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Offshore Floating Asset Decommissioning Market Study January 2018

Offshore Floating Asset Decommissioning Market Study and Gas Factsheets/Offshore... · Offshore Floating Asset Decommissioning Final Report January 2018 1) Executive Summary 2) Macro

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Offshore Floating Asset

Decommissioning Market StudyJanuary 2018

Offshore Floating Asset Decommissioning

Final Report January 2018

1) Executive Summary

2) Macro Economic Analysis

3) Drivers of Decommissioning

4) Decommissioning Processes & Considerations

5) Western Europe Market Outlook

6) Competitive Analysis of Scottish Ports

7) Acronyms & Abbreviations

8) Appendix

1) Executive Summary

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Source : Westwood Analysis, Rig Logix

Executive SummaryKey points and conclusions from our report

4

Macro Economic Analysis

Drivers of Decommissioning

Decommissioning Processes &

Considerations

Western Europe Market Outlook

Competitive Analysis of Scottish

Ports

Vessel Decommissioning

• Oil will continue to be a primary source of energy over the long-term, with production increasingly sourced from deepwater. Investment in deepwater will inevitably drive the requirement for floating production solutions in the long-term.

• However, projects sanctioned prior to the downturn will compound global oversupply of oil in 2018. As such, oil prices will remained supressed in the near-term with volatility expected to continue which could translate into increasing numbers of assets being considered for stacking or decommissioning.

• The decision to decommission an asset or field is typically driven by a number of key drivers, including commodity price fluctuations, basin maturity, operational cost overheads, and/or whether an asset could be used as a production hub.

• MMO spend is not expected to recover to pre-downturn to levels as E&P companies seek to prolong reductions in pricing, as well as delay non-essential maintenance. MMO cost pressures will inevitably factor into the decision to decommissioning an asset

• Owners are faced with a decision when their assets are proving to be uneconomical. They can Warm or Cold Stack them in ports across the globe or they can look to fully decommission them to save on ongoing OPEX costs. Stacking has been the historic option of choice in the region.

• There is a significant number of considerations when planning a decommissioning programme, beginning with regulator approval. Cessation of field Production is closely followed by the decision on the assets future. If the asset is to be decommissioned, there is a great deal of onshore as well as offshore preparatory work required to ensure a smooth project from start to finish.

• There are a number of ageing assets in the North Sea region that are potential candidates for decommissioning in the next 10 years. If the current oil price environment persists then it is likely owners will be looking to make decisions on stacking and or decommissioning of these which could present opportunity for the Scottish ports. Decisions to decommission floating assets have been taken by the likes of Transocean who do own a number of the stacked rigs in the North Sea region at present and therefore discussion with the asset owners would be encouraged of the Port operators to investigate possible workloads.

• The most important key award factor when an owner is assessing a facility to decommission an asset is the presence, or otherwise, of a Tier 1 contractor who can manage the programme for them. Having a reputable contractor in place allows the asset owner to concentrate on what it is they do best.

• Westwood believes there are a number of Scottish ports who in time could become competitive in tendering for work in the floating asset and MODU decommissioning market. However at present Dales Voe, Greenhead Base and Dundee stand out as being most prepared to service the market immediately.

• The levels of ship breaking / decommissioning activity that has taken in place in the UK over the last 5 years is minimal considering the global levels.

• The market is clearly dominated by 5 countries, India, Bangladesh, Turkey, China and Pakistan. Westwood believe the Scottish ports do not currently represent a competitive offering when considering this market.

• There exists chronic oversupply in global OSV provision and without brave decisions by vessel owners on decommissioning, this will continue into the future.

Use of a Dry Dock

• When considering whether or not the presence of a Dry Dock offers a commercial advantage with regards floating asset decommissioning, our consultation and opinion suggests that if a Dry Dock exists already at a facility then it will offer an advantage. It is unlikely to represent an immediate investment opportunity for an existing facility which does not have a Dry Dock as the level of activity forecast at this stage would perhaps not sustain the level of required investment..

• The basis for this being the bespoke nature of every decommissioning project and the presence of the Dry Dock allows an increased number of project engineering options in terms of access, machinery used and flow back contamination protection.

2) Macro-Economic Analysis

Source: Westwood Analysis, EIA, BP.

Macro-Economic Analysis

Global Outlook Long-Term Energy DemandGlobal energy demand is the principal indicator of all Oil & Gas (O&G) related investments, driving support for hydrocarbon exploration and consequently oilfield services over the long-term

6

Global Energy Demand OutlookMmboe/d (LHS), Billions (RHS)

Global Energy Demand by RegionMmboe/d

Global Energy Demand by FuelMmboe/d

▪ Energy demand is expected to

increase by c. 31% between 2015

and 2035, driven by growth in

population and rising GDP per

capita across developing countries.

▪ Almost all of the growth in energy

consumption will come from

emerging non-OECD economies -

primarily China and India.

▪ Outside of Asia, strong growth in

demand is expected in Africa (c.

+77%), Middle East (c. +49%) and

South & Central America (c. +32%).

▪ Energy demand within developed

nations is expected to stagnate,

with the combined European and

North American share of global

energy demand falling from c. 36%

in 2015 to c.28% in 2035.

▪ Whilst hydrocarbons will continue

to dominate the energy mix,

renewables demand is expected to

play an increasingly significant role

as nations look to fulfil the COP21

GHG emissions commitment,

supported by increased energy

diversification and independence

agendas.

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35

Energy Demand

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1,000

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9,000

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APAC

Americas

Europe & Eurasia

Middle East

Africa0

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Coal

Natural Gas

Renewables

Nuclear

Liquids

Global Population

▪ Growth in oil supply during the past

10 years has principally come from

the onshore sector. Between 2005

and 2016, global onshore oil supply

grew by c. 7.7 mmbbl/d, driven

primarily by growth in output from

US unconventionals.

▪ Over the same period, the offshore

sector has seen moderate growth in

supply of c.1.6 mmbbl/d.

▪ Offshore shallow water supply contracted by c. 1.3 mmbbl/d.

▪ Offshore deepwater supply however grew by c. 2.9 mmbbl/d.

▪ Westwood anticipates that oil

supply growth from 2017 to 2023

will be as follows:

▪ Onshore c.8%

▪ Offshore shallow water c.3%

▪ Offshore deepwater c.12%

▪ Strongest growth anticipated from

the offshore deepwater sector.

However, onshore oil production is

expected to remain the dominant

source of global oil supply to 2023.

Source: Westwood Analysis, BP, EIA, OPEC.

Macro-Economic Analysis

Oil will continue to be a primary source of energy over the long-term, with production increasingly sourced from deepwater. Investment in deepwater will inevitably drive the requirement for floating production solutions in the long-term

7

Oil Supply Outlook to 2030Mmbbl/d

Indexed Oil Supply Growth by SourceIndex 2000

Global Outlook Long-Term Oil Supply

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Offshore Deepwater

c.6.2 mmbbl/d (2017)

c.0.8 mmbbl/d (Δ 2017 to 2023)

Onshore

c.62 mmbbl/d (2017)

c.5.0 mmbbl/d (Δ 2017 to 2023)

Offshore Shallow Water

c.21 mmbbl/d (2017)

c.0.7 mmbbl/d (Δ 2017 to 2023)

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97

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Source: Westwood Analysis, EIA.

Macro-Economic Analysis

Near Term Oil Supply & Demand TrendsProjects sanctioned prior to the downturn will compound oversupply in 2018. As such, oil prices are expected to remain supressed in the near-term with volatility expected to continue

8

▪ Currently estimated at 96.7 mmbl/d, global

liquids consumption is at unprecedented

levels, driven in part by lower spot prices for

crude oil. There is general consensus that

growth rates will be sustained over the next

few years with both the IEA and EIA

expecting liquids consumption to top 100

mmbl/d 2H 2018.

▪ However, despite this growth, the global

economy has been unable to absorb recent

supply additions. Between 2014-15, global

liquids output increased by 3.1 mmbl/d, 70%

greater than consumption, and resulting in

overcapacity and an oil price crash.

▪ US Shale has been well documented as the

principal culprit for this supply surge, and

accounted for 43% of incremental output

with OPEC and major offshore projects

accounting for 21% and 35% respectively.

▪ Since the industry downturn supply has

increased by a further 1.3 mmbl/d despite

net losses from the US and China. These

gains have mainly come from OPEC and

Russia who have added a net 2 mmboe/d

despite 1.8 mmboe/d production cuts in

place since November 2016.

▪ Over the next few years, overcapacity is

likely to be exacerbated by the start-up of

numerous high profile oil projects

sanctioned during 2013-14. Westwood

estimates that an additional 1.6 mmbl/d of

new capacity will enter the market by 2018

in addition to 0.6 mmboe/d from resumption

of production from Libya and Nigeria.

Short-term Liquids Consumption and Stock Change BalanceConsumption mmbbl/d (LHS), Stock Change & Balance Mmbbl/d (RHS)

Recent Oil Supply Trendsmmbbl/d

Major New Oil Capacity by Country (Top 30 Oil Fields)Incremental Increase 2017-18 mmbbl/d

Major New Oil Capacity by Operator Type (Top 30 Oil Fields)Incremental Increase 2017-18 mmbbl/d

90

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98

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Q1

US

Cru

de

Ru

ssia

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ina

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oth

ers

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15

Q1

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de

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ssia

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ina

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Q1

-3

-2

-1

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84

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102

Q1

'12

Q3

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Q3

'13

Q1

'14

Q3

'14

Q1

'15

Q3

'15

Q1

'16

Q3

'16

Q1

'17

Q3

'17

Q1

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Q3

'18

Implied Stock Balance

World Consumption

+ + ++

+

+

+ +

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go

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UK

Onshore

Offshore

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1,500

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'17

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sho

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'18

IND

'17

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IND

'18

▪ In November 2016, OPEC members agreed to cut supply by c.1.2mmbbl/d as long as non-OPEC countries, such as Russia, cut production as well by a further c.600,000bbl/d.

▪ Compliance is a key issue to the success of the cuts. Although some non-OPEC nations have missed targets, OPEC nations (primarily Saudi Arabia and Angola) collectively surpassed targets in March-May 2017. The deal has recently been extended by a further nine months to March 2018.

▪ As a result, Westwood expects market rebalancing to continue in 2017 with c. 0.6 mmbbl/d undersupply expected as the market adjusts to the supply reduction.

▪ Oversupply returns in 2018 and if the current levels of under investment continue in the sector, coupled with the decline rates in production then there is an undersupply position that exists until the end of the decade.

Macro-Economic Analysis

Global Outlook Near to Medium Term Oil Supply-Demand BalanceWestwood identified some oil price stabilisation in 2017 as OPEC market leavers reduce oversupply; however, the market could be poised for another decline as projects sanctioned pre-downturn contribute 4.6mmbbl/d between 2018-2020

9

Net Supply-Demand Change vs Oversupplymmbbl/d

Source: Westwood Analysis.

1.6

1.0

-0.6

0.7

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-0.1

-2.0

-1.5

-1.0

-0.5

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1.0

1.5

2.0

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3.0

-2.0

-1.5

-1.0

-0.5

0.0

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1.0

1.5

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2.5

3.0

2015 2016 2017 2018 2019 2020 2021

Demand Additions (Chart)

Supply Additions

Implied Oversupply

Impact of Opec Cuts

Key Offshore Projects based on Production Additions

Top 5 offshore projects represent c.48% of additions;

▪ Khafji (Kuwait/ KSA)▪ Kashagan (Kazakhstan)▪ Upper Zakum (UAE)▪ Buzios (Brazil)▪ Egina (Nigeria)

Source: Westwood Analysis, Various.

Macro-Economic Analysis

Near to Medium-Term Oil Price OutlookUnder the reference case, Westwood expect oil prices to range between $50-$60/bbl over the next 12 to 18 months as any equilibrium gains from increased consumption and OPEC production cuts are offset by excess US shale capacity

10

Oil Spot PriceBrent $/bbl

High case impact on Western Europe decommissioning:

▪ Incentive to keep assets producing for longer periods of time

▪ Delay of decommissioning expenditure

▪ Westwood estimate of c$86bn of expenditure for 2017-2040

Reference case impact on market

▪ This reference case forms the basis for the market forecasts outlined in this report

▪ Westwood estimate of c$103bn of expenditure for 2017-2040

Low case impact on Market

▪ Increased asset abandonment

▪ Acceleration of decommissioning expenditure

▪ Westwood estimate of c$117bn of expenditure for 2017-2040

▪ Oil prices are a key indicator for levels of E&P investment in both new offshore production capacity and maintenance of existing infrastructure. The recent price collapse has severely impacted the free cash flow of E&P companies, leading them to pressure supplies to achieve lower pricing to reduce costs.

▪ Our oil price reference case expects an average of $51/bbl for 2017. 2018 is expected to remain suppressed due to incremental supply from major offshore projects, compounded by OPEC ending the production cuts after 1Q2018.

▪ 2019 is projected to average $54/bbl with a net surplus in oil supply and significant US shale capacity still looming large. Post 2020, we assume a more rapid growth profile as limited incremental supply is outstripped by anticipated consumption growth. Oil prices are projected to reach $65-72/bbl over 2021/22 as US shale capacity is absorbed, leading to a net-deficit supply balance.

▪ Our high case assumes prices reaching $60/bbl by end of 2018 and $85/bbl by 2022. Main factors driving our high case are a continuation of OPEC cuts post 1Q2018 and more aggressive than expected natural decline rates.

▪ Our low case assumes prices range from $40-45/bbl between 2017-22. Factors driving our low case include further improvements to US shale economics, premature withdrawal of OPEC cuts and the rise of Libyan and Nigerian supply.

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Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22

Fracklog

Improved US Shale Efficiency

Libya & Nigeria

Suspension of OPEC cuts

OPEC Cuts Sustained

Chinese Imports

Global Consumption Growth

Decline Rates

Forward oil price spread is based on WGEG analysis and views from over 50 leading industry analysts andinvestment banks.

HIGH CASEREF CASE

LOW CASE

▪ Overall production in the North Sea is mature, with the UK sector in particular in long-term decline. Norway, another major producer in the North Sea, is less mature but numerous major fields are reaching the end of their commercial lives, despite enhanced recovery techniques.

▪ Norway’s oil production will be boosted significantly in the long-term by Statoil’s giant Johan Sverdrup development. Gas will remain stable throughout the period with the Aasta Hansteen development of particular note due to its utilisation of the world’s largest spar platform.

▪ Combined oil & gas production in the UK peaked in 2000, and output declined by 8% year-on-year through to 2014. Production will rally to 2.1 mmboe/d by 2019 due to developments sanctioned prior to the market downturn. However, the lack of investment from 2015-2017 could lead to production decline towards the end of the period.

▪ Total offshore E&P spend (including life of field activities) reached $55.2 billion in 2014 before contracting to $38.6 billion by 2017 – a drop of 30%. 2018 is expected to see a return to growth as E&P investment grows by 3% to reach $39.8 billion.

▪ There is a resurgence in spending levels between 2018-2020, largely resulting from c.14 fixed and c.4 floating platform installations – most notably the Johan Sverdrup installations in Norway, and the Culzean development in the UK.

▪ Reduced investment appetite among E&P operators during 2015-2017 will cause regional investment to return to 2017/2018 levels in 2021, suggesting this could be the ‘new norm’ for annual spend. While cost savings have been achieved, Westwood believes the market would require a substantial, and prolonged increase in oil prices in order to support new capital commitment over the longer term.

▪ In addition, considering lead time, any project which may secure FID in the period (2017-21), will only impact spend levels towards the end of the period.

▪ Capex serves as a proxy for the evolution of the offshore platform asset base. Given the current oil price outlook, it may be difficult to achieve the economics required for new project FID, meaning only a few FPS’ are expected to be installed/ secure FID in the medium term.

Source: Westwood Analysis, Various.

Macro-Economic Analysis

North Sea Capex OutlookThe continued decline in oil production coupled with reduced investment appetite among E&P operators could see numerous fields and assets considered for shut-in and decommissioning in the medium-term

11

Western European E&P Expenditure vs. Oil Price Reference CaseCapex $bn Brent $/bbl

North Sea Drilling & ProductionNorth Sea Wells Drilled (LHS), Kboe/d (RHS)

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North Sea Wells

UK Production

Norway Production

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2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

Capex

Brent Oil Price

▪ Norway – 1x FPSS, 1x FPSO, 1x Spar

▪ UK – 1x FPSO

3) Drivers of Decommissioning

Source: Westwood Analysis.

Drivers of Decommissioning

Western Europe Decommissioning DriversThe decision to decommission an asset or field is typically driven by a number of key drivers, including commodity price fluctuations, basin maturity, operational cost overheads, and/or whether an asset could be used as a production hub

13

▪ Commodity prices are extremely important to E&P operators, and are a key determinant for their future investment plans.

▪ A forecasted long-term decline in prices will be factored in by E&P operators who can ignore short term fluctuations in the market, but will have to factor in the prolonged decline or suppression in pricing.

▪ This is especially true for small E&Ps which have purchased stakes in many of the older UK fields, and need a strong cash flows to keep producing.

▪ Decommissioning activity may ramp up faster than expected in the next few years if the latest reference or low case is realised. Notably, the expected influx in liquids supply in 2018 has led industry commentators to revise the reference case from almost $60/bbl to $52/bbl for 2018.

▪ The asset base in the region is mature, with increasing O&M requirements.

▪ Stringent regulation demands regular maintenance. This also applies to assets which have been abandoned. Regular maintenance coupled with high labour costs makes this a substantial expense for E&P operators.

▪ O&M costs feature heavily when reviewing a fields life. If O&M costs consistently exceed revenues, assets will likely be abandoned.

▪ While MMO spend is not expected to recover to pre-downturn levels, the growing requirements for MMO and current oil price outlook will continue to compound cost pressures on E&P operators. As such, offshore MMO will be a key contributing factor into the decision to decommissioning an asset.

▪ A field may be able to produce cheaply, but there will always come a point where field production will diminish to a level where it simply is not economical to maintain production.

▪ The North Sea is a mature region with assets operating well beyond their intended design lives as a result of MMO, EOR and subsea-tieback strategies. However, the decommissioning market is now on the cusp of its first major cycle.

▪ Coupled with oil price considerations, the economic viability of a field can heavily fluctuate, with periods of prolonged low oil prices impacting E&P operator cash flows, and bringing field abandonment into the frame.

▪ Due to the proximity to shore, and size of some smaller fields, a number of fields simply do not offer the economics required to support processing or storage facility investment.

▪ The solution is to utilise tiebacks from the smaller fields to a ‘hub field’ which already hosts an offshore asset, thus improving the smaller fields commerciality.

▪ Hub’s can be installed specifically for a group of projects that would be uncommercial on their own, although existing assets are typically used where production has declined significantly enough to allow room for new production. This can effectively serve to extend the life of existing assets, prolonging the decision to decommission.

Commodity Prices Operations & Maintenance

Basin Maturity Offshore Field Hubs

Source: Westwood Analysis

Drivers of Decommissioning

Offshore Platform Spend Outlook MMOMMO spend is not expected to recover to pre-downturn to levels as E&P companies seek to prolong reductions in pricing, as well as delay non-essential maintenance. MMO cost pressures will inevitably factor into the decision to decommissioning an asset

14

North Sea Fixed Platform Population# of Platforms

North Sea Floating Platform Population# of Platforms

North Sea Offshore MMO ExpenditureMMO $m (LHS), Brent Oil Price $/bbl (RHS)

Average MMO Spend per Asset 2017-21$m

▪ The platform population serves as an indicator of future demand for MMO spend, and subsequently future decommissioning volumes. MMO will be a critical factor behind the decision to decommission, with operators heavily weighting Opex against asset or field revenues.

▪ The continued increase in Brent oil price (pre-2014) helped E&P operators maintain profitability despite mounting Opex overheads from EOR and MMO requirements.

▪ Notably, while the North Sea MMO market has been impacted by the oil price downturn, it has fared better than capex-led markets, with regional Opex falling 22% compared with Capex at 30% –between 2014 peaks and the respective market troughs.

▪ The decline in MMO spending was broadly caused by the delay of non-essential modifications by operators, service line pricing cuts, and headcount reductions.

▪ However, despite substantial reductions in costs, operators are still faced with substantial MMO spend requirements. This is particularly notable in the UK and Norway where average spend per asset is c.670% and c.320% greater than the global average.

▪ The UK and Norway can be classified as low volume, high tonnage markets, whereby the asset population forms a fraction of the global installed base, yet the average tonnage of each asset is significant; thereby attracting large MMO spend per asset.

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RoWeNorwayUKBrent Oil Price

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Global Average

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UK

Norway

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2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

UK

Norway

Source: Westwood Analysis.

Drivers Of Decommissioning

Cessation of Production (CoP) Decision MakingWhilst life-extension techniques are used, CoP will undoubtedly occur if the oil price downturn is prolonged. However, this willalso be dependent on operator comfort in relation to internal oil price estimates, balanced with asset cost pressures

15

“The biggest issue that operators have is the yearly expenditure to keep the platform

operable. Just keeping the lights on, on some of these platforms is 20-30 million a

year, so again it comes down to having a good economist on your team, who can

look at the scenarios of oil price vs. decommissioning costs v. Opex costs.”

Decommissioning Planner

“If they had realistic decommissioning costs built into their balance sheet they

probably should have started decommissioning some years ago.”

Well Abandonment Advisor

Illustrative Lifecycle of an Offshore Field$m

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17Ca

sh F

low

($m

)

Years from Project Start

Cumulative Cash Flow

Annual Cash Flow

Maximum Exposure

Loss Making

Payback

Net Present Value (NPV)

▪ The decision to cease production occurs as recoverable reserves are exhausted and incremental recovery costs prove financially less attractive.

▪ CoP is underpinned by the balance between oil price, Opex and petroleum tax versus the cost to decommission. As such, sustained low oil prices can lead to an increased focus on CoP on more mature fields which are near or past optimal lift.

▪ A key output from the above cashflow analysis of a producing field is to identify the critical point that will trigger the decommissioning process. This typically occurs when the field’s remaining NPV equates to ~150% of estimated decommissioning costs.

▪ Sustained low oil prices are likely to impact CoP for fields which are near or past their optimal life. Numerous small fields in the UK have had life extension work which requires a high oil price to be economic; without it, E&P operators are more likely to proceed with CoP programmes.

▪ The FPS development Athena, which only began production in 2012, as well as the well-established Dunlin field that first entered production in the 1970s are two CoP examples resulting from sustained low oil prices.

▪ The FPSO BW Athena was demobilised in February 2016, while the well management company Exceed was awarded a contract in March 2016 to support Fairfield Energy in its decommissioning programme at Dunlin.

Source : Westwood Analysis, Desktop Research

Drivers of Decommissioning

Vessel Decommissioning Overview The market for global vessel decommissioning is regarded as a highly fragmented market driven by varying degrees of policy, governance and geographic dynamics

16

• As with the decommissioning of floating oil & gas assets the main driver for ship owners to consider decommissioning is economics of the vessel.

▪ Vessels will typically have a life span of 25 to 30 years from the time of building however there is no hard and fast defining rule for a ships lifespan.

▪ Demand for the vessels services across all types will be crucial in deciding the future operational life or otherwise. If a vessel cannot be utilised on a contract the owner may take a decision to lay up or deep freeze a vessel. Similar to the warm and cold stacking model with oil & gas assets.

▪ Whilst a vessel is in lay up however it is still subject to ongoing maintenance, anchorage, fuel charges and staff costs associated with crew.

▪ When these costs outweigh the potential revenue from a vessel, the vessel owner may then decide to try and recover some costs by way of scrappage.

▪ When a vessel owner has taken the decision to decommission or break it down, if the vessel cannot be sold in secondary markets, they will initiate an auction process whereby any number of ship brokers will bid for ownership of the vessel with a view to then selling it on to a ship breaking yard.

▪ There is residual value in the vessel to both the owner and the broker creating an interim market between owner and shipbreaking yards.

▪ In developed countries the process would then typically be to dry dock the vessel and dismantle in stages with rigorous environmental and safety standards adhered to.

▪ In the countries where most shipbreaking activities take place however, there is perceived to be less attention to these standards and vessels are often run aground on beaches and then dismantled presenting serious environmental and health risks.

▪ There are a number of international and regional agreements that regulate the safe and environmental recycling of vessels globally.

▪ Annexe VI of the MARPOL convention as of January 2020 will limit fuel used in marine vessels to 0.5% mass on mass of sulphur content. This will mean vessels will have to comply or take rectifying action.

▪ The Hong Kong Convention from 2009 aims to ensure that ships in the process of recycling and disposal do not pose a health risk to human life.

▪ The Basel Convention regulates the movement of vessels to be decommissioned and the associated hazardous materials from developed to less developed nations.

▪ The European Convention which is aimed at regulating the transport of European flagged ships which are to be decommissioned, outside of the European region, should be fully implemented by 2019 however to date circumvention of this by less scrupulous asset owners has been witnessed.

▪ The Ship Breaking market is dominated by a small number of countries globally. These being:

▪ Bangladesh

▪ India

▪ Turkey

▪ China

▪ Pakistan

▪ Yards in these countries have carried out c.86% of global decommissioning's in the last 5 years to 2017.

▪ Costs are considered to be as low as one tenth of what they are outside of these countries.

Ship Breaking / Decommissioning Ship Breaking Process

Regulatory Environment Geographic Location of Activity

4) Decommissioning Processes & Considerations

▪ The procedure for dismantling an asset

will always be bespoke, even within the

same asset class. Despite looking similar,

vessels are very different in the way

internal elements are assembled and

therefore need careful planning and

consideration as to how to be dismantled.

▪ FPSO: A dry-dock or a slipway presents

significant benefits for the

decommissioning of an FPSO. However,

workarounds are available for facilities

lacking those capabilities.

▪ FPSS : Once the vessel is on the quayside,

it can be kept floating or landed on the

seabed for steps 2-4.

▪ TLP/SPAR: The deck would generally be

lifted off the hull offshore, and both

would be transported to shore separately

for dismantlement.

▪ Jack-up Rig: The legs of the jack-up rig

could be used to position the vessel to

facilitate dismantlement. Following this

however, they will need to be lifted or

dragged from the water and dismantled.

18

Specific Considerations

1. Secure the vessel to the quayside, dry

dock or graded bay

2. If necessary, clean the vessel

further to ensure all waste from production is

removed

3. Remove all loose modules or equipment such as storage units

or accommodation

modules4. Dismantle and dispose / recycle modules as they are taken off the

vessel

5. Once the hull is bare, move

ashore or keep in working station

6. Dismantle and dispose / recycle

the rest of the hull

Every dismantling project presents a unique requirement in terms of planning and execution. As every asset is built in a bespoke way, logic dictates they must be dismantled in a similar bespoke manner

Decommissioning Processes & Considerations

Decommissioning Procedure Onshore Dismantling

Source: Westwood Analysis, Industry Consultations

Source: Westwood Analysis.

Decommissioning Processes & Considerations

Asset Decommissioning The Path to DecommissioningWhen deciding to decommission a floating asset as part of the abandonment of a field, the asset owner must outline a plan for the asset, which can include stacking, removal for re-use, recycling or refurbishment, or final decommissioning

19

Capex

Opex

Gross Revenue

Illustrative Lifecycle of an Offshore Field$m

▪ When a decision on cessation of production (CoP) has been taken on a field or well with an assigned floating asset, the decision of what happens to the asset remains with the owner. The owner may differ from the operator of the field who may have leased the floating asset.

▪ The field owner is required to seek an agreement on the CoP and decommissioning project with the regulator. In the UK, this is the Offshore Petroleum Regulator for Environment and Decommissioning (OPRED), and the Oil & Gas Authority (OGA).

▪ Once the outline of the project has been agreed and CoP achieved, well P&A activity can then take place.

▪ The flushing and cleaning of floating production asset pipelines and subsea equipment is carried out in the field to ensure safe disconnection from all infrastructure prior to removal.

▪ In the case of both production and drilling assets, the owner will explore opportunities to re-use or sell the asset before considering decommissioning.

▪ Stacking floating assets for future use, or to delay decommissioning may be undertaken, particularly if the asset is still considered to be competitive (i.e. age of asset).

▪ If the asset is unable to move under it’s own propulsion, as is the case with the majority of floating assets in the North Sea, tug boats or other transportation solutions will be required to deliver the structure to its decommissioning facility.

Decision to Decommissioning

(A) Project Agreement with Regulator

Cessation of Production

Flushing & Well / Field P&A

Field Owner/ Operator Decision

(B) Asset Owner Decision

Can the Asset be Re-used or sold?

Is Warm/ Cold Stacking an option?

Decision to Decommission the

Asset

Warm Stack/ Cold Stack the rig

Decision as to Location of Work

Removal of Asset from the Field

Transportation of Asset to Shore

Decommissioning Work Performed

on Asset

(A) + (B)

Flow Chart: The Path to Decommissioning

Transfer of Asset to new owner

Yes

No

Yes

No

Source: Westwood Analysis, Riglogix. *Only six out of the 12 units detailed are currently located in the region.

Decommissioning Processes & Considerations

Historic Removals & Near-Term OpportunitiesWestwood has identified a number of floating production assets and drilling rigs as prospective candidates for decommissioning or scrappage, should the low oil price environment persist

20

North Sea Floating Production Asset Removals# of Platforms

North Sea Offshore Drilling Assets# of Offshore Rigs

▪ There have been 36 floating production asset removals between 1977 and 2017.

▪ Westwood notes that five of these units have been decommissioned to date, while 12 units are currently classified as ‘Laid Up’ or Shut-in’, and arguably qualify as potential near-term targets for decommissioning or scrappage. However, the scale of the opportunity has been reduced as only six of these assets are still located in the region.

▪ Of the five assets that have been decommissioned, only two of these have been carried out (in part) in the UK.

▪ The topside of the Hutton TLP was removed and exported to Russia for refurbishment and re-application, whilst the damaged hull was transported to Invergordon for decommissioning. Westwood understand however the physical breakdown of this hull piece, has yet to take place.

▪ 46 out of 101 drilling rigs in Western Europe are classified as either warm or cold stacked.

0

5

10

15

20

25

30

35

40

Removals Relocated Laid Up Shut-In Decomm.

FPSO

FPSS

TLP

Buchan Alpha (FPSS) ▪ Built 1981; Decommissioned 2017 in Shetland.

Hutton (TLP)▪ Built 1983; hull decommissioned 2008 in Invergordon.▪ Topsides were sourced and re-purposed in Russia

Janice A (FPU)▪ Built 1999; Decommissioned 2017 in Norway.

North Sea Producer (FPSO)▪ Built 1984; Upgraded 1997; Decommissioned 2016 in

Bangladesh

Seillean OPV - renamed Noble Seillean (FPSO)▪ Built 1998; Decommissioned 2013 in the UAE

0

20

40

60

80

100

120

Total Active Warm Stacked Cold Stacked

Jackup

Semisub

Drillship

54%

46%

Warm Stacked

<30 >30

40%

60%

Cold Stacked

<30 >30

North Sea Offshore Drilling Asset by Age ProfileYears, %

Near-term opportunities*

Near-term opportunities

Source: Westwood Analysis, Riglogix

Decommissioning Processes & Considerations

Decommissioning Previous RemovalsThe table shown below shows the floating production assets which have been removed since 1984 and the outcome of the removal. Some have been reused and therefore appear as duplicates in the table

21

Field Name Asset Name Year Removed Asset Type Outcome

Argyll Transworld 58 1984 FPSS Reused

Birch Benvrackie 1989 FPSS Reused

Crawford (ex Cragganmore) North Sea Pioneer 1990 FPSS Reused

Dunlin Seillean OPV 1991 FPSS Reused

Argyll Deepsea Pioneer 1992 FPSS Scarpped Turkey

Dumbarton (Donan) Seillean OPV 1992 FPSS Scrapped

Angus (UK) Petrojarl 1 1993 FPSO Reused

Captain Captain FPSS 1993 FPSS ReusedHudson Petrojarl 1 1995 FPSO Laid Up Norway

Varg (Lilleulv) Petrojarl Varg 2016 FPSO Laid Up Norway

Cheviot (ex Emerald redevelopment) Emerald Producer 1996 FPSS Reused

Machar Sedco 707 1996 FPSS Laid up MalaysiaBanff Banff FPSS 1997 FPSS Reused

Athena BW Athena 2016 FPSO Laid up UK

Mariner (UK) Petrolia FPSS 1997 FPSS Laid up Gulf of Mexico

Durward/Dauntless Glas Dowr FPSO 1999 FPSO Active SingaporeBlenheim Petrojarl 1 2000 FPSO Reused

Kyle Petrojarl 1 2000 FPSO Reused

Chestnut Crystal Ocean FPSO EWT 2001 FPSO Laid up Gulf of Mexico

Dunbar Sedco 706 2002 FPSS Reused

Darwin (Hutton) Hutton TLP 2002 TLP Scrapped UK

Leadon Global Producer III FPSO 2006 FPSO In Use North SeaGalley Northern Producer 2007 FPSS Reused

Fife Uisge Gorm 2008 FPSO In Use North Sea

Ivanhoe/Rob Roy AH001 FPSS 2009 FPSS Reused

Shelley Voyageur FPSO (Sevan 300 No 3) 2010 FPSO In Use North SeaGlitne Petrojarl 1 2013 FPSO Reused

Schiehallion Schiehallion FPSO 2014 FPSO Refurbed and Laid up Indonesia

MacCulloch North Sea Producer 2015 FPSO Scrapped

Ettrick Nexen Ettrick FPSO (Aoka Mizu) 2016 FPSO Laid up Poland

Jotun Jotun A FPSO 2017 FPSO Shut In

Foinaven Ocean Guardian 1994 FPSS Laid Up UK

Connemara JW McLean 1997 FPSS Laid Up Uk

Buchan Alpha Buchan A 2017 FPSS Decommissioned UK

Njord Njord A FPU 2016 FPSS Laid Up for Renovation in NorwayJanice Janice A FPU 2017 FPSS Decommissioned Norway

There is a significant degree of planning and preparation required from the yard before a project can be delivered, with eachproject representing unique challenges due to the bespoke design and age of the floating assets

22

Decommissioning Processes & Considerations

Asset Decommissioning Onshore Preparations

Source: Westwood Analysis. *Figure concluded from industry consultation.

Administration

Prepare all the appropriate documentation, authorisations and permits, to ensure assets, with potential hazardous waste onboard can come along the facility and be moored.

Securing the Asset

Review the facility and establish how the asset will be secure at the quayside or dock.

Materials

Verification of all material (hazardous and non-hazardous), and cross-check with documentation provided by operator / asset owner. Includes further cleaning of the asset prior to removing equipment/ modules.

Waste Management Plan

Ensure plans, and procedures for managing all the waste in-house and transporting it to other facilities for further processing or disposal, are in place.

Project Management – Asset Dismantling Processes

Finalize bespoke dismantling and disposal plans for the asset in co-ordination with the asset owner.

Asset Dismantling

Removal of module topsides, storage, derricks etc. from the hull. Dismantle and dispose / recycle all loose items as they are removed. Where possible, land the hull in a dry dock ahead of dismantling.

Waste Disposal

Dispose of the waste (hazardous or not) in a safe and environment-friendly manner, recycling wherever possible. Materials are typically moved to a third party location.

• Each floating asset examined by Westwood Energy will present unique challenges and requirements when planning for decommissioning due to their bespoke designs – even within the same asset class.

• Westwood have outlined the logical path each asset will follow when decommissioned / dismantled.

• A Port or decommissioning facility must secure the required permits to allow the activity to take place.

• It is vital that a capable contractor is aligned to the Port, either prior to yard’s contract award, or as part of the contract being awarded.

• The facility must be able to accommodate the weight and physical volume of material to be decommissioned.

• There must be a clear process for removal of all material, hazardous and non hazardous, either to disposal or recycling facilities onshore. This will involve working with specialist logistics companies.

• For the recycling of steel and other metals, the port and contractor must identify a suitable smelter or recycling centre capable of handling waste levels and materials.

• Scottish steel recycling facilities currently operate at c.30% capacity, thus the c.350-400te* per week from decommissioning activities should be accommodated.

• Assets will typically be moored at a quayside using ballast as a control for height access. Jack Up assets will likely utilise their legs for positioning.

• Given the ‘vessel-like’ hull of an FPSO, a dry dock may be utilised to dismantle the structure.

“A lot of floating assets in the North Sea are being

decommissioned outside the UK... due largely to the bad

reputation of UK facilities and costs. But incidents like Maersk’s

North Sea Producer ending up on a beach in Bangladesh with

radioactive waste shows cheap is not always better.”

Decommissioning Manager

Asset owners and the decommissioning contractor have a number of waste types to consider when flushing and cleaning the structure either in field or at the facility onshore

23

Decommissioning Processes & Considerations

Floating Asset Decommissioning Waste Removal

Source: Westwood Analysis

Asset Preparation & Cleaning

Subsea Installations & Stabilisation Features

Waste Stream Management

Waste Type

▪ Structures

▪ Wellheads

▪ Wellhead Protection Structures

▪ FPU Mooring System Structure Piles

Waste Type

▪ Bulk Liquids

▪ Marine Growth

▪ Normally Occurring Radioactive Material (NORM)

▪ Low Specific Activity (LSA) Scale

▪ Asbestos

▪ Other Hazardous Wastes

Method/ Approach

▪ Vessels, pipework and lumps will be drained prior to removal, and shipped in accordance with maritime transportation guidelines. Further cleaning and decontamination will take place onshore prior to recycling / re-use.

▪ Marine growth removed onshore and managed according to Oil and Gas UK ‘Management of Marine Growth during Decommissioning (2013)’ guidelines.

▪ NORM may be partially removed offshore under appropriate permit.

▪ Any sections found to contain NORM, LSA or Asbestos during recovery will be quarantined and taken to shore for disposal under the appropriate permit.

Waste Type

▪ Onboard Hydrocarbons

▪ Other Hazardous Materials

▪ Original Paint Coating

▪ Asbestos & Ceramic Fibre

Method/ Approach

▪ Hydrocarbons filtered and discharged into water disposal wells.

▪ Hazardous materials ashore for re-use/disposal by appropriate methods.

▪ Paint may give off toxic fumes/dust if flame-cutting or grinding/blasting is used. Appropriate safety measures must be taken.

▪ Appropriate control and management must be enforced

Method/ Approach

▪ Hydrocarbons filtered and discharged into water disposal wells.

▪ Transported ashore for re-use/disposal by appropriate methods.

▪ Structures may give off toxic fumes/dust if flame-cutting or grinding/blasting is used so appropriate safety measures will be taken.

▪ Recovered sections of piles will be returned to shore for recycling.

“Some of the hulls are contaminated – they have been used for

storing oil. This could be significant work, and it is different from

regular large transport ships.”

Decommissioning Project Manager

“We would have an influence over the safety and the

environmental acceptability of their plans. So, we would take a

strong position on those, and if we felt that were not behaving in

an appropriate fashion […] we would have a discussion.”

Decommissioning Assurance Manager

▪ The decommissioning of floating assets may also include subsea structures, which could be contaminated with waste material.

▪ The removal and decommissioning of subsea items is typically the responsibility of the field owner (may differ from asset owner).

▪ However, it is possible that the field owner will include all associated infrastructure and P&A activity of the well, to a Tier 1 contractor under the same decommissioning contract award.

▪ It is essential that all hazardous materials are identified as part of the project outline so that appropriate steps can be taken to ensure safe disposal either offshore or onshore.

▪ This is particularly true in the case of remaining hydrocarbons, NORM, LSA and Asbestos.

▪ In most cases, the services of a specialist third party waste removal contractor will be employed to clear and dispose of the waste.

▪ The chosen facility/ yard must demonstrate proven disposal track record and waste stream management throughout the deconstruction process, as well as demonstrate their ability to deliver innovative recycling options.

Source, Westwood Analysis, Clarkson’s shipping database

Decommissioning Processes & Considerations

Vessel Decommissioning Global LocationsScottish and UK ports along with the rest of Western Europe are not considered competitive in the global vessel decommissioning market and have had minimal involvement in activity in recent years

24

2013 2014 2015 2016 2017

Rest of the World 93 168 69 81 58

Pakistan 18 101 104 128 84

China 58 218 165 120 126

Turkey 25 139 90 85 128

India 85 314 214 335 205

Bangladesh 48 194 217 221 143

Netherlands 0 1 2 5 2

Norway 0 2 1 3 0

Denmark 1 13 20 13 14

UK 1 2 2 3 0

0

200

400

600

800

1000

1200

1400

Nu

mb

er

of

Ve

sse

ls

Location of vessel decommissioning's by year# vessels

66

25

6

India Turkey Rest of the World

Location of OSV decommissioning’s 2013 - 2017# vessels

▪ The chart above to the left reflects the total number of vessels that have been decommissioned across the globe from 2013 – 2017. This includes all vessel types as listed on the Clarkson’s shipping database.

▪ It clearly highlights the dominance of India, Pakistan, China, Bangladesh and Turkey when it comes to the vessel decommissioning market with countries in Western Europe undertaking only a small amount over the period.

▪ The fleet of vessels which are specific to operations in the Oil & gas industry are regarded as OSV’s (offshore support vessels), further information on these classes of vessels are found in the appendix on slide 53.

▪ The pie chart above and to the right, splits out the OSV decommissioning’s from the global fleet and indicates that further dominance by India is evident in this particular area of the market with 66 out of 97 being carried out there. Turkey is second with 25 and in this case, the rest of the world reflects the USA with the remaining 6 being decommissioned there.

▪ The above charts indicate that the Scottish ports in particular have had no involvement in the recent decommissioning activities of the global vessel fleet in the last 5 years. With the introduction and enforcement of a stricter European Convention this dynamic may be forced to change in the future, however there has been evidence of less scrupulous vessel owners changing the flag state of vessels prior to decommissioning decisions to allow for work to be undertaken by the dominant countries globally.

Source: Westwood Analysis.

Decommissioning Processes & Considerations

OSV Over Supply A Prelude to Decommissioning?The OSV industry has undergone two major build cycles, with the second run focused on building higher spec units. Westwood believes the only remedy for the over supply position this has caused, is to scrap a number of the existing fleet

25

OSV Build Cycle 1955-2019# of Vessels

▪ OSV deliveries are highly cyclical in nature and are typically correlated to oil prices (and rig orders). To-date, the OSV industry has undergone two main build cycles, the first between 1973-1984 and the second build cycle between 1997-2017.

▪ The first build cycle marked the advancement of the offshore oil & gas industry which consequently led to a spike in OSV construction. Deliveries were predominantly configured for shallow water activity, with small OSVs comprising 85% of the 1483deliveries over 1973-1984.

▪ The second build cycle was a direct consequence of a surge in requirements as a result of growing greenfield activity and an increasingly larger installed base necessitating servicing. Newbuilding in the second cycle has been centred on higher specced’ units to cater to evolving requirements of the offshore industry.

▪ As a result of the aggressive second build cycle, the recent volatility in oil price and a subsequent drop in demand for vessels, the global OSV market is experiencing serious oversupply as shown in the table opposite. Currently c1800 vessels are laid up globally. Westwood believe whilst laying up is an effective strategy for fleet owners at this time, the most efficient remedy for this over supply position would be to scrap significant numbers of the fleet currently laid up.

▪ This would however prove challenging for companies without the balance sheet strength to allow it to happen and there is seemingly little appetite for this to happen at present.

Insert supply evolution chart (see North Star)

0

50

100

150

200

250

300

350

400

450

19

55

19

56

19

57

19

58

19

59

19

60

19

61

19

62

19

63

19

64

19

65

19

66

19

67

19

68

19

69

19

70

19

71

19

72

19

73

19

74

19

75

19

76

19

77

19

78

19

79

19

80

19

81

19

82

19

83

19

84

19

85

19

86

19

87

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

Small OSVPSV>2000dwtAHTS>8000hpE&P Spend to OSVs<25 years

OSV deliveries by year# vessels

First Build Cycle (1973-1984)

Beginning of Significant Speculative

Building

Second Build Cycle (1997-Present)

1483 deliveries85% Small OSVs

3% Large PSV(>2000dwt)

12% Large AHTS (>8000hp)

3998 deliveries43% Small OSVs

33% Large PSV(>2000dwt)

23% Large AHTS (>8000hp)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

20

21

Demand

Available Supply (excluding Lay-ups)

Competitive Supply

OSV Supply vs Demand # vessels.

5) Western Europe Market Outlook

1. Jackup Platforms (extendable legs)

2. Gravity Base Fixed Platform

3. Pile Structure Fixed Platform

4. Compliant Pile System Platform

5. Tension Leg Platform (TLP)

6. Spar Platform

7. Floating Production Storage & Offloading (FPSO) Platform

8. Semisubmersible Platform

Variations of the above fixed & floating platforms, and MODUs have also been included in the pie chart, where applicable.

9. Drillship

10. Semisubmersible Drilling Rig

11. Jack-Up Drilling Rig

12. Drilling Barge

Source: Westwood Analysis.

Western Europe Market Outlook

Overview of Addressable Market Assets North SeaThe offshore assets reviewed as part of this study have been detailed below, and include floating production platforms and offshore MODUs

27

“There is not a great number of floating production vessels in the North Sea,

and they tend to be released sporadically, so trying to build a business purely

on the basis of demolishing FPSOs would be very difficult.”

Decommissioning Assurance Manager

Offshore Platforms/ Production Assets Mobile Offshore Drilling Units (MODUs)

Offshore Drilling RigsFixed Production Platform Floating Production Platform

308

8542

351

43

35078%

11% 11%

1

2

3

4

5

6

7

89

1011

12

“Buchan is an FPU, which means deep anchorage… each yard will need to

pick the right floating project [to bid for] depending on its capabilities. The

Buchan Alpha [for example] will remain floating throughout its

decommissioning, so it will block the quay.”

Decommissioning Assurance Manager

For the purpose of this study, Westwood analysis will focus on floating production assets and MODUs only. Please see Appendix pages 44 & 45 for a more detailed overview of each major asset type.

% of North Sea asset

population 2017

▪ Westwood forecasts the North Sea decommissioning market size at c.$84bn between 2017 and 2040. This figure is inclusive of asset/ structure removal, onshore deconstruction, support vessels and well decommissioning.

▪ Structure removal is the process of removing a fixed or floating asset from the field (i.e. cutting. De-mooring, etc.). Over the period, FPS removals will represent c.2% (c.$308m) of North Sea structure removal expenditure.

▪ The large installed base of fixed platforms in the UK and Norway will dominate decommissioning spend. Westwood believes this asset type forms the primary market given the volume of installed tonnage which will need to be removed over the next two decades.

▪ Considering the average weight and scale of each structure, it is widely considered that a large proportion of tonnage will be processed at Western European yards. However, given the lack of British-owned heavy-lift and offshore support assets, it is quite possible that this will dilute the UK’s share of decommissioning work.

▪ The comparative ease of transporting FPS units does reduce the scale of potential for such assets to be deconstructed and processed at Western European yards. Similar to vessel scrapping, FPS units may be transported to yards/ locations in Asia or the Middle East .

Source: Westwood Analysis.

Western Europe Market Outlook

Western Europe Decommissioning North SeaThe North Sea is a mature region with assets operating well beyond their intended design lives as a result of MMO, EOR and subsea-tieback strategies. However, the decommissioning market is now on the cusp of its first major cycle

28

North Sea Decommissioning ExpenditurePlatform Removals (LHS), Expenditure $m (RHS)

Total Structure Removal Expenditure (All Platform Types)$bn

FPS Structure Removal Expenditure$m

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0

5

10

15

20

25

30

35

20

16

20

17

20

18

20

19

20

20

20

21

20

22

20

23

20

24

20

25

20

26

20

27

20

28

20

29

20

30

20

31

20

32

20

33

20

34

20

35

20

36

20

37

20

38

20

39

20

40

Platform Removals

Expenditure

0

1

2

3

20

16

20

18

20

20

20

22

20

24

20

26

20

28

20

30

20

32

20

34

20

36

20

38

20

40

0

5

10

15

20

25

20

16

20

18

20

20

20

22

20

24

20

26

20

28

20

30

20

32

20

34

20

36

20

38

20

40

Source: Westwood Analysis, Riglogix.

Western Europe Market Outlook

Offshore Rig UtilisationThe current UK and Norway drilling outlook does not support a significant recovery in utilisation rates. As such, the market could see an increase in the number of cold stacked rigs, thus increasingly placing pressure on contractors to consider decommissioning

29

North Sea Rig Utilisation%

North Sea Active Rigs# of Rigs

▪ There are currently 28 warm stacked, and 20 cold stacked rigs in Western Europe.

▪ Excluding the economic downturn in 2009, the North Sea (UK & Norway) sustained rig utilisation above 80% between 2008-H1 2015.

▪ New project installations will help increase Norway’s drilling activity in the short to medium-term (2018-2020). Similarly, a number of greenfield projects will drive an increase in UK drilling, though modest.

▪ Westwood believe the increases in drilling activity will help boost utilisation rates in both geographies between 2018-20; however, it is likely it will not be sufficient enough to support the reactivation of warm stacked rigs.

▪ Beyond 2020, the continued decline in drilling activity is expected to worsen the outlook for utilisation rates. This is largely due to the lack of project sanctioning during the low oil price environment.

▪ The current outlook for drilling in the UK and Norway is not supportive of the reactivation of warm stacked rigs, given adequate supply exists in the market. Thus, some rig contractors could be faced with the decision to cold stack a number of warm stacked rigs.

40%

50%

60%

70%

80%

90%

100%

110%

Jan

-08

Au

g-0

8

Ma

r-0

9

Oct

-09

Ma

y-1

0

De

c-1

0

Jul-

11

Fe

b-1

2

Se

p-1

2

Ap

r-1

3

No

v-1

3

Jun

-14

Jan

-15

Au

g-1

5

Ma

r-1

6

Oct

-16

Ma

y-1

7

De

c-1

7

UK

Norway

0

10

20

30

40

50

60

70

80

90

Jan

-08

Au

g-0

8

Ma

r-0

9

Oct

-09

Ma

y-1

0

De

c-1

0

Jul-

11

Fe

b-1

2

Se

p-1

2

Ap

r-1

3

No

v-1

3

Jun

-14

Jan

-15

Au

g-1

5

Ma

r-1

6

Oct

-16

Ma

y-1

7

De

c-1

7

North Sea

Source: Westwood Analysis.

Western Europe Market Outlook

Decommissioning Production AssetsWestwood has identified 17 production assets (incl. Jack-Ups) for removal between 2017-2030. Norway will dominate the tonnage landscape, while the UK represents c.18% of tonnage over the period

30

Production Asset Removals by Asset Type# of Platforms

Production Asset Removals by Country# of Platforms

Production Asset Removal TonnageThousand Te

Tonnage by Country & Customer 2017-30Thousand Te

▪ Westwood anticipates a ramp-up in floating production removals beyond 2020, with 15 units to be removed between 2020-30.

▪ At a country level, the UK and Norway will dominate, representing c.40% and c.50% of assets removed respectively, between 2017-30.

▪ Interestingly, Norway will represent around 80% of Western European tonnage removed between 2017-30. The five key projects include;

▪ Heidrun TLP – c.289 kte▪ Troll B – c.194 kte▪ Aasgard A – c.184 kte▪ Norne FPSO – c.107 kte▪ Snorre A TLP – c.106 kte

▪ The above five projects represent c.65% of total tonnage removed between 2017-2030.

▪ Statoil represent the largest proportion of operator-owned tonnage. As the E&P operator is an NOC, it will likely favour Norwegian yards for any decommissioning work in the region.

▪ There have been plans approved with the Oil & Gas Authority (UK) to remove the accommodation platform supporting the Leman field on the UK Continental Shelf (UKCS), however as yet, Westwood is not aware of any formal consideration for the removal of the Leman DP and Leman FP platforms.

▪ A table showing the production assets reflected here is on the following page.

0

1

2

3

4

5

6

20

16

20

17

20

18

20

19

20

20

20

21

20

22

20

23

20

24

20

25

20

26

20

27

20

28

20

29

20

30

UK

Norway

Netherlands

Denmark

0

100

200

300

400

500

600

700

20

16

20

17

20

18

20

19

20

20

20

21

20

22

20

23

20

24

20

25

20

26

20

27

20

28

20

29

20

30

Th

ou

san

ds

18%

81%

0.4% 1%

UK

Norway

Netherlands

Denmark

73%

8%

6%

5%8%

StatoilShellMaersk OilPoint ResourcesOther

0

1

2

3

4

5

6

20

16

20

17

20

18

20

19

20

20

20

21

20

22

20

23

20

24

20

25

20

26

20

27

20

28

20

29

20

30

FPSO

FPSS

TLP

Converted Jack Up

Source: Westwood Analysis, Riglogix

Western Europe Market Outlook

Decommissioning Production AssetsThe table shown below represents Westwood’s opinion as to which production assets represent prime candidates for decommissioning between 2017 and 2030

31

Asset Type Asset Name Asset owner Status Current Location Year of Removal Age at Removal Asset Tonnage

FPSO Gryphon Alpha Maersk Oil Operational UK 2023 30 88,193

FPSO Maersk Curlew Shell Operational UK 2027 30 115,800

FPSO Aasgard A Statoil Operational Norway 2030 31 184,300

FPSO Norne FPSO Statoil Operational Norway 2030 33 107,320

FPSS Balmoral FPV Premier Oil Operational UK 2020 32 31,479

FPSS Veslefrikk B Statoil Operational Norway 2020 31 43,998

FPSS Troll B Statoil Operational Norway 2025 30 193,700

FPSS Visund A (PDQ) Statoil Operational Norway 2029 30 62,600

TLP Snorre A TLP Statoil Operational Norway 2027 35 106,472

TLP Heidrun TLP Statoil Operational Norway 2030 35 288,770

Jack Up Inde BP Perenco Operational UK 2017 40 750

Jack Up Millom West ConocoPhillips Operational UK 2027 31 1,550

Jack Up Leman DP Perenco Operational UK 2027 41 925

Jack Up Leman FP Perenco Operational UK 2027 41 925

Jack Up AWG-1P NAM Operational Netherlands 2023 37 5,053

Jack Up Siri INEOS (Dong) Operational Denmark 2028 31 10,000

FPSO Jotun A FPSO Point Resources Shut In Norway 2017 18 65,417

Source: Westwood Analysis. *NLDs: Netherlands.

Western Europe Market Outlook

Decommissioning Drilling AssetsCold stacked offshore drilling rigs are viewed as prime candidates for decommissioning or scrappage, with significant costs associated with bringing these units back to market

32

Warm & Cold Stacked Rig TonnageThousand Te

▪ Warm Stacking is a term used to describe an asset which is currently not in operation but is still subject to regular Maintenance and Inspection requirements.

▪ Asset owners will tend to keep rigs ‘Warm Stacked’ so they can be quickly mobilised if a new drilling contract is won and needs fulfilled at short notice. However, after some time, the unit may be cold stacked if it fails to secure work –this is largely dependent on the contractors financial position and the Opex outlay required to maintain the rig.

▪ There are currently 46 stacked offshore rigs in Western Europe, with the majority stacked in Norway (21) and the UK (14).

▪ ‘Cold Stacking’ is essentially when an asset is ‘mothballed’ and all operations, maintenance and inspection ceased.

▪ Industry consultation and research estimate the cost to an asset owner of bringing these assets to operational levels ranges between £9m - £20m. This can make the decision to bring an asset back to market less attractive, and highlights such rigs as prime candidates for decommissioning.

▪ Cold stacked rigs represent c.55% of tonnage. Of the cold stacked tonnage, Norway currently holds c.311 kte (c.75%) and the UK holds c.91 kte (c.22%).

▪ Tables showing the individual assets both warm and cold stacked are found on the following pages.

Warm Stacked Rigs by Country# of Rigs

Cold Stacked Rigs by Country# of Rigs

26%

54%

Jackup

Semisub

Drillship

24%

62%

7%7%

UK

Norway

Netherlands

Denmark

55%

45%

Warm Stacked

Cold Stacked

15%

7%

7%

6%65%

North Atlantic DrillingTransocean Ltd.SaipemParagon OffshoreOther

0

2

4

6

8

10

12

UK

No

rwa

y

NL

Ds

De

nm

ark

Jackup

Semisub

Drillship

0

2

4

6

8

10

12

UK

No

rwa

y

NL

Ds

De

nm

ark

Jackup

Semisub

Drillship

*

Source: Westwood Analysis, Riglogix

Western Europe Market Outlook

Decommissioning Drilling AssetsThe table shown below represents Westwood’s opinion as to which warm stacked drilling assets represent prime candidates for decommissioning between 2017 and 2030

33

Asset Type Asset Name Asset owner Status Current Location Age at Removal Asset Tonnage

Jackup Paragon C20051 Paragon Offshore Warm Stacked Denmark 35 7,175

Jackup Maersk Giant Maersk Drilling Warm Stacked Denmark 31 16,425

Jackup Paragon HZ1 Paragon Offshore Warm Stacked Denmark 36 11,229

Jackup Maersk Inspirer Maersk Drilling Warm Stacked Denmark 13 25,056

Jackup Swift 10 Swift Drilling BV Warm Stacked Netherlands 7 7,422

Jackup Paragon C462 Paragon Offshore Warm Stacked Netherlands 36 15,170

Jackup Paragon C20052 Paragon Offshore Warm Stacked Netherlands 35 7,519

Jackup Paragon C463 Paragon Offshore Warm Stacked Netherlands 35 6,660

Jackup Ran Borr Drilling Warm Stacked Netherlands 5 14,268

Jackup Energy Enhancer Northern Offshore Warm Stacked Netherlands 35 7,625

Jackup Paragon C461 Paragon Offshore Warm Stacked Netherlands 36 6,958

Jackup Paragon B391 Paragon Offshore Warm Stacked UK 36 8,168

Jackup Maersk Reacher Maersk Drilling Warm Stacked UK 8 15,589

Jackup Baug Borr Drilling Warm Stacked UK 26 5,125

Jackup ENSCO 71 ENSCO Warm Stacked UK 36 8,161

Jackup Rowan Gorilla VI Rowan Warm Stacked UK 17 19,526

Semisub Scarabeo 8 Saipem Warm Stacked Norway 6 35,304

Semisub Stena Don Stena Drilling Warm Stacked Norway 16 27,851

Semisub Borgland Dolphin Fred Olsen Energy Warm Stacked Norway 18 17,111

Semisub Byford Dolphin Byford Dolphin P/R Warm Stacked Norway 43 12,420

Semisub Songa Dee Songa Offshore AS Warm Stacked Norway 33 15,757

Semisub Deepsea Bergen Deep Sea Drilling Warm Stacked Norway 35 15,549

Semisub Island Innovator Island Drilling Company Warm Stacked Norway 5 29,929

Semisub COSLPioneer China Oilfield Services Warm Stacked Norway 7 26,951

Semisub COSLInnovator China Oilfield Services Warm Stacked Norway 6 26,951

Semisub Ocean Guardian Diamond Offshore Warm Stacked UK 33 14,476

Drillship Deepsea Metro II Chalfont Shipping Warm Stacked Norway 6 51,283

Drillship Sertao Dleif Drilling Warm Stacked UK 6 60,316NOTE: The Rowan Gorilla VI was warm stacked following contract termination by ConocoPhillips; however, the E&P operator will need to pay $225k/d for the remainder of the period (end Q1’18), serving to cover warm stacking costs in the short-term. The unit secured a new contract Q2’18 in Trinidad for 150 days.

Source: Westwood Analysis, Riglogix

Western Europe Market Outlook

Decommissioning Drilling AssetsThe table shown below represents Westwood’s opinion as to which cold stacked drilling assets represent prime candidates for decommissioning between 2017 and 2030

34

Asset Type Asset Name Asset owner Status Current Location Age at Removal Asset Tonnage

Jackup Energy Endeavour Northern Offshore Ltd Cold Stacked Netherlands 35 9,642

Jackup GSP Saturn GSP Cold Stacked Netherlands 29 5,235

Jackup West Epsilon North Atlantic Drilling Cold Stacked Norway 25 15,131

Jackup Fonn Borr Drilling Cold Stacked UK 31 10,272

Jackup Eir Borr Drilling Cold Stacked UK 18 15,223

Jackup Brage Borr Drilling Cold Stacked UK 19 14,471

Jackup ENSCO 70 ENSCO Cold Stacked UK 36 7,198

Semisub Blackford Dolphin Fred Olsen ASA Cold Stacked Norway 43 19,442

Semisub Scarabeo 5 Saipem Cold Stacked Norway 28 29,611

Semisub Bredford Dolphin Fred Olsen Energy Cold Stacked Norway 37 13,819

Semisub Polar Pioneer Transocean Ltd. Cold Stacked Norway 32 38,564

Semisub Songa Trym Songa Offshore AS Cold Stacked Norway 41 12,143

Semisub West Venture North Atlantic Drilling Cold Stacked Norway 18 31,248

Semisub West Alpha North Atlantic Drilling Cold Stacked Norway 31 17,193

Semisub Songa Delta Songa Offshore AS Cold Stacked Norway 37 23,535

Semisub West Hercules Seadrill Ltd Cold Stacked Norway 9 40,731

Semisub WilHunter WilHunter (Malta) Cold Stacked UK 34 14,504

Semisub Sedco 714 Transocean Ltd. Cold Stacked UK 34 15,641

Semisub Sedco 711 Transocean Ltd. Cold Stacked UK 35 14,073

Drillship West Navigator North Atlantic Drilling Cold Stacked Norway 18 69,851

North Sea Offshore Rig Utilisation & Dayrates$’000 (LHS), % (RHS)

Tonnage by Country & CustomerThousand Te

Source: Westwood Analysis.

Western Europe Market Outlook

Decommissioning Operational Drilling Asset CandidatesA number of operational drilling assets are operating beyond the intended design life, highlighting these units as potential candidates for stacking or eventual decommissioning

35

▪ The data shown is sensitised to only include those assets which have an age of 30 years or more at the end of their current contract.

▪ Considering current market utilisation, and the anticipated decline in UK and Norwegian drilling, older drilling assets are increasingly less attractive.

▪ Furthermore, with younger, more competitive rigs underutilised or operating at lower dayrates, it may become increasingly difficult for older drilling rigs to secure drilling workscopes.

▪ Westwood has identified 14 rigs as potential candidates for stacking, with eventual decommissioning.

Asset Type Asset Name Asset owner Status Current Location Contract End Age at Removal Asset Tonnage

Jackup ENSCO 72 ENSCO Drilling Netherlands Dec 2017 36 8,400

Jackup ENSCO 100 ENSCO Drilling UK Jun 2018 31 12,460

Jackup ENSCO 92 ENSCO Drilling UK Aug 2018 35 6,541

Jackup ENSCO 80 ENSCO Workover UK Dec 2018 39 7,588

Semisub Transocean Arctic Transocean Ltd. Drilling Norway Oct 2017 31 22,194

Semisub Bideford Dolphin Fred Olsen ASA Drilling Norway Oct 2017 42 16,813

Semisub Paragon MSS1 Paragon Offshore Drilling UK Oct 2017 38 20,067

Semisub Stena Spey Stena Drilling Workover UK Oct 2017 34 16,581

Semisub Ocean Patriot Diamond Offshore Workover UK Oct 2017 34 13,432

Semisub Paul B Loyd Jr Transocean Ltd. Drilling UK Dec 2017 31 39,504

Semisub Ocean Valiant Diamond Offshore Workover UK Feb 2018 29 27,149

Semisub WilPhoenix WilPhoenix (Malta) Drilling UK Apr 2018 35 15,130

Semisub Transocean Leader Transocean Ltd. Drilling UK Jun 2018 30 26,099

Semisub Transocean 712 Transocean Ltd. Workover UK Oct 2018 34 14,933

42%

16%

14%

8%

20%

Transocean Ltd.Diamond OffshoreENSCOParagon OffshoreOther

81%

16%

3%

UKNorwayNetherlands

Potential Candidates for DecommissioningOffshore Rig Data

0%

20%

40%

60%

80%

100%

120%

0

50

100

150

200

250

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

Average Dayrate

Av. Jackup Utilisation

Av. Semisub Utilisation

6) Competitive Analysis of Scottish Ports

Our research and industry consultation highlighted the key award factors crucial to a port’s ability to win future work in the floating asset decommissioning market

37

Competitive Analysis of Scottish Ports

Decommissioning Ports Key Award Factors

Source: Westwood Analysis

Scottish Ports – Key Award Considerations ▪ The involvement of a Tier 1 contractor is key.▪ Allows E&P firms to focus on their main activity.▪ Allows smooth control of the supply chain.

Tier 1 Relationship

Cost

WD & Draft Capability

Quayside Length & Strength

Lay Down Area

Licenses

Supply Chain

HSE & Environmental

Practices

Access/ Location

Logistical Support

Key Award Considerations

Logistical Support

Tier 1 Relationship

Cost

WD & Draft Capability

Quayside Length & Strength

Lay Down Area

Licenses

Supply Chain

HSE & Enviro.

Practices

Access/ Location

▪ Cost is a key commercial driver when considering where to award projects.

▪ Cheaper is not however, always better.

▪ The Port has to have sufficient water depth to allow the asset to come along quayside and anchor.

▪ Floating assets can use ballast to lift themselves.

▪ Suitable quayside strength is essential to allow safe operation.

▪ The longer a quayside is, the easier access will be.

▪ Sufficient lay down area is required for pieces as they come off the asset.

▪ Efficient logistic support to remove this is vital.

▪ Ports must have the relevant PPC & RSA licenses. ▪ These licenses relate to the handling of NORM &

LSA waste from the asset.

▪ An efficient supply chain with ease of access to the Port is essential.

▪ Established Ports have a distinct advantage here.

▪ High standards and practices are very important to asset owners in their consideration.

▪ Reputation can suffer as a result of poor standards.

▪ The Scottish Ports have ease of access to the fleet▪ Even the Ports on the West Coast have close

proximity and this is not a limiting factor.

▪ Asset owners want a project done as quickly as possible. Strong logistic support and ease of access to waste recycling plants is therefore crucial.

“An operator does not want to have to manage

multiple contracts wherever possible. We are not

scrap men, we want to focus on Exploration &

production”

Buchan Alpha Project Manager – Repsol Sinopec

“A yard wouldn’t have to have enough area to set the

entire asset down at once, however key is having an

efficient process in removing the waste so no

bottlenecks happen at the yard”

Decommissioning Consultant – The Oil & Gas

Technology Centre

“For UK facilities, putting emphasis on environmental

and safety is key. Vessels which are going

internationally seem to be disposed of cheaply but

very dirty. You can’t have both. One of those criteria

must be prioritised.” Decommissioning Manager -

Peterson

“The closer the asset is to a Port with the capability

to decommission it, the better. The extra days sailing

to the West Coast is not punitive for asset owners”

Director, Decommissioning – Borr Drilling

“The logistics in removal and processing of the waste

from the project can determine the speed at which it

is completed. The more efficient this can be the

more costs can be controlled”

Project Manager - Veolia

“Overall cost is cheaper in the UK than in Norway

and Holland, especially when you consider

manpower”

Decommissioning Manager - BP

Scottish Ports – Westwood Approach

• Westwood decommissioning insights and analysis isunderpinned by;

• Extensive industry consultations with keystakeholders,

• Research products and modelling (i.e. WesternEuropean Decommissioning report)

• International consulting experience in relationto decommissioning, working with a diverseclient offering across the decommissioningvalue chain

Based on our consultation and research on decommissioning activity already carried out, there are 6 port’s outside of Scotland that stand out as being the main competitors to the Scottish port’s

38

Competitive Analysis of Scottish Ports

Scottish Ports Competitive Analysis

Source: Westwood Analysis, Industry Consultation, Port Analysis Desktop Research

Key

1. Tier 1 Contractor

2. Water Depth

3. Quay Length

4. Quay Strength / Construction

5. Land Available

Veolia & Peterson – Gt. Yarmouth

1. Veolia & Peterson

2. 10 m

3. 250 m

4. 25 t/m2

5. 10,000 m2

Scheepssloperji – Netherlands

1. Scheepssloperji

2. 45 m

3. 300 m

4. Undefined

5. 40,000m2

Kvaerner Stord - Norway

1. Kvaerner Stord AS

2. 26 m

3. 620 m

4. High Impact Concrete

5. 68,000m2

Harland & Wolff – Belfast

1. Harland & Wolff

2. 8.6 m

3. 432 m

4. Various

5. 68,500m2 of dry dock

AF Decom – Norway

1. AF Gruppen

2. 23 m

3. 182 m

4. High Impact Concrete

5. 128,000m2

ABLE UK - Hartlepool

1. Able UK

2. 15 m

3. 306 m

4. 60 t/m2

5. 510,000m2

Westwood concludes that a dry dock can offer a competitive advantage if one already exists at the port. However it was not considered to be a key award factor when we consulted with industry

39

Competitive Analysis of Scottish Ports

Scottish Ports Dry Dock

Source: Westwood Analysis, Industry Consultation

Dry Dock“ Most definitely, the ability to lift these assets out

of the water into a dry dock provides far superior

access than you could achieve if it was left floating.

Equally a grading bay can be as effective in

dragging the asset out for access”

Decommissioning Director, Borr Drilling

Positive Negative

Ease of access to the entire asset

Floating assets were not designed to stand

Natural air bund preventing pollution

Expensive to develop if not already in place

Less dependency on tide / weather for

operations

Essential for FPSO decommissioning

Cost benefit with speed of project

Floating assets can use buoyancy

Small number available in the

Region

Adds complication to level the asset

Potentially allows multiple projects at

once

Other yards do not need them to win

work

Dry Dock“In a dry-dock, you could attack it with mechanical

cutters, and it also presents less spillage risk than if

the vessel is floating along the quayside. But a very

efficient process at quayside can still be as

effective.”

Buchan Alpha Decommissioning Project Manager

Dry Dock“From an Environmental perspective a dry dock

offers an excellent natural barrier to reverse

pollution whilst decommissioning activity is

underway”

Decommissioning Consultant – The OGTC

Dry Dock“ A dry dock will be almost essential if the project is

breaking down an FPSO, in particular the hull and I

don’t think there are any in Scotland capable of

taking a North Sea class FPSO at present ”

Regional Decommissioning Manager - BP

Dry Dock“ If the use of a dry dock can in anyway speed up

the process of the overall decommissioning project

then it will be of significant appeal to an operator

looking for a quick and efficient process”

Decom North Sea

Dry Dock“Dry-dock offers an advantage but is a very

expensive asset and there are enough. If a yard

does not have one, there is no point in investing

into one. And it’s more critical for construction work

instead of decommissioning work.”

Project Manager - Veolia

The most recent example of a floating asset being decommissioned in a Scottish port is that of the Buchan Alpha at Dales Voe,Shetland. The Tier 1 relationship of Veolia & Peterson was key to the port winning the work

40

▪ Built in 1973 as a semi-submersible drilling rig

▪ Converted into FPSS

in 1978-80▪ Started production on

the Buchan field in

1981▪ Stopped production in

2017

Full Load Displacement

19,400 tonnesLightweight

12,000 tonnes

Decommissioning Site

Dales Voe

Lerwick, Shetlands

The Buchan Alpha

▪ Production on the Buchan Alpha commenced in 1981 and peaked in

1983 at an average of c.32,000 bbl/d. In 2017, after 36 years and c.150

mmbbl produced, the FPS ceased production.

▪ Repsol Sinopec UK, an E&P company operating in the North Sea,

inherited the Buchan Alpha field and its associated FPSS after the

acquisition of Talisman Sinopec UK by Repsol Energy in 2015.

▪ The contract for disposal of the Buchan Alpha FPSS was internationally

tendered, with Veolia UK (environmental solutions provider) and

Peterson (logistics provider) being selected having formed a joint

venture focusing on decommissioning works.

▪ Key considerations for the contract award included Veolia’s track-

record in large decommissioning projects, Peterson’s significant logistics

capabilities, and the network of tier 2 contractors accessible from the

newly upgraded Dales Voe facility.

▪ Buchan Alpha arrived in Lerwick in August 2017. It was initially moored

offshore in deeper water where the thrusters were removed to reduce

the draught, allowing it to be moved to the quayside.

▪ Veolia has commenced the dismantling of the steel structure with the

aim of maximising the recycling rate and achieving 98%.

▪ Dismantling is expected to last 12 to 18 months, and end late 2018.

.

“I am delighted that we have now seen the safe arrival of the Buchan Alpha in Lerwick. This is great news for

Shetland and a clear sign of the opportunities available in this emerging market. The decommissioning of the

Buchan Alpha provides Scotland and our supply chain with the opportunity to demonstrate our skills,

capabilities and competitiveness in this area.”

Scottish Government Minister for Business Innovation and Energy

Quotes

“Veolia has tendered the work, presented a compelling case stating they have background, expertise, and some of the

specialist services available, and are in the position to take ownership of a vessel such as an FPS.”

Decommissioning Program Manager, Repsol Sinopec

“Repsol Sinopec was attracted by our offering because it was a full UK offering [..], we have over 10 years experience in doing

offshore infrastructure decommissioning [..], and our skills and competences meet all requirements for this project.”

Decommissioning Development & Proposals Manager, Veolia UK

“For UK facilities, emphasis on environmental and safety standards is key. Vessels which are going internationally seem to be disposed of cheaply but in a very dirty matter. You can’t have both” Decommissioning Manager, Peterson

Case Study Decommissioning of The Buchan AlphaCompetitive Analysis of Scottish Ports

Overview

Source: Westwood Analysis, Industry Consultations, Desktop Research

7) Acronyms & Abbreviations

DRAFT

Acronyms & Abbreviations (1/2)

AHTS Anchor handling supply tugAPAC Asia PacificAUV Autonomous underwater vehicleAvg. AverageAVO Amplitude versus offsetBbl BarrelBn BillionBnboe Billion barrels of oil equivalentBoe Barrels of oil equivalentBoepd Barrels of oil equivalent per dayBoP Blowout preventerBtoe Billion tonnes of oil equivalentc. circaCAGR Compound annual growth rateCapex Capital expenditureCIS Commonwealth of Independent StatesCoCS Chance of commercial successCoGS Chance of geological successCoS Chance of success CP Competent persons reportCS Construction SupportCSR Commercial success rateCSRs Commercial success ratesD&P Drilling & ProductionDW DeepwaterDECC Department of Energy & Climate ChangeDecomm DecommissioningDevt DevelopmentDSV Dive support vesselDS Drill SupportDUC Drilled but uncompletede. estimateE&A Exploration & AppraisalE&P Exploration & ProductionEBITDA Earnings before interest taxes depreciation and amortizationEE&FSU Eastern Europe & Former Soviet UnionEIA Energy Information AdministrationEM ElectromagneticEOR Enhanced Oil Recovery

EPC Engineering, Procurement, ConstructionEPCI Engineering, Procurement, Construction, InstallationEU European UnionEtc. Et ceteraExc Excludingf/e frontier / emergingFEED Front end engineering and designFID Final Investment DecisionFPS Floating production and storage vesselsFPSO Floating production storage and offloading vesselsFPSS Floating production semi-submersible vesselsGDP Gross domestic productGFC Global Financial CrisisGoM Gulf of MexicoGP Gross profitHI High impactHP HorsepowerHPHT High pressure, high temperatureICD Inflow control deviceILX Infrastructure led explorationIMR Inspection Maintenance & RepairIMF International Monetary FundIOC International Oil CompaniesIPM Integrated Project ManagementISO International Organisation for StandardisationIRM Inspection, Repair and MaintenanceJV Joint VentureKPI Key performance indicatorsKSA Kingdom of Saudi ArabiaL.Cret Lower CretaceousLatAm Latin AmericaLCOE Levelized cost of energyLCV Light construction vesselLHS Left hand sideLNG Liquefied Natural GasLWD Logging While DrillingLWIV Light weight intervention vessels

42

DRAFT

Acronyms & Abbreviations (1/2)

m MillionM&A Mergers and AcquisitionsMa Mega-annum (million year)mboe Thousand barrels of oilmboe/d Thousand barrels of oil equivalent per dayMEFS Minimum economic field sizeMENA Middle East North AfricaMmbbl Million barrels of liquid (oil and or condensate)Mmboe Millions of barrels of oil equivalentmmbtu Million british thermal unitsMMO Maintenance, modifications and operationsMODU Mobile offshore drilling unitMSGBC Mauritania-Senegal-Guinea-Bissau and Conarky Basin MSV Multipurpose support vesselMT Metric tonnesMtoe Million tonnes of oil equivalentMWD Measuring While DrillingN/A Not applicableNAm North AmericaNB Nota beneNM Not meaningfulNOC National Oil CompanyNS North SeaO&G Oil & GasO&M Operations & maintenanceOCTG Oil County Tubular GoodsOECD Organisation for Economic CooperationOFE Oilfield EquipmentOFS Oilfield ServicesOWF Offshore WindOPEC Organization of the Petroleum Exporting CountriesOSV Offshores support vesselOpex Operational expenditureP&A Plug & AbandonmentPLEM Pipeline end manifoldPLET Pipeline end terminationPNG Papua New GuineaPOSg Geological probability of success (geological chance of success)POSc Commercial probability of success (commercial chance of success)Prodn Production

PoB Persons on boardPSV Platform supply vesselR&D Research & DevelopmentREP Richmond Energy Partners LtdREP40 40 study group of companiesRHS Right hand sideRoW Rest of the worldROV Remotely operated vehiclesROVSV Remotely operated vehicle support vesselRVD Rex Virtual DrillingSA Stand-aloneSEA South-East AsiaSLB SchlumbergerSURF Subsea Umbilicals Risers and FlowlinesTcf Trillion cubic feetTEN Tweneboa-Enyenra-NtommeTSR Technical success rateTSRs Technical success ratesU.Cret Upper CretaceousUK United KingdomUKCS United Kingdom Continental ShelfUS United StatesUS GoM United States Gulf of MexicoUSD US DollarUSP Unique selling pointvs versusWD Water depthWFT WeatherfordWGEG Westwood Global Energy GroupWTI West Texas Intermediatey-o-y Year on yearYTD Year to date$/bbl Dollars per barrel$/boe Dollars per barrels of oil equivalent$’000 Thousands of dollars$m Million dollars$bn Billion dollars# Number of

43

8) Appendix

45

Appendix

Major New Oil Capacity Top 30 Oil Fields

Field Country OperatorIncrease

2017-18

West Qurna-2 Iraq Lukoil 300

Halfaya Phase 3 Iraq Missan Oil Company 251

Khafji Kuwiat/ KSA Al Khafji JOC 145

Fort Hills - Phase 1 Canada Suncor Energy Inc 120

Kashagan Kazakhstan North Caspian OC 120

Upper Zakum UAE ADNOC 115

Rumaila Iraq BP 109

Buzios Brazil Petrobras 104

Wafra Kuwiat/ KSA KGOC/Chevron 98

Egina Nigeria Total 80

Khurais KSA Saudi Aramco 79

Azadegan Iran NIOC 79

Tartaruga Verde Brazil Petrobras 79

Clair Ridge UK BP 75

Nasiriyah Iraq South Oil Company 67

Hebron Canada ExxonMobil 66

Horizon - Phase 3 Canada CNR 60

Franco SW Brazil Petrobras 53

Suzunskoye Russia Rosneft 52

Ayatsil Mexico Pemex 51

Zubair Iraq ENI 50

Mazalij KSA Saudi Aramco 50

Abu Jifan KSA Saudi Aramco 50

Berri KSA Saudi Aramco 50

Satah Al-Razboot UAE ADNOC 50

South Pars Phase 14 Iran NIOC 50

South Pars Phase 13 Iran NIOC 49

Tambococha Ecuador Petroamazonas 48

Agbami Nigeria Chevron 46

Kaombo Angola Total 46

Other Various Various - 38

Source: Westwood Analysis.

Appendix

Overview Floating Production Systems (incl. Jack-Ups)There are four primary floating production systems which include FPSO, FPSS, SPAR and TLP. Although uncommon, older jack-up rigs can also be used as production platforms

46

FPSO FPSS TLP SPAR

▪ Floating, Production, Storage and Offloading (FPSO) assets are ship-shaped units with process topsides and onboard storage. They are the most common type of FPS.

▪ Oil throughputs range from 5,000 bpd to 285,000 bpd, with storage capacities reaching 2.5 million barrels for some of the larger vessels.

▪ Floating Drilling, Production, Storage and Offloading (FDPSO) are FPSO with added drilling capability. This removes the need for an independent drilling rig ,thus reducing overall project costs.

▪ FPSOs offer large deck areas and capacity for topside processing. This provides the advantage of allowing flexible oil distribution, and providing storage capacity for produced oil.

▪ Floating Production Semi-Submersibles (FPSS) provide a highly stable production platform through the use of pontoons which are partially flooded with seawater.

▪ Many of the early FPSS’ are converted Mobile Offshore Drilling Units (MODU).

▪ FPSS’ are considered more stable than vessel-based FPS designs, but less than TLP, which have their vertical motion (heave) held in check by tendons, or some Spar designs.

▪ For this reason, FPSS’ have traditionally been considered unsuitable for surface completions in deepwater, although a number of new deep draft dry tree designs are now attempting to change this.

▪ A Tension Leg Platform (TLP) is a floating structure held in place by tensioned tubular tendons fixed to seabed piling (suction anchors or driven piles). The force of buoyancy and the resistance formed by the anchors suppresses platform movement and delivers a high degree of stability with removal of nearly all vertical motion, whilst retaining some lateral flexibility. This stability allows the TLP to support dry trees.

▪ There are limitations in the use of TLPs. The weight of the mooring tendons themselves imposes a penalty, especially deepwater, and they are not often found in WD greater than 1,500m. However, the use of lightweight composite materials for TLP mooring tendons and risers may help exceeded the threshold.

▪ The Spar concept comprises a single cylindrical hull’ supporting the deck structure.

▪ The hull consists of three sections – upper, centerwell, and keel. The centerwell is flooded with seawater while the upper section is filled with air to provide buoyancy.

▪ Most Spars in operation are of the Truss Spar design which differs from the classic Spar in that the lower part of the hull is replaced with a much lighter trussed structure that joins and fortifies four outer columns.

▪ Spars have better vertical motion behaviour than FPSS’ and FPSOs. The main hull protects the risers from waves and currents for the first 250m.

▪ The mooring system allows the platform position to be altered, an advantage for drilling, completion, and workover.

Source: Westwood Analysis.

Appendix

Overview Offshore Drilling RigsThere are three primary MODU (Mobile Offshore Drilling Unit) designs, which include jack-ups, drillships, and semisubmersible drilling rigs

47

Jack-Up Drillship Semisubmersible

▪ A jack-up platform consists of a buoyant hull fitted with a number of movable legs, capable of raising the hull over the surface of the sea. The buoyant hull enables transportation of the unit to a desired location.

▪ Once on location, the hull is raised above the sea surface, supported by the sea bed.

▪ The legs are either designed to penetrate the sea bed, or fitted with enlarged sections or footings, or attached to a bottom mat, limiting jack-up platforms to shallow waters.

▪ Jack-up drilling rigs can be converted at the end of their initial design-life into service rigs or production platforms (i.e. Tyra accommodation platform), though very few are converted for production.

▪ Drill Ships are designed with a ship-shape hull, drilling units, derricks and module topsides.

▪ Given their ability to move under their own propulsion at short notice, they are considered the most agile of the MODU’s and are particularly effective for deepwater.

▪ Drillships are typically the most Capex-intensive rigs to build. However, given their WD capabilities and ability to mobilise with minimal aid, such units will usually command higher day rates, serving to help offset construction costs.

▪ Drillships are considered to be less stable in design given their ship-shape hull, however the ability to move side-to-side under propulsion, coupled with stabilising anchors can help to compensate for this.

▪ A semi submersible drilling platform is supported on large pontoon like structures. These pontoons provide buoyancy, allowing the unit to be towed from location to location.

▪ Once on location, the pontoon structure is slowly flooded until it achieves the required depth and stability.

▪ The operating deck is elevated above the pontoons on large steel columns to provide clearance above the waves.

▪ After the well is drilled, the water is pumped out of the buoyancy tanks and the vessel is re-floated and towed to the next location.

▪ Given their ability to achieve good stability, and lack of requirement to land on the sea floor, semi submersibles are often used for deepwater drilling activities.

48

Appendix

Waste Removal

Asset Preparing / Cleaning

Waste Type Composition of Waste Disposal Route

Onboard hydrocarbons Process fluids, fuels and lubricantsHydrocarbons filtered and discharged into water disposal

wells

Other hazardous materialsNORM, LSA scale, any radioactivematerial, instruments containing

heavy metals, batteries

Transported ashore for re-use/disposal by appropriate methods

Original paint coating Lead-based paintMay give off toxic fumes/dust if flame-cutting or

grinding/blasting is used so appropriate safety measures must be taken

Asbestos & Ceramic fibre Asbestos and ceramic fibre Appropriate control and management must be enforced

Subsea Installations and Stabilisation Features

Type Option Disposal Route (if applicable)

StructuresFull recovery to vessel by lifting

as complete unitHydrocarbons filtered and discharged into water disposal

wells

Wellheads Full recoveryTransported ashore for re-use/disposal by appropriate

methods

Wellhead Protection Structures Full recoveryMay give off toxic fumes/dust if flame-cutting or

grinding/blasting is used so appropriate safety measures will be taken

FPU Mooring SystemStructure Piles

Leave in-situ. Any piles will be cut below the natural seabed level at such a depth to ensure

that any remains are unlikely to become uncovered.

Recovered sections of piles will be returned to shore for recycling.

Waste Stream Management Methods

Waste Type Management Method

Bulk LiquidsRemoved from vessels and transported to shore. Vessels, pipework and lumps will be drained prior to

removal to shore and shipped in accordance with maritime transportation guidelines. Further cleaning and decontamination will take place onshore prior to recycling / re-use

Marine GrowthRemoved onshore. Disposed of according to Oil and Gas UK Management of Marine Growth during

Decommissioning (2013)

NORM/LSA ScaleNORM may be partially removed offshore under appropriate permit. Any sections found to contain NORM

or LSA during recovery will be quarantined and taken to shore for disposal under the appropriate permit

Asbestos Will be contained and taken onshore for disposal

Other hazardous wastes Will be recovered to shore and disposed of under appropriate permit.

Onshore dismantling sitesAppropriate licenced sites will be selected. Facility chosen must demonstrate proven disposal track record

and waste stream management throughout the deconstruction process and demonstrate their ability to deliver innovative recycling options.

Throughout our consultations and when examining the addressable market, some key award factors are evident. We examine these in detail here

49

Scottish Ports

Scottish Ports Key Award Factors

Source: Westwood Analysis, Industry Consultation

Scottish Ports – Key Award Considerations

• Our industry consultations and knowledge ofthe decommissioning process have highlightedsome key award factors when considering theopportunity for the Scottish Ports.

• These key criteria are:• Tier 1 Contractor Relationship,• Cost,• Water Depth & Draft Capability• Quayside Length & Strength• Lay Down Area• Correct Licenses,• Supply Chain,• HSE & Environmental practices,• Access / Location,• Logistical Support.

Tier 1 Contractor Agreement

• When an asset owner or E&P Company is making the decision as to which facility to award the contract to, our consultation suggests that if the Port in question has an established relationship with a Tier 1 contractor who can offer a complete solutionpackage to the asset owner, it will be an incredibly powerful proposition. As was the case with the award of the Buchan Alpha to Dales Voe, Veolia and Peterson have an agreement with the Port which. Asset owners and in particular E&P companies do not make any profit from decommissioning activity and as such welcome the opportunity to assign this work to a capable Tier 1 contractor who can handle it for them. Allowing them to focus on what they do best. This along with water depth, is consideredto be a key reason the AF Decom operated VATS Decommissioning facility in Norway has been awarded a significant level of works in recent years.

Cost

• As with all commercial enterprise, cost is a key motivator in deciding where to award contracts. It is no different in the case of asset decommissioning. Not only the cost involved in the contract for physical dismantling of the asset but the costs involved with transporting it to the chosen facility. The insurances required to tow the asset through in some cases, international waters and across borders, according to our industry consultation can be up to £1mil which adds considerable cost if the owner decides to have the facility decommissioned at a facility out with immediate reach of the current location. It is however true that this cost can be offset if the other terms being offered give allowance for this when compared to proposals closer to the asset location. In terms of the overall cost for projects, our consultation suggests that currently the UK can offer a more cost effective proposition to the likes of Norway however the specialism and reputation in particular AF Decom have at the VATS facility outweighs this saving.

Water Depth & Draft

• It is fundamental to the contract award that the Port can accept the floating structure from a depth perspective and therefore allowing the assets draft to be accommodated within the facility. It is not possible to determine a threshold when considering the addressable market for this depth given the bespoke nature of every asset in question. Given the floating nature of the assets and their ability to control water draft using ballast, the key indicator when assessing suitability is the Port requirements for Draft + figures which range from 0.5m to 1.5m as well as the assets draft. The general consensus from industry however is that the deeper the better to allow a wide range of access both for the asset and any vessels required to help in the processDales Voe in Shetland has a water depth of c 12.5m. When compared to the AF Decom operated VATS Port Decommissioning facility in Norway however, a facility which is seen as a world leader in floating decommissioning activity and has a water depth of c 23m, it is clear there is a significant difference in proposition.

Throughout our consultations and when examining the addressable market, some key award factors are evident. We examine these in detail here

50

Scottish Ports

Scottish Ports Key Award Factors

Source: Westwood Analysis, Industry Consultation

Scottish Ports – Key Award Considerations

• Our industry consultations and knowledge ofthe decommissioning process have highlightedsome key award factors when considering theopportunity for the Scottish Ports.

• These key criteria are:• Tier 1 Contractor Relationship,• Cost,• Water Depth & Draft Capability• Quayside Length & Strength• Lay Down Area• Correct Licenses,• Supply Chain,• HSE & Environmental practices,• Access / Location,• Logistical Support.

Quayside Length & Strength

• If the decommissioning project is to be operated at quayside, it is important that that the quay is long enough and has an acceptable load bearing capacity when considering the tonnage to be taken from the asset as well as the machinery required todo so. In the case of an FPSO project, given the ship shape design of the hulls, it is not possible to break these down at quayside and hence would require settlement in a dry dock for dismantling. The topside and modules however could be removed provided there is suitable water draft to accommodate the asset at quayside. The quay in all cases however does not need to accommodate the total length of the asset, it must however allow sufficient capacity to ensure a secure mooring and access alongside for the required machinery and if needed, a heavy lift crane.

Lay Down Area

• When considering the footprint that a Port facility must have in order that it can accommodate large floating structures, it is not required of the facility that this space equates to the overall dimension of the asset. It is more important as an award factor that the project can be handled swiftly and as such the pieces being removed from the asset under dismantlement can be set down and processed or removed efficiently to ensure no bottle necks in the yard.

Correct Licenses

• Key to the award is to ensure the Port facility has the necessary permits in place to carry out the works. These are required in order that the Port can tender for works. The Pollution Prevention Control (PPC) license and Radioactive Substance Act (RSA)licenses are required. In order to achieve these permits the Port must evidence its ability to handle both NORM and LSA materials for the RSA license and it must have a fully isolated and bunded flushing and cleaning facility to ensure no external pollution is swept back into the Port as part of the work. The PPC license is awarded by Scottish Environmental Protection Agency (SEPA)

Supply Chain

• If a Tier 1 contractor is not aligned to the Port facility then the asset owner will examine in great detail to what extent a locally based supply chain is present to complete the works. Wherever possible they will consider existing reputation built on previousprojects, ease of access, labour force requirements, suitability of contracting agreements and efficiency when considered to theoverall project plan. It is a much more compelling proposition to the asset owner if the Port can evidence an effective supply chain when tendering for decommissioning projects rather than the asset owner having to source these independently wherever possible.

Throughout our consultations and when examining the addressable market, some key award factors are evident. We examine these in detail here

51

Scottish Ports

Scottish Ports Key Award Factors

Source: Westwood Analysis, Industry Consultation

Scottish Ports – Key Award Considerations

• Our industry consultations and knowledge ofthe decommissioning process have highlightedsome key award factors when considering theopportunity for the Scottish Ports.

• These key criteria are:• Tier 1 Contractor Relationship,• Cost,• Water Depth & Draft Capability• Quayside Length & Strength• Lay Down Area• Correct Licenses,• Supply Chain,• HSE & Environmental practices,• Access / Location,• Logistical Support.

HSE & Environmental Practices

• Common to our feedback from industry it is becoming increasingly important that the chosen facility has exemplary HSE and Environmental practices when considering decommissioning project awards. With recent examples such as the North Sea Producer FPSO which has been left to rust on a beach in Bangladesh causing reputational damage to the asset owners, it is nowincreasingly important that the facility carrying out the work can evidence first class practises when it comes to the HSE and Environmental impact of projects.

Access / Location

• It is clear from the analysis on the potential addressable market in section 5 of this report, that the majority of the assets in the Region are within relatively close reach of the Scottish Ports and as such this will be an important factor when assessing wherebest to have assets decommissioned. The closer the facility to the asset in its current location, the less cost associated with the transport to the facility. It was highlighted in our consultation that with regards geography of the assets in question, when examining the Scottish Ports, it is unlikely one would be favoured over the other on this basis given their relative close proximity and to access Ports such as Hunterston or Kishorn on the West Coast, it would in real terms only equate to an extra days sailingwhen compared to the Ports on the East coast or Shetland. If there is a facility close to the asset able to carry out the works then that would be the preferred option but this would only be true provided the Port can meet the other award factors.

Logistical Support

• It is desirable from the asset owners perspective when considering where to award projects that the Port facility can carry out the work swiftly and efficiently. It is also important from the Ports perspective that logistical support can be offered with regards moving the material to be recycled or discarded following the project. Whilst this is something that is considered fundamental to the project plan, it is of more importance to the Port to ensure they have sufficient access to the facilities capable of handling the waste products. Hazardous and Non Hazardous. In particular, Ports with ease of access to the Central Belt of Scotland where the smelting plants are that would recycle the steel, is an important consideration in the overall project. Thisagain is was a compelling reason for the partnership between Veolia and Peterson at Dales Voe being awarded the Buchan Alpha. Peterson are a logistics expert and despite the facility being in Shetland with no road access to the mainland, Petersonwere able to evidence efficient removal of the waste to the mainland by vessel and subsequent road transfer to the recycling or waste facilities.

Vessel Decommissioning

Vessel Decommissioning OSV TypesWhilst the number of

52

Crew BoatsAnchor

Handling Supply Tugs (AHTS)

Platform Supply Vessels (PSV)

ROV Support Vessels

(ROVSV)

Light Construction Vessels (LCV)

Dive Support Vessels (DSV)

Flex Layers Reel-LayersConventional

Pipelay Monohulls

Heavy Lift Monohull

Semis

Offshore Support Vessels (OSV) Subsea Vessels SURF Vessels Offshore Construction

Small, typically aluminum hulled vessels used to

ferry workers and minor supplies to and from offshore

installations.

May compete with multipurpose

workboats which have not been

included in this analysis.

Anchor Handling Tug Supply (AHTS)

vessels are used extensively in the

offshore O&G industry to tow,

anchor and supply larger

infrastructure such as offshore drilling

rigs and floating production platforms.

AHTS vessels are characterized by

towing winches and relatively higher horsepower and

bollard pull ratings.

Platform Supply Vessels (PSVs) are used to re-supply

existing production platforms with dry

and liquid consumables. PSVs

are also used to support Drillships.

PSVs are characterized by

their storage tanks and deck space but are considered as

highly versatile vessels able to be

modified to provide light construction.

ROVSVs support operations of

Remotely Operated Vehicles (ROVs) which are used to conduct a

variety of construction and

maintenance activities on

offshore O&G fields in water depths where diving is not

practical.

In addition to ROV capability, ROVSVs

are typically equipped with subsea cranes

(<100MT) and may be differentiated

by other capability such as moonpools

and dynamic positioning.

Light Construction Vessels (LCV) are used primarily in

the installation of subsea

infrastructure such as trees, jumpers,

manifolds and control systems.

LCVs are characterized by

large subsea cranes (>100MT), sizable

deck space and will typically also have ROV capability to

support deepwater operations. There may be crossover

between DSVs with large cranes

and LCVs.

Dive Support Vessels (DSV)

provide saturation diving services

supporting construction and maintenance of offshore O&G fields in water

depths less than 250m.

DSVs are characterized by

integrated saturation diving facilities and may be single or twin

bell and house up to 24 divers. Larger

DSVs will also typically be

equipped with ROVs and subsea

cranes.

Dedicated subsea Flex-Lay vessels

with horizontal or vertical lay systems

with higher capacity top-tensioning to

support deeper water SURF.

Reel-Layers use a coiled pipe on a

spool unlike pipelay, and lays

pipes in a continuous manner

by unwinding it from the reel.

Typically used for rigid flowlines.

Conventional pipelayers install

offshore pipe connecting production

platforms to onshore processing

facilities and also international

trunklines.

Pipelayers are characterized by

the type of lay system as well as

their pipe-handling and onboard

welding capabilities.

Pipelayers are typically owned and operated by

EPCI contractors such as McDermott

and Saipem.

Heavy Lift vessels install large

offshore infrastructure such

as jackets and topsides and are characterized by their large crane

capacity.

Like pipelayers, Heavy Lift vessels

are owned and operated by EPCI

contractor.

Small OSVs:AHTS vessels rated <8,000hp and PSVs rated <2,000dwt are typically seen as highly versatile shallow water support vessels and are grouped together under small OSVs in this analysis.

SURF vessels are large and specialized assets focusing on the installation of subsea

umbilical's and pipelines.

SURF vessels are characterized by their lay systems and top-tensioning capability. They

will typically also be equipped with ROVs and subsea cranes. In shallow water SURF vessels

may compete with modified LCVs.

These assets are typically owned and operated by very large subsea engineering contractors such as Technip and Subsea 7.