UPSTREAM GREENHOUSE GAS EMISSIONS FROM NATURAL

GAS: IMPLICATIONS OF A LIFECYCLE-BASED CARBON TAX

ON THE U.S. ELECTRICITY SECTOR

Master’s Thesis Submitted to the Faculty of Bard Center for Environmental

Policy

By Natalie Narotzky

In partial fulfillment of the requirement for the degree of

Master of Science in Climate Science and Policy

Bard College

Bard Center for Environmental Policy

P.O. Box 5000

Annandale-on-Hudson, NY 12504-5000

May, 2012

i

Contents

Abstract .................................................................................................................. iii

Executive Summary ............................................................................................... iv

Chapter 1: Introduction ........................................................................................... 1

Carbon pricing and lifecycle analysis of natural gas........................................... 1

Approach ............................................................................................................. 6

Relevant Units ................................................................................................. 7

Chapter 2: Literature Review of Natural Gas Life-Cycle Analyses ....................... 8

Introduction and Subject Background ................................................................. 8

Summary Statistics .......................................................................................... 9

Sources of Upstream Emissions in the Natural Gas Industry ........................... 11

Vented Emissions ........................................................................................ 11

Flaring Emissions .......................................................................................... 14

Fugitive Emissions ........................................................................................ 14

Combustion .................................................................................................... 15

Discussion ...................................................................................................... 15

GHG Emissions by Natural Gas Type .............................................................. 16

Emissions from Imported Liquefied Natural Gas .......................................... 16

GHG Emissions from Shale Gas ................................................................... 17

Global Warming Potential (GWP) and its Relevance to Shale Gas .............. 20

Summary Statistics and Conclusions ................................................................ 22

Chapter 3: Lifecycle Analysis of Fossil Fuels in Relation to Greenhouse Gas

Taxes ..................................................................................................................... 24

Introduction ....................................................................................................... 24

Literature on Carbon Taxation .......................................................................... 27

Survey of GHG Pricing Levels ...................................................................... 28

ii

Conclusions ....................................................................................................... 30

Chapter 4: Results ................................................................................................. 32

Introduction ....................................................................................................... 32

Integrating Natural Gas LCA and GHG Taxation ............................................ 33

Existing Regulatory Framework ....................................................................... 35

Current Work to Reduce Methane Emissions ................................................... 39

Policy Recommendations .................................................................................. 42

Appropriate Tax to Encourage Renewables? ................................................ 44

Discussion ......................................................................................................... 47

Bibliography ......................................................................................................... 49

iii

Abstract

In the U.S. electricity sector, the importance of natural gas as a fuel source is

growing relative to the long-time dominant fuel, coal. Between 2002 and 2011

natural gas combined cycle generation has increased from 10 to 20 percent in the

U.S., while in the same time period coal steam generation has decreased from 51

to 44 percent (FERC, 2012). There is debate within the environmental and energy

community about the greenhouse gas (GHG) emissions associated with natural

gas relative to coal. Natural gas burns cleaner than coal at the power plant, but the

emissions associated with its production are widely contested. This thesis

attempts to quantify the emissions associated with the production of natural gas

through surveys of the lifecycle analysis literature. It also recommends a policy

that will encourage cleaner natural gas production, particularly focusing on

emissions of the GHG, methane (CH4). Literature surveys indicate that when all

lifecycle emissions are included, natural gas is approximately half as GHG-

intensive as coal, and 20 percent of these emissions come from upstream activities

not related to combustion at the power plant. Policies that will encourage cleaner

natural gas production, particularly focusing on emissions of the GHG methane

(CH4), will need to address lifecycle emissions through methane monitoring,

taxation and compliance.

iv

Executive Summary

The electricity sector emits 40 percent of the U.S.’s greenhouse gas (GHG)

emissions. Most of these emissions come from natural gas and coal, the two fossil

fuels that dominate the electricity sector. There is at debate within the

environmental and energy community as to the actual emissions benefits of

natural gas over coal. It is largely accepted that natural gas emits fewer GHGs

than coal in the combustion stage, but the ratio of full life-cycle emissions

between the two fuel sources is contested. Most of this debate stems from

uncertainty regarding the upstream lifecycle emissions of natural gas. To

determine the relative impacts of these two fuels, I survey the lifecycle analysis

literature.

In this paper, I define upstream emissions as those coming from the

production, processing, transmission and distribution of natural gas before it is

combusted at the power plant. Specifically, these upstream emissions sources

include vented, flared, fugitive and combusted emissions. Between 1.49 and 5.33

percent of total produced natural gas in the U.S. is emitted through these

processes. The impacts that dominate the upstream lifecycle are vented and

fugitive methane emissions. From a global warming potential perspective, venting

and flaring are of the most concern due to the potency of methane gas and the fact

that natural gas is primarily composed of methane. Venting emits between 0.4 and

2.75 percent of total U.S. produced natural gas, while fugitive losses account for

0.88 to 2.0 percent. Also of importance are the emissions associated with

v

imported liquefied natural gas (LNG) and shale gas. Much of the literature agrees

that shale gas and LNG have higher production emissions than conventional

domestically produced gas. Since production and use of shale gas are increasing

rapidly, its emissions in specific are highly relevant to this analysis.

The review of the lifecycle analysis literature found that on average for all

studies reviewed natural gas emits 537 kg CO2e/MWh,1 which makes it 49 percent

less GHG intensive than coal on a lifecycle basis. Natural gas lifecycle emissions

range from 419 kg CO2e/MWh (DiPietro, 2010) to 610 kg CO2e/MWh

(conventional gas in Clark, Han, Burnham, Dunn & Wang, 2011). These full

lifecycle emissions of natural gas are 20 percent higher than combustion-only

emissions. While emissions from natural gas combustion comprise 80 percent of

its lifecycle, coal combustion emissions contribute 95.5 percent of that fuel’s

total. Although lifecycle analysis of all fuels should play a role in policy

discussion, natural gas’s high upstream emissions are of particular concern in a

future that includes regulations of GHGs and high natural gas use. They are also

of concern because of federal clean energy standards that will promote natural gas

over coal-fired generation (U.S. Congress, 2012). This paper focuses on

quantifying these emissions and applying this result to a method of taxing and

regulating these lifecycle emissions, focusing on methane.

One of the most commonly discussed policies for GHG mitigation is a

carbon tax, which places a price on carbon per unit of emissions. Typically these

1 This is averaged among natural gas source types and generation systems, including NGCC.

vi

are levied in terms of the carbon combusted at a power plant or tailpipe, and they

therefore would not address the upstream emissions central to this work. Carbon

taxes have been found to be particularly effective in reducing emissions from the

electricity sector due the role of fuel switching from coal to less carbon intensive

fuels such as natural gas or renewables. A review of the literature on carbon

pricing recommends a range of prices designed to yield moderate emissions

reductions while minimizing losses to economic efficiency. These recommended

prices range from $17 to $240 per ton carbon, with a mean of $67 and a median of

$50.

Using these recommended carbon prices from the literature we can

determine the impact of carbon taxation on prices of both natural gas production

and electricity. The average emissions from natural gas systems analyzed was

determined to be 537 kg CO2e/MWh, and the average contribution to total

emissions from the combustion at the power plant is 80 percent. Therefore, the

tax on 429.6 kg CO2e must be paid by the utility burning the fuel while the tax on

107.4 kg CO2e must be paid for by the upstream parties. Assuming prices ranging

from $5 to $65 per ton carbon dioxide, this would result in prices ranging from of

$3.68 to $52 per MWh combusted and $0.92 to $13 per MWh for upstream

emission sources.2 However, collecting these funds from all relevant parties may

be an administrative challenge. Additionally, this policy would not incentivize

2 This analysis assumes a perfectly inelastic demand, an unrealistic assumption.

vii

emissions reductions since it is based on data from the literature and not on

measurement and monitoring of methane emissions.

In order to appropriately assign responsibility for upstream and

combustion emissions, I propose a simpler tax more specifically focused on

methane emissions, which drive the upstream portion of NG’s lifecycle emissions.

The EPA’s Natural Gas STAR program would be a partner in this policy

initiative. This is a voluntary partnership between the industry and the federal

government aimed at developing methane mitigation technology and practices.

This program works in conjunction with natural gas companies, who already have

financial incentives to reduce these emissions because of the product loses they

incur. Specifically, the proposed tax would be levied on vented and fugitive

methane emissions from natural gas production systems. This would require

monitoring of methane emissions using currently available and proven infrared

and laser-based technology. The producer would be given a choice whether to pay

a tax or to reduce emissions using available technology and assistance from the

Natural Gas STAR Program.

This recommended tax plays an important role among the existing

regulatory activities of the U.S. EPA. The EPA began requiring mandatory

reporting of fugitive and vented methane emissions in 2011. Data will be

available later in 2012, but it is uncertain when this data will be translated into

effective policy. Similarly, the New Source Performance Standards (NSPS),

proposed in 2011 and revised earlier in 2012, require green completions on

viii

fractured and refractured wells beginning in 2015. In the meantime they require

flaring at these sites to reduce GHG impacts. This leaves us with a few years gap

in which a tax would be highly effective at reducing GHG impacts from the

natural gas production sector. Reducing methane in the near term is of particular

importance from a climate change perspective because of its potency as a heat

trapping gas; methane is assumed to be 72 times more potent than CO2 over a 20

year lifetime (IPCC, 2007a). Because natural gas systems are the highest emitter

of methane in the U.S., reducing emissions in the near term from this sector will

help reduce climate change impacts as the federal government determines a) how

to regulate these methane emissions, and b) how to regulate CO2 from all sources

potentially through a carbon tax or cap and trade mechanism.

1

Chapter 1: Introduction

Carbon pricing and lifecycle analysis of natural gas

The electricity sector is the largest emitter of the greenhouse gas carbon dioxide

(CO2) in the U.S. This sector emitted over 2000 teragrams (Tg) of CO2 in 2010,

which comprises 40 percent of total emissions of the gas in that year (U.S. EPA,

2012a). The two dominant fossil fuels driving electricity sector emissions are

coal and natural gas (NG). The consumption of natural gas is rising in the

electricity sector, but coal still dominates (Figure 1). Between now and 2035

coal’s share in electricity generation is projected to fall from 49 percent to 39

percent, while natural gas’s share will rise from 24 to 27 percent (U.S. EIA,

2012a). These changes are projected to occur because of the increasing supply of

natural gas, the need to comply with environmental regulations, and the projected

growth in electricity demand. Figure 1 below shows the consumption of natural

gas and coal in the electricity sector between 1997 and 2010 and projections for

2011 to 2035. Between 2011 and 2035 the consumption of coal is projected to

level off while that of natural gas is expected to grow by 0.4 percent (U.S. EIA,

2012a).

2

Figure 1: Consumption of Natural Gas and Coal in the U.S. Electricity Sector in 1997-2010 and

2011-2035 projections. Based on data from the U.S. EIA (U.S. EIA, 2012a; U.S. EIA, 2011a, U.S. EIA, 2011b)

Many nations around the world, excluding the U.S., have undertaken carbon

pricing mechanisms primarily under the frameworks of emissions trading or

carbon taxation. Under carbon pricing the electricity sector is projected to

transition more quickly than projected from coal to natural gas generation due to

the greenhouse gas benefits of the latter (van Vuuren, de Vries, Eickhout & Kran,

2004). Carbon taxes are typically levied on the carbon emissions associated with

the fuel’s combustion (Pearce, 1991). Because of that carbon taxes do not take

into account the upstream emissions associated with these fuels. In this paper, I

define upstream emissions as the emissions associated with the fuel before it

reaches the power plant; they include production, processing, transmission and

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distribution. These emissions are of concern because recent EPA estimates

estimate lifecycle emissions from natural gas production to be the highest emitter

of the potent greenhouse gas methane in the U.S (Figure 2). Natural gas systems

emitted 221.2 teragrams CO2e in 2009 (U.S. EPA, 2011a).

Figure 2: Sources of methane emissions in the U.S. in Teragrams CO2e. Natural gas systems

accounted for 32 percent of total methane emissions in 2009. Data from U.S. EPA 2011.

The upstream emissions from production, processing, transmission and

distribution can contain large quantities of methane (CH4). Methane has a global

warming potential (GWP), or heat-trapping capacity, 25 times that of carbon

dioxide (CO2), whose combined atmospheric volume and GWP make it the most

important GHG from a climate forcing perspective. Because natural gas is

Natural Gas Systems

32%

Enteric Fermentation

20%

Landfills 17%

Coal Mining 10%

Manure Management

7%

Petroleum Systems

4%

Wastewater Treatment

3%

Stationary Combustion

1%

Abandoned undergraound coal

mines 1%

Petrchemical Combustion

0.8%

Other 5%

4

primarily composed of methane, emissions of the gas are important to lifecycle

analysis (U.S. EPA, 2011a).

Since carbon taxes are based on the GHG emissions associated with the

fossil fuel combustion and do not take into account upstream emissions of fuel

sources, if these emissions are significant it is necessary to determine how to

regulate and potentially tax these emissions. It is a challenge to integrate lifecycle

emissions into any carbon pricing policy. This issue is relevant for all energy

sources, including fossil fuels, but lifecycle emissions are also of concern for

renewable energy sources, like wind and solar. It is important to note, however,

that the upstream emissions for coal and petroleum are significantly lower than

for natural gas, in terms of emissions per delivered MWh of electricity. This is, in

part, due to the high methane emissions associated with natural gas, as well as its

lower combustion emissions.

For these reasons the focus of my work will be on natural gas. This

question of how to integrate lifecycle emissions into carbon pricing policy is

worthy of attention in the energy and climate community. Therefore, in this thesis

I will address the question of how to integrate lifecycle emissions of natural gas

into GHG mitigation strategies for the electricity sector in the United States. In

particular, I will focus on how a tax on vented and fugitive methane emissions

from natural gas systems can reduce emissions from the sector, but I will also

discuss regulatory mechanisms that work to reduce these emissions, specifically.

As the U.S. experiences a boom in production of controversial unconventional

5

sources of natural gas, such as shale gas, which may have higher upstream

emissions than conventional gas, it is important to consider how these emissions

can be figured into these policy mechanisms.

The inclusion of a methane tax has the potential to affect the amount of

fuel switching from coal to natural gas under policies that impose carbon

penalties. If the inclusion of these methane emissions significantly affects the

comparative emissions under GHG pricing, and therefore the price of electricity

generation from natural gas relative to coal, this may affect the fuel switching that

will likely result from GHG pricing mechanisms (van Vuuren et al., 2004;

Pettersson, Soderholm & Lundmark, 2011).

A price on carbon should favor renewable sources over coal and natural

gas, but integrating lifecycle methane emissions into carbon pricing may have

perverse effects. It may delay the projected transition from coal to natural gas to

renewables because it will reduce the price gap between coal and natural gas and

increase the price difference between natural gas and renewables, once methane

emissions are priced. Many analysts predict that we are entering or have already

entered a “golden age of natural gas,” in which natural gas is a key fuel source in

many parts of the world (IEA, 2011). Since the International Energy Agency

(IEA) projects this to be the case, there is concern that our reliance on natural gas

may delay the widespread proliferation of non-fossil fuel-based energy

technologies. Natural gas has an important role to play in this transition as a

bridge fuel, but the competitive prices of natural gas may “outmuscle” renewable

6

sources (Flavin & Kitasei, 2010). The issue of how lifecycle carbon pricing will

affect fuel switching in the electricity sector will be addressed throughout this

research. Designing a policy to regulate methane emissions from natural gas that

incentivizes reductions in these emissions will be a focus of my policy

recommendations.

Approach

In order to answer the proposed research question I will first present a review of

existing lifecycle analyses of natural gas and studies that compare emissions of

natural gas to coal. Based on the literature, I will estimate the comparative total

emissions of natural gas and coal, which is critical to developing suitable GHG

policy. The range as well as summary statistics in life-cycle greenhouse gas

emissions for natural gas and coal will provide basis for further analysis presented

in Chapters 3 and 4.

Chapter 3 will discuss carbon taxation in detail, surveying literature on the

subject to determine how taxes on upstream methane can fit into the current

discourse. Chapter 4 will focus on synthesis and the current regulations and policy

regarding upstream methane emissions. Chapter 5 provides policy

recommendations, discussion and conclusions regarding natural gas life cycle

analysis and methane taxation.

7

Relevant Units

My working unit for analysis will be kilograms of carbon dioxide equivalent per

megawatt hour of electricity generated (kg CO2e/MWh). My analysis will assume

a CO2 equivalent emissions tax, that will use the internationally recognized 100-

year Global Warming Potential (GWP) for CH4 of 25 (IPCC, 2007a).3 Addressing

GWP appropriately will ensure the proposed method of taxation and regulation

accounts for most significant GHG emissions of the analyzed systems.

Comparisons between the lifecycle GHG emissions of natural gas and coal

appear consistently throughout the literature and will reoccur throughout this

thesis. The two fuels’ emissions will be used in order to compare lifecycle studies

to one another. When discussing lifecycle emissions it is necessary to discuss the

percentage of emissions that come from upstream sources and from combustion

sources. This will provide the baseline for my calculations of the taxation

responsibility of the upstream parties involved in the natural gas lifecycle.

3 Global Warming Potential represents the heat-trapping capacity of a gas in the earth’s

atmosphere, relative to CO2.

8

Chapter 2: Literature Review of Natural Gas Life-Cycle Analyses

Introduction and Subject Background

Natural gas is well known to emit fewer greenhouse gases than coal during

combustion at the power plant, but it has higher emissions than coal during

upstream production, processing, transmission and distribution of the fuel.4

Lifecycle data on these two fuels that dominate the electricity sector are often

employed in comparison in the literature. According to the U.S. EPA (2012a)

GHG Inventory, natural gas systems are the largest U.S. non-combustion GHG

emissions source with 215 Teragrams (Tg) CO2e emitted in 2010. Methane, a

highly potent GHG, is the primary component of natural gas, and its release from

these systems affects the lifecycle emissions of the energy source. Even though

these upstream natural gas emissions are high, there is some variability in their

quantification, as methodologies employed in the literature vary.

There are many places throughout the fuel’s upstream lifecycle where gas

can be released to the atmosphere. Emissions from extraction, processing and

transport can be classified as vented emissions, flared emissions, fugitive

emissions, or combustion emissions (Kirchgessner, Lott, Cowgill, Harrison &

Shires, 1997; Fulton, Mellquist, Kitasei & Bluestein, 2011). Methane loss is a

major component of the upstream greenhouse gas footprint of natural gas. These

4 Production is the extraction is natural gas from underground formations. Processing removes

other substances to get nearly pure natural gas. Transmission is the delivery of natural gas from

the wellhead to industrial users; this also includes storage. Distribution is the transport of natural

gas to end users (U.S. EPA, 2011b)

9

upstream emissions comprise 20 percent of total natural gas lifecycle emissions,

based on the literature reviewed in this chapter. Also important to lifecycle

emissions are emissions from LNG and from unconventional sources, like shale

gas.

Many studies have attempted to quantify the lifecycle emissions of natural

gas, but the results contain a wide range of values and study authors have

indicated that the data are still incomplete. Pricing or regulating these emissions is

necessary in order to mitigate this key emissions source category, but with the

variation in emissions levels, it is difficult to reach consensus among

policymakers and regulatory agencies. In this chapter I will review some of these

studies in order to determine a more accurate comparison of the lifecycle

emissions of natural gas and coal. The range of values from the studies reviewed

in this chapter will give a range of upstream emissions values that will be used in

the policy recommendations section.

Summary Statistics

Figure 3 below summarizes the results from the studies reviewed in this chapter

expressed as kg CO2e emissions per MWh of electricity. Natural gas emissions

range from 419 kg CO2e per MWh for DiPietro (2010) to 610 for conventional gas

from Clark et al. (2011), giving an average of 537 kg CO2e per MWh.5 The range

5 This average was calculated by taking the arithmetic mean of all studies reviewed, aside from

Howarth et al. (2011) due to incomparable units.

10

of the ratios of natural gas to coal emissions is 41.9 percent for Drauker (2010) to

87 percent for Howarth, Santoro and Ingaraffea (2011). The average ratio of

natural gas to coal emissions for all studies reviewed is 54.2 percent.6

Figure 3: Full lifecycle natural gas and coal emissions from the electricity sector

from the LCA studies reviewed here, including upstream and combustion emissions.

Sources listed on x-axis.

6 These ratios were calculated by taking the full LCA footprint of natural gas divided by that of

coal. Its average was taken as the arithmetic mean of all studies reviewed, aside from Howarth et

al. (2011).

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Sources of Upstream Emissions in the Natural Gas Industry

This section will discuss the range of values and the wide variability in the way

the literature quantifies vented, flared, fugitive, and combustion emissions. The

contributions from upstream combustion emissions play a small role in total fuel

LCA. Table 1 below depicts the ranges of these emissions in terms of percent of

total U.S. produced gas lost. In total 1.49 to 5.33 percent of natural gas produced

in the U.S. is lost through vented, flared, fugitive and combusted emissions.

Venting and fugitive emissions emit the most methane. From a climatological

perspective these emissions are important to regulate since combustion emissions

release minor quantities of methane and flared emissions convert methane to

carbon dioxide, which has a lower global warming potential.

Vented Flared Fugitive Combusted (Upstream) Total

Losses

Low 0.40% 0.21% 0.88% -- 1.49%

High 2.75% 0.48% 2.00% 0.10% 5.33%

Table 1: Range in losses of natural gas throughout the production lifecycle through vented,

flaring, fugitive, and combustion.

Vented Emissions

Vented emissions are intentional releases of natural gas as part of processing,

design or normal operation (Fulton et al., 2011). This can occur when a

compressor is taken out of service for repair and the gas within the system must

be released, or during start up operations when new plants or pipelines need to be

purged of gas (Kirschgessner et al., 1997; Fulton et al., 2011). During processing,

12

gas is often released or flared during emergency shutdowns or in over-pressure

situations (Kirchgessner et al, 1997). The literature demonstrates a range between

0.4 and 2.75 percent of total U.S. production released through venting. More

recent literature trends towards the higher end of this estimation.

Kirschgessner et al. (1997) found vented emissions to be 94.2 billion

standard cubic feet (bscf), 0.4 percent of total U.S. production. Jiang et al. (2011),

estimate that production of Marcellus Shale releases 1.8 grams CO2e per

megajoule (MJ), in total. Sixty four percent of these emissions come from venting

or flaring during the completion period. Because of the uncertainty between

quantities vented and quantities flared the standard deviation around this number

is high, 1.8 g CO2e/MJ (Jiang et al., 2011). Skone (2011) estimates venting and

flaring rates at 2.5 percent of total without providing estimations for each of the

two emissions sources.

Clark et al. (2011) found that the largest emissions sources in the upstream

processes to be venting and leakage of methane, responsible for more than half of

upstream emissions. Clark et al. (2011) estimate that conventional natural gas

emits 2.75 percent of total produced gas in the processes of production,

processing, transmission and distribution, while shale gas emits less, 2.01 percent.

This reduction is due entirely to shale gas’s lower processing emissions in their

estimation. Liquid unloadings are a major source of fugitive methane leaks, and

they therefore contribute to this difference between shale gas and conventional

gas. Liquid unloadings remove liquids that build up and blow flow in wet gas

13

wells. The EPA contends that liquid unloadings pertain only to conventional

wells, since shale is typically a dry gas (Clark et al., 2011).

Clark et al. (2011) recommend reducing vented emissions from liquid

unloadings in conventional wells by surveying available technologies to

determine where this process is needed. They also recommend that flaring

feasibility should be explored at these sites. For shale wells they recommend

examination of vented gas and released fracturing fluid during well completions

during the flowback period. This demonstrates the potential interplays between

environmental quality issues associated with hydraulic fracturing and its

associated methane emissions (Clark et al., 2011).

Venting of methane also occurs throughout the natural gas lifecycle

through pneumatic devices. According to Spath and Mann (2000), the second

largest source of methane from natural gas production, accounting for 20 percent

of total, is that from pneumatic devices employed during extraction. Pneumatic

devices are mechanical components powered by natural gas and can release

methane to the atmosphere (Shires & Harrison, 1996). The U.S. industry emitted

31.4 bscf from pneumatic devices in the production phase in 1996 (Shires &

Harrison, 1996).

14

Flaring Emissions

Natural gas is frequently flared when it cannot be easily recovered (Drauker et al.,

2010). This can occur when the well is not yet ready to use, when it is not

economically beneficial to recover the NG, or during emergency operations, for

example (Drauker et al., 2010). Flaring is the burning of natural gas, which

converts CH4 to CO2 , thereby reducing its GWP and diminishing its GHG impact,

but it still represents a loss of natural gas (Kirchgessner et al. 1997).

Estimates of flaring rates vary across the literature. Drauker et al. (2010)

estimates flaring rates at 0.21 to 0.48 percent of extracted gas according to data

from the U.S. Government Accountability Office.

Fugitive Emissions

Fugitive emissions (or leaks) are unintentional releases of natural gas that occur

throughout equipment such as poorly sealed valves or pipes (Fulton et al., 2011).

Most studies estimate these emissions to be between 1 and 2 percent of total

produced natural gas in the U.S. Kirchgessner et al. (1997) found fugitive

emissions to be 195.2 bscf, 0.88 percent of total U.S. production. Skone (2011)

finds fugitive losses at 1.7 percent of total production. Spath and Mann (2000)

estimates that 1.4 percent of gross natural gas extracted is lost to the atmosphere

in the form of fugitive emissions. They estimate that thirty-eight percent of these

losses are fugitive emissions, 90 percent of which come from leakage of

15

compressor components. Jiang et al. (2011) found fugitive emissions rates for

Marcellus shale to be 2 percent. They estimate that a 14 percent leakage rate

would be required for natural gas emissions to be higher than those of coal.

Combustion

Finally, combustion emissions are burned exhaust from compressor engines,

burners and flares through which methane is released due to incomplete

combustion. In comparison with other emissions categories, combustion

emissions are small and contribute less to the GHG impacts of natural gas

systems. Kirchgessner et al. (1997) found combusted emissions, entirely from

compressor exhaust, to be 24.9 bscf, 0.1 percent of total U.S. gas production.

Discussion

Many LCA studies discuss methane emissions in terms of percentage of total

produced gas released. It is important to note these total production figures do not

take into account the fact that total production of natural gas does not directly

relate to the electricity sector alone. To put this into perspective in 1997, the

electricity sector consumed 4065 bscf, approximately 17 percent of total

withdrawals (U.S. EIA, 2012c; U.S. EIA, 2012d).

16

GHG Emissions by Natural Gas Type

One important result that is prevalent in the natural gas LCA literature is the

difference in emissions between different sources of natural gas. Most literature

reviewed here looks at the average over domestic production, which includes

shale sources in later studies. Also important to analysis are the emissions

associated with imported LNG, as it is projected that shale gas will replace the

need for these imports (Jiang et al., 2011).

Some of the literature reviewed above looks at shale gas in particular, due

to processes specific to hydraulic fracturing. This section will therefore focus on

shale gas because of the controversy over its methane emissions as well as its

parallels to the environmental consequences of hydraulic fracturing.7

Emissions from Imported Liquefied Natural Gas

According to many studies, liquefied natural gas, which is almost always

imported, has higher emissions than all other natural gas sources (Drauker et al.,

2010; Skone, 2011). This is largely due to the energy intensive processes involved

in liquefying, transporting and re-gasifying the imported fuel (Skone, 2011).

Jaramillo, Griffin and Matthews (2007) found LNG life-cycle emissions to be

727.3 kg CO2e/MWh. Lifecycle emissions of LNG lie between domestic natural

7 Shale gas is extracted using horizontal drilling and hydraulic fracturing. The coapplication of

these two techniques helped spark the boom in shale gas production. Shale gas is extracted using a

drill that curves laterally several thousand feet through shale. Fluid is pumped through the

wellbores at a high enough pressure to create fissures in the shale up to 3000 feet long (Andrews et

al., 2009).

17

gas and coal (Jaramillo et al., 2007). My analysis considers only domestic

consumption in the electricity sector, but it is important to note that the U.S.

would be responsible for emissions associated with processing LNG for export.

Six percent, or 65 billion cubic feet, of exported gas in 2010 was LNG (U.S. EIA,

2010). U.S. imports of LNG are predicted to decrease to nearly zero by 2015

(U.S. EIA, 2011c).

GHG Emissions from Shale Gas

Some studies have found that shale gas has the highest upstream emissions of all

domestic sources of natural gas (Drauker et al., 2010). Its GHG emissions are of

particular interest because shale currently represents 14 percent of U.S. domestic

production and is projected to increase to 42 percent by 2035 (Fulton et al., 2011).

Shale gas is likely to replace LNG as the primary unconventional source of

natural gas consumed in the U.S. According to Jiang et al. (2011), Shale gas from

the Marcellus has emissions 3 percent lower, on average, than imported LNG.

They therefore conclude that as shale gas replaces LNG sources, total emissions

from natural gas will not rise (Jiang et al., 2011).

Drauker et al. (2010) analyzed five domestic natural gas types:

conventional onshore gas (63% of U.S. total), conventional offshore gas (1.2%),

conventional onshore associated gas (21.5%), Bartnett Shale (6.6%) and coal bed

methane (7.5%). These percentages of total U.S. production are as of 2009.

Barnett Shale has the highest emissions of the five domestic sources analyzed at

18

9.2 kg CO2e/MMBTu (Drauker et al., 2010). These results demonstrate the

importance of the GHG emissions associated with shale gas.

As of 2010, 55 percent of drill rigs were drilling horizontally (Newell,

2010). As domestic production grows, imports are projected to decrease from 13

percent of total supply in 2008 to 6 percent by 2035 (Newell, 2010). Even though

the literature demonstrates the high GHG emissions associated with LNG, shale

gas being the most quickly growing domestic source of natural gas makes it

worthy of the most attention regarding GHG emissions from natural gas.

Figure 4: Natural Gas Supply, 2008-2035. Based on data from and projections made by the U.S.

EIA (U.S. EIA, 2011d, U.S. EIA, 2011e).

0

20

40

60

80

100

120

140

160

180

Nat

ura

l Gas

Su

pp

ly (

Trill

ion

cu

bic

fe

et)

Conventional

Unconventional

19

If the U.S. were importing a large quantity of LNG it would be possible

that offsetting this greenhouse gas intensive natural gas source with increasing

domestic shale natural gas resources the U.S. could reduce the overall lifecycle

greenhouse gas intensity of its natural gas supplies. The U.S. will need to import

less LNG due to higher domestic production, particularly from shale sources (U.S.

EIA 2012a). LNG is currently a very small fraction of domestic supply. In 2008

the U.S. imported 0.3 trillion cubic feet of LNG and these imports are projected to

decrease by over 50 percent by 2035 (U.S. EIA 2011d; U.S. EIA, 2011e).

Unconventional (shale gas, tight gas and coal bed methane) sources of gas

are projected to increase in supply by 44 percent by 2035, while conventional

sources are expected to increase only 10 percent in the same time period (U.S.

EIA, 2011d; U.S. EIA, 2011e).

An analysis by Howarth et al. (2011) specifically focuses on emissions

from shale gas. Their analysis concludes that 3.6 to 7.9 percent of natural gas is

vented or leaked into the atmosphere during shale gas production throughout the

processes of flow-back during well completion, leakage, processing losses and

venting as well as during transmission, storage and distribution (Howarth et al.,

2011). These numbers are higher than those estimated in studies mentioned

previously. The GWP employed by Howarth et al. (2011) can compound the

already existing variability around this data.

20

Global Warming Potential (GWP) and its Relevance to Shale Gas

Global Warming Potential (GWP), which describes the amount of climate change

forcing from molecules of greenhouse gases, adds further variability to the

already tenuous boundaries of lifecycle analysis. Aside from varying estimations

of methane and other gas emissions, GWP can affect the amount of climate

forcing these gases cause. The global warming potential time horizon8 employed

affects the total GWP of the system analyzed. In Skone’s (2011) analysis, the full

life-cycle emissions of natural gas has 55 percent fewer emissions than coal on a

100 year time horizon, but 50 percent fewer emissions on a 20 year time horizon.

The Intergovernmental Panel on Climate Change (IPCC) GWP time horizon for

methane is 25 times that of CO2 over 100 years, but it is 72 over a 20 year time

horizon (IPCC, 2007a). There can be a large discrepancy in results depending

which time horizon is used. Using a 20 year time horizon will place emphasis on

short-term climate change effects but will downplay the severe effects of climate

change into the future (Fulton et al., 2011).

The estimate from Howarth et al. (2011) is on the high side when

compared to other studies reviewed here. This is in part due to their assumptions

regarding global warming potentials. The authors model both the 100 and 20 year

residence time GWPs for methane but contend that the 20 year lifetime is more

8 When discussing GWP, the time horizon employed refers to the lifetime a molecule of a GHG

has in the atmosphere, or the amount of time it traps heat.

21

crucial given the need to reduce GHGs in the immediate future. This assumption

in their analysis results in higher emissions factors when compared to other

studies. Additionally, the authors employ GWPs for methane of 105 and 33 for 20

and 100 years, respectively, while the IPCC uses 72 and 25 (Howarth et al.,

2011). While these two diversions from scientific convention (Howarth et al.

argue IPCC GWPs are out of date) regarding GWPs may have some support from

outside sources they are not conventionally employed in the literature and

therefore inflate the results of the study in comparison to most other analyses.

According to this study, results for shale gas emissions, estimating 3.6 percent

methane escaping, using the 100 year time scale are 18 percent lower than deep

mined coal. Shale gas emissions that estimate 7.9 percent methane escaping are

15 percent higher than surface-mined coal (Howarth et al., 2011).

Fulton et al. (2011) calculated their results employing both GWPs for

comparison. When using the 100 year GWP of 25 for methane, the authors find

the LCA emissions for natural gas to be 47 percent lower than that of coal.

However, when the authors recalculated their results using both the IPCC’s 20

year GWP of 72 and a higher 20 year GWP of 105, they found natural gas

emissions to be 34.8 percent and 26.8 percent lower than coal, respectively

(Fulton et al., 2011). This demonstrates the effect varying GWPs can have on

study results.

22

Summary Statistics and Conclusions

Figure 3 presented at the beginning of this chapter summarizes the results from

the studies reviewed here. To reiterate, natural gas emissions range from 419 kg

CO2e per MWh in DiPietro (2010) to 610 for conventional gas in Clark et al.

(2011). This yields an average of 537 kg CO2e per MWh. The ratios of natural gas

to coal emissions range from 41.9 to 87 percent. The average of these ratios from

natural gas to coal is 54.2 percent.

However, it is important to analyze the breakdown of upstream and

downstream emissions from each study. In terms of the policy relevance of the

research presented here, it is important to note the large discrepancy in upstream

and downstream emissions between coal and natural gas. For coal the average

contribution of combustion emissions is 95.5 percent among the studies reviewed.

For natural gas the contribution of combustion emissions is lower at 80 percent

among the studies reviewed. Despite the fact that natural gas’s emissions are on

the whole approximately half those of coal, when both upstream and downstream

emissions are included the proportion of upstream emissions are much higher in

natural gas than in coal. This demonstrates a regulatory failure in how most

nations regulate, or discuss regulation of, greenhouse gas emissions. Regulation

of greenhouse gas emissions typically is concerned with tailpipe or smokestack

emissions. Regulation in this sense would omit close to 20 percent of emissions

from natural gas, which could affect the desired results of mitigation policy: to

reduce greenhouse gas emissions and to encourage fuel switching from dirtier to

23

cleaner sources of energy. In the next chapter, I will provide a literature review on

the issue of carbon taxation and its relevance to GHG mitigation. In the following

chapter I will explore how to integrate the conclusions from life-cycle analyses

into the carbon pricing structure by imposing a tax on upstream methane

emissions from natural gas production.

24

Chapter 3: Lifecycle Analysis of Fossil Fuels in Relation to

Greenhouse Gas Taxes

Introduction

The previous chapter revealed that upstream natural gas emissions comprise 20

percent of the fuel’s lifecycle emissions. Despite these high upstream emissions,

discussion of pricing GHG emissions usually includes only combustion

emissions. Implementing a lifecycle-based greenhouse gas tax has been

mentioned only in passing in relevant literature, and a major aim of my work is to

expand discussion on the issue (Morrow, Griffin & Matthews, 2008; Jaramillo,

Griffin & Matthews, 2008).

There are two primary methods by which to price carbon and other

greenhouse gases: emissions trading schemes and carbon taxes. Both methods

have been implemented throughout the world at a variety of scales: local,

regional, federal and international. One primary difference between the two

methods is that emissions trading sets an emissions level and taxes set a price per

unit of emissions (Weitzman, 1974). While there are benefits and drawbacks to

both policies my analysis will focus on taxes.

There are several reasons why I have chosen to focus on taxes in this

analysis. First, being able to set a price on emissions per unit of produced

electricity makes it easier to identify the different parties responsible for paying

the tax. Under an emissions trading scheme it may be more complicated to

allocate permits to the different industries involved along each step in the

25

lifecycle. Secondly, with GHG taxes there is great potential to accumulate

revenue to be used for environmental regulation and enforcement. Although both

emissions trading schemes and carbon taxes function to price carbon, while in

different ways, from a revenue point of view taxes may be preferable. This is due

to the fact that there is uncertainty in permit distribution associated with emissions

trading schemes, since many programs grandfather permits instead of auctioning

them (Cramton & Kerr, 1998). The economic literature on the topic strongly

recommends that all permits are auctioned, but this is often not the case in

practice (Speck, 1999; Cramton & Kerr, 1998). Lastly, the electricity sector has

also been found to be most strongly affected by carbon taxation. This is supported

by results from modeling studies. For example, Choi, Bakshi and Haab (2010)

found that a $50 per ton carbon tax reduces emissions from the electricity sector

by 52 percent, far higher than the other sectors analyzed in their study.

My analysis focuses on the electricity sector due to the importance of coal

and natural gas generation and the potential for large-scale emissions reductions

from GHG taxation. By surveying the literature on carbon pricing mechanisms I

will aim to arrive at the range and average of suggested pricing levels to achieve

emissions reductions. Since carbon prices are reflected in terms of dollars per ton

of carbon or per ton of CO2 (equivalent) it will be possible to relate both

combustion and upstream emissions of natural gas to these proposed prices. In the

next chapter, I will discuss to which parties each of these taxes could be levied.

26

Important effects of carbon taxation include reduced energy consumption,

and adoption of cleaner and more efficient energy generation technologies

(Newell, Jaffe & Stavins, 2006). There is a strong consensus in the literature that

fuel switching is one of the primary ways in which carbon pricing reduces

greenhouse gas emissions in the short to medium term (Newell et al., 2006; Van

Vuuren et al., 2004). Often the literature discusses a dichotomy in which short-

term efficiency and fuel switching are primary modes of emissions reduction, but

later on carbon-free technologies are necessary to meet mitigation or stabilization

goals. Since the aim of this work is to focus on near-term climate change

impacts, namely reducing methane emissions, these near-term impacts are central.

Fuel switching implies a shift from one fuel to another, and in this case it refers to

a movement away from coal and toward natural gas and/or renewables for

electricity generation. Most of the models discussed here show that carbon taxes

encourage fuel switching. At the minimum studies will mention that many

emissions reductions are met through switching from coal to less carbon-intensive

fuels. Some studies quantify these statements with data. Results of this type are

presented in terms of percentage change in generation from different fuel sources

based on pricing levels.

The literature also reveals that fuel switching from coal to natural gas is

one of the most inexpensive methods to reduce carbon emissions (Newell et al.,

2006). This is due to a number of factors including the low price of natural gas in

the U.S., the inefficiency of many coal-fired power plants and the comparatively

27

higher efficiency of natural gas combined cycle plants (NGCC). Modern NGCC

plants have efficiencies of between 52 and 60 percent, while coal-fired plants

have efficiencies around 45 percent (IEA, 2010). Since 2004 more than 90 percent

of new natural gas turbine installations in the U.S. have used NGCC (Natural Gas

Combined Cycle) technology, as opposed to conventional natural gas generation

(IEA, 2010). Carbon taxes can greatly reduce GHG emissions from the electricity

through fuel switching. The following section will detail a range of recommended

carbon prices.

Literature on Carbon Taxation

Commonly, carbon taxes are assumed to be levied in proportion to the

combustion emissions associated with the fuel. Pricing is based on the carbon

content per unit energy generated (Padilla & Roca, 2002). Therefore, the tax

levied on natural gas is typically much lower than those levied on coal. For

example, a carbon tax modeled by Boyd, Krutilla and Viscusi (1995) suggested

the tax level of natural gas to be 26 percent that of coal, based on natural gas’s

lower GHG emissions from combustion per unit energy produced. However,

results from the previous chapter demonstrate that natural gas is approximately

half as GHG intensive as coal when accounting for full lifecycle emissions.

28

Survey of GHG Pricing Levels

Recommended carbon taxes based on modeling studies vary between $17 and

$240 per ton carbon to achieve moderate levels of emissions reduction. Results

from the literature survey are depicted below in Table 2. The rest of this section

will detail the literature reviewed and why there is variation among recommended

carbon prices.

Low High Mean Median

$17 $240 $67 $50

Table 2: Range, mean and median of recommended carbon pricing levels surveyed from the

literature. Prices are in US$/ton carbon.

Research in economic modeling can be conducted using integrated climate

and economy models to estimate how high a carbon tax needs to be to impact

emissions over a specified time frame. According to Roughgarden and Schneider

(1999), median optimal taxes to avoid loss in global output predicted from a 3

degree C increase in global temperatures are $52 per ton carbon by 2055 and $67

per ton C by 2105. These were found using an updated version of Nordhaus’s

Dynamic Integrated model of Climate and the Economy (DICE). They improved

Nordhaus’s model by integrating a range of potential climatic impacts and the

carbon taxes necessary to avoid them (Roughgarden & Schneider, 1999).

29

A literature review by Krause (1996) contends that a carbon tax in

conjunction with tax shifting and subsidy removal would reduce Europe’s

emissions by 2 percent annually. The author examines a wide range of studies and

states that taxes around $50 per ton carbon result in some emissions reductions

below the baseline year while reducing deadweight loss, if tax shifting is included

(Krause, 1996).9

To reduce emissions to 1990 levels by 2020, a carbon emission reduction

of 14.4 percent, would require a tax of $17 per ton carbon (Jorgenson &

Wilcoxen, 1993). The comparatively lower value for this study is in part due to

the high elasticity in demand for coal assumed by the study authors. Production of

coal falls by 26.3 percent in their analysis under a carbon tax scenario (Jorgenson

& Wilcoxen, 1993).

Research presented by the IPCC in AR4 shows great optimism for the

effectiveness of a carbon tax. They contend that a carbon price could yield

significant mitigation across all sectors (IPCC, 2007b). The IPCC found that

modeling studies that take into account induced technological change recommend

prices ranging from $19 to $240 per ton carbon to be effective for the period

2007-2030 (IPCC, 2007b). The IPCC defines induced technological change as

improvement to technology motivated by policy. In the case of methane

mitigation from natural gas systems, it is reasonable to assume induced

9 Tax shifting refers to applying the tax revenue to offset a more regressive form of tax, like

payroll tax and tends to increase economic efficiency.

30

technological change based on the already existing regulatory framework aimed at

reducing these emissions.

The literature demonstrates the effectiveness of a carbon tax in

encouraging fuel switching (Fischer & Newell, 2008). One recent modeled

simulation found that a $26 per ton carbon tax yielded a 5.7 percent reduction in

coal-based electricity generation, a 6 percent increase in gas-based generation,

and a 23 percent increase in renewable generation (Fischer & Newell, 2008).

Most of the literature reviewed in this chapter pertains to taxing

greenhouse gas emissions from combustion sources. Since the aim of this work is

to quantify upstream emissions from natural gas systems, the following chapter

will discuss several mechanisms by which to regulate these emissions, including

recommending a methane tax.

Conclusions

The literature reviewed in this chapter recommends carbon taxes between $17 and

$240 per ton carbon with a mean of $67 and a median of $50. The carbon taxes,

as described here, do not include emissions from upstream sources, which in the

case of natural gas are 20 percent of total GHG emissions. Because of these high

upstream emissions, I recommend a tax on the upstream methane emissions,

primarily focusing on fugitive and vented emissions, priced similarly to

combustion emissions discussed in this chapter. The literature describes many

ways in which tax revenue can be distributed to achieve various aims such as

31

environmental protection, renewable development, poverty alleviation or

reduction in payroll taxes (Hyder 2008; Bossier & Brechet, 1995; Barker &

Kohler, 1998). Funds can be similarly allocated towards methane mitigation for

natural gas systems. Funds generated from a tax could be earmarked to finance

equipment required to monitor and reduce upstream natural gas emissions

(Baranzini, Goldemberg & Speck, 2000). If a GHG tax were levied on upstream

natural gas emissions the result would be a reduction in fuel switching from coal

to natural gas, as the price gap between these two fuels would be reduced. The

next chapter will focus on how to apply these surveyed prices to reducing

methane emissions from natural gas systems.

32

Chapter 4: Results

Introduction

The review of lifecycle analysis studies presented in Chapter 2 demonstrated the

quantity of upstream emissions from natural gas and coal, the two dominant fuels

in the U.S. electricity sector. On average for all studies reviewed natural gas is 49

percent less GHG intensive than coal when accounting for full life-cycle

emissions. When accounting for only combustion emissions, natural gas is 57

percent less GHG intensive than coal. Average lifecycle emissions for natural gas

in the U.S. are 536.7 kg CO2e per MWh of produced electricity. Most of the

studies reviewed assume NGCC. Coal on the other hand emits 1061 kg CO2e per

MWh of produced electricity. Furthermore, emissions from combustion of natural

gas were found to be 80 percent of total lifecycle emissions, while for coal,

combustion comprises 95.5 percent. This difference is important in regard to

carbon taxes because they are typically levied based on the fuel’s carbon content

per unit energy produced. Thus, a carbon tax on coal based only on combustion

emissions would reflect nearly the full lifecycle emissions, while because of the

high upstream emissions from natural gas, 20 percent of GHG emissions would

be omitted from combustion-only pricing mechanisms.

The literature review in Chapter 3 on carbon pricing demonstrated that

fuel switching from coal to natural gas in the electricity sector is one of the

strongest effects found in studies modeling a carbon tax. These results have

33

shown that under carbon pricing natural gas will be favored due to its lower

combustion emissions. However, pricing of upstream emissions will alter this

predicted fuel switching effect. My survey of carbon pricing levels found a

median recommended carbon price to be $50 per ton carbon ($14 per/tCO2), to

achieve moderate emissions reductions in the near term while minimizing

economic losses.

The purpose of this chapter is to link the data on lifecycle emissions and

the discussion of carbon pricing into cohesive policy recommendations aimed at

reducing upstream methane emissions from natural gas systems. It will also focus

on what is currently being done to reduce these emissions as well as policy

measures presently on the table.

Integrating Natural Gas LCA and GHG Taxation

I propose a tax on vented and fugitive methane emissions from natural gas

systems. This method of taxation would involve accurate measurement to gauge

true emissions from these systems and their progress towards mitigation. My

recommendation requires monitoring and measurement of methane emissions, so

that the tax is effectively levied.

Based on the data presented thus far in the previous chapter, an estimate

for an effective price on carbon to achieve appropriate emissions reductions

ranges from $17 to $240 per ton carbon ($5 to $65 per ton CO2), with a mean of

$67 and a median of $50 per ton C. Applying the low and high end of this range

34

to estimates derived for life-cycle emission from the natural gas electricity sector

allows us to ascertain the new price per MWh of natural gas-based electricity

produced with the proposed tax based on emissions data from the literature,

instead of true measured emissions. Since upstream and combustion emission are

the responsibility of separate parties, we can then apportion the emissions tax to

be paid by separate parties under the proposed lifecycle-based tax to determine

what new prices may look like based on average emissions data from the

literature. The average emissions from natural gas systems analyzed was

determined to be 537 kg CO2e/MWh and the average contribution to total

emissions from the combustion at the power plant is 80 percent. Therefore, the

tax on 429.6 kg CO2e must be paid by the utility burning the fuel while the tax on

107.4 kg CO2e must be paid for by the upstream parties. Assuming a CO2 tax

ranging between $5 and $65 per ton would result in prices rising by a maximum

amount ranging between $3.68 and $52 per MWh combusted and a maximum

amount ranging from $0.92 to $13 per MWh for upstream emission sources.10

This paper focuses on the electricity sector, but a tax like this could be extended

to cover emissions for other end uses of natural gas.

There are several issues with allocating taxes in this manner. Firstly, and

most importantly, it may lead to the perverse incentive of allowing for no

incentive to reduce upstream emissions. If we were to tax producers based on

emissions data from the literature, it would not be possible to reward producers

10

These maximum amounts are based on the assumption that the demand elasticity is zero, which

is clearly unrealistic.

35

who have worked to reduce their emissions. And secondly, it would be

administratively difficult to assign charges to all of the parties involved in the

processes of production, processing, transmission and distribution of the fuel.

Therefore, I propose a simpler method of sharing the tax burden with upstream

parties. Because methane from natural gas production is the major driver of the

fuel’s higher upstream emissions, I recommend a tax on the vented and fugitive

methane emissions from production sources. My proposal reduces the

disincentive to reduce methane emissions because it requires measurement of

methane emissions from producers. Once methane emissions are quantified, the

producer must either pay a tax for their emissions or reduce the emissions through

currently available technology. There is already policy and technological

background to influence and provide precedence for this proposition.

Existing Regulatory Framework

Currently, under the Subpart W of the U.S. EPA’s mandatory reporting rules of

greenhouse gases, petroleum and natural gas producers that emit more than

25,000 metric tons or more CO2e are required to report fugitive and vented

emissions of CH4 and CO2 (U.S. EPA, 2011d). Data was first collected in 2011

and will be available later in 2012. Monitoring and reporting of emissions is now

required for venting during well workovers and completions, well testing and

flaring, fugitive emissions and equipment leaks in gas processing, transmission

36

compression, and gas storage (U.S. EPA, 2012b). At this point these rules require

only reporting of emissions, which has many potential benefits. Subpart W

reporting rules will provide better data on emissions from the natural gas

production sector, including where mitigation work has been successful

(Fernandez, 2011). The improved and expanded available data will also inform

policy in the future (Fernandez, 2011). During the data collection period, while

the EPA assesses the trends and emissions sources, reductions could be met in the

intermediary through the proposed tax on methane emissions. Because of

methane’s high potency as a GHG over a 20 year lifecycle, a tax on these methane

emissions may help to reduce heat trapping emissions while more permanent

solutions for CO2 and other GHGs are discussed.

The EPA’s Natural Gas STAR Program works specifically to minimize

methane emissions from natural gas systems in the U.S. (U.S. EPA, 2011b). The

EPA has worked to identify the major sources of methane throughout the natural

gas lifecycle and has developed cost-effective methods for monitoring and

reducing these emissions. As stated in previous chapters, the major sources of

methane in the natural gas lifecycle are fugitive leaks or vented emissions during

normal operations or routine maintenance; 64 percent of methane comes from the

production portion of the lifecycle (U.S. EPA, 2011b). Based on this data, more

administratively feasible policy recommendations would address these key

sources of methane.

37

On July 28, 2011 EPA proposed regulations for reducing pollution from

natural gas production. They developed New Source Performance Standards

(NSPS), which would reduce volatile organic compound (VOC) emissions as well

as methane emissions from hydraulically fractured wells. These standards include

decreasing emissions that occur during the flowback period or during well

completion when hydraulic fracturing fluids and gases flow from the well up to

the surface. Emissions can be decreased through “green completions,” which

capture and treat released gas to be sold (U.S. EPA, 2011c). Using special

equipment, hydrocarbons are separated out to be sold on the market. These EPA

rules have a net cost of $754 million with sales potential from the recovered gas

of $783 million, based on 2011 natural gas prices, yielding a net benefit of $29

million across the U.S. natural gas sector (U.S. EPA, 2011c). Additionally, the

potential environmental hazards during the flowback period pertain to water

quality issues commonly discussed in regard to hydraulic fracturing of shale

plays. Fluid released during the flowback period can be treated and recycled to

reduce environmental harm from depositing potentially toxic fluids into the

municipal wastewater system (NETL, 2011). These associated environmental

quality issues are not directly related to methane emissions, and the technology

designed to treat the gas will not treat the liquid. Yet, this does demonstrate the

parallels between environmental protection and greenhouse gas emissions in

terms of natural gas production.

38

In April 2012 the EPA changed the new rules to allow for a transition

period before requiring green completions on all fractured and refractured wells.

Between now and January 2015 the EPA requires emissions reductions through

flaring. The EPA still encourages early adoptions of green completions, but is

delaying requiring them until 2015 when they believe the technology will be more

widespread (EPA, 2012c).

These described reporting rules and regulations of methane emissions

from the natural gas industry demonstrate the awareness of this problem. In the

future these rules will likely lead to regulations designed to reduce these

emissions using a command and control framework based on the Clean Air Act.

These regulations are projected to reduce emissions to a similar extent as would

have Waxman-Market cap and trade legislation, if it had passed (Burtraw, Fraas

& Richardson, 2011). Despite the potential for emissions reduction, the regulatory

agency does not have perfect information on low-cost emissions reductions

techniques and strategies. Without this information regulatory strategy will not

reduce emissions at as low a cost as would an incentive-based policy, like the

proposed carbon tax (Burtraw et al., 2011). A proposed carbon tax would

compliment these regulations by allowing for incentives to industry to reduce

emissions in the most cost-effective manner. It would promote information

sharing between the regulatory agency and industry, additional to the preexisting

Natural Gas STAR Program.

39

Current Work to Reduce Methane Emissions

Methane gas leaks are invisible to the human eye, and therefore go unnoticed

(U.S. EPA, 2010). As is known, natural gas systems are the number one source of

methane emissions in U.S. Fugitive emissions of methane are significant, and can

be valued at over $230,000 per production plant annually. There are over 700

natural gas processing plants in the U.S. that operate approximately 5000

compressors (U.S. EPA, 2010). The majority of methane released from natural

gas systems, 58 percent, comes from the field production stage (U.S. EPA,

2012a). The value of this product lost to producers is significant, and therefore

provides incentives to companies to reduce their emissions of methane.

One way natural gas producers reduce methane emissions is by using

infrared cameras and airborne laser-based gas analysis to detect and seal the leaks

(Kargbo, Wilhelm & Campbell, 2010). These surveys can be performed on the

ground to screen components at processing plants or wells and cost between

$15,000 and $20,000 for a medium sized plant. The recovery is highly profitable

with repair costs ranging from $10 to $2000 per component, while the value of

lost gas ranges from $11,032 to $29,498 per component (U.S. EPA, 2010).

Additionally, aerial leak surveys can detect escaping gas over long stretches of

pipelines using helicopters or aircrafts with IR detection devices (U.S. EPA,

2010).

The literature has demonstrated success of laser and infrared technology in

reducing methane emissions from natural gas systems (Chambers, Strosher,

40

Wootton, Moncrieff & McCready, 2006). Differential Absorption Light Detection

and Ranging (DIAL) remotely measure the concentration of gases in the

atmosphere from a distance using laser-based technology. This technology has

been successfully employed in Europe to measure fugitive methane emissions

from oil and gas production plants and flares, in addition to other chemical

compounds. Infrared cameras typically cannot differentiate between different

compounds or measure volumes of gas released, but they are useful in detecting

where leaks occur, so that companies can then monitor and measure the volume

and species being released. A pilot study in Alberta, Canada used both DIAL and

Infrared cameras to detect and measure leaks from 5 processing plants, and then

successfully mitigated these emissions based on the results. These improvements

reduced methane emissions by 50 percent and yielded increased revenue of

$730,000 per year (Chambers et al., 2006).

A large Canadian oil and gas company, EnCana, is currently reducing its

methane emissions from natural gas processing by using infrared cameras to find

methane leaks on pipelines and wells and then sealing them, in partnership with

the EPA Natural Gas Star Program (Lustgarten, 2009). Programs like this one

could be repaid in two years and then begin to turn profit once captured gas can

be sold on the market (Lustgarten, 2009). EnCana implemented their program in

2007. They detected leakage rates as high as 17 thousand cubic feet (Mcf) per day

per station. The program has reduced emissions by 358,000 Mcf per year with an

41

annual savings of $2.5 Million per year, given a price of $7 per Mcf11

(U.S. EPA,

2010).

Another company, Targa Resources, found leakage rates of about 3.6

percent and repaired 80 to 90 percent of these, reducing their yearly emissions by

198,000 Mcf, with an annual savings of $1.4 million per year, again given a price

of $7 per Mcf (U.S. EPA, 2010).

As evidenced by the cases presented here, methane emissions from natural

gas systems have the potential to be reduced substantially with currently available

technologies. A methane tax can speed up this process and influence natural gas

companies to reduce their emissions to mitigate climate change and increase their

bottom lines.

11

In 2011 the price of natural gas has decreased to around $3.95 per Mcf, so the total cost benefits

presented from this earlier analysis may be reduced (U.S. EIA, 2012b).

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Chapter 5: Policy Recommendations and Discussion

Policy Recommendations

Currently, in the U.S. there is a regulatory framework aimed at reducing methane

emissions from natural gas systems. It consists of the GHG reporting guidelines,

NSPS on fractured and refractured wells requiring green completions in 2015, and

the Natural Gas STAR Program, which works with industry to reduce methane

emissions from their systems. As of now, there is no carbon or GHG tax in the

U.S., despite discussions. Quantifying and reporting these emissions to the EPA is

a critical step in determining the extent of these impacts for when policy on GHG

emissions is eventually implemented. Based on this existing regulatory

framework for greenhouse gas emissions within the U.S., I propose a system of

methane measurement and taxation for producers of natural gas. This strategy

would complement the work already being performed by the EPA in their

programs and regulations. A tax implemented in the near-term would help to

incentivize emissions reductions before policy based on reporting is implemented

and before green completions are required in 2015. Additionally, it would help

mitigate methane emissions, which have a high GWP and are particularly potent

over a twenty year atmospheric lifetime. This would help fill the gap as we wait

for comprehensive policy on CO2 emissions to be implemented.

Firstly, I recommend measurement of methane sources at natural gas

production sites. This can be achieved using aerial leak detection with either laser

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or infrared technology, as described in Chapter 4 (U.S. EPA, 2011b). Once the

producer has a record of their methane contributions they can choose to pay a tax

equivalent to $14/ton CO2e ($50/ton C), which would be $338/ton CH4 (based on

a GWP of 25), or they can choose to work with the EPA to reduce emissions

through proven cost effective technology options available through the Natural

Gas STAR Program given a set compliance period. The revenue generated

through this tax would be used to fund the EPA’s Natural Gas STAR

programming as well as finance the mitigation technology installations and

equipment manufacturing.

Although the focus of this work is on the lifecycle emissions of natural gas

and how to incentivize their reduction, it is important to consider and apply this

method of analysis to all other forms of energy. It would be unfair to producers of

natural gas to tax their upstream emissions while ignoring those associated with

coal. And similarly, it is necessary to consider the lifecycle emissions of

renewable sources of energy. These emissions from renewables would be small in

comparison to fossil fuels, but regulation of lifecycle emissions should be applied

across all energy sources.

Environmental taxes are known to yield a “double-dividend,” meaning

they produce both environmental and economic benefits. This is particularly true

of this proposal in that the methane tax will incentivize reductions in GHG

emissions while simultaneously helping industry increase profits by capturing

escaped natural gas to sell to the market. Since between 1.49 and 5.33 percent of

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natural gas is lost during production, this could represent a significant economic

benefit to the natural gas industry (depending on natural gas prices) and may also

reduce the need to expand production fields, which in itself could yield substantial

environmental benefits.

The aim of this work does not center on the political viability of GHG

taxation in the U.S., which may be a challenge in the current political climate.

However, the specific nature of the tax proposed here does have certain

advantages, which could win it favor in political discussion. As with any tax,

environmental or non-environmental, the political climate surrounding its

discussion will be challenging, but by highlighting the potential benefits to

industry as well as the potential to further sustain the EPA’s natural gas programs,

discussion may be more successful. The fact that industry is already on board with

the Natural Gas STAR Program shows that they may be in favor of this

proposition. In fact, it may be a way for natural gas companies to compete against

one another as not only environmental stewards, but as efficient businesses

reducing product waste.

Appropriate Tax to Encourage Renewables?

Economic models work to predict the appropriate level of a carbon tax to meet

greenhouse gas mitigation goals. A carbon tax that does not include lifecycle

emissions favors natural gas over coal due to its lower GHG emissions from

combustion. A carbon tax reduces emissions through fuel switching to either

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renewables or natural gas from coal. However, including lifecycle emissions in

carbon pricing may reduce the degree of fuel switching from coal to natural gas

due its comparatively higher price. Inclusion of lifecycle emissions in carbon

pricing may reduce the amount of switching from coal to natural gas, and it may

also encourage fuel switching from coal to renewables, skipping over natural gas.

This outcome would reduce greatly reduce emissions, but the high cost of

renewables, like wind power is an obstacle to their widespread proliferation.

Therefore, it is important to determine what degree of tax would level the

playing field between prices of natural gas and substitutable renewable energy

sources, like wind power. In 2010 average U.S. wholesale wind power prices

were approximately $50 per MWh (U.S. DOE, 2011). Based on a 2011 price of

$3.95 per Mcf of natural gas, electricity generation costs $13.21 per MWh (U.S.

EIA, 2012b). Given the over threefold price difference between natural gas and

wind generation, a high lifecycle-based carbon tax would be necessary to level the

playing field between these two energy sources. A tax of $77 per ton CO2e ($284

per ton C) would be required to increase the price of natural gas generation to $50

per MWh, equivalent to wind power. A tax of this level or above would make

wind power as attractive economically as natural gas. A tax of this level would

encourage fuel switching not from coal to natural gas, but from fossil fuels to

wind or other similarly priced renewable sources. Consumers currently pay

approximately $0.12 cents per kilowatt hour, while wholesalers pay between

$0.20 and $0.40 per kWh. This tax would increase the wholesale price by just

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$.01 to $.03, so it may not result in substantially higher prices for consumers

(U.S. EIA, 2012e).

Any increases in price from this policy would be buffered by the federal

policies currently on the table to encourage renewable development. The

calculation performed above does not take into consideration these subsidies.

Currently, wind power enjoys a 2.1 cent per kilowatt hour federal Production Tax

Credit, which was renewed until 2012 under the American Recovery and

Reinvestment Act (UCS, 2009). This is further aided by an Investment Tax Credit

(ITC), which covers 30 percent of the project’s costs within initial production

years. States also give aid to renewable energy sources. For example, New York

will receive over $700 billion in federal incentives by 2014 for wind energy

(Hoerig, 2010). These forms of federal and state aid further close the gap in price

between fossil fuels and renewable energy sources.

A carbon tax of this level is highly unlikely to be politically or

economically palatable in the near future. Chapter 3 recommended a carbon tax

level closer to $14 per ton CO2 ($50 per ton C). Some studies are less

conservative with their pricing recommendations. Van Vuuren et al. (2004)

recommend a tax of $200-$300 per ton carbon to meet a 450 ppm stabilization.

Their figure is more in line with the tax just presented, and it is predicted to be

met primarily through fuel switching and energy efficiency.

There are two major potential effects that integrating a methane tax on

upstream emissions could have on fuel switching. Both of these are potential

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outcomes of the proposed tax but are highly divergent and have vastly different

climatological consequences. Firstly, it may actually have the unintended negative

environmental consequence of delaying a shift from coal to natural gas. Because

natural gas becomes comparatively less beneficial on GHG terms under this new

tax structure, more electricity generation may remain in coal rather than shifting

to natural gas through the retirement of old, inefficient coal plants and the

construction of new NGCC plants. Secondly, some experts have predicted and

cautioned that natural gas’s low price and abundance may retard our transition to

a renewable economy (IEA, 2011). An upstream methane tax may actually speed

up our transition from fossil fuels to renewables, or to cleaner natural gas systems.

Natural gas is seen by some as a stepping stone on the path to a renewable future,

and by taxing its GHG intensive upstream emissions we may be able speed up this

transition, while ensuring we not become locked in an age dominated by natural

gas.

Discussion

As discussed previously, fuel switching is a primary predicted effect under a

carbon tax. That is to say once carbon is taxed producers are more likely to shift

to less GHG-intensive energy sources. Currently, and in the near future, this

switch will be primarily from coal-fired generation to NGCC generation. This

concept is highly relevant to this work in that carbon pricing that ignores lifecycle

emissions, particularly of natural gas, will not properly account for GHG

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emissions from these sources. Simply evaluating the GHG emissions of a fuel

based on its combustion emissions will give an incorrect picture of its true GHG

merits over another fuel and the true climatological consequences of its use. Since

natural gas’s upstream emissions account for 20 percent of the fuel’s total

lifecycle emissions, integratin