Post on 23-Oct-2020
transcript
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
0
5
10
15
20
25
19
97
19
99
20
01
20
03
20
05
20
07
20
09
20
11
20
13
20
15
20
17
20
19
20
21
20
23
20
25
20
27
20
29
20
31
20
33
20
35
Qu
adti
llio
n B
TU
Natural Gas
Coal
3
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).
0
200
400
600
800
1000
1200
Kg
CO
2 e
qu
ival
en
t e
mis
sio
ns
pe
r M
Wh
NG Upstream Emissions
NG Combustion Emissions
Coal Upstream Emissions
Coal Combustion Emissions
11
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).
42
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
43
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
44
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
45
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
46
$.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
47
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
48
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