# 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 16 th 

### 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

# 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 Statew ide

.................................................................. 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

### 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
estima tes 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 ef fectiveness 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 differ ing levels of uncontrolled emissions , with lower emitting tanks having a much higher cost per ton of VOC reduced than the higher emitting tanks.

### 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 G reater 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 G reater 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
G reater 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
G reater 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

L ess 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 G reater than 50

- - - - - - Total $15,406,710 $77,033 $8,641 $744,025 $3,720 $667 Subsequent Year LDAR Costs

L ess 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
G reater than 50

- - - - - - Total $6,467,142 $32,336 $15,41 6 $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.

### 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 p rograms 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 attainme nt 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 c ost 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 4Dollars Per TonTPY



### 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

### 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 LDA R 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 thous ands 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 numbe r 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 la rgest 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 Berge r 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 propo sed 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 th e 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

### Page 7 successful L DAR implementation reduce s costs and improve s 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 f or 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 uncontrol led em issions 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 h igher 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 traini ng requirements , among other factors

.

### 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 inc rease resulti ng 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 t o 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 wo uld 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. Of fice 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 )

.

Tab le 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 reduction s 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 r ule change and that by adding flares to these particular tanks, VOC
emi ssions would decline by 5,162 TPY

. Louis Berger analyz ed 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

### Page 9 W hen the costs are separate d by uncontrolled emissions , the differences ar e significant. For tanks with lower unc ontrolled 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
D ivision’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 Wate r 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

### 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 a n 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 t he LDAR costs using data and information obtained through an operator survey and follow up interviews. Table 6 summarizes the cost assumptions f or the analysis

.

### 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/
t ank

Inspection, Operations and Maintenance costs Assume one camera can inspect 2 tanks a day in the AA , 4 00 tanks /year ; 3 tanks per day in the NAA, 6 00 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
t anks /year Camera repair $12,500 Camera $12,500/

c amera/

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/t ank/
year
$200/t ank/
year Compiling data, record

- keeping and reporting $1,530 (annual, quarterly)

$3,060 (monthly) Tank $1,530/
t ank/year

$3,060/
t ank/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 estimate s of the number of component s , potential number of leaks, and average leak

### Page 12 frequency for production tank s. 3 

### Louis Berger assumed for this cost estimate that the typical production tank in Colorado has 38 component s ( 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 lab or 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

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

n on -a ttainment a rea and $640 in the a ttainment a rea

.

Table 7 : Repair and Re

- monitoring Cost Assumptions

Percent of Leaks Type of repair Repair T ime (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 bottle s, 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 attainme nt area and non

- attainment area over all the different types of tanks, costs per tank in the
attai nment area are approximately $1,000 higher than tanks in the non

- attainment . The higher costs in the attainment area due to longer travel time s and per diem costs
, as ability to perform fewer inspections on an annual basis. For the greater than 50 TPY ta nks, the STEM cost s are $23,676 per tank
in attainment area compar ed with the non

- attainment area STEM costs of $2 0 ,966 per tank

. The STEM costs are provided in Table s 8 .1 and 8.2

.

3 

### Clearstone Engineering, Ltd. 2013. Technical Report: Draft Update of Fugitive Equipment Emissions Factors. Prepared for the Canadian Associa tion 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

### Page 13 Table 8 .1 : Initial Year STEM Cost Analysis , P art 1

Tank Uncontrolled VOC Emissions Monitoring Requirement Number of Storage Tanks and C rude O il Tanks Number of inspections/ Year Capital C osts for I nspections

(annualized) (1) Annual C osts for I nspections , O&M

(2) Number of Cameras N eeded

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 - G reater 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

G reater 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

G reater 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

Gr eater 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

### Page 14 Table 8 .2 : Initial Year STEM Cost Analysis , P art 2

Tank Uncontrolled VOC Emissions Monitoring R equirement Buffer Bottle C osts (3) Annual Number of Leaks Leak R epair Costs (4) Re

monitoring

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

G reater 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

G reater 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

G reater 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

G reater 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

s ubsequent 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 o f 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.

### Page 15 Table 9 : Subsequent Year STEM Cost Analysis

Tank Uncontrolled VOC Emissions Monitoring Requirement Number of Storage Tanks

and C rude O il Tanks Annual Number of

Leaks Leak R epair 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

Gr eater 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

G reater 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 a nnually 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

G reater 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 a nnually 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

G reater 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 ).

### Page 16 Table 10 : Uncontrolled E miss ions for T anks

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

G reater 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

G reater 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

G reater 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 purposes 6 

### . 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

. E mission 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 indic a ted 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.

### Page 17 reductions captur ed in subsequent years would be consistent with this decline in leak frequency . For example, if STEM was assumed to reduce emission s by 100 TPY in the initial year, the subsequent emissions reductions would be 23.5 percent (0.4/1.7) of the initial reductio n.
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 c ost 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 ini tial 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 co sts 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 cost s per ton of VOC reduced.

Figur e 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, wit h 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).

### Page 18 Table 11 : STEM Cost s Per Ton of VOC Reduced

Tank Uncontrolled VOC Emissions STEM Costs Emission R eduction from STEM STEM Cost Per Ton of VOC

Reduced Annual STEM Costs Emission R eductions 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

G reater 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
G reater 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 4,35 7 $7,778
G reater than 50 $16,752,144 29,677 $564 $15,562,105 6,982 3 $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
G reater 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

### 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 emis sions 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 0.1 9 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.

Lou is 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, i t is assumed that facilities in the attainment area would require an additional hour for travel time due to more remote operations and greater dist ance 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 4Dollars Per TonTPY



### 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

### Page 20 T able 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, 4 00 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
t raining $7,500 Per 100 WPF $7,500 $7,500/100 WPF /year Camera repair $12,500 Camera $12,500/

c amera/

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, d ata on c osts to repair components for well production facilities were obtained from Nelson and Brown (2012). 8 

### The initial and subsequent year leak frequency rate s

w ere 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.

### Page 21 analysis in the EPA technical memorandum, based on the well pad model plant 2 , with an average number of component s of 592

. 9 

### As shown in the Division’s analysis of its 40 well production facilities (Exhibit RR) , the uncontrolled emissions of the tank s do not correlate with the components and uncontrolled emissions of the well production facilities. Additionally, infor mation 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, w e 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 co sts 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 Table s 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.

### Page 22 Tab le 13 .1 : Well Production Facility LDAR Cost Analysis for the Initial Year, P art 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

G reater 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

G reater 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

G reater 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

### Page 23 Table 13 .2 : Well Production Facility LDAR Cost Analysis, P art 2

Tank Uncontrolled VOC Emissions Monitoring R equirement Annual Number of

Leaks Leak R epair 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

G reater 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

G reater 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

G reater 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 s ubsequent 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 subs equent 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 c osts for a one

- time LDAR inspection and monthly AVO

.

### 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 R epair 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

G reater 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

G reater 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

G reater 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 emissio ns 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 product ion 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 representative s

. Table 15 summarizes the uncont rolled 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.

### Page 25 Table 15 : Uncontrolled E missions for Well Production Facilities

Uncontrolled VOC Emissions for Well Production

Facilities Monitoring F requency Number of Well Production

Facilities Uncontrolled VOC E missions per Well Production Facility (TPY) Total U ncontrolled VOC E missions (TPY)

WPF in the Attainment Area s 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

G reater 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

G reater 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

G reater 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 i nitial 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, s ubsequent emission reductions in future years are expected to be much lower than in the initial year. T he emi ssion reductions in subsequent years are assumed to decline by the same proportion as the decline in le a k 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 $45,85 5 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.

### Page 26 When comparing across the geographies, the costs per ton reduced are approximately $1,000 more in
the a ttainment area when compared to costs in the non

- attainment area. Table 1 6 and Figure 2 shows the initial and subsequent year total cost s, 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 R eduction from LDAR LDAR Cost Per Ton of VOC

Reduced Annual LDAR Costs Emission R eductions 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

G reater 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

G reater 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

G reater 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

### Page 27 Figure 2: Well Production Facilities LDAR Costs and Emission Reductions Over Time



## LDAR Costs for Compressor Stations

L ouis Berger estimated LDAR costs for compressor stations with a simila r 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 4Dollars Per TonTPY



### 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

### Page 28 Table 17 : Compressor Station LDAR Cost Assump tions (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 inspect ion s 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 ,5 00 $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, d ata on costs to repair components were obtained from Nelson and Brown (2012). 12 

### The initi al year leak frequency rate was assumed to be 1.1 7 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.

Table s 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.

### Page 29 Table 18 .1 : Compressor Stations LDAR Cost Analysis for the Initial Year , P art 1

Compressor

Station Uncontrolled VOC
Emissions Monitoring Frequency Number of
C ompressor

Stations Number of
I nspections/
Year Capital C osts for I nspections

(annualized) (1) O&M Annual
C osts for
I nspections (2) Number of
Cameras
N eeded

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

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

G reater than 50 monthly - - - - - Total - 200 359 $492,433 $3,224,073 7



### Table 18 .2 : Compressor Station LDAR Cost Analysis for the Initial Year , P art 2

Compressor

Station Uncontrolled VOC Emissions Monitoring Frequency Number of
C omponents Annual Number of Leaks Leak Repair
Costs (3) Re

- monitor
C ost s (4) Total Annual
LDAR Costs for Compressor

Stations (1+2+3+4) Per Compre ssor 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
G reater 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. Th e 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.

### Page 30 Table 19 : Compressor Station LDAR Cost Analysis for Subsequent Year s

Compressor

Stations Uncontrolled VOC Emissions Monitoring
F requency Number of
C omponents Annual Number of Leaks Leak Repair
Costs (3) Re

- monitor
C ost s (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
G reater 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

use d these assumptions for u ncontrolled emissions for the analysis as summarized in Table 20

.

Table 20 : Uncontrolled Emissions for Compressor Stations

Compressor

Stations Uncontrolled VOC Emissions Monitoring F requency Number of C ompressor Stations Uncontrolled VOC E missions per Compressor Station (TPY) Total U ncontrolled VOC E missions (TPY)

Less than 12 TPY annual 147 10.1 1,485

12 to 50 TPY quarterly 53 16.4 869

G reater than 50 monthly - - - Total - 200 - 2,354



### Similar to the analyses on storage tanks and well production facilities, Louis Berger again uses the emission reduction s 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 (2 014).

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 p er ton of VOC reduced increases to $15,416. T able 21 shows the initial year and subsequent year total cost s, emission reductions, and cost per ton of VOC reduced.

### 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 R eductions Cost Per Ton of VOC Reduced Annual LDAR Costs Emission R eduction s 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

G reater 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 i ndustry.

Under the proposed rules, high

- bleed pneumatic controllers shall be replaced or retrofitted with low

bleed 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 high

bleed 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 pneumati c 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 fea sibility 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 $2,55 3 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 years 14 

### and cost are annualized at a 5 percent intere st
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

13 

### U.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”, O ctober, 2006.

### 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 a s 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 Produ ct 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 re

inspection.” 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

15 

### Colorado 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.

### 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 P rogram for Well Production Facilities for the Initial Year

Tons of VOCs Captured by LDAR Program at WPF Average Gas/VOC Ratio 1 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 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.



### 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 P rogram for Well Production Facilities for Subsequent Years

Tons of VOCs Captured by LDAR Program at WPF Average Gas/VOC Ratio 1 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 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 En glish 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.

### 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 (s ee 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 off set 10.9 percent of the repair and r e- 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 P rogram for Compressor Stations for the Initial
Year

Tons of VOCs Captured by LDAR Program for Compressor Stations Average Gas/VOC Ratio 1 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 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.



### 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.

### Page 35 Table 27: Product Savings Attributable to the LD AR P rogram for Compressor Stations for Subsequent
Years

Tons of VOCs Captured by LDAR Program for Compressor

Stations Average Gas/VOC Ratio 1 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 En glish 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 tab le 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 an d re

- monitoring
costs.


## Indirect Costs of Regulations on Small Operators and Marginally Producing W ells

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 a verage 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 impac ted 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%

### 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 W ells 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 wor ds, 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 a s shown in Figure 3

.

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

### Page 37 T he amount of production that would result under different economic limits was calculated as follows.



## Remaining Oil = (Q i 

## – Q f 

## ) * 365

_

___ Limit (1 – Decline Rate) Where:

Q i 

## = Current Production Rate = 2 BOPD Q f 

## = 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 wer e included as additional monthly unit costs in the lea se 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 facil ities. 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 cos t 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.

### 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.

### Page 39 

## Costs to Division to Implement Proposed R ules

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 associate d 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 St orage 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.

### 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 Inc rease 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 ha ve 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.

### Page 41 Standardization of de minimis Reporting Threshold

The Division is proposing to revise method ( Part A, Appendix A ) for determining n on

- 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 thoug h 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 impo se additional requirements beyond the mi nimum 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 additi onal 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 d et ermination 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.

### Page 42 Approval of STEM Plans

Owners or operators of storage tanks would be required to develop, ce rtify 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 maintai n 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 o f 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 Divis ion 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 regula tion, 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

### 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 a nnually. 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 numbe r 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 rep orts 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 implementat ion 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 v enting 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

re quired 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.

### Page 44 Conclusions

The net increase in the number of labor hours at the Division as result of t he 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 Divisio n. 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 signi ficant additional net costs to implement the proposed requirements beyond current expenditures , contrary to the Division’s assertions to date.

### 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 co st 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 cost s per ton of VOC reduced after initial rounds of inspections and repairs. Reducing the monitoring to reflect successful LDAR implementation reduce s costs and improve s the cost effectiveness of the proposed rule compared to the Division’s proposal while maintaining program integrity through realized emission reduc tions

. 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 AV O 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 th e 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 o ption for inspection monitoring
, would reduce costs to industry with faster inspections, reduced camera training requirements, among other factors

.