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OIL & GAS OUTLOOK PAGE 05

FRACASOVER UKFRACKING

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OIL & GASECONOMICFORECAST

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NEW LIFEFOR OLDFIELDS…

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Ȗ There have been few times in recent history when the oil and gas industry has not been at the centre of the global geo-political land-scape – and 2014 is no exception.

The Russian annexation of Crimea and continued instabil-ity in Ukraine has heightened Europe’s awareness of its reliance on Russia’s gas, while it faces a different threat from the other side of the Atlantic in the form of a competitive disadvantage caused by the United States’ shale gas revolution, which has slashed North American gas prices.

Although the situation is cur-rently calm in the major Middle Eastern production areas, unrest on the fringes of the region, in Syria, Egypt, Libya and Turkey, is among factors that have kept the global oil price above $100 a bar-rel for a prolonged period. Strong demand from emerging markets has been another factor. The high oil price has a double impact in Europe because gas prices are for the most part index-linked to the oil price.

In addition, most of the world’s oil reserves are now known and in the hands of national oil com-panies, leaving the Western oil companies to explore ever-more problematic resources either in

terms of their remote and difficult conditions (such as the Arctic), technically challenging (such as Brazil’s pre-salt reserves, Kazakh-stan’s Kashagan project, or even shale gas and oil) or politically vol-atile (Iraq). This means that find-ing and exploiting new reserves is becoming more challenging and more expensive.

At the same time, the industry faces a new challenge in the form of the increasingly certain evi-dence that fossil fuels are a major contributor to climate change, meaning that companies are com-ing under pressure from investors, governments and consumers to be aware of and reduce the envi-ronmental impacts of their opera-tions, which is also challenging and expensive.

Closer to home, the North Sea is a mature resource and output is falling significantly from year to year. Mirroring the global trend, much of the oil and gas that is left is remoter and more technologically challenging to exploit, particularly ultra-high pressure high-tempera-ture clusters.

Nonetheless, a study for Oil and Gas UK shows the upstream oil and gas supply chain remains a £35-billion industry with a strong export capability that employs

200,000 people, and that there remains around 24 billion barrels of oil still to be extracted from the North Sea basin. And indeed, there has been significant investment in the UK Continental Shelf in recent years, with inflows increasing from £11.4 billion in 2012 to £14.4 billion in 2013 and a further £13 billion foreseen this year, according to Oil & Gas UK’s Activity Survey 2014.

But as well as identifying the sig-

nificant opportunities for the UK industry – the UK is a recognised world leader in offshore oil and gas developments, with the expertise developed providing a competi-tive advantage for UK companies competing internationally, the survey says – it also identifies a number of threats, notably the difficulty of attracting and retain-ing skilled workers, and a lack of policy consistency that has seen the Chancellor of the Exchequer impose windfall taxes one year followed by tax breaks a year later.

Malcolm Webb, chief executive of Oil & Gas UK, says: “It is increas-ingly obvious that the offshore oil and gas fiscal regime has become overly complex, burdensome and uncompetitive. The industry faces marginal tax rates of 62 per cent – 81 per cent on oil and gas produc-tion – which are unsustainable in a mature basin.” The industry needs “a simpler regime more attuned to the industry’s challenges and better able to secure international investment in the many, varied opportunities that remain”.

According to Alex Milward, oil and gas advisory partner at EY,

there are significant opportuni-ties facing the UK oilfield services industry, but also barriers that must be overcome if growth is to be sustained in the sector. “Crucially, the attractiveness of the UK as a place to do business must be max-imised. Steps must also be taken to realise domestic and international demand for oilfield services, and to promote the industry to new tal-ent,” he says.

Another mirror of global trends is the climate of political uncer-tainty. In the UK’s case this is cre-ated by the forthcoming Scottish independence referendum, which has raised concerns for some in the sector, although any upheaval would be relatively minor com-pared to the risks that pertain in other markets.

Meanwhile, the industry has welcomed publication of the Wood Review of the future of the North Sea oil and gas industry, and the government’s acceptance of its recommendations, which include plans for a new allowance to encourage investment in ultra-high-pressure high-temperature (u-HPHT) oil and gas field clusters, that it is estimated could attract an extra £5 billion to £6 billion of investment to the North Sea.

Sir Ian Wood, the review’s author, says: “The UK offshore oil and gas industry has made an immeasurable and vastly under-estimated contribution to the UK economy over the past 50 years. This review provides the opportu-nity for it to face its next 30 years and beyond.”

The UK oil and gas industry remains the country’s largest industrial investor, but faces major challenges to maintain its potential to deliver significant wealth over the coming decades, writes Mike Scott OVERVIEW

OVERCOMING BARRIERS TO SUSTAIN SUCCESS

The upstream oil and gas supply chain remains a £35-billion industry with a strong export capability that employs 200,000 people

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ROHAN BOYLEFreelance business journalist with expertise in energy and the environment, he has a specific focus on renewables and sustainability, and contributes to Bloomberg New Energy Finance and Green Futures.

FELICIA JACKSONEditor at large of Cleantech magazine and author of Conquering Carbon, she specialises in issues concerning the transition to a low-carbon economy.

JIM McCLELLANDSustainable futurist, speaker, writer and social-media commentator, his specialisms include built environment, corporate social responsibility and ecosystem services.

MIKE SCOTT Freelance journalist, specialising in environment and business, he writes regularly for the Financial Times, The Guardian, Forbes and 2degrees Network.

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CONTRIBUTORS

Models of North Sea oil and gas rigs at the Norwegian Oil

Museum, Stavanger

OIL & GAS

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Changing asset integrity to meet the needs of the oil and gas industry

world’s floating production projects are planned.

Mr Constantinis explains the growth of EM&I: “When we started the business 30 years ago, we set out to be the world’s leading asset integrity service provider and this meant doing things differently. Rather than providing a commod-itised service, we chose to focus on high added value innovations. While this required greater investment, the growth in revenue and profits justifies our strategy.”

EM&I has always believed that strong partnerships with industry and regulators are key foundations for long-term success. Joint ventures and alliances with Odebrecht, Stan-tec, Bureau Veritas and others have proven the value to both EM&I and their partners. EM&I’s leadership of the HITS (hull inspection techniques and strategies) joint industry project is an example of how EM&I brought all sectors of the industry together to identify challenges and develop innovative solutions. One challenge was the need to reduce diver-based inspection of floating installation hulls which included floating production and mobile offshore drilling units.

ODIN™, EM&I’s Diverless UWILD (underwater inspection in lieu of dry-docking) is a major part of EM&I’s “No dry-dock” strategy. David Mortlock, EM&I’s chief techni-cal officer, explains: “Our Diverless UWILD methodology changes the way floating assets are inspected. We built a validation centre in the UK to demonstrate the new methodol-ogy to classification societies, regu-lators and operators.

“As a result, ODIN was success-fully implemented on two FPSOs [floating production storage and offloading units] in Brazil within a few months of it becoming avail-able. We are now planning a fleet-wide approach with one of the larg-est operators, and are negotiating contracts with several drilling con-tractors and floating LNG [liquefied natural gas] operators.”

ODIN is a complete hull structural integrity package comprising engi-neering, planning and site implemen-tation, including a patented means of

The number of floating offshore installations (FOIs) and mobile off-shore drilling units (MODUs) is increasing as oil and gas reserves are discovered in ever-deeper waters. Currently there are 333 FOIs and 700 MODUs in service or on order, a 69 per cent increase over the last decade. Many operational FOIs and MODUs are based in deep water, on long-life projects with no dry-dock intended for 25 years or more.

EM&I recognised the challenges that operators and owners of these increasingly complex units would have to face to ensure their assets complied with safety regulations while optimising production efficiency.

Chief executive of the EM&I Group Danny Constantinis believed that fundamental changes were needed in the way FOIs and MODUs were designed, operated, maintained and inspected to avoid the signif-icant penalties associated with unplanned dry-docking.

“The industry has recognised cost and lost production consequences when coming off station for many weeks to dry-dock” he says. “But no one had developed a holistic solu-tion that met the requirements of the operators, classification socie-ties and regulators.

“We have spent the last ten years developing and implementing a comprehensive ‘No Dry-dock… Safely’ package. This ensures com-pliance with regulatory and clas-sification society requirements, provides our clients with the tools to manage the integrity of their assets while on station and pro-ducing safely for extended periods, and we have reduced the number of people required to undertake the offshore element of the work.”

EM&I has been a best-in-class provider to the oil and gas industry for more than 30 years with addi-tional customer demand contributing to the company’s growth and geo-graphic expansion. Having previously established bases in North Amer-ica, South-East Asia, Australia and Northern Europe, EM&I has addi-tionally established bases and won long-term contracts in Brazil and West Africa where 43 per cent of the

inspecting critical safety valves, with-out divers while giving better quality and more accurate data on valve con-dition. EM&I’s life cycle and holistic capability of finding and fixing anoma-lies at an early stage helps operators run their plant efficiently and safely.

“EM&I’s diverless approach has changed the way this type of inspec-tion will be carried out in the future,” adds Alexander Constantinis, chief financial officer. “Our long-standing relationships with classification societies and regulators are a result of working together at all stages of the solution development. This brings benefits to the industry by

replacing the old periodic method of underwater inspections with the ODIN continuous approach.”

EM&I’s chief operating officer Pat Lawless comments: “We have been in the business for many years so have a clear understanding of what our clients need and how we can help solve their challenges. We con-tinue to conceive innovative solu-tions to improve asset integrity for high capital value projects. We work closely with classification societies, regulators and industry bodies, and understand the value and impor-tance of their input and acceptance.

“Our work with R&D organisations and knowledge of other industries expedites solutions. Our policy of continuous improvement, exploring new markets, and transferring our knowledge and expertise into other areas of the industry, keeps our people energised and motivated.”

EM&I is not standing still, as chief executive Mr Constantinis notes: “We have further developments underway and significant interest is being shown in another of our clas-sification society accepted innova-tions, HullGuard™. This diverless,

retro-fittable, impressed current cathodic protection (ICCP) system protects the hull against corrosion for an extended period and avoids the risk of having to dry-dock to repair coating or the hull structure.

“We have been managing gas plant integrity for many years and, with the requirement for politically stable supplies, it is a strong part of our business. Recent develop-ments in floating LNG production and regasification correspond well with our expertise, and we are working with these operators and classification societies to adapt our existing systems. In addition, we have developed new physics, in col-laboration with a number of univer-sities, to make sure we stay ahead of the game.”

For many in the oil and gas indus-try, EM&I’s name is synonymous with delivering integrity through innovation – and that fits very well with EM&I’s vision and culture.

For more information on the EM&I Group and its services go to www.emialliance.com

We have spent the last ten years developing and implementing a comprehensive ‘No Dry-dock… Safely’ package

Market leader in asset integrity management services to the oil and gas industry, the EM&I Group has seen increased demand for its services because of its innovative approach to solving challenges faced by the floating-production and drilling sectors

Ȗ Perfect for puns on placards and front pages, fracking is the media-friendly short-form name for hydraulic fracturing, the process of extracting shale gas from layers of rock by drilling down and injecting fluid at high pressure.

The technology has faced vocal and widespread opposition from “fractivists”, including public fig-ures and celebrities, from Green MP Caroline Lucas to Hollywood actor Mark Ruffalo, star of the Incredible Hulk.

The campaign against fracking is focused primarily on environmen-tal issues: big-picture concerns about climate-change impacts of fossil-fuel consumption; plus local-community fears for poten-tial groundwater contamination and air pollution.

The two most high-profile UK test-drilling locations have seen protesters marching in their thou-sands and camped on site. In North-West England, at Barton Moss, campaigners won a stay of eviction in March. Two month earlier, in the Sussex village of Balcombe, energy firm Cuadrilla announced it will not now frack the besieged site, due to unfavour-able geology.

These flashpoints have kept the bad-press bandwagon rolling since fracking-related earth tremors shook Blackpool in 2011.

Given such a controversial track record, has the global oil and gas industry been deterred from entry into the UK market? It most definitely has not, says founder, president and chief executive of

Texas-based Breitling Energy Corporation, Chris Faulkner – the self-styled “Frack Master” – who describes commercial attitudes and investor confidence as robust.

“The UK is likely to become the next shale revolution, and many companies are looking closely at the country as the government makes steps towards encouraging the industry through new trespass laws and tax incentives,” he says.

With strong positive signals from key political quarters, the business case is being built on emerging data. The numbers are big and get-ting bigger.

Recent reports from the British

Geological Survey have seen origi-nal estimates for total UK reserves revised upwards substantially to 1,300 trillion cubic feet (tcf ), lifting expectations for amounts which are economically recoverable. Additional data for the Bowland Basin region, which stretches from Cheshire to Yorkshire, now make it perhaps the largest such reserve in the world.

“It is early days, but the UK shows every sign of following the example of the United States,” says Mr Faulkner. “Estimates of recoverable oil and gas are being upgraded as more detailed sur-veys are conducted and test drill-ing completed.”

Taking a conservative recov-ery ratio of 10 per cent, fracking

advocates calculate 130tcf of gas extracted could provide anything up to 52 years’ UK supply.

If figures for reserves and recov-erability remain works in pro-gress, those quoted for poten-tial employment are open to even more debate. Estimates for jobs to be created have ranged from 74,000 (Cuadrilla), down to 24,000 (AMEC) and back up to 64,000 (EY).

A fracking boom had at one point also been touted by Prime Minister David Cameron as having “real potential” to drive UK energy bills down, only for the suggestion to be dismissed by economist Professor

Lord Nicholas Stern as “base-less economics”.

On the matter of price, chief scientist at Greenpeace UK Doug Parr argues it is vital to understand market differences either side of the Atlantic. “The situation in the US is radically different from the UK. We have much smaller land area to supply a denser population, stronger public environmental concerns and an open gas market. Conditions are the opposite of those in the US, where a fracking boom in a closed market led to a gas glut and collapse in prices,” he says.

“No energy expert sees the same price falls happening in Europe. The impact on gas costs is actu-ally likely to be marginal or non-existent.”

bility of fracking in the energy mix, might shale gas offer an interim means to wean the UK off coal addiction and reduce emis-sions in the medium term, while other, cleaner forms of generation, including renewables and nuclear, achieve critical mass?

According to Dr Parr at Green-peace, such pragmatism is not credible in terms of timeframes for delivery, even putting aside environmental concerns and social resistance. “Given that shale gas production will not become signifi-cant for well over a decade, it is no quick fix for anything. It will play little or no role in displacing coal out of the UK power system. Coal should be mostly gone by the time shale ever becomes substantial,” he says.

There is neither consensus nor compromise on how fracking will play out in the UK. Depending which side of the police cordon you stand, the potential is as strong as the protest. The only aspect on which both sides might agree is that the pitch, marketing fracking to communities, has been found wanting so far.

As Mr Faulkner concludes: “Gen-erally in Europe, the industry has handled the public relations very badly. The ‘bunker mentality’ of putting up barricades and getting on with it was not right. Engag-ing with communities, helping them understand shale explora-tion, fracking and the actual risks involved, hearing their views, is an approach used in the US, and it has worked.”

If little else about the future of fracking in the UK can be forecast with certainty, the local “sell” can be predicted to change. Expect a charm offensive.

TIME FOR A FRACKING CHARM OFFENSIVE?

It has split public opinion and tempers are still rising. Fracking for shale gas is a contentious issue, but supporters claim it holds huge potential benefits for the UK economy, as Jim McClelland reports

SHALE GAS

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Data for the Bowland Basin now make it perhaps the largest such shale gas reserve in the world

A police officer patrols the perimeter of the Cuadrilla

test drill site at Balcombe, West Sussex

1,300trnCUBIC FEET OF UK

SHALE GAS RESERVES

52 yearsOF UK SHALE GAS SUPPLY

Source: British Geological Survey

64,000UK JOBS TO BE

CREATED DIRECTLY AND INDIRECTLY BY

2032Source: EY

Fundamental differences between US and UK regulatory frameworks are also highlighted by Mike Pocock, a partner at law firm Pinsent Masons. “In the US there is no national statutory framework for land-use planning, except for certain environmental laws and some enabling legislation. By contrast, the UK has a statutory plan-led system subject to both local consultation and independ-ent examination. Nine separate applications make fracking one of the most regulated activities in the energy sector,” he says.

Blamed for exacerbating drought conditions in the US, water abstraction demands for fracking represent one issue where UK understanding has changed, as head of corporate affairs at Water UK Neil Dhot explains. “Overall, the potential amount of water needed in the fracking process was a big question raised very early on. However, all the studies and work we have seen in the last few months point to the amount of water needed being manageable,” he says.

So, looking at the strategic via-

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DECOMMISSIONING

Ȗ Production may have been in decline since 2000, but the final chapter in the North Sea oil and gas saga, that in which the vast assemblage of ageing platforms and pipes is pulled up and taken back to shore, has hardly begun.

The benefits to the UK from the once-prolific North Sea fields have been enormous. Between 1970 and 2012, it is estimated that the UK Continental Shelf (UKCS) produced 42 billion barrels of oil equivalent (boe), according to industry body Oil and Gas UK.

Although total recoverable reserves stand at somewhere between 15 and 24 billion boe, a growing number of ageing offshore installations will soon have to be decommissioned.

A strict legal framework of national, regional and interna-tional regulations governs what happens to offshore facilities at the end of their life.

In 1995, Royal Dutch Shell pro-voked widespread outrage with plans, approved by the UK govern-ment, to abandon the floating oil storage facility Brent Spar in deep Atlantic water.

The controversy led 15 European states, members of the Convention for the Protection of the Marine Environment of the North-East Atlantic, to ban “the disposal of offshore installations at sea, as well as requiring all the topsides of all installations to be returned to shore”.

Over the next 30 years, virtually all the oil and gas infrastructure on the UKCS will have to be removed from the sea and decommissioned on shore. This amounts to some

475 offshore installations of all types, 10,000 kilometres of pipes, 15 onshore terminals and 5,000 wells. Some 470,000 tonnes of material will have to be retrieved between 2013 and 2022 alone.

To put this in perspective, the contract for removal of nine plat-forms from the Norwegian Ekofisk oilfield, between 2008 and 2014, amounted to 113,500 tonnes or three times the weight of all the cabs in London.

Exactly how much all this will cost to implement is difficult to calculate as there are many unknowns and fluctuations. How-ever, Oil and Gas UK estimates the total will amount to £10.4 billion between 2013 and 2022, with the total bill climbing to a cumulative £31.5 billion by 2040. New invest-ment in probable developments would add £3.5 billion to the total,

but much of this would be incurred after 2040.

Not all this will have to be borne by the industry. The UK govern-ment will incur more than half the cost through a 50 per cent tax relief mechanism – 75 per cent for older fields – making the taxpayer one of the most important stakeholders in the process.

A view widely held in the indus-try, according to the Royal Acad-

emy of Engineering, is that a tax rebate to offset decommissioning expenditure was always an essen-tial condition of oil and gas compa-nies’ involvement in the North Sea.

Such is the importance of this measure that any hint of uncertainty over its future is enough to put off new investment in older fields and dissuade new market entrants.

The government therefore acted to bolster confidence last October when it issued the first decommis-sioning tax relief deeds to seven oil and gas companies operating in the North Sea. These guarantee the tax relief a company will receive, so that even if a future government makes tax changes they can still claim a “difference payment”.

Also recently, the government took steps to streamline the lengthy decommissioning process by issuing a standard template that will allow the regulator, the Department for Energy & Climate Change, to ratify plans more quickly and easily.

First to trial the template was BP with its Schiehallion decommis-sioning programme. “It took seven months from initiation to approval, compared to up to three years in the case of the Miller oilfield. Also, the document ended up only 42 pages in length. This equates to a

major saving in man-hours,” says Alistair Corbett, BP’s decommis-sioning projects manager.

With so many fields reaching the end of their life, there are rising concerns the supply chain has neither the capacity nor the work-force to handle the large, heavy offshore platforms.

“There’s an opportunity for us [the UK industry]. Billions of pounds of work is coming to us in the North Sea,” according to Trevor Garlick, head of BP’s North Sea operations. “At the moment, there is not the technical capac-ity or supply chain to meet it. We need to meet it, or Norway, Spain or others will.”

Current figures indicate that the UK faces a major shortage of the necessary skilled workers unless

there is a significant increase in engineering and technical gradu-ates as well as sustained retention of experienced workers within the industry.

As part of a push to fill this gap, the oil and gas industry skills body OPITO has launched a drive to recruit suitable ex-military personnel.

Innovation will also play a role in meeting the decommissioning challenge. Edward Heerema, chief executive of engineering group All-seas, is hoping a 382-metre-long, 124-metre-wide catamaran he commissioned will capture a large part of the business.

The giant craft, strong enough to lift four Eiffel Towers, is scheduled to set off from a South Korean shipyard later this year. The suc-cess of Mr Heerema’s $3-billion bet will depend on timing. He is hoping that oil companies will be queuing up for its services by the time it arrives in the North Sea.

Decommissioning represents a significant opportunity as well as a challenge for the UK off-shore oil and gas industry. The North Sea is not the only place that will be dismantling such infrastructure and the lessons learnt here could potentially be transferred abroad.

Removal of nine platforms from the Norwegian Ekofisk oilfield amounted to 113,500 tonnes or three times the weight of all the cabs in London

SINK OR SWIM AS WAVE OF DECOMMISSIONING APPROACHESOf the estimated £500 billion spent by the UK offshore oil and gas industry between 1970 and 2012, just £2 billion was channelled into decommissioning. The clean-up represents an enormous engineering challenge, one that will take decades and cost tens of billions, writes Rohan Boyle

Economicforecasting

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CASE STUDY

EX-MILITARY PERSONNELHELP BRIDGE SKILLS GAP

The UK oil and gas industry faces a skills shortage across all sectors and not just in the area of decommissioning. A report by OilCa-reers.com and Air Energi estimates that it will require more than 120,000 skilled personnel over the next decade to realise the full potential of renewed investment in the North Sea and recent shale discoveries.“Specialist disciplines are in very short supply. Graduate programmes are not attracting the right amount of people into the industry and, where good graduates are found, it’s often a case of too little, too late,” the report says. In a recent survey of the industry by Barclays Bank, 66 per cent of those polled highlighted the skills shortage as the biggest challenge facing the industry.At the same time, the armed forces are down-sizing, creating a potentially sizable source of new recruits. “We’re not going to find a lot of geologists or drilling engineers, but there will be quite a number of people in the military who we think have skills and qualifications that are transferable to our industry,” says Alix Thom, employment and skills policy manager at indus-try body Oil and Gas UK. “The armed services are a good source of tech-nicians, such as mechanics and electricians, while submariners are currently in demand for certain kinds of subsea work,” she says.The oil and gas industry is already a popular career choice for former soldiers, sailors and airmen, according to training standards body OPITO. Between 2011 and 2013, some 2,500 found jobs in the industry.“They are generally well trained, safety conscious and very dependable,” says Morven Spalding, skills development director at OPITO. “In addition, their work ethic and familiarity with operations allow them to fill jobs in all sectors of the industry, including offshore positions.” With 20,000 posts to go in the regular Army by 2020, on top of the 18,000 to 20,000 armed services leavers in any normal year, the number of potential recruits could increase.

To better co-ordinate the hoped-for jobs transfer, the government launched a nationwide programme last year run by the Ministry of Defence, Oil and Gas UK, plus OPITO and the Career Transition Partnership, which helps resettle demobbed service personnel. One of its top priorities is to increase the level of understanding, both of the experience and skills that ex-services personnel possess, and the skills that are needed in oil and gas. The scheme runs awareness events at military bases as well as training courses. Some of the larger oil and gas companies already run their own programmes targeting ex-military people. GE Oil & Gas holds career fairs aimed at the military and has what it calls a junior officers leadership programme, while Wood Group PSN runs a course that fast-tracks skilled technicians from the armed forces into the industry.Oilfield services company Petrofac is also actively recruiting ex-servicemen and women. It uses the Career Transition Partnership to iden-tify candidates who are enrolled on a training programme as a first step in their new careers. On successful completion of the course, they will go into permanent positions, with some ready to go offshore in just eight weeks.Starting salaries in the industry are between £35,000 and £40,000, according to Dominic Simpson, head of sales at industry website rigzone.com. “Lack of supply and increased demand for qualified staff is putting huge infla-tionary pressure on wages in the oil and gas industry,” says Kevin Forbes, chief executive of Oilandgaspeople.com. “There is a lot of press coverage around North Sea oil being in decline, but the truth is there is still 30 to 40 years left in the North Sea, and that estimate increases all the time as new fields are discovered and come online. Anyone looking to get into the industry now will enjoy a career that will easily last their lifetime,” says Mr Forbes.

Prime Minister David Cameron visits the Total Oil depot shale-drilling site in Gainsborough, Lincolnshire

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Ȗ Oil accounts for around 40 per cent of current global energy mix, with natural gas accounting for a further 23 per cent. While, under existing policies, the Inter-national Energy Agency (IEA) expects renewable energy genera-tion to double by 2035, world pri-mary energy demand is on track to increase 43 per cent over the same period.

BP estimates that renewable energy will make up 27 per cent of the growth in global energy supply to 2030, just ahead of growth in coal, at 26 per cent, and gas, at 21 per cent. So what does this mean for the oil and gas economy?

Marc van Loo, head of energy & utilities and senior investment analyst at ING Investment Man-agement, says: “Barring any new black-swan-like energy source, energy trends will cause some market share loss for fossil fuels, down from 87 per cent of primary energy supply today, but still remaining a material part of the primary energy mix within the next 25 years.”

Surprise black-swan events could be economic, technologi-cal or political. A decade ago, the development of US shale gas and tight oil would have been such an event. In a previously unimagina-ble shift, the United States is set to become one of the major global sources of oil and gas, with the IEA projecting the US will replace Saudi Arabia as the world’s largest oil producer by 2015.

Despite that growth, the margin of error in the global oil markets remain thin, at about two to three million barrels a day, as disruptions affect production in Iraq, Libya, Angola and while gas markets remain unsettled by the Russia-Ukraine impasse.

David Hemming, commodities portfolio manager at Hermes Fund Managers, says: “While US pro-duction growth is matching growth in global demand, all the major producing areas are going to run into issues with higher depletion rates, especially in tight oil plays.”

A result of high oil demand forecasts and decreasing supply has been the exploration of new higher- risk areas of oil and gas supply, ranging from Canada’s tar sands, pre-salt reserves off the coast of Brazil and in the Gulf of Guinea, and the Arctic.

Success in Canada has become a global model for the exploitation of tar sands and oil shale. Both the Middle East and China are inter-ested in their domestic potential, while Israel is estimated to have potential reserves equivalent to 260 barrels of oil (bbl). The energy intensity of the technology means that such sources require high oil prices for the projects to be viable. While the last few years have seen Brent oil prices at a cyclical high, there are concerns from investors about the impact on return if the oil price falls. Mr Hemming says that, while the projects have a high marginal cost, they have easy-to-model resource boundaries, which helps in planning.

Following the 2007 discovery of oil off the coast of Brazil, there were predictions that output could double to five million barrels a day by 2013, making Brazil the world’s fourth largest oil producer. Recent finds off the coast of Angola, Cam-eroon, Congo, Equatorial Guinea and Gabon have encouraged hope that Africa’s reserves will be as strong. Yet in 2014, Brazil’s output has increased by only 20 per cent, with only 350,000 barrels a day coming from the pre-salt fields. Political and structural challenges have been an issue, but it is fail-ings in Brazil’s infrastructure and domestic skills-base that have been cited as pushing up costs. The marginal cost of the oil is around $30 to 40bbl, which makes these fields an exciting opportunity.

Shell has estimated that the Arc-tic holds around 30 per cent of the world’s undiscovered natural gas and 13 per cent of its yet-to-find oil. Russia has already shipped its first oil from offshore Arctic waters, though the challenge with Arctic drilling is the technical and

environmental unknowns, but a big discovery could mean rela-tively cheap oil, again at $30 to 40bbl.

The mixture of global energy supply, both in terms of type and origin, is likely to remain a function of demand, supply and economic cost. Mark Henderson, director of oil and gas at West-house Securities, says if these new areas of exploration are proved to be economic, “there will be a gold rush”, but it is economics that will dictate the viability of new exploration, nothing else. The oil market is cyclical and he says that the continuation of supply growth could see marginal costs in the oil industry fall below $40 bbl.

Existing conventional sources could also provide the necessary supplies to meet demand growth, especially if the continuing high price of oil has its expected impact on energy efficiency. Mr Hender-son points out that energy inten-sity in Organisation for Economic Co-operation and Development countries is now a third of what it was before the oil shocks of the seventies and eighties, mean-ing lower consumption per unit of GDP.

And there are signs of a similar path in China, where energy intensity is slowing faster than

predicted. Emma Wild, head of upstream advisory at professional services company KPMG, says: “Everything that impacts on future energy mix depends on China – its attempts to reduce the country’s dependence on coal are already beginning to impact on the rest of the world.”

Arthur Hanna, global manag-ing director of energy business at Accenture, says that different predictions are dependent on views on the likelihood of different interventions, ranging from fossil-fuel subsidies to a carbon price. Mr Hanna says: “The future energy mix is not dominated by one form of supply, which has never hap-pened before.” He warns though that predictions are still “missing energy demand management, and the impact and sources of innova-tion, local content, jobs and so on”. These latter elements are what enable the balance of economic, social and environmental concerns in energy policy.

Laszlo Varro, IEA director of gas and power, says that in order to understand potential change in the energy mix, we need to understand what drives demand for differ-ent fuels. According to Mr Varro, energy demand can be effectively split into three areas: electricity (where the most important source is coal); transport (predominantly oil); and heating (mainly gas).

He says that it’s useful to look at the dominant form of supply for each and how that might change. “Outside of transport, oil is being pushed out of every other sector in the economy,” he says. “On the other hand, you would need an astonish-ing shift in the fleet to challenge oil in the transportation sector.”

Coal in fact provided around half the growth in electricity demand in the past decade and is expected to remain the largest single source of power by 2035 – and its growth is of far more concern than oil. Mr Varro says that the world is adding a UK’s worth of electricity demand every nine months or a

Germany every year. In terms of emissions, this is a critical issue.

What’s significant for new areas of oil exploration is that a fall in the marginal cost of oil could have a major impact on high-risk pro-jects. According to Mr Hemming, current oil projects have an inter-nal rate of return (IRR) of 15 to 20 per cent, so the question of how long those IRR’s can be maintained becomes ever-more important. He also believes that demand is man-ageable within existing reserves. “These new areas of exploration and production will only work at a certain price,” he concludes.

ENERGY MIX

Future exploration and production of oil and gas depend on sustainable prices in the global energy market, as Felicia Jackson reports

FORECASTING THE OIL AND GAS ECONOMY

PREDICTING GLOBAL ENERGY SUPPLY

Everything that impacts on future energy mix depends on China – its attempts to reduce the country’s dependence on coal are already beginning to impact on the rest of the world

COAL-TO-GAS SWITCHING AND RENEWABLE POWER GROWTH ARE THE PRINCIPAL TRENDS IN EUROPE**Data is indexed to 2008. CAGR is compound annual growth rate. RES is renewable energy supply

DIFFERENT SCENARIOS RESULT IN VARYING GENERATION CAPACITY NEEDS BY 2030

18

12

6

0

2013 UK ENERGY MIX

2040 WORLD TARGET SUSTAINABLE ENERGY DISTRIBUTION

2014 WORLD ENERGY MIX

31,9%5.6%2.3%10.5%

33%10%11%3%

38%

28%

20.6%29.1%

8%2%

17%16%

2%11%21%

Renewables OilHydroNuclearCoal Gas Geo BioWind Other

Source: IEA (New policies scenario)/Vivid Economics

Source: Vivid Economics

PRIMARY ENERGY PRODUCTIONFORMER SOVIET UNION STATES

SOUTH & CENTRAL AMERICA

NORTH AMERICA

MIDDLE EAST

EUROPE

ASIA-PACIFIC

AFRICA

1990

1990

2005

2005

2020

2020

2035

HIT

TIN

G

TAR

GE

T

GA

S IS

K

EY

AUST

ERIT

Y R

EIG

NS

120

100

80

60

40

20

0GEN

ERAT

ION

CA

PAC

ITY

IN 2

030

(GW

)

CARBON CAPTURE STORAGE

UNABATED GAS/ BIOGAS

UNABATED COAL/ BIOMASS

NUCLEAR POWER

ONSHORE WIND

OFFSHORE WIND

SOLAR PV

3

2

1

0

BIL

LIO

N

TOE

% OF TOTAL(RHS)

RENEWABLES SHALE GAS TIGHT OIL,OIL SANDS,BIOFUELS

200%

150%

100%

50%

0%

RES 3.4%

ELECTRICITY 0.7%

OIL -0.9%COAL -2.5%

NUCLEAR 0.0%ENERGY 0.0%

GAS 0.5%

2008

- 203

5 C

AG

R

NEW SOURCES HELP TO SUPPLY SUFFICIENT ENERGYSource: Energy Outlook 2035, BP 2014

NEW ENERGY FORMS**TOE is tonnes of oil equivalent

2035

18%

12%

6%

0%

BIL

LIO

N

TOE

Solar

GAS ELECTRICITY COAL OIL NUCLEAR RESTOTAL ENERGY

1995 2000 2010 2015 2020 2025 1995 2030 2035

3

2

1

0

HITTING THE TARGET

High degree of political cohesion and direction supports record investment in power sector and drives down carbon emissions to achieve 2030 target GAS IS KEY

Moderate commitments to limit greenhouse gas emissions and competitively priced gas supplies dissuade investors from financing new coal-fired power stations, resulting in all gas-fired fossil plants AUSTERITY REIGNS

Absolute prioritisation of economic growth and fiscal stability in a UK economy which has seen stagnation followed by anaemic growth

11raconteur.net twitter: @raconteur10 raconteur.net twitter: @raconteur 1009 1009

facility’s production - now at 3.4 million metric tonnes per annum - and a multi-billion-dollar gas pipeline project to connect Nige-ria, Cameroon and Equatorial Guinea gas fields to the plant. The government has partnered with a US company to develop the petrochemical sector to meet domestic and regional industrial demands, create jobs and grow the economy.

Africa – from petrodollars to progress

MAPPING RESOURCES IN AFRICA

The shift in approach by a growing number of African states to the exploitation of their oil and gas resources could help transform Africa’s economies. Jason Kerr, Joshua Siaw and Anthony Elghossain of global law firm White & Case explain

African states rich in resources are striving to increase domes-tic involvement in their econo-mies – especially in oil and gas. In attempting to increase domes-tic participation throughout the value chain, some African states have begun introducing local content laws, supporting indus-trial diversification and creating a broader economic base for the future. If effective, these meas-ures could provide a framework to enable resource-rich states to benefit from Africa’s potential and transform their economies.

Afr ica holds around 8 per cent of the world’s oil and nat-ural gas reserves. Some states have developed their oil and gas sectors significantly. Nige-ria and Angola, in particular, have established themselves as exporters and borrowers in the international market, and rank as the top two producers in sub-Saharan Africa. Buoyed by sig-nificant new energy finds, other states, such as Ghana, the Ivory Coast, Kenya, Tanzania, Uganda, Mozambique and Chad, offer new opportunities. In 2012, about half the world’s discoveries of con-ventional oil and gas were in East Africa alone.

Natural resource exploita-tion provides important sources of revenue for African states through investments, sales and commodities-backed borrow-ings. But this investment has not necessarily broadened the eco-nomic base, promoted employ-ment or added value domesti-cally. African governments have reaped financial rewards with-out maximising residual ben-efits, such as ownership, skills development and the growth of related sectors.

With their new policies, how-ever, African states will look to encourage international inves-

Despite moving towards local ownership and participation in the value chain, African states must overcome common challenges. Although policies on local con-tent and diversification could be transformational, African states and local businesses - even in relatively established markets such as Nigeria or Angola - have struggled to raise capital, acquire new technologies and improve inadequate infrastructure.

While states with new discover-ies may seek to learn from history and avoid the “resource curse” that confronted some of the more established oil and gas produc-ers, they will also face chal-lenges. States such as Tanzania and Mozambique have found that their plans to monetise natural gas reserves will require exten-sive international participation to succeed, given the high-risk and capital-intensive nature of these projects. Mozambique, in particu-lar, may find it difficult to finance and develop massive new gas finds, which could require initial investments of more than $50 bil-lion. Newer resource-rich states will need to balance the desire to promote these policies against the need to attract international investment if they are to maximise their natural resource potential.

In pursuing their policies, African states must avoid deterring inter-national investors who can provide funds, management expertise and technical knowhow necessary to achieve their goals. Indeed, local content laws could have counter-productive effects as international investors may elect to engage other states or regions with less onerous requirements, such as taxes, training, procurement and other costs of conformity. And because these laws and related policies are relatively new, inves-tors may prefer to engage states with legal frameworks seen as more established and predictable.

Despite these risks, African states will continue to explore new ways to manage their natural resources and resultant windfalls. They will seek to grow domestic industry, build institutions, and develop services to allow industry and agriculture to flourish. As local companies continue to increase their participation in domes-tic industry, they will gradually develop necessary experience and expertise. International investors must understand that the land-scape is changing and push for-ward partnerships with domestic participants. If successful, the oil and gas industry could help Africa achieve its potential.

operations in the relevant fields.)In a deal demonstrating the

potential effect of local content laws, including on political and operational risks, Shoreline Nat-ural Resources, a joint venture between UK-listed Heritage Oil and local company Shoreline Power Company, acquired a sig-nificant interest in a major Niger Delta oil-producing block from a consortium led by Shell. As Nigeria’s largest-ever upstream acquisition financed by interna-tional banks, the deal was origi-nally bridge-financed and sub-sequently completed through a reserves-based loan arranged by Standard Bank.

Other Afr ican states have adopted s imil ar measures . Ghana, for example, has legis-lated to increase local participa-tion in terms of equity, employ-ment, training and ser vices. Beyond those requirements, Gha-naian legislators have also estab-lished parameters for minimum equity participation by indigenous companies. Without this partici-pation, petroleum-related agree-ments and licences will be inva-lid. Since passing local content laws in 2013, Ghana has awarded several oil blocks to consortiums, including Ghanaian companies, and has seen related services in insurance and finance grow.

Alongside the enactment of local content laws, African states and citizens have begun harnessing reserves to support industrial diversification and broaden their economic base. For decades, outside investors have extracted resources and the value derived from processing and manufactur-ing as African states have raked in petrodollars without increas-ing their stakes in the value chain.

Nigeria, for example, imports 95 per cent of its diesel, subsi-

dised at great expense with crude oil exports, and has historically flared much of its natural gas, in part because of inadequate infrastructure. To move forward, Nigeria has sought to develop its refining capacity, for petroleum products such as diesel and fer-tilisers, and monetise its natural gas reserves. While several for-eign firms have failed to deliver on oil refineries announced over the last 15 years, the Nigerian Dan-gote Group is poised to construct a major refinery and related pet-rochemical and fertiliser plants. Once complete, at a projected cost of $9 billion, the refinery will have a production capacity of 445,000

barrels a day and employ thou-sands of workers.

Similarly, having exported liq-uefied natural gas (LNG) for more than a decade, Nigeria has passed laws that require oil producers to supply natural gas for domestic uses such as power generation or petrochemical production. Oper-ating under these laws, Indorama Eleme, a Nigerian poly-olefins producer, owned by the Indorama Corporation based in South East Asia, has sold 95 per cent of its production domestically since 2006. Building on that success, Indorama Corporation closed on the financing of a large-scale fer-tiliser project in 2013. The new

plant will be the largest of its kind in Africa, and will benefit from competitive feedstock pricing and a growing domestic market.

In Ghana, meanwhile, the gov-ernment spends roughly $1 bil-lion a year importing crude oil to fuel power plants. To reduce reli-ance and allow public and private entities to benefit from cheaper power, the Ghana National Gas Company is building a $1.4-bil-lion gas processing plant to sup-ply the domestic market with natural gas from the nearby Jubilee Field. Equatorial Guinea is also building a new LNG train, which will add 4.4 million met-ric tonnes a year to an existing

tors and Africans to progress in shaping the continent’s eco-nomic destiny.

In recent years, states such as Nigeria, Ghana and Uganda, have passed local content laws. By encouraging domestic partici-pants to become stakeholders in a range of enterprises relating to oil and gas, African states have sought to ensure that their citi-zens increase their role in devel-oping the broader economy.

In 2010, for example, Nigeria enacted local content laws. Oil and gas deals now require cer-tain types of domestic partici-pation, including profit-sharing, equity involvement, training and employment. Nigerians have since benefited from 38,000 jobs in exploration and produc-tion, engineering, transportation and logistics, in large part due to local content requirements. In that time, local companies have increased their participa-tion in the oil and gas business from 10 per cent to more than 30 per cent.

Partnerships between local businesses and junior oil compa-nies are growing in the upstream oil sector of exploration and pro-duction, especially in more acces-sible fields that may not require significant capital or new tech-nologies. Arguably, local partic-ipation has yielded benefits that would have been absent other-wise. Production in some places has increased by 40 per cent, according to some estimates, and interruptions are down signifi-cantly. (By responding effectively to community concerns and build-ing on their domestic relation-ships, local companies may have reduced the interruptions that plagued foreign oil companies’

International investors must understand that the landscape is changing and push forward partnerships with domestic participants

Investment has not necessarily broadened the economic base, promoted employment or added value domestically

PROVEN RESERVES OF CRUDE OIL IN AFRICA 2012 TOP AFRICAN EXPORTS BY PRODUCT 2009-12

RESOURCE AND NON-RESOURCE CONTRIBUTION TO REAL GDP GROWTH 2000-11 (%)

FOREIGN DIRECT INVESTMENT INFLOWS INTO AFRICA BY SECTOR (US$m)

Source: US Energy Information Administration, Oil and Gas Journal

Source: UNCTAD

2012

2011

2010

Petroleum and related materials

Gas, natural and manufactured Commodities and transactions Non-ferrous metals

Coal, coke and briquettes Crude materials, inedible Iron and steel Non-commodities

2009

4.9% 1.5%1.4%4.2%

10.000+ (High)

1.000+ (Medium)

0.010+ (Low)

No data

Levels of crude oil (billion barrels)

0.200

0.425

2.000

0.660

1.100

1.600

Tunisia

Gabon

Cameroon

Equatorial Guinea

Congo (Brazzaville)

Ghana

3.5%2.8% 1.7% 2.2%

5.2%3.7% 1.4% 1.8%

4.6%2.8% 1.5% 2.4%

Source: IMF, African Department Database Source: UNCTAD, based on information from The Financial Times, fDi Markets

Real GDP growth

Non-resource contribution to growth

Resource contribution to growth

E. G

uine

a

Ang

ola

Sier

ra L

eone

Nig

eria

Cha

d

Tanz

ania

Gha

na

Zam

bia

Rep

. Con

go

Cam

eroo

n

Sout

h A

fric

a

Dem

. Con

go

Nig

er

Nam

ibia

Bot

swan

a

Mal

i

Gui

nea

Gab

on

C. A

fric

an R

ep.

20

15

10

5

0

20122011

2,940

3,151

2,316

2,227

1,886

1,426

1,511

Mining, quarrying & petroleum

Electricity, gas & water

Business services

Motor vehicles & transport equipment

Coke, petroleum prod. & nuclear fuel

Transport, storage & communications

Metals & metal products

Finance

Food, beverages & tobacco

13raconteur.net twitter: @raconteur12 raconteur.net twitter: @raconteur

OIL & GASOIL & GAS

SUBSEA INNOVATION

Ȗ The world’s oceans are the plan-et’s last great frontier. Only around 10 per cent of the sea floor has been mapped and we probably know more about the dark side of the moon than the seas that cover 71 per cent of the Earth’s surface. But one thing is certain – there is still much subsea oil and gas to recover.

Offshore drilling is technically difficult and expensive, and is set to become even more so as the industry is forced into deeper, ever-more remote waters to coun-terbalance declining production in mature shallow-water basins.

While there is no cheap and easy technological solution to these challenges, operators are gradually adopting changes that are enabling them to cost-effectively target reservoirs over a much wider area, tying back subsea wells both to fixed platforms in shallow waters and to floating infrastructure in deeper water.

A combination of high oil prices coupled with rising surface facil-ity costs and advances in technol-ogy have helped fuel a boom in so-called subsea developments in recent years. In the UK, for instance, the sector has 53,000 employees, more than 750 com-panies and is worth £8.9 billion in products and services.

Globally, investment in ultra-deep water developments, which can be up to 3km below the sur-face, is expected to capture 48 per cent of total subsea capital expend-iture from 2013 to 2017, in contrast to 37 per cent between 2008 and 2012, according to UK-based industry analysts Infield Systems.

Some of this investment is being channelled into development of new technologies and materials that will make oil and gas extrac-tion at great depths financially viable yet safe both for operating personnel and the environment. In recent years, operators have focused on bringing many of the processes formerly carried out at the surface down to the seafloor.

One of the first examples of the current generation of subsea tech-nologies appeared in 2007 when US engineers FMC Technologies supplied a full-scale commercial subsea separation, boosting and injection system to Norway’s Sta-toil. The device separates out the seawater, cleans it and injects it into a low-pressure aquifer, while boosting the pressure of recovered oil and gas mixture to 1,000psi for the 16-mile trip to the Gullfaks field for processing.

North Sea oil fields now depend heavily on enhanced oil recovery (EOR) techniques, and in this case the FMC system boosted total recoverable oil by 19 million barrels.

Next year, Statoil hopes to install the next generation of technol-ogy, the world’s first subsea gas compression station in the Åsgard field off the coast of Norway. Two advanced 11.5-megawatt compres-

sors will boost falling gas pressures in the Midgard and Mikkel satellite reservoirs, thereby prolonging the life of the field and increasing gas recovery by the equivalent of 280 million barrels of oil. The developers say the project avoids the need to build a new, large semi-submersible platform and will reduce operating costs.

However, this technology was dealt a blow last month when Royal Dutch Shell postponed a project to provide subsea compres-sion at Ormen Lange, the second-largest Norwegian gas field. “The oil and gas industry has a cost challenge,” says Odin Estensen, chairman of the Ormen Lange management committee. “This, in combination with the maturity and complexity of the concepts and production volume uncer-tainty, makes the project no longer economically feasible.”

Although the pioneering subsea compression system, also designed by Aker Solutions, promises to reduce capital and operating costs, and enable greater production, it still faces considerable techno-logical challenges. It will have to pump gas from wells at a depth of 2,790 to 3,600 feet some 75 miles to onshore processing plants and be available 97.6 per cent of the time, with maintenance taking place only every four or five years. A daunting challenge even for compressors based onshore.

Low-salinity water flooding of oil reservoirs is another EOR technique that is gaining ground. Normal seawater creates electrical charges, because salt is a conductor of electricity, causing oil to stick to the rock walls, thus reducing the quantity that can be recovered. But if low-salinity water is used instead, the charge is lowered and the oil is more easily liberated from the rock. The International Energy Agency estimates that an additional 42 million barrels of

North Sea oil could be recovered using this technique.

One of the biggest problems facing subsea projects is the pro-vision of a reliable, safe power supply to drive and control the pumps, compressors, separators and other processing equipment that has traditionally been kept on platforms on the surface. Ger-man multinational engineering and electronics conglomerate Siemens has developed what it calls a subsea power grid that combines electricity transmission with control and communications

elements, while Swiss engineering giant ABB has entered a five-year programme with Statoil to develop a similar system.

Subsea engineering firms are working on a range of new tech-nologies. “We are looking at new materials, new construction meth-ods, new welding techniques, as well as higher strength steels, as projects go deeper and encounter higher pressures. We are also witnessing the emergence of com-posites and carbon fibre,” says John Mair, technology develop-ment director at engineering firm Subsea 7. “You are going to see new developments in underwater communications, fibre optics and acoustics, especially for the Arctic.”

If the polar ice cap continues to recede, large-scale drilling in the Arctic Circle will soon become a reality and could account for as much as 20 per cent of the world’s undiscovered but recover-able oil and natural gas resources. Indeed, by 2030, the majority of oil reserves will be in as yet unde-veloped or undiscovered fields and extracted using additional EOR techniques, according to the Inter-national Energy Agency.

Advanced technologies look set to play a pivotal role in the future, but will only do so if they are cost efficient. This will depend on continued high oil prices and therefore seems likely, but is far from assured.

We are looking at new materials, new construction methods, new welding techniques, as well as higher strength steels, as projects go deeper and encounter higher pressures

33

of rising oil prices in unconven-tional plays, adopting proactive approaches. Adaptability is key, and by better integrating functions and operations, overall performance can be improved, from selection of locations to flowing the well.

As costs rise, reserves decline and infrastructure ages, “business as usual” is no longer a viable strategy. Change is challenging, but instead of regarding it as a burden, the North Sea oil sector must use it as an opportunity to innovate and improve efficiency, and thus become a more attractive investment opportunity.

If it doesn’t, companies’ futures and thousands of jobs will be at stake.

Gavin Hall has more than 25 years of management consulting experience serving exploration and production clients across the globe. He is currently managing director of MTG Europe, specialising in operations improvement. www.mtgconsulting.com

Adapt or die:Challenge forNorth Sea oil industry

Latest figures from Oil & Gas UK show that predicted reserves are in the region of 24 billion barrels of oil equivalent. Production declined by 14.5 per cent in 2012 and, although it is expected to rise slightly this year, there has been an overall downward trend since 2000.

At the same time, costs are increasing. 2013 saw operating expenditure rise by 15.5 per cent to a record £8.9 billion and it is predicted to be higher this year.

Declining production and increased costs are not necessarily terminal as

long as prices rise accordingly. This cannot be relied upon, so a better option is to find new oil and/or extract existing reserves more effectively.

The problem with finding new reserves is they are becoming more economically challenging. The past three years have seen the low-est exploration levels in history and project performance has been poor, in terms of cost, schedule and promised volumes.

There is also scope to extract existing reserves more effectively either by reducing field lifting costs by focusing on profitability over production, which will require a fundamental change of mindset, or by concentrating on production, not just by improving efficiency, but also understanding true production potential and driving to deliver that.

New technology will play an impor-tant role, but the sector must also revise its approach. The development of deeper, service level-based rela-tionships will help promote long-term investment in technology, and govern-ment must provide a framework that supports investment in R&D and its application in a mature market.

These factors require a long-term view of asset development, which is often at odds with the shorter time-frame of shareholders wanting a return on investment.

All of the above are possible, but having spent the past 25 years work-ing in exploration and production, I know their implementation is not going to be easy. As an industry, we aren’t known for proactively adapt-ing to changing circumstances. This is no better evidenced than in the UK sector, where high staff turnover and localised wage inflation are a conse-quence of reluctance by the industry to address the root causes of a clear skills shortage.

But it can be done. Our clients, particularly those in the United States, have taken advantage

CO

MM

ERC

IAL FE

ATUR

E

North Sea oil reserves are declining. Though there is still a wealth of oil and gas out there, the “easier-to-access” reserves are becoming depleted, says Gavin Hall, managing director of MTG Europe

Adaptability is key, and by better integrating functions and operations, overall performance can be improved, from selection of locations to flowing the well

rise in operating expenditure in the oil

and gas sector

15.5%

Curseor cure?

Page 15

CASE STUDY

SUBSEA COMPRESSIONIN NORWAY’S ÅSGARD FIELD

Last summer, 125 miles off the coast of Norway, a 30,000-square-foot steel structure was sent plunging to the ocean floor. By next year it will house a giant compres-sor that will pump an estimated £18 billion worth of gas from a mature offshore field. Analyses show that, towards the end of 2015, the pressure in the Midgard and Mikkel gas reservoirs in the Åsgard field will fall below levels required to sustain a stable, high level of production. Until now the solution has been to install gas compres-sors on an existing platform or to build a new staffed compression platform. Instead, Statoil and Aker Solutions are developing a subsea gas compression unit that will be installed on the seabed next year – the first time this has been attempted anywhere in the world. By situating the compressor close to the wellheads, recov-ery rates will be better than if it were on the surface, and cheaper to build and operate, according to Acker Solutions. “The technology represents a quantum leap that can contribute to significant improvements in both recovery rates and lifetime for a number of gas fields,” the company says. It is expected that the project’s two state-of-the-art 11.5-megawatt (MW) subsea compressors will increase recovery by around 280 million barrels of oil equivalent, similar to the output from a medium-sized North Sea gas field. Qualification testing began in 2005, followed by a lengthy testing programme at Statoil’s Kårstø laboratory facilities from 2008. Most recently, a water-filled test pit was built at the same laboratory to simulate subsea conditions.The project is estimated to cost 15 billion Norwegian crowns (£1.5 billion), about the same price as a compres-sor on a new platform. However, a semisubmersible platform weighs in at around 30,000 tonnes, some five times more than the subsea compressioan station. It will also require far less energy to operate, 25MW compared with 41MW for a platform. There will be no atmospheric emissions or discharges into the sea from the subsea station, further reducing its envi-ronmental footprint. Power-related annual CO2 emissions will be around 109,000 tonnes compared with 200,000 tonnes for a platform. Furthermore, the subsea station will be safer as it is oper-ated remotely and will not, like a surface platform, require a full-time on-board crew. Technical barriers, the high capital cost and difficulties with integration into existing infrastructure have held back subsea production for years. Although the new technology has yet to earn the full confidence of operators, as Shell’s decision to postpone its Ormen Lange compression project demonstrates, the decision by Statoil to press ahead with a fully sanctioned, commercial project should set a valu-able precedent.

BREATHING NEW LIFE INTO OLD OIL FIELDS There is still plenty of oil and gas under the oceans and we need to recover it if we are to satisfy rising global energy consumption, writes Rohan Boyle

Brazil's Petrobras oil-drilling platform,

Guanabara Bay, Rio de Janeiro

AFP/Getty Images

Statoil

OIL & GAS OIL & GAS

15raconteur.net twitter: @raconteur14 raconteur.net twitter: @raconteur

When governments and other national stakeholders take control of oil and gas reserves, there can be disadvantages as well as the seemingly obvious advantages, writes Jim McClelland

John V. Mitchell, associate research fellow at Chatham House, the Royal Institute of International Affairs, sketches the changing shape of the global oil and gas industry – and concludes that there are no certainties

ARE OIL AND GAS RESERVES AN ECONOMIC CURSE OR CURE?

RESHAPING THE OIL AND GAS INDUSTRY

RESOURCE NATIONALISM

Ȗ It is easy to assume newly discov-ered oil and gas reserves represent a no-lose situation for a country or government, as well as commercial partners. However, with increased export duties, restrictions and measures, such as legislated local ownership, all potentially impact-ing supply and viability, there can be pitfalls and risks.

Rather than boosting politi-cal independence and sovereign wealth, reactive approaches to resource nationalism can have unintended, adverse consequences for energy security.

“A degree of resource national-ism can be a good thing,” says Sam Wills, research fellow at the Oxford Centre for the Analysis of Resource-Rich Economies. “Har-nessed properly, it makes countries better places to do business, plus it helps bring the greatest economic and social benefit to the popula-tion. However, taken too far, it forgoes benefits of foreign finance and expertise, limits transparency, and can lead to corruption, poor investments and inflation.”

The poster child for resource nationalism is Norway. The coun-try has transitioned from a 10 per cent royalty on 1969 North Sea

oil, to collecting 78 per cent of oil and gas revenues in taxes and a sovereign wealth fund worth more than $100,000 per capita.

If Norway is the past and present, East Africa could be the future, as Dr Wills suggests:

“In November 2013, leaders of the East African Community endorsed a move towards mon-etary union. However, the past three years have seen huge oil and gas discoveries in Kenya, Uganda and Tanzania.

“Confining this wealth within each country would see them grow at vastly different rates. Resource nationalism could mean the difference between a vibrant, emergent East Africa and instabil-ity in a developing region of 150 million people.”

Potential pitfalls of resource nationalism are many, as global oil & gas transactions leader at profes-sional services firm EY, Andy Bro-gan, explains. “Oil and gas ‘crowds out’ other activity, leading to a lopsided economy which becomes vulnerable to shocks. Inadequate local engagement and content can also mean employment and long-term investment is imported, giv-ing rise to very narrow distribution

Ȗ The oil and gas industry is changing to a “multipolar” struc-ture. This comes after the “bipolar” model of the international oil com-panies and OPEC (Organization of Petroleum Exporting Countries) which dominated the last quarter of the 20th century, and the ear-lier monopolistic regime of the so-called “seven sisters” oil giants.

These structures floated on the geopolitics of imperial and colo-nial power in the 30s, the rising nationalism of the 60s and 70s in developing countries, and will now ride on the current integra-tion of Russia and China into the world economy. The strategic local choices of industry players will decide who gains and loses in the new game.

The industry now faces:• Higher oil prices – around $100 a barrel – which open the door to new suppliers and substitution• Application of new supply tech-nologies, which reduce the effect of depletion and cut off the peak of “peak oil”• Flattening and even reversal of growth in demand for oil in developed countries, as a result of higher prices, new technology in the automobile and other user industries, and above all in the increasing strength of policies to restrict greenhouse gas emissions• New focus of downstream growth questions of security of supply in Asia rather than in the Organisation for Economic Co-operation and Development (OECD)• Mismatch between the oppor-tunities for investment, the funds available, and corporate structures through which funds and opportu-nities are brought together.

The balance within the oil indus-

try is changing. The advantages of the largest international oil companies lie in the past. They have strong generation of funds, but their opportunities are limited geographically to high-cost and difficult exploration and produc-tion. The strength of local and national companies excludes them from most of the downstream growth in developing markets.

In 2006 there were six interna-tional private sector companies among the world’s top ten oil producers. In 2012 there was one. There are now only 19 private sector companies in the top 50 oil producers and their share of pro-duction has dropped by 5 per cent to below 20 per cent, less than the growing share of smaller, private sector companies outside the top 50. The share of production from the wholly-owned state companies in the top 50 has fallen slightly, to around 46 per cent, though the biggest companies have increased their part of it.

More and more large state-controlled companies are being partially listed in financial mar-kets; for them the traditional international company package of “money plus management

and technology” no longer hangs together. They can raise finance directly, and hire management and technology from the service com-panies. These “mixed” companies, state-controlled but with listings on public stock exchanges, now supply about 13 per cent of world liquid production.

There remains a large section of the industry, controlling about 50 per cent of world oil reserves, where private companies partici-pate as contractors to state com-panies. These do not offer the kind of “bookable reserves” which large international companies have been seeking, but small and mid-cap [mid-market capitalisation] companies have been successful in striking new deals with new producers outside OPEC.

The critical factor for success is to match local needs and institu-tions with appropriate foreign resources. The smaller private sector and state companies may find it easier to focus than big, bureaucratic corporations whose bureaucracies may not offer the same continuity of attention.

About 70 per cent of world gas consumption is supplied from within each consuming country. Growth depends on finding prices in each market which simultane-ously expand demand and supply to that market. Transportation costs separate markets. Investors in the international gas trade face volume and price risks from the different government policies for power generation from renewables or nuclear energy.

The key uncertainties for the major players are do the no-growth OECD downstream businesses add value, and are upstream invest-ments cornered into high-cost projects, which will be vulnerable if in fact global demand levels off and eventually declines?

Investors can no longer assume an escalator in oil demand or prices. It is not difficult to generate sce-narios in which strong emissions policies lead to oil being left in the ground at the end of the century. It will be the most expensive oil in the world, on the books of those com-panies who invested in it.

The critical factor for success is to match local needs and institutions with appropriate foreign resources

of economic gains,” he says.Not necessarily just about the

money, there is more to resource nationalism than export restric-tions and tax revenues alone, he argues. “Governments don’t just want economic exposure, but much greater involvement in the supply chain and operations. This can be positive, but also negative if there is inadequate local supply of people, services or kit,” he says.

“International oil companies [IOCs] need to become experts in local stakeholder engagement and in partnering with national oil companies on a more equal basis. IOCs are successful when they can articulate the benefit they bring – historically this used to be capital, but now it needs to be much more.”

While cash might not always be king, what if the resource value cannot be realised and numbers stop adding up?

Depending on quite how the game plays out, countries or companies sitting on ill-chosen or badly-managed fossil-fuel assets are increasingly in danger of being left holding expensive, unplayed cards.

Divestment campaigns are upping the ante, as Ben Caldecott, director of the stranded assets programme at Smith School of Enterprise and the Environment, University of Oxford, points out.

“Countries with relatively high-cost reserves may never be able to extract them profitably as new fac-tors continue to place downward pressure on demand and price. These include significant develop-ments in renewables deployment, shale gas, efficiency, air pollution, water stress and social factors such as divestment, as well as climate policies,” he says. “All things being equal, fossil-fuel divestment will put higher-cost reserves at more risk of becoming stranded assets.”

The global grassroots movement of the divestment campaign is growing, particularly in church and on campus. Endorsed by reli-gious leaders, communities and multi-faith groups, it is also mobi-lising support across universities, schools and colleges, particularly in the United States, as evidenced at Harvard by an open letter, signed by nearly 100 faculty mem-bers, calling for divestment of the $33billion university endowment.

Author and environmentalist Bill McKibben, founder of 350.org, which has led the campus divestment campaign, is direct in his description of new discovery issues. “Finding new hydrocarbons is a serious Midas problem. We can’t burn them without wreck-ing the planet, but each new mine or field creates a small group of potential billionaires who will do anything to get them out,” he says.

The prognosis is apocalyptic in his forecast of what the future holds for fossil-fuel assets.

“It all depends on whether the world ever takes global warming seriously. If it does, they’ll take a bath, and if it doesn’t, well, then we’ll all take a different kind of bath.”

Oil and gas professionals not yet persuaded by the rhetoric to take divestment seriously, might be interested to learn which nation opened debate this year on pulling its $840-billion wealth fund out of fossil-fuel stocks – the country is Norway.

Stakes just rose for resource nationalism.

Governments don’t just want economic exposure, but much greater involvement in the supply chain and operations

OPINION

78 %

OF NORWAY’S OIL AND GAS REVENUES COLLECTED IN TAXES

Source: Statoil

$840bn TOTAL WEALTH FUND DEBATED FOR FOSSIL-

FUEL DIVESTMENTSource: Thomson Reuters

$33bn VALUE OF HARVARD

UNIVERSITY ENDOWMENTSource: Harvard Magazine

Fighting in South Sudan has cut oil production, the country's economic  lifeline