before the air quality control commission - Weld County

BEFORE THE AIR QUALITY CONTROL COMMISSION

STATE OF COLORADO

______________________________________________________________________________

IN THE MATTER OF PROPOSED REVISIONS TO REGULATION NO. 7 AND

REGULATION NO. 22

______________________________________________________________________________

PREHEARING STATEMENT OF THE BOARD OF COUNTY COMMISSIONERS OF

WELD COUNTY, COLORADO

______________________________________________________________________________

I. EXECUTIVE SUMMARY

This Prehearing Statement is submitted on behalf of the Board of County Commissioners

of Weld County (“Weld County”) in connection with the above-captioned hearing and pursuant to

C.R.S. §§ 24-4-101 et seq., §§ 25- 7-101 et seq., 5 CCR 1001-1, and the Filing Requirements for

Parties circulated by the Air Quality Control Commission (“Commission”). Weld County

appreciates the opportunity to participate in this rulemaking regarding revisions to Regulation No.

7 and No. 22 (“Proposed Rule”) proposed by the Colorado Department of Public Health and

Environment’s Air Pollution Control Division (“the Division”). As the largest oil and gas

producing county in the state, Weld County has a keen interest in the efficient, effective, and

common-sense regulation of oil and gas production for the protection of the environment, public

health, and the economic prosperity of over 325,000 Weld County residents.

This rulemaking concerns the following greenhouse gas (“GHG”) emission reduction

requirements for operations in the upstream and midstream segments of the oil and gas (“oil and

gas”) industry:

• Air pollution control requirements (Regulation 7, Part D, Section II);

• Midstream segment requirements pertaining to leak detection and repair (LDAR),

compressor rod packing, pneumatic controllers, pigging and blowdown operations, and

long-term planning for midstream fuel combustion equipment (Regulation 7, Part D,

Sections II and III; Regulation 22, Part B, Section III);

• Upstream segment intensity program (Regulation 7, Part D, Sections II and VI; Regulation

22, Part B, Section IV); and

• Inventory revisions related to the proposed requirements above (Regulation 7, Part D,

Section V).

Weld County is highly concerned with the late rule revisions issued by the Division on

October 21, 2021, one (1) week before the prehearing statements are due. There was insufficient

time to evaluate the substance of the proposed revisions and provide meaningful comments.

Further, Weld County asserts that rule revisions are not legally required “for consistency with” the

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EPA’s Control Techniques Guidelines for the Oil and Natural Gas Industry (“CTG”). EPA’s

statements requiring revision of the State Implementation Plan for the Moderate 2008 Ozone

Standard are without basis. Weld County agrees with the statement from Colorado that “states are

allowed to have divergent programs where sufficiently protective.” Colorado’s requirements are

at minimum consistent with—if not more stringent than—the recommendations in the EPA’s

CTG; therefore, Weld County does not support the revised rule language issued on by the Division

on October 21, 2021 and has procedural concerns with the limited time allowed to review and

comment on the rules.

Weld County supports flexible intensity-based GHG emission reduction programs, such as

the Division’s intensity program in the Proposed Rule, particularly in the context of the diverse

emission profiles of the state’s operators and the high level of controls already mandated by the

state. An intensity program would allow operators to examine and implement the most cost-

effective measures to meet the state’s reduction goals. Weld County is concerned the Division’s

proposal of additional command and control regulations in parallel with the proposed intensity

program will negate the key benefit of an intensity program, which affords operators the flexibility

to identify and implement the emission reduction measures that are best suited to their specific

operations. In addition, Weld County is concerned the Division’s intensity targets rely on

projections of future oil and gas production that may not be borne out and could result in

excessively burdensome regulation or insufficient emission reductions. The Proposed Rule should

include provisions that allow for reassessing these targets.

Although Weld County generally supports additional emission reductions, the Division’s

enclosed combustion device (“ECD”) testing program will result in limited emission reductions,

if any, and comes with significant cost, safety, and feasibility implications. Testing of ECD, which

is typically conducted when these devices are operating at optimal conditions, is not likely to

identify or resolve any issues associated with the operation of ECD. Even by the Division’s own

estimates, the ECD testing requirements are expected to result in reductions corresponding to less

than 0.1% of the 2005 oil and gas baseline GHG emissions, which is equivalent to the emissions

from a single mid-sized boiler (i.e., smaller than 30 million British thermal units per hour) fired

by natural gas. Further examination of ECD issues is warranted but should be achieved through a

more focused study to identify and evaluate those parameters that drive continuous control

efficiency in ECD, rather than through a widespread testing program.

Moreover, Weld County is generally supportive of increased leak detection and repair

(“LDAR”) and rod packing replacement requirements, as well requirements to reduce emissions

from pigging, blowdown, and well maintenance activities to the extent these measures are cost-

effective and technically feasible. However, Weld County is concerned with the Proposed Rule’s

prescriptive best management practices (“BMP)” to reduce emissions from pigging, blowdown,

and maintenance activities. Given that no one set of BMP will be appropriate or feasible for all

operations, and that BMP are continually evolving, the Commission should provide operators with

the flexibility to adopt provisions that would allow the operators to identify BMP for their

operations. Likewise, Weld County questions the merits of the Division’s proposed expansion of

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the state’s extensive LDAR requirements that apply to oil and gas operations in Colorado, which

the Division estimates would achieve GHG emission reductions of less than 0.1% of the 2005 oil

and gas baseline GHG emissions.

The initial economic impact analysis (“EIA”) indicates that the ECD testing program has

an abatement cost of $847.85 per metric ton of carbon dioxide equivalent (mtCO2e). This

abatement cost is very high and is further justification to not adopt the proposed ECD testing

requirements and instead conduct tests on a representative sample set.

VOLUMINOUS EXHIBITS

Weld County is not identifying any voluminous exhibits as a part of this Prehearing

Statement.

ESTIMATE OF TIME

Weld County requests 20 minutes, but notes that if one or more alternate proposals require

a significant response, the County would ask that an additional 20 minutes of time—for a total of

40 minutes—be allocated to it for direct and rebuttal testimony and cross-examination, if any.

TABLE OF CONTENTS

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

II. LEGAL, FACTUAL, AND POLICY CONCERNS................................................................. 4

A. The Commission Should Not Alter the Proposed Rule In Response to the EPA’s

Belated Comments. ............................................................................................................. 4

B. Oil and Gas GHG Emissions Have Decreased Significantly Over the Past Eight

Years. .................................................................................................................................. 4

1. Oil and Gas GHG Emission Reductions Are Consistent with Ground-based and Satellite-

based Measurements ................................................................................................................ 4

2. The Division Should Disclose the Reason(s) for the Change in Methodology between the

Draft and Final 2021 Greenhouse Gas Inventory Report. ....................................................... 7

3. Uncertainty in the Oil and Gas Emissions Inventory does not Affect the Ability to

Implement an Intensity Program .............................................................................................. 8

C. Weld County Supports the Proposed Rule’s Upstream Intensity Program. ........................ 9

D. The ECD Testing Provides Limited Emissions Reductions While Imposing

Significant Costs and Unjustifiable Safety Risks. ............................................................ 16

E. The Proposed Changes to the LDAR Requirements are Unnecessary and

Inefficient. ......................................................................................................................... 16

F. Economic Impact Analysis ................................................................................................ 17

1. The Initial EIA May Be Significantly Over-Estimating Cost Effectiveness. ................ 17

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2. The Social Cost of Carbon is Seriously Flawed. ............................................................ 18

3. Cost Estimates in the Initial EIA Demonstrate the Need for an Intensity-Based Program

without the Additional Control Requirements. ...................................................................... 18

III. LIST OF ISSUES .................................................................................................................... 19

IV. LIST OF EXHIBITS ............................................................................................................... 19

V. LIST OF WITNESSES ........................................................................................................... 19

VI. CONCLUSION ....................................................................................................................... 20

II. LEGAL, FACTUAL, AND POLICY CONCERNS

Weld County generally supports the Proposed Rule’s emission reduction requirements for

oil and gas operations with a few exceptions, as set forth more specifically below.

A. The Commission Should Not Alter the Proposed Rule in Response to the

EPA’s Belated Comments.

As an initial matter, Weld County is concerned about the U.S. Environmental Protection

Agency’s (“EPA”) belated comments requesting that Colorado include in its State Implementation

Plan (“SIP”) additional monitoring requirements for storage vessel and wet seal centrifugal

compressor combustion devices “for consistency with” the EPA’s Control Techniques Guidelines

for the Oil and Natural Gas Industry (“CTG”). As noted in Colorado’s response letter, dated

October 20, 2021, CTGs are “presumptive” RACT, and “states are allowed to have divergent

programs where sufficiently protective.” Colorado’s requirements are at minimum consistent

with—if not more stringent than—the recommendations in the EPA’s CTG. Moreover, were the

Division to alter the Proposed Rule in light of the EPA’s request, doing so at this late hour would

raise due process concerns about whether the public was provided adequate notice and a

meaningful opportunity to participate in the rulemaking.

B. Oil and Gas GHG Emissions Have Decreased Significantly Over the Past Eight

Years.

1. Oil and Gas GHG Emission Reductions Are Consistent with Ground-

based and Satellite-based Measurements

During past oil and gas rulemakings, other parties have raised concerns that oil and gas

methane emissions in Colorado are not decreasing despite new control requirements. As Weld

County has clarified in these previous rulemakings, this assertion is not supported by: (1) the

Division’s long-term ground-based monitoring data collected at Platteville; (2) a recent peer-

reviewed journal article that assessed oil and gas contributions to nonmethane VOCs (NMOC) in

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the Front Range and found NMOC concentrations are decreasing1; or (3) Long-term methane

trends measured by the AIRS instrument on the Aqua satellite.2

Most importantly, the concern that oil and gas emissions are not decreasing is not

supported by long-term monitoring conducted by the Division at Platteville, Colorado. The State

of Colorado’s “Technical Support Document for Point Source and Oil and Gas Emissions

Inventory Development” for the Serious Ozone SIP provided an analysis of oil and gas emissions

trends and compared the trends to measured VOC concentrations (shown in Figure 1).3 The

Division concluded that oil and gas VOC emissions inventories are steadily decreasing and have

decreased 67% since 2012. Furthermore, these trends are consistent with ambient air quality

measurements (shown in Figure 1). These trends in decreasing in ambient VOC concentrations

have continued through 2020.4 Due to a change in 2017 in the laboratory used by the Division,

the Platteville methane concentration trends cannot be evaluated; however, trends in nonmethane

hydrocarbons monitored at Platteville and emitted primarily from the oil and gas sector (e.g.,

ethane, propane, and n-butane) show substantial downward trends and there is no evidence to the

contrary that methane emissions from oil and gas sector are not also decreasing. Overall,

Platteville station monitoring data and the Division’s emissions inventory data indicate that

1 See C. Lou, S.L. Capps,, K. Kurashima, D.K. Henze, G. Pierce, A. Hakami, S. Zhao, J. Resler,

G.R. Carmichael, A. Sandu, and A.G. Russell, “Evaluating oil and gas contributions to ambient

nonmethane hydrocarbon mixing ratios and ozone-related metrics in the Colorado Front Range,”

Atmospheric Environment 246, at 118113 (2021). 2 See WeldCo_PHS-EX-002, “Preliminary Analysis of Northern Colorado Methane and Ethane

Trends Using AIRS Satellite Data and Platteville Surface Measurements,” Ramboll (2021). 3 “Technical Support Document for Point Source and Oil & Gas Emissions Inventory

Development,” RAQC (accessed on July 7, 2021),

https://raqc.egnyte.com/dl/hi3MOfNkUP/DMNFR_Serious_PointSourceTSD_APCD_Final_12N

OV2020.pdf_. 4 Ozone Precursor Monitoring, CDPHE (accessed on October 24, 2021),

https://www.colorado.gov/airquality/tech_doc_repository.aspx#ozone_precursor_data

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emission control measures on the oil and gas industry have reduced VOC and methane

concentrations in northern Colorado, contrary to concerns raised by some other parties.

Figure 1. VOC Emissions Inventory Trends Compared to Measured Concentrations

Furthermore, to better understand the efficacy of past oil and gas regulations and drivers

for future emission control regulations, Weld County commissioned a study of methane trends in

northern Colorado over the past decade using satellite and surface measurement data. The study

and preliminary findings are presented in WeldCo_EX-001.5 While a variety of agencies,

researchers, and other groups have assessed methane and VOC concentrations in Colorado from

surface and aerial measurements, satellite methane data has not been widely used to assess

methane in Colorado. Ramboll selected the Atmospheric Infrared Sounder instrument, or AIRS,

to assess methane trends in northern Colorado because of the reliability of its data. AIRS was

launched in 2002, continues to operate, and provides an accurate estimate of the rates of change

in methane from year-to-year. The use of AIRS to estimate methane trends and relative changes

is consistent with analyses conducted by other scientists and published in peer-reviewed journals.6

As shown in Figure 2, results from the Ramboll study indicate background-adjusted AIRS

satellite data of northern Colorado methane concentrations are estimated to have decreased 52%

from the peak in 2013 through 2019. During the same period, ethane concentrations monitored at

Platteville decreased by 65%. Ethane is a better tracer for oil and gas emissions and is well

correlated with background-adjusted methane concentrations estimated from AIRS (R2 of 0.67).

5 See WeldCo_ EX-001. 6 Xiaodi Wu, Xiuying Zhang, Xiaowei Chuai, Xianjin Huang, and Zhen Wang.. “Long-term trends

of atmospheric CH4 concentration across China from 2002 to 2016,” Remote Sens. 11, no. 5: 538

(2019), https://doi.org/10.3390/rs11050538.

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Figure 2. Estimated northern Colorado methane trends adjusted for background concentrations.

These preliminary findings are significant. In particular, these trends demonstrate that past

regulatory changes have effectively reduced local methane emissions from the oil and gas sector

even during a period with substantial production increases. This data set evidences the

effectiveness of regulations undertaken by the Commission over the last decade to reduce oil and

gas emissions, including methane.

2. The Division Should Disclose the Reason(s) for the Change in

Methodology between the Draft and Final 2021 Greenhouse Gas

Inventory Report.

In September 2021, the Division released the final emission inventory publication

“Colorado 2021 Greenhouse Gas Inventory Update Including Projections to 2050” (final

publication). In the final publication, the Division revised the downstream oil and gas emissions

estimates which resulted in a slight decrease in the historic (2005-2019) Natural Gas and Oil

Systems emissions compared to draft inventory released in January 2021 (draft publication). The

upstream oil and gas emissions in the final publication remain unchanged. Downstream

(transmission and distribution) emission estimates in the final publication are based on the EPA

State Inventory Tool (“SIT”), whereas downstream emissions in the draft publication are based on

measurements of methane from flyover studies.

The downstream emission estimation methodology in the final publication is completely

different from the draft publication. As previously stated, emissions in the draft publication are

estimated using the “catchall” leak rate derived from the flyover studies. According to the

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Division, the methane leak rate from the flyover studies is based on the studies conducted in

Colorado and elsewhere. These studies do not provide sufficient information available to evaluate

the accuracy or completeness of the leak rate data. Further, some flyover studies are conducted

outside of Colorado which may not represent operations. The SIT Natural Gas and Oil System

module used in the final publication estimates greenhouse gas emissions from all phases of natural

gas systems (including production, transmission, venting and flaring, and distribution) and

petroleum systems (including production, refining, and transport). It is understood that only

downstream emissions from the draft publications are replaced with the SIT estimates in the final

publication. The Division estimated emissions based on the default SIT emission factors and total

transmission pipeline mileage and total distribution mileage from the Public Utilities Commission

in the Department of Regulatory Agencies and the U.S. Department of Transportation’s Pipeline

and Hazardous Material Safety Administration. The analysis excludes emissions from natural gas

processing plants, LNG storage compressor stations and emissions associated with end service in

the SIT. Although the SIT uses the state specific activity data, the emission factor in the tool

represents an average for the entire country. There are no State specific emission factors available

in the tool. These emission factors are based on the various measurements, equipment design,

surveys, and engineering calculations which may not represent State-specific characteristics

including facility design, operation, controls, and maintenance. Considering the stringent controls

currently required of facilities in Colorado, the SIT likely overestimates emissions.

The Division alleges that the approach used in the draft publication is less reliable

compared to estimates from SIT without adequate supporting details. The Division should disclose

the reason for the change in methodology between the draft and final publication. Without

sufficient details on the reason to revise the downstream emissions methodology, Weld County’s

ability to agree or disagree with the Division’s decision is inappropriately limited.

3. Uncertainty in the Oil and Gas Emissions Inventory does not Affect the

Ability to Implement an Intensity Program

Concerns about oil and gas emissions not declining are either implicitly or explicitly

questioning the accuracy of oil and gas emissions inventories. Importantly, there are other sectors

of the Colorado economy that have far more uncertainty inherent in the emissions inventory than

the oil and gas sector. Efforts at emissions inventory improvements would yield more substantive

benefits by systematically evaluating the statewide GHG emissions inventory as a whole and

focusing efforts on those sectors with the largest uncertainty. As related to the oil and gas sector,

the Division has commissioned a study referred to as the Colorado Coordinated Campaign to

provide a scientifically rigorous evaluation of the accuracy of oil and gas methane emissions

inventories in the Denver-Julesburg Basin. In addition, the Division has proposed revisions to

specific emissions inventory reporting elements in Regulation 7, Part D, Section V to further

improve the completeness and accuracy of collected emissions inventory data. While on-going

work may not resolve all questions about the accuracy of reported emissions estimates, it will

continue to inform our agencies and provide more reliable and quantifiable assessment of actual

emissions from the oil and gas sector. Further, the use of best available data to inform decisions

is necessary and is preferable to inaction or action based on speculation. The criticism of existing

emissions inventory data to undermine consensus and support for an intensity program is a red

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herring, not relevant to the basis and purpose of the Proposed Rule, and therefore should be

disregarded.

C. Weld County Supports the Proposed Rule’s Upstream Intensity Program.

Weld County supports flexible intensity-based GHG emission reduction programs for both

upstream and midstream oil and gas operations, such as the Division’s proposed intensity program

for upstream operations. The flexibility of an intensity-based program, where the reduction levels

may be dictated by regulation but the means by which those reductions are achieved are identified

by the operators themselves, is necessitated by two main factors: (1) oil and gas operations in

Colorado are already subject to numerous and stringent “command and control” type regulations

such that obvious targets for further industry-wide regulation and emissions reduction are limited;

and (2) oil and gas operations in Colorado are variable enough that no one single measure or even

a set of measures can be expected to result in the same level of emissions reductions from all

operators. These two factors are discussed in further detail below.

The following table provides a summary of key State and Federal regulations applicable to

oil and gas operations in Colorado, which illustrates the significant degree of regulation that is

already applicable to these operations.

Table 1. Recent State and Federal Oil and Gas Regulation Summary

Regulation Description

State Regulations

Regulation 7

Revisions

February 2021

• Pneumatic controllers need to transition to non-emitting pneumatic

controllers at oil and gas production plants and natural gas

compressor stations.

• De minimis emissions no not alter a controller’s classification as

“intermittent.”

• Retrofits required for pneumatic controllers at facilities beginning

production, recompleted or refractured on May 1, 2021.

• Company-wide plans for pneumatic controllers prior to May 1,

2021 to convert to non-emitting controllers.

• Operators must determine total liquid production with non-

emission controllers.

• Retrofitting will be completed incrementally until May 1, 2022

and May 1, 2023 based on percentages.

• Pneumatic controllers necessary for safety or process purpose that

cannot be met without emitting natural gas are an exception.

• Pneumatic controllers must be tagged for authorized emission of

natural gas to atmosphere.

• Operators must keep records for five years for retrofit completions,

claiming exception demonstrating applicability, copies of

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Regulation Description

compliance plans, records of qualification under section

III.C.4.c(iv), tags of pneumatic controllers.

Regulation 3

Revision I.DDD

12/19/2019

• Established definition for the end of flowback and commencement

of operations to prevent use of temporary equipment.

• Oil and Gas Facilities require pre-construction permit and 90-day

deferral was repealed.

• Routine or predictable venting emissions no longer exempt from

APEN.

• Wastewater impoundments are no longer excluded from APEN

reporting.

Regulation 7

Revision S

12/19/2019

• Increase frequency of LDAR requirements

• Expand condensate tank control requirements to tanks containing

hydrocarbon liquids and produced water

• Prohibit tank venting during loadout.

• Establish annual emission inventory reporting requirements

• Requirement to install controls for tanks in non-attainment areas

with uncontrolled VOC emissions equal to or greater than 4 tons

per year

Regulation 22

New Regulation

5/10/2020

• Establish GHG emissions reporting requirements.

• HFCs not approved by federal requirements need to be replaced by

manufacturers.

• GHG reduction plan requires inventory records to be monitored.

Colorado Oil and Gas

Conservation

Commission

(COGCC) Mission

Change

4/16/2019

• Mission of COGCC changed with Senate Bill 19-181

• Distance of oil and gas facilities must be 2,000 feet from all other

building units.

• Flaring is regulated to protect and minimize adverse impact to

public health.

• Operators must estimate emissions of specific pollutants that have

specific impact on formation of ozone and direct climate change

impacts.

• Cumulative impact analysis collects data and creates database

(CIDER) to evaluate cumulative impacts.

Regulation 7

Revision T

September 2020

• Reciprocating Internal Combustion Engines (RICE) greater than or

equal to 1,000 horsepower must meet emissions standards by May

1, 2026

• Owners required to monitor air quality at and/or around pre-

production operations and early production operations.

• New requirements for flowback vessels to control emissions.

• New definition of Class II Disposal Well facilities.

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Regulation Description

• Annual Emission reporting now includes reporting on CO2 and

N2O with periodic samples of liquid to inform emissions estimates.

• Engine brought into 8-hour Ozone Control Area is considered

“relocated” and must meet or exceed standards as of operation

date.

• Engines must meet emissions standards by May 1, 2024.

Regulation 3

Revision I.EEE

12/16/2020

• Previously approved regional haze requirements in Regulation 3

including emission reduction requirements for sources subject to

BART and Reasonable Progress during first planning period

registered to Regulation Number 23.

• Regulation 23 will contain reasonable progress goals for second

10-year planning period.

• Emissions of NOX, SO2 and PM10 are new regulation alongside

existing emissions limits.

Regulation 3

Revision I.FFF

12/18/2020

• Revised definitions and construction, operating and new source

review permitting programs to update definitions and conform to

federal regulations.

• Definition of CO2e revised to reflect the EPA’s revisions to global

warming potentials for fluorinated greenhouse gases.

• Operating permit program aligns with 50 CFR Part 70 and new

sources align with 40 CFR Part 51.

• Clarification on permits that require hearings.

• Clarifications of electronic submittal process.

• Engine exception removal included in Section III.E.3.xxx.

Regulation 7

Revision U

December 2020

• Shorter LDAR repair deadlines for leaks within 1,000 feet of

occupied area.

• Reasonably available control requirements implemented for non-

attainment areas.

• Requirements for LDAR inspections have been clarified with

correct typographical, grammatical, and formatting errors

removed.

• Boilers greater than or equal to 50 MMBtu/hr in non-attainment

areas must comply with 0.1 lb/MMBtu NOX emission limit.

• RICE requirements adjusted and include landfill gas and biogas

RICE in non-attainment areas.

• Turbines constructed before February 18th, 2006 in non-

attainment areas must comply with NSPS KKKK. 30-day average

of compliance.

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Regulation Description

Federal Regulations

40 CFR 60 Subpart

GG

9/10/1979 as

amended

• Applies to all stationary gas turbines with a heat input at peak load

equal or greater than 10 million Btu per hour that commenced

construction, modification, or reconstruction 10/3/1977.

• Contains emission standards for NOX and SOX, and restrictions on

fuel sulfur content.

40 CFR 60 Subpart

KKK

6/24/1985 as

amended

• Applies to compressors, pumps, pressure relief devices, open-

ended valves or lines, valves, and flanges or other connectors that

are in VOC service or in wet gas service, and any device or system

required by this subpart that commenced construction,

reconstruction, or modification after 1/20/1984 and on or before

8/23/2011 and that are located at onshore natural gas processing

facilities.

• Establishes LDAR requirements that apply to equipment above

and associated monitoring, recordkeeping, and reporting

requirements.

40 CFR 60 Subpart

LLL

10/1/1985 as

amended

• Applies to sweetening units that commence construction or

modification after 1/20/1984 and on or before 8/23/2011.

• Established standards for SO2 emissions and associated

monitoring, recordkeeping, and reporting requirements.

40 CFR 60 Subpart

IIII

7/11/2006 as

amended

• Applies to owners and operators of stationary compression ignition

internal combustion engines that commence construction after

7/11/2005.

• Establishes emission standards for engines and associated

monitoring, recordkeeping, and reporting requirements.

40 CFR 60 Subpart

JJJJ

1/18/2008 as

amended

• Applies to owners and operators of stationary spark ignition

internal combustion engines that commence construction after

6/12/2006.

• Establishes emission standards for engines and associated

monitoring, recordkeeping, and reporting requirements.

40 CFR 60 Subpart

KKKK

7/6/2006 as amended

• Applies to stationary combustion turbines that commenced

construction, modification or reconstruction after 7/18/2005.

• Establishes NOX and SO2 emission standards for turbines and

associated monitoring, recordkeeping, and reporting requirements.

40 CFR 60 Subpart

OOOO

8/16/2012 as

amended

• Applies to affected facilities in the crude oil and natural gas

production source category that commence construction,

modification, or reconstruction after 8/23/2011, and on or before

9/18/2015.

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Regulation Description

• Affected facilities consist of gas wells, centrifugal and

reciprocating compressors, pneumatic controllers, storage vessels,

onshore natural gas processing plant fugitive emission

components, and onshore natural gas processing plant sweetening

units.

• Establishes emission standards for the control of VOC and SO2,

and associated monitoring, recordkeeping, and reporting

requirements.

40 CFR 60 Subpart

OOOOa

6/3/2016 as amended

• Applies to affected facilities in the crude oil and natural gas

production source category that commence construction,

modification, or reconstruction after 9/18/2015.

• Affected facilities consist of wells, centrifugal and reciprocating

compressors, pneumatic controllers, pneumatic pumps, storage

vessels, onshore natural gas processing plant fugitive emission

components, and onshore natural gas processing plant sweetening

units.

• Establishes emission standards for the control of VOC and SO2,

and associated monitoring, recordkeeping, and reporting

requirements.

40 CFR 63 Subpart

HH

6/17/1999 as

amended

• Applies to glycol dehydration units, storage vessels with potential

for flash emissions, fugitive emission components, and

compressors at facilities that process, upgrade or store

hydrocarbon liquids and natural gas.

• Establishes hazardous air pollutant (HAP) emission standards and

associated monitoring, recordkeeping, and reporting requirements.

40 CFR 63 Subpart

HHH

6/17/1999 as

amended

• Applies to glycol dehydration units at natural gas transmission and

storage facilities.

• Establishes HAP emission standards and associated monitoring,

recordkeeping, and reporting requirements.

40 CFR 63 Subpart

YYYY

3/5/2004 as amended

• Applies to stationary combustion turbines located at major sources

of HAP emissions.

• Establishes HAP emission standards and associated monitoring,

recordkeeping, and reporting requirements.

40 CFR 63 Subpart

ZZZZ

6/15/2004 as

amended

• Applies to stationary RICE.

• Establishes HAP emission standards and associated monitoring,

recordkeeping, and reporting requirements.

In addition to being highly regulated, operators in Colorado have highly variable GHG

emission profiles, which further supports the need for flexible programs where the means of

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achieving reductions can be tailored to the specific operations and emissions profiles of each

company. This variability in emissions profiles is easily made evident by a review of calendar year

2020 GHG emissions data reported by oil and gas operators in Colorado under 40 CFR 98 Subpart

W where, for example, natural gas pneumatic device emissions comprised 67% of total reported

production emissions for one operator (Occidental Petroleum Corp.) but only 36% for another

operator (Chevron Corp.). This variability is also acknowledged by the Division in its Initial EIA

for the Proposed Rule, where it states that there is an “extremely wide range of GHG intensities

across upstream operators”. This underlies, again, the need for flexible programs that can be

tailored to this significant variability in emissions profiles between different operators.

This two-part challenge of a highly regulated sector combined with large intra-sector

variability in GHG emissions necessitates an innovative regulatory mechanism such as the

intensity-based program. Weld County supports the Division’s Proposed Rule and commends the

Division’s willingness to take a hard look at the underlying emissions profiles to design a

regulatory program that best drives the desired performance changes. Colorado’s oil and gas

regulations have been leading the nation for years and the adoption of an intensity-based program

continues that legacy of innovation. Further, such a program is consistent with broader national

and international momentum which has led to voluntary intensity programs in response to social

pressure. As a result of consistency with broader international and corporate trends, the adoption

of an intensity-based program is more likely to be successful. This is because emerging voluntary

programs are actively developing methods and solutions for many of the outstanding questions

raised by intensity-based metrics such as how to quantify methane emissions, how to conduct

independent third-party verification, what would a certification process entail, etc. and these

voluntary programs will likely be a source of information for the Division as the intensity-based

program matures.

Weld County’s additional concern with the Division’s proposed upstream program pertains

to the use of projections of future oil and gas production in Colorado. Given that GHG intensity is

defined as the ratio between GHG emissions and oil and gas production, the intensity targets

established in the proposed upstream program rely on projections of future oil and gas production

to ensure that the targets achieve the required reductions in emissions and not just reductions in

GHG intensity. However, the Division’s proposal does not address the very real possibility that

future production will not be consistent with the Division’s projections and, therefore, the

established intensity targets may either be excessive or insufficient to meet the intended GHG

emission reductions. Accordingly, Weld County encourages the Commission to adopt provisions

for a reassessment of the intensity targets if future production diverges significantly from the

Division’s initial projections. Weld County’s proposed revisions are provided in

WeldCo_PHS_EX-001.

Weld County supports the Proposed Rule’s requirement that the Division prepare a

verification plan no later than March 2023. Weld County, like other parties, recognizes the

importance of verification as a critical component of a GHG intensity program. This aspect is too

important to rush. As stated by the Division, the findings from the 2021 aerial and ground-based

monitoring program are not yet available and are expected to provide key information to support

future GHG emissions quantification and verification work. Therefore, it is reasonable to allow

sufficient time to develop the methodology for how to verify the GHG intensity program. The

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field of emissions quantification and verification programs is rapidly evolving. As described

earlier, one of the benefits of the intensity program is its consistency with voluntary programs

actively under development and the development of verification methods as part of voluntary

programs could help inform the Division’s verification plan. There are now technologies to

estimate the overall level of methane and volatile organic emissions, including Kemp and

Ravikumar (2021)7 and Mingle (2019).8 Colorado is leading the world in methane detection

technology,9 and could encourage innovation and economic efficiency through a well-considered

verification plan. It is reasonable to establish the targets and provide certainty to the industry

regarding the requirements for GHG emissions reductions during this rulemaking, as well as

direct the Division to conduct further data collection and analysis to determine the most feasible

and defensible method to verify GHG emissions reductions.

Related to the verification plan, Weld County has two recommendations, the verification

plan should: (1) clearly define methods to evaluate how the total GHG emissions from the Oil and

Gas sector compare to the GHG emissions reduction requirements included in the GHG Roadmap

and specified in HB21-1266 and (2) include incentives for operators to reduce GHG emissions

ahead of requirements. Weld County’s proposed revisions to the rule for these two items are

provided in WeldCo_PHS_EX-001.

Weld County recommends that the verification plan, or other elements of Regulation 22

Part B Section IV, be revised to incentivize early GHG emissions reductions that result in a lower

intensity than is required. Given that methane has a higher global warming potential and a shorter

lifetime than carbon dioxide, emphasis in early reduction of methane would provide long-lasting

climate benefits. Incentivizing early reductions provides an opportunity to potentially make more

rapid progress towards Colorado’s statewide GHG emissions reduction goals and would also

reward those operators that make gains ahead of requirements.

Weld County is concerned that the Division has proposed further command and control

regulations in parallel with the proposed intensity program which undermines the purpose and

efficacy of an intensity program. These additional regulations, especially in the context of an

already highly regulated industry, would negate the principal benefit, which is to afford operators

the flexibility to identify and implement the emission reduction measures that are best suited to

their specific operations and emissions profile. Weld County requests that the Division forego

further regulation at this time in lieu of an intensity program.

7 C. Kemp and A. Ravikumar, “New technologies can cost effectively reduce oil and gas methane

emissions, but policies will require careful design to establish mitigation equivalence,”

Environmental Science and Technology, 55, 19140-9149 (2021),

(https://pubs.acs.org/doi/10.1021/acs.est.1c03071). 8 J. Mingle, “Methane detectives: Can a wave of new technology slash natural gas leaks,?” Yale

Environment 360 (2019), https://e360.yale.edu/features/methane-detectives-can-a-wave-of-new-

technology-slash-natural-gas-leaks. 9 See id.

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D. The ECD Testing Provides Limited Emissions Reductions While Imposing

Significant Costs and Unjustifiable Safety Risks.

Weld County is concerned that the ECD testing requirements provide limited emissions

reductions while raising significant cost, safety, and feasibility issues associated with conducting

widespread testing of these devices. Testing is generally conducted when these devices are

operating at optimal conditions and any issues associated with the operation of ECD are not likely

to be identified or resolved by testing. The efficacy of these devices is driven more by operational

parameters and conditions that, in many cases, are already required to be continuously monitored

by federal rule and state permits. Furthermore, there are safety concerns inherent to testing ECDs,

which would be exacerbated by the implementation of such a large-scale testing program. In

addition to the dangers inherent to testing the hot gas streams in a firebox, such large-scale testing

would increase vehicular traffic, vehicle emissions, road dust emissions, and road wear and tear to

test combustors annually.

Even if the proposed ECD testing requirements achieve the emission reductions estimated

by the Division in its Initial EIA, this will amount to an annual reduction of only 540 tons of VOCs

and 545 tons of methane (a greenhouse gas benefit of 13,843.18 mtCO2e per year) at an estimated

annual cost of over $11,700,000.10 This level of emission reductions corresponds to less than 0.1%

of the 2005 oil and gas baseline GHG emissions estimated by the State. To further put these GHG

emission reductions into perspective, the total reduction from testing all ECDs are equivalent to

the emissions from a single mid-sized boiler (i.e., smaller than 30 million British thermal units per

hour) fired by natural gas.

Given the significant cost, safety, and feasibility implications and negligible emission

reduction benefits, Weld County cannot support the Division’s proposed ECD testing

requirements. Weld County does, however, believe further examination of this issue is warranted,

which could be achieved through a more focused study to evaluate continuous operating

parameters for combustors, such as gas flow, gas composition, and ignitor function. Such a study

could validate the concern that these combustors are possibly operating at lower-than-expected

destruction efficiencies, identify the issues driving any lower efficiencies identified, and inform

the need for, and nature of, future rulemaking for ECD testing.

E. The Proposed Changes to the LDAR Requirements are Unnecessary and

Inefficient.

Weld County is generally supportive of BMPs to reduce emissions from pigging,

blowdown, and well maintenance activities in the County to the extent that these measures are

cost-effective and technically feasible. Weld County is concerned that the proposed Leak

Detection and Repair (LDAR) requirements are unnecessary and inefficient.

10 The emission reduction estimates provided by the Division in its Initial EIA appear to include

reductions associated with both the ECD testing requirements and the combustion device flow

meter requirements, in which case the reductions associated with only ECD testing would be even

lower.

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The Division’s proposed rules include prescribing specific BMP to reduce emissions from

pigging, blowdown, and well maintenance activities. However, no one set of BMP will be equally

effective for every operator and certain BMP may not even be technically feasible for some

operators. Furthermore, and as with any industry, BMP for the oil and gas industry are continually

evolving. Therefore, Weld County encourages the Commission to adopt provisions that would

allow the operators themselves to identify, and submit to the Division for approval, those BMP

that would be technically feasible and most effective in reducing emissions for their specific

operations in lieu of requirements to follow a rigid set of BMP for all operators.

With regards to increased LDAR requirements for both upstream and midstream segments,

Weld County questions the need for, and merit of, the expansion of already extensive LDAR

requirements applicable to oil and gas operations in the State given that the combined reductions

estimated by the Division in its Initial EIA amount to only approximately 280 tons per year of

VOC and 500 tons per year of methane (or 12,800 metric tons of carbon dioxide equivalents). This

again corresponds to less than 0.1% of the 2005 oil and gas baseline GHG emissions estimated by

the State. On this basis, Weld County does not support the Division’s proposed LDAR

requirements, and we believe that the Division and the regulated community’s time and efforts are

better focused on other provisions of the Proposed Rule expected to achieve greater reductions.

F. Economic Impact Analysis

1. The Initial EIA May Be Significantly Over-Estimating Cost

Effectiveness.

The Division estimates that the Proposed Rule would reduce greenhouse gas emissions

by 7.4 million metric tons of carbon dioxide equivalents per year (mtCO2e) at a cost of $122

million per year, implying a unit cost of $16.55 per ton. A close examination of its EIA, however,

indicates that roughly 84 percent of this reduction in emissions is from the presumed adoption of

plunger lift systems to capture emissions during pre-production activities.

While the Division estimates that the adoption of plunger systems could save producers

$570,864, there is no clear statement of the overall cost of these systems nor is there any analysis

supporting the presumed rate of adoption by operators. Essentially, the Division assumes that

these emission reductions are achieved at no cost. Putting aside these emissions reductions from

the greenhouse gas intensity program, the unit costs of the emission reductions achieved from the

other proposed actions under Regulations 7 and 22 exceed $105 per ton. Hence, the Division’s

claim that the Proposed Rule is cost effective is misleading at best. Pre-production systems to

capture emissions during flowback and other pre-production activities are complex, costly, and

in some cases technically infeasible. These costs should be considered in the initial EIA. If they

were, the costs of regulations 7 and 22 are likely to be significantly higher than the $122 million

estimated by the Division.

These higher operating costs will reduce the rate of return on investment in oil and gas

assets in Colorado. As a result, investment may shift to other states like New Mexico, Wyoming,

and Utah. In this case, any emission reductions achieved in Colorado would be offset by higher

emissions in other states. This lost investment in Colorado will reduce royalties, employment,

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wages and salaries, and severance and ad valorem tax revenues. These regional economic impacts

are part of the costs of adopting Regulations 7 and 22. Accordingly, the initial EIA, which

purports to estimate social benefits, captures only a select portion of the full social costs of the

Proposed Rule.

2. The Social Cost of Carbon is Seriously Flawed.

The calculations supporting the Division’s estimate of the social benefits from the

Proposed Rule assumes that the emission reductions occur immediately and remain the same each

year. In reality, the emission reductions will occur gradually over time depending upon the rate

of adoption of plunger-lift systems that would generate most of the savings in greenhouse gas

emissions. As a result, the Division’s estimates for the social benefits are likely over-estimated.

Another caveat is that the size of the estimated emission reduction is miniscule compared

with annual global carbon emissions, which are roughly 34 billion tons. The estimated emission

reduction under the Proposed Rule, therefore, amounts to 0.02 percent of global emissions.

Moreover, the estimated reductions in emissions do not appreciably affect the stock of greenhouse

gases in the atmosphere, only having an effect very gradually over time. This means the Division

is asking Colorado’s oil and gas industry to incur at least $122 million in costs to reduce emissions

that generate exceedingly small benefits that won’t even be realized until the far distant future.

The social cost of carbon is variable and estimated from integrated assessment models

(IAM) that are used in the absence of market data. These models project future emissions and

atmospheric concentrations of CO2, average global temperatures, the economic impacts from

these temperature changes, the costs of abating greenhouse gas emissions, and the trade-offs from

cutting pollution today to avoid environmental damages in the future. Each IAM is different

depending on assumptions made about abatement costs, damage costs, and many other

parameters. As a result, various IAM studies have produced strikingly different estimates for the

social cost of carbon ranging from $5 to $80 per ton. The Division’s use of one IAM’s social cost

of carbon of $80 per ton does little to justify adoption of the Proposed Rule, and does not cure

the other flawed assumptions plaguing it. Existing carbon markets likely provide a more

appropriate basis to infer a value on incremental reductions in carbon emissions associated with

the Proposed Rule or other future rulemaking.

3. Cost Estimates in the Initial EIA Demonstrate the Need for an

Intensity-Based Program without the Additional Control

Requirements.

Command-and-control rules tend to inhibit technological innovation, which reduces

economic efficiency. For example, the Division proposes to test all 9,505-combustion device at a

cost of more than $11.7 million to achieve a 1.09 percent performance improvement and a

greenhouse gas benefit of 13,843.18 mtCO2e per year. This implies an abatement cost of $847.85

per mtCO2e. This abatement cost is very high and is further justification to not adopt the proposed

ECD testing requirements and instead conduct tests on a representative sample set.

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This extremely high marginal cost of abatement demonstrates that the proposed intensity

program is a better way to reduce emissions of methane in Colorado. The costs of controlling

emissions are often very site specific with some equipment and practices having low costs of

marginal costs of abatement while others may have higher costs due to operator-specific variance

in operations, design, existing controls, and emissions profiles. The intensity program is an

efficient regulatory strategy that does not constrain operators to marginally efficient but

regulatory mandated controls. It acknowledges the diversity of marginal abatement costs and

would allow operators to remediate low-cost sources first. As a result, the costs of the Intensity

Rule are anticipated to be far lower than those quantified in the EIA by allowing a more flexible

approach.11

III. LIST OF ISSUES

Weld County requests the Commission resolve the following issues:

1. The addition of new elements to the proposed intensity program’s verification plan

to include incentive structure among other considerations;

2. The necessity of ECD testing for all combustors instead of conducting studies for a

representative sample; and

3. The alignment of proposed changes to LDAR with costs and benefits.

IV. LIST OF EXHIBITS

Weld County has provided a table of contents for the exhibits associated with this

Prehearing Statement as an attachment to this Prehearing Statement.

V. LIST OF WITNESSES

Each of the following witnesses may testify on the topics and comments articulated in this

Prehearing Statement, including but not limited to:

• Tim Considine, PhD, Professor of Economics, University of Wyoming. Dr. Considine will

testify regarding the adequacy of the Division’s initial EIA submitted in support of its

noticed original Proposed Rule.

• Eric Hodek, Principal, Ramboll Group. Mr. Hodek will testify regarding proposed

revisions related to Regulation 7 and 22.

Weld County reserves the right to identify rebuttal witnesses based on issues raised in other

parties’ prehearing statements. In addition, Weld County is not submitting any written testimony

8 C. Munnings and A. Krupnick, “Comparing policies to reduce methane emissions in the natural

gas sector,” Resources for the Future, July (2017),

https://www.rff.org/publications/reports/comparing-policies-to-reduce-methane-emissions-in-

the-natural-gas-sector/.

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with this prehearing statement but reserves the right to submit written rebuttal testimony in

response to other parties’ prehearing statements.

VI. CONCLUSION

Weld County appreciates the opportunity to participate in this rulemaking and thanks the

Commissioners in advance for their attention to this prehearing statement.

Respectfully submitted this 28th day of October, 2021.

BOARD OF COUNTY COMMISSIONERS

OF WELD COUNTY, COLORADO

s/Bruce T. Barker

Bruce T. Barker, Weld County Attorney

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CERTIFICATE OF SERVICE

I hereby certify that on this 28th day of October 2021, a true and correct copy of the

foregoing Prehearing Statement was sent via electronic mail to the following:

Air Quality Control Commission

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

Air Pollution Control Division

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

American Petroleum Institute Colorado

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

Colorado Oil and Gas Association

[email protected]

[email protected]

[email protected]

Conservation Groups

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

DJ Basin Operator Group

[email protected]

[email protected]

Environmental Defense Fund

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

Great Western Operating Company

[email protected]

Local Community Organizations

[email protected]

Local Government Coalition

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

[email protected]

Occidental Petroleum Corporation

[email protected]

[email protected]

[email protected]

[email protected]

Small Operator Society

[email protected]

[email protected]

West Slope Colorado Oil and Gas Association

[email protected]

[email protected]

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Western & Rural Local Government

Coalition

[email protected]

[email protected]

[email protected]

Williams

[email protected]

/s/ Bruce T. Barker