Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

INITIAL

ECONOMIC IMPACT ANALYSIS

PER § 25-7-110.5(4), C.R.S.

For proposed revisions to 

Colorado Air Quality Control Commission 

Regulation Number 7 (5 CCR 1001-9)

I. INTRODUCTION 

The Colorado Air Pollution Control Division (Division) submits the following Initial Economic 

Impact Analysis in conjunction with its proposed revisions to Colorado Air Quality Control 

Commission (AQCC) Regulation Number 7 (5 CCR 1001-9). The Regulation Number 7 

rulemaking package proposes revisions that expand existing oil and gas control requirements and 

establish additional monitoring, recordkeeping and reporting requirements. Among other things, 

the Division proposes to: increase control requirements and improve capture efficiency 

requirements for oil and gas storage tanks; minimize fugitive emissions of hydrocarbons 

(including volatile organic compounds, methane and ethane) from leaking components at 

compressor stations and well production facilities; expand control requirements for pneumatic 

devices; increase control requirements for glycol dehydrators; and minimize venting at oil and 

gas production facilities. 

In this Initial Economic Impact Analysis, the Division has assessed the costs and benefits 

associated with each of the proposed strategies based on the reasonably available data. In 

collecting this data, the Division has sought input 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. To the extent that additional data regarding the costs and benefits of the 

proposed strategies is made available, the Division will assess this data and, where appropriate, 

incorporate it into the Final Economic Impact Analysis required under AQCC Procedural Rules, 

Section V.E.7. 

II. REQUIREMENTS FOR AN INITIAL ECONOMIC IMPACT ANALYSIS

Section 25-7-110.5(4), C.R.S. sets forth the requirements governing the preparation and 

submittal of economic impact analyses for air quality rules. This section provides that: 

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

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

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

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

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

the commission.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

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Section 25-7-110.5(4)(a), C.R.S. The statute further provides that: 

The proponent and the division shall select one or more of the following economic 

impact analyses. The commission may ask affected industry to submit information with 

regard to the cost of compliance with the proposed rule, and, if it is not provided, it shall 

not be considered reasonably available. The economic impact analysis required by this 

subsection (4) shall be based upon reasonably available data .... 

Section 25-7-110.5(4)(c), C.R.S.. For the purposes of this Initial Economic Impact Analysis, the 

Division has chosen to utilize the methodology set forth in § 25-7-110.5(4)(c)(I), C.R.S., which 

requires the following:

(I) Cost-effectiveness analyses for air pollution control that identify: 

(A) The cumulative cost including but not limited to the total capital, operation, 

and maintenance costs of any proposed controls for affected business entity or 

industry to comply with the provisions of the proposal; 

(B) Any direct costs to be incurred by the general public to comply with the 

provisions of the proposal; 

(C) Air pollution reductions caused by the proposal; 

(D) The cost per unit of air pollution reductions caused by the proposal;

(E) The cost for the division to implement the provisions of the proposal.

III. OVERVIEW OF PROPOSED REGULATORY CHANGES

The Division is proposing revisions to AQCC Regulation Number 7 in an effort to enhance the 

effectiveness of Colorado’s air quality requirements for the oil and gas exploration and 

production sector. These proposed revisions consist of the following:

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

a. Lowering the existing control requirement threshold for condensate 

storage tanks from twenty to six tons per year of uncontrolled actual 

volatile organic compound (VOC) emissions;

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

uncontrolled actual VOC emissions that are equal to or greater than six 

tons per year; and

c. Expanding non-attainment area 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;
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

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3) Establishing leak detection and repair requirements for compressor stations and 

well production facilities;

4) Expanding the existing non-attainment area requirements for auto-igniters on flare 

devices to the rest of the state;

5) Expanding the existing non-attainment area requirements for low bleed pneumatic 

devices to the rest of the state and where feasible requiring no-bleed pneumatic 

devices; 

6) 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;

7) Lowering the existing control requirement threshold for existing glycol 

dehydrators to six tons per year of uncontrolled actual VOC emissions and two 

tons per year of uncontrolled actual VOC emissions for dehydrators located 

within 1,320 feet of a building, and establishing a two ton per year control 

threshold for all new glycol dehydrators; and

8) Establishing requirements for the use of best management practices both to 

minimize the need for downhole well maintenance and liquids unloading and to 

minimize emissions during well maintenance and liquids unloading events.

IV. COST/BENEFIT ANALYSIS:

The Division’s assessment of the costs and benefits for the proposed strategies is set forth below. 

For each strategy, these assessments identify the cumulative costs for the affected industry, the 

estimated air pollution reduction, and the projected cost per unit of air pollution reduced. The 

Division also assessed whether any of the proposed strategies would impose a direct cost on the 

general public to comply, and determined that based on the available data there will be no direct 

costs on the general public for any of the proposed requirements. Finally, the Division 

considered whether there would be any additional costs for the Division to implement the 

proposed requirements beyond current expenditures, and concluded that there would be no 

additional implementation costs associated with these proposed strategies.

A. Control Requirements for Petroleum Storage Tanks

Commencing in 2004 the Air Quality Control 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 

non-attainment areas 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 AQCC’s Common Provisions regulation as 

“hydrocarbon liquids . . . with an API gravity of 40 degrees or greater.” While most of the 

petroleum liquid produced in Colorado qualifies as condensate, there are heavier hydrocarbon 
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

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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 six 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 twenty tons per year VOC to six 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 non-attainment area 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 1 below. Utilizing the calculated flare costs, the estimated costs and benefits for each 

of the three tank control strategies are discussed in subsections 2-4 below.

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 study1 adjusted for inflation. Based on this data, the estimated annualized cost of a flare 

control device with auto-igniter2 is about $6,287.

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

 1 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 AQCC as part of the 

2008 Ozone Action Plan process.

2 Currently only flares in the non-attainment area 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 D.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

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*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.

** Pilot fuel costs $3.41/MMBtu (Henry Hub Spot Price - Aug. 2013)

*** Annualized over 15 years at 5% ROR

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 non-attainment area and the remaining 192 are within the current nonattainment area.

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,3 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.

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.

 3 The costs and benefits associated with improving the capture percentage for controlled storage tanks are discussed 

below in Section B.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

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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 (six 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

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 AQCC 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 six 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 database, the Division estimates that statewide there are 52 uncontrolled produced water 

tank batteries with VOC emissions over six 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.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

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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 

(six 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),

4 it appears 

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.5

Table 8: Crude Oil Tank Battery Analysis

Tank Battery Type Total Statewide Crude Oil Tanks

Controlled Crude Oil Tanks 37

Uncontrolled Crude Oil Tanks 30

Total: 67

Uncontrolled Tanks (≥6 tpy) 8

 4 Based on an analysis of 2010 COGCC data.

5 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.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

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The total VOC emission reduction associated with controlling these eight 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 (six 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

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 

non-attainment area 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 issue in the non-attainment area, the AQCC 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 non-attainment area 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,6

 6 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.

total uncontrolled actual VOC emissions from these tanks during the first 90 days is 1,842.5 tons. 
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

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Assuming enhanced capture efficiency for these new tanks (See Section B) the flare control 

efficiency is 95%, thus the calculated benefit from expanding the first 90 day control 

requirement to tanks outside the non-attainment area will be 1,750.4 tons per year.

While the Division estimates that there are 141 new and modified storage tanks outside the nonattainment area 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 three 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

B. 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 infra-red (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.

 
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

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To assure compliance with these capture standards, the Division’s proposal requires that owners 

and operators of controlled storage tanks implement a Storage Tank Emission Management 

(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 weekly7 auditory, visual, and 

olfactory (AVO) inspection for all controlled tanks, and a periodic instrument based monitoring 

for tanks using 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 six tons per year would need to be controlled consistent with 

the Division’s proposal discussed in Section A above. Based on reported data, there are 

currently 5,270 storage tanks statewide with emissions greater than or equal to six tons per day. 

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 assumed that buffer bottle 

technology would be installed on each of the subject tanks.8

 7 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.

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.

8 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.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

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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 $6,000

Freight/Engr $600

Installation $2,280

Maintenance $2,000

Subtotal Costs $6,000 $2,880 $2,000

Annualized Costs* $832 $192 $2,000 $3,024

* 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 24,622 tank inspections per year9

Assuming that each inspection takes two hours and utilizing a $99/hour inspection cost,

.

10 the 

total annual cost associated with conducting enhanced inspections under the proposed rule is 

$4,875,156, which equates to $925 per year for each tank that will be subject to STEM.

Table 14: Instrument Based Tank Inspections Based on Proposed Tiering 

Tank Uncontrolled 

Actual VOC 

Emissions

Number of 

Tanks

Inspection 

Frequency

Number of 

Inspections

STEM Inspection 

Costs

≥ 6 tpy to ≤ 12 tpy 1,390 Annually 1,390 $275,220

>12 tpy to ≤ 50 tpy 2,916 Quarterly 11,664 $2,309,472

> 50 tpy 964 Monthly 11,568 $2,290,464

5,270 24,622 $4,875,156

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.11

 9 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.

 Accordingly, the total projected annual cost of the proposed capture 

10 The hourly inspection cost is discussed below in Table 20. 11 See “Oil & Gas Emissions Reduction Strategies Cost Analysis and Control Efficiency Determination,” Lesair 

Environmental, Inc., June 2008, at pg. 8.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

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requirements based on the use of a buffer bottle and enhanced monitoring requirements is $3,949 

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 5,270 

storage tanks statewide with emissions greater than or equal to six tons per day, the projected 

emission reduction from the proposed capture requirements is 52,624 tons per year.

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]

5,270 221,575 63,703 11,079 52,624

Applying this reduction to the costs calculated above, the cost effectiveness of these proposed 

requirements is $396/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 5,270 $3,949 $20,811,230 52,624 $395

During the stakeholder process 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 116,327 

tpy VOC. Accordingly, the emission reduction benefit from increasing capture to 100% would 

be 105,248 tons per year (116,327-11,079) and the cost effectiveness would be $198/ton VOC12

 12 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%.

. 

For the 95% capture scenario, current controlled emissions would be 21,604 tons per year VOC 
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

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and the emission reduction would be 10,525 tons per year (21,604-11,079). Under this scenario, 

the cost effectiveness would be $1,977/ton VOC13.

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 

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, the total annual control costs for a new tank will be 

$25,628 per year. Including instrument based monitoring costs of $925 per tank each year, the 

total annual cost for each new tank will be $26,553.

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 

 13 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.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

14

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 $443 per ton VOC reduced. If 

instead, the highest cost scenario (using a six tpy tank) is assumed, the cost effectiveness is 

$4,658 per ton VOC.

C. Leak Detection and Repair Requirements for Compressor Stations and Well 

Production Facilities

AQCC Regulation Number 7 requires owners and operators of gas processing plants in Colorado 

to implement leak detection and repair 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 2114 and repair leaks within a prescribed time 

frame.

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 leak detection and repair requirements for these facilities.15 To address these emissions, 

the Division is proposing regulatory changes that would establish leak detection and repair 

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 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

 14 While 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. 15 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.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

15

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 a Method 21/IR 

camera monitoring schedule that is consistent with the monitoring schedule proposed as part of 

the STEM emission capture requirements discussed in Section B above.16

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 leak detection and repair 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.17 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 

$186,129, which equates to an hourly inspection rate of $99.

Table 20: Leak Detection and Repair (LDAR) Inspector – Annualized Cost Analysis

Item Capital Costs

(one time)

Annual Costs Annualized Total 

Costs

FLIR Camera $122,000

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 $146,250

Annualized Costs* $39,879 $146,250 $186,129

 16 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 potential to 

emit VOC.

17 This assumes a 40 hour work week with ten holidays, two weeks of vacation, and one week of sick leave.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

16

*over 5 years at 6% ROR Annualized Hourly Rate $99

Second, the Division calculated the average amount of time that it would take to conduct a 

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.

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 this overall average component count each Method 21 inspection will take 9.5 

hours and each IR camera based inspection will take 4.75 hours. 

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. The 

calculated inspection costs for compressor stations and well production facilities do not include 

the cost to repair leaking components or re-monitor these components post-repair to verify that 

the repair was effective. Conversely, the calculated costs also do not account for the cost savings 

from capturing additional product as a result of repairs. For the purposes of this initial cost 

analysis the Division assumes that the cost savings from additional product capture will be equal 
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

17

to or greater than the cost of repair and re-inspection. However, the Division welcomes 

additional input from stakeholders on the costs and benefits associated with repairing leaking 

components.

 

Based on this methodology, the calculated costs for compressor stations are set forth in Table 22.

Table 22: 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 $154,262

>12 to ≤ 50 tpy 53 4 28.1 5,957.2 $589,763

≥ 50 tpy 0 12

Total: 200 7,515.4 $744,025

Estimated annual inspection costs for well production facilities are set forth in Table 23.

Table 23: Well Production Facility Leak Inspection Costs Using IR Camera/Method 21 

Hybrid

Uncontrolled 

VOC at 

Storage Tank 

Battery Tier 

[tpy]

Number of 

Facilities

Annual 

Inspection 

Frequency

Inspection

Time Per 

Inspection

[hours]

Total 

Inspection

Time

[hours]

Total Annual 

Inspection 

Cost

≥ 6 to ≤12 1,390 1 4.75 6,602.5 $653,648

> 12 to ≤ 50 2,916 4 4.75 55,404.0 $5,484,996

> 50 964 12 4.75 54,498.0 $5,439,852

Total: 5,270 116,954.5 $11,578,496

Additionally, there are 2,810 well production facilities with uncontrolled actual storage tank 

emissions below six 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 $1,321,403.18

 18 The Division’s proposal also requires monthly AVO inspections at these facilities. Based on information 

provided during the stakeholder process, the Division understands that AVO inspections are part of current standard 

operational practice. Accordingly, the regulatory provisions should not result in additional costs. The Division 

requests, however, additional information from interested parties during the pre-hearing process regarding this issue.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

18

Finally, the Division calculated the cost effectiveness of the proposed leak detection and repair 

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 1,115 tpy VOC and 2,320 tons per year methane/ethane.

Table 24: 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% 10.1 593.9 15.5 911.4

> 12 to ≤ 50 53 60% 16.4 521.5 44.3 1,408.7

> 50 80%

200 1,115.4 2,320.1

Based on these reductions, the cost effectiveness of conducting leak inspections at compressor 

stations is estimated to be $667/ton VOC and $321/ton methane/ethane.

Table 25: Compressor Station Leak Inspection Cost Effectiveness using IR Camera/Method 21

Comp. 

Station 

Fugitive 

VOC Tier 

[tpy]

Number

of Comp 

Stations

Total 

Annual 

Inspection 

Cost

LDAR 

Program 

Reduction 

%

Total 

VOC 

Reduction 

[tpy]

VOC 

Control 

Cost 

[$/ton]

Total 

MethaneEthane 

Reduction 

[tpy]

Methane

-Ethane 

Control 

Cost 

[$/ton]

≤ 12 147 $154,262 40% 593.9 $260 911.4 $169

> 12 to ≤ 50 53 $589,763 60% 521.5 $1,131 1,408.7 $419

> 50 80%

200 $744,025 1,115.4 $667 2,320.1 $321

For well production facilities the total emission reductions is estimated to be 14,153 tpy VOC 

and 22,461 tpy methane/ethane. 
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

19

Table 26: 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]

≥ 6 to ≤ 12 1,390 40% 4.6 2,557.6 7.3 4,058.8

> 12 to ≤ 50 2,916 60% 4.6 8,048.2 7.3 12,772.1

> 50 964 80% 4.6 3,547.5 7.3 5,629.8

Total: 5,270 14,153.3 22,460.7

Based on these reductions, the cost effectiveness of conducting ongoing instrument based 

inspections at well production facilities is estimated to be $818/ton VOC and $516/ton 

methane/ethane.

Table 27: Well Production Facility Leak Cost-Effectiveness Using IR Camera/Method 21

Uncont. 

VOC at Tank 

Battery Tier 

[tpy]

Number 

of Tanks

Total Annual 

Inspection 

Cost

LDAR 

Program 

Reduction 

%

Total 

VOC 

Reduction 

[tpy]

VOC 

Control 

Cost 

[$/ton]

Total 

MethaneEthane 

Reduction 

[tpy]

Methane

-Ethane 

Control 

Cost 

[$/ton]

≥ 6 to ≤ 12 1,390 $653,648 40% 2,557.6 $256 4,058.8 $161

> 12 to ≤ 50 2,919 $5,484,996 60% 8,048.2 $682 12,772.1 $429

> 50 964 $5,439,852 80% 3,547.5 $1533 5,629.8 $966

Total: 5,270 $11,578,496 14,153.3 $818 22,460.7 $516

Additionally, for the 2,810 well production facilities with uncontrolled actual storage tank 

emissions below six tons per year that will be subject to a one-time instrument based inspection, 

the calculated one-time benefit is 5,170 tons VOC and 8,205 tons methane/ethane, assuming a 

40% reduction and a current leak rate of 4.6 tpy VOC and 7.3 tpy methane/ethane. 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 $256/ton 

VOC and $161/ton methane/ethane.

In addition to conducting its own cost effectiveness analysis for the proposed leak detection 

requirements, the Division has considered cost information provided by industry19

 19 See “Analysis of Industry Survey LDAR Responses” Lisa McDonald, PhD and Holly Bender PhD, September 11, 

2013.

and 
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

20

environmental groups20 as part of the stakeholder process leading up to the Division’s request for 

a hearing on its proposed changes. While none of this information specifically analyzed the 

Division’s proposed leak detection program, the information provides additional perspectives on 

the likely costs and benefits of the Division’s proposal.

To assess potential costs of a Colorado leak detection program for well production facilities, 

McDonald and Bender analyzed industry survey responses on leak detection to determine total 

costs for annual, quarterly and monthly inspections at 8,702 well production facilities21 in 

Colorado. Since the inspection numbers in this analysis is different than the number of 

inspections that will be required under the Division’s proposal, the overall cost that McDonald 

and Bender calculated is less relevant to this analysis. Based on the data they present, however, 

it is possible to calculate a per inspection cost that can be used to analyze the cost effectiveness 

of the Division’s proposal. Specifically, McDonald and Bender’s analysis shows that on average 

an annual leak detection inspection costs $2,468, a quarterly inspection costs $1,067, and a 

monthly inspection costs $765. Using these inspection cost numbers applied to the expected

number of inspections required under the Division’s proposal (See Table 23 above) yields a total 

annual cost of $24,725,528. This equates to $1,747/ton of VOC reduced, and $1,101/ton of 

methane/ethane reduced based on the Division’s emission reduction calculations (See Table 26 

above).

In their analysis, McCabe et.al., looked at cost and benefit data from actual IR camera 

inspections at gas plants, compressor stations and well-sites conducted pursuant to Canada’s oil 

and gas leak detection program. The information they provided includes a range of cost 

assumptions. At the high end the cost per ton of VOC reduced at well facilities is approximately 

$300 per ton. For compressor stations the high end shows a net cost benefit from conducting IR 

camera inspections.

Environmental Defense Fund’s analysis looked at a number of different scenarios and concluded 

that the cost effectiveness of quarterly leak detection and repair ranged from between 

approximately $1,000/ton and $7,000/ton for VOCs and between approximately $400/ton and 

$2,300/ton for methane. For monthly leak detection they estimated that the cost per ton for 

VOCs ranged between approximately $2,000 per ton and $13,000/ton. For methane, monthly 

leak detection costs ranged between approximately $600/ton and $4,100/ton.

D. Auto Igniter Requirements on Existing Flare Control Devices Outside the NonAttainment Area

Unlike the non-attainment area, 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 

 20 See “An Examination of the Cost-Effectiveness of Leak Detection and Repair Programs Using Infrared Cameras” 

David McCabe, Ellen Baum, Stephanie Saunier, September 11, 2013; “Analysis of Leak Detection and Repair 

Program for O&G Emissions in Colorado” Environmental Defense Fund, September 20, 2013. 21 The analysis did not look at leak detection costs for compressor stations.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

21

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 and glycol dehydration is 652. The reported 

uncontrolled actual emissions from these units are 47,675 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.22

Table 28: 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 47,675 tons per year VOC from units equipped with flares without autoigniters, the emissions during this downtime period will be 1,430.2 tons of VOC. Of this total, 

495.1 tons of the emissions are from dehydrators and 935.1 tons are from storage tanks. 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 1,137 tons/year. Given that the annualized 

cost of installing 652 auto-igniters is about $309,700, the estimated cost effectiveness of this 

strategy is about $272 per ton of VOC reduced.

Table 29: Auto Igniter Control Cost Estimates (Outside NAA)

Number Each Auto-Igniter 

Annualized Costs

Total Annualized 

Costs

VOC Reduction*

[tons/year]

Control Costs

[$/ton]

652 $475 $309,700 1,136.6 $272

* Dehydrator flares assumed to have 95% control (1.0*0.95)-thus VOC reduction is 495.1*0.95 = 470.3 tpy; Tank 

flares assumed to have 71.25% control (0.75*0.95)-thus VOC reduction is 935.1*0.75*0.95=666.3 tpy. Total VOC 

reduction = 470.3 + 666.3 = 1,136.6 tpy.

 22 See “Oil & Gas Emissions Reduction Strategies Cost Analysis and Control Efficiency Determination,” Lesair 

Environmental, Inc., June 2008.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

22

E. Expanding Low Bleed Pneumatics Requirements Statewide 

As part of the 2008 Ozone Action Plan the AQCC adopted regulatory requirements mandating 

the use of low bleed pneumatic controllers in the non-attainment area. 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 Colorado Oil and Gas 

Conservation Commission (COGCC) well count data. Based on this methodology, there are 

9,877 high-bleed pneumatic devices outside the nonattainment area. 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 non-attainment area low bleed pneumatic rule will be approximately 14,921 tons per 

year VOC (40.9 tons per day).

The average retrofit cost of a high-bleed pneumatic device is based on costs from the 2008 cost 

study23

 

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 four months.

Table 30: 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)

 23 See “Oil & Gas Emissions Reduction Strategies Cost Analysis and Control Efficiency Determination,” Lesair 

Environmental, Inc., June 2008.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

23

* 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

Assuming 9,384 total devices replaced, adoption of this strategy will result in $10,172,256 in 

annual cost savings. 

Table 31: 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) $(10,172,256) 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. 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. The 

Division requests that interested parties provide additional information regarding this issue.

F. 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 not 

result in any additional costs.

G. 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 two 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 fifteen 
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

24

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 six 

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 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. See Section IV.A.1. above.

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 six 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. Given this, the Division conducted 

two cost calculations for dehydrators. The first cost calculation assumed that all of the two to six 

ton dehydrators are located within 1,320 feet of a building unit or designated outside activity area 

and thus will require a control. Based on this assumption the proposed requirement will reduce 

1,736 tpy of VOC at a cost effectiveness of $786/ton VOC.

Table 32: 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

The second calculation assumed that assumed that none of the two to six ton existing dehydrators 

will require controls. Based on this assumption the proposed requirement will reduce 1,472 tpy 

of VOC at a cost effectiveness of $632/ton VOC.

Table 33: 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
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

25

H. 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.

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.24 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. Given the wide variety of 

practices that this could entail, the Division currently does not have information about the 

potential cost-effectiveness of this provision, but requests additional information from interested 

parties during the pre-hearing process regarding this issue. 

 24 See EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2009, April, 2011.
Initial Economic Impact Analysis for Proposed Revisions to AQCC Regulations No. 7,

Submitted with Request for Hearing Documents on November 15, 2013

26

V. CONCLUSION

The Division projects that the entire proposal will reduce VOC emissions in Colorado by 

approximately 92,000 tons per year at a cost of approximately $29 million per year. The leak 

detection component of the package is estimated to reduce methane/ethane emissions by 

approximately 25,000 tons per year. The calculated cost per ton of VOC reduced ranges from 

$176 to $818 per ton. The overall cost effectiveness for the entire package is approximately 

$300 per ton of VOC reduced.

The Division prepared this Initial Economic Impact Analysis in accordance with the 

requirements of Section 25-7-110.5(4), C.R.S. Specifically, the Division utilized the 

methodology identified in § 25-7-110.5(4)(c)(I), C.R.S. In completing this analysis, the Division 

assessed the costs and benefits associated with each of the proposed strategies based on the 

reasonably available data. In collecting this data, the Division sought input 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 the analysis. To the extent that additional data regarding 

the costs and benefits of the proposed strategies is made available, the Division will assess this 

data and where appropriate incorporate it into the Final Economic Impact Analysis required 

under AQCC Procedural Rules, Section V.E.7.