NORTH SEA STUDY OCCASIONAL PAPER No. 100 Options … · NORTH SEA STUDY OCCASIONAL PAPER No. 100...

NORTH SEA STUDY OCCASIONAL PAPER No. 100

Options for Exploiting Gas from West of Scotland

Professor Alexander G. Kemp and Linda Stephen

University of Aberdeen

December, 2005 Price £20.00

DEPARTMENT OF ECONOMICS

ISSN 0143-022X

NORTH SEA ECONOMICS Research in North Sea Economics has been conducted in the Economics Department since 1973. The present and likely future effects of oil and gas developments on the Scottish economy formed the subject of a long term study undertaken for the Scottish Office. The final report of this study, The Economic Impact of North Sea Oil on Scotland, was published by HMSO in 1978. In more recent years further work has been done on the impact of oil on local economies and on the barriers to entry and characteristics of the supply companies in the offshore oil industry. The second and longer lasting theme of research has been an analysis of licensing and fiscal regimes applied to petroleum exploitation. Work in this field was initially financed by a major firm of accountants, by British Petroleum, and subsequently by the Shell Grants Committee. Much of this work has involved analysis of fiscal systems in other oil producing countries including Australia, Canada, the United States, Indonesia, Egypt, Nigeria and Malaysia. Because of the continuing interest in the UK fiscal system many papers have been produced on the effects of this regime. From 1985 to 1987 the Economic and Social Science Research Council financed research on the relationship between oil companies and Governments in the UK, Norway, Denmark and The Netherlands. A main part of this work involved the construction of Monte Carlo simulation models which have been employed to measure the extents to which fiscal systems share in exploration and development risks. Over the last few years the research has examined the many evolving economic issues generally relating to petroleum investment and related fiscal and regulatory matters. Subjects researched include the economics of incremental investments in mature oil fields, the impact of the Gas Levy on incremental investments in mature gas fields, economic aspects of the CRINE initiative, economics of gas developments and contracts in the new market situation, economic and tax aspects of tariffing, economics of infrastructure cost sharing, the effects of comparative petroleum fiscal systems on incentives to develop fields and undertake new exploration, the oil price responsiveness of the UK petroleum tax system, and the economics of decommissioning, mothballing and re-use of facilities. This work has been financed by a group of oil companies and Scottish Enterprise, Energy For 2005 the programme examines the following subjects:

a) Updated Assessment of Prospects for Activity Levels in UKCS, Including Short-Term and Long-Term to 2020 and 2030

b) A Reassessment of the Economics of Exploration and Development West of Shetland

c) Barriers to Asset Trading and their Removal d) Analysis of Third Party Infrastructure Market in Light of 2003 PRT Change

and Signing of New Infrastructure Code of Practice e) Effects of Any Tax Change Made in 2005 Budget f) Economics of Heavy Oil

i

g) CO2 Capture, Sequestration and EOR h) (i) Analysis of Working of EU Emissions Trading Scheme in the UKCS

(ii) Analysis of Working of Trading Scheme for Oil in Produced Water

The authors are solely responsible for the work undertaken and views expressed. The sponsors are not committed to any of the opinions emanating from the studies.

Papers are available from: The Secretary (NSO Papers) Department of Economics University of Aberdeen Business School Edward Wright Building Dunbar Street Aberdeen A24 3QY Tel No: (01224) 273427 Fax No: (01224) 272181 email: [email protected] Papers published to date are: OP 01 North Sea Oil and the Scottish Economy

by D. I. Mackay (1975) £ 2.25

OP 02 Estimated Demand for Supply Boat Berths in Scotland, 1974 - 80 by N. F. Trimble (1975)

£ 2.50

OP 03 The Demand for Production Platforms and Platform Sites, 1974 -1980 by G. A. Mackay and N. F. Trimble (1975)

£ 2.25

OP 04 Prospects for the Shetland Economy by G. A. Mackay (1975)

£ 2.50

OP 05 The Demand for Helicopter Services for the UK Continental Shelf by N. F. Trimble (1975)

£ 2.50

OP 06 Prospects for the Moray Firth Sub-Region by G. A. Mackay (1975)

£ 3.00

OP 07 Foreign Nationals in North East Scotland by A. Marr (1975)

£ 2.25

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OP 08 Prospects for the Orkney Economy By G. A. Mackay (1975)

£ 3.00

OP 09 Prospects for the Buchan Economy by G. A. Mackay and A. Marr (1976)

£ 2.50

OP 10 The Costs of North Sea Oil Developments, Past Trends and Future Prospects by N. F. Trimble (1976)

£ 2.50

OP 11 The Taxation of North Sea Oil by A. G. Kemp (1976)

£ 2.75

OP 12 Revised Estimates of the Demand for Production Platforms, 1977-82 by G. A. Mackay (1977)

£ 3.50

OP 13 A Review of the Proposed Changes in North Sea Oil Taxation by A. G. Kemp and D. Crichton (1978)

£ 5.00

OP 14 The 1981 North Sea Fiscal System by A. G. Kemp and D. Rose (1981)

£ 5.50

OP 15 The Reform of Petroleum Taxation of the UK Continental Shelf by A. G. Kemp and D. Rose (1982)

£ 7.50

OP 16 The Benefits of North Sea Oil by A. G. Kemp, C. P. Hallwood and P. W. Wood (1982)

£ 3.50

OP 17 The Effects of Taxation of Petroleum Exploitation: a Comparative Study by A. G. Kemp and D. Rose (1982)

£ 5.00

OP 18 Investment in Oil Exploration and Development: a Comparative Study of the Effects of Taxation by A. G. Kemp and D. Rose (1982)

£ 6.50

OP 19 The North Sea Oil and Gas Supply Industry, 1977-1990 by D. Newlands, R. Shaw and P. Jones (1983)

£ 2.50

OP 20 Fiscal Aspects of Incremental Investments in the UK Continental Shelf by A. G. Kemp and D. Rose (1984)

£ 8.00

OP 21 Fiscal Aspects of the Rise and Fall of Oil Production in the UK Continental Shelf by A. G. Kemp and D. Rose (1985)

£ 5.00

OP 22 Fiscal Aspects of Field Abandonment in the UKCS by A. G. Kemp and D. Rose, assisted by B. Creed (1985)

£ 7.50

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OP 23 The Offshore Oil Supply Industry in Aberdeen: the Affiliates - their Characteristics and Importance by P. Hallwood (1986)

£ 5.00

OP 24 Barriers to Entry in the North Sea Offshore Oil Supply Industry by J. A. Cairns, A. H. Harris and H. C. Williams (1987)

£ 5.00

OP 25 The Fiscal System Applied to the North Sea Southern Basin Gas Fields by A. G. Kemp and G. K. Kellas (1987)

£ 12.00

OP 26 Petroleum Development Investment Risks and Fiscal Systems: a Comparative Study of the UK, Norway, Denmark and The Netherlands by A. G. Kemp, D. Rose and G. K. Kellas (1988)

£ 12.00

OP 27 Petroleum Exploration Risks and Fiscal and State Participation Systems: a Monte Carlo Study of the UK, Norway, Denmark and The Netherlands by A. G. Kemp, D. Rose and G. K. Kellas (1988)

£ 12.00

OP 28 Economic and Fiscal Aspects of the Development and Decommissioning of New Oil Fields in the North Sea: a Comparative Study of the UK, Norway, Denmark and The Netherlands by A. G. Kemp and G. K. Kellas, assisted by D. Reading (1989)

£ 12.00

OP 29 The Economics of Field Abandonment in the UKCS by A. G. Kemp (1989)

£ 5.00

OP 30 Twenty-Five Years on: an Assessment of UK North Sea Oil and Gas Policies by A. G. Kemp (1990)

£ 15.00

OP 31 A Comparative Analysis of the Impact of the UK and Norwegian Petroleum Tax Regimes on Different Oil Fields by A. G. Kemp and D. Reading (1990)

£ 6.00

OP 32 The Impact of Petroleum Fiscal Systems in Mature Field Life: a Comparative Study of the UK, Norway, Indonesia, China, Egypt, Nigeria and United States Federal Offshore by A. G. Kemp with D. Reading (1991)

£ 10.00

OP 33 The Medium Term Prospects for UK North Sea Oil and Gas: a Financial Simulation by A. G. Kemp, D. Rose, R. Dandie with D. Reading (1991)

£ 10.00

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OP 34 Economic and Fiscal Aspects of Field Abandonment with Special Reference to the UK Continental Shelf by A. G. Kemp with D. Reading (1991)

£ 10.00

OP 35 Development and Production Prospects for Oil and Gas from the UK Continental Shelf after the Gulf Crisis: a Financial Simulation by A. G. Kemp, D. Rose and R. Dandie (1991)

£ 10.00

OP 36 The Economics of Incremental Investments in Mature Oil Fields in the UK Continental Shelf by A. G. Kemp and D. Reading (1991)

£ 15.00

OP 37 The Effects of the Fiscal Terms applied to Offshore Petroleum Exploitation of New Fields: a Comparative Study of the UK, Norway, Denmark, The Netherlands, Australia, China, Indonesia, Egypt, Nigeria and United States Outer Continental Shelf by A. G. Kemp, D. Reading and B. MacDonald (1992)

£ 12.00

OP 38 The UK and Norwegian Fiscal Systems: a Comparative Study of their Impacts on New Field Investments by A. G. Kemp and B. MacDonald (1992)

£ 12.00

OP 39 Potential Gas Supplies from the UKCS and some Possible Fiscal Constraints by A. G. Kemp assisted by M. Høvring (1992)

£ 12.00

OP 40 Incremental Investments in Mature Gas Fields in the UKCS and the Fiscal Problem with Special Reference to the Gas Levy by A. G. Kemp and B. MacDonald (1992)

£ 12.00

OP 41 The Impact of the UK 1993 Budget Proposals on Oil and Gas in the UKCS by A. G. Kemp, D. Rose, M Høvring and D. Reading (1993)

£ 17.00

OP 42 The Interaction of the Petroleum Fiscal System and Cost-Savings in the UKCS Pre and Post the 1993 Budget by A. G. Kemp and B. MacDonald (1993)

£ 14.00

OP 43 Fiscal Aspects of Investment Opportunities in the UKCS and Norway, Denmark, The Netherlands, Australia, China, Alaska (North and South) and the US Outer Continental Shelf by A. G. Kemp and D. Rose (1993)

£ 14.00

OP 44 The Economics of Field Abandonment and Mothballing in the UKCS by A. G. Kemp and B. MacDonald (1993)

£ 14.00

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OP 45 Economic Aspects of Cost Savings in the UKCS by A. G. Kemp and B. MacDonald (December 1993, pp. 95)

£ 16.00

OP 46 Low Oil Prices, Prospective Activity Levels in the UKCS and the effects of Cost Savings by A. G. Kemp and B. MacDonald (May1994, pp. 61)

£15.00

OP 47 Economic and Fiscal Aspects of Incremental Oil Investments in the UKCS by A. G. Kemp, B. MacDonald and Linda Stephen (June 1994, pp. 128)

£17.00

OP 48 Economic and Fiscal Aspects of Oil Tariffing in the UKCS by A. G. Kemp and Linda Stephen (October 1994, pp.101)

£15.00

OP 49 Petroleum Investment and Taxation: the North Sea and the Far East by A. G. Kemp, David Rose and Linda Stephen (January 1995, pp. 56)

£15.00

OP 50 Prospective Developments, Production and Revenues from the UKCS 1995-2000: a Financial and Regional Simulation by A. G. Kemp and Linda Stephen (March 1995, pp. 44)

£14.00

OP 51 The Economics of Gas Developments in the UKCS in the New Market Situation by A. G. Kemp and Linda Stephen (July 1995, pp.82)

£15.00

OP 52 Recent and Prospective Developments in Natural Gas Markets in the UK and Continental Europe by A. G. Kemp and Linda Stephen (October 1995, pp. 39)

£12.00

OP 53 The Economics of Infrastructure Cost Sharing with Cluster Type Developments in the UKCS by A. G. Kemp and Linda Stephen (November 1995, pp.98)

£16.00

OP 54 Petroleum Tax Systems and Incentives to Explore by A. G. Kemp and Peter D. A. Jones (January 1996, pp.26)

£ 5.00

OP 55 Investment, Taxation and Production Sharing in the Russian and Azerbaijan Petroleum Industries by A. G. Kemp and Peter D. A. Jones (April 1996, pp. 67)

£12.00

OP 56 Oil and Gas Prospects in the UKCS to 2010: Price, Cost and Reserve Sensitivities by A. G. Kemp and Linda Stephen (May 1996, pp.52)

£14.00

OP 57 Investment Risk Aspects of New Gas Contracts in the UKCS by A. G. Kemp and Linda Stephen (July 1996, 115)

£17.00

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OP 58 Reforming the Alaskan Petroleum Fiscal System: a Positive Sum Game by A. G. Kemp and Peter D. A. Jones (August 1996, pp.32)

£8.00

OP 59 Progressive Petroleum Taxes and the ‘Gold Plating’ Problem by A. G. Kemp and Peter D. A. Jones (September 1996, pp. 88)

£12.00

OP 60 The Oil Price Responsiveness of the UK Petroleum Fiscal System by A. G. Kemp and Linda Stephen (November 1996, pp. 25)

£5.00

OP 61 Economic and Fiscal Aspects of Decommissioning, Mothballing, and Re-use of Facilities in the UKCS by A. G. Kemp and Linda Stephen (January 1997, pp. 62)

£10.00

OP 62 Investment Prospects in Exploration and Development in the UKCS After the 1997 Budget by A. G. Kemp and Peter D. A. Jones (March 1997, pp.93)

£15.00

OP 63 Risk : Reward Aspects of Contractual Arrangements Among Oil Companies and Contractors by A. G. Kemp and Linda Stephen (May 1997, pp.115)

£15.00

OP 64 The Effects of the July 1997 Budget on Exploration and Development in the UKCS by A. G. Kemp and Linda Stephen ( August 1997, pp.65)

£10.00

OP 65 A Reassessment of Petroleum Taxation in the UKCS by A. G. Kemp, Linda Stephen and Kathleen Masson (November 1997, pp. 119)

£15.00

OP 66 Taxation and Project Risk Sharing with Special Reference to the UKCS by A. G. Kemp and Kathleen Masson (March 1998, pp.57)

£12.00

OP 67 The Economics of Oil and Gas Exploration and Development West of Scotland by A. G. Kemp and Linda Stephen (September 1998, pp.143)

£17.00

OP 68 Exploration and Development Prospects in the UKCS : the 1998 Perspective By A. G. Kemp and Linda Stephen (September 1998, pp.21)

£6.00

OP 69 Oil and Gas Exploration and Development in the UKCS: A Monte Carlo Analysis of the Risks and Returns By A. G. Kemp and Kathleen Masson (October 1998, pp.62)

£10.00

vii

OP 70 Expenditures in and Revenues from the UKCS: Estimating the Hypothetical Scottish Shares 1970 – 2003 By A G Kemp and Linda Stephen (January 1999, pp. 24)

£5.00

OP 71 Prospective Activity Levels in the Regions of the UKCS Under Different Oil and Gas Prices: an Application of the Monte Carlo Technique By A G Kemp and Linda Stephen (May 1999, pp. 42)

£15.00

OP 72 Risk and Investment Decision-Making: a Comparison of the Monte Carlo and FORM/SORM Techniques with Applications to an Oilfield Development By A G Kemp and Linda Stephen and Patrick McIntosh, Det Norske Veritas (July 1999, pp. 41)

£10.00

OP 73 Incremental Investment and Taxation in Mature Fields in the UKCS By A G Kemp and Linda Stephen (July 1999, pp. 81)

£12.00

OP 74 Prospects for the UKCS: Cost, Exploration and Price Sensitivities By A G Kemp and Linda Stephen (September 1999, pp.19)

£10.00

OP 75 The Prospects for UK Gas Supply and Demand By A G Kemp and Linda Stephen (March 2000, pp. 27)

£10.00

OP 76 Prospective Oil Production from and Investment in the UKCS: the 2000 Perspective By A G Kemp and Linda Stephen (June 2000, pp. 47)

£15.00

OP 77 The Economics of Field Cluster Developments in the UKCS By A G Kemp and Linda Stephen (August 2000, pp. 59)

15.00

OP 78 Enhancing Understanding of Energy Investment Risks: The Contribution of the FORM and SORM Techniques By A G Kemp, Linda Stephen and Patrick McIntosh (December 2000, pp. 36)

£10.00

OP 79 An Econometric Model of Oil and Gas Exploration, Development, and Production in the UKCS: A System Approach By A G Kemp and Sola Kasim (December 2000, pp. 54)

£15.00

OP 80 Characteristics of North Sea Oil Reserve Appreciation By GC Watkins, (December 2000, pp. 119)

£20.00

OP 81 Economic Aspects of Field Decommissioning in the UKCS By A G Kemp and Linda Stephen (May 2001 pp. 58)

£20.00

viii

OP 82 Prospects for Activity Levels in the UKCS By A G Kemp and Linda Stephen (June 2001, pp.51)

£20.00

OP 83 Prospects for UK Gas Supply and Demand By A G Kemp and Linda Stephen (July 2001, pp.35)

£20.00

OP 84 The Full Cycle Returns to Exploration in the UKCS By A G Kemp and Linda Stephen (October 2001, pp. 28)

£15.00

OP 85 An Integrated Medium-Term Econometric Forecast of Activity Levels in the UKCS By A G Kemp and Sola Kasim (November 2001), pp. 47

£20.00

OP 86 The Prospects for Activity Levels in the UKCS: The 2002 Perspective By A G Kemp and Linda Stephen (February 2002), pp. 66

£20.00

OP 87 An Analysis of Production Decline Rates in the UK Continental Shelf (UKCS) By A G Kemp and Sola Kasim (June 2002) pp. 48

£20.00

OP 88 UK Gas Production, Imports and Networks: Response to the PIU Report By A G Kemp and Linda Stephen (July 2002), pp. 34

£20.00

OP 89 The Impact of the 2002 Tax Changes on the UK Continental Shelf By A G Kemp and Linda Stephen (August 2002), pp. 44

£20.00

OP 90 UK Oil and Gas Production Prospects, the Optimal Utilisation of UKCS Infrastructure, and the 2003 Budget Tax Changes By A G Kemp and Linda Stephen (April 2003), pp. 73

£20.00

OP 91 Possible Taxation Incentives for the Norwegian Petroleum Industry By A G Kemp and Linda Stephen (September 2003), pp: 67

£20.00

OP 92 A Regional Model of Oil and Gas Exploration in the UKCS By A G Kemp and Sola Kasim (November 2003), pp. 44

£20.00

OP 93 A Reassessment of Potential Production from and Expenditures in the UKCS By A G Kemp and Linda Stephen (March 2004), pp. 52

£20.00

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OP 94 The Petroleum Development Investment Risks and Returns in Libya: a Monte Carlo Study of the Current Contractual Terms (EPSA IV) By A G Kemp and Waniss Otman (April 2004), pp. 39

£20.00

OP 95 Economic Aspects of Incremental Projects in the UKCS By A G Kemp and Linda Stephen (June 2004), pp. 60

£20.00

OP 96 The Prospects for UK Gas Supply and Demand By A G Kemp and Linda Stephen (September 2004), pp.38

£20.00

OP 97 Economic Aspects of Prospective Decommissioning Activity In the UKCS to 2030 By A G Kemp and Linda Stephen (December 2004), pp.61

£20.00

OP 98 Prospects for Activity Levels in the UKCS to 2030: the 2005 Perspective By A G Kemp and Linda Stephen (May 2005), pp. 52

£20.00

OP 99 A Longitudinal Study of Fallow Dynamics in the UKCS By A G Kemp and Sola Kasim, (September 2005), pp. 42

£20.00

OP 100 Options for Exploiting Gas from West of Scotland By A G Kemp and Linda Stephen, (December 2005), pp. 70

£20.00

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Options for Exploiting Gas from West of Scotland

Professor Alexander G. Kemp and Linda Stephen

University of Aberdeen Contents Page 1. Introduction................................................................................................... 1 2. Data and Methodology (General) ................................................................. 3 3. Option 1 – Maximum Use of Existing Infrastructure................................... 6 4. Option 2 – Laggan as Hub .......................................................................... 20 a) Scenario 2A – Laggan Direct to St. Fergus, Lower Tariff Case ............ 20 b) Scenario 2B – Laggan Direct to St. Fergus, Higher Tariff Case............ 25 c) Scenario 2C – Laggan to Alwyn North then Frigg UK to St. Fergus .... 27 d) Scenario 2D – Laggan to MCPO1 and then to St. Fergus...................... 29 e) Scenario 2E – Laggan to SAGE and then to St. Fergus ......................... 31 f) Scenario 2F – Laggan to FLAGS (tie-in) then to St. Fergus.................. 32 g) The Ullage Problem at North Alwyn, Frigg UK, and SAGE................. 34 5. Option 3 – Victory as Hub.......................................................................... 37 a) Scenario 3A – Victory as Hub with Modest Tariffs............................... 37 b) Scenario 3B – Victory as Hub with Higher Tariffs ................................ 41 6. Option 4 – Seonaid as Hub ......................................................................... 43 a) Scenario 4A – Seonaid as Hub and Modest Tarrifs................................ 43 b) Seonaid as Hub with Higher Tariffs ....................................................... 46 7. Rephasing of WOS Field Developments.................................................... 48 8. Independent Communal Pipeline Company ............................................... 55 9. Summary and Conclusions ......................................................................... 64

1. Introduction

The first licences for the West of Scotland (WOS) area were granted in 1971-

1972 under the 4th Licensing Round. The Clair field was the first to be

discovered in the West of Scotland area by BP in block 206/8. Later that year

the first gas discovery (Victory) was made in Block 207/1 now operated by

Chevron. There were further discoveries but it was not until after the Foinaven

discovery in 1992 that development plans were put in place.

Foinaven, Schiehallion, Loyal, and Clair have since been granted development

approval and production from WOS commenced in 1997. Foinaven was

developed using a leased converted support vessel, Petrojar 1 IV, as an FPSO.

Schiehallion has been developed using a new-build FPSO and Loyal is a sub-

sea satellite. Clair South is the first fixed platform development in the West of

Scotland area.

A new gas pipeline, WOSPS, was given consent in late 2000. This pipeline

takes gas from the Foinaven, Schiehallion and Loyal fields to Sullom Voe then

onwards to Magnus and St Fergus via the FLAGS pipeline.

Currently these are the only producing fields but there is a substantial number of

discoveries and prospects. These discoveries are modestly-sized and the

aggregate expected reserves is moderate. There is a mixture of oil fields, gas

fields, and fields containing both oil and gas. It is likely that the development

and operating costs of these undeveloped fields will be relatively high. One of

the problems associated with the fields is their wide geographic dispersion.

There is also limited investor alignment among the licensees. Another problem

is the limited existing infrastructure, both processing and pipelines, in the area.

Other than the WOSPS and the link to it from Clair there is no gas transport

1

infrastructure in the area. There are however, limits to the quantity of gas which

the WOSPS pipeline can transport so questions remain regarding how the rest of

the known gas in the West of Scotland area can be economically produced and

transported to markets. The smaller finds are not viable without an established

pipeline into which they could put their gas.

As all these fields are geographically remote from the nearest mainland gas

terminal at St Fergus and almost all of them are small in size the aim of this

paper is to look at a number of development scenarios which could result in a

comprehensive development.

Four comprehensive scenarios were developed as follows:

1 Use of the existing infrastructure both WOS and EOS, with the gas

being sent from Magnus to St Fergus. Schiehallion and the Clair

Area would act as hubs to minimise the transport costs. Most gas

fields would connect to a new platform in the Clair Area because of

the relatively shallow water in the Clair area.

2 Use of the Laggan field, which is one of the larger gas fields in the

study, as the main hub, with a new communal pipeline linking

Laggan to St Fergus either directly, or indirectly via FLAGS, Frigg,

or SAGE.

3 Use of the Victory field, which is in relatively shallow water, as the

main hub, with a new communal pipeline linking Laggan to St Fergus

either directly, or indirectly via FLAGS, Frigg, or SAGE.

4 Use of the Seonaid field, which is in relatively shallow water and

slightly closer to St Fergus than the previously mentioned fields, as

the main hub with a new communal pipeline linking Laggan to St

Fergus either directly, or indirectly via FLAGS, Frigg, or SAGE.

2

2. Data and Methodology (General) Cost and production data for the fields already in production or under

development were validated by the operators. To these have been added 19

fields in the West of Scotland area and 4 Prospects – Tormore, Tamdhu,

Capercaillie and Cardu. The total reserves/recoverable resources amount to just

under 3tcf. For these fields the reserves, costs, development concepts and

timing of development have been estimated using P50 estimates from a variety

of information either in the public domain or by the authors’ own calculations.

For the scenarios analysed, different development concepts were considered for

the fields, including fixed platforms, FPSOs, TLPs, and sub-sea tieback

systems. The chosen scheme was determined by cost and reserves

considerations. The development cost estimates employed reflect the recent and

ongoing cost escalation in the UKCS. Each field’s operating costs were

modelled based on the accumulated development costs. The annual operating

costs attributed to each field ranged from 7% to 23% of accumulated

development costs depending on the reserves size and type of development.

The average percentage was relatively high at 10.5% because many of the fields

are small. The highest of 23% occurred with some leased FPS facilities. For

each of the 23 projects the pipeline length was calculated using maps from the

DEAL website. Estimates of the pipeline diameters required for each of the

fields, the pipeline costs between the different hub fields, and the different

landfall or pipeline routes was calculated using information from a variety of

sources.

It was assumed that almost all fields would have their own separation facilities

and that produced oil would generally be tanker loaded. Where sub-sea

developments were involved a processing tariff of 50p/bbl was paid to the

receiving field.

3

As part of the study was to determine how the gas from WOS could be

developed and taken to market it was necessary to determine what ullage would

be available in the existing pipeline network not only in the WOS area but in the

North Sea including the FLAGS, Frigg UK, and SAGE systems. From

information in the public domain the various pipeline capacities are known and

from the authors’ database of sanctioned and future fields (validated by the field

operators) estimates were made of the capacity expected to be employed to

transport gas in each pipeline. To this was added the volume of gas likely to

come from as yet undeveloped technical reserve fields and (modelled) new

discoveries1. The geographic location of the technical reserves fields gives a

good indication of which transport route the fields would choose. The

geographic location of new discoveries is less precise, but assumptions can be

made regarding the likely route. All of these volumes were aggregated and the

total volumes compared with the capacity in each pipeline. The result is the

prospective ullage available.

1 For details of how future production estimates were made see A.G. Kemp and L. Stephen, North Sea

Study Occasional Paper No. 98, University of Aberdeen, Department of Economics, May 2005, pp. 52.

4

Further exploration will take place in the WOS area in the time period under

study. It was assumed that the size of the effort from the 22nd and 23rd

Licensing Rounds will be greater than over the past decade, partly because of

the higher levels of oil and gas prices. An exploration success rate of 15% was

assumed with a 42% probability of any find being gas (based on historic

experience). Using Monte Carlo analysis 5 gas fields were discovered over the

next few years with average reserves of 42mboe (227Bcf with a small quantity

of associated oil). The development of these exploration finds could commence

in 2008 with the 5th field commencing development in 2016. Because of the

many uncertainties these possible discoveries were not included in the economic

modelling but are employed to indicate the longer-term total production

potential.

First development dates for Alligin and Suilven were as estimated by the

operators and the phasing chosen for the other fields was determined in relation

to the first development of Laggan which was taken to be sometime in 2006.

Where there are sub-hub developments the phasing was arranged such that the

fields connecting to the sub-hub field would post-date the hub field’s first

production. The results have been shown under 2 timing assumptions, namely,

(a) Fast-Track and (b) a slower, and probably more realistic, pace of

development.

The analysis was based on financial simulation modelling employing the

following price scenarios (real 2005). Oil Price Gas Price Base Case $30/bbl 28p/therm Low Case $20/bbl 18p/therm High Case $40/bbl 36p/therm

The gas price is that received at St Fergus. The economic results are shown in

terms of NPVs at 10% and 15% in real, post-tax terms. The study was

5

undertaken before the announcement by the Chancellor to increase taxation and

thus the NPVs reflect CT+SC at 40%.

3. Option 1 – Maximum Use of Existing Infrastructure

This scenario would use Schiehallion and the Clair Area as the main hubs. The

Clair Area facilities would need to be enhanced and a new 10km pipeline from

the Clair area to the WOSGPS would be required. It is assumed that Suilven,

Alligin and 204/23-1 would all link directly to Schiehallion. Solan, 204/28-1

and 205/26a-2 would be tied back to Strathmore, the largest of the 4 fields, and

oil would be tanker loaded.

Estimated costs for these fields are shown below in real 2005 prices. Field

development costs are split between drilling and other investment. They

exclude pipeline costs except where indicated. Tariff costs are added to the

operating costs where applicable. The costs shown assume that Strathmore acts

as a hub for the 4 field cluster containing 62mmbbls. A TLP is assumed for

Strathmore, and each of the fields in the cluster is assumed to pay a tanker

loading tariff of £1/bbl and an oil processing tariff of 50p/bbl to Strathmore.

Reserves mboe % Gas

First Devex (Fast-Track)

Development Costs $/boe

Capex £m

Drilling £m

Alligin * 21 13% 2008 5.54 36.4 29.47 Suilven * 25 98% 2012 4.62 35.99 29.37 204/23 1 100% 2006 9.46 1.71 5.13 Strathmore 39 0% 2006 8.95 125.05 70.34 205/26 6 0% 2008 9.46 8.34 25.01 Solan 15 0% 2007 8.27 20.42 50.00 * Pipeline costs included

6

The field linkages, pipeline distances, assumed pipeline diameters and estimated

pipeline costs are shown below. In total the developments would require 48km

of wet gas pipeline and 47km of oil pipeline. Block 204/28, Strathmore, 205/26

and Solan being oil only could be developed as a stand-alone cluster.

Chart 1

Schiehallion

Suilven (25.5mb)

Alligin (21.4)

It is assumed that 204/23 pays a gas tariff of 20p/mcf to Schiehallion.

Strathmore, Solan, 205/26 and 204/28-1 all pay a tanker loading charge of

£1/bbl and Solan and 205/26 pay £0.5/bbl to Strathmore. Block 204/28 also

pays £0.5/bbl.

Tariff assumptions for Scenario 1 Schiehallion Route $30/bbl and 28p/therm

1 £m NPV 10% NPV 15%

Tariff to Schiehallion

Tariff to Strathmore

Tanker Loading Tariff

Alligin 1 70.35 51.14 20p/mcf £1/bbl Suilven 1 97.52 81.29 20p/mcf £1/bbl 204/23-1 1 0.30 -0.45 20p/mcf Strathmore 1 69.19 43.35 £1/bbl 204/28-1 1 -1.36 -1.82 50p/bbl £1/bbl 205/26a-2 1 8.53 5.70 50p/bbl £1/bbl Solan 1 28.32 20.66 50p/bbl £1/bbl

204/23-1 (1.3)

204/28/-1 (1)

Strathmore (39.3)

205/26a-2 (6.4)Solan (15.3)

6" 2km £1.04m

6" 11km £2.33m

12" 19km £6.34m

6" 6 km£1.61m

6" 23km £4.05m

6"34km £5.63m

7

Chart 2

Potential Real NPV of new Fields using Schiehallion Route$30/bbl and 28p/therm

Under the $30, 28p scenario all but one of the projects exhibit positive NPVs,

but at the low price level, $20/bbl and 18p/therm, 204/23-1, Strathmore, 204/28-

1, 205/26a-2 and Solan all fail the 10% hurdle.

-20

0

20

40

60

80

100

120

Alligin

Suilven

204/2

3-1

204/2

8-1

Strathm

ore

205/2

6a-2

Solan

£m

NPV 10% NPV 15%

8

Chart 3


At the high price level, $40/bbl and 36p/therm, all fields pass the 10% hurdle

rate.

Chart 4

-30

-20

-10

0

10

20

30

40

Alligin

Suilven

204/2

3-1

204/2

8-1

Strathm

ore

205/2

6a-2

Solan

£m

NPV 10% NPV 15%


0

20

40

60

80

100

120

140

160

Alligin

Suilven

4/28-1

4/23-1

thmor

20 20Stra

e

205/2

6a-2

Solan

£m

NPV 10% NPV 15%

9

With respect to the other fields in this scenario (Option 1) Victory and Laxford

are tied back to Glenlivet. Tamdhu, being oil, is developed independently.

Tobermory is linked by pipeline to Torridon (116km). Torridon is linked by

pipeline to Laggan (12km away) with a 16” pipeline to accommodate Torridon

and Tobermory gas as well. Rosebank is linked by pipeline to Laggan (47km

away). Tormore is 14km from Laggan and 205/10-2b is 23km from Laggan.

These fields are tied back to Laggan. Seonaid is linked by pipeline to Laggan

(58km away) with a 12” gas pipeline to take peak gas of 76mmcf/d. Laggan is

35km from Clair. Rosebank may require a pipeline costing £25.74m.

The possible development costs for the fields and prospects under this

development scenario are given below. A TLP is assumed for Laggan.

4 40.00% 2008 9.46 5.38 16.13

Tamdhu 21 40.00% 2008 9.84 52.08 60.72

Capercaillie 500 5.00% 2007 6.5 1029.17 776.39

Cardu 20 0.00% 2008 8.27 34.01 57.9

Reserves mboe % Gas

First Devex (Fast-Track)

Assumed Development Costs $/boe

Capex £m Drilling £m

Clair Ph3 1 0.00% 2006 9.46 1.58 4.73Victory 15 100.00% 2008 8.27 19.72 48.29Freya 32 100.00% 2007 7.05 49.94 74.22Laxford 16 100.00% 2008 8.27 20.84 51.03Torridon 17 100.00% 2008 9.6 38 54.68Seonaid 35 100.00% 2007 6.83 60.25 71.62Tobermory 62 100.00% 2008 5.9 137.34 64.57Glenlivet 23 100.00% 2008 7.47 34.22 60.4205/10-2b 6 0.00% 2008 9.46 8.13 24.4Rosebank 338 26.00% 2007 6.5 585.87 634.69Cambo 35 100.00% 2008 6.84 61.22 72.54Laggan 149 84.00% 2006 5.29 342.29 96.52

Tormore PROSPECT

PROSPECT

PROSPECT

PROSPECT

10

The field linkages, pipeline distances, assumed pipeline diameters and assumed

hart 5

ay a tanker loading charge of £1/bbl and Tormore and 205/10-2b pay an oil

pipeline costs are shown below. In total the Clair links would require 517km of

gas pipelines and 37km of oil pipelines.

C

ClairClair Ph3 (1.2)Freya (31.7)

Victory (14.8)Capercaillie (500)

Glenlivet (22.8) (15.64)

Laggan (149)

Torridon (17.4)

ermory

Rosebank (338)

Cambo (35.2)

e (4.1) Cardu (20)

205/10-2b (6.2)

Tamdhu (20.6)

Laxford

Tob(61.6)

Seonaid (34.75)

Tormor

6" 9km

In the modelling Laggan, Tormore, Tamdhu, 205/10-2b, Cardu and Capercaillie

p

processing tariff of £0.5/bbl to Laggan. The tariffing arrangements for the other

fields are shown below.

£2.04m

6" ?km

12" 27km £8.21m 6" 15km

£2.9m

30" 35km £25.74m

12" 58km £15.44m

16" 49km £16.67m

16" 116km£36.79m

6" 34km £5.63m

1 £5.55m

6" 12km

18" 47km £16.18m

12 " 71km £18.48m2*6" 14km

£5.52m

6" 23km £4.05m

6" 30km £5.05m

11

To get the gas to the mainland market it is initially assumed that the gas can

proceed from Magnus to FLAGS and then to St. Fergus. The owners of

communal pipelines are assumed to require tariffs from user fields which are

high enough to produce a return on the incremental pipeline cost of at least 10%

in real, post-tax terms. In this Scenario it is also assumed that Magnus receives

a tariff of 5p/mcf and FLAGS receives a tariff of 10p/mcf. A tariff of 20p/mcf

to the Clair Area gives a 10% return on the incremental platform and pipeline

costs provided that these incremental costs amount to no more than £242m. For

the Laggan sub-hub field a tariff of 2.4p/mcf gives a 10% return on the

incremental costs. A tariff of 9p/mcf would give Glenlivet a 10% return on the

incremental pipeline cost but, to act as a sub-hub field whilst paying higher

tariffs, it requires a tariff of 12p/mcf to pass the 10% hurdle rate. A tariff of

1.5p/mcf is enough to give Torridon a 10% return on the incremental pipeline

costs, but to pass the 10% hurdle rate with the higher tariff levels payable it

requires a tariff of 18p/mcf.

Tariff assumptions for Scenario 1 Clai$30/bbl and 28p/therm

r Route

£m Tariff to Tariff to Tariff to Torridon

Tariff to Tobermory

Tariff to Laggan

Tariff to Magnus

Tariff to FLAGS


6 50p/bbl 1/bbl Clair Ph3 3.09 2.34 Freya -3.12

ictory cfp/mcf 0p/mcf

0p/mcf 2p/mcf p/mcf 0p/mcf p/mcf p/mcf

1/bbl ry 8p/mcf p/mcf

1/bbl p/mcf

1/bbl

lie 8p/mcf 5p/mcf

NPV 10% NPV 15%Clair Glenlivet205/10-2b 7.21 4.4 £

9.11 20p/mcf20p/m

12p/mcf

5p/mcf 5p/mcf

10p/mcf 10p/mcf V 5.99 -0.10

Glenlivet 0.30 -6.50 20p/mcf 5 1 Laxford 13.28 5.22 2 1 5 1 Torridon 0.91 -5.84 20p/mcf 3 5p/mcf 10p/mcf Seonaid 8.30 -5.09 20p/mcf 3 5p/mcf 10p/mcf Laggan 266.26 152.60 20p/mcf 5p/mcf 10p/mcf £Tobermo 0.01 -22.67 20p/mcf 1 3 5p/mcf 10p/mcf Cambo 6.96 -6.66 20p/mcf 3p/mcf 5p/mcf 10p/mcf Rosebank 636.02 383.66 20p/mcf 3p/mcf 5p/mcf 10p/mcf £Tormore Prospect 0.48 -1.24 20p/mcf

350p/bbl 5p/mcf 10p/mcf £

Tamdhu Prospect 14.45 3.52 20p/mcf 3p/mcf 5p/mcf 10p/mcf £1/bbl CapercailProspect 719.05 349.98 20p/mcf 1 1 3p/mcf 5p/mcf 10p/mcf £1/bbl Cardu Prospect 28.18 20.23 £1/bbl

12

The resulting NPVs under the $30, 28p scenario are shown in Chart 6. All

ts have positive NPVs at 10% but several fail at 15%.

hart 7

projec

Chart 6

Potential Real NPV of new fields using Clair Route $30/bbl and 28p/therm

-40 -20

20406080

bClair

Freya

Victory

Glenlive

t

Laxfo

rd

Torrido

n

Seona

id

Toberm

or

£m

0

Under the $40, 36p case all projects have positive NPVs at 15% (Chart 7). C

205/1

0-2y

Cambo

Roseban

k

Lagg

an

Tormore

(P)

Tamdh

u (P)

Caperca

illie (P

)

Cardu (P

)

NPV 10% NPV 15%

Potential Real NPV of new Fields using Clair Route$40/bbl and 36p/therm

20 Tob

0

20

40

60

80

100

5/10-2

bClair

Freya

Victory

Glenlive

t

Laxfo

rd

Torrido

n

Seona

id

ermory

Cambo

seban

k

Lagg

an

more (P

£m

NPV 10% NPV 15%

RoTor

)

Tamdh

u (P)

Caperca

illie (P

)

Cardu (P

)

13

Chart 8

Potential Gas Production from new fields WoS $30/bbl and 28p/therm

Hurdle Rate : 10%

0100200300400500600700800900

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

mmcf/d

Prospects Technical Reserve Fields

Chart 9

Potential Gas Production from new fields WoS $20/bbl and 18p/therm

00

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Hurdle Rate : 10%

050

100150200250300350

mmcf/d4540

Technical Reserve Fields

14

15

hart 10

The potential gas production from new fields under the different prices in

shown in Charts 8, 9 and 10. Production from new fields is large compared

with that from already sanctioned ones and potential incremental production

relating to the latter. This is seen from Chart 11.

C

Potential Gas Production from new Fields WoS $40/bbl and 36p/therm

Hurdle Rate : 10%

0100200300400500600700800900

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

mmcf/d

Prospects Technical Reserve Fields

15

Chart 11

Potential Gas Production from WoS

$30/bbl and 28p/thermHurdle : 10%

0

200

400

600

800

1000

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

mmcf/d

Sanctioned Current Incremental Future IncrementalProspects Technical Reserve Fields

There are considerable ullage problems for WOS gas. The problems arise with

the WSGP, the Magnus to Brent link, and the FLAGS pipeline itself. The

ullages likely to be available in the different systems are shown in Charts 12,

13, and 14.

16

Chart 12

WSGP Potential Ullage Scenario 1$30/bbl and 28p/therm

Hurdle Rate :10%

0

200

400

600

800

1000

1200

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d

Future WoS Tech Res WoSProspects New Exploration WoSUllage Net of existing users Low Debottlenecked Ullage High Debottlenecked Ullage

For the WSGP system it is seen (Chart 12) that the ullage, net of existing users

from fields already sanctioned or under development, is small. This pipeline

could have its capacity increased by de-bottlenecking schemes. However, even

the project for a high level of de-bottlenecking goes ahead the pipeline will

still lack the capacity to take all the gas from the technical reserves fields in the

WOS area. This is seen from Chart 12.

if

17

Chart 13

Magnus to Brent Potential Ullage $30/bbl and 28p/therm

Hurdle Rate: 10%

0

800

600

400

200

1000

1200

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d

Future WoS Tech Res WoS ProspectsNew Exploration WoS

The lack of capacity problem is even more apparent when the potential ullage in

the Magnus to Brent link is considered. This is shown in Chart 13.

Ullage Net of existing users Debottlenecked Ullage

18

Chart 14

m is shown

Chart 14. Much depends on what volumes of Norwegian gas are transported

through this system. Information on what quantity of Norway gas is likely to be

transported in the FLAGS pipeline shown in Chart 14 comes from a variety of

sources in the public domain. There is a serious danger that Norwegian gas

could utilise the ullage before gas from WOS becomes available.

The general conclusion is that, because of the prospective ullage problem a

comprehensive development of gas from the WOS area in the medium-term

based on use of existing infrastructure is rendered very problematic.

FLAGS Potential Ullage $30/bbl and 28p/therm

Hurdle Rate : 10%

0

500

000

0

0

500

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d2

200

150

1

Exp. Tech Res EoS Potential Tech Res EoS Tech Res WoSProspects Norwegian New ExplorationUllage net of existing users

The prospective position with respect to ullage in the FLAGS syste

in

19

4. Option 2 – Laggan as Hub

a) Scenario 2A – Laggan Direct to St. Fergus, Lower Tariff Case

his scenario uses Schiehallion, Clair, and Laggan as hub fields. The fields

ng with Schiehallion would be the same as under Option 1 and the fields

ith oil only would again be developed independently as a cluster. Freya and

lair Ph 3 would be tied back Clair. Freya to Clair would require a 27km 12”

gas pipeline (£8.21m) and the development costs would be as in Scenario 1.

hart 15

T

linki

w

C

CLaggan (149)

Rosebank (338)Tobermory (61.6)

Capercaillie (500)

Seonaid (34.75)Torridon (17.4)

Glenlivet (22.8)

Laxford (15.64)

Cambo (35.2) Victory (14.8)

Tormore (4.1)

Cardu (20)205/10-2b (6.2)

Tamdhu (20.6)

18" 47km £16.18m

6" 34km £5.63m

16" 117km £37.09m

12" 58km £15.44m 16" 38km

£13.36m 6" 9km £2.04m18" 12km

£5.6m

6" 15km £2.9m

12" 71km £18.48m

2*6" 14km £5.52m

6" 23km £4.05m

6" 30km £5.05m

20

Th ields linked to Laggan are se f hown in Chart 15. In Scenario 2A it is

ssumed that Laggan is linked directly by pipeline to St Fergus. This communal

3 would pay

ed

to Tobermory by pipeline. Tobermory is 117km from Laggan and a 16” pipe

would be more than adequate to take Tobermory and Capercaillie gas. Seonaid

is 58km from Laggan and a pipeline is required. Laxford could be

linked to Glenlivet by a 6” 9km pipeline. Victory would be linked to Glenlivet

by a 15km 6” gas line and Glenlivet could be linked to Torridon by a 16” 38km

gas pipeline. Torridon would then require an 18” 12km gas pipeline to Laggan.

Cambo could be lin 7 agga to scenario

would require 445km of gas pipelines and 47km of oil pipeline.

Possible developmen for Laggan a from Scenario 1 but those

of the other fields remain the same. However, the inter-field pipeline costs do

differ. T ggan ent would again be a TLP but, as the hub field,

there would be extra costs. The totals are shown below. They exclude the cost

of the communal pipeline to St. Fergus.

semboe

elopment Cost $/boe Capex £m Drill £m

aggan 149.28 6.82 469.1 96.52

a

30” 85km pipeline would cost £262m (real 2005). Other fields

tariff to Laggan and the sub-hub fields.

Rosebank, Tobermory, Seonaid, and Torridon may all be directly linked by

pipeline to Laggan as would Cambo and Tamdhu. Tormore and 205/10-2b may

be tied back to Laggan. Rosebank is 47km from Laggan. Capercaillie is link

12” gas

ked by a 1km pipeline to L n. In tal this

t costs re different

Re

he La developm

rves Dev

L

21

If Laggan becomes a hub field and the owners also develop the communal

pipeline to St. Fergus there would be a considerable increase in pipeline costs.

On a stand-alone basis an 18” pipeline could cost £118.37m, but a 30” pipeline

could cost £261.92m. To achieve a return of 10% on the extra pipeline costs

aggan would need to charge a tariff of around 17.715p/mcf. With this

requires a 16”

ipeline costing £13.36m. To achieve a return of 10% on the extra pipeline cost

L

scenario Torridon would become one of the sub-hub fields. Torridon itself

requires a 6” pipeline to Laggan which would cost £2.47m. Torridon as a sub-

hub would require an 18” pipeline costing £5.6m. To achieve a return of 10%

on the extra pipeline cost Torridon would have to charge a tariff of about

2p/mcf, but at this tariff it would fail as a sub-hub, and Glenlivet, Victory and

Laxford gas could be stranded. For Torridon to pass the minimum hurdle rate

and operate work as a sub-hub field it would have to charge a tariff of at least

12p/mcf.

Glenlivet would also become a sub-hub field. Glenlivet needs a 6” pipeline to

Torridon for its own use (costing £6.2m), but as a sub-hub it

p

Glenlivet would have to charge a tariff of 7.1p/mcf. If the tariff to Laggan was

17.715p/mcf, and the tariff to Torridon were 12p/mcf, the Glenlivet field only

just passes the hurdle rate at 10%. Tobermory also acts as a sub-hub in this

scenario and requires a 16” pipeline.

22

Tariff assumptions for Scenario 2A Laggan Route $30/bbl and 28p/therm

2A

£m NPV 10%

NPV 15%

Tariff to Laggan

Tariff to Torridon

Tariff to Glenlivet

Tariff to Tobermory


205/10-2b 7.21 4.46 50p/bbl £1/bbl Clair Ph3 3.09 2.34 Freya 9.11 -3.12 Victory 8.43 1.94 17.715p/mcf 12p/mcf 10p/mcf

Laxford 15.88 7.38 17.715p/mcf 12p/mcf 10p/mcf Torridon 0.78 -5.17 17.715p/mcf Seonaid 22.00 5.68 17.715p/mcf

Laggan SF 186.92 57.94 £1/bbl Tobermory 40.04 8.23 17.715p/mcf Cambo 20.82 4.24 17.715p/mcf Rosebank 665.21 405.20 17.715p/mcf £1/bbl Tormore Prospect 1.23 -0.61

17.715p/mcf 50p/bbl £1/bbl

Tamdhu Prospect Capercaillie

Glenlivet 3.63 -3.46 17.715p/mcf 12p/mcf

18.20 6.64 17.715p/mcf £1/bbl

rospect 734.91 360.98 17.715p/mcf 5p/mcf £1/bbl ardu

PCProspect 28.18 20.23 £1/bbl

23

Chart 16

24

Chart 17

Potential Real NPV of new fields using Laggan Route $30/bbl and 28p/therm

Ta L 1 orrido 0 mor0

tory

Gle La Torr S gga

Toberm

or

riffs : aggan 7.715p, T n 12p, Glenlivet 1 p, Tober y 5p

-20

0

20

40

60

80

10

205/1 Vic0-2

bnlive

txfo

rd idon

eona

idn SF

La

£m

NPV 10%NPV 15%

y

Cao

Roseban

k

Tormore

(Pmb )

Tamdh

u (P)

Caperca

illie (P

)

Car u (P

d)


Tariffs : Laggan 17.715p, Torridon 12p, Glenlivet 10p, Tobermory 5p

0

20

40

60

80

100

120

140

160

180

200

205/1

0-2b

Victory

Glenlive

t

Laxfo

rd

Torrido

n

Seona

id

Lagg

an SF

Toberm

ory

Cambo

Roseban

k

Tormore

(P)

Tamdh

u (P)

Caperca

illie (P

)

Cardu (P

)

£m

NPV 10%NPV 15%

The results of the modelling of Scenario 2A (Charts 16 and 17) indicate that all

elds have the 10% hurdle under the $30, 28p case but the NPVs are often quite

mall. Several fields fail the 15% hurdle. Under the $40, 36p case all NPVs are

ositive, but the values are often modest.

) Scenario 2B – Laggan Direct to St. Fergus, Higher Tariff

fi

s

p

b

lthough Laggan and the sub-hub fields do receive a 10% return on their

cremental pipeline costs, given the risks of this Scenario a higher rate of

turn may be required. A case was thus examined where the tariff to Laggan

as increased to 20p/mcf. The results are shown in Charts 18 and 19.

ssumptions for Scenario 2B Laggan Route 30/bbl and 28p/therm

B

£m NPV 10%

NPV 15%

Tariff to Laggan

Tariff to Torridon

Tariff to Glenlivet

Tariff to Tobermory


05/10-2b 7.21 4.46 50p/bbl £1/bbl lair Ph3 3.09 2.34 reya 9.11 -3.12

4.99 -0.94 20p/mcf 15p/mcf 15p/mcf 4.35 -2.85 20p/mcf 15p/mcf

axford 12.21 4.33 20p/mcf 15p/mcf 15p/mcf orridon 3.65 -2.73 20p/mcf eonaid 20.45 4.46 20p/mcf

an SF 198.99 66.71 £1/bbl obermory 39.07 7.45 20p/mcf

bo 19.26 3.02 20p/mcf osebank 661.92 402.77 20p/mcf £1/bbl

ore rospect 1.15 -0.68

20p/mcf 50p/bbl £1/bbl

Tamdhu rospect 17.77 6.29 20p/mcf £1/bbl

rospect 732.52 359.32 20p/mcf 10p/mcf £1/bbl ardu Prospect 28.18 20.23 £1/bbl

A

in

re

w

Tariff a$

22CFVictory Glenlivet LTSLaggTCamRTormP

PCapercaillie PC

25

Chart 18

26


Tariffs : Laggan 20p, Torridon 15p, Glenlivet 15p, Tobermory 10p 100

Chart 19

-20

0

20

40

60

80

0-2b

tory

livet

ford

£m

NPV 10%NPV 15%

205/1 Vic

Glen Lax

Torrido

n id SF or

Seona

Lagg

an

Toberm

y

Cambo

Roseban

k

Tormore

(P)

Tamdh

u (P)

Capail

lie (P

erc

)

Cardu (P

)

Poten e g aggan R ute b 6

s n ri G 1 , Tobermor 10p

0

205/1

0-2b

Victory

Glenlive

t

Laxfo

rd

Torrido

n

Seona

id

Lagg

an SF

Toberm

ory

Cambo

Roseban

k

Tormore

(P)

Tamdh

u (P)

Caperca

illie (P

)

Cardu (P

)

£m

tial R al NPV of new fields usin L o$40/ bl and 3

on 15p,p/thermenlivetTariff : Lagga 20p, Tor d l 5p y

20

40

60

80

100

120

140

160

180

200NPV 10%NPV 15%

It is seen that at the $30, 28p price scenario the NPVs at 10% are all positive but

everal are very small. The proposed tax changes will, of course, render them

ven smaller. Under the $40, 36p case NPVs are significantly improved. All

ut one have NPVs at 15% of at least £20 million.

aggan need not be linked directly to St Fergus, it may connect to Alwyn North,

the Frigg MCPO1, to SAGE, or to a FLAGS tee. Estimated pipeline costs are

s follows (£m 2005).

aggan to St Fergus MCPO1 Alwyn North FLAGS Sage Magnus

4" 207.42 151.41 135.94 122.61 172.75 127.94 261.92 191.01 171.5 154.63 218.06 161.38

) Scenario 2C – Laggan to Alwyn North then Frigg UK to St. Fergus

s

e

b

L

to

a

L230"

c

nder this Scenario the communal pipeline from Laggan goes to North Alwyn

St. Fergus via Frigg UK. To receive a 10% return on the incremental

ipeline costs to Alwyn North, Laggan needs to charge a tariff of 6.645p/mcf.

cenario 2C is a low tariff one where all hub fields receive a return of at least

0% on their incremental costs, including the Laggan owners of the pipeline to

orth Alwyn, and Alwyn North/Frigg share a tariff of 15p/mcf.

U

and then to

p

S

1

N

27

Tariff assumptions for Scenario 2C Laggan Route $30/bbl and 28p/therm

2C

£m

10% NPV 15% Laggan Torridon Glenl

Alwyn Tanker NPV Tariff to Tariff to Tariff to

ivetTariff to Tobermory

North /Frigg

Loading Tariff

205/10-2b 7.21 4.46 50p/bbl £1/bbl lair Ph3 3.09 2.34

4 6.656p/mcf 15p/mcf 6.656p/mcf 15p/mcf

aggan TLP AN 150.12 41.00 15p/mcf £1/bbl obermory 35.56 4.78 6.656p/mcf 15p/mcf

Cambo 18.13 2.13 6p/mcf 15p/mcf 6p/m 15p/mcf £1/bbl

ore pect 09

p/m/bbl 15p/mcf £1/bbl

amdhu Prospec

CFreya 9.11 -3.12 Victory 6.78 0.56 6.656p/mcf 13p/mcf 10p/mcf 15p/mcf Glenlivet 0.90 -5.76 6.656p/mcf 13p/mcf 15p/mcf Laxford 14.12 5.91 6.656p/mcf 13p/mcf 10p/mcf 15p/mcf Torridon 0.45 -5.4Seonaid 19.34 3.59LT

6.65 6.65Rosebank 659.54 401.01 cf

TormPros 1. -0.73

6.656 cf 50p

T t 17.47 6.04 6.656p/mcf 15p/mcf £1/bbl Capercaillie

rospect 733.62 360.09 6.656p/mcf 5p/mcf 15p/mcf £1/bbl ardu Prospect 28.18 20.23 £1/bbl

PC

Chart 20


Tariffs : Laggan 6.656p, Torridon 13p, Glenlivet 10p, Tobermory 5p, AN/Frigg 15p

60

80

00

-20

0

1

205/1

0-2b

Victory

Glenlive

t

Laxfo

rd

Torrido

n

Seona

id

Lagg

an AN

Toberm

or

£m

40

20

y

Cambo

Roseban

k

Tormore

(P)

Tamdh

u (P)

Caperca

illie (P

)

Cardu (P

)

NPV 10% NPV 15%

28

It is seen that the NPVs at 10% are all positive under the $30, 28p case, but they

aller still if the ta proposals are

enacted.

enari gan o MCPO and th n to S Fergus

are often very small and will become sm x

d) Sc o 2D – Lag t 1 e t.

is Sc o om Laggan goes to MCPO1 and

then g erg s case a ariff o 9p/mcf g 1 % real

pip line costs and a rger t iff of 25 s o

gg ow er 2 p price scenario even if the tariff to

in in p it must itself pay the higher tariff levels,

te. t lso fails the 10% hurdle rate when the

ust a rate, Victory and

Without the Glenlivet, Victory, and Laxford tariffs,

paying higher tariffs, Torridon also fails the hurdle rate. Laggan

ould then receive no tariffs from Torridon, Glenlivet or the stranded fields,

nd, while the 9p/mcf tariff should have given Laggan a 10% return on the

cremental pipeline costs the 10% is not achieved when this cluster of fields

ario is thus not viable.

Under th enari the c munal pipeline from

the gas oes to St. F us. In thi t f ives a 0

return on the incremental e la ar p/mcf i paid t

the Fri ners. Und the $30, 8

Torridon creased to 17 /mcf when

it fails the 10% hurdle ra Glenlive a

tariffs it m pay are incre sed. As Glenlivet fails the hurdle

Laxford gas are stranded.

and after

w

a

in

fails to pay tariffs. This Scen

29

Tariff assumptions for Scenario 2D Laggan Route $30/bbl and 28p/therm

2D 2

NPV 10%

NPV 15%

Tariff to Laggan

Tariff toTorridon

Tariff to Glenlivet

Tariff toTobermory Frigg


05/10-2b 7.21 4.46 50p/bbl £1/bbl

a ictory 1.31 -4.02 9p/mcf 17p/mcf 10p/mcf 25p/mcf

Clair Ph3 3.09 2.34 Frey 9.11 -3.12 VGlenlivet -7.11 -12.49 9p/mcf 17p/mcf 25p/mcf Laxford 8.27 1.07 9p/mcf 17p/mcf 10p/mcf 25p/mcf Torridon -19.10 -21.94 9p/mcf 25p/mcf Seonaid 11.00 -2.96 9p/mcf 25p/mcf Laggan TLP MCPO1 120.16 16.72 25p/mcf £1/bbl Tobermory 21.55 -6.03 9p/mcf 25p/mcf Cambo 9.69 -4.51 9p/mcf 25p/mcf Rosebank 641.77 387.91 9p/mcf 25p/mcf £1/bbl

Tormore Prospect 0.63 -1.11 9p/mcf 50p/bbl 25p/mcf £1/bbl

Tamdhu Prospect 15.19 4.13 9p/mcf 25p/mcf £1/bbl

Capercaillie Prospect 729.57 357.27 9p/mcf 5p/mcf 25p/mcf £1/bbl Cardu Prospect 28.18 20.23 £1/bbl

Chart 21


Tariffs : Laggan 9p, Torridon 17p, Glenlivet 10p, Tobermory 5p, Frigg 25p

-40 -20

020406080

100

205/10-2b

Victory

Glenlivet

Laxford

Torridon

Seonaid

Laggan M

CPO1

Toberm

oryCambo

Roseban

k

Tormore (P

)

Tamdhu (P

)

Capercaillie

(P)

Cardu (P

)

£m

NPV 10% NPV 15%

30

e) Scenario 2E – Laggan to SAGE and gas on to St. Fergus

nk to the SAGE pipeline. Because of

long distance th i ld a

3.2p/mcf c a turn on the inc emental pipeline costs. In

se a relative

umptions for d 28p/therm

Niff to gan

ariff to orridon

ariff to lenlivet

TaTobermory SAGE


/bbl £1/bbl Clair Ph3 3.09 2.

. . p/mcf 6p/mcf 8p/mcf

Glenlivet 4.26 -2.92 13.2p/mcf 16p/mcf 10p/mcf p/mcf 6p/mcf

7 13.2p/mcf eonaid 18.29 2.77 13.2p/mcf 10p/mcf

SAGE 168.31 49.17 10p/mcf £1/bbl 33.81 3.43 13.2p/mcf 10p/mcf

ambo 17.07 1.30 13.2p/mcf 10p/mcf osebank 657.32 399.37 13.2p/mcf 10p/mcf £1/bbl

ore Prospect 1.03 -0.78 13.2p/mcf 50p/bbl 10p/mcf £1/bbl

Tamdhu Prospect 17.18 5.80 13.2p/mcf 10p/mcf £1/bbl Capercaillie Prospect 733.11 359.73 13.2p/mcf 5p/mcf 10p/mcf £1/bbl Cardu Prospect 28.18 20.23 £1/bbl

In this Scenario it is seen that the fields have positive but generally very small

NPVs at 10% under the $30/28p price case. The tax proposals reduce the

turns further.

Another possibility is that Laggan may li

the and us h gh cost of the pipeline Laggan wou require

tariff of 1 to re eive 10% re r

this ca ly low tariff of 10p/mcf is paid to the SAGE licensees.

Tariff ass Scenario 2E Laggan Route $30/bbl an

2E PV 10% NPV 15% LaTar

gTT

TG

riff to

205/10-2b 7.21 4.46 50p 34 12 Freya 9.11 -3

Victory -2 95 13.2 1 1 10p/mcf 2.58

Laxford 9.63 2.19 13.2 1 18p/mcf 10p/mcf -2.7 3.60 Torridon 10p/mcf

SLaggan TLP Tobermory CR

Torm

re

31

Chart 22

enario 2F an ) then t St. Fe us

f) Sc – Lagg to FLAGS (tie-in o rg


Tariffs : Laggan 13.2p, Torridon 16p, Glenlivet 18p, Tobermory 5p, Sage 10p

-20

0

20

40

60

80

100

205/1

£m

bilit at t pe ay t -in direc h

a a .5p/mcf gives a 10% return on th

cremental pipeline costs of the Laggan licensees.

A further possi y is th he pi line from Laggan m ie tly to t e

FLAGS pipeline. In this c se then tariff of 4 e

in

0-2b

Victory

Glen livet

Laxford

Torridon

Seonaid

Laggan SAGE

Toberm

oryCambo

Rosebank

Tormore (P

)

Tamd (P

hu)

Capercaillie (P

)

Cardu (P)

NPV 10% NPV 15%

32

Ta$3

riff assumptions for Scenario 2F Laggan Route 0/bbl and 28p/therm

F NPV 10%

NPV 15%

Tariff to Laggan

Tariff to Torridon

Tariff to Glenlivet

Tariff toTobermory FLAGS


205/10-2b 7.21 4.46 50p/bbl £1/bbl lair Ph3 3.09 2.34

ya 9.11 -3.12 ictory 9.51 2.84 4.5p/mcf 12p/mcf 10p/mcf 10p/mcf lenlivet 5.27 -2.09 4.5p/mcf 12p/mcf 10p/mcf axford 17.03 8.33 4.5p/mcf 12p/mcf 10p/mcf 10p/mcf orridon 2.21 -3.94 4.5p/mcf 10p/mcf eonaid 24.17 7.38 4.5p/mcf 10p/mcf aggan TLP FLAGS 158.35 48.74 10p/mcf £1/bbl obermory 43.69 11.05 4.5p/mcf 10p/mcf ambo 23.02 5.97 4.5p/mcf 10p/mcf osebank 669.84 408.61 4.5p/mcf 10p/mcf £1/bbl

ormore Prospect 1.35 -0.51 4.5p/mcf 50p/bbl 10p/mcf £1/bbl

amdhu Prospect 18.79 7.14 4.5p/mcf 10p/mcf £1/bbl 735.97 361.72 4.5p/mcf 5p/mcf 10p/mcf £1/bbl

ardu Prospect 28.18 20.23 £1/bbl

is seen that not only do all fields receive a return of at least

10% on the incremental pipeline costs but the NPVs at 10% of the fields

emselves are positive, albeit often very small. The size of the tariffs are very

2

CFreVGLTSLTCR

TTCapercaillie Prospect C

In this Scenario it

th

small, however, the asset owners may feel that higher ones are necessary to

reflect the costs and risks.

33

Chart 23

g) The Ullage Problem at North Alwyn, Frigg UK, and SAGE

Potential Real NPV of new fields using Laggan Route0

Tariffs : Lagg p id 0

-20

0

20

40

60

80

100

205/1

0b y et for

d

T

idL

$3

, Torr/bbl and 2on 12p, G

8p/lenlivet

therm 10p, Tobean 4.5 rmory 5p, FLAGS 1 p

-2 ctor

enliv x

ViGl La or Serid

onon

a

Lagg

an F

AGS

Toberm

or

£m

king account of the volumes from existing users was

alculated. The likely volumes not only from WOS but also from EOS (and

from Norway in the case of Frigg UK) were also estimated. The resulting

available ullage is seen in Charts 24, 25 and 26.

The ullage issue was investigated with respect to Scenarios 2D, 2E, and 2F.

The potential ullage after ta

c

y

Cambo

Rosan

k

Tormore

Peb

()

Tdh

u (P

am

)

C

caill

aper

ie (P)

Cardu (P

)

NPV 10% NPV 15%

34

Chart 24

Alwyn North Potential Ullage $30/bbl ane 28p/therm

Hurdle Rate : 10%

0

100

200

300

400

500

600

700

800

900

1000

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d

Future WoS Tech Res Laggan Route Prospects Laggan RouteNew Exploration WoS

It is clear from Chart 24 that the Alwyn North pipeline link to Frigg does not

gan route. have enough capacity to transport the WOS gas fields using the Lag

Chart 25

Ullage net of existing users

Frigg Potential Ullage$30/bbl and 28p/therm

Hurdle Rate : 10%

12001400160018002000

mmcf/d

0200400600800

1000

2005

2007

2009

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

Exp. Tech Res EoS Potential Tech Res EoS Future WoSTech Res Laggan Route Prospects Laggan Route NorwegianExploration WoS Ullage net of existing users

35

From Chart 25 it is seen that even without the potential Norwegian imports, the

rigg pipeline does not have the capacity to accept all the WOS gas via the

Laggan route until after 2010. Chart 26

he SAGE pipeline has much more prospective available capacity and has

nough to accept a considerable amount of WOS gas via the Laggan route.

ith delays in the implementation of the WOS projects there would be enough

apacity available. The problem with this Scenario relates to the high pipeline

ost.

was clearly shown above (Chart 14) that FLAGS could not take the WOS gas

there are imports from Norway on the scale indicated.

F

SAGE Potential Ullage$30/bbl and 28p/therm

Hurdle Rate : 10%

200

0

0

0

1000

00mmcf/d

12

80

60

40

02005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029


T

e

W

c

c

It

if


36

5. Option 3 – Victory as Hub

a) Scenario 3A – Victory as Hub with Modest Tariffs

his scenario would use Schiehallion, Clair, and Victory as hubs. The fields

th Schiehallion would be the same us with the other scenarios. The

nkages of the fields to Victory are shown in Chart 27.

hart 27

ubs would be different

and there would need to be a dramatic increase in the Victory facilities before it

T

linking wi

li

C

Victory (14.8)

Tobermory (61.6)

Freya (31.7)

Capercaillie (500)

Glenlivet (22.8)

Laxford (15.64)

Rosebank (338)

Torridon (17.4)

Laggan (149)

Seonaid (34.75)

Cambo (35.2)

Cardu

37

Victory is in relatively shallow water. This represents the case for considering

it as a hub. The interfield network of pipelines and sub-h

(20) Tormore (4.1)

205/10-2b (6.2)

Tamdhu (20.6)

16" 9km £4.65m

30" 12km £10.22m

18" 47km £16.18m

30" 25km £18.99m

16" 89km £28.68m

6" 34km £5.63m

12" 46km 12.64m£

18" 15km m£6.51

12" 58km £15.44m

6" 30km £5.05m

2*6" 14km £5.52m

12" 71km £18.48m

6" 23km £4.05m

could as osts for Laggan would be reduced if

ictory became the hub field. The cost estimates are as follows:

aggan 149.28 5.01 318.99 96.52

Victory 14 n/a 132.6 48.29

Freya, Glenlivet and Torridon could be linked directly by pipeline to Victory.

Capercaillie would k to Tobe hich could be linked to Laxford

by an 89km pipeline. Laxford would require a 9km pipeline to link to

G ivet is 15km from Victo linked to Laggan

by a 12” 71 km pipeline. Laggan would require a 30” 12km pipeline to link to

Torridon. Torridon is 25km from Vic t le pelines

would be required.

The cost of a communal 30% pipeline to St. Fergus is estimated at £259.22m.

To achieve a return of 10% on the extra pipeline costs Victory would need to

charge a tariff of around 18.9p/mcf, bu oes not take any account of the

extra field development costs required. In fact Victory requires a tariff of

to achieve a 10% field return on the incremental costs and pass the

0% field development hurdle rate. This case is shown in Chart 28.

act a hub. The development c

V

Reserves mboe

Development Cost $/boe Capex £m Drill £m

L

Freya would require a 12”, 46km pipeline.

again lin rmory w

lenlivet. Glenl ry. Cambo could be

tory. A ast 450km of gas pi

t this d

27.7p/mcf

1

38

Under this scenario Glenlivet would become one of the sub-hub fields.

Glenlivet needs a 6” pipeline to Victory for its own use costing, £2.9m but as a

ub-hub field it requires an 18” pipeline costing £6.51m. To achieve a return of

10% on the extra pipeline cost Glenlivet would have to charge a tariff of at least

.4p/mcf.

e a sub-hub fi line to

Glenlivet for its own use costing £2.04m, but as a sub-hub field it requires a 16”

e co £4.65 To ach re extra pipeline cost

pipeline.

on to pass the hurdle rate and work as a sub-hub field it

ould have to charge a tariff of at least 6p/mcf.

e indicated

riffs all fields have positive NPVs at 10%. But several, including Victory as

hub, have negative NPVs at 15%.

s

1

Laxford would also becom eld. Laxford needs a 6” pipe

pipelin sting m. ieve a turn of 10% on the

Laxford would have to charge a tariff of at least 1.3p/mcf. Tobermory also acts

as a sub-hub in this scenario, requiring a 16”

Torridon would also become one of the sub-hub fields. It requires a 6” pipeline

to Victory which could cost £4.34m. Torridon as a sub-hub would require a 30”

pipeline costing £18.99m. To achieve a return of 10% on the extra pipeline cost

Torridon would have to charge a tariff of 2.07p/mcf, but at this tariff Torridon

would fail economically, and Glenlivet, Victory and Laxford gas could be

stranded. For Torrid

w

Laggan would also become a sub-hub field. As a sub-hub field it requires a 30”

pipeline costing £10.22m. To achieve a return of 10% on the extra pipeline cost

Laggan would have to charge a tariff of 1.3p/mcf.

It is seen from Chart 28 that under the $30, 28p price case and th

ta

39

Tariff assumptions for Scenario 3A Victory Route $30/bbl and 28p/therm

3A

£m

10% 15% Victory GlenlivetLaxford TobermoryTorridon Laggan

Tanker

Tariff

Clair Ph3

NPV NPV Tariff to Tariff to Tariff to Tariff to Tariff to Tariff to

Loading

205/10-2b 7.21 4.46 50p/bbl £1/bbl 3.09 2.34

ya 10.93 -2.18 27.7p/mcf ictory to St Fergu

FreV s18.89 -25.76

6p/mcf 5p/mcf 50p/bbl £1/bbl

amdhu Prospect 14.32 3.41 27.7p/mcf 6p/mcf 5p/mcf £1/bbl Capercaillie

Cardu Prospect 28.18 20.23 £1/bbl

Glenlivet 9.85 2.06 27.7p/mcf Laxford 23.25 12.96 27.7p/mcf 5p/mcf Torridon 3.98 -3.97 27.7p/mcf Seonaid 7.83 -5.46 27.7p/mcf 6p/mcf 5p/mcf Laggan 296.17 178.13 27.7p/mcf 6p/mcf £1/bbl Tobermory 23.66 -3.16 27.7p/mcf 5p/mcf 5p/mcf Cambo 6.48 -7.03 27.7p/mcf 6p/mcf 5p/mcf Rosebank 635.01 382.92 27.7p/mcf 6p/mcf 5p/mcf £1/bbl

Tormore Prospect 0.46 -1.26 27.7p/mcf T

Prospect 728.35 356.43 27.7p/mcf 5p/mcf 5p/mcf 5p/mcf £1/bbl

Chart 28

Scenario 3B – Victory as Hub with Higher Tarrifs

Potential Real NPV of new fields using Victory Route $30/bbl and 28p/therm

Tariffs : Victory 27.7p, Glenlivet 5p, Laxford 5p, Tobermory 5p, Torridon 6p, Laggan 5p 100£m

-40

-20

10-2b

Freyay S

Fnlive

tgg

anxfo

rdr

0

80

205/

Victor Gle La La To

NPV 10%NPV 15%

20

40

60

r don

Seona

id

Toberm

oriy

Cambo

Roseban

k

Tormore

(P)

Tamdh

u (P)

Caperca

illie (P

)

Cardu (P

)

40

b) Scenario 3B – Victory as Hub with Higher Tariffs

with higher tariffs are shown below. Tariff assumptions ce 3B R

bbl and 28p/th

riff tolenlivet

ariff toaxford

ariff toobermory

ariff toorridon

ariff toaggan

oading ariff

0p/bbl 1/bbl

t Fergu

The resulting NPVs

for Serm

nario Victory oute $30/

3B

£m NPV 10%

NPV 15%

Tariff toVictory

Ta TG

TL

TT

TT

LL

Tanker

T205/10-2b 7.21 4.46 5 £Clair Ph3 3.09 2.34 Freya 9.51 -3.29 30p/mcf Victory to S s18.78

p/mcf

Tobermory 11.33 -12.71 30p/mcf 10p/mcf 10p/mcf

rospect 0p/mcf 10p/mcf

0p/bbl

amdhu Prospect 12.23 1.67 30p/mcf 10p/mcf 10p/mcf £1/bbl apercaillie rospect 722.67 352.49 30p/mcf 10p/mcf 10p/mcf 10p/mcf £1/bbl

ct 28.18 20.23 £1/bbl

was felt that a case with higher tariffs should be examined given the risk

volved for the asset owners. A case where the Victory owners received a

riff of 30p/mcf and other sub-hub assets owners received one of 20p/mcf was

xamined. The results are shown in Chart 29.

-25.58 Glenlivet 16.58 7.45 30p/mcf Laxford 27.43 16.13 30p/mcf 10 Torridon 16.48 6.37 30p/mcf Seonaid 0.20 -11.45 30p/mcf 10p/mcf 10p/mcf Laggan 291.37 174.68 30p/mcf 10p/mcf £1/bbl

10p/mcfCambo -1.25 -13.10 30p/mcf 10p/mcf

Rosebank 618.74 370.92 30p/mcf 10p/mcf 10p/mcf £1/bbl

Tormore P 0.00 -1.65 30p/mcf 1 5 £1/bbl

TCP

Cardu Prospe

It

in

ta

e

41

Chart 29

The results sh

Potential Real NPV of new fields using Victory Route $30/bbl and 28p/therm

, Tobermory 10p, Torridon 10p, Laggan 10p

80

0-2 eya

V

S liv gaa

fo

Tariffs : Victory 30p, Glenlivet 10p, Laxford 10p100

-40

-20

0

20

40

60

205/1 Fr

ictory

b F et

Glen Lag

L

nx

Torrd

£m

o ne of th field have ositive PVs a 0% u

e $30, 28p case, but Victory, the hub, has a negative NPV at 15%. The

pipeline costs are shown below

m).

Victory to St Fergus MCPO1 Alwyn North FLAGS Sage

24" 205.29 144.48 109.27 116.74 165.82 30" 259.22 182.30 137.76 147.21 209.29

w that all but o e s p N t 1 nder

th

general conclusion is that this Scenario is very unlikely to be viable.

In principle a communal pipeline from Victory could go to MCPO1, North

Alwyn, FLAGS or SAGE. The comparative

(£

r don

onaid

Tober

oriSe m

y

Camb

Roseban

k

Tormore

(Po )

Ta

(

mdhu

P)

Caperca

illie (P

)

Cardu (P

)

NPV 10% 15%NPV

42

As with the Laggan-based Scenarios cases were developed for those based on

ictory. They are not shown here because it was felt that the returns available

the owners of Victory for accepting the increased development and

ansportation risks were likely to be inadequate. The general conclusion is that

ll the Scenarios with Victory as hub are unlikely to be viable.

Option 4 - Seonaid as Hub

V

to

tr

a

6

) Scenario 4A – Seonaid as Hub and Modest Tariffs a

scenario would use Schiehallion, Clair and Seonaid as hubs. The fields

nking with Schiehallion would be the same us with the other scenarios.

s a hub Seonaid’s costs would also increase substantially (see table below) and

ere would be a different configuration of inter-field pipelines with different

ub-hubs. The configuration is shown in Chart 30.

This

li

A

th

s

Reserves mboe

Assumed Development Cost $/boe Capex £m Drill £m

Seonaid 34.75 10.37 128.61 71.62

43

Chart 30

Seonaid (34.75)

Cambo (35.2)

If Seonaid became a hub field there would be a considerable increase not only

in develop costs el ergus. A 30” pipeline would

cost £225.48m plus the increase in development costs. To achieve a return of

0% on the extra pipeline costs Seonaid would need to charge a tariff of around

3.22p/mcf, but this does not take any account of the extra development costs.

o achieve a 10% return on the incremental pipeline and

ment but in pip ine costs to St F

1

1

T development costs

Seonaid would have to charge a tariff of 23p/mcf.

With this scenario Rosebank would become one of the sub-hub fields and

requires an 18” pipeline.

Rosebank (338)

Tormore (4.1)

Cardu (20)

Glenlivet (22.8)

Laxford (15.64)

Tobermory (61.6)

Capercaillie (500)

Laggan (149)

205/10-2b(6.2)

Torridon (17.4)

Tamdhu (20.6)

Freya (31.7)Victory (14.8)

12" 69km £18.01m

16" 38km £13.36m

18" 62km £20.72m

16" 99km £31.68m

6" 9km £2.04m

12" 57km £15.21m

6" 25km £4.34m

18" 58km £19.51m

6" 15km £2.9m

18" 74km £24.35m

6" 47km £7.49m

2*6" 37km £12.11m

6" 34km £5.63m

44

Under this scenario Torridon would become one of the sub-hub fields. Torridon

needs a 6” pipeline to Seonaid for its own use costing £9.64m but as a sub-hub

field it requires an 18” pipeline costing £20.72m. To achieve a return of 10%

on the extra pipeline cost Torridon would have to charge a tariff of 2.7p/mcf.

However, with this tariff it fails the economic hurdle rate, and so Tamdhu,

Glenliv fo ry, Tober d Capercaillie gas would be stranded.

For viab rr eeds a tariff of at least 10p/mcf.

With this scenario Glenlivet would also become one of the sub-hub fields.

Glenlivet needs a 6” pipeline to Torridon for its own use costing £6.2m, but as a

sub-hub field it requires a 16” pipeline costing £13.36m. To achieve a return of

10% on the extra pipeline cost Glenlivet would have to charge a tariff of

2.4p/mcf. Toberm ub i o, and requires a 16”

pipeline for its own use.

ariff assumptions for Scenario 4A Seonaid Route 30/bbl and 28p/therm

£1/bbl Tobermory 20.29 -6.36 23p/mcf 10p/mcf 5p/mcf

ambo 17.49 1.68 23p/mcf

p/mcf 50p/bbl £1/bbl

rospect 15.82 4.73 23p/mcf 10p/mcf £1/bbl apercaillie

Prospect 728.25 356.36 23p/mcf 10p/mcf 5p/mcf 5p/mcf £1/bbl Cardu Prospect 28.18 20.23 £1/bbl

et, Lax

ility To

ory also acts as a sub-h n this scenari

rd, Victo mory an

idon n

T$

4A NPV 10%

NPV 15%

Tariff to Seonaid

Tariff to Torridon

Tariff to Glenlivet

Tariff to Tobermory

Tariff to Rosebank


205/10-2b 5.06 2.32 50p/bbl £1/bbl Clair Ph3 3.09 2.34 Freya 12.27 -1.41 23p/mcf Victory 9.00 2.42 23p/mcf 10p/mcf 5p/mcf Glenlivet 4.68 -2.81 23p/mcf 10p/mcf Laxford 16.49 7.89 23p/mcf 10p/mcf 5p/mcf Torridon 1.54 -6.21 23p/mcf Seonaid to SF 2.45 -40.43 Laggan 297.31 177.80 23p/mcf

CRosebank 654.31 396.44 23p/mcf £1/bbl Tormore Prospect -3.29 -5.04 23

5p/mcf

Tamdhu PC

45

Chart 31

Potential Real NPV of new fields using Seonaid Route $30/bbl and 28p/therm

Tariffs : Seonaid 23p, Torridon 10p, Glenlivet 5p, Rosebank 5p, Tobermory 5p

40

60

80

100£m

NPV 10%NPV 15%

-40

-20

0

5/10-2

bFreya

Victory

Glenlive

t

Lagg

an

Laxfo

d

Tor

20

20

rr

Se To

ridon

onaid S

F

berm

o y

Cambo

seban

k

more (

RoTor

P)

The results are shown in Charts 31. It is seen that all fields exce t Tormore

pass the 10% hurdle rate and obtain at least 10% on their incremental costs.

size o e

at un rate. his ca s much doubt on the viability of this

io.

n 4B o

p

The f th NPV to Seonaid is very small and becomes substantially

negative 15% disco t T st

Scenar

b) Sce ario – Se naid as Hub with Higher Tariffs.

a n th igher ta ffs was onsidered.

g onaid owners received 25p/mcf and other sub-

er m a d. Th results are shown in Chart 32 for the

p c al b ave pos tive NPV at 10% ize of

e

e NP o ubstantially negative.

Given the risks on the sset ow ers a case wi h ri c

Accordin ly, one where the Se

hub own s 10p/ cf w s examine e

$30, 28 ase. While l fields ar one h i s , the s

the returns to Seonaid are still v ry modest given the risks and at 15% discount

rate th V bec mes s

Tamdh

u (P)

Caperca

illie (P

)

C

P

ardu (

)

46

Tariff assumptions for Scenario 4B Seonaid Route $30/bbl and 28p/therm

NPV 10%

NPV 15%

Tariff toSeonaid

Tariff to Torridon

Tariff to Glenlivet

Tariff to Tobermory

Tariff to Rosebank


05/10-2b 5.06 2.32 50p/bbl £1/bbl Clair Ph3 3.09 2.34

reya 11.04 -2.38 25p/mcf ictory 6.66 0.46 25p/mcf 10p/mcf 10p/mcf lenlivet 13.23 4.10 25p/mcf 10p/mcf axford 13.99 5.81 25p/mcf 10p/mcf 10p/mcf orridon 0.76 -6.86 25p/mcf

eonaid to SF 17.53 -28.85 aggan 293.35 174.94 25p/mcf £1/bbl obermory 13.97 -11.26 25p/mcf 10p/mcf 10p/mcf ambo 16.13 0.61 25p/mcf ose 651.43 394.32 25p/mcf £1/bbl ormore rosp -3.55 -5.26 25p/mcf

10p/mcf 50p/bbl £1/bbl

amdhu ct 15.45 4.43 25p/mcf 10p/mcf £1/bbl

apercaillie Prospect 724.31 353.63 25p/mcf 10p/mcf 10p/mcf 10p/mcf £1/bbl

ardu ct 28.18 20.23 £1/bbl

4B 2

FVGLT

SLTCR bank

ect TPTProspeC

CProspe Chart 32

Potential Real NPV of new fields using Seonaid Route $30/bbl and 28p/therm

Tariffs : Seonaid 25p, Torridon 10p, Glenlivet 10p, Rosebank 10p, Tobermory 10p

80

100

£m

NPV 10%NPV 15%

40

60

-40

-20

0

20

205/1

0-2b

Freya

Victory

Glenlive

t

Lagg

an

Laxfo

rd

Torr CRose

Tormor

Tamd

Caperca

illiCar

idon

Seona

id SF

Toberm

oryambo

bank

e (P)

hu (P)

e (P)

du (P

)

47

In principle a communal pipeline from Seonaid could go to MCPO1, North

Alwyn, FLAGS or SAGE. The calculated costs are shown below. Calculations

were made th su ral

n t n he cos and risks to the Seonaid licensees, the option

Seon r

North FLAGS Sage Magnu8 105.5 152. 145.01

ephasing of WOS Field Developments

of e re lting returns but are not shown here. The gene

conclusio is tha , give t ts

of the aid hub is ve y unlikely to be viable.

Seonaid St 24" 17

Fergus8.62

MCPO1 133.28

£m Alwyn

s 139.6 4 48

30" 225.48 168.13 176.22 133.04 192.42 182.97 7. R

ve k field evelopments. The question of

i ent was slower (and

ly more realistic) was examined. The comparative timings are shown

elow.

evelopment Fast Track Rephased lair PH 3 2006 2007 ictory 2008 2010

2010 axford 2008 2010

Torridon 2008 2010 eonaid 2007 2010

rmory 2008 2010 lenlivet 2008 2010 05/10-2b 2008 2009 ormore 2008 2010 amdhu 2008 2010 osebank 2007 2008 ambo 2008 2012 apercaillie 2007 2009 ard 2008 2012 aggan 2006 2006

The abo analysis was based on fast-trac d

whether the ullage problem m ght be less if developm

probab

b

First DCVFreya 2007 L

STobeG2TTRCCC u L

48

With constant real prices and costs rephasing would not generally change the

individual field NPVs to the base year of first development. Where a field is a

tariff receiver, however, there would be some change in the NPV attained if

there is a lag in the timing of the tariff revenues received.

Two cases have been analysed with the above slower pace of development,

namely Scenario 1 (use of existing infrastructure) and Scenario 2A (Laggan

T e nc re cases. The results

he mo a n rt d

route). here is very littl differe e between the 2 phased

of t delling re show in Cha s 33 an 34.

Chart 33

Potential Gas Production from new fields WoS Scenario 1 $30/bbl and 28p/therm

Hurdle Rate : 10% No new Exploration

60

700

800

900mmcf/d

0

100

0

400

500

0

20 07 11 2013 2015 2017 2019 2021 2023 2025 2027 2029

20

300

05 20 2009 20

P ts Fa krospec st Trac SD Fast Track Prospects Rephased SD Rephased

49

Chart 34

The

he peak has shifted but the ullage problem with the WSGPS and the Magnus

Brent link remains.

ullage problem is shown for the rephrased Scenario 1 in Charts 35 and 36.

T

to

Potential Gas Production from new fields WoS Scenario 1 $30/bbl and 28p/therm


800

9001000

mmcf/d

0

700

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

100

200300

400500600

Fast Track Rephased

50

Chart 35

WSGP Potential Ullage Scenario 1 Rephased

$30/bbl and 28p/therm Hurdle Rate :10%

0

200

400

600

800

1000

1200

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d

Future WoS Tech Res WoSProspects New Exploration WoSUllage Net of existing users Low Debottlenecked Ullage High Debottlenecked Ullage

Chart 36

M1200

mmcf/dagnus to Brent Potential Ullage 1 Rephased

$30/bbl and 28p/therm Hurdle Rate: 10%

0

200

400

600

800

1000

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

Future WoS Tech Res WoSProspects New Exploration WoSUllage Net of existing users Debottlenecked Ullage

51

The FLAGS ullage problem (Chart 37) also remains. In fact the problem may

e worse when the technical reserve fields are rephased because the FLAGS

wners are likely to attempt to use the capacity and the gas will most likely be

btained from Norway.

hart 37

b

o

o

C

FLAGS Potential Ullage 1 Rephased $30/bbl and 28p/therm

Hurdle Rate : 10%

0

500

1000

1500

2000

2500

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d

Exp. Tech Res EoS Potential Tech Res EoS Tech Res WoSProspects Norwegian New ExplorationUllage net of existing users

52

The production profiles for case 2A are shown in Charts 38 and 39.

Chart 38

Potential Gas Production from new fields WoS Scenario 2A $30/bbl and 28p/therm


0

100

200

300

400

500

600

700

800

900

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d

Prospects Fast Track SD Fast Track Prospects Rephased SD Rephased

Chart 39

Potential Gas Production from new fields WoS Scenario 2A $30/bbl and 28p/therm


0100

200300

400500

600700

800900

1000

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d

Fast Track Rephased

53

The ullages for the rephased case 2A is shown in Charts 40, 41 and 42.

here is still a problem with lack of capacity in the Alwyn North link.

Chart 40

Alwyn North Potential Ullage Scenario 2A Rephased $30/bbl ane 28p/therm

Hurdle Rate : 10%

0

100

200

300

400

500

600

700

800

900

1000

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d

Future WoS Tech Res Laggan Route Prospects Laggan RouteNew Exploration WoS Ullage net of existing users

T

Chart 41

Frigg Potential Ullage Scenario 2A Rephased$30/bbl and 28p/therm

Hurdle Rate : 10%

0

500

1000

1500

2000

2500

2005

2007

2009

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

mmcf/d

Exp. Tech Res EoS Potential Tech Res EoS Future WoSTech Res Laggan Route Prospects Laggan Route NorwegianExploration WoS Ullage net of existing users

54

The Frigg ullage problem is greatly reduced, but there is again the possibility

at gas from Norway may book the available capacity before the WOS fields

hart 42

he SAGE route, from the ullage viewpoint, now looks more plausible.

owever, the route has the disadvantage of distances and it is questionable

hether the fields would be willing to pay the SAGE transportation tariff,

hich lowers the NPV for all of them except Laggan, or take the gas directly to

t Fergus via a dedicated pipeline.

. Independent Communal Pipeline Company

th

are ready.

C

SAGE Potential Ullage Scenario 2A Rephased$30/bbl and 28p/therm

Hurdle Rate : 10%

0

200

400

600

800

1000

1200

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

mmcf/d


T

H

w

w

S

8

quite different possibility is that a communal pipeline would be owned and

eveloped by an independent pipeline company i.e. separate from the licensees

nd engaged only in the transportation business. Such a company would be

A

d

a


55

taxed at 30% with capital allowances on 25% declining balance basis, compared

to 40% (and soon to be 50%), with capital allowances on 100% first year basis.

It is also possible that an independent company would have a lower cost of

apital, though this would depend on fairly secure long-term contracts being

h the producers.

he case examined in detail corresponds to Scenario 2A above i.e. the

ommunal pipeline from the Laggan area direct to St. Fergus. A range of

ossible minimum returns to the independent pipeline company were calculated,

amely 12.5%, 10% and 8%, all in real, post-tax terms. (In money-of-the-day

rms 8% corresponds to around 10.5%). Under the $30, 28p case it was found

at to obtain a 12.5% real, post-tax return a tariff of 22p/mcf would be required

all the fields went ahead. Unfortunately, two fields, Glenlivet and Torridon

iled to obtain their minimum acceptable returns, and Victory and Laxford gas

ould become stranded. In the absence of these fields the NPV at 12.5% real

r the independent pipeline becomes negative. The results are shown in Chart

3 and the accompanying table.

c

agreed wit

T

c

p

n

te

th

if

fa

w

fo

4

56

Chart 43

$30/bbl and 28p/therm

£m

Potential real NPV of new fields using Independent pipeline $30/bbl and 28p/therm, Tariff 22p

Hurdle : 10% 000

Tariff assumptions for Independent pipeline to St Fergus from Laggan Route

dependent NPV 10%

NPV 15%

Tariff toLaggan

Tariff to Torridon

Tariff toGlenlivet

Tariff to Tobermory

Tariff to Independent pipeline


205/10-2b 7.21 4.46 50p/bbl £1/bbl Clair Ph3 3.09 2.34 Freya 10.62 -2.78 3p/mcf 22p/mcf Victory 5.99 -0.10 3p/mcf 12p/mcf 10p/mcf 22p/mcf Glenlivet -0.25 -6.72 3p/mcf 12p/mcf 22p/mcf Laxford 13.28 5.22 3p/mcf 12p/mcf 10p/mcf 22p/mcf Torridon -15.90 -19.24 3p/mcf 22p/mcf Seonaid 17.08 1.81 3p/mcf 22p/mcf Laggan 208.46 101.51 22p/mcf £1/bbl Tobermory 31.77 1.85 3p/mcf 22p/mcf Cambo 15.84 0.33 3p/mcf 22p/mcf Rosebank 654.73 397.46 3p/mcf 22p/mcf £1/bbl Tormore Prospect 0.96 -0.83

3p/mcf 50p/bbl 22p/mcf £1/bbl

Tamdhu Prospect 16.85 5.52 3p/mcf 22p/mcf £1/bbl Capercaillie Prospect 732.52 359.32 3p/mcf 5p/mcf 22p/mcf £1/bbl Cardu Prospect 28.18 20.23

£1/bbl

Pipeline -14.40 -37.05

In

-6-4-2

2468

10

Pi

£m

0 0 0 00

peline

205/1

0-2b

ClairFreya

Victory

Glenlive

t

Laxfo

rd

Tor

0

ridon

Seona

id

Toberm

ory

Cambo

Roseban

kgg

an

Tormore

(PLa

)

Tamdh

u (P)

Caperca

illie (P

)

Cardu (P

)

NPV 10% NPV 15%

57

If the minimum required rate of return for the independent pipeline company

ere 10% in real, post-tax terms a tariff of 19.5p/mcf would be required

rovided all the fields went ahead. Unfortunately Torridon again fails to meet

inimum return and, with Laxford and Glenlivet gas being stranded as a

consequence, the pipeline company has a negative NPV at 10% in real, post-tax

terms. The results are shown in Chart 44 and the accompanying table.

hart 44

w

p

its m

C

Potential real NPV of new fields using Independent pipeline $30/bbl and 28p/therm, Tariff 19.5p

Hurdle : 10%

-80 -60

0

00

80100

£m

-40 -20

2046

Pi 05pel

/10-ine 2

2

bCl

Fair

re rya

Victoy

Glenlive

t

Laxfo

rd do

Torri

n

Sn

eoaid

Toberm

ory

Camboan

Rosebk

Lagg

an

Tormore

(P)

Tamdh

u (P)

Caerc

aie (

P

p

lli)

Cardu (P

)

NPV 10% NPV 15%

58

Tariff assumptions for Independent pipeline to St Fergus from Laggan Route $30/bbl and 19.5p/therm

Independent

£m NPV 10%

NPV 15%

Tariff toLaggan

Tariff to Torridon

Tariff to Glenlivet

Tariff to Tobermory

Tariff to Independent pipeline


205/10-2b 7.21 4.46 50p/bbl £1/bbl Clair Ph3 3.09 2.34 Freya 12.16 -1.58 3p/mcf 19.5p/mcf Victory 6.83 0.60 3p/mcf 12p/mcf 10p/mcf 19.5p/mcf GL

lenlivet 0.98 -5.69 3p/mcf 12p/mcf 19.5p/mcf axford 14.17 5.96 3p/mcf 12p/mcf 10p/mcf 19.5p/mcf

-1.01 -6.67 3p/mcf 19.5p/mcf 18.77 3.14 3p/mcf 19.5p/mcf

aggan 213.39 105.09 19.5p/mcf £1/bbl rmory 34.61 4.04 3p/mcf 19.5p/mcf

ambo 17.55 1.67 3p/mcf 19.5p/mcf Rosebank 658.32 400.12 3p/mcf 19.5p/mcf £1/bbl

ore Prospect 1.06 -0.76

3p/mcf 50p/bbl 19.5p/mcf £1/bbl

dhu ct 17.31 5.91 3p/mcf 19.5p/mcf £1/bbl

ct 733.34 359.89 3p/mcf 5p/mcf 19.5p/mcf £1/bbl ardu

pect 28.18 20.23 £1/bbl line -35.62 -55.87

he minimum acceptable return for the independent pipeline company were

% real, post-tax (i.e. 10.7% in MOD terms) the tariff required would be

7.7/mcf if all the fields went ahead. In this case all the fields do pass the

inimum hurdle. The results are shown in Chart 45 and the accompanying

ble.

Torridon Seonaid LTobeC

Torm

TamProspeCapercaillie ProspeCProsPipe

If t

8

1

m

ta

59

Chart 45

p ent p peline to St Fergus from Laggan Route d 2

Tariff to Tanker

0.23 -5.62 3p/mcf 17.7p/mcf 19.98 4.09 3p/mcf 17.7p/mcf

aggan 220.85 110.64 17.7p/mcf £1/bbl rmory 36.65 5.62 3p/mcf 17.7p/mcf

Cambo 18.78 2.64 3p/mcf 17.7p/mcf Rosebank 660.91 402.03 3p/mcf 17.7p/mcf £1/bbl Tormore Prospect 1.12 -0.70


Tamdhu Prospect 17.64 6.18 3p/mcf 17.7p/mcf £1/bbl Capercaillie Prospect 733.93 360.30 3p/mcf 5p/mcf 17.7p/mcf £1/bbl Cardu Prospect 28.18 20.23 £1/bbl Pipeline -19.74 -58.59

Tariff assum$30/bbl an

tions fo8p/therm

r Independ

i

Potential real NPV of new fields using Independent pipeline $30/bbl and 28p/therm, Tariff 17.7100

05/10

£m p

Independent NPV 10%

NPV 15%

Tariff toLaggan

Tariff to Torridon

Tariff to Glenlivet

Tariff toTobermory

Independent pipeline

Loading Tariff

205/10-2b 7.21 4.46 50p/bbl £1/bbl Clair Ph3 3.09 2.34 Freya 13.26 -0.70 3p/mcf 17.7p/mcf Victory 7.27 0.97 3p/mcf 12.5p/mcf 10p/mcf 17.7p/mcf Glenlivet 1.85 -4.94 3p/mcf 12.5p/mcf 17.7p/mcf Laxford 14.64 6.34 3p/mcf 12.5p/mcf 10p/mcf 17.7p/mcf TorridonSeonaidLTobe

Hurdle : 10%

-80 -60 -40 -20

020406080

Pip2

eline -2b Cla ir

FreyaictV

ory

Glenlive

t

Laxfo

rd

Torrido

n

Seona

id

Toberm

ory

Cambo

Roseban

k

Lagg

moan

re (P)

Tor Tamdh

u (P)

Capeill

rcaie

(P)

Cardu (P

)

NP 10%V NPV 15%

60

It is noteworthy that under the $40, 36p scenario the independent pipeline

ompany can obtain returns of 12.5% in real, post-tax terms with a tariff of

2p/mcf as all the fields pass their minimum hurdle at these oil/gas prices. The

sults are shown in Chart 46 and the accompanying table.

hart 46

c

2

re

C

Potential real NPV of new fields using Independent pipeline $40/bbl and 36p/therm, Tariff 22p

Hurdle : 10%

20

40

60

80

00

Pipeline

205/1

0-2

£m1

0

bClair

Freyaicto

ry

Gnlive

txfo

rdrid

oneo

naid

rmor

V le La Tor STob

e

y

Camboban

k P

Rose Lagg

an

Tormore

( )

Tamdh

u (P)

Caperca

illP

ie ( )

Cardu (P

)

NPV %10 NPV 15%

61

Tariff assumptions for Independent pipeline to St Fergus from Laggan Route $40/bbl and 36p/therm

£m Tariff toTariff to Tariff to Tariff to IndepeIndependent NPV 10%NPV 15% Laggan Torridon Glenlivet Tobermory

Tariff to ndent

pipeline


05/10-2b 22.35 17.68 50p/bbl £1/bbl 5.64 4.63 59.87 35.93 3p/mcf 22p/mcf

ictory 33.19 22.63 3p/mcf 12p/mcf 10p/mcf 22p/mcf lenlivet 40.73 27.47 3p/mcf 12p/mcf 22p/mcf axford 41.87 28.94 3p/mcf 12p/mcf 10p/mcf 22p/mcf orridon 29.24 18.59 3p/mcf 22p/mcf

71.08 44.26 3p/mcf 22p/mcf aggan 412.44 250.84 22p/mcf £1/bbl obermory 123.41 72.41 3p/mcf 22p/mcf ambo 70.54 43.32 3p/mcf 22p/mcf osebank 1182.53 787.74 3p/mcf 22p/mcf £1/bbl

ore rospect 10.01 6.94

3p/mcf 50p/bbl 22p/mcf £1/bbl

Tamdhu rospect 59.97 41.68 3p/mcf 22p/mcf £1/bbl

rospect 1447.46 862.65 3p/mcf 5p/mcf 22p/mcf £1/bbl ardu rospect 73.01 58.04 £1/bbl

31.32 4.89

imilarly, if the minimum return for the independent pipeline were 10% in real,

ost-tax terms a tariff of 19.5p/mcf would suffice and all the fields would pass

eir minimum hurdle. The results are shown in Chart 47 and the

ccompanying table.

2Clair Ph3 Freya VGLTSeonaid LTCRTormP

PCapercaillie PCPPipeline

S

p

th

a

62

Chart 47

um or nd ipeline to St Fergus fr m Laggan Route nd 3 m

£m Tariff to Tanker

3 3p/mcf 12p/mcf 19.5p/mcf Laxford 42.77 29.68 3p/mcf 12p/mcf 10p/mcf 19.5p/mcf

orridon 30.21 19.40 3p/mcf 19.5p/mcf 72.77 45.58 3p/mcf 19.5p/mcf

aggan 417.94 254.77 19.5p/mcf £1/bbl obermory 126.29 74.62 3p/mcf 19.5p/mcf ambo 72.24 44.66 3p/mcf 19.5p/mcf osebank 1186.15 790.41 3p/mcf 19.5p/mcf £1/bbl ormore rospect 10.10 7.02


amdhu rospect 60.44 42.07 3p/mcf 19.5p/mcf £1/bbl apercaillie rospect 1448.28 863.22 3p/mcf 5p/mcf 19.5p/mcf £1/bbl

rospect 73.01 58.04 £1/bbl 3.41 -20.11

Tariff ass ptions f Indepe ent p o $40/bbl a 6p/ther

Potential real NPV of new fields using Independent pipeline $40/bbl and 36p/therm, Tariff 19.5p100

-2

Hurdle : 10%

-40 -20

0204060

80

Pip20

5/elin 10

e

Independent NPV 10%

NPV 15%

Tariff toLaggan

Tariff to Torridon

Tariff to Glenlivet

Tariff toTobermory

Independent pipeline

Loading Tariff

205/10-2b 22.35 17.68 50p/bbl £1/bbl Clair Ph3 5.64 4.63 Freya 61.41 37.14 3p/mcf 19.5p/mcf Victory 34.05 23.34 3p/mcf 12p/mcf 10p/mcf 19.5p/mcf Glenlivet 42.01 28.5

TSeonaid LTCRTPTPCPCardu PPipeline

bCla

Freyir a

Victory

Glenlive

t

Laxfo

rd

Torrn

Seona

iido

d

Toberm

ory

Camo

osebanb

R

£m

N

k

Lagg

To

anre

(P

orm

)

Tamdh

u (P)

Capeill

rcaie

(P)

Cardu (P

)

PV 10% NPV 15%

63

While the reduced rate of tax payable by an independent pipeline company has

ome effect it is clear that the viability of the entire activity is very sensitive to

e required rate of return of the company and the associated level of tariffs.

. Summary and Conclusions

s

th

9

his study has examined the economic aspects relating to a possible

omprehensive development of the known gas discoveries and prospects for

t of Scotland. Nineteen discovered fields and 4 prospects were identified.

e are virtually all gas but others are associated with oil, and some are

redominantly oil. The combined gas reserves are estimated at around 3 tcf

ith the average size being quite small. Given the scattered location of the

elds over a large area, and the hostile operating environment, with resulting

igh unit development costs, the economic exploitation of these reserves

infrastructure

(b) processing facilities adds greatly both to the technical

and econom ha es also

s a l n ptions. T te oth to the

rtati u emes. study various

rela o anding f the gas at St. Fergus were examined.

lu infrastructure (including its possible

ti and EOS areas Thus th um of the

sys o ie to Sullom Voe to Magn am The

e e s from Magnus to Brent/FLAGS to St. Fergus

d t I addit on the ble us North

/Frigg UK, and the SAGE systems were examined. Further, a new

sy ir WOS to St. Fergus was considered.

T

c

Wes

omS

p

w

fi

h

represents a considerable challenge. The relatively undeveloped

of (a) pipelines and

ic c

ntial

lleng

to the

. The

challen

long d

ge.

istance to a recognised gas market

adds substa ly

There i arge ra ge of possible development o hese rela b

transpo on ro tes and the development sch In this

options ting t the eventual l o

These inc ded maximum use of existing

augmenta on) both in the WOS . e maxim use

existing tem f r Sch hallion us was ex ined.

use of th xisting pipeline system

was inclu ed in he study. n i possi further e of

Alywn

pipeline stem d ect from

64

With respect to the fields in the WOS area various possible development

options were examined, including fixed platforms, FPSOs, TLPs, and sub-sea

systems. For FPS systems both purchase and lease options were considered.

he system which appeared most suitable for the size of reserves, water depth,

host fields was chosen. Consideration had

lso to be given to the initial processing of the gas when it was associated with

was possible to estimate the likely ullage in

ll the main pipeline systems which might take additional gas from the WOS

T

and location in relation to possible

a

oil. Generally it was assumed that much initial processing would be undertaken

on the field. The field development costs reflected the associated costs. Where

no pipeline was readily available oil was assumed to be evacuated by tanker

loading.

The economic analysis was undertaken by financial simulation modelling

backed up by a large field database incorporating key data on production, and

development and operating costs for sanctioned fields and those currently under

active consideration for development. In addition a less comprehensive

database incorporating fields in the technical reserves category was employed.

The financial modelling also included possible new discoveries in all areas of

the UKCS. From this modelling it

a

area. The financial modelling was undertaken for 3 price scenarios namely

(a),$20, 18p, (b) $30, 28p, and (c) $40, 36p all in real, 2005 terms. The results

for the fields are shown in terms of NPVs at 10% and 15% in post-tax real

terms. In MOD terms this corresponds to 12.75%, and 17.875% post-tax at the

inflation rate employed. The work was undertaken prior to the Pre-Budget

Statement of the Chancellor that the tax would be increased and the results

reflect CT + SC at 40%.

65

With respect to the Scenario involving maximum use of the existing

infrastructure enhanced facilities in the Clair Area involving some synergy with

the existing facilities were assumed. The relatively shallow water depth was a

main consideration here. A new, but short, pipeline link to the existing

Schiehallion gas pipeline would also be required. The results of the modelling

indicated that, if adequate ullage was available, WOS, EOS and to St. Fergus

the fields would generally be marginally acceptable at 10% real discount rate.

Several would fail at 15% real discount rate. When the ullage issue was also

considered it was found that there was inadequate capacity both in the

Schiehallion – Sullom Voe – Magnus pipeline systems and in the system from

agnus to FLAGS to St. Fergus to accommodate the volumes from the fields. M

This remained the case even when significant augmentation of the WOSGPS,

EOSGPS and the Magnus – FLAGS systems were included. With respect to the

FLAGS system a major issue is the distinct possibility that substantial volumes

of Norwegian gas will use it and pre-empt gas from WOS.

The study then considered the idea of a separate, communal pipeline system

emanating from a hub in the WOS area and coming to St. Fergus either directly

or via tie-ins to existing pipeline systems, namely at Alwyn North, MCPO1,

FLAGS (direct tie-in), and SAGE. The first hub examined was at the Laggan

field. This is the largest in terms of reserves. The modelling proceeded on the

basis that the Laggan owners would develop the new separate pipeline and

change tariffs to all the other fields as users. A working assumption was that

the asset owners would require post-tax rate of return of 10% in real terms on

any incremental pipeline costs. This assumption would apply to sub-hub

owners as well.

66

The modelling found that under the $30, 28p case it was possible to find

combinations of tariffs which left positive NPVs at 10% on the individual fields

and satisfied the stated conditions for the asset owners for the system involving

a pipeline direct to St. Fergus. But the size of the NPVs was often quite small.

Under the $40, 36p case there was some additional margin for the field owners,

but the NPVs at 15% were still sometimes unlikely to be acceptable.

When the modelling examined the prospective returns to field and pipeline

owners for schemes linking into North Alwyn, MCPO1 and FLAGS it was

found that, while there could be reductions in the pipeline costs problems of

ullage in the Frigg UK and FLAGS pipelines re-emerged.

The study then examined the possibilities of using Victory and Seonaid as hubs.

They were chosen because of their location in relatively shallow water and on

transport distance minimisation grounds. But both of these fields have small

serves and their employment as hubs would entail major increases in re

investment costs. The modelling examined a direct communal pipeline to St.

Fergus and the other options discussed above in relation to Laggan as a hub.

It was found that, under the $30, 28p case, while it was possible to find a

combination of tariffs which produced positive NPVs for the fields and gave the

asset owners a 10% real post-tax return on their incremental costs, the size of

the returns to the asst owners was quite modest. Generally they failed to

produce 15% real post-tax returns. The downside risks would, therefore, be

high and these options were felt to be less attractive than the hub based on

Laggan.

67

The modelling was based on a fast-track pace of development for the gas fields

in the WOS area. A case where the pace was rephrased was examined to

ascertain whether this would make the use of the existing infrastructure more

plausible. Even with a significant rephrasing it was found that the ullage

problem was likely to be present. A significant rephrasing of field

developments may also make the development of a communal pipeline system

ore difficult. The asset-owners will have to wait a longer time before

5% declining balance

asis. It is also possible that the cost of capital might be relatively low if

his

inimum return. A similar result emerged when the required minimum return

m

receiving tariffs from some of the user fields.

Finally, the idea of an independent communal pipeline system was examined.

This would attract tax at 30% with capital allowances on 2

b

substantial long-term contracts were secured. The case examined in detail was

a pipeline from Laggan direct to St. Fergus. The modelling indicated that,

under the $30, 28p case, the requirement of a 12.5% real post-tax return by the

pipeline owner (15.3% in MOD terms) would result in tariffs being such that

some of the new fields would become uneconomic at 10% real, post-tax

discount rates. The result was that the asset-owner did not achieve

m

of the asset owner was 10% in real, post-tax terms (12.75% in MOD terms).

When the asset owner’s minimum return was 8% in real, post-tax terms (10.7%

in MOD terms) it was found that tariffs could be levied which would leave the

field owners with positive returns at 10% in real, post-tax terms. Under the $40,

38p price scenario there is distinctly more scope for the achievement of

minimum acceptable returns to both field and asset owners.

68

The overall conclusion is that under the price scenarios likely to be employed

by investors the comprehensive development of gas from WOS is only

marginally attractive. Substantial extra discoveries would, of course, greatly

facilitate development by making the returns to a cluster development and

communal pipeline more attractive. If the expected exploration in 2006 and

2007 produced discoveries in the 1-2 tcf range the economic prospects would be

greatly enhanced.

The study was conducted before the Pre-Budget Statement announcing that the

tax on new fields such as are examined here is to be increased from 40% to

50%, an increase of 25%. This generally reduces the field returns in terms of

NPVs by 16.67%. The already marginal returns under the $30, 28p case

become even more marginal. The tax system itself does not cause a positive

pre-tax return to become negative after tax. But on a risk basis the chances of a

return becoming very small are increased by the proposed tax change. Thus the

chance of a project having a chance of an unacceptably low return are increased

by the tax change.

The tax increased applies to tariff incomes. This study has shown that the

returns to fields are very sensitive to the tariffs which are payable. In many of

the Scenarios relatively low tariffs were necessary to ensure that field

developments took place. The increase in the tax on tariff income by 25% may

cause upward pressure on tariffs by asset owners which could further jeopardise

the development of the fields. In this respect there is a further advantage to the

independent pipeline company.

69

The overall conclusion is that the comprehensive development of the gas

discoveries in the WOS is very marginal at gas prices likely to be employed for

long-term investments. The attainment of a cluster development involving

many fields demands a very high degree of cooperation among licensees.

Success is also likely to depend on tariffs which do not produce high returns to

the asset owners. The proposed tax changes certainly do not help to promote a

comprehensive development. Given all the challenges it is possible that

iecemeal developments will occur with the economically most attractive fields p

leading the way using existing infrastructure, while many small fields are left

undeveloped for a long time. A comprehensive development is likely to require

a combination of strong leadership and initiatives by both Government and

industry.

70

NORTH SEA STUDY OCCASIONAL PAPER No. 100 Options … · NORTH SEA STUDY OCCASIONAL PAPER No. 100...

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Transcript of NORTH SEA STUDY OCCASIONAL PAPER No. 100 Options … · NORTH SEA STUDY OCCASIONAL PAPER No. 100...