OilVoice Magazine | March 2014

Edition Twenty Four – March 2014

Why none of us can ignore the fate of North Sea oil Ghana's Jubilee oil field - stable or stagnating?

The only play on earth bigger than the Bakken Cover image by Berardo62

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OilVoice Magazine | MARCH 2014

Adam Marmaras Chief Executive Officer Issue 24 – March 2014 OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 208 123 2237 Email: press@oilvoice.com Skype: oilvoicetalk Editor James Allen Email: james@oilvoice.com Director of Sales Terry O'Donnell Email: terry@oilvoice.com Chief Executive Officer Adam Marmaras Email: adam@oilvoice.com Social Network Facebook Twitter Google+ Linked In Read on your iPad You can open PDF documents, such as a PDF attached to an email, with iBooks.

Cover image by Berardo62

flickr.com/photos/92819961@N04/

Welcome to the 24th edition of the OilVoice Magazine.

Hmmmm, 24 editions? That must mean it's our second anniversary.

Time certainly has flown. I remember when we first launched we considered doing a printed version of the magazine. At the same time we were reading about magazines like Newsweek going digital only. And from people I know in the oil magazine publishing business, it's no easy task to print and distribute hard copies. So we stuck to digital, and I'm glad we did.

We enjoy putting the magazine together and getting it out to the market. I think a printed version would cause a few sleepless nights.

This month we have great articles from Euan Mearns, Keith Schaefer, Angus Warren, Mark Young and Graham Dewhurst.

We'd also like to introduce some new authors to the fold, including Ed Conway from Sky News, and Hiren Sanghrajka from Upstream Advisors Ltd. If you've been reading the magazine from the start, then thanks for your support. If it's your first time, then welcome!

Adam Marmaras CEO OilVoice

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Contents Authors Bios for this months featured authors

The hidden risks of development decisions

by Hiren Sanghrajka

3 4 11 13 18 22 25 29 34 37

Manufacturing innovation powers growth across Britain's oil and gas supply chain

by Graham Dewhurst

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UK shale gas potential and perspectives

by Euan Mearns The only play on earth bigger than the Bakken

by Keith Schaefer Why have investments in E&P performed so badly?

by Angus Warren How to win bigger than the Bakken

by Keith Schaefer East Africa oil & gas outlook: Global export hub by 2020?

by Mark Young Ghana's Jubilee oil field - stable or stagnating?

by Mark Young Why Shell needs this junior's big play

by Keith Schaefer Why none of us can ignore the fate of North Sea oil

by Economics Editor Ed Conway

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Featured Authors Keith Schaefer Oil & Gas Investments Bulletin Keith Schaefer, editor and publisher of the Oil & Gas Investments Bulletin.

Mark Young Evaluate Energy Mark Young is an analyst at Evaluate Energy.

Edmund Conway Edmund Conway Edmund 'Ed' Conway is the Economics Editor of Sky News, the 24-hour television news service operated by Sky Television, part of British Sky Broadcasting.

Hiren Sanghrajka Upstream Advisors Hiren Sanghrajka is CEO of Upstream Advisors.

Graham Dewhurst Manufacturing Technologies Association (MTA) Graham Dewhurst is Director General for the Manufacturing Technologies Association.

Euan Mearns Energy Matters Euan Mearns has B.Sc. and Ph.D. degrees in geology.

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UK shale gas potential and perspectives Written by Euan Mearns from Energy Matters  

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In order to place some perspectives on social and environmental impacts of shale gas developments I have built a gas model for the UK. The model is based on a type shale well with 3 million cubic feet per day initial production declining 33% in year 1. This is an optimistic guess based on production history data for more productive shale plays in the USA. Drilling 100 such wells / year for 10 years may employ 17 drilling rigs and would stabilise UK gas production at around today’s levels.

Drilling 200 such wells / year for 10 years would see production growing to 2.7 tcf per annum and the UK may once again become self-sufficient in natural gas.

There are huge uncertainties in these estimates. The Bowland shale where most hopes are pinned may turn out to be a dud. Productivity could be higher or lower than my assumptions. If productivity was 25% of my guesstimate and declines higher, 1000 wells over a decade could easily rise to 5000 wells for the same production. It is extremely important that the UK gets some real test data from exploration wells to delineate what the real prospects are.

Figure 1 The distribution of the Bowland-Hodder shale in England. The areas in red delineate land where the shale is present at depth in the sub-surface [1].

The British Geological Survey have published a detailed and competent report on

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the potential of the Bowland-Hodder shale, the highlights of which are summarised below [1]. It needs to be stressed that without test data from at least 10 to 20 exploration wells it is impossible to assess the potential with any certainty. It may turn out that Bowland is a super rich shale to rival the Marcellus of the USA, or it may turn out to be a dud like the recent Polish experience. Shale plays are also nonuniform and tend to have sweet spots that can only be identified through quite extensive exploration drilling. The main focus of this post is to try and place the uncertain potential into a perspective for what this may mean for the UK in terms or providing energy security and the potential for environmental and social disruption.

What is shale gas?

Gas shales are fine grained, tight rocks that contain mature organic matter that has been converted to gas (or oil in the case of shale oil). Not all so-called gas shales are shales; some are limestones and some are tight (impermeable) sandstones. The lack of permeability means that gas or oil is trapped in the rock that needs to be hydraulically fractured (fracked) to liberate its prize. Organic matter may comprise plant material or marine organisms that when buried and subject to pressure, elevated temperatures and time, is slowly converted to oil and gas. This process is called maturation and very generally the hydrocarbon window may occur at depth of 10,000 ft at temperatures around 100?C. Potential of the Bowland-Hodder Shale This account of the Bowland-Hodder Shale (Bolland Shale from here on) is based on the BGS report [1] that has a quite readable two page summary (link at end of this post).

The Bowland is a deep marine Carboniferous shale (318 to 347 million years old) that underlies much of northern England (Figure 1). It is extremely thick, locally up to 16,000 ft, which is much thicker than many of the N American shale plays. But the organic matter content is relatively lean at 1 to 3%, it would have been better had the thickness been half and the organic content double. Organic matter ranges up to 8% and it will be sweet spots like this that companies will look for.

The BGS estimate that the Bowland shale will be in the “gas window� below 9,500 ft.

That is, once it has been buried to this depth, some of the organic matter may have been converted to gas. But the picture is made more complex by the fact that some areas have been uplifted, hence gas bearing shales may be encountered at shallower levels.

There was also a natural build-up of methane in the Wyresdale Tunnel, Lancashire, which lead to the fatal Abbeystead explosion in May 1984.

The Bowland Shale has Upper and Lower units. There is more data for the Upper, but the Lower potentially contains a lot more gas. The RESOURCE estimates are shown in Figure 2. With a range of numbers, the one to focus on is the P50 estimated total resource of 1329 tcf (trillion cubic feet; that is the mid range estimate). Compare that with the total production from the North Sea to 2012 of 86 tcf. The shale gas estimated resource is vast. The resource is the amount of gas

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believed to be in place. The reserve is that part of the resource that can be developed commercially and the numbers here are much smaller with a guesstimate of 4.7 tcf. As we shall see below, that sort of recovery level will make little difference to the UK’s lamentable energy status.

Figure 2 Resource estimates for the Upper and Lower Units of the Bowland-Hodder shale [1].

UK shale gas production perspectives I wanted to try and place “the hype” around UK shale gas into some form of perspective. Without test data from exploration wells, this is quite impossible to do with any meaningful certainty. But here goes…

Based on US production experience (Figure 3) I have modelled what a UK shale gas well production profile might look like if the Bowland shale is as productive as the good US shale plays (Figure 4). I have then assumed that armed with successful test data like this, the UK goes on to drill 100 shale wells per year for 10 years. How much would this contribute to national gas production?

Figure 3 Average production profiles for shale gas wells in the USA [2]. Note units are million cubic feet per year.

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Figure 4 Based on the data in Figure 3, if the UK gets lucky, a well may produce 1000 million cubic feet per year in its first year translating to about 3 million cubic feet per day at the beginning of year 1. Modelled decline rates are shown as percentage values.

Shale wells decline extremely fast in the first years of operation and then decline slows in the tail. I’ve been advised that the rather steep declines I have used here could even prove to be optimistic. This is all guess work and reality may turn out to be very different.

Figure 5 Assuming that 100 wells are drilled per year, the production stack after 10 years, when 1000 wells will have been drilled, takes on this shark fin shape that is characteristic of shale provinces. Each slice represents production from 100 model wells as depicted in Figure 4.

The result is shown in Figure 6. Drilling 1000 shale wells between 2016 and 2025 would stabilise declines from conventional gas creating a production plateau of about 1.5 tcf / annum, compared with current consumption of around 2.8 tcf / annum. This outcome would significantly reduce UK future dependency on imported gas (Figure 6) but would still leave us importing about 50%.

Figure 6 Historic UK conventional North Sea gas production (BP) amounts to 86 tcf, 1970 – 2012. The projection includes a 10% decline which is the historic average. Without shale gas, conventional gas will have declined to near zero come 2025. The 100 well / year model (Figure 5) would stabilise UK production at about today’s levels. The 8.2 tcf production estimate is more than double the BGS guess for reserves but is still tiny compared with the size of the resource.

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Being reasonably impressed by the outcome of drilling 100 shale wells / year I built a second model simply doubling the number of wells to 200 / year. This lifts UK production to about 2.6 tcf / annum by 2025 in which case we would once again achieve self sufficiency – a very big prize worth going for!

Figure 7 Doubling the drilling rate to 200 wells / year would see UK gas production growing significantly, potentially towards a point where we were once again self-sufficient.

The catch If this sounds too good to be true then there has to be a catch. The 100 well / year model contains 8.2 tcf of production, roughly double BGS reserves guesstimate. The 200 well / year model contains 16.5 tcf of production. The bottom line, without exploration and production history data this is all guess work. Zero production by 2025 is probably just as likely as 16.5 tcf and vice versa.

Social perspectives While the USA is turning out shale gas wells faster than Henry Ford turned out Model Ts the pace is likely to be more sedate in rural England. Let’s imagine it takes a rig 2 months to drill a well, this will dictate the pace of development. That would mean 17 drilling rigs operating round the clock to turn out 100 wells per year. Most of the population living in cities would notice nothing. Many rural populations would notice something once in a while and may grumble when there was a drilling operation near by, but then after a short while, the drilling and fracking crews move on. Landlords would celebrate as highly payed drill and fracking crews moved around the country.

17 operational rigs doesn’t sound a lot spread over a large area. To move up to 200 wells / year would mean 34 rigs. If the production results are lower than my model well, expect more rigs and less profits, if the production results are higher, proportionally less. Uncivil unrest that disrupts drilling operations and slows them down will increase the number of rigs required that would add to the social impact.

One final point, the Bowland Shale is so thick, a single vertical well could potentially have several horizontal laterals off it meaning that the number of drill sites could be substantially reduced.

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Environmental impact One concern with shale gas and fracking operations is the contamination of subsurface drinking water supplies by drilling fluids, fracking fluids and gas. A study of drinking water wells in Pennsylvania did find a correlation between methane levels in drinking water and proximity to shale gas wells [3]. About a dozen wells were found to have gas concentrations above 30 ppm, the threshold to take action to mitigate the problem.

I believe it is the case in northern England that most drinking water supplies are drawn from surface reservoirs. Society as a whole needs to weigh small and manageable environmental risks against the potential strategic importance of shale gas to the UK economy and national energy security. There are environmental risks associated with all forms of energy “production�. We either accept these risks or sit at home shivering in the dark.

Conclusion It is vitally important that companies are encouraged and enabled to conduct comprehensive exploration of shale gas resources in the UK in order to evaluate potential contribution of this energy source to the future UK economy and energy security.

If the UK gets lucky and the Bowland shale turns out to be as productive as the good US plays, then 2000 wells by 2025 may once again see the UK achieve self sufficiency in natural gas supplies.

References 1. Andrews, I.J. 2013. The Carboniferous Bowland Shale gas study: geology and resource estimation. British Geological Survey for Department of Energy and Climate Change, London, UK. Link here.

2. EIA Annual Energy Outlook 2012 3. Robert B. Jackson et al 2013, Increased Stray Gas Abundance in a Subset of Drinking Water Wells Near Marcellus Shale Gas Extraction: www.pnas.org/cgi/doi/10.1073/pnas.1221635110 Link here.

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The only play on earth bigger than the Bakken Written by Keith Schaefer from Oil & Gas Investments Bulletin Argentina is the 'Comeback Kid' story of 2014. After getting vilified for nationalizing one large ownership block in the prolific Vaca Muerta shale play in 2012, Big Oil is coming back in a Big Way-and dragging up the share price of the fast growing juniors in the play.

Most investors have forgotten that it's the only shale oil play in the world that appears to be better than the giant US shale oil deposit in North Dakota and Montana-the Bakken. That's right-more productive, more oil charged, and thicker-than the Bakken.

It's located in west central Argentina, in the Nequen Basin.

Energy gurus Wood Mackenzie recently called Argentina's shales the best in the world. And just this month, market strategists Lux Research named Argentina as one of the top spots to watch in the race to bring shale production to new lands.

In 2012, Argentina became hot as a pistol in the junior energy markets-and then went from hero to zero as soon as the government announced it was nationalizing the shareholding of its National Oil Company, YPF, that was owned by Spain's NOC, Repsol.

Stocks that had meteoric rises-came down to earth. The leading Argentine juniors had a bottoming period through 2013 but are now make their way back because Big Oil is pouring a lot of money into the Vaca Muerta shale.

And why are they doing that? Because, as the government said at the time, the Repsol deal was a one-time thing. And in the two years since then-while the Vaca Muerta translates as 'Dead Cow'-the action there has been very lively.

The area's biggest booster recently has been petro-majors like Shell, Chevron, Wintershall and Total SA. Shell announced in December 2013 that it was increasing its capex three-fold, spending $500 million in the Vaca Muerta shale in 2014.

That's a big outlay in a country that even a year ago was considered high-risk for incoming capital.

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But Shell officials say that recent changes in the hydrocarbon sector have today made Argentina a great place to work. 'Now we feel a different wind blowing and we are assessing our possibility to invest in exploring the resources,' said the company's Argentina chief executive officer Juan Jose Aranguren.

What's happened to change the tune of a big player like Shell? Several key developments-ones most investors haven't yet taken stock of.

The Repsol deal was the biggest cloud hanging over the Argentinean energy sectorand caused a flight of capital out of Argentina's oil and gas fields.

But after mulling this move for over a year, Argentina's government seemed to realize they had done wrong. In November 2013, reports emerged that Repsol would likely be compensated for its lost oil and gas fields-to the tune of $5 billion.

That got the attention of international operators-especially as that came on the heels of another key regulatory development-a decision to allow producers to export up to 20% of their oil and gas output, tax-free.

The government also said it will remove foreign exchange controls for companies that invest over $1 billion in Argentina over a five year period, which most petromajors are doing. This addresses two major concerns that made the industry pause.

(That makes their cheap currency even more profitable for energy producers.)

Those changes were enough to bring big firms back to Argentina. In July 2013, Chevron finalized a deal for $1.2 billion in investment alongside local producer YPF. That partnership is now producing 16,000 bopd from the Vaca Muerta shale.

Soon after, ExxonMobil and Apache committed to $250 million and $200 million, respectively, in local spending and Total SA announced an estimated $400 million pilot in the Vaca Muerta. All of this cash was earmarked for unconventional shale exploration and development. Then in late 2013, Wintershall announced a threephase joint venture in the Vaca Muerta shale for up to $3.3 Billion for a net 12,00 acres.

It's attention like that led analysts Lux Research to put Argentina atop their list of global shale hotspots this month. The firm noted that all of the new 'powerful government incentives' in Argentina make this one of the best destinations going for unconventional (tight oil) plays. Despite the growing excitement over Argentinean shale, there's an issue here for investors. How to play this emerging story?

View more quality content from Oil & Gas Investments Bulletin

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Why have investments in E&P performed so badly?

Written by Angus Warren from Warren Business Consulting Introduction: There's a good chance that many readers' investments in E&P have disappointed in recent years. Even the super-sluggish Supermajors and mid-sized companies such as BG and Oxy have delivered better shareholder returns (often through nothing more than dividend yield) than small cap E&P. E&P investors on London's AIM market have seen share prices decrease by over 40%, over the last 3 years according to the FT:

Source: Financial Times So what's driving investor thinking and can we expect any relief from this period of under-performance?

In this article I take the investor's view and highlight the factors that have contributed to professional investors' subdued interest in investments in E&P. I include the good news also, to show what can be done when things work well.

Macroeconomics: oil demand is strongly correlated with economic growth and with the news from China and India that their economies are starting to slow, and further news that recent recoveries in the US and UK may not be sustainable, interest in oil and gas investment has waned. However, support is provided by a weakening dollar (which often leads to higher oil prices) and the continued expectation that interest rates will remain low.

Oil and gas prices: Expected oil price has a significant impact on investor sentiment

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towards the sector (see chart below) and here again the bears would seem to have the upper hand. Concerns over global economic growth, and increased supplies from Iraq, Iran (with loosening sanctions) and oil shale oil in the U.S., have trumped short term disruptions in Iraq and political tension in the Middle East.

Source: Ernst and Young* More worrying for oil and gas investors is the apparent disconnect between share prices and oil price in the E&Y plot above. Over the last 18 months stable oil prices have been met with declining share prices.

Investor sentiment: Currently investor sentiment towards the E&P sector seems to be very low. This is partly explained by the investment cycle. A potted recent history of investment in E&P would look something like this:  

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2010 - 2012: a good run of exploration success by companies like Cove Energy and Tullow Oil results in strong share price performance.

New institutional funds pile into various high risk plays, underestimating the risks. Examples include Chariot in Namibia and a host of Falkland Island explorers. All raised significant funding, but did not deliver with the drill bit.

2012-2013: A continuing bad run of drilling results turned the initial enthusiasm to despair and investors exited. Tullow Oil is again a good example of this.

The risk appetite amongst professional investors has been further reduced by the underlying financial and sovereign debt crises. E&P is perceived by many to be the riskiest investment of all.

Many investors are now taking a 'risk off' approach.

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Exploration failure is, unfortunately, not the only example of recent poor E&P company performance. Others include reduced production guidance, equity dilutions and arguments with host governments, to name a few. Faith in the sector has been shaken.

Company performance: so how do investors in small E&P companies assess likely returns, and current and prospective performance? Typically the following are analysed: 

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

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Actual versus prospective growth: reserves additions and production growth dominate here. The recent good news from Forum Energy that production has started from offshore Philippines and that profits and production have increased at Empyrean Energy, have not been enough to offset negative news flow elsewhere.

Technical and non-technical risk performance: mediocre drilling results (Faroe Petroleum) and poor government relations (Bahamas Petroleum impacted by a host government referendum on oil and gas) are just two examples from a raft of bad news. Positive news such as Lekoil's upgrade to resources and Afren's reserves upgrade, both in Nigeria, have been well rewarded by the market. Increasing project complexity and risk in non-OPEC oil is fuel to the fire for those that believe that risk management performance is in decline.

Financing: in today's world balance sheet flexibility is rewarded by investors.

Companies with strong balance sheets are seen to be able to move quickly to monetise resources and grab opportunities. However, investors seem reluctant to fund financially weaker companies that have great opportunities, especially explorers and developers. AIM E&P funding at £621.2M in 2013 is a fraction of what it was in the 2000s. Many believe that AIM O&G sector is too fragmented, and lacking the materiality that investors seek, and the materiality that E&P companies need to monetise projects.

Capital discipline. The E&Y plot above shows that the oil price has been relatively stable for several years. However, costs during this period have been rising steeply, and this has contributed to a softening of share prices.

Capital discipline is the new buzz word and it means that not all discoveries will get commercialised in the short term.

News flow generation: Investors' time frames are narrowing also. Currently many seek news flow over a 6 month period, rising to 12-18 months for the big funds, in their target investments. This comes at a time when project life cycles are getting longer, mainly due to the increased time required for access, seismic acquisition and exploration drilling. The following events tend to move share prices up (or down): o Down: Unfortunately for the sector much of the recent news flow has been negative and share prices have been punished. Examples include: equity issuance (Victoria O&G); production guidance decreases (Ithaca); capex increases; dry wells (e.g. Wessex Exploration's dry hole in offshore French Guiana and Serica Energy's dry whole in offshore Morocco). o Up: Investors will reward the following with share price hikes: discoveries (e.g. Andes Energia light oil discovery in Argentina, Trinity Exploration's oil discovery in Trinidad); farm-downs (Bahamas

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

Petroleum lack of farm-out partner has had a negative impact); and new license awards.

Good due diligence: In addition to the above, the following are also typically addressed as part of investment good practice: o Regional geology and contracts/licences won ( with increased government take around the world applying further downward pressure to E&P company profits). o Company assets: material prospects, resources and reserves. o Competing companies, either in the region or competing for future investment. o Business model, management team, corporate governance, strategy, exit strategy and any analogue transactions.

Current low share prices will be a concern to those sitting on paper losses. Many will worry that one outcome will be increased private equity investment in the sector, crystalizing such losses. Corporate action such as Spike Exploration's purchase of Bridge Energy will not be welcome by some, especially in deals that are at less than NAV. However, perhaps the pendulum has swung too far the other way and there are a number of companies currently trading at a discount to NAV and in some cases a discount to cash. So what triggers will bring investment back to E&P and lead to a sector re-rating?

My top four triggers are: 1. Economy: global economic growth, particularly good news on China.

2. Oil price: firming, with a belief that price is on an upward trend.

3. Company performance: management teams that deliver on their promises, especially with the drill bit.

4. Corporate activity: consolidation of a fragmented AIM E&P market. * Ernst and Young's Oil and Gas Eye provides analysis and commentary on the top twenty AIM listed Oil & Gas shares by market weight. The vast majority of these are E&P companies (rather than service companies).

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How to win bigger than the Bakken Written by Keith Schaefer from Oil & Gas Investments Bulletin In Part 1 I explained how Argentina’s Vaca Muerta shale is the only international play—so far—that looks like it could be bigger than the Bakken.

For investors, the challenge is that most of the activity in Argentina today is controlled by major companies. Names like Shell, ExxonMobil, EOG Resources and Total. Those stocks are not the kind of pure plays that will give investors serious upside from a big discovery.

In fact, there’s really only one way to make a direct investment in Argentina’s shale today—through a junior firm that’s had the foresight to stick with the play since day one.

Madalena Energy—MVN-TSXv; MDLNF-PINK. Madalena was a significant acreage holder in the Vaca Muerta shale back when the whole play was just an engineering pipe dream. The company grabbed nearly 300,000 acres of exploration blocks here way back in 2007—at a time when even shale in the U.S. was just starting to take off.

It wasn’t until three years later that things really started to click in the Vaca Muerta— in November 2010—when major oil player YPF (the federal Argentine oil company, which is publicly traded) brought Argentina’s first shale oil well online here.

That well was drilled into YPF’s Loma La Lata field, and completed (fracked) using fracking techniques of the kind that have transformed U.S. shale. The result was initial production of 250 barrels per day of oil—numbers that at the time were considered a major success in this new basin.

This kicked off a round of frenetic activity in the Vaca Muerta shale. Work that’s shown this formation to have some of the best petroleum geology on the planet.

For one, the shale is exceptionally thick—100-200 metres in the shallower, oily part of the basin and 1000 metres as it dips to west in the deeper gassier parts. It’s also very high in organic carbon—the stuff that sources oil. It has up to 12% “total organic carbon”, or TOC–similar to the peak values seen in mega-producing shales like the Marcellus.

As operators learned more, they realized the Vaca Muerta could be much more productive than first thought. They pushed to understand the rocks and optimize completion (fracking) techniques.

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The result has been steadily increasing flow rates from new wells—and that’s evident in Madalena’s results over the past two years.

When the company completed its first test of the Vaca Muerta in early 2012, the well flowed 314 barrels per day. But just a few months later—in July 2012—the company tested its CAN-7 well at 1,340 barrels oil equivalent per day from a light oil reservoir sourced from the Vaca Muerta. That well showed the huge difference a little knowledge can make in emerging plays.

That learning curve is continuing–with recent wells showing even better performance. Two months ago, Madalena drilled its first horizontal well and it came in at 2,238 barrels of oil equivalent per day. That’s a quantum leap!

This sets the company up for a lot of development work ahead. Initial vertical test wells have already identified six separate light oil pools across Madalena’s acreage in a light oil reservoir sourced from the Vaca Muerta shale.

The Big Prize is the massive Vaca Muerta shale itself, and other tight oil or liquid rich gas plays like the Lower Agrio and Mulichino. The industry pays big to have this kind of stacked formations on top of each other that can be reached from one surface location (called a pad).

Madalena has an independent engineering report showing a best-case estimate of 34.8 billion barrels of oil equivalent in place net to Madalena across its three Nequen basin land blocks.

Projections on recoverable resources are currently pegged at 2.9 billion barrels of oil equivalent net to Madalena, of which ~2.0 bilion barrels are driven by the Vaca Muerta alone.

That’s a lot of oil, gas and natural gas liquids in the ground. And if horizontal drilling and fracking can produce the large amounts suggested by initial testwork, it’s easy to see how the Vaca Muerta could indeed become the leader in the international race for shale.

What’s It All Worth?

The key of course is— what kind of economics will producers like Madalena get when they

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start pulling Vaca Muerta crude out of the ground?

Here are some eye catching numbers: $8,000 an acre. GYP, the provincial (Nequen) oil company, will likely go public in 2014, and $8000 per acre is the Chairman is saying he’ll get for valuation. Note that GYP holds a 10% interest in all three of MVN’s blocks.

Mackie Research oil and gas analyst Bill Newman says: “If one applies the $8,000/acre value to MVN’s three blocks (135,000 net acres) it equals $1.1 billion.

MVN’s Curamhuele and Cortadera blocks might not attract this valuation given the relatively earlier stage of appraisal.

“However, given the drilling and acquisition activity on and around the Coiron Amargo block, we believe that $8,000/acre for this block is a fair value, which equates to $280 million or ~ $0.77/sh.”

Just one asset–Coiron Amargo is the crown jewel so far for Madalena–is worth 77 cents, and the current share price for the whole company is 65 cents.

Analysts are also estimating that Chevron’s July 2013 joint venture with YPF is valued at $10,240 per acre, and roughly $48,000 per flowing barrel. That makes Coiron Amargo worth 99 cents a share for Madalena.

Energy Prices Are Moving Up; Costs are Coming Down The government ‘s improving fiscal regime helps a lot. Producers are now able to receive an increased price for oil sold outside Argentina—solving the issue of low domestic prices. The fact that 20% of exports are tax-free also adds to the bottom line.

On top of that, Argentina has made recent moves to boost natural gas prices, to $7.50 permmbtu, up from $5.

That should lift economics on many Vaca Muerta wells—given the significant

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volumes of natural gas associated with oil production. Madalena Energy’s recent CAN.xr-2(h) horizontal well tested 2.7 million cubic feet per day, along with big oil production.

The other big part of the profit equation will be drilling costs. That’s where many other shales globally have stumbled—with high costs for drilling and completing wells eating up profits from the ensuing production.

But the Neuquen basin is a mature petroleum-producing region–so road access is good, and there’s a lot of pipelines and infrastructure already there. That cuts down on costs for bringing in drilling rigs, and for tying in production once wells have been completed.

The Neuquen also has a key drilling resource: water. In other parts of the world, fracking activity is limited by water availability. But the nearby Limay and Colorado rivers should help Vaca Muerta producers overcome this challenge, and avoid the high cost of sourcing far-afield water.

Parts are a big question for the Vaca Muerta. But the government is making a specialized industrial park just to service drilling and fracking.

All of this suggests Argentina has a legitimate shot at becoming The World’s Next Big Shale Play—with a billion-barrel prize for early developers.

The last thing to remember about Madalena—is management. CEO Kevin Shaw spent a lot of time in the field before spending some time as one of Canada’s top oil and gas brokerage analysts.

Ray Smith is the Chairman. Smith has set a new bar for Canadian management teams in attracting foreign joint ventures into his Alberta gas play, Bellatrix Explorations (BXE-TSX/NYSE). Madalena has the potential to do the same in Argentina, and with their assets in Canada.

It all creates some exciting blue sky numbers–and an obvious exit strategy with all the Petro-Majors involved in the Vaca Muerta–for investors to think about.

View more quality content from Oil & Gas Investments Bulletin

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OilVoice Magazine | MARCH 2014

East Africa oil & gas outlook: Global export hub by 2020?

Written by Mark Young from Evaluate Energy East Africa could become the world’s next oil and gas export hub by 2020, according to a new report by Evaluate Energy. There are three countries with ambitions to make this a reality; Kenya, Mozambique and Tanzania. If even one of these countries achieves its goals, the impact on the global oil and gas industry would be very significant indeed.

The landscape of African oil and gas has changed very little in the last 20+ years.

Historically, it has been the more economically developed Western and Northern countries that have produced the most oil and gas. Only Angola has stepped out of relative obscurity since 1990.

Source: Evaluate Energy Angola has changed dramatically since 2000 and is the only country in the last 25 years to have increased production from under 500 bbl/d to rival the continents biggest 4 producing countries; Algeria, Nigeria, Libya and Egypt. Every other country in Africa produced 100,000 boe/d or less in 2012. African oil exports have therefore been restricted to coming from 4 of these 5 countries as well; Egypt is the only one of the big producers to import more oil than it exports. Angola is now the second

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largest oil exporter compared to its imports in the entire continent; Angola exports 1.7 million more barrels of oil than it imports each day. Angola also has a Liquefied Natural Gas (LNG) export terminal with a capacity to export 5.2 million tonnes of LNG per year (mtpa) that became operational in June 2013. Angola has shown just how quickly things can change with major investment into a developing country with large natural resources.

Recent developments in the exploration and production industry in 3 East African countries - Kenya, Mozambique and Tanzania - have laid a possible foundation for one or maybe some of these countries to follow in Angola’s footsteps on the path to exporting oil and gas on a major scale. This would end a 20+ year period of relative status-quo – Angola notwithstanding – on the continent. All 3 of these countries should be the main attraction of any new African investment before the end of the decade because of these export ambitions, which could represent a major opportunity for all E&P companies involved in the region, no matter their size.

These 3 export projects, which are the focus of Evaluate Energy’s new East Africa Oil & Gas Outlook report, make East Africa the continent’s region to watch for the remainder of the decade and the E&P companies involved very interesting prospects in the immediate future.

Overview of East African Export Ambitions: The $25.5 Billion LAPSSET Project is underway, focused on exporting oil and gas from 3 countries out of Lamu Port on the northern coast.

Multi-tcf deep-water gas discoveries by experienced IOC’s have been made Mozambique and wealthy NOC benefactors mean that LNG exports are a real possibility in the very near future.

Huge gas discoveries by IOC’s with LNG export ambitions and a separate Tanzania Chinese-backed mega-port at Bagamoyo is planned.

Kenya

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OilVoice Magazine | MARCH 2014

Ghana's Jubilee oil field - stable or stagnating?

Written by Mark Young from Evaluate Energy In December 2010, the first oil was produced from Ghana’s Jubilee field, breaking a record for major deepwater development, as this was only 3.5 years after the field’s first discovery well. Tullow Oil (the unit operator – see note 1) led the celebrations, along with its major partners Kosmos Energy and Anadarko Petroleum, and the future for the field looked really bright. But although production now averages at around 100,000 barrels of oil equivalent per day (boe/d), issues are beginning to pile up and progress has been virtually non-existent since first oil. The field’s performance looks stable but may in fact be stagnating, according to this new analysis of annual 2013 data by Evaluate Energy, which holds financial and operating data for every publicly listed oil and gas company in Africa.

Kosmos Energy, the technical operator of the field (see note 2) and 24% owner, is probably the most exposed to the risk associated with the Jubilee field experiencing operational issues; Kosmos’ only producing asset is the Jubilee field. The company has just released its 2013 annual results and the operational data for Jubilee begins to highlight the problems.

Production has been relatively stable since a fall back to initial rates at the start of 2012, according to Kosmos’ quarterly data from Jubilee’s first oil.

Source: Evaluate Energy

The Jubilee partners noticed this fall in production and began what they called

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Jubilee Development Phase 1A, which involved drilling 5 new producing wells and 3 injection wells to bring production back up towards peak levels. Despite this, the producing facilities continued to experience technical issues into 2013, which caused unplanned downtime and a fall in production. Most of the companies’ efforts and cash have so far been spent on maintaining the field’s performance rather than improving it; reserves have also been stable since first oil.

Source: Evaluate Energy

Kosmos’ proved reserves data shows a steady increase in the developed percentage of total reserves and also shows that total reserves have not really changed in the 3 years of the field being operational. Proved reserves life at the current rate of production (97,500 boe/d was the average in 2013) without further development is now down to just over 6 years - at peak rate of 130,000 boe/d its even lower.

So the logical conclusion for the companies here is surely to invest heavily in development, try to unlock further reserves, enable an increase in production to raise more cash and then continue to reinvest. However, if the companies’ dealings with the Ghanaian government so far are anything to go by, this will prove to be much easier said than done. It is here where the main reason lies as to why this record breaking deepwater field has seemingly stagnated from the companies’ perspective since first oil.

The first step of investing heavily in development is being held back by the delay in finalising the Jubilee Full Field Development Plan (JFFDP) with the Ghanaian government, which is aimed at unlocking the full potential of the record breaking field. Kosmos states in its annual report that a plan was submitted to the government in December 2012. More plans are expected to be submitted in 2014, but Kosmos is quick to state that it can offer no assurances over approvals being received at all.

Even if the plans are approved quickly and the field is set for “full development”, there have also been delays with gas production facilities that mean production couldn’t be increased straight away anyway. A government project to build a pipeline and gas processing facility has fallen behind schedule, meaning the companies have no export plan for the associated gas being produced right now. Flaring would normally be an unhappy alternative here but the government has not granted the

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partners with a substantial-enough flaring license either, meaning any kind of immediate ramp-up in production due to the gas involved is impossible. The government is clearly paying a great deal of respect to making sure the oil is produced at a steady, manageable, and sustainable rate, but this is clearly at odds with how the companies actually doing the work want to move the project forward.

The current situation at the Jubilee field could be seen as stability or stagnation, depending on your own perspective. Either way, the situation is obviously not ideal for the operators and stands in stark contrast to the euphoria in 2010 upon first oil. If these governmental issues are not sorted, the situation will not end any time soon.

The fact that even a record breaking mega project with such large potential is vulnerable to issues on this level is important to note. In particular, it should serve as a warning to companies and government bodies involved in the other African countries with major discoveries of their own, such as Kenya, Mozambique and Uganda. High resource figures and record breaking development timescales are obviously desirable, but the key for prolonged, successful oil and gas production seems to be a high level of cohesion between all relevant parties – and definitely a higher level of cohesion than is on show in Ghana right now.

This report was created using the Evaluate Energy database. Evaluate Energy provides efficient data solutions for oil and gas company analysis, with 20+ years of financial and operating data for the world’s biggest oil and gas companies, as well as every publicly listed company in Africa. Now, All SEC-reported operational data, including oil and gas proved reserves, costs incurred and discounted future net cash flows, is now all available for Africa as a stand-alone region. For a demo of Evaluate Energy’s African Company database, click here.

1) The Unit Operator is responsible for drilling and completing the development wells for the Jubilee Field development, according to the specifications outlined by the Integrated Project Team (IPT), and providing other in-country support. Upon first production, the Unit Operator assumed responsibility for the day-to-day operations and maintenance of the Floating production, storage and offloading vessel as well as overseeing and optimizing the reservoir management plan based on field performance, including any well workover activity or additional infill drilling and subsequent phases.

2) The Technical Operator led the IPT, which consisted of geoscience, engineering, commercial, project services and operations disciplines from within the Jubilee Unit partnership. The technical operator evaluated the resource base and developed an optimized reservoir depletion plan. This plan included the design and placement of wells, and the selection of topside and subsea facilities. Responsibilities also extended to project management of the design and implementation of the complete field development system.

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Health, Safety, Environment and Risk Management RPS Energy is a global multi-disciplinary consultancy, providing integrated technical, commercial and project management support services in the fields of geoscience, engineering and HS&E.

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OilVoice Magazine | MARCH 2014

Why Shell needs this junior's big play Written by Keith Schaefer from Oil & Gas Investments Bulletin Elephant hunting for huge international oil plays usually means going into (very) politically risky areas. That’s what makes junior Petromanas (PMI-TSXv) stand out from the crowd.

They’re chasing a potential 500-800 million barrel target in Europe—Albania to be exact. Lots of energy investors are familiar with Bankers Petroleum and their heavy oil play there—it’s the largest onshore oilfield in all of Europe.

But few people know about Petromanas. I expect that to change in a hurry in Q3 2014 if their next well hits. They already have one success under their belt.

But even better, they’re getting carried for $100 million on exploration and seismic costs on two high-impact Albanian blocks by oil industry super major Royal Dutch Shell (NYSE:RDS.A). Plus, Shell paid them cash for their sunk costs.

It’s rare to see a super major aggressively seek out a partnership with a company the size of Petromanas. Shell’s interest is a huge validation of the true potential of the assets that Petromanas owns.

However, Shell knew the geology very well—they’re already a partner in two large producing properties that are analogous to the Petromanas property in Albania, just across the Adriatic Sea from Albania in Italy.

Not only does Shell bring to the party big financial and geological resources, but also in this case specific field experience in this particular type of play. (It’s a sub-thrust play which is very similar to what you see in the Canadian foothills in western

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Alberta).

I was intrigued by Shell’s interest in this play so I called up Petromanas CEO Glenn McNamara to get some background.

He said Shell had started expressing interest in the property even before Petromanas had formerly opened up a data room in 2011 to seek out a joint venture partner. Once the data room was officially opened Shell bid on the property.

McNamara said that Shell’s joint venture bid was clearly one that Shell knew Petromanas would find attractive. Shell didn’t do any beating around the bush. It wanted these assets.

In February 2012 Petromanas had Shell in as a partner for 50%, and by June of the next year (after the first well) Shell had upped its interest to 75%. Again, they knew the geology.

Those two Italian properties are big, 500 million and 300 million barrel fields respectively.

The first field started production 14 years ago and it is still producing over 80,000 barrels per day. The second field will commence production in 2016 and is expected to hit 50,000 bbls/day quickly.

Individual wells on those fields can be prolific with rates ranging from 1,000 bbls/day up to 7-10,000 bbls/day.

Shell needs multi-hundred million barrel discoveries to move the needle. Clearly Shell thinks it has a good chance of finding something like that in Albania.

A positive needle move is something Shell shareholders would welcome. Despite spending $46 billion on exploration and development in 2013 Shell’s production actually declined by 5% to 3.25 million barrels a day year on year. 2013 earnings were also down from 2012.

Albanian Blocks 2-3 – Activity to Date Shell and Petromanas have already drilled a well (Shpirag-2) on these blocks.

The result of the drilling was a light oil discovery. The well was tested in the fourth quarter of 2013 and flowed at

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rates of 1,500 to 2,200 boe/day (60% oil).

Drilling problems at Shpirag-2 meant they had to tap the reservoir with smaller diameter hole at the bottom—so the rates of the flow test make it difficult to predict how much oil the well can produce.

But the discovery at Shpirag-2 did confirmed there is definitely oil in the tank.

The question now becomes “how much oil”?

To help determine that, Petromanas and Shell will be drilling another well (Molisht-1) 18 kilometers to the south.

When I spoke with CEO McNamara he was clearly trying to keep a lid on his enthusiasm, but he did say that the Molisht-1 well target could actually prove to be the same structure as the Shpirag-2 well.

That would mean this discovery is actually an oil field that is at least 18 kilometers long.

If that is the case, it could easily mean that this field is 500 million to 800 million barrels in size.

That is the potential. The challenge with this play is that the wells are very complicated and very expensive.

Which is another reason why having Shell as a partner is a big plus for Petromanas.

Shell has been drilling exactly these types of wells for 15 years across the Adriatic in Italy.

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Experience counts, but even after 15 years, these wells aren’t easy for even Shell to drill.

The complication lies in the fact that the companies are drilling through a “flysch shale” rock enroute to the carbonate reservoir. It is flaky stuff that is not very stable.

On the Shpirag-2 well the rock caved in on the drill string three times.

Petromanas CEO McNamara described the flysch shale rock as being “coal like” with a tendency to “sluff” in on the well bore.

Every well sounds like a challenge.

On the Shpirag-2 well those challenges compromised the actual flow rates. That well ended up being only 4.5 inches in diameter instead of the 6 inches that the companies had hoped to use.

As I said, we know there is oil in this tank. We just need another well or two to understand how much oil is there and how profitable it will be to produce.

Shell’s interest in this Albanian property is what put Petromanas on my short list.

Some back of the envelope math is what keeps the company close to the top of that list The size of the prize here is huge. We are talking about 500 to 800 million barrels.

And these aren’t resource-play barrels that require hundreds of wells that decline very quickly. This is a conventional play–prolific wells with lower decline curves.

Little Petromanas could have a 25% interest of a 500 to 800 million barrel field. That would be 125 to 200 million barrels net to them. Based on the analogous fields across the Adriatic in Italy, barrels in this type of field have NPVs (net present values) of $10 to $12 per barrel.

Now the simple math: 120 million barrels worth $10 each adds up to.... $1.2 billion.

Petromanas has a market capitalization of $90 million and an enterprise value of $60 million (market cap less cash on hand).

Now, Petromanas has had to issue a lot of stock for that money—there is now 694 million shares out basic and 890 million fully diluted. That’s 100 million warrants at 45 cents due February 2015, 50 million performance shares depending on how much oil is discovered, and 46 million options at an average 27 cents.

So at some point, management will almost certainly do a reverse split. But with a good well, that will mean the stock trades higher, not lower.

And if this Albania play is the real deal Petromanas isn’t going to be a double or

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triple. Petromanas has the potential to be a multi-multi-multi-bagger. 1.2 billion divided by 60 million = 20x.

That’s the potential. It’s exciting and why I’m interested, but it is very important to note that this Albanian play has not been “de-risked”. Petromanas CEO McNamara was careful to stress that several times when I spoke to him.

We know there is oil, the Shpirag-2 discovery confirmed that. And we know the tank appears to be very large.

What is needed next are a couple of additional wells to provide further detail on the find and a better indication of commerciality.

There are two big events for Petromanas in 2014.

The first will be the results of a new 51-101 resource assessment that Petromanas will get from a third party. TSX listed stocks must get independent resource appraisers. Since the last resource assessment was done Petromanas has obtained twice as much seismic data on the play and drilled a well.

Petromanas believes one interpretation indicates that the structures could be a lot bigger than they appeared the first time around. Now we need to wait and see if the resource appraiser confirms this, and just how big they think it is.

I think there is a very good chance that the third party reserve engineers come back with a big increase to their original resource assessment.

I would expect those resource assessment numbers to show up in the second quarter.

The second big event is the Molisht-1 well. Results from that well are expected in the third quarter of this year. It is possible this well will confirm that it has been drilled into the same structure as Shpirag-2 which is 18 kilometres away.

That would be a day that Petromanas shareholders would welcome.

View more quality content from Oil & Gas Investments Bulletin

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Why none of us can ignore the fate of North Sea oil Written by Economics Editor Ed Conway from Sky News It’s easy to forget just how important a contribution oil and gas makes to the UK economy. Britain, after all, is a large and highly-diverse economy. But while it’s not a pure petro-economy, by the same token there is simply no way the economy would have been as strong as it was or its public finances in decent (pre-crisis) shape were it not for North Sea oil.

Oil and gas production from the North Sea (DECC)

Consider the following: at its peak in 1999, the UK was pumping out more oil each year (about 2.9m barrels a day) than OPEC members Iraq, Kuwait or the United Arab Emirates. In the 1980s, though total production levels were a touch lower, tax revenues from the North Sea nonetheless accounted for a large chunk of the Government’s total takings: peaking at more than 8% in 1984.

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Even though the output from UK fields has dropped sharply in recent years Britain still produces more oil, in absolute terms, than Oman; more oil and gas combined than Azerbaijan.

In fact, while the simple amount of oil and gas being pumped out of the North Sea might have fallen, the fact that the oil price has risen during that period from below $20 a barrel to over $100 a barrel has meant that even that reduced amount has boosted Britain’s fortunes. Since the turn of the millennium the share of Britain’s goods exports accounted for by oil has risen from just over 5% to almost 14%. That’s the highest share since the mid-1980s.

And there is plenty of it left. About 42 billion barrels of oil equivalent have been extracted since 1965; there is probably about 24 billion still left. The problem is that the remaining stuff is harder to get hold of – it involves reaching into deeper waters, digging deeper underground and squeezing more resource out of older fields, rather than hoping for brand new discoveries. That, in turn, is changing the make-up of the sector. Whereas in the glory days of the ‘80s and ‘90s the big players were the oil majors – Shell, BP, Total and so on – the North Sea is increasingly home to socalled “scavenger” firms which buy old, abandoned fields and attempt to maximise return from them.

Total reserves in North Sea vs amount recovered (Wood Review)

That change in constituency means it’s highly sensible for the Government to consider a shake-up in the regulation of the sector, as Sir Ian Wood’s report into the future of the North Sea today recommends.

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However, all of this could end up being moot if the Scottish people vote for independence. Which raises a few vexed questions. First, how much of the existing output should go to Scotland? If one were dividing it based on geography, isolating the fields of the Scottish coast, around 90% of production would go to an independent Scotland. However, if one were dividing it based on population, then on a per capita basis the share would be closer to 8.4%.

The oilfields that would go to Scotland under potential Independence, according to a geographical split (Scottish Government)

That’s clearly an enormous difference. Were it to be divided on a geographic share, the rest of the UK would miss out on almost £6bn of tax revenues, equivalent to an almost 2% increase in basic rate income tax for every member of the population.

However, set against that is the fact that it would no longer have to take care of Scottish social spending, which is considerably higher than for the rest of the UK. Were the oil production to be split up on a per-capita basis, it’s hard to see how Alex Salmond could make his sums work.

But the split would also raise some more important long-term questions for both sides. The Wood Review today nukes the notion that the North Sea is all but dead.

However, it underlines the volatility of the sector. An independent Scotland really would be a petro-economy, its demand and income buffeted about as the oil price rose and fell. By the same token, the rest of the UK would lose out on one of the main sources of its exports. The balance of payments – already extremely nasty –

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would be even deeper in negative territory.

In short, there are significant dangers on both sides.

Finally, there is the question of why Britain never set aside its oil revenues and did as Norway did, setting up a sovereign wealth fund for the nation’s long-term economic health. There is no good answer for this, save for that it was a decision of successive governments (Labour and Conservatives) to use the proceeds for today’s consumption rather than saving it for tomorrow. It helped support Britain through what would have been even darker economic days in the late ‘70s and 80s.

Was it wise that such an enormous sum of money, over £300bn, was spent rather than set aside? Today’s younger generation is facing decades of higher taxes to pay off Britain’s enormous national debt; however, some would argue that this would have been the case whatever the treatment of the oil revenues. Either way, there is no satisfactory answer to this vexed question – save that it will continue to spark anger as long as the oil keeps pumping, and probably some years thereafter.

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The hidden risks of development decisions Written by Hiren Sanghrajka from Upstream Advisors The pre-decision process is increasingly important as production risks and costs escalate for both large and small plays, says Hiren Sanghrajka of Upstream Advisors The commercial landscape for oil and gas production has never been straightforward. Early stage planning has always been of paramount importance but today it has become increasingly vital to get it right as a range of factors continually transform the risk picture.

A study published this month, into project execution and budget overruns by the Norwegian Petroleum Directorate (NPD), pinpointed insufficient planning at the front-

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end engineering and design (FEED) stage as one of the most critical failings of projects that had seen their schedules and budgets balloon.

All projects reviewed that had huge time and cost overruns, had major shortcomings in the early design work, said NPD's Evaluation of Implemented Projects on the Norwegian Shelf report, referring to all engineering work before delivery of the proposed development option (PDO) and before procurement and construction starts.

Flaws and faults in the early planning will propagate further in the project. Time spent early in a project's life is crucial to the success of completing the project within time and cost estimate and according to quality standards, the report added.

So how and why does this happen?

One of the key reasons is pressure from shareholders. Many companies tend to rush into projects in order to demonstrate value creation to their investors. This in turn puts heat on project managers to make rapid progress and shorten project cycles because their reputations are at stake.

Furthermore, it's easy to under-estimate the number of preliminary decisions that have to be made during the evaluation of a project and, as a result, get lost in the 'decision jungle'. As soon as that happens, the risk of a poor outcome obviously increases.

Effective pre-decision management is really about orchestration and leadership: knowing all the players, everything that is involved in making the best decision possible. It demands a properly structured pre-decision process, based on a lot of detailed experience.

There is always a way to make good early stage decisions, no matter how small or big you are, which fully takes into account all these developing risk factors and any others than may come down the track. At Upstream Advisors, we have collaborated with many clients in this field and have helped them through a management process that ensures that every option is considered in an equal and balanced way.

As advisors, we are driven by process, industry knowledge, understanding of current issues and perspective. What militates against this are things like gut instinct, bias, hunches and overly compressed timetables, all which tend to precipitate bad decisions.

Even the most scrupulous companies with the most sophisticated processes and systems in place can benefit from having an external eye. At Upstream Advisors, we have heard the majors saying they could have done with an outside view on things earlier.

Of course, attention to detail is key; it's so often the small things you don't think about that come back to bite you. But knowing what those small things might be comes with experience of many different early stage projects. Unfortunately, there is no one universal project tick list.

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Given the sums involved in many major projects and the substantial knock-on costs and effects of a bad decision, an external audit can add significant risk management value for a relatively tiny cost.

There are many issues in play at the early stage decision making-stage- and subsequently many instances of where things can go wrong.

The increasing complexity of exploration as frontiers are extended into ever more challenging environments and depths and a background of a chronic skills shortage and tight supply markets, are all very real factors in today's market.

These factors are pushing for new technology not only to tackle the new scenarios but to increase efficiency, particularly in production drilling, well completion, and floating production facilities with subsea wells. The implementation of this new technology has introduced significant new uncertainties that are not adequately considered in the budgeting and execution of projects.

Throw in the changing face of regulations to the equation and early stage decision making suddenly looks a lot more challenging than it was in years gone by.

This is especially true for the growing number of National Oil Companies and small and medium enterprises entering the scene, which, unlike super majors, simply don't have the experience or permanent in-house capabilities.

Unpicking a decision and building the case for pursuing another option should never be seen as anything other than a major 'win' saving an organisation from sometimes inestimable financial and reputational costs of going down the wrong road.

The truth is that in most cases, in order to speed up, you need to slow down.

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OilVoice Magazine | MARCH 2014

Manufacturing innovation powers growth across Britain's oil and gas supply chain Written by Graham Dewhurst from Manufacturing Technologies Association (MTA) The oil and gas sector is a shining example of how Britain is building on its proud heritage as a world-class manufacturing base. MTA Director General Graham Dewhurst discusses how vital it is to maintain a technological competitive edge ahead of MACH 2014, the UK’s largest manufacturing technologies show.

Oil and gas supply chain companies make a significant contribution to the UK economy. The sector encompasses thousands of firms and represents a core component of the British engineering and manufacturing base. This is reflected in the growing importance placed on the sector by MACH exhibitors.

The supply chain supports the oil and gas industry across all of its requirements – from seismic acquisition of reservoir data, through exploration and appraisal drilling, field developments and production operators, to decommissioning at end of life. In the 2012 Oil Field Services Report for the UK, published by Ernst & Young (EY), the combined activity of 390 companies was found to be providing direct employment for almost 93,000 people and generating £27 billion in revenues.

Shale gas boom Meanwhile, the shale gas boom is seeing a number of notable British industrial companies benefit. These include pump-maker Weir Group, and Rotork, the world’s largest producer of valve actuators and control systems. Weir Group increased its involvement in the industry at the end of last year following its acquisition of Mathena, the US equipment supplier to the onshore oil and gas drilling sub-sector, while Rotork is reported to have seen a 15% increase in its order book since the turn of 2013.

Another major player, Newcastle-based flexible pipeline specialist GE Oil & Gas, was awarded £3 million recently by the Regional Growth Fund to increase its manufacturing capability and build on its leading offshore research role for liquefied natural gas (LNG) market. This is expected to create more than 120 new jobs while

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safeguarding 80 existing posts.

GE’s broader strategy to keep pace with the global demand for critical subsea production components has seen it invest £10.4 million in its Brent Avenue site in Montrose, Scotland. The expansion includes a new 2,250 square metre assembly and test facility, which will allow for the in-house manufacturing of large, deepwater horizontal subsea trees used in the extraction of oil and gas reserves from the seabed in some of the most challenging environments across the globe. It will also lead to a significant increase in machining capacity, from 63 systems a year to more than 90, as well as in-house machining of much larger vertical tree systems.

Advanced manufacturing 2014 is set to be a bumper year for market in machine tools and related equipment WITH THE MTA predicting solid growth over and above the levels reached in 2012 and 2013. Other aspects of manufacturing technology such as metrology (measuring) equipment and computer aided design and manufacturing systems (CAD/CAM) combine with the machines, tooling and work-holding equipment to deliver complete systems, making manufacturing technology fundamental to the nation’s economy.

Despite being ignored for some time, the innovators have continued to innovate. This has ensured Britain continues to boast truly world-class and high-value-added industries. New ways to realise design and new modes of production are changing the way products are made. Coming under the umbrella term of ‘advanced manufacturing’, we are seeing the implementation of innovative technology to improve products and processes from design, concept and prototyping, through machining of raw material to delivery of the finished product.

Much of the innovation we are seeing today in advanced manufacturing technology is around processes rather than hardware. For example, design and prototyping can now be downloaded directly to machine tools, and the manufacturing process controlled and refined remotely. This is particularly important for sectors such as oil and gas, because much of the design takes place in regional centres of excellence, with subsequent manufacture completed in low-cost markets.

At the same time, oil and gas hardware and services are being exported globally, with hubs such as Aberdeen and Newcastle acting as gateways to markets including the Gulf of Mexico, Gulf of Arabia, Indonesia and Australia. Smaller companies too are playing an essential role in driving innovation and with better access to finance and support from across the supply chain, will continue to flourish.

Maintaining the strategic edge Recognising the economic importance of the sector, the UK government published an oil and gas strategy in the spring of 2013. Managed jointly by the Department for Business, Innovation and Skills (BIS) and the Department for Energy and Climate Change (DECC), the strategy aims to secure billions of pounds of future investment and thousands of jobs. It includes a pledge to maintain a fiscal regime encouraging investment and innovation, as well as measures to boost supply chains and tackle

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OilVoice Magazine | MARCH 2014

the engineering skills gap.

The strategy included £7 million for a new research facility known as the Neptune National Centre for Subsea and Offshore Engineering. The new facility will be based at Newcastle University and will act as a place for industry and academia to interact, providing crucial infrastructure for emerging research opportunities. The Neptune Centre will also have a strong element of developing highly-skilled graduates to help address key skill shortages.

With Britain’s industrial base now recognised as holding as important a place in the economy as sectors such as financial and professional services, the government is looking to rebalance the economy, rebuild supply chains and nurture artisan skills.

One organisation tasked with furthering these objectives is the Technology Strategy Board (TSB). Working across business, academia and government to help companies take ideas through to commercialisation, the TSB is currently overseeing the creation of a network of world-leading technology and innovation centres known as ‘Catapults’.

The Catapults cover a range of sectors including High Value Manufacturing. The High Value Manufacturing Catapult is building on the strength of seven constituent institutions, one of which in particular, The University of Sheffield’s Advanced Manufacturing Research Centre (AMRC) has been a great example of collaboration between academia, industry and government.

The Catapults represent a win-win scenario, whereby Britain’s engineering and science graduates and apprentices are nurtured in a high-technology and innovative environment that will ensure they are fit-for-purpose when they enter the global economy. A prosperous high-tech UK manufacturing industry depends and thrives on a highly-skilled and knowledgeable workforce, so a strong foundation of trained staff and well-educated students will enable Britain’s manufacturing industries to maintain their competitive edge and successfully compete on the international stage.

The theme of MACH 2014 is ‘innovation in action.’ It is the UK’s largest event for Manufacturing Technologies. Over five days, more than 20,000 visitors will see some 500 exhibitors putting their latest technologies and innovations through their paces to register for the event go to www.machexhibition.com

View more quality content from Manufacturing Technologies Association (MTA)