strategy will be cost effective. 

4 CLOSING SUMMARY

On December 13, 2013, interested parties, stakeholders and state representatives filed requests 

for a Regulatory Analysis. This Regulatory Analysis is a careful and considerate response to 

those Requests and is a good faith effort on the part of the Division. 

The Division has addressed, to the best of its ability, issues related to the entirety of proposed 

revisions to Regulation 3, 6, and 7. The Division believes that the proposal before the 

Commission reflects a balanced approach that includes proven and cost effective strategies to 

reduce emissions from the oil and gas sector, while enabling the sector to continue to grow in a 

responsible and protective manner. The Division looks forward to the Commission’s 

consideration of its proposal and alternate proposals of other parties at the February 2014 

hearing. 

 

54 See EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2009, April, 2011.