centrica plc - centrica energy asset book

Centrica Energy Upstreamasset book

final book_single pages_Layout 1 30/11/2011 14:04

centrica energy upstream

Contents

Introduction 1

Our story so far 3

Our business outlook 5

Regional overview 9

Northern and Central North Sea 11

Southern North Sea 17

East Irish Sea 23

Netherlands 27

Norway 33

Trinidad and Tobago 39

Glossary 42

a real sense ofmomentumThe Centrica Energy Upstream story is a compelling one. Through the acquisition of Venture Production in 2009 we haveforged a company with exceptional strength and resilience. Our teams across six regions draw on their unique blend of expertise and experience to bring fresh thinking to the challenges of exploration and production. This enables us to succeedwhere others have been unable.

It is this pioneering spirit and dedication to high performance which has seen us mark more than 25 years of gas productionin the East Irish Sea, increase our profits in 2010 by over 30% to £566 million, achieve an enviable drilling record in the North Sea, enter the natural gas sector in Trinidad and Tobago, deliver groundbreaking projects such as the self-installingF3-FA platform and be the first to undertake horizontal hydraulic fracturing in North Sea gas wells. We have also significantlyenhanced our position in Norway through the recent acquisition from Statoil of interests in Kvitebjørn, Heimdal and Valemon.

In 2010 Centrica Energy Upstream was one of the top three producers of gas on the UK Continental Shelf, pumping 650 million cubic feet every day. We contribute a significant proportion of Centrica’s profits and, if we were a stand alonecompany, would be in the FTSE 100 in our own right.

Our commitment to finding and producing gas and oil safely, efficiently and effectively has brought significant achievementsand we plan to build on that success. We expect to drill more than 20 exploration wells in the next three years alone and,with ambitious production targets and a strategy to expand our international reach, Centrica Energy Upstream is focused on growth.

As we look to the future, we do so with a sense of purpose and adventure. Our path to long-term success is clear, and wehave great teams in place who have a proven track record of delivering outstanding results time and again.

There is a real sense of momentum in Centrica Energy Upstream and with high performance, pioneering spirit and safety atthe heart of our business, we will write a new and exciting chapter in our story.

Jonathan RogerManaging Director, Centrica Energy Upstream

“We have great teams in place who have a proven track record of delivering outstanding results time and again.”


1

our story so farCentrica Energy Upstream has enjoyed another strong year. New wells have performed better than anticipated, helping usachieve a strong production performance. Elsewhere, we have delivered an impressive exploration rate and have becomeone of the fastest growing new entrants in Norway in the last decade. Since acquiring assets in Trinidad and Tobago lastyear, we have already expanded our interests with the award of the NCMA-4 block.

Centrica Energy Performance 2010/11

Upstream overview

l 8 developments brought on-streaml 7 out of 14 exploration wells successfull Resource additions replace production

UK and Netherlands

l One of the top three largest gas producers in the UKl Most active E&A drilling programmel Largest net acreage in 2010l Awarded 7 blocks in UKCS 26th licensing roundl F3-FA came on-stream

Norway

l One of the fastest growing new entrants in Norway in the last ten years l Drilled three operated exploration wellsl Licence round application success

l Acquired equity from Statoil in Kvitebjørn, Heimdal and Valemon and further equity in Statfjord from Shell

Trinidad and Tobago

l Successfully entered a new region; acquisition completed in 2010l Progressing Block 22 development optionsl Success in 2010 licensing round with award of the NCMA-4 block

Our F3-FA platform, the largest self-installing platform in the North Sea,

is on-stream.a real sense of scale


32

We are continually investing in world-class projects

to build on our successes.a real sense of direction


our business outlookOur current portfolio will deliver a sustainable flow of gas and oil from an increasingly international mix. We are achieving this both by maximising value from our existing assets while delivering technically challenging projects, and by focusing exploration activity in known gas and oil basins using our specialist subsurface expertise.

We have investment plans that will deliver over 1.3 billion boe of production over the life of our portfolio of assets. By 2020 we aim to have produced more than 600 mmboe and invested over £7 billion.

Production in the short-term is largely provided by our 2P reserves and is supported by 2C resources and yet to findprospective resources from exploration and business development in the longer-term.

Base

2011-20 Post 2020

Production (mmboe) 345 66

Investment (£bn) 0.7 0

Current Projects

2011-20 Post 2020



Development Options

2011-20 Post 2020


Investment (£bn) 3.6 0.5

Exploration Development

2011-20 Post 2020


Investment (£bn) 2.0 4.5

Total

2011-20 Post 2020



CEU 2P Reserves

2P reserves (end 2010) 403*

2P reserves from 2011 acquisitions 117

Portfolio Unit Costs

2011 Unit Lifting Cost (£/BOE) 10.0

2011 DDA rate (£/BOE) 10.0

Anticipated total recoverable resources

*Excludes Centrica Storage Limited cushion gas (Rough field = 30.5 mmboe) and North America reserves.Also excludes 2011 production and non-acquisition-related reserves additions.

411 mmboe

450 mmboe

354mmboe

141 mmboe

54

2012 2013

0

10

20

30

40

50

60

70

80

2014 2015 2016 2017 2018 2019 2020

2012 2013 2014+

Upstream oil and gas production profile

Current Project 2P Reserves

Volume, mmboe p.a.

0

20

40

60

80

Reserves, mmboe

Ensign

Seven Seas

Rhyl

Atla

York

AnnabelEast

Kew Cygnus

Valemon


76

Base

Current projects

Development options

Exploration

Planned year of first production


regional overviewCentrica Energy is active across six regions. Each one has a portfolio of producing assets, developments (including current project activity) and exploration potential.

98

Northern and Central North Sea Centrica Energy is the operator of three production hubs in the Northern and Central North Sea area of the United Kingdom Continental Shelf (UKCS): Greater Kittiwake, Trees and Chestnut. It also has non-operated interests in the Armada and Braecomplexes and in the Skene and Buckland fields. Overall there are more than 20 producing fields in the region, mainly delivering oil and contributing about 15% of Centrica Energy’s daily production.

Centrica Energy’s focus in the area has been on improving operational performance on these maturing assets, enhancing production efficiency and reservoir performance, and subsequently extending the economic life of the fields. In addition,Centrica Energy has continued to execute an active exploration and appraisal programme, aimed at building on existing production hubs and on developing potential opportunities.

High performance,pioneering spirit and safety are at the heart of the way we work.

a real sense of energy


North & Central North Sea key metrics

2012-20 production (mmboe)* 46

Gas % 27

2011 unit lifting cost (£/boe) 13.9

2011 DD&A rate (£/boe) 10.5

*Excludes exploration

0

1

2

3

4

9

10

8

7

6

5

2012 2013 2014 2015 2016 2017 2018 2019 2020

Production from Northern and Central North Sea

Map of Northern and Central North Sea area

Volume, mmboe p.a.

Base Development options

1110

Northern and Central North Sea

Greater Kittiwake Area

Centrica Energy acquired its interests in the GreaterKittiwake Area (GKA) from TotalFinaElf in 2001 andShell in 2003. Centrica Energy now has a 50% operated interest in the five fields which make up the GKA: Kittiwake, Mallard, Gadwall, Goosander and Grouse.

When the Kittiwake platform was purchased fromShell it was producing less than 5,000 barrels a dayand was due to be abandoned in 2005. Since then aconcerted campaign of developing satellite fields andinvesting in modernised equipment has increasedproduction and extended field life beyond 2020.

Status: Producing oil.

Location: 160km north east of Aberdeen.

Production: Current daily production from the field is 23 mboe/d gross. Production has recently beenboosted by the Goosander Crestal well which cameon-stream in July 2011.

The area has been developed using a fixed steel platform on the Kittiwake field with the other fieldsbeing developed as subsea satellite tie-backs to theKittiwake platform. Oil used to be exported usingtanker loading, but since 2007 has been exported via the Forties pipelines system. Any gas not used for production purposes is exported to St Fergusthrough the Fulmar gas line.

Future plans: Further satellite prospects continue to bepursued, with plans to evaluate and drill prospects suchas Mallard South, Gadwall South and Jaeger. In addition,Centrica Energy’s prospective Bligh development could potentially utilise the GKA facilities as an export route.

Chestnut

Chestnut was discovered in 1986 by Premier Oil butnot developed due to its size and the fact that it didnot have access to nearby infrastructure. In 2003Centrica Energy acquired 70% equity in the field andbecame the operator. It was brought on-stream in2008 using the innovative Sevan Marine 300 floating production system. A further production well wasdrilled in 2009, increasing production and reserves for the field. A sidetrack of the existing water injectionwell to increase injectivity and reservoir pressure iscurrently being drilled.


Location: 200km north east of Aberdeen, 10km south of the Britannia field.

Production: Currently produces around 5 mboe/dgross. The field was developed using the Sevan Marine 300 floating production vessel, with integratedstorage and offloading capability.

Future plans: Evaluate options for a potential third producing well.

Trees

The Trees Area comprises the currently producingBirch, Larch, Sycamore Central and Sycamore Southfields in which Centrica Energy has a 100% operatedinterest. Birch, Larch and Sycamore Central are subsea developments tied-back to the Marathon- operated Brae platform. Sycamore South has beendeveloped using an extended reach well from theMarathon operated Tiffany platform.



Production: Currently produces around 2.7 mboe/d gross.

Future plans: Further development of South Sycamoreand potential prospects in the Trees area, includingthe Cedar prospect which underlies the Birch field.

Armada

The Armada area comprises three producinggas/condensate fields: Drake, Fleming and Hawkins.Centrica Energy has an 11% non-operated interest. The Armada platform also acts as a hub for a numberof satellite fields, including the Seymour and Maria fields in which Centrica Energy has non-operated equity interests ranging between 18 and 35%.

Status: Producing gas/condensate.

Location: UK Central North Sea.

Production: Currently produces around 29.8 mboe/d. Gas is exported through CATS whileheavier oil and condensates are exported through the Forties pipeline system.

Future plans: Further development of the South Seymour field and Seymour Horst is being evaluatedand further third party business will be secured fromthe Gaupe field in Norway.

Brae

The Brae complex comprises a number of fields developed using a combination of fixed platform andsubsea tie-backs. Gas is exported through the SAGEsystem and back to the SAGE gas plant at St Fergus.Centrica Energy has non-operated interests of 5% to8% in the fields in the area and 4% in the SAGEpipeline.

Status: Producing oil and gas.


Production: Currently produces around 36.7 mboe/d gross.

Future plans: Further development of the Brae fieldscontinues and further third party business continuesto be attracted to the SAGE system.


Asset CEU % Operator Status Production Reserves(Anticipated FY 2011, (End 2010

net mboe) net mboe)

Greater Kittiwake area 2,742 10,300 2P

Kittiwake 50.00 CEU Producing 74

Goosander 50.00 CEU Producing 1,553

Grouse 50.00 CEU Producing 833

Mallard 50.00 CEU Producing 232

Gadwell 50.00 CEU End of life 0

Trees area 956 4,300 2P

Birch 100.00 CEU Producing 525

Larch 100.00 CEU Producing 277

Sycamore Central 100.00 CEU Producing 135

Sycamore South 100.00 CEU Producing 19

Chestnut area 1,077 4,000 2P

Chestnut 69.88 CEU Producing 1,077

Armada area 942 8,400 2P

Armada 11.05 BG Producing 545

Maria 35.04 BG Producing 170

Seymour 18.00 BG Producing 227

Skene/Buckland area 1,797 4,400 2P

Skene 33.33 ExxonMobil Producing 624

Buckland 33.33 ExxonMobil Producing 1,173

Brae area 1,197 2,600 2P

Brae West 8.00 Marathon Producing 330

Brae NSC 8.00 Marathon Producing 214

Brae East 7.32 Marathon Producing 543

Brae Beinn 8.00 Marathon Producing 29

Braemar 5.00 Marathon Producing 79

SAGE 4.00 Mobil Pipeline & terminal N/A

Other areas 96 300 2P

Halley 40.00 Talisman Producing 96

Goldeneye 3.47 Shell End of life 0

Acorn 100.00 CEU End of life 0

Acorn 29/8b 77.62 CEU End of life 0

Producing assets

1312


Skene and Buckland

The Skene and Buckland fields are subsea developments, tied-back to the ExxonMobil-operatedBeryl complex and on through the SAGE system.Skene is a gas condensate field, while Buckland is an oil producing field. Centrica Energy has a 33.33%non-operated share in both fields and the surrounding acreage.

Status: Producing oil and gas.


Production: Currently produces around 8 mboe/d gross.

Future plans: Further development of both fields isbeing evaluated, as is the potential of other prospectsin the surrounding acreage.

Bligh, Selkirk and Christian

The Bligh field was discovered in 1995 and is a HighPressure/High Temperature (HP/HT) gas condensatefield. Christian was discovered in 1991 and like Blighis an HP/HT gas condensate field. Joint production of both fields via a subsea tie-back to Kittiwake is being evaluated. This would result in the creation of a newHP/HT operated production hub. Selkirk is a potentialsingle well subsea development to be tied-back tothe future Bligh and Christian infrastructure.

Status: Bligh and Christian are gas condensate discoveries.

Location: 200km north east of Aberdeen, close tothe Greater Kittiwake Area fields.

Future plans: A Bligh appraisal well is planned for2012 to further evaluate the field and determine potential development scenarios.


Asset CEU % Operator Status Key Milestones P50 Potential (Anticipated year) Resources

(Net mboe)

Greater Kittiwake area 6,400

Gadwall South 50.00 CEU Development option Appraisal well 2013

Mallard infill 50.00 CEU Development option Appraisal well 2013

Mallard South 50.00 CEU Development option Appraisal well 2015

Trees area 11,600

Sycamore SP5 100.00 CEU Development option

Chestnut area 2,500

Chestnut infill 69.88 CEU Development option

Brae area TBD

Brae NSC infill 8.00 Marathon Development option

Armada area TBD

Seymour Horst infill 18.00 BG Development option

Other areas 35,400

Bligh 100.00 CEU Development option Appraisal well 2012

Christian 100.00 CEU Development option

Selkirk 31.50 CEU Development option

Asset CEU % Operator Status Location P50 PotentialResources(Net mboe)

Jaeger 50.00 Dana Exploration prospect Greater Kittiwake area

Cedar 100.00 CEU Exploration prospect Trees area

Marconi 20.00 GdF Exploration prospect Central North Sea

Exploration

Centrica Energy continues to look for exploration and appraisal opportunities in acreage close to its operated production hubs in the North and Central North Sea. Additional acreage was acquired in the 25th and 26th licensing round and opportunities are beingmatured for potential drilling in the next 1 to 3 years. The table below provides an indicative programme of drilling activity.

Development opportunities

1514

15,000 - 50,000 prospective

Southern North Sea The Southern North Sea represents a growing business for Centrica Energy. Three new fields came on-stream in 2010 and significant developments are underway or planned at Seven Seas, Ensign, York and Cygnus. Centrica Energyhas also made a number of exploration discoveries over the last few years and has been awarded further acreage in recentlicensing rounds. These will in turn be matured into further development opportunities.

Centrica Energy has a broad portfolio of assets in the Southern North Sea, including 15 major producing fields, 50% ofwhich are operated. The fields have been developed using a combination of normally unattended installations and subseatie-backs. Centrica Energy’s strategy in the Southern North Sea is to maximise the value of its hubs by developing near-field discoveries and exploring near-field prospectivity.

In 2010 we were the most active exploration & appraisal driller in

the North Seaa real sense of energy


Southern North Sea key metrics


Gas % 98


2011 DD&A rate (£/boe) 13.2

*excludes exploration

0

4

8

6

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12

20

18

16

14

2012 2013 2014 2015 2016 2017 2018 2019

Base

2020

Current projects Development options

Volume, mmboe p.a.

Production from Southern North Sea

Map of Southern North Sea area

1716

Main production hubs

A Fields Area

The area comprises eight fields, four of which are operated by Centrica Energy (Ann, Audrey, Alison andAnnabel) and four of which are operated by other parties (Victor, Saturn, Galleon and Mimas). Audreyacts as the main gas processing and export hub forour operated fields, with gas exported via the LOGGS pipeline.

Status: Producing gas fields.

Location: 100km north east of the Norfolk coast.

Production: Current daily production from the area is 30 mboe/d gross (8 mboe/d net to CEU).

Future plans: An infill well at Annabel is planned for2012. In addition, the Ensign field will be developedthrough the Audrey facilities. We are also evaluating thepotential for further infill drilling at Audrey and Annabeland potential reinstatement of the Alison well.

Western Area

The area comprises six producing fields, two operatedby Centrica Energy (Eris, Ceres) and four operated by others (Amethyst East and West, Babbage andRavenspurn North). It will also include the Seven Seasproject currently under development.

Status: Mature producing gas fields, with significantdevelopment potential.

Location: 50km off the east coast of England.

Production: Current daily production from the area is20 mboe/d gross (2.8 mboe/d net to CEU). Babbageand Eris/Ceres came on-stream in 2010.

Future plans: Seven Seas is due to come on-stream in 2012 and the York development has now been sanctioned. Both assets are operated by Centrica Energy. York has additional upside potential that will beassessed once the field has come in to production. In addition, the Olympus field was discovered from an exploration well and there is further prospectivity in the area.

Southern Area

The Southern Area comprises five non-operatedfields nearing the end of their field life. It is not considered to be a core area.

Status: Mature producing gas fields.

Location: 100km east of Great Yarmouth off the Norfolk coast in the UK Continental Shelf.

Production: Current daily production from the area is1 mboe/d gross (0.2 mboe/d net to CEU).

Future plans: Extract remaining production and perform field abandonment.

Cygnus

The field was originally discovered in 1988. CentricaEnergy has a 48.75% interest. Two successful appraisal wells were drilled in 2009, confirming thepotential of the eastern field with further appraisal ofthe Western fault blocks undertaken in 2010. Thesedrilling programmes both increased the recoverablereserves for the field and confirmed Cygnus as one of the largest undeveloped gas discoveries remainingin the Southern North Sea.

Status: Undergoing appraisal and evaluating development options.

Location: 159km north east of the North Norfolkcoast.

Future plans: Centrica Energy is working closelywith the development operator GdF on determiningthe optimum development plan for the field. This islikely to involve a manned platform as a hub, with tie-backs from normally unattended installations.Once established, Cygnus can act as the export and processing hub for the greater Cygnus area.There is significant potential upside in Cygnus itselfand the surrounding exploration acreage in whichCentrica Energy has a significant interest.

Southern North Sea Southern North Sea

Asset CEU % Operator Status Production Reserves(Anticipated FY 2011, (End 2010,

mboe net) net mboe)

A Fields area 3,008 9,100 2P

Annabel 100.00 CEU Producing 636

Audrey 100.00 CEU Producing 367

Ann 100.00 CEU Producing 124

Alison 100.00 CEU Currently shut-in 0

Saturn 22.00 ConocoPhillips Producing 864

Victor 30.00 ConocoPhillips Producing 671

Galleon 8.40 Shell Producing 262

Mimas 15.00 ConocoPhillips Producing 84

Western area 1,038 13,900 2P

Eris 54.00 CEU Producing 91

Ceres 90.00 CEU Producing 95

Ravenspurn North 17.75 BP Producing 301

Babbage 13.00 E.ON Ruhrgas Producing 384

Amethyst 8.95 BP Producing 167

Rose 100.00 CEU End of life 0

Southern area 72 300 2P

Horne & Wren 50.00 Shell Producing 20

Davy East 40.00 Perenco Producing 40

Thames 10.00 Perenco Producing 12

Thurne 13.04 Tullow End of life 0

Producing assets

1918

Current projects

North West Core Area

Centrica Energy has built up a significant explorationportfolio of carboniferous gas opportunities.

Status: Exploration acreage surrounding the Pegasus prospect.

Location: 60km off the coast of Scarborough, Yorkshire.

Future plans: Centrica Energy is currently evaluatingthe area in detail and expects to drill several exploration wells in the next couple of years.

Ensign

The opportunity is operated and fully owned by Centrica Energy. Development will be by an unmannedplatform and up to 4 wells that will need to be fracturedto improve flow rates. The platform has already been installed and drilling of the production wells is currentlyunderway. First production is anticipated in early 2012.

Status: Tight gas field discovered in 1986 by Shell, but undeveloped due to the complex nature of thereservoir, now under development.

Location: North east of the Centrica Energy-operated Audrey field.

Future plans: Full field evaluation to determine potential upside once first production has commenced.

York

The opportunity is operated and fully owned by Centrica Energy. Development will be by a normally unattended installation, with five wells and gas exportvia a pipeline directly to the Centrica Storage LimitedEasington terminal. Fabrication of the platform is currently underway in Hereema’s construction yard inHartlepool and a rig has been secured for drilling theproduction wells in 2012. First gas is anticipated for Q4 2012/Q1 2013.

Status: Gas field discovered by Hess in 1993,now under development.

Location: Block 47/3, north of the Rough storage facility.

Future plans: Further subsurface appraisal and evaluation of the York field is likely to result in incrementaldrilling opportunities in the licence block. In addition, further potential exists in surround exploration acreagethat was applied for in the 26th licence round.

Seven Seas

First discovered in 1991 by Enterprise Oil. Currentlybeing developed via a subsea tie-back to the BP operated Newsham and West Sole fields, with gas export to BP Dimlington. Drilling and subsea infrastructure installation has been completed. It is now waiting on the completion of BP’s work on commissioning at West Sole for first production. Production anticipated in early 2012.

Status: Gas development underway.

Location: Block 48/7c, east of Dimlington.

Future plans: Further potential may exist in the field,which will be evaluated once the field is in production.

Olympus

Olympus was first discovered in 2010 by Centrica Energy which has 100% equity. Development optionsare currently being evaluated.

Status: Gas discovery.

Location: Block 48/12e east of Dimlington, south ofSeven Seas.

Future plans: Further potential may exist in surrounding exploration acreage.

Pegasus

Pegasus was discovered in January 2011 by CentricaEnergy. Discovery currently under evaluation, with further appraisal drilling required.

Status: Gas discovery.

Location: Block 48/13.

Future plans: Further appraisal drilling is required to complete evaluation of the full potential of the discovery.

Southern North Sea Southern North Sea

Asset CEU % Operator Status Key Milestones P50 Potential (Anticipated year) Resources

(Net mboe)

A Fields area 35,600 (inc 18,200 2P)

Ensign 100.00 CEU Current project First production 2012

Annabel East 100.00 CEU Current project First production 2013

Audrey infill 100.00 CEU Development option

Galleon infill 8.40 Shell Development option

Saturn infill 22.00 Conoco Phillips Development option

Western area 40,000 (inc 24,100 2P)

Seven Seas 90.00 CEU Current project First production 2012

York 100.00 CEU Current project First production 2013

Olympus 100.00 CEU Development option

Eris infill 54.00 CEU Development option

Babbage infill 13.00 E.ON Ruhrgas Development option

Cygnus area 51,900 2P

Cygnus 48.75 GdF Current project FID 2012

North West Core area 10,000

Pegasus 90.00 CEU Discovery

Exploration

Centrica Energy has an active exploration programme in the Southern North Sea, aimed at building on existing production hubs and adding value to recent discoveries. Centrica Energy was successful in the 25th and 26th licensing rounds and anticipates executing a number of exploration wells over the next 3 years.

Asset CEU % Operator Status Location P50 PotentialResources (Net mboe)

Endymion 90.00 CEU Exploration prospect Western area

York area exploration 100/55 CEU Exploration prospect Western area

Cygnus area exploration 48.28 GdF Exploration prospect Cygnus area

York exploration 90.00 CEU Exploration prospect North West Core area


2120


Current projects

East Irish Sea The combined fields of the East Irish Sea have been a cornerstone asset for Centrica Energy since the company was formed. The region continues to provide a significant portion of the UK’s gas supply and Centrica Energy’s assets have become a keyhub for processing third party volumes. The fields in the region are among the largest in the UK Continental Shelf in terms of remaining reserves and Centrica Energy believes there is still significant upside potential. Morecambe will continue to be acore asset for the company for many years to come.

The pioneering spirit thatruns through our business

is really paying offa real sense of adventure


0

2

4

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2012 2013 2014 2015 2016 2017 2018 2019

Base

2020


Production from East Irish Sea

Volume, mmboe p.a.

12

14

16

18

Map of East Irish Sea area

2322

East Irish Sea key metrics


Gas % 98


2011 DD&A rate (£/boe) 4.0


East Irish Sea

South Morecambe

The field was originally discovered in 1974 with firstproduction in 1985. It is entirely owned and operatedby Centrica Energy. The field is subject to PetroleumRevenue Tax (PRT).

Status: Producing gas.

Location: Situated in Irish Sea, 39km west of Barrow.

Production: Current daily production from the field is~38 mboe/d. The field has been developed usingseven fixed jacket platforms. Over 35 developmentwells have been drilled on the field. Gas is exportedvia a 39km, 36” dedicated pipeline to the terminal at Westfield Point near Barrow. The Barrow terminal isalso operated by Centrica Energy.

Future plans: A full subsurface study is being undertaken to evaluate the future potential of the field.The main focus is on improving recovery from the illite zone and potential well intervention programmesto improve current production rates. The study willdetermine if there are further infill drilling opportunitiesin the field. In addition there are a number of near-fieldexploration opportunities that are being progressed,including the Ventnor prospect.

North Morecambe

North Morecambe was discovered in 1976, with first gasin 1994. It is entirely owned and operated by CentricaEnergy. It also acts as the main producing hub for thearea. The ConocoPhilips-operated Millom and Daltonfields are tied-back to the North Morecambe platformand their Rivers field uses the North Morecambefacilities at the Barrow terminal. The Centrica Energy-owned and operated Rhyl field will also be developedvia the platform and there is further potential from other satellite fields.

Status: Producing gas field and processing hub.

Location: Situated in Irish Sea 39km west of Barrow,just north of the main Morecambe South field.

Production: Current daily production from the field is ~7 mboe/d. The field has been developed using anormally unmanned platform with gas export viapipeline to the North Morecambe terminal at Barrow.

Future plans: The Rhyl field has been approved for development and will be tied-back into the North Morecambe platform. Further potential satellite opportunities will be pursued.

Rhyl

Status: Discovered in 2009 by Centrica Energy.

Location: Situated in Irish Sea 39km west of Barrow,north of the North Morecambe field.

Background: Rhyl will be drilled and completed in2012 and tied-back to North Morecambe.

Future plans: Investigate additional opportunities atNorth Rhyl and Whitehaven.

East Irish Sea

Asset CEU % Operator Status Key Milestones P50 Potential(Anticipated year) Resources

(Net mboe)

South Morecambe area 43,000

North West Attic 100.00 CEU Development option Appraisal well 2013

Illite 100.00 CEU Development option Appraisal well 2014

North Morecambe area 16,800 (inc. 6,800 2P)

Rhyl 100.00 CEU Current project First production 2012

North Rhyl 100.00 CEU Development option Appraisal well 2012

Whitbeck 70.00 CEU Development option

Marram 70.00 CEU Development option

Asset CEU % Operator Status Location P50 PotentialResources (Net mboe)

Ventnor 100.00 CEU Exploration prospect South Morecambe area

North West Terrace 100.00 CEU Exploration prospect South Morecambe area

Whitehaven 100.00 CEU Exploration prospect North Morecambe area

Exploration

Centrica Energy has an inventory of exploration prospects in the acreage around the Morecambe fields which, if successful, will add incremental field life for the whole region. A rig has been secured for drilling a number of high value exploration and appraisal prospects in2012 and 2013. The table below provides an indicative programme of exploration drilling activity in the next two to three years.

Producing assets


2524

Asset CEU % Operator Status Production Reserves(Anticipated (End 2010,

FY 2011 mboe net) net mboe)

South Morecambe area 85,300 2P

South Morecambe 100.00 CEU Producing 12,000

Bains 86.80 CEU Producing 0

North Morecambe area 8,200 2P

North Morecambe 100.00 CEU Producing 1,900


Current projects

The NetherlandsCentrica Energy operates the Greater Markham Area (GMA) and the Northern Fields from its Netherlands office in Hoofddorp.The GMA straddles the UK and Netherlands continental shelves with the bulk of production coming from the UK side. It includes the Markham, Chiswick, Grove, Windermere and Stamford fields. The Northern Fields comprise the recently developed F3-FA field and the A15-A and B17-A discoveries.

Centrica Energy’s aim is to continue to sustain its production from the Netherlands region, while executing a number of development options which will increase the value and extend the field life of the operating hubs. The key to our successhas been leveraging maximum value from our regional expertise in carboniferous reservoirs and in project execution.

We continue to attract, select and develop

the very best peoplea real sense of pride


Netherlands key metrics


Gas % 90


2011 DD&A rate (£/boe) 13.0


0

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2012 2013 2014 2015 2016 2017 2018 2019

Base

2020


Production from Netherlands

Volume, mmboe p.a.

12

Map of Netherlands area

2726

The Netherlands

Markham

The field was initially discovered in 1987 by Ultramarand first production began in 1992. Centrica Energyacquired 37.5% equity in the unitised field in 2006through the Venture transaction. Centrica Energy isthe operator of the field and infrastructure.

Status: Producing gas field and processing hub for third party volumes.

Location: 144km east of Cromer off the Norfolk coast,the field straddles the UK and Netherlands median line.

Production: Current daily production from the field is 2 mboe/d gross (0.75 mboe/d net). The field hasbeen developed using one manned and one unmanned platform with 4 current production wells.Gas is exported via the West Gas Transport systemto the NAM-operated Den Helder plant.

Future plans: Markham field life will continue to be extended through exploiting its position as a processing and pipeline export route for the area. Future GMA development opportunities include Kew,Fulham, Arrol, and additional developments at Grove,while GMA continues to process volumes fromChiswick, Grove and Stamford.

Chiswick

The field was initially discovered by a BP consortiumin 1984, but not developed due to the complex natureof the subsurface structure. Centrica Energy acquired100% equity in the field in 2006 and proceeded toengineer a technical solution for developing the field,based on the multiple fraccing of long horizontal wells.This process is based on creating fractures in therock using proppants to increase the exposure of thewell to the surrounding formation and to make thegas flow more easily. The field came on-stream in2007 and there are now four wells operational.

Status: Producing gas field with further development potential.

Location: 144km east of Cromer, off the Norfolkcoast on the UK Continental Shelf.

Production: Current daily production from the field is 14 mboe/d gross. The field has been developedusing a normally unmanned installation, with fourhorizontal fracced production wells. The platform istied-back 19km southeast to the Markham installation,from where gas is exported via the West Gas Transportpipeline to the NAM-operated Den Helder plant.

Future plans: Further infill drilling opportunities in thenorthern part of the field continue to be evaluated. The new Kew field development scheduled for 2012 will be tied-back to the Chiswick platform.

Grove

The field was discovered in 1971 by Shell, but remained undeveloped as it was considered to be uncommercial. Centrica Energy became the operatorwhen it acquired an 85% stake as part of the acquisition of Newfield Petroleum in 2007 and then a further 7.5% from Sjoitz in 2008. The field wasbrought on-stream in 2007.

Status: Producing gas field, developed via Markham.

Location: 133km north east of Great Yarmouth offthe Norfolk coast on the UK Continental Shelf.

Production: Current daily production from the field is around 8 mboe/d gross (7.5 mboe/d net). The field has been developed using a normally unmanned installation, with five production wells. The platform istied-back to the Markham installation, from where gasis exported via the West Gas Transport pipeline to theNAM-operated Den Helder plant.

Future plans: A field study has been undertaken toassess further in-field potential and an infill well is adevelopment option for 2013. There is also additionalprospectivity in the surrounding area.

The Netherlands

Producing assets


(Net mboe)

Greater Markham area 17,800 (inc. 7,300 2P)

Kew 99.00* CEU Current project First production 2013

Fulham 90.00 CEU Development option

Grove infill 92.50 CEU Development option

Arrol infill 90.00 CEU Development option

Northern fields 2,500

A15-A 27.00 CEU Development option

B17-A 23.53 CEU Development option

Exploration

Centrica Energy will continue to build on its existing portfolio by undertaking targeted exploration in acreage around the existing producinghubs in the Netherlands region. Exploration activity will follow from the successful award of licences in the 25th and 26th UKCS licensingrounds. Centrica Energy has also been succesful in licensing applications in the Dutch continental shelf and will become operator of Blocks E1, 2, 4 & 5.


mboe net) net mboe)

Greater Markham area 8,496 47,200 2P

Markham UK 27.20 CEU Producing 198

Markham NL 10.33 CEU Producing 75

Chiswick 100.00 CEU Producing 5,362

Grove 92.50 CEU Producing 2,791

Stamford 100.00 CEU Producing 18

Windermere 20.00 RWE Dea Producing 21

J3aC 4.03 Total Producing 31

Northern fields 10,000 2P

F3-FA 58.00 CEU Producing 1,716


2928

*Awaiting unitisation - to be confirmed

Current projects

F3-FA

The F3-FA field was originally discovered in 1971 by NAM, but not developed due to geological complexity and challenging economics. Centrica Energy acquired operatorship through Venture’s acquisition of EDP’s equity in 2007 and now holds a58% working interest in the field.

Status: In production.

Location: 230km north of Den Helder in the Netherlands Continental Shelf.

Production: The F3-FA field started production inJanuary 2011 and current production from the field is9 mboe/d (5 mboe/d net). The field has been developed through a single high angle well via a self-installing movable platform with full separation,gas drying, processing and compression facilities. Gas export is via the NOGAT pipeline system back to the NAM-operated Den Helder plant.

Future plans: There are potential upside reservesbelow the current reservoir. There is also additionalprospectivity in the area.

Kew

The opportunity is operated by and 99% owned byCentrica Energy. Development will be via a single well subsea tie-back to Chiswick, utilising the original appraisal well for the development.

Status: Discovered by Ultramar in 1998 and appraised by Centrica Energy in May 2009 with the 49/c-7 well.

Location: North east of the Centrica Energy-operated Chiswick field.

Future plans: Development drilling is planned for2012, with first production in 2013.

Fulham

The opportunity is operated by Centrica Energy, whichhas a 90% interest (subject to unitisation). The likelydevelopment scenario is a normally unmanned installation with export to Markham. This would allowfor the possibility to tie-in subsequent developmentssuch as Arrol.

Status: Discovered by Centrica Energy in 2010.

Location: Block 44/28b north west of the CentricaEnergy-operated Chiswick field.

Future plans: Further subsurface appraisal and further evaluation of the Arrol discovery.

Arrol

The opportunity is operated by Centrica Energy,which has a 90% interest. The likely developmentscenario is a combined development with Fulham via a normally unmanned installation with export toMarkham.

Status: Discovered by Shell in 1987.

Location: Block 44/28a 16km North West of theCentrica Energy-operated Chiswick field.

Future plans: Further subsurface evaluation in conjunction with the Fulham discovery.

The Netherlands The Netherlands

3130

NorwayCentrica Energy sees Norway as one of the key areas for growth and as a source of long-term gas for the UK. The Norwegian business was established in 2006 in Stavanger and since then Centrica Energy has become one of the fastest growing new entrantsinto the Norwegian Continental Shelf. The business comprises producing assets, development opportunities and exploration potential.

The Centrica Energy business started with the acquisition of producing fields and discoveries in the Heimdal area in 1998. This wasthen supplemented with the acquisition of equity in the major Statfjord field. In 2011 we secured a groundbreaking deal with Statoil that covered the acquisition of Upstream assets, a long term gas supply contract and a memorandum of understanding for collaboration on future exploration activity. The Upstream assets provided us with interest in the Kvitebjørn producing field, further enhanced our equity in the Heimdal area and increased our development options, including the current Valemon project which is under development.

The Norway office has a strong focus on exploration and currently has equity in 14 exploration licences. In April 2010, Centrica Energyfound gas with its first ever operated well in Norway, discovering gas and condensate in the Fogelberg field. It has also made recentdiscoveries in the Maria and Atla (previously David) fields. The most recent success has been at the operated Butch prospect whichwas drilled in the second half of 2011 and discovered light oil. Our exploration portfolio and activity will be further enhanced as a resultof our collaboration agreement with Statoil.

We’re helping satisfy more than 25% of

the UK’s demand for gasa real sense of direction


Norway key metrics


Gas % 53


DD&A rate (£/boe) 17.7


0

5

10

15

20

30

25

2012 2013 2014 2015 2016 2017 2018 2019

Base

2020


Production from Norway

Volume, mmboe p.a. 35

Map of Norway area

3332

Producing assets


(Net mboe)

Heimdal area 18,700 (inc. 2,500 2P)

Atla 20.00 Total Current project First production 2012

Peik UK 66.67 CEU* (Enquest) Development option Operatorship TBC

Peik Norway 50.00 CEU* (Lundin) Development option Operatorship TBC

Other areas 88,000 (inc. 16,000 2P)

Maria 20.00 Wintershall Development option FID 2013

Fogelberg 28.00 CEU Development option FID 2017

Butch†

40.00 CEU Recent discovery Discovered 2011

Frigg Gamma Delta 40.00 CEU Development option

Fulia 50.00 CEU Development option

Rind 37.87 Total Development option

Kvitebjørn area 35,000 (inc. 21,200 2P)

Valemon 13.00 Statoil Current project First production 2014

Kvitebjørn Øst 19.00 Statoil Current project First production 2013

Asset CEU % Operator Status Location P50 Potential Resources(Net mboe)

Cooper 40.00 CEU Exploration prospect Norwegian Sea

PL475 Exp 20.00 Wintershall Exploration prospect Norwegian Sea

Batseba 20.00 Total Exploration prospect North Sea

Nyk 30.00 Suncor Energy Norge Exploration prospect Norwegian Sea

Exploration

Centrica Energy will continue to build on its existing portfolio by partaking in a targeted exploration programme in the Norwegian Continental Shelf.CEU currently has equity in 14 different exploration licences, both operated and partner operated, which includes two exploration licences in theNorwegian Sea that CEU was awarded in the 21st licence round. The first, an operated licence, is close to the Fogelberg discovery and the second is an extension for the Maria discovery. The table below provides an indicative programme of drilling activity in the next two to three years.


mboe net) net mboe)

Statfjord area 5,978 49,500 2P

Statfjord UK 66.66 ConocoPhillips Producing 2,824

Statfjord Norway 11.04 Statoil Producing 2,751

Statfjord Øst 5.52 Statoil Producing 172

Statfjord Nord 11.04 Statoil Producing 213

Sygna 6.07 Statoil Producing 18

Heimdal area 1,694 15,500 2P*

Heimdal 33.80 Statoil Producing 348

Vale 75.80 CEU†(Statoil) Producing 0

Skirne 30.00 Total Producing 1,346

Kvitebjørn area 90,000 2P*

Kvitebjørn 19.00 Statoil Producing

Norway

Statfjord

The field was discovered by Mobil in 1974 and hasbeen producing since 1979. By the end of 2010 thefield had produced 4,722 mmboe of oil and gas.Today the field is operated by Statoil.

Centrica Energy currently owns a non-operated19.1% share of the main Statfjord field and has interests in the satellite fields Statfjord Nord, Statfjord Øst and Sygna.

Status: Producing oil and gas. 64% of current production is liquids.

Location: Situated in the Tampen area 180km west ofSognefjord in Norway, approximately 85% of the field is in Norwegian waters and the remaining 15% in UK waters.

Production: Current daily production from the field is80 mboe/d gross. The field comprises three concretebased platforms. The UK wet gas is exported fromStatfjord via the SPUR line, into the FLAGS systemand on to the St Fergus terminal in the UK where it issold. The Norwegian part of the gas is exported viathe Tampen Link and the Segal system to St. Fergus.The oil is lifted using an offshore loading system andis then shipped by tankers.

The Statfjord facilities also process hydrocarbons andreceive tariff income from third party fields (Snorre,Statfjord Nord, Statfjord Øst and Sygna).

Future plans: The Statfjord Late Life project commenced in 2007, with the aim of lowering operatingcosts and increasing reservoir recoverability. The projectshould be completed in 2012 and includes additionalcompression facilities and upgrades to the drillingrigs. As a result the end of field life for Statfjord hasbeen extended to at least 2020.

Heimdal

Heimdal was discovered in 1972 and productionstarted in 1986. In 2000, the facilities were convertedto enable processing of third party gas and the majorityof production now comes from third party fields. Centrica Energy acquired Marathon’s equity in Heimdal, Skirne, Vale and Peik in 2008 and further increased its equity in 2011 through its acquisitionfrom Statoil.

Status: Producing gas mainly from satellite fields.

Location: Situated in the central Norwegian NorthSea, approximately 80km west of Stavanger.

Centrica Energy holds 33.8% equity in Heimdal and75.8% of Vale and 30% of Skirne, both of which aresatellites tied-back to Heimdal.

Production: Heimdal consists of two platforms, withthe satellite fields Vale, Byggve/Skirne and 3rd partyHuldra contributing the majority of current production.

Vale is a gas/condensate field developed with a single subsea well tied-back by a 16km pipeline tothe Heimdal Gas Centre. The field is operated by Statoil, but operatorship is planned to be transferredto Centrica Energy through the acquisition from Statoil.

Byggve/Skirne is a subsea development comprisingtwo wells tied-back to the Heimdal Gas centre forprocessing and export. The field is operated by Total.

Current net production to Centrica Energy from itsvarious interests in the area is around 5 mboe/d.

The Heimdal Gas Centre is an integral part of theGassled gas export system and is connected to landing points both in UK (St. Fergus) and the continent, which transports dry gas to the Draupnergas hub. Condensate is exported to Brae and onwards via the Forties line to Cruden Bay in the UK.

Future plans: An agreement has been signed to tie-in a new field development, Valemon, for the processing of rich gas at Heimdal. With start-up expected in 2014, the project will extend the life ofHeimdal by up to 20 years, as well as that of some ofthe current satellite fields. Centrica Energy acquiredequity in the Valemon development from Statoil in 2011.

Further third party processing opportunities exist, not least of which are the Atla and Peik discoveries,both of which Centrica Energy has equity interests in. Further exploration potential exists in the area, whichcould further enhance Heimdal’s status and value as the key gas export facility in the area.

Norway


3534

150,000 - 300,000 prospective

*Resources associated with 2011 asset acquisition from Statoil are from 01/01/2012, all others from 31/12/2010 †Centrica Energy to become operator subject to government approval

*Centrica Energy to become operator subject to government approval †Butch potential resources not included

Current projects

Kvitebjørn

The Kvitebjørn High Pressure/High Temperature fieldwas discovered by Statoil in 1994, with productioncommencing in 2004. The field is operated by Statoiland Centrica Energy acquired a 19% non-operated interest in 2011. Remaining recoverable reserves areestimated at over 470 mmboe gross. In addition, theValemon development will utilise Kvitebjørn’s facilitiesfor processing condensate.

Status: Producing gas and condensate.

Location: Situated in the Viking Graben, east of theGullfaks fields.

Production: Kvitebjørn has been developed using aprocessing, drilling and quarters platform. The platformis being modified for additional compression facilitiesand for the facilities tie-in requirements for the Valemondevelopment.

Condensate is exported via a dedicated 16" pipeline to the Troll Oil pipeline and then to the Mongstad terminal and rich gas is exported via a dedicated 26"pipeline to Kollsnes for gas and NGL processing. Gasis exported from there to the UK and the continent.

Future plans: Additional gas compression will comeinto effect from 2013 and the Valemon developmentwill export condensate to Kvitebjørn from 2014. Thereare also additional infill drilling opportunities, includingKvitebjørn Øst and the second stage development ofthe main reservoir itself.

Valemon

Valemon is a High Pressure/High Temperature development operated by Statoil. It will be developedusing a normally unmanned steel jacket platform, remotely controlled from the Kvitebjørn facilities. Condensate will be exported to Kvitebjørn, while richgas will be exported via the Huldra/Heimdal systemand processed at Heimdal.

Status: Project PDO approval was received in 2011and the development is currently underway, with firstproduction anticipated in 2014.

Location: In the Viking Graben, close to the Kvitebjørnand Gullfaks developments.

Future plans: Development is currently being undertaken by Statoil. All major contracts have been placed.

Atla (previously David)

Centrica Energy has a 20% interest in Atla which is operated by Total (40%) with Det Norske and Petoroowning the remaining equity. Development will be via the Heimdal Gas Centre which is close to the discovery.

Status: Gas condensate field discovered in 2010 by Total.

Location: East of Heimdal in the North Sea.Future plans: Fast track development is currentlybeing undertaken by Total via the Heimdal facility.

Fogelberg

Fogelberg was Centrica Energy’s first operated exploration well in Norway. It was drilled by the WestAlpha rig in April 2010 and was a successful discovery.Centrica Energy owns 28% of the discovery, alongsidepartners E.ON Rhurgas, Faroe Petroleum, North Energyand Suncor Energy Norway.

Status: Gas condensate discovery made in 2010.

Location: 250km North West of Kristiansund in theNorwegian Sea.

Future plans: The requirement for further appraisaldrilling activity and conceptual development optionsare currently being evaluated.

Peik

Peik is an undeveloped gas/condensate field discovered in 1985, that can be developed potentiallyvia the Heimdal Gas Centre. Operatorship of the fieldhas changed on a number of occasions in recent years,with Centrica Energy planning to assume the unitoperatorship in 2011, subject to regulatory consent.

Status: The UK and Norwegian licenses have approvedtransfer of operatorship to Centrica Energy and activities to obtain regulatory consent are ongoing.

Location: West of Heimdal in the North Sea, straddling the UK/Norway median line.

Future plans: Work has been ongoing to determinean economic development plan for the discovery. This work can now be re-focused given the recentchange in operatorship of the development.

Norway

3736

Maria

Light oil discovery made in Maria South in 2010 - net 2P reserves are 16 mmboe net to Centrica Energy. Maria is operated by Wintershall (50%), Centrica Energy is a partner with 20% along withPetoro (30%).

Status: Development project is in phase with an appraisal well to be drilled on the northern part of the structure in Q1 2012 (Maria North).

Location: Southeast of Åsgard Field in the Norwegian sea.

Future plans: The plan is to make a design conceptselection decision in the second half of 2012. Earliest production start-up is 2016.

Butch

The Butch exploration well was drilled in the secondhalf of 2011 by Centrica Energy. Centrica Energy isthe operator of the block with 40% equity.

Status: Light oil discovery made in 2011.

Location: Butch is located 220km offshore Norwayin Block 8/10, approximately 11km to the south eastof the BP’s producing Ula Field.

Future plans: Butch is our most recent discoveryand is currently being geologically side-tracked. A full technical evaluation of the data acquired is beingcarried out to evaluate the size of the discovery. Initialresults point to Butch being a commercial discovery.

In addition, part of the 2011 acquisition from Statoilwas the agreement to collaborate in future explorationactivity in Norway and the UK. It is anticipated this willresult in exploration activity in Norway, including in the Barents Sea. The scope of this activity has yet to be determined and would supplement the current exploration plans.

Norway

Development options

Trinidad and Tobago key metrics

2012-20 entitlement 55

Gas % 100


DD&A rate (£/boe) 4.6


Trinidad and TobagoCentrica Energy has built a substantial business in Trinidad and Tobago (T&T) which includes operated equity positions inBlock 22, NCMA-4, Blocks 1a and 1b, and a non-operated position in Block 2(ab) and NCMA-1.

Trinidad and Tobago is one of the most established LNG producing areas in the world. The four trains at Atlantic LNG nowconsume 2,375 million cubic feet per day (mmcfd) out of T&T’s total gas sales of 4,501 mmcfd. Historically the UnitedStates has been the predominant market for LNG from T&T, but as LNG has become a globally traded commodity, export to Asia and Europe has increased. Centrica Energy has imported four LNG cargoes from T&T since 2009 and is looking to procure more.

Centrica Energy’s portfolio of assets in T&T secures a significant share of un-contracted gas awaiting development throughexport by LNG or other routes. In addition, the exploration acreage offers significant and exciting upside potential.

Our commitment to safety and the wellbeing of our

people, communities, partners, customers and the environment is paramount

a real sense of responsibility


+tax barrel volume (mmboe)*

0

2

4

6

8

10

2012 2013 2014 2015 2016 2017 2018 2019

Base

2020

Production from Trinidad and Tobago

Volume, mmboe p.a.

14

12

Map of Trinidad and Tobago area

3938

Producing assets

Asset CEU % Operator Status Key Milestones P50 Potential Resources(Anticipated year) (mboe entitlement

+ tax barrels)

Block 22 90.00 CEU Development option FEED study 2012 138,800

(Cassra & Sancoche & Iris)

Block 1a & 1b 80.00 CEU Development option 26,900

NCMA4 80.00 CEU Development option 29,400

Orchid & Iris

Asset CEU % Operator Status Location P50 Potential Resources(mboe entitlement

+ tax barrels)

Block 2ab 29.25 Niko 3 Exploration prospects Trinidad East coast 50,000-100,000 prospective

NCMA4 exploration 80.00 CEU 2-3 Exploration prospects North Coast Marine Area 40,000-80,000 prospective

Block 22 exploration 90.00 CEU 1-2 Exploration prospects North of Tobago 20,000-40,000 prospective

Exploration

Trinidad and Tobago has a significant amount of upside exploration potential, which Centrica Energy is now in an excellent position to exploit. Seismic data has been acquired and interpreted in order to better understand and prioritise the emerging prospect inventory. The table below provides an indicative programme of drilling activity.

Asset CEU % Operator Status Production Reserves(Anticipated FY 2011, (End 2010,mboe entitlement mboe entitlement + tax barrels) + tax barrels)

North Coast Marine Area 26,300 2P

NCMA 1 17.31 BG Producing 2,620

Trinidad and Tobago

NCMA

The North Coast Marine Area Block (NCMA-1) contains four gas fields to the north of the island of Trinidad: Hibiscus, Chaconia, Poinsettia and Poinsettia Southwest. They were discovered in the late1970s/early-1980s and Hibiscus was the first field tocome on-stream in 2002. It was developed to supplygas to Atlantic LNG's (ALNG) Trains 2 and 3. CentricaEnergy has a 17.3% equity interest in NCMA-1.

Status: Gas producing field.

Location: 60km north of Trinidad in the Caribbean Sea.

Production: Centrica Energy’s entitlement share ofproduction from the field is approximately 7 mboe/d.The NCMA fields are developed using two platforms.The gas is very dry and does not require significantprocessing offshore. A 107-kilometre gas pipelineruns from Hibiscus to the Atlantic LNG (ALNG) plantat Point Fortin, where the gas is sold to ALNG's Trains 2, 3 and 4.

Block 22

Block 22 contains two gas discoveries. The first discovery, Cassra was made in 2007 and the secondSancoche in 2008, both wells being drilled by Petro-Canada. Centrica Energy is currently evaluating development options for monetising the value in these discoveries.

Status: Contains two gas discoveries and exploration potential.

Location: 25km north of the island of Tobago in the Caribbean Sea.

Future Plans: Front End Engineering & Design willcommence in 2012 and a further appraisal well is alsoplanned. The block also contains a number of otherpotential exploration prospects which are currentlybeing evaluated following the acquisition of furtherseismic data.

NCMA-4

NCMA-4 contains two gas discoveries, Orchid andIris. Centrica Energy signed a production sharing contract as operator of the block in April 2011 following success in the 2010 exploration shallowwater bid licensing round.

Status: Contains two gas discoveries and explorationpotential, with new block-wide 3D seismic data beingacquired.

Location: 50km West of the island of Trinidad andwest of Tobago in the Caribbean Sea.

Future Plans: Evaluation of development optionsand further appraisal activity is currently underway.

Blocks 1a and 1b

Block 1a contains three gas discoveries, Iguana, Zandolie West and East. Block 1b contains the Anole gas discovery.

Status: Contains four gas discoveries, awaiting development of the gas market.

Location: 20km west of the island of Trinidad.

Future Plans: To continue dialogue with NGC with a view to potentially developing the block.

Trinidad and Tobago


Anole, Iguana, E & W Zandolie

4140

glossary


2C Resources: Already discovered P50 contingent resource

2P Reserves: Proved and probable reserves

ALNG: Atlantic Liquefied Natural Gas terminal in Trindad and Tobago

boe: Barrel of oil equivalent

CEU: Centrica Energy Upstream

DD&A: Depreciation, depletion & amortisation

FEED: Front End Engineering & Design

FID: Final Investment Decision

GMA: Greater Markham Area

Lifting cost: Field operating costs, including tariff

LNG: Liquefied Natural Gas

mboe: Thousands of barrels of oil equivalent

mmboe: Millions of barrels of oil equivalent

mmscf/d: millions of square cubic feet of gas per day

Net: Centrica equity share

NCMA: North Coast Marine Area licence blocks in Trinidad and Tobago

NUI: Normally Unmanned Installation

P50 resources: Best estimated remaining life of field production from a development/opportunity

PRT: Petroleum Revenue Tax

Prospective resources: Estimated undiscovered resources from exploration

PSC: Production Sharing Contract

Remaining recoverable resources: The total estimated volumes to be produced

T&T: Trinidad and Tobago

WGT: West Gas Transport system in the Netherlands

42

Centrica Energy Upstreamasset book

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