MM4MPR - Dissertation9

1 Copyright © 2013 University of Nottingham
M.Eng. Mechanical Engineering
MM4MPR Individual Research Paper 2012/13
Electricity Generation and the Environment in the UK – Should the Dash for Gas Continue?
A Life Cycle and Economical Analysis
João Vasques, Jon Mckechnie
Faculty of Engineering,
University of Nottingham, UK
ABSTRACT
A major problem to be faced in today’s
World is a clean and secure source of energy
supply. The aim of this project is to study what
actions will the UK government need to take in
order to meet the growing demand of electricity,
while attempting to meet the targets that itself has
committed upon reducing the levels of Green
House Gases emissions. This was done by
evaluating the life cycle emissions of the actual and
future sources of natural gas to the UK, together
with a comparison with the coal industry
emissions. Furthermore, an economic analysis was
performed in order to assess the costs associated
with the adoption of various future scenarios. It
was acknowledged that technologies such as
Carbon Capture and Sequestration will be required,
given the aggressive long term emissions reduction
targets. Finally, despite the fact that the economical
advantage of operating a gas power plant instead of
a coal plant is lost beyond 2030, it was
demonstrated that the Dash for Gas must be
pursuit, if the emissions targets are to be met.
1. INTRODUCTION
The uncertainties regarding the future of
fuel prices together with the lack of secure sources
of energy supply are factors that make predictions
on the way electricity is going to be generated a
very complex topic.
This is coupled with the fact that governments have
become more concerned with the implications that
Human actions have on the environment. As a
result, the UK has committed to the Kyoto
Protocol, which called for a reduction in the
emissions by 12.5% by 2012. Furthermore the UK
agreed to meet the European targets to decarbonise
the UK economy. The Climate Change Act 2008
calls for an 80% reduction in green house gases
(GHG) emissions by 2050. This includes an interim
target of 34% reduction in emissions by 2020 and
50% reduction in emissions by the 2023-2027
budget. These reductions take the amount of GHG
emitted in the year of 1990 as a baseline [1].
Since the power generation sector is by a large
margin the biggest emitter of CO2 (i.e.28% in
2008) [2], this was the main sector where
improvements had to be made in terms of reducing
the emissions.
This gave motivation for the “Dash for
Gas” to occur, where coal power plants have been
decommissioned over the years and replaced by
natural gas power plants (around 9.5 GW of new
gas-fired capacity invested since 1990) [2].
This is due to the fact that generation of electricity
in Natural Gas Combined Cycle Plants (NGCC) is
estimated to produce about half of the emissions
than using coal [3].
Consequently, the emissions from the power
generation sector have reduced, and its effect can
be seen in the overall emissions, which are lower
than the 1990 levels.
The shift done so far towards gas was
enough for the present emissions targets to be met.
However, more detail is required for a better
understanding of how this movement is
contributing to the emissions targets in terms of
emissions and life cycle costs, and that is the aim of
this study.
Furthermore, the European Union has
launched a Large Combustion Plant Directive
(LCPD), which covers the emissions of SO2, NOX
and particulate matter from all power plants over
50 MW. This requires for power stations that do not
meet the specifications to add the necessary air
quality equipment (opt-in) or close down (opt-out).
Facilities that opt out the standards can operate for
a maximum of 20,000 hours after January 2008 and
must shut down by 2015 [4]. Therefore, 11 GW of
electricity from coal and oil fired stations are going
to be decomissioned (opt-out) by 2015 and about
20 GW of coal fired stations will have restricted
operation after 2016 (opt-in). In addition, around 7
GW of nuclear power generation is scheduled to
close by 2020 [5].
These decomissioned capacities have been replaced
over the last five years by new NGCC plants and
more are planned to be built in an attempt to fully

2
fill the energy gap created. By taking this approach,
and by aiming to meet their target in terms of
renewable generation of 15%, the UK government
estimates that the interim target set for 2020 is
going to be met [2].
Moreover, a study made by the Comittee
on Climate Change established 100gCO2e/kWhe as
a suitable target for the electricity sector to meet in
2030, if the 80% reduction in overall emissions is
to be done by 2050 [2]. This mid-target was
accepted by the a wide range of institutions, which
include: the Energy and Climate Change Select
Committee, the Confederation of British Industry,
the Institution of Mechanical Engineers, the
Scottish Government and others.
However, it is still uncertain of what
actions are required to be taken in terms meeting
the emissions targets beyond 2020, where currently
there are other technologies such as Renewables
and Nuclear, which are seen as low carbon
competitors to the Dash for Gas movement.
However, offshore wind, where most of the hopes
are being put on, requires an extremely high capital
investment and suffers from intermittency issues,
since it only has a capacity factor of 30%.
Additionaly, there is still a lot of public scrutiny
regarding nuclear, especially after the recent
catastrophic events of Fukushima in 2011.
Furthermore, current nuclear projects being
undertaken in Europe, such as in Finland are highly
overbudget and late [6], not to mention the
decomission issues that the UK currently faces,
where a budget of £67.5 bn has been established
[7]. As a result, this study does not view nuclear
and renewable generation as the main electricity
generation sources in the foreseeable future.
Nevertheless, despite the environmental
advantages that natural gas represents in
comparison to coal, obtaining a secure source of
supply is a problem that the UK currently faces [8].
This is due to the fact that the UK is no longer self-
sufficient when it comes to gas supply, as the UK
Continental Shelf (UKCS - North Sea) reserves
started to deplete at a faster rate than expected [2].
Since 2004, the UK started being a net importer of
gas, ‘with imports in 2010 accounting for just
under a half of the UK’s gross gas demand’ [9].
Therefore, the UK is nowadays higly dependent on
the piped gas from Norway and the importing of
Liquefied Natural Gas (LNG) from the Middle East
(mainly Qatar) [9]. To suffice the dependence of
the UK towards their current exporting countries, it
is being considered to start importing gas from
North America, as large amounts of shale gas have
been discovered and are currently being extracted
[10]. In political terms, importing gas from North
America will probably be advantageous for the UK
due to their close relationship, thus presenting a
more secure source of supply than the Middle East
or even Russia. Moreover, a lot of research is being
conducted to estimate what the UK shale gas
reserves are, in a clear attempt to follow America’s
footsteps regarding this resource [11].
Another problem associated with the
“Dash for Gas” is its inability to meet the long
terms emissions targets without additional
measures, such as Carbon Capture and
Sequestration (CCS) [2] [8].
As a result, this study aims to provide a
greater insight on the Dash for Gas movement, by
taking into consideration the limitations numerated
above, the growing demand of electricity and
emissions targets that need to be met.
This will be done by first evaluating the
life cycle emissions of the actual and future sources
of natural gas to the UK. By having accurate data
regarding the complex industry of gas, it will be
possible to fully demonstrate what the actual
advantages of using natural gas to displace existing
coal power plants are. This will be done in
conjunction with an analysis of the costs associated
with this approach.
Finally, with the data obtained from the
LCA and the economical analysis, a deeper
evaluation is going to be performed in order to
evaluate future scenarios given the aggressive long
term emissions reduction targets.
2. METHODOLOGY
This study will initially investigate the
factors associated with generating electricity with
both natural gas and coal. This will be done by
investigating the actual emissions produced by both
industries, where more detail will be given to the
natural gas industry due to its high complexity, as it
comprises numerous activities. Furthermore, an
economic analysis will be done to first investigate
the costs associated with building new gas and coal
plants to start operating in 2013. The year of 2030
is seen as crucial by this study, due to the degree of
emissions reductions required for the targets to be
met [2]. As a result, different operating timeframes
for the new power plants will be investigated. It
will include: operation of plants until 2030 (17
years operation) and early shutdown; operation of
plants in unabated regime throughout its entire
lifetime until 2048 (35 years in operation), which
will come at a cost as the emissions targets will not
be met; and operation of power plants in unabated
regime until 2030 with the retrofit of CCS post
combustion technology until 2048. Finally, an
additional scenario will be performed in order to
access which technology will be more
economically beneficial if new plants are to be
built in 2030 with CCS already included, where
they will operate throughout their entire lifetime
until 2065.
This will be done by dividing the study into two
different sections: Life Cycle Analysis of emissions
from the gas industry and an Economical Analysis.
A summary of the data collected to perform the
analyses is shown in Table 1. The next sections
describe the methods and assumptions used to
process this data, together with a description of the
sources where the information was obtained.

3
Table 1: Summary of data used on the LCA and Economical analyses
a
Fugitive emissions and fuel inputs. More details on Section 2.1.1
b
Includes activities from the country of origin in addition to the distribution emissions within the UK. More detail on Section 2.1.3
c
Due to difficulty of distinguishing which emissions occur during Transmission and Distribution, they are reported under one category
d
Shale gas requires LNG activities in order to bring it to the UK
2.1 LCA
As stated above, the gas industry is very
complex since it comprises numerous activities.
They can be seen in the following diagram:
Figure 1: Different natural gas pathways
From Figure 1 it can be seen that an analysis of the
cradle to grave activities of natural gas is being
conducted, where all the data used refers to the
year of 2010. Furthermore, only the emissions of
the three most common GHGs released are under
consideration (CO2, CH4, and N2O).
Ultimately, the main focus of the gas used
within this report is the generation of electricity. As
a result, the emissions of this Life Cycle Analysis
will be reported in terms of grams of CO2
equivalents per kilowatt hour of electricity
generated.
To give equivalency of methane (CH4) and
Nitrogen Oxygen (N2O) into carbon dioxide, a
global warming potential (GWP) was used. The
values used were the ones suggested by Kyoto
Protocol, where GWP values were calculated for
the Intergovernmental Panel for Climate Change
(IPCC) Second Assessment Report [19]. A time
interval of 100 years (convention) was chosen for
this study.
The main steps undertaken to obtain the emissions
of the various activities on this analysis were:
1. Convert Gg or pounds into grams of GHG
2. Divide the values obtained in 1 by the
amount of gas produced to obtain
emissions in grams of GHG per MJ of gas
produced
3. Convert the values obtained in 2 into
grams of CO2e per MJ of gas produced by
multiplying them by the respective GWP
So far, by performing these steps, the emissions
would be reported in terms of grams of CO2 per MJ
of gas produced. The efficiency of the power plant
will dictate how much gas is required to produce a
Power Plant [reference]
Technical Data Units CCGT CCGT+CCS ASC ASC+CCS
Power Output [12] MW 830.000 830.000 1600.000 1600.000
Plant Efficiency [12] % 50.000 40.250 35.000 27.300
Load Factor [12] % 90.000 90.000 90.000 90.000
CO2 removal [12] % 0.000 90.000 0.000 90.000
Plant Emissions g CO2e/kWh 406.875 [13] 40.688 882.700 88.270
Capital Costs [12] £/MW 718.300 1372.000 1789.400 3072.500
Fixed Operating Costs [12] £/MW/yr 15000.000 32000.000 38000.000 77000.000
Variable Operating Costs [12] £/MWh 2.200 3.200 2.000 3.800
CO2 transport Operating
Costs [12]
£/MWh 0.000 3.800 0.000 7.800
Sources of Fuel
UKCS Norway LNG Shale Coal [14]
Activity Emissions in g CO2e/MJ [reference]
Exploration/Extraction with
Venting and Flaring
2.273
a
[15]
[16]
2.273
a
[15]
[16]
6.781
a b
[17] 4.863
a b
[17] 1.446
a
Production/Processing 0.092 [15] 0.092 [15] 0.833 [17] 0.833 [17] 0.000
Distribution
2.337
a c
[15]
[16]
2.337
a c
[15]
[16]
2.338
a b c
[15]
[17]
2.338
a b c
[15]
[17]
0.000
Liquefaction 0.000 0.000 9.046 [18] 9.046
d
[18] 0.000
Transportation 0.000 0.000 0.907 [18] 0.907
d
[18] 6.746
Regasification 0.000 0.000 0.989 [18] 0.989
d
[18] 0.000
Total 4.702 4.702 22.004 18.144 8.192

4
given amount of electricity. Therefore, this aspect
of the analysis can always be subject to some
sensitivity investigation, depending on the plant
efficiency used. That is why the data shown in
Table 1 is in terms of grams of CO2 per MJ of gas
produced and in Section 2.1.5 more detail will be
given on what further processing is required to
convert this data into the desirable functional unit
(grams of CO2 equivalents per kilowatt hour of
electricity generated).
Currently, the sources of natural gas to the UK
include:
 Conventional Natural Gas coming from
the UKCS (green pathway);
 Conventional Natural Gas coming from
Norway via pipelines (green pathway);
 LNG coming from various countries,
which include: Algeria, Norway, Egypt,
Nigeria, Qatar and Trinidad and Tobago
(green + orange pathway);
This study will evaluate all the emissions
associated with these sources and activities by
reviewing existing inventories or literature and
processing their figures using the steps stated
above. Moreover, since it is predicted that shale gas
will be part of the natural gas supply mix in the
next 5 years [10], its activity is also under the scope
of this study. With the knowledge of the US shale
gas emissions, it would be then possible to make
estimates of how the shale gas industry in the UK
will behave if satisfactory reserves are found in the
future.
2.1.1 Conventional Natural Gas from
the UKCS
To find data for these emissions, UK emissions
inventories were used, which are available in a
variety of sources [20]- [15]. However, they only
present the fugitive emissions associated with this
industry, since this is the only disclosure
requirement, and they are sometimes combined
under one category. The latter [15] was used in this
study, as it provides a breakdown of the fugitive
emissions for all the activities displayed in Figure1.
The natural gas from the UKCS comes from the
exploration of gas itself, where it is commonly
called dry gas, but also from the oil activities,
where it is referred as associated gas. That is why
the venting and flaring emissions of the oil industry
are also considered in this report, as a breakdown
of which percentage of these emissions are related
to oil industry and which is related to the associated
gas will be done.
Furthermore, in order for the step 2 of
process to obtain the emissions in terms of grams
of GHG emissions per MJ of natural gas to be
made, the amount of natural gas (dry and
associated) and oil produced in 2010 are required
to be known: 5.971x1010
m3
and 4.272 x107
tonnes
respectively [9].
Assuming an energy density of 40.25 MJ/m3
and
39 MJ/kg for gas and oil respectively [21], the total
energy content of the gas and oil produced was
found: 2.567x1015
KJ and 1.666 x1012
KJ
respectively.
It can be observed that so far, only fugitive
emissions are being reported. However, there are
energy inputs required for the gas activities to be
performed, which themselves produce carbon
dioxide upon burning and therefore need to be
taken into consideration in this analysis.
This is a stage where more efforts need to
be put in the future, since the amount of available
information is very scarce, especially when
comparing with the wide range of literature
published about the natural gas emissions within
the US. A report published in 2011 by Marcogaz,
the Technical Association of the European Natural
Gas Industry [22], is the only recent literature
published regarding the life cycle analysis of the
natural gas industry in the UK. Furthermore, to
emphasize the lack of data available, when
regarding the fuel inputs, the report itself referred
to another study initiated in 1995, which was part
of the ExternE project, ordered by the European
Commission [16]. This date is included in Table 1.
2.1.2 Conventional Natural Gas from
the Norway
A great amount of the UK’s imports come
from Norway. Since Norway also obtains its natural
gas from the North Sea, it is assumed that its
emissions are the same as the ones obtained for the
UKCS. This approach is supported by the studies
from Marcogaz and ExternE.
2.1.3 LNG activities
About 35% of the imported natural gas
arrives in the form of Liquid Natural Gas (LNG),
since its sources are far away from the UK for the
transportation of gas through a pipeline. As a
result, the natural gas is liquified so that it becomes
more dense, thus occupying around 600 times less
volume than natural gas in gaseous state. This will
consequently ease the way it is transported.
It comprises three stages, as seen in Figure
1 (orange): Liquefaction, Transport by ship and
Regasification, each incuring in GHG emissions
that need to be adressed. Jaramilo et al [18] are a
very respectable group of researchers on the field
of Life Cycle Analysis of different fuels. Their
study on LNG is the one being used in the context
of obtaining data for the emissions associated with
this activity.
Additionally, it is important to point out
that for the natural gas to be exported by LNG, it
needed to be produced in the first place. Due to
lack of data regarding the emissions of the gas
industry of the exporting countrites, this study
follows Jaramillo’s et al guidance of assuming that
the emissions during the production, processing
and transmissions stages to be the same as in the
US. The data of emissions of the US gas industry

5
was obtained from the Greenhouse Gases,
Regulated Emissions, and Energy Use in
Transportation Model (GREET) [17]. The values
acquired are displayed in Table 1.
More detail will be now given on the LNG stages.
2.1.3.1 Liquefaction
The liquefaction stage involves the
removal of certain components, such as dust, acid
gases, helium, water and heavy hydrocarbons
which could difficult its storage. Furthermore, as
the name says, it is here where the liquid is
condensated by lowering the natural gas
temperature to negative values. This stage
obviously incurs in emissions which can be seen in
Table 1.
2.1.4.2 Transportation
The transportation of LNG is made by
using large ships with tanks in which the natural
gas is stored. The emissions associated with
maintaining the natural gas in liquid form are
negligible compared to the amount of carbon
dioxide emitted due to fuel burnt to power the
ships. As a result, they are not regarded. In order to
estimate the amount of CO2 released, the following
equation was used [18]:
Where:
D is the distance to be travelled by the tank (in
km);
is the velocity of the tanker ( 25.928 km/h);
FC is the fuel consumption of the tanker (1.708
tonnes of fuel burnt/hour);
EF is the emission factor (3,200,000 grams of CO2
burnt per ton of fuel burnt;
2 refers to the number of trips that the tanker needs
to do;
By knowing the distances between the
port of origin of the natural gas and Milford Haven,
where most of the regasification takes place in the
UK, the actual emissions are then found.
Furthermore, by knowing the amount of energy
that the tanker is able to store (3.147x109
MJ) it is
possible to calculate the emissions in terms of
grams of CO2/MJ of natural gas.
For easiness of analysis, the Transportation
emissions displayed in Table 1 are simply an
average of the values reported here.
2.4.3 Regasification
Regasification is characterized by the
actions taken in order to bring the liquid natural gas
to atmospheric conditions, where it is then
introduced into the distribution system of the
importing country. Jaramillo et al refer to two
studies (Tamura et al [23] and Ruether et al [24])
when attempting to derive the emissions associated
with this activity. Their figures are reported as
lower and upper bounds and therefore an average is
going to be used in Table 1.
2.1.4 Shale Gas from the US
Shale gas is natural gas trapped within
shale formations. Despite being extracted since the
last century in the US, its importance only boomed
in the last decade, going from 1% of the total
natural gas produced in the US up to 20% in 2010
and with predictions to supply nearly half of US
gas production by 2035 [25].
Due to its different characteristics, the
extraction method (known as hydraulic fraction) is
very different than the one used in the extraction of
conventional gas. In order to obtain shale gas,
hydraulic fraction is used, where a well is drilled
and tubing is put in place, so that water, sand and a
wide range of chemicals are pumped to the well in
order to fracture the shale rock and release the gas
contained in it and induce pressure so that it flows
to the surface [17]. During the well completions,
the fracturing fluids are expelled in a process called
flowback, where about half of the fluids used come
back and natural gas production initiates. It is
during this flowback period that a great amount of
emissions are assumed to occur, since large
amounts of methane are released. Furthermore,
once every 10-15 years workovers occur, where the
well needs to be cleaned and maintenance activities
occur, yielding additional emissions.
Since this source of gas has only matured
in the recent past, and due to its difference in the
extraction methods, there is not still a consensus on
the amount of emissions produced by this source,
with recent studies stating that its emissions are
either lower [17], the same [26] or even higher than
conventional gas sources within the US [27].
More specifically, a paper produced by
Howarth et al [27] received a lot of criticism as it
concluded that shale gas would be more polluting
than coal. This statement was based on the fact that
it was assumed that the fugitive methane emissions
during well completion in shale were all vented to
the atmosphere, and since methane is more harmful
than carbon dioxide, its effect on the environment
was extremely harmful. This is an inaccurate
assumption, since by regulation, at least 51% of all
unconventional completions are required to be
flared in the US. Additionally, in some states the
adoption of recovery technologies is compulsory
and extracting companies have willingly started to
recover this gas, as it has been demonstrated to be
economically viable. It can be concluded that
Howarth’s el al paper was highly biased, and this
can be demonstrated by the fact that the US
emissions in 2012 dropped to a 20 year low [28].
After considering all these aspects and the
multiple papers published regarding shale gas in
the US, this study will again use GREET’s [17]
paper as the guideline for estimating the shale gas
industry emissions, since it is the one that best
analyses all the factors regarding this activity,

6
together with provision of a balanced review of
other literature.
2.1.5 Power Plant
Presently, the most advanced NGCC
power plant in operation is the Irsching Power
Plant in Germany, with an efficiency of 60.4%
(LHV) [29]. This would be a good indicator of the
baseline efficiencies of the next plants to be build
in the UK. However, public reporting of power
plant emissions is scarce in Europe, and therefore
the Emissions and Generation Resource Integrated
Database (eGRID) from the US was used [30]. The
parameters used in the screening of an optimum
power plant were: lowest heat rate, capacity factor
above 50%, rated power above 200 MW and no
CHP involved.
As a result, the power plant found was the
Westbrook Energy Centre. It can be seen from
Table 1 that the plant efficiency is 50% (HHV
basis). This is going to be taken into account
throughout the entire analysis, given that if the
plant was 100% efficient, 3.6MJ of natural gas
would generate exactly 1kWh of electricity. Since
this is not the case (the efficiency is half), it means
that 7.2MJ of gas are required in order to generate
1kWh of electricity. This is the last step required to
convert the data obtained from the various
literature resources into grams of CO2 equivalents
per kilowatt hour of electricity generated. The
results of this LCA are displayed in Figure 2 of the
Results and Discussion Section.
2.1.6 Emissions from Coal Industry
in the UK
As said before, the coal industry in the UK
is far less complex than the gas industry and as a
result, a great variety of literature has been
published in regards to it Life Cycle Analysis. This
is due to the fact that fewer activities are required
to bring coal into the generation stage and since
coal is a solid fuel, the likelihood of fugitive
emissions to occur is far less than in the gas
industry. A study made by Odeh et al [14] is going
to be used as reference for the emissions of this
industry. This is due to the fact that its results are
validated by previous studies performed. A
breakdown of the emissions is given in Table 1.
2.2 ECONOMICAL ANALYSIS
Despite the fact that concern over the implication
of Human actions on the environment is in high
regard in terms of political agenda, the economics
behind adopting a given energetic policy must be
assessed. This will be done for all the scenarios
referred at the beginning of this chapter.
In order to perform this economic analysis, a
review on the recent literature regarding these
aspects was done. A report done by the consultancy
company Mott Macdonald upon request from the
DECC and published in 2010 is going to be used
[12]. It will serve as guideline and source of data
regarding the capital costs of different
technologies, together with future fuel prices and
carbon costs. The data acquired from this report
was also checked against a report published by the
Environmental Protecting Agency in the US [31] in
order to fully validate its accuracy.
In the end of this analysis, the levelised costs for
each scenario will be presented in terms of £/MWh
of electricity generated.
2.2.6 Technical data, Capital Costs
and Operating Costs
Predicting the current and future power generation
costs associated with large scale technologies is a
very challenging topic. This is especially so for less
proven technologies such as Carbon Capture and
Sequestration. The main challenge for this type of
technology is to understand the background behind
implementing a first of a kind (FOAK) premium, as
it has never been in operation at a large scale. In
regards to the gas and coal technologies, the data
used was in regards of Combined Cycle Power
Station and Advanced Supercritical Coal
respectively. These are the best available
technologies and considered to be nth
of a kind
(NOAK), as they have been widely used up to date.
The capital costs reported in Table 1 include the
following: pre-licensing costs, technical and design
costs; regulatory and licensing costs; engineering,
procurement and construction (EPC) costs; and
infrastructure costs.
Fixed operating and maintenance costs (FOM)
relate to the costs associated with staffing wages,
bonuses, plant related administrative expenses and
routine maintenance.
Variable operation and maintenance costs (VOM)
relate to the costs associated with waste disposal,
chemicals, catalysts and lubricants used; and
consumable materials and supplies.
CO2 costs refer to the costs associated with the
transportation of the captured CO2 at the power
station to a given storage site and the costs
associated with this storage. Consequently, these
costs are only present when CCS is being
considered.
To evaluate the cost of production of
electricity, the capitals costs for each technology
are converted to a net present value using the time
value of money. This was done by using a discount
factor of 10%/year throughout the entire lifetime of
a given technology, and hence the term levelised
cost. This enabled to convert the capital costs into
£/yr.
However, capital costs and the FOM are not
reported in terms of £/MWh.

7
In order to convert them, first it is required to know
the amount of electricity produced by a given
technology, which is dependent on its power rating
and load factor. Dividing this by the cost factor for
capital costs or the FOM, which should now be in £
depending on the lifetime, will convert them into
£/MWh. Note that the values obtained from Mott
McDonald refer to their medium cost scenario.
2.2.7 Fuel Costs
Similarly to the challenges in predicting future
power generation costs, it is very difficult to predict
future fuel prices. As a result, DECC has published
them in terms of Low, Medium and High Costs.
The Medium Costs are the ones used by Mott
McDonald and by this study:
 Natural Gas prices are assumed to steadily
increase from £0.58/therm in 2015 up to
£0.74/therm in 2030
 Coal prices are expected to decline from
$1.1/tonne in 2010 to $0.8/tonne in 2015
and remain constant at this level
These results were plotted on a graph and a
best fit line was set, thus allowing for a calculation
of the fuel prices at the beginning and the end of
each given scenario to be calculated.
Based on the efficiencies of each technology
and on the energy content of each fuel, it is
possible to calculate the amount of fuel required to
generate a certain amount of electricity over a year.
By multiplying the amount of fuel required by the
fuel costs factors calculated, by averaging them and
then dividing by the amount of electricity produced
by each technology, the fuel costs in £/MWh were
found.
2.2.8 Carbon Costs
The carbon prices used in this estimate are
based on the DECC’s central estimate case for the
future: carbon prices rise slowly from £14.10/ton
CO2 in 2010 into £16.3/ton CO2 in 2020, then
more rapidly to £70 /ton CO2 in 2030 and £135/ton
CO2 in 2040. In order to derive the amount of CO2
emitted by each technology, the following emission
factors were used: 491.481 g/kWh and 900 g/kWh
for gas and coal respectively. These are the values
obtained from the LCA more detail on them will be
given in the following Section.
Again, a best fit line was done on the
carbon costs in order to find the carbon costs at the
beginning and end of each scenario. By multiplying
the amount of CO2 emitted by the carbon factors
calculated, by averaging them and then dividing by
the amount of electricity produced by each
technology, the carbon costs in £/MWh were
found.
3. RESULTS AND DISCUSSION
The summary of the emissions for all the
sources of natural gas, with a breakdown of the
numerous activities associated with them is shown
on the Figure 2. The values for coal are not shown,
as they were obtained from another study’s analysis
(990 gCO2e/kWhe) and they would offset the
results shown in Figure 2.
Figure 2: LCA Results
It can be seen from Figure 2 that the
biggest descripancy in the Results occurs at
Extraction stage, where emissions in the UKCS are
much lower than conventional gas from the US,
which was assumed to be the same as the emissions
of the current LNG exporting countries to the UK.
This could be due to the fact that despite that both
sources are referred as conventional, their
extraction method is slighty different, since one is
performed Offshore (UKCS) while the other is
performed Onshore (US). As predicted by the
GREET model, the difference in the extraction
method of shale gas (unconventional) makes the
emissions of this industry slighty lower than the
conventinal gas from the US but still higher than
the UKCS. As a result, obtaining natural from the
UKCS or Norway incurs in the lowest GHGs
emissions. On the other hand, importing shale gas
from the US is much less beneficial not only
because of the descripncies at the Extraction Stage
but also due to the LNG stages required to be
performed in order to bring it to the UK.
Unfortunately, due to the depletion of the UKCS
resources and due to the recent contracts made
between Centrica and an US gas company, it is
very likely that the shale gas from the US will play
a key role in the future imported gas mix. This
conclusion is based on the assumption that the
LNG imports being currently made are not the
most desirable scenario that the UK would like to
face, since many of the countries where the gas
comes from are politically unstable.
Despite this, this analysis shows that even
with shale gas imports, the emissions are still far
inferior than the ones of generating electricity from
coal (485.478 against 990 gCO2e/kWhe).
However, the data collected so far is not enough to
predict how the target of 100 gCO2e/kWhe will be
met. For this to be done, the results from the

8
economic analysis need to be known, which are
shown in Figure 3.
It can be seen that in regards to CCGT, the
fuel costs are more dominant than the capital costs,
whereas in ASC the opposite occurs. An interesting
conclusion that can be taken from Figure 3 is that
for CCGT, if there was no penalty for not meeting
the emissions targets, it would be economically
more viable to keep a power plant which has
started operation in 2013 in the unabated regime
beyond 2030, rather than retrofit CCS equipment to
be used for only 18 years.
Furthermore, Figure 3 also shows that for
all the scenarios where the power plants start
operation in 2013, it is economically more viable to
use CCGT. This is not only due to the higher
capital costs of ASC, but more importantly, due to
the impact that carbon costs will have in the future.
This strengthens the argument made in regards of
keeping the “Dash for Gas” as the best option in
the foreseeable future.
However, due to future fuel costs of
natural gas, in the medium regime, the economic
advantage of CCGT with CCS disappears if new
plants are to be considered to be built in 2030 to
operate until 2065.
In terms of the emissions targets for 2030, only
generating electricity using natural gas in
conjunction with CCS will enable for the targets to
be met. This is demonstrated by the following
calculations and assumptions:
 Assuming most of the generation of
electricity comes from either NGCC or
ASC
 Remaining comes from Renewables, with
a percentage of the electricity mix of at
least 20%
 Natural gas mix in the UK in 2030 will be
50% from UKCS and 50% from shale gas
from the US
It is reasonable to predict that the Renewables
percentage in 2030 will be 20%, since it is
expected for it to be 15% of the electricity mix by
2020. By knowing that CCS incurs in a 90%
capture of the power plants emissions, their
correspondent emissions will be 40.688 and 88.270
gCO2e/kWhe. By having a mix of gas coming from
the UKCS (33.228 gCO2e/kWhe) and shale
(134.974 gCO2e/kWhe), the overall emissions of
generating electricity using a mix of natural gas
and Renewables will be 99.831 gCO2e/kWhe. In
terms of the upstream and downstream activities of
coal, they induce emissions in the order of 106.9
gCO2e/kWhe, which will represent overall
emissions of 156.136gCO2e/kWhe for electricity
generation using a mix of coal and Renewables.
As a result, it can be seen that despite the fact
that beyond 2030, operating a coal plant is slightly
cheaper than a natural gas plant, this comes at the
cost of not meeting the established emission
targets. Additionally, since the emissions from the
natural gas industry are so close to the limit
(99.831 against 100gCO2e/kWhe), attempting to
have a mix of electricity generation from Natural
Gas, Renewables and Coal will not be possible.
Consequently, the Dash for Gas movement
with the addition of CCS techonoly in the future
must be pursuited.
4. CONCLUSION
This study provides a great insight of what
energetic challenges the UK faces in the future.
The emissions of the activities associated with the
natural gas industry in the UK were analysed and
demonstrated to be lower than the ones from the
coal industry, with emissions ranging from
440.103-569.644 for gas against 990gCO2e/kWhe
for coal. It was also demonstrated that up to 2030,
which is seen as a crucial year in this analysis,
NGCC plants have an economical advantage over
ASC. Beyond 2030, where strict emissions targets
have been set (100gCO2e/kWhe), CCS needs to be
included if the targets are to be met. However, only
generation of electricity from gas with CCS is able
for the targets to be met (99.831 against
156.136gCO2e/kWhe for coal). This demonstrates
that the Dash for Gas should be pursuit if the UK is
committed upon meeting its environmental targets.
Figure 3: Economical Analysis Results

9
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