Natural gas and CO2 price variation: Impact on the relative cost-efficiency of LNG and pipelines

Abstract

Natural gas is often promoted as the most environmentally friendly of all fossil fuels, and liquefied natural gas (LNG) as a modern and efficient way of transporting it. Some research has been carried out into the local environmental impact of LNG facilities, but almost none into aspects related to climate change.

What actually causes most greenhouse gas emissions, LNG or pipelines? This question is highly relevant for climate change, but in practice the choice of transport option for natural gas in the real world will depend on the cost of CO2 emissions. How these costs play out depend on the volume of gas to be transported, the distance etc.

This article therefore develops a formal model for comparing LNG and pipelines. In particular, it evaluates how variations in the prices of natural gas and greenhouse gas emissions affect the relative cost-efficiency of these two options.

The paper concludes that, at current price levels for natural gas and CO2 emissions, the distance from field to consumer and the volume of natural gas transported are the main determinants of transport costs. The pricing of natural gas and greenhouse emissions influence the relative cost-efficiency of LNG and pipeline transport, but only to a limited degree at current price levels. Because more energy is required for the LNG process (especially for fuelling liquefaction) than for pipelines at distances below 9100 km, LNG is more exposed to variability in the price of natural gas and greenhouse gas emissions up to this distance. If the prices of natural gas and/or greenhouse gas emission rise dramatically in the future, this will affect the choice between pipelines and LNG. Such a price increase will be favourable for pipelines relative to LNG.

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Natural gas and CO2 price variation:
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Marte Ulvestad a & Indra Overland a
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Natural gas and CO
2
price variation: impact on
the relative cost-efficiency of LNG and pipelines
MARTE ULVESTAD* AND INDRA OVERLAND
Norwegian Institute of International Affairs (NUPI)
(Received 12 February 2012)
This article develops a formal model for comparing the cost structure of the two main transport
options for natural gas: liquefied natural gas (LNG) and pipelines. In particular, it evaluates how vari-
ations in the prices of natural gas and greenhouse gas emissions affect the relative cost-efficiency of
these two options. Natural gas is often promoted as the most environmentally friendly of all fossil
fuels, and LNG as a modern and efficient way of transporting it. Some research has been carried out
into the local environmental impact of LNG facilities, but almost none into aspects related to climate
change. This paper concludes that at current price levels for natural gas and CO
2
emissions the
distance from field to consumer and the volume of natural gas transported are the main determinants
of transport costs. The pricing of natural gas and greenhouse emissions influence the relative cost-
efficiency of LNG and pipeline transport, but only to a limited degree at current price levels. Because
more energy is required for the LNG process (especially for fuelling the liquefaction process) than
for pipelines at distances below 9100 km, LNG is more exposed to variability in the price of natural
gas and greenhouse gas emissions up to this distance. If the prices of natural gas and/or greenhouse
gas emission rise dramatically in the future, this will affect the choice between pipelines and LNG.
Such a price increase will be favourable for pipelines relative to LNG.
Keywords: Natural gas; Liquefied natural gas; Pipelines; Greenhouse gases; Pricing
Introduction
The natural gas from large fields is normally transported by one of two means: either by
pipeline or in the form of liquefied natural gas (LNG) [1]. In recent years, the production
of LNG has risen rapidly as new facilities have been brought online, increasing its share
of internationally traded natural gas to 30% in 2011 [2]. For the period 2005–2020, LNG
production is expected to continue growing at a clip of 6.7% per year [3].
The building of new LNG facilities has often resulted in local resistance due to
fears over the risk of explosions. Interestingly, however, there has been limited discus-
sion of the environmental impact of LNG in terms of greenhouse gas emissions. This
question is becoming increasingly pertinent as natural gas is cast as the transitional
fossil fuel for a low-carbon world: worse than renewable or nuclear energy, but better
than coal and oil. LNG is relatively abundant, the necessary technology exists, and
much of the infrastructure needed for its exploitation is already in place. If natural gas
*Correspondence address: marte_ulvestad@hotmail.com
International Journal of Environmental Studies,
Vol. 69, No. 3, June 2012, 407–426
International Journal of Environmental Studies
ISSN 0020-7233 print: ISSN 1029-0400 online Ó2012 Taylor & Francis
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is part of the medium-term solution to reducing greenhouse gas emissions and this is
going to lead to increasing amounts of it being moved around the globe as LNG, the
emissions aspect of LNG will become increasingly salient. In Norway, for example,
the new LNG facility at Melkoya is the country’s fourth largest source of greenhouse
gas emissions [4].
Regardless of the mode of transport for natural gas, some of the gas is used to generate
the energy required to transport the rest of the gas. In pipelines, a portion of the gas is
burned in order to run the turbines that force the rest of the gas through the pipeline to the
consumers. In an LNG plant, a portion of the gas is burned in order to generate enough
energy to cool the rest of the gas. When natural gas reaches a low of 161°C (260°F),
it shrinks into a liquid that takes one 600th the amount of space of the gaseous form,
becoming far more economical to ship [5,6].
Since both pipelines and LNG involve the burning of a portion of the gas, they also
result in the emission of greenhouse gases. The market value of the gas that is burned as
well as the cost of the resultant emissions will vary over time. Any major natural gas
extraction project that has to choose between pipelines or LNG thus also has to take into
account whether such future price variations may change the relative cost of the two infra-
structure types. Some of the largest natural gas fields currently slated for extraction are
located at distances from markets where such choices between pipelines and LNG need to
be made, including those in the Barents Sea, on the Yamal Peninsula and possibly in the
Persian Gulf.
Current assumptions in the literature
LNG and pipelines differ in their cost structures. Whereas the cost of pipelines tends to
rise steeply and linearly with distance, the cost of LNG has a high initial threshold but a
lower increase with distance [6]. When choosing between these two options for transport-
ing natural gas from a new field, a break-even point somewhere between 3000 and 5000
kilometres is often mentioned in the literature [7]. For the transport of natural gas over
shorter distances, pipelines are assumed to be cheaper, whereas transport using LNG is
normally more cost-effective for distances longer than this.
The literature offers several different formulations of this break-even point. Tongia and
Arunachalam note that, due to the expense of building LNG facilities –such as tankers,
re-gasification facilities and reception and storage terminals –pipelines will have a lower
cost over shorter distances of around 2000 miles (3219 kilometres) or less [8]. According
to Cornot-Gandolphe et al. [9], in 2003 the break-even point was around 4500 km at a
price level of $1.60/MMBtu ($1.90/MMBtu in 2010). The same year, Quintana [10]
argued that LNG is the best option for markets located more than 4000 kilometres away
from the gas field and which have a volume of more than 16 MMm
3
/day.
In a 2009 report, Paul Stevens argued that the cost of LNG had risen significantly, and
that the break-even point had therefore risen to around 5000 km [1]. Further nuancing the
comparison of LNG and pipelines, Mäkinen [11] claimed that, ‘In general, LNG becomes
economically feasible in contrast to 3000 to 4000 kilometres of land pipe or 2000 km of
offshore pipe.’The break-even point will differ from project to project, depending on the
geography, logistics and legal and political factors involved [11].
The literature says little about the analysis and data upon which these break-even points
are based. This leaves several important questions unanswered: are both construction and
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operating costs taken into account? If the price of natural gas rises, will the transport of
natural gas as LNG still be cheaper than pipeline transport over distances greater than
4000 kilometres, taking into account the fact that the LNG chain consumes more gas than
do pipelines? Are costs related to CO
2
emissions included in the calculations? This article
aims to fill the void in the literature represented by these questions, by developing a for-
mal model for estimating the impact of natural gas and greenhouse gas price variation on
the overall cost of the two transport options.
The prices of natural gas and greenhouse gas emissions are, however, only two out of
many factors that determine the cost of LNG and pipelines. In order to understand their
impact on overall costs, we must view these prices in the context of the other factors upon
which the overall costs depend, in particular the amount of natural gas and the distance it
must be transported. As the comparative advantages of LNG and pipelines change in
accordance with these factors, we need to understand their impact before examining how
variation in the prices of natural gas and greenhouse gas emissions plays into the relative
cost-efficiency of LNG and pipelines.
In addition to the various factors that affect the cost structure of LNG and pipelines
that we will cover here, there are many other factors which might affect the choice of
transport method, for supplier and importer: taxes, capital charge, interest rates, insurance,
the economic lifetime of capital, the flexibility of the LNG spot marked, demand and
supply security, the risk of terrorist attacks, and the value of scrap metal at end of capi-
tal’s lifetime. Putting a general price on these conditions is difficult, so they are not
included in this analysis –but they remain important for the decisions made about such
infrastructure.
Before developing a model for comparing LNG and pipelines, it is necessary to explain
some of the basics of pipelines and LNG. We start with pipelines, as this is the older,
baseline technology.
Note: Figures in brackets show gas delivery capability in BCM
2000 4000
MILES
6000 8000
1
2
3
/MMBTU /BBLOE
20
10
20"
Onshore
Gas Line
(2.5)
36" LP
Offshore
Gas Line
(10)
36" LP
Onshore
Gas line
(10)
42" HP Offshore
Gas Line (29)
56" LP Onshore
Gas Line (31)
Single Train LNG (4.3)
Onshore
Crude Line
Crude Oil
Tanke r
Coal by Collier
15
5
Figure 1. Break-even points.
Source of data: [6].
Natural gas and CO
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Pipeline economics
The costs of pipelines and LNG can be divided into capital (construction) expenditure
(CAPEX) and operating expenses (OPEX). CAPEX consists of pipe materials, installation
and coating of the pipe, the building of compressor stations, construction management and
right-of-way clearance. OPEX include compressor station fuel, pipe repairs, environmental
permits and administrative costs [12].
Both construction and operating costs may vary significantly from one region to another.
Differences in terrain, climate, labour costs, population density and the degree of
competition between different natural gas provinces make pipeline economics highly pro-
ject-specific [9]. Pipeline planners are therefore often hesitant to generalise the costs of
constructing pipelines. A pipeline that runs through a dense urban area might cost five times
more than a pipeline of the same length and diameter crossing a rural area [13]. The generic
model for estimating the impact of variations in natural gas and emissions costs developed
in this article will therefore have to be adapted when applied to individual cases.
Pipeline CAPEX
This article focuses on onshore pipelines, which are more common and normally less
expensive than offshore pipelines. Several approaches will be used in this section in order
to make an estimation of the costs of transporting natural gas by pipeline. The estimation
will mainly follow the ‘cookbook’approach developed in Jung et al. [14] for East Asian
projects, drawing on Kubota [15]. This is combined with a formula for cost per pipe diam-
eter per distance as suggested by the Canadian Energy Pipeline Association [16], while
pipeline data from the USA published by Parker [13] are used to discuss the costs of
constructing and operating natural gas pipelines.
Pipeline construction costs depend mainly on the cost of material (carbon steel), cost of
labour, pipeline length and diameter and the number and capacity of the compressor sta-
tions. The data published in the Oil & Gas Journal were derived from the US Federal
Energy Regulatory Commission and are divided into four categories: material, labour, right
of way and miscellaneous costs [17]. The latter category includes surveying, engineering,
supervision, administration and overhead, interest, contingencies and allowances for funds
used during construction, and regulatory filing fees [18].
The capital costs (C) for a common onshore pipeline can be calculated by means of the
following equation:
C¼$52;675ld þð$3 107Þaþ$3091c
The costs of constructing the pipeline are calculated by multiplying a constant cost by the
diameter (μ) measured in inches, and by the length of the pipeline (δ) measured in km. α
is the number of compressor stations and c is the total capacity of the compressor stations,
measured in horsepower. Jung et al. [14] used $21,300 as the cost per inch per kilometre
for a common onshore pipeline in 2000. The estimated costs used in Jung et al.’s report
[14] are more than 10 years old, and may no longer be valid for new projects. The costs
of labour, materials or other components may have risen, or new cost-reducing technology
may have been introduced to the market. We will ignore the last problem because, as pipe-
line transport is less complex, there have been only small cost reductions for pipeline
transport compared to LNG in recent years [9] . The cost estimates from 2000, however,
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do need to be revised in view of the increased costs of vital inputs. In the USA, actual
costs per pipeline mile rose by an average of 247.3% from 2001 to 2010, rising from
approximately $1,310,000 per mile to $4,550,000 per mile in the same period. This
increase was caused mainly by higher costs of labour and materials [18]. In the absence of
more reliable data, we will use these figures to revise the figures from Jung et al.’s [14]
report.
Nevertheless, price levels may have changed differently, depending on the country in
question. The figures used by Jung et al. [14] are for a ‘Common Onshore Pipeline’, and
it is unclear upon which country’s prices the estimates are based. For example, the USA,
Russia and Japan have seen the price level of investment (PPP over investment) develop
in different directions over the past decade. In the USA, 2000–2007, the price level of
investments decreased by 11.7% (although it has probably increased sharply since then)
and in Japan by 32.8%, whereas in Russia the price level of investments increased by
124.1% during the same period [19]. But it is nevertheless important to revise the pipeline
costs from 2000 to make them comparable with the revised LNG costs.
It is possible to check the accuracy of these estimates by comparing them with a
proposed pipeline where the estimated costs are more or less current. We have estimated
the costs of the Nabucco pipeline by entering the pipeline details (diameter of 56 inches,
11 compressor stations, distance 3893 km) into the equation below [20,21]. The equation
calculates a total construction cost of almost $16.8 billion –afigure much higher than the
estimated e7.9 billion ($11.5 bn) stated on the Nabucco project website [22]. According
to Webb [23], however, the oil and gas company BP has produced a new estimate of e14
billion ($20 bn) for the same construction costs. These differing estimates exemplify the
difficulty of determining pipeline construction costs.
Compressor stations constitute a large percentage of total construction costs. Jung et al.
[14] use a fixed cost per compressor station (α) and then a variable cost per unit of horse-
power. We assume that average distance between the compressor stations is 200 km [24]
and that average capacity per compressor station is 110 MW. The latter assumption was
made after a comparison of several proposed Russian pipelines and their capacities [25].
Parker [13] uses construction cost projections for over 20,000 miles of pipelines in the
USA to generalise the construction costs for a pipeline of a given length and diameter. Par-
ker concludes: ‘Materials costs account for approximately 26% of the total construction
costs on average. Labour, right of way, and miscellaneous costs make up 45%, 22% and
7% of the total cost on average, respectively.’These shares are estimated on the basis of
US data for the years 1991–2003. The data refer to pipelines between 4 and 42 inches in
diameter, which is less than many of the long-distance pipelines in Russia. For example
the diameter of the pipeline running from Yamal to Europe is 56 inches (1420 mm) [26].
The small pipeline size is a problem, as pipeline diameter determines the share of the total
costs within the four construction cost categories. For example, for a 4-inch diameter pipe-
line, materials account for 15% of total construction costs, but this figure rises to 35% for
a pipeline 42 inches in diameter [13].
The cost of labour often differs significantly between countries or regions, as does the
cost of materials (steel not least), which are never exactly the same throughout the world
[27]. Furthermore, pipeline construction costs do not remain static within a country.
Therefore, the relative share of construction costs depends on a range of interlinked fac-
tors with, for example, material or labour costs fluctuating as wages or steel prices
change. Figure 2 shows the average breakdown of construction costs in the USA for the
period 2009/2010.
Natural gas and CO
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price variation 411
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Here, the cost of materials differs markedly from the 26% share mentioned by Par-
ker [13] above. The reason is that Parker’s data are from 1991–2003, whereas the data
presented in the figure are from July 2009–June 2010. Figure 3 below shows the
development of the share of material and labour costs in the USA over the past 10
years.
According to Chandra [28], steel may account for as much as 45% of the total cost of a
typical pipeline. It is possible to estimate the cost of steel in the overall share of
construction costs in greater detail by using the Figure 3 graph above, Figure 5, and the
US Carbon Steel Plate Prices from Figure 7 fig7 below. The estimates show that steel
accounted for 5.6% of total construction costs from 2001 to 2003. The share rose mark-
edly in 2004, due to a steep increase in steel prices, and was as high as 14.5% of total
costs from 2005 to 2008. This may even be an underestimate.
Figure 2. Pipeline construction cost components.
Source of data: [18].
Figure 3. The share of the two major cost components in pipeline construction, 2001–2010.
Source of data: [18].
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Pipeline OPEX
A pipeline has annual operating costs such as fuel for the compressor stations, repair costs,
SCADA and telecommunications, lease and rental, wages and administrative costs [12].
Operating costs are relatively project-specific, but may be broken down into two catego-
ries: operating costs as a fixed percentage of the construction costs and fuel.
Operating costs for a typical onshore pipeline can be estimated as follows:
Op¼Csþ1ð1lÞd
g

Np
N is the volume of natural gas, measured in cubic meters per year, p is the price of natural
gas, measured in dollars per cubic meter, and ηis the number of kilometres between the
compressor stations. The operating cost as a share of the capital costs (τ) is 3.5% for a
common onshore pipeline. The percentage of the natural gas used as fuel in the compres-
sor stations (ℓ) is 0.4% per every 100 miles (according to Jung et al. [14]). The reason
why authors use the term ‘every 100 miles’is probably that they account for compressor
stations every 100 miles on average. But 100 miles (161 km) between the compressor sta-
tions seem short compared with long-distance pipelines like the proposed Nabucco pipeline
and the Altai project. The Nabucco pipeline route is 3893 km long, with an estimated 11
compressor stations [20,22]: thus, the average distance between compressor stations will
be 354 km. Furthermore, the Altai gas pipeline will be over 2600 km long and will have
10 compressor stations [25], corresponding to one compressor station every 260 km. In
contrast, the Gryazovets–Vyborg pipeline will have a compressor station every 131 km,
and the Ukhta–Torzhok pipeline every 198 km on average. The estimated distance between
the compressor stations (η) will therefore be 200 km, as mentioned in Whist’s article [24].
LNG economics
The production and transport of liquefied natural gas is a three-step process: first liquefac-
tion of the natural gas, then tanker transport and finally re-gasification. Here we will ignore
the transport of natural gas from the field to the liquefaction plant, which is usually situ-
ated on the coast, because this stage is necessary for both pipeline and LNG transport and
will not make a difference in the comparison[29]. The costs of LNG projects are difficult
to generalise because they vary significantly from location to location, and depend on
whether the project is greenfield or an expansion of an existing plant [30].
The liquefied natural gas is made in a liquefaction plant where the gas is refrigerated to
161°C (260°F). The gas becomes a liquid, in the process shrinking to 1/600th of its
volume in gaseous form. The liquefaction plant consists of so-called ‘trains’, processing
modules, the size of which depends on the available compressors. In 2004, the largest
trains could produce around 4 million tonnes per year (tpy). But, with improved compres-
sor technology it is now possible to produce larger trains and further exploit the economies
of scale. These costs may be further reduced by around 25% by replacing two 2-million-
tonne trains with one 4-million-tonne train [6]. Today, Qatar has several single-train lique-
faction plants with a capacity of 7.8 million tpy per train [31].
Field
development Liquefaction Shipping Re-gasification Power
generation
Figure 4. The LNG chain.
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The liquefaction plant is usually the most expensive link in the LNG chain. This is
because the liquefaction process demands a considerable amount of the gas delivered to
the plant [32], but also because of the remote locations, strict design and safety standards
and the large amounts of materials required [30].
Most LNG plants have their own fleet of LNG carriers, ‘... operating a “virtual”pipeline’,
according to Chandra [28]. This might change, however, with the increasing spot-trade mar-
ket [28]. According to Jensen [6], a typical LNG carrier can transport 135,000 to 138,000
cubic meters of cargo: this capacity is currently increasing, due to better designs. By March
2011, the world fleet of LNG carriers had 44 active carriers with a capacity of over 200,000
cubic meters. The largest LNG carriers have a capacity of 266,000 cubic meters of LNG [33].
The final link in the LNG chain is the re-gasification terminal with vaporisers which
warm the liquefied natural gas from 161°C to about +5°C, and into its normal gaseous
form. Other main components of the re-gasification facilities are the offloading berths,
LNG storage tanks and pipelines to the local gas grid [28].
Due to new technology and designs, there will be several changes or options coming in
the near future that might improve the LNG chain. Floating LNG production, which will
make the costly gas transport from the field to the onshore LNG plant unnecessary, is on its
way. Vautrain and Holmes [34] claim that for a remote offshore field the cost of bringing
the gas to an onshore plant might add as much as 40% to the total cost of the LNG plant.
Furthermore, the possibility of offloading the LNG offshore is currently under study, as
is ship-to-ship transfer. This might lead to larger ships offloading some of the LNG onto
smaller ships which could transport it directly into port, warm the LNG into gaseous form
and offload it directly into the local pipe grid [28]. As this technology is not in widespread
use, it is therefore outside the focus of this paper.
LNG CAPEX
The costs of LNG projects are difficult to determine because the costs of the components,
such as steel, nickel, wages and services may vary significantly over time. For example, in
2004 the cost of building a liquefaction plant had fallen to less than $300 tpy, due to the
exploitation of economies of scale and the development of trains with larger capacity.
Because of rapid increases in the price of materials and services, however, the cost of a
liquefaction plant rose to $650 tpy in 2008 –more than double the 2004 price [35].
This corresponds well with the figures used in the report ‘Natural Gas Pipeline Develop-
ment in Northeast Asia’by Jung et al. [14], which will be used as a basis for the cost
composition, but with revised figures. Jung et al. [14] break the total LNG costs into LNG
liquefaction plant costs, LNG carrier costs and LNG re-gasification terminal costs.
The capital costs of the LNG liquefaction plant (P) are divided into a fixed cost for a
greenfield plant with a capacity of 4 million tpy of LNG (5.5 bcmpa) and a variable cost
per extra million tonne, if further expansion is needed. L is the amount of LNG, measured
in million tonnes per year.
P¼ð$5:5109Þþð$1 109ÞðL4Þ
The cost of a single-train 4-million tpy onshore LNG plant is $5.5, billion according to
Vautrain and Holmes [34]. Train sizes of around 4 million tpy are the most common
capacities, but this will probably change as the designs are further developed. Qatar
already has several 7.8 million tpy trains [31]. Moreover, adding a train to an LNG plant
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in order to expand the capacity is far cheaper than a greenfield project. Adding a second
train can reduce the unit costs per train by 20 to 30% [9], because many of the expensive
facility components are already constructed and can be shared [30]. The Qatargas 4
project, where Qatargas added another train, with a capacity of 7.8 million tpy, to the
existing Qatargas 2 and 3, will have a cost of around $8 billion [36,37].
According to the US Energy Information Administration [30] around 50% of LNG liq-
uefaction plant costs are construction and related costs, 30% are equipment costs and 20%
are for bulk materials. These shares are only approximations and may change as the prices
of the various components change.
The sizes of LNG carriers are also increasing due to better designs and technology.
Today, a carrier might have a capacity of 266,000 cubic meters. There are 10 carriers of
this size; these are also among the newest. Qatar Gas Transport Company’sRasheeda was
delivered in August 2010. All the largest carriers have a speed of 19.5 knots, or about 36
km/h.
The cost of an LNG carrier with a capacity of 266,000 cubic meters is about $290 mil-
lion. The size of the fleet needed to transport the LNG depends on the distance (δ) from
the market, the speed (λ) and the capacity (k) of the LNG carriers, and annual production
at the liquefaction plant (N). λis measured in kilometres per hour and k is measured in
cubic meters of natural gas. The following equation is derived to find the number of carri-
ers required and the capital cost of the LNG carriers (s). Here 266,000 cubic meter carriers
will be used irrespective of the size of the field, because the aim of this paper is to analyse
long-distance and large-scale transport.
S¼ð$29 107ÞN
365
ðd
24k2Þþ2K
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
2000 2001 2002 2003 2004 2005 2006 2007
USD per Short Ton
Figure 5. Nickel prices.
Source of data: [35].
Natural gas and CO
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According to the US Energy Information Administration [30], ‘the costs of building regasi-
fication or receiving terminals show wide variation and are very site-specific’. Therefore, it
is also difficult to estimate the cost of a general LNG re-gasification terminal. The most
expensive components are the storage tanks, which may account for one-third to one-half
of the total construction costs, and the marine facilities [30].
The capital cost of a re-gasification terminal (R) is highly site-specific, but a rough
estimate might be $1 billion for every 10 million tpy of LNG (L), or $100 million per
million tpy LNG:
R¼ð$1 108ÞL
A US Energy Information Administration report from 2003 estimated that a new
re-gasification terminal in the United States, with capacity between 3.8 and 7.7 million
tpy, would cost $200 to $300 million. That estimate is probably too low today, because of
the escalation of costs for materials and wages that started in 2004 and has not been
reversed [36]. Furthermore, two LNG regasification terminals, the Gulf terminal in the
United States and the Gate terminal in the Netherlands, which will both be operating from
2011, have announced their estimated total project costs to be $1.1 billion [38,39]. The
Gulf terminal has a capacity of 5 million tpy; the Gate terminal has a capacity of 8.8
million tpy (12bcmpa), but this can be expanded to 16 bcmpa [31,39]. Jung et al. [14] use
$500 million as an estimate for the cost of a 6-million-tpy re-gasification terminal.
LNG OPEX
Annual operating costs for the facilities needed to transport natural gas as LNG include
maintenance costs, port charges, capital charges, taxes, fuel and boil-off. Boil-off is the
small amount of LNG that evaporates from the storage tank during transport [40]. Fuel
costs include liquefaction of the natural gas, fuel for the LNG carriers and re-gasification
of the LNG [14,35][35] [14]. Operating costs are first divided into different shares of the
construction costs, mainly covering operational and maintenance costs. Thereafter the
amount of the natural gas used as fuel deserves discussion (see below).
Annual operating costs for the transport of natural gas as LNG may be estimated as
follows:
Operating costs as a share of capital costs ( ,ν,σ) are 3.5% for the LNG liquefaction plant
(P), 3.6% for the LNG carriers (S) and 2.5% for the LNG re-gasification terminal (R) [14].
The variable share used as fuel (ω) depends on several parameters. These include the
share of natural gas used in the liquefaction process (Θ), the share of natural gas used in
the re-gasification process (Ω), boil-off per day (ξ) and shipping fuel per day (u).
x¼HþXþð1ð1nÞd
24kÞþð1ð1uÞd
24k2Þ
The liquefaction process whereby the natural gas is cooled down to 161°C consumes a
considerable share of the natural gas. Re-gasification and shipping consume a portion of
the gas as fuel. The quantity of natural gas used for cooling, heating, boil-off and LNG
carrier fuel depends on the design, efficiency and the size of the liquefaction plant, the
LNG carrier and the re-gasification terminal [41].
416 M. Ulvestad and I. Overland
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According to the engineer Kandiyoti [42], a total of up to 20% of the natural gas is used
in the process of liquefaction, shipping and re-gasification. This was supported by ship-
owner Trygve Seglem in 2007, who stated that 20–25% of the natural gas is needed for
the entire LNG transport chain [43]. Nevertheless, others have claimed that less natural
gas fuel is necessary for LNG transport. An anonymised source in an international oil
company [44] informed us by email that only 5–6% is needed specifically for the liquefac-
tion process, 1–2% for transport by LNG carriers and 1% for re-gasification. According to
a report from 2004 by the Norwegian Directorate for Watercourses and Energy [45],
between 5 and 15% of the natural gas is used in the liquefaction process [46].
A share of only 5–6% for the liquefaction process, however, seems too low compared
with figures given in the majority of the published sources available. Furthermore, the
figure of 1–2% natural gas usage for shipping must refer to shorter distances only, where
the return journey is not accounted for. Jung et al. [14] cite the following figures: 9% for
liquefaction, 2.5% for re-gasification and 0.17% per day to boil-off. LNG carriers may also
use some of the natural gas as fuel. These figures fit well with those indicated by Kandiy-
oti, who claims that the liquefaction process takes up to 9–10% of the natural gas, and that
up to 6% is needed for a 20-day voyage. This seems to include both boil-off and fuel, but
not fuel for the return voyage. This means that a little less than 0.14% per day is fuel only
(not including boil-off). The re-gasification process claims 2–3% of the natural gas [47].
These shares may vary due to differences in design, efficiency and technology, among
other factors. The natural gas that boils off during shipping may be used as fuel –or other
fuels, such as bunker fuel or diesel, may be used instead [47]. This will probably reduce
the share of the natural gas needed for the LNG chain. We assume that the boil-off is lost,
and that the fuel for the LNG carriers is natural gas taken from the cargo.
Comparison of LNG and pipeline CAPEX
We will first discuss the break-even point between the two transport options by examining
only the capital costs. The ‘break-even point’refers to the position when the cost of con-
structing the pipeline infrastructure is equal to the cost of constructing the LNG chain
needed to transport the natural gas. As mentioned, the literature assumes a break-even
point somewhere between 3000 and 5000 km. Because the cost of pipeline construction
starts from a low level and rises relatively steeply with distance (whereas LNG has a high
threshold, but thereafter increases less), LNG construction costs will be lower after the
break-even point has been reached. The costs of pipeline constructions will be lower for
distances shorter than the break-even point.
Not only the distance, but also the quantity of natural gas transported affects the costs
and the break-even point. According to our calculations, the economies of scale are more
pronounced for pipelines than for LNG. Even though there are significant cost reductions
for adding trains to an already-planned LNG greenfield plant, the cost reductions are
higher for increasing the diameter of a pipeline (not yet constructed) to expand the capac-
ity. Not only the pipeline diameter, but also the power of the compressor stations must be
increased in order to expand the capacity of a pipeline [48]. That point is not accounted
for in this analysis because we have used a fixed capacity per compressor station (110
MW). In any case, this seems to be a relatively high figure, as a 110 MW compressor sta-
tion every 200 km will probably be able to pump relatively large amounts of natural gas
through the pipeline. In addition, the LNG chain might gain something from economies of
Natural gas and CO
2
price variation 417
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scale, because it is cheaper to increase the size of an existing plant than to build a
greenfield plant. It is also cheaper to use a large LNG carrier than several carriers with
smaller capacities. But, the transport of natural gas is not associated with economies of
scale to the same degree as is pipeline transport.
The break-even point for an annual transport of 30 bcm is about 5100 km, assuming a
pipeline diameter of 1420 mm (56 inches). If, however, if the amount of natural gas is 20
bcmpa, and the pipeline has a diameter of 1220 mm (48 inches), the break-even point is
around 3750 km. For 10 bcmpa, with a pipeline diameter of 1020 mm (40 inches), it is
around 2200 km.
Comparison of LNG and pipeline OPEX
We have used the actual market price for natural gas sold by Russia to Germany in 2010
to price the natural gas throughout this comparison, $296 per 1000 cubic meter [49].
Even though construction costs might be lower for LNG when considering long dis-
tances or relatively small volumes of natural gas, this does not necessarily mean that LNG
will be the cheapest transport option. The large amounts of natural gas needed during the
LNG chain usually make annual operating costs higher for LNG than for pipelines.
The break-even point for constructing the transport facilities needed to transport 20
bcmpa is around 3750 km. Pipeline construction costs will be the lowest for shorter dis-
tances, whereas LNG construction costs will be lower for longer distances. But, if we
include the operating costs and assume that the project will run for 20 years, the distance
break-even point for 20 bcmpa will increase to around 4550 km; for 30 bcmpa it will
increase from 5100 km to 5900 km when operating costs are included. The break-even
point for 10 bcmpa will be 2800 km, increased from 2200 km.
Operating costs will not always be higher for LNG than for pipeline transport. Our esti-
mates show that for transporting 30 bcmpa over distances greater than 6550 km, annual
operating costs for pipelines exceed those for LNG. One reason is that pipeline construc-
tion costs are higher, and we have developed operational and maintenance costs as a share
of construction costs. Furthermore, for long distances the share of natural gas used as fuel
for the compressor stations will approach the share of fuel used in the LNG chain. For
particularly long distances, the fuel share will be higher for pipelines than for LNG
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
5 1015202530
Unit cost,
Bn per bcmpa
Volume, bcmpa
Cost per unit construction -
pipeline
Cost per unit construction -
LNG
Figure 6. Capital cost per unit for 4000 km.
418 M. Ulvestad and I. Overland
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transport. If the natural gas is transported more than 9100 km, pipeline transport will
demand a greater share of the natural gas than LNG transport, regardless of transport vol-
ume. Nevertheless, LNG transport is more exposed to changes in the natural gas price than
pipeline transport for reasonably long distances. This is shown in Figure 9, which is based
on a distance of 4550 km from the field to the market, a volume of 20 bcmpa and a pro-
ject life of 20 years. The costs of European Union Allowances (EUAs) are also included
here.
CO
2
emissions
Because of the relatively large amount of fuel required by the LNG process compared to
pipelines, LNG causes greater CO
2
emissions than pipeline transport. CO
2
emission
allowances will therefore be used in order to estimate the extra costs associated with the
environmental damage brought on by LNG.
0
5
10
15
20
25
30
35
40
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
Bn
Distance, km
Construction costs -
pipeline
Construction costs -
LNG
Figure 7. Break-even point for 20 bcmpa.
0
10
20
30
40
50
60
70
80
1000
2000
3000
4000
5000
6000
7000
Bn
Distance, km
Total costs - pipeline
Total costs - LNG
Figure 8. Break-even point for 20 bcmpa.
Natural gas and CO
2
price variation 419
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The extra operating costs can be calculated as follows:
Ep¼
36N1ð1ð1lÞd
nÞ

106A
EL¼
36NHþXþð1ð1nÞd
24kÞþð1ð1uÞd
24k2Þ

106A
CO
2
emissions (ɛ) from natural gas are around 53.06 kg CO
2
per million Btu [50]. The
price per ton CO
2
of emissions (A) is currently $29.84 when buying from the European
Union emission trading scheme, the European Union Allowance (EUA) [51]. As shown in
Figure 10, LNG transport is more exposed to changes in the price of CO
2
emission allow-
ances than pipeline transport. Figure 10 is based on a distance of 4550 km from field to
market, a volume of 20 bcmpa and a project life of 20 years.
The model
Combining all the equations results in a model that may help to answer the question about
the relative cost-efficiency of pipelines and LNG. Let fbe equal to total pipeline costs and
let g equal total LNG costs, measured in dollars. (A full list of variables and parameters is
provided at the end of the article.)
0
20
40
60
80
100
120
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3
Bn
Price of natural gas ( per m3)
Total pipeline costs (+EUA)
Total LNG costs (+EUA)
Figure 9. Total transport costs and gas price.
420 M. Ulvestad and I. Overland
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If the equation yields a figure higher than 1 for a given set of parameters, then LNG trans-
port has the lowest costs. If the equation gives a figure smaller than 1, pipeline transport is
economically preferable.
Such a large and complicated equation is not particularly elegant, and one may question
whether it is necessary. But, according to our analysis, this equation captures the main
factors that must be taken into account in choosing which type of infrastructure to build.
Thus it mirrors the calculations that anyone choosing between LNG and pipelines must
make, and the complexity of these decisions about crucial infrastructure. It is also possible
to calculate the partial derivatives of f(total pipeline cost) and (g) (total LNG cost) with
respect to the natural gas price (p) or with respect to the price of CO
2
emission allowances
(A), where all other variables are held constant, in order to calculate how a one unit price
increase affects total pipeline and LNG costs.
@f
@p¼N1ð1‘Þd
g

c
@g
@p¼NHþXþð1ð1nÞd
24kþð1ð1uÞd
24k2Þ

c

@f
@A¼N1ð1‘Þd
g

36e
106c
@g
@A¼NHþXþð1ð1nÞd
24kÞþð1ð1uÞd
24k2Þ

36e
106c
For example, the transport of 10 bcmpa over a distance of 3000 km during 20 years,
and with the values of the other parameters as discussed above, gives:
48
50
52
54
56
58
60
10 20 30 40 50 60 70 80 90 100
Total pipeline costs
Total LNG costs
Figure 10. Transport costs and EUA prices.
Natural gas and CO
2
price variation 421
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@f
@p¼11;669;754;730 @g
@p¼27;114;448;860
This demonstrates how the costs of LNG transport (g) are more sensitive to changes in
the price of natural gas than pipeline costs (f).
Similarly, the parameters give the following expressions for the partial derivatives with
respect to A:
@f
@A¼22;291;099 @f
@A¼51;792;936
Again, LNG transport appears more exposed to price variations than transport by pipe-
line. A one unit increase in the price of greenhouse gas emission allowances results in a
considerably larger cost increase for LNG than for pipelines, as shown below:
C= ($52,675 × 56 inches × 1615km) + ($3 ×10
7
)11 + ($3091 × 1,327,612 hp)=
$9,189,537,160
C¼$9;189;537;160 þ$10;750;000;000 þ$2;000;000;000
2¼$15;564;537;160
C= ($52,675 × 56 inches × 1365 km) + ($3 × 10
7
)10 + ($3091 ×1,206,920 hp)=
$8,050,272,517
PþSþR¼ð$5:5109Þþð$1 109Þð20:34Þþ ð$29107Þð28109Þ
365
ð3520
2436 2Þþ2152;950;000
þð$1 108Þ20:3$25;280;000;000
Op¼ð$21;939;537;160 3:5%Þþð28;000;000;000 ð28;000;000;000
ð10:4%Þ2839
200 Þ$0:296Þ¼$1;226;257;190
OL¼ðð$5:5bnþð$1:0bn ð20:34ÞÞÞ  3:5%Þþðð$ 290 MM 5Þ3:6%Þ
þðð$100MM 20:3Þ2:5%Þþð28;000;000;000 13:8% 0:296ÞÞ
Conclusions
Many variables affect the cost of pipeline and LNG transport of natural gas. In this article
we have developed a generic model for the comparison of pipelines and LNG that can be
adapted to different projects by revising the prices for the various factors included in the
model.
The exact break-even point between LNG and pipelines will depend on the volume of
natural gas and the distance that it is transported. Pipeline transport is a better option for
larger volumes and shorter distances. LNG transport has the lowest costs for smaller vol-
umes (up to 15 bcmpa) and for longer distances.
422 M. Ulvestad and I. Overland
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A substantial amount of natural gas is required as fuel for internal use in the liquefac-
tion process, and for compressor stations in the case of pipelines. This causes the costs of
both transport options to vary with the price of natural gas and greenhouse gas emissions.
For distances up to 9100 km, LNG transport is more exposed to fluctuations in the prices
of natural gas and greenhouse gas emissions than pipeline transport. This is because the
LNG process –liquefaction, shipping and re-gasification –requires a larger share of the
natural gas than do pipeline compressor stations over such distances. At greater distances,
pipelines will expend more gas than will LNG, making pipelines more sensitive to changes
in the price of natural gas and greenhouse gas emissions. We have thus identified 9100 km
as an important threshold for the comparison of LNG and pipelines. In addition to this
threshold, the amount of gas transported also impacts significantly on the comparison. In
general, an increase in the price of natural gas and/or greenhouse gas emissions will favour
the choice of pipeline transport.
If the aim is to replace coal and oil with natural gas in order to reduce greenhouse gas
emissions, account should also be taken of the emissions associated with the different
transport options for natural gas. On the other hand, more effective technologies developed
in the future may reduce the burning of natural gas in connection with its transport. This
is particularly true in the case of LNG, where the technology is newer and far more
complex than the technology involved in pipelines. Future innovations within LNG may
improve the viability of LNG relative to pipeline transport, as well as relative to coal and
oil.
Additional conditions must also be taken into account when considering the transport of
natural gas. LNG transport avoids transit countries and the associated, possible legal and
political risks, and provides flexibility to sell on the market where the price is highest.
Price differences for natural gas on different regional markets can be so great as to cancel
out the impact of the higher fuel consumption and greenhouse gas emissions involved in
LNG.
This article has not taken into account greenhouse gas emissions from the production of
steel for pipelines, or the materials for LNG facilities and tankers. We have shown the
effect of variations in the prices of natural gas and greenhouse gas emissions on the
relative cost-efficiency of LNG and pipelines, but with only a partial analysis of the full
climate impacts. Full assessment of the full carbon footprint of these two transport options
for natural gas would require expanding the model to cover also the production of steel
for pipes. That would be a logical next step for further research.
List of variables
N = natural gas (cubic meter per year)
L = LNG (million tonnes per year)
p = price of natural gas (US$ per cubic meter)
δ= distance (in km)
γ= number of operating years
C = pipeline capital costs (US$)
μ= pipeline diameter (inches)
α= number of compressor stations
c = total capacity of compressor stations (horsepower)
O
P
= pipeline operating costs per year (US$)
Natural gas and CO
2
price variation 423
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τ= OPEX as a share of CAPEX –pipelines (%)
ℓ= loss per compressor station (%)
η= distance between compressor stations (in km)
P = capital cost of liquefaction plant
S = capital cost of LNG carriers
λ= speed of LNG carrier (km/h)
k = capacity per LNG carrier (cubic meter natural gas)
R = capital cost of re-gasification terminal
O
L
= LNG operating costs per year (US$)
= OPEX as a share of CAPEX –liquefaction plant (%)
ν= OPEX as a share of CAPEX –LNG carriers (%)
σ= OPEX as a share of CAPEX –re-gasification terminal (%)
ω= share of natural gas used as fuel for the LNG chain (%)
Θ= liquefaction –share of natural gas used in the liquefaction process (%)
ξ= boil-off per day (% of natural gas)
/= shipping fuel per day (% of natural gas)
Ω= re-gasification –share of natural gas used in the re-gasification process (%)
E
P
= pipeline CO
2
emission costs
E
L
= LNG CO
2
emission costs
A = price of CO
2
emission allowance (US$ per ton CO
2
)
=CO
2
emission (kg per million Btu of natural gas)
List of parameters
p = $0.296 per m
3
[49]
γ= 20 [45]
μ=40‘‘,48‘‘ ,56‘‘
c = 147,512 per compressor station
τ= 3.5% [14]ℓ= 0.4% [14] η= 200 km [24]
λ= 36.114 [33]
k = 152,950,000 [33]
= 3.5% [14]
ν= 3.6% [14]
σ= 2.5% [14]
Θ= 9.5% [14,47]
ξ= 0.17% per day [14]
/= 0.1389% per day [47]
Ω= 2.5% [14,47]
A = $29.84 per ton CO
2
[51]
= 53.06 kg per MMBtu [50]
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