FINAL

ECONOMIC IMPACT ANALYSIS

For Industry’s Proposed Revisions to 

Colorado Air Quality Control Commission

Regulation Number 3, 6, and 7 (5 CCR 1001-9)

Prepared by: 

Lisa McDonald, PhD

Holly Bender, PhD

Louis Berger Group

555 16th Street, Suite 600

Denver, CO 80202

303.985.6613

Prepared for: 

David Graham & Stubbs, LLP

1550 17th Street

Suite 500

Denver, CO 80202

January 30, 2014

JIWG-REB EX. B
Table of Contents

Executive Summary....................................................................................................................................... 3

Economic Impact Analysis......................................................................................................................... 3

Support of Industry’s Proposed Language................................................................................................ 6

Economic Impact Analysis............................................................................................................................. 8

Lowering Statewide Tank Control Threshold (from 20 tpy to 6 tpy)........................................................ 8

Emission Capture Requirements for Controlled Petroleum Storage Tanks............................................10

Leak Detection and Repair Requirements for Well Production Facilities...............................................19

LDAR Costs for Compressor Stations......................................................................................................27

Expanding Low Bleed Pneumatics Requirements Statewide..................................................................31

Recovered Product Estimates Attributable to proposed STEM and LDAR Requirements......................32

Indirect Costs of Regulations on Small Operators and Marginally Producing Wells..............................35

Costs to Division to Implement Proposed Rules.....................................................................................39

Support of Industry’s Proposed Language..................................................................................................45

JIWG-REB EX. B
Page 3 

Executive Summary

This document provides an economic analysis of the proposed revisions to Colorado Air Quality Control 

Commission (AQCC) Rules. This analysis is focused on specific parts of the regulations, including the 

costs for flares and auto-igniters, pneumatic controllers, storage tank emission management (STEM), 

and LDAR for well production facilities and compressor stations. Louis Berger has also estimated the 

value of the product saved as a result of the LDAR programs for well production facilities and 

compressor stations. Additionally, Louis Berger analyzed the impacts to marginally producing wells as 

they become less economically viable and are shut in or plugged as regulatory costs increase, resulting 

in loss of production, operator revenues, royalties, and severance taxes. Finally, Louis Berger provides 

estimates on the costs to the state to implement the proposed rules and regulations. This document 

also provides support for industry’s proposed language. 

Economic Impact Analysis

Important results of the analysis are summarized in table ES-1 and described in the bullets below. 

• Louis Berger estimated pollution control costs using information obtained from industry 

sources. Total costs to add flares and auto-igniters to tanks between 6 and 20 TPY uncontrolled 

VOC emissions are estimated to be $5.8 million, $511,680, and $7,872 for condensate, produced 

water, and crude oil tanks, respectively. Annualized costs of buffer bottles are estimated to be 

$5,850, with a total annual cost of $31.1 million. 

• LDAR programs result in decreased emission reduction benefits after the initial year of program 

implementation. That is, after initial monitoring, leaks are found and fixed, resulting in reduced 

leak frequencies and emissions. These decreased leak frequencies in subsequent years affect 

the cost effectiveness of the regulations. As emissions reductions decline in subsequent years, 

LDAR annualized costs decrease by a smaller proportion; therefore, costs per ton of VOC 

reduced in subsequent years are significantly higher in subsequent years compared to the initial 

year of implementation. Figure ES-1 shows how the emission reductions decline while LDAR 

costs per ton of VOC increase after the initial year. This figure also demonstrates the disparity in 

costs for the facilities with differing levels of uncontrolled emissions, with lower emitting tanks 

having a much higher cost per ton of VOC reduced than the higher emitting tanks. 

JIWG-REB EX. B
Page 4 

Table ES-1: Summary of Louis Berger Final EIA Results in Comparison to the 

Division’s Updated EIA Estimates

Louis Berger Estimate Division Estimate

Item Total Annual

Cost

Per 

Facility/

Tank Costs

Cost Per Ton 

of VOC 

Reduced

Total 

Annual Cost

Per Facility/

Tank Costs

Cost Per Ton 

of VOC 

Reduced

Lowering Threshold for Flares and Auto Igniters for Tanks

 Condensate Tanks $5.8M $9,840 $988 $3.7M $6,287 $716 

 Produced Water Tanks $511,680 $9,840 $1,121 $326,914 $6,287 $715

 Crude Oil Tanks $78,720 $9,840 $670 $50,294 $6,287 $427 

Storage Tank Emission Management Plan (buffer bottle and inspections) 

 Buffer Bottle $31.1M $5,850 - $21.0M $3,949 $391 

 Initial Year STEM Costs (with buffer bottle)

 6 to 12 TPY $16.2M $11,453 $4,800 $5.6M $4,147 NA

 12 to 50 TPY $39.9M $13,669 $1,945 $13.8M $4,741 NA

 Greater than 50 $21.0M $21,433 $555 $6.2M $6,325 NA

 Total $77.1M $14,509 $1,250 $25.6M $4,875 $4,800* 

 Subsequent Year STEM Costs (with buffer bottle)

 6 to 12 TPY $16.0M $11,324 $20,172 $5.6M $4,147 NA

 12 to 50 TPY $38.5M $13,164 $7,960 $13.8M $4,741 NA

 Greater than 50 $19.5M $19,903 $2,192 $6.2M $6,325 NA

 Total $73.9M $13,915 $5,097 $25.6M $4,875 $4,800*

LDAR for Well Production Facilities

 Initial Year LDAR Costs 

 Less than 6 TPY $19.8M $6,995 $3,629 $1.3M $470 NA

 6 to 12 TPY $9.8M $6,962 $3,611 $663,993 $470 $256

 12 to 50 TPY $56.2M $19,227 $9,818 $5.5M $1,881 $682 

 Greater than 50 $50.9M $51,999 $25,390 $5.5M $5,643 $1,533

 Total $136.7M $16,778 $8,590 $13.0M $1,598 $819 

 Subsequent Year LDAR Costs 

 Less than 6 TPY $3.0M $1,051 $5,454 $1.3M $470 NA

 6 to 12 TPY $6.3M $4,452 $9,815 $663,993 $470 $256

 12 to 50 TPY $27.3M $9,336 $20,261 $5.5M $1,881 $682 

 Greater than 50 $21.6M $22,097 $45,855 $5.5M $5,643 $1,533 

 Total $58.2M $7,138 $19,354 $13.0M $1,598 $819 

LDAR Costs for Compressor Stations

 Initial Year LDAR Costs 

 Less than 12TPY $3,873,936 $26,353 $3,465 $154,262 $1,049 $260

 12 to 50 TPY $11,532,775 $217,599 $17,344 $589,763 $11,128 $1,131 

 Greater than 50 - - - - - -

 Total $15,406,710 $77,033 $8,641 $744,025 $3,720 $667 

 Subsequent Year LDAR Costs 

 Less than 12TPY $2,020,457 $13,745 $7,681 $154,262 $1,049 $260 

 12 to 50 TPY $4,446,685 $83,900 $28,421 $589,763 $11,128 $1,131

 Greater than 50 - - - - - - 

 Total $6,467,142 $32,336 $15,416 $744,025 $3,720 $667

Value of Product Savings – Initial Year

 Well Production Facilities $12.4M $1,532 - NA NA NA

 Compressor Station – Initial Year $1.3M $6,993 - NA NA NA

Value of Product Savings – Subsequent Years

 Well Production Facilities $2.3M $289 - NA NA NA

 Compressor Stations $329,453 $1,647 - NA NA NA

Division Implementation Costs of Proposed Rules 

 Hours 12,282 0 

 FTE 6.1 0 

*Calculated based on the emission reductions associated with the STEM Control Analysis on page 12 of Division’s Updated EIA. 

JIWG-REB EX. B
Page 5 

Figure ES-1: STEM Emission Reductions and Cost Per Ton of VOC Reduced 

• STEM costs are estimated to be $77.1 million in the initial year and $73.9 million in subsequent 

years, while the cost per ton of VOC reduced is $1,250 in the initial year and $5,097 in 

subsequent years, on a recurring annual basis. 

• Inspections and LDAR programs are more expensive to implement in the attainment area in 

comparison to the relatively dense operations in the non-attainment area due to the additional 

travel time, travel expenses, and fewer inspections possible on an annual basis in the attainment 

area. The STEM costs show that across all tank levels, the attainment area tanks have $1,000 

higher costs per tank per year than in the non-attainment area to implement this program. 

Similar results occur for well production facilities, with LDAR costs per facility in the initial year 

higher in the attainment area than non-attainment area for each level of monitoring required. 

• LDAR costs for well production facilities are considerable, with initial year costs of $136.7M 

($16,778 per facility) and subsequent recurring annual costs of $58.2 million ($7,138 per 

facility). The cost per ton of VOC reduced is $8,590 in the initial year and $19,354 in the 

subsequent years on an annual recurring basis. 

• LDAR costs for compressor stations are $15.4 million in the initial year ($77,033 per compressor 

station) and subsequent recurring annual costs of $6.5 million ($32,336 per compressor station). 

The cost per ton of VOC reduced is $8,641 in the initial year and $15,416 in the subsequent 

years on an annual recurring basis. 

• The total cost to expand the regulatory mandate to modify or retrofit high-bleed pneumatic 

devices statewide was estimated to be $32 million. This includes the cost to replace an 

$0

$5,000

$10,000

$15,000

$20,000

$25,000

 -

 10,000

 20,000

 30,000

 40,000

 50,000

 60,000

 70,000

Year 1 Year 2 Year 3 Year 4

Dollars Per Ton

TPY

Year

All

Greater than 50

12 to 50 TPY

6 to 12 TPY

All

Greater than 50

12 to 50 TPY

6 to 12 TPY

TPY VOCs Reduced

Dollars / Ton

JIWG-REB EX. B
Page 6 

estimated 9,800 high-bleed devices that are located at facilities outside the nonattainment area. 

When considering the amount of gas that can be recovered with the low-bleed devices, payback 

of the costs are expected to occur within 2.8 years. . 

• Louis Berger estimated the product savings that can be expected from LDAR requirements for 

well production facilities and compressor stations. In the initial year, the value of the product 

captured represents approximately 8.7 percent of the LDAR costs. In subsequent years, the 

value of the natural gas captured represents 4 and 5 percent of the LDAR costs in subsequent 

years for well production facilities and compressor stations, respectively. The Economic Impact 

Analysis requires an assessment of the cost for the Division to implement the proposed rule 

changes. Oversight of an LDAR program, STEM plans, and annual report review of 5,312 tank 

batteries, 5,312 well production facilities, and 200 compressor stations with possibly hundreds 

of thousands of components would require additional Division manpower. Louis Berger 

reviewed the revised (November 21, 2013) Regulations 3, 6 and 7 to understand the 

implementation costs to the Division associated with the new rules. The net increase in the 

number of labor hours at the Division as result of the proposed regulations is anticipated to be 

approximately 12,282 labor hours annually. Notably, the Division would need 5,600 hours to 

review and approve initial STEM plans required under Regulation 7, the largest estimated time 

commitment for the Division. This represents approximately 6.1 FTEs of additional staff for the 

Division to review, oversee, inspect, manage, and approve various requirements associated with 

the proposed rules. Therefore, Louis Berger concludes that the Division would incur additional 

net costs to implement the proposed requirements beyond current expenditures. 

In order to gain an understanding of the potential indirect costs to businesses, in particular small 

businesses if the proposed rules were implemented, Louis Berger evaluated the impacts on small, 

marginally producing wells within the state. Marginally producing wells with production less than 2 

BOPD represent over half (55 percent) of the total producing wells in the state (46,495) as of 2013. 

Under current economic and regulatory conditions, the economic limit for marginally producing wells 

was estimated to be 0.43 BOPD, which is the point at which revenues would no longer cover operating 

expenses and the well would be shut in. Additional operating costs associated with the proposed rules 

were estimated per well production facility and tank and included in the analysis. Over time, the 

additional cost burden would result in as much as 128.6 million barrels of oil being left in place and not 

produced. The calculated present values for these losses include $1.9 billion in lost revenue to 

producers, $384 million in lost royalties and $96 million in lost severance taxes.

• Support of Industry’s Proposed Language

The results of the final economic impact analysis presented here support the industry’s key suggested 

revisions to the Division’s proposed rule. Specifically, the proposed revisions will allow similar emission 

reductions to be achieved in a cost effective, achievable, and reasonable manner. Key points to the 

analysis include: 

 

• Diminishing marginal benefits associated with LDAR programs implies decreasing cost 

effectiveness after initial rounds of inspections and repairs. Reducing the monitoring to reflect 

JIWG-REB EX. B
Page 7 

successful LDAR implementation reduces costs and improves the cost effectiveness of the 

proposed rule compared to the Division’s proposal while maintaining program integrity through 

realized emission reductions. The “step-down” of monitoring frequency, which rewards 

companies with four inspections with no leaks, is an example of how the industry changes to the 

proposed rule would provide incentives for industry to maintain compliance and reduce costs 

for good behavior. 

• Generally, compliance costs of STEM and LDAR for small tanks and well production facilities are 

more burdensome than for larger facilities on a cost per ton basis. As such, requiring a one-time 

LDAR inspection and monthly AVO for all facilities (including all well production facilities) with 

uncontrolled emissions between 2 and 6 TPY would improve the overall cost effectiveness of the 

proposed rule by limiting the very high costs per ton of VOC reduced incurred by very small 

facilities with very small VOC fugitive emissions. 

• Compliance costs are higher for operations outside of the non-attainment area as the distance 

among facilities and tanks increases inspection travel time and expenses. Limiting the 

geographic scope to the non-attainment area will improve the cost effectiveness of the 

proposed rule. 

• Allowing for the use of other established technology, such as the tunable diode laser absorption 

spectroscopy technology (TDLAS) as an option for inspection monitoring, would reduce costs to 

industry with faster inspections and reduced camera training requirements, among other 

factors. 

JIWG-REB EX. B
Page 8 

Economic Impact Analysis

This document provides an economic analysis of the proposed revisions to Colorado Air Quality Control 

Commission (AQCC) Regulation Number 3, 6 and 7. This analysis is focused on the specific parts of the 

regulation, including the costs for flares and auto-igniters, STEM, LDAR for well production facilities and 

compressor stations, and pneumatic controllers. Louis Berger has also estimated the value of the 

product saved as a result of the LDAR programs for well production facilities and compressor stations. 

Additionally, Louis Berger analyzed the impacts to marginally producing wells as they become less 

economically viable and are shut in or plugged as compliance costs increase resulting in a loss of

production, operator revenues, royalties, and severance taxes. Finally, Louis Berger provided estimates 

on the costs to the state to implement the proposed rules and regulations. 

Lowering Statewide Tank Control Threshold (from 20 tpy to 6 tpy)

Louis Berger evaluated the costs to industry associated with installing flares and auto-igniters on 

condensate tanks with uncontrolled emissions between 6 TPY and 20 TPY. The analysis used the state’s 

estimate of 588 condensate tanks that that would be affected by the change in the regulatory threshold, 

along with updated costs estimated by the EPA and in the industry survey. 

Louis Berger developed cost estimates for flares and auto-igniters using data and information obtained 

from an industry survey conducted in 2013 and data from the EPA. The capital, non-recurring and 

annual costs were obtained from the EPA.

1 Because the costs were reported in 2008 dollars they were 

escalated to 2013 dollars using the GDP price index obtained from the U.S. Office of Management and 

Budget.2

 These costs were annualized for an 11-year life of the equipment based on information 

obtained from the industry survey at a 5 percent interest rate. The annual cost for the flare is estimated 

to be $9,840 (Table 1). 

Table 1: Estimated Cost for Flares and Auto-Igniters

Item Estimated Cost (2013$)

Capital and Non-Recurring Cost $35,070

Annual Costs $5,823 

Annualized Capital Costs $4,018

Total Annual Costs $9,840 

The Division estimated the cost per ton of VOC emission reductions by lowering the statewide tank 

control threshold from 20 TPY to 6 TPY. According to the Division’s analysis, there are 588 condensate 

tanks that would be affected by this rule change and that by adding flares to these particular tanks, VOC 

emissions would decline by 5,162 TPY. Louis Berger analyzed the cost of lowering the threshold from 20 

tpy to 6 tpy using the flare cost estimate summarized above. The results are summarized in Table 2. 

 

1 EPA. 2011. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, 

Transmission, and Distribution: Background Technical Support Document for Proposed Standards.

2 Office of Management and Budget. 2013. Fiscal Year 2014. Gross Domestic Product and Deflators Used in Historic 

Tables. Table 10.1. Available: http://www.whitehouse.gov/sites/default/files/omb/budget/fy2014/assets/hist.pdf 

JIWG-REB EX. B
Page 9 

When the costs are separated by uncontrolled emissions, the differences are significant. For tanks with 

lower uncontrolled emissions (6 to 10 TPY), the control costs are double what they are for the higher 

emitting tanks (between 10 and 20 TPY). Average cost per ton of VOC reduced is estimated to be $1,121. 

Table 2: Estimated Cost Per Ton of VOCs Reduced for Condensate Water Tanks

Uncontrolled 

Emissions

Number of 

Tank Batteries 

Affected

Average 

Uncontrolled 

Emissions per 

tank 

Total 

Uncontrolled 

Emissions

Emission 

Reduction 

with Flare and 

Auto-Igniter 

Total Cost of 

Flares Per 

Tank Category

Cost Per Ton 

of VOC 

Reduced Per 

Tank Category

(1) (2) (3) (4) = (3) * (2) (5) = (4) * 

0.7125 

(6) = (2) * 

$9,840 (7) = (6)/(5)

6 to 10 235 7.35

 

1,729 

 

1,232 $2,314,368 $1,879 

10 to 20 353 13.98 

 

4,932 

 

3,514 $3,471,552 $988 

Total Affected 

(State 

Estimate) 588 12.32 

 

7,244 

 

5,161 $5,785,920 $1,121 

Using the same logic and data as described for condensate tanks, the controls for produced water tanks 

and crude oil tanks yields the following results. According to the Division’s analysis, there are 52 

produced water tanks and 8 crude oil tanks. Louis Berger believes that there are considerably more 

crude oil tanks than are reported in the APEN. However, without additional data, Louis Berger used the 

Division’s estimate of 8. Cost per ton of VOC reduced for produced water and crude oil tanks are 

estimated to be $1,121 and $670, respectively. 

Table 3: Estimated Cost Per Ton of VOCs for Produced Water Tanks

Uncontrolled 

Emissions

Number of 

Produced 

Water Tanks 

Affected

Average 

Uncontrolled 

Emissions per 

tank 

Total 

Uncontrolled 

Emissions

Emission 

Reduction 

with Flare and 

Auto-Igniter 

Total Cost of 

Flares Per 

Tank Category

Cost Per Ton 

of VOC 

Reduced Per 

Tank Category

(1) (2) (3) (4) = (3) * (2) (5) = (4) * 

0.7125

(6) = (2) * 

$9,840 (7) = (6)/(5)

Total Affected 

(State 

Estimate) 

52 12.32 641 456 $511,680 $1,121 

JIWG-REB EX. B
Page 10

Table 4: Estimated Cost Per Ton of VOCs for Crude Oil Tanks

Uncontrolled 

Emissions

Number of Oil 

Tanks Affected

Average 

Uncontrolled 

Emissions per 

tank 

Total 

Uncontrolled 

Emissions

Emission 

Reduction 

with Flare and 

Auto-Igniter 

Total Cost of 

Flares Per 

Tank Category

Cost Per Ton 

of VOC 

Reduced Per 

Tank Category

(1) (2) (3) (4) = (3) * (2) (5) = (4) * 

0.7125

(6) = (2) * 

$9,840 (7) = (6)/(5)

Total Affected 

(State 

Estimate) 

8 20.62 165 118 $78,720 $670 

Emission Capture Requirements for Controlled Petroleum Storage Tanks 

This section of the analysis evaluates requirements under the Storage Tank Emissions Management 

(STEM) plan, including costs of adding a buffer bottle and implementing a LDAR program. With data 

collected from the industry survey conducted in 2013, Louis Berger estimated an annual cost for buffer 

bottles of $5,850, as described in Table 5. 

Table 5: Estimated Cost for Buffer Bottles

Item Estimated Cost (2013$)

Capital and Non-Recurring Cost $25,000 

Annual O&M Costs $2,500

Annualized Capital Costs* $3,350 

Total Annual Costs $5,850

*Capital costs and non-recurring costs were annualized over 9 years, the estimate life of the control 

 technology. 

The STEM program would require instrument based monitoring. The monitoring frequency would be 

based on the uncontrolled emissions of various tanks as reported in the APEN database. Louis Berger 

estimated the LDAR costs using data and information obtained through an operator survey and follow 

up interviews. Table 6 summarizes the cost assumptions for the analysis. 

JIWG-REB EX. B
Page 11

Table 6: STEM Cost Assumptions for Tanks (2013$)

LDAR AVO

Item Estimated 

Cost Annualized* Unit Cost Estimated Cost Annualized* Unit Cost

Capital and Non-Recurring Costs

 Camera $122,000 $28,179 $46.96/ins

pection in 

NAA

$70.45/ins

pection in 

the AA

 Vehicle $30,000 $6,929 $11.54/ins

pection in 

the NAA

$17.32/ins

pection in 

the NAA

 Program set up costs (i.e., 

 Tagging, software, travel, 

 etc.)

$1,000 $231 $231/Tank $500 $115.49 $115.49/ 

tank

Inspection, Operations and Maintenance costs

Assume one camera can inspect 2 tanks a day in the AA, 400 tanks/year; 3 tanks per day in the NAA, 600 tanks/year; 10 weeks 

for repair and training. Assume weekly inspections for all tanks over 6 TPY. 

 Inspection Labor, 

 including travel time

 Hourly Rate:

 Inspection and Travel 

 Time (NAA and crude) 

 Inspection and Travel 

 Time (AA) 

$150 

3 

4 

$150/hour 

4.75 hours

5.75 hours

$100 

.5

.5

$100/Hour 

0.5 Hours

0.5 Hours

 Camera/Inspection training $7,500 Per 100 

Tanks

$7,500 $7,500/100 

tanks/year

 Camera repair $12,500 Camera $12,500/ 

camera/

year

 Travel and per diem costs (NAA 

Condensate and Crude Oil)

 Travel and per diem costs (AA 

Condensate)

$30 

$40 

Inspection $30/ 

inspection

$40/ 

inspection

 Supervision $100 

(annual, 

quarterly)

$200 

(monthly)

Tank $100/tank/

year

$200/tank/

year

 Compiling data, record-keeping 

 and reporting 

$1,530 

(annual, 

quarterly)

$3,060 

(monthly)

Tank $1,530/ 

tank/year

$3,060/ 

tank/year

*Camera and set up costs annualized at 5% over 5 year-life of the equipment. 

Louis Berger estimated the repair costs using information from a Canadian study and a Trihydro report

that provide estimates of the number of components, potential number of leaks, and average leak 

JIWG-REB EX. B
Page 12

frequency for production tanks.3 Louis Berger assumed for this cost estimate that the typical production 

tank in Colorado has 38 components (Clearstone Engineering 2013) with an initial leak rate of 1.7 

percent (Trihydro 2014), which equates to 0.65 components discovered leaking during each inspection. 

The Trihydro report indicates that subsequent leak frequencies associated with quarterly LDAR drop to 

0.4 percent (0.15 leaking components per production tank), which was used to estimate the number of 

leaks repaired and re-monitored in subsequent years. Costs to repair components were obtained from 

Nelson and Brown (2012) and include only the labor needed to repair the leak, not materials and 

equipment costs.

4 Data and cost assumptions for the repair and re-monitoring costs are summarized in 

table 7. The re-monitoring cost was assumed to apply to the 25 percent of leaks, and the inspection and 

travel costs were obtained from the operator survey, with a cost estimate of $480 per inspection in the 

non-attainment area and $640 in the attainment area. 

Table 7: Repair and Re-monitoring Cost Assumptions

Percent of Leaks Type of repair Repair Time

(hours) Hourly Rate Re-monitor Cost (per leak)

75% On-line 1 $75 - 

25% On the ground 4 $75 $480 (NAA)

$640 (AA)

The total estimated cost of the proposed STEM program, which includes the costs for the inspections 

and the buffer bottles, are summarized in the following two tables. Total STEM costs include annualized 

capital costs, recurring inspection, operations, and maintenance costs, buffer bottle costs, repair costs, 

and re-monitoring costs. Total costs for all storage tanks are estimated to be $77.1 million, of which the 

non-attainment area tanks account for $64.1 million. When comparing the costs per condensate tank in 

the attainment area and non-attainment area over all the different types of tanks, costs per tank in the 

attainment area are approximately $1,000 higher than tanks in the non-attainment. The higher costs in 

the attainment area due to longer travel times and per diem costs, as ability to perform fewer 

inspections on an annual basis. For the greater than 50 TPY tanks, the STEM costs are $23,676 per tank

in attainment area compared with the non-attainment area STEM costs of $20,966 per tank. The STEM 

costs are provided in Tables 8.1 and 8.2. 

 

3 Clearstone Engineering, Ltd. 2013. Technical Report: Draft Update of Fugitive Equipment Emissions Factors. 

Prepared for the Canadian Association of Petroleum Producers. August. See Tables 5 and 12. 

Trihydro Corporation. 2014. Colorado Regulation/Litigation Support. Prepared for WPX Energy, Inc. January 6. 

4 Nelson, Bradley and Heather Brown. 2012. Equipment Leak Emission Reduction and Cost Analysis for Well Pads, 

Gathering and Boosting Stations, and Transmission and Storage Facilities Use Emission and Cost Data from the 

Uniform Standards. Memorandum to Greg Nizich and Bruce Moore, EPA. April 

JIWG-REB EX. B
Page 13

Table 8.1: Initial Year STEM Cost Analysis, Part 1

Tank

Uncontrolled 

VOC Emissions

Monitoring 

Requirement

Number of 

Storage Tanks 

and Crude Oil 

Tanks 

Number of 

inspections/

Year 

Capital Costs 

for Inspections 

(annualized)

(1)

Annual Costs 

for 

Inspections, 

O&M

(2)

Number of 

Cameras 

Needed

Crude Oil Tanks

6 to 12 TPY annually 23 23 $9,314 $114,080 - 

12 to 50 TPY quarterly 5 20 $2,903 $32,000 - 

Greater than 50 monthly 14 168 $14,681 $178,680 1 

Total - 42 211 $26,898 $324,760 1 

Attainment Area Condensate Tanks

6 to 12 TPY annually 325 325 $141,125 $1,676,500 1 

12 to 50 TPY quarterly 323 1,292 $225,305 $2,323,920 4 

Greater than 50 monthly 165 1,980 $230,950 $2,337,850 5 

Total - 813 3,597 $597,381 $6,338,270 10 

Non-Attainment Area Condensate Tanks

6 to 12 TPY annually 1,065 1,065 $431,297 $5,307,400 2 

12 to 50 TPY quarterly 2,593 10,372 $1,505,272 $16,820,200 18 

Greater than 50 monthly 799 9,588 $837,847 $9,684,130 16 

Total - 4,457 21,025 $2,774,416 $31,811,730 36 

All Tanks

6 to 12 TPY annually 1,413 1,413 $581,736 $7,097,980 3 

12 to 50 TPY quarterly 2,921 11,684 $1,733,480 $19,176,120 22 

Greater than 50 monthly 978 11,736 $1,083,478 $12,200,660 22 

Total - 5,312 24,833 $3,398,695 $38,474,760 47 

JIWG-REB EX. B
Page 14

Table 8.2: Initial Year STEM Cost Analysis, Part 2

Tank

Uncontrolled 

VOC Emissions

Monitoring 

Requirement

Buffer 

Bottle Costs

(3)

Annual 

Number 

of Leaks

Leak 

Repair 

Costs (4)

Remonitoring 

Cost (5)

Total Initial 

Year STEM 

Costs for

Tanks 

(1+2+3+4+5)

Per Tank Cost 

for Initial Year

Crude Oil Tanks

6 to 12 TPY annually $134,545 15 $1,950 $1,783 $261,672 $11,377 

12 to 50 TPY quarterly $29,248.83 13 $1,696 $1,550 $67,398 $13,480 

Greater than 50 monthly $81,897 109 $14,244 $13,023 $302,525 $21,609 

Total - $245,690 136 $17,890 $16,357 $631,595 $15,038 

Attainment Area Condensate Tanks

6 to 12 TPY annually $1,901,174 210 $27,556 $33,592 $3,779,946 $11,631 

12 to 50 TPY quarterly $1,889,474 835 $109,545 $133,541 $4,681,786 $14,495 

Greater than 50 monthly $965,211 1,279 $167,879 $204,653 $3,906,544 $23,676 

Total - $4,755,859 2,324 $304,981 $371,786 $12,368,276 $15,213 

Non-Attainment Area Condensate Tanks

6 to 12 TPY annually $6,230,000 688 $90,299 $82,559 $12,141,554 $11,401 

12 to 50 TPY quarterly $15,168,441 6,700 $879,416 $804,037 $35,177,366 $13,566 

Greater than 50 monthly $4,673,962 6,194 $812,943 $743,262 $16,752,144 $20,966 

Total - $26,072,403 13,582 $1,782,657 $1,629,858 $64,071,064 $14,375 

All Tanks

6 to 12 TPY annually $8,265,719 $913 $119,805 $117,934 $16,183,172 $11,453 

12 to 50 TPY quarterly $17,087,164 $7,548 $990,657 $939,128 $39,926,550 $13,669 

Greater than 50 monthly $5,721,070 $7,582 $995,066 $960,938 $20,961,213 $21,433 

Total - $31,073,952 $16,042 $2,105,528 $2,018,001 $77,070,935 $14,509 

As a result of initial implementation of a LDAR program, it has been shown that leak frequencies 

decrease from 1.7 percent to 0.4 percent (Trihydro 2014). Therefore, in subsequent years, the number 

of leaks was adjusted to reflect the reduced leak frequency. The reduced leak repair and re-monitoring 

costs with the adjusted number of leaks were estimated and shown in table 9. It is assumed that 

subsequent LDAR and AVO capital (annualized), recurring annual, and annualized buffer bottle costs 

would remain as estimated in the initial year (table 8), while the number of repairs and re-monitoring 

needed would fall as the leak rate frequency also falls in subsequent years (table 9). The total STEM 

costs for subsequent years, shown in table 9, include the capital, inspection and O&M costs, and buffer 

bottle costs in table 8, with the adjusted leak repair and re-monitoring costs in table 9. 

JIWG-REB EX. B
Page 15

Table 9: Subsequent Year STEM Cost Analysis

Tank

Uncontrolled 

VOC Emissions

Monitoring 

Requirement

Number 

of 

Storage 

Tanks 

and 

Crude 

Oil Tanks 

Annual 

Number of 

Leaks 

Leak Repair 

Costs (4)

Re-monitoring 

Cost (5)

Total 

Subsequent 

Year STEM 

Costs for 

Tanks 

(Annual 

Cost) 

(1+2+3+4+5)

Per Tank 

Cost in 

Subsequent 

Years 

(Annual 

Cost)

Crude Oil Tanks

6 to 12 TPY annually 23 3 $459 $420 $258,817 $11,253 

12 to 50 TPY quarterly 5 3 $399 $365 $64,915 $12,983 

Greater than 50 monthly 14 26 $3,352 $3,064 $281,673 $20,120 

Total - 42 32 $4,209 $3,849 $605,406 $14,414 

Attainment Area Condensate Tanks

6 to 12 TPY annually 325 49 $6,484 $7,904 $3,733,186 $11,487 

12 to 50 TPY quarterly 323 196 $25,775 $31,421 $4,495,896 $13,919 

Greater than 50 monthly 165 301 $39,501 $48,154 $3,621,666 $21,949 

Total - 813 547 $71,760 $87,479 $11,850,749 $14,577 

Non-Attainment Area Condensate Tanks

6 to 12 TPY annually 1,065 162 $21,247 $19,426 $12,009,369 $11,276 

12 to 50 TPY quarterly 2,593 1,577 $206,921 $189,185 $33,890,019 $13,070 

Greater than 50 monthly 799 1,457 $191,281 $174,885 $15,562,105 $19,477 

Total - 4457 3,196 $419,449 $383,496 $61,461,493 $13,790 

All Tanks 

6 to 12 TPY annually 1,413 214 28,190 27,750 $16,001,372 $11,324 

12 to 50 TPY quarterly 2,921 1,776 233,095 220,971 $38,450,830 $13,164 

Greater than 50 monthly 978 1,784 234,134 226,103 $19,465,444 $19,903 

Total - 5,312 3,775 495,418 474,824 $73,917,648 $13,915 

To better understand the costs per ton of VOCs reduced across the different levels of uncontrolled 

emissions, Louis Berger queried data from the APEN database provided by the Division to identify the 

uncontrolled emissions for the various tanks which is summarized in table 10.

5

 

 

5 The following Exhibits were analyzed on the state’s rulemaking ftp site: APCD-PHS EX TT (produced 

water tanks), APCD-PHS-EX-LL (condensate tanks), APCD -PHS- EX - MM (crude oil tanks), APCD-PHS EX- 

(STEM emission control).

JIWG-REB EX. B
Page 16

Table 10: Uncontrolled Emissions for Tanks

Tank Uncontrolled 

VOC Emissions

Monitoring 

frequency

Number of storage 

tanks and crude oil 

tanks 

Uncontrolled VOC 

emissions per tank 

(TPY)

Total uncontrolled 

VOC emissions (TPY)

Crude Oil Tanks

6 to 12 TPY annually 23 8.70 200 

12 to 50 TPY quarterly 5 25.80 129 

Greater than 50 monthly 14 268.63 3,760 

Total - 42 97.38 4,090 

Attainment Area Condensate Tanks

6 to 12 TPY annually 325 8.62 2,802 

12 to 50 TPY quarterly 323 22.41 7,237 

Greater than 50 monthly 165 156.01 25,742 

Total - 813 44.01 35,781 

Non-Attainment Area Condensate Tanks

6 to 12 TPY annually 1,065 8.77 9,341 

12 to 50 TPY quarterly 2,593 26.15 67,797 

Greater than 50 monthly 799 135.99 108,656 

Total - 4,457 41.69 185,794 

The approach used by Louis Berger for the initial emission reductions (year 1) is very similar to that of 

the Division’s: the uncontrolled emissions less the control for the flares (71.25%) or 0.2876 percent of 

the uncontrolled emissions, times 95 percent. Note that the Division’s efficiency rate for the flare and 

auto-igniter of 71.25 percent is not supported by empirical data or industry literature, nor is it consistent 

with EPA guidance regarding the estimated effectiveness of such control requirements for air quality 

planning purposes6

. These sources would suggest that the control efficiency of flares is considerably 

higher than the estimates by the Division, and the effectiveness of such control requirements is also 

higher (83% under EPA’s noted revised rule effectiveness guidance, not 75%). As such, the emission 

reductions attributed to STEM in this analysis (as well as in the Division’s analysis) are likely 

overestimated. The cost per ton of VOC reduced associated with STEM are therefore likely to be higher 

than estimated in this analysis due to the higher efficiency factor of the flare, with fewer fugitive 

emissions to capture with STEM.

The initial year results reveal an average of $1,250 per ton of VOC reduced. Emission reductions in 

subsequent years are much smaller than initial reductions, especially with leak definitions as low as 500 

and 2,000 PPM. The Clearstone study has indicated that annual leak detection and monitoring emissions 

factors result in a net reduction of 75.3 percent compared to what would occur without instrument 

monitoring.7

 This is consistent with Trihydro’s estimated drop in leak rate frequencies after quarterly 

LDAR from 1.7 percent to 0.4 percent (Trihydro 2014). Louis Berger assumed that the emissions 

 

6 Emissions Inventory Guidance for Implementation of Ozone and Particulate Matter National Ambient Air Quality 

Standards (NAAQS) and Regional Haze Regulations, Appendix B, Doc.No. EPA-454/R-05-001 (August 2005). 7 See Clearstone Engineering study previously cited, page 19.

JIWG-REB EX. B
Page 17

reductions captured in subsequent years would be consistent with this decline in leak frequency. For 

example, if STEM was assumed to reduce emissions by 100 TPY in the initial year, the subsequent 

emissions reductions would be 23.5 percent (0.4/1.7) of the initial reduction. 

It should be noted that the smaller tanks incur significantly larger costs per ton of VOC reduced. In the 

initial year, these costs per ton are $4,800 for tanks between 6 and 12 TPY uncontrolled emission, while 

tanks above 50 TPY, the initial year cost is $555 per ton reduced. Across all tanks, the subsequent year 

cost per ton of VOC reduced is approximately four times as high as the initial year cost, with the average 

cost in the subsequent years of $5,097 per ton of VOC reduced compared to the initial year cost per ton 

of VOC reduced of $1,250. This is due primarily to the effectiveness of the initial year LDAR in reducing 

fugitive emissions to a quarter of initial year rate. Despite the relatively higher travel and inspection 

costs in the attainment area, since the non-attainment area is where the overwhelming majority of 

tanks are located, there is not a considerable difference in the cost per ton of VOC reduced between 

these two geographic regions. However, as shown in Table 9, the tank STEM costs are more than $1,000 

higher for attainment area tanks when compared to non-attainment tanks (for all tank uncontrolled 

emissions). Table 11 shows the initial year and subsequent total costs, emission reductions, and costs 

per ton of VOC reduced.

Figure 1 shows how the emission reductions decline after the initial year while LDAR costs per ton of 

VOC increase after the initial years. This figure also demonstrates the disparity in costs for facilities with 

different levels of uncontrolled emissions, with the lower emitting tanks having a much higher cost per 

ton of VOC reduced than higher emitting tanks. Over time, STEM for the tanks with the smallest 

uncontrolled emissions control the least amount of VOC emissions with the highest cost per ton of VOC 

($20,172), while STEM for the tanks with the highest uncontrolled emissions capture the greatest 

amount of emissions and have the lowest cost per ton of VOC reduced ($2,192). 

JIWG-REB EX. B
Page 18

Table 11: STEM Costs Per Ton of VOC Reduced 

Tank

Uncontrolled 

VOC Emissions

STEM Costs

Emission 

Reduction 

from STEM

STEM Cost Per 

Ton of VOC 

Reduced 

Annual 

STEM Costs

Emission 

Reductions

Recurring 

Annual Cost Per 

Ton of VOC 

Reduced

Initial Year Subsequent Years

Crude Oil Tanks

6 to 12 TPY $261,672 55 $4,786 $258,817 13 $20,120 

12 to 50 TPY $67,398 35 $1,913 $64,915 8 $7,831 

Greater than 50 $302,525 1,027 $295 $281,673 242 $1,165 

Total $631,595 1,117 $565 $605,406 263 $2,303 

Attainment Area Condensate Tanks

6 to 12 TPY $3,779,946 765 $4,939 $3,733,186 180 $20,732 

12 to 50 TPY $4,681,786 1,977 $2,369 $4,495,896 465 $9,667 

Greater than 50 $3,906,544 7,031 $556 $3,621,666 1,654 $2,189 

Total $12,368,276 9,773 $1,266 $11,850,749 2,299 $5,154 

Non-Attainment Area Condensate Tanks

6 to 12 TPY $12,141,554 2,551 $4,759 $12,009,369 600 $20,006 

12 to 50 TPY $35,177,366 18,517 $1,900 $33,890,019 4,357 $7,778

Greater than 50 $16,752,144 29,677 $564 $15,562,105 6,9823 $2,229

Total $64,071,064 50,745 $1,263 $61,461,493 11,940 $5,148 

Total Tanks

6 to 12 TPY $16,183,173 3,371 $4,800 $16,001,372 793 $20,172 

12 to 50 TPY $39,926,549 20,529 $1,945 $38,450,830 4,830 $7,960 

Greater than 50 $20,961,213 37,735 $555 $19,465,444 8,879 $2,192 

Total $77,070,935 61,635 $1,250 $73,917,648 14,502 $5,097 

JIWG-REB EX. B
Page 19

Figure 1: STEM Costs and Emission Reductions Over Time

Leak Detection and Repair Requirements for Well Production Facilities

The Division’s proposed regulations include leak detection and repair requirements for well production 

facilities. The Division has based the LDAR monitoring frequency associated with these facilities on the 

uncontrolled VOC emissions with associated tanks. However, the Division’s well production facility data 

(Exhibit RR) indicates that the tank VOC uncontrolled emissions do not correlate with fugitive emissions 

from well production facilities. The correlation coefficient is 0.19 indicating a weak positive correlation 

among the well production facilities and tank VOC uncontrolled emissions. For example, one tank had 

uncontrolled VOC emissions of 1,000 TPY, while the well production facilities accompanying the tank 

had a reported 2.4 TPY of VOC uncontrolled emissions. Regardless, the Division is requiring LDAR 

monitoring at various frequencies based on tank VOC uncontrolled emissions levels, and this section 

provides an estimate of the costs of these requirements to industry. 

Louis Berger estimated LDAR inspection costs for well production facilities with a similar approach as 

described above for tanks. The Division has indicated that well production facilities would take on 

average 4.75 hours to inspect, which is consistent with Louis Berger’s estimate of two facilities could be 

inspected per day in the non-attainment area. However, it is assumed that facilities in the attainment 

area would require an additional hour for travel time due to more remote operations and greater 

distance to access operations. Table 12 summarizes these assumptions for well production facilities. 

$0

$5,000

$10,000

$15,000

$20,000

$25,000

 -

 10,000

 20,000

 30,000

 40,000

 50,000

 60,000

 70,000

Year 1 Year 2 Year 3 Year 4

Dollars Per Ton

TPY

Year

All

Greater than 50

12 to 50 TPY

6 to 12 TPY

All

Greater than 50

12 to 50 TPY

6 to 12 TPY

TPY VOCs Reduced

Dollars / Ton

JIWG-REB EX. B
Page 20

Table 12: Well Production Facility LDAR Cost Assumptions (2013$)

LDAR AVO

Item Estimated 

Cost Annualized* Unit Cost Estimated Cost Annualized* Unit Cost

Capital and Non-Recurring Costs

 Camera $122,000 $28,179 $70.45/inspection 

in the AA and 

NAA

 Vehicle $30,000 $6,929 $17.32/inspection 

in the AA and 

NAA

 Program set up costs 

 (i.e., Tagging, software, 

 travel, etc.)

$1,000 $231 $231/WPF $500 $115.49 $115.49/WPF

Inspection, Operations and Maintenance costs

Assume one camera can inspect 2 well production facilities a day in the AA and NAA, 400 WPF/year; 10 weeks for repair and 

training. Assume monthly inspections for all tanks between 6 and 50 TPY. 

 Inspection Labor, 

 including travel time

 Hourly Rate: 

 Inspection and Travel 

 Time (NAA) 

 Inspection and Travel 

 Time (AA) 

$150 

4.75 

5.75 

$150/hour 

4.75 hours

5.75 hours

$100 

.5

.5

$100/Hour 

0.5 Hours

0.5 Hours

 Camera/Inspection 

 training 

$7,500 Per 100 WPF $7,500 $7,500/100 

WPF/year

 Camera repair $12,500 Camera $12,500/ 

camera/

year

 Travel and per diem 

 costs (NAA Condensate 

 and Crude Oil)

 Travel and per diem 

 costs (AA Condensate)

$30 

$40 

Inspection $30/inspection 

$40/inspection 

 Supervision $100 

(annual, 

quarterly)

$200 

(monthly)

WPF $100/WPF/year

$200/WPF/year

 Compiling data, record- 

 keeping and reporting 

$1,530 

(annual, 

quarterly)

$3,060 

(monthly)

WPF $1,530/ 

WPF/year

$3,060/ 

WPF/year

*Camera and set up costs annualized at 5% over 5 year-life of the equipment. 

Similar to the storage tank analysis, data on costs to repair components for well production facilities 

were obtained from Nelson and Brown (2012).8 The initial and subsequent year leak frequency rates 

were assumed to be 1.7 percent and 0.4 percent, respectively, consistent with the Trihydro report 

(2014) and Clearstone Engineering (2013) study. The number of components was consistent with the 

 

8 Nelson, Bradley and Heather Brown. 2012. Equipment Leak Emission Reduction and Cost Analysis for Well Pads, 

Gathering and Boosting Stations, and Transmission and Storage Facilities Use Emission and Cost Data from the 

Uniform Standards. Memorandum to Greg Nizich and Bruce Moore, EPA. April. See attachments 3 and 4. 

JIWG-REB EX. B
Page 21

analysis in the EPA technical memorandum, based on the well pad model plant 2, with an average 

number of components of 592.

9 As shown in the Division’s analysis of its 40 well production facilities

(Exhibit RR), the uncontrolled emissions of the tanks do not correlate with the components and 

uncontrolled emissions of the well production facilities. Additionally, information on 40 well production 

facilities does not provide a representative sample of well production facilities across the state, 

accounting for facilities in only five counties. As a result, without further information on the well 

production facilities, we used a constant number of components and uncontrolled emissions factors for 

all the well production facilities based on the EPA technical report (2011), consistent with information 

obtained from communications with industry representatives. 

LDAR costs for well production facilities for the first year were estimated by Louis Berger using the 

approach described above to be $136.7 million, of which 81 percent of the cost is attributed to well 

production facilities in the non-attainment area. For each of the various tank uncontrolled emissions 

levels, the costs per well production facility are greater in the attainment area when compared to those 

in the non-attainment area. However, when averaged across all the facilities, since there are more 

higher cost tanks (in the 12-50 TPY and over 50 TPY) in the non-attainment area than in the attainment 

area, the per well production facility cost is actually higher in the non-attainment area. The LDAR costs 

are summarized in Tables 13.1 and 13.2. 

 

9 EPA. 2011. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, 

Transmission, and Distribution: Background Technical Support Document for Proposed Standards. See Table 8.3.

JIWG-REB EX. B
Page 22

Table 13.1: Well Production Facility LDAR Cost Analysis for the Initial Year, Part 1

Tank

Uncontrolled 

VOC Emissions

Monitoring 

Requirement

Number of 

WPF 

Number of 

inspections/

Year 

Capital Costs 

for Inspections 

(annualized) 

(1)

Annual Costs 

for Inspections 

(2)

Number of 

Cameras 

Needed

Attainment Area WPF 

Less than 6 TPY One-time and 

monthly AVO 849 849 $368,662 $2,854,293 2 

6 to 12 TPY annually 328 328 $142,428 $1,105,560 1 

12 to 50 TPY quarterly 324 1,296 $226,003 $1,994,460 3 

Greater than 50 monthly 169 2,028 $236,549 $2,456,385 5 

Total - 1,670 4,501 $973,641 $8,410,698 11 

Non-Attainment WPF

Less than 6 TPY One-time and 

monthly AVO 1,986 1986 $862,381 $6,363,085 5 

6 to 12 TPY annually 1,085 1,085 $471,140 $3,479,663 3 

12 to 50 TPY quarterly 2,597 10,388 $1,811,512 $14,348,800 26 

Greater than 50 monthly 809 9,708 $1,038,928 $8,900,035 25 

Total - 6,477 23,167 $4,183,961 $33,091,583 59 

All WPF 

Less than 6 TPY One-time and 

monthly AVO

 

2,835 

 

2,835 $1,231,043 $9,217,378 7 

6 to 12 TPY annually 1,413 1,413 $613,568 $4,585,223 4 

12 to 50 TPY quarterly 2,921 11,684 $2,037,515 $16,343,260 29 

Greater than 50 monthly 978 11,736 $1,275,477 $11,356,420 30 

Total - 8,147 27,668 $5,157,602 $41,502,281 70 

JIWG-REB EX. B
Page 23

Table 13.2: Well Production Facility LDAR Cost Analysis, Part 2

Tank

Uncontrolled 

VOC Emissions

Monitoring 

Requirement

Annual 

Number of 

Leaks 

Leak Repair 

Costs (3)

Re-monitoring 

Cost (4)

Total Initial 

Year LDAR

Costs for WPF 

(1+2+3+4)

Per WPF Cost 

for Initial Year

Attainment Area WPF

Less than 6 TPY One-time and 

monthly AVO

 

8,544 $1,121,444 $1,927,816 $6,272,214 $7,388 

6 to 12 TPY annually 3,301 $433,255 $744,786 $2,426,029 $7,396 

12 to 50 TPY quarterly 13,043 $1,711,886 $2,942,814 $6,875,164 $21,220 

Greater than 50 monthly 20,410 $2,678,785 $4,604,959 $9,957,162 $58,918 

Total - 45,298 $5,945,371 10,220,376 $25,530,568 $15,288 

Non-Attainment Area WPF

Under 6 TPY One-time and 

monthly AVO 19,987 $2,623,307 $3,710,106 $13,558,880 $6,827 

6 to 12 TPY annually 10,919 $1,433,177 $2,026,921 $7,410,900 $6,830 

12 to 50 TPY quarterly 104,545 $13,721,509 $19,406,134 $49,287,955 $18,979 

Greater than 50 monthly 97,701 $12,823,297 $18,135,806 $40,898,067 $50,554 

Total - 233,153 $30,601,290 $43,278,968 $111,155,802 $17,162 

All WPF

Under 6 TPY One-time and 

monthly AVO 28,531 $3,744,751 $5,637,922 $19,831,094 $6,995 

6 to 12 TPY annually 14,220 $1,866,432 $2,771,707 $9,836,929 $6,962 

12 to 50 TPY quarterly 117,588 $15,433,395 $22,348,948 $56,163,119 $19,227 

Greater than 50 monthly 118,111 $15,502,082 $22,740,765 $50,855,229 $51,999 

Total - 278,451 $36,546,661 $53,499,344 $136,686,370 $16,778 

Similar to the storage tank STEM analysis, following the initial implementation of a LDAR program, leak 

frequencies decrease, and as a result, the number of leaking components also decrease along with 

repair and re-monitoring costs, when compared to the initial year. Therefore, in subsequent years, the 

number of leaks was adjusted to reflect the reduced leak frequency (0.4%). As a result, reduced leak 

repair and re-monitoring costs with the adjusted number of leaks were estimated and shown in table 

14. The total LDAR costs for subsequent years include the capital, and inspection and O&M costs in 

table 13 with the adjusted leak repair and re-monitoring costs in table 14. The exception is for well 

production facilities with tanks less than 6 TPY, which have been adjusted to include costs for a one-time 

LDAR inspection and monthly AVO. 

JIWG-REB EX. B
Page 24

Table 14: Subsequent Year LDAR Cost Analysis for Well Production Facilities

Tank

Uncontrolled 

VOC Emissions

Monitoring 

Requirement

Number of 

Well 

Production 

Facilities

Annual 

Number 

of Leaks

Leak Repair 

Costs (3) 

Re-monitoring 

Cost (4) 

Total 

Subsequent 

Year LDAR

Costs for 

WPF 

(Annual 

Cost) 

(1+2+3+4) 

Per WPF 

Cost in 

Subsequent 

Years 

(Annual 

Cost)

Attainment Area Well Production Facilities

Less than 6 TPY One-time with 

monthly AVO 849 4,021 $263,869 $0 $892,542 $1,051 

6 to 12 TPY annually 328 777 $101,942 $175,244 $1,525,174 $4,650 

12 to 50 TPY quarterly 324 3,069 $402,797 $692,427 $3,315,687 $10,234 

Greater than 50 monthly 169 4,802 $630,302 $1,083,520 $4,387,239 $25,960 

Total - 1,670 12,669 $1,662,780 $2,858,398 $10,120,642 $6,060 

Non-Attainment Area Well Production Facilities

Less than 6 TPY One-time with 

monthly AVO 1,986 9,406 $617,249 $0 $2,087,856 $1,051 

6 to 12 TPY Annually 1,085 2,569 $337,218 $476,923 $4,764,943 $4,392 

12 to 50 TPY quarterly 2,597 24,599 $3,228,590 $4,566,149 $23,955,051 $9,224 

Greater than 50 monthly 809 22,989 $3,017,246 $4,267,248 $17,223,458 $21,290 

Total - 6,477 59,562 $6,583,055 $11,056,253 $48,031,308 $7,416 

All Well Production Facilities

Less than 6 TPY One-time with 

monthly AVO 2,835 13,427 $881,118 $0 $2,980,398 $1,051 

6 to 12 TPY Annually 1,413 3,346 $439,160 $652,167 $6,290,117 $4,452 

12 to 50 TPY quarterly 2,921 27,668 $3,631,387 $5,258,576 $27,270,738 $9,336 

Greater than 50 monthly 978 27,791 $3,647,549 $5,350,768 $21,610,697 $22,097 

Total - 8,147 72,231 $8,245,834 $13,914,651 $58,151,950 $7,138 

To better estimate the potential uncontrolled emissions from these facilities, uncontrolled emission 

factors from the well pad model number 2 were used from the EPA technical document.

10 As described 

above, the tank uncontrolled emissions factors do not correlate with uncontrolled emissions associated 

with the well production facilities.

11 Additionally, the Division has utilized a very small sample of the well 

production facilities in the state for its analysis. As a result, Louis Berger used the VOC uncontrolled 

emissions per well production facility of 2.56 TPY associated with well pad model number 2 (592 

components), which we believe more accurately reflects the types of facilities operating in Colorado 

based on communication with industry representatives. Table 15 summarizes the uncontrolled 

emissions for well production facilities. 

 

10 See EPA (2011) previously cited, tables 8-2, 8-3, and 8-10. 11 See Division’s analysis of 40 well production facilities in Exhibit RR in the rulemaking documents.

JIWG-REB EX. B
Page 25

Table 15: Uncontrolled Emissions for Well Production Facilities

Uncontrolled VOC 

Emissions for Well 

Production 

Facilities

Monitoring 

Frequency

Number of Well 

Production 

Facilities

Uncontrolled VOC 

Emissions per Well 

Production Facility

(TPY)

Total Uncontrolled 

VOC Emissions 

(TPY)

WPF in the Attainment Areas

Less than 6 TPY One time and AVO 849 2.560 2,173 

6 to 12 TPY annually 328 2.560 840 

12 to 50 TPY quarterly 324 2.560 829 

Greater than 50 monthly 169 2.560 433 

Total - 1,670 - 4,275 

WPF in the Non-Attainment Area

Less than 6 TPY One time and AVO 1,986 2.560 5,084 

6 to 12 TPY annually 1,085 2.560 2,778 

12 to 50 TPY quarterly 2,597 2.560 6,648 

Greater than 50 monthly 809 2.560 2,071 

Total - 6,477 - 16,581 

All WPFs

Less than 6 TPY One time and AVO 2,835 2.560 7,257 

6 to 12 TPY annually 1,413 2.560 3,618 

12 to 50 TPY quarterly 2,921 2.560 7,477 

Greater than 50 monthly 978 2.560 2,504 

Total - 8,147 - 20,856 

Louis Berger again uses an approach which utilizes a Canadian study, described above, and assumes an 

across the board reduction of 75.3 percent of uncontrolled emissions in the initial year with a one-time 

and annual LDAR program. The quarterly LDAR program is assumed to reduce emissions in the initial

year by 76.5, consistent with the report by Trihydro (2013), and monthly LDAR is assumed to be even 

more effective, reducing emissions by 80 percent in the initial year. The average initial year cost per ton 

of VOC reduced across all well production facilities was estimated to be $8,590 per ton. 

As with the STEM program, subsequent emission reductions in future years are expected to be much 

lower than in the initial year. The emission reductions in subsequent years are assumed to decline by 

the same proportion as the decline in leak frequency (0.4/1.7). The emission reductions were then 

divided by total annual costs in subsequent years to estimate the cost per ton of VOC reduced. In 

subsequent years, the average cost is $19,354 per ton of VOC reduced, approximately twice the initial 

year cost. Since uncontrolled emissions per well production facility are assumed constant across all of 

the tank uncontrolled emissions levels, the costs per tons of VOC reduced increase significantly with the 

higher tank VOC uncontrolled emissions levels (greater than 50 TPY) as more monitoring is required of 

these facilities. The cost per ton of VOC reduced for well production facilities is $45,855 in subsequent 

years for the greater than 50 TPY, while 12 to 20 TPY facilities incur a cost of $20,261 per ton of VOC 

reduced in subsequent years. 

JIWG-REB EX. B
Page 26

When comparing across the geographies, the costs per ton reduced are approximately $1,000 more in 

the attainment area when compared to costs in the non-attainment area. Table 16 and Figure 2 shows 

the initial and subsequent year total costs, emission reductions, and cost per ton of VOC reduced. 

Table 16: Well Production Facility LDAR Cost per Ton of VOC Reduced 

Tank

Uncontrolled 

VOC Emissions

LDAR Costs

Emission 

Reduction 

from LDAR

LDAR Cost Per 

Ton of VOC 

Reduced

Annual LDAR 

Costs

Emission 

Reductions

with LDAR

Recurring 

LDAR Annual 

Cost Per Ton 

of VOC 

Reduced

Initial Year Subsequent Years 

Attainment Area WPF 

Less than 6 TPY $6,272,214 1,637 $3,832 $892,542 164 $5,454 

6 to 12 TPY $2,426,029 632 $3,837 $1,525,174 149 $10,252 

12 to 50 TPY $6,875,164 635 $10,835 $3,315,687 149 $22,208 

Greater than 50 $9,957,162 346 $28,769 $4,387,239 81 $53,872 

Total $25,530,568 3,250 $7,857 $10,120,642 543 $18,633 

Non-Attainment Area WPF 

Less than 6 TPY $13,558,880 3,828 $3,542 $2,087,856 383 $5,454 

6 to 12 TPY $7,410,900 2,092 $3,543 $4,764,943 492 $9,682 

12 to 50 TPY $49,287,955 5,086 $9,691 $23,955,051 1,197 $20,018 

Greater than 50 $40,898,067 1,657 $24,684 $17,223,458 390 $44,181 

Total $111,155,802 12,663 $8,778 $48,031,308 2,462 $19,513 

Total WPF

Less than 6 TPY $19,831,094 5,465 $3,629 $2,980,398 547 $5,454 

6 to 12 TPY $9,836,929 2,724 $3,611 $6,290,117 641 $9,815 

12 to 50 TPY $56,163,119 5,720 $9,818 $27,270,738 1,346 $20,261 

Greater than 50 $50,855,229 2,003 $25,390 $21,610,697 471 $45,855 

Total $136,686,370 15,913 $8,590 $58,151,950 3,005 $19,354 

JIWG-REB EX. B
Page 27

Figure 2: Well Production Facilities LDAR Costs and Emission Reductions Over Time

LDAR Costs for Compressor Stations

Louis Berger estimated LDAR costs for compressor stations with a similar approach as described above 

using the Division’s estimates of the number of compressor stations affected by the proposed 

regulations. Louis Berger assumed two and four days per inspection for small and large compressor 

stations, respectively. Table 17 summarizes these assumptions. 

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

$45,000

$50,000

 -

 2,000

 4,000

 6,000

 8,000

 10,000

 12,000

 14,000

 16,000

 18,000

Year 1 Year 2 Year 3 Year 4

Dollars Per Ton

TPY

Year

All

Greater than

50

12 to 50 TPY

6 to 12 TPY

less than 6 TPY

All

Greater than

50

12 to 50 TPY

6 to 12 TPY

less than 6 TPY

Dollars / Ton

TPY VOCs Reduced

JIWG-REB EX. B
Page 28

Table 17: Compressor Station LDAR Cost Assumptions (2013$)

Item Estimated Cost Annualized* Unit Cost

Capital and Non-Recurring Costs

 Camera $122,000 $28,179 $282 per inspection

for small CS and $564 

for large CS

 Vehicle $30,000 $6,929 $69 per inspection

for small CS and $139 

for large CS

 Program set up costs (i.e., 

 Tagging, software, travel, 

 etc.)

$13,688 for small 

compressor stations, 

and $27,272 for large 

CS 

$1,319 for small CS 

and $2,627 for large 

CS 

$1,319/small CS and 

$2,627/large CS

 Assume inspections would take 2 days to inspect for smaller facilities, 100 inspections with one 

 camera per year; inspections would take 4 days for larger facilities, 50 inspections with

 one camera per year. 

 

Inspection, Operations and Maintenance costs

 Small CS with Annual LDAR $6,468 $6,468/year/CS 

 Large CS with Quarterly LDAR $32,683 $32,683/year/CS

 Travel and per diem costs $32 $32/Inspection

 Supervision $200 $200/CS

 Camera Repair $12,500 $12,500/year/camera 

 Camera Training $7,500 $7,500 per 100 CS

 Record-keeping and 

 reporting of comments

$1,530 for small CS

$3,060 for large CS

$1,540/small CS

$3,060/large CS

*Camera and vehicle costs annualized at 5% over 5 year-life of the equipment. Program set up costs are annualized 

over 15 years at 5%. 

Similar to the previous analysis, data on costs to repair components were obtained from Nelson and 

Brown (2012).12 The initial year leak frequency rate was assumed to be 1.17 percent, consistent with the 

Trihydro study (2014). The number of components was assumed to be 2,544 for small compressor 

stations and 6,744 for large compressor stations. Cost assumptions for repairs and re-monitoring are 

similar to those described above. 

Tables 18.1 and 18.2 summarize the LDAR costs for compressor stations. LDAR costs for 200 compressor 

stations were estimated to be $15.4 million. Small compressor stations are estimated to incur $26,353 

per facility in the initial year, while larger compressor stations would incur $217,599 per facility in the 

initial year. 

 

12 Nelson, Bradley and Heather Brown. 2012. Equipment Leak Emission Reduction and Cost Analysis for Well Pads, 

Gathering and Boosting Stations, and Transmission and Storage Facilities Use Emission and Cost Data from the 

Uniform Standards. Memorandum to Greg Nizich and Bruce Moore, EPA. April. See attachments 3 and 4. 

JIWG-REB EX. B
Page 29

Table 18.1: Compressor Stations LDAR Cost Analysis for the Initial Year, Part 1

Compressor 

Station 

Uncontrolled VOC 

Emissions

Monitoring 

Frequency

Number of 

Compressor 

Stations 

Number of 

Inspections/

Year 

Capital Costs 

for Inspections 

(annualized)

(1)

O&M Annual 

Costs for 

Inspections (2)

Number of 

Cameras 

Needed

Less than 12TPY annual 147 147 $204,321 $1,245,835 2 

12 to 50 TPY quarterly 53 212 $288,112 $1,978,238 5 

Greater than 50 monthly - - - - - 

Total - 200 359 $492,433 $3,224,073 7 

Table 18.2: Compressor Station LDAR Cost Analysis for the Initial Year, Part 2

Compressor 

Station 

Uncontrolled VOC 

Emissions

Monitoring 

Frequency

Number of 

Components

Annual 

Number 

of Leaks

Leak 

Repair 

Costs (3)

Re-monitor 

Costs (4)

Total Annual 

LDAR Costs 

for 

Compressor 

Stations 

(1+2+3+4)

Per 

Compressor 

Station Cost, 

Initial Year

Less than 12 annual 2,544 6,357 $834,416 $1,589,364 $3,873,936 $26,353 

12 to 50 TPY quarterly 6,744 24,305 $3,190,081 $6,076,344 $11,532,775 $217,599 

Greater than 50 monthly - - $0 $0 $0 - 

Total - 9,288 30,663 $4,024,497 $7,665,708 $15,406,710 $77,033 

Similar to the storage tank STEM analysis, following the initial implementation of a LDAR program, leak 

frequencies decrease, and as a result, the number of leaking components also decrease along with 

repair and re-monitoring costs, when compared to the initial year. Therefore, in subsequent years, the 

number of leaks was adjusted to reflect the reduced leak frequency (0.4%). As a result, reduced leak 

repair and re-monitoring costs with the adjusted number of leaks were estimated and shown in table 

19. The total LDAR costs for subsequent years include the capital, and inspection and O&M costs in table 

18 with the adjusted leak repair and re-monitoring costs in table 19. 

JIWG-REB EX. B
Page 30

Table 19: Compressor Station LDAR Cost Analysis for Subsequent Years 

Compressor 

Stations 

Uncontrolled VOC 

Emissions

Monitoring 

Frequency

Number of 

Components

Annual 

Number 

of Leaks

Leak 

Repair 

Costs (3)

Re-monitor 

Costs (4)

LDAR Costs 

for 

Compressor 

Stations in 

Subsequent 

Years 

(Annual 

Cost)

(1+2+3+4)

Per 

Compressor 

Station Cost, 

Subsequent 

Years 

Less than 12 annual 2,544 1,496 $196,333 $373,968 $2,020,457 $13,745

12 to 50 TPY quarterly 6,744 5,719 $750,607 $1,429,728 $4,446,685 $83,900 

Greater than 50 monthly - - - - - - 

Total - 9,288 7,215 $946,940 $1,803,696 $6,467,142 $32,336 

The Division has identified an average uncontrolled emission rate for compressor stations of 10.1 TPY of 

VOCs for small compressor stations and 16.4 for large compressor stations, respectively. Louis Berger 

used these assumptions for uncontrolled emissions for the analysis as summarized in Table 20. 

Table 20: Uncontrolled Emissions for Compressor Stations

Compressor 

Stations 

Uncontrolled 

VOC Emissions

Monitoring 

Frequency

Number of Compressor 

Stations 

Uncontrolled VOC 

Emissions per 

Compressor Station (TPY)

Total Uncontrolled VOC 

Emissions (TPY)

Less than 12 TPY annual 147 10.1 1,485 

12 to 50 TPY quarterly 53 16.4 869 

Greater than 50 monthly - - - 

Total - 200 - 2,354 

Similar to the analyses on storage tanks and well production facilities, Louis Berger again uses the 

emission reductions associated with annual LDAR from the Clearstone Engineering, Ltd. study, described 

above, which estimates 75.3 percent emissions reductions associated with the annual LDAR program. 

Quarterly LDAR monitoring is assumed to be slightly more effective, reducing emissions by 76.5 percent, 

consistent with declining leak frequencies documented in the Trihydro report (2014). 

As with tanks and well production facilities, Louis Berger accounts for subsequent year emission 

reductions with LDAR for compressor stations. The emission reductions in subsequent years are 

assumed to decrease by the proportion based on the reduction in leak frequency (0.4/1.7). The 

subsequent year costs were then divided by emission reductions in subsequent years to estimate the 

cost per ton of VOC reduced. Initial year cost per ton of VOC reduced is $8,641, while in subsequent 

years, the cost per ton of VOC reduced increases to $15,416. Table 21 shows the initial year and 

subsequent year total costs, emission reductions, and cost per ton of VOC reduced. 

JIWG-REB EX. B
Page 31

Table 21: Compressor Station LDAR Cost per Ton of VOC Reduced in Initial and Subsequent Years

Compressor 

Stations VOC 

Uncontrolled 

Emissions

LDAR Costs Emissions 

Reductions

Cost Per Ton 

of VOC 

Reduced 

Annual LDAR 

Costs

Emission 

Reductions 

Annual Cost 

Per Ton of 

VOC Reduced

Initial Year Subsequent Years

Less than 12 TPY $3,873,936 1,118 $3,465 $2,020,457 263 $7,681 

12 to 50 TPY $11,532,775 665 $17,344 $4,446,685 156 $28,421 

Greater than 50 - - - - - - 

Total $15,406,710 1,783 $8,641 $6,467,142 420 $15,416 

Expanding Low Bleed Pneumatics Requirements Statewide

The Division is proposing to expand statewide the regulatory requirements mandating the use of low 

bleed pneumatic controls that were adopted for the nonattainment area in 2008. This section estimates 

the cost of the requirement to industry. 

Under the proposed rules, high-bleed pneumatic controllers shall be replaced or retrofitted with lowbleed pneumatic devices by May 1, 2015. It is assumed that the Division would define a low-bleed 

pneumatic device as one that emits less than or equal to 6 standard cubic feet per hour (scfh), while 

high-bleed devices bleed at a rate greater than 6 scfh. The Division has estimated that 9,877 highbleed pneumatic devices are being utilized outside the nonattainment area. Louis Berger utilizes 

this estimate of the number of devices that will need to be replaced to comply with the proposed 

rule. 

The EPA through their Natural Gas Star Program, has evaluated the effectiveness of reducing methane 

emissions through the replacement of high-bleed pneumatic devices with low-bleed pneumatics. In the 

document titled, “Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas 

Industry”, EPA provides estimates of costs, service life, benefits and decision process for determining the 

feasibility of replacing high-bleed pneumatics.13 The costs of several models of pneumatic devices are 

summarized in Appendix B and range from $380 to $3,500 in 2006 dollars. In addition, EPA reported the 

average cost of a low-bleed pneumatic device of $2,553 in 2008 dollars. Based on this information, Louis 

Berger assumes the cost of low-bleed pneumatic devices averages $2,775 adjusted to 2013 dollars. In 

addition, the analysis assumes a service life of 5 years14 and cost are annualized at a 5 percent interest 

rate. 

Replacement of pneumatic devices would require an initial assessment of the devices used at various 

facilities. The EPA suggests that a system-wide or facility-specific pneumatic survey would need to 

record for each device “location, function, make and model, condition, age, estimated remaining useful 

 

13U.S. EPA, “Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry”, 

October, 2006. 

14 U.S. EPA, “Options for Reducing Methane Emissions from Pneumatic Devices in the Natural Gas Industry”, 

October, 2006. 

JIWG-REB EX. B
Page 32

life, and bleed rate characteristics (volume and whether intermittent or continuous).”i Louis Berger has 

estimated the cost of conducting a pneumatic survey in the cost of the regulatory mandate as 

summarized in Table 22. Total cost of the mandate is estimated to be $32 million. 

Table 22: Estimated Cost of Low-Bleed Pneumatic Devices

Item Estimated Cost Annualized*

Capital and Non-Recurring Costs

Low-Bleed Pneumatic Devices $2,775 $641 

Pneumatic Survey $500 $115 

Total Cost $3,275 $756 

 *Annualized at 5% over a five year service life.

Replacing high-bleed pneumatics with low-bleed devices will likely result in gas savings and the value of 

these savings per device are estimated in Table 23. Payback period is estimated to be 2.8 years. 

Table 23: Gas Savings Associated with Low-Bleed Pneumatic Devices

Estimated Annual Bleed 

Emission Reductions 

(Methane) (Tons)ii

Gas Volume (Mcf) Gas Price 

($/Mcf)

Value of Gas 

Recovered

(1) (2) = (1)*40.49 Mcf/ton (3) (4) = (3) * (2)

6.65 269 $4.34 $1,168 

Recovered Product Estimates Attributable to proposed STEM and LDAR Requirements

In their analysis of cost effectiveness of LDAR requirements, the Division “...assumes that the costs 

savings from additional product capture will be equal or greater than the cost of repair and reinspection.”15 In order to test the validity of this assumption, Louis Berger estimated the product 

savings that can be expected from LDAR requirements for well production facilities and compressor 

stations. 

Gas Savings Attributed to LDAR – Well Production Facilities

Product savings attributable to the LDAR program as it relates to well production facilities in the initial 

year are estimated as shown in Table 24. Column 1 shows that 15,913 tons of VOCs are estimated to be 

detected and captured by the LDAR program for all well production facilities in the initial year of the 

program (see Table 16). Louis Berger used a Gas/VOC ratio (22.4%) reported by the Division in their 

analysis of LDAR costs of well production facilities to estimate the amount of gas that would be captured 

by the controls. In this case, 71,040 tons of gas is expected to be captured by the LDAR program at well 

production facilities in the initial year. The gas mass was then converted to a volume metric using a 

 

15Colorado Air Quality Control Commission 2014. Updated Economic Impact Analysis for Proposed Revisions to 

AQCC Regulations Number 7. Submitted with Pre-Hearing Statement on January 6, 2014. Page 17.

JIWG-REB EX. B
Page 33

natural gas density factor and results in 2,876,121Mcf of gas recovered. The value of the recovered gas 

was estimated at $12.4 million for the initial year using a recent natural gas price of$4.34 Mcf. The 

value of the product savings equates to 8.8 percent of the total LDAR costs ($136 million) for the initial 

year of implementation. 

Table 24: Product Savings Attributable to the LDAR Program for Well Production Facilities for the 

Initial Year

Tons of VOCs 

Captured by 

LDAR Program at 

WPF 

Average 

Gas/VOC Ratio1

Tons of Methane 

Captured by 

LDAR Program 

for WPF (Tons)

Natural Gas 

Volume 

Recovered 

(MCF)2

Natural Gas Price 

($/Mcf)3

Value of 

Recovered Gas

(1) (2) (3) = (1) / (2) (4) = (3)/0.0247 

ton/mcf (5) (6) = (4) * (5)

15,913 22.4% 71,040 2,876,121 $4.34 $12,482,363 

1 Taken from the Division's calculation on LDAR costs for well production facilities. Spreadsheet titled "APCD-PHS EXRR.xlsx"; sheet: statewide wells model FAC. 

2 Natural gas volumes calculated by assuming a gas density of 0.791 kg/m3 and converted to English units.

3 Henry Hub Natural Gas Spot Price for December, 2013. Obtain from the Energy Information Agency at 

http://www.eia.gov/dnav/ng/hist/rngwhhdm.htm. 

For subsequent years, the LDAR program at well production facilities is expected to realize product 

savings though they are expect to decline from the initial year. An estimate of the amount and value of 

the product saved is estimated as shown in Table 25. Using the same approach as used for the initial 

year, the amount of natural gas expected to be recovered in subsequent years is estimated to be 

543,125 Mcf and is valued at $2.3 million which is less than four percent of the total annual LDAR costs 

in subsequent years. 

Table 25: Product Savings Attributable to the LDAR Program for Well Production Facilities for 

Subsequent Years

Tons of VOCs 

Captured by 

LDAR Program at 

WPF 

Average 

Gas/VOC Ratio1

Tons of Methane 

Captured by 

LDAR Program 

for WPF (Tons)

Natural Gas 

Volume 

Recovered 

(MCF)2

Natural Gas Price 

($/Mcf)3

Value of 

Recovered Gas

(1) (2) (3) = (1) / (2) (4) = (3)/0.0247 

ton/mcf (5) (6) = (4) * (5)

3,005 22.4% 13,415 543,125 $4.34 $2,357,161 

1 Taken from the Division's calculation on LDAR costs for well production facilities. Spreadsheet titled "APCD-PHS EXRR.xlsx"; sheet: statewide wells model FAC. 

2 Natural gas volumes calculated by assuming a gas density of 0.791 kg/m3 and converted to English units.

3 Henry Hub Natural Gas Spot Price for December, 2013. Obtain from the Energy Information Agency at 

http://www.eia.gov/dnav/ng/hist/rngwhhdm.htm. 

JIWG-REB EX. B
Page 34

The Division’s assertion that product captured and sold would offset costs of repair and re-monitoring is 

not supported by this analysis. Well production facility LDAR repair and re-monitoring costs in the initial 

year are estimated to be $90.0 million (see table 13), while the value of the recovered gas is estimated 

to be $12.4 million in the initial year, or 13.8 percent of the repair and re-monitoring cost. In subsequent 

years, the value of the gas recovered would offset 10.9 percent of the repair and re-monitoring costs. 

Gas Savings Attributed to LDAR – Compression Stations

Gas savings attributable to the LDAR program as it relates to compressor stations in the initial year are 

estimated as shown in Table 26. The amount of gas that is expected to be detected and captured by a 

successful LDAR program at compressor stations during the initial year is 322,260 Mcf and is valued at 

$1.3 million. This value represents 8.6 percent of the total cost of the LDAR program during the initial 

year. It is worth noting that Louis Berger believes the estimated product savings for compressor stations 

may be conservatively high. This opinion is based on the likelihood that the gas/VOC ratio is not as high 

for compressor stations as it is for well production facilities. 

Table 26: Product Savings Attributable to the LDAR Program for Compressor Stations for the Initial 

Year

Tons of VOCs 

Captured by 

LDAR Program 

for Compressor 

Stations 

Average 

Gas/VOC Ratio1

Tons of Methane 

Captured by 

LDAR Program 

for Compressor 

Stations (Tons)

Natural Gas 

Volume 

Recovered 

(MCF)2

Natural Gas Price 

($/Mcf)3

Value of 

Recovered Gas

(1) (2) (3) = (1) / (2) (4) = (3)/0.0247 

ton/mcf (5) (6) = (4) * (5)

1,783 22.4% 7,960 322,260 $4.34 $1,398,608 

1 Taken from the Division's calculation on LDAR costs for well production facilities. Spreadsheet titled "APCD-PHS EXRR.xlsx"; sheet: statewide wells model FAC. 

2 Natural gas volumes calculated by assuming a gas density of 0.791 kg/m3 and converted to English units.

3 Henry Hub Natural Gas Spot Price for December, 2013. Obtain from the Energy Information Agency at 

http://www.eia.gov/dnav/ng/hist/rngwhhdm.htm. 

For subsequent years, the LDAR program at compressor stations is also expected to generate gas savings 

though these savings are expected to decline from the initial year. An estimate of the amount and value 

of the project saved is shown in Table 27. The amount of natural gas expected to be recovered in 

subsequent years is estimated to be 1,875Mcf and is valued at $329,453 which represents 5 percent of 

total annual costs of the program in subsequent years. 

JIWG-REB EX. B
Page 35

Table 27: Product Savings Attributable to the LDAR Program for Compressor Stations for Subsequent 

Years

Tons of VOCs 

Captured by 

LDAR Program for 

Compressor 

Stations 

Average Gas/VOC 

Ratio1

Tons of Methane 

Captured by 

LDAR Program for 

Compressor 

Stations (Tons)

Natural Gas 

Volume 

Recovered (MCF)2

Natural Gas Price 

($/Mcf)3

Value of 

Recovered Gas

(1) (2) (3) = (1) / (2) (4) = (3)/0.0247 

ton/mcf (5) (6) = (4) * (5)

420 22.4% 1,875 75,911 $4.34 $329,453 

1 Taken from the Division's calculation on LDAR costs for well production facilities. Spreadsheet titled "APCD-PHS EX-RR.xlsx"; 

sheet: statewide wells model FAC. 

2 Natural gas volumes calculated by assuming a gas density of 0.791 kg/m3 and converted to English units.

3 Henry Hub Natural Gas Spot Price for December, 2013. Obtain from the Energy Information Agency at 

http://www.eia.gov/dnav/ng/hist/rngwhhdm.htm. 

The Division’s assertion that product captured and sold would offset costs of repair and re-monitoring is 

not supported by this analysis. Compressor station LDAR repair and re-monitoring costs in the initial 

year are estimated to be $11.7 million (see table 13), while the value of the recovered gas is estimated 

to be $1.4 million in the initial year, or 12.0 percent of the repair and re-monitoring cost. In subsequent 

years, the value of the gas recovered would also offset only 12.0 percent of the repair and re-monitoring 

costs. 

Indirect Costs of Regulations on Small Operators and Marginally Producing Wells

In order to gain an understanding of the potential indirect costs to businesses, in particular small 

businesses, if the proposed rules were implemented, Louis Berger evaluated the impacts on small 

operators and marginally producing wells within the state. Evaluation of historical production and well 

count data maintained by the Colorado Oil and Gas Conservation Commission (COGCC) indicates that 

25,463 conventionally completed wells produce approximately 1.57 million barrels of oil per month 

(BOPM) or on average two barrels of oil per day as of mid-year 2013. These marginally producing wells 

represent over half (55 percent) of the total producing wells in the state (46,495) as of 2013. Given the 

likelihood that smaller operations would be negatively impacted by the increased costs of the proposed 

rules and regulations as well as the large percentage of these wells that occur within the state, small and 

marginally producing operations are the focus of this analysis. 

Louis Berger first evaluated the economic limit (in barrels per day) that marginally producing wells 

would realize under current economic and regulatory conditions. The economic limit is defined as the 

point that production levels are no longer economic given a number of factors (price of oil, lease costs, 

tax rates, etc.). Relevant assumptions for this analysis are as follows: 

• Current Rate of Production – 2 BOPD

• Oil Price - $90 ($/BO)

• Severance Tax Rate – 5%

JIWG-REB EX. B
Page 36

• Net Return on Investment (NRI) (well income minus royalties) – 80%

• Lease Operating Expense ($/well/month) (includes ad valorem taxes) - $900

• Number of Tanks per lease – 2 

• Number of Wells per lease – 4 

• Production Decline Rate – 2.5%

The economic limit in barrels of oil per day (BOPD) was calculated for wells using the following equation. 

Economic Limit (BOPD) = Lease Operating Expense (LOE)________ _

 (Oil Price) * (30.4 days) * (NRI * (1- severance tax))

Implementation of the new air quality rules would have an impact on lease operating expenses for each 

well. The increase costs would change the economic limit for each well as shown in Figure 3. Under 

current economic and regulatory conditions, the economic limit for marginally producing wells was 

estimated to be 0.43 BOPD. In other words, when production falls below 0.43 BOPD, the well is no 

longer economic and will be shut it or plugged. If lease operating costs increase, the economic limit 

increases, causing wells to be shut in earlier than planned. This leads to oil left in place as shown in 

Figure 3. 

Figure 3: Oil Production Loss with an Increase in the Economic Limit

JIWG-REB EX. B
Page 37

The amount of production that would result under different economic limits was calculated as follows. 

Remaining Oil = (Qi – Qf) * 365____

 Limit (1 – Decline Rate)

Where:

Qi = Current Production Rate = 2 BOPD

Qf = Calculated Economic Limit

Louis Berger estimated the economic limit for marginally producing wells if the air regulations relevant 

to oil and gas operations were implemented as proposed by the Division. The STEM costs for tanks and 

the LDAR costs for well production facilities were included as additional monthly unit costs in the lease 

operating expenses, increasing these costs for operators. The results are summarized in Table 19. 

Changes in lease operating costs due to the regulations were estimated for different sizes of facilities. 

Costs are expected to increase from $22 to $1,290 per month with an average of $729 for all facilities. 

The increase costs are expected to increase the economic limit from 0.44 to 1.05 BOPD, depending on 

the size of facilities. 

The additional cost burden would result in as much as 128.6 million barrels of oil being left in place and 

not produced over time. Assuming a price per barrel of oil is $90, this would equate in $11.6 billion in 

lost revenue to producers, $2.3 billion in lost royalties and $579 million in lost severance taxes. Present 

values for these losses are $1.9 billion in lost revenue, $384 million in lost royalties and $96 million in 

lost severance taxes.16

 

16 Present value analysis assumed a 10 percent discount rate over 60 years. 

JIWG-REB EX. B
Page 38

Table 28: Evaluation of Impacts of Air Regulation Costs on Marginally Producing Wells

Item 

Oil and Gas Leases

Base Case WITH WPF & TANK

less than 6

WITH WPF & TANK

s>=6 to <=12

WITH WPF & TANK

s>12 to <= 50

WITH WPF & TANK

>50

WITH WPF & TANK

TOTAL

LOE ($/well/month) $900 $900 $900 $900 $900 $900 

Additional LOE with new rules 

($/well/month) $0 $22 $565 $743 $1,290 $729 

Total LOE ($/wee/month) $900 $922 $1,465 $1,643 $2,190 $1,629 

Economic Limit (BOPD) 0.43 0.44 0.70 0.79 1.05 0.78 

Remaining Oil (BO) 22,594 22,442 18,679 17,442 13,652 17,543 

Estimated Oil Shut In (BO) - 152 3,914 5,151 8,942 5,051 

Facility Allocation - 0.35 0.17 0.35 0.12 1 

Production Lost (BO) - 1,353,302 16,944,548 45,908,655 27,321,315 128,611,449 

Lost Royalties ($) - $24,359,432 $305,001,869 $826,355,781 $491,783,676 $2,315,006,074 

Lost Severance Taxes ($) - $6,089,858 $76,250,467 $206,588,945 $122,945,919 $578,751,519 

*Values in the table have not been discounted and reflect revenues and costs over the life of the well. 

JIWG-REB EX. B
Page 39

Costs to Division to Implement Proposed Rules

The Economic Impact Analysis requires an assessment of the cost for the Division to implement the 

proposed rule changes. Oversight of an LDAR program, STEM plans, and annual report review of 5,312 

tank batteries, 5,312 well production facilities, and 200 compressor stations with possibly hundreds of 

thousands of components would require additional Division manpower. Louis Berger reviewed the 

revised (November 21, 2013) Regulations 3, 6 and 7 to understand the implementation costs to the 

Division associated with the new rules. A summary of potential cost implications for the Division, as 

result of the rule changes, is provided in Table 29. The rationale for the estimated additional costs or 

cost savings is provided after the table. 

Table 29: Summary of Potential Implementation Costs to the Division with Proposed Changes in 

Regulation 3, 6, and 7

Regulation Subpart Description Cost Impact Estimated Savings/Cost

Regulation 3

Minor Source Permits Facilities with emissions less than the 

APEN no longer have to file for a minor 

source permit. 

Cost Savings An estimated 882 hours per 

year in labor would be saved 

from not having to review 

and approve minor source 

permits.

Standardization of de 

minimis Reporting Threshold

The de minimis reporting threshold 

would be set to a standard of 250 

pounds per year. This increases the 

clarity of reporting requirements.

Cost Savings An undetermined amount of 

savings would be realized by 

the Division. 

Crude Oil Storage Tank 

Permitting

Additional permits would now be 

required for crude oil tanks as the tank 

permitting exemptions are removed. 

Cost Increase An estimated 128 hours per 

year in additional labor would 

be required to review and 

approve permits. 

Regulation 6

Adoption of NSPS OOOO This regulation adopts NSPS OOOO. No 

additional impacts beyond the minimum 

required by federal law would occur. 

No Impact No Impact

Regulation 7

Evaluation of Operation and 

Maintenance of Air Pollution 

Control Equipment

The Division would be required to make 

determinations on the acceptableness 

of operating and maintenance 

procedures used to control Air Pollution 

Control Equipment.

Cost Increase An estimated 1,062 hours per 

year in additional labor would 

be required to review and 

monitor o&m procedures.

Approval of STEM Plans The Division would be required to 

review and approve STEM plans for 

compliance with regulatory 

requirements. 

Cost Increase An estimated 5,600 hours in 

additional labor would be 

required for review and 

approval of STEM plans.

JIWG-REB EX. B
Page 40

Ongoing Management of 

STEM Program

The Division would incur labor costs for 

review of records that would be 

retained by each operator or owner as 

part of their STEM plan compliance. 

Cost Increase An estimated 1,062 hours per 

year in additional labor would 

be required.to manage the 

STEM program

Division Approval of 

Monitoring Devices or 

Methods

When the Division is required to 

approve monitoring devices or methods 

not mentioned in these regulations it is 

anticipated that additional labor costs to 

the Division would occur. 

Cost Increase An undetermined additional 

cost would be incurred by the 

Division. 

Recordkeeping Requirements The owner or operator of each facility is 

required to keep records of various tests 

and repairs. It anticipated that the 

Division would review a percentage of 

these records annually. 

Cost Increase An estimated 1,062 hours per 

year in additional labor would 

be required.

Reporting Requirements Each owner or operator is required to 

submit an annual report summarizing 

the inspection and maintenance 

activities of all facilities during the 

previous year. It is anticipated that the 

Division would review a percentage of 

these annual reports. 

Cost Increase An estimated 2,125 hours per 

year in additional labor would 

be required to review annual 

reports.

Venting Recordkeeping 

Requirements

Each owner or operator is required to 

record venting statistics and make them 

available to the Division upon request. 

Additionally, the Division may be called 

upon to make a determination on the 

visibility of venting. It is anticipated that 

the Division would commit a certain 

amount of time annually to reviewing 

these venting records and making 

visibility determinations on venting 

events. 

Cost Increase An estimated 2,125 hours per 

year in additional labor would 

be required for review and 

monitoring.

The following section provides an explanation of the implementation cost analysis summarized in Table 

29 for each proposed rule change. 

Regulation 3

Minor Source Permits

Under Regulation 3, the Division is proposing that NSPS OOOO affected facilities with uncontrolled 

actual emissions that are less than the APEN and minor source permit thresholds no longer 

automatically have to file APENs and obtain minor source permits. As such, it expected that the Division 

would realize an implementation cost savings with this proposed rule change. As a result of this revision, 

up to 441 facilities would be exempt from submitting an APEN. If it is assumed that it requires two 

hours to process each APEN application, then this rule change could save the Division up to 882 hours of 

processing time. This would allow the Division to reallocate permitting resources to more complicated 

sources with greater impact to Colorado air quality, as well as develop and maintain other guidance and 

compliance assistance tools.

JIWG-REB EX. B
Page 41

Standardization of de minimis Reporting Threshold

The Division is proposing to revise method (Part A, Appendix A) for determining non-criteria reportable 

pollutant de minimis levels in order to standardize the de minimis reporting threshold and set a 250 

pounds per year threshold for all non-criteria reportable pollutants, regardless of the pollutant, height 

of release point or distance to property boundary. This revision increases regulatory clarity and reduces 

the administrative reporting burdens on both sources and the Division by simplifying the process. This 

revision is therefore anticipated to reduce costs to the Division though it is uncertain what the cost 

savings would be for this rule change. 

Crude Oil Storage Tank Permitting

The Division is proposing to remove the crude oil storage tank permitting exemptions in Part B, Section 

II.D.1.n. and Part C, Section II.E.3.ddd. It is estimated that up to 64 additional crude oil tanks would be 

required to obtain a permit under this revision. If it is assumed that it takes approximately two hours to 

review and issue each permit, it is anticipated that this would result in up to 128 hours of additional 

labor for the Division each year to implement this rule. 

Regulation 6

This regulation adopts NSPS OOOO; therefore, this rule makes NSPS OOOO enforceable under Colorado 

law and is not anticipated to impose additional requirements beyond the minimum required by federal 

law. The revised changes to this regulation are not anticipated to impact regulation implementation 

costs to the Division. 

Regulation 7

It is anticipated that several new provisions of the revised Regulation 7 would require owners or 

operators of facilities to prepare reports and documentation or perform tasks that would require 

review, approval and inspection by the Division. These additional tasks are expected to result in an 

increase in the implementation costs to the Division. 

Evaluation of Operation and Maintenance of Air Pollution Control Equipment

The revised regulations would require that air pollution control equipment be maintained and operated 

in a manner consistent with good air pollution practices. A determination on whether or not acceptable 

operating and maintenance procedures are being used at a facility would be based on information 

provided to the Division by the owner or operator of the facility. This information could include, but 

would not be limited to: monitoring results, opacity observations, review of operating and maintenance 

procedures, and inspection of the source. The requirement for the Division to make a determination on 

the acceptability of operating and maintenance procedures is expected to take 2 hours per facility per 

year. The Division has reported that there are 5,312 facilities that would be affected by this rule. If it is 

assumed that the Division would review approximately 10 percent of these records annually, then the 

rule change would require an additional 1,062 labor hours per year for implementation. 

JIWG-REB EX. B
Page 42

Approval of STEM Plans

Owners or operators of storage tanks would be required to develop, certify and implement a Storage 

Tank Emission Management System (STEM) plan to identify appropriate strategies to minimize 

emissions from venting at thief hatches (or other access points to a storage tank) and pressure relief 

devices during normal operation under the revised Regulation 7. It has been estimated that 

approximately 5,312 storage tanks under the revised regulations would have to meet the STEM 

requirements. Assuming that a STEM plan could be developed for sites with multiple tanks (2), at most, 

2,800 STEM plans would be developed and require review by the Division. Assuming the Division would 

review and approve each plan and it would require 2 hours per review would result in an additional 

5,600 hours to initially review and approve the individual STEM plans, resulting in additional 

implementation costs as a result of the revised regulation. 

Ongoing Management of STEM Program

As each owner or operator of a storage tank subject to section XII.D or XVII.C under the revised 

regulation must maintain records of STEM, including the plan, any updates, and the certification; and as 

these records should be made available to the Division upon request, it is anticipated that the Division 

would incur additional implementation costs as a result of this requirement. Further document 

retention requirements under the revised regulation would include retention of the AIRS ID for the 

storage tank; the date and duration of any period where the thief hatch, pressure relief device, or other 

access point are found to be venting hydrocarbon emissions; the date and duration of any period where 

the air pollution control equipment is not operating, or where a flare or other combustion device is 

being used; the date and result of any Method 22 test, as well as the timing of and efforts made to 

eliminate venting, restore operation of air pollution control equipment, and mitigate visible emissions. 

While the Division is not required to review this information, the requirement for the retention of this 

information would allow it to be reviewed. It is anticipated that the Division would review 

approximately 10 percent of these records annually. As there would be at most 5,312 facilities under the 

revised regulations subject to these requirements and each would take an assumed 2 hours of review 

per set of records, this would require, at most, 1,062 hours per year, resulting in additional 

implementation costs as a result of the revised regulation.

Division Approval of Monitoring Devices or Methods

Under section XVII.F.6, the Division may be required to approve monitoring devices or methods not 

mentioned in these regulations, resulting in additional time and funding costs to the Division. 

Recordkeeping Requirements

As a result of recordkeeping requirements under the proposed regulation, the owner or operator of 

each facility subject to inspection and maintenance requirements under Section XVII.F is required to 

maintain documentation of the pre-start-up pressure tests for new well production facilities; date and 

site information for each inspection; a list of leaking components and monitoring method used to 

determine the presence of the leak; the date of the first attempt to repair the leak and additional 

JIWG-REB EX. B
Page 43

attempts; the date the leak was repaired; the delayed repair list; the date the leak was re-monitored to 

verify effectiveness of the repair and the results of re-monitoring effort; and a list of identification 

numbers for the components designated as unsafe or inaccessible to monitor, as well as an explanation 

for each component stating why the component was so designated and the plan for monitoring such 

components for a period of two years and make them available to the Division upon request. It is 

anticipated that the Division would review approximately 10 percent of these records annually. As there 

would be at most 5,312 facilities under the revised regulations subject to these requirements and it is 

assumed to take approximately 2 hours of review per set of records, this would require, at most, 1,062 

hours per year in additional labor. This would result in increased implementation costs of Regulation 7.

Reporting Requirements

In addition to recordkeeping, the owner or operator of each facility subject to the inspection and 

maintenance requirements in Section XVII.F would be required to submit a single annual report each 

year summarizing the inspection and maintenance activities at all of their subject facilities during the 

previous year. This report would contain at least the number of facilities inspected as well as the total 

number of inspections, leaks identified, categorized by component type and the number of leaks 

repaired. It would also require the identification of the number of leaks on the delayed repair list at the 

end of the calendar year. Additionally, each of these reports would be required to be accompanied by a 

self-certification form certifying the accuracy of the information in the report. It is anticipated that 

review of one annual report by the Division would require 4 hours. As there would be at most 5,312 

annual reports, depending on the ownership of individual facilities in the state of Colorado, this new 

requirement is anticipated to add an additional amount of 2,125 hours, at most, of labor to the Division 

each year. This would result in increased implementation costs of Regulation 7. 

Venting Recordkeeping Requirements

Records of the cause, date, time, and duration of venting events under Section XVII.H would be required 

to be kept and made available to the Division upon request under the revised regulation. Regarding 

visible emissions, the Commission expects that both Division inspectors and the regulated community 

will, if any smoke is observed, determine whether the emissions are considered visible emissions for 

purposes of Regulation Number 7. When the venting event records are reviewed by the Division or if 

the Division makes a determination on the visibility of emissions this would result in additional 

implementation costs as a result of the revised regulation. It is anticipated that the average time 

required to determine the visibility of emissions or review the records of a facility would be four hours 

per facility. As there would be, at most, 5,312 facilities that may require review by an inspector annually 

and assuming 10 percent of these facilities require monitoring per year it is anticipated that up to 2,125 

labor hours would be required. This would result in increased implementation costs of Regulation 7. 

JIWG-REB EX. B
Page 44

Conclusions

The net increase in the number of labor hours at the Division as result of the proposed regulations is 

anticipated to be approximately 12,282 labor hours annually. Notably, the Division would need 5,600 

hours to review and approve initial STEM plans required under Regulation 7, the largest estimated time 

commitment for the Division. This represents approximately 6.1 FTEs of additional staff for the Division 

to review, oversee, inspect, manage, and approve various requirements associated with the proposed 

rules. Therefore, Louis Berger concludes that the Division would incur significant additional net costs to 

implement the proposed requirements beyond current expenditures, contrary to the Division’s 

assertions to date. 

JIWG-REB EX. B
Page 45

Support of Industry’s Proposed Language

The results of the initial economic impact analysis presented here support the industry’s key suggested 

revisions to the Division’s proposed rule. Specifically, the proposed revisions will allow similar emission 

reductions to be achieved in a much more cost effective manner than the regulatory approach proposed 

by the Division. Key points to the analysis include: 

• Diminishing marginal benefits associated with LDAR programs implies increasing costs per ton of 

VOC reduced after initial rounds of inspections and repairs. Reducing the monitoring to reflect 

successful LDAR implementation reduces costs and improves the cost effectiveness of the 

proposed rule compared to the Division’s proposal while maintaining program integrity through 

realized emission reductions. The “step-down” of monitoring frequency, which rewards 

companies with four inspections with no leaks, is an example of how the industry changes to the 

proposed rule would provide incentives for industry to maintain compliance and reduce costs 

for good performance. 

• Generally, compliance costs of STEM and LDAR for small tanks and well production facilities are 

more burdensome than for larger facilities on a cost per ton basis. As such, requiring a one-time 

LDAR inspection and monthly AVO for all facilities (including all well production facilities) with 

uncontrolled emissions between 2 and 6 TPY would improve the overall cost effectiveness of the 

proposed rule by limiting the very high costs per ton of VOC reduced incurred by very small 

facilities with very small VOC fugitive emissions. 

• Compliance costs are higher for operations outside of the non-attainment area as the distance 

among facilities and tanks increases inspection travel time and expenses. Limiting the 

geographic scope to the non-attainment area will improve the cost effectiveness of the 

proposed rule. 

• Allowing for the use of other established technology, such as the tunable diode laser absorption 

technology (TDLAS), as an option for inspection monitoring, would reduce costs to industry with 

faster inspections, reduced camera training requirements, among other factors. 

 

JIWG-REB EX. B