Oil & Gas UK Economic Report 2014

ECONOMIC REPORT 2014 OIL & GAS UK

ECONOMIC REPORT 2014

Contents

ECONOMIC REPORT 2014

Designed and produced by The Design Team at Oil & Gas UK.

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Foreword

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Industry at a Glance

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Oil and Gas Markets

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The UK’s Continental Shelf

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5.

PILOT

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Case Studies for New Investment

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– West of Shetland

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The Supply Chain, Employment and Skills

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8. a. b. c.

Appendices

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The Fiscal Regime for Oil and Gas

Oil Recovery

Glossary of Terms and Abbreviations

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Foreword

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1. Foreword

Oil & Gas UK’s Economic Report 2014 is the definitive guide to the current health and future prospects of the offshore oil and gas industry in the UK. Oil & Gas UK is the country’s leading trade body for the offshore oil and gas industry, and data provided by its members, along with information from the Department of Energy & Climate Change, form the basis of this new report. The debate around Scottish independence has focused attention on this country’s offshore oil and gas resource like never before. It rightly highlighted the industry’s critical role as a major contributor to economies both north and south of the border. This industry is a multi-billion pound investor, a provider of hundreds of thousands of skilled, well paid jobs and an exporter of high value oilfield goods and services around the globe. It generates significant revenues and, crucially, gives this country a secure supply of primary energy. Today, we depend on oil and gas for some 70 per cent of our primary energy needs and oil and gas from the UK supply 50 per cent of that. The people of Scotland have decided that Scotland should remain part of the United Kingdom. Oil & Gas UK’s responsibility is to continue to work closely with both the UK and Scottish Governments towards our shared ambition of maximising the economic recovery of our offshore oil and gas resource. There is much work to do. In 2013, we saw capital investment on the UK Continental Shelf (UKCS) reach £14.4 billion, its highest in three decades. Such massive expenditure will, for a while at least, halt the decline in production we have seen in the North Sea for the last consecutive 14 years. There is clearly life still on the Continental Shelf. Companies are investing and those investments are paying off. Yet here is the paradox. Behind this encouraging news lies an urgent need for substantially more exploration to discover the untapped sources that will feed the future development of newoil and gas fields. Only 15 exploration wells were drilled in 2013. That number needs to increase substantially. Equally concerning are the industry’s rising costs. Every pound invested in the UKCS yields only about one fifth of the return achieved ten years ago, and as the industry in the UK must compete for investment in a global marketplace, our current situation is simply not sustainable. How can we reverse this pattern? Oil & Gas UK sees the need for three remedies all of which need to be urgently applied.

First, we need to see radical change to our industry’s fiscal regime. We need a lighter tax burden, a simpler and more predictable system of field allowances, and fiscal support for exploration. Time is not on our side. The outcome of the Fiscal Review, due to be announced in December, needs to be relevant, radical and robust. Second, we need to see prompt and full implementation of the Wood Report recommendations, all of which have been accepted in full by the industry and both governments. Third, our industry needs to tackle the cost, efficiency and productivity challenges which are now bearing down on us. This report underscores some of these challenges. Production efficiency has experienced a significant decline, falling on average from 80 per cent in 2004 to close to 60 per cent in 2012. Unit operating costs are now 62 per cent higher than they were as recently as 2011. It will take bold and purposeful action to redress the balance on costs and secure a sustainable future. Nothing should be considered to be off limits. Collaboration will be the key to our success. Maximising recovery from the UKCS is the collective responsibility of all those who fund, regulate, tax and operate the offshore oil and gas industry. It also involves getting assets into the right hands, which demands a swift resolution to the current market overhang on disposals. Achieving our full potential will require a tremendous effort on the part of industry, the regulators and both governments. A stronger production profile will reap benefits too for the industry’s extensive supply chain across the UK. Data published earlier this year show that the UK supply chain provides jobs for almost half a million people and exports almost £15 billion a year in oilfield goods and services. Collaboration is key here too if we are to strengthen our supply chain businesses in all parts of the United Kingdom. Our industry makes far too important a contribution to the economic and energy security of the nation to be allowed to falter. Luckily we have strong foundations but we cannot stand still. We must embrace change and continue to invest for the future.

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MalcolmWebb Chief Executive, Oil & Gas UK

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Industry at a Glance

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2. Industry at a Glance

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The following summarises the key findings of Oil & Gas UK’s Economic Report 2014 . Figures below refer to 2013, unless otherwise stated.

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Security of Supply • Oil and gas provided more than 70 per cent of the UK’s total primary energy, with oil for transport and gas for heating being dominant in these markets. • In2030, 70per cent of theUK’s total primary energy is still expected to come from oil and gas, according to the Department of Energy & Climate Change (DECC). • If the current rate of investment is sustained, the UK’s Continental Shelf (UKCS) would continue to satisfy close to 50 per cent of the UK’s oil and gas demand in 2020 (>50 per cent for oil, <50 per cent for gas). Economic Contribution • Production of oil and gas boosted the balance of payments by some £30 billion. • Offshore oil and gas remained the largest investing sector and the largest contributor to national gross value added (GVA) among the industrial sectors of the economy. • The supply chain in the UK generated over £20 billion of sales from the UKCS (in 2012). • In addition, almost £15 billion of supply chain sales were in the export of goods and services (again, in 2012).

Oil and Gas Prices • The price for Brent oil averaged $109 per barrel, slightly lower than the averages of $112 in 2012 and $111 in 2011. • The oil price was remarkably stable throughout the year, with dated Brent crude oil trading mainly in a narrow range of $105-110 per barrel. • The day-ahead gas price at the National Balancing Point (NBP) rose to an average of 68 pence per therm (p/th) from 60 p/th in 2012. • The combined oil and gas price for UKCS production was, on average, $90 per barrel of oil equivalent (boe); it was $89 per boe in 2012. Production • Production declined by eight per cent from 2012 to 524 million boe, or 1.44 million boe per day 1 , a decline rate about half of that in 2011 and 2012. • The UK remained the second largest producer of oil in Europe, after Norway, and the third largest producer of gas, after Norway and the Netherlands. • The UK also remained in the top 25 global producers of both oil (25th) and gas (22nd), despite the sharp decline in production in recent years.

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1 N.B. These are net production figures, after deducting the industry’s own consumption.

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Total Expenditure (in 2013 money) • Total expenditure on the UKCS rose by over 20 per cent to almost £26 billion, with capital investment accounting for more than half of the increase. • Since 1970, the industry has spent £525 billion, comprising: o £330 billion of capital investment in exploration drilling and field developments • Total expenditure of up to £1,000 billion will be required over the remaining life of the UKCS, if recovery of oil and gas is to reach the upper end of the range forecast under ‘reserves’. Capital Investment on Developments • Capital investment was £14.4 billion, the highest on record. • Oil & Gas UK expects capital investment to remain above £10 billion a year in 2014 and 2015, assuming that new projects continue to be developed as anticipated. • DECC approved capital investment of £8 billion in ten new fields. • Total capital investment committed to new field developments and brownfield projects (fields already in production) totalled £39 billion at the end of 2013. o £192 billion on production operations £3 billion on decommissioning assets that have ceased production o

Operating Costs • Total operating expenditure rose by 15.5 per cent to £8.9 billion. • Unit operating costs (UOCs) also continued to rise, to an average of £17 ($26.5) per boe. • The number of fields with a UOC greater than £30 per boe doubled during the year. Taxation • The industry paid £4.7 billion in corporate taxes on production in 2013-14. • Since 1970, the industry has paidmore than £316 billion (in 2013 money) in such taxes. Reserves • Almost 43 billion boe of oil and gas have been recovered from the UKCS so far. • Further overall recovery is forecast to be in the range of 15-24 billion boe. • Considering the full range of opportunities available, current investment plans have the potential to deliver 10.7 billion boe in total: o 6.6 billion boe from existing fields or those currently under development

About four billion boe from new field and incremental developments which have not yet been approved

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New Developments • Thirteen new fields came on-stream, bringing 392 million boe into production. • DECC approved ten new fields, which will yield 460 million boe of production over time, as well as 26 brownfield projects of various sizes. Drilling Activity • The number of wells drilled (including sidetracks) was: o 15 exploration wells o 29 appraisal wells o 120 development wells • Twenty exploration and appraisal wells were postponed and four were cancelled because of difficulties in securing rigs and/or finance. • Some 80 million boe of recoverable resources were discovered, taking the total to only 100 million boe since the start of 2012.

Employment • The industry supported some 450,000 jobs, many highly skilled and well paid, across the whole economy, with: o 36,000 employed by operating companies o 200,000 employed in the supply chain o 112,000 in jobs induced by the economic activity of the above employees Decommissioning (in 2013 money) • Decommissioning expenditure was around £900 million and is likely to rise to an average of £1.3 billion per year for the rest of this decade, with a peak of £1.7 billion in 2016. • Some 475 installations, 10,000 kilometres of pipelines, 15 onshore terminals and 5,000 wells will eventually have to be decommissioned. • From 2014 to 2040, £37 billion is forecast to be spent on decommissioning of existing assets. • Expected new investment in future developments would add £3.6 billion to the total, although much of this expenditure will be after 2040. o 100,000 in the export of goods and services

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Editorial Notes: • A Glossary of Terms and Abbreviations is included in the Appendix. • The drafting of this report was undertaken during June and July 2014.

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Oil and Gas Markets

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3. Oil and Gas Markets

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Oil Markets and Prices

from the average in 2012. Dubai prices also showed a $3/bbl decline, but the average price of West Texas Intermediate (WTI, the standard quality of crude oil for trading in the USA) at Cushing, Oklahoma, gained $4/bbl as new domestic pipelines from the mid-continent andwest Texas to the Gulf Coast alleviated the over-supply of light crude in the mid-continental region. Gradually, the distortions in international crude oil prices seen from 2011 to 2013 are being corrected (see Figure 1 below). The forward month discount of WTI to dated Brent narrowed from $17/bbl in 2012 to $11/bbl in 2013 and by mid-2014 it had settled in the $5-8/bbl range.

Crude oil prices in 2013 and 2014 have been high, but unusually stable. Brent, the benchmark for most internationally traded crude oil, has for most of these two years been trading within a range of $100-115 per barrel (bbl). Indeed, it has become easy to think of Brent prices in this range as ‘normal’, even though history shows that price stability is typically short lived in oil markets. Indices of daily volatility of Brent prices were again exceptionally low. In 2013, dated Brent averaged $109/bbl, down $3/bbl

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Figure 1: Monthly Crude Oil Prices from January 2008 to June 2014

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Dated Brent WTI Cushing Dubai

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Behind this unusual Brent price stability lie significant changes in the worldwide balance between demand and supply in 2013 and some large-scale supply disruptions, especially in the Middle East and North Africa. These were largely offset by the continued rise in production of US light, tight oil (LTO). Oil markets tightened moderately in 2013 as the rise in demand (+1.2 million barrels per day (mb/d)) exceeded the growth in supply (+0.6 mb/d) and reported inventories of crude and products, in turn, declined. However, on the supply side, US crude oil production, driven by tight oil plays, rose by 1.1 mb/d in 2013, exceeding ten mb/d for the first time since 1986. This pace of growth of LTO production has continued in 2014 and few observers of the US ‘shale revolution’ are willing to anticipate a halt in this remarkable story. In volumetric terms, the increase in US LTO in 2013 offset the major supply disruptions in North Africa and the Middle East which have beset the oil market since the onset of the Arab Spring in 2011. Libyan output fell by 0.5 mb/d in 2013 while Iranian output declined by a further 0.2 mb/d due to international sanctions. After record production in 2012, Saudi Arabia curbed its crude output in 2013 to 9.4 mb/d, as it sought successfully to balance the world market. Since it is not possible to export US crude oil (except under licence in restrictive circumstances), rising LTO production has been reflected mainly in fewer US seaborne imports of crude oil, increased exports of oil products and wide fluctuations in intra-US crude price spreads until the domestic pipeline network has responded to the new sources of production.

The competitive advantage for US Gulf Coast refiners due to rising LTO production has put additional pressure on European refiners who are already facing a progressive decline in demand for their products. In 2013, an additional 0.3 mb/d of distillation capacity was closed in Europe, bringing the closures since the end of 2010 to 1.5 mb/d. As mentioned, relatively low price volatility characterised North Sea crude oil markets in 2013 and the first half of 2014. Persistent disruption to low sulphur Libyan oil exports supported these North Sea crude prices, although the influence of Korean demand was more subdued than in 2012. Crude oil production continued to decline in 2013 in both Norway and the UK to 1.46 mb/d and 0.80 mb/d, respectively. The combined output from the Brent market’s four component streams (Brent, Forties, Oseberg and Ekofisk) fell to 0.9 mb/d. Encouragingly, recent production data from the UK and Norway indicate that crude oil output has stabilised in the first six months of 2014 compared with the same period in 2013. In recent years, Forties’ higher sulphur content has meant that it is normally the grade that sets the price of dated Brent. However, in 2013, the reporting agencies revised their pricing methods to reflect all four component streams, leading to a more diverse assessment of dated Brent and more frequent trading of non-Forties grades. If Brent is to retain its key benchmark status in international markets, further reform of the Brent assessment process may be necessary in future years. Exchange rates were relatively stable in 2013. The average US$/£ rate moved marginally from 1.585 in 2012 to 1.564 in 2013, which means that the price of Brent crude oil

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Figure 2: Nominal and Real Brent Prices from 1970 to 2013

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Brent Price (Nominal) Brent Price (Real)

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Source: BP Statistical Review 2014, World Bank

expressed in sterling was almost unchanged at £69.50/bbl for the year. However, over the course of 2013, sterling steadily appreciated against the dollar, a trend which continued in the first half of 2014. By mid-2014, the $/£ exchange rate stood at 1.70, the highest since the onset of the financial crisis in 2008. This will have put pressure on upstream margins of late, given the exposure of UK Continental Shelf (UKCS) producers to costs denominated in sterling.

natural gas markets are more regional in nature, but are increasingly linked by price responsive flows of liquefied natural gas (LNG). The wholesale gas market in Britain at the National Balancing Point (NBP) reflects supply and demand conditions in the closely integrated markets of north west Europe. In 2013, NBP prices continued their steady recovery from the recessionary low in 2009. Reform and re-negotiation of continental term contracts and the post-Fukushima tightness of world LNG markets both again served to tighten the north west European market in 2013 amid near-stagnant demand in the UK and the Eurozone. Month ahead NBP averaged 67.1 pence/therm (p/th) in 2013 ($10.50 per million British Thermal Unit), the highest

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Gas Markets and the National Balancing Point

Oil markets are truly international with inter-regional trade flows of crude and products on a very large scale. In contrast,

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demand, progressive renegotiation of long- term, oil-indexed import contracts and the recent strengthening of sterling. This demand-led weakness in NBP and continental hub prices has been all the more remarkable because it has occurred against a background of conflict in Ukraine, growing tension between Russia and western nations, and a tightening of economic sanctions against Russia (but not specifically against its gas industry). Russia supplies about one quarter of the gas consumed in Europe, about half of which is delivered by pipeline through Ukraine. Fears of an interruption to Russian gas supplies, reminiscent of the two-week disruption in

annual figure (in both nominal and real terms) since the emergence of the NBP hub market in the mid-1990s. The brief spike in NBP prices in each of the two previous winters had raised fears of a repeat in the winter of 2013-14, but the mild weather confounded expectations, depressing demand throughout Europe and leaving gas stocks in underground storage unusually high at the end of March 2014. As a result, prompt hub prices have fallen to their lowest for four years. Day ahead gas at the NBP dipped below 40 p/th during June and July 2014 and the forward price for winter 2014 2 gas fell below 60 p/th under the influence of weak European

Figure 3: Daily National Balancing Point Prices from January 2010 to June 2014

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2 ‘Winter’ in this context refers to the six-month period from October to the following March, in this case from October 2014 to March 2015 inclusive. The forward price is, therefore, the amount agreed in advance to be paid for gas to be delivered during this six-month period.

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January 2009, may yet play an important role in price formation for winter 2014-15. UK gas demand decreased by 1.1 per cent to 77.9 billion cubic metres (bcm) in 2013. This is the lowest since 1995 when the ‘dash for gas’ was in full swing. The UK mean temperature in 2013 (8.7 degrees Celsius) was almost identical to that in 2012 and in line with the long-term average; the only unusual feature was the exceptionally cold March at the end of the winter 2012-13 which provoked a spike in NBP prices. Gas demand from the domestic sector (mainly households) in 2013 was almost unchanged at 31.3 bcm. Demand from industry and the service sector increased slightly, but for generating electricity it fell by six per cent to 18.6 bcm; only 27 per cent of the UK’s electricity was generated from gas. As recently

as 2008, gas use in electricity generation was 34.3 bcm, representing 48 per cent of total UK generation. This sharp contraction in gas-fired generation is due to the decline in electricity demand to its lowest since 1998, the wide fuel cost advantage enjoyed by coal since 2011 and the steady rise of subsidised renewables to 15 per cent of total generation in 2013. A further contraction in gas use occurred in the first half of 2014, suggesting that stabilisation of gas-fired generation may have to await either further coal plant closures or a recovery in power demand. The exceptionally mild and windy weather in early 2014 and the reduction in gas-fired generation in the first half of this year indicate that UK gas demand in 2014 may turn out to be less than 75 bcm.

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Figure 4: UK Gas Demand by Sector from 1995 to 2014

Domestic Industrial Electricity Generation Other Sectors Services

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UK Gas Demand (Billion Cubic Metres)

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Gas production from the UK’s Continental Shelf (UKCS) has been in decline since 2000 at an average annual rate of eight per cent. In 2013, gross production fell by a further six per cent to 38.8 bcm. Nevertheless, despite this steady reduction in output, indigenous production still met 50 per cent of the UK’s demand in 2013 and there are signs that the rise in dependence on imports will moderate in the next few years, unless demand recovers strongly. It is unlikely that onshore shale gas exploration will make a material contribution to indigenous production before 2020. Net imports of gas have stagnated since 2010 at 38-39 bcm a year, as demand has fallen in line with the decline in domestic production. There have, however, been significant changes in the origin of imports and in the size of pipeline exports in response to fluctuations in the world LNG markets. Indeed, the UK’s supply patterns are highly sensitive to the state of the LNG market because of the lack of imports by pipeline under term contracts,

the extensive regasification capacity (for LNG) in the UK and the liquidity of the NBP market. LNG imports rose from ten bcm in 2009 to 25 bcm in 2011, but then steadily fell to 9.4 bcm in 2013 as demand in higher value markets in Asia and Latin America diverted supply away from north west Europe. UK exports to the continent via the Interconnector pipeline reached a corresponding peak in 2011 of 9.3 bcm before falling to just 2.5 bcm in 2013. As new sources of LNG supply emerge from Australia and the US Gulf Coast from 2015 to 2017, there may be some alleviation of the post-Fukushima tightness of LNG markets. However, the impact on trade flows and price formation is still highly uncertain. The exceptional inter-regional price spreads prevailing since 2011 may ease, but the NBP market is still expected to set the reference value for supplies of LNG in the Atlantic basin that are not under contract.

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Figure 5: Benchmark Regional Gas and Liquefied Natural Gas Prices from January 2010 to June 2014

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4. The UK’s Continental Shelf

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The Wood Review

The the recommendations of the Wood Review and announced that the new, better resourced regulator will be called the Oil and Gas Authority. At the time of writing (July 2014), this new regulator is in its formative stages, with DECC undertaking the necessary legislative steps and sourcing of a chief executive. government has accepted Output from the UKCS did not peak until the year 2000, confounding all predictions when production of North Sea gas and, subsequently, oil began from the West Sole field in 1967 and the Argyll field in 1975, respectively. Although production has declined steadily since, the UKCS continues to satisfy around half of domestic oil and gas demand and is expected to continue to supply close to 50 per cent in 2020. Reserves and Resources

In June 2013, the British Government commissioned an independent review of the UKCS, to be led by Sir Ian Wood, with the objectives of examining the main factors affecting the industry’s current performance and making recommendations for achieving maximum economic recovery of oil and gas. An interim report was published in November 2013 and the final report 3 in February 2014. The review’s principal recommendations were that: i. The government (HM Treasury, as well as the Department of Energy & Climate Change (DECC)), the industry and a new regulator should develop and commit to a tripartite strategy for maximising the economic recovery of oil and gas from the UKCS (to be known as MER UK). ii. An arm’s length and properly resourced regulator should be created and charged with the stewardship of the UKCS’ resources and regulation of the industry so as to achieve MER UK. iii. The industry should commit to a high degree of collaboration on the UKCS.

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3 The final report, UKCS Maximising Recovery Review , is available to download at www.woodreview.co.uk

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Figure 6: Cumulative Reserves Discovered and Produced

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Cumulative Reserves Discovered and Produced

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Almost 43 billion barrels of oil equivalent (boe) have been recovered over the past 46 years – 28 billion boe of oil and 15 billion boe of gas. In that time, the UKCS has changed from being dominated by a small number of very large fields in the 1970s and 1980s to a highly diverse oil and gas province of some 300 producing fields in the southern, central and northern North Sea, the Irish Sea and, more recently, west of Shetland. Regarding the future recoverable potential from the UKCS, DECC has numbers as low as 4.5 billion boe for fields in production or under development through to 34.5 billion when considering the fullest exploration potential. Taking into account the range of possibilities for undiscovered and potential additional resources (PARs 4 ), together with discovered reserves, DECC’s current best forecast of the remaining recoverable oil and gas is between 11 and 21 billion boe. Oil & Gas UK believes the remaining recoverable reserves are still Future Opportunity

from 15-24 billion boe, but acknowledges that the recent lack of exploration success and slow rate of bringing discovered resources through to maturity as recoverable reserves demonstrate how difficult it will be to reach the upper end of these ranges. Even if no further capital investment is sanctioned, Oil & Gas UK expects a further 6.6 billion boe to be produced, around two thirds from the 300 fields currently in production and one third from new fields under development. In addition, companies are considering investments to produce a further 2-5.5 billion boe of reserves. New developments account for 1-3 billion boe of this, with a further 1-2.5 billion boe due to potential, incremental investment in existing fields. This takes the remaining recoverable reserves of the UKCS to 8.5-12 billion boe, representing resources for which there is a significant degree of certainty of recovery.

4 Potential additional resources (PARs) are those associated with existing fields, as distinct from undiscovered or yet-to-find (YTF) resources.

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More uncertain are the PARs in existing fields and yet-to-find (YTF) resources; these are much harder to evaluate. Oil & Gas UK believes that the UKCS has PARs of up to 3.5 billion boe, of which there is slightly more oil than gas, and YTF resources of 3-9 billion boe, again with slightly more oil than gas. Oil & Gas UK forecasts that over £1,000 billion of expenditure (in 2013 money) – encompassing exploration and appraisal (E&A) drilling, capital investment, operating and decommissioning costs – will be required

if the upper end of our remaining resources, that is above 20 billion boe (see Figure 7), are to be recovered in the fullness of time. It is essential that government and industry work together to create the right fiscal and regulatory environment for the necessary investment to be made in the UKCS, hence the significance of the tripartite strategy, MER UK. It should be noted that this report does not consider potential onshore shale gas or oil resources. The relevant organisation for this subject is the UK Onshore Operators’ Group 5 .

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Figure 7: Forecast of UK Continental Shelf Reserves and Resources (as at the end of 2013)

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Yet-to-Find 3-9 bln boe

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Potential Additional Resources 1-3.5 bln boe New Field Reserves 1-3 bln boe Brownfield Reserves 1-2.5 bln boe Existing Fields and Sanctioned Investments 6.6 bln boe

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How Should Maximum Economic Recovery of Resources Be Achieved? A variety of plans and initiatives are in place with the aim of achieving maximum economic recovery of oil and gas from the UKCS. If the full 6.6 billion boe of sanctioned reserves are to be recovered, production efficiency will need to improve to ensure that fields are not closed and decommissioned prematurely. There are further resources trapped inside these fields that are not currently considered recoverable, even with established methods for improved oil recovery (IOR) 6 . However, with evolving techniques for enhanced oil recovery (EOR) 7 , reserves to be extracted from existing fields could increase. New technology will play a crucial role, as it has done throughout the life of the UKCS. There have been various examples of how technical advances have helped to develop fields over 20 years after their discovery. Oil & Gas UK is aware of more than 150 projects that are seeking investment and have yet to receive sanction; it is important these are brought through to development. A high, stable oil price has provided the right background for this investment, but, without significant advances in technology over the past ten years, the development of fields such as Stella, Cygnus, Mariner and Kraken would not have been possible. Assuming the UKCS remains an active region for exploration for another 20 years, total volumes discovered will need to average 150 million boe per year in order to find Oil & Gas UK’s low estimate of three billion boe of YTF resources (as shown in Figure 7). This is significantly larger than is being discovered currently (see Exploration and Appraisal Drilling on p42). An Exploration Task Force

under PILOT (see Section 5) is examining the reasons behind the shortfalls in E&A drilling and its poor success rate. Exploration potential remains in all the main areas of the UKCS, most significantly carboniferous gas in the southern North Sea (SNS), ultra-high pressure, high temperature reservoirs in the central North Sea (CNS), heavy oil in the northern North Sea (NNS) and deep water oil and gas to the west of Shetland (WoS). The rate of decline in production slowed to just eight per cent in 2013, a significant improvement on the 19 per cent and 15 per cent experienced in 2011 and 2012, respectively (see Figure 8 opposite). As a result, the UKCS produced an average of 1.44 million boe per day (mboepd) during 2013, or 524 mboe for the whole year. This comprised 315 mboe of liquids (oil and natural gas liquids (NGLs) – 60 per cent of the total) and 209 mboe of gas (40 per cent). Production of liquids and gas was nine per cent and six per cent lower, respectively, than in 2012. The slowing in the rate of decline in production during 2013 was largely because 13 new fields came on-stream, including Jasmine, a large condensate field, and there was significant incremental investment in existing fields, as well as notable improvements in production from large fields such as Buzzard and Bruce. Existing assets produced 11 per cent less, which reflects the natural decline of reservoirs in a mature oil and gas province, partly offset by the positive effects of incremental (or brownfield) investments. Figure 9 opposite illustrates the changes in production between 2012 and 2013. Production

6 See Appendix b for an explanation of the three main phases of recovering oil from a reservoir. 7 See Section 5 for more details about EOR.

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Figure 8: UK Continental Shelf Production Decline Curve

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-9.4%

-5.1%

2.5

2

- 19.2%

-6.5%

2.0

-7.7%

-14.5%

1.5

3

1.0

Oil and Gas Production (Million boepd)

0.5

4

0.0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Source: DECC, Oil & Gas UK

5

Figure 9: Production Changes from 2012 to 2013

6

1.8

Increased Production from 2012-2013 Start-ups and Re-starts

Production Decline in Existing Fields

7

1.6

Fields Shut-in/Cessation of Production

-0.17

1.4

0.07

-0.02

8

1.2

1

1.44

1.56

0.8

2013 Production

2012 Production

0.6

Production (Million boepd)

0.4

0.2

0

Source: DECC, Oil & Gas UK

31

ECONOMIC REPORT 2014

Performance for the first half of 2014 has been encouraging, with DECC’s figures indicating a one per cent increase in production compared with the same period in 2013. Output of liquids has risen by 1.7 per cent, but that of gas has fallen slightly, albeit by just one per cent. There are two main reasons for this welcome improvement: i. Following a number of years of major investment, new fields are having a material effect on production, particularly Breagh, Huntington and Jasmine. More than ten per cent of production in 2014 is expected to come from fields that came on-stream in 2013 or 2014. ii. Since the start of last year, production has re-started on Elgin-Franklin (following a gas leak), Gryphon (weather damage) and

the Penguins cluster (loss of export route), all of which produced well below capacity in the first half of 2013 after being shut for extended periods. The final figures for production in 2014 will largely depend upon the industry’s performance during the summer maintenance season. Figure 10 shows the traditional dip in output during the summer months as various installations and pipelines are closed for maintenance, upgrading or modification to accommodate a new field being tied into existing facilities. Even when accounting for this expected drop in production, provisional data for the year so far suggest that, for the first time since 2000, there is a reasonable chance that there will not be an overall decline in UKCS production.

Figure 10: Monthly Production Trends from 2010 to 2014

90

2010 2011 2012 2013 2014

80

70

60

50

40

30

20

Monthly Production (Million boe)

10

0

Source: DECC, Oil & Gas UK

32

ECONOMIC REPORT 2014

If Oil & Gas UK’s central production forecast (shown in Figure 11) is to be realised, the development of new fields will continue to be crucial. Large projects such as Clair Ridge, Schiehallion (a re-development) and Mariner are all expected to come on-stream by 2017, and these three fields alone will be producing over 250,000 boepd (or some 17.5 per cent of 2014’s production) by the end of this decade. Although the expected impact of new fields on production in thenext fewyears isencouraging, the performance of existing fields will have to improve markedly for the strategy of MER UK to be realised in the longer term. There are a number of factors that will influence production beyond the end of this decade and industry and government need

to work together to create the right fiscal and regulatory framework to ensure that: • Typical field recovery rates are improved by harnessing EOR techniques • The UK offers an environment that encourages brownfield investments to recover more reserves and postpone decommissioning • The UKCS remains an attractive destination for international investment in exploration for and the development of new opportunities • Advances in technology are appropriately supported to help extract the more difficult resources remaining on the UKCS

1

2

3

4

5

Figure 11: UK Continental Shelf Production – Actual and Forecast

6

4.0

3.5

7

Actual Production

3.0

8

2.5

Upper

2.0

Forecast Range

Central

1.5

Lower

1.0

Total Production (Million boepd)

0.5

0.0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Source: DECC, Oil & Gas UK

33

ECONOMIC REPORT 2014

Expenditure

Such was the scale of expenditure on the UKCS in 2013 that collective post-tax cash-flow was negative. This is the first time the UKCS has not generated a positive, post-tax cash-flow since 1992. Clearly this is not sustainable in the longer term. Although much of theexpenditure relates tocapital investment which, by its nature, is discretionary, the industry is seeking to manage its costs and increase revenues from production. i) Capital Investment Since the industry began in the North Sea during the 1960s, over £330 billion (in 2013 money) has been invested in E&A drilling and field developments. Figure 13 opposite shows how investment has gone through a number of peaks and troughs over the past 45 years. A surge of investment was required in the early years as some of the largest fields on the

Total expenditure on the UKCS was another record in 2013 with almost £26 billion being spent on the costs of seismic surveying, E&A drilling, capital investment, operations and decommissioning (see Figure 12). Expenditure has more than doubled over the last eight years because: • The development of large projects has attracted billions of pounds of capital • The cost of operating mature fields and their installations has risen rapidly • More technically challenging E&A wells are being drilled • More fields are approaching the end of their lives – cessation of production – and are starting to incur decommissioning expenditure

Figure 12: Total Expenditure on the UK Continental Shelf

35

Decommissioning

E&A Spend

Operating Expenditure

Capital Investment

30

Post-Tax Revenue

25

20

15

2013 Money

10

5

Total Expenditure/Post-Tax Revenue (£ Billion)

0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Source: DECC, Oil & Gas UK

34

ECONOMIC REPORT 2014

UKCS, such as Leman, Forties, Brent, Beryl and Ninian were being developed. The next big peak was in the aftermath of the tragic Piper Alpha disaster of 1988, when the industry implemented the recommendations of Lord Cullen’s investigation and report, and there was a further surge of investment in new fields. Another peak came in 2008 when the oil price surpassed $140/bbl, and investment in 2013 reached a record high of £14.4 billion. It should be noted, however, that, although Figure 13 is in constant (2013) money, it has been produced using national inflation rates from the Office of National Statistics (ONS). There is no recognised inflation index applicable only to this industry, whose costs have not generally followed the national economic cycle; were there such an index, the relative heights of the peaks in Figure 13 would probably be different.

Capital investment of £14.4 billion last year was some £3 billion higher than the previous record set just 12 months earlier. Oil & Gas UK believes 2013 will be the peak year for capital investment, although it will remain above £10 billion during 2014 and 2015, before falling to £7-8 billion a year by the end of the decade. In recent years, there have been a small number of very high value opportunities available on the UKCS. Figure 14 overleaf illustrates that the top five such investments have typically accounted for around 30 per cent of annual capital expenditure over the past three years, each of them holding significant value and containing at least 100 million boe of recoverable reserves. They are, though, technicallychallenginganddifficult to access.

1

2

3

4

5

6

Figure 13: Capital Investment in the UK Continental Shelf since 1970 (in 2013 money)

16

7

14

12

8

10

8

6

4

Capital Investment (£ Billion) 2013 Money

2

0

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Source: DECC, Oil & Gas UK

35

ECONOMIC REPORT 2014

To complement these large investments, there has been a steady stream of small field and life-extending brownfield projects. It is crucial that these different types of investment remain competitive if the strategy of MER UK is to be achieved. Figure 15 opposite shows the extent of investment in a blend of both large and small opportunities during the last five years. Another significant factor leading to higher aggregate investment is the recent surge in development costs. Each pound now yields about one fifth of that a decade ago and

the trend shown in Figure 16 opposite is not sustainable. The average unit development cost for a new field approved last year was over £17/boe and has been increasing at a rate well above inflation over the last ten years. Opportunities on the UKCS are simply becoming unattractive as capital costs continue to rise. Development of the Rosebank and Bressay fields, operated by Chevron and Statoil, respectively, has been delayed as investors look for alternative solutions following substantial increases in cost estimates.

Figure 14: Proportions of Capital Expenditure

16

14

12

10

8

6

All Other Investments

4

2

Capital Expenditure (£ Billion) 2013 Money

Top Five Largest Annual Investments

0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Source: Oil & Gas UK

36

ECONOMIC REPORT 2014

Figure 15: Total Investment by Year of Field Approval

14

12

1

10

8

2

6

Money of the Day

3

4

2

Total Capital Investment by Field (£ Billion)

4

0

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 (H1)

Year of Field Approval

Source: DECC, Oil & Gas UK

5

Figure 16: Average Unit Development Cost by Year of Project Approval

6

35

Maximum Average Minimum

7

30

25

8

20

15

10

5

Unit Capital Cost of New Developments (£/boe)

0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Source: DECC, Oil & Gas UK

Year of DECC Field Approval

37

ECONOMIC REPORT 2014

Few UKCS investments can proceed at today’s marginal tax rates of 62 per cent and 81 per cent. Since the Supplementary Charge (SC) to Corporation Tax was increased in the Budget of 2011, field allowances (FAs) have become essential vehicles for retaining investors’ confidence which would otherwise have been undermined by the lack of fiscal predictability. The review of the fiscal regime announced by the government in the Budget of 2014

provides a most timely opportunity to create arrangements that are far simpler than the current, complex combination of high tax rates and FAs 8 . Figure 17 illustrates this point all too clearly; an increasing proportion of future capital investment is dependent on receipt of FAs. It is also clear that the new regime will need to be capable of evolving, as the years go by, in pursuit of MER UK.

Figure 17: Capital Investment by Type of Field Allowance

16

14

12

10

8

Ultra HPHT

6

4 Capital Investment (£ Billion)

2

Not in Receipt of Allowance

0

2013

2014

2015

2016

2017

2018

Source: DECC, Oil & Gas UK

8 For full details of taxes and FAs applicable to the UKCS and how these interact, please refer to Appendix a.

38

ECONOMIC REPORT 2014

ii) Operating Expenditure The costs of operating assets on the UKCS reached a record £8.9 billion in 2013, 15.5 per cent higher than in 2012. Following a sharp rise in 2008 and then three years of largely stable operating costs, significant inflation occurred in 2012 and 2013. Oil & Gas UK believes that this rising trend will continue in 2014 and operating costs are forecast to surpass £9.5 billion.

1

The number of active fields on the UKCS continues to grow with 300 producing fields in 2013 compared with 278 in 2004. Economies of scale suggest that costs are likely to be lower if production can come from a smaller number of larger fields and, therefore, as the number of fields has increased, so have total operating costs.

2

3

4

Figure 18: Operating Expenditure on the UK Continental Shelf

12

5

10

6

8

6

Actual Forecast

7

4

8

2

Operating Cost - £ Billion (2013 Money)

0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Source: Oil & Gas UK

39

ECONOMIC REPORT 2014

Operating costs per field have also risen, particularly over the last three years. In 2011, the average cost of operating a field was £23 million compared with almost £30 million in 2013. Such rising costs become all the more concerning when put in the context of declining production in recent years. Not only have fields become more expensive to operate, but their output has fallen.

The net result is that the average unit operating costs (UOCs across the UKCS in 2013 are now 62 per cent higher (at £17/boe) than they were as recently as 2011 (£10.50/boe). See Figure 20 opposite. It should, however, be noted that there are still over 50 fields on the UKCS whose operating costs are less than £10/boe, while a growing number of fields, now as many as 19, have a UOC greater than £30/boe.

Figure 19: Average Operating Cost per Field

35

30

25

20

15

2013 Money

10

5

Average Operating Cost per Field (£ Million)

0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Source: DECC, Oil & Gas UK

40

ECONOMIC REPORT 2014