Energy trading and gas supply business in Europe

Energy Trading and Gas Supply in Europe

January 2011

2RWE – Energy Trading and Gas Supply in Europe | January 2011

The following chapter provides an overview of the power, gas and coal market in Europe, the commodities that are important for utilities like RWE, where they are traded, how liquid they are, and how this has developed over time.

Power, gas and coal trading in Europe


The TOP energy traders

European electricity

OilHard coal

Natural gas

Source: Energy Risk Commodity Ranking 2010; RWE.

http://de.wikipedia.org/w/index.php?title=Datei:Goldman_Sachs.svg&filetimestamp=20090506002119

http://de.wikipedia.org/w/index.php?title=Datei:J_P_Morgan_Chase_Logo_2008_1.svg&filetimestamp=20090531011935

http://de.wikipedia.org/w/index.php?title=Datei:Morgan_Stanley_logo.svg&filetimestamp=20090911043501

http://www.totsa.com/home.php

http://www.shell.com/

http://group.barclays.com/Home

http://de.wikipedia.org/wiki/Datei:Vitol_logo.svg


http://www.edftrading.com/default.aspx


http://de.wikipedia.org/w/index.php?title=Datei:J_P_Morgan_Chase_Logo_2008_1.svg&filetimestamp=20090531011935

http://de.wikipedia.org/w/index.php?title=Datei:Goldman_Sachs.svg&filetimestamp=20090506002119


http://www.eon.com/de/index.jsp

http://www.shell.com/

http://www.electrabel.be/




http://www.peabodyenergy.com/default.asp





The main products in European energy trading

ElectricityNatural gas

Hard coal CO2

Oil / oil products

Liquid tenor 3 years 3 years 3 years 3 years 5 - 10 years

Products Spot, forwards, futures, options

Spot, forwards, futures, options

Spot, forwards, futures, swaps, options

Spot, forwards, futures

Spot, forwards, futures, swaps, options

Major exchanges

EEX, Nordpool, APX

ICE, APX, EEX, Powernext

ICE, CME/NYMEX, EEX

EEX, ICE ICE, NYMEX

Delivery periods

Hourly, daily, weekly, monthly, quarterly, seasonally, yearly

Daily, weekly, monthly, quarterly, seasonally, yearly

Weekly, monthly, quarterly, yearly

Yearly Weekly, monthly, quarterly, yearly

Trading volumes p.a.

c. 8,000 TWh c. 3,300 TWh c. 170 million t physical / 930 million t financial (API#2)

c. 4,440 million t c. 800 million bbl


Fundamental drivers of European power pricesSupply

Dem

and

Weather impacts

Precipitation/ Snow melt

Wind

Temperature

Solar radiation

Cloud coverPower price

Long-term influences

> Regulatory decisions> Capacity changes

(plant/grid new builds & shutdowns)> Macroeconomic developments/economic activity

Fuel markets

CO2 prices Crude prices Coal prices

Plant availabilityPower generation from renewables

Cross border exchange balance

Revisions

Power demand

Gas prices

Wind generators

PV & Solar thermal

Lighting

Climatisation, electric heating

School holidays

Time of day

Thermal power plants

Reservoir/Run-of- river hydro plants

Bank holidays

Technical outages


0

100

200

300

400

500

2006 2007 2008 2009

EEX Nord Pool

European power trading hubs (I): Increasing liquidity and number of market participants

Oslo

Amsterdam

Paris

Madrid

LeipzigLondon Warsaw

Prague

Graz

Brussels

RomeBucharest

Ljubljana

ExchangeExchangeTrading HubTrading Hub

> EPEX (EEX/Powernext), Leipzig/Paris

> Nord Pool, Oslo> APX/Endex, Amsterdam

Major power exchanges (spot and futures)

> OMEL, Madrid> EXAA, Graz> Belpex, Brussels> APX(UK), London> GME, Rome> OTE, Prague> PPX, Warsaw> Borzen, Ljubljana> Opcom, Bucharest

Further power exchanges (primarily spot)

0

2,000

4,000

6,000

8,000

2002 2003 2004 2005 2006 2007 2008 2009

NetherlandsFranceScandinaviaGermany

Power trading volumes in Continental EuropeTotal trading volume per year (TWh)

Development of number of participants


European power trading hubs (II): prices are converging more and more

Forward baseload front-year in €/MWh

Correlation between prices increased due to European emissions trading and increased globalisation of fuel markets.

Correlation coefficient for electricity cal forwards

Year Germany/ France

Germany/ Netherlands

Germany/ Nord Pool

Germany/ UK

2006 forw in 2005 0.96 0.82 0.67 0.36

2007 forw in 2006 0.96 0.86 0.62 0.54

2008 forw in 2007 0.88 0.86 0.74 0.72

2009 forw in 2008 0.90 0.96 0.82 0.67

2010 forw in 2009 0.86 0.97 0.78 0.56

2011 forw in 2010 0.95 0.94 0.59 0.76

UKDepend on UK gas prices, very limited export capacity to the continent

The Netherlands No lignite and only one small nuclear plant

FranceHuge nuclear capacities, limited mid-merit capacity, price path very similar to Germany due to crossborder capacities

GermanyBalanced fuel mix Strong dependence

on hydro

20

40

60

80

100

120

Jan

05

Jul 0

5

Jan

06

Jul 0

6

Jan

07

Jul 0

7

Jan

08

Jul 0

8

Jan

09

Jul 0

9

Jan

10

Jul 1

0


Fundamental drivers of the European natural gas market


> Regulatory decisions, market design> Production and reserves

(e.g. unconventional gas)

Fuel marketsCO2 prices Coal prices Oil pricesClimate, weather

(temperature)Economic activity

(industrial production)

Holidays

Households, commercial buildings Industry Power generation

Natural gas hub market price

Working days per week Long-term contracts (flow, price)

Global LNG production, liquefaction, shipping

Supply and demand regional markets (Asia, US)

LNG long term

LNG spot LNG regasification

Storage levels/flows

Transmission flows

Mainte-

nance/disruptions

Domestic production (flow)

> Capacities (transmission, interconnectors, storage)

> Macroeconomic developments

> Political framework

SupplyD

emand


0

50

100

150

200

250

300

350

2003 2004 2005 2006 2007 2008 2009

GASPOOL (04)PSV (03)CEGH (05) PEG (04) NCG (06) Zeebrugge (00)TTF (03)

European gas trading hubs: Increasing liquidity and market participants

> ICE/APX, London> Powernext, Paris> APX/NP-Endex,

Amsterdam> EEX, Leipzig

Natural gas exchanges

> NBP, UK> Zeebrugge, Belgium> TTF, Netherlands> Gaspool, Germany> NCG, Germany> CEGH, Austria> PEG, France> CDG, Spain> PSV, Italy

Natural gas hubs

Development of hub traded volumes (bcm)

Market shares

Q2 2010 Source: IHS CERA.

Source: IEA.

Amsterdam

Paris

Leipzig

London

NBPZeebruggeTTF

Gaspool

NCG

PEGCEGH

CDG

PSV

ExchangeExchangeTrading HubTrading Hub 74%

4%

8%

5%

1 %3%2%

3%NBPZEETTFNCG

GASPOOLCEGHPSVPEG


European gas markets converge: NBP and TTF on a comparable price level if adjusted for FX-effects

> NBP in the UK as the most liquid natural gas market in Europe is – despite low physical interconnection of the markets – basically setting the price for the continent.

> TTF in the Netherlands, and accordingly Gaspool and NCG market areas in Germany, typically follow NBP suit.

> Differences can normally be explained by transportation costs or short-term physical constraints.

NBP is the price-setter for natural gas in Europe

10

15

20

25

30

35

40

45

-8

-6

-4

-2

0

2

4

6Spread TTF/NBP (right axis)

TTF 1 year forw ard (left axis)

NBP 1 year forw ard (left axis)

Jan 06 Jan 07 Jan 08 Jan 09 Jan 10

€/MWh €/MWh

TTF 1 year forward (left axis)

NBP 1 year forward (left axis)

Spread TTF/NBP (right axis)

Jan 11


Fundamental drivers of the European coal marketSupply

Dem

andWeather impacts

Coal price


> Legislation Land preservationExport quota/tax

Marginal costs

Mining Freight

Hydro availability

Rail

Cold snap

Nuclear availability

Transport bottleneckRail Ports

Fuel markets

Oil prices Gas prices Vessel availabilityIron ore demand

Storm/flooding

> World coal reserves/production ratio


Physically traded volumes

Steam coal trading volumes, import/export volumes and trading hubs

Exchanges:> ICE> EEX> CME NymexBrokers (physical):> globalCOAL> LCB> GFI> Ginga Petroleum> ICAP> TFS> Evolution MarketsBrokers (financial):> GFI> ICAP> Spectron> TFS> T. Prebon> globalCOAL> Ginga Petroleum> Evolution Markets

Exchanges/brokers

Financially traded volumes

0

5

10

15

20

25

30

35

Jan 09 Jul 09 Jan 10 Jul 10

DES ARA

CME Nymex CAPP

0

40

80

120

160

200

Jan 09 Jul 09 Jan 10 Jul 10

Month API#4Quarter API#4Year API#4Month API#2Quarter API#2Year API#2

6

10

million t

million t

12

19

14

63

4

67 139

2333

167424

18

2966

Exports 2009 (million t)Exports 2009 (million t)

Imports 2009 (million t)Imports 2009 (million t)

C4, C7, C12: Standardised freight routesC4, C7, C12: Standardised freight routes

API#4: South African coalAPI#4: South African coal

NEWC Swaps: Newcastle (Australian coal)NEWC Swaps: Newcastle (Australian coal)

API#2: Coal delivered (including freight) to Amsterdam, Rotterdam or AntwerpAPI#2: Coal delivered (including freight) to Amsterdam, Rotterdam or Antwerp

Indo

Total: 637 million tTotal: 637 million t

NEWC Swap

API#4

API#2/ARA

C7

C4

C12

DES ARA: Fixed-price forward contract for physical delivery of thermal coal on a DES (delivered ex-ship) basis at the ports of Amsterdam, Rotterdam or Antwerp (ARA) in North-West Europe

DES ARA: Fixed-price forward contract for physical delivery of thermal coal on a DES (delivered ex-ship) basis at the ports of Amsterdam, Rotterdam or Antwerp (ARA) in North-West EuropeCME Nymex CAPP: Aggregated monthly volumes of Central Appalachian (CAPP) Coal Futures traded at CME Nymex (Chicago Mercantile Exchange / New York Mercantile Exchange)

CME Nymex CAPP: Aggregated monthly volumes of Central Appalachian (CAPP) Coal Futures traded at CME Nymex (Chicago Mercantile Exchange / New York Mercantile Exchange)


Freight rates play an important role in coal markets

> China's booming construction sector and heavy industries are consuming vast amounts of both coal and iron ore. Meanwhile, China is a net-importer of thermal coal.

> Changes in China's spot demand for international coal continue to have a large influence on international coal prices.

> Strong iron ore demand from China in 2007/08 was the largest price driver on the freight market as it targeted larger and less available ships.

> With Australia not being able to supply sufficient volumes of iron ore increasing volumes come from Brazil. This substantially lengthens journey times and ties up ships.

> The tightness resulted in record high order books of new build ships that caused an oversupply in 2008/09 and in conjunction with the economical downturn prices plummeted to record lows.

Asia's strong energy demand determines freight availability and pulls up international coal prices 1,700

500

700

900

1,100

1,300

1,500

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Oversupply230/280 ships

Supply growth Based on firm orders until

2011 and 60/65 Capes delivered p/y from 2013

onwards

Demand growth Av +7.5% p/y until 2016

Port congestion continues at 2007 levels in the future

Supply, removing 30% of orders placed at new or non existing yards

Demand with 7.5% growth

Source: ICG; IISI-Ramco; World Energy Council.

1 Sector indices of Baltic Dry Index (BDI). The BDI assesses the rates charged for chartering ships that carry major raw materials, i.e. coal. The sector indices Capesize Index, Panamax Index, Supramax Index and Handysize Index measure the different sizes of bulk vessels. These are usually divided into the smaller carriers (Handysize and Supramax) and the larger carriers (Panamax and Capesize).

Number of ships

Index points

0

5,000

10,000

15,000

20,000

Jan 06 Jan 07 Jan 08 Jan 09 Jan 10 Jan 11

Capesize Index1

Panamax Index1


The following chapter provides an overview of the gas market in Europe, the major sources, assets, players and latest developments.

Gas supply business in Europe


Some "boring" facts about natural gas

1 In its purest form, such as the natural gas that is delivered to residential homes, it is almost pure methane. H-Gas (high calorific gas) consists almost entirely of hydrocarbons (methane, ethane, propane, butane,...). L-Gas (low calorific gas) contains substantial amounts (up to 25%) of nitrogen and/or carbon dioxide, in addition to hydrocarbons.

Conversion factorsTypical composition1

0 – 0.2%O2Oxygen

0 – 5%N2Nitrogen

0 – 5%H2 SHydrogen sulphide

TraceA, He, Ne, XeRare gases

C4 H10Butane

70 – 90%

0 – 20%

0 – 8%CO2Carbon Dioxide

C2 H6Ethane

C3 H8Propane

CH4Methane Assumed calorific value of natural gas of 10.76 kWh/m3 (1,040 btu/ft3)1 billion cubic meter (bcm)

10.8 Terawatt hours (TWh) or

6.1 million barrel oil equivalent (boe) or

830,000 tonnes oil equivalent (toe) or

710,000 tonnes of liquefied natural gas (LNG) or

36.7 billion British thermal units (btu) or

35.3 billion cubic foot (bcf)

Typical composition1


113

103

45

74

133

65 LNG net import s

Ot her pipeline import s

Russia pipeline import s

NL product ion

Norway product ion

Ot her EU product ion

Main gas infrastructure (pipelines and hubs) in Europe

European gas market: The main sources and pipelines

ProposedProposed

Main (and potential) pipeline gas sources for EuropeWorld Rank Country

Proven reserves (bcm)

Production volume/year (bcm)

1. Russia 44,900 5464. Turkmenistan 8,400 36

15. Norway 2,986 10318. Kazakhstan 1,950 331

21. Uzbekistan 1,745 621

23. Azerbaijan 1,359 1324. Netherlands 1,222 74

Top 20 countries 169,000 2,570Rest of world 20,000 401World total 189,000 2,971

Supply and demand balance (533 bcm in 2009)

Source: Cedigaz; Wood Mackenzie.

Turkey

Ukraine

France

Poland

Italy

LNG regasification terminals:

Gas pipelines:ExistingExisting Under constructionUnder construction

ExistingExisting Proposed/Under constructionProposed/Under construction

1 Via Russia.

91

87

774943

186

0

200

400

600

Rest of Europe

Netherlands

France

Italy

United Kingdom

Germany

bcm

Demand Supply

Rest of Europe

Netherlands

France

Italy

UK

Germany

LNG net imports

Other pipeline imports

Russia pipeline imports

NL production

Norway production

Other EU productionProposedProposed

Nord stream pipeline

South stream pipeline

Nabucco pipeline

GermanyUK


Breakdown of supply and demand of individual European countries

2009Demand

Import (of which LNG)

Export (of which LNG) Production

Austria 9.65 7.98 (0) 0 1.67Belgium 18.54 21.54 (6.53) 2.78 (0.24) 0.02Bulgaria 2.64 2.64 (0) 0 0Croatia 2.61 1.2 (0) 0 1.41Czech Republic 9.45 9.4 (0) 0 0.05Denmark 4.44 0 4.01 8.45Finland 4.10 4.10 (0) 0 0France 49.10 49.06 (13.07) 0.84 0.88Germany 90.61 88.82 (0) 12.80 14.59Greece 2.81 2.79 (0.74) 0 0.02Hungary 11.19 8.10 (0) 0 3.09Ireland 5.40 5.08 (0) 0 0.32Italy 77.21 69.31 (2.90) 0.13 8.02Latvia 1.19 1.19 (0) 0 0Lithuania 2.77 2.77 (0) 0 0Luxembourg 1.30 1.30 (0) 0 0Netherlands 41.60 17.21(0) 49.67 74.06Norway 4.57 0 98.85 103.47Poland 11.76 7.65 (0) 0 4.11Portugal 4.41 4.41 (2.82) 0 0Romania 13.00 2.05 (0) 0 10.95 Slovakia 5.50 5.40 (0) 0 0.10Slovenia 1.00 1.00 (0) 0 0Spain 35.15 36.00 (26.44) 1.00 0.15Sweden 1.31 1.31 (0) 0 0United Kingdom 87.52 41.13 (10.25) 12.17 58.56Switzerland 3.09 3.09 (0) 0 0Turkey 28.21 28.21 (5.71) 0 0Europe 530.13 422.74 (68.46) 182.25 289.92

> Besides Norway (demand is just 5% of own production) and the Netherlands (demand is 58% of own production) all other countries depend to a large extent on imports of natural gas.

> Import dependency of large consumers like Germany, France, Italy, Spain and Turkey is at 80 –100% of their overall demand.

> Almost 100% of the surplus from Norway and the Netherlands goes to other European countries (mainly by pipeline).

> LNG imports go to a large extent to Spain (about 42% of total European LNG imports) covering more than 75% of the overall demand.

Some noteworthy facts

Source: Cedigaz.

bcm


European gas market: storage capacity per country

2009# storage

facilities

Max working volume

(million m3)

Max withdrawal capacity

(million m3/day)

Working volume/ consumption

ratio1

Deliverability/ peak demand

ratio2

Austria 5 4,530 59 48% 93%Belgium 1 625 13 3% 10%Bulgaria 1 600 4 24% 35%Croatia 1 558 5 22% -Czech Republic 8 2,891 58 33% 103%Denmark 2 1,000 25 22% 168%Estonia 0 0 0 - -Finland 0 0 0 - -France 15 12,349 218 25% 59%Germany 47 20,502 490 23% 100%Greece 0 0 0 - -Hungary 6 6,180 75 54% 68%Ireland 1 210 3 4% 16%Italy 10 13,370 281 17% 73%Latvia 1 2,300 22 230% -Lithuania 0 0 0 - -Luxembourg 0 0 0 - -Netherlands 3 5,000 146 12% 34%Poland 6 1,660 35 12% 57%Portugal 1 180 7 4% 40%Romania 8 2,910 24 22% 35%Serbia 1 300 2 13% -Slovakia 2 2,750 34 54% 78%Slovenia 0 0 0 - -Spain 2 2,376 13 7% 7%Sweden 1 9 1 1% -United Kingdom 6 3,695 83 4% 17%Switzerland 0 0 0 - -Turkey 2 1,600 5% -Europe 133 85,586 1,594

Denmark

Netherlands

Czech Republic

Switzerland

Germany

FranceAustria

United Kingdom

LuxembourgBelgium

Poland

Italy

> Large consumers like Germany, France and Italy have enough storage capacity to cover at least reasonable shares of their annual demand and the seasonal swing.

> Poor storage capacities in other large consuming countries like the Netherlands, Spain and the UK.

Storage capacity

1 Aggregated gas storage volume available [m3] / normalised annual gas demand [m3].2 Aggregated maximum gas storage release capacity [m3/h] / normalised maximum gas demand [m3/h].Source: Cedigaz Jan10.


Nigeria15%

Algeria28%

Qatar27%

Egypt10%

Others4%

Libya1%

Trinidad Tobago

10%

Oman2%

Norw ay 3%

LNG: Swing capacity for the European gas market

Breakdown of European LNG imports of 68 bcm by supplying country

Extension of regasification capacities

Distribution of regasification capacities

> Already today, LNG connects the European markets with the US and Asia.> Increasing LNG liquefaction, transportation and regasification capacity will underpin the fact

of gas being a global commodity and markets becoming more and more correlated.

Source: Cedigaz Jan10. Source: Wood Mackenzie/BCG. Source: BCG.

64 7396 103 103 111 111

2009 2010 2011 2012 2013 2014 2015

12% 14% 18% 19% 19% 20% 20%

XX% Share of total estimated demand

Isle of Grain

Rotterdam

Toscana

PanigagliaFos Cavaou

Fos Tonkin

MontoirAdriatic LNG

Zeebrugge

Existing terminalExisting terminalTerminal under constructionTerminal under constructionPlanned terminalPlanned terminal

Milford Haven

Capacity in bcm/a

Teesside

South Hook


CERA 2010

209 207 210 218 223 225 223

151 141 148 153 157 161 165

172 189 213 228 232 248 260

32323232312322

0

200

400

600

800

2005 2010 2015 2020 2025 2030 2035

Eurogas 2010

European gas demand and supply outlook

> While European resources are depleted more and more there is an increasing need for natural gas in Europe.

> Depending on political targets on CO2 reduction natural gas demand may increase by 20% until 2020 based on 2010 levels.

The need for more resources from outside Europe

EU27 Natural Gas Demand Outlook by Sector EU27 Supply Outlook

193 200 197 204 196 204 192 202

140 136 139 144 143 148 148 155

185 203 221 216 238 217 244

157

3537

373737363632

655

5441

0

200

400

600

800

2007 2015 2020 Base Case 2020Environmental

Scenario

2025 Base Case 2025Environmental

Scenario

2030 Base Case 2030Environmental

Scenario

524 558 578 608 595 630 600 642bcm

TransportationOthers (Heat Plants and Others)Power GenerationIndustryResidential & Commercial

169 123 92

102117

112

289 325330

69213 106

86

313228

1146516

423523

0

200

400

600

2007 2015 2020 2025 2030

Addit ional suppliers to be def ined – Environmental ScenarioAddit ional suppliers to be def ined – Base CaseContracted imports and possible prolongat ions from outside EuropeAvailable volumes from NorwayEU27 indigenous product ion

156

bcm

1 Assumptions: Faster economic recovery and GDP growth, more favourable energy policies towards natural gas, natural gas prices competitiveness is ensured, CO2 prices at the upper end of the assumed range.

1

1

554 561 602 631 644 666 679bcm

Source: Eurogas 2010 11

Own Use and Losses / Statistical DifferencePower GenerationIndustryResidential & Commercial


Europe's Largest Gas Companies1 (2009)

35

36

82

110

130

140

50

0 50 100 150

Gas Natural (ESP)

Wintershall (GER)

RWE (GER)

Gasterra (NED)

ENI (ITA)

GdF Suez (FRA)

E.ON (GER)

1 No information available on Centrica. 2 Standard factor: 1 TWh = 0.093 billion m3

3 Gas sales volumes and estimated gas usage in CCGTs calculated on a 40% efficiency level.Source: RWE estimates based on publicly available data.

Gas procurement volume in bcm2, 3


The following chapter provides an overview of the gas procurement portfolios in Continental Europe, how they have developed over time and which optionalities there are to hedge and optimise the portfolio.

Gas portfolio-management in Continental Europe


Gas procurement portfolios of European midstreamers consist partly of long-term gas contracts

Typical elements of long-term contracts (LTCs)

> Often oil-indexed contract prices which are recalculated every month or quarter> Term: >5 years up to 30 years> "Take-or-Pay": minimum annual volume> Volume flexibility with minimum and maximum volume per hour, per day, per year, etc.> Carry forward, make up: moving volumes from one contract year to another> Location swap: sometimes possibility to change the delivery point

Any flexibility can be seen as an option which can be executed againsta liquid gas wholesale market.


How gas portfolio management changed with the emergence of a gas-to-gas market

The old days

> Distributors closed long-term contracts:– Producers aim to cover investment cost– Linkage to substitute fuels to ensure

competitiveness of gas> Distributors have secured supply and

retained flexibility (weather dependency)> "Take-or-Pay" of typically 90%> Customer contracts priced at cost plus

The new market

> Hybrid situation:– Long-term oil-indexed gas contracts, and– Liquid markets with fixed-price gas trading

> Decoupling of supply and demand:– Managing the gas-to-oil spread– Potential to procure back-to-back

from wholesale market> Customer contracts increasingly priced

at gas wholesale price level

> Potential of price differentials between long-term procurement contracts and wholesale market prices, with risk of negative gas-to-oil spreads

> Opportunity to manage flexibilities provided in long-term procurement contracts


Midstreamers are now managers of complex portfolios rather than just the intermediary between producer and end-customer

> Low demand: due to the economic slump

> Higher supply: new gas sources, e.g. through unconventional gas (shale gas) in the US, led to more LNG on the global market

> What will trigger major changes to the current situation?– Sustainable economic recovery

in Europe– Supplier reaction (e.g. production

cuts) – Increasing demand

from Asia for LNG (new markets like India and China)

Main drivers for the current situation

Development of TTF gas price and brent oil price since January 20091

2011

2012

1 Relative development of the TTF and brent forwards for the years 2011 and 2012 since January 2009. To compare both, the brent oil price is normalised to the TTF gas price as of January 2009. The curves simply illustrate the development of the market prices which should give a rough indication about the gas-to-oil-spread situation. The real gas-to-oil-spread exposure depends on the individual contract details and will deviate from this slide.

€/MWh

05

10152025

3035

-16-14-12-10-8-6-4-2024

0

5

10

15

20

25

30

35

Jan 09 Apr 09 Jul 09 Oct 09 Jan 10 Apr 10 Jul 10 Oct 10-16-14-12-10-8-6-4-2024

Spread Crude Brent (in EUR, normalised to TTF) TTF forward


LTCs are virtually paid in oil: When gas is sold at fixed prices you have to hedge the oil risk accordingly

> When selling gas from long-term oil-indexed gas contracts to the gas wholesale market the midstream companies receive a fixed amount of money via the sold gas forward but would still have to pay a variable amount of money depending on the oil price (virtually pay in oil).

> This means: The financial short position in oil will loose on rising oil prices.

> To hedge this risk you have to buy oil swaps (forwards) from a third party (e.g. a bank) at the same time when selling the gas (e.g. at the TTF).

> This is comparable with buying hard coal forwards at the same time when selling forward electricity generation from a hard-coal fired power plant.

Producer

Hedged

TTF

Not hedged

Oil short positionMidstreamer

Third party (e.g. bank)

GasLong position

GasShort position

Fixed price Hedge via oil- swap

OilFinancial short position

Background information


After having hedged the bulk of the take-or-pay volumes there are still optionalities left to optimise (e.g. "make up")

May/June Y0 April/May Y1 LTC price 22 LTC price 24 TTF price 12 TTF price 18 Spread -10 Spread -6

Taking-off 50 units of gas in May/June Y0 would mean a loss of 50 x (-10) = -500

Through make up (explained on the right) this changes to:

Costs: 75% x 50 x 22 x 1.051 + 25% x 50 x 24 = 1,166

Revenues: 50 x 18 = 900 Loss: 900 - 1,166 = -266The advantage is 234

A simplified calculation

0

20

40

60

80

100

120

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Off-Take of Year 1 make up GasMake up Gas in Year 1Original Off-Take Shedule

On purpose, the off-take is lowered by 50 units. In the portfolio, this "hole" is filled with gas purchased at the spot market.

It is optimal to schedule the off-take of the make up in the months April and May: it requires the forward sale of gas as well as an oil hedge.

Paying 50 units at 75% of average contract price over the year

Monthly Off-Take

1 Assumed 5% cost of carry.


After having hedged the bulk of the take-or-pay volumes there are still optionalities left to optimise (e.g. "volume flexibilities")

Normal situation

> Oil-indexed contract is in-the-money in winter> And out-of-the-money in summer

Unusual situation

> Oil-indexed contract is out-of-the-money in winter

Optimising the portfolio means: Gas volumes are shifted to months were the spread is most positive (within physical constraints). These shifts are hedged via forward deals on the wholesale market.

20

25

30

35

40

Jan-

08

Mar

08

May

08

Jul-0

8

Sep-

08

Nov

-08

Jan-

09

Mar

09

May

09

Jul-0

9

Sep-

09

Nov

-09

Oil-indexed contract

TTF

20

25

30

35

40

45

Jan-

08

Mar

08

May

08

Jul-0

8

Sep-

08

Nov

-08

Jan-

09

Mar

09

May

09

Jul-0

9

Sep-

09

Nov

-09

Oil-indexed contract

TTF

EUR

/MW

h

EUR

/MW

h


RWE AG Investor Relations – Contacts

Gunhild GrieveTel.: +44 207 015 5459 E-mail: [email protected]

Judith Heise (as of 01.02.2011) Tel.: +49 201 12-15141 E-mail: [email protected]

Lars Korinth Tel.: +49 201 12-15043 E-mail: [email protected]

Dr. Stephan Lowis Head of Investor RelationsTel.: +49 201 12-15031 E-mail: [email protected]

Martin Vahlbrock Tel.: +49 201 12-15055 E-mail: [email protected]

Dr. Burkhard Pahnke Tel.: +49 201 12-15182 E-mail: [email protected]

RWE AGOpernplatz 145128 EssenGermany

Cornelia RathTel.: +49 201 12-15039E-mail: [email protected]

Contacts for Institutional Investors & Analysts

Contacts for Private Investors

Documents

Energy trading and gas supply business in Europe