DECOMMISSIONING INSIGHT Contents

DECOMMISSIONING INSIGHT 2017

DECOMMISSIONING INSIGHT 2017 Contents 1. Foreword 5 2. Key Findings 7 3. The North Sea Decommissioning Market 10 3.1 The Regulatory Environment 11 3.2 A Growing Market 12 3.3 Planning for Decommissioning 13 4. Forecast Activity Across the North Sea 14 4.1 Survey Development and Methodology 15 4.2 Well Plugging and Abandonment 16 4.3 Topside and Substructure Removal 23 4.4 Subsea Infrastructure 26 4.5 Onshore Recycling and Final Disposal 28 4.6 Site Remediation and Long-Term Monitoring 28 5. UK Continental Shelf Expenditure Forecasts 29 5.1 Maturity of Estimates 30 5.2 Cost Reduction Targets 30 5.3 Historical Comparison of Forecasts 30 5.4 Regional Breakdown 32 5.5 Expenditure by Decommissioning Component 32 5.6 Operator Project Management and Facility Running Costs 34 5.7 Well Plugging and Abandonment Costs 35 5.8 Platform Removal Costs 38 6. Glossary 41 3

HEALTH DECOMMISSIONING & SAFETY REPORT INSIGHT 2017 2017 The UK Oil and Gas Industry Association Limited (trading as Oil & Gas UK) 2017 Oil & Gas UK uses reasonable efforts to ensure that the materials and information contained in the report are current and accurate. Oil & Gas UK offers the materials and information in good faith and believes that the information is correct at the date of publication. The materials and information are supplied to you on the condition that you or any other person receiving them will make their own determination as to their suitability and appropriateness for any proposed purpose prior to their use. Neither Oil & Gas UK nor any of its members assume liability for any use made thereof. 4

1. Foreword 1 Oil & Gas UK s 2017 Decommissioning Insight captures an even broader picture of the decommissioning opportunities across the North Sea in Norway, Denmark and The Netherlands, as well as a focus on what the UK will offer between 2017 and 2025. We hope this further expands the information available to operators planning to decommission assets across the basin and assists supply chain companies in understanding the future demand for their services and expertise within a wider North Sea context. Our report shows the UK Continental Shelf (UKCS) is the largest decommissioning market in the North Sea, with annual decommissioning expenditure in 2016 amounting to 1.2 billion. Over the next five years, the annual expenditure profile is forecast to remain consistent at 1.7-2 billion per year, indicating that there is not a rush to decommission despite the downturn. Decommissioning will represent around 11 per cent of total expenditure in the basin this year, compared to 2 per cent in 2010. Looking ahead, 17 billion is forecast to be spent on UKCS decommissioning between now and 2025, which is in line with the trends we observed in the 2016 report. The forecast shows that decommissioning activity on the UKCS is greater than for the other three countries in the report, reflecting the total amount of infrastructure in the basin and the fact that an increasing number of mature assets are naturally coming to the end of their productive lives. This does not mean the UKCS is entering its declining years. Indeed, since 2014, production has increased by 16 per cent following a decade of continuous decline and, by the end of the year, one-third of production will come from new fields that have started up since 2016. More generally, there are also signs that development activity on the UKCS could pick up in 2018, with decommissioning expected to take place alongside more productive activities in oil and gas production. The UK s oil and gas industry has strived to improve its competitiveness in the face of the oil price downturn over the last few years. The increase in operational efficiency has helped to halve operating costs and boost production, as well as extend field life on many mature fields causing decommissioning to be postponed. Our industry s desire to collaborate to deliver a more sustainable future underpins this step change in performance, and a key vehicle for promoting positive change is the pan-industry Efficiency Task Force. This initiative has promoted sector-wide sharing of guidance, tools and best practice to support efficiency improvement. It is exciting to see how many companies have helped drive progress in this area across their whole business and are now applying the same lessons to control decommissioning costs. This report provides fresh evidence of how this focused approach has benefitted well plugging and abandonment (P&A) activities, where forecast expenditure has reduced on average by 5 per cent across the UKCS with many companies achieving much greater cost reductions. With well P&A predicted to be the largest category of expenditure through to 2025, the industry is concentrating on delivering big improvements in these high cost activities, while maintaining safety and environmental standards at the highest levels. In support of this, industry Guidelines for the Abandonment of Wells are currently being updated to reflect the latest lessons and best practices from around the world. Our collective experience shows we are doing the right things now to deliver an efficient and evolving decommissioning sector, where operators and their contractors work together to drive continuous self-improvement. Industry is committed to working closely with its regulators and the government to reach the shared target of a 35 per cent reduction in the total cost of decommissioning on the UKCS, and good progress is already being achieved. 5

DECOMMISSIONING INSIGHT 2017 It should be remembered that decommissioning on the UKCS is just getting under way. Our experience as a sector in decommissioning will in time become a valuable part of the UK oil and gas industry s international reputation. We will be judged by how effectively we manage late-life assets and how successfully we deliver our decommissioning programmes. If we continue to build on current achievements, the UK will in time earn its place as a global leader in late-life asset management and decommissioning. Our competencies in this field have already been recognised in the UK Government s Industrial Strategy as a key opportunity for our economy and we have clear aspirations to make decommissioning a part of a Sector Deal over the next few months. Looking at the wider North Sea picture, 23 fields are preparing for decommissioning on the Norwegian Continental Shelf. The Norwegian Petroleum Directorate s outlook for the next five years shows that expenditure will rise to 800 million by 2021. In The Netherlands, decommissioning between now and 2025 is forecast to take place on 106 fields totalling between 650-800 million. We face an exciting future; what we do now to build a decommissioning capability in the UK will reap rewards for years to come. The provision of an increasingly open and broad perspective on decommissioning activity will arm the industry with the information it requires to become more efficient and competitive. There is a very real opportunity for the UK s decommissioning sector to become a champion of decommissioning excellence within the global arena. Together we can achieve this, and this Decommissioning Insight with its wealth of market intelligence is one key way to prepare for achieving that outcome. Michael Tholen, Upstream Policy Director, Oil & Gas UK 6

2. Key Findings Decommissioning Across the North Sea Decommissioning is a growing market across the North Sea. Activity on the UK Continental Shelf (UKCS) is expected to be significantly higher than on the Norwegian, Danish and Dutch Continental Shelves to 2025. This reflects the scale of total infrastructure and the relative maturity of the different regions of the North Sea, with more fields reaching the end of their productive lives in the UK. 2 From 2017 to 2025, decommissioning is forecast to take place on 349 fields across the four regions of the North Sea: Six fields on the Danish Continental Shelf 23 fields on the Norwegian Continental Shelf 106 fields on the Dutch Continental Shelf 214 fields on the UKCS Across the four regions: Over 200 platforms are forecast for complete or partial removal Close to 2,500 wells are expected to be plugged and abandoned Nearly 7,800 kilometres of pipeline are forecast to be decommissioned UK Continental Shelf in Focus Decommissioning, as a proportion of total UKCS expenditure, has increased from 2 per cent in 2010 to 7 per cent ( 1.2 billion) in 2016. Operators forecast this figure will rise to 11 per cent ( 1.8 billion) this year. From 2017 to 2025, 17 billion is forecast to be spent on decommissioning on the UKCS. The annual expenditure profile is forecast to remain consistent over the near term at 1.7-2 billion per year. Forty-six per cent ( 7.9 billion) of the total UK decommissioning spend from 2017 to 2025 will be concentrated in the central North Sea. The largest category of expenditure is well plugging and abandonment (P&A) at 49 per cent ( 8.3 billion). The UK offshore oil and gas industry is committed to ensuring that decommissioning is carried out as cost-effectively as possible, while maintaining high safety and environmental standards. The average forecast cost for well P&A has fallen by 5 per cent in the central and northern North Sea and west of Shetland, and by 4 per cent in the southern North Sea and Irish Sea. These figures are expected to fall further as lessons learnt from industry experience are shared sector-wide to further improve efficiency. 7

DECOMMISSIONING INSIGHT 2017 Forecast Decommissioning Activity Across the North Sea, 2017 to 2025 Northern North Sea and West of Shetland Central North Sea Southern North Sea and Irish Sea Total UKCS Norwegian Continental Shelf Danish Continental Shelf Dutch Continental Shelf Total Number of fields with decommissioning activity Number of wells for P&A Proportion of wells that are platform wells Number of platforms for removal Topside weight to be removed Substructure weight to be removed Subsea infrastructure to be removed 45 77 92 214 23 6 106 349 568 604 452 1,624 300 113 410 2,447 70% (399) 49% (297) 76% (345) 64% (1,041) 85% (254) 98% (111) 84% (345) 72% (1,751) 12 19 67 98 14 17 77 206 238,110 52,655 13,586 224,458 128,024 31,015 78,760 68,979 4,772 541,328 249,658 49,373 123,205 115,176 2,555 75,602 58,602 590 119,665 84,502 1,385 859,800 507,938 53,903 Length of pipelines to be decommissioned 778 kilometres 2,624 kilometres 2,112 kilometres 5,514 kilometres 222 kilometres 217 kilometres 1,827 kilometres 7,780 kilometres Total tonnage coming onshore 304,351 383,497 152,511 840,359 240,936 134,794 205,552 1,421,641 8

Forecast Decommissioning Expenditure on the UK Continental Shelf, 2017 to 2025 1 Operator project management and facility running costs Central and Northern North Sea and West of Shetland Southern North Sea and Irish Sea Total UKCS 2.4 billion 216 million 2.7 billion Well P&A 6.8 billion 1.5 billion 8.3 billion Facilities making safe and topside preparation 808 million 150 million 958 million Pipelines making safe 121 million 162 million 283 million Topside removal 1.3 billion 133 million 1.4 billion Substructure removal 689 million 449 million 1.1 billion Mattress decommissioning and other subsea infrastructure removal 546 million 248 million 794 million Pipeline decommissioning 834 million 173 million 1 billion Onshore recycling and disposal 215 million 65 million 279 million Site remediation 136 million 43 million 179 million Monitoring 20 million 10 million 29 million Total 13.9 billion 3.2 billion 17 billion 2 Forecast Average Unit Costs for Well P&A and Cost per Tonne on the UK Continental Shelf, 2017 to 2025 Central and Northern North Sea and West of Shetland Southern North Sea and Irish Sea Average UKCS Platform well P&A 4.9 million 2.8 million 3.8 million Suspended exploration and appraisal well P&A Subsea development well P&A 6.9 million 3.4 million 4.9 million 10.1 million 7.8 million 9.7 million Facilities making safe 509 928 578 Topside removal 2,800 Substructure removal 4,700 3,600 3,436 1 All forecasts by region and component are rounded and so the sum of them may not come to the total forecast expenditure 9

DECOMMISSIONING INSIGHT 2017 3. Decommissioning Infograph The North Sea Decommissioning Market Facts and Figures, November 2017 In Summary W ith significant remaining resource yet to recover, the focus of the offshore oil and gas industry and its regulators across the North Sea (the UK, Norwegian, Danish and Dutch Continental Shelves) is to maximise economic recovery. In parallel with this, and a necessary part of the petroleum economics life cycle, is decommissioning of an oil and gas field. Decommissioning is a growing market as an increasing number of fields naturally reach the end of their productive lives. The timing around cessation of production (CoP) and subsequent decommissioning is notoriously challenging to plan for as it is affected by variables such as oil price, asset integrity, production efficiency, field interdependencies and brownfield investment potential. The recent fall in oil price, by and large, has not accelerated decommissioning, with only a small number of isolated examples where this has happened. Instead, the focusnovember across the North Sea Facts and Figures, 2017 is to maintain or extend field life by reducing costs and increasing operating efficiencies. The majority of decommissioning activity taking place now has long been in companies plans. Forecast decommissioning expenditure over the next five years: 1.7 2 billion on the UK Continental Shelf per year 400 800 million on the Norwegian Continental Shelf per year 650 800 million Decommissioning Infographics total on the Dutch Continental Shelf Decommissioning Forecast Supply activity is forecast onchain companies decommissioning must be The UK Continental Shelf (UKCS) currently has the largest 349 fields across the UK,able to compete expenditure in a global marketplace Norwegian, Danish decommissioning market in the North Sea, at around 1.2 billion in over the next five years: for decommissioning and Dutch Continental 2016 and is expected to grow to 1.8 billion in 2017. This is equalshelves to to 2025 contracts on quality, efficiency and cost around 11 per cent of total UKCS expenditure, and could increase 1.7 further to around 17 per cent by 2025 as more fields enter their billion decommissioning phase and spend in 2 other areas reduces. on the UK Continental Shelf per year The UK supply chain is therefore in a good position to develop the requisite skillset and experience to form 400 an international centre of excellence in decommissioning, with 800 the opportunity millionto export its expertise. Companies must, however,on develop the capability and Operators forecast that the Norwegian capacity to compete in a global marketplace on quality, total decommissioning Continental Shelf per yearefficiency spend in the and cost, while maintaining focus on high environmental and UK Continental Shelf safety standards. 650 will be 10 800 million total on the Dutch Continental Shelf 17 billion between 2017 and 2025 Almost 2,50 wells are forecast plugged and ab across the Nort to 2025, with m two-thirds in The Oil and Authority is tar 35%

3.1 The Regulatory Environment The OSPAR Commission is an international convention that aims to protect the marine environment of the North-East Atlantic. As contracting parties to the OSPAR Convention, the UK, Norway, Denmark and The Netherlands are committed to OSPAR Decision 98/3, which requires all offshore structures to be removed during decommissioning. Pipelines are not covered by OSPAR and are regulated under national legislation. National regulators can grant an exemption (derogation) from OSPAR Decision 98/3 for concrete structures and the footings of steel structures that weigh more than 10,000 and were installed before 1999; the infrastructure owner must demonstrate appropriate safety, environmental and technical considerations. Contracting parties are committed to carrying out a review every five years to determine if there is a case for reducing the scope of this derogation. The three reviews carried out since 1999 have concluded that a change in the criteria is not required. The next review is due in March 2018. 3 In the UK, the Department for Business, Energy & Industrial Strategy (BEIS) is the competent authority for decommissioning and is responsible for approving decommissioning programmes under the Petroleum Act 1998. The Oil and Gas Authority (OGA) ensures platforms do not prematurely cease production in line with the principles of MER UK (maximising economic recovery from the UKCS), and that decommissioning is carried out in a cost-effective manner. The OGA therefore grants approvals to cease production. In Norway, the Norwegian Petroleum Act regulates the shutdown and disposal of offshore facilities, while the Norwegian Ministry of Petroleum and Energy makes the final decision on decommissioning in consultation with the Norwegian Petroleum Directorate. In Denmark, platform decommissioning is regulated by the Subsoil Act and Offshore Safety Act, and approval and permits for decommissioning are awarded by the Danish Working Environment Authority. In the Netherlands, this activity is regulated under the Dutch Mining Act. In November 2016, The Netherlands Masterplan for Decommissioning and Re-use 2 set out plans to: establish a national platform to drive the decommissioning and re-use agenda; develop a national decommissioning database; promote effective and efficient regulation; and share learnings. The National Platform for Re-use and Decommissioning Nexstep was launched in October 2017 following a joint industry project between Energie Beheer Nederland (EBN) and The Netherlands Oil and Gas Exploration and Production Association (NOGEPA) 3. 2 See the Netherlands Masterplan for Decommissioning and Re-use at http://bit.ly/ebnmasterplan 3 See Nexstep National Platform for Re-use and Decommissioning at www.nexstep.nl 11

DECOMMISSIONING INSIGHT 2017 3.2 A Growing Market Across the North Sea, the current inventory of offshore infrastructure that will eventually require decommissioning includes over 11,000 wells, a pipeline network of 45,000 kilometres (including cables and umbilicals), 560 steel platforms and 24 gravity-based structures. In addition, there are some 40,000 mattresses plus hundreds of thousands of of other offshore infrastructure such as subsea templates and manifolds. To date, around 10 per cent of oil and gas platforms installed across the North Sea have been decommissioned and less than 5 per cent of pipelines. While decommissioning activity has not yet started in Denmark, it is already a growing market in the UK, Norway and The Netherlands. Decommissioning on the UKCS expanded from 2 per cent of total industry expenditure in 2010 to 7 per cent ( 1.2 billion) in 2016. This is expected to reach 1.8 billion in 2017, representing 11 per cent of total industry expenditure ( 17.1 billion). In Norway, decommissioning represented 2 per cent ( 400 million) of expenditure offshore in 2010. The Norwegian Petroleum Directorate forecasts that this will double as decommissioning expenditure is expected to rise to 800 million by 2021 4. While in The Netherlands, EBN forecasts that decommissioning expenditure will total between 650-800 million over the next five years, which is similar to the forecast spend on capital expenditure ( 570-800 million) 5. Decommissioning does not represent a new industry, but is part of the natural life cycle of an installation, relying on many of the same people and skills that have already been developed through oil and gas exploration and production. It encompasses a broad range of activities from well plugging and abandonment (P&A), to cleaning and flushing of facilities and pipelines, offshore removals and onshore disposal. With almost half of the estimated expenditure on the UKCS up to 2025 in well P&A, and a further 16 per cent to be spent on the preparatory work for decommissioning and running facilities after they cease production, much of the employment will be in these areas. The operator and service sector is already applying its extensive project delivery, engineering and offshore construction skills to deliver decommissioning projects across the North Sea and will continue to mature as the industry learns through experience. Well P&A is a key focus area and is benefitting from increasing technology development. Activities such as onshore recycling and final disposal are meanwhile increasingly visible and therefore attract significant attention, despite representing just 2 per cent of total expenditure in decommissioning on the UKCS from 2017 to 2025. The decommissioning of subsea infrastructure, meanwhile, is a less established discipline offering scope for companies to showcase and apply their expertise by driving innovation in subsea engineering. In the UK, current experience suggests that the supply chain already has the necessary skills and equipment to compete for over 80 per cent of the total decommissioning scope forecast over the next decade. However, companies must be able to compete successfully for this work in a global marketplace on quality, efficiency and cost. The supply chain has a significant role to play in offering cost-efficient solutions, while maintaining focus on high environmental and safety standards. 4 See Norwegian Petroleum Directorate at www.npd.no/en 5 See EBN s Focus on Energy report, June 2017, at http://bit.ly/ebnenergyfocus 12

3.3 Planning for Decommissioning The decommissioning process across the North Sea involves rigorous planning and consultation with regulators several years before production ceases. Decommissioning regulations, physical interdependencies of other fields, asset and equipment integrity, safety and environmental considerations, available technologies and market conditions are some of the factors that will determine the approach. Over time, the scope of each project is refined as engineering studies and comparative assessments are carried out to determine the optimum approach. Forecasting the precise schedule of each activity and the associated expenditure at the outset of a project is therefore challenging. 3 In addition to the complexities involved in planning each decommissioning project, there is also a great deal of uncertainty around the date that production will cease. CoP is not solely driven by oil price and the economics of the field. On older assets, CoP may be driven by asset integrity challenges, or it may be dependent on the economics of other interlinked fields or third-party tie-backs. In some cases, operators may continue production on sub-economic infrastructure because it acts as a host to other fields. On the UKCS, operators must gain regulatory approval from the OGA to cease production and often need to demonstrate that they have looked at different scenarios for maximising economic recovery of reserves and possible reuse of infrastructure. Infill drilling, subsea systems restructuring, near-field exploration and transfers in asset ownership are ways that operators can extend field life. Oil & Gas UK has analysed 23 UK asset transfers since 2011, which reveal that deals have extended field life by 4.8 years on average, with some fields producing for up to an additional 14 years. 13

Forecast decommissioning expenditure over the next five years: DECOMMISSIONING INSIGHT 2017 4. Forecast Activity Across the North Sea 1.7 2 billion on the Norwegian Continental Shelf per ye Supply chain co must be able to in a global mar for decommis total oncontracts the Dutchon efficiency Continental Shelf an 650 800 million on the UK Continental Shelf per year Decommissioning Infographics In Summary Decommissioning Facts and Figures, November 2017 400 activity is forecast on 800 million349 fields across the UK, he Decommissioning Insight 2017 T provides the first joint activity forecast for four regions of the North Sea: the Forecast UK, Norwegian, decommissioning Danish and Dutch Continental Shelves. Forecasts are provided for expenditure overto thegive nextafive years: the period 2017 to 2025 comprehensive picture of forthcoming activity, enabling 1.7to plan for operators and the supply chain decommissioning in the most cost-effective way. 2 billion on the Norwegian Norwegian, Danish Continental Shelf per year and Dutch Continental Shelves to 2025 Supply chain companies must be able to compete in a global marketplace for decommissioning on quality, total oncontracts the Dutch efficiency Continental Shelf and cost 650 800 million on the UK Continental Shelf per year Close to 2,500 wells are expected to be plugged and abandoned across the North Sea by 2025, Decommissioning Around with more than two-thirds 400 in the UK. activity200 is forecast on million fields across the UK, platforms are forecast 800 for complete or 349 partial the Norwegian Norwegian, Danish removal, with just underonhalf in the UK sector. Continental Shelf per year and Dutch Continental Shelves to 2025 On the seabed, there is an extensive network of 650 pipelines and other subsea infrastructure that million will eventually need to 800 be decommissioned. total on the Dutch After depressurisation and the removal Continental Shelf of hydrocarbons, current forecasts suggest around 7,800 kilometres of pipeline could be decommissioned by 2025. The timing of this activity is inherently uncertain and couldoperators be forecast that total decommissioning pushed out as the industry strives to maximise Decommissioning spend in the economic recovery. activity is forecast on Almost 349 fields across the UK, Norwegian, Danish and Dutch Continental Shelves to 2025 14 Operators forecast that total decommissioning UK Continental Shelf will be wells 2,500 17 billion between 2017 and 2025 are forecast to be plugged and abandoned across the North Sea up to 2025, with more than two-thirds in the UK The Oil and Gas Authority is targeting a Operators forecast that total decommissioning spend in the Almost UK Continental Shelf will be wells p a t A 2,500 17 billion between 2017 and 2025 are forecast to be plugged and abandoned across the North Sea up to 2025, with more than two-thirds in the UK U The Oil and Gas Authority targeting a Over 200isplatforms are expected to be removed in the North Sea from 2017 to 2025 35% reduction in UKCS decommissioning costs by 2035 The average forecast t

4.1 Survey Development and Methodology Data have been compiled from 25 operators on the UKCS, nine in The Netherlands, six on the Norwegian Continental Shelf and three on the Danish Continental Shelf. There are more operators with forecast decommissioning activity in the UK, reflecting the larger number of companies in the basin and its relative maturity. This year, forecasts for the UKCS were collated from raw data that operators submitted as part of the OGA s mandatory Asset Stewardship Survey, providing even better coverage of the market than previously. Detailed interviews were also carried out with operators on the UKCS to discover how they intend to deliver the OGA s 35 per cent cost reduction target (see section 5). Data from The Netherlands came from Nexstep National Platform for Re-use and Decommissioning, while Oil & Gas UK collected data directly from operators in Norway and Denmark. All data are structured around the components of the Decommissioning Work Breakdown Structure described in Oil & Gas UK s Decommissioning Cost Estimation Guidelines 6. The information is presented in a non-attributable and aggregated format. Analysis has been split by country. The UKCS data have been split further into the following groups: the central (CNS) and northern North Sea (NNS) and west of Shetland (WoS); and the southern North Sea (SNS) and Irish Sea. 4 It should be recognised that the activity forecasts provided in this report reflect operators current best estimates, and the timing is subject to change. The cost estimates provided for the UKCS could also adjust as efficiency gains drive costs down, while market pressures could influence them in either direction. With the aim of providing visibility of the whole North Sea decommissioning market, joint activity forecasts have been compiled for the UK, Norwegian, Danish and Dutch Continental Shelves, where available. In total, decommissioning activity is forecast on 349 fields across the North Sea: 214 on the UKCS, 106 on the Dutch Continental Shelf, 23 on the Norwegian Continental Shelf and six on the Danish Continental Shelf. Forecast activity on the UKCS to 2025 is significantly higher than in other regions of the North Sea. 6 The Guideline on Decommissioning Cost Estimation is available to download at www.oilandgasuk.co.uk/product/op061 15

DECOMMISSIONING INSIGHT 2017 4.2 Well Plugging and Abandonment The purpose of well P&A is to isolate reservoir fluids within the wellbore and from the surface or seabed. This activity is carried out in accordance with industry guidelines 7, as well as the Offshore Wells Design and Construction Regulations 1996 8 on the UKCS and the NORSOK D-10 regulations on the Norwegian Continental Shelf 9. Well P&A can be challenging and may involve intervention in the form of removing downhole equipment, such as production tubing and packers, and well-scale decontamination treatment. The process also requires the wellhead and conductor to be removed. Well P&A is the largest category of decommissioning activity, with 2,447 wells forecast to be plugged and abandoned across the North Sea to 2025 (1,624 in the UK, 300 in Norway, 113 on the Danish Continental Shelf and 410 in The Netherlands). The combined forecast for the North Sea has been relatively consistent year-on-year, clearly demonstrating the strong market opportunity that well P&A represents for the supply chain. Year-on-year activity will average at around 230 wells per year to 2022, before a new wave of projects starts in 2023. Seventytwo per cent of this activity is for platform wells (1,751), and the remainder are subsea wells. This ratio does however vary when looking at each region specifically (see regional breakdown on subsequent pages). The region with the highest number of wells forecast for P&A is the central North Sea where a quarter of the wells (604 wells) are located, while the Danish Continental Shelf is expected to see the least amount of activity with 113 wells due to be plugged and abandoned by 2025. Figure 1: Well P&A Forecast Across the North Sea CNS - Platform Wells CNS - Subsea Wells SNS and Irish Sea - Platform Wells SNS and Irish Sea - Subsea Wells NNS and WoS - Platform Wells NNS and WoS - Subsea Wells Norway - Platform Wells Norway - Subsea Wells Denmark - Platform Wells 500 Denmark - Subsea Wells The Netherlands - Platform Wells The Netherlands - Subsea Wells 450 400 Number of Wells 350 300 250 200 150 100 50 0 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: Oil & Gas UK, The Netherland's Nexstep National Platform, Asset Stewardship Survey 7 Guidelines on the Abandonment of Wells and Qualification of Materials for Abandonment are available to download at www.oilandgasuk.co.uk/product/op105 and www.oilandgasuk.co.uk/product/op109 8 See www.legislation.gov.uk/uksi/1996/913/made 9 See NORSOK Standard D-010 Well Integrity in Drilling and Well Operations, (Rev.4 June 2013) at http://bit.ly/20bwqdd 16

UK Central North Sea Operators forecast that 604 wells will be plugged and abandoned in this region to 2025. This is similar to estimates in 2016, although shifts in the timing of some projects have increased the proportion of platform wells from 37 to 49 per cent (297). Sixty-two wells are planned for P&A in 2017, with around 57 wells forecast per annum to 2020. From 2021, around 75 wells will be plugged and abandoned each year as a new wave of projects begin activity. Figure 2: Well P&A Forecast in the Central North Sea 120 100 Suspended Exploration and Appraisal Wells Subsea Development Wells Platform Wells 4 80 Number of Wells 60 40 20 0 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: Oil & Gas UK, Asset Stewardship Survey Number of Wells Proportion that are Platform Wells Forecast Expenditure 604 49% 4.2 billion 17

DECOMMISSIONING INSIGHT 2017 UK Northern North Sea and West of Shetland Forecast activity in these regions has increased from 428 to 568 wells. The 140 additional wells all lie towards the end of the survey timeframe. This increase is primarily due to greater survey coverage rather than the acceleration of well P&A. Large and complex decommissioning projects, which have long been in operators plans, are driving nearer-term activity (up to 2021). Seventy per cent of wells (399) forecast for P&A are platform wells. Year-on-year activity is at around 50 wells per year, until 2023 when a new wave of projects start, peaking at 153 wells in 2023. Figure 3: Well P&A Forecast in the Northern North Sea and West of Shetland 180 160 140 Suspended Exploration and Appraisal Wells Subsea Development Wells Platform Wells 120 Number of Wells 100 80 60 40 20 0 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: Oil & Gas UK, Asset Stewardship Survey Number of Wells Proportion that are Platform Wells Forecast Expenditure 568 70% 2.6 billion 18

UK Southern North Sea and Irish Sea Of the 452 wells forecast to be plugged and abandoned in these regions to 2025, 76 per cent (345) are platform wells. Forecast activity has increased by 77 wells since 2016, primarily due to greater survey coverage. Most of this new activity falls at the end of the timeframe. Near-term activity remains closely aligned to the forecast in 2016 and is associated with ongoing well P&A campaigns. Figure 4: Well P&A Forecast in the Southern North Sea and Irish Sea 100 90 Suspended Exploration and Appraisal Wells Subsea Development Wells Platform Wells 80 4 70 Number of Wells 60 50 40 30 20 10 0 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: Oil & Gas UK, Asset Stewardship Survey Number of Wells Proportion that are Platform Wells Forecast Expenditure 452 76% 1.5 billion Danish Continental Shelf Operators in Denmark forecast that 113 wells will be plugged and abandoned by 2025. The majority of activity 100 wells will take place in 2023 across four decommissioning projects, with the remaining 13 wells in 2025. Ninety-eight per cent (111) are platform wells. Figure 5: Well P&A Forecast on the Danish Continental Shelf Number of Wells Proportion that are Platform Wells 113 98% 19

DECOMMISSIONING INSIGHT 2017 Norwegian Continental Shelf Around 800 of the 3,800 wells that will eventually require decommissioning have already been plugged and abandoned on the Norwegian Continental Shelf 10. Of the remaining 3,000 wells, 10 per cent (300 wells) are forecast to be decommissioned by 2025. Eighty-five per cent (254) of these are platform wells. Activity is forecast at around 27 wells per year to 2024, peaking at 87 wells in 2025 indicating the start of several large projects that fall partially outside the survey timeframe. All the activity is concentrated in the most mature region of the basin the Norwegian North Sea. Figure 6: Well P&A Forecast on the Norwegian Continental Shelf 100 90 Subsea Development and Suspended Exploration and Appraisal Wells Platform Wells 80 70 Number of Wells 60 50 40 30 20 10 0 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: Oil & Gas UK Number of Wells Proportion that are Platform Wells 300 85% 10 See Abandonment of Obsolete Wells and Installations on the Norwegian Continental Shelf; a Study into the Magnitude and Technical and Economic Challenges, June 2014, University of Stavanger, at http://bit.ly/1m8jpnw 20

Dutch Continental Shelf Of the some 1,400 wells drilled in the waters in offshore Netherlands, 410 are forecast for P&A to 2025. Eighty-four per cent (345) of these are platform wells and the remainder subsea wells. Activity in the near-term to 2020 is forecast at 20 wells on average per year, increasing to an average of over 70 from 2022 onwards. Figure 7: Well P&A Forecast on the Dutch Continental Shelf 100 90 80 70 Suspended Exploration and Appraisal Wells Subsea Development Wells Platform Wells 4 Number of Wells 60 50 40 30 20 10 0 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: The Netherland's Nexstep National Platform for Re-use & Decommissioning Number of Wells Proportion that are Platform Wells 410 84% Rig Types Well P&A is typically carried out using a drilling rig, although in some cases, technologies exist that preclude the need for a rig altogether. The requirements depend on various factors, including well type, water depth and availability of rig-less techniques. Platform wells are typically plugged and abandoned in phases. The first phase can be rig-less and uses lower cost methods such as wireline, coil tubing or a hydraulic workover unit. This is followed by the second and third phases that are more likely to require a rig. Many platforms in the UK central and northern North Sea and the Norwegian Continental Shelf have an integral rig that could be used for platform well P&A. The decision to upgrade the integral rig for P&A will depend on when it was last used, the cost to upgrade and the availability of alternative approaches. Rig upgrades can be challenging and costly, and operators are considering alternatives to this approach. 21

DECOMMISSIONING INSIGHT 2017 In the Dutch sector, the few wellhead oil platforms that were originally equipped with a fixed drilling derrick have had these removed, which means all platform well P&A will be carried out with a jack-up rig or rig-less methods where available. For subsea wells requiring a rig, this will typically depend on water depth. For wells located in shallower water, a jack-up rig is typically used as they operate at a lower cost. Figure 8: Forecast Rig Type for Well P&A Across the North Sea, 2017 to 2025 Platform Wells NNS and WoS Integral rig 98% Stand-alone semi-submersible 2% CNS Integral rig 78% Modular rig 11% Stand-alone jack-up 11% SNS and Irish Sea Modular rig 5% Other rig-less 19% Stand-alone jack-up 55% To be decided 21% Danish Continental Shelf Stand-alone jack-up 90% Other rig-less 10% Norwegian Continental Shelf Stand-alone jack-up 40% Integral rig 47% More than one rig type 13% NNS and WoS Other rig-less 11% Stand-alone jack-up 11% Stand-alone semi-submersible 78% Subsea Wells CNS Other rig-less 11% Stand-alone jack-up 2% Stand-alone semi-submersible 84% To be decided 3% SNS and Irish Sea Stand-alone jack-up 69% To be decided 31% Danish Continental Shelf Stand-alone jack-up 100% Norwegian Continental Shelf Stand-alone jack-up 91% Semi-submersible 7% To be decided 2% Combined Wells Dutch Continental Shelf (platform and subsea combined) Stand-alone jack-up 50% Other rig-less 30% To be decided 20% 22

4.3 Topside and Substructure Removal The removal of 206 platforms is forecast across the UK, Norwegian, Danish and Dutch Continental Shelves to 2025. These range from small, unmanned, steel installations weighing 350 to larger, manned, steel and concrete gravity-based structures that weigh more than 1,000 times that. The total weight of infrastructure to be removed is close to 860,000 of topsides and 510,000 of substructure. Activity is greatest in the UKCS where 98 of the platforms are to be decommissioned, closely followed by The Netherlands with 77, 14 in Norway and 17 in Denmark. Making Safe and Topside Preparation Before a platform can be decommissioned, it must be hydrocarbon free. This is referred to as making safe and involves cleaning, freeing equipment of hydrocarbons, disconnection and physical isolation, and waste management. 4 The topsides are then prepared for removal, which involves separating them from the process and utilities modules and appropriate engineering, such as installing lift points. Topsides are prepared in line with the removal method being used (see below for the varying removal methods). The overall activity levels for making safe and topside preparation mirror that for topside removal. Making safe can be carried out several years prior to removing the platform, while topside preparation typically occurs directly prior to removal and can either be contracted out separately or built into the removal contract. Removal Methods The most common methods for topside removal are piece-small, reverse installation (piece-large) or single-lift. The piece-small method involves dismantling the topsides and using demolition techniques typically used onshore to produce small, manageable pieces that can be transported to shore. For reverse installation or piece-large, the topside modules are lifted separately onto a transportation barge or the deck of a crane vessel before being taken onshore. The single-lift method involves removing topsides in one piece and may involve extra engineering work to reinforce them in preparation for removal. For the substructure, the removal method depends on the type, weight and configuration. In the southern North Sea, Irish Sea and The Netherlands, the substructures that are to be decommissioned are primarily shallow-water jackets that typically weigh less than 2,000 and are usually deployed in water depths of 55 metres or less; the single-lift method is suitable for these structures. For larger substructures (barge-launched, lift-installed and some self-floaters), the jackets may be cut into smaller sections in situ and removed in segments. These more complex projects are typically located in the central and northern North Sea and on the Norwegian Continental Shelf. The supply chain continues to innovate in cutting technology to undertake this task. 23

DECOMMISSIONING INSIGHT 2017 Figure 9: Forecast Topside and Substructure Removal Across the North Sea, 2017 to 2025 11 Number of platforms CNS NNS and WoS SNS and Irish Sea Norwegian Continental Shelf Danish Continental Shelf Dutch Continental Shelf 19 12 67 14 17 77 206 Total Small steel 2-61 2 12 Large steel 17 8 6 11 5 Gravity based structure Total topside weight to be removed () Total substructure weight to be removed () Water depth 26 manned and 51 unmanned 11-4 - 1 - - 5 224,458 238,110 78,760 123,205 75,602 119,665 859,800 128,024 52,655 68,979 115,176 58,602 84,502 507,938 45 to 143 metres 118 to 190 metres 18 to 73 metres 66 to 174 metres 37 to 60 metres 22 to 50 metres - 18 to 190 metres UK Central North Sea Nineteen platforms and eight floating, production, storage and offloading (FPSO) vessels are forecast for complete or partial removal to 2025. Two are small steel structures weighing less than 4,000, while the remainder are large steel structures weighing between 4,500 and 56,600. Operators are actively looking to group activity into multi-platform removal campaigns, particularly for substructures that can be more easily left in situ until decommissioning activity aligns with that of other infrastructure in the area. 843 million is forecast to be spent on topside and substructure removal to 2025. 11 Platforms in The Netherlands have been categorised differently into manned and unmanned installations. 24

UK Northern North Sea and West of Shetland Twelve platforms are forecast for complete or partial removal, four of which are gravity-based and the remainder large steel installations weighing between 15,400 and 70,000. Two FPSOs are also expected to be decommissioned. Eleven of these platforms were built prior to 1999 and weigh in excess of 10,000, making them candidates for derogation under OSPAR rules (see section 3 on the regulatory environment). Due to the size and complexity of platforms in these regions, removal of the topside and substructure are often carried out individually rather than as part of a multi-platform campaign. Some operators are, however, actively looking at opportunities to decommission substructures in a campaign approach. 1.1 billion is forecast to be spent on topside and substructure removal in these regions to 2025. UK Southern North Sea and Irish Sea Of the 67 platforms forecast for removal, only six of these weigh more than 4,000 with the majority being small, steel, unmanned installations that are likely to be removed by single-lift. Platform weights range from 350 to 9,200 (1,900 on average). Several operators are already removing platforms in these regions as part of multi-platform campaigns spanning many years. Operators with fewer platforms are exploring opportunities to combine their activities with those of other operators. 582 million is forecast to be spent on topside and substructure removal in these regions to 2025. 4 Norwegian Continental Shelf Operators forecast that 14 fixed platforms and two floating production units will be removed by 2025. Total platform weights range from 4,000 to 30,000 (12,000 on average). Nine of the platforms are to be removed in a multi-platform campaign approach. Danish Continental Shelf Seventeen platforms, four of which are normally unmanned installations, are to be removed from the Danish Continental Shelf. Platform sizes range from 970 to 22,100 (5,700 on average). Operators plan to carry out all activity in a multi-platform campaign approach. The sizes of individual campaigns range from two to 11 platforms. Dutch Continental Shelf Of the 150 platforms remaining in the Dutch North Sea 12, 77 are forecast for removal by 2025. Looking at the total inventory offshore in The Netherlands, the platforms range from small wellhead structures weighing just 500 to larger gravity-based structures of around 50,000 13. Through the combined effort of EBN and NOGEPA, the Dutch industry has developed a database and Nexstep National Platform for Re-use and Decommissioning so that activity can be co-ordinated and carried out in the most efficient manner. 12 See the Netherlands Masterplan for Decommissioning and Re-use at http://bit.ly/ebnmasterplan 13 See the OSPAR Inventory of Offshore Installations 2015 at https://odims.ospar.org/odims_data_files/ 25

DECOMMISSIONING INSIGHT 2017 4.4 Subsea Infrastructure Pipelines The extensive pipeline network across the North Sea measures in excess of 45,000 kilometres and is used to deliver hydrocarbons to receiving facilities and end-users across Europe. This transportation network is critical when assessing the economics of field-life extension projects or new developments. It is therefore essential that major pipelines are not decommissioned prematurely. Options for pipeline decommissioning include full removal, decommissioning in situ, trenching and burial. The agreed approach is decided on only when all the different methods are considered in a robust comparative assessment that accounts for safety and environmental factors, technical feasibility, other users of the sea and cost. All decisions are made on a case-by-case basis in consultation with key stakeholders and subject to regulatory approval. Around 7,800 kilometres of pipeline (including cables and umbilicals) are forecast to be decommissioned across the four regions of the North Sea up to 2025. Around 2,000 kilometres are associated with decommissioning projects that have already started. As pipeline decommissioning is one of the final activities in a typical project, the timing is difficult to predict and is dependent on all other tasks that precede it. For this reason, a detailed yearly forecast has not been provided. Figure 10: Forecast Pipeline Decommissioning, 2017 to 2025 Trunkline (km) Other Pipelines (km) Umbilicals (km) CNS 631 1,367 626 NNS and WoS 170 418 190 SNS and Irish Sea 671 908 533 Norwegian Continental Shelf 64 124 34 Danish Continental Shelf - 208 9 Dutch Continental Shelf 139 1,529 159 n 26

For a pipeline to be decommissioned it must be hydrocarbon-free. Making safe of pipelines involves depressurising them and removing any hydrocarbons. Then the pipelines are cleaned and purged, with the cleaning programme based on the specific needs of the system. This may involve the use of pigs, which are maintenance tools used to clean or inspect the insides. Making safe is often carried out several years prior to the next phase of decommissioning. In some cases, pipelines can be brought back into use after making safe, reflecting the importance of the infrastructure and the drive to maximise economic recovery of reserves where possible. In the UKCS, for example, there has been an influx of investment in key pieces of upstream and midstream infrastructure as private equity firms see that opportunities are still available to recover the significant resources that remain in the basin. Antin Infrastructure Partners has taken on operatorship and invested in a major export route called the Central Area Transmission System (CATS), while Arclight is investing in the Shetland Islands Regional Gas Evacuation System (SIRGES) and Frigg UK pipeline (FUKA). Further deals this year included the sale of the Forties pipeline, which INEOS bought from BP, and purchase of the decommissioned Thames pipeline from Perenco by Independent Oil & Gas. The latter was with a view to using the pipeline as the export route for its southern North Sea infrastructure. 4 Mattresses and Other Subsea Infrastructure Mattresses are concrete structures that are usually used to protect or support subsea pipelines. Mattress decommissioning typically involves recovery from the seabed. This is a diver and vessel-intensive operation, with duration of the work dependent on the mattress age and condition. In some cases where mattresses are badly degraded, regulatory approval may be sought to decommission in situ. Other subsea infrastructure includes manifolds, Christmas trees, risers, spools, jumpers, anchors and subsea isolation valves, which are removed as part of the decommissioning programme. Operators forecast that over 15,200 mattresses will be decommissioned across the UK, Norwegian and Danish Continental Shelves from 2017 to 2025. Information on mattresses was not available for The Netherlands. Around 54,000 of other subsea infrastructure are also expected to be removed from the North Sea. Figure 11: Forecast for Mattresses and Other Subsea Infrastructure Decommissioning, 2017 to 2025 14 Number of Mattresses Other Subsea Infrastructure () CNS 7,975 31,015 NNS and WoS 2,433 13,586 Southern North Sea and Irish Sea 4,670 4,772 Norwegian Continental Shelf 186 2,555 Danish Continental Shelf 9 590 Dutch Continental Shelf 14-1,385 14 The number of mattresses forecast to be decommissioned was not available for the Dutch Continental Shelf. 27

DECOMMISSIONING INSIGHT 2017 4.5 Onshore Recycling and Final Disposal Onshore recycling and disposal includes activities related to the cleaning and handling of hazardous waste, deconstruction, reuse, recycling, disposal and waste management. Preferred processes to deal with offshore structures that are no longer in use follow the hierarchy of reuse, recycling and onshore disposal. Once the structures are onshore, disassembling and processing takes place on specialist licensed sites. Operators have a duty to monitor all waste generated offshore and its handling and disposal through an environmental management system 15. Transporting topsides and substructures to shore is the most visible and obvious aspect of decommissioning, yet onshore dismantling represents less than 2 per cent ( 279 million) of the estimated total UKCS decommissioning expenditure to 2025. Lifting and transportation costs can be significant compared to those of onshore dismantling. This is due to the cost of equipment required and the distances to travel. Therefore, the location of onshore dismantling yards relative to offshore structures, as well as the yards ability to receive the largest offshore lifting vessels, are important factors in developing competitive bids for work. Just over 1.4 million of offshore infrastructure are expected to be brought onshore for recycling and final disposal from the North Sea to 2025. Twenty-seven per cent (383,497 ) will come from the central North Sea, 21 per cent (304,351 ) from the northern North Sea and west of Shetland, 17 per cent (240,936 ) from the Norwegian Continental Shelf, 14 per cent from the Dutch Continental Shelf (205,552 ) 11 per cent from the southern North Sea and Irish Sea (152,511 ) and ten per cent from the Danish Continental Shelf (134,794 ). 4.6 Site Remediation and Long-Term Monitoring Site remediation includes cuttings piles management, debris clearance and over-trawl surveys. Over-trawl surveys ensure the seabed is safe for normal fishing activities to resume. Long-term monitoring is the very final stage of decommissioning, where operators carry out surveys on the site after decommissioning has been completed and continue to monitor the site based on an agreed programme with regulators. In the UK, estimated expenditure for these activities from 2017 to 2025 is 208 million. 15 See Oil & Gas UK s Environment Report at www.oilandgasuk.co.uk/environmentreport 28

is forecast on 800 million349activity fields across the UK, 5. on the Norwegian Norwegian, Danish Continental Shelf per year and Dutch Continental Shelves to 2025 Supply chain companies must be able to compete in a global marketplace for decommissioning total oncontracts the Dutchon quality, Continental Shelf and cost efficiency Forecast decommissioning expenditure over the next five years: 650 800 million UK Continental Shelf Expenditure Forecasts 1.7 2 billion In Summary T on the UK Continental Shelf per year 400 he primary objective for the UK industry activity is forecast on 800 million 349 fieldsto across the UK, and government is for decommissioning on the Norwegian Norwegian, Danish be carried outcontinental in a cost-effective, safe and and Dutch Continental Shelf per year environmentally sound manner, but Shelves only once to 2025 remaining resources have been economically maximised. 650 The OGA is targeting a 35 per cent reduction in total 800 million decommissioning costs on the UKCS by 2035 from the total on the Dutch 2017 baseline expectationcontinental of 60 billion, Shelf and is working with industry to deliver this. Decommissioning Looking nearer term, operators forecast that 17 billion will be spent on decommissioning in the basin fromforecast that Operators total 2017 to 2025.Decommissioning This is 4 per cent higher than thedecommissioning forecast spend in the for the sameactivity periodis last year, forecast ondue to more projects Almost Shelf UK Continental 349 fields across the being included in the report UK, rather than increasedwill cost be Norwegian, Danish estimates for projects. While 90 per cent of wells andexisting Dutch Continental these projectsshelves are in their early scoping stages, the data to 2025 between 2017 and 2025 reveal that around one quarter of the total UKCS well to be are forecast plugged abandoned stock is anticipated to be plugged and abandonedand over across the North Sea up the period, accounting for almost half of the expenditure. to 2025, with more than 2,500 17 billion two-thirds in the UK As the industry strives towards efficient decommissioning, operators are increasingly adopting an approach to late-life asset management that Operators forecast thatdecommissioning incorporates operational and Theactivities Oil and Gas total decommissioning Authority in parallel as part of their strategic planning. A goodis targeting a spend in the example of this is the P&AShelf of redundant wells before the UK Continental field ceases production. will be 17 billion 35% The anticipated cost of well P&A has fallen across the between 2017 and 2025 UKCS for all well types as operators increasingly look reduction in to carry out such activity in a campaign approach, UKCS decommissioning whereby multiple wells are grouped to costs by 2035 increase efficiencies. Operators forecast that total decommissioning spend in the Almost UK Continental Shelf will be wells 2,500 17 billion between 2017 and 2025 are forecast to be plugged and abandoned across the North Sea up to 2025, with more than two-thirds in the UK The Oil and Gas Authority is platforms targeting a Over 200 are expected to be removed in the North Sea from 2017 to 2025 35% reduction in UKCS decommissioning costs by 2035 The average forecast un cos it t for well plugging and abandonment has fallen across all well types and regions of the UK Continental Shelf 29 5

DECOMMISSIONING INSIGHT 2017 5.1 Maturity of Estimates Each year, UK operators provide the cost classification for each of their decommissioning projects using the Association for the Advancement of Cost Engineering (AACE) classifications. These seek to define the project stage and indicate the degree of uncertainty in the estimates. Estimates are comprised of various elements and the detail typically increases as project planning progresses. Class 4 or 5 estimates mean that the projects are in the early planning stages where the scope of work is still being defined and feasibility studies are being carried out. Class 5 estimates have an expected accuracy range of -20 to +100 per cent; this wide range narrows over time. Class 2 estimates, meanwhile, represent projects that are in the contracting stage with some activities already being executed. These have a higher degree of accuracy of -5 to +20 per cent. In the last five years, over 90 per cent of projects reported in the Decommissioning Insight have been Class 4 or 5 estimates, with forecasts being refined year-on-year as the project scopes are better defined. Logging carried out to determine a well stock s condition, for example, may change the assumed duration of well P&A, or engineering studies might change the planned method for removing a platform. 5.2 Cost Reduction Targets In June 2017, the OGA estimated that it would cost around 59.7 billion to decommission all current and proposed future offshore facilities, pipelines, wells and onshore terminals in the UK 16. This forecast was derived by applying a probabilistic cost estimation methodology to operators 2016/2017 Asset Stewardship Survey data. It is the mid-point in a range from 44.5 billion to 82.7 billion (2016 money), which reflects the high level of uncertainty in Class 4 and Class 5 projects used in the forecast. The OGA has set a target, working with industry, to reduce decommissioning costs by 35 per cent to 39 billion, as set out in its Decommissioning Strategy 17. Progress is already being made in a number of areas, as outlined in the following sections, while maintaining safety and environmental standards. 5.3 Historical Comparison of Forecasts Accounting for 2 per cent of total UKCS expenditure in 2010, the decommissioning market is expected to grow to 11 per cent ( 1.8 billion) this year. Overall, decommissioning expenditure in the basin is forecast at 17 billion from 2017 to 2025, compared with the 16.4 billion forecast over the same period in the 2016 Decommissioning Insight 18. This increase is due to greater survey coverage, resulting in the inclusion of new projects, rather than increased cost estimates for existing projects. 16 The OGA s UKCS Decommissioning 2017 Cost Estimate Report is available at www.ogauthority.co.uk/media/3815/ukcs-decommissioning-cost-report-2.pdf 17 See the OGA s Decommissioning Strategy at www.ogauthority.co.uk/media/1020/oga_decomm_strategy.pdf 18 The nine-year time period 2017 to 2025 is the timeframe included in the OGA s Asset Stewardship Survey whereas historically the Decommissioning Insight has covered a ten-year timeframe. 30

Figure 12 shows how cumulative expenditure estimates of decommissioning have varied over the last five years. As recently as 2013, the ten-year forecast was 10.8 billion due to fewer projects with cost estimates available and forecasts were rising by up to 30 per cent per year from 2013-15. Although the outlook is ever-changing, there has been a relatively consistent trend since 2015. Some of the drivers behind the anticipated growth in expenditure since 2013 include: More decommissioning activity as the UKCS matures as the ten-year window moves forward each year, decommissioning activity grows in line with the UKCS maturity. The change in economic environment the current lower oil price environment has encouraged companies to develop more robust estimates for decommissioning. In 2013, the UKCS was in a phase of growing capital investment and operators were more focused on where they could invest in new developments. For this reason, decommissioning expenditure and activity forecasts tended to tail off in the second half of the ten-year outlook. Now companies are planning further ahead for decommissioning as a key part of their overall business expenditure. Cost estimates becoming more detailed as any decommissioning activity draws closer, cost estimates become better defined and often increase as the scope becomes clearer. 5 Figure 12: Historical Comparison of Cumulative Forecast Expenditure 25 2013 Survey 2014 Survey 2015 Survey 2016 Survey 2017 Survey Cumulative Expenditure ( Billion - 2016 Money) 20 15 10 5 0 2013 2015 2017 2019 2021 2023 2025 Source: Oil & Gas UK, Asset Stewardship Survey 31

DECOMMISSIONING INSIGHT 2017 5.4 Regional Breakdown Forty-six per cent ( 7.9 billion) of UKCS decommissioning expenditure from 2017 to 2025 is concentrated in the central North Sea, 35 per cent ( 6 billion) in the northern North Sea and west of Shetland, and 19 per cent ( 3.2 billion) in the southern North Sea and Irish Sea. The higher proportion of expenditure in the central and northern North Sea regions reflects the size and degree of complexity of projects in these regions where sea conditions are more challenging due to deeper water. While the number of platforms to be removed is greater in the southern North Sea and Irish Sea, these are typically much smaller installations that are simpler and therefore cheaper to decommission. Figure 13: Regional Breakdown of Decommissioning Expenditure Southern North Sea and Irish Sea 19% Central North Sea 46% Northern North Sea and West of Shetland 35% Source: Oil & Gas UK, Asset Stewardship Survey 5.5 Expenditure by Decommissioning Component Costs are estimated according to the different components of decommissioning as defined in the Work Breakdown Structure (see Figure 14 opposite). The largest category of expenditure from 2017 to 2025 is well P&A at 49 per cent ( 8.3 billion), compared to 47 per cent in the Decommissioning Insight 2016. This is due to an increase in the number of wells and does not reflect higher forecast unit costs, which have fallen for all well types and regions in the UKCS as outlined in section 5.7. The removal of topsides and substructures accounts for 15 per cent ( 2.6 billion) or 21 per cent ( 3.5 billion) when the associated preparatory work for removal is also considered. 32

Figure 14: Decommissioning Expenditure Broken Down by Activity, 2017 to 2025 Topside preparation Cleaning and flushing of hydrocarbons Offshore construction Separation of processing equipment Platform removals Offshore lifting operations Vessel, sea-fastening, transportation and load-in Subsea and pipeline decommissioning Pipeline flushing Subsea operations 12% Onshore disposal, remediation and monitoring Onshore disposal, remediation and monitoring Field debris clearance Monitoring programme 2% 15% Well P&A Wells project management services Specialist wells services Rig upgrades Project management and facility running costs Offshore operations Project management services Preparation of decommissioning programme 16% 49% 6% Estimated Cost - 17 Billion 5 3,000 2,500 Project management and facility running costs Topsides preparation Subsea and pipeline decommissioning 2016 Actuals Well P&A Platform removals Onshore disposal, remediation and monitoring Expenditure ( Billion - 2016 Money) 2,000 1,500 1,000 500 0 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: Oil & Gas UK, Asset Stewardship Survey 33

DECOMMISSIONING INSIGHT 2017 5.6 Operator Project Management and Facility Running Costs Operators forecast that a significant proportion of overall decommissioning expenditure will be spent on project management and facility running costs ( 2.7 billion, 16 per cent) from 2017 to 2025. This includes preparatory work for decommissioning such as regulatory compliance and feasibility studies, as well as running installations after CoP until they are fully decommissioned. The proportion of expenditure in this area has declined from 19 per cent in last year's report as the industry strives to reduce decommissioning costs. For projects that involve platforms for removal, the costs in the central and northern North Sea and west of Shetland account for 26 per cent ( 2 billion) of expenditure compared to just 7 per cent ( 216 million) in the southern North Sea and Irish Sea. Indeed, 92 per cent of project management and facility running costs in the UKCS are concentrated in the central and northern North Sea and west of Shetland, a reflection of the size and complexity of these typically manned installations. As more fields approach the end of their productive lives and operators learn from the experience of recent decommissioning projects, there is an increasing drive towards streamlining the regulatory process and schedule of activities to enable a smoother and more cost-effective transition into decommissioning. Industry is also focused on delivering efficiency gains and cost reductions in the decommissioning process itself. For assets that were included in the survey last year, operators expect to spend close to 440 million less than was forecast. Measures being taken to safely reduce the cost of running facilities in late-life and once they cease production include: Concurrent late-life production and decommissioning activities carrying out decommissioning activities while production continues, for example P&A on redundant wells, means the manpower on an asset can be lowered earlier and the decommissioning project s overall duration can be reduced. Some operators on the UKCS are aiming to carry out up to 75 per cent of their well P&A activity before production ceases. Tailored maintenance strategy for late-life assets as CoP approaches, maintenance requirements change. An optimised strategy will help avoid maintenance on equipment that is no longer required or will shortly become redundant. This has the potential to deliver significant savings in decommissioning, from 20 to 25 per cent in the southern North Sea and Irish Sea to up to 50 per cent in the central and northern North Sea. Fixing the date of CoP this gives a much clearer picture of maintenance requirements in late-life and allows activities to be scheduled with decommissioning in mind. However, there are several challenges, notably whether the planned date aligns with the regulatory approvals process and the industry s focus on maximising recovery. It is acknowledged that this approach requires a change in mindset which several operators are looking to adopt. New operating models for fields in late-life and decommissioning the decision to hand over operatorship and the right time to do so is asset specific, but also depends on market capabilities and pressures. Operators must find the right balance between maintaining asset-specific knowledge and ensuring decommissioning expertise. 34

5.7 Well Plugging and Abandonment Costs The cost of well P&A depends on water depth, weather, reservoir type, age, condition and, in some cases, measures to prevent well collapse caused by depressurisation. The costs included in this report vary significantly in their degree of maturity. While some are informed by previous experience and data, other estimates are at an earlier stage of development and are inherently more uncertain. Oil & Gas UK has carried out analysis to look at the average and range in unit cost estimates for well P&A over the past five survey years. As shown in Figures 15 and 16 overleaf, the range is wide, particularly for subsea wells, although the average cost is relatively stable. Wells at the low-cost end are typically simple rig-less P&As, using wireline, pumping or crane jacks, where the reservoir may already have been isolated. Wells at the top end are more complex, rig-based P&As, with challenging access and cementing. They may require retrieval of tubing and casing, milling, and cement repairs. Since forecasts were made in 2016, the average unit cost for well P&A has fallen across all well types and regions of the UKCS. This reflects greater industry experience in this area as well as lower rig rates, which have fallen 30 per cent for jack-up rigs and 37 per cent for semi-submersible rigs over the past year. 5 35

DECOMMISSIONING INSIGHT 2017 Figure 15: Historical Variation in Well Plugging and Abandonment Cost Forecasts in the Central and Northern North Sea and West of Shetland Estimated Cost per Well ( Million - 2016 Money) 50 45 40 35 30 25 20 15 10 5 0 Average Forecast Cost Platform Wells Average Forecast Cost Suspended Exploration and Appraisal Wells Average Forecast Cost Subsea Development Wells 2013 2014 2015 2016 2017 2013 2014 2015 2016 2017 2013 2014 2015 2016 2017 Platform Suspended Exploration and Appraisal Subsea Development Source: Oil & Gas UK, Asset Stewardship Survey Well P&A 2016 Survey Average 2017 Survey Average Platform wells 5.3 million 4.9 million Subsea development wells 10.7 million 10.1 million Suspended exploration and appraisal wells 6.8 million 6.9 million Figure 16: Historical Variation in Well Plugging and Abandonment Cost Forecasts in the Southern North Sea and Irish Sea Estimated Cost per Well ( Million - 2016 Money) 25 20 15 10 5 0 Average Forecast Cost Platform Wells Average Forecast Cost Suspended Exploration and Appraisal Wells Average Forecast Cost Subsea Development Wells 2013 2014 2015 2016 2017 2013 2014 2015 2016 2017 2013 2014 2015 2016 2017 Platform Suspended Exploration and Appraisal Subsea Development Source: Oil & Gas UK, Asset Stewardship Survey Well P&A 2016 Survey Average 2017 Survey Average Platform wells 2.9 million 2.8 million Subsea development wells 8 million 7.8 million Suspended exploration and appraisal wells 7.3 million 3.4 million 36

Approaches to Cost Reduction in Well P&A As the largest category of decommissioning expenditure, well P&A is an important area to drive cost reductions and efficiency improvements. Oil & Gas UK expects costs to continue to fall as industry experience grows. Operators have reported the following measures being explored to reduce costs: A campaign approach carrying out multiple well P&As in a campaign allows mobilisation costs to be spread across several wells and incremental improvements in technique can be cascaded across the campaign. Some operators have reported time savings per well of more than one-third over the course of large multi-platform campaigns spanning several years. Adoption of a risk-based approach analysing the risk to develop a scope of work that is appropriate on a well-by-well basis has significantly reduced costs for some operators. Each well has a different risk profile and the scope of work is developed accordingly. Cross-operator collaboration by vessel sharing and adding wells to the campaigns of other operators in the area, there are opportunities for cross-operator campaigns. Continued investment in technology technological advancements continue to drive down costs in well P&A. The newly formed Oil & Gas Technology Centre (OGTC) put out a call offering match-funding for concepts and ideas that could drive transformation in well P&A. Four new technologies are currently being explored, focused on three key themes: new barriers placement and materials; verification of permanent barriers; and optimising P&A scope. 5 Optimising the activity schedule for platform wells this could mean carrying out P&A in an order that reduces the distance the drilling derrick must travel across the platform between wells and leaves the highest performing wells until last. Alternatives to the existing drilling derrick considering rig-less methods, or removal of the topsides so that a workover rig can be used. Early removal of subsea infrastructure reducing the amount of subsea infrastructure around the well-site prior to carrying out subsea well P&A reduces the time spent manoeuvring around complex subsea infrastructure landscapes. Assessing the well condition using a light well intervention vessel to set plugs and carry out logging on the subsea well stock to assess their condition prior to beginning the campaign. The approach ultimately adopted to carry out well P&A depends on various factors, with no single approach being appropriate for every situation. Operators are learning from each other through proactive networking and sharing lessons learnt through conferences and forums. This area continues to be one of significant development and progress. 37

DECOMMISSIONING INSIGHT 2017 5.8 Platform Removal Costs A platform s weight has little effect on some of the standard overheads associated with removal, including removal preparation, vessel mobilisation, sea-fastening, transportation and load-in onshore. The smallest and lightest structures, commonly found in the southern North Sea and Irish Sea, can therefore have a much larger cost per tonne for topside removal. The overall cost per platform, meanwhile, is significantly lower in these regions. Looking at the graphs below and overleaf, there is a wide range in forecast removal costs per tonne across the UKCS. Platforms at the top of the range are the smallest, weighing less than 500. In the central and northern North Sea, most platforms are expected to fall below 6,000 per tonne for topside removal and 8,000 per tonne for substructure removal, with just a few platforms at the high-end of the cost scale. There are a variety of factors driving the removal cost for the large, complex platforms found in these regions, including weather constraints, removal method, or the ease with which removal activity can be carried out as part of a campaign. Figure 17: Historical Variation in the Removal Costs per Tonne for Topsides and Substructures in the Central North Sea and Northern North Sea and West of Shetland Estimated Cost per Tonne ( - 2016 Money) 14,000 12,000 10,000 8,000 6,000 4,000 2,000 Average Forecast Topside Removal Cost per Tonne Average Forecast Substructure Removal Cost per Tonne 0 2013 2014 2015 2016 2017 2013 2014 2015 2016 2017 Topside Substructure Source: Oil & Gas UK, Asset Stewardship Survey Removal Cost per Tonne 2016 Survey Average 2017 Survey Average Topsides 3,600 2,800 Substructures 4,300 4,700 38

Figure 18: Historical Variation in the Removal Cost per Tonne for Topsides and Substructures in the Southern North Sea and Irish Sea 18,000 Estimated Cost per Tonne ( - 2016 Money) 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 5 0 2013 2014 2015 2016 2017 Topside and Substructure Source: Oil & Gas UK, Asset Stewardship Survey Removal Cost per Tonne 2016 Survey Average 2017 Survey Average Topside and Substructure 3,900 3,600 Approaches to Cost Reduction The market for heavy-lift vessels required for topside and substructure removals is well-established, particularly for platforms that can be removed by single-lift using smaller barges. As the market matures, vessels such as the Pioneering Spirit are being built to lift heavier loads 19 and the supply chain is increasingly offering integrated packages that combine different decommissioning activities into a single contract, often through consortiums of several companies that individually offer very different services. With topside and substructure removal and the associated preparatory work representing 21 per cent of total decommissioning expenditure on the UKCS to 2025, efficiency gains in this area will have a substantial impact in lowering the overall cost of decommissioning. 19 See www.allseas.com/equipment/pioneering-spirit 39

DECOMMISSIONING INSIGHT 2017 Operators have indicated that they are looking to reduce the costs of removal by: Consolidating decommissioning activity as part of a longer-term programme aggregating the removal of several platforms in a single campaign spreads mobilisation costs across assets. This may involve leaving some assets in place until their removal aligns with activity for other assets. Allowing the market to drive the removal method rather than dictating a particular approach, operators are increasingly looking to the supply chain to specify the optimum solution, and are open to integrated packages of services and contracts. Being flexible about when activity takes place this allows the removal contractor to carry out the activity when the vessel is available. Exploring the potential for cross-operator campaigns this is already proving a valuable approach in the southern North Sea where platforms are smaller and the cost for removal per tonne is therefore higher. 40

6. Glossary AACE Barge-launched jacket Casing Christmas tree CNS Coiled tubing Comparative assessment CoP Conductor Drilling derrick Decommissioning in situ EBN Flexible flowlines FPSO Infill drilling Integral rig Intervention Association for the Advancement of Cost Engineering Barge-launched jackets weigh between 5,000 and 25,000. They are yard fabricated and transported horizontally to the field on a transportation barge, then launched from the barge over rocker beams and upended through controlled flooding. Final positioning may require crane assistance. Pipe installed in the wellbore to retain the borehole dimension and seal off hydrocarbon and water-bearing formations. Casing is usually cemented in place to ensure the pipe remains in place. The valves and fittings assembled at the top of a completed well. Central North Sea A long continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Used to compare options, examine differences and identify the most preferred option in the development of decommissioning programmes for: a) All installations for which derogation is sought under OSPAR Decision 98/3 b) All pipelines being decommissioned under the Petroleum Act 1998 c) All drill cuttings piles that are not screened-out at Stage 1 of OSPAR Cessation of production A large diameter pipe extending upwards from or beneath the seafloor to the top of the well on the platform. The purpose of the conductor is to act as a guide for drilling the well and a protective barrier from the elements for the well casings and tubing during the life of the well. A structure used to support crown blocks and drilling string of a rig. Leaving infrastructure in place and carrying out appropriate work to ensure that there is minimal risk to other sea users or the marine environment. This could apply to any installed facilities on the seabed, such as pipelines, manifolds, pipeline crossings and the footings of larger jackets. Energie Beheer Nederland is a company that invests in the exploration, extraction and storage of gas and oil on behalf of the Dutch State. Flexible flowlines usually transport hydrocarbons between subsea infrastructure and the host platform or vessel. They are manufactured from composite layers of steel wire and polymer sheathing that provide protection and flexibility to the flowline. Floating, production, storage and offloading vessel. The addition of wells in a field that decreases average well spacing to accelerate expected recovery and increase estimated recovery in heterogeneous reservoirs. Fixed rig installed at the well location, usually self-contained, with steel or concrete legs anchored to the seafloor. Well servicing operations conducted within a completed wellbore to restore or improve production or injection. 6 41

DECOMMISSIONING INSIGHT 2017 Jack-up rig Jumper Lift-installed jackets Logging Making safe Manifold Mattresses MER UK Milling Modular rig NNS NOGEPA NUI OGA Over-trawl surveys Piece-large Piece-small Pig Plug Self-contained combination drilling rig and barge with legs that can be raised and lowered independently onto the seafloor. A short segment of flexible pipe with a connector half at either end. A jumper is commonly used to connect flowlines and/or subsea facilities together. These structures weigh less than 10,000 and are yard-fabricated before being transported on a barge to the field. Once at the field, the jacket is lifted from the barge into position using a suitable crane vessel. To continuously measure formation properties with electrically powered instruments to make decisions about drilling and production operations. Making safe of facilities includes cleaning, freeing equipment of hydrocarbons, disconnection and physical isolation, and waste management. Making safe of pipelines involves depressurising them and removing any hydrocarbons. Then the pipelines are cleaned and purged, with the cleaning programme based on the specific needs of the system. A manifold in the context of oil and gas production is a pipe to which wells are connected in order to collect, co-mingle and direct fluid flow from more than one well. Such an installation can be on a platform or on the seabed for accumulating several subsea wells. Manifolds can be used for the distribution of fluids for injection into a series of wells. Mattresses are often used to provide protection, for stabilisation, and as crossover support for pipelines. These comprise flexible blocks linked with rope or wire, or concrete forms or grout bags filled with cement. Maximising Economic Recovery from the UKCS A mill or similar downhole tool is used to remove casing in the well where a barrier needs to be installed in case of pressure or potential movement of hydrocarbons behind the casing. The objective is to prevent fluids flowing into another formation or to the surface. Rig designed in modules that can be lifted onto a platform by crane to be erected on site. Northern North Sea The Netherlands Oil and Gas Exploration and Production Association Normally Unmanned Installation Oil and Gas Authority Over-trawl surveys make sure the seabed is safe for normal fishing activities to resume. Reverse installation whereby the topsides modules are lifted separately onto a transportation barge or the deck of the crane vessel before being taken onshore. The piece-small method involves dismantling the topside and using onshore demolition techniques to produce small, manageable pieces that can be transported onshore. A device used to clean pipelines. A solid or gel made out of a variety of materials designed to stop up a hole or aperture, to fill a gap, or to act as a wedge. 42

Reverse installation Rigid pipelines Risers Satellite installations Sea-fastening Self-floaters Single-lift Semi-submersible rig Shallow-water jackets SNS Spool Subsea isolation valves Subsea tie-back Trunkline Tubing UKCS Umbilical Same as piece-large Rigid pipelines are manufactured from carbon steel or a high performance steel alloy, with additional coatings providing corrosion protection, stabilisation or, in some cases, insulation. Rigid pipelines transport hydrocarbons between subsea infrastructure and platforms and to shore. The portion of a pipeline extending from the seafloor to the surface is termed a riser. The function of a riser is to provide conduit(s) to move produced fluids and/or injection fluids between the seafloor equipment and the production host. Small, unmanned platforms consisting of minimal facilities (wells, manifolds, and perhaps minimal separation and or testing facilities). These installations are designed to operate in conjunction with a host fixed production platform to provide further processing and onward transportation of fluids. The securing of cargo to a vessel so that movement during transportation does not cause damage. These steel jacket structures weigh more than 12,000 and are designed with two large diameter legs for buoyancy during installation. The single-lift method involves removing the topside in one piece and may involve extra engineering work to reinforce the topside in preparation for removal. Used for deepwater drilling. They have ballasted columns to remain on location assisted by either mooring lines or dynamic positioning systems. Used for exploration and development drilling. These structures usually weigh under 2,000 and are typically deployed in water depths of 55 metres or less. They include smaller launched and lift-installed jackets, as well as minimum facilities platforms. Southern North Sea Short segment of rigid pipe with a connector half at either end. A spool is commonly used to connect flowlines and/or subsea facilities together, e.g. a subsea tree to a subsea manifold. On platforms, spools are used to connect pre-installed piping where final connection is performed offshore. A safety device installed in the upper wellbore to isolate producing fluids in the event of an emergency. Subsea tie-backs usually connect small reservoir accumulations, developed using subsea trees and manifolds, back to a host platform for onward processing and or transportation. Trunklines are defined as pipelines with a diameter greater than 14 inches and a length above 18 kilometres. Usually referred to as production (or injection) tubing. This is a pipe inserted in the well to carry and contain the production (or injection) from the reservoir to the surface. UK Continental Shelf Utility support pipes 6 43

DECOMMISSIONING INSIGHT 2017 Well-scale decontamination Well P&A Wellhead Wireline Workover rig WoS The removal and decontamination of scale build-up that deposits in the tubing of a well during production of reservoir fluids. Well plugging and abandonment The wellhead is the termination point where the casing strings in the well are supported and provide pressure containment. A form of well intervention that uses an electrical cable to lower tools into the borehole and to transmit data to the surface. A mobile self-propelled rig used to perform one or more remedial operations, such as deepening, plugging back, pulling and resetting liners. West of Shetland 44

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