Offshore Floating Asset Decommissioning Market Study. January 2018

Transcription

1 Offshore Floating Asset Decommissioning Market Study January 218

2 Offshore Floating Asset Decommissioning Final Report January 218 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

3 1) Executive Summary

4 Executive Summary Key points and conclusions from our report Macro Economic Analysis [click to Oil add will text] 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. 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. Drivers of [click to add text] Decommissioning 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 Decommissioning Processes & Considerations Competitive Analysis of Scottish Ports There is a significant number of considerations when planning a decommissioning programme, beginning with regulator approval. Cessation of field Production [click to add text] 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. [click to When add text] 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.. Use of a Dry Dock Vessel Decommissioning However, projects sanctioned prior to the downturn will compound global oversupply of oil in 218. 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. 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 are a number of ageing assets in the North Sea region that are potential candidates for decommissioning in the next 1 years. If the current oil price Western Europe 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 Market Outlook 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. [click to add text] 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 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. [click to The add levels text] 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. Source : Westwood Analysis, Rig Logix 4

5 2) Macro-Economic Analysis

6 Macro-Economic Analysis Global Outlook Long-Term Energy Demand Global 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 Energy demand is expected to increase by c. 31% between 215 and 235, 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 215 to c.28% in 235. 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. Global Energy Demand Outlook Mmboe/d (LHS), Billions (RHS) Energy Demand Global Population Global Energy Demand by Region Mmboe/d 9, 8, 7, 6, 5, 4, 3, 2, 1, APAC Americas Europe & Eurasia Middle East Global Energy Demand by Fuel Mmboe/d Liquids Coal Natural Gas Renewables Nuclear Africa Source: Westwood Analysis, EIA, BP. 6

7 Macro-Economic Analysis Global Outlook Long-Term Oil Supply 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 Growth in oil supply during the past 1 years has principally come from the onshore sector. Between 25 and 216, 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 217 to 223 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 223. Oil Supply Outlook to 23 Mmbbl/d Indexed Oil Supply Growth by Source Index Offshore Deepwater c.6.2 mmbbl/d (217) c..8 mmbbl/d (Δ 217 to 223) Onshore c.62 mmbbl/d (217) c.5. mmbbl/d (Δ 217 to 223) Offshore Shallow Water c.21 mmbbl/d (217) c..7 mmbbl/d (Δ 217 to 223) Source: Westwood Analysis, BP, EIA, OPEC. 7

8 214Q1 US Crude Russia China OPEC others 215Q1 US Crude Russia China OPEC others 217Q1 NOC '17 Onshore Offshore NOC '18 IOC '17 Onshore Offshore IOC '18 IND '17 Onshore Offshore IND '18 Q1'12 Q3'12 Q1'13 Q3'13 Q1'14 Q3'14 Q1'15 Q3'15 Q1'16 Q3'16 Q1'17 Q3'17 Q1'18 Q3'18 Angola Brazil Canada Ecuador Iran Iraq Kazakhstan Kuwiat/KSA Mexico Nigeria Russia KSA UAE UK Macro-Economic Analysis Near Term Oil Supply & Demand Trends Projects sanctioned prior to the downturn will compound oversupply in 218. As such, oil prices are expected to remain supressed in the near-term with volatility expected to continue 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 1 mmbl/d 2H 218. However, despite this growth, the global economy has been unable to absorb recent supply additions. Between , global liquids output increased by 3.1 mmbl/d, 7% 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 216. Over the next few years, overcapacity is likely to be exacerbated by the start-up of numerous high profile oil projects sanctioned during Westwood estimates that an additional 1.6 mmbl/d of new capacity will enter the market by 218 in addition to.6 mmboe/d from resumption of production from Libya and Nigeria. Short-term Liquids Consumption and Stock Change Balance Consumption mmbbl/d (LHS), Stock Change & Balance Mmbbl/d (RHS) 12 1 Recent Oil Supply Trends mmbbl/d Implied Stock Balance World Consumption Major New Oil Capacity by Country (Top 3 Oil Fields) Incremental Increase mmbbl/d Onshore Offshore Major New Oil Capacity by Operator Type (Top 3 Oil Fields) Incremental Increase mmbbl/d 4,5 4, 3,5 3, 2,5 2, 1,5 1, 5 Source: Westwood Analysis, EIA. 8

9 Macro-Economic Analysis Global Outlook Near to Medium Term Oil Supply-Demand Balance Westwood identified some oil price stabilisation in 217 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 In November 216, 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.6,bbl/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 217. The deal has recently been extended by a further nine months to March 218. As a result, Westwood expects market rebalancing to continue in 217 with c..6 mmbbl/d undersupply expected as the market adjusts to the supply reduction. Oversupply returns in 218 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. Net Supply-Demand Change vs Oversupply mmbbl/d 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) Demand Additions (Chart) Supply Additions Implied Oversupply Impact of Opec Cuts Source: Westwood Analysis. 9

10 Macro-Economic Analysis Near to Medium-Term Oil Price Outlook Under the reference case, Westwood expect oil prices to range between $5-$6/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 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 is expected to remain suppressed due to incremental supply from major offshore projects, compounded by OPEC ending the production cuts after 1Q is projected to average $54/bbl with a net surplus in oil supply and significant US shale capacity still looming large. Post 22, 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 221/22 as US shale capacity is absorbed, leading to a net-deficit supply balance. Our high case assumes prices reaching $6/bbl by end of 218 and $85/bbl by 222. Main factors driving our high case are a continuation of OPEC cuts post 1Q218 and more aggressive than expected natural decline rates. Our low case assumes prices range from $4-45/bbl between 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. Oil Spot Price Brent $/bbl Forward oil price spread is based on WGEG analysis and views from over 5 leading industry analysts and investment banks. Improved US Shale Efficiency Fracklog Suspension of OPEC cuts HIGH CASE Libya & Nigeria OPEC Cuts Sustained Chinese Imports Global Consumption Growth Decline Rates REF CASE LOW CASE Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-2 Jan-21 Jan-22 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 Reference case impact on market This reference case forms the basis for the market forecasts outlined in this report Westwood estimate of c$13bn of expenditure for Low case impact on Market Increased asset abandonment Acceleration of decommissioning expenditure Westwood estimate of c$117bn of expenditure for Source: Westwood Analysis, Various. 1

11 Macro-Economic Analysis North Sea Capex Outlook The 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 Western European E&P Expenditure vs. Oil Price Reference Case Capex $bn Brent $/bbl North Sea Drilling & Production North Sea Wells Drilled (LHS), Kboe/d (RHS) 6 5 Norway 1x FPSS, 1x FPSO, 1x Spar UK 1x FPSO , 4,5 4, ,5 3, Capex Brent Oil Price North Sea Wells UK Production Norway Production 2,5 2, 1,5 1, 5 Total offshore E&P spend (including life of field activities) reached $55.2 billion in 214 before contracting to $38.6 billion by 217 a drop of 3%. 218 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 , 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 will cause regional investment to return to 217/218 levels in 221, 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 (217-21), 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. 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 2, and output declined by 8% yearon-year through to 214. Production will rally to 2.1 mmboe/d by 219 due to developments sanctioned prior to the market downturn. However, the lack of investment from could lead to production decline towards the end of the period. 11

12 3) Drivers of Decommissioning

13 Drivers of Decommissioning Western Europe Decommissioning Drivers 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 Commodity Prices Operations & Maintenance 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 218 has led industry commentators to revise the reference case from almost $6/bbl to $52/bbl for 218. 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. Basin Maturity Offshore Field Hubs 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. Source: Westwood Analysis. 13

14 Africa Asia Australasia EE & FSU LatAm M. East NaM Norway UK RoWe Drivers of Decommissioning Offshore Platform Spend Outlook MMO 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 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-214) 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 3% between 214 peaks and the respective market troughs. The decline in MMO spending was broadly caused by the delay of nonessential 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.67% and c.32% 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. North Sea Fixed Platform Population # of Platforms North Sea Offshore MMO Expenditure MMO $m (LHS), Brent Oil Price $/bbl (RHS) UK Norway RoWe Norway UK Brent Oil Price North Sea Floating Platform Population # of Platforms Average MMO Spend per Asset $m UK Norway Regional Average Global Average Source: Westwood Analysis 14

15 Cash Flow ($m) Drivers Of Decommissioning Cessation of Production (CoP) Decision Making Whilst life-extension techniques are used, CoP will undoubtedly occur if the oil price downturn is prolonged. However, this will also be dependent on operator comfort in relation to internal oil price estimates, balanced with asset cost pressures Illustrative Lifecycle of an Offshore Field $m Annual Cash Flow Cumulative Cash Flow Net Present Value (NPV) Loss Making Payback Years from Project Start Maximum Exposure 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 ~15% 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 212, as well as the well-established Dunlin field that first entered production in the 197s are two CoP examples resulting from sustained low oil prices. The FPSO BW Athena was demobilised in February 216, while the well management company Exceed was awarded a contract in March 216 to support Fairfield Energy in its decommissioning programme at Dunlin. If they had realistic decommissioning costs built into their balance sheet they probably should have started decommissioning some years ago. Well Abandonment Advisor 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 2-3 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 Source: Westwood Analysis. 15

16 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 Ship Breaking / Decommissioning Ship Breaking Process 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 3 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. Regulatory Environment 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. Geographic Location of Activity 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 22 will limit fuel used in marine vessels to.5% mass on mass of sulphur content. This will mean vessels will have to comply or take rectifying action. The Hong Kong Convention from 29 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 219 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 217. Costs are considered to be as low as one tenth of what they are outside of these countries. Source : Westwood Analysis, Desktop Research 16

17 4) Decommissioning Processes & Considerations

18 Decommissioning Processes & Considerations Decommissioning Procedure Onshore Dismantling 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 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 6. Dismantle and dispose / recycle the rest of the hull 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 lacking those capabilities. FPSS : Once the vessel is on the quayside, it can be kept floating or landed on the Specific Considerations 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. 5. Once the hull is bare, move ashore or keep in working station 4. Dismantle and dispose / recycle modules as they are taken off the vessel 3. Remove all loose modules or equipment such as storage units or accommodation modules Source: Westwood Analysis, Industry Consultations 18

19 Decommissioning Processes & Considerations Asset Decommissioning The Path to Decommissioning When 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 Illustrative Lifecycle of an Offshore Field $m Capex Opex Gross Revenue Flow Chart: The Path to Decommissioning Removal of Asset from the Field Transportation of Asset to Shore Decommissioning Work Performed on Asset (A) Field Owner/ Operator Decision Decision as to Location of Work Project Agreement with Regulator Decision to Decommission the Asset No Cessation of Production Is Warm/ Cold Stacking an option? Yes Warm Stack/ Cold Stack the rig (B) Decision to Decommissioning No (A) + (B) Flushing & Well / Field P&A Asset Owner Decision Can the Asset be Re-used or sold? Yes Transfer of Asset to new owner 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. Source: Westwood Analysis. 19

20 Decommissioning Processes & Considerations Historic Removals & Near-Term Opportunities Westwood 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 There have been 36 floating production asset removals between 1977 and 217. 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 reapplication, 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 11 drilling rigs in Western Europe are classified as either warm or cold stacked. North Sea Floating Production Asset Removals # of Platforms North Sea Offshore Drilling Assets # of Offshore Rigs Near-term opportunities* FPSO FPSS TLP Removals Relocated Laid Up Shut-In Decomm. Jackup Semisub Drillship Near-term opportunities Buchan Alpha (FPSS) Built 1981; Decommissioned 217 in Shetland. Hutton (TLP) Built 1983; hull decommissioned 28 in Invergordon. Topsides were sourced and re-purposed in Russia Janice A (FPU) Built 1999; Decommissioned 217 in Norway. North Sea Producer (FPSO) Built 1984; Upgraded 1997; Decommissioned 216 in Bangladesh Seillean OPV - renamed Noble Seillean (FPSO) Built 1998; Decommissioned 213 in the UAE North Sea Offshore Drilling Asset by Age Profile Years, % Warm Stacked 46% 54% Cold Stacked 6% 4% 2 Total Active Warm Stacked Cold Stacked <3 >3 <3 >3 Source: Westwood Analysis, Riglogix. *Only six out of the 12 units detailed are currently located in the region. 2

21 Decommissioning Processes & Considerations Decommissioning Previous Removals The 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 Field Name Asset Name Year Removed Asset Type Outcome Argyll Transworld FPSS Reused Birch Benvrackie 1989 FPSS Reused Crawford (ex Cragganmore) North Sea Pioneer 199 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 FPSO Reused Captain Captain FPSS 1993 FPSS Reused Hudson Petrojarl FPSO Laid Up Norway Varg (Lilleulv) Petrojarl Varg 216 FPSO Laid Up Norway Cheviot (ex Emerald redevelopment) Emerald Producer 1996 FPSS Reused Machar Sedco FPSS Laid up Malaysia Banff Banff FPSS 1997 FPSS Reused Athena BW Athena 216 FPSO Laid up UK Mariner (UK) Petrolia FPSS 1997 FPSS Laid up Gulf of Mexico Durward/Dauntless Glas Dowr FPSO 1999 FPSO Active Singapore Blenheim Petrojarl 1 2 FPSO Reused Kyle Petrojarl 1 2 FPSO Reused Chestnut Crystal Ocean FPSO EWT 21 FPSO Laid up Gulf of Mexico Dunbar Sedco FPSS Reused Darwin (Hutton) Hutton TLP 22 TLP Scrapped UK Leadon Global Producer III FPSO 26 FPSO In Use North Sea Galley Northern Producer 27 FPSS Reused Fife Uisge Gorm 28 FPSO In Use North Sea Ivanhoe/Rob Roy AH1 FPSS 29 FPSS Reused Shelley Voyageur FPSO (Sevan 3 No 3) 21 FPSO In Use North Sea Glitne Petrojarl FPSO Reused Schiehallion Schiehallion FPSO 214 FPSO Refurbed and Laid up Indonesia MacCulloch North Sea Producer 215 FPSO Scrapped Ettrick Nexen Ettrick FPSO (Aoka Mizu) 216 FPSO Laid up Poland Jotun Jotun A FPSO 217 FPSO Shut In Foinaven Ocean Guardian 1994 FPSS Laid Up UK Connemara JW McLean 1997 FPSS Laid Up Uk Buchan Alpha Buchan A 217 FPSS Decommissioned UK Njord Njord A FPU 216 FPSS Laid Up for Renovation in Norway Janice Janice A FPU 217 FPSS Decommissioned Norway Source: Westwood Analysis, Riglogix 21

22 Decommissioning Processes & Considerations Asset Decommissioning Onshore Preparations There is a significant degree of planning and preparation required from the yard before a project can be delivered, with each project representing unique challenges due to the bespoke design and age of the floating assets 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.3% capacity, thus the c.35-4te* 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. 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. 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. 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. Decommissioning Manager Source: Westwood Analysis. *Figure concluded from industry consultation. 22

23 Decommissioning Processes & Considerations Floating Asset Decommissioning Waste Removal 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 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. 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 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 Asset Preparation & Cleaning Waste Type Onboard Hydrocarbons Other Hazardous Materials Original Paint Coating Asbestos & Ceramic Fibre Subsea Installations & Stabilisation Features Waste Type Structures Wellheads Wellhead Protection Structures FPU Mooring System Structure Piles Waste Stream Management Waste Type Bulk Liquids Marine Growth Normally Occurring Radioactive Material (NORM) Low Specific Activity (LSA) Scale Asbestos Other Hazardous Wastes 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. 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 (213) 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. Source: Westwood Analysis 23

24 Number of Vessels Decommissioning Processes & Considerations Vessel Decommissioning Global Locations Scottish 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 Location of vessel decommissioning's by year # vessels Location of OSV decommissioning s # vessels Rest of the World Pakistan China Turkey India Bangladesh Netherlands Norway Denmark UK India Turkey Rest of the World 66 The chart above to the left reflects the total number of vessels that have been decommissioned across the globe from 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, Clarkson s shipping database 24

25 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 OSV OSV Build deliveries Cycle by year # vessels of Vessels First Build Cycle ( ) 1483 deliveries 85% Small OSVs 3% Large PSV(>2dwt) 12% Large AHTS (>8hp) Second Build Cycle (1997-Present) 3998 deliveries 43% Small OSVs 33% Large PSV(>2dwt) 23% Large AHTS (>8hp) Beginning of Significant Speculative Building Small OSV PSV>2dwt AHTS>8hp E&P Spend to OSVs<25 years Insert supply evolution chart (see North Star) 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 and the second build cycle between 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 1483 deliveries over 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 c18 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. OSV Supply vs Demand # vessels. Demand 7, Available Supply (excluding Lay-ups) 6, Competitive Supply 5, 4, 3, 2, 1, Source: Westwood Analysis. 25

26 5) Western Europe Market Outlook

27 Western Europe Market Outlook Overview of Addressable Market Assets North Sea The offshore assets reviewed as part of this study have been detailed below, and include floating production platforms and offshore MODUs Offshore Platforms/ Production Assets Mobile Offshore Drilling Units (MODUs) Fixed Production Platform Floating Production Platform Offshore Drilling Rigs 85 % of North Sea asset population % 11% % 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 9. Drillship 1. Semisubmersible Drilling Rig 11. Jack-Up Drilling Rig 12. Drilling Barge Variations of the above fixed & floating platforms, and MODUs have also been included in the pie chart, where applicable. 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 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. Source: Westwood Analysis. 27

28 Western Europe Market Outlook Western Europe Decommissioning North Sea 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 North Sea Decommissioning Expenditure Platform Removals (LHS), Expenditure $m (RHS) Platform Removals Expenditure Total Structure Removal Expenditure (All Platform Types) $bn FPS Structure Removal Expenditure $m , 7, 6, 5, 4, 3, 2, 1, Westwood forecasts the North Sea decommissioning market size at c.$84bn between 217 and 24. 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. Demooring, etc.). Over the period, FPS removals will represent c.2% (c.$38m) 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. 28

29 Jan-8 Aug-8 Mar-9 Oct-9 May-1 Dec-1 Jul-11 Feb-12 Sep-12 Apr-13 Nov-13 Jun-14 Jan-15 Aug-15 Mar-16 Oct-16 May-17 Dec-17 Jan-8 Aug-8 Mar-9 Oct-9 May-1 Dec-1 Jul-11 Feb-12 Sep-12 Apr-13 Nov-13 Jun-14 Jan-15 Aug-15 Mar-16 Oct-16 May-17 Dec-17 Western Europe Market Outlook Offshore Rig Utilisation The 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 There are currently 28 warm stacked, and 2 cold stacked rigs in Western Europe. North Sea Rig Utilisation % Excluding the economic downturn in 29, the North Sea (UK & Norway) sustained rig utilisation above 8% between 28-H % 1% 9% New project installations will help increase Norway s drilling activity in the short to medium-term (218-22). 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 218-2; however, it is likely it will not be sufficient enough to support the reactivation of warm stacked rigs. Beyond 22, 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. 8% 7% 6% 5% 4% North Sea Active Rigs # of Rigs UK Norway North Sea Source: Westwood Analysis, Riglogix. 29

30 Western Europe Market Outlook Decommissioning Production Assets Westwood has identified 17 production assets (incl. Jack-Ups) for removal between Norway will dominate the tonnage landscape, while the UK represents c.18% of tonnage over the period Westwood anticipates a ramp-up in floating production removals beyond 22, with 15 units to be removed between At a country level, the UK and Norway will dominate, representing c.4% and c.5% of assets removed respectively, between Interestingly, Norway will represent around 8% of Western European tonnage removed between The five key projects include; Heidrun TLP c.289 kte Troll B c.194 kte Aasgard A c.184 kte Norne FPSO c.17 kte Snorre A TLP c.16 kte The above five projects represent c.65% of total tonnage removed between 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. Production Asset Removals by Asset Type # of Platforms Production Asset Removal Tonnage Thousand Te FPSO FPSS TLP Converted Jack Up Production Asset Removals by Country # of Platforms UK Norway Netherlands Denmark Tonnage by Country & Customer Thousand Te.4% 1% 81% UK Norway Netherlands Denmark 18% 8% 5% 8% 6% Statoil Shell Maersk Oil Point Resources Other 73% Source: Westwood Analysis. 3

31 Western Europe Market Outlook Decommissioning Production Assets The table shown below represents Westwood s opinion as to which production assets represent prime candidates for decommissioning between 217 and 23 Asset Type Asset Name Asset owner Status Current Location Year of Removal Age at Removal Asset Tonnage FPSO Gryphon Alpha Maersk Oil Operational UK ,193 FPSO Maersk Curlew Shell Operational UK ,8 FPSO Aasgard A Statoil Operational Norway ,3 FPSO Norne FPSO Statoil Operational Norway ,32 FPSS Balmoral FPV Premier Oil Operational UK ,479 FPSS Veslefrikk B Statoil Operational Norway ,998 FPSS Troll B Statoil Operational Norway ,7 FPSS Visund A (PDQ) Statoil Operational Norway ,6 TLP Snorre A TLP Statoil Operational Norway ,472 TLP Heidrun TLP Statoil Operational Norway ,77 Jack Up Inde BP Perenco Operational UK Jack Up Millom West ConocoPhillips Operational UK ,55 Jack Up Leman DP Perenco Operational UK Jack Up Leman FP Perenco Operational UK Jack Up AWG-1P NAM Operational Netherlands ,53 Jack Up Siri INEOS (Dong) Operational Denmark , FPSO Jotun A FPSO Point Resources Shut In Norway ,417 Source: Westwood Analysis, Riglogix 31

32 UK Norway NLDs Denmark UK Norway NLDs Denmark Western Europe Market Outlook Decommissioning Drilling Assets Cold stacked offshore drilling rigs are viewed as prime candidates for decommissioning or scrappage, with significant costs associated with bringing these units back to market 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 - 2m. 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 Warm & Cold Stacked Rig Tonnage Thousand Te 54% Jackup Semisub Drillship 26% * 65% Jackup Semisub Drillship 15% 7% 7% 6% North Atlantic Drilling Transocean Ltd. Saipem Paragon Offshore Other Cold Stacked Rigs by Country # of Rigs % 7% 62% 24% UK Norway Netherlands Denmark 45% Jackup Semisub Drillship 55% Warm Stacked Cold Stacked Source: Westwood Analysis. *NLDs: Netherlands. 32

33 Western Europe Market Outlook Decommissioning Drilling Assets The table shown below represents Westwood s opinion as to which warm stacked drilling assets represent prime candidates for decommissioning between 217 and 23 Asset Type Asset Name Asset owner Status Current Location Age at Removal Asset Tonnage Jackup Paragon C251 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 25,56 Jackup Swift 1 Swift Drilling BV Warm Stacked Netherlands 7 7,422 Jackup Paragon C462 Paragon Offshore Warm Stacked Netherlands 36 15,17 Jackup Paragon C252 Paragon Offshore Warm Stacked Netherlands 35 7,519 Jackup Paragon C463 Paragon Offshore Warm Stacked Netherlands 35 6,66 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 35,34 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 12,42 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 6,316 NOTE: 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 15 days. Source: Westwood Analysis, Riglogix 33

34 Western Europe Market Outlook Decommissioning Drilling Assets The table shown below represents Westwood s opinion as to which cold stacked drilling assets represent prime candidates for decommissioning between 217 and 23 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 1,272 Jackup Eir Borr Drilling Cold Stacked UK 18 15,223 Jackup Brage Borr Drilling Cold Stacked UK 19 14,471 Jackup ENSCO 7 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 4,731 Semisub WilHunter WilHunter (Malta) Cold Stacked UK 34 14,54 Semisub Sedco 714 Transocean Ltd. Cold Stacked UK 34 15,641 Semisub Sedco 711 Transocean Ltd. Cold Stacked UK 35 14,73 Drillship West Navigator North Atlantic Drilling Cold Stacked Norway 18 69,851 Source: Westwood Analysis, Riglogix 34

35 Western Europe Market Outlook Decommissioning Operational Drilling Asset Candidates A number of operational drilling assets are operating beyond the intended design life, highlighting these units as potential candidates for stacking or eventual decommissioning The data shown is sensitised to only include those assets which have an age of 3 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. Potential Candidates for Decommissioning Offshore Rig Data Asset Type Asset Name Asset owner Status Current Location Contract End Age at Removal Asset Tonnage Jackup ENSCO 72 ENSCO Drilling Netherlands Dec ,4 Jackup ENSCO 1 ENSCO Drilling UK Jun ,46 Jackup ENSCO 92 ENSCO Drilling UK Aug ,541 Jackup ENSCO 8 ENSCO Workover UK Dec ,588 Semisub Transocean Arctic Transocean Ltd. Drilling Norway Oct ,194 Semisub Bideford Dolphin Fred Olsen ASA Drilling Norway Oct ,813 Semisub Paragon MSS1 Paragon Offshore Drilling UK Oct ,67 Semisub Stena Spey Stena Drilling Workover UK Oct ,581 Semisub Ocean Patriot Diamond Offshore Workover UK Oct ,432 Semisub Paul B Loyd Jr Transocean Ltd. Drilling UK Dec ,54 Semisub Ocean Valiant Diamond Offshore Workover UK Feb ,149 Semisub WilPhoenix WilPhoenix (Malta) Drilling UK Apr ,13 Semisub Transocean Leader Transocean Ltd. Drilling UK Jun ,99 Semisub Transocean 712 Transocean Ltd. Workover UK Oct ,933 North Sea Offshore Rig Utilisation & Dayrates $ (LHS), % (RHS) Tonnage by Country & Customer Thousand Te 25 12% 2 1% 3% Average Dayrate Av. Jackup Utilisation Av. Semisub Utilisation 8% 6% 4% 2% % 16% 81% UK Norway Netherlands 8% 2% 14% 16% 42% Transocean Ltd. Diamond Offshore ENSCO Paragon Offshore Other Source: Westwood Analysis. 35

36 6) Competitive Analysis of Scottish Ports

37 Competitive Analysis of Scottish Ports Decommissioning Ports Key Award Factors 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 Scottish Ports Key Award Considerations Access/ Location HSE & Enviro. Practices Logistical Support Supply Chain Tier 1 Relationship Key Award Considerations Licenses Cost Lay Down Area Scottish Ports Westwood Approach WD & Draft Capability Quayside Length & Strength Westwood decommissioning insights and analysis is underpinned by; Extensive industry consultations with key stakeholders, Research products and modelling (i.e. Western European Decommissioning report) International consulting experience in relation to decommissioning, working with a diverse client offering across the decommissioning value chain Tier 1 Relationship Cost WD & Draft Capability Quayside Length & Strength Lay Down Area Licenses Supply Chain HSE & Environmental Practices Access/ Location Logistical Support 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. 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 Overall cost is cheaper in the UK than in Norway and Holland, especially when you consider manpower Decommissioning Manager - BP 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 Source: Westwood Analysis 37

38 Competitive Analysis of Scottish Ports Scottish Ports Competitive Analysis 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 ABLE UK - Hartlepool 1. Able UK m m 4. 6 t/m ,m 2 Harland & Wolff Belfast 1. Harland & Wolff m m 4. Various 5. 68,5m 2 of dry dock AF Decom Norway 1. AF Gruppen m m 4. High Impact Concrete ,m 2 Kvaerner Stord - Norway 1. Kvaerner Stord AS m m 4. High Impact Concrete 5. 68,m 2 Veolia & Peterson Gt. Yarmouth 1. Veolia & Peterson 2. 1 m m t/m , m 2 Key 1. Tier 1 Contractor 2. Water Depth 3. Quay Length 4. Quay Strength / Construction 5. Land Available Scheepssloperji Netherlands 1. Scheepssloperji m 3. 3 m 4. Undefined 5. 4,m 2 Source: Westwood Analysis, Industry Consultation, Port Analysis Desktop Research 38

39 Competitive Analysis of Scottish Ports Scottish Ports Dry Dock 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 Dry Most Dock 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 Dry In a Dock 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 Positive Ease of access to the entire asset Natural air bund preventing pollution Less dependency on tide / weather for operations Cost benefit with speed of project Negative Floating assets were not designed to stand Expensive to develop if not already in place Essential for FPSO decommissioning Floating assets can use buoyancy Dry Dry-dock 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 Dry If the Dock 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 From Dock an Environmental perspective a dry dock offers an excellent natural barrier to reverse pollution whilst decommissioning activity is underway Decommissioning Consultant The OGTC Small number available in the Region Potentially allows multiple projects at once Adds complication to level the asset Other yards do not need them to win work Dry A Dock 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 Source: Westwood Analysis, Industry Consultation 39

40 Competitive Analysis of Scottish Ports Case Study Decommissioning of The Buchan Alpha 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 Built in 1973 as a semi-submersible drilling rig Converted into FPSS in Started production on the Buchan field in 1981 Stopped production in 217 Full Load Displacement 19,4 tonnes Lightweight 12, 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, bbl/d. In 217, after 36 years and c.15 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 215. 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 trackrecord 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 217. 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 Overview 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 1 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 Source: Westwood Analysis, Industry Consultations, Desktop Research 4

41 7) Acronyms & Abbreviations

42 Acronyms & Abbreviations (1/2) AHTS Anchor handling supply tug APAC Asia Pacific AUV Autonomous underwater vehicle Avg. Average AVO Amplitude versus offset Bbl Barrel Bn Billion Bnboe Billion barrels of oil equivalent Boe Barrels of oil equivalent Boepd Barrels of oil equivalent per day BoP Blowout preventer Btoe Billion tonnes of oil equivalent c. circa CAGR Compound annual growth rate Capex Capital expenditure CIS Commonwealth of Independent States CoCS Chance of commercial success CoGS Chance of geological success CoS Chance of success CP Competent persons report CS Construction Support CSR Commercial success rate CSRs Commercial success rates D&P Drilling & Production DW Deepwater DECC Department of Energy & Climate Change Decomm Decommissioning Devt Development DSV Dive support vessel DS Drill Support DUC Drilled but uncompleted e. estimate E&A Exploration & Appraisal E&P Exploration & Production EBITDA Earnings before interest taxes depreciation and amortization EE&FSU Eastern Europe & Former Soviet Union EIA Energy Information Administration EM Electromagnetic EOR Enhanced Oil Recovery EPC EPCI EU Etc. Exc f/e DRAFT FEED FID FPS FPSO FPSS GDP GFC GoM GP HI HP HPHT ICD ILX IMR IMF IOC IPM ISO IRM JV KPI KSA L.Cret LatAm LCOE LCV LHS LNG LWD LWIV Engineering, Procurement, Construction Engineering, Procurement, Construction, Installation European Union Et cetera Excluding frontier / emerging Front end engineering and design Final Investment Decision Floating production and storage vessels Floating production storage and offloading vessels Floating production semi-submersible vessels Gross domestic product Global Financial Crisis Gulf of Mexico Gross profit High impact Horsepower High pressure, high temperature Inflow control device Infrastructure led exploration Inspection Maintenance & Repair International Monetary Fund International Oil Companies Integrated Project Management International Organisation for Standardisation Inspection, Repair and Maintenance Joint Venture Key performance indicators Kingdom of Saudi Arabia Lower Cretaceous Latin America Levelized cost of energy Light construction vessel Left hand side Liquefied Natural Gas Logging While Drilling Light weight intervention vessels 42

43 Acronyms & Abbreviations (1/2) m M&A Ma mboe mboe/d MEFS MENA Mmbbl Mmboe mmbtu MMO MODU MSGBC MSV MT Mtoe MWD N/A NAm NB NM NOC NS O&G O&M OCTG OECD OFE OFS OWF OPEC OSV Opex P&A PLEM PLET PNG POSg POSc Prodn Million Mergers and Acquisitions Mega-annum (million year) Thousand barrels of oil Thousand barrels of oil equivalent per day Minimum economic field size Middle East North Africa Million barrels of liquid (oil and or condensate) DRAFT Millions of barrels of oil equivalent Million british thermal units Maintenance, modifications and operations Mobile offshore drilling unit Mauritania-Senegal-Guinea-Bissau and Conarky Basin Multipurpose support vessel Metric tonnes Million tonnes of oil equivalent Measuring While Drilling Not applicable North America Nota bene Not meaningful National Oil Company North Sea Oil & Gas Operations & maintenance Oil County Tubular Goods Organisation for Economic Cooperation Oilfield Equipment Oilfield Services Offshore Wind Organization of the Petroleum Exporting Countries Offshores support vessel Operational expenditure Plug & Abandonment Pipeline end manifold Pipeline end termination Papua New Guinea Geological probability of success (geological chance of success) Commercial probability of success (commercial chance of success) Production PoB Persons on board PSV Platform supply vessel R&D Research & Development REP Richmond Energy Partners Ltd REP4 4 study group of companies RHS Right hand side RoW Rest of the world ROV Remotely operated vehicles ROVSV Remotely operated vehicle support vessel RVD Rex Virtual Drilling SA Stand-alone SEA South-East Asia SLB Schlumberger SURF Subsea Umbilicals Risers and Flowlines Tcf Trillion cubic feet TEN Tweneboa-Enyenra-Ntomme TSR Technical success rate TSRs Technical success rates U.Cret Upper Cretaceous UK United Kingdom UKCS United Kingdom Continental Shelf US United States US GoM United States Gulf of Mexico USD US Dollar USP Unique selling point vs versus WD Water depth WFT Weatherford WGEG Westwood Global Energy Group WTI West Texas Intermediate y-o-y Year on year YTD Year to date $/bbl Dollars per barrel $/boe Dollars per barrels of oil equivalent $ Thousands of dollars $m Million dollars $bn Billion dollars # Number of 43

44 8) Appendix

45 Appendix Major New Oil Capacity Top 3 Oil Fields Field Country Operator Increase West Qurna-2 Iraq Lukoil 3 Halfaya Phase 3 Iraq Missan Oil Company 251 Khafji Kuwiat/ KSA Al Khafji JOC 145 Fort Hills - Phase 1 Canada Suncor Energy Inc 12 Kashagan Kazakhstan North Caspian OC 12 Upper Zakum UAE ADNOC 115 Rumaila Iraq BP 19 Buzios Brazil Petrobras 14 Wafra Kuwiat/ KSA KGOC/Chevron 98 Egina Nigeria Total 8 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 6 Franco SW Brazil Petrobras 53 Suzunskoye Russia Rosneft 52 Ayatsil Mexico Pemex 51 Zubair Iraq ENI 5 Mazalij KSA Saudi Aramco 5 Abu Jifan KSA Saudi Aramco 5 Berri KSA Saudi Aramco 5 Satah Al-Razboot UAE ADNOC 5 South Pars Phase 14 Iran NIOC 5 South Pars Phase 13 Iran NIOC 49 Tambococha Ecuador Petroamazonas 48 Agbami Nigeria Chevron 46 Kaombo Angola Total 46 Other Various Various

46 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 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, bpd to 285, 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 1,5m. 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 25m. The mooring system allows the platform position to be altered, an advantage for drilling, completion, and workover. Source: Westwood Analysis. 46

47 Appendix Overview Offshore Drilling Rigs There are three primary MODU (Mobile Offshore Drilling Unit) designs, which include jack-ups, drillships, and semisubmersible drilling rigs 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. Source: Westwood Analysis. 47

48 Appendix Waste Removal Asset Preparing / Cleaning Waste Type Composition of Waste Disposal Route Onboard hydrocarbons Process fluids, fuels and lubricants Hydrocarbons filtered and discharged into water disposal wells Other hazardous materials Original paint coating NORM, LSA scale, any radioactive material, instruments containing heavy metals, batteries Lead-based paint Transported ashore for re-use/disposal by appropriate methods May 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) Structures Wellheads Wellhead Protection Structures FPU Mooring System Structure Piles Full recovery to vessel by lifting as complete unit Full recovery Full recovery 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. Hydrocarbons filtered and discharged into water disposal wells Transported ashore for re-use/disposal by appropriate methods 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. Waste Type Bulk Liquids Marine Growth NORM/LSA Scale Asbestos Other hazardous wastes Onshore dismantling sites Waste Stream Management Methods Management Method Removed 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 Removed onshore. Disposed of according to Oil and Gas UK Management of Marine Growth during Decommissioning (213) NORM 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 Will be contained and taken onshore for disposal Will be recovered to shore and disposed of under appropriate permit. Appropriate 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. 48

49 Scottish Ports Scottish Ports Key Award Factors Throughout our consultations and when examining the addressable market, some key award factors are evident. We examine these in detail here Scottish Ports Key Award Considerations Our industry consultations and knowledge of the decommissioning process have highlighted some key award factors when considering the opportunity 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 solution package 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 considered to 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.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 process Dales 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. Source: Westwood Analysis, Industry Consultation 49

50 Scottish Ports Scottish Ports Key Award Factors Throughout our consultations and when examining the addressable market, some key award factors are evident. We examine these in detail here Scottish Ports Key Award Considerations Our industry consultations and knowledge of the decommissioning process have highlighted some key award factors when considering the opportunity 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 to do 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 previous projects, ease of access, labour force requirements, suitability of contracting agreements and efficiency when considered to the overall 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. Source: Westwood Analysis, Industry Consultation 5

51 Scottish Ports Scottish Ports Key Award Factors Throughout our consultations and when examining the addressable market, some key award factors are evident. We examine these in detail here Scottish Ports Key Award Considerations Our industry consultations and knowledge of the decommissioning process have highlighted some key award factors when considering the opportunity 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 now increasingly 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 where best 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 sailing when 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. This again 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, Peterson were able to evidence efficient removal of the waste to the mainland by vessel and subsequent road transfer to the recycling or waste facilities. Source: Westwood Analysis, Industry Consultation 51

52 Vessel Decommissioning Vessel Decommissioning OSV Types Whilst the number of Crew Boats Anchor Handling Supply Tugs (AHTS) Platform Supply Vessels (PSV) ROV Support Vessels (ROVSV) Light Construction Vessels (LCV) Dive Support Vessels (DSV) Flex Layers Reel-Layers Conventional Pipelay Monohulls Offshore Support Vessels (OSV) Subsea Vessels SURF Vessels Offshore Construction Heavy Lift Monohull Semis 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. Small OSVs: AHTS vessels rated <8,hp and PSVs rated <2,dwt are typically seen as highly versatile shallow water support vessels and are grouped together under small OSVs in this analysis. 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 (<1MT) 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 (>1MT), 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 25m. 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 toptensioning 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. 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. 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. 52