Spends&Trends UKCS

Transcription

1 Spends&Trends UKCS

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3 Executive Summary 4 1. Introduction 6 2. Oil & Gas Production Forecasts 8 3. Overall Expenditure Summary Historical expenditure Expenditure forecasts Capital Expenditure Forecasts Historical capital expenditure Capital expenditure forecasts 15 Development wells 17 Topsides equipment 18 Subsea production systems 19 Pipelines 20 Floating production systems 21 Platform structures Field Developments Fields under development Fields under consideration Incremental investments Operating Expenditure Forecasts Historical operating expenditure Operating expenditure forecasts Exploration and Appraisal Activity Historical exploration and appraisal activity Forecast exploration and appraisal activity Decommissioning Overview Expenditure forecasts Decommissioning projects 32 Appendix 1: Fields under development 34 Appendix 2: Fields under consideration 68 3

4 EXECUTIVE SUMMARY This is the latest in the series of Spends and Trends reports produced by Scottish Enterprise. It gives detailed forecasts of activity and expenditure on the UK Continental Shelf (UKCS) for the five years The UKCS is now a very mature oil and gas province, having produced for over 30 years. Although oil and gas output has declined during the last few years, the remaining recoverable reserves should ensure production for another 20 years. The expenditure forecasts show that there will be a surprisingly high level of activity over the next few years, with a number of major field developments underway or planned, notably in the West of Shetland area. One of the main reasons for the increase in development activity is obviously high oil prices, with Brent crude trading at over $100 per barrel at the time of writing. The table and figures opposite set out the overall expenditure forecasts to The total is just over 90 billion with an annual average of 18 billion. Capital expenditure is forecast to be just under 44 billion or 49% of the overall total. Most of that will be for new field developments but there are also some important new investments on existing fields such as Forties and Schiehallion. Table 5.1 lists 34 new fields currently under development and Table 5.2 lists 52 fields on which work could begin before Table 5.3 lists 12 existing fields on which major new investments are currently underway. There is a long list of other possible developments, however it is thought that only a few of those will be developed during the period to 2016, therefore these have not been included in this report. The UKCS capital expenditure is predicted to fall from 9.7 billion in 2012 to 6.7 billion in Nevertheless, there will undoubtedly be a very high level of development activity over the next few years. Operating expenditure is forecast to be just over 36 billion or 40% of the overall total. Despite the falling production, this expenditure is predicted to increase slowly from 6.9 billion in 2012 to 7.4 billion in Exploration expenditure is forecast to be 6.8 billion or 7.5% of the overall total. The annual number of exploration and appraisal wells is predicted to fall from 56 in 2012 to 28 in Decommissioning expenditure is forecast to be 3.7 billion or 4% of the overall total. This is clearly a growing market but difficult to predict because of the major influence of oil prices. The decommissioning of the Brent field is expected to account for most of the expenditure during the period to

5 OVERALL EXPENDITURE SUMMARY Million 22,000 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2, Capital Expenditure Operating Expenditure Exploration Decommissioning OVERALL EXPENDITURE SUMMARY MILLION Capex 9,650 10,250 9,400 8,000 6,650 43,950 Opex 6,900 7,100 7,300 7,350 7,400 36,050 Exploration 1,750 1,700 1,400 1, ,800 Decom ,050 3,690 TOTAL 18,790 19,650 18,750 17,350 15,950 90,490 5

6 1. INTRODUCTION The Scottish Enterprise Energy Team has published Spends and Trends on a regular basis over the last few years. The reports have covered most of the regions of the world with offshore oil and gas operations. This new report covers the UK Continental Shelf (UKCS) and gives forecasts of expenditure for the five years , disaggregated into four categories: capital expenditure (capex) operating expenditure (opex) exploration decommissioning The UKCS is now a very mature oil and gas province, with exploration dating back to the 1960s and production to the 1970s. Both oil and gas production have declined in recent years and are currently about 50% of their historic peaks. However, there is currently a significant upturn in activity, mainly as a result of high oil prices which were above $100 at the time of writing. That is particularly noticeable in the West of Shetland area where various fields previously believed to be non-commercial are now being developed. There will therefore be a surprisingly high level of capital expenditure over the next few years. There is also significant investment in existing fields such as Forties in order to extend their productive lives. These new fields should help to slow down the decline in UKCS production when they come onstream. They will also ensure that there is production for at least another 20 years. If oil prices continue to be high, it is also possible that there will be resurgence in exploration activity, particularly by the smaller, independent companies. The Spends and Trends forecasts are derived from Mackay Consultants database, which covers all producing fields on the UKCS, all fields under development and all known discoveries. This report also makes considerable use of information from the Department of Energy and Climate Change (DECC) and Oil & Gas UK, the industry s representative body. 6

7 FIGURE 1.1: MAP OF UKCS Source: Department of Energy and Climate Change (June 2012) 7

8 2. OIL & GAS PRODUCTION FORECASTS UKCS oil production peaked in 1999 at million tonnes, equivalent to 2.9 million barrels per day (bpd), and UK gas production peaked in 2000 at (net) billion cubic metres. Since then production has declined. The Department of Energy and Climate Change (DECC) produces frequent production figures and forecasts. DECC s figures for UKCS oil and gas production are reproduced in Figure 2.1 and Table 2.1. The average decline since peak output has been about -5% per year but the falls in 2011 were much greater. Oil production fell by a massive -17.5% and gas production by -21.6%, with a combined decline of -19.3%. Million Tonnes Oil Equivalent FIGURE 2.1: UKCS OIL AND GAS PRODUCTION Crude Oil & NGLs Natural Gas TABLE 2.1: UKCS OIL AND GAS PRODUCTION Million tonnes of oil equivalent (Mtoe) MILLION TONNES Crude Oil & NGLs Natural Gas TOTAL % CHANGE Source: Department of Energy and Climate Change 8

9 Oil & Gas UK, the industry s representative body, recently published its annual Economic Report The report states that over the last 45 years more than 41 billion boe of oil and gas have been recovered from the UKCS. Even now, after more than four decades, there are still substantial reserves to be recovered. Oil & Gas UK forecasts that there are between 15 and 24 billion boe to be extracted. This encompasses proven, probable and possible reserves from existing fields and new developments, plus a contribution from additional resources arising from marginal or tertiary developments using improved or enhanced oil recovery techniques as well as from further exploration. The estimates of these reserves are illustrated in Figure 2.2. FIGURE 2.2: UKCS RESERVES AND RESOURCES Billion boe - - Resources Yet to Find Undeveloped Discoveries Possible Probable Existing Fields and Sanctioned Investment Production in Source: Oil & Gas UK 9

10 Oil & Gas UK s latest projections of UKCS oil and gas production are reproduced in Figure 2.3 below. FIGURE 2.3: UKCS OIL AND GAS PRODUCTION PROJECTIONS PRODUCTION FORECAST (OIL AND GAS LIQUIDS) PRODUCTION FORECAST (GAS) Liquids Production (million boepd) Gas Production (million boepd) % 90-99% 80-89% 70-79% 100% 90-99% 80-89% 70-79% 60-69% 50-59% Possible 60-69% 50-59% Possible Source: Oil & Gas UK These projections have been used as the basis for the operating expenditure forecasts. They also take account of the new fields which will come onstream during the period to

11 3. OVERALL EXPENDITURE SUMMARY 3.1 Historical expenditure Figure 3.1 and Table 3.1 set out the historical expenditure estimates for the period Total UKCS expenditure increased from 12.4 billion in 2007 to 14.2 billion in 2010 and subsequently to 17 billion in The main reason for the large rise in 2011 was an increase in capital spending, as explained in Section 4 of this report. Of the 2007 total of 12.4 billion, operational expenditure (opex) accounted for 47%, capital expenditure 43%, exploration 8% and decommissioning 1%. The estimated shares in 2011 were opex 39%, capex 51%, exploration 8% and decom 1%. Opex increased by +15% over the five years However, the table and figure show a surprising fall in opex in 2009, presumably because of the economic recession in the UK at that time. Capex has fluctuated from year to year, with a notably large +49% increase in Million 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 FIGURE 3.1: TOTAL EXPENDITURE Capital Expenditure Operating Expenditure Exploration Decommissioning TABLE 3.1: TOTAL EXPENDITURE MILLION Capex 5,303 4,780 4,850 5,850 8,700 29,483 Opex 5,829 6,857 6,375 6,500 6,700 32,261 Exploration 1,090 1,274 1,200 1,550 1,400 6,514 Decom TOTAL 12,385 13,074 12,625 14,150 17,000 69,234 Source: Department of Energy and Climate Change / Mackay Consultants 11

12 The UKCS is a very mature oil and gas province, and whilst production has been declining for several years, it may be surprising that total expenditure increased during the period. There were two main reasons: (a) the large increase in oil prices and modest increase in gas prices, leading to challenging, capital intensive fields becoming economic (b) cost inflation in the industry These reasons merit discussion in this report because of their relevance to the forecasts as well as the historical experience. In relation to prices, Figure 3.2 is reproduced from Oil & Gas UK s 2012 Activity Survey and shows how oil and gas prices changed over the period. The price of Brent crude, for example, shot up during 2008 to a peak of about US$140 per barrel and then collapsed to about US$40. The figure shows steady increases since the beginning of 2009 and during the first quarter of 2012 Brent crude averaged over US$120 per barrel. High oil prices have many implications for the industry because they can extend the lives of existing fields and make marginal prospects economically viable. The industry has to take a long term view of prices, of course, but at the time of writing the general expectation seems to be that oil prices will remain high for the next few years, potentially over US$100 per barrel. Gas prices in Europe, in contrast, have been much less volatile, as shown in Figure 3.2. Nevertheless, the average National Balancing Point (NBP) price in the first quarter of 2012 was double the low experienced in late The second reason mentioned above is that there has been substantial cost inflation, partly because of falling production and partly because of high demand for particular goods and services. 160 FIGURE 3.2: COMPARISON OF BRENT OIL AND NBP GAS PRICES, Oil/Gas price ($/boe) Brent Oil Price ($/boe) Day Ahead Gas Equivalent Price ($/boe) 12 0 Jan 08 Jul 08 Jan 09 Jul 09 Jan 10 Jul 10 Jan 11 Jul 11 Jan 12 Source: Oil and Gas UK/ Heren Energy

13 3.2 Expenditure forecasts The forecasts in Figure 3.3 and Table 3.2 show total expenditure of 90.5 billion over the five years , with an annual average of 18 billion. It is predicted to peak at 19.7 billion in 2013 and then fall to just under 16 billion in Capex is forecast to account for just under 44 billion or 49% of the overall total. It is predicted to peak at billion in 2013 and then fall to 6.7 billion in Opex is forecast to total just over 36 billion or 40% of the overall total. It is predicted to increase slowly from 6.9 billion in 2012 to 7.4 billion in 2016, despite forecast declines in oil and gas production. Exploration and appraisal expenditure is forecast to total 6.8 billion or 7.5% of the overall total. It is expected to fall by about half over the five years. Million FIGURE 3.3: OVERALL EXPENDITURE SUMMARY ,000 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2, Decommissioning expenditure is forecast to total 3.7 billion or 4% of the overall total. It is expected to increase steadily over the five years. Capital Expenditure Operating Expenditure Exploration Decommissioning TABLE 3.2: OVERALL EXPENDITURE SUMMARY MILLION Capex 9,650 10,250 9,400 8,000 6,650 43,950 Opex 6,900 7,100 7,300 7,350 7,400 36,050 Exploration 1,750 1,700 1,400 1, ,800 Decom ,050 3,690 TOTAL 18,790 19,650 18,750 17,350 15,950 90,490 Source: Mackay Consultants 13

14 4. CAPITAL EXPENDITURE FORECASTS 4.1 Historical capital expenditure Figure 4.1 and Table 4.1 show the estimated UKCS capital expenditure for the last five years It averaged about 5 billion per year but increased substantially to 8.7 billion in A high level of capex is expected over the next few years at least until There can be little doubt that the main reason for this substantial increase in capex is high oil and gas prices. Brent crude, for example, has traded at up to $125 per barrel during the first half of The oil and gas companies must take a long term view of prices but there seems to be a general expectation in the industry that they will remain high, in the short term at least. Million 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 FIGURE 4.1: CAPITAL EXPENDITURE TABLE 4.1: CAPITAL EXPENDITURE MILLION Capital Expenditure 5,303 4,780 4,850 5,850 8,700 Source: Mackay Consultants 14

15 4.2 Capital expenditure forecasts Most of the capital expenditure during the period will be for new field developments but incremental investments will also be important. The latter include the 3 billion redevelopment of the Schiehallion and Loyal fields known as the Quad 204 project and the 4.5 billion Clair Ridge development, which could be regarded as Phase 2 of the existing Clair field. The forecasts show total capex of just under 44 billion during the period , which is just under 49% of the total expenditure forecast. The annual average is about 8.8 billion, with a peak of billion in Figure 4.2 and Table 4.2 provide a breakdown by category. Million FIGURE 4.2: CAPITAL EXPENDITURE BY CATEGORY 12,000 10,000 8,000 6,000 4,000 2, Development wells Topsides equipment Subsea systems Pipelines Floating production systems Platform structures Other 15

16 TABLE 4.2: CAPITAL EXPENDITURE BY CATEGORY MILLION Development wells 4,630 5,235 4,900 4,320 3,610 22,695 Topsides equipment 1,265 1,405 1,085 1, ,740 Subsea systems 915 1,140 1, ,710 Pipelines ,975 Floating production systems ,575 Platform structures ,845 Other ,410 TOTAL 9,650 10,250 9,400 8,000 6,650 43,950 Source: Mackay Consultants FIGURE 4.3: BREAKDOWN OF CAPITAL EXPENDITURE BY CATEGORY % Development wells are predicted to account for by far the largest share (52%), followed by topsides equipment (13%), subsea production systems (11%), pipelines (7%), platform structures (6%), floating production systems (6%) and other (5%). 7% Pipelines 11% Subsea systems 13% Topsides equipment 5% Other 52% Development wells 6% Floating production systems 6% Platform structures 16 Source: Mackay Consultants

17 Development wells Expenditure on development wells is expected to total 22.7 billion over the five years, which is 52% of the capex forecast and 25% of the total expenditure forecast. Details for the fields currently under development are provided in Appendix 1. A breakdown of this expenditure is given in Figure 4.4 and Table 4.3. Rig costs, which have risen considerably in recent years, are expected to account for about 55% of this category, downhole and well services 32% and support services 13%. Million 6,000 5,000 4,000 3,000 FIGURE 4.4: DEVELOPMENT DRILLING EXPENDITURE BY CATEGORY 2,000 1, Support services Downhole and well services Rig costs TABLE 4.3: EXPENDITURE ON OFFSHORE DEVELOPMENT DRILLING MILLION Rig costs 2,685 2,985 2,695 2,325 1,915 12,605 Downhole and well services 1,400 1,675 1,615 1,380 1,120 7,190 Support services ,900 TOTAL 4,630 5,235 4,900 4,320 3,610 22,695 Source: Mackay Consultants 17

18 Topsides equipment Both the fixed platforms and the floating production systems will require topsides equipment, usually in modular form. Figure 4.5 and Table 4.4 set out the forecasts of capex on topsides equipment, which is predicted to total over 5.7 billion over the five years or 13% of the total capex. It is expected to peak at 1.4 billion in 2013 and then decline to 935 million in In contrast with the FPSO and platform structures, there is existing capability in Scotland for this category of work. Million FIGURE 4.5: EXPENDITURE ON TOPSIDES EQUIPMENT 1,200 1, TABLE 4.4: EXPENDITURE ON TOPSIDES EQUIPMENT MILLION Topsides equipment 1,265 1,405 1,085 1, ,740 Source: Mackay Consultants 18

19 Subsea production systems Most of the fields under development and fields under consideration, as listed in Tables 5.1 and 5.2, will be developed with subsea production systems tied back to existing infrastructure. Details are provided in the Appendices. Figure 4.6 and Table 4.5 set out the forecast capex on subsea systems, which is predicted to total 4.7 billion over the five years or 11% of the total capex. The time profile is similar with that for the development wells, with peak spending of 1.1 billion in 2013 and 2014, declining to 0.7 billion in Specific mention should be made of the Laggan and Tormore gas/condensate fields West of Shetland, being developed by Total and partners, at an estimated cost of 2.5 billion. These fields are being developed with subsea systems and two 140 kilometre (87 miles) pipelines to a new gas processing terminal at Sullom Voe in the Shetland Islands. Million FIGURE 4.6: EXPENDITURE ON SUBSEA SYSTEMS 1,200 1, TABLE 4.5: EXPENDITURE ON SUBSEA SYSTEMS MILLION Subsea systems 915 1,140 1, ,710 Source: Mackay Consultants 19

20 Pipelines Most of the new fields will use the existing oil and gas pipeline infrastructure on the UKCS. However, there will be some major new lines, notably for the Laggan and Tormore fields. 1,000 FIGURE 4.7 EXPENDITURE ON PIPELINES Figure 4.7 and Table 4.6 set out the forecasts of capex on pipelines, which is predicted to total just under 3 billion over the five years or 7% of the total capex. Million TABLE 4.6: EXPENDITURE ON PIPELINES MILLION Subsea systems ,975 Source: Mackay Consultants 20

21 Floating production systems There has been a notable trend in recent years away from fixed platforms to floating production systems, and nine of the fields listed in Table 5.1 will use the latter namely Alma, Athena, Cheviot, Galicia, Huntington, Loyal, Schiehallion, Stella and Western Isles. Figure 4.8 and Table 4.7 set out the forecast capex on floating production systems, which is predicted to total just under 2.6 billion over the five years or 6% of the total capex. It is difficult to forecast this category of spending because some FPSOs are leased rather than purchased. Fields for which new builds are required have been included in the capex forecasts. The leasing of existing FPSOs has been included in the opex forecasts, where appropriate. Specific mention can be made of the Quad 204 project, which involves the redevelopment of the existing Schiehallion and Loyal fields, in the West of Shetland area, by BP and partners, at an estimated cost of 3 billion. The work includes the replacement of the existing FPSO with a new one, currently under construction in South Korea. It should also be mentioned that all the recent FPSO orders have gone to overseas shipyards, in South Korea and elsewhere. There is no current capability in Scotland for this category of work. Million FIGURE 4.8: EXPENDITURE ON FLOATING PRODUCTION SYSTEMS TABLE 4.7: EXPENDITURE ON FLOATING PRODUCTION SYSTEMS MILLION Floating production systems ,575 Source: Mackay Consultants 21

22 Platform structures Most of the large fields listed in the tables will be developed with fixed platforms or floating production systems. Eight of the fields in Table 5.1 will use fixed steel platforms Bentley, Breagh, Clair Ridge, Ensign, Golden Eagle, Jasmine, Solan and York and there may be others for the probable developments. Details of the latter are provided in Appendix 2: Fields under consideration. Figure 4.9 and Table 4.8 set out the forecast capex on platform structures, which is predicted to total just under 2.9 billion over the five years, which would be just over 6% of the total capex. Million FIGURE 4.9: EXPENDITURE ON PLATFORM STRUCTURES The largest platforms will be for Clair Ridge in the West of Shetland area. The drilling and production jacket will have a total weight of about 22,300 tonnes and the production and utilities jacket about 9,000 tonnes. In contrast, some of the platforms will be for shallow water gas fields in the Southern North Sea (SNS) and be much smaller It should be mentioned, however, that most of the recent orders for platform structures have gone to overseas fabrication yards. There is now only a very small capability in Scotland to undertake this category of work following the closure of most of the fabrication yards. TABLE 4.8: EXPENDITURE ON PLATFORM STRUCTURES MILLION Platform structures ,845 Source: Mackay Consultants 22

23 5. FIELD DEVELOPMENTS In relation to capital expenditure, it is useful to distinguish between: new field developments incremental investments on existing fields New field developments can be grouped into three categories: fields currently under development probable developments possible developments 5.1 Fields under development Table 5.1 lists fields currently under development. An overview of each is provided in Appendix 1: Fields under development. Most of the fields listed are small subsea developments but they also include the 2.5 billion development of the Laggan and Tormore gas/condensate fields in the West of Shetland area, which are being developed with two 140 kilometre (87 mile) subsea flowlines in a very innovative development for the UKCS. The other fields are a mixture of platform and floating (FPSO) developments. Seven of the fields listed in the table will involve capex of over 1 billion each, namely: Clair Ridge 4.5 billion Quad 204 (Schiehallion/Loyal) 3 billion Laggan/Tormore 2.5 billion Bentley 2.25 billion Golden Eagle 2 billion Jasmine 2 billion Cheviot 1 billion TABLE 5.1: FIELDS CURRENTLY UNDER DEVELOPMENT Alma Arundel Bentley Breagh Causeway Cawdor Cheviot Clair Ridge Columbus Conwy Cygnus Devenick Fionn Flyndre Fram Galia Godwin Golden Eagle Harrier Huntington Jasmine Juliet Katy Kinnoull Laggan/Tormore Quad 204 Rhyl Rochelle East Rochelle West Seven Seas Solan Stella Western Isles York Source: Mackay Consultants 23

24 5.2 Fields under consideration Table 5.2 lists probable developments before They include fields for which development plans had been submitted to DECC at the time of writing but had not yet been approved. TABLE 5.2: FIELDS UNDER CONSIDERATION Acorn Agatha Alder Amanda Appleton Arran Auk South Banks Barnacle Beechnut Benbecula Blackhorse Bligh Bressay Burgman Catcher Cayley Christian Cladhan Crawford Corfe Culzean Edradour Enochdhu/Finlaggan Fiddich Freya Fulla Fyne Halley Jackdaw Kells Kepler Kew Kidd Kildare Kraken Mariner Monkwell Monterey Orca Orlando Ormonde Peik Perth Pilot Ptarmigan Rosebank/Lochnagar Shaw Sheryl Skipper Torridon West Wick Source: Mackay Consultants There is a long list of other possible developments but it is thought that only a few of those will be developed during the period to 2016, therefore these have not been included in this report. The forecasts, however also take into account possible new discoveries. 24

25 5.3 Incremental investments Incremental investments are developments within existing fields. Fields with substantial new capital expenditure are listed in Table 5.3. TABLE 5.3: EXISTING FIELD DEVELOPMENTS Andrew Arbroath Auk Clair Appleton Forties Gryphon Heather Lomond Beechnut Loyal Montrose Penguin Schiehallion Burgman Source: Mackay Consultants The largest projects of this type are the 4.5 billion development of Clair Ridge and the 3 billion redevelopment of Schiehallion and Loyal, also known as the Quad 204 project. 25

26 6. OPERATING EXPENDITURE FORECASTS 6.1 Historical operating expenditure Figure 6.1 and Table 6.1 show the estimated UKCS operating expenditure (opex) for the last five years It totalled just over 32 billion, with an annual average of just under 6.5 billion. Million FIGURE 6.1: OPERATIONAL EXPENDITURE ,000 6,800 6,600 6,400 6,200 6,000 5,800 5,600 5,400 5,200 5, Operating expenditure forecasts Figure 6.2 and Table 6.2 set out the forecasts of opex, which is predicted to increase slightly from 6.7 billion in 2011 to 7.4 billion in The opex unit costs are expected to continue to rise. The 2011 estimate is 39% of total expenditure and the 2016 forecast 46%. Million FIGURE 6.2: OPERATIONAL EXPENDITURE FORECASTS 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1, Operations Modifications Maintenance TABLE 6.1: OPERATIONAL EXPENDITURE MILLION Operating expenditure 5,829 6,857 6,375 6,500 6,700 32,261 TABLE 6.2: OPERATIONAL EXPENDITURE FORECASTS MILLION Maintenance 1,050 1,140 1,240 1,285 1,330 43,950 Modifications 3,040 3,050 3,135 3,080 3,100 36,050 Operations 2,810 2,910 2,925 2,985 2,970 6,800 TOTAL 6,900 7,100 7,300 7,350 7,400 36, Source: Mackay Consultants

27 Oil & Gas UK s 2012 Activity Survey shows how unit operating costs have risen substantially in recent years, as illustrated in Figure 6.3, from about 3 per barrel oil equivalent (boe) in 2001 to about 11 boe in According to the report there was a 25% rise in unit costs in 2011 because of the massive fall in production. However, the survey report also shows unit operating costs declining slightly in real terms after 2012 because of the current programme of large field investments. FIGURE 6.3: GROWTH IN UNIT OPERATING COSTS Unit operating costs /boe (2011 money) /04 02/03 06/07 05/06 04/05 07/08 Survey /09 09/10 10/ Source: Oil & Gas UK 27

28 7. EXPLORATION AND APPRAISAL ACTIVITY Exploration activity can be a key indicator of trends in the oil and gas industry. It normally increases in frontier areas and declines in mature areas. 7.1 Historical exploration and appraisal activity The number of exploration and appraisal (e+a) wells on the UKCS has fallen significantly in recent years, as shown in Table 7.1. However, exploration expenditure has actually increased because of much higher costs per well, particularly in the frontier areas such as West of Shetland. Nevertheless, it now accounts for only a small proportion of total UKCS expenditure, e.g. an estimated 8% in Table 7.1 shows that the number of e+a wells started in 2011 was 42, which was less than half the number in 2007 and Since then there has been a substantial fall in activity. TABLE 7.1: UKCS EXPLORATION AND APPRAISAL DRILLING WELLS Exploration Appraisal TOTAL Source: Department of Energy and Climate Change 28

29 Table 7.2 gives a geographical breakdown of the e+a activity. Over the last five years the Central North Sea has accounted for just over 50% of the total activity, the Northern North Sea 20%, Southern North Sea 16% and West of Shetland 13%. TABLE 7.2: GEOGRAPHICAL BREAKDOWN OF E+A ACTIVITY MILLION TOTALS Southern North Sea Central North Sea Northern North Sea West of Shetland West of England/ Wales TOTALS Source: Department of Energy and Climate Change Table 7.3 sets out the expenditure on exploration and appraisal activity for the five years The total was just over 6.5 billon, with an annual average of 1.3 billion. TABLE 7.3: EXPENDITURE ON EXPLORATION AND APPRAISAL ACTIVITY WELLS Exploration 1,090 1,274 1,200 1,550 1,400 6,541 Source: Department of Energy and Climate Change 29

30 7.2 Forecast exploration and appraisal activity Oil & Gas UK s 2012 Activity Survey shows an increase in the number of wells to about 60 in This is mainly due to the pressure to meet drill or drop licence commitments from the 25th and 26th Licensing Rounds. The survey shows that 12 wells delayed from 2011 have been put back to Table 7.4 forecasts the numbers of e+a wells to be drilled in each year to There is expected to be an increase to about 56 wells in 2012 followed by a steady decline to 28 in Figure 7.1 and Table 7.5 show the forecast expenditure on exploration and appraisal wells. The five year total is 6.8 billion, which is 7.5% of the overall total. Annual spending is predicted to decline from 1.7 billion in 2012 to 850 million in The latter would be just over 5% of the overall forecast. Million FIGURE 7.1: OFFSHORE EXPLORATION EXPENDITURE 2,000 1,800 1,600 1,400 1,200 1, TABLE 7.4: EXPLORATION AND APPRAISAL WELL FORECASTS WELLS Exploration Appraisal TOTAL TABLE 7.5: OFFSHORE EXPLORATION EXPENDITURE Source: Mackay Consultants MILLION Exploration 1,750 1,700 1,400 1, , Source: Mackay Consultants

31 8. DECOMMISSIONING 8.1 Overview The UKCS is now a very mature petroleum province. Output has been declining for many years and various fields have ceased production. However, the decommissioning market has been much smaller to date than generally predicted, including in previous Spends and Trends reports. There are two main reasons for that. Firstly, high oil prices (and to a lesser extent gas prices) have helped extend the life of many fields. Secondly, technological developments have had similar impacts. 8.2 Expenditure forecasts Figure 8.1 and Table 8.1 set out the forecasts of decommissioning expenditure in the period to The forecast total is 3.7 billion, rising from 490 million in 2012 to 1,050 million in It is expected to continue to increase after ,200 1,000 FIGURE 8.1: DECOMMISSIONING EXPENDITURE Nevertheless, there will undoubtedly be a significant increase in decommissioning spending during the period to In particular, Shell is now making detailed plans for the decommissioning of the Brent field, which is estimated to cost at least 4.5 billion. Brent began production in 1986 over 25 years ago. There have also been uncertainties about the taxation of decommissioning spending, which has delayed some projects. However, in July 2012 the HM Treasury published a consultation paper which proposes the creation of Decommissioning Tax Deeds, which would specify the levels of relief that companies would receive and provide a degree of certainty. Million TABLE 8.1: DECOMMISSIONING EXPENDITURE MILLION Decommissioning ,050 3,690 Source: Mackay Consultants 31

32 Oil & Gas UK published their 2011 Decommissioning Insight which gives longer term forecasts. The report states that decommissioning expenditure could total over 30 billion over the next years. Figure 8.2 is reproduced from the recent Oil & Gas UK Economic Activity report and provides a forecast breakdown of expenditure. Additional information is available from Decom North Sea, the industry s representative body Decommissioning projects The DECC Project Pathfinder website lists the projects in Table 8.2 and gives some information on their current status. The DECC website also states that the Department approved decommissioning programmes for the Fife, Flora, Fergus and Angus fields (operated by Hess) earlier in 2012 and for the Don field (BP) in However, as mentioned above, it is expected that the Brent field (Shell) will account for most of UKCS decommissioning expenditure over the next few years. FIGURE 8.2: SEGMENTATION OF DECOMMISSIONING MARKET BY ACTIVITY ( millions, 2011 money) Pipelines Decommissioning 2,124 Onshore Disposal 1,009 Survey & Monitoring 359 Project Management 3,590 Subsea Structural Removal 664 Decommissioning Programme 463 Jacket Removal 6,101 Operations 4,957 Topside Removal 6,359 Wells P&A 5,706 Pipelines Cleaning 916 Conductor Removal 1,615 Topsides Cleaning 1,926 Source: Oil & Gas UK 32

33 TABLE 8.2: DECOMMISSIONING PROJECTS FIELD NAME OPERATOR LOCATION FIELD TYPE FIRST PRODUCTION Big Dotty ENI Hewett 48/29 Gas 1995 Brae Area Marathon 16/07a Oil 1983 Brent Shell 211/29 Oil/gas 1976 Camelot Energy Resource Technology 53/1a Gas 1990 Dawn ENI Hewett 48/29 Gas 1995 Don BP 211/18 Oil 1989 Fife Area Hess 31/26 Oil 1995 Glamis Premier 16/21a Oil 1989 Goldeneye Shell 14/29a Condensate 2004 Hewett ENI Hewett 48/28, 48/29, 48/30 Gas 1969 Inde North Perenco 49/18 Gas/condensate 1990 Ivanhoe & Rob Roy Hess 15/21 Oil 1989 Leadon Maersk 9/14 Oil 2001 Leman Perenco 47/27c Gas/condensate 1969 Little Dotty ENI Hewett 48/30 Gas 1995 Miller BP 16/07 Oil/gas 1992 Murchison CNR 211/19a Oil 1980 Ninian CNR 3/3 and 3/8a Oil 1982 Welland Perenco 53/4a Gas/condensate

34 APPENDIX 1: FIELDS UNDER DEVELOPMENT RED No opportunities - all contracts awarded AMBER Opportunities available - some contracts still to be tendered GREEN All opportunities - no contracts yet awarded ALMA Blocks 30/24, 30/25b, 30/29b Discovered 1971 Development approval March 2012 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: EnQuest Oil: 2.8 million tonnes (low case), 4.4 mt (high case) 650 million (2011 values) (joint development with Galia field) Alma (which formerly produced as both Argyll and Ardmore) is in the Central North Sea, 192 miles south-east of Aberdeen. The field was first discovered in 1971 and as Argyll was the first oil field on the UKCS. EnQuest now aim to bring the field on stream for a third time. Because of the relatively short expected field life of 10 years, Alma is being developed through two drill centres tied back via new oil production and water injection flowlines to the EnQuest Producer (formerly Uisge Gorm) FPSO. Alma will be developed jointly with the Galia field. Produced crude will be collected by shuttle tanker once every two weeks. The majority of the produced gas will be used for power generation. All produced water will be re-injected. EnQuest received approval from DECC in March 2012 and anticipate bringing the field onstream in Q In May 2012, EnQuest agreed a deal with the Kuwait Foreign Petroleum Exploration Company for a 35% interest in the Alma and Galia fields for 300 million of development costs. June 2012: Technip awarded the contract for installation of flowlines, risers and installation of a 175 tonne manifold structure, plus associated trenching operations, tie-ins, testing and commissioning. March 2012: The Uisge Gorm FPSO is currently undergoing a refit at Blohm & Voss yard in Hamburg and will be renamed the EnQuest Producer. January 2012: EnQuest purchased the Uisge Gorm FPSO from Bluewater for 33 million. 34

35 ARUNDEL Blocks 16/22 Discovered 2001 Development approval September 2011 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: BP Gas condensate: 75 million (2011 values) The Arundel field is being developed as a subsea tieback to the Andrew platform. Arundel along with Kinnoull (see below) and Kidd will help prolong Andrew s productive life beyond Three wells will be drilled on Kinnoull, and one each on Arundel and Kidd. A pipeline will transport production from all three fields to Andrew. From Andrew, production will enter the existing Forties pipeline to Kinneil and the Central Area Transmission System (CATS) pipeline to Teesside. Engineering began at Subsea 7 offices in Aberdeen with the offshore work beginning in early Start-up is scheduled for The Andrew platform will be shut down for 18 months. June 2012: Dolphin Drilling awarded 243 million contract extension for the use of the Byford Dolphin semi-submersible drilling rig for new work on Arundel and Kinnoull. July 2010: Technip awarded contract for engineering, project management services and fabrication of umbilicals for the Andrew development. June 2010: Subsea 7 awarded 84 million contract for pipeline bundle. 35

36 BENTLEY Blocks 9/3b Discovered 1977 Development approval Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: February 2012 Phase 1A Xcite Energy Resources Oil: 116 million barrels 650 million (2011 values) (joint development with Galia field) The Bentley oil field is in the Northern North Sea, 138km east of the Shetland Islands. XER will develop the field in a phased manner, with the initial phase involving a two-stage approach. A multilateral well test producing to the Rowan Norway jack-up rig Phase 1A to be followed by the first of several intended permanent production phases Phase 1B, which will introduce a jacket alongside Rowan Norway to produce to a nearby tanker. The First Stage Production is currently planned to last around 3 to 4 years, after which the Rowan Norway will be replaced by a permanent fixed platform for the second and subsequent development stages. The overall field life is expected to be in the order of 20 years. Phase 1: 2.1km pipelines installed from the jack-up Rowan Norway to a shuttle tanker. First production of Phase 1 is expected in July Further phases of the development still require approval. In March 2012 Xcite Energy announced they had raised 31 million for the Bentley development. July 2012: Expro awarded 7.5 million equipment and services contract for a 90 day extended well test. Expro will provide heavy oil well testing and data management services through drilling and completions company ADTI on the Rowan Norway. May 2012: Teekay Navion Offshore Loading will supply the tanker Scott Spirit to store oil extracted from the appraisal well. March 2012: Stavanger-based Ocean Installer received a letter of intent for the installation of two oil export pipelines using a subcontracted vessel from Reef Subsea Power and Umbilical. 36

37 BREAGH Blocks 42/8, 9, 12, 13 Discovered 1997 Development approval July 2011 Phase 1 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: RWE Dea Gas: 28 million boe 600 million first phase (2011 values) The Breagh field is located in the Southern North Sea about 62 miles east of Teesside and is claimed to be one of the largest undeveloped natural gas discoveries on the UKCS. Breagh will be developed in two phases. Phase 1 comprises installation of the Breagh Alpha platform on the western side of the field from which 10 wells will be drilled. The platform was installed in October 2011 and will be leased to third parties. Phase 2 is currently being considered and a second platform could be installed on the eastern side of the field. The wells will connect to the Breagh Bravo platform and tied back to the Breagh Alpha platform. At the time of writing bidding for Phase 2 development was on hold. Sanction of Phase 2 has been moved to late Gas will be exported via 62 miles pipeline to Teeside gas processing plant. Modifications have been carried out to the gas processing plant. Development drilling started in May First gas from the Breagh field is scheduled for Q after delays and further cost overruns on the project. The field is expected to reach a peak annual rate of 160 MMcf/d in November 2010: Switzerland-based Allseas Construction Contractors awarded the engineering, installation and pre-commissioning work of the offshore pipeline and associated fibre optic cable. August 2010: Heerema Vlissingen B.V awarded construction of the jacket, topsides and piles, which were completed at their Vlissingen yard in the Netherlands. 37

38 CAUSEWAY Blocks 211/22a SE, 211/23d Discovered 2006 Development approval December 2011 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: Valiant Petroleum Oil: 15.6 million barrels 400 million Causeway is in the Northern North Sea, East of Shetland. Valiant Petroleum took over operatorship of Causeway from Antrim Energy in March Causeway is being developed via subsea wells tied back to the North Cormorant platform, nine miles away. Hydrocarbons will be processed on the Cormorant North platform operated by TAQA Bratani before being exported to the Sullom Voe terminal. It is planned that oil production from Fionn will be combined with Causeway s output to be transported to the Cormorant North platform. First production is expected in the second half of Average production in the first year is expected to be 8,400 barrels of oil per day. October 2011: Technip 20.6 million contract covering the engineering, procurement, installation and commissioning of rigid and flexible pipelines, subsea equipment and umbilicals. Technip s operating centre in Aberdeen is executing the contract which is scheduled to be completed in the second half of Rigid pipelines will be welded at the Technip spoolbase in Evanton. September 2011: GE Oil & Gas contract to provide subsea production equipment. 38

39 CAWDOR Blocks 30/13c, 30/14 Discovered 2007 Development approval Submitted July 2011 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: Maersk Oil UK Oil: 6.4 million tonnes of oil (jointly with Flyndre) Associated gas: 2.8 million Mm 3 (jointly with Flyndre) 115 million (2011 values) The Cawdor field is located approximately 180 miles southeast of Aberdeen. Cawdor will be developed jointly with the Flyndre field by drilling one well on Cawdor and utilising the existing Flyndre appraisal well. The wells will be tied back via a common production line to Talisman s Clyde platform located in block 30/17b. Based on production levels a further two wells may be drilled on Cawdor at a later date (Phase 2). Tieback via a new 12 pipeline to Talisman s Clyde platform. From the Clyde platform the oil and gas will be transported to the Teeside and St Fergus terminals respectively. Production from Flyndre is expected to begin in Q3 2013, with production from Cawdor field beginning in Q Production from both fields is expected to continue to the end of The drilling contract for the Cawdor wells has not yet been awarded, but it is expected the wells will be drilled and completed using the Noble Ton van Langveld rig. 39

40 CHEVIOT Blocks 2/10b, 2/15a, 3/1 Discovered 1978 Development approval Submitted July 2008 Recoverable reserves Estimated investment: Development: Transport: ATP Oil and Gas Oil: 58 million boe 1 billion (2011 values) The Cheviot field (formerly known as Emerald) is in the Northern North Sea. Development will be via 16 wells, 13 oil producers, two water injectors and one gas producer connecting to a new platform. The platform, Octabouy, a new design by Moss Maritime is a semi-submersible floating platform and will have its first use on the field. Octabuoy is designed to have a useful lifetime of 50 years. Peak production from Cheviot is expected to be 35,000 barrels of oil equivalent per day and 60 million cubic feet per day of gas. Fixed platform using Octabuoy semi-submersible floating platform. Status: Production from the development is expected in Contracts: April 2012: GE Oil & Gas 50 million contract to supply subsea production and other equipment. They will deliver wellheads, christmas trees and subsea control systems, as well as system engineering and design, procurement and on-site testing services. March 2012: Subsea million contract to fabricate and install associated subsea structures. Post installation they will carry out trenching of the subsea lines, tie-in of the lines to the Octabuoy and drilling centres, as well as carry out testing and pre-commissioning activities for the entire field facilities. March 2012: Technip s wholly-owned subsidiary Duco awarded contract to supply umbilicals. Four steel tube umbilicals will be manufactured at Duco s facility in Houston, while four thermoplastic umbilicals will be made at Duco s Newcastle facility in the UK. June 2011: Gulf Island Fabrication in Houma, Louisiana awarded the 6200 tonne process module fabrication. August 2008: The hull contract for Octabuoy awarded to Cosco Nantong Shipyard in China. 40

41 CLAIR RIDGE Blocks 206/7a, 206/9, 206/12, 206/13a Discovered 1977 Development approval October 2011 BP Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: 4.65 billion (2011 values) The Clair Ridge project is the second phase development of the Clair field, west of Shetland, targeting the northern area, and will extend the producing life of Clair to Clair Ridge will involve construction and installation of two new bridge-linked steel platforms, with drilling and production facilities on one platform and quarters and utilities on the other. Oil will be exported to the Sullom Voe terminal via a new pipeline tied into the existing Clair Phase One pipeline. Gas export will be via the Sullom Voe terminal via a new pipeline tied into the West of Shetland Pipeline System (WOSPS). The steel jackets should be ready for load-out mid-february 2013, and delivered March Production from the Clair Ridge complex is expected to range between 120,000 and 150,000 barrels per day, adding to the 60,000 bpd currently produced from Clair phase one through a single fixed platform. May 2012: US engineering Emerson 14 million contract to supply support control and safety systems. February 2012: Floatel International contract for accommodation and construction support vessel Floatel Victory for an initial period of one year beginning in June February 2012: Subsea 7 $100 million ( 62 million) contract for oil and gas export pipelines to connect between the existing Clair Phase 1 export systems and the two new bridge-linked platforms. Engineering and project management will take place in their Aberdeen office early in 2012 with offshore operations to start in October 2011: Amec $150 million ( 94 million) contract for engineering and project management services for the construction and installation of the two platforms. July 2010: Aker Solutions $267 million ( 167 million) contract for delivery of two steel jackets being fabricated at Verdal in Norway. 41

42 COLUMBUS Blocks 23/16f, 23/21 Discovered 2006 Development approval Submitted October 2008 Serica Energy Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: 150 million (2011 values) Columbus is being developed as a subsea tie back to the Lomond platform, via an 8 pipeline with a minimum facility platform which will be connected to Lomond by a short bridge. In 2010 Serica Energy signed a deal with BG International to jointly develop the field with BG set to carry out the front-end engineering and design work for the new Lomond BLP platform. The Columbus gas field is in water depth of 1,211 feet (369 metres). Gas is exported via the Etap gas pipeline to the CATS pipeline, which comes ashore at Teesside. Condensates from the project will be exported via the Etap oil pipeline, which ties into the Forties Pipeline System. In October 2011 BG froze tendering work on the 300 million Lomond extension. The engineering design of the subsea and production facilities has been completed. Development wells are due to be drilled in 2014 and subsea equipment installed that year. First production is due No significant contracts have been awarded. 42

43 CONWY Blocks 110/12 Discovered 2006 Development approval March 2012 Recoverable reserves Estimated investment: Development: Transport: EOG Resources Oil: 11 million barrels 240 million (2011 values) Conwy is in the East Irish Sea. It is being developed with five wells via a normally unmanned platform tied back to BHP Billiton s nearby Douglas complex. Tieback via a 12km, 8 production flowline to the Douglas complex. At Douglas, commingled fluids from Conwy and Corfe will be re-exported from Liverpool Bay to the existing offshore storage installation in block 110/8a. Associated gas will be commingled with gas from Douglas and used offshore for power generation or exported to the Point of Ayr terminal in north Wales. Status: Drilling of the development and water injection wells was expected to start Q Contracts: June 2011: Dutch contractor Seafox Contractors to deploy its accommodation and multi-support jack-up vessel for Conwy. March 2011: Technip 17 million contract for the welding and installation of pipeline umbilicals. Technip s operating centre in Aberdeen is executing the contract expected to be completed in 3Q

44 CYGNUS Blocks 44/11a, 44/12a Discovered 1988 Development approval March 2010 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: GDF Suez Gas: 1 trillion cubic feet 1.4 billion (2011 values) Cygnus is in the Southern North Sea. It is being developed by installing Cygnus Alpha (A), a permanently manned structure consisting of three bridge-linked platforms with a central production, processing and accommodation facility; and Cygnus Bravo (B), a normally unmanned satellite wellhead platform. Produced gas will be exported via a new pipeline to the Trent platform, where it will enter the ETS pipeline to the Bacton terminal. A final investment decision on the Cygnus project was expected in Q It is planned for construction to start in 2014 with first gas expected in September December 2011: GDF delayed a decision on the preferred bidders for fabrication contracts to mid October 2011: Amec awarded the FEED contract including an option to continue into the detailed design and procurement phase. 44

45 DEVENICK Blocks 9/29a, 9/24a and 9/24b Discovered 1983 Development approval September 2010 Recoverable reserves Estimated investment: Development: Transport: BP Gas: 430 billion cubic feet 550 million (2011 values) Devenick is a gas/condensate field 234km north-east of Aberdeen. The field will initially be developed with two producing wells tied to a four-slot subsea manifold, which will in turn be tied back via pipeline to the existing East Brae platform, located to the south of Devenick. The development requires modification of the East Brae platform to accommodate Devenick production. Condensate from the East Brae platform is exported via the Brae-Forties pipeline and Forties Pipeline System to the crude oil stabilization plant at Kinneil. Gas is exported via the ExxonMobil-operated Scottish Area Gas Evacuation (SAGE) system, and some gas is also re-injected into the East Brae reservoir to maximize liquid recovery. Status: With an estimated 20 year life span, first gas was planned to commence in Q The 600 tonne module, built by McNulty in South Shields, was successfully lifted onto the East Brae platform in October Modifications to the East Brae platform will continue until 2012 to coincide with first Devenick production. Contracts: July 2010: Technip subsea engineering and installation contract. Technip s operating centre in Aberdeen providing project management, engineering, fabrication, installation and commissioning of the pipelines, flowlines and umbilicals. June 2010: Isleburn contract for the fabrication of the manifold and subsea isolation valve. 45

46 FIONN Blocks 211/22a Discovered Development approval August 2012 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: Valiant Petroleum Oil: 6.3 million barrels 40 million (2011 values) Fionn is to be developed as a subsea tieback to the Causeway field using a previously drilled and suspended well. It is planned that oil production from Fionn will be combined with Causeway s output to be transported to the Cormorant North platform, operated by TAQA Bratani, before being exported to the Sullom Voe terminal. Gathering lines for Fionn were already installed at the same time as Causeway as a pre-investment by Causeway operator Antrim. First oil is expected in mid No significant contracts have been awarded. 46

47 FLYNDRE Blocks 30/13, 30/14 and Norwegian Block N1/5a Discovered 2003 Development approval Submitted July 2011 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: Maersk Oil UK Oil: 6.4 million tonnes (jointly with Cawdor) Associated gas: 2.8 million Mm3 (jointly with Cawdor) 75 million (2011 values) Flyndre is located approximately 180 miles southeast of Aberdeen. It is being jointly developed with the Cawdor field by drilling one well on Cawdor and utilising the existing Flyndre appraisal well. The wells will be tied back via a common production line to Talisman s Clyde platform located in block 30/17b. Tieback via a new 12 pipeline to Talisman s Clyde platform. From the Clyde platform the oil and gas will be transported to the Teesside and St Fergus terminals respectively. Production from Flyndre is expected to begin in Q3 2013, with production from Cawdor in Q Production from both fields is expected to continue to the end of No significant contracts have been awarded. 47

48 FRAM Blocks 29/3c, 29/8a Discovered 1969 Development approval Submitted March 2012 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: Shell Oil: 25 million boe Gas: 420 billion cubic feet 500 million (2011 values) Fram is in the Central North Sea approximately 220km south east of Aberdeen and approximately 50km west of the UK/Norway median line. Fram will be developed with up to eight production wells, one produced water reinjection well and subsea infrastructure tied back to a new FPSO facility. Treated oil will be stored in the vessel s tanks for export via shuttle tankers. Produced gas will be transported via a new 18km, 4 gas export pipeline tied-in to the existing Fulmar Gas Line to St Fergus. The final investment decision on Fram was expected in the second half of First oil is targeted for June 2012: SBM Offshore received a letter of intent to supply the FPSO. 48

49 GALIA Blocks 30/24b Discovered Development approval Submitted May 2012 EnQuest Recoverable reserves Estimated investment: Development: Transport: 550 million (2011 values) (joint development with Alma field) The Galia field (formerly Duncan) will be developed with a single production well tied-back via a new production flowline to the nearby Alma production field, which is in turn tied back to the EnQuest Producer (formerly Uisge Gorm) FPSO vessel. It will be developed jointly with the Alma field (see above). Galia and Alma produced liquids will be co-mingled at the Alma production manifold. Produced crude will be collected by shuttle tanker once every two weeks. Status: EnQuest sanctioned the development of the Alma/Galia fields in November Drilling of the Galia well is scheduled to start in September 2012 and will take three months. First oil is scheduled for October 2013 and field life is anticipated to be ten years. In May 2012 EnQuest agreed a deal with the Kuwait Foreign Petroleum Exploration Company for a 35% interest in the Alma and Galia fields for 300 million of development costs. Contracts: June 2012: Technip contract for installation of flowlines, risers and installation of a 175 tonne manifold structure, plus associated trenching operations, tie-ins, testing and commissioning. March 2012: The Uisge Gorm FPSO is currently undergoing a refit at Blohm & Voss yard in Hamburg and will be renamed the EnQuest Producer. January 2012: EnQuest purchase the Uisge Gorm FPSO from Bluewater for 33 million. 49

50 GODWIN Blocks 22/17S, 22/17N Discovered 2009 Development approval January 2012 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: Talisman Energy Oil: 6.1 million barrels 75 million (2011 values) Godwin is in the Central North Sea, 117 miles east of Peterhead. It will be developed with an extended reach well drilled from the Arbroath platform, 6km away. The well will be drilled through a spare well slot on the Arbroath platform by a cantilevered jack-up drilling unit over the Arbroath platform. Godwin fluids will undergo initial separation on the Arbroath platform. The products will be piped, along with those from the Arkwright and Brechin fields, to the Montrose platform. From Montrose, oil is exported to shore via the Forties pipeline system. Surplus gas would be exported via the CATS pipeline to a landfall at Teeside. Platform modifications have taken place from Q onwards. The jack-up rig is expected to be on site and commence well operations between Q2/Q3 of 2012, with first oil expected Q to Q No significant contracts have been awarded. 50

51 GOLDEN EAGLE Blocks 20/1, 20/1N, 14/26a Discovered 2007 Development approval October 2011 Recoverable reserves Estimated investment: Development: Transport: Nexen Petroleum UK Oil: 275 million barrels 2 billion (2011 values) The Golden Eagle field is in the Central North Sea, 110 kilometres north east of Aberdeen. The Golden Eagle Area comprises the Golden Eagle and Peregrine fields. Peregrine was previously known as Pink, while the Hobby discovery is now defined to be part of the Golden Eagle field. Development will be with up to 24 wells (7 subsea and 17 platform), two subsea drilling/production centres and a jack-up drilling rig over a wellhead platform that will be bridge-linked to a fixed production/utilities/quarters platform. Oil and gas will be processed at the platform complex with gas exported to the SAGE export line via the Ettrick pipeline end manifold. Oil will be exported either to the Forties pipeline system via a tie-in at the Buzzard field or to Flotta terminal via a tie-in at the Claymore field. Status: Pipeline and subsea infrastructure installation work is expected to start in early Platforms will be installed in Q2 of 2013 and Q3 of Drilling will begin in late 2013 and will continue over three years. First oil production is expected in Q4 2014, peaking at 70,000 barrels per day between 2016 and The field has an expected life span of 25 years. Contracts: February 2012: GE Oil and Gas awarded 106 million contract to supply the production subsea system. January 2012: Technip 111 million contract for manufacture, installation and commissioning of flowline and umbilicals. Technip s operating centre in Aberdeen will execute the project. December 2011: SLP Engineering contract for engineering, procurement and construction of the accommodation module. December 2011: Heerema contract to fabricate two 6000 tonne jackets. November 2011: United Arab Emirates firm Lamprell awarded 124 million plus contract to build the two platforms. The platforms will be built at Lamprell s Jebel Ali yard in the UAE. September 2011: Prosafe contract for a 240 day firm period using the Safe Caledonia for accommodation support. Onsite operations should begin between May and July

52 HARRIER Blocks 30/6a Discovered 2004 Development approval April 2012 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: Ithaca Energy Oil: 12 million barrels 350 million, including Stella Harrier is approximately 148 miles south east of Peterhead and 10km south of the Stella field. Ithaca will create a production hub (Greater Stella Area Hub) based on a floating production unit located over the Stella field. The Harrier field will be tied back to Stella where the hydrocarbons from both fields will be combined. Gas and oil exported via new pipelines connecting to the CATS and GAEL systems respectively. Development will be in two phases, commencing in Q on Stella and Q on Harrier. First production from the Stella field is expected Q First production from the Harrier field is estimated Q The nearby Hurricane and Helios discoveries are also possible tiebacks. July 2012: Technip awarded the subsea contract covering the Greater Stella area. October 2011: EPC contract to Penspen Group to conduct the Front-End Engineering Design (FEED). September 2011: GE Oil & Gas contract to provide subsea systems and services. 52

53 HUNTINGTON Blocks 22/14b Discovered 2007 Development approval November 2010 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: E.ON Ruhrgas Oil: 150 million boe 320 million (2011 values) The Huntington oil field is located 140 miles northeast of Aberdeen. Development will be via with three to four production wells and one to two water injectors tied back to the Sevan Voyageur FPSO. The facilities will have a production capacity of 30,000 barrels of oil per day. Oil will be stored onboard the FPSO and periodically exported to tankers. Produced gas will be used to generate power on the FPSO. Gas in excess of these requirements will be transported through a new 12km, 8 gas export pipeline to the CATS pipeline system. Originally scheduled to start production in Q this has been delayed because of financial problems at Sevan Marine who were contracted to supply the fields FPSO. Canadian Teekay have since acquired the Sevan Voyageur. Upgrades to the vessel are now being completed and first oil is anticipated from the field in October May 2011: AGR Drilling Services 2 million contract to supply its proprietary mud recovery technology (RMR) system to be deployed from the jack-up rig Ensco 100 to multiple wells. March 2011: Subsea 7 contract for installation of gas export pipeline, flowlines, umbilicals, associated risers and installation of subsea structures. Engineering work and installation work will be carried out by Subsea 7 s Aberdeen office. November 2010: Wood Group awarded a five year, 100 million operations and maintenance contract by Sevan Marine to provide operation management and offshore technical, logistical and supply chain support on the Sevan Voyageur. May 2010: Norway s Sevan Marine awarded a 334 million contract for charter of its Voyageur FPSO vessel for a fixed term of five years, with extension options. 53

54 JASMINE Blocks 30/6, 30/7a Discovered 2006 Development approval October 2010 (Phase 1) Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: ConocoPhillips Gas: 100 million boe 2 billion (phase 1) (2011 values) The Jasmine field, a high pressure, high temperature (HPHT) gas condensate field, is in a water depth of 266 feet (81 meters) in the Central North Sea. Jasmine is part of the J-Block first round licence awarded to ConocoPhillips in 1964 and is the fourth development there after Judy, Joanne and Jade. The field is planned to be developed in three phases. In the first phase, Jasmine will be developed with a three platform complex; a wellhead platform, an accommodation and utility platform and a five mile pipeline to a new riser platform connected to the Judy platform. Production from the wellhead platform will be exported via a multiphase pipeline and a new riser platform bridge-linked to the operator s Judy platform. Platforms are currently being fabricated. First production from Jasmine phase one is expected during December 2010: Halliburton awarded contract for drilling, logging-while-drilling and surface data logging. December 2010: Amec awarded engineering and procurement contract for the hook-up and commissioning covering the existing Judy platform. November 2010: WorleyParsons awarded contract for detailed engineering for the three platforms, interconnecting bridges, design and specification for the subsea pipeline, valves, cable and umbilicals. May 2010: Spain s Dragados Offshore awarded the contract for the wellhead deck and riser deck for Jasmine. Dragados Offshore subcontracted fabrication of a module to Rosetti Marino who are fabricating Jasmine s three jackets. Lamprell to build the accommodation quarters. March 2010: Saipem awarded the installation contract for the three platforms and related structures. 54

55 JULIET Blocks 47/14b Discovered 2006 Development approval June 2012 GDF Suez Energy UK Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: 115 million (2011 values) Juliet is located in the Southern North Sea, off the coast of Lincolnshire. The field will be developed by two horizontal subsea wells tied back via a 22km, 12 diameter export pipeline and control umbilical to the Pickerill A platform operated by Perenco. Gas will go to the Theddlethorpe terminal. Wells are expected to be spudded by Q with topsides and subsea construction taking place throughout The project is due online in Q with peak production forecast to be around 80 million cubic feet per day. The subsea contract will be awarded in summer 2012 and will comprise the installation of the control umbilical and export pipeline. The scope also includes the installation of a manifold, riser and J-tube on Pickerill A. 55

56 KATY Blocks 44/19b Discovered 2007 Development approval February 2012 ConocoPhillips Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: 175 million (2011 values) Katy (formerly Harrison) is in the Southern North Sea. Katy will be developed as a single production well via a new platform tied back to the Kelvin platform. The new platform is based on the SeaPony design. Minor modifications will be required on the Murdoch platform. The field has an anticipated life of 20 years. Gas will be exported via a new export line with an umbilical tied in to a subsea T-piece at the Kelvin field subsea manifold where Katy gas will be exported to the Murdoch platform complex. Offshore work was due to commence in May In June 2012 the Katy platform departed SLP s Lowestoft yard for installation off the coast of East Anglia where it will be tied into the Murdoch complex via the Kelvin platform. First gas is expected December September 2011: The Katy platform was fabricated by SLP Engineering in Lowestoft. 56

57 KINNOULL Blocks 16/23, 16/22 Discovered 2008 Development approval September 2011 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: BP Oil: 45 million boe 700 million (2011 values) The Kinnoull oil field is in the Central North Sea, 180km east of the northeast coast of Scotland and approximately 4.6km west of the UK/Norway boundary line. The Kinnoull field development will consist of three producing wells tied back to a subsea manifold which in turn will be tied back to the Andrew platform. The Andrew platform will undergo major modifications including the addition of a 750 tonne process module. From Andrew, production will enter the existing Forties pipeline to Kinneil and the CATS pipeline to Teesside. Start-up is scheduled for Construction will be completed over two years, with the Andrew platform expected to shut down for 18 months. June 2012: Dolphin Drilling 243 million contract extension for the use of Byford Dolphin semi-submersible drilling rig for new construction on Arundel and Kinnoull. August 2010: Wood Group 75 million two-year topside engineering and project management contract on the Andrew platform including the installation of a new module and supporting the development of the Kinnoull subsea tieback to Andrew. June 2010: Isleburn fabrication contract for a 120 metre long caisson and subsea structures. June 2010: Subsea 7 contract for the pipeline bundle system for Arundel and Kinnoull. Heerema Hartlepool contract for the construction and commissioning of the 750 tonne process module. 57

58 LAGGAN/ TORMORE Blocks 206/1, 205/5a, 2054b Discovered 1986 Development approval March 2010 Total E&P Recoverable reserves Estimated investment: 2.5 billion (2011 values) Development: The Laggan and Tormore gas condensate fields are located about 87 miles (140 kilometres) northwest of the Shetland Islands. Development will consist of a long distance tieback of subsea wells connected to a new 60 million gas processing terminal at Sullom Voe on Shetland. The subsea development system will consist of two six-slot template-manifolds with production from up to eight development wells. Laggan-Tormore will be implemented in several phases with the first phase focusing on drilling four wells on Laggan and two wells on Tormore. Phase 2 of the drilling campaign will include an additional well to be drilled on each field. Glenlivet, Tornado and Edradour discoveries are all within tieback distance of the Laggan infrastructure. Transport: Status: Contracts: Production will be sent to the Shetland Islands via two 87-mile rigid steel flowlines. The 60 million Laggan-Tormore gas production plant will then export to the UK Frigg pipeline system and onwards to the St Fergus gas terminal. Drilling of the offshore wells was expected to commence in Q and continue through to the middle of The project is on target for first gas in mid December 2010: Allseas pipeline installation contract for two gas and condensate pipelines running from the field to the new processing facility on the Shetland Islands and pipeline to take output form the Shetlands to the St Fergus terminal. October 2010: Subsea million pipeline bundle system contract for engineering, fabrication and installation of pipelines, umbilicals and associated subsea structures and tie-ins. April 2010: FMC Technologies 131 million contract to manufacture and supply subsea production equipment. Includes the manufacture of nine subsea trees, eight wellheads and two six-slot manifolds, and providing 12 multiphase meters, 10 subsea control modules and associated control systems. March 2010: Corus pipeline contract for more than 165,347 tonnes (150,000 tonnes) of pipeline, around 311 miles (500 kilometres) in length and diameter at their Hartlepool plant. 58

59 QUAD 204 Blocks 204/20 Discovered 1993/1994 Development approval June 2011 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: BP Oil: 450 million boe 3 billion (2011 values) The Quad 204 project is located approximately 130km west of Shetland. It involves the redevelopment of the existing Schiehallion and Loyal fields. The project, named after where the two fields are located, includes replacement of the existing Schiehallion Floating Production Storage and Floating and Offloading (FPSO) vessel with a new FPSO, new production and water injection wells, and additional subsea infrastructure. The redevelopment will allow the fields to continue to produce until at least Subsea tieback to a new FPSO. In March 2012 BP and partners announced the existing FPSO will cease operations and be removed during The existing FPSO will be replaced with a new vessel scheduled to begin operations in late 2015/early Production is scheduled for June 2012: Singapore s Dyna-Mac Holdings contract from SBM Offshore to fabricate and assemble electrical and instrumentation facilities for the turret equipment room. March 2012: Technip 500 million contract for the removal of the existing FPSO and mooring system, as well as the recovery of all existing flexible risers and umbilical systems. January 2012: Odfjell Drilling 775 million seven year contract with an extension for the provision of a new build, semi-submersible drilling unit. September 2011: Wood Group Kenny contract to provide engineering, design and project management services for the subsea, umbilical, riser and flowline (SURF) infrastructures. March 2011: South Korea s Hyundai Heavy Industries 625 million contract to build the new FPSO. 59

60 RHYL Blocks 113/27b Discovered 2009 Development approval Submitted August 2011 Recoverable reserves Estimated investment: Development: Transport: Hydrocarbon Resources Limited Gas: billion cubic feet 85 million (2011 values) Rhyl is in the East Irish Sea, 24 kilometres off Barrow near the Morecambe fields. The Rhyl development will consist of a single production subsea well connecting to a manifold. The manifold will be tied back to North Morecambe platform via a 12.7km, 12 flexible export flowline and control umbilical. From the North Morecambe platform gas from Rhyl will be exported onshore to the North Morecambe gas terminal in Barrow-in-Furness via an existing North Morecambe pipeline. Status: Production is expected late Contracts: No significant contracts have been awarded. 60

61 ROCHELLE EAST Blocks 15/27 Discovered 2000 Development approval February 2011 Recoverable reserves Estimated investment: Development: Transport: Endeavour Oil: 30 million barrels 600 million (2011 values) The East Rochelle field is located in the Central North Sea, 115 miles northeast of Aberdeen. Rochelle is being developed as a subsea tieback to the nearby existing Scott platform. East Rochelle is being treated as Phase One of the development of the Greater Rochelle area, with West Rochelle, discovered in 2010, forming Phase Two. Subsea development to be linked by a 30km pipeline to production facilities on the nearby Scott platform. Status: Initial Rochelle modifications were made to the Scott topside facility during First production from East Rochelle is expected in November Contracts: July 2011: Aker Solutions 9 million contract to provide subsea umbilicals and associated equipment. June 2011: Technip 62 million EPCI contract covering full project management and design, fabrication, installation and pre-commissioning of 30km of pipe-in-pipe, flexible riser, free-issue umbilical, subsea isolation valves and manifolds. 61

62 ROCHELLE WEST Blocks 15/26b, 15/27 Discovered 2000 Development approval Submitted August 2011 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: Endeavour Energy Gas condensate 600 million (2011 values) West Rochelle is in the Central North Sea approximately 8km west of the East Rochelle field and 30km south of the Nexen operated Scott platform. West Rochelle will be developed via pipeline tied back to the East Rochelle development. The West Rochelle development has a potential field life of eight or more years, depending upon reservoir performance with facilities designed for 15 years. Gas produced from the field will be sent to Nexen s Scott platform for processing and will be exported via the SAGE system to St Fergus. Phase One development of the East Rochelle field is on schedule to begin production in November West Rochelle will be developed as Phase Two. As above. 62

63 SEVEN SEAS Blocks 48/7c Discovered 2007 Development approval March 2009 Centrica Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: 40 million (2011 values) Seven Seas is a small gas field in the Southern North Sea. It will be tied back subsea to the existing West Sole Alpha platform about 60km off Easington on the east coast of England. The project will try to use, as far as practicable, the existing subsea infrastructure and topside facilities at West Sole Alpha. The topside process facility will be upgraded where possible to accommodate and will enable future development of other prospects. Hydrocarbons will be processed at West Sole Alpha and exported to the Dimlington terminal via the existing 16 West Sole Alpha export line. In August 2011 Centrica announced that development work at the Seven Seas gas project was continuing as planned, with first gas expected in Q although startup had yet to commence at the time of writing. June 2008: Subsea 7 43 million engineering, procurement, installation and commissioning contract. The EPIC contract was for a production well tieback to the West Sole Alpha platform via 6 carbon steel production pipeline and integrated service and control umbilicals. 63

64 SOLAN Blocks 205/26a Discovered 1991 Development approval April 2012 Recoverable reserves Estimated investment: Development: Transport: Chrysaor Oil: 40 million barrels 540 million (2011 values) The Solan field is in the West of Shetland area approximately 135km to the west south west of the Shetland mainland. Solan will initially be developed by the drilling of four subsea wells, two of which will be producers and the other two for water injection which will be tied back to a normally unmanned platform with a subsea storage tank. Future development drilling will include a further two or three wells depending on reservoir performance. Oil will be stored in a subsea tank prior to being offloaded to shuttle tanker every few weeks. Status: First oil is expected in Q with an estimated initial production rate of 24,000 barrels of oil per day. Contracts: July 2012: Burntisland Fabrications (BiFab) in Fife 140 million contract for the design, procurement and fabrication of the topsides and jacket. An agreement has been entered into with Awilco Drilling for the provision of the WilPhoenix for Solan drilling, commencing in Q2 of

65 STELLA Blocks 30/6a Discovered 1979 Development approval April 2012 Ithaca Energy Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: 350 million including Harrier Acquired by Ithaca Energy in August 2008, the Stella gas field is 148 miles south east of Peterhead. The Greater Stella Area includes the Stella field and two satellite discoveries, Harrier and Hurricane. Ithaca will create a production hub based on a floating production unit located over the Stella field for production from Stella, followed by Harrier and other possible tiebacks of nearby Hurricane and Helios discoveries. The Stella/Harrier development will consist of five subsea wells on Stella and two subsea wells on Harrier, tied back via infield flowlines to the floating production facility FPF1. Gas and oil exported via new pipelines connecting to the CATS and GAEL systems respectively. The activities will be undertaken in two phases, commencing in Q on Stella and Q on Harrier. First production from the Stella field in expected Q First production from the Harrier field in Q Contracts for the procurement and installation of the field s production unit will be awarded shortly, while the yard conversion work on the FPF1 will also be announced. July 2012: Technip subsea contract covering the Greater Stella area. October 2011: EPC Offshore contract to Penspen Group to conduct the Front-End Engineering Design (FEED) for the Greater Stella area development. September 2011: GE Oil & Gas contract to provide subsea systems and services. May 2011: EPC Offshore 1 million to develop the concept selection process across the Greater Stella Area. 65

66 WESTERN ISLES Blocks 210/24a Discovered 2008 Development approval Submitted January 2011 Recoverable reserves Estimated investment: Development: Transport: Status: Contracts: KNOC Oil: 45 million barrels 1 billion (2011 values) The Western Isles fields are located in the Northern North Sea, 100 miles east of Shetland. The project comprises four oil accumulations - Lewis, Harris (formerly Rinnes), Uist and Barra (formerly Melville). A FPSO has been chosen to develop the fields. A total of 12 wells (six oil producers and six water injectors) are envisaged in the initial phase of the development tied back to the FPSO. Output is expected to be 40,000 to 50,000 barrels per day of mainly oil, with some gas that will be used partly to power the FPSO and partly for export. A gas export/import line will be connected subsea to the Tern and North Cormorant gas pipeline system. First oil is anticipated late Approval for the field development plan is expected by the end of Development drilling is to start in early Subsea installation is due summer 2014 with the vessel installed in The final investment decision is expected in Q2 or Q July 2012: Singapore-based Cosco Shipyard Group to build a Sevan Marine-designed cylindrical floating production, storage and offloading vessel. November 2011: Aker 7.8 million contract for the project management, engineering, procurement and construction and installation of several subsea systems. 66

67 YORK Blocks 47/3a Discovered 1991 Development approval February 2011 Centrica Recoverable reserves Estimated investment: Development: 350 million (2011 values) The York field is located in the Southern North Sea approximately 35km northeast of Easington. York will be developed via an unmanned platform tied back to Centrica s Easington gas terminal. Transport: Unmanned platform tied back to Centrica s Easington gas terminal via a 34km, 16 pipeline. Status: Contracts: The fabrication of the deck and supporting steel jacket has been completed and loadout was undertaken in May Hook-up and commissioning is scheduled for August, with first gas expected in early in York s field life is eight years but the platform is built for a 25 year lifespan. February 2011: Heerema Fabrication Group contract for construction and installation of the 1300-tonne topsides and 1450-tonne jacket. The work was undertaken at Heerema s Hartlepool yard. Saipem s Castoro Sei will install the export line from the York platform to the Easington terminal. 67

68 APPENDIX 2: FIELDS UNDER CONSIDERATION RED No opportunities - all contracts awarded AMBER Opportunities available - some contracts still to be tendered GREEN All opportunities - no contracts yet awarded ACORN Blocks 29/8a, 29/9a Discovered 1984 Centrica Oil Development options for Acorn are a subsea tieback to Shell s Curlew production, storage and offloading vessel or a redeployment of the Sevan Hummingbird floating production, storage and offloading unit. Development costs are estimated in the range million. AGATHA Blocks 49/11a Centrica Gas Agatha is in the Southern North Sea. The plans of previous owners Venture were a joint development of the Agatha and Amanda gas discoveries, which would be subsea satellites to the company s nearby Alison subsea facilities. 68

69 ALDER Blocks 15/29a Discovered Submitted March 2012 Chevron North Sea Oil/Gas About 17 miles (27km) to the west of Britannia field, the Alder high temperature, high pressure oil and gas discovery is being evaluated as a potential subsea development. In 2012 the project began FEED. A final investment decision is expected in 2012 with first production projected for Production is estimated at peaking at 9,000 barrels per day of oil and 80 million cubic feet per day of gas. AMANDA Blocks 49/11a Discovered 2007 Centrica Gas An appraisal well of Amanda in 2007 tested at rates of about 2 million cubic feet per day, which was below expectations and apparently not economic on a standalone basis. The plans of previous owners Venture was a joint development of Agatha and Amanda gas discoveries, as subsea satellites to the company s nearby Alison field. APPLETON Blocks 30/11b Discovered 1993 Talisman Energy Gas Appleton includes the Appleton Alpha and Appleton NW discoveries. It is expected to be jointly developed along with Halley as tiebacks to the Fulmar field. Appleton and Halley have up to 37 million barrels of oil equivalent and could come onstream in

70 ARRAN Blocks 23/11a, 23/16b, 23/16c Discovered 2002 Dana Petroleum Gas Condensate Arran, a gas condensate project (formerly known as Barbara-Phyllis), is 222 km east of Aberdeen and may be developed with three wells tied back to a new riser platform, Lomond BLP and BG Group s existing Lomond production platform. The contract for Lomond BLP, a tonne jacket and a 3500 tonne deck has yet to be awarded. Four companies have tendered: UK joint venture Bifab and ODE, Dragados in Spain, Netherlands-based Heerema and Italy s Saipem. The new platform will handle production from two gas condensate discoveries - Arran as well as Serica Energy s Columbus find. Produced fluids will undergo primary processing on the Lomond BLP before being transported to the Lomond platform for secondary processing. Gas will then be exported to the CATS onshore terminal; while condensate will be exported to Kinneil through the Everest Liquids System and Forties pipeline system. Peak gas production rates at Arran are expected to be about 2.5 million cubic metres per day, falling to 330,000 by the end of the field s life in In October 2011 BG Group put their 300 million Lomond expansion project to build the bridge-linked platform on hold. AUK SOUTH Talisman Energy Gas Auk South involves installing new accommodation and drilling modules on the Auk A platform and drilling up to nine development wells. First production from the Auk South redevelopment would be in 2015 or In June 2010 Talisman Energy awarded procurement and fabrication of an integrated drilling deck to Rosetti Marino. Consafe are fabricating an accommodation module. 70

71 BANKS Blocks 22/15 Discovered 2006 BG Group Oil/Gas Banks is a small oil and gas find with about 8 million barrels of oil equivalent, although the operator believes that the Banks Deep prospect could hold a further 27 million barrels. Further exploration work is required. The finds could be exploited via subsea wells with production piped 16km to BP s South Everest platform. BARNACLE Blocks 211/29a and 211/30a Development approval February 2007 Energy Development Partners (EDP) Gas The Barnacle field is 110 miles from the Shetland Islands in the Northern North Sea. Development of Barnacle is planned via an extended reach well drilled from Shell s Brent Delta platform. The well is to be drilled as a sidetrack of Brent s existing BD-46 well, extending the life of the Brent Delta platform by at least two years. Development costs are expected to be about 20 million. The stranded gas find received government approval in February 2007 but there appears to have been little progress since then. 71

72 BEECHNUT Blocks 211/29a-S and 211/30a Discovered 1985 Centrica Gas Development possibilities are either a tieback to a FPSO or some form of joint development with the nearby Acorn field. BENBECULA Blocks 154/01 Discovered 2006 Apache Gas Benbecula is a small gas find West of Shetland. In September 2011 Apache announced they had acquired the Benbecula exploration acreage. BLACKHORSE Blocks 15/22 Discovered 2005 Nexen Petroleum Oil Nexen operate the Blackhorse block with a 50% interest; Premier Oil holds the remaining interest. In November 2008 a well encountered tested oil at a maximum rate of 5,248 barrels of oil per day. The operator is currently evaluating development alternatives. 72

73 BLIGH Blocks 21/20a Venture Gas/condensate Bligh is a high-pressure, high-temperature find with up to 30 million barrels of oil equivalent. The field is expected to be tied back to Venture s nearby Kittiwake platform, targeting first oil in BRESSAY Blocks 3/28a Discovered 1976 Statoil Oil Bressay is to the north-east of the Mariner field. There are two alternative development concepts one using a floater and wellhead platform or a replica of the Mariner field using an integrated platform with living quarters and processing facilities. The final investment decision is expected to be taken in late The company expect total investment of 6 billion. Bressay is estimated to have about 700 million barrels of oil equivalent in place. BURGMAN Blocks 28/9 Discovered 2011 Premier Oil Oil Burgman adds further impetus to an already commercially viable development at the nearby Catcher, Catcher North and Varadero discoveries. Initial estimates suggest a likely oil-in-place resource of million barrels. Development screening work is underway with FEED expected to begin soon. Approval for a development plan could follow by the end of 2012, with delivery of a fixed or floating structure earmarked for late 2014, targeting first oil by the end of that year. 73

74 CATCHER Blocks 28/9c Discovered 2010 Premier Oil Oil The Catcher prospect is in the Central North Sea and combines the Catcher, Catcher East, Catcher South West and Catcher North discoveries. The first drilling programme commenced in June 2010 with a significant light oil discovery announced at Catcher, along with Catcher East. In July 2010 the Catcher South West appraisal well was drilled and preparation for a second drilling campaign to include the wider Greater Catcher area began. In February 2011 oil and gas was discovered at Catcher North. Initial analysis indicated there could be as many as 300 million barrels recoverable reserves but after a disappointing appraisal on Catcher North it was revised to a combined discovery of between 40 and 80 million barrels. Development could be via a FPSO or a fixed platform allied to a FPSO. Further discoveries of the Varadero and Burgman fields were made in the Greater Catcher area in January and March The Carnaby prospect was also discovered in June In January 2012 Premier Oil completed a million takeover of EnCore Oil which doubled its stake to 30% and became the operator of the Catcher field. Premier is understood to be eager to fast-track production from the complex. CAYLEY Blocks 22/17 Discovered 2007 Talisman Gas condensate The Cayley discovery is about 200km west of Aberdeen in the Montrose-Arbroath (MonArb) complex. Development would be a subsea tieback to the company s Montrose platform. Cayley is estimated to have gross resources of 40 million barrels of oil equivalent. Talisman is considering the re-development of the MonArb field by installing a new bridge-linked platform to handle production from satellite fields, namely Cayley, Godwin and Shaw, to extend the life of Montrose. Fiddich and Seagull finds which lie farther afield could also be included. Start-up dates are estimated between 2014 and

75 CHRISTIAN Blocks 3/28a Discovered 1976 Centrica Gas condensate The Christian discovery is a high-pressure, high-temperature gas condensate field similar to the nearby Mallard field. Two potential development options exist either a subsea tieback to the Kittiwake platform via Mallard or a subsea tieback to a FPSO. CLADHAN Blocks 210/29a, 210/30a Discovered 2008 Sterling Resources Oil The Cladhan field is north east of Shetland. Indications are that development would be primarily focused on a subsea tieback to nearby third party facilities. Infrastructure in the area includes the Tern, Heather and Cormorant platforms. Environmental survey work to appraise Cladhan has begun with first oil targeted for Through this northern hub, other areas could be developed such as the South Cladhan (210/29c) and prospective areas to the east (210/30b). Appraisal drilling on Cladhan South will be undertaken in Cladhan is estimated to have in excess of 250 million barrels of oil in place. In April 2012 TAQA increased its interest in the Cladhan prospect and will assume ship on or shortly after approval of a final field development plan to be submitted by the end of Q

76 CRAWFORD Blocks 9/28a Discovered 2007 Fairfield Energy Oil Crawford was Discovered by Hamilton Brothers in the mid-1970s and was developed with five wells, with production commencing in In late 1990 Crawford was abandoned and all facilities were removed. Fairfield acquired the licence in Crawford is currently estimated to have more than 200 million barrels of oil in place in two reservoirs. In July 2011 EnQuest increased its stake in the Crawford prospect and in exchange will carry Fairfield for certain development costs up to 35 million. Crawford will be developed as a subsea tieback to Marathon Oil s East Brae complex. CORFE Blocks 29/3b EOG Resources Gas condensate Corfe is a high-pressure, high-temperature field potentially holding about 660 bcf in-place gas. The prospect lies about 20km west of Total s Elgin/Franklin HPHT complex, which would provide an obvious transport route. Further appraisal is required. CULZEAN Blocks 22/25a Discovered 2008 Maersk Oil and Gas Gas/condensate Culzean is a high-pressure, high-temperature field located in the Central North Sea approximately 145km east of Aberdeen. Appraisal is ongoing. 76

77 EDRADOUR Blocks 206/4 Discovered 2010 Total Gas condensate Edradour is 75km north west of Shetland. Edradour will be developed as a subsea satellite to the nearby Laggan and Tormore infrastructure currently under development. Further appraisal wells are expected to be drilled in The final investment decision is expected in Q Edradour could come onstream in ENOCHDHU/FINLAGGAN Blocks 21/05a Discovered 2010 ConocoPhillips UK Oil/Gas A consent application to install a subsea manifold and an 8km connecting pipeline to a tie-in skid in relation to the Enochdhu development 167km north east of Peterhead was submitted in July FIDDICH Blocks 22/18 Discovered 2010 Talisman Oil Fiddich is 20km to the south-west of the Montrose-Arbroath (MonArb) fields. There are a number of development options including subsea tieback to either Montrose or other infrastructure hubs. Fiddich is estimated to have 20 million barrels of oil equivalent. Talisman is considering the redevelopment of the MonArb field by installing a new bridge-linked platform to handle production from nearby satellite fields, namely, Cayley, Godwin and Shaw, to extend the life on Montrose, although Fiddich lies farther afield. Start-up dates for redevelopment are estimated between 2014 and

78 FREYA Blocks 206/10a Discovered 1980 Faroe Petroleum Oil Freya is likely to be developed alongside nearby Fulla via FPSO or as a subsea tieback to the Clair complex, to the south west. Further appraisal is required for both Freya and Fulla. In August 2011 an exploration well was completed on Fulla which proved positive. Freya is estimated to have 60 million barrels of probable oil. FULLA Blocks 206/5a Discovered 2011 Faroe Petroleum Oil Fulla is likely to be developed alongside nearby Freya via FPSO or as a subsea tieback to the Clair complex, to the south west. Further appraisal on the find is required. Fulla is estimated to have 35 million barrels of probable oil. FYNE Blocks 21/28a Discovered 1998 Premier Oil Fyne is west-south-west of the Guillemot group of oilfields and 35km from the Catcher and Burgman fields in Block 21/9. Fyne is estimated to have probable of 27 million barrels of oil. Premier took over as of Fyne in April 2011 from Antrim Energy, and is considering a FPSO development or an unmanned installation or a subsea tieback to close-by infrastructure. A decision on whether a commercial development is viable was expected to be taken by the end of the Q In June 2012 Antrim secured an extension for the submission of the field development plan until January

79 HALLEY (ALPHA AND GAMMA) Blocks 30/11b, 30/12b Discovered 2000 Talisman Oil The Halley area comprises the Halley Beta, Halley Gamma and Halley Alpha discoveries. The Halley Beta discovery was developed by Talisman in August 2002 via an extended reach well drilled from the Shelloperated Fulmar platform 5km to the southwest of the field but ceased production in The Fulmar platform is also expected to host production in the coming decade from a tentative joint development of the s Halley and Appleton discoveries. These two fields could have up to 37 million barrels of oil equivalent and could come onstream in JACKDAW Blocks 30/02a, 30/02c Discovered 2006 BG Group Gas/condensate Jackdaw is a high-pressure, high-temperature discovery. Drilling and appraisal of the field is ongoing. Jackdaw is estimated to have of million barrels of oil equivalent. Development options have to date focused on a wellhead platform tied back to nearby infrastructure. The development concept could be finalised late 2012 or in early 2013, with a project sanction decision around First production is scheduled for the period. 79

80 KELLS Blocks 3/8d Discovered 1985 Development Approval Submitted February 2012 Iona Energy Oil/associated gas The Kells field (formerly named Staffa) is located approximately 75 miles east of the Shetland Islands. The field previously produced in the early 1990s as a two well tieback to the Ninian Southern production platform. In October 2011 Iona Energy acquired the full rights from Fairfield Energy to an advanced development plan for Staffa. The development consent application for the Kells field is for a subsea tieback to the Ninian Central Platform approximately 13km to the north/northwest. Separated oil will be exported via an existing pipeline to Sullom Voe and associated gas will be used for power generation on the Ninian Central platform. A semi-submersible will be used to drill and complete a new production well on Kells in late A second production well will be drilled months later. First oil is expected in the last quarter of 2012, with the second well producing from the last quarter of Investment is estimated at 150 million. KEPLER Blocks 44/16c Discovered 1991 Centrica Gas/condensate Kepler is expected to be developed as a tieback to the Cavendish field. 80

81 KEW Blocks 49/4a, 49/4c, 49/5a, 49/5b Discovered 1988 Development Approval Submitted January 2012 Centrica Gas and associated condensate The Kew field is in the Southern North Sea. Centrica proposes to develop the Kew field as a subsea tieback to the Chiswick NUI (Normally Unmanned Installation) via a new pipeline. Produced fluids will be co-mingled with the Chiswick field fluids and then exported via the Markham Compression Tower to the Markham J6A platform in the Dutch sector of the North Sea for further processing. Production from the Kew field is scheduled to commence in Q1 2013, peaking during years 2013 and End of field life is predicted in KIDD Blocks 16/23 BP Oil The Kidd field will be developed as a subsea tieback to the Andrew platform. Kidd along with Kinnoull and Arundel will help prolong Andrew s productive life beyond KILDARE Blocks 15/26b Nexen Oil Kildare is a discovery near the Scott field. Nexen is continuing to evaluate development alternatives. 81

82 KRAKEN Blocks 9/1a, 9/2b Discovered 1985 EnQuest Oil The Kraken heavy oil field is located south east of Shetland. The project will be based around a floating production, storage and offloading vessel with both newbuild and converted vessels being evaluated. A field development plan is expected to be submitted in late 2012 or early Kraken has an estimated 160 million barrels of likely. In January 2012 EnQuest agreed a deal with Nautical to take over control of Kraken after agreeing to up its stake to 45%. The deal will see EnQuest buy 25% in return for carrying 150 million of Nautical s development costs. In April 2012 EnQuest acquired a further 15% from First Oil, giving it a 60% share. MARINER Blocks 9/11a Discovered 1997 Development Approval Submitted July 2012 Statoil Oil Mariner is a heavy oil field south-east of Shetland, together with the smaller nearby Mariner East (Block 9/11b). Statoil s development proposal for Mariner includes 50 wells and 92 sidetracks, comprising 76 production wells, 64 produced re-injectors, a make-up water well and a waste disposal well. A further four wells will be drilled separately to develop the nearby Mariner East field. All will be tied to the Production, Drilling and Quarters (PDQ) platform linked to a Floating Storage Unit (FSU). Front-end engineering and design has been completed and an Environmental Impact Assessment was submitted to the authorities in July Mariner is estimated to have 430 million barrels in place with proven and probable of 82 million barrels. First oil is anticipated at the end of Mariner East will begin producing when Mariner production comes off plateau, expected in

83 MONKWELL Blocks 42/29a Discovered 1989 Dana Petroleum Gas Monkwell is located in the Southern North Sea and consists of two separate gas accumulations. The initial development is expected to consist of a single production well on Monkwell Central, with the potential for a future well for Monkwell South West. MONTERAY Blocks 49/8c Discovered 1989 Wintershall Gas Monterey is 15km west of the Windermere gas platform and south of Schooner and Ketch gas fields. Monterey is estimated to have 165 billion cubic feet of. Pre-development studies still require to be carried out. ORCA Blocks 44/24, 44/29 and 44/30, Dutch D18a, D15b Discovered 1989 GdF Suez Gas The Orca gas field is one of the larger accumulations in the southern gas basin. The development plan envisages three wells producing to a normally unmanned platform weighing about 2000 tonnes, with output then being carried about 20km to the D15A platform in the Dutch sector. In February 2012 it was reported that GdF Suez and partners were soon expected to sanction the Orca gas field development. The Orca project is expected onstream in If all goes to plan, it will be the second field straddling the UK- Netherlands median line to progress to production. 83

84 ORLANDO Blocks 3/3b Discovered 1988 Development Approval Submitted January 2012 Iona Energy Oil Orlando, in the Northern North Sea, was first Discovered by Chevron. Orlando will be developed via two subsea production wells tied back to the Ninian Central platform operated by CNR International and oil will be exported to the Sullom Voe terminal on Shetland. Recoverable are estimated to be 9-13 million barrels of oil. Subsidiary MPX North Sea submitted a development plan for Orlando in January ORMONDE Blocks 113/28a, 113/29a and 113/29b. Vattenfall Gas Ormonde in the eastern Irish Sea consists of the Ormonde South and Ormonde North fields. Between them they are estimated to contain billion cubic feet of gas. Development options include a gas-to-wire development where the gas is converted to electricity offshore via combustion in aero-derivative turbines and exported the short distance to shore via cable. An alternative plan is for gas processing platforms to be installed on the two field locations with the gas piped 10km to shore to the gas terminal at Barrow-in- Furness. PEIK Blocks 9/15a Discovered 1985 EnQuest Gas/condensate Peik straddles the UK and Norway median line. Development is expected to be a subsea tieback to nearby facilities. Peik has estimated of 13 million barrels of oil equivalent. 84

85 PERTH Blocks 15/21a, 15/21c Discovered 1983 Development Approval Submitted January 2012 Deo Petroleum Oil Perth is 115 miles northeast of Aberdeen, 7km from the Tartan platform and about 11 km from the Scott complex. Development will be by means of four development wells and two injection wells tied back to a new FPSO with oil exported by shuttle tanker. Deo has selected a preferred FPSO provider and is in advanced discussions regarding design specifications and contractual terms. The capacity of the proposed FPSO will be sufficient to cope with further anticipated phases of the development and is also capable of attracting third party crude within a 30km radius of Perth. The fabrication, installation and commissioning of the new facilities is expected to begin in 2012 with drilling commencing in Q First oil is targeted for the first half of 2014 with a production life of up to 15 years. Deo estimates proved and probable of 21.5 million barrels. Deo recently agreed a deal worth 12.7 million to be taken over by the Parkmead Group. PILOT Blocks 21/27a Discovered 1989 Centrica Oil Development is expected to be via a floating, production storage and offloading vessel. Pilot is estimated to have 77 million barrels of recoverable oil. PTARMIGAN Blocks 15/29a Discovered 1994 Premier Oil Oil Ptarmigan is approximately 14km from the Balmoral FPF. It is likely to be developed with a single well via Balmoral, along with the Caledonia field. 85

86 ROSEBANK/LOCHNAGAR Blocks 213/26, 213/27 Discovered 2004 Chevron North Sea Oil/gas The Rosebank discovery is 81 miles northwest of the Shetland Islands. Nearby infrastructure includes Schiehallion and Foinaven and BP s Clair field. Front-end engineering design work began in July 2012 which will include a newbuild FPSO as well as subsea infrastructure. Crude will likely be offloaded by shuttle tanker and gas piped to the Shetland Islands, located about 130 km from the field. A final investment decision for the 5 billion development is planned for The field is estimated to contain recoverable in the range of million barrels. SHAW Blocks 22/22a Discovered 2009 Talisman Oil Shaw is adjacent to the Godwin discovery. It has estimated 100 million barrels of oil in place. Development options would be via the Montrose and Arbroath facilities. The development would likely include upgrades to the host facility to improve operating efficiency and to enhance recovery from the Montrose-Arbroath reservoirs. Talisman is currently considering the redevelopment of the MonArb field by installing a new bridge-linked platform to handle production from satellite fields, namely, Cayley, Godwin and Shaw, to extend the life on Montrose. Start-up dates for redevelopment could be between 2014 and

87 SHERYL Blocks 21/23a Discovered 2006 Sterling Resources Oil Sterling Resources became the of Sheryl (formerly known as Disraeli) in early Independent studies indicate the potential for up to 10,000 barrels of oil per day. The project is currently on hold, awaiting use of the Pict pipeline system. Sheryl lies close to the Blakeney discovery and overall economic potential could be enhanced with a common production and export facility. SKIPPER Blocks 9/21 Discovered 1990 ATP Oil and Gas Oil Skipper has been considered for development via some type of floating, production, storage and offloading vessel. It is forecast to enter production in TORRIDON Blocks 214/27a Discovered 2000 Total Gas Torridon is a small gas field. Development would be through Phase 2 of the Laggan-Tormore project. Subsea production wells would be fed into a 120km line running from Laggan to Sullom Voe in Shetland. 87

88 WEST WICK Blocks 13/21a Discovered 2006 Centrica Gas West Wick is located in the Inner Moray Firth to the west of the producing Captain field. The discovery could be developed as a satellite to the Captain complex, with output predicted to reach 2800 barrels per day. 88

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