economic report 2013

ECONOMIC REPORT 2013

10

Energy Security• Oil and gas provides some 73 per cent

of the UK’s total primary energy • Production from the UK’s continental shelf

(UKCS) satisfied 49 per cent of the country’s primary energy demand in 2011:

- 68 per cent of oil demand - 58 per cent of gas demand• In 2020, 70 per cent of primary energy in the

UK will still come from oil and gas, even if the 15 per cent target for renewable energy is met

• The UKCS has the potential to satisfy close to 50 per cent of the UK’s oil and gas demand in 2020 if the current rate of investment is sustained

• A total of 41 billion barrels of oil equivalent (boe) has so far been recovered from the UKCS, with further overall recovery estimated at 15-24 billion boe

UK Employment • The industry supported at least 440,000 jobs

across the UK in 2011• Employment is spread across the UK: - Scotland – 45 per cent - South East England – 21 per cent - North West England – 6 per cent - West Midlands – 5 per cent

For more information about Oil & Gas UK, the voice of the UK’s offshore oil and gas industry, please contact:

Jenny Stanning 01224 577337 [email protected]

Andrew Bassett 020 7802 [email protected]

Economic Contribution • Over £300 billion in production related

corporate tax has been paid to the Exchequer in over 40 years since production began

• The industry paid £11.2 billion in corporate tax on production in 2011-12, almost 25 per cent of total corporation tax received by the Exchequer

• The wider supply chain is estimated to have contributed another £6 billion in corporation and payroll taxes

• Production of oil and gas boosted the balance of payments by some £40 billion

• The supply chain added another £6 billion in exports of goods and services

• The UK offshore oil and gas industry remains the largest investor and the largest contributor to national gross value added among the industrial sectors of the economy

www.oilandgasuk.co.uk@oilandgasuk

ECONOMIC REPORT 2013 3

Contents

1. Foreword 4

2. Industry at a Glance 6

3. Oil and Gas Markets 10

4. TheUK’sContinentalShelf 14

5. CaseStudiesofNewInvestment 34 – Cygnus and Montrose-Arbroath

6. Fiscal Policy 42

7. TheSupplyChain,EmploymentandSkills 48

8. EnergyPolicyandSecurityofSupply 60

9. Appendices 70a. Oil & Gas UK’s Membership 71b. Field Allowances 72c. GlossaryofTermsandAbbreviations 73


1.


Oil & Gas UK’s Economic Report 2013isthedefinitiveguide to the performance of the offshore oil andgas industry in the UK, regarding its investment, production and overall economic contribution.Working with data from our wide and growing membership – currently over 370 companies,including all the leading players in the industry – and the Department of Energy and Climate Change (DECC), this report provides insights into the current health and future prospects of this crucial sector of Britain’s economy. 2013marks25yearssincethePiperAlphatragedy,ananniversarywhichpromptsustoreflectonandrededicate ourselves to the cause of safety. The Cullen Inquiry and consequent report transformed the approach to oil and gas safety in the UK’s waters.However, at thePiper 25Conferenceheldin June of this year, at which Lord Cullen gave the keynote speech, we reminded ourselves that there is absolutely no room for complacency, that very importantchallengesstillremainandthatwemustdedicateourselvestocontinuallyimprovethesafetyperformance of this industry. Ibelievethatthesamecanbesaidofouroperationalgoals. In this report you will find evidence of arenewed commitment by the government and the industrytotheextractionofoilandgasfromtheUK’sContinentalShelf(UKCS).TheCoalitionGovernmenthas takensomesignificantandpositivestepsoverthe past two years. New and much needed tax allowances have boosted investment in oil and gas productionby£6billionover2012and2013;totalinvestment isexpectedtoreachanall-timerecordof £13.5 billion this year. Furthermore, the muchneeded certainty provided on decommissioning tax relief will release additional funds for futureinvestment.Partlyduetothesefiscalimprovements,explorationactivityisnowalsoincreasingwhich,inturn, boosts the prospect of more discoveries and hencemore indigenous productionof oil and gas.But the improving business environment needs to be sustained and enhanced over the coming decades so that this industry can support the economic wellbeing of this country and its energy security.

Both the British and Scottish governments haverecognised the substantial contribution made byour industry’s world class supply chain and its great potential for growth in domestic and overseasmarkets. This supply chain now contributes £27billionayeartotheeconomy,about£7billionbeing in exports. The UK is a world leader in subsea engineering, capturing 45 per cent of the globalmarket, and the well services companies are generatingthehighestgrossrevenuessincerecordsbeganin1996.Britain’sfabricatorshavemeanwhilebeen integral to the construction of around 6.5million tonnes of concrete and steel structures installedontheUKCStodate.

The industrial strategies launched by both governments set a strong framework for increased investment, improved application of newtechnology, growth in exports of goods and services and, as a result of all of these, yet more jobs to add to the450,000which this sector already supportsthroughout the economy. There is indeed much more that needs to be done. Despite impressive investment in new developments, theproductionefficiencyofexistingassetshasbeeninworryingdecline,withanumberoffields failingto produce as expected. DECC and the industry are working to tackle this serious concern through a joint task group. We were also encouraged when, in June, EdwardDavey,theSecretaryofStateforEnergyandClimate Change, commissioned an independently led reviewof the recoveryof theUK’soffshoreoiland gas. We very much look forward to seeing the recommendations of the Wood Review early in2014.Unlocking the fulleconomicpotentialof theUKCSwillrequireboththeindustryandgovernmenttoplaytheirrespectivepartstothefull.

Malcolm WebbChiefExecutive,Oil&GasUK

July2013

1. Foreword


2.


SecurityofSupply • Currently, oil and gas provide some

73 per cent of the UK’s total primaryenergy, with oil for transport and gas for heatingbeingdominantinthesemarkets.

• In 2030, 70 per cent of primary energyin the UK will still come from oil andgas, according to the Department of Energy and Climate Change’s (DECC) latestprojections.

• If the current rate of investment issustained, the UK’s Continental Shelf(UKCS)hasthepotentialtosatisfycloseto50percentoftheUK’soilandgasdemandin2020(>50percentforoil,<50percentfor gas).

EconomicContribution• Production of oil and gas boosted the

balanceofpaymentsbysome£32billion.• The supply chain in the UK generated

more than £20 billion of sales from theUKCS.

• Another £7 billion of supply chain saleswere in the export of goods and services.

• Offshore oil and gas remained thelargest investing sector and the largestcontributortonationalgrossvalueadded(GVA) among the industrial sectors of the economy.

Oil and Gas Prices• ThepriceforBrentoilaveraged$112per

barrel, less than 50 cents higher than2011’saverage.

• Theoilpricepeakedat$128perbarrelinMarch2012,beforeslippingtoaminimumof$89perbarrelat theendof Juneandthen recovering again.

• The day-ahead gas price at the NationalBalancingPoint(NBP)wasrelativelystablethroughout theyear,averaging60penceper therm, although it did spike to almost £1perthermon7February2012becauseof supply constraints in mainland Europe caused by extremely cold weather.

• Thecombinedoilandgasprice forUKCSproduction was, on average, $89 perbarrel of oil equivalent (boe).

Production• Productiondeclinedby14.5percentfrom

2011 to 567million boe, or 1.54millionboe per day.

• TheUKremainedthethirdlargestproducerof gas, and second largest producer of oil in Europe. The UK also remained in the top25globalproducersofbothoil(20th)andgas(23rd)despitethesharpdeclineinproductionoverthelasttwoyears.

2. Industry at a Glance

ThefollowingsummarisesthekeyfindingsofOil&GasUK’sEconomic Report 2013. Figures below referto2012,unlessotherwisestated.


TotalExpenditure(in2012money) • Total expenditure on theUKCSwas over

£20billionforthefirsttimeinitshistory.• Since 1970, the industry has spent over

£500billionby:o Investing £317 billion in exploration

drillingandfielddevelopmentso Spending £183 billion on production

operationso Spending£2billionondecommissioning

assetsthathaveceasedproduction

Taxation• Theindustrypaid£6.5billionincorporation

taxesonproductionin2012-13.• Whilst subdued production and record

investment have driven tax revenues down in theshort-term, thecontributionfromoilandgasproductionwasstillover 15 per cent of the Exchequer’s totalreceiptsofcorporationtax.

• The wider oil and gas supply chain isestimated to have paid an additional £5billionincorporationandpayrolltaxes.

CapitalInvestmentonDevelopments• Capital investment reached £11.4 billion

as the development of a number of large projects continued and other smalleropportunities were incentivised by fieldallowances.

• Oil & Gas UK predicts that capitalinvestment will reach a record of £13.5billionin2013.

• Over 2011 and 2012, 45 projects havebeen approved by DECC which require capital expenditure of the order of £22billion,yieldingovertwobillionboeofproductionovertime.

• Total capital investment committed toprojects already in production or underdevelopment totalled £44 billion at thestart of 2013, £13 billion higher than 12 months earlier.

OperatingCosts• Total operating expenditurewas ten per

centhigherthanin2011,at£7.7billion.• Unitoperatingcosts continued to rise to

anaverageof£13.50($21.50)perbarrelasproductioncontinuedtofallandspendingon asset integrity and rejuvenationincreased.

Reserves• Almost42billionboehasbeenrecovered

fromtheUKCSsofar.• Furtheroverall recovery is forecasttobe

intherangeof15to24billionboe.• Consideringthefullrangeofopportunities

available, current investment plans have thepotentialtodeliver11.4billionboeintotal,asfollows:o 7.4billionboe fromexistingfieldsor

those currently under developmento Four billion boe from incremental

andnewfielddevelopments (notyetapproved)

• Total expenditureof up to £1,000billion(in2012money)willberequiredovertheremaininglifeoftheUKCS,ifrecoveryistoreach the upper end of the forecast.


NewDevelopments• Ninenewfieldscameon-stream,bringing

146millionboeintoproduction.• DECC approved 21 new projects, as

well as eight substantial, incrementalredevelopments.

• 55percentoffieldsapprovedinthelastfiveyearshavebeenorwillbedevelopedassubseatie-backstoexistinginfrastructure.

DrillingActivity• The number of wells drilled (including

sidetracks)was:o 26explorationwellso 25appraisalwellso 122 development wells

• Whilstdrillingfiguresimprovedfrom2011,they are still below the average for thelast ten years. They need to rise further to avoidlosingsubstantialpotentialreservesfromtheUKCSas infrastructurestartstobe decommissioned.

• Explorationdrillingisexpectedtopickupfurtherin2013with37wellsplannedforthe year.

• Appraisal drilling of 18 to 20 wells isexpectedin2013.

Employment• The industry supported some 450,000

jobs, many highly skilled, across the whole economy,with:o 36,000 employed by operating

companies (12,500 ofwhomworkedoffshore)

o 200,000employedinthesupplychain(45,000ofwhomworkedoffshore)

o 112,000 in jobs induced by theeconomic activity of the aboveemployees

o 100,000 in the export of goods andservices

Decommissioning• Some475installations,10,000kilometres

of pipelines, 15 onshore terminals and5,000 wells will eventually have to bedecommissioned.

• Decommissioningexpenditurewasaround£500millionandthatislikelytorisetoanaverage of £800-1,000 million per yearduring the rest of this decade.

• From2013throughto2040,£31.5billionisforecast to be spent on decommissioning ofexistingassets.

• Newinvestmentinprobabledevelopmentswould add £3.5 billion to the total,although much of this will be incurred after2040.

Editorial Notes:• AGlossaryofTermsandAbbreviations is

included in the Appendix.• Thedraftingofthisreportwasundertaken

duringJuneandJuly2013.


3.


Oil Markets

Oil prices in 2012 were characterised by ashort-term peak followed by an even shorter trough during the first half of the year andsteadiness for the second half of the year. Overall, although world demand for oil edged upwards, with demand in OECD1 countries falling and non-OECD rising, there has been notable consistency during the past two years in the price of Brent crude oil, the main ‘marker’priceintheAtlanticbasin(seefigure1).

The average price was $112 per barrel in2012 (versus $111 in 2011), to the nearestwhole numbers. However, if measured with greaterprecision,thedifferencebetweenthetwowasevensmaller: lessthan50centsperbarrel. The maximum was $128 per barrelin March and the minimum $89 in June.Sincethebeginningof2013,thepricehasfallenby about ten per cent and, in recent months, has largelyoscillated in the rangeof$100 to$105 per barrel, but with a slight increaseevidentatthetimeofwriting,inJuneandJuly,owingtorenewedpoliticalturmoilinEgypt.

Worthnoting is thecomparisonofoilpricedin dollars and pounds sterling which obviously reflects movements in exchange rates(seefigure2).Inparticular,thepriceofBrentin sterling has been largely constant over most of the past two years, apart from the brief excursionsinMarchandJune2012mentionedabove,atatimewhenworldwidedemandhasbeen creeping steadily upwards (to an average of 90 million barrels per day (bpd) in 2012.Forcomparison,itwas80millionbpdin2003).

3. Oil and Gas Markets

Figure 1: Brent Oil Price, January 2008 to June 2013 (in money of the day)

Figure 2: Annual Brent Price since 1965, £/barrel versus $/barrel (infl ati on adjusted)

1 ThemissionoftheOrganisationforEconomicCo-operationandDevelopment(OECD)istopromotepoliciesthatwillimprovetheeconomicandsocialwell-beingofpeoplearoundtheworld.Thirty-fourcountriesaremembersoftheorganisation.Moreinformationcanbefoundat:htt p://www.oecd.org

0

20

40

60

80

100

120

140

160

Jan

08M

ar 0

8M

ay 0

8Ju

l 08

Sep

08N

ov 0

8Ja

n 09

Mar

09

May

09

Jul 0

9Se

p 09

Nov

09

Jan

10M

ar 1

0M

ay 1

0Ju

l 10

Sep

10N

ov 1

0Ja

n 11

Mar

11

May

11

Jul 1

1Se

p 11

Nov

11

Jan

12M

ar 1

2M

ay 1

2Ju

l 12

Sep

12N

ov 1

2Ja

n 13

Mar

13

May

13

Bren

t Oil

Pric

e ($

/bbl

)

Source: EIA

Brent Oil Price ($/bbl)

0

20

40

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100

120

1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

Oil

Pric

e Co

mpa

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(201

2 Pr

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) Brent Price ($/bbl)

Brent Price (£/bbl)

Source: EIA, Bank of England

Source:EIA

Source:EIA,BankOfEngland

12

Meanwhile, the gap between Brent and lower priced West Texas Intermediate (WTI) crude oils has narrowed from its range of $10 to$20perbarrelinrecentyearstolessthan$10perbarrel.Variousnewprojectsaredivertingsupplies away from Cushing, Oklahoma, where the price of WTI is set, with WTI rising towards Brentandthedifferencenarrowingtoaslittleas$3perbarrelinJuly2013.

Notwithstandingtheabove,severalsignificanttrendsarebecomingestablishedinoilmarkets:• In OECD countries demand is falling, while

itcontinuestoriseinnon-OECDcountries.• As a result of shale oil and oil sands,

production in North America is rising,reversing a previous, long term decline.

• Middle Eastern oil is increasingly servingtheAsia-Pacificregion,withlessgoingtotheAtlanticbasin.

Gas Markets

The consequences of Japan’s Fukushima disaster, following an earthquake in March 2011, continue to be felt in Europe’s gasmarkets. Demand for liquefied natural gas(LNG) remains high in Japan as a result of most of its nuclear power stations beingclosed (although its current government has indicated that it wishes to re-open a number of them).ThisledtoareductionofLNGcargoesarriving in western Europe during the winter of2012-13,whenitwasnotonlycoolerthanin the previous winter, but was characterised by a particularly cold ending, with demandfor gas at mid-winter rates throughout March and into early April. This raised gas prices at Britain’s National Balancing Point (NBP) andother trading hubs in the EU, such as the Netherlands, Belgium and Germany.


Figure 3: Wholesale Gas Price at the NBP in Great Britain, January 2008 to July 2013

-

20

40

60

80

100

120

Jan 08 Jul 08 Jan 09 Jul 09 Jan 10 Jul 10 Jan 11 Jul 11 Jan 12 Jul 12 Jan 13 Jul 13

Penc

e pe

r The

rm

Source: Heren Energy

Day Ahead Price

2012 Fwd Price

2013 Fwd Price

0

2014 Fwd Price

13

Figure3showshowday-aheadpricesroseattheNBP in late 2012 and into 2013, havingbeen steady throughout 2011 andmuch of2012, as winter’s higher demand and thearrival of fewer LNG cargoes took effect.The cold end to the winter 2012-13 putconsiderable strain on storage stocks and caused the largest flows ever through theInter-Connector pipeline between Belgium andBritain,withmorethan70millioncubicmetresperdayflowingonanumberofdays.This clearly demonstrated the value of an open and competitive market at the NBPandhow important the liberalisationof theEU’smarketingasis. Itwouldbedifficulttoimaginesuchflowsoccurringatshortnoticewithoutthebenefitsofliberalisation.

Incontrast,USgasprices,whilerisingslightly,have remained at a substantial discount tothose in Europe, with all the competitiveadvantagesthisentailsfortheUSA’seconomy.

Within mainland Europe, several buyers have successfully challenged the operation ofthe oil indexation of prices under long-termcontracts and obtained discounts as a result. Nonetheless, it would appear as though the underlying pricing structures mostly remain in place, albeit with the formula having been adjustedtoreflectmorecloselyopenmarketconditionsatthetradinghubs.However, it isunderstood that many long-term Norwegian gassupplycontractshavebeenre-negotiatedtoreflectmarketconditions.

According to the European Commission, about halfoftheEU’sgasconsumptionin2012wassupplied under oil indexed contracts, with north-west Europe being considerably more liberal(about70percentopenmarketpricing)than central Europe (less than 40 per cent).The story of oil indexation and its expecteddecline in the EU would appear to have further to run, therefore.



4.


DevelopmentoftheUKContinentalShelf

In the 1960s, thediscoveryof natural gas inthe southern North Sea (SNS) was the firststepinthedevelopmentofanoffshoreoilandgasindustryintheUK.Overthepast45years,42 billion barrels of oil equivalent (boe) have been recovered from the UK’s ContinentalShelf(UKCS). Asaresultoftheearlydiscoveries,productionofgasbeganin1967fromtheWestSolefieldand other gas resources were developed rapidly in the late 1960s and early 1970s,with various large fields such as Leman,Indefatigable and Hewett being quicklybroughton-stream.ItwasnotuntilDecember1969 that oil was discovered further northin the central North Sea (CNS) and shortlyafterwards in thenorthernNorth Sea (NNS).ThefirstoilwasproducedfromtheArgyllfieldin June 1975. Large, iconic oil fields such asForties(alsoin1975),BrentandBeryl(1976),and Ninian (1978) commenced productionover the next few years.

After the first exploration successes, theensuing surge in activity led to more than 25 billion boe being discovered by the mid-1970sand,todate,almost55billionboehavebeendiscoveredinmorethan400fieldsacrosstheUKCS.Justunder300oftheseareinproductiontoday,includingthefirst,WestSole,leaving about 100 not yet developed, someof which may never be so for technical and commercial reasons. Whilst it is anticipatedthatproductionfromtheBrentfieldwillceasein about the middle of this decade, many of these early large fields remain in productionand there are even plans afoot to redevelop

smaller,oldfieldssuchasArgyll,whichceasedproductionin1992andisnowrenamedAlma.

The industry has three main goals in the coming years. These are to: continue to explore forand make new discoveries, increase the rate ofrecoveryfromexistingfieldsandextendtheproductive life of the existing infrastructure,all in a safe and environmentally responsible manner.

Figure 4 overleaf shows that, as the UKCShas matured, the rate of discovering new resourceshasslowed,yetsignificantvolumescontinue to be found. Even since the turnof the century when production peaked, 4.1 billion boe of recoverable reserves have been discovered. These discoveries vary in size with some, such as the Buzzard fielddiscovered in 2001, nowbelieved to containmore than 700 million boe of recoverablereserves.However,findssuchasBuzzardarerare and discoveries have typically been much smallersince2000,withthemediansizebeingjust ten million boe.

TheregiontothewestofShetlandisthelatesttobedeveloped,withproductiononlybeginningin1997.Already,sevenfieldsof100millionboeormoreinsizehavebeendiscovered;itistheareaof theUKCSthat isbelievedtohavethemost undeveloped resources. The gap between the volumes discovered and produced (see figure 4) has convergedinrecentyearsasproductionfromtheearly,largefieldscontinues,albeitatdecliningrates,and new discoveries are being developed with the benefit of the extensive infrastructureavailablethroughouttheNorthSea.

4.TheUK’sContinentalShelf


However, there are still a significant numberof discoveries which have taken a long time to be developed, either because oflimitations in prevailing technologies, a lackof local infrastructure or marginal economics. ClairandMarinerareexamplesoffieldsthatwere first discovered in the late 1970s andearly 1980s, but were not developed untilmore than two decades later, after newtechnologies became available.

ThedynamicsoftheUKCSintheearlydaysofproduction were very different from today.Throughout the 1970s and 1980s, a smallnumber of very large fields dominated UKCSproduction,whereastoday’sproductioncomesfromamuch largernumberoffields,mostofwhich are considerably smaller in size.

Figure5demonstratesthiseffectforoilsinceproductionbeganin1975.Thisisnotunusualfor a maturing oil and gas province. The biggest and easiest reservoirs are found and developed first,with laterandsmallerdiscoveriesoftenbeing tied back to existing infrastructure.Whilethisisoftenanenablingfactorbecauseitmakesthenewfieldeconomic,itmeansthattie-backsaredependentontheperformanceofanolder,hostinstallation,therebyaddingadegreeofcomplexitytotheoperation.

Targetedpoliciesdrivethepaceofdevelopment

Much of the newer resources are to be found in high pressure high temperature (HPHT),heavy oil, and deep water fields. However,many of the technologies required to recover these resourcesare stillunderdevelopment.If technology continues to advance at therate experienced over the last 40 years andif commodity prices remain high, the share of productionfromsuchdemandingreservoirsisexpected to increase in future.

Figure 4: Cumulative Resources Discovered and Produced

Figure 5: Oil Production by UKCS Field

0

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1967

1969

1971

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1981

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1985

1987

1989

1991

1993

1995

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2001

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Billi

on b

oe

Resources Discovered

Production

Source: Wood Mackenzie

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1975 1978 1981 1984 1987 1990 1993 1996 1999 2002 2005 2008 2011

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Source: DECC

Source:WoodMackenzie

Source:DECC


As well as the rate of technical change and oil andgasprices,governmentpolicy,particularlyfiscal policy, has also affected the pace ofdevelopment.Figure6showshowindustryandgovernment are working together, under the auspicesof the task force,PILOT.Theoverallintentionistoensurethattherightpoliciesarein place and are being implemented to achieve maximum economic recovery of oil and gas fromtheUKCS.

For more information about PILOT and itswork, please refer to the sub-section belowentitled‘TheRoadto2040’.

RemainingResourcesandReserves

Oil and gas extraction from the UKCS hasprovided the economy with energy supplies,

highly skilled and paid jobs, and more than £300billion(in2012money)totheExchequerin production taxes over the past 45 years.During this period, 42 billion boe of oil and gas have been produced, but there is still asignificant resource of some 15 to 24 billionboe left to be developed. This will requirefurther exploration activity and increasedinvestment,inbothexistingandnewfields.

About 7.4 billion boe should be produced from existing fields and new projects that havealready been sanctioned. This can be seenas the lowest likely figure for reserves, thatis the oil and gas which have a greater than 90 per cent chance of being recovered. Inreality, it is highly likely that there will be furtherinvestmentontheUKCSand,therefore,more reserves recovered.

Figure 6: Policies to Increase Recoverable Resources

Aim Policy WorkGroup

IncreaseReservesDiscovered SmallFieldAllowanceOil & Gas UK Economic & Fiscal Forum

PILOTExplorationTaskForce

IncreaseRecoveryfromExistingAssets Brown Field AllowanceOil & Gas UK Economic & Fiscal Forum

PILOTIORandEORWorkGroups

CommercialisationofMarginalDiscoveries All Field Allowances Oil & Gas UK Economic & Fiscal Forum

Extending the Life of Infrastructure Infrastructure Code of Practice(ICoP) PILOTInfrastructureAccessGroup

IncreaseProductionEfficiency AssetStewardship PILOTProductionEfficiencyTaskForce

PromotingInvestmentandPostponingDecommissioning

Fiscal Certainty on DecommissioningRelief Oil & Gas UK Economic & Fiscal Forum


If companies invest in projects which they deemtohaveagreaterthan50percentchanceof being developed (‘probable reserves’), as is reasonablyexpectedwiththepassageoftime,afurther2.5billionboeofoilandgaswillberecovered. Additionally, there are resourceswith,currently,alessthan50percentchanceof being developed (‘possible reserves’). These accountforafurther1.5billionboe,althoughmanyoftheseprojectsaretechnicallydifficultand/or marginal in commercial terms, hence their classification as ‘possible’. The totalresources in companies’ plans, ranging from producingfieldstopossibleneworbrownfielddevelopments, is 11.4 billion boe.

The latest figures from the Department ofEnergy and Climate Change (DECC) show a range for potential additional resources(PARs) of 1.5 to seven billion boe and yet-to-findresources(YTF)ofsixto17billionboe. However, Oil & Gas UK has taken a more conservative position, reflecting theuncertainties in these ranges,andbelieves itismoreprudenttoconsiderPARsintherangeofonetofourbillionboeandYTFresourcesofthree to nine billion boe. The forecast of total

UKCSreservesandresources,asattheendof2012,isdepictedinfigure7.Whileitindicatesthepotentialrangeineachcategory,cautionis required in its interpretationand it shouldnot be assumed that the top of each range will be achieved.

None of these can be realised without substantialexpenditure.Ifthe11.4billionboein companies’ current plans are to be realised, around£300billion(intoday’smoney)willberequired:• £100 billion of capital investment to

developbothgreen-andbrown-fields.• £160 billion to operate these assets

throughouttheirproductivelives.• £35-40billiontodecommissionthemafter

productionhasceased.

Significant additional investment will berequired ifPARsandYTFresourcesaretoberecovered from theUKCS. This isbecauseoftheneedforfurtherextensiveexplorationandthe fact that unit costs of development and operation are now approaching £30/boe asreservesbecomemoredifficulttoextract.

Figure 7: Forecast of UKCS Reserves and Resources (as at the end of 2012)

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15

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Source: DECC, Oil & Gas UK

Yet To Find3-9 bln boe

Potential AdditionalResources

1-4 bln boe

Possible Reserves1-3 bln boe

Probable Reserves2-4 bln boe

Existing Fields and Sanctioned Investments

7.4 bln boe

Produced in 2012


Oil&GasUKestimatesthattotalexpenditureof£600-1,000billion(in2012money)willberequiredoverthelifeoftheUKCS,ifrecoveryistoreachthehigherfiguresintheforecasts.

However, investment is not the only factor that willinfluencethelongevityoftheUKCS.Whilstsanctioned investments already guaranteethe industry will be active for another15to20years,thefutureto2050andbeyondis reliant on a number of determinants, such as commodity prices, cost inflation,rate of technical improvement, access to infrastructure, fiscal policy, and supply chaincapacity and capability. As long as the UKCScontinues to be a competitive oil and gasprovince in which to invest, Oil & Gas UK believes that up to some 24 billion boe of resources remain to be recovered (towards the higher end of these various projections) andtheindustrywillbeactivebeyond2050.

Production

In 2012, 1.54 million boe per day (boepd)wereproducedfromtheUKCS,14.5percentlessthanin2011.Thiscomparesunfavourablywith an average annual reduction of aboutnine per cent a year over the previous decade (showninfigure8).

Furthermore,the14percentreductionin2012followedoneof19percentin2011,resultingina30percentreductionoverthecourseofthelasttwoyearsandthelowestproductionsince 1977. Figure 9 illustrates how numerous fieldshavecontributedtothisdecline. The 19 per cent decline during 2011 wasthe largest recorded for the UKCS sinceproductionpeakedattheturnofthecentury,with 230 fields accounting for a 542,000boepd reduction.Many of these are naturaldeclines on account of ageing, but ten large fieldsmadeup37percentof the reduction:of the ten, Buzzard, North Morecambe and

Figure 8: The UKCS – A Decade of Declining Producti on

Figure 9: Producti on Losses since 2010 (with the ten largest contributors highlighted by

more densely shaded bars in each column)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Oil

and

Gas

Pro

duct

ion

(Mill

ion

boep

d)-19.2%

-6.5%

-14.5%

-9.4%

-5.1%-4.6%

-9.6%-10.1%

-8.7%

Source: DECC / Oil & Gas UK

230 fields produced less in 2011 than they

did in 2010

93 fields produced more in

2011 than they did in 2010

239 fields produced less in 2012 than they

did in 2011 82 fields

produced more in 2012 than they

did in 2011


Actual Production

02010 2011 2012

1.5

1.7

1.9

2.1

2.3

Mill

ion

boep

d

Source:DECC,Oil&GasUK



Brent had lengthy maintenance shutdowns, Goldeneye ceased production in preparationfor its role in a carbon capture and storage project,Rhumhadbeenshut forgeopoliticalreasons (and remains so) and Gryphon’s floating production, storage and offloading(FPSO) vessel had to undergo substantialrepairs following damage in bad weather. Fortunately, 93 fields increased their outputrelative to 2010, which meant that the netdeclinefor2011was413,000boepd.

In 2012, 239 fields produced 470,000 boepdlessthanin2011.Thisdeclinewasdominatedby ten fields which eclipsed the positivecontributions made by the 82 fields thatincreased their output. A gas leak at Elgin in the centralNorthSea(CNS)duringMarchandthesubsequentclosureoftheSEALpipelinehadasubstantialeffectonproductionfortheyear;thesevenfieldsfeedingintotheSEALpipeline,including Shearwater, produced 126,000boepdlessthanin2011,or41percentofthenetdeclinebetween2011and2012.

The fields that increased production were amixtureofexistingandnewones.Ninefieldsstarted production in 2012, although withrelativelymodesttotalreservesof146millionboe. These included Islay, Wingate, Bacchus and Devenick, but their impact was too small tooffsetthedeclinefromexistingfields.Thisoffsettingeffectwouldhavebeen largerhadthedatesforthestartofproductionnotbeenlater than anticipated for some fields. The

likely reasons underlying the limited reserves broughton-streamin2012arethepoorresultsfrom exploration drilling in recent years andanunexpected tax increase in2006,with itsadverseeffectsoninvestment.

Some key fields, such as Buzzard, emergedfrom lengthy, planned maintenance periods and provided a timely boost to productionin 2012. Meanwhile, the Sean gas fieldincreased its output as it came to the end of itsproductioncontractwhichhadpreviouslykept it in a reserve role.

In 2013, there are 15 fields anticipated tocome on-stream (with combined reserves of 470millionboe).AsOil&GasUKforecast inFebruary, production in 2013 has continuedto decline and, using the latest available data (totheendofMay),theindicationsarethatitistowardsthebottomofourpredictedrange,namely 1.4 million boepd. If this rate were maintainedfortherestoftheyear,productionwouldbe8.5percentlowerthanin2012.

However, maintenance is concentrated in the summer months and so, although the decline willbeoffsetinpartbythereturntoproductionof the Elgin and Franklin fields and Banffand Gryphon FPSOs and by new productioncomingon-stream,notablytheJasminefieldinthe fourth quarter of the year, Oil & Gas UK’s updated forecast is for production to be intherangeof1.2to1.4millionboepdfor2013overall(seefigure10opposite).


Figure 10: Actual and Forecast Production from 2005 to 2017

Figure 11: Production Efficiency of the UKCS

50

55

60

65

70

75

80

85

90

2004 2005 2006 2007 2008 2009 2010 2011

Prod

uctio

n Effi

cien

cy (%

)

SNS and IS

CNS

NNS and WoS

UKCS Average

Source: DECC

Lookingtothemid-termfuture,productionisexpectedtobesimilarin2014beforeimprovingagain, potentially rising towards two millionboepd in 2017. This potential reinforces theneed to improve production efficiency (seebelow)andthesignificanceoftheworkofthegovernment-industry task force, PILOT (see‘TheRoadto2040’onpage31)andtheWoodReviewmentionedintheForeword.

ProductionEfficiency

Production efficiency – the ratio of actualproduction to the maximum potential – fellto63per cent in2011,witha further fall toabout 60 per cent expected in 2012 whenall data are available. Paradoxically, thiscame against a backdrop of high oil prices, record capital investment and man-hours expendedoffshore.

Average production efficiency of the UKCSwas in the high 70s of per cent just fouryears ago and around 80 per cent seven to eight years ago. The recent decline has resulted from deteriorating reliability,with extended maintenance shutdowns, compounded by several major productionoutagesmentionedabove.

Had such efficiencies been maintained in2012, production would have been almosthalf a million boepd higher. The government and industry are working together to combat the various issues affecting productionand are charting a course to return to such overallefficiencies.

Source:Oil&GasUK

Source:DECC

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

2005 2007 2009 2011 2013 2015 2017

Mill

ion

boep

d

Actual Production

Source: Oil & Gas UK

Forecast Range


ExpenditureandInvestment

In 2012, total expenditure exceeded£20 billion for the first time in the historyof the industry in theUK (measured in 2012money, that isadjusted for inflation).Afterareasonably flat period during the 1990s andearly2000s,expenditurehasnowrisenbyanaverageof16percentayearforthelastfouryears.Whileexpenditureonoperations(opex)and exploration and appraisal (E&A) drillinghaverisensteadilyoverthattime,itiscapitalinvestment (capex) that is responsible for the majority of the increase.

The offshore oil and gas exploration andproduction industry continues to be thelargest investing sector and contributor tonational gross valueadded (GVA)among theindustrial sectors of Britain’s economy.

CapitalExpenditure

Figure 13 opposite shows a time series ofcapital investment over the life of the UKCSsince 1970, adjusted for inflation (basedon general inflation across the economy2). In today’smoney, £270 billion of capital hasbeen invested in developing fields over thepast45years.

Having started in the shallow waters of the southern gas basin, large amounts of capital were spent as the industry found and developed oil fields in the deeperwaters oftheCNSandNNSduring the1970s, reachingover£11billionin1976.Anumberofverylargefields were brought rapidly into production,but the pace of development then slowed throughthe1980s,reflectingthetechnicalandeconomic challenges arising from the building

Figure 12: Total Expenditure on the UKCS

2 Inreality,theindustry’sinflationhasbeengreaterthaninflationinthewidereconomyoverthelast40years.Howeverthereareinsufficientdatacollectedtopresentareliabledeflatorfortheindustryonitsown.

0

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£ Bi

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, 201

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2005 2006 2007 2008 2009 2010 2011 2012 2013


andcommissioningof thefirst generationofdeepwaterplatforms,highmarginaltaxratesand, subsequently, falling oil prices, with capex decliningsharplytoaround£4billionin1987.

There was another surge of investment at the end of the 1980s and into the early 1990s,as the industry responded to meet more stringenthealthandsafetyregulationsintheaftermathofthePiperAlphadisaster.Severalnew fields were also developed and someearly,largefieldsunderwentre-development.However, with low oil prices and high costs, capital investment declined again in the late 1990s and early 2000s, as many investorsconsidered the UKCS to be a less attractivedestination for their capital compared withotheropportunitiesaroundtheworld.Despitetheoilpricetreblingbetween2003and2008,investmentontheUKCScontinuedtoremainrelativelyflatuntil2009.

In 2012, capital expenditure rose to£11.4billion,andOil&GasUKbelievesthatitwill increasebya further£2billion, reaching£13.5billion in2013.This rateof investmenthas not been seen since the mid-1970sand capital expenditure this year is almost certain to be an all-time record (but subjectto the caveat in footnote 2). This represents a step-change in activity for an oil and gasprovince that had not previously seen capital investment above £7 billion since the early1990s. Five main reasons have identifiedbehindthisrecentincrease:

a. A new wave of investment in a smallnumber of large fields – 30 per cent ofthe capital in 2012 (almost £3.5 billion)was spent in just four fields. Eightdevelopments approved by DECC since the beginning of 2010 have a projectedcapital investmentofover£1billioneach(see figure 14). Capital in such projectsistypicallyspentoverathreetofiveyearperiod and Oil & Gas UK’s analysis suggests

Figure 13: A History of Capital Investment on the UKCS (2012 money)

Figure 14: Total Field Investment by Year of Approval

0

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1970

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2005 2006 2007 2008 2009 2010 2011 2012 2013

Tota

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ital I

nves

tmen

t in

the

Fiel

d (£

Bill

ion)

Year of Field Approval Source: DECC, Oil & Gas UKSource:DECC,Oil&GasUK



that the year-by-year expenditure on these developments peaks in 2013.

As well as these large developments, there has been investment in a stream of smaller, new projects in recent years and many more incremental developments have been approvedin2012and2013asaresultofthenewly introduced Brown Field Allowance.

b. RenewedconfidenceontheUKCSamongthe major companies – the amount of capital that the majors3 have invested ontheUKCShasmorethantrebledfrom2009 to 2013 (see figure 15 opposite).This represents a significant change ofattitude. The companies had previouslybeen rationalising and reducing theircommitments, but, having streamlined their portfolios, they are now investingheavilyagaininlarge,newandbrownfielddevelopmentson theUKCS, especially tothewestofShetland.

c. The impact of field allowances – to the benefit of the wider industry and theExchequer, field allowances are nowmaking many marginal investments possible following their introductionin 2009 and subsequent expansion(for details, please refer to figure 48 inthe Appendix). During 2012 and 2013,Oil&GasUKexpectsmorethan£6billionof capital to be spent on fields that arein receipt of field allowances. For manyofthesefields,anallowancehasenabledinvestment that would not otherwise have happened under prevailing market conditions.

d. Asset integrity and rejuvenation – Oil & Gas UK has noted that companies areadoptingamoreriskaverseattitudetooperationssincetheMacondoincidentin

theGulfofMexico inApril 2010.Around£1 billion was spent on asset integritywork in 2012 and the same is expectedin 2013. Although this expenditure doesnot immediately yield additional barrelsof oil or gas, companies can expect these assets to be more reliable and, therefore, experience less downtime over theremainderoftheirproductivelives,whichmay well have been extended as a result.

e. The extraction of more technicallychallengingreservesleadingtoincreasedcapital intensity – as the UKCS hasmatured, the reserves which were easiest to recover have already been extracted. More recently, advances in technology, higherpricesandanevolvingfiscalregimehave enabled companies to develop oil and gas inmore technically challengingfields.A wide variety of HPHT, heavy oil andvery deep reservoirs, as well as difficultshallow water gas fields, have begun tobe developed.

Theconsequencesofthisactivityforunitcosts are shown in figure 16. Over time,projects approved by DECC are becoming significantly more expensive to developper barrel recovered. Each pound of capital investedontheUKCSnowyieldsonlyonefifth of the oil and/or gas it did in 2002.Therefore, investment would have to be fivetimeshigherthan in2002toachievethesameoutcome,asaresultofinflationof capital costs and the complexity of the reservoirs. This concept of capital intensity is becoming a crucial measure for the future health of the province.

3 Forthispurpose,Oil&GasUKhasdefinedmajorsasBP,Chevron,ConocoPhillips,ExxonMobil,ShellandTotal.


Figure 15: Investment in Assets Operated by the Majors as a Proportion of Total Investment

Figure 16: Average Annual Unit Development Costs for Projects Approved since 2005

0

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18

2005 2006 2007 2008 2009 2010 2011 2012 2013

Aver

age

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nit D

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osts

(£/b

oe)

Year of Project Approval

Unit Development Cost (£/boe)

(to 1 July)Source: DECC, Oil & Gas UK

Exponential Trendline


After this current wave of investment, it isanticipated that capital investmentmay fallto around £8-10 billion a year from 2015(in 2012 money). However, were the rateof investment to be below this, at around £6-8 billion per annum, it would probablybe insufficient to sustain current rates ofproduction and the programme of workson asset integrity. On the other hand, if investment were to rise significantly aboveits current rate, it would apply additionalinflationary pressure, as the capacity of the supply chain would become yet more stretched.

It is expected that a number of large new field developments of at least 100 millionboe of recoverable reserves will materialise in the coming years, including Rosebank,Bressay and further development of the

Clair field. Additionally, there is a reneweddrive to recover more from existing fieldswhich should ensure the UKCS remainshealthy. This is being achieved through improved reservoir management, enhanced oilrecovery(EOR)andothersuchtechniques,togetherwith continued investment inmanysmalleropportunities.Allthiswillneedtobesupported by the necessary investment to extendthelifeofcriticalinfrastructure.

OperatingExpenditure

The costs of operating the fields and theirassets across the UKCS totalled £7.7 billionin2012,anincreaseoftenpercentfromtheprevious year. A further ten per cent increase is expected in 2013, such that Oil &GasUKestimatesthattotaloperatingexpenditurewillreach£8.5billionfortheyear.

Figure 17: Rise in UKCS Operating Costs

3

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Operating costs have risen by around90percentsince2000.Adjustingforinflation,the increase isonlyaround50per centoverthe last 13 years, or about 3.5 per cent ayear, representinggoodcostcontrol fromanoverall perspective. This increase has beenconsistent over the last decade, excluding a dip after the financial crisis in 2008 and2009. Keeping operating costs under controlis a considerable achievement for the industry, given the need to maintain ageing assets to satisfactory standards4 and the worldwide competition for resources,especially skilled people.

While growth in operating costs has beenfairly well contained, the unit cost per barrel produced has risen much more, particularlyin recent years as production has declined.Theunitoperatingcost(UOC)hasrisenfour-

fold over the past decade, a worrying trend that could have a major influence on thelongevity of the UKCS. Lower production isproviding constant upward pressure on UOCs, alongside the recent increase in expenditure on asset integrity.

The range of UOCs for individual fieldson the UKCS is very wide, from less than£5/boe all the way up to around £70/boe.ThereareseveralfieldsontheUKCSthatnowcostmorethan£40/boetooperate.Oil&GasUKhasfoundthatmuchofthecostescalationisconcentratedinasmallnumberoffields,butthe general trend for UOCs is rising markedly and this will not change unless the decline in production is reversed. If thereweretobeafall in commodity prices, the more expensive assets would have to be shut down and could face premature decommissioning.

Figure 18: Unit Operati ng Costs for the UKCS, 2001 to 2013

4 MoreinformationaboutassetintegrityandtheHealth&SafetyExecutive’sKeyPerformance4(KP4)programmecanbefoundat:htt p://www.oilandgasuk.co.uk/asseti ntegrity.cfm

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LicensingandDrilling

a)Exploration Anactiveexplorationmarket remainscrucialto thesuccessof theUKCS;without it, therecan be no long-term future for oil and gas production.Since2000,358explorationwellshavebeendrilled, resulting in4.1billionboeof reserves being discovered with a median discovery size of ten million boe.

Despite the high volume of reserves already recovered, the UKCS still has substantial oiland gas resources and exploration potential. Oil & Gas UK believes that between three and nine billion boe have yet to be discovered (see figure 7 on page 18). At the current rate ofdrilling,itisestimatedthatitwilltakesome20yearsand250to500wellstoexploreforandfindthese resources, the recovery of which will rely, to a large extent, on the availability of existinginfrastructure.

Exploration and appraisal (E&A) drillingincreasedoverall in2012,with24exploration(14in2011)and19appraisal(16in2011)wellsbeing drilled, together costing £1.7 billion.These numbers exclude sidetracks of which therewere two exploration and six appraisalwells in 2012. Despite this increase in E&Adrilling, the industry is struggling to reach the ratesof2007and2008.

Exploration drilling activity, averaged overthe past four years, has been the lowest for a decade, with 2011 being notably low. This can partly be blamed on the economic crisisandlimitedaccesstofinanceforsmallerexplorationcompanies.

Figure 19: Forecast Distribution of Yet-to-Find Resources

13%

48%9%

22%

9%

NNS

CNS

SNS, Irish Sea and Celtic Basin

West of Shetland

West of Scotland

Source: DECC


Figures 20 and 21: Exploration and Appraisal Wells Drilled, including Sidetracks, 2003 to 2012


Furthermore, theperiod2009to2012sawadecoupling of the relationship between theoilpriceandthenumberofexplorationwellsdrilled. During this period, the number of wells drilled was consistently below average, despite a generally high oil price. It is evident that exploration drilling is responsive toboth oil price and fiscal shocks. Figure 22shows that there was almost no time lagbetween the sudden increases in tax rates of 2002, 2006 and 2011 and the fall in drillingfigures; exploration capital is very mobile and so can be quickly moved to other parts of the world. Encouragingly, surveys conducted by Oil & Gas UK indicate a positive outlook for2013 to 2015, with operators forecasting apotentialof37explorationwellstobedrilledin2013.Despiteatighteningrigmarket,roughly85per centofexplorationwells and100percent of appraisal wells to be drilled this year havesecuredfirmrigslots,providingadditionalconfidenceintheforecast.Explorationactivityis expected to peak in 2014, with 53 wellsforecast to be drilled. Even if 80 per cent ofthesearedrilled,2014wouldseethehighestrateofexplorationsince2008.

b)ExplorationandAppraisalExpenditureE&A expenditure typically corresponds to the number of wells drilled, but is also directly linkedtotheriseandfalloftheinternationaldrillingrigmarket(seefigure24opposite).

In 2009 and 2010, a similar number ofwellsweredrilledto2006,buttheamountspentwasnearly double, demonstrating an escalationin costs. Then, in 2011, the number ofwellsdrilled decreased, despite a further increase in expenditure. The rise in expenditure in 2012,though,wasmainlyduetoan increasein exploration drilling compared with 2011.It is anticipated that there will be a furtherincreaseinexpenditurein2014tonearlythreetimesasmuchaswasspentin2011.

Figure 22: Relationship between Exploration Drilling and the Oil Price

Figure 23: Forecast of Exploration and Appraisal Drilling


Source:Oil&GasUK,WoodMackenzie,EIA

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Total Exploration Wells

Oil Price (2012 Money)

Tax IncreaseSCT Introduced

Tax Increase

Tax Increase

Small Field Allowance Increased

Financial Crisis -Decoupling of the

Relationship between Oil Price and Drilling

Small Field Allowance Introduced

Source: Oil & Gas UK, Wood Mackenzie, EIA


c)LicensingOver the past 49 years, there have been 27 Licensing Rounds with the 28th Roundexpected to be launched in January 2014.DECC issued a total of 167 new licencescovering330UKCSblocks in the27thRoundofOctober2012.Thiswasthelargestnumberin the history of offshore exploration in theUK and it is anticipated that the increasedinterestinLicensingRoundswillhelpstimulateexplorationactivityintheyearstocome.

SeventypercentofallE&Awellsdrilledin2012were in acreage that was awarded in Licensing Rounds22to26(of2004to2010),yetonlyfourpercentwere inacreageawarded inRounds17to21(of1996to2003).Thiscontrastcouldbe a direct result of the changes to licensing terms in 2002, which increased pressure onoperatorstofulfilcertaindrillingrequirementswithinafouryeartime-frame.

Around 17 per cent of wells drilled were in acreage obtained in Rounds 1 to 4 (of 1964to 1972), demonstrating that companies arerevisitingoldandpreviouslyexploredacreageusing improved seismic imaging and/or prospects have become commercial because of the proximity of surrounding infrastructure. Constraints on access to finance for smallercompanies and a tight drilling rig markethave heightened uncertainty and pushed companiestodeveloplowerriskopportunitiesthathaveanumberofinfrastructureoptions.

Only nine per cent of wells drilled in 2012were in acreage awarded in Rounds 5 to 16 (of1976-1995),raisingthequestionofwhetherornot theacreageawarded in thoseRoundshas been fully exploited to date.

The Road to 2040

Sinceproductionpeaked in theyear2000, theoffshoreoilandgasindustryintheUKhasentereda mature phase and its outlook has changed. In

Figure 24: Exploration and Appraisal Expenditure versus Number of Wells Drilled

Figure 25: Drilling Activity in 2012 by Licensing Round

Source:Oil&GasUK


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recent years, most new developments have not involved the construction of large, newproduction platformswith their own pipelinesto shore. Instead, the tendency has been to use existing infrastructure for new developmentswhich has two main benefits: it extends theinfrastructure’s lifeandallowssmallerfields tobe developed economically.

Today,mostnewfieldsaresmallwhencomparedwiththeearlygiantssuchasLeman,FortiesandBrent. Also, remaining reserves are increasingly difficultandcostlytoextract.Asaresult,therehas been a drive to make the industry more cost effective, without compromising safety or theenvironment,sothattheUKCScancontinuetowin investment for new projects.

PILOT, the government and industry taskforce,was formed inearly2000todevelopanappropriate strategy for delivering a sustainable, long-termfuturefortheUKCS.Itwasbornoutofacrisis.Asoilpricesfellto$10abarrelattheendof1998,allstakeholdersintheoffshoreoiland gas industry realised that powerful factors outside their control could jeopardise the contributionthatitmakestotheeconomy.

PILOT is a unique arrangement between theindustry and government, uniting seniormanagement in operators, contractors, suppliers and relevant government departments who are working co-operatively to deliver quickerand smarter solutions aimed at securing themaximum economic recovery of the country’s oil andgasresources.ThiswasandremainsPILOT’soverall objective. Itmeets twice a year and ischairedbytheSecretaryofStateforEnergyandClimateChangeandincludesaround13industryrepresentatives, as well as representatives of government.

Now in its 14th year, PILOT covers mattersrelatingtoallphasesoftheoilandgaslifecycle,fromexploration,developmentandproductionthrough to decommissioning. The task force

promotes initiatives to reduce costs, eliminateun-necessary barriers and maximise the effectivenessof resources.Thegoal is tobringabouta future thatcouldstill see the industrymeeting approximately half of the nation’s oilandgasneedsin2020.

Through its various initiatives, PILOT has beenextremely influential inadvisingandsupportingboth government policy and industry practicesand has had various successes as a result of its innovativeandco-operativework.Theseinclude:

• Attracting new players and globalinvestment – a diverse range of new players has entered the province which has led to moresmallfieldsbeingdevelopedandtheintroductionofnewtechnologies.

• Stimulating activity – the Fallow initiativehasplacedstillprospectiveacreageintothehands of companies that want to develop it.

• Enabling access to infrastructure – companies are able to negotiate withowners for access to production facilitiesand pipelines for processing and transport of oil and gas. This has typically enabled subsea tie-backs of small fields to establishedinfrastructurehubs,althoughtherearestillvarious challenges in this regard.

• Improvingstewardship – an ability to analyse thoroughlythepotentialofproducingfieldshas been created, through techniques such asinfillandnear-fielddrilling,togetherwitha more transparent mechanism for the sharing of infrastructure data.

• Facilitatingnewtechnology – the Industry Technology Facilitator (ITF) has been established to foster innovation andpromote the development and use of new technologies.

• Training and skills – the industry workforce has increased by 100 per centthroughout the life of PILOT, and the oiland gas academy, OPITO,was established.


• Exports – there have been more exports by the industry thananticipatedand theUK’ssubsea sector is renowned for its excellence around the world

• Investment – investment has exceeded expectations in recent years, because ofhigheroilpricesandtheremainingpotentialoftheUKCS.

Thematters addressed by PILOT are aimed attheoverallobjectiveofrecoveringthemaximumamount of the UK’s oil and gas resources that can beeconomicallyachieved.However,thespecificmattersbeingaddresseddochangeastheyearsgoby.Currentlytheseare:

• DeclineinexplorationIn response to the sharp decline in exploration drilling in 2011 (see page 28),PILOT’sExplorationTaskForcewascreatedtoidentifythemainobstaclestoexplorationdrilling and to determine what government andindustrycoulddotoincreaseactivity.

• Improved/enhancedoilrecovery(IOR/EOR)As oil and gas become more difficult andcostlytoextract,theindustryisinvestinginimprovedmethodsofextraction.Asaresult,IORandEORworkgroupswerecreatedtoundertakeaformalanalysisofthebenefitsofusing new technologies to increase recovery fromtheUKCS.

• InfrastructureaccessPILOT’s Infrastructure Access Groupwas formed in 2012 and has three areasof work: the Infrastructure Code ofPractice5 (ICoP), criticality of infrastructureand transformational options forcriticalinfrastructure.

One of the recommendations of thisgroup was to establish areas of ‘special economic interest’ on the UKCS toencouragegreaterco-operationbetweenparties, targeting critical infrastructurehubs to promote maximum economic recovery. Work groups have been established that are looking at specificinfrastructure issues in the northern and centralNorthSea.

• ProductionefficiencyAsaresultoftherapiddeclineinproductionefficiency(seepage21),PILOThaslauncheda Production Efficiency Task Force thatis challenging the industry to increase efficiency from 60 per cent to nearer80percent.

• Technology Technical innovation and application canand will play a major part in enhancing the future of the UKCS by improvingexploration success, increasing recoveryandsafelyextendingthelivesoffields.Therange of technologies required is broad with the required funding, policy and supply mechanisms complex. Therefore, PILOThascommissionedthecreationofaTechnologyStrategy tohelpestablish theUK as a leader in selected areas of oil and gas technology, thereby strengthening the supply chain.

The success of past PILOT initiativeshas demonstrated the willingness of governmentandtheindustrytofindsolutionsto difficulties in a co-operative manner.There will be a continuing need towork together toensure that theproductivelifeoftheUKCSstretchestoatleast2050.

5 To ensure that new and smaller companies can develop and bring on-stream discoveries which require use of others’ infrastructure, the industry developedaCodeofPracticeforthirdpartyaccesstoinfrastructure,knownasICoP.Adoptedin2004andupdatedsince,theICoPoutlinesthebestpracticeandexpectedbehaviourofthosewhoconductnegotiationsforaccesstoinfrastructure.MoreinformationaboutICoPmaybefound at htt p://www.oilandgasuk.co.uk/knowledgecentre/InfrastructureCodeofPracti ce.cfm


5.


Introduction

The special tax regime which applies to the UKCS has undergonemany changes since itsinceptioninthemid-1970s,notleastinMarch2011. It is clear that the regimewill have tobe refined further in the years to come toensure that the overall objective, shared bygovernment and the industry, of recovering as much oil and gas as is economically possible fromtheUKCSisachieved.Sincetheshockof2011’staxrises,muchworkhasbeendonebyboth HM Treasury (HMT) and the industry to findwaysofhelping to stimulate investment in technically difficult and economicallymarginal fields; investment that would nototherwise happen.

Two such projects which have benefitedfromnewlyintroducedtaxreliefs,calledfieldallowances,areoutlinedbelow,thefirstbeinga greenfield development (Cygnus) and thesecond brownfield (Montrose-Arbroath). Itshould be emphasised that field allowancesonlyeasethetaxburden;theydonotremoveit.AnexplanationofhowUKCSproductionistaxed and how these allowances are applied is giveninSection6.

GDFSUEZE&PUK’sCygnusDevelopment

GDFSUEZE&PUKLtd isbecomingoneoftheleading,newoperatorsinoilandgasexplorationandproductionontheUKCSandisfocusedongrowth in three core areas: the central andsouthernNorthSeaandwestofShetland.

Since entering the UK in 1997, the companyhas built a substantial portfolio of assets inthese areas, comprising almost 50 licences,18asoperator.Withmorethan300staffandcontractors based in London and Aberdeen, the operator recently underlined its commitmenttotheUKCSbytakinga15-yearlease on a new building in Aberdeen which will becompletedin2014.

GDF SUEZ E&PUK is operator of theCygnusdevelopment, with partners Centrica and Bayerngas UK. Cygnus is one of the most significant undeveloped gas fields in thesouthern North Sea (SNS) and the sixthlargest field in the UKCS by remaining gasreserves. The company is also operator of the Juliet gas field in the SNS, a subsea tie-backdevelopmentwithfirst gas due in late 2013,and has an exciting portfolio of discoveriesandexplorationprojects inthecentralNorthSeaandwestofShetland.

5.CaseStudiesofNewInvestment:Cygnus and Montrose-Arbroath Fields


Cygnus is the largest gas discovery in the SNSduringthelast25years.Theprojecthasreached development thanks to innovativegeological and technical thinking by operator GDF SUEZ E&P UK and also because of atax relief for large, shallow water gas fieldsannouncedbythegovernmentinJuly2012.

The partners are investing approximately £1.4billionintheproject,ofwhichmorethan80percentisbeingspentintheUKwiththecreationof4,000directandindirectjobs.Firstgasfromthefieldisexpectedtobeproducedinlate2015.Itwillmeetthedemandofnearlyone and a half million homes at the plateau of its production in 2016, when it will bethe second largest gas producing field andaccount for aroundfiveper centof theUK’sgasproduction.

The development concept comprises two drilling centres. The central production,processing and accommodation facilities

consistofthreebridgelinkedplatforms(AlphaProductionandUtilities (PU),AlphaQuartersandUtilities(QU)andAlphaWellheadPlatform(WHP)) located on Cygnus East. The seconddrilling centrewill be a satelliteWHP (BravoWHP)locatedapproximatelysevenkilometresnorth-west of Alpha on Cygnus West and will be tied back to the Alpha PU via a 12 inch pipeline.

There will be compression facilities situatedonAlphaPU inorder tomeet thefield’s fullproduction potential. The Bravo WHP willbe a ‘normally unattended installation’ andthe gas export route will be via a 24 inch, 55 kilometre pipeline connected to theEsmondTransmissionSystemandthroughtothe onshore gas terminal at Bacton in Norfolk.

GDFSUEZE&PUKisalignedwithOil&GasUKintheindustrybody’sconstructiveengagementwith HMT and DECC. This dialogue has resulted in a range of tax measures, such as the small

Figure 26: Field Layout of the Cygnus Development


fields and high pressure, high temperaturefieldallowances,whichhaveenabledinvestorsto take a fresh look at the economic viability of projectsontheUKCS.

The tax relief to support large shallow water gasfieldsprovided theCygnuspartnerswiththecertaintyandconfidencetoproceedwiththe project which was sanctioned in August2012.Induecourse,productionfromCygnuswillgeneratesubstantialtaxrevenuesfortheExchequer,aswellascontributingsignificantlyto the balance of payments, security of supply and jobcreation.GDFSUEZE&PUKbelievesthat it is important that the right investment andfiscalregimeexiststohelpmovepotentialnew projects through to their development.

Leading edge geophysics and a successful appraisal programme have been central to the progress of Cygnus since GDF SUEZ E&P UK

became operator in 2002. The company hastransformed a small discovery into the largest gasdevelopmentintheSNSduringthelast25years. Cygnus also faces technical challenges because of its shallow water location. Thislimits the number of vessels that can work in suchwater depths which in turn affects theweight and size of the platforms. In deeperwater,anumberoftheseplatformscouldbecombined. The large areal extent means that a minimumoftenlongwells(upto18,000feet)withhorizontalsections(upto3,500feet)havetobedrilledtoreachthemultiplereservoirs.

By drawing on international knowledgewithin the organisation, applying bespokedrilling techniques and revitalising existinginfrastructure, GDF SUEZ E&P UK aims toensure that Cygnus is a North Sea successstory set to secure future energy supplies.

Figure 27: Cygnus Milestones

• 1988 and 1989: Blocks including the Cygnus fieldwere drilled by other operators, butwere not pursuedbecauseinitialevaluationsuggestedapoorqualityreservoir

• 2002:GDFSUEZE&PUKacquiredthelicencefortheblocks

• 2003:Theappraisalprogrammebeganwiththefirst3DseismicsurveyintheSNSusingwhatwasthennewlong cable technology

• 2006: First appraisal well drilled

• 2009:Plansweredrawnupforarelativelysimpledevelopment;however,otherpartsofthefieldshowedmuchbetterreservoirquality.Twofurtherappraisalwellsweredrilled.

• 2010:Anothertwoappraisalwellsdrilled,confirmingawesterlyextensionwithgoodqualityreservoirdeliveringhighflowrates

• 2011: Extended development concept for Cygnus selected

• July 2012:ShallowwatergasfieldtaxallowanceintroducedbyHMTreasury

• August 2012:Projectsanctioned

• September 2012: The Chancellor of the Exchequer, George Osborne, visited Heerema yard in Hartlepool for ceremonial contract signing

• December 2012: First steel for the project cut at Heerema, Hartlepool

• May 2013:FirststeelcutforthefourjacketsatBurntislandFabricators,Fife


Figure 28: Cygnus Project – Locations of Principal Contractors

FactorsforSuccess

• Innovative geological thinking combined withleading edge geophysics

• Along-termperspectiveonE&Aactivity• Subsurface knowledge sharing between GDF

SUEZ E&P affiliates in the UK, the Netherlands and Germany

• Applicationofhigh-tech3Dseismictechnologytocapture previously unseen images

• Applicationof drilling techniques for fine grainedreservoirs

• Revitalisationofexistingtransportinfrastructure

Key Facts

• Cygnus is located in the southern North Sea, 150kilometresoffthecoastofLincolnshire

• £1.4billionwillbeinvestedbythepartners,morethan80percentofwhichwillbespentintheUK,creatingaround4,000jobs

• Firstgasisdueinfourthquarterof2015• Gas will be landed at the terminal at Bacton on the

coast in north-east Norfolk• It has reserves (with at least a 50 per cent

probabilityofrecovery)ofapproximately18billionstandard cubic metres of natural gas

• It is the UK’s sixth largest gas field by remainingreserves

• Atplateauproductionin2016,itwillbethesecondlargestsourceofgasontheUKCS

• ThepartnershipisledbyoperatorGDFSUEZE&PUK(38.75 per cent),with Centrica (48.75 per cent) andBayerngasUK(12.5percent)

MajorcontractsawardedintheUK

Companies that are alreadybenefiting from contractsawardedfortheCygnusprojectinclude:

• Heerema Fabrication Group’s Hartlepool yard – forthefabricationandcommissioningoftheAlphaWHPandPUplatformtopsides

• Burntisland Fabrication (BiFab) – for the engineering,procurementandconstructionoftheCygnus jackets and piles, as well as constructionof theQUplatform.Thisworkwillbeundertakenat their facilities inMethil andBurntisland in FifeontheScottishmainlandandArnishontheIsleofLewis in the Outer Hebrides

• AMEC Group in London – for the detailed engineering design contract

• Saipem in London – for the diving works and the installation of the main 55 kilometre exportpipelinefromtheplatformtotheEsmondpipelineandthesevenkilometreinfieldlinefromtheBravoWHPtotheAlphaComplex.

• Ensco in London –fortheEnsco80rigtodrilltheten horizontal wells.

• IsleburninInvergordon–forthefabricationofthestructures forthesubsea ‘Y’manifoldandsubseaisolationvalves(SSIVs)

• Genesis in Aberdeen – which completed the subsea detailed design and remains involved in follow-up engineering


Talisman Sinopec Energy UK’s Montrose AreaRedevelopment

Talisman Sinopec Energy UK (TSE UK) is oneof the newest and most dynamic companies exploring for and producing oil and gas in the North Sea. TSE UK, based in Aberdeen, wascreated in 2012 as a joint venture betweenTalismanEnergyIncandAddaxPetroleumUKLimited, a wholly-owned subsidiary of China Petrochemical Corporation (Sinopec Group).TSEUKisoneofthelargestoperatorsontheUKCS,with26fields,11offshoreinstallationsand one onshore terminal.

The main purpose of the organisation is tounlockopportunitiesintheNorthSeaandbuildasafe,profitableandsustainablebusiness.Themost recent effort to realise this potential isthe£1.6billionMontroseAreaRedevelopment(MAR)projectwhichwillextendthelifeofoneof theUK’s oldest platforms – inaugurated in1976–toatleast2030.

TheMontroseplatformwillundergosignificantmodifications, including the development ofa new bridge linked platform (BLP) which isplannedtobeinstalledin2015.Twocurrentlyundevelopedfields,CayleyandShaw,willalsobebroughtintoproductionbybeingtiedbacktotheBLP.

The MAR project will unlock 100 millionbarrels of reserves when it comes on-stream in2016andwill createor sustainmore than2,000 jobs during construction, fabrication,installation, subsea engineering and drilling.The government has recognised its value to theeconomybymakingitthefirstprojecttobenefitfromaBrownFieldAllowance(BFA),ataxreliefintroducedin2012toencouragetherenewal and life extension of existing fields(seesection6formoreinformationaboutthisallowance).

Figure 29: MAR Milestones

• 1969: Arbroathreservoirdiscovered,thefirstoilfieldontheUKCS

• 1971: Montrose reservoir discovered

• 1976: First oil from Montrose Field

• 1990: First oil from Arbroath Field

• 1996: ArkwrightFielddevelopedviaasubseatie-backtoArbroath

• 2005: BrechinFielddevelopedasasubseatie-backtoArbroath

• 2007: WoodFielddevelopedasasubseatie-backtoMontrose

• 2007 to 2009: AsuccessfulexplorationcampaignresultedinthediscoveryoftheCayley,GodwinandShawFields

• 2011: SanctionoftheGodwinFielddevelopment

• 2012: SanctionofintegratedMontroseAreaRedevelopmentprogrammetodevelopCayleyandShawviaabridge-linkedplatformatMontroseandtocarryoutfurtherinfilldrillingintheMontrosefield

• 2013 to 2014: Godwin Field development by drilling extended reach well from Arbroath

• Quarter 1 2016: FirstexpectedoilfromCayleyandShawFields


The project will create new infrastructure in the Montrosefieldandcomprisesthefollowing:• Thedevelopmentofabout100millionboeof

reserves,with40percentcomingfromtheShawoil field, 30per cent from theCayleygas-condensate field and the balance frominfill drilling on and life extension of theMontrosefield

• LifeextensionoftheMARinfrastructurefrom2017tobeyond2030

• Subseatie-backof17to18kilometresoftheShawfieldtotheBLPviarigidsubseapipelines

• Subseatie-backoftenkilometresoftheCayleyfieldtotheBLPviatwopipelinebundles

• A modular rig to be installed on Montrose to allowdrillingofinfillwellsstartingin2016

• Modifications on the existing Montroseplatformrequiringover200,000directhoursof offshore construction work. Additionalliving quarters for 30 personnel are beinginstalled on Montrose, together with a new central control room with associated integrated control and safety system and new officespaces.VariousmodificationsarealsorequiredtosupportthenewBLPinterfaces,along with life extension upgrades

MajorContractsAwardedintheUK

• Subsea7LtdinAberdeen – provision of engineering, procurement and installation of two five-kilometre pipeline bundles complete with towing heads; procurement, installation, trenching andpre-commissioningof17.5kilometreproductionandgasliftpipelinesandan18.5kilometrewaterInjectionpipeline; and installation of four subsea umbilicallines, production manifold and gas export SSIVstructure.Offshoreinstallationwilltakeplaceduring2014and2015seasons.Contractvalue:£178million.

• AMEC Group in Aberdeen – engineering, procurement, construction and commissioningservices on the Montrose platform.Contractvalue:£67million

• CB&IUKinLondon – engineering design of jacket and topsides.Contractvalue:£62million

• OGN North Sea in Newcastle – engineering, procurementandconstructionoftheMontroseBLPjacketandpiles.Contractvalue:£55million

• Saipem inLondon – transportationand installationservices.Contractvalue:€37million

• ProservControls inGreatYarmouth – engineering, procurement,manufactureandtestingofthesubseacontrolsystem.Contractvalue:£10million

• DucoLtdinNewcastle – engineering, procurement, manufactureandtestingofsixsubseaumbilicallines.Contractvalue:£10million

• InvensysSystems (UK) inLondon – new integrated control and safety systems for Arbroath, Montrose andthenewBLP.Contractvalue:£5million

• Hertel in Middlesbrough – engineering and construction of additional living quarters for30personnelonMontrose.Contractvalue:£6million

Figure 30: MAR Project – Locati ons of Principal Contractors in the UK

Amec Group LtdBrownfield EPCC

£67m

Subsea 7 LtdSubsea Construction

£178m

Duco LtdSubsea Umbilicals

£10m

Hertel Technical Services LtdAdditional Living Quarters

£6m

OGN North Sea LtdJacket Fabrication (EPC)

£55m

Proserv Controls LtdSubsea Controls

£10m

CB&I UK LtdJacket Topside Engineering

£62m

Saipem LtdTransportation and Installation

Euro 37m

2-10m Invensys Systems (UK) LtdIntegrated Control and Safety Systems

£5m

Source: Talisman Sinopec

10-45m 45-100m 101-200m

AMEC Group LtdBrownfield EPCC

£67m

Source:TalismanSinopec


• Constructionworkstobecompletedoverathree-yearperiodfrom2013to2015.Aflotel(floating hotel) will be on location for tenmonthstoprovideadditionalaccommodationover the various phases of construction.At their peak, the upgraded facilities areexpectedtoproduce55,000boepdfromtheMAR fields and the annual average will besome35,000boepd

The BLP has four significant elements (jacket,deck, bridge and flare), requiring the design,procurement,constructionandcommissioningofover17,000tonnesofmaterialsandequipment.The jacket includes three caisson riser systems to facilitate the tie-in of the Cayley and Shawpipelines and umbilical lines, whilst providing spare risers and a J-tube for future developments.The deck houses state-of-the-art process facilitiesforseparatingthehydrocarbonstreams

fromCayley(gascondensate)andShaw(oilandassociated gas), produced water treatment and water injection. The development uses existingoilandgasexportsubseafacilities,althoughgaswill now be exported through a new rigid caisson risersystemlocatedontheBLP.

Subseaisolationvalves(SSIVs)arebeinginstalledonallnewproductionandgas liftpipelinesandwill be contained within a single structure to the north-westoftheBLP.

The subsea field developments of Cayley andShaw require 100 kilometres of pipelines to beprocured, assembled and installed to tie-backseven subsea wells from three drilling centres. Some 600 kilometres of control hoses andtubing will be manufactured into umbilical lines contained within pipeline bundles to distribute hydraulicfluidsandchemicalsacrossthefields.

Key Facts

• TSE UK and its co-venturer, Marubeni, will invest £1.6billionintheMARproject

• MAR encompasses four fields in Palaeocene-agedreservoirs (Montrose, Arbroath, Arkwright and Brechin), four fields in Jurassic-aged reservoirs (Wood, Godwin, Cayley and Shaw) and a Zechstein-aged reservoir(Carnoustie)

• The fields are located approximately 210 kilometresnorth-east of Aberdeen

• Sinceproductionstartedin1976,over270millionboeofoil and associated gas have been produced

• The MAR project will unlock 100 million barrels ofreserveswhenitcomeson-streamin2016andwillcreateor sustain more than 2,000 jobs during construction,fabrication,installation,subseaengineeringanddrilling

• OilisexportedviatheFortiesProductionSystem(FPS)toCruden Bay and then on to Grangemouth

• GasisexportedviatheCentralAreaTransmissionSystem(CATS)toTeesside

• TheprojectwasthefirsttobeawardedaBFA

Figure 31: Layout of the Montrose-Arbroath Project


6.


Introduction

TheproductionofoilandgasfromtheUKCSis themost highly taxed business activity inthe country, with three separate corporate taxeswhichgeneratesubstantialrevenuesforthe Exchequer.

Over the past decade or so, the UKCS hasbeensubjecttoconsiderablefiscalinstability,with the most recent tax change, in March 2011, increasingoveralltaxratestobetween62 per cent and 81 per cent. To ensure thattheremainingdevelopmentopportunitiesontheUKCSareinternationallycompetitive,thegovernmenthashadtobuildonexistingfieldallowances (FAs), first introduced in 2009,providing targeted relief from the scope of the SupplementaryCharge(SC).

These allowances have contributed to a greater diversity of marginal tax rates which reflect the varying commercial opportunitiesavailableontheUKCS.Sincetheintroductionof the Brown Field Allowance (BFA) in September2012andwith the security tobeprovided by Decommissioning Relief Deeds(DRDs),thegovernmentnowhastheabilitytoinfluenceallphasesofthedevelopmentcyclethrough the fiscal regime. This should helpensurethatthefulleconomicpotentialoftheUKCSisrealisedoverthecomingyears.

TheFiscalRegimeforOilandGas

TheproductionofoilandgasfromtheUKCSissubject to a ‘ring fence’ tax regime6comprising:• Ring Fence Corporation Tax (RFCT) –

this is computed in a similar way to normal Corporation Tax (CT), but withdifferentrulesforthetreatmentoflosses,100percentfirstyearcapitalallowancesand a higher rate of 30 per cent on allprofits. The oil and gas industry has notbenefitted from reductions in the rateof CT seen elsewhere in the economy in recent years.

• Supplementary Charge (SC) – this is an additional corporation tax, levied on allprofitsattherateof32percent(was20per cent beforeMarch 2011). Profits arecomputed in the same way as for RFCT,but finance costs are not deductible forSCpurposes.

• PetroleumRevenueTax (PRT)– this is a field-basedtaxonprofitsintheregimeandonly applies to fields given developmentconsent by DECC before March 1993.PRT is levied at a rate of 50 per centand is deductible for the purposes ofcomputingprofitschargedtoRFCTandSC.Immediate relief is given for all capital and revenue expenses.

6. Fiscal Policy

6 The‘ringfence’ensuresthattheprofitsfromoilandgasproductionaretaxedseparatelyfromanyotheractivitieswithinacompanyandanylossesmadebythoseotheractivitiescannotbeusedbythecompanytooffsettheprofitsfromtheproductionofoilandgas.


Marginal tax rates therefore vary across the UKCSasfollows:• FieldssubjecttoPRT,SCandRFCTpay81

percentoftheirprofitsintax,comprisingPRTat50percent,plus30percentRFCTand 32 per cent SC of the remaining50percent

• FieldsnotpayingPRT(eitherbecausetheyare not liable to this tax, or by virtue of a relief called Oil Allowance7) are subject to tax at a marginal rate of 62 per cent(30percentRFCTplus32percentSC)

• Fieldswhich benefit from a FA – a reliefagainstSC–paytaxataratebetween30percent(thatisonlypayingRFCTat30percent)and62percent(onprofitsoncethefieldallowancehasbeenused).

As the oil and gas fiscal regime taxes profitsat a minimum rate of 30 per cent which isconsiderably higher than for companies in all other parts of industry and commerce, the Oil Allowancewithin the PRT regime and fieldallowances for SC purposes only ever reducethe tax burden from very high rates to one that is closer to,but stillhigher than that forothercompanies. Therefore, these allowances cannot be said to represent a subsidy for the industry as theyonlypartiallyalleviatethetaxburden.

Furthermore, some companies are also subject to both the RFCT regime in respect of theirupstreamoil andgasproductionactivitiesandthe normal CT regime for their downstream refining and marketing activities. Companiescannotoffsettheirprofitsorlossesbetweenthetwo regimes to reduce their overall tax liability, asupstreamprofitsarealwaystaxedseparatelyunder the ring fence regime.

7 OilAllowanceisarelieftoensurethatPRTisonlyleviedonthelargest,mostproductivefields.TheallowancegiveseachfieldliabletoPRTamountsofoilandgaswhichcanbeproducedfreeofPRTpertaxperiodandforthelifeofthefield.AnyproductionabovetheseamountsissubjecttoPRTattheprevailingrate.

Figure 32: Tax Rates for the UKCS and Other UK Companies

0 20 40 60 80 100

Non Oil andGas Company

Qualifies forAllowance

Non-PRT, NoAllowance

PRT PayingField

Share %

50% PRT 30% RFCT 32% SC

30% RFCT

23% CT

32% SC

30% RFCT

38% Post-Tax Profit

38% Post-Tax Profit

77% Post-Tax Profit

of remaining 50%


0-32% SC 38-70% Post-Tax Profit


RecentDevelopmentswithFieldAllowances

During 2012, there were a number ofextensionstotheFAs,asfollows:• A new class of FA was introduced in

March2012fordeepwateroilfieldswitha pre-tax value of £3,000 million. Thisenabled a consortium led by Chevronto continue with its development of theRosebankfieldtothewestofShetland.

• Also in March 2012, the Small FieldAllowance was increased in value to £150 million pre-tax and in scope to cover fields up to 50 million boe ofrecoverable reserves.

• In July 2012, another new FA wasintroduced with a £500 million pre-taxvalueforlarge,shallowwatergasfields.

The most significant change occurred inSeptember 2012, when the FA concept, whichhadonlypreviouslybeenappliedtonewfields,was extended to cover incremental investment projects in fields already in production. The resulting BFAwas the culmination of over12 months of work, led by Oil & Gas UK, with the government and industry.

It introduced a capital cost based allowance per project, scaled with its size. As long as the capital costs exceed £60 per tonne of recoverableoil (approximately $12/bbl), the allowance isavailable for each tonne that the project is expected to recover. The BFA is calculated on estimated capital expenditure and estimatedreservestoberecoveredatthetimetheprojectis granted development consent.

Figure 33: The Brownfield Allowance


Oil&GasUKbelievesthattheBFAisessentialin enablingmaximum recovery of the UKCS’resources and ensuring that projects are competitiveinattractinginternationalcapitalinvestment. Since the BFA was introduced,morethan£3billionofcapitalexpenditurehasbeen allocated to some of the oldest and most maturefieldsontheUKCS,unlockingaround300millionboeofreserves.

However,asmentionedaboveinSection4,itisclearthatthetaxationoftheUKCSwillhavetoberefinedfurtherintheyearstocometoensure that the overall objective, shared bygovernment and the industry, of recovering as much oil and gas as is economically possible is achieved.

Atableexplainingthevariousfieldallowancescan be found in the Appendix of this report.

DecommissioningTaxRelief

Operators are under an obligation to decommission their wells, platforms, pipelines and other facilities once production from a field has ceased (there are strict regulatory requirements in place). Clearly, this is an expensive process which is currently forecast to cost the order of £35-40billion for thewholeUKCS (in2012money). As with the original investment, it is a cost which is allowable for tax purposes. However, profits have been taxed year by year without any provisions being allowed for future decommissioning expenditure and, furthermore, there has never been any certainty that tax relief on decommissioning costs will be available as and when the expenditure is incurred.


This has been a substantial and longstanding concern for the industry, which was exacerbated in the Budget of March 2011 when a restriction was introducedon the rate of relief allowed. Since then, Oil & Gas UK has led the industry in working with the government to secure the necessary tax reliefs for the whole of the UKCS.Subsequently,theFinanceAct2013legislatesfor the introduction of DecommissioningRelief Deeds (DRDs), which will providecontractual certainty that costs arising from decommissioning activities can be offsetagainst tax previously paid by companies (for RFCTandSCpurposes)andfields(forPRT).

Securing certainty for tax relief ondecommissioning is a seminal moment for the industry. It will mean that the current barriers to the trading of assets are lifted,enabling these assets to be transferred to those companies most likely to develop them. Inturn,thisshouldunlockasignificantamountof new investment to extend theproductivelives of a wide variety of fields. All this hasbeen achieved at no cost to the government and without requiring any pre-funding from the industry.


7.


A healthy supply chain is integral to the successoftheUKCS.Industryandgovernmentrecognisethatsupportingthedomesticsupplychain has positive effects on employment,Gross Domestic Product (GDP), taxes, thedevelopment of technology, exports and, ultimately,therecoveryofoilandgasreserves.

IndustrialStrategies

Both the Scottish and British governmentshave published oil and gas sector strategies, the former in the summer of 20128 and the latter in the spring of 20139 jointly by the Department for Business, Innovation andSkills (BIS) andDECC. Both documents coversimilar themes, focus on the upstream oil and gas supply chain and are jointly owned by government and industry.

BISandDECC’sstrategyhasthreeunderpinningaims:• Tomaximise theeconomicproductionof

theUK’soffshoreoilandgasresources• To sustain and promote the growth of the

industry’s supply chain, inbothdomesticandinternationalmarkets

• To promote purposeful collaborationacross industry and between industry and government

An industry council has been formed to advise BIS and DECC. Of the 42 actions that havecome from the council, mapping the supply chain represents one of the biggest challenges. Once complete, themapwill identify wherebest to promote growth and further expand theoilandgassupplychain’scapabilities,bothdomesticallyandinternationally.

7.TheSupplyChain,EmploymentandSkills

8 Seehtt p://www.scotti sh-enterprise.com/your-sector/energy/oil-and-gas/strategy.aspx

9 Seehtt ps://www.gov.uk/government/publicati ons/uk-oil-and-gas-industrial-strategy-business-and-government-acti on-plan


Many of these actions are underway, eachbeing led by more than one council champion. As part of the council’s work, the government has agreed to consider its role in improving thepublic’sperceptionoftheindustry.Apilotproject, ‘Energising the Nation’s Future’,10 has been initiated by Oil & Gas UK to raiseawareness of the industry and the positivecase studies from the sector. Other actionsunderway include co-operative work bygovernment and industry to help stimulatestudent demand for engineering careers and mapping of the work carried out by BIS to address the uptake of STEM(Science, Technology, Engineering, andMathematics)subjects.

All actions arising from both the Scottish andBritish strategies are in place to help worktowards the ultimate goal of maximisingeconomicrecoveryofoilandgasfromtheUKCS.

Ernst&Young’sOilFieldServicesReport2012

The supply chain supports the industry across all itsrequirements,fromtheseismicacquisitionof reservoir data, through exploration andappraisal drilling, field developments andproduction operations, to decommissioningat the end of field life. According toErnst&Young’s2012 Oil Field Services Report11 for the UK, the combined activity of 390companiesgenerated£27billionof revenuesin2011fortheirgoodsandservices;thiswas17 per cent more than the previous year. In terms of jobs, these companies provided directemploymentforalmost93,000peoplein 2011, a seven per cent increase on 2010,reflectingtheincreasedactivityintheindustryand its supply chain.

Figure 34 suggests that revenues have risensteadilysincedatawerefirstcollectedin2008.

10 See htt p://www.energisingthenati onsfuture.co.uk

Figure 34: Profi ts and Revenues for the Supply Chain

Profits

Revenues Costs

2%

- -

Profits

Revenues Costs

2% 15% 17%

-21% -16% 27%

2009

2009 2010

2010

2011

2011

11 Ernst&Youngonlyincludecompanieswhereatleast50percentoftheirturnoverisintheoilandgassector,areUKregisteredandhaveannualrevenuesexceeding£10million.E&Yidentifiedanother720companiesinvolvedinthesector,butwithannualrevenuesoflessthan£10million.

Source:Ernst&Young


However,pre-taxprofitsactually fell in2009and2010,beforerisingby27percentin2011.The failure to translate increased revenues intoincreasedprofitssuggeststhatthesupplychain struggled to contain its costs in 2009and2010.Risinglabourcosts,resultingfromatightmarketforhighlyskilledpeople,arethelikely cause of these increased costs.

Ernst&Young’sreportsplitsthesupplychaininto four broad categories: reservoir andseismic, exploration and production drilling,operations (comprising production andmaintenance), and engineering, fabricationandinstallation.TherelativeturnoversoftheseareshowninFigure35andtheirprofitabilityinFigure36.

Engineering,fabricationandinstallationisthelargestsectorintermsofrevenue,accountingfor some 40 per cent of total UK supplychain turnover in 2011 and employing some32,000 people. Operations (production andmaintenance) comprise the second biggest sectorintermsofrevenuewitha30percentshare and it is the largest sector in terms of employment,with38,000employeesin2011.Exploration and production drilling typicallymake up a quarter of supply chain revenues and employs some 19,000 people, whilethe smallest sector in terms of revenue and employment is reservoir and seismic, which typically captures less than five per cent ofrevenuesandemploysaround4,000people.

The 26 per cent growth in revenues for theUK’s engineering, fabrication and installationsectorin2011wasdrivenbytheinternationalsuccess of subsea engineering businesses and the demand for engineering and design work.

Operations’ (production and maintenance)revenues recorded a healthy increase for a thirdconsecutiveyear.Thissegment ismadeupofproductionprocesses,includingabroadrange of operations and maintenance work

Figure 35: Supply Chain Sector Revenues

Figure 36: Supply Chain Sector Profitability

0

5

10

15

20

25

30

2008 2009 2010 2011

£ Bi

llion

Reservoir and Seismic

Exploration and Production Drilling

Operations (Production and Maintenance)

Engineering, Fabrication and Installation

Oil & Gas UK, Ernst & Young

0.0

0.5

1.0

1.5

2.0

2.5

2008 2009 2010 2011

£ Bi

llion

Reservoir and Seismic

Exploration and Production Drilling

Operations (Production and Maintenance)

Engineering, Fabrication and Installation

Oil & Gas UK, Ernst & Young

Source:Oil&GasUK,Ernst&Young

Source:Oil&GasUK,Ernst&Young


and activities associated with increasing oilrecovery. Given the ageing infrastructure present on the UKCS and the number ofbrownfieldprojects,itisnotsurprisingtoseesuchariseinrevenuesfromoperations.

Revenues in exploration and productiondrilling grew slightly in 2011, but overall itsmarket share in the UK has been decreasing. Revenues are consistently lower than thoseseen in the equivalent Norwegian sector, but costs in Norway are also consistently higher.

Reservoir and seismic is a growing sectorin the UK, but from a relatively small base.Profitabilityfellby54percentin2010,whichwas probably caused by the six month drilling moratorium in the Gulf of Mexico (GoM) between May and November, releasing spare seismic vessels from the GoM to the UKCSand depressing day rates. The supply of these vessels in theUKtightened in2011after themoratorium in the GoM was lifted, helpingbothrevenuesandprofitstorecoverin2011.

Scottish Council for Development andIndustry’sReport–Exports

The Scottish Council for Development andIndustry’s 2011-12 Survey of Internati onal Acti vity in Scotland’s Oil and Gas Sector12

indicates that the Scottish supply chain’srevenuestotalled£17.2billionin2011,growingby5.8percentfrom2010.Internationalsalesincreased by 8.4 per cent to £8.2 billion in2011,withNorthAmericaremainingthemainexport market. Scottish exports to Norway,Angola, Nigeria and the UAE are also strong.

SubseaEngineering

A particular strength of the UK’s supplychain is subsea engineering which generates £8.9 billion in revenue for the economy

accordingtoSubseaUK13.Subseatechnologyhas become increasingly important, both in producingoilandgasreservesfromtheUKCSand in expanding exports.

More than 800 companies are active in theUK’s subsea sector, with SMEs making upthe largestproportion.Of that totalnumber,seven per cent each generate more than £100 million of turnover a year, with themedian turnover being £2.6 million. The36 largest companies and their subsidiariesproduce70percentofsubseaturnoverintheUK and 77 per cent of the sector’s total output.

The companies involved are spread across the country, although three quarters of the total revenue is generated in the north-east of Scotland (£6.7 billion). Around £614 million ofoutput is concentrated in the east of England and £400 million and £126 million in thenorth-east and south-east of England, respectively.Theremainderisspreadacrosstheeast Midlands, the north-west and south-west of England,WalesandtherestofScotland.

The export of subsea goods and services from theUKisvaluedat£4.4billion.KeymarketsareNorway, West Africa, North America and Asia. Engineering and manufacturing companies generatea substantial shareof this revenue,asdo service providers in disciplines such as diving, remotelyoperatedvehicleinspection,underwaterconstruction,installationandsurveying.

On the back of this strong performance, 16,000newjobshavebeencreatedsince2010,bringing the total number of people directly employed in the subsea sector to 53,000,with another 13,000 employed indirectly.Engineering, construction and diving rolesaccountfor48percentoftheworkforce,withmanufacturing accounting for 19per centofthe total.

12 Seehtt p://www.scdi.org.uk/pi/2013/2011-2012Oil-Gas-Survey(May2013-SDI-SE-SCDI).pdf

13 Seehtt p://www.subseauk.com/4277/uk-subsea-sector-now-valued-at-almost-9billion-almost-50-growth-in-three-years


The future prospects of the subsea sector are positive and, if companies’ growth forecastsare achieved, over £11 billion of revenuescouldbeachievedby2016.Futuregrowth inexportsisanticipatedtocomeprimarilyfromNorthandSouthAmericaandAsia.

WellServices

The state of the well services’ sector is a good indicator of current and future activityon the UKCS, because of its involvementin the exploration for and appraisal anddevelopmentofoilandgasreservoirs.In2012,companies delivering drilling, completion,testing and maintenance services for oiland gas wells generated the highest gross revenue since records began in 1996, at £1.9 billion. This higher than expectedrevenue can be attributed to the growingnumber of technically complex wells which require the specialist skills and knowledge of well services’ contractors.

This success has in turn boosted employment, as the number of highly skilled jobs in the UK supported by the sector also rose by ten per cent in 2012 to 13,000, including 2,200graduateengineersand1,700technicians.

The sector’s future prospects are good with companies forecasting a further five percent increase in revenues in 2013. Technicalinnovation is a priority for well services’contractors with some companies spending up to 90 per cent of their annual capitalinvestment on developing new technologies. Indeed, their overall investment in future capacity increased by 20 per cent in 2012to £111million, half of whichwas in capitalequipment, the other half in new technology.

Fabrication

Since the discovery of oil and gas on theUKCS more than 40 years ago, the industryhas developed an indigenous fabricationsupply chain with expertise in the designandconstructionofoffshoreplatformsandabroad range of associated structures.

Britain’s fabricators have been involved in much of the construction of around 6.5million tonnes of concrete and steel structures installedontheUKCStodate.Thesectorhasdemonstrated it has the capacity to design andfabricate:• Jackets (the steel substructures which

supportplatforms)• Decks and modules comprising the

topsidesfacilities(abovethejackets),suchas drilling, production, process, utilitiesandaccommodationunits

• Flare booms and towers• Subseamanifoldsandpipelinebundles

While the requirement for very large, integrated offshore platforms is no longeras it was in the 1970s, 1980s and 1990s,there still remains substantial demand forfabrication services, especially associatedwith fields developed as subsea tie-backs toexisting production platforms. The existinginfrastructure often requires modificationandupgradingtoaccommodatenewflowsofoiland/orgas(55percentoffieldsapprovedin the last five years have been or will bedevelopedassubseatie-backs).

An illustration of a pair of bridge linked,offshore platforms is depicted in Figure 37overleaf (note that it is not unusual for all the topsides facilities to be accommodated in asingle,integratedplatform).


a)DistributionofFabricatorsintheUKFabricationfirmstendtobelocatedalongthecoasts,ofteninregionswithastrongheritagein heavy engineering industries, such as ship-building, mining or power generation.Overthepast40years,thebiggerfabricationyards have also encouraged the emergence of a diverse, often local, supply chain in whichSMEs have evolved to support fabricatorsby delivering more specialised goods and services,suchaspipeworkfabrication,paintingandinsulation,assetintegrityconsultancyandother technical services.

b)FabricationWorkforFieldDevelopmentsontheUKCS,2008to2013Oil & Gas UK recently conducted a survey covering the five year period 2008 to mid-2013 to assess the volume and locationof fabrication activity taking place in theUKassociated with UKCS developments and toidentifywherefabricationfortheseprojectsisundertakenbyfirmsoverseas.

DECC approved more than 60 fielddevelopments from2008 tomid-2013which

Figure 37: Typical Offshore Platforms

Source:BP


Oil&GasUKhascategorisedintofivedifferenttypesforfabricationpurposes:• Subsea• Floating Production Storage andOffloading

vessels(FPSOs)• Steelstructureswithinthreemainweight

ranges:o Under4,000tonneso Between4,000tonnesand20,000tonneso Greaterthan20,000tonnes

The number of projects in each category over this five-year period can be seen infigure39(overleaf)and,asmentionedabove,the majority in this time-frame are subseatie-backs. For this type of development, thesurvey results show that most of the structures are fabricated in the UK. Larger platformstructures are being built in both the UK and overseas,butfabricationofFPSOsisinvariablycontracted to ship yards located in Korea and China for commercial and capacity reasons.

Harland and Wolff

Sembmarine SLP

Global Energy Group (Nigg Energy Park)

Burntisland Fabrications, Burntisland

Burntisland Fabrications, Arnish

Burntisland Fabrications, Methil Babcock, Rosyth

OGN Tyneside

Hereema Hartlepool Able Seaton Port (Hartlepool)

Hertel Wilton Engineering

TAG Energy Solutions

Rigmar Group (Dundee)

Babcock, Appledore

OGN Lowestoft

Able Middlesbrough Port

Ledwood

A&P

ZE1 Global

Pallion Engineering

Global Energy Group (Aberdeen)

Global Energy Group (Dunfermline)

Global Energy Group (Invergordon/Evanton Cluster) Global Energy Group (Muir of Ord)

Figure 38: Distributi on of Fabricati on Companies in the UK


InBISandDECC’sindustrialstrategyforoilandgas, referred to above, fabrication has beenidentifiedasrequiringspecificattention.Whilethere are several British fabrication yardsthat actively tender for substantial offshoreprojects,anumberofrecentmajorfabricationcontracts have been awarded to overseas yards that are apparently more competitive thanthose at home. The government is working with the industry, without compromising the competitiveness of projects, to ensure thatfabricators in this country are given every opportunitytobidforallUKCScontracts.

Technology

The development and production of oil andgas from the UKCS has a history of greattechnical innovation to find and develop awide variety of oil and gas reservoirs in varying water depths, often with a high degree ofgeological uncertainty and in demanding maritimeconditions.

Historically, much of the research and development(R&D)hastakenplacewithintheinternational oil companies (IOCs) and largerservice companieswhohave significant R&Dcapability.Thegovernment’s2010scoreboardshowedthat,ofthetop1,000UKcompaniesinvestinginR&D,16investedsome£1.2billioninoilandgasR&Dinthiscountry.

Meanwhile, direct government funding of R&Dfortheoilandgasindustryhasbeenfairlylow(about£7millionbetween2006and2011)with no thematic oil and gas research areawithinResearchCouncilsUK14. The majority of research council funding has been indirect via projects in areas of relevant science (such as advanced materials) and other related subjects (such as carbon capture and storage). This has raisedthetotalof£7millionmentionedabovetonearer£10millionbetween2006and2011,or about two per cent of the total public sector funding of energy research.

Figure 39: Number of Projects per Fabricati on Category Approved in 2008 to 2013

0

5

10

15

20

25

30

35

2008 2009 2010 2011 2012 2013

Num

ber o

f New

Fab

ricati

on P

roje

cts A

ppro

ved

Each

Yea

r

FPSO

Steel > 20,000t

Steel 4,000 - 20,000t

Steel < 4,000t

Subsea

Source: Oil & Gas UK, DECC and Wood Mackenzie

14 See htt p://www.rcuk.ac.uk/Pages/Home.aspx

Source:Oil&GasUK,DECCandWoodMackenzie


In addition, the Technology Strategy Board15

has funded some £22 million of oil and gasrelatedprojectssince2007(11percentofitsenergy funding).

Looking to the future, it is clear that the prosperity of the UKCS will be significantlyinfluenced by successful development andimplementation of new technologies. Inrecent years, the number of operators has increased, while the role of the major IOCs has decreased. As a consequence, the ability ofoperators toundertakeR&D in-househasdeclined. This means that, more than ever, an efficient, industry-wide system of researchthroughtodeploymentinthefieldisrequired.

The technical challenges facing this diverse range of operators are becoming greater, as outlinedbelow:• Current exploration success rate is low

compared with other oil and gas provinces. The exploration targets are small andgeologicallycomplexandsometimeswithhigh pressures and temperatures.

• Current oil field recovery factors in thecentral and northern North Sea are just

over40percent.IORandEORtechnologieswill be required to increase the average recoveryfactortoabove50percent.

• Much of the infrastructure is beyond its design life, requiring comprehensive plans to extend its life and increase recovery (note the Health and Safety Executive’sKey Programme 4 on asset integrityreferenced in footnote 4).

• Cessationofproductionfromcriticalfieldscould constrain access to new resources.

• The remaining reservoirs hold resources whichareincreasinglydifficulttorecover.

• Longand/orcomplexsubseatie-backsarenecessary for many new developments.

• Decommissioning is a growing activityacrosstheUKCS.

However, the above challenges represent an enormous opportunity for the companies involved and for Scotland and the UK as awhole,hencetheworkofthetaskforce,PILOT,in addressing these matters (see ‘The Roadto2040’ inSection4)and the two industrialstrategiesdiscussedearlierinthissection.

Figure 40: New Technology – the Treatment of Injected Water for EOR Purposes in the Clair Field

15 See htt p://www.innovateuk.org

Heat Exchangers

LiftPumps

CoarseFilters

UF MembranePre-treatment

MembraneDesalination

De-aeration WIPumps

WIWells

ElectroChlorinator

ChemicalDosing

Sea Water ExcessCW + Brine

OtherUsers

Source:BP


Employment

The industry is a major source of employment throughout the UK. Themost recent figuresavailable show that direct employment by companies exploring for and producing oil and gasfromtheUKCShasgrownby12percentto36,000comparedwith theprevious studyconductedin2010.

Overthesameperiod,itisestimatedthatthenumber in indirect employment (in supply chain companies contracted for work by operators) has remained fairly stable at around 200,000,inpartbecauseofgainsinefficiency,but also due to increased competition forlabour internationally and the awarding ofsome contracts overseas. However, induced employment is estimated to have grownfrom100,000 to112,000.Overall, therefore,the compositionof theupstreamoil andgasworkforceintheUKduring2012was:

• 36,000 directly employed by operatingcompanies(12,500ofwhomworkedoffshore)

• 200,000 employed in the wider supplychain(45,000ofwhomworkedoffshore)

• 112,000in jobs inducedbytheeconomicactivityoftheaboveemployees

• 100,000 in jobs in exporting goods and services

This suggests that the industry supported some450,000jobswithinBritain’seconomyin2012,abouthalfofwhichareinScotland,withthe other half spread across the rest of the UK. However,thisislikelytobeanunderestimate,given that total expenditure by the industry has risen by more than 15 per cent in thelast year alone (although some of this will be spent abroad). The industry has sizeable employment multipliers. It is estimated that13 jobs are supported by every £1 millionof operational expenditure on theUKCS and15 jobsaresupportedbyevery£1millionofcapital expenditure.

Figure 41: Offshore Employment by Home Address

Source:Vantage


Skills

The past year has seen frequent reports in the media of the skills shortages facing the industry and it is acknowledged as one of the biggest challenges. The limited data available about the labour market (which was tested at Oil&GasUK’sskillsconferenceinSeptember2012)showthatthecriticalareasofshortageare in a number of mid-career, onshore roles, including design engineering, subsea and drilling engineering, project management and geosciences.Techniciansandskilledcraftsmenare also in short supply because of the high volumeofactivity.

The shortages are partly due to reductionsimplemented when the oil price has been lowinthepast,asinthe1990s,buttheyarealso very much a consequence of the current success of the industry. The skills, expertiseand technology developed on the UKCSare highly sought after by other oil and gasprovinces around theworld; competition forskillsistrulyinternational.

Supply chain companies have highlightedthe mid-career gap and have been working with the Chartered Institute of Purchasingand Supply to develop accredited courses.However, the large number of applicants for the Upstream Oil and Gas Industry Technician Training Scheme and companies’ graduateschemes indicates that the industry is attracting new entrants straight from schooland university. During the past year, Oil & Gas UK has been workingwithindustrytoidentifywhereandtowhatextentco-operationacrosstheindustrycan help tackle the demand for skills. A number ofactionshavebeenidentified,including:

• Establishing a high level industryrelationshipwiththeMinistryofDefence(MoD) – 18-20,000menandwomenwillleave the armed forces in each of the next three years and many of them will have transferable skills. The industry’s training organisation,OPITO16, is working with the MoD to map and identify skills in bothindustry and military roles to facilitate the matching of skills and the development of appropriatetransitiontraining.

• Discipline work groups in areas ofshortage have been established toexplore the feasibility of transitiontraining/accelerateddevelopment.

• Creatingsmarter trainingsolutions – for example, through possible development of facilitiesthatcouldbeusedasassessmentor proving centres for skilled workers from otherindustriesandtoreducetheoffshoretrainingtimerequired.Afeasibilitystudyisunderwayforthisinitiative.

• Lobbyingthegovernmentonimmigrationpolicytofacilitaterecruitmentofskilledpersonnelfromnon-EUcountries.

• Education – pooling of resources and effort under the auspices of OPITO sothe industry can reach more schools throughout the country, more often,and with consistent messages about the importanceofandopportunitiesaffordedbystudyingSTEMsubjects.

Though the sector has no difficulties inattracting new entrants to the industry, it isimportantforthelongertermtosustainaflowof school leavers and university graduates with STEMqualifications,notjustforthisindustry,butfortheeconomyasawhole.

16 See htt p://www.opito.com


8.


The world’s energy landscape continues tospring its surprises. Just a few years ago, who would have considered that North America maywellreturntoself-sufficiencyinoilbytheendofthecurrentdecadeorshortlythereafter,just as ten years ago who foresaw its coming self-sufficiency in gas, with the likelihood offuture exports of LNG rather than imports?

Thesedramaticchangesinoneoftheworld’slargest markets, driven entirely by technicaladvances, have turned many assumptionsabout energy policy on their head. Instead of ever rising prices for fossil fuels, as oftenassumed, the price of gas has been low for the past four years in North America and this, in turn, has driven down the price of coal around the world, as surplus American coal has been exported.

In Europe and Germany in particular, thishas led to a significant increase in coalconsumptionforpowergenerationpurposes,thusthreateningtheEU’sprojectedreductionsin greenhouse gas (GHG) emissions, at least in the short term.

Elsewhere,coal’suseinpowergenerationhasmeant that almost half of the rise in energy demand worldwide over the past ten years has been met by coal, expanding faster than all renewable energies combined, with China king of the coal consumers and India following on a similar trajectory, but from a lower starting point. In end use terms, electricitydemand is growing the fastest, hence the increaseincoalconsumption,andthisislikelyto continue as non-OECD countries continueto develop rapidly. The contrast between the energy requirements of OECD and non-OECD countries is illustrated vividly in Figure 42.

8.EnergyPolicyandSecurityofSupply

Figure 42: A Tale of Two Worlds – Energy Demand in OECD and Non-OECD Countries

0

100

200

300

400

500

2000 2020 20400

100

200

300

400

500

2000 2020 2040

Non OECD Quadrillion British Thermal Units

Other Renewables

Oil

Quadrillion British Thermal Units

OECD

Coal

Gas

Source: ExxonMobil 2013 Outlook for Energy Source:ExxonMobil2013OutlookforEnergy


In terms of investment, however, the rise in non-OECD demand is paralleled by the need for OECD countries to renew much of their energy,particularlyelectricity, infrastructure.Most of this infrastructure was either built or rebuilt during the great economic recovery following the Second World War and so isnow reaching the end of its expected life. This provides both an opportunity to rebuild so as to accommodate new technologies and sources of supply, but also poses a threat, as the necessary financial and other, especiallyhuman, resources stretch both the investingcompanies and the supply chain beyond what isdeliverablewithinthetime-frameenvisaged.This point has been raised in these Economic Reports for several years.

Gas is currently the fuel of choice for power generationinNorthAmerica,sharplyreducingemissions of GHGs while lowering electricity costs for consumers including, importantly, for heavy industry, making it more competitiveinternationally.

Gas is also starting to be used in mediumto heavy commercial road transport in the USA and in buses in various parts of theworld, offering both cost and environmentalbenefits.IntheInternationalEnergyAgency’s(IEA) most recent World Energy Outlook17, publishedinNovember2012,gasremainstheonly fossil fuel whose demand is forecast to grow in all three of the IEA’s policy scenarios (new, current and 450).

Within Europe, gas is primarily a fuel for heat, although it has a significant presencein electricity generation as well, albeit thishas been reduced of late by the resurgence of coal.Nonetheless, lookingahead to2030,gas is likely to gain market share in Europe and elsewhere for power generation purposes,as demand in non-OECD countries and environmental pressures almost everywhere

keep on rising. New nuclear power is delayed or, in some countries, rejected, and large scale renewable electricity projects are struggling for funding, notably in the EU.

EvolutionoftheUK’sEnergyPolicy

ItshouldnotbeforgottenthattheUK’senergyconsumption divides broadly into threesimilarly sized parts: electricity, heat andtransport. Gas dominates heat supply;morethan80percentofBritain’shomesareheatedby gas, together with much of the smaller commercial sector and significant parts ofthe larger commercial and industrial sectors. Meanwhile, oil products supply transport to an overwhelming extent, as is the case around the world, with electricity holding a shareoftherailmarketwheretrafficdensitiesmake investment in the necessary infrastructure sensible.

Almost all the policy debate in the EU and UK continues to concentrate on electricity,although DECC published a heat strategy in March2013.Itisclearfromthisstrategyhowdifficult and expensive reforming heatingthroughout the country is going to be. At its highest level, policy is governed by the energy and climate change triangle, depicted in figure 43 opposite. As has been commentedon before in these reports, it is Oil & Gas UK’s viewthat farmoreattentionhasso farbeenpaid to reducing emissions than on security ofenergysuppliesandtheiraffordabilitywithwhichcomeseconomiccompetitiveness.

However, the consequences of the recession in much of the EU have moved the debate perceptibly towards security of supply andaffordability. This is understandable, giventhat the public at large are likely to react adversely to any threat to supplies and/or the affordabilityofenergy.

17 Seehtt p://www.iea.org/W/bookshop/add.aspx?id=433%20


In some analysis undertaken for Oil & Gas UK, LondonEnergyConsultingexaminedtheenergyuseandcarbonintensitiesofvariousOECD,butmainly European countries and compared these, as shown in Figure 44. The UK’s Carbon Budgets (carbon emissions’ targets) are superimposed as green lines, together with the 2050 target.Interestingly,theUKisbetterplacedthanseveralcomparable economies such as the Netherlands, Germany, Japan and Denmark, but it is behind France(duetotheeffectsofnuclearpower)andItalyandSpain(duetotheirwarmerclimates).

Above all, though, this chart demonstrates clearlythemagnitudeofthetask if the2050target is to be met by almost any Member State of the EU, given that major energyinvestmentssuchaslargepowerstationsandoil and gas fields typically last for 45 to 50yearsandthat2050isonly37yearsaway.

a)ElectricityAt thetimeofwriting (July2013), anEnergyBill is being debated in parliament. It seeks to reform the electricity market and stimulatethe very large investment in low carbon powergeneration,especiallynewnuclearandoffshorewind,tomeetthegovernment’sowntargets as well as its European obligations.Within the Bill, the main instruments being proposedare:• ContractsforDifference(CfDs) – a means

to support the incomes of generators who invest in low carbon technologies where generationcostsareabovemarketprices.

• A Capacity Mechanism – a payment to encouragetheprovisionofthegeneratingcapacity that will be required to back up intermittent renewable power andstabilise the grid.

• An Emissions Performance Standard – a mechanism to prevent the building of unabated coal fired power stations, butnot gas, although in future the standard could be adjusted so as to affect allunabated fossil fuel power.

Figure 43: The Energy Policy Triangle

Figure 44: Carbon Emissions for Various OECD Countries(in tonnes of CO2 per person per year,

averaged over the years 2006 to 2010)

EU and the

UK

Reduced Emissions of Greenhouse Gases: by 20 per cent in 2020 and 80 per cent in 2050 (v 1990)

Security of

Supply

Affordability / Economic Competitiveness


Source: London Energy Consulting analysis; data from Gapminder

Carbon Intensity (gCO2 /kWh)

Ener

gy U

se (k

Wh/

pers

on/d

ay)

2050 target = 2

CB4 = 5

CB3 = 6.5

CB2 = 7.1

CB1 = 7.7

250 230 210 190 170 150 130 110 90 70 5020

40

60

80

100

120

140

160

180

Source:LondonEnergyConsultinganalysis;datafromGapminder


Inadditionthere isalreadyanother, relevantinstrument:• A Carbon Price Floor – legislated by HM

Treasury through the Finance Act 2011,this sets a minimum price to be paid for carbon emissions through the Climate Change Levy and is intended to encourage power generation by low carbonmeans.It took effect on 1 April 2013, but onlyapplies in the UK, raising our power prices relative to those inotherMemberStatesof the EU.

Itisdifficulttoreachanyconclusionwhichdoesnot recognise the inherent complexity that these measures will engender. Indeed, it has tobeamatterofconcernthatsuchcomplexmeasures underpin the whole strategy for low carbon generation. Furthermore, muchof the decision making in power generationwill be moved from companies and markets to government departments and ministers. As stated in the last of six conclusions of Oil & Gas UK’s response in March 2011 toDECC’s consultation on its proposals forelectricitymarket reform: “A greater degreeof realism is called for. Policies should besimplified and de-risked; they would have abetterchanceofsuccess.”

However, Oil & Gas UK was pleased when DECC announced and, in late 2012, releaseditsgasgenerationstrategy.Thisrecognisesthenecessaryrolethatgasfiredpowergenerationwill to have to play over the next 15 to 20yearsandprobablyformanyyearsthereafter,if carbon capture and storage (CCS) can bemadetoworkatpowerstationscale.

Under the Large Combustion Plant Directive(LCPD),whose effects are already being felt,some12giga-watts(GW)ofcoalandoilfiredpowergenerationcapacitywillbeclosedbytheendof2015.Inaddition,undertheIndustrialEmissions Directive (IED), up to 18.5GW of

coal and 18GWof early gas fired generatingcapacity will be closed by the end of 2023,whenmostofthecoalfiredplantswillbe50years old anyhow (although some of it is being converted to burn biomass). In aggregate, these represent a very substantial share ofthecountry’stotalpowergeneratingcapacity,to which must also be added the progressive closure of 9.5GW of nuclear capacity withinthesametime-frame,becauseofoldage,andpremature closure of some early gas power plants which are now uneconomic, owing to thelowpriceofcoalmentionedabove.

Meanwhile, construction of the first of theplanned new nuclear power stations, atHinkleyPoint inSomerset, isslippingfurther,throughacombinationofdifficultiesinraisingthenecessaryfinance,continuingnegotiationsabout the ‘strike price’ under a CfD (that is the size of the subsidy to be paid by customers), and concerns about the cost and complexity ofthereactor’sdesign.Apotentialrival typeofnuclearreactor,meanwhile,stillneedstogothrough its Generic Design Approval for use in the UK (a procedure likely to take two to three years) and it needs to gain planning permission before construction can begin. This meansthat it is now unlikely that any new nuclear power plant will start operation in Britainmuchbeforethemid-2020sandtherewillbeless nuclear generating capacity throughoutmostofthe2020sthanthereistoday.

Itisthereforeinevitablethatafleetofnewgasfired power stations (mainly combined cyclegas turbines (CCGTs)) will have to be built to cover the considerable shortfall in base-loadgenerating capacity and to provide back-upfor intermittent renewable power, especiallyoffshore wind, where substantial expansionof capacity is planned. There is no other technologyavailablethatcanfulfiltheseneedson this scale, with the necessary reliability and withinthetime-framementionedabove.


LondonEnergyConsultingalsocomparedtheeconomicsofoffshorewindgenerationandaCCGTpowerplantrunningat90percentloadfactor. The results are shown in Figure 45.Over therangeofpricesconsidered,Round2offshore wind only becomes economic witha gas price above 90p/therm (p/th) and aCO2 price of £120/tonne;with a gas price of 120p/th, offshore wind power becomeseconomic above a CO2priceof£70/tonne(theenvisagedpricein2030undertheUK’sCarbonPriceFloor).

Such prices for CO2 are beyond the realms of current contemplation under the EU’sEmissionsTradingSchemeandthesetwogaspricesareoftheorderof50and100percentabove current prices. Even under the reference conditionsusedbyDECC(80p/th forgasand£80/tonneofCO2), it is not economic to invest inoffshorewindand,asFigure45alsoshows,

Round3offshorewind isevenmoredifficultthanRound2.

Atthetimeofwriting,DECChadjustpublishedits draft proposals for ‘strike prices’ forrenewable generation associated with CfDs.Per mega-watt hour (MWhr) of electricityproduced, the proposals include £155 foroffshore wind, £100 for onshore wind, £125 for large scale, solar photo-voltaic (PV)and£305foreitherwaveortidalpower.Thesecomparewithacurrentmarketpriceof£50to55/MWhrand,ifconfirmed,wouldmeanthatthe subsidies which consumers will have to fund through their future bills are of the order of100and200percentforon-andoff-shorewind, respectively, 150 per cent for largescale solar PV and 500 per cent for marinetechnologies. The sustainability of subsidies onthisscalehastobequestionable.

Figure 45: The Economics of Gas and Offshore Wind Generation

120 7.5 8.1 8.7 9.3 9.9 10.5 11.1 11.7 12.3 12.9 12.9 12.9110 7.2 7.8 8.4 9.0 9.6 10.2 10.8 11.4 11.9 12.5 12.5 12.5100 6.8 7.4 8.0 8.6 9.2 9.8 10.4 11.0 11.6 12.2 12.2 12.290 6.5 7.1 7.7 8.3 8.9 9.5 10.1 10.7 11.3 11.9 11.9 11.980 6.2 6.8 7.4 8.0 8.6 9.2 9.8 10.4 11.0 11.6 11.6 11.670 5.9 6.5 7.1 7.7 8.3 8.9 9.5 10.1 10.7 11.3 11.3 11.360 5.5 6.1 6.7 7.3 7.9 8.5 9.1 9.7 10.3 10.9 10.9 10.950 5.2 5.8 6.4 7.0 7.6 8.2 8.8 9.4 10.0 10.6 10.6 10.640 4.9 5.5 6.1 6.7 7.3 7.9 8.5 9.1 9.7 10.3 10.3 10.330 4.6 5.2 5.8 6.4 7.0 7.6 8.2 8.8 9.4 10.0 10.0 10.020 4.3 4.9 5.5 6.1 6.7 7.3 7.9 8.5 9.0 9.6 9.6 9.610 3.9 4.5 5.1 5.7 6.3 6.9 7.5 8.1 8.7 9.3 9.3 9.3

40 50 60 70 80 90 100 110 120 130 140 150

Gas Price in p/th

Go Wind ? offshore R3 Text DECC reference conditions 80p/th, £80/tonneGo Wind ? offshore R2Go Gas Text Market conditions at Jan 2013

Carb

on P

rice

( £/t

onne

)

Generation projects, starting in 2018, using 10% discount rate. Gas at load factor of 100%.

Source: London Energy Consulting using data from DECC October 2012

Carb

on P

rice

(£/t

onne

)

Gas Price in p/th

Source:LondonEnergyConsultingusingdatafromDECCOctober2012


b)HeatItstillremainsnotablehowlitt leoftheenergydebate, in public at least, is about heat, especially given the size of the heat sector in thiscountry.GasdominatesheatinginBritain,most particularly in the domestic and smallcommercial sectors where individual boilers are the preferred choice of providing heat. According to National Grid’s Future Energy Scenarios18publishedinSeptember2012,gasdemand for these purposes is declining as a resultofbetterinsulatedbuildingsandhigherefficiency boilers. These changes, while notrapid, accumulate steadily as the years go by.

DECC published its heat strategy, The Future of Heati ng: meeti ng the challenge19, in March2013,havingconsultedon thematterduring the spring of 2012. It has dividedits strategy for this large subject into four maincategories:• Efficientlowcarbonheatinindustry• Heat networks• Heat and cooling for buildings• Grids and infrastructure

Themost important characteristic of heat isthe extent of the change in demand between summer and winter. While industrial demand forheatusedinvariousproductionprocessesis reasonably constant and predictable, seasonaldemandforheating(andcooling) indomesticandcommercialpremises isalmostwholly weather dependent. During the winter peak, demand for heat – mostly supplied by gasinBritain–isaboutfivetimesthedemandfor electricity.

Thissimplemultipliergivesaclear indicationof the scale of the transformation which

the government foresees, especially when DECC’s strategy envisages the spread of heat networks in towns and cities and greateruse of electricity in heating through air andground source heat pumps; in this regard, itisworthnotingthatheatpumpsperformbestin thermally efficientbuildings. Furthermore,increasingrequirementsforairconditioningincommercialand,probably,domesticpremisesin future will add to the demand for electricity forheatingandcooling.

Thebiggestdifficultyliesinthelackofenergyefficiency inmuchof this country’sbuildingsstock. Modern buildings to the latest standards are part of the answer, but in the domesticsector the turnover is slow (100+ years),whereas in the large commercial sector it is muchfasterandtheopportunitiestoinvestinthe latest technologies considerably greater.

According to National Grid’s Future Energy Scenarios, the domestic insulation market willstart to saturate in the next ten years, with the residual housing stock being much harder and more expensive to treat. In like manner, the replacement of older gas boilers with modern, highefficiencyones–oneof thesimplestandmost beneficial changes which is being madenow – will have largely run its course by the mid-2020s.Nonetheless,itisalmostimpossiblefor an upgraded, older building to reach the thermalefficiencystandardsofanewbuilding.

It is likely, in our opinion, that effecting thechanges inthenation’sheatsupplies implicit inthe four main categories listed above will require substantial investment and will only happenslowly. Therefore, gas will continue to play asubstantial role in providing heat for severaldecades to come.

18 Seehtt p://www.nati onalgrid.com/uk/Gas/Operati onalInfo/TBE/Future+Energy+Scenarios/

19 Seehtt ps://www.gov.uk/government/publicati ons/the-future-of-heati ng-meeti ng-the-challenge


c)TransportOil products continue to dominate fuels fortransport throughout the world (>90 percent share). Apart from the electrificationof railway lines with high traffic densities,the inherent properties of oil products –availability, portability and energy density – make them uniquely suitable for land, sea and air transport, especially over long distances. Asmentionedpreviously,however,gasisnowbeing tried on a modest scale in medium to heavycommercial road transport in theUSAand in buses in various parts of the world.

While some of the new technologies being developed demonstrate applicability for road transport over shorter distances, such as for cars, buses and vans in and around towns and cities,nonesofarshowssignsofreplacingoilproducts for longer distances on land, never mind at sea or in the air. And thus far, neither hybrid nor purely electric vehicles have capturedthepublic’simagination.

Meanwhile, under a combination of morestringent regulatory requirements, high prices and competitive pressures, manufacturershave already made considerable progress in improving the fuel efficiency of petrol anddiesel vehicles during the past ten years and there is the likely prospect of more advances intechnologyimprovingefficiencyyetfurtherduring the coming years.

In the air, new technologies such as are evident in Boeing’s 787, which enteredservice in October 2011, and Airbus’s A350,whichflewforthefirsttimeinJune2013,arecreating stepchanges in fuelefficiency.Evenwith long established airframes, such as the popular 737 and A320 families of aircraft,

the relentless demands of competition aredeliveringeverbetterperformanceandlowerfuelconsumption.

It seems inevitable that oil’s products will remainthedominantfuelsfortransportuntil2030andprobablybeyond.

GasfromShale

As a result of the extraordinary developments in theUSA in thepast fewyears,oneof themost openly debated subjects in Britain and the EU has been shale gas and the hydraulic fracturing (or ‘fracking’) of wells, a technique which has existed in oil and gas explorationandproductionformorethan60years, longbeforeshalegasexplorationstarted20.

A wide variety of reports has been published, but a joint publication by the Royal SocietyandtheRoyalAcademyofEngineeringinJune201221 was among the more keenly awaited in this country. It had been commissioned by the government’s Chief Scientific Adviser intheaftermathoftwosmalltremorsfollowinghydraulic fracturing of a well by Cuadrilla Resources in Lancashire during spring 2011.DECC lifted the temporary moratorium onshale gas drilling in mid-December 2012,together with imposing some additionalcontrolsonoperatorstomitigatetherisksofa recurrence.

In June 2013, DECC released the latestassessment by the British GeologicalSurvey22 of thepotential shale gas resourcesin the Bowland Shale across the northmidlands and northern England (most of Lancashire,Yorkshire,Cheshire,Staffordshire,Derbyshire and Nottinghamshire plus parts

20 Thereareunderstoodtobemorethanamillionwellsworldwidewhichhavebeenhydraulicallyfractured;suchwellsalreadyexistbothonshoreandoffshoretheUK.

21 Seehtt p://www.raeng.org.uk/news/publicati ons/list/reports/Shale_Gas.pdf

22 Seehtt ps://www.gov.uk/government/publicati ons/bowland-shale-gas-study


of Leicestershire and Lincolnshire). The size of the resources in place is much larger than previouslyforecast,withacentralcaseof37.6trillion cubic metres (tcm). For comparison, current consumption in the UK is about 85billion cubic metres (bcm) per year and so, even if only ten per cent of the resource were to be recovered, this would still equalmorethan 40 years of supply at today’s rate ofconsumption.

However, it is not possible at this stage to forecast how much will be technically and economically recoverable. This will only become apparent when many more wells have been drilled and tested. As data are accumulated, it will gradually be possible to forecastthepotentialsizeoftheprize.

Nonetheless, the signs are encouraging. Shale gas is most unlikely to induce thedegree of change in the UK (or EU) which has occurredintheUSAbecauseofverydifferentcircumstances, but there is the potentialfor a new arm of the oil and gas industry to

develop in Britain, providing investment, jobs, new gas supplies and tax revenues, while reducing imports. A report published by the Institute of Directors inMay 2013 examinesthepossibilities23.Inaddition,everythingelsebeing equal, any new supplies of gas will tend toexertdownwardpressureonpricesrelativeto what they would otherwise be.

As drafting of this report was beingcompleted, the government announced new taxarrangementsfortheproductionofshalegas, modelled on the FA concept which applies totheUKCS(seeSection6formoredetailsofthetaxregimeasappliestotheUKCS).

Further information about shale gasmay be found at the following three websites especially established by the industry inEurope:

htt p://www.ngsfacts.org htt p://www.shalegas-europe.eu/en htt p://www.europeunconventi onalgas.org

23 See htt p://www.iod.com/infl uencing/policy-papers/infrastructure/infrastructure-for-business-getti ng-shale-gas-working


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9.


a)Oil&GasUK’sMembership

Much of the data used in this publicationhave been collected from Oil & Gas UK’s membership, the composition of which canbe seen below in Figure 47. The membership has changed dramatically since 2007, fromconsistingofalmostentirely largeroperatorsto encompassing all parts of the industry.

The influxof smaller independentoperators,contractors, suppliers and associated service businesses is a reflection of Oil & Gas UK’sobjective of welcoming a broader, morerepresentative membership. The increaseof smaller, independent operators is a result of the changing nature of the companies that operate on the UKCS compared withearlier years.

9.Appendix

Figure 47: Composition of Oil & Gas UK’s Membership

Operator16%

Contractor / Supply Chain80%

Associate Member4%



Figure 48: Field Allowances Available for the UKCS

Notes.

1.Ifafieldqualifiesformorethanonefieldallowancethenitcanonlyclaimthemorevaluableone,withtheexceptionoffieldsthatsubsequentlyqualifyforaBrownFieldAllowance,whichisavailableinadditiontoanyoftheothercategoriesoffieldallowance.

2. The conversion of oil from tonnes into barrels varies depending on the density of the crude from each reservoir. Forillustrativepurposesonly,alightsweetcrudeisaround0.132tonnes.Forgastheconversionissetat1,100cubic metres to equal one tonne.

b)FieldAllowances

Name Pre-Tax Value QualificationCriteria (asperFieldDevelopmentPlanconsent) EffectiveDate

SmallFields Up to £75million

Central case recoverable reserves of up to 3.5milliontonnes(circa25millionboe)

March2009

UltraHighPressure/High Temperature (HPHT)

Up to £800million

Reservoirconditionsexceedingpressuresof862barandtemperatureof166degreesCelsius

March2009

Ultra Heavy Oil £800million OilatAPIgravitybelow18degreesandviscosityexceeding50centipoiseatreservoirtemperature and pressure

March2009

Deep Water Gas Up to £800million

• Thefieldisinwaterdepthsexceeding300metres

• Morethan75percentofthereservescomprise gas

• Gas is to be transported for more than 60kilometresalonganewpipelinetorelevant infrastructure

January2010

SmallFields[amended] Up to £150million

Central case recoverable reserves of up to sevenmilliontonnes(circa50millionboe)

March2012

Large Deep Water Oil Up to £3,000million

• Central case recoverable reserves of between25millionand55milliontonnes(circa187.5–412.5millionboe)

• Thefieldisinwaterdepthsexceeding1,000metres

March2012

LargeShallow Water Gas

Up to £500million

• Central case recoverable reserves of between10and25billioncubicmetres

• Morethan95percentofthefield’sreserves comprise gas

• Thefieldisinwaterdepthslessthan 30metres

July2012

Brown Field Allowance Up to £50/tonne, up to a cap of £250million(£500millionifPRTpaying)perproject

• Authorised project capital costs exceed £60perincrementaltonneofoilandgas produced

• Projecthasbeengrantedconsentbythe Department of Energy and Climate Changeafter7September2012bywayofFieldDevelopmentPlanAddendum(see main text for further details)

September2012


API AmericanPetroleumInstitutebbl barrel(ofoil)(onebarrel=0.16m3 and7.55barrels=onetonne)BBL Balgzand (in the Netherlands) to Bacton (in Norfolk, England) gas pipelinebcm billion cubic metres (one metre3=35.3cubicfeet)bcm/y billion cubic metres per year (of gas)BFA Brown Field AllowanceBIS Department for Business, InnovationandSkillsbillion onethousandmillionor109

boe barrelofoilequivalent: this includes oil, gas and other hydrocarbons and equates all of these with oil, in energy equivalent terms, so that a common measure can be made ofanyofthem(oneboe=164m3 or5.8thousandcubicfeetofgas)bpd barrels per dayboepd barrel of oil equivalent per daybrownfield anoilorgasfieldalreadyin productionBTU BritishThermalUnit(ofenergy)capex capital expenditureCATS CentralAreaTransmissionSystemCCGT combinedcycle(gas+steam) gas turbineCCS carbon capture and storageCDA Common Data Access (a subsidiary of Oil & Gas UK)CfD contractfordifferenceCHP combined heat and powerCNG compressed natural gasCNS centralNorthSeaCO2 carbon dioxide (one of the six ‘greenhouse gases’ under the Kyoto protocol)condensate low density, liquid hydrocarbon usually associated with natural gas which, depending on temperature and pressure, can be gaseousCoP CessationofProduction (fromafield)CT CorporationTax(seealsoRFCT)DEAL Digital Energy Atlas & LibraryDECC Department of Energy and Climate ChangeDRD DecommissioningReliefDeed

E&A explorationandappraisal(drilling)EEA European Economic Area (the EU plus Norway, Iceland and Liechtenstein)EIA EnergyInformationAdministration (oftheUSA)EMR electricity market reform (by DECC)EOR enhanced oil recoveryE&P explorationandproduction (of oil and/or gas)EU European Union (the28memberstates)EUETS European Union’s Emissions Trading SchemeFA Field Allowance, a tax relief for certaincategoriesoffieldFDP FieldDevelopmentPlanFiT Feed-inTariff(forelectricity)FPAL FirstPointAssessmentLtd, anorganisationproviding aregistration,qualificationand performance monitoring system of the industry’s suppliers and contractorsFPSO floatingproduction,storage andoffloading(vessel)GDP GrossDomesticProduct

(themainmeasureofdomesticeconomic output)

GHG greenhouse gas (of which there are six under the Kyoto protocol)GtL gas to liquidsGVA Gross Value AddedGW GigaWatt(ofelectricity): onebillionwattsHH Henry Hub (the principal trading pointforgasintheUSA)HMRC HerMajesty’sRevenueand Customs(sometimesknownas ‘the Exchequer’)HMT Her Majesty’s Treasury HPHT high pressure, high temperature

(of reservoirs)HSE HealthandSafetyExecutiveICoP InfrastructureCodeofPractice

(forthirdpartyaccesstoplatforms,pipelines etc)

IEA InternationalEnergyAgency(part of the OECD)IOC InternationalOilCompanyIOR increased oil recoveryITF Industry Technology Facilitator, a not-for-profit,industryownedbody

c)GlossaryofTermsandAbbreviations


JOA JointOperatingAgreement (betweenpartnersinafield)kms kilometresKW KiloWatt(ofelectricity)–unitof power:onethousandwattsKWh KiloWatthour–unitofenergyLNG liquefiednaturalgasmboepd million barrels of oil equivalent per daymbopd million barrels of oil per daymcm/d million cubic metres per day (of gas)mtoe million tonnes of oil equivalentmt/y million tonnes per yearMW MegaWatt(ofelectricity)–unitof power:onemillionwattsMWhr Mega-WattHourNBP NationalBalancingPoint(fictional locationinBritainwheretheNTS isnotionallyinbalanceandat which the trading of gas takes place)NGL natural gas liquid (e.g. butane, propane)NNS northernNorthSeaNTS NationalTransmissionSystem(high pressure gas transmission system inBritainoperatedbyNationalGrid – the ‘motorway’ network for gas)OCGT open cycle gas turbineOECD OrganisationofEconomic

Co-operationandDevelopmentOGP InternationalAssociationofOiland GasProducersONS OfficeofNationalStatisticsOPEC OrganisationofPetroleum ExportingCountriesopex operatingexpenditureOPITO the upstream oil and gas industry’s trainingorganisationOTC over the counter

PAR potentialadditionalresourcesPILOT joint oil and gas industry – government task force chaired by theSecretaryofStateofDECCPRT PetroleumRevenueTaxp/th pence per therm (for gas)R&D research and developmentRFCT ‘RingFence’CorporationTax

(as applied to upstream oil and gasproduction)

ROV remotely operated vehicle (subsea)SC SupplementaryCharge(acorporate tax applied to upstream oil and gas productioninadditiontoRFCT)SCDI ScottishCouncilforDevelopment and IndustrySIC StandardIndustrialClassification (refONS)sidetrack descriptionofawellthatisstarted

fromtheboreofanexistingwell,but is then deviated to create a new well

SME small to medium (sized) enterpriseSNS southernNorthSea(sometimes referred to as ‘southern gas basin’)STEM Science,Technology,Engineering and Mathstrillion onemillionmillionor1012

tcm trillion cubic metresUKCS UnitedKingdomContinentalShelfUKTI UK Trade & InvestmentUDC unit development costUOC unitoperatingcostWoS westofShetland(sometimes referredtoas‘Atlanticmargin’)YTF yet-to-findresources

Editorial Note:• Thedraftingofthisreportwasundertaken

duringJuneandJuly2013.

Designed and produced by The Design Team at Oil & Gas UK.

Oil&GasUK(Aberdeen)3rdFloorThe Exchange 262MarketStreetAberdeen AB115PJ

Tel:01224577250

Oil&GasUK(London)6thFloorPortlandHouse BressendenPlaceLondon SW1E5BH

Tel:02078022400

ISBN:1903004098©2013TheUKOilandGasIndustryAssociationLimitedtradingasOil&GasUK

www.oilandgasuk.co.uk

[email protected]

economic report 2013

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