## REGULATORY ANALYSIS

for Proposed Revisions to Colorado Air Quality Control Commission Regulation Numbers 3, 6 and 7 (5 CCR 1001-5, 5 CCR 1001-8, and CCR 1001-9)

February 11, 2014

Colorado Department of Public Health and Environment

Air Pollution Control Division 4300 Cherry Creek Drive South Denver, CO 802462/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page ii [this page is inten tionally left blank]2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page iii 

### Table of Contents

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

4 CLOSING SUMMARY............................................................................................ 572/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 1 

### 1 EXECUTIVE SUMMARY

The Colorado Air Pollution Control Division’s (“ Division’s”) proposed revisions to the Air Quality Control Commission’s (“Commission’s”) Regulation Numbers 3, 6, and 7, collectively expand the air emission control requirements on o il and gas facilities in Colorado. They were developed after the Division’s extensive, year -long stakeholder process leading up to the Commission’s rulemaking heari ng, including input from divers e industry, environmental and governmental stakeholders. The proposal ha s received the support of several industry and environmental leaders, including Anadarko Petrol eum, Noble Energy, Encana Oil and Gas, and the Environmental Defense Fund. The proposal a ffects not only the oil and gas industry and supporting businesses in Colorado, but the Regula tion Number 3 revisions broadly affect all businesses in Colorado. Further, the proposal broadly benefits all persons in Colorado, especially those who live and work in the pr oximity of oil and ga s operations, given the anticipated emissions reductions that will be ac hieved and the reasonable associated cost of implementation. The Division estimates that the pr oposed strategies will result in substantial reductions of hydrocarbon emissions from the oi l and gas industry. Mo re specifically, the Division estimates the proposed strategies will reduce volatile organic compound (VOC) emissions by 93,500 tons per year, and methane/et hane emissions by 64,000 tons per year. The Division conservatively estimates that the annual net costs to indus try of the Division’s proposal will be $42.4 million per year. This translates to approximately $453 per ton of VOC reduced, which is very reasonable when compared to ot her air pollution reducti on strategies adopted by

the Colorado Commission and the U.S. Environmen tal Protection Agency (EPA). In prehearing submittals to the Commission, the supporters of th e proposal have concluded that the Division’s costs estimates methodology and cost estimates ar e reasonable. Some opponents of the proposal have asserted that the costs may be much highe r. The Commission will consider the Division’s proposal and any alternate propos als at the rulemaking hearing commencing February 19, 2014.



### 2 INTRODUCTION

On December 13, 2013, interested pa rties, stakeholders, and state representatives filed eleven separate requests for both a Cost Benefit Analysis and a Regulatory Analysis (“Requests”) with the Division, per C.R.S. §24-4-103(2.5), C. R.S. §24-4-103(4.5) and the Commission’s Procedural Rules, 5 CCR 1001-1, §V.E.13. This document satisfies the requirements for a Regulatory Analysis, and is separate from the related Cost-Benefit Analysis. Similarly, this Regulatory Analysis is different from, but related to, the requ ired Economic Impact Analysis, C.R.S. §25-7-110.5(4). The Requests were specific to proposed revisions to the Commission’s Regulation Numbers 3, Parts A, B, and C (“Regulation 3”); Re gulation 6, Part A (“Regulation 6”); and Regulation Number 7 (“Regulation 7”).2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 2 The Colorado Administrative Procedure Act (“APA”) 1 serves as the legal authority for this rulemaking process, and sets forth requirements for both cost-benefit and regulatory analyses. Under the APA, any person may request an ag ency engaged in a rulemaking to prepare a regulatory analysis. 2 The regulatory analysis must include:

 A description of the classes of persons who will be affected by the proposed rule, including classes that will bear the costs of the proposed rule and classes that will benefit from the proposed rule;

 To the extent practicable, a description of the probable quantitative and qualitative impact of the proposed rule, economic or otherwis e, upon affected classes of persons;

 The probable costs to the agency and to a ny other agency of the implementation and enforcement of the proposed rule and a ny anticipated effect on state revenues;

 A comparison of the probable costs and benef its of the proposed rule to the probable costs and benefits of inaction;

 A determination of whether there are less co stly methods or less intrusive methods for achieving the purpose of the proposed rule; and

 A description of any alternative methods fo r achieving the purpose of the proposed rule that were seriously considered by the agency and the reasons why they were rejected in favor of the proposed rule.

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

must take into account both short- term and long-term consequences. 3
So long as the regulatory analysis is unde rtaken in good faith, it satisfies the APA. 4

This Regulatory Analysis evaluates the Divi sion’s November 15, 2013 proposed revisions to Regulations 3, 6, and 7, as amended on January 30, 2014, using informati on gathered through the Division’s Cost Benefit Analysis, and Econom ic Impact Analyses, and other documents

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

The Division’s proposed revisions to Regulation 3, 6, and 7 are part of an overall effort to fully adopt federal Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution found in 40 C. F.R. Part 60, Subpart OOOO (“NSPS OOOO”), by incorporating them into Regulation Number 6, Pa rt A, and making the co rresponding revisions to the Regulation Number 3 catch-all provisions to address barriers that prevented full adoption of NSPS OOOO. The proposal also revises Regulation Number 7 to address differences and overlaps between NSPS OOOO and Re gulation Number 7 oil and ga s control requirements, and to further reduce hydrocarbon emissi ons and leaks from oil and ga s facilities. These revisions

include:

1. Expanding Colorado’s adoption of NSPS OOOO, such that it is adopted in full (Regulation 6);

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

1 See C.R.S. § 24-4-101 et. seq

. 2 Id. at § 24-4-103(4.5)

3 Id.

4 Id. at § 24-4-103(2.5)(d) & § 24-4-103(4.5)(d).2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 3 3. Removing crude oil storage tank permitting exemptions (Regulation 3);

4. Expanding condensate tank cont rol requirements state-wide, including establishing storage tank emission monitoring (“STEM ”) requirements (Regulation 7);

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

6. Establishing leak detection and repair (“L DAR”) requirements for components at well production facilities and natural gas compre ssor stations state-wide (Regulation 7);

7. Establishing well maintenance and liquids unl oading requirements state-wide (Regulation 7); and

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

In addition to these more prominent revisions, th ese proposals also correc t minor administrative errors, and make typographical, grammatical, a nd formatting changes in Regulation 3, 6, and 7. This Regulatory Analysis focuses on the more significant revisions and does not address typographical, grammatical, and formatting changes.

This analysis represents information gathered from various stakeholders in an effort to generate the most complete and accurate assessment of the costs and benefits of th e proposed strategies. Where data was not reasonably avai lable, the Division utilized assu mptions that are set forth in this analysis.



### 3 ANALYSIS

3.1 Regulation Number 6

3.1.1 Proposed Revisions

The proposed revisions to Regulation 6 fully incorporate by reference the federal NSPS OOOO into Regulation Number 6, Part A, including the provisions not inco rporated during the Commission’s partial adoption. In late 2012, the Commission partia lly adopted the Standards of

Performance for Crude Oil and Natural Gas Pr oduction, Transmission, a nd Distribution found in 40 C.F.R. Part 60, Subpart OOOO (“NSPS OOOO”), su ch that Colorado currently administers NSPS OOOO, for all affected facilities unde r NSPS OOOO including centrifugal compressors, reciprocating compressors, pneuma tic controllers, storage vessels, process unit equipment, and sweetening units, except for natura l gas wells (well completion requi rements) and equipment that emits less than current reporting and permitting thresholds. At that time, the Commission

directed the Division to consider full adoption of NSPS OOOO, as well as other improvements to Colorado’s oil and gas emission regulations.

It appears that all parties to the Commission rulemaking support the pr oposed revisions to Regulation 6.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 4 3.1.2 Class of Persons Affected

“A description of the classes of persons who will be affected by th e proposed rule, including classes that will bear the costs of the proposed rule and classes that will benefit from the proposed rule.”

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

a federal level and the Commission has alr eady partially adopted NSPS OOOO for Colorado. The classes of persons affected by the proposed full adoption of NSPS OOOO include oil and gas companies operating in Colorado, and busines ses that support the o il and gas industry in Colorado. Also, citizens statewide are impacted by the proposal. In all cases, it is simpler and less confusing to no longer have to deal with fe deral and state agencies administering the same requirements.

Full adoption of NSPS OOOO does not have an addi tional cost impact on any affected classes of persons because this rule is currently in effect and federally enforceable. Full adoption of NSPS OOOO does not provide addi tional health or economic benefits to classes of persons affected by the proposal because NSPS OOOO is currently in effect and federally enforceable. However, affected classes of persons will benefit from the proposed full adoption of NSPS OOOO due to having Colorado implement and enforce NSPS O OOO for all sources subject to NSPS OOOO in

Colorado.

Further, full adoption of N SPS OOOO benefits the United Stat es Environmental Protection Agency (“EPA”) by relieving the agency of the primary responsibility to implement and enforce

NSPS OOOO in Colorado.

The Colorado Oil and Gas Conservation Comm ission (“COGCC”) does have well completion requirements that are different but similar to NSPS OOOO requirements. However this proposal to fully adopt NSPS OOOO does not change the fact that there are two di fferent requirements that may apply to natural gas we lls. The Division continues to work with the COGCC to address

this issue and coordinate im plementation of these rules.

3.1.3 Quantitative and Qualitative Impacts

“To the extent practicable, a description of the probable quantitative and qualitative impact of the proposed rule, economic or otherwis e, upon affected classes of persons.”

There are few if any additional quantitative impa cts of the Regulation 6 proposal because these rules are already in effect on a federal level. The qualitative impact of the proposed rule upon affected classes of persons includes Colo rado’s implementation and enforcement of NSPS OOOO, using Division staff much more familiar with Colorado’s oil and gas issues than EPA staff. Full adoption of NSPS OOOO does not provide any other additional costs or benefits beyond those affected by NSPS OOOO.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 5 3.1.4 Probable Agency Costs

“The probable costs to the agency and to any other agency of th e implementation and enforcement of the proposed rule and any anticipated effect on state revenues.”

The probable costs to the Division of implementing and enforcing the NSPS OOOO requirements for affected facilities below current Air Pollutant Emission Notice (“APEN”) reporting and minor source permitting thresholds, as well as implementing and enforcing the NSPS OOOO well completion requirements, are unknow n at this time. These sources are not currently subject to Colorado’s reporting and permitting requirements.

The Division will largely implement the provisions of its proposal through its oil and gas inspection team. This team currently consists of nine full time inspectors and four term limited inspectors. In 2012, in response to the growth in the oil and gas indus try in Colorado, the legislature approved increasing the size of the insp ection team from six inspectors to nine. In 2013, the legislature appropriated a dditional funds to hire four te rm limited inspectors to conduct IR camera inspections at well production faciliti es in Colorado. The term for these positions runs through June of 2015, but could be extended by the legislature if warranted. The additional inspectors provided during the 2012 and 2013 legisla tive sessions has significantly expanded the capabilities of the oil and gas inspection team , which will further en able the Division to implement and enforce the proposed requirement s if the Commission chooses to adopt the Division’s proposal. The total proj ected annual cost to the Divisi on for the oil and gas inspection team in fiscal year 2013-14 is $1,305,304, which incl udes salary costs, fringe benefits, operating costs (including vehicles, field equipment, and office equipment) , travel training and indirect

costs.

There is no anticipated effect on state revenues because the proposal does not assess any additional emissions reporting or permitting fees than those that already apply.

3.1.5 Comparison to Inaction

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

If the Commission does not fully adopt NSPS OO OO, EPA and the Division will continue to share the implementation and enforcement re sponsibilities for NSPS OOOO. However, regardless of partial or full a doption, NSPS OOOO remains effectiv e and federally enforceable.

Importantly, the Division does not advocate fu ll adoption of NSPS OOOO without removing the catch-all provisions in Regulation Number 3 due to the reporting and permitting impacts on both the regulated community and the Division.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 6 3.1.6 Less Costly Methods/Less Intrusive Methods

“A determination of whether there are less co stly methods or less intrusive methods for achieving the purpose of the proposed rule.”

There are no less costly or intrusive methods for achieving full adoption of NSPS OOOO. Retaining partial adoption of NSPS OOOO will not resolve the issue of shared implementation responsibilities between EPA and the Division.

3.1.7 Alternative Methods

“A description of any alternative methods for achieving the purpose of the proposed rule that were seriously considered by the agency and the re asons why they were rejected in favor of the proposed rule.”

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

OOOO.

3.1.8 Quantification of Data

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

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

The short and long term consequences of the full adoption of NSPS OOOO are full implementation and enforcement by Colorado, instead of split implementation and enforcement

between EPA and Colorado. The Division did no t further quantify the short- or long-term consequences of the Regulation 6 proposal to fully adopt NSPS OOOO beyond what was already performed by EPA.



### 3.2 Regulation Number 3

3.2.1 Proposed Revisions

The Division is proposing revisi ons to Regulation 3’s reporting and permitting requirements in order to improve the efficiency of Colorado’ s air quality reporting and permitting system.

The proposed revisions remove the requirement for sources subject to either a federal New Source Performance Standard (“NSPS”) or fede ral National Emission Standards for Hazardous Air Pollutant (“NESHAP”)/Maximum Availabl e Control Technology (“MACT”) adopted into Regulation Number 6, Part A or Nu mber 8, Parts A, C, D, and E to file an APEN and obtain a minor source permit regardless of whether th eir emissions exceed the reporting or permitting thresholds (“catch-all provisions”) . As a result, sources subject to a NSPS incorporated into Regulation Number 6, Part A or a NESHAP/MAC T incorporated into Regulation Number 8,2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 7 Parts A, C, D, or E are subject to APEN reporting and permitting only if their emissions exceed the applicable APEN and permitting thresholds.

In addition, the proposed revisions simplify the Appendix A non-criteria reportable pollutant de minimis determination to 250 pounds per year of a ny individual non-criteria reportable pollutant. The proposed revisions also remove the cr ude oil storage tank permitting exemptions.

Finally, the proposed revisions correct an inadvert ent error to the mi nor source permitting exemption for crude oil and condens ate truck loading equipment. This revision is administrative in nature, as the Division curre ntly implements the provision as it was originally intended.

It appears that all parties to the Commission rulemaking support the pr oposed revisions to Regulation 3, and some parties have submitted alternative proposals requesting additional revisions (see Section 3.2.7 in this Regulatory Analysis).

3.2.2 Class of Persons Affected

“A description of the classes of persons who will be affected by th e proposed rule, including classes that will bear the costs of the proposed rule and classes that will benefit from the proposed rule.”

The classes of persons affected by the proposed revisions to Regulation 3 are broad. Revisions to the catch-all provisions affect any stati onary source subject to an NSPS adopted into Regulation Number 6 or NESHAP /MACT adopted into Regulation Number 8 that has emissions below the APEN reporting and minor source permitting thresholds. To demonstrate the breadth of impact, some examples of business and indus try that are affected include dry cleaners, aggregate mining operations, grain elevators, natural gas compre ssor stations, surface coating operations, and power plants. T hose activities subject to an NSPS or NESHAP/MACT, whose emissions fall below current reporting and perm itting thresholds, will no longer have to report emissions and obtain minor source permits.

The proposed revisions to the non-criteria reportab le pollutant de minimis threshold will affect stationary sources with emissi ons of non-criteria re portable pollutants greater than 250 pounds per year. This revision also has a broad impact , as most sources emit some degree of hazardous air pollutants or other non-cr iteria reportable pollutants.

Further, the revisions to the crud e oil storage tank permit exempti ons affect owners and operators of crude oil storage tanks with capacities of 40,000 gallons or less. The correction to the minor source permitting exemption for crude oil a nd condensate truck loading equipment is

administrative in nature and aff ects oil and natural gas operations.

3.2.3 Quantitative and Qualitative Impacts

“To the extent practicable, a description of the probable quantitative and qualitative impact of the proposed rule, economic or otherwis e, upon affected classes of persons.”2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 8 Quantitative and qualitative consequences for each revision are discussed below. Short- and long-term consequences include the continued delay in adopting NSPS OOOO in full, as well as

other federal NSPS and NESHAP/M ACT that apply to small sources in Colorado. There are minimal if any costs to the regulated community due to these revisions, and in some cases, cost savings are anticipated. Further, the Division anticipates that there will be no significant environmental impact associated with the proposal.

3.2.3.1 Catch

‐ all Provisions There are no anticipated costs to either the regulated community or the government associated with these proposed revisions. Removal of the ca tchall provisions will actually reduce reporting, permitting, and associated cost burdens for the re gulated community. By reducing reporting and permitting activities, the proposed revision will also reduce costs to the Division associated with

these activities.

The Division conducted a permit tracking project from February, 2013 to September, 2013 to understand the impact of this propo sal. All pre-construction perm its issued were evaluated to determine if they would have required an APEN and permit under this pr oposal. The Division’s permit tracking project indicated that 7% ( 167 of 2,355) permits processed required permits solely due to the catch-all provision, account ing for approximately 0.03% of the total uncontrolled actual criteria pollu tant emissions and 0.003% of statewide uncontrolled actual criteria pollutant emissions. The total hourly permit processing fees for these permits was approximately $50,000. 5 This cost estimate does not include the time saved by the sources by no longer having to complete and submit an APEN or minor source permit application.

The environmental impacts of revising the catc h-all provisions are minimal. Further, no emissions increases are anticipated from these sources that would no l onger require a permit because these revisions will not exempt them from having to comply with the requirements of an applicable NSPS or NESHAP/MACT.

3.2.3.2 Non

‐ criteria Reportable Pollutants Some stationary sources affected by the propos ed revisions to the non-criteria reportable pollutant thresholds may have new costs rela ted to reporting emissions previously below reporting thresholds, including fili ng and annual fees. Revision of the threshold for non-criteria reportable pollutants could result in ether cost savings or additional costs to the regulated community depending on the source. Sources that are required to report hazardous air pollutants (a subset of non-criteria re portable pollutants) must pay an emission fee of $152.90 per ton. Currently Regulation Number 3 contains a co mplex reporting formula involving multiple and different thresholds, some of which are above and some of which are below the proposed 250 pound threshold. Accordingly, chan ging the threshold will reduce costs for some sources, while increasing costs for other sources. Based on an analysis of reported emissions, the proposed threshold change will reduce indus try fees paid to the Division by $47,702 per year. Because the emissions from sources that are not currently re porting is unknown it is not possible to calculate

5 Permit cost savings were calculated using an average of 4 hours spent per permit, as determined by the time spent on permits processed due to the catch-all provisions in the Division’s permit tracking project, multiplied by the Division billing rate of $76.45 an hour.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 9 the additional costs to sources that will be re quired to report for the first time under the new proposed threshold. Based on the relative prev alence of different emissions, however, the

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

Additionally, beyond the actual emi ssion fees, the current reporti ng system is very complex resulting in numerous hours bei ng spent by both the regulated community and Division staff in determining whether reporting is required. Si mplifying the reporting system will eliminate the costs associated with this analysis.

Some stationary sources affected by the proposed revisions would benefit because they would no longer be required to report thei r non-criteria reportable pollutant emissions, thus saving filing and possibly annual fees. The revised threshold of 250 pounds per year preserves at least 96% of

the Division’s current inventor y of non-criteria reportable pollu tants. Other sources may have new costs related to having to re port emissions that were previ ously below reporting thresholds, including filing and annual fees. This impact is unknown at this time because these sources are not currently subject to Colorado’s reporting and permitting requirements. While EPA does not require States to report hazardous air pollutant emissions, EPA util izes this data to annually populate the National Emissions I nventory. Accordingly, Colorado will continue to provide a robust set of data while also serving an im portant regulatory stream lining purpose.

3.2.3.3 Crude Oil Storage Tanks Owners and operators of crude oil storage tanks ma y have new costs related to obtaining permits for previously permit-exempt equipment. Ther e are minimal direct costs projected for the

affected businesses and industrial sector associated with the rem oval of the crude oil storage tank permitting exemption. Stationary sources with cr ude oil storage tanks whose uncontrolled actual emissions exceed the minor source or operating permit thresholds would be required to obtain a permit. In 2008, the Commission removed the reporti ng exemption for crude oil storage tanks to improve the inventory of uncontrolled actual emi ssions. While the Division believes there are many crude oil storage tanks in Colorado, the Division’s APEN inventory only identifies 64 crude oil storage tanks with a design capacity of 40,000 gallons or less in Colorado. Removal of the crude oil storage tank minor source permitti ng exemption would require these tanks to obtain minor source permits at a cost of approximately $19,500.

3.2.3.4 Minor Source Permitting Correction No practical impact is anticipat ed as a result of this revisi on, as the Division continues to implement the provision as was originally intended.

3.2.4 Probable Agency Costs

“The probable costs to the agency and to any other agency of th e implementation and enforcement of the proposed rule and any anticipated effect on state revenues.”

The Division does not anticipate any negative effect on state revenues. Any potential Full Time Equivalent (“FTE”) personnel savings will be re directed to addressing the current permitting backlog. Any loss in permitting fees, will be offs et by the processing of backlog permits. In2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 10 addition, the crude oil storage tank permitting exem ption revisions will slightly increase the submission of permitting fees. Similarly, the Division anticipates the reduction in filing and annual fees due to the approxima tely 4% reduction in current non- criteria reportable pollutant reporting to be offset by the incr eased reporting and associated fe es by stationary sources with non-criteria reportable pollutant emi ssions greater than 250 pounds per year.

3.2.4.1 Catch

‐ all Provisions The revisions to the catch-all provisions will reduce the administrative burden on both the Division and the regulated community. The Division estimated through the permit tracking project that the staffing of approximately 0.6 FTE would be saved due to the revisions. However, revising the catch-all provisions does no t change the applicability or enforcement of

the NSPS or NESHAP/MACT.

3.2.4.2 Non

‐ criteria Reportable Pollutants

The revisions to the non-criteria reportable pollutant threshold establish a simplified, standard reporting threshold of 250 pounds per year for al l non-criteria reportable pollutants. This eliminates the complicated matrix system and streamlines the process for sources, and for the Division, both in explaining the process to sour ces and reviewing reported emissions. The work associated with any increased reporting will be absorbed by existing Division staff or potentially offset by the approximately 4% reduction in cu rrent non-criteria reporta ble pollutant reporting.

3.2.4.3 Crude Oil Storage Tanks The Division’s APEN inventory currently identi fies 64 crude oil storage tanks with a design capacity of 40,000 gallons or less. The work as sociated with permitting and inspecting these, and potentially more, sources will be absorbed by existing Division staff.

3.2.4.4 Minor Source Permitting Correction There are no additional agency costs incurred as a result of this revision, as the Division continues to implement the provisi on as was originally intended.

3.2.5 Comparison to Inaction

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

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

Division would not recommend full adoption of NSPS OOOO. Furthe r, absent adoption of the proposed revisions to the catchall provisions , the Division’s permitti ng backlog will be negatively impacted. Finally, the public, regulated community, and other agencies will continue to experience the complexity and confusion of the APEN reporting th resholds and Appendix A de minimis levels applicability determinations . If the Commission does not adopt the proposed crude oil storage tank exemption revisions, a potentially significant source of emissions will continue to be exempt from permitting require ments. If the Commission does not make the minor source permitting correction, the provision w ill not align with the Commission’s intent at the time of adoption nor the Division’s current implementation of the pr ovision. The purposes of the proposed revisions to Regulation 3 incl ude allowing full a doption of NSPS OOOO,2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 11 streamlining and clarifying reporting and permitting, and requiring permits for a potentially significant source of emissions.

3.2.5.1 Catch

‐ all Provisions The revisions to the catch-all provisions re duce reporting and permitting costs. If the Commission does not adopt the pr oposed revisions, the regula ted community and the Division will retain those reporting and permitting costs. Further, if the Commission adopts NSPS OOOO, and other NSPS and NESHAP/MACT simila rly affecting very small sources, in full without removing the catch-all provisions, the in crease in APEN reporting and minor source permitting would overwhelm both the Divi sion and the regulated community.

3.2.5.2 Non

‐ criteria Reportable Pollutants

The revisions to the non-criteri a reportable pollutant threshol ds may reduce costs for some

sources and increase costs for other sources. However, all sources wi ll benefit from the increased clarity of the de minimis reporting de termination. If the Commission does not adopt the proposed revisions, the public, regulated comm unity, and the Division will continue to deal with a complex and confusing reporting determination.

3.2.5.3 Crude Oil Storage Tanks The costs of the proposed revisions to the crud e oil storage tank permit exemptions include the costs to the regulated community of obtaining pe rmits and the costs to the Division of permitting and inspecting subject tanks. Removing the permitting exemptions also increases the consistency of Colorado’s regulations with N SPS OOOO by requiring these sources to also be subject to Colorado’s no tification, recordkeeping, and contro l requirements. If the Commission does not adopt the proposed crude oil storage tank exemption revisions, there will not be costs associated with permitting but a potentially signifi cant source of emissions will continue to be exempt from permitting requirements.

3.2.5.4 Minor Source Permitting Correction No costs are anticipated with the proposed revisi ons, as the Division will continue to implement the provision as was originally intended.

3.2.6 Less Costly Methods/Less Intrusive Methods

“A determination of whether there are less co stly methods or less intrusive methods for achieving the purpose of the proposed rule.”

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

NSPS OOOO than the Division’s proposal.

3.2.6.1 Catchall Provisions

The Division believes that the revisions to the catch-all provisions are necessary to adopt NSPS OOOO, and other NSPS and NESHAP/MACT similarl y affecting very small sources, due to the anticipated extensive number of APENs and minor source permit applications that would be required. Consider how the current catch-all pr ovisions would apply if the Commission adopts MACT JJJJJJ, which applies to a multitude of sm all boilers. Under the catch-all provisions,2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 12 every boiler providing electricity, steam, or hot water in a hotel , restaurant, laundry, medical center, research center, institution of higher education, or manufacturing, processing, mining, or refining facility would be required to file an AP EN and obtain a minor source permit, even if the source had emissions less than the reporting and permitting thresholds. Other examples of rules similarly affecting very small sources include NSPS JJJJ, which applies to numerous stationary spark ignition internal combustion engines; MACT M, which applies to all perchloroethylene dry cleaning facilities; MACT HHHHHH, which applies to paint stripping and sp ray applications of greater than three motor vehicl es or mobile equipment; and MA CT SSSSSS, which applies to all glass manufacturing facilities. Under the current catch -all provisions, all of these facilities would require APENs and minor source permits, ev en if emissions are below the reporting and permitting thresholds.

If NSPS OOOO is adopted in full without the corresponding adoption of the proposed revisions to the catch-all provisions, the regulated commun ity will be required to file APENs and obtain minor source permits for every NSPS OOOO affected facility. In turn, the Division’s permitting backlog will likely grow and i ndustry’s ability to obtain timely permits will be negatively impacted. In comparison, if NSPS OOOO is adopted in full along with the proposed revisions to the catch-all provisions, only N SPS OOOO affected faci lities with emissions greater than the reporting and minor source permitting thresholds w ill be required to report emissions and obtain minor source permits. This is currently how the partial adoption of NSPS OOOO is implemented. Thus, the Division does not believe there are less costly or intrusive methods than the proposed catch-all provisions revisions to reduce the administ rative impact of full adoption

of NSPS OOOO.

Similarly, the Division does not believe there ar e less costly or intrus ive methods than the proposed catch-all provisions revisions to impr ove the efficiency of Colorado’s reporting and permitting system for NSPS or NESHAP/MACT s ubject sources with emissions below the reporting and permitting thresholds, especially sin ce these revisions will save costs for both the Division and the regulated community.

3.2.6.2 Appendix A The purpose of the revisions to the non-criteria reportable pollutant thres holds is to simplify a complex and confusing reporting determination.

The Division cannot quantify the costs of unknown non-criteria repor table pollutants but considers the true cost savings of the proposed revision to th e non-criteria repor table pollutant threshold the savings in time and effort of the public and regu lated community in determining applicability under the revised Appendix A. While so me sources non-criteria reportable pollutant reporting will increase, the Division does not believe ther e is a less costly or intrusive method to streamline the non-criteria reportable pollutant reporting dete rmination while still maintaining a robust non-criteria repo rtable pollutant inventory.

3.2.6.3 Crude Oil Tank Permit Exemption Requiring permits for crude oil storage tanks, a potentially significant source of emissions, cannot be accomplished in any less costly or less intrusive method. Further, some sources will2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 13 want enforceable permit limits on th eir crude oil storage tanks so as to be exempt from NSPS OOOO storage vessel requirements.

3.2.6.4 Minor Source Permitting Correction There are no less costly or no le ss intrusive methods, as the Divisi on will continue to implement the provision as was originally intended.

3.2.7 Alternative Methods

“A description of any alternative methods for achieving the purpose of the proposed rule that were seriously considered by the agency and the re asons why they were rejected in favor of the proposed rule.”

In addition to the Division’s proposal, various pa rties to the rulemaking have submitted different alternative proposals for the Commission to consider . Some of these proposals request that the Commission adopt additional requirements , increasing APEN reporting and permitting thresholds, as well as change how emi ssions are reported to the Division.

The Division considered revising the APEN and minor source permitting thresholds to further simplify and clarify APEN reporting and minor source permitting. However, the Division decided not to pursue revising the APEN and minor source permitting thresholds at this time, in order to avoid diverting focus from the importa nt emission reductions associated with the proposed revisions to Regulation Number 7, and provide additional time to work with EPA on the potential development of a sufficient nonin terference demonstration for such revisions.

Further, the Division considered alternative threshol ds for the proposed revisions to the noncriteria reportable th reshold. The Division selected the 250 pound per year threshold due to concerns about higher thresholds and the retention of approxi mately 96% of the Division’s current non-criteria reportable pollutant inventory under the proposed revision.

The Division did not consider any alternatives concerning the proposed revi sions to the crude oil storage tank permitting exemptions or the minor source permitting correction.

3.2.8 Quantification of Data

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

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

The Division quantified the short-term conse quences and used them to project long-term consequences of the Regulation 3 proposal.

3.2.8.1 Catch

‐ all Provisions The Division tracked all pre-construction perm its, which includes permits processed for point sources at both major stationary sources a nd minor sources, between mid-February and September, 2013. The permit tracking project indi cates that 7% (167 of 2,355) of those permits2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 14 processed required permits becau se of the catch-all provision. In addition, the potentially eliminated emissions in comparison to statewide emissions are all much less than 1%, as

illustrated in Table 1 below.

Table 1: Emissions from Sources Pote ntially No Longer Requiring Permits due to the Catch-all Revisions (State-wide)

Pollutant Uncontrolled actual emissions of potentially eliminated permits during

tracking project (tpy, %

of statewide emissions) Uncontrolled actual

emissions statewide 6 (tpy)

CO 45 (0.05%) 99,929 NOx 110 (0.07%) 165,192

Total PM 7 32 (0.0004%) 7,385,720 SO2 0.2 (0.0002%) 115,715 VOC 24 (0.005%) 469,396 TOTAL 211.2 (0.003%) 8,235,952

Further, 4% (87 of 2,355) of the permits processe d that required permits b ecause of the catch-all provision are in the nonattainment area (“NAA”). The potentially eliminated emissions in comparison to NAA emissions are also much less than 1%, as illustrated in Table 2 below.

Table 2: Emissions from Sources Pote ntially No Longer Requiring Permits due to the Catch-all Revisions (8-Hour Ozone NAA)

Pollutant Uncontrolled actual emissions of potentially eliminated permits during

tracking project in the NAA (tpy, % of NAA emissions) NAA uncontrolled actual

emissions 8 (tpy)

CO 19 (0.1%) 19,110 NOx 90 (0.24%) 37,831

Total PM 9 15 (0.003%) 441,084 SO2 0.1 (0.0004%) 23,994 VOC 5 (0.004%) 140,463 TOTAL 129.1 (0.02%) 662,482

Importantly, these tables represent point source emissions, and do not include mobile source or area source emissions. Therefore, the percentage of emissions potentially eliminated from

6 January-November, 2013, total emissions.

7 Includes PM, PM10, and PM2.5.

8 January-November, 2013, total emissions.

9 Includes PM, PM10, and PM2.5.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 15 permitting due to the removal of the catch-all pr ovisions is even less, if the total emissions inventory, including point, mobile a nd area source emissions, were used.

The revisions to the catch-all pr ovisions reduce costs to affected classes of persons, due to fewer sources being required to file APENs and obtain minor source permits. The Division’s permit tracking project shows that 7% (167 of 2,355) of the permits processed between mid-February and September, 2013, were permitted due to the catch-all provision. The total hourly permit processing fees for these permits was approximately $50,000 10 . This cost estimate does not include the time saved by the sources by no longer having to complete and submit an APEN or minor source permit application.

The environmental impacts of revising the catc h-all provisions are minimal and no emissions increases are anticipated because these revisi ons will not exempt any source from complying with the requirements of an applicable NSPS or NESHAP/MACT. The Division’s permit tracking project shows that th e 7% of permits processed between mid-February 14, and September 30, 2013, accounted for approximately 0.03% of the total uncontroll ed actual criteria pollutant emissions during the tracking projec t and 0.003% of statewid e uncontrolled actual criteria pollutant emissions. 11

3.2.8.2 Appendix A There are potential increased costs to the affected classes of persons associated with the revisions to Appendix A, however the full extent is unkno wn. This revision may increase the reporting requirements for a currently unknown quantity of Bin B and Bin C non-criteria reportable pollutants because the revised threshold is lowe r than the current lowest de minimis reporting thresholds of 500 and 1,000 pounds per year, respec tively. This revision may also decrease the reporting requirements for some Bin A pollutants becau se the revised threshold is higher than the current lowest de minimis reporting threshold of 50 pounds per year. Sour ces will save emission fees of $152.90 per ton of non-criteria reportabl e pollutant no longer required to report, not including the time saved by the sources due to not collecting the emissions data for and submitting APENs.

The environmental impacts of revising the catc h-all provisions are minimal and no emissions increases are anticipated because these revisi ons will not exempt any source from complying with applicable requirements. In addition, the Division estimat es that the proposed reporting thresholds of 250 pounds per year will retain at l east 96% of the Division’s current non-criteria reportable pollutant tracking for inventory purposes, which will continue to provide data to the EPA for the National Emissions Inventory, as well as to external custormers such as environmental groups and the public. In additi on, because the proposed reporting threshold is less than the current thresholds for many of th e current scenarios, the revision will result in

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

10 Permit cost savings were calculated using an average of 4 hours spent per permit, as determined by the time spent on permits processed due to the catch-all provisions in the Division’s permit tracking project, multiplied by the Division billing rate of $76.45 an hour.

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

of noninterference with the NAAQS.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 16 3.2.8.3 Crude Oil Tank Permit Exemption There are anticipated costs to the affected classe s of persons associated with the removal of the crude oil storage tank permitting exemptions. Th e Division’s APEN inventory currently only identifies 64 crude oil storage tanks with a desi gn capacity of 40,000 gallons or less in Colorado. Removal of the crude oil storage tank minor source permitting exemption would requires these tanks to obtain minor source permits at a cost of approximately $19,500.

The emissions from crude oil storage tanks can be significant and permitting exemptions are meant to be limited to emission points with neglig ible impacts on air quality. The environmental impacts of revising the crude oil storage tank permitting exemptions may be significant, however, due to data limitations that impact is known.

The short term consequences of the proposed catch-all revisions include allowing the Commission to fully adopt NSPS OOOO. The long term consequences of the proposed catch-all revisions include potentially allowing the Commission to adopt other NSPS and NESHAP/MACT similarly affecting very small sources.

The short term consequences of the proposed re visions to the non-criter ia reportable pollutant threshold include simplifying the non-criteria reportable pollutant reporting determinations for both the Division and the regulated community and reducing the Divi sion’s current non-criteria reportable pollutant inventory by approximately 4%. The long term consequences of the proposed revisions to the non-criteria reportable polluta nt threshold are unknown.

The short-term consequences of the proposed cr ude oil storage tank permit exemptions include requiring existing crude oil stor age tanks with a capacity of 40,000 gallons or less to obtain permits. The long term consequences of the pr oposed crude oil storag e tank permit exemptions include requiring new crude oil st orage tanks to obtain permits.

3.2.8.4 Minor Source Permitting Correction Short- and long-term consequences of the pr oposed correction include aligning the provision with the Commission’s original intent. No data was quantif ied relating to this revision.



### 3.3 Regulation Number 7

3.3.1 Discussion of Proposed Revisions

T he Regulation 7 rulemaking package proposes revi sions that expand existi ng oil and gas control requirements and establish additional monitoring , recordkeeping and repo rting requirements. These proposed revisions include the following:

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

a. Lowering the control requirement threshol d for condensate storage tanks from 20 to 6 tons per year of uncontrolled actual volatile or ganic compound (VOC) emissions;2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 17 b. Requiring controls for crude oil and produced water storage tanks with

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

and

c. Expanding NAA requirements for tank cont rols during the fi rst 90 days of production to the rest of the state; 2) Establishing requirements to ensure that emissions from controlled storage tanks are captured and routed to the control device; 3) Enhancing the existing cont rol program for dehys by:

a. Increasing the control requi rements from 90% to 95%;

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

c. Establising more stringent requirements for individual dehys located in proximity to a building unit or designa ted outside activity area; 4) Establishing LDAR requirements for compre ssor stations and well production facilities, including requirements to reduce emissions fr om compressor seals and open ended lines consistent with current federal requirements; 5) Expanding the existing 8-hour ozone NAA require ments for auto-igniters on flare devices to the rest of the state; 6) Expanding the existing NAA requirements for low bleed pneumatic devices to the rest of the state and where feasible requiring no-bleed pneumatic devices; and 7) Requiring that the gas stream at newly constr ucted well production fa cilities either be connected to a pipeline or r outed to a control device from the date of first production.

If adopted, these proposed revisions will result in substantial reduction of hydrocarbon emissions including volatile organic co mpounds (VOCs) and methane.

Several industry and environmental parties fully support the Division’s proposed revisions to Regulation 7. Conversely, some parties reque st that the Commission adopt additional requirements that go beyond the Division’s proposal, while other alternatives request that the Commission limit aspects of the Division’s pr oposed revisions. See Section 3.3.7 of this Regulatory Analysis for details on the pa rties’ alternative proposals.

3.3.2 Class of Persons Affected

“A description of the classes of persons who will be affected by th e proposed rule, including classes that will bear the costs of the proposed rule and classes that will benefit from the proposed rule.”

The proposal affects the oil and gas industry and supporting businesses in Colorado. Further, the proposal broadly benefits all persons in Colorado, especially those who live and work in the proximity of oil and gas operations. Companies that will bear the cost s of this rule change include the oil and gas companies operati ng, drilling, recompleting or otherw ise stimulating wells in the NAA, as well as well production facilities, comp ressor stations and de hys. Revisions to Regulation 7 may require installation of controls to reduce hydrocarbon emissions from storage tanks, dehys, and separators on newly constructed, hydraulically fractured or recompleted wells. Typically flares are used as control equipment, but vapor recovery units (“VRUs”) and other2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 18 Division-approved pollution preven tion devices may be used. Use of best management practices or controls may also be required for well maintenance and liquids unloading activities. Regulation 7 revisions may also require installation of auto-ign iters on combustion devices and

installation of low- or no-bleed pneumatic controllers. In add ition, compressor stations and well production facilities may be required to monitor components for emissions and repair leaks. Owners and operators of well production faciliti es or compressor stations that include compressor seals and open-ended lines may have to comply with additional work practice

standards.

The proposed Regulation 7 will benefit those comp anies that manufacture and/or distribute flare control devices, VRUs, auto-igniters or low- a nd no-bleed pneumatic controllers. Companies that manufacture hydrocarbon monitoring equipm ent, including infra-red (“IR”) cameras, photoionization detectors, flame i onization detectors and other Division-approved monitoring methods, as well as those companies that provi de or support monitoring services may also benefit from these proposed revisions.

Given that VOCs are precursors to ozone, the ci tizens in the NAA will benefit from the proposed rule through reduced ozone precursor emissions . State-wide, persons living or working in proximity to storage tanks, dehys, wells, well pr oduction facilities or compressor stations will

benefit from reduced air emissions. See Secti on 3.3.3 of this Regulatory Analysis for a more comprehensive review of public health impacts.

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

3.3.3 Quantitative and Qualitative Impacts

“To the extent practicable, a description of the probable quantitative and qualitative impact of the proposed rule, economic or otherwis e, upon affected classes of persons.”

The proposed changes to Regulation Number 7 are projected to result in substantial reductions of hydrocarbon emissions (including both VOCs and meth ane/ethane) from the oil and gas industry.
The Division estimates approximately 93,500 tons per year VOC, or 257 tons per day, and approximately 64,000 tons per year methane/ethane will be reduced.

Qualitative impacts of this Regula tion 7 proposal are closely relate d to Colorado’s air quality and economy. During the past ten years, Colorado has been a leader in developing and implementing requirements to reduce air emissions from the oil and gas sector. As a result of these efforts, Colorado now has in place a series of cost-eff ective requirements that significantly reduce air emissions from Colorado oil and gas facilities. Despite this success, however, the tremendous growth of oil and gas production in Colorado continues to threaten the air quality gains that we have achieved. Since 2004 gas production in Colorado has increased by 50% while oil production has more than doubled. While this gr owth has provided important economic benefits for Colorado, increased air emissions can have a negative impact on Co lorado’s public health

and environment.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 19 Specifically, VOC emissions contribute to th e formation of ground level ozone. Ozone is photochemical oxidant and known re spiratory irritant. Ground level ozone is a secondary pollutant produced through the reacti on of VOCs, nitrogen oxides and sunlight. Elevated levels of ground level ozone have been linked to a variet y of adverse health eff ects including decreased lung function, increased respirat ory symptoms, serious indicato rs of respiratory morbidity including emergency visits and hospital admissi ons, as well as total non-accidental and cardiorespiratory mortality. Accordi ng to EPA, ground-level ozone also damages vegetation and ecosystems. It leads to reduced agricultural cr op and commercial forest yields, reduced growth and survivability of tree seedlings, and increa sed susceptibility to diseases, pests and other

stresses such as harsh weather. In the United States alone, ground-level ozone is responsible for an estimated $500 million in reduced crop produc tion each year. Ground-level ozone also damages the foliage of trees and other plants, aff ecting the landscape of ci ties, national parks and forests, and recreation areas. 12

The U.S. EPA has set the current National Ambient Air Quality Standards (“NAAQS”) for ground level ozone at 75 parts per billion (ppb) averaged over an 8- hour period. Based on a

review of the then current h ealth literature, the Clean Air Scientific Advisory Committee concluded in 2008 that the 75 ppb st andard was not sufficiently pr otective of public health, and

recommended that the standard be set at betw een 60 ppb and 70 ppb. EPA is in the process of considering whether to lo wer the ozone standard.

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

Other areas of the state have also experienced elevated ozone levels recently, with one monitor in Western Colorado showing concentrations a bove 75 ppb and a number of other monitors showing levels between 60 ppb and 75 ppb.

Addressing oil and gas emissions is a critical component of Colorado’s efforts to lower ozone levels since this sector represen ts the largest source of VOC emi ssions in the state. Based on the most recent inventory (2011), 54% of the anthrop ogenic VOC emissions in the state come from the oil and gas sector, which is roughly triple the amount of emissions from the next largest source. Moreover, because of the ongoing growth in the oil and gas indus try and the projected decline in VOC emissions from other sectors, the share of VOC emissions attributable to the oil and gas sector will likely increase over the foreseeable future. The proposed emission reduction strategies will further enhance existing public health and envir onment protections on both a local and regional scale.

In addition to VOC emissions, oil and gas operations are a large source of methane. Methane is a potent greenhouse gas, which contributes to glob al climate change. In addition to reducing VOCs that contribute to regional ozone pollution, the Division’s proposed strategies will reduce methane, and thereby play a role in Colo rado’s overall efforts to reduce greenhouse gas emissions. Finally, the proposed strategies will redu ce the exposure of people that live and work

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

. February 11, 2014.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 20 near oil and gas production sites to VOC emissions . Methane is also a valuable natural resource (natural gas), and reducing leaks will benefit Colorado’s environment and economy.

The Division assesses the direct and indirect costs to the regu lated community for each of the proposed strategies in Regulation Number 7 in Section 3.3.8 of this Regulatory Analysis. Equipment costs, labor costs, maintenance costs, supervision costs, tr avel costs, and costs associated with recordkeeping and reporting are a ll evaluated. The Division estimates that the total annual costs to the regulated community as a result of the proposed strategies will be approximately $59.2 million. Further, the proposed strategies are expected to result in the capture of additional product worth approximate ly $16.8 million, for a total net cost of $42.4 per year. In addition to thes e direct costs, implementation of the proposed strategies could result in the shut-in of certain marginally producing wells, resulting in indirect costs in the form of lost revenues to oil and gas companie s, loss of jobs associated with these facilities, lost royalty payments, and lost severance taxes. Based on available information the Division cannot reasonably calculate the amount of additional oi l and gas that would be shut-in due to the proposed rules, but believes that the amount is li kely to be very small due to the low costs attributable to small, marg inally producing facilities. 13 An analysis by an economist hired by certain industry parties has suggested that these indirect costs could be quite large. 14 This information will be considered by the Commission as part of the rulemaking hearing.

The Division recognizes that the oil and gas i ndustry plays an important role in Colorado’s economy in the evaluation of qualita tive impacts of the Regulation 7 proposal. The industry is a significant employer of highly skilled and well-pa id employees. The industry generates large revenues and pays significant taxes in the state. It produces valuable domestic resources that help keep prices low while adding to national stability a nd security. At the same time, emissions from the oil and gas industry represent a significant portion of the total VOC emissions both in the NAA and throughout the rest of the state. Th e Division’s proposal is intended to achieve significant reductions in air emissions without imposing unreasonable costs that could stifle economic activity.

As discussed above, the Division’s proposal is pr ojected to result in a net annual cost to the industry of approximately $42.4 million. As with any increase in costs, the costs associated with the Division’s proposal could have some adverse impact on economic activity associated with the oil and gas industry in Colorado. However, over the past decade Colorado’s oil and gas industry has experienced unprecedented growth, even as Colorado has enacted regulatory measures to ensure that development continues in a protectiv e and responsible manner. Moreover, given the relative size of the costs of the current proposal to the overall size of the industry, the total impact of these costs will likely be minimal. In 2012, for example, oil and gas producers in Colorado sold 48,450,717 barrels of oil and 1,661,073,176 MCF of natural gas.

Based on the current price of o il, $96 per barrel, a nd assuming a price for natural gas of

13 See discussion in Section 3.3.8 of this Regulatory Analysis.

14 See Attached Exhibit A.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 21 $3.5/MCF 15 , annual revenue from the sale of oil and gas in Colorado based on 2012 production levels is approximately $10.5 bill ion. Accordingly, the net cost of the Division’s proposal is approximately 0.4% of the annual re venues. Given this small per centage, the Divi sion’s proposal is unlikely to have any appreciable impact on th e economic competitiveness of the industry as a whole. This conclusion is bolstered by the fact that several of the larg est oil and gas companies in the state (Anadarko Petrol eum Corp., Noble Energy, Inc., En cana Oil and Gas USA, and DCP Midstream) fully support the Divisi on’s proposed revisions. Collec tively, the Division estimates that these companies will bear approximately 75% of the total a nnual cost of the proposed rules.

While it is unlikely that the costs associated with the pr oposed revisions will have any meaningfully adverse impacts on the competitiveness of the i ndustry as a whole in Colorado, the costs could incrementally add to the current costs associated with operating marginally producing wells. This could poten tially lead to some wells being shut in and the resultant economic consequences of these shut-ins including lost production revenue, lost royalties, lost severance taxes and potentia lly lost jobs. To mitigate agains t this possibility, the Division’s has crafted a tiered proposal that triggers requirements based on emission thresholds that are directly tied to production. Based on this, the truly small facilities are subject to less requirements and less costs; for example, only a one-time instrument-b ased leak inspection,

which the Division estimates will cost approximately $712.

Finally, it does not appear that the costs associated with the Division’s proposal will have any meaningful negative impact on th e general public or small busine sses that purchas e natural gas and other petroleum products. Oil and natural gas are sold on international and national markets, making it extremely unlikely that any in crease in production costs in Colorado will be reflected in prices for Colorado consumers.

3.3.4 Probable Agency Costs

“The probable costs to the agency and to any other agency of th e implementation and enforcement of the proposed rule and any anticipated effect on state revenues.”

The Division will largely implement the provisions of its proposal through its oil and gas inspection team. This team currently consists of nine full time inspectors and four term limited inspectors. In 2012, in response to the growth in the oil and gas indus try in Colorado, the legislature approved increasing the size of the insp ection team from six inspectors to nine. In 2013, the legislature appropriated a dditional funds to hire four te rm limited inspectors to conduct IR camera inspections at well production faciliti es in Colorado. The term for these positions runs through June of 2015, but could be extended by the legislature if warranted. The additional inspectors provided during the 2012 and 2013 legisla tive sessions has significantly expanded the capabilities of the oil and gas inspection team , which will further en able the Division to implement and enforce the proposed requirement s if the Commission chooses to adopt the Division’s proposal. The total proj ected annual cost to the Divisi on for the oil and gas inspection

15 The Division assumed a price per MCF of $3.50 throughout its analysis; however, natural gas prices are currently around $5 per MCF, suggesting that the Division has underestimated the value of gas saved by the proposal.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 22 team in fiscal year 2013-14 is $1,305,304, which incl udes salary costs, fringe benefits, operating costs (including vehicles, field equipment, and office equipment) , travel training and indirect

costs.

The Division does not anticipate state revenues to be affected because the proposal does not assess any additional emissions reporting or permitting f ees beyond those that already apply. However,

s tate revenues could potentially be affected by implementation of the proposed strategies, in that they could potentially result in the shut-in of a few marginally producing wells, resulting in indirect costs in the form of lost revenues to oil and gas companie s, loss of jobs associated with these facilities, lost royalty payments, and lost severance taxes. Based on available information the Division cannot reasonably calculate the amount of oil and gas that could be shut-in due to the proposed rules, but believes that the amount is likely to be very small due to the low costs attributable to small, marginally producing facilities.

3.3.5 Comparison to Inaction

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

The Division estimates the proposed strategi es will reduce volatile organic compound (VOC) emissions by 93,500 tons per year, and methane/ethane emissions by 64,000 tons per year. The Division conservatively estimates that the annual net costs to industry of the Division’s proposal will be $42.4 million per year. This translates to approximately $453 per ton of VOC reduced. Costs and benefits of the proposed Regulation 7 revi sions are detailed in Section 3.3.8.

Conversely, inaction would mean that the above em issions reductions are not realized, that the associated captured methane (natural gas), a valuab le natural resource, is lost to the ambient air and that the estimated cost saving s in captured product that can be so ld at a profit is not realized. Further, emissions from this sector are projected to grow substantially, esp ecially in shale gas/oil development. 16

The forecast growth in shale gas/oil developmen t will result in increased emissions of VOC and other hydrocarbons including greenhouse gases, unless additional controls are implemented.

This could result in increases in ozone form ation and the developmen t of additional State Implementation Plan requirements to meet curr ent and future NAAQS requirements. According to EPA, attaining the current ozone standard throughout the nation will result in between $6.9
billion and $18 billion in annual health benefits. For lower standards the health benefits are even greater. For example, EPA projects that achi eve a 70 ppb standard will result in between $13
billion and $37 billion in annual health benef its, and for a 65 ppb standard the benefits will increase to between $22 billion and $61 billi on per year. EPA does not report these health benefits by state, but since th e population of the Denver Metropo litan Area/North Front Range NAA accounts for approximately 2.5% of the total na tional population living in areas that are in

16 U. S. Energy Information Administration. “Annual Energy Outlook 2013”. April 15-May 2, 2013.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 23 violation of the current NAAQS, the health benef its attributable to Colorado are likely to be

substantial.

The proposed rules will also produce substantial benefits associated with reducing greenhouse gases. As part of this rulemaking the Envir onmental Defense Fund has engaged an expert to analyze the benefits of the rulemaking based on th e social cost of carbon. Based on this analysis, EDF projects that the total annua l benefit from the projected me thane reductions is between $104
million and $318 million in 2016 and between $132 million and $404 million in 2025. 17

In addition to the benefits associated with reduc tions of VOCs and methane, the proposed rules will produce additional economic benefits in the form increased product capture and the creation of new jobs associated with the implementation of the new requirements.

3.3.6 Less Costly Methods/Less Intrusive Methods

“A determination of whether there are less co stly methods or less intrusive methods for achieving the purpose of the proposed rule.”

In 2004, 2006 and again in 2008, the Commission es tablished oil and gas industry specific emissions control requirements in an effort to reduce VOC emissions in the 8-hour ozone NAA. The tremendous growth of oil and gas production in Colorado and the associated emissions continue to threaten the air quality gains that have been achieved. Since 2004 gas production in Colorado has increased by 50% while oil production has more than doubled. Since then, the oil and gas industry has grown significantly (mor e than predicted), a nd changes in drilling technologies and other advancements have further supported growth in this industry. The oil and gas industry continues to be the largest VOC emitte r in Colorado (illustrated in Figure 1, below).

Several industry alternative propos als identify less costly and/or less intrusive methods to reduce emissions (see Section 3.3.7 of this Regulat ory Analysis). The Division made several clarifications based on these alternatives, but did not substantially re vise the Division’s Regulation 7 proposal. The Divisi on believes the Regulation 7 proposal secures more emissions reductions than those alternatives, and those addi tional emission reductions are cost effective. Moreover, several parties have proposed more costly and/or more intrusive methods to reduce

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

substantial emissions reductions in a cost effective manner.

17 See Attached Exhibit B.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 24 Figure 1 - Colorado Statewide Anth ropogenic VOC Emissions (2011)

3.3.7 Alternative Methods

“A description of any alternative methods for achieving the purpose of the proposed rule that were seriously considered by the agency and the re asons why they were rejected in favor of the proposed rule.”

In addition to the Division’s proposal, various parties to the rulemaking have submitted 6 different alternative proposals fo r the Commission to consider. Some of these proposals request that the Commission adopt additional requirements that go beyond the Division’s proposal, while other alternatives request that the Commission limit aspects of the Division’s proposed revisions. In some cases, the parties submitting the proposals included analyses estimating the costs and benefits associated with their proposals. C opies of each of these proposals along with any economic impact analysis that the parties submitted identifying the projected costs and benefits of their particular proposals are attached to this Regulatory Analysis as exhibits. Upon evaluation of these proposals, and other part ies’ comments, the Division made several clarifications to but did not substantially revise the Division’s Re gulation 7 proposal. The Division believes the Regulation 7 proposal strikes an appropriate balan ce between the various alternatives.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 25 The section below identifies each of the submitte d proposals, discusses how the proposals differ from the Division’s proposal, and addresses the projected costs and benefits of each proposal. 18

3.3.7.1 Joint Industry Work Group A collection of oil and gas companies and industry trade groups have submitted an alternative proposal seeking to limit the requirements set forth in the Division’s proposal. 19 Specifically, the Joint Industry Work Group request that the Co mmission limit the Division’s proposal in the following respects: 1) restrict all proposed requirements to th e Denver Metropolitan Area/North Front Range 8-hour ozone NAA; 2) reduce the re quired frequency proposed for leak inspection and repair; 3) eliminate the proposed requi rements for dehydrators; 4) limit proposed requirements for compressor seals and open-ended lin es to compressor stations; and 5) eliminate proposed requirements related to well maintenan ce and liquids unloading. In addition to these proposed limitations, the Joint Industry Work Group have proposed a number of additional changes, which could have some minimal additio nal impacts on the costs and benefits of the proposal.

Since the Joint Industry Group did not submit an ec onomic analysis detaili ng the projected costs

and benefits of thei r alternative proposal, 20 the Division has conducted an analysis of the Joint Industry Work Group alternative proposal util izing the same methodologies and assumptions detailed in Section 3.3.8 of this Regulatory Anal ysis. Based on this analysis, the Division estimates that the Joint Industry Work Group alternative proposal would have a net cost 21 to the regulated community of approximately $32.2 m illion, and would reduce emissions of VOCs by 56,525 tons per year and methane/ethane by 33,058 t ons per year. The decrease in net costs should have some positive impact on the indirect co sts associated with potential well shut-ins,

but the Division is unable to reasona bly calculate this impact. The decrease in costs relative to the Division’s proposal includes a decrease in th e number of facility inspections, which would result in fewer new inspector jobs attributab le to the proposal. Finally, because the Joint Industry Work Group proposal would result in less VOC and methane emission reductions, the

economic benefits associated with thes e reductions discussed in Section 3.3.8 of this Regulatory Analysis would be reduced.

18 In instances where a party submitted an analysis of the costs and benefits associated with their proposal such analysis is attached. Where parties submitted proposal without an analysis of their own proposal the Division has endeavored to analyze the costs and benefits of these pr oposals using the same methodologies used to analyze the costs and benefits of the Division’s proposal.

19 A copy of this alternative proposal is attach ed to this Regulatory Analysis as Exhibit C.

20 The group did submit an analysis of the Division’s proposal showing substantially higher costs than reflected in the Division’s analysis. A copy of this analysis is attached hereto as Exhibit A. It should be noted that while the Joint Industry Work Group predicts much higher costs from the Division’s proposals, Anadarko Petroleum Corporation, Noble Energy, Inc. and Encana Oil and Gas USA have submitted information during the rulemaking supporting the reasonableness of the Division’s cost and benefit calculations. Submissions from these companies can be found at the following link: ftp://ft.dphe.state.co.us/apc/aqcc/REBUTTAL%20 STATEMENTS,%20EX HIBITS%20%26%20ALT%20PROPOS
AL%20REVISIONS/

21 Net cost reflects the cost of implementing the proposed strategy less the value of the additional product captured as a result of the proposed strategies.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 26 3.3.7.2 WPX Energy WPX is the largest natural gas producer in the st ate. In the current rulemaking WPX has offered an alternative proposal that woul d decrease the total number of leak inspections by allowing well production facilities with low l eak rates during two consecutive inspections to reduce inspection frequency from monthly to quarter ly, or from quarterly to annua lly depending on the size of the facility. 22 While it is difficult to predict in advance how many facilities would be able to take advantage of this reduced inspection rate, for the purposes of this Regulatory Analysis the

Division assumes that one half of the facilities wo uld be able to utilize the reduced frequency. Based on this assumption, adoption of WPX’s alte rnative proposal woul d reduce the total net annual cost of the proposed revisions from approximately $42.4 million to approximately $36.8 million. This change would also decrease the am ount of emission reductions from the Division’s proposal by 1,845 tons per year of VOC and 2,757 tons per year of methane/ethane.

The decrease in net costs should have some positiv e impact on the indirect costs associated with potential well shut-ins, but the Di vision is unable to reasonably cal culate this impact. Given the relatively small difference in net costs between th e two proposals, any positive impact should be fairly small. The decrease in costs relative to the Division’s proposal in cludes a decrease in the number of facility inspections, wh ich would result in fewer new insp ector jobs attributable to the proposal. Based on the number of inspecti on hours for each proposal, the number of new inspector jobs would decrease. Finally, because the WPX proposal would result in less VOC and methane emission reductions, the eco nomic benefits associated w ith these reductions discussed

in Section 3.3.8 of this Regulatory Analysis would be reduced.

3.3.7.3 Conservation Groups As part of the rulemaking a number of cons ervation groups have submitted an alternative proposal requiring additional le ak detection inspections for well production facilities and compressor stations relative to the Division’s proposal. In addition, the Conservation Groups’ alternative proposal increases the nu mber of pneumatic devices that would need to be retrofitted. A copy of the Conservation Groups’ alternative propos al is attached as Exhibit D. Additionally, their analysis of the costs and benefits associated with their alternative pr oposal is attached as

Exhibit E.

3.3.7.4 Local Community Organizations A group of local community organizations have submitted an alternative proposal aimed at increasing the stringency of the Division’s proposal for facilities that are located within 1,320 feet of a building unit or designa ted outdoor activity area. Specif ically, for such facilities the Local Community Organizations’ al ternative proposal would decrea se the threshold for controls from petroleum storage tanks from 6 tons per year (as proposed by the Division) to two tons per year. Additionally, facilities loca ted within 1,320 feet of these designated areas would be subject to a more stringent leak inspection schedule. Copies of the Local Community Organizations’

22 In addition to this change, WPX has proposed a limited nu mber of additional changes and clarifications that do not impact the cost and benefit calculations conducted for the Division’s proposal. A copy of WPX’s alternative proposal is attached as Exhibit F.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 27 alternative proposal and their assessment of costs and emission reduction benefits are attached as

Exhibits G and H.

3.3.7.5 Local Government Coalition

The Local Government Coalition consists of a number of county and city governments including Adams County, Boulder County, La Plata Count y, Pitkin County and San Miguel County, Fort Collins, the City of Boulder, a nd the City and County of Denver. In their alternative proposal,

the Local Government Coalition seeks to increase the number of leak detection inspections for compressor stations and well produc tion facilities relativ e to the Division’s proposal. The Local Government Coalition also seeks to require that well production facilities be tied in to a gas gathering line within 90 days af ter the date of firs t production, unless the Division approves an

extension of this deadline. C opies of the Local Government Co alition’s alternative proposal and documents assessing the costs and be nefits of that proposal are at tached hereto as Exhibits I through M.

3.3.7.6 Worldwide Liquid Solutions, LLC Worldwide Liquid Solutions (WLS) is a ma nufacturer of emission reduction technology designed to control VOC emissions from petroleum storage tanks . According to WLS, their emission reduction technology cannot control meth ane and ethane and therefore cannot meet the

control standards for tanks re flected in the Division proposal . To address this, WLS has submitted an alternative proposal that would only require reductions of VOCs from tanks and not

methane/ethane. As an alternative to their al ternative, WLS has proposed rejecting all of the proposed changes to Regulation No. 7 set forth in the Division’s proposal . Copies of WLS’ alternative proposal and their assessment of costs and emission reduction benefits are attached as

Exhibits N and O.

3.3.8 Quantification of Data

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

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

As set forth below, the Divisi on has assessed the direct and i ndirect costs to the regulated community for each of the proposed strategies in Regulation Numb er 7. The Division estimates revisions to Regulation 7 will reduce VOC emissions by 93,500 tons per year, and methane/ethane emissions by 64,000 tons per year. The Division conservatively estimates that the annual net costs to industry of the Division’s proposal will be $42.4 milli on per year. This translates to approximately $453 per ton of VOC reduced, which is very reasonable when compared to other air pollution reduction strategies adopted by the Colorado Commission and the EPA. The Division estimates

that the total annual costs to th e regulated community as a result of the proposed strategies will be approximately $59.2 million. Further, the propos ed strategies are exp ected to result in the capture of additional product worth approxima tely $16.8 million, for a total net cost of $42.4 million per year. In addition to these direct co sts, implementation of the proposed strategies could potentially result in the shut -in of certain marginally produci ng wells, resulting in indirect2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 28 costs in the form of lost revenues to oil and ga s companies, loss of jobs associated with these facilities, lost royalty payments, and lost seve rance taxes. Based on available information the Division cannot reasonably calcula te the amount of oil and gas that could be shut-in due to the proposed rules, but believes that the amount is li kely to be very small due to the low costs attributable to small, marg inally producing facilities. To mitigate against this possibility, the Division’s has crafted a tiered proposal that trigge rs requirements based on emission thresholds that are directly tied to production. Based on this, the truly small facilities are subject to less requirements and less costs; for example, only a one-time instrument-based leak inspection, which the Division estimates will cost approximately $712. An analysis by an economi st hired by certain industry parties has suggested that these i ndirect costs could be quite large. 23 This information will be considered by the Commission as part of the rulemaking hearing.

The detailed discussions below largely focus on short-term consequences of the proposal. Long term consequences potentially include having to establish greater and potentially more extreme

control measures in the future to address the cu rrent mass of emissions a nd anticipated growth in emissions. The oil and gas industry is expected to continue to grow significantly, especially in shale gas/oil development. 24

This continued growth in shale gas/oil developm ent will result in increased emissions of VOC and other hydrocarbons including methane a nd ethane, unless addi tional controls are implemented. This could result in increas es in ozone formation and additional State Implementation Plan requirements to meet curren t and future NAAQS requirements. According to EPA, attaining the current ozone standard throughout the nation will result in between $6.9
billion and $18 billion in annual health benefits. For lower standards the health benefits are even greater. For example, EPA projects that achiev ing a 70 ppb standard will result in between $13
billion and $37 billion in annual health benef its, and for a 65 ppb standard the benefits will increase to between $22 billion and $61 billi on per year. EPA does not report these health benefits by state, but since th e population of the Denver Metropo litan Area/North Front Range NAA accounts for approximately 2.5% of the total na tional population living in areas that are in violation of the current NAAQS, the health benef its attributable to Colorado are likely to be

substantial.

3.3.8.1 Control Requirements for Petroleum Storage Tanks Commencing in 2004 the Commission has adopted a series of requirements aimed at reducing emissions from petroleum storage tanks at well production facilities, compressor stations and gas processing plants. Currently, condensate tanks with uncontrolled actual emissions of 20 tons per year or greater of VOC must be equipped with a c ontrol device that has a control efficiency of at least 95%. Additionally , with certain exceptions, operators in the NAA must achieve a 90% system-wide reduction of VOC emissions from condensate tanks during the period from May 1 through September 30, and 70% during the period from October 1 through April 30. These current requirements only apply to tanks that store condensate, which is defined in the

Commission’s Common Provisi ons regulation as “hydr ocarbon liquids . . . with an API gravity

23 See Attached Exhibit A.

24 U. S. Energy Information Administration. “Annual Energy Outlook 2013”. April 15-May 2, 2013.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 29 of 40 degrees or greater. ” While most of the petroleum liqui d produced in Colorado qualifies as condensate, there are heavier hydroc arbon liquids, typically referred to as crude oil, with an API gravity below 40 degrees that are not subject to the current control requirements. Additionally, there are a number of high volume produced water tanks that have VOC emissions above 6 tons per year that are not currently regul ated under the existing requirements.

While Colorado has achieved considerable succe ss in controlling emissions from condensate tanks since 2004, petroleum storage tanks at oil and gas production and midstream facilities continue to be the most signifi cant source of VOC emissions from this sector. To address this emission source the Division is proposing the fo llowing strategies: 1) reducing the control threshold from 20 tons per year VOC to 6 tons per year; 2) eliminating the distinction between condensate and other liquids and requiring controls strictly ba sed on emission levels; and 3) extending the current requirement that all conde nsate tanks in the NAA be controlled during the first 90 days of production to stor age tanks throughout the state. In order to meet each of these three strategies, the Division assumes that owners and operators will equip tanks with enclosed flares, as is the typical practice under the existi ng tank control requirements. The estimated costs associated with installing and maintaining an enclosed flare are set forth in subsection 3.3.8.1.1 of this Regulatory Analysis. Utilizing the calculat ed flare costs, the estimated costs and benefits for each of the three tank control strategies are discussed in subsections 3.3.8.1.2 – 3.3.8.1.4 of this Regulatory Analysis.

3.3.8.1.1 General	Cost	Estimates	for	Flares

The estimated cost for a flare control device is based on identified costs from a 2008 oil and gas cost study 25 adjusted for inflation. Based on this data , the estimated annualized cost of a flare

control device w ith auto-igniter 26 is about $6,287. 27

25 See “Oil & Gas Emissions Reduction Strategies Cost Analys is and Control Efficiency Determination,” Lesair Environmental, Inc., June 2008. Information from this study was previously submitted to the Commission as part of the 2008 Ozone Action Plan process. For reference or background purposes, the Division has cited herein certain information that has been submitted to the Commission as part of the rulemaking; however, it is not necessarily included with this Regulatory Analysis as an exhibit.

26 Currently only flares in the NAA are required to have auto-igniters. Under the current proposal, the auto-igniter requirement would be extended statewide. For the purposes of this cost analysis, it is assumed that auto-igniters will be required statewide. The cost and benefits associated with equipping existing flares outside the non-attainment with auto-igniters are discussed below in Section 3.3.8.1.7.

27 Certain parties to the rulemaking have asserted that the actual cost per combustion device is higher based on EPA’s cost analysis conducted in acco rdance with NSPS OOOO. Based on a review of EPA’s analysis it appears

that additional costs were included fo r surveillance systems that are not ap plicable to the proposed rule. Additionally, unlike the analysis in NSPS OOOO, the costs that the Division has identified are based on a Colorado specific cost analysis.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 30 Table 1: Flare Control Device with Auto Igniter – Annualized Cost Analysis*

Item Capital Costs (one time) Non-Recurring Costs (one time) O&M Costs (recurring) Annualized

Total Costs Flare $18,169 Freight/Engineering $1,648 Flare Installation $6,980 Auto Igniter $1,648
Pilot Fuel** $768 Maintenance $2,197 Subtotal Costs $19,817 $8,628 $2,965 Annualized Costs*** $2,747 $575 $2,965 $6,287

*Control cost evaluation based on 200 8 Ozone Rulemaking cost survey and pr oducer data. Control device costs were developed based on an oil and gas cost study and in formation submitted by industry in 2008. However, those costs were escalated by 9.85% to reflect CP I-U increases that have occurred since 2008. 28
** Pilot fuel costs $3.41/MMBtu (Henry Hub Spot Price - Aug. 2013) *** Annualized over 15 years at 5% ROR

3.3.8.1.2 Lowering	Statewide	Condensate	Ta nk	Control	Threshold	(from	20	t py	to	6	tpy) The Division is proposing to lower the uncontroll ed VOC emission control threshold from 20 tpy down to 6 tpy on condensate storage tanks statewid e. Based on an analysis of the Air Pollution Emissions Notice (APEN) databa se, the Division estimates that statewide there are 588

uncontrolled condensate tank batterie s with VOC emissions over six tons per year. Of these 588 tanks, 396 are outside the NAA and the remaining 192 are within the current NAA.

Table 2: Condensate Tank Battery Analysis

Tank Battery Type Ozone NAA [count] Outside NAA [count] Cancelled Tanks [count] Total Statewide Tanks [count] Controlled Tanks 4,971 490 5,461 Uncontrolled Tanks 1,451 1,132 36 2,619
All Tanks 6,422 1,622 36 8,080

Uncontrolled Tanks ( ≥ 6 tpy) 192 396 588

Based on the reported uncontro lled actual VOC emissions for these 588 tanks, and assuming

both that 75% of the VOC emissions are captured and sent to the flare, 29 and that the flare has a 95% destruction efficiency, the total VOC emission reduction associated with lowering the

condensate tank threshold statew ide is 5,162 tons per year.

28 It has been suggested that the Division should have used the Producer Price Index to calculate an escalation from 2008 to 2013 costs. From 2008 to 2013, however, the Producer Price Index for the oil and gas field equipment sector grew at a slower rate than th e CPI. Accordingly, the Division’s an alysis may actually overstate the increase

in cost from 2008 to 2013.

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

below in Section 3.3.8.1.5.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 31 Table 3: Condensate Tank Battery Emissions Analysis for Lowering Statewide Threshold

Tank Battery Type Uncontrolled

VOC Emissions [tons/year] Controlled

VOC

Emissions [tons/year] VOC

Emission

Reduction [tons/year] NAA Uncontrolled Tanks ( ≥ 6 tpy) 2,355 677* 1,678 Outside NAA Uncontrolled Tanks ( ≥ 6 tpy) 4,890 1,406* 3,484 Totals: 7,245 2,083 5,162

*Emission reduction estimated by accounting for 75% capture and 95% destruction efficiency.

The annualized cost of installing 588 flare cont rol devices is about $3.7 million dollars with an average cost effectiveness of about $716 per ton of VOC reduced. For the smallest individual tank battery subject to controls (6 tons/year), the flare cost e ffectiveness is estimated at $1,471 per ton of VOC reduced.

Table 4: Tanks over 6 tpy – Control Co st Estimates for Flare Control Devices

Affected Tanks [count] Each Flare

Annualized Cost Total Annualized

Costs VOC Reduction [tons/year] Control Costs [$/ton] 588 $6,286.8 $3,696,638 5,162 $716

In addition to VOC reductions , this strategy will significan tly reduce methane and ethane emissions from currently uncontrolled tanks. To calculate methane and ethane emission reductions, the Division determined the relativ e proportion of VOCs to methane and ethane based on reported average values from 30 natural gas liquid analyses submitted to the Division. Based on these analyses, methane/ethane emissi ons from condensate storage tanks are about 38% of the VOC emissions by weight. Acco rdingly, projected methane/ethane emission reductions from this proposed strategy are 1,963 tons per year or $1,884 per ton of

methane/ethane reduced.

3.3.8.1.3 Requiring	Controls	for	Produce d	Water	and	Crude	Oil	Tanks As discussed above, the Division is proposing to eliminate the distinct ion between condensate tanks and other storage tanks. If the Commission adopts this proposal, crude oil tanks and produced water tanks with uncontrolled actual VOC em issions of six tons per year or greater will require controls. Because produced water and cr ude oil tanks are identif ied separately in the Division’s APEN data base, the co sts and benefits for these two t ypes of storage ta nks are broken out separately.

The Division is proposing that all statewide produced water tanks with uncontrolled VOC emissions over 6 tons/year be required to instal l emission controls. Some uncontrolled produced

water tanks could be co-located at sites with condensate or crude oil tanks that have flare controls, but pressure and flow differences may re quire the installation of a separate flare control

device for the water tank. Conse quently, the control costs are ba sed on the assumption that each water tank battery will install a new flare control device. Base d on an analysis of the APEN2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 32 database, the Division estimates that statewid e there are 52 uncontrolled produced water tank batteries with VOC emissions over 6 tons/year.

Table 5: Produced Water Tank Battery Analysis Tank Battery Type Total Statewide Water Tanks

Controlled Water Tanks: 338

Uncontrolled Water Tanks: 530

Total: 868

Uncontrolled Tanks ( ≥ 6 tpy) 52

Based on the reported uncontrolle d actual emissions, the Division estimates that the total VOC emission reduction associated with controlling these produced water tanks statewide is 457 tons

per year.

Table 6: Produced Water Tank Battery – Emissions Analysis

Tank Battery Type Uncontrolled

VOC Emissions [tons/year] Controlled

VOC

Emissions [tons/year] VOC

Emission

Reduction [tons/year] Uncontrolled Tanks ( ≥ 6tpy) 641.4 184.4* 457

*Emission reduction estimated by accounting for 75% capture and 95% destruction efficiency.

The annualized cost of installing 52 flare contro l devices is about $327,000, with an average cost effectiveness of about $715 per ton of VOC reduced. For the smallest indi vidual tank battery (6 tons/year), the flare cost effectiveness is estimated at $1,471 per ton of VOC reduced.

Table 7: Produced Water Tanks – Control Co st Estimates for Flare Control Devices

Tank Size Affected

Tanks [count] Each Flare

Annualized

Cost Total

Annualized

Costs VOC

Reduction [tons/year] Control

Costs [$/ton]

≥ 6tpy 52 $6,286.8 $326,914 457 $715

The Division is proposing that all statew ide hydrocarbon liquid stor age tanks with VOC emissions over six tons/year must install emissi on controls. Based on a recent analysis of 2013 APEN data, there are 67 reported cr ude oil tanks batteries statewid e. Thirty seven of the tank batteries are already equipped with controls. Of the remaining thirty, eight are over the proposed six tons/year threshold. Given that approximately 5% of the total wells in the state report crude oil production to the Colorado Oil a nd Gas Conservation Commission (COGCC), 30 it appears

30 Based on an analysis of 2010 COGCC data.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 33 likely that the Division’s APEN database may be undercounting crude oil tanks, either because these tanks have not been reported or because they are being reported as condensate tanks. 31

Table 8: Crude Oil Tank Battery Analysis Tank Battery Type Total Statewide Crude Oil Tanks

Controlled Crude Oil Tanks 36

Uncontrolled Crude Oil Tanks 29

Total: 65

Uncontrolled Tanks ( ≥ 6 tpy) 8

The total VOC emission reduction associated with co ntrolling these 8 crude oil tanks statewide is 118 tons per year.

Table 9: Crude Oil Tank Ba ttery – Emissions Analysis

Tank Battery Type Uncontrolled VOC

Emissions [tons/year] Controlled

VOC Emissions [tons/year] VOC Emission

Reduction [tons/year] Uncontrolled Tanks ( ≥ 6tpy) 165.2 47.5* 117.7

*Emission reduction estimated by accounting for 75% capture and 95% destruction efficiency.

The annualized cost of installing eight flare co ntrol devices is about $50,294 dollars with an average cost effectiveness of about $427 per ton of VOC reduced. For the smallest individual tank battery (6 tons/year), the flare cost effectiveness is es timated at $1,471 per ton of VOC

reduced.

Table 10: Crude Oil Tanks – Control Co st Estimates for Flare Control Devices

Tank Size Affected

Tanks [count] Each Flare

Annualized

Cost Total

Annualized

Costs VOC

Reduction [tons/year] Control

Costs [$/ton]

≥ 6tpy 8 $6,286.8 $50,294.4 117.7 $427

3.3.8.1.4 Requiring	Controls	During	the	First	90	Days	of	Production	State wide Under current requirements owners and operators of ne w and modified storage tanks outside the NAA have 90 days after the date of first produ ction to determine if emissions from the tank trigger the requirement to insta ll a control. Because production is typically at its highest during this initial period, significant emissions can occur be fore controls are installed. To address this

31 Prior to 2008 crude oil storage tank s were exempt from APEN reporting requ irements, which may explain in part the small numbers of tanks identified in the system.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 34 issue in the NAA, the Commission mandated in the 2008 Ozone Action Plan that all condensate tanks be controlled during the first 90 days. The Division is now proposing to expand this requirement to storage ta nks throughout the state.

To calculate the cost effectiveness of this strategy, the Division first determined the number of new and modified storage tanks outside the NAA ba sed on reported APEN data for the period of 2010-2012. Based on this APEN data, there are on average 141 new and modified tanks each year, with yearly reported uncont rolled actual emissions of 7, 370 tons VOC. Assuming that emissions during the first 90 days equal 1/4 th of the annual reported emissions, 32 total

uncontrolled actual VOC emissions from these ta nks during the first 90 days is 1,842.5 tons. Assuming enhanced capture efficiency for these new tanks (see subsection 3.3.8.1.5 of this Regulatory Analysis) the flare control efficiency is 95%, and thus the calculated benefit from expanding the first 90 day control requirement to tanks outside the NAA will be 1,750.4 tons per

year.

While the Division estimates that there are 141 new and modified storage tanks outside the NAA each year, the majority of these, 84, will require control devices regardless of this strategy since

their uncontrolled actual emissions are over six t py. For these 84 tanks, the cost of operating a flare during the first 90 days will be approxima tely 25% of the total annualized cost, or $1,571.70 per tank. For the remaining 57 tanks with emissions less than six tons/year, because controls for these tanks will only need to be in place for 90 days, the Division assumes that each flare can control 3 tanks per year, which means th at 19 new flares are required to comply with this proposed strategy. For other applications, the annualized cost of a flare is estimated to be $6,287. Since flares required for this applicat ion will be relocated three times a year, the Division assumes an additional $3,000 in annual relo cation costs, for a total annualized cost of about $9,287 per flare. Based on the emission re ductions calculated above, the total cost effectiveness of this requirem ent is $176/ton of VOC reduction.

Table 11: Control Cost Estimates for Flare Co ntrol Devices Required During the First 90 Days of Production Storage

Tank

Threshold [tpy] Number of

New Storage

Tanks Number

of New

Flares Annualized

Cost Each

Flare Total Flare

Cost Total VOC

Reduction [tons/year] VOC

Control

Cost [$/ton] <6 57 19 $9,286.8 $176,449.2 44.7 $3,947

≥ 6 84 84 $1,571.7 $132,022.8 1,705.7 $77
141 $308,472 1,750.4 $176

Using the methodology discussed in subsecti on 3.3.8.1.2 of this Regulatory Analysis, the projected methane/ethane emission reductions fr om this strategy is 665.5 tons per year or $464 per ton of methane/ethane reduced.

32 Because reported emissions typically are based on a calculation assuming a standard rate of production decline after the first 90 days, actual emissions during the first 90 days could be much higher.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 35 3.3.8.1.5 Emission	Capture	Requirements	fo r	Controlled	Petroleum	Storage Tanks In order for storage tank control requirements to be effective, emissions from the tank must be

routed to the control device. Historically the Division has a ssumed that 100% of a tank’s emissions will be captured and routed to the contro l device, typically a flare, resulting in a 95%

reduction of emissions. Field observations usi ng IR cameras and other methodologies indicate that in actuality emissions from controlled st orage tanks often escape through the thief hatches and pressure relief valves (PRV) and therefore are not being combuste d in the flare. This occurs when the tank cannot adequately contain the fl ashing emissions that occur when pressurized liquids from the separator are dumped into the atmospheric tank. To address this issue, the Division is proposing new regulat ory language clarifying that a ll emissions from controlled storage tanks must be routed to the control devi ce and that these tanks must be operated without venting emissions from thief hatches, PRVs and other openings, except when venting is reasonably necessary for maintenance, gaugi ng, or safety of personnel and equipment.

To assure compliance with these capture standard s, the Division’s proposal requires that owners and operators of controlled storage tanks implemen t a STEM plan. Pursuant to the STEM plan, owners and operators must evaluate and em ploy appropriate contro l technologies and/or operational practices designed to meet the propose d capture requirements, and certify that these technologies and/or operational pr actices are designed to minimize emissions from the tank. The Division’s STEM proposal also requires impl ementation of a two-pronged monitoring strategy involving a weekly 33 auditory, visual, and olfactory (AVO) inspection for all controlled tanks, and a periodic instrument based monitoring fo r tanks using EPA Reference Method 21, an IR camera or other Division approved monitoring de vice or method. As proposed, the frequency of this instrument based monitoring will depend on the level of uncontrolled actual emissions from

the tank.

Table 12: Proposed Tiering for Instrument Based Tank Inspections

Tank Uncontrolled Actual VOC Emissions Inspection Frequency

≥ 6 tpy to ≤ 12 tpy Annually > 12 tpy to ≤ 50 tpy Quarterly > 50 tpy Monthly

In assessing the cost effectiveness of the propos ed requirements, the Division first calculated the costs associated with implemen ting technological and/or operationa l changes at controlled tanks. For the purposes of this analysis the Division assumed that all tanks with uncontrolled actual emissions greater than or equal to 6 tons per year would need to be contro lled consistent with the Division’s proposal discussed in Section 3.3.1 of this Regulatory Analysis. Based on reported data, there are currently 5,310 storag e tanks statewide with emissions greater than or equal to 6 tons per year. While the Division’s proposal does not specify the type of technology or operational practices that operators will use, fo r the purposes of this analysis the Division

33 There is an exception for the weekly inspection requireme nt where the operator loads out liquids from the storage tank on less than a weekly basis. In these circumstances the operator must conduct th e inspection whenever liquids are loaded out, but no less often than every 30 days. Typi cally liquids are loaded out multiple times in a given week, meaning that for the majority of the tank s AVO inspections will be required weekly.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 36 assumed that buffer bottle technology would be installed on each of the subject tanks. 34 The buffer bottle technology utilizes a sm all tank that is installed after the separator which allows for a secondary flash of pressurized liquids prior to dumping into th e storage tank. The second-stage flash reduces the pressure of the liquids going to the tank and thereby helps to ensure that the tank can adequately handle the flashing emissions that occur when the liquids are brought to atmospheric pressure. Based on industry provid ed information, the estimated annual cost of a

buffer bottle is set forth in Table 13. 35

Table 13: Annualized Cost Analysis for Buffer Bottle

Item Capital Costs (one time) Non-Recurring Costs (one time) O&M Costs (recurring) Annualized

Total Costs Buffer Bottle $11,500 Freight/Engr $600 Installation $2,280 Maintenance $2,500
Subtotal Costs $11,500 $2,880 $2,500 Annualized Costs* $1,593.8 $192 $2,500 $4,285.8

* Annualized over 15 years at 5% ROR

The Division also calculated th e costs associated with conducti ng enhanced inspections. Based on the proposed tiering, operato rs will need to conduct 24,840 tank inspections per year. 36

Assuming that each inspection take s two hours and utilizing a $103/hour 37 in-house inspection cost and a $134/hour contractor inspection cost (30% profit added to in-hous e rate), the total annual cost associated with conducting enhan ced inspections under the proposed rule is $5,392,010, which equates to $1,015.4 per year for each tank that will be subject to STEM.

34 Based on discussions with industry representatives during the stakeholder process there may be other less costly technologies and operational practices that could be used to ensure good emission capture from tanks such as replacing seals, more frequent maintenance, changing the size of piping going to the storage tank, and timing well dumps to avoid overloading the separator. There may also be other options for new facilities that allow for the capture and sale of additional gas such as the installati on of high-low pressure separators or utilizing a liquids gathering system that eliminates atmospheric storage tanks at well sites.

35 For this Regulatory Analysis, the Division increased th e capital and maintenance costs for buffer bottles based on input from industry stakeholders.

36 In practice, many operators are already conducting IR camera inspections at storage tanks, however, the Division does not have information regarding how many inspections are currently occurring.

37 The hourly inspection cost is discussed below in Table 20.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 37 Table 14: Instrument Based Tank Inspections Based on Proposed Tiering

Tank Uncontrolled

Actual VOC

Emissions Inspection Type/Hourly Rate Number

of Tanks Inspection Frequency Number of Inspections STEM Inspection

Costs >6 tpy to ≤ 12 tpy In-House/$103 1,085 Annually 1,085 $223,510 >12 tpy to ≤ 50 tpy In-House/$103 2,595 Quarterly 10,380 $2,138,280 > 50 tpy In-House/$103 745 Monthly 8,940 $1,841,640 Subtotal: 4,425 20,405 $4,203,430

>6 tpy to ≤ 12 tpy Contractor/$134 323 Annually 323 $86,564 >12 tpy to ≤ 50 tpy Contractor/$134 329 Quarterly 1,316 $352,688 > 50 tpy Contractor/$134 233 Monthly 2,796 $749,328

Subtotal: 885 4,435 $1,188,580

Total: 5,310 24,840 $5,392,010

The Division also considered whether additi onal costs should be included for conducting periodic AVO inspections. Because these activitie s are already required fo r controlled storage tanks under existing regulation, the Division did not include these co sts in determining the total cost of the proposed capture requirements. The Division also did not in clude costs associated with certifying that selected technologies and/or operational practices ar e designed to minimize emissions, since costs for certifyi ng capture efficiency are alrea dy included in the annualized cost of required flares. 38 Accordingly, the total projected annual cost of the proposed capture requirements based on the use of a buffer bottle and enhanced monitoring requirements is $5,301.2 per tank.

To calculate the projected emissions reduction from the proposed capture requirements, the Division assumed a current capture rate of 75% for controlled tanks based on analytical work that the Division, EPA and others have perfor med. Based on this capture rate, the Division

calculated the emissions reduction that would occur if the capture rate were increased to 100% using the following equation:

Emission reduction = [uncontro lled VOC*(1-(0.75*0.95))] – [uncontrolled VOC *(1-0.95)],

Using this equation as applied to the reporte d uncontrolled actual emissions from the 5,310 storage tanks statewide with emi ssions greater than or equal to six tons per day, the projected emission reduction from the proposed capture re quirements is 53,386 tons per year. Included in the total are 33 existing crude oil tanks with flar e controls (>6 tpy) and 8 crude oil tanks that would need flare controls (>6 tpy).

38 See “Oil & Gas Emissions Reduction Strategies Cost Analys is and Control Efficiency Determination,” Lesair Environmental, Inc., June 2008, at pg. 8.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 38 Table 15: STEM Emission Co ntrol Analysis (Statewide)

Number of

Tanks ≥ 6 tpy Uncontrolled

VOC [tons/year] Controlled VOC (@ 71.25% Control) [tons/year] Controlled VOC (@ 95% Control)

[tons/year] VOC

Reduction [tons/year] 5,269 221,569 63,701 11,078 52,623 41 3,213 924 161 763
5,310 224,782 64,625 11,239 53,386

Applying this reduction to the costs calculated above, the cost effectiv eness of these proposed requirements is $527/ton of VOC.

Table 16: STEM Control Cost Estimates (Statewide)

Type of Technology Number

of Tanks Each Device

Annualized Costs [$/year] Total

Annualized

Costs VOC

Reduction [tons/year] Control

Costs [$/ton] Buffer Bottle 5,310 $5,301.2 $28,149,372 53,386 $527.3

Using the average ratio of VOC to methane/etha ne emissions from storage tanks, the projected methane/ethane reduction from this strategy is 20,287 tons per year, wh ich equates to $1,388 per

ton of methane/ethane reduced.

During the Division’s stakeholde r process leading up to the Co mmission’s rulemaking hearing, certain parties have raised questions about the Division’s assumption that currently controlled tanks have a 75% capture efficien cy. In light of this the Di vision has also calculated cost effectiveness based on the assumption that current capture efficiency is 50% and 95%. For the 50% case, current controlled emissions woul d be 118,011 tpy VOC. Accordingly, the emission reduction benefit from increasing capture to 100% would be 106,772 tons per year (118,011- 11,239) and the cost effectiv eness would be $264/ton VOC 39 . For the 95% capture scenario, current controlled emissions would be 21,916 to ns per year VOC and the emission reduction would be 10,677 tons per year ( 21,916-11,239). Under this scenar io, the cost effectiveness would be $2,636/ton VOC 40

.

While the buffer bottle technology offers a good alte rnative in a retrofit situation for reducing pressures to the tank and increa sing emission capture, for new fac ilities, installation of a highlow pressure (HLP) separator to satisfy STEM may prove to be a better performing option. This equipment allows for two stages of separation of the gas and the liquids instead of the single stage separation accomplished in traditional separa tors. By adding a second stage of separation, the pressure of the liquids sent to the tank is significantly redu ced, thereby helping to ensure

39 This may overestimate the cost effectiveness given that if the current capture rate we re only 50% additional costs could be required to increase the capture rate to 100%.

40 This is a conservative calculation given that if the curren t capture rate were 95% it is likely that the control costs to increase the capture rate to 100% would be significantly less.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 39 complete capture of flashing emissions instead of venting a portion of the emission stream through the thief hatch or PRV. Additionally, rather than being routed to the flare, as in the case of the buffer bottle technology, gas from the second stage of separation can be sent to a vapor recovery unit (VRU), recompressed and sent to the sales line, resulting in increased product recovery. Based on information provided from industry, the Division ha s calculated that the annual cost of a HLP separator w/VRU is about $19,341.

Table 17: Annualized Cost Analysis for HLP Separator

Item Capital Costs (one time) Non-Recurring Costs (one time) O&M Costs (recurring) Annualized

Total Costs HLP/VRU $90,000 Freight/Engr $1,648 HLP/VRU Installation $11,154 Maintenance $9,396 VRU Recovered NG * $(3,382) Subtotal Costs $90,000 $12,802 $6,014 Annualized Costs** $12,474 $853 $6,014 $19,341

* Recovered NG fuel costs $3.5/MCF (Henry Hub Spot Price - Aug. 2013) and average tank battery size of 63.2 tpy – based on 3-yr average of APEN data on storage tanks ≥ 6 tpy (uncontrolled VOC).

** Annualized over 15 years at 5% ROR

Unlike the retrofit situation analy zed above where the emission contro ls are already in place, it is appropriate in new instal lations to aggregate the cost of th e HLP separator w/VRU with the costs of the control unit (flare ) to determine the overall cost of controlling emissions from the tank. Based on the $6,286.8 annual cost of a flare and a nnual instrument based monitoring costs of $1,015.4 per tank, the total annual control costs for a new tank will be $26,643 per year.

Based on an analysis of reported data for new tanks during the past three years, the average

uncontrolled actual emissions of a new tank is 63.2 tpy. Assuming a 95% overall control efficiency, equipping a tank with an HLP separato r and a flare will reduce the emissions from an average new tank by 60 tpy. This yields a cost effectiveness of $444 per ton VOC reduced. If instead, the highest cost scenario (using a six tpy tank) is assu med, the cost effectiveness is $4,674 per ton VOC. For methane ethane the cost per ton is $1,168 per ton reduced on average.

3.3.8.1.6 LDAR	Requirements	for	Compressor Stations	and	Well	Production	F acilities Commission Regulation Numb er 7 requires owners and operators of gas processing plants in Colorado to implement LDAR programs to iden tify and repair fugitive emission leaks from components at these facilities. Under this requirement, owners and operators must conduct periodic inspections using EPA Reference Method 21 41 and repair leaks within a prescribed time

frame.

41 While EPA Reference Method 21 sets performance sta ndards for inspection equipment rather than specifying technology, typically Method 21 inspections utilize phot o ionization detectors (PIDs) to assess leak levels.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 40 Although component leaks at compressor stations and well production facilities in Colorado are also a significant source of VOC and methane emissions, Regulation No. 7 does not currently include LDAR requirements for these facilities. 42 To address these emissions, the Division is proposing regulatory changes that would establish LDAR requirements for compressor stations and well production facilities. Pursuant to th is proposal, owners and operators of compressor stations and well production faciliti es will be required to conduct periodic leak inspections, and repair identified leaks. As sp ecified, required inspections may be done either in accordance with

EPA Reference Method 21 or utiliz ing an IR camera. The proposed language also allows the Division to approve other insp ection methods as new leak detection technologies are

demonstrated to be effective.

The proposed regulation establishe s a tiered system to determin e inspection frequency. For compressor stations the tiering is based on the uncontrolled actual leak emissions at the facility

as follows:

Table 18: Proposed Tiering for Leak Inspections at Compressor Stations Component Leak Uncontrolled Actual VOC

Emissions Inspection Frequency

≤ 12 tpy Annually >12 tpy to ≤ 50 tpy Quarterly > 50 tpy Monthly

For well production facilities the proposed tierin g is based on uncontrolled actual emissions from the largest emitting storage tank at the facility as set forth in Table 19. The tiering is based on

tank emissions rather than uncontrolled actual leak emissions in order to create an EPA Reference Method 21/IR camera monitoring schedul e that is consistent with the monitoring schedule proposed as part of S TEM emission capture requirements. 43

42 Although leak detection is not currently required at most of these facilities, some operators currently conduct voluntary leak detection and repair programs. Additionally, the Division has issued a limited number of permits that include some leak detection requirements. For the purpos es of this analysis, however , the Division assumes that there is no leak detection occurring at well production f acilities and compressor stations. Accordingly the actual additional costs that operators may incur may be less than the costs calculated in this analysis.

43 Because there may be a limited number of instances wh ere well production facilities don’t have storage tanks, the proposal also provides that for tank-less facilities, the inspection schedule will be based on the facility’s total VOC emissions. This provision is intended to apply to la rge facilities that utilize a liquids gathering system for transporting petroleum liquids to a centralized facility. Thes e facilities are not included in the facility count used in this Regulatory Analysis, bu t because the number of these facilities in Co lorado is extremely small this exclusion should have a negligible impact on the overall costs and emission reduction benefits of the proposed LDAR requirement. Additionally, because the costs and benefits from the proposed LDAR prog ram increase at roughly the same rate, the cost effectiveness of the program for th ese facilities should mirror the cost effectiveness of the program as applied to facilities with tanks.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 41 Table 19: Proposed Tiering for Leak Inspections at Well Production Facilities

Tank Uncontrolled Actual VOC Emissions Inspection Frequency < 6 tpy One Time (and Monthly AVO)

≥ 6 tpy to ≤ 12 tpy Annually >12 tpy to ≤ 50 tpy Quarterly > 50 tpy Monthly

The Division utilized a multi-step process to calc ulate the estimated costs and benefits associated with the proposed LDAR requirements. First, the Division calculated an hourly inspection rate based on the total annual cost for each inspec tor divided by an assumed 1,880 annual work

hours. 44 To calculate the total annual cost for each inspector, the Divisi on included salary and fringe benefits for each insp ector, annualized equipment and ve hicle costs, and add-ons to account for supervision, overhead, travel, r ecord keeping, and reporting. Based on the assumptions set forth in Table 20 below, the total annual cost for each inspector will be $193,629, which equates to an hourly inspection rate of $103.

Table 20: LDAR Inspector – Annualized Cost Analysis

Item Capital Costs (one time) Annual Costs Annualized Total

Costs FLIR Camera $122,000

FLIR Camera Maintenance/Repair $7,500

Photo Ionization Detector $5,000 Vehicle (4x4 Truck) $22,000 Inspection Staff $75,000 Supervision (@ 20%) $15,000 Overhead (@10%) $7,500 Travel (@15%) $11,250 Recordkeeping (@10%) $7,500 Reporting (@10%) $7,500 Fringe (@30%) $22,500
Subtotal Costs $149,000 $153,750 Annualized Costs* $39,879 $153,750 $193,629 *over 5 years at 6% ROR Annualized Hourly Rate $103

Initially, the Division assumed that conducting in spections in-house would be the lowest cost option since it would not involve additional profit to be paid to a contractor. For smaller companies that cannot fully utilize an IR cam era, however, conducting in spections in-house may not be the most cost effective option. To acc ount for this in this Regulatory Analysis, the Division assumed a 30% profit margin for contract ors, which it added to the calculated hourly rate in instances where it appe ared that contractors would be used to conduct the inspection ($134 per hour).

44 This assumes a 40 hour work week with ten holidays, two w eeks of vacation, and one week of sick leave.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 42 Second, the Division calculated the average amount of time that it would take to conduct an EPA Reference Method 21 inspection at compressor st ations and well producti on facilities based on the number of components to be inspected and assuming that a component could be inspected every 30 seconds. The proposed rule also allows owners and operators to use IR cameras either as the sole inspection tool, or as a screening tool to identif y potential leaking components followed by a Method 21 inspection. An IR came ra inspection or IR Camera/Method 21 hybrid inspection can be conducted more quickly than a Method 21 inspection of each component. While the Division does not currently have actual data regarding how much faster an inspection could be completed using an IR camera, for the purpose of this analysis the Division assumed that an IR camera based inspection would take 50% of the time required for a Method 21 inspection. 45

For compressor stations, the Division used re ported component counts for compressor stations

within each of the tiers identified in Table 18 above. Based on these counts, and the inspection times per component discussed above, the Divisi on calculated that the to tal inspection time per compressor station facility tier are as follows:

Table 21: Calculated Inspection Time Compressor Station Leak Inspections Component Leak Uncontrolled

Actual VOC Emissions Method 21 Inspection IR Camera/ Hybrid Inspection

≤ 12 tpy 21.2 hours 10.6 hours >12 tpy to ≤ 50 tpy 56.2 hours 28.1 hours > 50 tpy*

* there are currently no compressor stations in Colorado with calculated leaks at this level

For well production facilities, the Division has limited data on the number of components per facility. Based on this limitati on, the Division did not attempt to calculate a separate inspection time for each of the proposed facility tiers, a nd instead used the overall average component count. Based on the limited available data, how ever, there does appear to be a distinction between component numbers at well produc tion facilities in the NAA and well production

facilities outside the NAA. Acco rdingly, the Division calculated separate inspection times for well production facilities by area as set forth in Table 22.

Table 22: Calculated Inspection Times for Well Production Facility Leak Inspections

Area Method 21 Inspection IR Camera/ Hybrid Inspection

NAA 12.2 hours 6.1 hours

Rest of the State 6.8 hours 3.4 hours

45 Based on the Division’s own IR camera inspections, and reports from various parties during the stakeholder and prehearing process it appears that the Division’s assumption may significantly overstate the actual time needed to conduct an IR camera inspection.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 43 In addition to the travel costs that are built into the hourly inspection rate as set forth in Table 20, for the purposes of this Regulator y Analysis the Division also a ssumed an additional three hours

in travel time for each in spection outside the NAA. This assump tion reflects the fact that certain well sites in basins outside the NAA may be remote, requiring a dditional travel.

Next, the Division calculated the projected insp ection costs for both compressor stations and well production facilities. To make th is calculation the Division used industry reported emission data to determine the number of facilities that will be subject to annual, quarterly and monthly inspections to determine the total number of inspections for each tier, and multiplied these inspections by the calculated inspection time and projected ho urly inspection rate. For compressor stations the Division assumed that all inspections would be conducted by 3 rd party contractors. For well production facilities, the Division assumed that any company with 500 or more inspections per year would conduct inspecti ons in-house, and that companies with less than 500 inspections per year would use contractors. 46 Because the proposed rule also requires owners and operators of well pr oduction facilities that are not subject to monthly instrument monitoring to conduct monthly AVO inspections th e Division considered whether additional costs should be included for these inspecti ons. Based on information provided during the Division’s stakeholder process leading up to the Commission’s rulemaking hearing it appears that operators already routinely conduct such inspections and repair leaks identified during these AVO inspections. Additionally, while the pr oposed rule may impose recordkeeping and reporting requirements associated with these AVO inspections, given the relatively small number of leaks that are expected to be identified, a nd the fact that any recordkeeping can be readily included in existing inspection and maintenance r ecords the Division believ es that any additional recordkeeping and reporting costs will be nominal relative to the overall cost of the LDAR

program.

In its Initial EIA, the Division did not include the cost to re pair leaking components or remonitor these components post-repair to verify th at the repair was effective, assuming that the cost to repair and re-monitor would be offset by the cost savings from capturing additional product as a result of repairs. Based on inform ation that the Conservation Groups submitted as part of their Pre-Hearing Statement to the Co mmission, it appears that the Division’s assumption

in the Initial EIA was reasonable. See Exhibit A to CG-PHS, Testimony of David McCabe at pg. 8. Nevertheless, for this Regul atory Analysis, the Division has included both repair costs and estimated product savings from conducting leak detec tion activities. To ca lculate repair costs, the Division used EPA information regarding le aking component rates, component repair times, and hourly repair rates. Sp ecifically, the Division assume d a $66.24 hourly rate to repair components, and an average repair time of between 0.17 hours and 16 hours, depending on the both type of component and th e complexity of the repair. 47 To calculate the number of leaking components the Division used industry reported component counts and assumed a 1.18% leaking

46 Based on this assumption, 3,545 inspections per year will be conducted using 3 rd party contractors.

47 See “Equipment Leak Emission Reduction and Cost Analysis for Well Pads, Gathering and Boosting Stations, and Transmission and Storage Facilities Using Emission and Cost Data From the Uniform Standards,” Bradley Nelson and Heather Brown, April 17, 2012; “Analysis of Emissions Reduction Techniques for Equipment Leaks,” Cindy Hancy, December 21, 2011.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 44 component rate for facilities subject to annual inspections. 48 To account for the projected additional emission reductions from quarterly and monthly inspection schedules the Division used annual leaking component ra tes of 1.77% for facilities with quarterly inspection schedules

and 2.36% for facilities with m onthly inspection schedules. To calculate the value of the additional product captured, the Division convert ed the amount of VOC and methane/ethane reduced to MCF of natural gas, with a price of $3.50/MCF. With respect to re-monitoring, the

Division determined that because of the small num ber of components that will require repair and the fact that re-monitoring can be undertaken at the same time as repa ir, any additional costs associated with re-monitoring are negligible.

Based on this methodology, the calculated annual in spection costs for compressor stations are set

forth in Table 23.

Table 23: Compressor Station Leak Inspection Costs Using IR Camera/Method 21 Hybrid

Compressor Station Fugitive VOC Tier [tpy] Number of Compressor

Stations Annual Inspection Frequency Time per

IR Camera Inspection

[hours] Total Annual Inspection

Time [hours] Total Annual Inspection Cost

≤ 12 tpy 147 1 10.6 1,558.2 $208,799

>12 to ≤ 50 tpy 53 4 28.1 5,957.2 $798,265

≥ 50 tpy 0 12 Total: 200 7,515.4 $1,007,064

Repair costs associated with these inspections are set forth in Table 24 and fuel savings associated with these repairs are set forth in Table 25.

Table 24: Compressor Station Leak Repair Costs

Compressor Station Fugitive VOC Tier [tpy] Number of Compressor

Stations Leak Repair Rate [$/hr] Number of Leaks per Compressor

Station Total Leak Repair Time per CS [hours] Total Annual Repair Cost

≤ 12 tpy 147 $66.24 30.1 23.0 $223,957.4

>12 to ≤ 50 tpy 53 $66.24 119.4 85.2 $299,113.3

≥ 50 tpy 0 $66.24 - - -
Total: 200 $523,071

48 This leaking component rate is consistent with the rate that the Louis Berger Group us ed in their Initial Economic Impact Analysis for Industry’s Proposed Revisions to Colorado’s Air Quality Control Commission Regulation No. 7 (DGS-PHS Ex. C), and is based on the leak rate utilized by Nelson and Brown in their analysis of leak reduction costs and benefits (See footnote 41).2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 45 Table 25: Compressor Station Recovered Natural Gas Value from Leak Repairs

Compressor Station Fugitive VOC Tier [tpy] Number of Compressor

Stations Total

Recovered

Natural Gas per CS [tons/year] Value of

Natural

Gas [$/MCF] Conversion

Factor [MCF/ton] Total Annual

Value of

Recovered

Natural Gas

≤ 12 tpy 147 10.2 $3.5 35.8 $187,875

>12 to ≤ 50 tpy 53 36.4 $3.5 35.8 $241,729

≥ 50 tpy 0 $3.5 35.8 - Total: 200 $429,604

The total net costs for compressor sta tion LDAR are set forth in Table 26.

Table 26: Compressor Station Net Leak Inspection and Repair Costs

Compressor Station Fugitive VOC Tier [tpy] Number of Compressor

Stations Total Annual Inspection

Cost Total

Annual Repair Cost Total

Annual

Value of

Recovered

Natural

Gas Net Annual

Leak Inspection and

Repair Costs

≤ 12 tpy 147 $208,799 $223,957.4 $187,875 $244,882

>12 to ≤ 50 tpy 53 $798,265 $299,113.3 $241,729 $855,650

≥ 50 tpy 0 - - - Total: 200 $1,007,064 $523,071 $429,604 $1,100,531

For well production facilities the estimated a nnual inspection costs are set forth in Table 27.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 46 Table 27: Well Production Facility Leak Inspection Costs Using IR Camera/Method 21 Hybrid

Uncontrolled

VOC at Storage Tank Battery Tier [tpy] O&G

Basin* Number

of

Facilities Annual Inspection Frequency Total

Number of Inspections Inspection

Time Per Inspection

[hours] Total Annual Inspection

Cost

In-House Inspections at $103/hour

> 6 to ≤ 12 DJ/NAA 945 1 945 6.1 $593,744

> 12 to ≤ 50 DJ/NAA 2,447 4 9,788 6.1 $6,149,800 > 50 DJ/NAA 693 12 8,316 6.1 $5,224,943
Subtotal: 4,085 19,049 $11,968,487

In-House Inspections at $103/hour

> 6 to ≤ 12 ROS 173 1 173 6.4** $114,042

> 12 to ≤ 50 ROS 176 4 704 6.4 $464,077 > 50 ROS 115 12 1,380 6.4 $909,696
Subtotal: 464 2,257 $1,487,815

Contract Inspections at $134/hour

> 6 to ≤ 12 DJ/NAA 150 1 150 6.1 $122,610

> 12 to ≤ 50 DJ/NAA 153 4 612 6.1 $500,249 > 50 DJ/NAA 118 12 1,416 6.1 $1,157,438
Subtotal: 421 2,178 $1,780,297

Contractor Inspections at $134/hour

> 6 to ≤ 12 ROS 140 1 140 6.4** $120,064

> 12 to ≤ 50 ROS 148 4 592 6.4 $507,699 > 50 ROS 52 12 624 6.4 $535,142
Subtotal: 340 1,356 $1,162,905

Total: 5,310 24,840 $16,399,504

* ROS = Remainder of State

** ROS inspection time includes additional 3 hours for travel time

Repair costs associated with these inspections are set forth in Table 28 and fuel savings associated with these repairs are set forth in Table 29.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 47 Table 28: Well Production Facility Leak Repair Costs

Uncontrolled

VOC at Storage Tank Battery Tier [tpy] O&G

Basin Number of

Facilities Number of Leaks per

Tank Total Leak Repair Time

per Tank

[hours] Total Annual Repair Cost

> 6 to ≤ 12 DJ/NAA 1,095 17.0 11.8 $855,887

> 12 to ≤ 50 DJ/NAA 2,600 25.5 17.7 $3,048,365 > 50 DJ/NAA 811 34.1 23.6 $1,267,807 Subtotal: 4,506 $5,172,059

> 6 to ≤ 12 ROS 313 9.7 7.7 $159,645

> 12 to ≤ 50 ROS 324 14.5 11.6 $248,956 > 50 ROS 167 19.4 15.4 $170,356
Subtotal: 804 $578,957

Total: 5,310 $5,751,016

Table 29: Well Production Facility Recover ed Natural Gas Value from Leak Repairs

Uncontrolled

VOC at Storage Tank Battery

Tier [tpy] O&G

Basin Number

of

Facilities Total

Recovered

Natural Gas per

tank [tons/year] Value of

Natural

Gas [$/MCF] Conversion

Factor [MCF/ton] Total Annual

Value of

Recovered

Natural Gas

> 6 to ≤ 12 DJ/NAA 1,095 4.6 $3.5 35.8 $631,136

> 12 to ≤ 50 DJ/NAA 2,600 7.0 $3.5 35.8 $2,280,460 > 50 DJ/NAA 811 9.3 $3.5 35.8 $945,050
Subtotal: 4,506 $3,856,646

> 6 to ≤ 12 ROS 313 4.6 $3.5 35.8 $180,407

> 12 to ≤ 50 ROS 324 6.8 $3.5 35.8 $276,061 > 50 ROS 167 9.1 $3.5 35.8 $190,418
Subtotal: 804 $646,886

Total: 5,310 $4,503,532

The total net costs for well production facility station LDAR are set forth in Table 30.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 48 Table 30: Well Production Facility –Net Leak Inspection and Repair Costs

Uncont.

VOC at Storage

Tank Battery Tier [tpy] O&G

Basin Total Annual Inspection

Cost Total

Annual Repair

Cost Total

Annual

Value of

Recovered

Natural Gas Net Annual

Leak Inspection and Repair

Costs In-House Contractor

> 6 to ≤ 12 DJ/NAA $593,744 $122,610 $855,887 $631,136 $941,105

> 12 to ≤ 50 DJ/NAA $6,149,800 $500,249 $3,048,365 $2,280,460 $7,417,954 > 50 DJ/NAA $5,224,943 $1,157,438 $1,267,807 $945,050 $6,705,138
Subtotal: $11,968,487 $1,780,297 $5,172,059 $3,856,646 $15,064,197

> 6 to ≤ 12 ROS $114,042 $120,064 $159,645 $180,407 $213,344

> 12 to ≤ 50 ROS $464,077 $507,699 $248,956 $276,061 $944,671 > 50 ROS $909,696 $535,142 $170,356 $190,418 $1,424,776
Subtotal: $1,487,815 $1,162,905 $578,957 $646,886 $2,582,791

Total: $13,456,302 $2,943,202 $5,751,016 $4,503,532 $17,646,988

Additionally, based on informati on in the Division’s APEN reporting system, there are 2,799
well production facilities with uncont rolled actual storage tank emissions less than or equal to 6
tons per year that will be subject to a one-tim e instrument based inspection. The one-time cost
for inspecting these facilitie s is estimated to be $1,639,239. 49

Table 31: Well Production Facility Leak Inspection Costs Using IR Camera/Method 21 Hybrid

Uncontrolled

VOC at Storage Tank Battery

Tier [tpy] O&G

Basin Number of

Facilities and

Inspections Inspection

Time Per Inspection

[hours] Inspection Type/Hourly Rate Total Annual Inspection Cost

≤ 6 DJ/NAA 1,598 6.1 In-House/$103 $1,004,023

≤ 6 ROS 500 3.4 In-House/$103 $175,100
Subtotal: 2,098 $1,179,123

≤ 6 DJ/NAA 389 6.1 Contractor/$134 $317,969

≤ 6 ROS 312 3.4 Contractor/$134 $142,147
Subtotal: 701 $460,116

Total: 2,799 $1,639,239

49 To calculate these costs the Division used the same methodology applicable to periodic inspection costs, except

that it did not include additional travel time for facilitie s outside the NAA based on the assumption that companies could coordinate these one-time inspections with visits to the facilities for other purposes.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 49 The Division recognizes that th ere are likely additional faciliti es not included in the APEN
database that will be subject to this one-time inspection requirement, thereby increasing the
overall cost of the one-time inspection require ment. Roughly speaking th e additional cost for
one-time inspections will be proportional to the numb er of additional faciliti es, so that if there

are twice the number of facili ties, the overall cost will be approximately double. However,
because the expected emission reduc tion benefit will increase roughly at the same rate as the cost
of inspections the overall cost-effectiveness of the one-time inspection requirement should
remain approximately the same regard less of the number of facilities.

Finally, the Division calculated the cost effectiveness of the proposed LDAR requirements based
on the costs identified above and the projecte d emission reductions. To determine emission
reductions the Division first calculated pre- inspection program VOC and methane emissions
based on the reported component counts, standard emission factors for these components, and
the average fraction of VOC a nd non-VOC emissions (methane/e thane). Based on EPA reported
information, the Division calculated a 40% reduc tion for annual inspections, a 60% reduction for
quarterly inspections, and an 80% reduction for monthly inspections.

Using this information the Division calculated th at the total emission reductions from leaks at
compressor stations will be 1,107 tpy VOC and 2,321 tons per year methane/ethane.

Table 32: Compressor Station Leak Inspection Emission Reductions Comp.

Station Fugitive

VOC Tier [tpy] Number of Comp

Stations LDAR Program
Reduction

% Fugitive

VOC

Emissions

for each CS

tier [tpy] Total

VOC

Reduction [tpy] Fugitive

Methane-Ethane

Emissions for

each CS tier [tpy] Total

MethaneEthane

Reduction [tpy]

≤ 12 147 40% 10.1 588.0 15.5 911.4

> 12 to ≤ 50 53 60% 16.4 519.4 44.3 1,409.8

> 50 80%
200 1,107.4 2,321.1

Based on these reductions, the co st effectiveness of conducting l eak inspections at compressor stations is estimated to be $994/t on VOC and $474/ton methane/ethane.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 50 Table 33: Compressor Station Leak Inspection Cost Effectiveness using IR Camera/Method 21 Comp.

Station Fugitive

VOC Tier [tpy] Number of Comp

Stations Total Net

Annual Inspection & Repair

Cost LDAR Program
Reduction

% Total

VOC

Reduction [tpy] VOC

Control

Cost [$/ton] Total

MethaneEthane

Reduction [tpy] Methane

-Ethane

Control

Cost [$/ton]

≤ 12 147 $244,882 40% 588.0 $416 911.4 $269

> 12 to ≤ 50 53 $855,650 60% 519.4 $1,647 1,409.8 $607

> 50 80% 200 $1,100,531 1,107.4 $994 2,321.2 $474

For well production facilities the total emission reductions is estimated to be 14,015 tpy VOC and 21,927 tpy methane/ethane.

Table 34: Well Production Facility Le ak Inspection Emission Reductions

Uncontrolled

VOC at Tank Battery

Tier [tpy] Number

of

Facilities LDAR Program
Reduction

% Fugitive

VOC

Emissions

for each

Tank Battery [tpy] Total VOC

Reduction [tpy] Fugitive

MethaneEthane

Emissions for

each Tank Battery [tpy] Total

MethaneEthane

Reduction [tpy]

DJ/NAA

> 6 to ≤ 12 1,095 40% 4.6 1,971.0 7.0 3,066.0

> 12 to ≤ 50 2,600 60% 4.6 7,280.0 7.0 10,920.0 > 50 811 80% 4.6 3,000.7 7.0 4,541.6
Subtotal: 4,506 12,251.7 18,527.6

Remainder of State

> 6 to ≤ 12 313 40% 3.9 500.8 7.5 939.0

> 12 to ≤ 50 324 60% 3.9 745.2 7.5 1,458.0 > 50 167 80% 3.9 517.7 7.5 1,002.0 Subtotal: 804 1,763.7 3,399.0

Total: 5,310 14,015.4 21,926.6

Based on these reductions, th e cost effectiveness of c onducting ongoing instrument based inspections at well production facilities is estimated to be $1,259/ton VOC and $805/ton

methane/ethane.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 51 Table 35: Well Production Facility Leak Co st-Effectiveness Using IR Camera/Method 21

Uncont.
VOC at Tank Battery Tier [tpy] Number

of Tanks Total Net

Annual Leak Inspection & Repair Cost LDAR Program
Reduction

% Total

VOC

Reduction [tpy] VOC

Control

Cost [$/ton] Total

MethaneEthane

Reduction [tpy] Methane

-Ethane

Control

Cost [$/ton]

DJ/NAA

> 6 to ≤ 12 1,095 $941,105 40% 1,971.0 $477 3,066.0 $307

> 12 to ≤ 50 2,600 $7,417,954 60% 7,280.0 $1,019 10,920.0 $679 > 50 811 $6,705,138 80% 3,000.7 $2,235 4,541.6 $1,476
Subtotal: 4,506 $15,064,197 12,251.7 $1,230 18,527.6 $813

ROS

> 6 to ≤ 12 313 $213,344 40% 500.8 $426 939.0 $227

> 12 to ≤ 50 324 $944,671 60% 745.2 $1,268 1,458.0 $648 > 50 167 $1,424,776 80% 517.7 $2,752 1,002.0 $1,422
Subtotal: 804 $2,582,791 1,763.7 $1,464 3,399.0 $760

Total: 5,310 $17,646,988 14,015.4 $1,259 21,926.6 $805

Additionally, for the 2,799 well prod uction facilities with uncont rolled actual storage tank emissions equal to or less than 6 tons per year that will be subject to a on e-time instrument based inspection, the calculated one-tim e benefit is 4,876 tons VOC and 8,000 tons methane/ethane, assuming a 40% reduction. Based on these reduc tions, for the one-time inspections of well production facilities with tanks that are less than six tons per year the cost effectiveness of the proposed rule is calculated to be $409/ton VOC and $249/ton methane/ethane.

In addition to the component LDAR requireme nts for compressor stations and well production facilities, the Division’s proposal includes additional requirements designed to reduce leaks from open ended lines and valves, reciprocating comp ressors, and wet seal centrifugal compressors. These requirements mirror existing cost-effec tive requirements set forth in NSPS OOOO and

other federal rules.

For open ended valves and lines at well produc tion facilities and co mpressor stations, the proposal requires that each such valve or line be equipped wi th a cap, blind flange, plug or second valve commencing January 1, 2015. Alte rnatively, the Division ’s proposal allows
operators to treat open- ended lines and valves as components and monitor them in accordance with the proposed LDAR requirements. As part of its LDAR cost effectiveness analysis detailed above, the Division included the costs of inspecti ng and repairing open ended lines and valves in

its overall calculation. While the Division has not identified specific in formation regarding the costs and emission reduction benefits from equi pping open ended lines with a cap, blind flange, plug or second valve it notes that the requirement has been include d in a multitude of federal air quality rules, including NSPS VV, NSPS VVa, MACT H, MACT CC, MACT TT, MACT YY, MACT GGG, MACT III, and MACT MMM, dati ng back as far as 1983. Based on this2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 52 widespread prevalence in federal rules the Division believes that the proposal represents a simple and cost-effective strategy to reduce emissions fr om open-ended lines and valves. However, to

the extent that it is not cost effective in a specific case operators can employ the monitoring option allowed for under the proposed rule.

For centrifugal compressors, the Division’s propos al requires that hydro carbon emissions from wet seal fluid degassing systems be reduced by 95% beginning January 1, 2015. In its updated technical support document for NSPS OOOO, EPA analyzed the cost-effectiveness of this strategy and found that accoun ting revenues from the captu re of additional product, implementation of this strategy would on a per unit basis reduce VOC emissions by 19.5 tpy, methane emissions by 216.2 tpy, and resu lt in a net cost savings of $46,974. 50

With respect to reciprocating compressors, the Division’s proposal requires that commencing January 1, 2015, the rod packing fo r reciprocating compressors loca ted at compressor stations be replaced every 26,000 hours of operation or every 36 months. As with the requirement for centrifugal compressors, EPA analyzed this proposed strategy as part of the adoption of NSPS

OOOO and found that it was a cost-effective way to reduce VOC and methane emissions. Specifically, EPA found that per compressor the st rategy reduces VOC emissions by 1.9 tons per year and methane emissions by 6.8 tons per year, at a net cost of $43 per ton of VOC reduced and $12 per ton of methane reduced. 51

3.3.8.1.7 Auto	Igniter	Requirements	on	Exi sting	Flare	Control	Devices	Out side	the	NAA Unlike the NAA, flares used to control emissi ons at condensate tank batteries and glycol dehydration units outside the NAA are not required to have auto-igniters. The Division is proposing that all flares used to control emi ssions at condensate tank batteries and glycol dehydration units statewide should have auto igni ters. Based on an analysis of the APEN database, the Division estimates the statewide nu mber of existing flare control devices without auto-igniters on condensate tank batteries, glycol dehydration, produced water tanks, and crude oil tanks is 796. The reported uncontrolled act ual emissions from these units are 53,101.1 tons per year VOC.

The estimated annualized cost for an auto-ignite r is $475 based on information that the industry provided to the Division in 2008, adjusted for inflation. 52

50 See APCD-PHS Ex. HHHH pp. 6-1—6-3

51 See initial technical support document for NSPS OO OO (submitted as DGS-PHS Ex . NN) at pp. 6-12—6-17.

52 See “Oil & Gas Emissions Reduction Strategies Cost Analys is and Control Efficiency Determination,” Lesair Environmental, Inc., June 2008.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 53 Table 36: Auto Igniter Control D evice – Retrofit Cost Analysis

Item Capital Costs (one time) Non-Recurring Costs (one time) O&M Costs (recurring) Annualized

Total Costs Auto Igniter $1,648 Freight/Engineering $200
Flare Installation $500
Maintenance $200
Subtotal Costs $1,648 $700 $200
Annualized Costs* $228.4 $46.7 $200 $475

* Annualized over 15 years at 5% ROR

The Division estimates that a flare without an au to-igniter could experience about 3% pilot light downtime (262.8 hours) over a one year peri od. During the downtime period, any VOC

emissions routed to the flare control device are uncontrolled. Based on the total uncontrolled actual emissions of 53,101.1tons per year VOC from units equipped with flares without autoigniters, the emissions during this downtime pe riod will be 1,593.1 tons of VOC. The Division

assumes that as a result of the installation of an au to-igniter, the amount of downtime can be eliminated, for a total emission reduction of 1,251.7 t ons/year. Given that the annualized cost of installing 796 auto-igniters is a bout $378,100 the estimated cost eff ectiveness of this strategy is about $302 per ton of VOC reduced.

Table 37: Auto Igniter Emission Reduction Estimates

Source Type for Existing

Flare Controls Number of

Auto Igniters Uncontrolled VOC [tpy] Uncontrolled VOC Using 3% Downtime [tpy] Total VOC

Reduction [tpy] Condensate Tanks 490 31,170.6 935.1 666.3 Dehydrators 131 16,372.0 491.2 466.6 Produced Water Tanks 172 4,842.2 145.3 103.5

Crude Oil Tanks 3 716.3 21.5 15.3
796 53,101.1 1,593.1 1251.7
* Dehydrator flares assumed to have 100% capture and 95% destruction – thus 95% control. Tank flares are assumed to have 75% capture and 95% destruction – thus 71.25% control.

Table 38: Auto Igniter Control Cost Estimates (Outside NAA)

Number Each Auto-Igniter

Annualized Costs Total Annualized

Costs VOC Reduction* [tons/year] Control Costs [$/ton] 796 $475 $378,100 1,251.7 $3022/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 54 3.3.8.2 Expanding Low Bleed Pneumatics Requirements Statewide As part of the 2008 Ozone Action Plan the Commission adopted regulatory requirements mandating the use of low bleed pneumatic controlle rs in the NAA. The current proposal would expand this requirement statewide.

To estimate the costs and benefits of this propo sed strategy, the Division estimated the number of high-bleed pneumatic devices based on Independ ent Petroleum Association of the Mountain States (IPAMS) survey data from 2006, which identified the averag e number of such devices per

well. The Division then scal ed this number up based on 2012 COGCC well count data. Based on this methodology, there are 9,877 high-bleed pneuma tic devices outside the NAA. Assuming a 95% replacement rate, the proposed rule will result in the replacement of 9,384 high bleed

devices with low bleed devices. Based on this count, and the average em ission reductions per device replaced identified in the IPAMS surv ey, the projected benefit from the proposed expansion of the current NAA low bleed pneumatic rule will be approximately 14,921 tons per year VOC (40.9 tons per day). Based on this information and assuming an 80/20 ratio of methane/ethane to VOC by volume, the estimated methane/ethane reduction from this strategy is 17,100 tons per year.

The average retrofit cost of a high-bleed pneum atic device is based on costs from the 2008 cost study 53 adjusted for inflation. Utilizing this me thodology, the annualized cost for each replaced device is $169. However, because the reduced bleed rate results in more natural gas being sold, operators will receive additional revenue as a resu lt of the installation of a low bleed device.

Based on the emission reduction data from the IPAMS survey and August 2013 spot prices for natural gas, the estimated average value of the recovered gas will be $1,268 for each device replaced. As a result, the net annual gain is $1,084 per replaced device. Based on this projected net gain, this strategy will pay for itself in approximately one year and two months.

Table 39: Replace High-Bleed Pneumatics with Low-Bleed Pneumatics – Annualized Cost Analysis*

Item Capital Costs (one time) Non-Recurring Costs (one time) O&M Costs (recurring) Annualized

Total Costs

Low/No Bleed

Device* $1,033

Labor $387 Value of NG Saved** $(1,268)
Maintenance $16 Subtotal Costs $1,033 $387 $(1,253) Annualized Costs*** $143 $26 $(1,253) $(1,084)

* Control device costs were developed based on an Oil and Gas Cost Study and informat ion submitted by industry in 2008. However, those costs were escalated by 9.85% to reflect CPI-U increases that have occurred since 2008. ** Recovered NG fuel costs $3.5/MCF (Henry Hub Spot Price - Aug. 2013) *** Annualized over 15 years at 5% ROR

53 See “Oil & Gas Emissions Reduction Strategies Cost Analys is and Control Efficiency Determination,” Lesair Environmental, Inc., June 2008.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 55 Assuming 9,384 total devices replaced, adoption of this strategy will result in $10,169,441 in annual cost savings.

Table 40: Low Bleed Pneumatic Control Cost Estimates (Outside NAA)

Number Each Device

Annualized Costs Total Annualized

Costs VOC Reduction [tons/year] Control Costs [$/ton] 9,384 $(1,084) $(10,169,441) 14,921 NA

The proposed rule also requires the use of no-blee d pneumatic devices if it is technically and economically feasible and where on- site electrical grid power is being used. Use of no-bleed pneumatic devices will further reduce emissions rela tive to the use of low bleed devices. Since

the Division does not have information indicatin g the number of no-bleed pneumatic devices that could be required, it is not possibl e to calculate the cost effectiven ess of this particular provision. However, because the proposed requirement expressly provides that use of no-bleed pneumatics is only required where economically feasible th e Division assumes that any use of no-bleed pneumatic devices pursuant to the propos ed rule will be cost effective.

3.3.8.3 Require Newly Constructed Gas Wells be Connected to a Pipeline or Route

Emissions to a Control Device Currently in Colorado, natural gas produced at oil and gas sites is typically routed to a transmission pipeline. With the advent of new drilling technologies, additional areas of the state without established pipeline in frastructure may experience oil and gas ex ploration and production. This can lead to instances where produ ced gas is vented or flared instead of being put into a transmission line. To date the Divi sion has identified 61 inst ances in Colorado where this is occurring. To address this, the proposed regulation provi des that for newly constructed, hydraulically fractured, or recomp leted wells, the gas stream must either be connected to a pipeline or routed to a control device achieving 95% cont rol efficiency. Currently all of the sites that are not routed to a pipeline are flaring thei r gas. Additionally, because venting the gas at such sites would create a safety issue, the Divisi on assumes that in the limited future instances where the gas stream is not routed to a pipeline , operators will route the emissions to a flare or other control device. Accordingly, adoption of th is portion of the proposed regulation will likely not result in any a dditional costs.

3.3.8.4 Control Requirements for Glycol Dehydrators The Division is proposing to revise the control requirements applicable to glycol natural gas dehydrators statewide. Currently any glycol natural gas deh ydrator with unc ontrolled actual VOC emissions of 2 tons per year or greater th at is located at a facility where the sum of uncontrolled actual emissions from all of the dehydrat ors at the facility is greater than 15 tons per year, must be equipped with a control device th at reduces emissions by at least 90%. Under the Division’s proposal, all existing de hydrators with uncontrolled act ual emissions of 6 tons per year or greater VOC must be controlled with ai r pollution control equipment achieving at least 95% reduction. The proposal also provides that existing dehydrators w ith uncontrolled actual emissions of two tons per year or greater VOC must be controlled if they are located within2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 56 1,320 feet of a building unit or designated outside activity area. Finall y, the proposal requires that all new dehydrators with uncont rolled actual emissions of two tons per year or greater VOC be controlled. The Division assumes that newly subject glycol dehydrators will be controlled using flares that achieve a 95% destruction efficiency. The annual cost for these units is $6,286.80 per unit.

Based on industry reported APEN data, there are currently 433 uncontrolled dehydrators at sites with total dehydrator uncontrolled actual VOC emissions below 15 tpy. Of these, 217 have uncontrolled actual emissions greater than or equal to two tons per year. The total uncontrolled actual emissions for these 217 dehydrators are 1,827.5 tpy VOC. There are 148 dehydrators with uncontrolled actual VOC emissions greater than or equal to 6 tons per year. The total uncontrolled actual emissions for these 148 dehy drators are 1,549.7 tpy VOC. Currently, the

Division does not have inform ation regarding the location of these uncontrolled dehydrators relative to a building unit or de signated outside activity area. A ssuming, however, that all of the 2 to 6 ton dehydrators are located within 1,320 f eet of a building unit or designated outside activity area and thus will require a control, the proposed requirement will reduce 1,736 tpy of VOC at a cost effectiveness of $786/ton VOC. For the smallest dehydrator subject to the proposed rule (2 ton/year) the cost effectiv eness is estimated to be $3309 per ton of VOC

reduced.

Table 41: Dehydrator Control Cost Estimates (2 TPY Control Threshold)

Number Each Device

Annualized Costs Total Annualized

Costs VOC Reduction [tons/year] Control Costs [$/ton] 217 $6,286.8 $1,364,236 1,736 $786

Conversely, if it is assumed that none of the 2 to 6 ton existing dehydrators will require controls the proposed requirement will reduce 1,472 tpy of VOC at a cost effectiveness of $632/ton VOC.

Table 42: Dehydrator Control Cost Estimates (6 TPY Control Threshold)

Number Each Device

Annualized Costs Total Annualized

Costs VOC Reduction [tons/year] Control Costs [$/ton] 148 $6,286.8 $930,446 1,472 $632

3.3.8.5 Control Requirements for Downhole Well Maintenance and Liquids Unloading

Events Historically, Colorado has not regulated air emi ssions from temporary activities such as well completions and well maintenance at well producti on sites. Recently, however, EPA, Colorado and other jurisdictions have identified these activ ities as potentially larg e sources of emissions from the oil and gas sector. In recognition of this, the Colorado O il and Gas Conservation Commission and more recently EP A have adopted requirements for green completions to reduce hydrocarbon emissions during well completion activities. The Divi sion is now proposing additional regulatory requirements designed to reduce emissions during well maintenance.2/11/14 Regulatory Analysis for Proposed Revisions to Regulation 3, 6, and 7 Page 57 Well maintenance is required when, over time, liquids build up inside the well and reduce gas

and oil flow out of the well. To remove thes e liquids and improve flow, the liquids are blown out of the well under pressure. This process is typically referred to as liquids load-out or well blow-down. Historically emissions from well bl ow-downs are vented to the atmosphere. EPA

has established emission factors for liquid unloading based on fluid equilibrium calculations to calculate the amount of gas needed to blow down a column of fl uids blocking a well and Natural Gas STAR partner data on the amount of additional venting after a blow-down. Based on its calculations, EPA estimated that in the United States the combined methane emissions for liquid unloading and well completions in 2009, was 217 b illion cubic feet, and that liquid unloading may account for 33% of the uncontrolled methan e emissions from the natural gas industry. 54 For Colorado, the Division has calculated that em issions from well blow-downs in 2008 were approximately 9,306 tons of VOC per year.

To address these emissions, the Division is proposing a two pronged requirement aimed at reducing the number of required liquids unloading events and re ducing the amount of emissions vented to the atmosphere during these events. Under the Division’s proposal operators shall use best management practices to minimize the need for venting associated with downhole maintenance and liquids unloading. For example, EPA’s Gas Star program advocates the use of a plunger lift system to reduce the need for liqui ds unloading. According to EPA, use of a plunger lift will on average pay for itself in less than one year through the capture of additional product. The Division’s proposal also provides that emission s during well maintenance and liquids unloading shall be captu red or controlled using best management practices to limit venting during well blow-downs to the maximu m extent practicable. Based on information provided by Environmental Defens e Fund, application of these requirements could result in annual VOC reductions of 2,881 tons and methane reductions of 19,207 tons per year. Given the wide variety of practices that this could entail, the Division cu rrently does not have information about the precise cost-effectiven ess of this provision. Given th e fact that the proposal only requires use of best management practices, which ta kes into account the cost of the practices in a given situation, the Division assumes that th e proposed strategy will be cost effective.



### 4 CLOSING SUMMARY

On December 13, 2013, interested pa rties, stakeholders and state representatives filed requests for a Regulatory Analysis. This Regulatory Analysis is a careful and considerate response to those Requests and is a good faith e ffort on the part of the Division.

The Division has addressed, to the best of its ab ility, issues related to the entirety of proposed revisions to Regulation 3, 6, and 7. The Division believes that the proposal before the Commission reflects a balanced approach that in cludes proven and cost effective strategies to reduce emissions from the oil and gas sector, while enabling the sector to c ontinue to grow in a responsible and protective manner. The Di vision looks forward to the Commission’s consideration of its proposal and alternate proposals of other parties at the February 2014 hearing.

54 See EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2009 , April, 2011.