I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r P r o p o s e d R e v i s i o n s t o A Q C C R e g u l a

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## 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 follo wing 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,

t he Division proposes to: increase control requirements and improve capture efficiency requirements for oil and gas storage tan ks; 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 re quirements 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 reasona bly 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 av ailable, 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,

in corporate 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

submit tal 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 propo sed 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

t i o n s N o

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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 inf ormation 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 f or 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 proposa l;

(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 t he 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 twe nty 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. Exp anding 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;I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

t i o n s N o

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### 3) Estab lishing 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

- attainmen t 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 we ll 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 eac h 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 ad ditional 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 def ined 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 hydrocarbonI n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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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 curr ently 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 ta nks 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 a ssociated 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. G e neral Cost Estimates for Flares

The estimated cost for a fl are control device is based on identified costs from a 2008 oil and gas

cost s tudy 1 

### adjusted for inflation. Based on this data, t he estimated annualized cost of a flare

control device with auto

- i gniter 2 

### 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 $1,64 8

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 $6,28 7

1 See “Oil & Gas Emissions Reduction Strategies Cost Analysis and Control Efficiency Determination

, ” Lesair

Environmental , Inc., June 2008. Information from this study was prev iously 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 t he 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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5 *Control cost evaluation based on 2008 Ozone Rulemaking cost surve y and producer data. Control device c osts 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 fue l costs $3.41/MMBtu (Henry Hub Spot Price

- Aug. 2013) *** Annualized over 15 years at 5% ROR



### 2. Lowering Statewide Condensate Tank Control T hreshold (from 20 tpy to 6 tpy)

The Division is proposing to lower the uncontrolled VOC emission control threshold f rom 20 tpy down to 6 tpy on condensate storage tanks statewide. Based on an analysis of the Air Pollution Emissions Notice (APEN) data base, the Division estimates that statewide there are 588

uncontrolled conden sate 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 non

attainment 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 6,42 2 1,622 36 8,080

Uncontrolled Tanks ( ≥ 6 tpy) 192 396 588

Based on the reported uncontrolled actual VOC emissio ns 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, t he total VOC emission reduction associated with lowering the

condensate tank threshold statew ide 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 Un cont rolled Tanks ( ≥ 6 tpy) 2, 355 677 * 1, 678

O utside NAA Uncontrolled Tanks ( ≥ 6 tpy) 4,890 1, 4 06 * 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### The annualized cost of installing 58 8 flare control devices is about $ 3.7 million dollars with an average cost effectiveness of about $7 16 per ton of VOC reduced. For the smallest individual

tank battery subject to controls (six tons/year), the flare cost effectiveness is estimated at $ 1,47 1 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 $6,28 6.8 $ 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 u ncontrolled VOC

emissions over six tons/year be required to install emission controls. Some uncontrolled produced water tanks could be co

- lo cated 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

t hat 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 ove r 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, t he Division estimates that the total VOC emission reduction associated with controlling these produced water tanks statewide is 457 tons

per year.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### Table 6 : Produced Wa ter 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 accounti n g for 75% capture and 95% destruction efficiency.



### The annualized cost of installing 52 flare control d evices is about $327,000, with an average cost effectiveness of about $715 per ton of VOC reduced. For the sma llest individual tank battery (six tons/ye ar), the flare cost eff ectiveness 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

Reduc tion [tons/year] Control

Costs [$/ton] ≥ 6tpy 52 $6,28 6.8 $326,9 1 4 457 $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 o f 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 ( C OGCC)

, 4 

### it appears likely that the Division’s APEN database may be undercounting crude oil tanks, either because these tanks have not been rep orted 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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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

V OC 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 $50,29 4 dollars with an average cost effectiven ess of about $42 7 per ton of VOC reduced. For the sma llest individual tank battery (six tons/year), the flare cost effectiveness is estimated at $1,4 71 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 $6,28 6.8 $50,29 4.4 117.7 $42 7

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 th is 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 calc ulate 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 averag e 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 1/4 th 

### 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 co uld be much higher. 

### total uncontrolled actual VOC emissions from thes e tanks during the first 90 days is 1,842.5 tons.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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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 outsid e 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 non

attainment area each year, the majority of these, 84, will require control devices regardless of this

s trategy 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 $ 17 6

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 contr ol 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 me thodologies 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 b e 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### To as sure 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 an d 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 ST EM proposal also requires implementation of a two

- pronged monitoring strategy involving a weekly 7 

### 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 : Pro posed Tiering for Instrument Based Tank Inspectio ns 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 Secti on 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 b ottle technology utilizes a small tank that is installed after the separator which allows for a sec ondary 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 dur ing 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 sto rage 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

g athering system that eliminates atmospheric storage tanks at well sites.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### Table 13 : Annualized Cost Analysis for Buffer Bottle

Item Capital Costs (one time) Non

- Recur ring 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 year 9



### 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 contr olled 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/o r 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 current ly 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 Co ntrol Efficiency Determination,” Lesair

Environmental , Inc., June 2008 , at pg. 8

.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### requirements ba sed 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 project ed 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 Estima tes (Statewide)

Type of Technology Number

of Tanks Each Device

Annualized Costs [$/year] Total

Annualized

Costs VOC

Reduction [tons/year] Control

Costs [$/ton]

Buffer Bottle 5,27 0 $3, 949 $20,811,230 52,624 $ 395

During the stakeholder process certain pa rties 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 VOC 12

12 This may overestimate the cos t 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 VOCI n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

t i o n s N o

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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 VOC 13



### .

While the buf fer 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 high

low pressure (HLP) separator to satisfy STEM may prove to be a better per forming 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 t ank 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 c alculated 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 Pric e

- 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 to tal 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### efficiency, equipping a tank with an HLP separator and a flare will reduce the emissions from an average new tank by 60 tpy. This yi elds 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

Produ ction 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 re quirement, owners and operators must conduct periodic inspections using EPA Reference Method 21 14 

### and repair leaks within a prescribed time

frame.

Although component leaks at compressor stations and well production facilities in Colorado are also a signif icant 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 detecti on 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 iden tified 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 demonstr ated 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 : Pro posed Tiering fo r 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 a ssess 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

inclu de 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

t i o n s N o

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### For well production facilities the proposed tiering is based on uncon trolled 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 th at is consistent with the monitoring schedule proposed as part of the STEM emission capture requirements discussed in Section B above. 16



### Table 19 : Pro posed Tiering for Leak Inspections at Well Production Facilities

Tank Uncontrolled Actual VOC Emissions I nspection 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 l eak 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 D ivision 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 tota l annual cost for each inspector will be $186,129, which equates to an hourly inspection rate of $99.

Table 2 0 : Leak Detection and Repair (LDAR) Inspector

– Annualized Cost Analysis

Item Capital Costs ( one time ) Annual Costs Annualized Total

Costs

FL IR 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 sche dule 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

t i o n s N o

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### *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 inspect ion 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 tak e 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 pe r 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 Emi ssions 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 produ ction 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 compres sor 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 o f 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 equalI n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### to or greater than the cost of repair and re

- inspection. However, the Division welcomes additional input from stakeholders on the costs an d benefits associated with repairing leaking

components.

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

Table 2 2: 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 2 3 : Well Production Faci lity Leak Inspection Costs U sing IR Camera/Method 21 Hybrid

Uncontrolled

VOC at Storage Tank Battery Tier [tpy] Number of

Facilities Annual Inspection Frequency Inspection

Time Per Inspection

[h ours ] Total Inspection

Time [h ours ] 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### Finally, the Division calculated the cost effectiveness of the propos ed 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 comp onent 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 qu arterly 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 2 4 : 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
[t py ] Fugitive

Methane

- Ethane

Emissions for

each CS tier [tpy] Total

Methane

Ethane

Reduction
[ tpy ]
≤ 12 147 40% 10.1 593.9 15.5 911.4

> 12 to ≤ 50 53 6 0% 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 VO C and $321/ton methane/ethane.

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

Station Fugitive

VOC Tier [tpy] Numbe r of Comp

Stations Total

Annual Inspection

Cost LDAR Program

Reduction

% Total

VOC

Reduct ion
[ tpy ] VOC

Control

Cost [$/ton] Total

Methane

Ethane

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 8 0%

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

a nd 22,461 tpy methane/ethane.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### 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 VO C

Reduction
[t py ] Fugitive

Methane

Ethane

Emissions for

each Tank Battery [tpy] Total

Methane

Ethane

Reduction
[t py ]

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

> 12 to ≤ 50 2,916 6 0% 4.6 8,048.2 7.3 12,772.1

> 50 964 8 0% 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 bas ed 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 U sing 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

Methane

Ethane

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 6 0% 8,048.2 $682 12,772.1 $429

> 50 964 $5,439,852 8 0% 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

4 0% reduction and a current leak rate of 4.6 tpy VOC and 7.3 tpy methane/ethane. Based on these reductions, f or the one

- time inspections of well production facilities with tanks that are less than six tons per year the cost effectiveness of the proposed ru le 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 industry 19

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

2013. 

### andI n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### environment al groups 20 

### 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 additio nal 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 determ ine total costs for annual, quarterly and monthly inspections at 8,702 well production facilities 21 

### 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, t he 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 detect ion 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 ) y ields 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 ca lculations ( 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 insp ections.

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 appr oximately $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 $6 00/ton and $4,100/ton.

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

Attainment Area

Unlike the non

- attainment area, flares used to control emissions at condensate tank batteries and glycol dehydration units outside the N AA 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.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### 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 D ivision estimates the statewide number of existing flare control devices without

auto

- igniters on condensate tank batteries and glycol dehydration is 6 52

. The reported uncontrolled actual emissions from these units are 47,675 tons per year VOC.

The estim ated 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

- Recurri ng 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

* Annualiz ed 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 a re uncontrolled . Based on the total uncontrolled actual emissions of 47,675 tons per year VOC from units equipped with flares without auto

igniter s , the emissions during this downtime period will be 1,4 30.2 tons of VOC

. Of this total,

495.1 tons of the em issions 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 t he annualized cost of installing 6 52 auto

- igniters is about $3 09,700, 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 Cos ts Total Annualized

Costs VOC Reduction* [tons/year] Control Costs [$/ton]

6 52 $475 $3 09

, 7 00 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 Co ntrol Efficiency Determination,” Lesair

Environmental , Inc., June 2008

.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### E. Expanding Low Bleed Pneumatics Requirements Statewide

As part of the 2008 Ozone Action Plan the AQCC adopted regulatory requirements mandati ng 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, t he Division estimated the number of high

- bleed pneumati c devices b ased 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

Conservatio n 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

wit h 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 approxi mately 14,921 tons per year VOC (40.9 tons per day).

The average retrofit cost of a high

- blee d pneumatic device is based on costs from the 2008 cost study 23 

### adjusted for inflation

. Utilizing this methodology, the annualized cost for each replaced

device is $169. However, because t he 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 Augus t 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 its elf 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

Lo w/No Bleed

Device* $1,033

Labor $387

Value of NG Saved ** $(1,2 68 )

Maintenance $16

Subtotal Costs $1,033 $387 $(1,2 53 )

Annualized Costs*** $143 $26 $(1,2 53 ) $(1,0 84 )

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

Environmental , Inc., June 2008

.I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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2 3 * 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 i n Colorado, natural gas produced at oil and gas sites is typically routed to a

tra nsmission 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 recomple ted 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 portio n 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 n atural 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 fifteenI n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### tons per year, mus t 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 equipm ent 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 out side 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 t hat 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 uncontrolle d 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

uncont rolled 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 Con trol Cost Estima tes (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 exi sting 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 Con trol Cost Estimates (6 TPY Control Threshold )

Number Each Device

Ann ualized Costs Total Annualized

Costs VOC Reduction [tons/year] Control Costs [$/ton]

148 $ 6,286.8 $930,446 1,472 $632I n i t i a l E c o n o m i c I m p a c t A n a l y s i s f o r Proposed R e v i s i o n s t o A Q C C R e g u l a

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### H. Control Requirements for Downhole Well Maintenance and Liquids Unloading

Events

Historically, Colorado has not regulated air emission s 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 se ctor. 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

addition al regulatory requirements designed to reduce emissions during well maintenance.

Well maintenance is required when, o ver time, liquids build up inside the well and reduce ga s and oil flow out of the well. To remove t hese liquids and improve flow, the liq uids 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 unl oading 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 es timated 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

indust ry. 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 requ ired 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

maintena nce and liquids unloading. For example, EPA’s Gas S tar 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 c apture 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

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### 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 componen t 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

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- 110.5(4), C.R.S. Specifica lly, the Division utilized the methodology identified in § 25

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- 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 co llecting 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 Econo mic Impact Analysis required under AQCC Procedural Rules, Section V.E.7.