1. business and industrial
2. energy
3. natural gas

EUROPEAN GAS DEMAND PROSPECTS: HOW TO MEET LONG TERM NEEDS?
Armelle Lecarpentier
CEDIGAZ
Keywords: 1. Security of Supply; 2. Markets.
1
Introduction
The High Growth Scenario of CEDIGAZ forecasts that European gas demand (OECD Europe and Central
Europe) will grow from 568 billion cubic meters (bcm) in 2008 to 692 bcm by 2020, at a pace of 1.7%/year
(1.5%/year for EU-27). This growth will be the most rapid over the 2010-2015 period.
The fast-growing gap developing between supply and demand is raising real challenges ahead. Which
sources will be required to ensure supply security from now to 2020? What will be their respective role?
Which share is LNG likely to grab in total gas supplies? How will pipeline supplies from Russia, Norway and
Africa position on the European supply scene?
2
Objectives of the paper
After a presentation of European markets' characteristics and recent developments (consuming outlets, coal
and gas competition, supply patterns), this paper will describe CEDIGAZ medium and long-term prospects
for European gas consumption, based on different assumptions on prices. It will in particular focus on the
growing role of the power generation sector in natural gas demand, standing as the main driver of gas
expansion. Attention will be drawn on countries likely to register the strongest demand growth.
CEDIGAZ will also present the current structure of the European supply portfolio and the activities of the
main producers of exporting countries. The analysis of future gas supply requirements to meet demand
growth gives an assessment of the respective role of the key different supply sources needed to ensure the
security of European gas supply in the long term.
Besides the growing importance of the three largest traditional suppliers, Gazprom, Sonatrach and
StatoilHydro, emphasis will be made on the structural shift of European supply pattern toward a growing
reliance on Liquefied Natural Gas (LNG). This means of transportation appears as a crucial option to
complement piped gas, to meet variations and peaks in European demand, and gain access to new distant
supply sources (Africa, Middle East) to reinforce, diversify and secure the region's gas supply.
The paper will focus on these issues, with the objective to provide a detailed outlook of the structural
evolution of the European gas market.
3
The European gas market: upstream and downstream characteristics
a. European reserves and production
As of 1 January 2008, total European remaining proven gas reserves were estimated at 6177 billion cubic
meters (bcm), representing 3.4% of global reserves. In terms of reserve life (proven reserves/production),
Europe has 20 years of reserves at the current production rate. Norway enjoys the leading position in
Western Europe with 30 years of reserves, followed by the Netherlands (19 years). Romania and Poland
display significant reserve lives, with ratios of up to 55 years and 22 years respectively.
According to preliminary estimates from CEDIGAZ, European natural gas reserves amounted to 6132 bcm
as of 1 January 2009, down 0.7% from the previous year.
The North Sea area is considered mature and Western European gas reserves are declining, accounting for
only 3% of world reserves in January 2009, compared to 4.9% in 2000. In the last five years, proven
reserves in Western Europe dropped 13.6%, while production declined 6.2%. The depletion of reserves in
mature fields located in the North Sea, the Norwegian Sea and the Netherlands (Groningen) explains this
structural downward trend.
The five North Sea area countries (Norway, the Netherlands, United Kingdom, Denmark and Germany)
combined had 5069 bcm of proven natural gas reserves on 1 January 2009, with two countries, Norway and
the Netherlands, accounting for over 80% of this volume. Two giant gas fields, Norway's Troll field and the
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Dutch Groningen field, together hold more than 1920 bcm of reserves, accounting for around a third of the
regional amount.
Norway accounts for almost half of European proven reserves. According to the Norwegian Petroleum
Directorate (NPD), remaining reserves (including resource categories 1, 2 and 3 from the NPD's resource
classification) amounted to 2985 bcm on 1 January 2009, down 0.8% from the previous year. With a volume
of 1683 bcm, the North Sea holds the majority of Norway's reserves (excluding resources from future
measures for improved recovery), although significant quantities also exist in the Norwegian and Barents
Seas, with volumes of 943 bcm and 282 bcm respectively. In terms of undiscovered resources, the
Norwegian Sea harbors the largest potential with a volume of 825 bcm.
The Netherlands rank second with estimated proven reserves of 1222 bcm on 1 January 2009, down 3.5%
from the previous year. Besides the Groningen field, which accounted for nearly 75% of this amount, small
onshore fields represented a volume of 129 bcm, while the Dutch Continental Shelf held 206 bcm. Dutch
proven reserves were reduced by 44 bcm in 2008, as small discoveries (+2.8 bcm) and positive reserves
reevaluations on onshore small fields (+ 23.5 bcm) and the Continental Shelf (+ 7.6 bcm) failed to offset the
declining trend observed on both Groningen field and the Continental Shelf.
The third-ranking United Kingdom has witnessed a dramatic decline in gas reserves in recent years. Since
January 2001, British proven and probable gas reserves have dropped from 1197 bcm in 2001 to 647 bcm in
2008, showing a 8.4%/year depletion rate. In 2007, they fell by 5.4% to reach 647 bcm on 1 January 2008,
comprising 245 bcm of dry gas, 269 bcm of condensate field gas and 132 bcm of associated gas. The
largest decline rate was posted by condensate field gas (-7.5%) and dry gas in fields under production and
development (- 10.5%). Over 70% of dry gas reserves are concentrated in the southern North Sea, where
discoveries under appraisal held an estimated volume of 46 bcm.
In Central Europe, the largest reserves are located in Romania, where major discoveries have been made in
recent years (Bilca, Fratauti, SE in the Suceava licence).
Natural gas production in Europe has grown steadily since the early 1980s, peaking at 322 bcm in 2004,
over 30% more than in the 1980s. Despite new developments, however, regional natural gas output has
gradually declined over the 2004 – 2007 period. Only Norway was added significant new production capacity
in recent years, with the start-up of high-profile developments like the Halten Bank West (Kristin, Lavrans,
Erlend, Morvin, and Ragnfrid fields) in 2005. The Kvitebjorn and Skirne fields also started producing during
the 2004 – 2007 period, accompanied by major developments on existing fields (Ekofisk area, West Flank of
Oseberg, North Flank of Valhall, etc).
The year 2008 reversely showed an exceptional growth in European production, contrasting with the steady
declining trend observed in the previous years. European marketed production rose by an unusual 4.1% to
302.7 bcm in 2008, driven by enhanced production in Norway and the Netherlands, surging 11% in both
countries. The three biggest producers, Norway, the Netherlands and the United Kingdom accounted for
81% of the produced volume, with respective outputs of 99.2 bcm (marking a record-breaking year for
Norwegian natural gas production), 75.8 bcm and 69.9 bcm.
In Norway, the 11% growth in net production was pushed by soaring production on recent fields outside the
North Sea, such as Ormen Lange (production up from 1.7 to 11.4 bcm) and Snohvit (0.14 to 2.35 bcm).
Output growth was also observed on Njord and Statfjord fields. Some mature fields like Kvitebjørn and
Oseberg also recorded higher volumes as production was temporarily reduced in 2007. These gains largely
counterbalanced the production decline in the Troll field (35.8 bcm to 29.7 bcm).
In the Netherlands, the exceptional growth in production largely resulted from the Groningen field, in line with
a national multi-year project that aims to maintain production capacity of the field and extend its operational
life via the addition of new compressors. The upgrading of the Groningen field in 2008 stepped up its output
by almost 30%.
In Denmark, marketed production also surged from 9.2 to 10.1 bcm in 2008, while the production decline in
the United Kingdom was less pronounced than in previous years. In fact, British dry gas production, which
accounted for more than 40% of domestic production in 2008, almost maintained its 2007 production level in
an environment of high annual average prices, while offshore associated gas production declined by 7%,
compared to a drop of 9% in 2007. Some associated gas fields like Brae East, Brent and Jade reversed their
downward output trend recorded in 2007 and managed to maintain or even increase their output in 2008, just
as the drop in oil output was also less significant than in the previous year.
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The largest concentration of natural gas production in the United Kingdom is located in the Shearwater-Elgin
area of the Southern Gas Basin. The area contains five non-associated gas fields: Elgin (Total operator),
Franklin (Total operator), Halley (Talisman), Scoter (Shell), and Shearwater (Shell). The development of the
Elgin-Franklin zone, which has been in production since 2001, ranks among the largest investment projects
in the British North Sea in the last twenty years. The United Kingdom also produces significant amounts of
associated natural gas from its offshore oil fields.
Germany, Italy and France continued to show significant structural production decline. In Romania,
production also fell sharply by almost 1 bcm.
The top ten natural gas producers in Europe in 2008 were: ExxonMobil (40.8 bcm), Shell (38 bcm),
StatoilHydro (37.1 bcm), Petoro (31 bcm), EBN (30 bcm), TOTAL (17.6 bcm), ENI (13.5 bcm),
ConocoPhillips (9.9 bcm), BP (8.1 bcm) and OMV (7 bcm). These companies combined accounted for
around 77% of indigenous European marketed gas production in 2008.
Table 1: Evolution of natural gas production in Europe, 2003-2008 (bcm)
99.2
Annual
growth rate
2008/2007
10.6%
Annual
growth rate
2008/2003
5.3%
72.3
69.9
-3.3%
-7.4%
70.7
68.3
75.8
11.0%
2.0%
19.0
18.8
17.1
15.6
-8.8%
-5.9%
12.6
12.4
12.0
11.6
10.7
-7.8%
-3.7%
14.0
12.9
12.1
10.9
9.7
9.1
-6.2%
-8.3%
Denmark
7.9
9.5
10.5
10.4
9.2
10.1
9.8%
5.0%
Others
14.3
14.6
14.0
14.2
12.9
12.3
-4.7%
-3.0%
TOTAL Europe
317.1
322.3
313.2
305.4
290.8
302.7
4.1%
-0.9%
2003
2004
2005
2006
2007
2008
Norway
76.6
81.0
87.0
90.5
89.7
United Kingdom
102.9
95.9
87.8
80.2
Netherlands
68.8
77.5
72.8
Germany
21.1
19.4
Romania
12.9
Italy
Source: CEDIGAZ
b. A large diversity of market profiles
The European Continent displays wide disparities among national markets as regards gas penetration in
energy balances and the role of the various consuming sectors. The key role of natural gas for residential
use in most national energy mixes (Table 2) attests to the maturity of the EU market and the high level of
development of the European transmission and distribution networks, which total lengths of 165,000 km and
1213,000 km respectively. The weight of the residential sector also means wide seasonal variations in
demand (and hence spot prices) and a significant peak demand in winter.
Exceptions to this pattern lie in some more recent gas markets on the periphery of the continent, which
record significant growth year after year. In 2008, countries like Portugal, Ireland, Finland and Greece
showed respective demand growth rates of 8.6%, 5.5%, 4.7% and 3.2%.
Over the 1997-2005 period, regional consumption grew steadily, at a rate of 2.6%/year. Over the 2005-2007
period, unusually mild weather reduced winter demand. Combined with high gas import prices, which
undermined gas competitiveness, actual gas demand declined, reversing past upward trends. In Germany, a
striking example, the competitiveness of coal relative to natural gas in power generation drastically pushed
down natural gas demand. Adding to these factors, weak economic growth and the implementation of energy
saving measures in some countries (Italy, Slovak Republic) damped gas use in the residential/commercial
and industrial sectors.
In 2008, European apparent consumption (OECD Europe and Central Europe) resumed, up 3.6% to
567.6 bcm, as natural gas appears more competitive than in the previous years, attesting to the volatility of
energy prices. Three markets, the United Kingdom, Germany and Italy, accounted for almost half of the
regional demand.
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This growth was driven by the power generation sector, due in particular to competitive natural gas prices
relative to oil and coal in the first nine months of the year. In addition, the increase in gas use in the
residential-commercial sector in many countries could be generally explained by the weather, as
temperatures returned to "normal levels" in 2008. However, the last quarter 2008 saw a significant drop in
gas use in the industrial sector in every EU markets because of the economic recession.
Subtracting storage variations from the apparent consumption, actual consumption in 2008 was estimated at
561 bcm by CEDIGAZ. The seven largest Western European markets described below accounted for 70% of
this volume.
In the United Kingdom, actual natural gas consumption was estimated at 95.6 bcm in 2008 (stock variations,
leakage and own use gas included), showing a 4.6% increase compared with 2007. Natural gas use for
power generation in the United Kingdom rose by 7.2% in 2008, while gas sales to the domestic sector
increased by 4.8%. Industrial sector sales were down by 6.1%. The residential-sector accounted for 45% of
consumption, followed by the power generation sector (39%) and industry (13%).
In Germany, actual natural gas consumption (including storage injections of 0.7 bcm) decreased slightly by
1% to 86.5 bcm, accounting for 22.8% of national primary energy supply. Natural gas used for space heating
increased 8% due to a colder weather in the first half of 2008. In addition, gas use in power plants rose 9%,
raising natural gas market share in electricity generation to 13%.
In Italy, apparent consumption increased 2.6% to 85.8 bcm in 2008, while actual consumption (after net
storage injections of approximately 1 bcm) slightly declined by 0.2% to 84.8 bcm. Natural gas demand is
shared among three main consuming sectors, power generation (47%), residential-commercial uses (33%)
and industry (20%). The decline in demand resulting from the economic downturn in the second half of the
year was partly offset by a very cold weather in the first quarter.
In France, actual natural gas consumption amounted to approximately 47.2 bcm in 2008, up 2.6% from
2007. Net imports soared 5% in 2008 to cope with a sharp growth in the residential-commercial sector, and
to a lesser extent, in the power sector, especially in the first months of the year.
In 2008, actual natural gas consumption in the Netherlands amounted to approximately 38.8 bcm, up 4.2%
from 2007. The more low-temperature days than 2007 explains this growth in real consumption, as gas use
in the residential-commercial sector was up by 20% in the first half of 2008. Dutch natural gas consumption
was dominated the residential/commercial sector (45%), followed by the power generation sector (30%) and
industry/energy use (25%).
In Spain, natural gas sales soared 10% to a new record level of 38.6 bcm (449.4 TWh) in 2008, making it the
sixth largest consumer market in the European Union. This significant increase in gas consumption was
explained by a 32% rise in gas use for power generation, as well as a 5% growth in the residentialcommercial sector. Conversely, consumption in the industrial sector declined by 3% in 2008. The expansion
of gas in the Spanish power sector raised natural gas market share to 32% of total electricity produced, while
coal market share declined from 24% to 16%.
Actual natural gas consumption in Belgium grew slightly by 0.8% to 17.7 bcm, only due to the increasing
number of connections to the distribution network. The role of L gas thus increased from 27.0% to 28.0% in
2008, accounting for 29% of the overall market. The distribution market (households and small customers)
represented a volume of 8.2 bcm, up 7.2% from the previous year, followed by the power generation sector
(5.1 bcm) and large industrial customers (4.4 bcm).
In Turkey, BOTAS’ sales jumped 2.7% to 36.0 bcm in 2008. The power sector accounted for 56% of this
volume, followed by the residential sector (22%) and Industry (22%). Over the 2003-2008 period, gas
consumption in Turkey soared by 11.4%/year, under the impulsion of every consuming sectors.
In Eastern Europe, three markets, Romania, Hungary and Poland cover 8% of European demand.
Actual consumption in Romania decreased 6.8% to 14.6 bcm in 2008. The main users segments are
industry (41%) including chemicals (17%), and energy production (32%), followed by power (32%).
Natural gas accounted for 44.7% of Hungary's primary energy consumption in 2008. Actual consumption
amounted to 13.3 bcm, down 0.7% from 2007.
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In Poland, PGNiG's domestic sales jumped from 13.7 bcm in 2007 to 13.9 bcm in 2008, while other domestic
3
suppliers provided a volume of approximately 300 Mm . Hence actual consumption amounted to 14.2 bcm,
up 2.4% from 2007. Natural gas penetration in Poland is relatively small compared with the European
average (13% versus 24% in the EU), as a result of the extensive use of coal as the primary source of
energy supply (59% of the national energy mix).
Table 2: Natural gas consumption by sector in the eight largest markets of OECD Europe in 2008
United
Kingdom
Germany
Italy
France
Netherlands
Turkey
91.2
87.4
84.9
45.9
37.2
35.1
35.1
17.6
95.6
86.5
84.8
47.2
38.8
36.0
38.6
17.7
43.0
41.5
28.0
26.0
17.5
8.0
5.0
6.7
Share in %
45%
48%
33%
55%
45%
22%
13%
38%
Industry and other
15.3
32.9
16.9
17.9
9.7
8.0
17.4
5.5
Share in %
16%
38%
20%
38%
25%
22%
45%
33%
Heat & Power
generation
37.3
12.1
39.9
3.3
11.6
20.0
16.2
5.1
Share in %
39%
14%
47%
7%
30%
56%
42%
29%
Actual consumption
(bcm)
2007
Actual consumption
(bcm)
2008
of which
Residential commercial
Spain Belgium
Source: CEDIGAZ
4
Natural gas demand prospects
a. Methods
Natural gas demand prospects in Europe have been constantly revised downward since 2005 because of
surging gas prices and growing competition between gas and coal, especially in the power sector. However,
while gas use in the residential-commercial and industrial sectors often shows signs of saturation in many
markets, especially in Northern Europe, gas development in the power generation sector has been more
recent and still offers significant growth potential.
Indeed, generation capacity in Europe is expected to face fast-growing bottlenecks, which are driven by:
- Ageing power plants and considerable needs for their replacement (40% of thermal and nuclear plants
are older than 25 years, 60% of hard coal plants are older than 25 years),
- Increased peak-load demand,
- The Large Combustion Plant Directive (LCPD) in the United Kingdom,
- Volatile hydro reservoir levels in Spain, Scandinavia and Austria,
- Decommissioning of old nuclear reactors in new EU member states.
Natural gas demand growth in the power sector will be driven by the intrinsic relative economic and
environmental advantages of Combined Cycle Gas Turbines (CCGT), considering an increasing price of
CO2 due to stricter carbon allocations. The role of natural gas will be especially relevant when gas is used
for semi-base power. As shown in the following graphs, natural gas appears as the most competitive energy
relative to coal and nuclear for the production of semi-base power, on the basis of the ollowing main
assumptions:
- Average oil price of $60/bbl over the 2009-2020 period in the High and Low Gas Demand Scenario,
- Average coal price of $60/ton (Low Gas Demand Scenario), or $110/ton (High Gas Demand Scenario),
- Average CO2 price of $25/ton over the 2008-2020 period (Low Gas Demand Scenario), or $38/ton over the
global period (High Gas Demand Scenario).
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Figure 1: Evaluation of average electricity costs (€/MWh) per fuel under the Low Demand Scenario
Close competition
between coal and gas
120
100
€/MWh
80
Natural Gas
60
Coal
Nuclear
40
20
0
8500
6000
3000
Number of hours' usage per year
Source: Institut Français du Pétrole
Figure 2: Evaluation of average electricity costs (€/MWh) per fuel under the High Demand Scenario
160
140
€/MWh
120
100
Natural Gas
80
Coal
60
Nuclear
40
20
0
8500
6000
3000
Number of hours' usage per year
Source: Institut Français du Pétrole
Besides the assumption on energy prices, the significant growth in European gas demand in the High
Growth Scenario is projected in the following context:
- Ongoing strong relationship between oil and gas prices,
- Rising price of CO2 due to strengthened environmental awareness. Growing environmental
concerns are likely to lead to a more significant breakthrough of renewables (approximately 140 GW
of wind/hydro and biomass power capacity are predicted to be added through the period 2007 –
2020 on the European continent) and clean coal technologies in the energy mix after 2015,
increased use of nuclear energy (United Kingdom, France, Romania) and the calling into question of
a number of national total nuclear phase-out programs (Belgium, Germany),
- Economic growth between 2 and 2.5%/year in most markets over the medium and long term, but
weaker economy in 2009-2010, primarily affecting the industrial sector,
- Increased thermal energy efficiency, which is forecast to impact gas demand, but gradually, and over
a longer time framework.
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b. Results
In the High Growth Scenario, CEDIGAZ forecasts that actual European gas consumption (OECD Europe
and Central Europe) will grow by 2.2%/year on average from 561 billion cubic metres (bcm) in 2008 to
652 bcm by 2015. However, this growth will show strong variations year on year, because of the volatility of
energy prices.
Stronger uncertainties affect natural gas development in Europe in the longer term, related to the probable
relaunch of nuclear programs in many countries (United Kingdom, Italy, France), higher energy efficiency,
the impact of clean coal technologies, and, to a lesser extent, the increasing contribution of renewables.
CEDIGAZ forecasts continuing sustainable growth in European gas demand in the long term, although at a
slower pace, to exploit the intrinsic advantages of combined cycle power plants (efficiency and flexibility of
use, low lead times, ready public acceptance and slight environmental impact). Over the 2015-2020 period,
gas-fired power generation will thus continue to account for more than half of absolute growth, dedicated
mainly to peak and semi-base power needs. Under the optimistic scenario, European gas demand is
expected to expand at a pace of 1.2%/year on average over the 2015-2020 period to reach a volume of 692
bcm in 2020, when natural gas is expected to account for 27% share of the European energy balance,
compared to 24% today.
In the European Union 27, natural gas consumption is expected to rise by 1.5%/year until 2020, growing
from 508 bcm in 2008 to 578 bcm in 2015 and 605 bcm in 2020. Five markets, the United Kingdom,
Germany, Italy, France and Spain, are expected to account for more than 70% of absolute growth. The
power generation sector will lead European gas expansion, with an estimated share of gas consumption
growing from 28% in 2008 to 32% by 2020, while the share of the residential-commercial sector is expected
to drop from 39% to 35%, and industry & energy uses’ share to grow slightly from 33% to 34%. In Western
Europe, three markets, the United Kingdom, Italy and Spain, are expected to account for around half of the
absolute growth in gas demand in the EU27 during the 2008 - 2020 period, boosted primarily by the power
generation sector. In fact, up to 70% of additional future CCGT capacity in the EU is expected to come from
these three countries.
Considering additional renewable capacity and decreasing old plant capacity, future needs for new thermal
power plants in the EU-27 are forecast to exceed 100 GW by 2015, doubling thereafter to 200 GW by 2020.
Realistic gas-fired power projects by 2012 represent generation capacity of approximately 45 GW, out of
almost 80 GW of total proposed power station projects. Realistic gas-fired power plants are estimated to
account for only 55% of total announced gas-fired projects, due to volatile gas prices (driven by oil prices)
and supply constraints for power plant components.
Under the alternative Low Demand Scenario based on a coal price of $60/ton and a CO2 price $25/ton on
average over the whole period, real gas consumption on the European continent is expected to grow by
1.8% to 636 bcm by 2015, and then rising at a slower rate of 0.9%/year to 665 bcm by 2020, raising natural
gas share in the European energy mix from 24% in 2008 to 25% by this horizon.
Figure 3: European gas demand prospects in the EU-27 (High Growth Scenario)
bcm
700
600
500
400
300
200
Industry & other
100
Residential-comm.
Power generation
0
2008
2010
2012
2015
2020
Source: CEDIGAZ
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c. National market profiles
Natural gas demand for power generation is expected to account for more than 60% of absolute gas growth
in the United Kingdom, Italy, Austria and Ireland, more than 50% in Germany, Turkey, Greece, Portugal and
Belgium, and more than 40% in France and Spain.
In the United Kingdom, demand is expected to grow slightly by almost 1%/year over the next ten years. The
small-customer segment (distribution) should expand at less than 0.5%/year, particularly affected by reduced
demand over 2009 – 2010 due to the economic recession. The bulk of future growth is expected in the
power generation sector (+1.9%/year), especially after 2010. Approximately 30 GW of new capacity (=3540% of total capacity) is estimated to be required by 2020 to maintain plant margins at more than 20%,
replace shut-down plants and meet rising demand. The Large Combustion Plant Directive (LCDP), which
sets new limits on oxides of sulphur and nitrogen emissions, should result in the shutdown of 12 GW by 2015
or earlier, mainly coal and oil-fired. As a result, 13 GW of new CCGT plant is forecast to connect by 2018,
the first of them slated to begin commercial operation in late 2009.
In Germany, the residential-commercial sector has already shown signs of saturation and power generation
will remain the fastest-growing branch. The planned decommissioning of power plants for age-related
reasons is expected to generate approximately 20 GW replace needed between 2010 and 2020 to maintain
required generation capacity (projected at 115 GW in 2020, of which 25% for peak load), excluding nuclear
phase-out (against 30 GW including nuclear phase-out). Natural gas used in the power sector, precisely for
peak and semi-base loads, is forecast to increase 2.6%/year over 2008-2015 to bridge part of this gap,
growing at a much slower pace afterwards. Planned gas-fired power plants in Germany are mostly slated for
the short and medium term and account for a total capacity of 6.3 GW over 2008-2012.
In France, natural gas demand is expected to grow by 1.9%/year over 2008-2015, mainly driven by the
power generation sector for semi-base load use in the medium term. The main power projects announced in
France for new generating capability to go on stream in 2012 at the latest and accounting for a total capacity
of over 14 GW are about 65% concerned with combined cycle gas turbines. Some of them are already under
construction, like the most-advanced 860 MW-Emile Huchet project, due for commissioning in 2010.
In Italy, natural gas consumption is forecast to rise sharply from 84.8 bcm in 2008 to 96 bcm by 2015 and
102 bcm by 2020, 70% of this growth due to the power generation sector. In fact, the restructuring and repowering of Italian generation capability is still ongoing and mainly focused on the construction of combined
cycle gas plants and, increasingly, wind power. Besides hard coal plants, gas-fired power plants indeed
account for more than 75% of over 10 GW of planned additional thermoelectric capacity by 2013. Out of
these 10 GW, 3.2 GW are under construction and 4.3 GW have already been authorised for construction. In
addition, wind power projects slated for commissioning after 2010 represent total capacity of approximately
4 GW.
In Spain, gas demand growth will soar at a rate of 3.9%/year until 2020 and should be characterised by
sustained strong growth in the domestic and industrial sector and a sharp increase in peak demand from
3
3
3
3
136 Mm /d to 283 Mm /d by 2016, especially for electricity (45.5 Mm /d in 2006 to 135 Mm /day by 2016). As
an illustration of the key role of natural gas in the national expansion of electric power capability, CCGTs
expected over the 2007-2010 period (according to the half-yearly review of the CNE's Framework Report on
Gas and Electricity System Adequacy) comprise a total over 24 GW (2.825 MW in 2008, 11.675 MW in 2009,
9.720 MW in 2010). They account for around 80% of total power projects in the medium term, besides
renewables and hard coal.
In Belgium, natural gas demand is expected to grow by 2.0% until 2015, driven by the power generation
sector (+2.8%/year), and to a lesser extent residential & commercial use (+2.2%/year). Over the 2008-2012
period, approximately 1,000 MW of power capacity is under construction, more than 60% of it is gas-fired. In
addition, the main scenario of the CREG study on the insufficient electricity generating capacity of Belgium
(September 2007) forecasts that there will be a need for additional power generation capacity of 2 GW base
units by 2012, rising to 18.4 GW base units and 2.5 GW peak units over the 2012 – 2017 period.
In Austria, power generation will also be the main driving factor for growth. A survey carried out in June 2007
in cooperation with the Association of Austrian Electricity Companies identified more than 22 power station
projects. New capacity due for commissioning by 2016 amounts to some 6.3 GW, of which thermal power
stations, mainly gas fired, account for 4.26 GW.
In Romania, natural gas consumption is predicted to increase slightly by 1.1% until 2020. The industrial
sector will be the main driver, as the power generation capacity gap is expected to be mainly covered by
additional nuclear power units, hydro units and renewable units (wind, biomass) other than hydro, according
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24 World Gas Conference Buenos Aires 2009
-8-
to Romania's Energy Strategy for 2007 – 2020. The share of natural gas in the electricity balance, which was
17% in 2007, is thus set to decrease.
In Hungary, natural gas demand is projected to grow slightly by 1.7%, with the fastest expansion expected
over 2010-2015, mainly boosted by gas use in the power generation sector and, to a lesser extent, the
industrial sector. Nuclear power is set to play a fast growing role over the longer term.
In Poland, electricity generation is mainly based on hard coal and lignite, and in accordance with national
energy policy, this will not change in the coming years. A significant increase in new wind farm capacity is
anticipated. The growth of natural gas demand in Poland is thus expected to be driven by increased use in
the small-customer segment essentially, in line with the expansion of the distribution network, and to a lesser
extent, fuel switching in CHP plants.
In Turkey, natural gas consumption is forecast to soar from 36 bcm 2008 to 55 bcm in 2015 and 66 bcm
2020 (High Scenario). Recent forecasts of the Ministry of Foreign Affairs indicate growth rate in total
electricity demand ranging from 6% up to 2020 (low demand scenario) to 7.7% (high demand scenario),
illustrating the need for new capacity additions in the short to medium term. The total capacity requirement is
estimated at 80 GW by 2020 according to the low demand scenario, representing a doubling from 2007. A
total amount of 11.5 GW of new natural gas-fired power capacity is expected to be deployed through the
2010 – 2020 period, compared to 11.2 GW of additional lignite and hard coal fired power capacity, 4.5 GW of
nuclear capacity and 15.3 GW of renewables (wind, hydro and jeothermal). The power generation sector is
thus expected to account for more than half of absolute growth in demand, with gas-fired power use growing
from 215 TWh in 2008 to almost 400 TWh in 2020. Natural gas expansion will also be driven by increased
residential and industrial use, especially between 2010 and 2015.
Besides these major markets, high relative growth is also expected in a number of less mature smaller
markets, often located on the periphery of the continent:
- In Ireland, natural gas demand is projected to increase substantially by 2.2%/year, above the average of
national energy growth (+1.4%/year), contributing to increased thermal energy growth and also displacing oil
in electricity generation.
- In Greece, steady growth of more than 5% per year is forecast. The highest relative growth is expected to
be registered in the residential-commercial sector (+11%/year) in line with the expansion plans of the Gas
Distribution Companies These prospects are based on the Long Term Planning Study (LTPS), increased
RES and CO2 abatement.
- In Portugal, natural gas expansion, running at 4.7%/year until 2020, is expected to occur in every sector,
especially power generation in the medium-term.
- In Bulgaria, the bulk of gas demand growth is expected in the distribution sector, as gas demand for the
residential-commercial sector is slated to soar from 0.4 bcm to 1.8 bcm by 2020, according to the low
scenario of Overgas.
- In Scandinavia (Sweden, Finland), natural gas expansion will be boosted by both the extension of the
distribution network and new gas-fired power plants which account for one-third of total planned additional
power capacity in the medium term. In Sweden for instance, E.ON Nordic is building the 440-MW gas CHP
Malmö plant.
In anticipation of a further clarification from the European Commission on its climate change policies,
Eastern European policymakers and incumbent power producers have oriented their strategy toward a
diversification of the generation mix, as illustrated by a number of gas-fired power projects across Eastern
Europe:
- In the Czech Republic, the dominant power producer CEZ aims to develop some 3 GW of gas-fired
capacity across the region to replace and supplement existing coal capacity, including its first
combined cycle gas turbine plant in the country, an 800-MW plant at its Pocerady lignite-fired plant in
northern Bohemia. In addition, RWE is planning to build floating gas-fired power plants to come into
operation from 2010,
- In Latvia, Latvenergo, which commissioned a new 420-MW CCGT in Riga in 2008, announced plans
to build a second 400-MW CCGT at the same site. In Lithuania, Lietuvos Elektrine plans a 350-450
MW CCGT plant,
- Macedonia's ELEM launched a tender in March 2008 for a 300 MW CCGT plant in Skopje, and
Serbia EPS, which is predominantly a coal-fired power producer, is preparing to launch a tender for
a strategic partner to jointly develop a 400 MW CCGT plant in Novi Sad, which would be the
country's first gas-fired plant,
- In Slovakia, E;ON Energie is building the 400 MW-Malzenice CCGT plant, due to start operation in
2010.
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24 World Gas Conference Buenos Aires 2009
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Table 3: European gas demand prospects in the eight largest markets of OECD Europe
(High Growth Scenario)
United Kingdom
2015
Bcm
2020
Bcm
Annual growth
rate
2008 - 2015
Annual growth
rate
2015 - 2020
Annual growth
rate
2008 - 2020
95.6
102.0
106.5
0.9%
0.9%
0.9%
Power & heat
generation
Res-comm.
Industry & other
37.3
44.0
47.0
2.4%
1.3%
1.9%
43.0
15.3
45.0
13.0
46.0
13.5
0.7%
-2.3%
0.4%
0.8%
0.6%
-1.0%
Germany
86.5
92.5
92.1
1.0%
-0.1%
0.5%
Power & heat
generation
Res-comm.
Industry & other
12.1
14.5
14.8
2.6%
0.4%
1.7%
41.5
32.9
44
34
42
35.3
0.8%
0.5%
-0.9%
0.8%
0.1%
0.6%
Italy
84.8
96.1
102.2
1.8%
1.2%
1.6%
Power & heat
generation
Res-comm.
Industry & other
39.9
41.6
45.7
0.6%
1.9%
1.1%
28.0
16.9
33.0
21.5
34.0
22.5
2.4%
3.5%
0.6%
0.9%
1.6%
2.4%
France
47.2
54.0
56.3
1.9%
0.8%
1.5%
Power & heat
generation
Res-comm.
Industry & other
3.3
5.8
7.3
8.4%
4.7%
6.8%
26
17.9
27.5
20.7
28
21
0.8%
2.1%
0.4%
0.3%
0.6%
1.3%
Spain
38.6
57.0
61.0
5.7%
1.4%
3.9%
16.2
19.5
21.0
2.7%
1.5%
2.2%
5.0
17.4
8.0
29.5
9.0
31.0
6.9%
7.8%
2.4%
1.0%
5.0%
4.9%
38.8
40.3
41.3
0.5%
0.5%
0.5%
Power & heat
generation
Res-comm.
Industry & other
Netherlands
Power & heat
generation
Res-comm.
Industry & other
11.6
12.0
12.3
0.5%
0.5%
0.5%
17.5
9.7
18.3
10.0
18.5
10.5
0.6%
0.4%
0.2%
1.0%
0.5%
0.7%
Belgium
17.7
20.4
22.8
2.0%
2.2%
2.1%
Power & heat
generation
Res-comm.
Industry & other
5.1
6.2
7.2
2.8%
3.0%
2.9%
6.7
5.5
7.8
6.4
8.7
6.9
2.2%
2.2%
2.2%
1.5%
2.2%
1.9%
Turkey
36
55
66
6.2%
3.7%
5.2%
20
29
35
5.5%
3.8%
4.8%
8
8
12
14
14
17
6.0%
8.3%
3.1%
4.0%
4.8%
6.5%
Power & heat
generation
Res-comm.
Industry & other
Source: CEDIGAZ
th
2008
Bcm
24 World Gas Conference Buenos Aires 2009
- 10 -
5
European gas supply, snapshot and prospects
a. European natural gas supply in 2008
According to CEDIGAZ, European gas supply (OECD Europe and Central Europe) represented a volume of
567.6 bcm in 2008, up 3.6% from 2007.
Figure 4: European gas supply in 2008
Lybia (pipeline)
1.7%
Russia/Central Asia
(pipeline)
28.4%
Algeria (pipeline)
6.3%
Middle East (pipeline)
1.0%
Other European
producers
9.9%
LNG
9.4%
Africa
7.2%
Netherlands
13.4%
Qatar
1.4%
Other
0.8%
United Kingdom
12.4%
Norw ay
17.5%
Source: CEDIGAZ
Among main European producing countries, Norway provided 17.5% of European supply, followed by the
United Kingdom (12.4%) and the Netherlands (13.4%). Total imports by pipeline increased 5.9% to
394.7 bcm in 2008 (including 184.3 bcm of intra-regional pipeline trade). Import dependence towards extraEuropean sources remained quasi unchanged at 47%. The European continent imported a total volume of
155 bcm from Gazprom, accounting for more 27% of European supply, while 6% was provided by Algerian
pipeline gas (Pedro Duran Farell and Enrico Mattei pipelines) and 4% via pipeline gas from other sources
(Libya to Italy, Iran to Turkey, Central Asia to Poland).
Pipeline imports from extra-European sources accounted 37.5% of supplies, while LNG purchases
accounted for 9.4%.
LNG imports reached approximately 55.3 bcm in 2008, mainly originating from Algeria (35%), Nigeria (27%),
Qatar (14%) and Egypt (12%). With a 4.1% growth in LNG demand in 2008, Europe displayed different
developments among countries: Spain posted the strongest increase in LNG imports, confirming its role as
the top European LNG importer, while LNG imports into the majority of European markets dropped
dramatically (Table 6).
Three companies, namely Gazprom, StatoilHydro and Sonatrach, ensured more than 50% of European gas
supply in 2008.
According to CEDIGAZ, Russia’s pipeline net physical exports to European markets increased from 150 bcm
in 2007 to 154.5 bcm in 2008, keeping a market share of 27.5%. Gazprom increased exports to almost every
Western European markets with some exceptions like the Netherlands and Greece, as this latter started
receiving gas from Azerbaijan in 2008.
Gazprom's main Western and Central European outlets in 2008 were Germany (36.2 bcm), Italy (24.5 bcm)
and Turkey (23.5 bcm), trailed by Hungary (8.9 bcm), France (8.8 bcm), the Czech Republic (6.6 bcm),
Poland (7.2 bcm) and Austria (5.8 bcm).
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24 World Gas Conference Buenos Aires 2009
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In 2008, Russian gas deliveries to France increased by approximately 1 bcm, while exports to Germany and
Italy rose by respective rates of 3.7% and 2.5%. The increase in Russian gas exports to Turkey (more than
3
300 Mm ) was related to increased domestic demand. In Eastern Europe, the strongest increases in Russian
imports were registered in Hungary (+25%) and Poland (+16%). Reversely, Russia dropped natural gas
exports to the Baltic countries from 5.6 bcm in 2007 to 4.5 bcm in 2008.
In recent years, Gazexport extended its long-term contracts with many European customers (long-term
contracts now last until 2035 with ENI Gas & Power, E.ON Ruhrgas and RWE Transgaz, 2031 with GDFSuez, 2030 with VNG, Wintershall and its subsidiaries WIEE and WIEH, 2027 with OMV, 2025 with Gasum)
and signed new ones, including those associated with the Nord Stream pipeline project (current contracts
with Wingas, DONG Energy, E.ON Ruhrgas and GDF-Suez) and a Romanian supply deal signed in April
2007 for a volume of 42 bcm to be delivered to Conef for the period 2010-2030. Mid-2008, Gazexport held a
supply portfolio of long-term contracts representing a plateau volume of approximately 200 bcm/year by
2015 and 185 bcm/year by 2020.
StatoilHydro is the second biggest gas supplier in Europe. In addition to its own equity production,
StatoilHydro is required by the Norwegian State to transport and sell gas on behalf of the SDFI. StatoilHydro
therefore marketed approximately 80% of all the Norwegian Continental Shelf (NCS) gas in 2008.
In 2008, Norwegian gas exports to Europe by pipeline increased by 9% to a new record level of 92.6 bcm,
while LNG exports to the continent soared from 0.14 bcm in 2007 to 1.38 bcm in 2008. The largest growth
occurred in exports to the United Kingdom (+ 26%). In addition, Norwegian gas sales to France and
Germany rose by 6.7% and 7.7% respectively.
According to CEDIGAZ, the two major export markets for Norwegian gas in 2008 were Germany (26.4 bcm)
and the United Kingdom (25.3 bcm), followed by France, (16.1 bcm), Belgium (8.0 bcm), the Netherlands
(6.5 bcm) and Italy (6 bcm). These six countries were the recipient for almost 80% of gas produced from the
NCS.
Norway's total export capacity reached approximately 130 bcm/year in mid-2008, with the following pipelines:
3
3
3
Statpipe-Norpipe (35 Mm /day), Europipe I (46-54 Mm /day) and Europipe II (71 Mm /day) to Germany,
3
3
Franpipe to France (52 Mm /day), Vesterled (38.6 Mm /day) and Langeled to the United Kingdom (the
1
3
3
southern leg has a capacity of 70 Mm /day), and the Zeepipe system (41 Mm /day) to Belgium. Considering
an utilisation rate of 90%, real export maximum capacity reached about 115 bcm/year.
According to CEDIGAZ provisional estimates, the 4.2% decline in Algerian LNG exports to Europe in 2008
was counteracted by increased pipeline deliveries, up 8.9% from the previous year. Sonatrach thus
maintained a market share of almost 10% of European gas supply in 2008.
European markets (Turkey included) purchased around 36 bcm of Algerian natural gas through pipeline in
2008. These pipeline deliveries were broken down as follows: Italy (24.4 bcm), Spain (9.0 bcm), Portugal
(1.9 bcm) and Slovenia (0.4 bcm). Algerian pipeline supplies increased by 1.5% in Spain, and soared from
1.4 to 1.9 bcm in Portugal.
Up to 19.5 bcm of Algerian gas were exported in the form of LNG in 2008, in particular to France (7.6 bcm),
Turkey (4.25 bcm) Spain (4.9 bcm), Italy (1.56 bcm), Greece (0.7 bcm) and the United KLingdom (0.37 bcm).
The national company is increasing piped gas deliveries to Italy through the long-term contracts associated
with the 2 phase-extension project of the Enrico Mattei (Trans Tunisian) pipeline. According to provisional
official figures, Algerian pipeline exports to Italy increased by 10.3% to 24.4 bcm in 2008. The upgrade of the
transport capacity on the Transmed pipeline was achieved, raising the pipeline capacity to 33.5 bcm/year.
The two portions of around 3.3 bcm/year each were respectively added in April and October 2008, with
capacity assigned to third parties. In addition, the Medgaz pipeline delivering gas to Spain is due for
commissioning in the second half 2009 with initial transport capacity of 8 bcm/year. The Medgaz consortium
has finished pipe-laying operations in April 2009. Medgaz pipeline is a strategic project enhancing supply
security for Spain and France. One of its major strengths is its proximity to Europe. Sonatrach also plans
additional deliveries to Italy in the short and medium term thanks to the planned Galsi pipeline project, which
is due to have a transport capacity of 8 bcm/year. This project reached a new stage on 15 November 2006,
when five preliminary purchases and sales agreements were concluded with ENEL, Edison, Hera,
WorldEnergy and Ascopiav, for a period of 15 years.
1
The southern leg (Sleipner to Easington) became operational in October 2006, with the northern leg (Nyhamna to the
Sleipner riser facility) following in October 2007. Capacity is just over 80 Mm3/day in the northern leg
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24 World Gas Conference Buenos Aires 2009
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In terms of LNG sales, Sonatrach has the objective to increase total LNG output by 30% by 2012, with the
commissioning of two projects: the Skikda plant, with a capacity of 4.5 Mt/year, and the Arzew LNG plant,
with a capacity of 4.7 Mt/year.
Table 4: Existing long term LNG contracts from Algeria to Europe (bcm/year)
Importing
country
France
Italy
Spain
Other
TOTAL LNG
Source: CEDIGAZ
2007
2012
2015
2020
10
3.3
2.6
4.6
20.5
10
3.3
2.6
4.6
20.5
10
1.5
2.6
0.7
14.8
1.5
1.6
0.7
3.8
Table 5: Existing long term pipeline contracts from Algeria to Europe (bcm/year)
Importing
country
ENI
ENEL
Edison
Other
Italy
Gas Natural
Gaz de France
Iberdrola
Other
Spain
Portugal
Slovenia
TOTAL
Source: CEDIGAZ
2007
2012
2015
2020
21.5
6
21.5
9
4
4.3
38.8
9
2
2.8
2
15.8
2.5
21.5
9
4
4.3
38.8
9
2
2.8
2
15.8
2.5
0
2
2
1
5
9
2
2
2
15
3
57.1
57.1
22
27.5
9
2.8
2
13.8
2.5
0.4
44.2
In total, Sonatrach plans to raise gas exports to the region to around 85 bcm/year by 2012, representing
additional sales of approximately 30 bcm.
b. National markets’ supply characteristics
The supply structures of European markets are actually heterogeneous. Some countries like France,
Belgium and Spain are substantially if not totally dependent on imports, while the Netherlands and Denmark
are the only two net exporters of natural gas in the EU.
Pipeline imports from Russia are the only supply source of supply in Finland and the Baltic countries, while
they account for more than 90% of supply (production plus imports) in Slovakia and Bulgaria, 76% of supply
in the Czech Republic, 63% in Turkey and Hungary, 35% in Germany, 28% in Italy and 18% in France.
The dependence on Algerian gas imports is more than 30% in Italy and Spain, compared to 15% in France
and 12% in Turkey.
LNG imports accounted for 72% of gas supply in Spain, one of the rare countries where LNG is the price
setter, and 57% in Portugal, versus 26% in France and less than 20% in Belgium, the United Kingdom and
Greece.
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24 World Gas Conference Buenos Aires 2009
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European producing countries generally display declining domestic output and a growing dependence on
imports, as shown in the three largest consuming markets:
- The case of the United Kingdom is a striking example. On this market, natural gas imports have increased
fivefold between 2003 and 2008, jumping from 7.5 bcm to more than 36 bcm. In the meantime, exports
decreased by 31%. Hence, the United Kingdom became a net importer for the first time in 2004, when net
imports represented 1.4% of apparent consumption. This percentage has since then soared, to reach 27% in
2008,
- In Germany, import dependence rose from 78% in 2003 to 82% in 2008. Domestic production still ensured
approximately 18% of domestic needs, the remainder was covered by imports, the bulk of them from Russia
(41% of net gas supply), Norway (30%) and the Netherlands (23%),
- In Italy, natural gas imports increased by 3.9% to approximately 77 bcm in 2008, accounting for 90% of
apparent consumption, compared to 82% five years ago.
c. European gas supply prospects
CEDIGAZ forecasts a strong decline in intra-EU production (Norway excluded) from 203 bcm in 2008 to
142 bcm by 2015 and 90 bcm by 2020.
The production decline in the British North Sea, which started in 2000, has accelerated since 2004 at a faster
rate than predicted. Most British natural gas fields have already reached a high degree of maturity and their
production decline has intensified dramatically in recent years. This is notably characterized by the shutdown
of depleted gas fields. The close of production of the Frigg field, operated by Total, in October 2004, is a
striking example.
Although 2008 forecasts indicate potential production from new developments (including the West of
Shetlands region), natural gas production on the UK Continental Shelf is expected to drop sharply from
70 bcm in 2008 to 56 bcm in 2012, 40 bcm in 2015 and 25 bcm in 2020.
In the Netherlands, a major multiyear project is under way to renovate production clusters, ensure the longterm integrity of existing facilities, and install new compression to maintain production capacity and extend
the operational life of the Groningen field. As a result of an amendment to article 55 of the Gas Act,
production from the Groningen field has been limited to a ceiling in order to maintain reserves for future use.
According to the Dutch Ministry of Economic Affairs, the maximum allowed production from the Groningen
accumulation has been limited to 425 bcm for the period 2006-2015. Therefore, the supply from the
Groningen accumulation until and including 2015 has been profiled as 46 bcm Geq per year.
Natural gas production in the Netherlands is forecast to drop by approximately 3%/year over the 2008-2015
period, to reach approximately 60 bcm by 2016, before declining at a slower rate to approximately 55 bcm in
2020.
In Romania, domestic production is forecast to drop abruptly by 5%/year until 2015, falling afterwards at
6.5%/year until 2020. In Denmark, the production decline rate is estimated at 11%/year over the 2009 – 2015
period. In Italy and Germany, production will also pursue their structural deep decline, at more than
10%/year over 2009 – 2020.
Based on these assumptions, CEDIGAZ forecasts that the gap between European supply (Norway
excluded) and demand will increase from 365 bcm in 2008 (equivalent to an import-dependence of 64%) to
602 bcm by 2020 (87%).
Norway is expected to account for a third of the absolute growth in European supply until 2020, relying
mainly on the production ramp up of non-North Sea projects (Ormen Lange, Snohvit) to provide significant
additional output.
According to the Norwegian Petroleum Directorate (NPD), Norwegian gas sales are expected to reach an
annual plateau of between 115 and 140 bcm during the next decade. The Ormen Lange field, discovered in
1997, had estimated proven reserves of 382 bcm as of 1 January 2009. Its production is expected to plateau
at more than 20 bcm/year. The Snohvit gas field started producing in autumn 2007, 23 years after it was
discovered. It contains the only commercial reserves in the Norwegian sector of the Barents Sea at present,
with an estimated volume of 158 bcm on 1 January 2009. The increase in Norwegian gas output will also be
ensured by new developments projects (Gjoa, Skarv, Tyrihans, etc.), as well as capacity and lifespan
expansion in some existing processing facilities and fields.
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24 World Gas Conference Buenos Aires 2009
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Intra-European production (Norway included) is forecast to decline from 302 bcm in 2008 to 272 bcm in 2015
and 230 bcm by 2020. European dependence on extra-European sources is thus expected to rise from 47%
in 2008 to 58% in 2015 and 67% in 2020.
The volume of pipeline imports from extra-European sources (Russia/Central Asia, Algeria, Libya, Middle
East) is projected to increase from 211 bcm in 2008 (37.5% of European supply) to 265 bcm by 2015 (41%),
which is almost quasi equivalent to long-term contracted deliveries. The steady growth in pipeline trade by
this horizon will mainly count on extensions on existing lines and interconnections, as major international
pipeline projects are facing various hurdles, pushing back their commissioning date or making the
implementation of some of them uncertain. Political risks, financing issues, transit and environmental
disputes, often add to their main handicap: the lack of sufficient gas supply in the short-term.
The growth in European pipeline imports will display different characteristics among markets in the mediumterm:
- Increased pipeline imports are expected from Algeria and Libya to Italy (Transmed and Greenstream
pipeline expansion) and from Algeria to Spain (Medgaz). However, this growth may be lower than expected
in the medium term because of rather small-sized recent finds and a cautious approach to resource
development in Algeria,
- The large majority of additional Norwegian output will be dedicated to the United Kingdom,
- Fast-growing imports via existing lines should be recorded from Russia to the Netherlands and Germany,
which will face declining domestic production and falling imports from the United Kingdom. A significant rise
in Russian imports is also likely to occur in Turkey, Greece, Finland, Central and Eastern European countries
(Bulgaria, Romania, Austria, Poland, Hungary).
The gap between projected pipeline imports from extra-European sources and long-term contracted
deliveries will then grow gradually after 2015, to reach approximately 100 bcm by 2020, highlighting needs
for contract extensions, additional pipeline capacity and new long-term agreements.
Filling the fast-growing gap between supply and demand is conditioned by the ability of Russia to add
significant volumes through the whole period, especially after 2015.
While part of rising Russian imports in the short and medium–term should come from a production ramp up
on existing fields in Western Siberia (Yuzhno-Russkoye in particular), Central Asian gas, mainly from
Turkmenistan to Russia, is poised to play a crucial role. Turkmenistan has planned to boost gas exports from
50 bcm in 2007 to 125 bcm by 2015, in line with the 80 bcm/year flows laid out in a 2003 Russian accord.
Over the long-term from 2015 onwards, the development of major new Russian upstream projects
(Bovanenkovo, Shtokmanovskoye) will be the key for Russian authorities to securing both growing exports to
Europe and rising domestic demand. Major growing outlets for Russia include some Central European and
Mediterranean countries (Romania, Hungary, Turkey), as well as Germany, France and the Netherlands.
Figure 5: Future minimum Russian gas needs for Europe versus long-term contracted volumes (bcm)
250
200
Contracted volume
(plateau)
150
Exports to Europe
100
50
0
2008
2012
2015
2020
Source: CEDIGAZ
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24 World Gas Conference Buenos Aires 2009
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The largest international pipeline projects from extra-European sources are encountering short-term
constraints, raising uncertainties as to their viability or delays in their implementation in the medium-term:
- Gazprom’s Nord Stream and South Stream projects require huge investments in remote new gas field
developments to offset declining production from existing fields (Urengoy, Yamburg), and meet both Russian
growing domestic demand and export requirements,
- Transit problems affect the original planned route of some major international pipeline projects,
- Despite recent announcements on feasible significant expansion of production capacity from Shah Deniz,
Azerbaijan may only be partially able to supply the 30-bcm/year-Nabucco pipeline project, which struggles to
find supply sources at adequate political and economic terms,
- In Algeria, significant additional exports to Europe via new pipeline projects require incremental
investments to link new south-western fields (Reggane, Touat, Hassi Mouina, etc.) to the processing center
of Hassi R'Mel.
- Added to some competition between piped gas and LNG, especially relevant in Northern Europe and Italy,
some pipeline projects supplying the same regions are consequently competing against one another
(Nabucco, Trans Adriatic Pipeline and South Stream in South Eastern and Central Europe).
Thus, in the short and medium term, LNG is poised to account for the largest share of incremental imports
into Europe, enhanced by its ability to offer flexible supply to meet variations and peak demand in liberalised
markets. In addition, the LNG option can offer positive pricing arbitrages in a probable future context of high
continental oil-indexed prices. Indeed, liquidity on European Hubs (NBP, TTF) has markedly increased in
Northern Europe, with the expansion of spot-indexed LNG prices. European LNG imports are thus expected
to increase from an estimated 55 bcm in 2008 to 115 bcm in 2015, representing a solid growth rate of more
than 10%/year during the period. LNG growth is expected to slow down thereafter in line with gas demand
and the growing tightness of LNG supply. The share of the European market in global LNG trade will
increase from 24% in 2008 to 28% in 2015.
Table 6: LNG demand prospects by country (bcm), 2008 - 2020
2007
Canada
21.8
United States
2.7
Mexico
1.2
Others
Total North
25.7
America
Brasil
Chile
Argentina
Total Latin
America
13.1
France
24.2
Spain
2.7
Belgium
2.5
Italy
1.5
United Kingdom
5.6
Turkey
3.7
Other Europe
53.1
Total Europe
78.8
Atlantic Basin
3.9
China
34.4
South Korea
10.0
India
88.8
Japan
11.0
Taiwan
Others
Total Pacific Basin 148.1
Total World
226.9
Source: CEDIGAZ
th
Annual
growth rate
2007-08
Annual
growth rate
2008 - 2015
12
50
20
1
-54.6%
35.3%
6.6%
14.1%
23.8%
1.7%
Annual
growth rate
2015 - 2020
11.4%
14.9%
4.6%
-7.3%
49
83
-42.4%
18.8%
10.9%
0.4
7
3
2
17
4
3
22
6
6
33.4%
5.3%
8.4%
14.9%
0.4
11
24
34
79.5%
7.2%
12.6
28.7
2.5
1.6
1.0
5.3
3.6
55.3
70.5
4.4
36.6
10.8
92.1
12.1
18
36
5
8
13
7
10
96
142
15
47
16
101
16
1
196
338
20
39
6
10
20
7
13
115
188
18
51
19
106
19
3
216
404
22
41
7
12
23
8
22
135
252
24
55
24
110
23
6
242
494
-3.6%
18.7%
-6.7%
-35.5%
-31.5%
-4.8%
-1.6%
4.1%
-10.5%
13.7%
6.4%
8.0%
3.7%
9.9%
6.4%
4.5%
13.3%
29.9%
53.4%
4.1%
20.1%
11.0%
15.0%
22.3%
4.9%
8.4%
2.0%
6.4%
5.3%
-0.2%
4.7%
8.6%
2.4%
1.0%
3.1%
3.7%
2.8%
2.7%
11.1%
3.3%
6.0%
5.9%
1.5%
4.8%
0.7%
4.3%
14.9%
2.3%
4.1%
2008
2012
2015
2020
9.9
3.6
1.3
3
18
13
1
7
25
16
1
14.8
35
156.0
226.5
24 World Gas Conference Buenos Aires 2009
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The highest absolute growths in LNG demand over the 2008 - 2015 period are expected in the United
Kingdom (+19 bcm), Spain (+10 bcm) and Italy (+ 7 bcm). The power generation sector in particular will
demonstrate a growing appetite for LNG in these three markets.
In March 2009, total regasification capacity reached approximately 137 bcm in OECD Europe, while 54 bcm
of additional capacity is under construction. In addition, there are many LNG regasification projects on the
continent. The most realistic of them represent a probable additional regisification capacity of 75 bcm by
2015. Even if European markets need excess regasification capacity to buy some market arbitrage options
and increase their attractiveness towards LNG producers, there may be far more planned LNG receiving
capacity than what is required.
For illustration, the utilization rate of regasification terminals is expected to drop from 76% to 47% in France
(assuming operational start-up Dunkerque terminal in addition to Fos-Cavaou before 2015), and from 55% to
25% in Italy (assuming operational start-up of four plants, including two now under final construction stage).
Considering overcapacity in terms of economics rather than physical capacity, this development suggests
the following strategic trends:
- LNG suppliers will secure more long term regas capacity than firmly secured volumes, to create an option
to place gas in a more lucrative market,
- LNG buyers will secure long term regas capacity without contracting LNG supply, to take advantage of the
differences in the profitability and competitivness of different regasification terminals at both regional and
national level (especially in the liquid markets in Northwest Europe), in line with the emergence and
development of a market for LNG regas capacity.
The gap between European LNG long-term contracted volumes and actual imports is estimated at 30 bcm in
2015 and approximately 56 bcm in 2020 (assuming extension of Algerian contracts with Spain and France
and Nigerian contracts with Italy). In the short and medium-term, a large majority of this gap is expected to
be met by the flexible long-term LNG portfolio, which is gaining large importance in the Atlantic Basin and
can be dedicated to multiple destinations (US, Europe). This will entail re-orientations of LNG cargoes from
the US to Europe. Indeed, the recent growing role of unconventional gas in the US has altered previously
forecast US LNG requirements. The Atlantic Basin’s long-term LNG portfolio is a main source of short-term
deliveries. Adding direct spot purchases between the two continents particularly related to different seasonal
national demand profiles, short-term LNG trading in the Atlantic Basin is expected to increase almost fourfold
to 55 – 60 bcm by 2015, representing around half of global short-term LNG trade by this horizon, compared
to 35% in 2007.
Figure 6: US LNG demand and long-term LNG contracted imports (including flexible portfolio)
2008 - 2020
Bcm
100
90
80
70
60
50
40
30
20
10
0
Contracted volumes
Demand
2008
2012
2015
2020
Source: CEDIGAZ
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24 World Gas Conference Buenos Aires 2009
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Qatar is set to gradually emerge as a key European LNG supplier, accounting for almost 8% of European
gas supply in 2020, compared to only 1% in 2007. Among the other main suppliers, LNG deliveries from
Algeria, Egypt and Nigeria are predicted to grow 35%, 200% and 67% respectively over the 2008-2020
period. In Egypt and Nigeria, marketable production has increased by more than 60% in the last five years
and proven reserves by 10%.
Figure 7: Total contracted volume in 2008
Total = 245 bcm
Figure 8: Total contracted volume in 2015
Total = 321 bcm
300
300
250
250
200
200
Pacific Basin
Pacific Basin
150
Middle East
150
Atlantic Basin
Middle East
Atlantic Basin
84
100
100
50
50
0
0
Import zones
Export zones
Import zones
Export zones
Source: CEDIGAZ
The analysis of disparities in the balance between contracted imports and projected LNG demand in the
Atlantic and Pacific Basins reveals that the Atlantic Basin is oversupplied over the 2008 – 2015 period, while
the gap between the contracted imports and actual LNG demand in the Pacific Basin is progressively
growing after 2010, to reach approximately 70 bcm by 2015. Around half of this volume is expected to be
provided by the Atlantic Basin’s long-term LNG portfolio initially dedicated to the US. Increasing spot trade
from re-divertible long term LNG contracts is thus expected to grow sharply to allow arbitrages in the Atlantic
Basin and the reorientation of LNG flows from the Atlantic Basin toward the under-supplied Pacific Basin in
the medium-term.
According to CEDIGAZ, the European market will reinforce its role in the international gas trade. Out of a
total projected volume of 660 bcm of inter-regional flows in 2020, Europe is forecast to share 70% of it.
6
Conclusions
To conclude, we note a significant and widening gap between European production and demand, growing
faster after 2012. This implies both challenges and opportunities since in terms of supply, the European
continent enjoys a strategic geographical position for imports from a variety of supply sources via both LNG
and pipeline.
While sufficient capacity is planned from international pipeline projects, their timely commissioning faces
obstacles and delays, due to constraints like the unavailability of sufficient short term resources and rising
costs.
In this context, LNG has become a critical option to meet surplus demand in winter in the coming years, due
to the flexibility mechanisms in LNG supply, especially attractive for gas and electric utilities. However, LNG
supply will be increasingly constrained by growing competition between exports and domestic needs in LNG
producer countries, market arbitrages and geopolitical issues. This lack of LNG supply capacity to meet the
rising demand from both the Atlantic and Pacific market is likely to become especially relevant after 2015.
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24 World Gas Conference Buenos Aires 2009
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Thus, risk mitigation in securing and optimizing the European gas supply portfolio in both the medium and
long term will require a growing diversity of sources and an adequate balance between the various transport
technologies.
From the analysis of production prospects, export infrastructure projects in producer countries and long-term
contracts, the structure of European gas supply in 2020 is expected to evolve as follows:
- Norway will become the key indigenous supply source, with a market share of around 20%,
- Subject to investment conditions and import capacity from Central Asia, Russia will maintain its
dominant share of European gas supply, estimated at more than 28% by 2020, relying on its large
reserves,
- LNG is forecast to account for 20% of European gas supply in 2020, coming from a variety of
sources,
- Africa and the Middle East will powerfully consolidate their role in European gas supply, accounting
for estimated respective shares of 22%-23% and 10% by 2020, compared to 15% and 2.5% in 2008.
This context of galloping globalisation demonstrates the need to reinforce international cooperation further to
ensure supply security on the European market.
Table 7: Evolution of European gas supply (Turkey and Central Europe included), 2008 - 2020
2008
Bcm
2015
Bcm
(Low
Scenario)
2015
Bcm
(High
Scenario)
2020
Bcm
(Low
Scenario)
2020
Bcm
(High
Scenario)
Total supply
568
636
652
665
692
Intra-EU production
203
142
142
88
90
Share in %
35.7%
22.3%
21.8%
13.2%
13.0%
Norway
99
128
130
135
140
Share in %
17.4%
20.1%
19.9%
20.3%
20.2%
Russia
154
170
175
190
195
Share in %
27.1%
26.7%
26.8%
28.6%
28.2%
Africa by pipeline
45
60
63
80
90
Share in %
7.9%
9.4%
9.7%
12.0%
13.0%
Middle East by pipeline
6
10
12
12
15
Share in %
1.1%
1.6%
1.8%
1.8%
2.2%
Central Asia by pipeline
6
15
15
25
25
Share in %
1.1%
2.4%
2.3%
3.8%
3.6%
Africa by LNG
41
58
60
68
70
Share in %
7.2%
9.1%
9.2%
10.2%
10.1%
Middle East by LNG
8
45
45
55
55
Share in %
1.4%
7.1%
6.9%
8.3%
7.9%
Other by LNG
6
8
10
12
12
Share in %
1.0%
1.3%
1.5%
1.8%
1.7%
Source: CEDIGAZ
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24 World Gas Conference Buenos Aires 2009
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References
[1] Cedigaz (2009), Natural Gas in the World - CEDIGAZ First Estimates 2008, Rueil Malmaison
(France)
[2] Cedigaz (2009), LNG Long Term Contracts by Exporter, Rueil Malmaison (France)
[3] Cedigaz (2009), Pipeline Long Term Gas Contracts by Exporter, Rueil Malmaison (France)
[4] Cedigaz (2009), Gas Reserves 2009, Rueil Malmaison (France)
[5] Cedigaz (2009), The 2008 Natural Gas Year in Review, Rueil Malmaison (France)
[6] Cedigaz News Report, Rueil Malmaison (France), various issues
[7] Cedigaz (2009), LNG Infrastructure Database, Rueil Malmaison (France)
[8] National Grid (2008), Gas Transportation – Ten Year Statement
[9] Ministère de l’Ecologie, de l’Energie, du Developpement durable et de l’Aménagement du territoire
(2008), Synthèse publique de l’étude des coûts de référence de la production électrique – Paris
(France)
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24 World Gas Conference Buenos Aires 2009
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