oilvoice magazine | march 2014

8/12/2019 OilVoice Magazine | March 2014

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Edition Twenty FourMarch 2014

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

The only play on earth bigger than the Bakken

Cover image by Berardo62


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1 OilVoice Magazine | MARCH 2014

Issue 24 March 2014

OilVoiceAcorn House381 Midsummer BlvdMilton KeynesMK9 3HP

Tel: +44 208 123 2237Email:[email protected]: oilvoicetalk

EditorJames AllenEmail:[email protected]

Director of SalesTerry O'DonnellEmail:[email protected]

Chief Executive OfficerAdam Marmaras

Email:[email protected]

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Adam Marmaras

Chief Executive Officer

Welcome to the 24th edition of theOilVoice Magazine.

Hmmmm, 24 editions? That mustmean it's our second anniversary.Time certainly has flown. I rememberwhen we first launched we considereddoing a printed version of themagazine. At the same time we were

reading about magazines likeNewsweek going digital only. And frompeople I know in the oil magazinepublishing business, it's no easy taskto print and distribute hard copies. Sowe stuck to digital, and I'm glad we did.We enjoy putting the magazinetogether and getting it out to themarket. I think a printed version wouldcause a few sleepless nights.

This month we have great articles fromEuan Mearns, Keith Schaefer, AngusWarren, Mark Young and GrahamDewhurst.

We'd also like to introduce some newauthors to the fold, including EdConway from Sky News, and HirenSanghrajka from Upstream AdvisorsLtd.

If you've been reading the magazinefrom the start, then thanks for yoursupport. If it's your first time, thenwelcome!

Adam Marmaras

CEO

OilVoice
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Contents

AuthorsBios for this months featured authors 3UK shale gas potential and perspectivesby Euan Mearns 4The only play on earth bigger than the Bakkenby Keith Schaefer 11Why have investments in E&P performed so badly?by Angus Warren 13How to win bigger than the Bakkenby Keith Schaefer 18East Africa oil & gas outlook: Global export hub by 2020?by Mark Young 22Ghana's Jubilee oil field - stable or stagnating?by Mark Young 25Why Shell needs this junior's big playby Keith Schaefer 29

Why none of us can ignore the fate of North Sea oilby Economics Editor Ed Conway 34The hidden risks of development decisionsby Hiren Sanghrajka 37Manufacturing innovation powers growth across Britain's oil and gassupply chainby Graham Dewhurst

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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-hourtelevision news service operated by Sky Television, part of British SkyBroadcasting.

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 TechnologiesAssociation.

Euan Mearns

Energy Matters

Euan Mearns has B.Sc. and Ph.D. degrees in geology.
http://oilandgas-investments.com/http://oilandgas-investments.com/http://www.evaluateenergy.com/http://www.evaluateenergy.com/http://www.edmundconway.com/http://www.edmundconway.com/http://www.upstream-advisors.com/http://www.upstream-advisors.com/http://www.mta.org.uk/http://www.mta.org.uk/http://euanmearns.com/http://euanmearns.com/http://euanmearns.com/http://www.mta.org.uk/http://www.upstream-advisors.com/http://www.edmundconway.com/http://www.evaluateenergy.com/http://oilandgas-investments.com/


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UK shale gas potentialand perspectives

Written by Euan MearnsfromEnergy Matters

In order to place some perspectives on social and environmental impacts ofshale 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 initialproduction declining 33% in year 1. This is an optimistic guess based onproduction 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 todays 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 naturalgas.

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

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

Figure 1Thedistribution of theBowland-Hoddershale in England. Theareas in red delineateland where the shaleis present at depth inthe sub-surface [1].
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the potential of the Bowland-Hodder shale, the highlights of which are summarisedbelow [1]. It needs to be stressed that without test data from at least 10 to 20exploration wells it is impossible to assess the potential with any certainty. It mayturn out that Bowland is a super rich shale to rival the Marcellus of the USA, or it mayturn out to be a dud like the recent Polish experience. Shale plays are also non-

uniform and tend to have sweet spots that can only be identified through quiteextensive exploration drilling. The main focus of this post is to try and place theuncertain potential into a perspective for what this may mean for the UK in terms orproviding 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 hasbeen converted to gas (or oil in the case of shale oil). Not all so-called gas shalesare shales; some are limestones and some are tight (impermeable) sandstones. Thelack 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 compriseplant material or marine organisms that when buried and subject to pressure,elevated temperatures and time, is slowly converted to oil and gas. This process iscalled maturation and very generally the hydrocarbon window may occur at depth of10,000 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 onthe BGS report [1] that has a quite readable two page summary (link at end of thispost).

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 to16,000 ft, which is much thicker than many of the N American shale plays. But theorganic matter content is relatively lean at 1 to 3%, it would have been better had thethickness 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 someareas have been uplifted, hence gas bearing shales may be encountered atshallower 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 areshown in Figure 2. With a range of numbers, the one to focus on is the P50estimated 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 86tcf. 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 bedeveloped commercially and the numbers here are much smaller with a guesstimateof 4.7 tcf. As we shall see below, that sort of recovery level will make little differenceto the UKs lamentable energy status.

UK shale gas production perspectives

I wanted to try and place the hype around UK shale gas into some form ofperspective. Without test data from exploration wells, this is quite impossible to dowith any meaningful certainty. But here goes

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

Figure 2Resourceestimates for the Upperand Lower Units of theBowland-Hodder shale [1].

Figure 3Average

production profiles forshale gas wells in theUSA [2]. Note units aremillion cubic feet peryear.


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The result is shown in Figure 6. Drilling 1000 shale wells between 2016 and 2025would stabilise declines from conventional gas creating a production plateau of about1.5 tcf / annum, compared with current consumption of around 2.8 tcf / annum. Thisoutcome would significantly reduce UK future dependency on imported gas (Figure6) but would still leave us importing about 50%.

Figure 4Based on the data in Figure3, if the UK gets lucky, a well mayproduce 1000 million cubic feet peryear in its first year translating to about3 million cubic feet per day at the

beginning of year 1. Modelled declinerates are shown as percentage values.Shale wells decline extremely fast inthe first years of operation and thendecline slows in the tail. Ive beenadvised that the rather steep declines Ihave used here could even prove to beoptimistic. This is all guess work andreality may turn out to be very different.

Figure 5Assuming that 100 wells aredrilled per year, the production stackafter 10 years, when 1000 wells willhave been drilled, takes on this sharkfin shape that is characteristic of shaleprovinces. Each slice representsproduction from 100 model wells asdepicted in Figure 4.

Figure 6Historic UK conventionalNorth Sea gas production (BP)amounts to 86 tcf, 19702012. Theprojection includes a 10% declinewhich is the historic average. Withoutshale gas, conventional gas will havedeclined to near zero come 2025. The100 well / year model (Figure 5) wouldstabilise UK production at about todayslevels. The 8.2 tcf production estimateis more than double the BGS guess forreserves 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 asecond model simply doubling the number of wells to 200 / year. This lifts UKproduction to about 2.6 tcf / annum by 2025 in which case we would once againachieve self sufficiencya very big prize worth going for!

The catch

If this sounds too good to be true then there has to be a catch. The 100 well / yearmodel contains 8.2 tcf of production, roughly double BGS reserves guesstimate. The200 well / year model contains 16.5 tcf of production. The bottom line, withoutexploration 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 outModel Ts the pace is likely to be more sedate in rural England. Lets imagine it takesa rig 2 months to drill a well, this will dictate the pace of development. That wouldmean 17 drilling rigs operating round the clock to turn out 100 wells per year. Most ofthe population living in cities would notice nothing. Many rural populations wouldnotice something once in a while and may grumble when there was a drillingoperation near by, but then after a short while, the drilling and fracking crews moveon. Landlords would celebrate as highly payed drill and fracking crews movedaround the country.

17 operational rigs doesnt sound a lot spread over a large area. To move up to 200wells / year would mean 34 rigs. If the production results are lower than my modelwell, expect more rigs and less profits, if the production results are higher,proportionally less. Uncivil unrest that disrupts drilling operations and slows themdown 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 potentiallyhave several horizontal laterals off it meaning that the number of drill sites could be

substantially reduced.

Figure 7Doubling the drilling rate to200 wells / year would see UK gasproduction growing significantly,potentially towards a point where wewere once again self-sufficient.


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Environmental impact

One concern with shale gas and fracking operations is the contamination of sub-surface drinking water supplies by drilling fluids, fracking fluids and gas. A study ofdrinking 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 foundto have gas concentrations above 30 ppm, the threshold to take action to mitigatethe problem.

I believe it is the case in northern England that most drinking water supplies aredrawn from surface reservoirs. Society as a whole needs to weigh small andmanageable environmental risks against the potential strategic importance of shalegas to the UK economy and national energy security. There are environmental risksassociated with all forms of energy production. We either accept these risks or sitat home shivering in the dark.

Conclusion

It is vitally important that companies are encouraged and enabled to conductcomprehensive exploration of shale gas resources in the UK in order to evaluatepotential contribution of this energy source to the future UK economy and energysecurity.

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

References

1. Andrews, I.J. 2013. The Carboniferous Bowland Shale gas study: geology andresource estimation. British Geological Survey for Department of Energy and ClimateChange, London, UK. Linkhere.2. EIA Annual Energy Outlook 20123. Robert B. Jackson et al 2013, Increased Stray Gas Abundance in a Subset ofDrinking Water Wells Near Marcellus Shale Gas Extraction:www.pnas.org/cgi/doi/10.1073/pnas.1221635110 Linkhere.

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The only play on earthbigger than the Bakken

Written by Keith SchaeferfromOil & Gas Investments Bulletin

Argentina is the 'Comeback Kid' story of 2014. After getting vilified for nationalizingone large ownership block in the prolific Vaca Muerta shale play in 2012, Big Oil iscoming back in a Big Way-and dragging up the share price of the fast growingjuniors 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-theBakken.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 theworld. And just this month, market strategists Lux Research named Argentina as oneof the top spots to watch in the race to bring shale production to new lands.

In 2012, Argentina became hot as a pistol in thejunior energy markets-and then went from heroto zero as soon as the government announcedit was nationalizing the shareholding of itsNational Oil Company, YPF, that was owned bySpain's NOC, Repsol.

Stocks that had meteoric rises-came down toearth. The leading Argentine juniors had abottoming period through 2013 but are nowmake their way back because Big Oil is pouringa lot of money into the Vaca Muerta shale.

And why are they doing that? Because, as thegovernment said at the time, the Repsol dealwas a one-time thing. And in the two yearssince 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 increasingits 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 todaymade Argentina a great place to work. 'Now we feel a different wind blowing and weare assessing our possibility to invest in exploring the resources,' said the company'sArgentina chief executive officer Juan Jose Aranguren.

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

The Repsol deal was the biggest cloud hanging over the Argentinean energy sector-and 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 torealize they had done wrong. In November 2013, reports emerged that Repsol wouldlikely 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 to20% of their oil and gas output, tax-free.

The government also said it will remove foreign exchange controls for companiesthat invest over $1 billion in Argentina over a five year period, which most petro-majors 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 millionpilot in the Vaca Muerta. All of this cash was earmarked for unconventional shaleexploration and development. Then in late 2013, Wintershall announced a three-phase joint venture in the Vaca Muerta shale for up to $3.3 Billion for a net 12,00acres.

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 'powerfulgovernment incentives' in Argentina make this one of the best destinations going forunconventional (tight oil) plays. Despite the growing excitement over Argentineanshale, there's an issue here for investors. How to play this emerging story?

View more quality content fromOil & Gas Investments Bulletin
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Why have investmentsin E&P performed so

badly?

Written by Angus WarrenfromWarren Business Consulting

Introduction:There's a good chance that many readers' investments in E&P havedisappointed in recent years. Even the super-sluggish Supermajors and mid-sizedcompanies 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 onLondon's AIM market have seen share prices decrease by over 40%, over the last 3years according to the FT:

Source: Financial Times

So what's driving investor thinking and can we expect any relief from this period ofunder-performance?

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

Macroeconomics:oil demand is strongly correlated with economic growth and withthe news from China and India that their economies are starting to slow, and furthernews that recent recoveries in the US and UK may not be sustainable, interest in oiland gas investment has waned. However, support is provided by a weakening dollar(which often leads to higher oil prices) and the continued expectation that interestrates 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 havethe upper hand. Concerns over global economic growth, and increased suppliesfrom Iraq, Iran (with loosening sanctions) and oil shale oil in the U.S., have trumpedshort 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 shareprices and oil price in the E&Y plot above. Over the last 18 months stable oil priceshave been met with declining share prices.

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

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

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

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

The risk appetite amongst professional investors has been further reduced by theunderlying financial and sovereign debt crises. E&P is perceived by many to be theriskiest 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&Pcompany performance. Others include reduced production guidance, equity dilutionsand arguments with host governments, to name a few. Faith in the sector has beenshaken.

Company performance: so how do investors in small E&P companies assess likelyreturns, and current and prospective performance? Typically the following areanalysed:

Actual versus prospective growth:reserves additions and productiongrowth dominate here. The recent good news from Forum Energy thatproduction has started from offshore Philippines and that profits andproduction have increased at Empyrean Energy, have not been enough tooffset 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 twoexamples from a raft of bad news. Positive news such as Lekoil's upgrade toresources and Afren's reserves upgrade, both in Nigeria, have been wellrewarded by the market. Increasing project complexity and risk in non-OPECoil is fuel to the fire for those that believe that risk management performanceis 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 tomonetise resources and grab opportunities. However, investors seemreluctant to fund financially weaker companies that have great opportunities,especially explorers and developers. AIM E&P funding at 621.2M in 2013 isa fraction of what it was in the 2000s. Many believe that AIM O&G sector istoo fragmented, and lacking the materiality that investors seek, and themateriality that E&P companies need to monetise projects.

Capital discipline.The E&Y plot above shows that the oil price has beenrelatively stable for several years. However, costs during this period havebeen 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 discoverieswill get commercialised in the short term.

News flow generation:Investors' time frames are narrowing also. Currentlymany 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 lifecycles are getting longer, mainly due to the increased time required foraccess, seismic acquisition and exploration drilling. The following events tendto move share prices up (or down):

o Down: Unfortunately for the sector much of the recent news flow hasbeen negative and share prices have been punished. Examplesinclude: equity issuance (Victoria O&G); production guidancedecreases (Ithaca); capex increases; dry wells (e.g. WessexExploration's dry hole in offshore French Guiana and Serica Energy'sdry 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, TrinityExploration's oil discovery in Trinidad); farm-downs (Bahamas


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

Good due diligence:In addition to the above, the following are also typicallyaddressed as part of investment good practice:

o Regional geology and contracts/licences won ( with increased

government take around the world applying further downward pressureto 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 willworry 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 thanNAV.

However, perhaps the pendulum has swung too far the other way and there are anumber of companies currently trading at a discount to NAV and in some cases adiscount to cash. So what triggers will bring investment back to E&P and lead to asector 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 toptwenty AIM listed Oil & Gas shares by market weight. The vast majority of these areE&P companies (rather than service companies).

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How to win bigger thanthe Bakken


InPart 1I explained how Argentinas Vaca Muerta shale is the only internationalplayso farthat looks like it could be bigger than the Bakken.

For investors, the challenge is that most of the activity in Argentina today iscontrolled by major companies. Names like Shell, ExxonMobil, EOG Resources andTotal. Those stocks are not the kind of pure plays that will give investors serious

upside from a big discovery.

In fact, theres really only one way to make a direct investment in Argentinas shaletodaythrough a junior firm thats had the foresight to stick with the play since dayone.

Madalena EnergyMVN-TSXv; MDLNF-PINK.

Madalena was a significant acreage holder in the Vaca Muerta shale back when thewhole play was just an engineering pipe dream. The company grabbed nearly300,000 acres of exploration blocks here way back in 2007at a time when evenshale in the U.S. was just starting to take off.

It wasnt until three years later that things really started to click in the Vaca Muertain November 2010when major oil player YPF (the federal Argentine oil company,which is publicly traded) brought Argentinas first shale oil well online here.

That well was drilled into YPFs Loma La Lata field, and completed (fracked) usingfracking techniques of the kind that have transformed U.S. shale. The result wasinitial production of 250 barrels per day of oilnumbers that at the time wereconsidered a major success in this new basin.

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

For one, the shale is exceptionally thick100-200 metres in the shallower, oily partof the basin and 1000 metres as it dips to west in the deeper gassier parts. Its alsovery high in organic carbonthe stuff that sources oil. It has up to 12% total organiccarbon, or TOCsimilar to the peak values seen in mega-producing shales like theMarcellus.

As operators learned more, they realized the Vaca Muerta could be much more

productive than first thought. They pushed to understand the rocks and optimizecompletion (fracking) techniques.
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The result has been steadily increasing flow rates from new wellsand thatsevident in Madalenas results over the past two years.

When the company completed its first test of the Vaca Muerta in early 2012, the wellflowed 314 barrels per day. But just a few months laterin July 2012the company

tested its CAN-7 well at 1,340 barrels oil equivalent per day from a light oil reservoirsourced from the Vaca Muerta. That well showed the huge difference a littleknowledge can make in emerging plays.

That learning curve is continuingwith recent wells showing even betterperformance. Two months ago, Madalena drilled its first horizontal well and it camein at 2,238 barrels of oil equivalent per day. Thats a quantum leap!

This sets the company up for a lot of development work ahead. Initial vertical testwells have already identified six separate light oil pools across Madalenas acreagein 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 richgas plays like the Lower Agrio and Mulichino. The industry pays big to have this kindof stacked formations on top of each other that can be reached from one surfacelocation (called a pad).

Madalena has an independent engineering report showing a best-case estimate of34.8 billion barrels of oil equivalent in place net to Madalena across its three Nequenbasin land blocks.

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

Thats a lot of oil, gasand natural gas liquidsin the ground. And ifhorizontal drilling andfracking can producethe large amountssuggested by initial

testwork, its easy to seehow the Vaca Muertacould indeed becomethe leader in theinternational race forshale.

Whats It All Worth?

The key of course iswhat kind of economics

will producers likeMadalena 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 issaying hell get for valuation. Note that GYP holds a 10% interest in all three of

MVNs blocks.

Mackie Research oil and gas analyst Bill Newman says: If one applies the$8,000/acre value to MVNs three blocks (135,000 net acres) it equals $1.1 billion.MVNs Curamhuele and Cortadera blocks might not attract this valuation given therelatively earlier stage of appraisal.

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

Just one assetCoiron Amargo is the crown jewel so far for Madalenais worth 77cents, and the current share price for the whole company is 65 cents.

Analysts are also estimating that Chevrons July 2013 joint venture with YPF isvalued at $10,240 per acre, and roughly $48,000 per flowing barrel. That makesCoiron 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 toreceive an increased price for oil sold outside Argentinasolving the issue of lowdomestic prices. The fact that 20% of exports are tax-free also adds to the bottomline.

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 wellsgiven the significant


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volumes of natural gas associated with oil production. Madalena Energys recentCAN.xr-2(h) horizontal well tested 2.7 million cubic feet per day, along with big oilproduction.

The other big part of the profit equation will be drilling costs. Thats where many

other shales globally have stumbledwith high costs for drilling and completingwells eating up profits from the ensuing production.

But the Neuquen basin is a mature petroleum-producing regionso road access isgood, and theres alot of pipelines and infrastructure already there. That cuts downon costs for bringing in drilling rigs, and for tying in production once wells have beencompleted.

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 Coloradorivers 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 aspecialized industrial park just to service drilling and fracking.

All of this suggests Argentina has a legitimate shot at becoming The Worlds NextBig Shale Playwith a billion-barrel prize for early developers.The last thing to remember about Madalenais management. CEO Kevin Shawspent a lot of time in the field before spending some time as one of Canadas top oiland gas brokerage analysts.

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

It all creates some exciting blue sky numbersand an obvious exit strategy with allthe Petro-Majors involved in the Vaca Muertafor investors to think about.



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East Africa oil & gasoutlook: Global exporthub by 2020?

Written by Mark YoungfromEvaluate Energy

East Africa could become the worlds next oil and gas export hub by 2020, accordingto anew report by Evaluate Energy.There are three countries with ambitions tomake 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 bevery 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 Northerncountries that have produced the most oil and gas. Only Angola has stepped out ofrelative obscurity since 1990.

Source:Evaluate Energy

Angola has changed dramatically since 2000 and is the only country in the last 25years to have increased production from under 500 bbl/d to rival the continentsbiggest 4 producing countries; Algeria, Nigeria, Libya and Egypt. Every other countryin Africa produced 100,000 boe/d or less in 2012. African oil exports have thereforebeen restricted to coming from 4 of these 5 countries as well; Egypt is the only oneof 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 exports1.7 million more barrels of oil than it imports each day. Angola also has a LiquefiedNatural Gas (LNG) export terminal with a capacity to export 5.2 million tonnes ofLNG per year (mtpa) that became operational in June 2013. Angola has shown justhow 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 Africancountries - Kenya, Mozambique and Tanzania - have laid a possible foundation forone or maybe some of these countries to follow in Angolas footsteps on the path toexporting oil and gas on a major scale. This would end a 20+ year period of relativestatus-quoAngola notwithstandingon the continent. All 3 of these countriesshould be the main attraction of any new African investment before the end of thedecade because of these export ambitions, which could represent a majoropportunity for all E&P companies involved in the region, no matter their size.

These 3 export projects, which are the focus of Evaluate Energys newEast AfricaOil & Gas Outlookreport, make East Africa the continents region to watch for theremainder of the decade and the E&P companies involved very interesting prospectsin the immediate future.

Overview of East African Export Ambitions:

KenyaThe $25.5 Billion LAPSSET Project is underway, focused on exporting oil andgas from 3 countries out of Lamu Port on the northern coast.

MozambiqueMulti-tcf deep-water gas discoveries by experienced IOCs have been madeand wealthy NOC benefactors mean that LNG exports are a real possibility inthe very near future.

TanzaniaHuge gas discoveries by IOCs with LNG export ambitions and a separate

Chinese-backed mega-port at Bagamoyo is planned.

View more quality content fromEvaluate Energy
http://info.evaluateenergy.com/east-africa-oil-gas-report-2014http://info.evaluateenergy.com/east-africa-oil-gas-report-2014http://info.evaluateenergy.com/east-africa-oil-gas-report-2014http://info.evaluateenergy.com/east-africa-oil-gas-report-2014http://www.oilvoice.com/description/Evaluate_Energy/479701d2.aspxhttp://www.oilvoice.com/description/Evaluate_Energy/479701d2.aspxhttp://www.oilvoice.com/description/Evaluate_Energy/479701d2.aspxhttp://info.evaluateenergy.com/east-africa-oil-gas-report-2014http://info.evaluateenergy.com/east-africa-oil-gas-report-2014


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Globe

Getechs agship global new ventures platform.

Regional ReportsFocussed assessments of exploration risks and opportunities.

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For further information contact Getech:Getech, Leeds, UK +44 113 322 2200

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Leaders in theworld of naturalresource location


26/44


Ghana's Jubilee oilfield - stable orstagnating?

Written by Mark YoungfromEvaluate Energy

In December 2010, the first oil was produced from Ghanas Jubilee field, breaking arecord for major deepwater development, as this was only 3.5 years after the fieldsfirst discovery well. Tullow Oil (the unit operatorsee note 1) led the celebrations,

along with its major partners Kosmos Energy and Anadarko Petroleum, and thefuture for the field looked really bright. But although production now averages ataround 100,000 barrels of oil equivalent per day (boe/d), issues are beginning to pileup and progress has been virtually non-existent since first oil. The fieldsperformance looks stable but may in fact be stagnating, according to this newanalysis of annual 2013 data byEvaluate Energy,which holds financial andoperating 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, isprobably the most exposed to the risk associated with the Jubilee field experiencingoperational issues; Kosmos only producing asset is the Jubilee field. The company

has just released its 2013 annual results and the operational data for Jubilee beginsto highlight the problems.

Production has been relatively stable since a fall back to initial rates at the start of2012, according to Kosmos quarterly data from Jubilees first oil.

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

Source:Evaluate Energy
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partners with a substantial-enough flaring license either, meaning any kind ofimmediate ramp-up in production due to the gas involved is impossible. Thegovernment is clearly paying a great deal of respect to making sure the oil isproduced at a steady, manageable, and sustainable rate, but this is clearly at oddswith 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 idealfor the operators and stands in stark contrast to the euphoria in 2010 upon first oil. Ifthese 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 isvulnerable to issues on this level is important to note. In particular, it should serve asa warning to companies and government bodies involved in the other Africancountries with major discoveries of their own, such as Kenya, Mozambique andUganda. High resource figures and record breaking development timescales areobviously desirable, but the key for prolonged, successful oil and gas production

seems to be a high level of cohesion between all relevant partiesand definitely ahigher level of cohesion than is on show in Ghana right now.

This report was created using theEvaluate Energydatabase. Evaluate Energyprovides efficient data solutions for oil and gas company analysis, with 20+ years offinancial and operating data for the worlds biggest oil and gas companies, as well asevery publicly listed company in Africa.Now, All SEC-reported operational data,including oil and gas proved reserves, costs incurred and discounted future net cashflows, is now all available for Africa as a stand-alone region.For a demo of EvaluateEnergys African Company database, click here.

1) The Unit Operator is responsible for drilling and completing the development wellsfor the Jubilee Field development, according to the specifications outlined by theIntegrated Project Team (IPT), and providing other in-country support. Upon firstproduction, the Unit Operator assumed responsibility for the day-to-day operationsand maintenance of the Floating production, storage and offloading vessel as well asoverseeing and optimizing the reservoir management plan based on fieldperformance, including any well workover activity or additional infill drilling andsubsequent 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 anoptimized reservoir depletion plan. This plan included the design and placement ofwells, and the selection of topside and subsea facilities. Responsibilities alsoextended to project management of the design and implementation of the completefield development system.

View more quality content fromEvaluate Energy
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rpsgroup.com/energy

Health, Safety, Environmentand 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.

Contact

James Blanchard

T+44 (0) 20 7280 3200

[email protected]


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Why Shell needs thisunior's big play


Elephant hunting for huge international oil plays usually means going into (very)politically risky areas. Thats what makes junior Petromanas (PMI-TSXv) stand outfrom the crowd.

Theyre chasing a potential 500-800 million barrel target in EuropeAlbania to beexact. Lots of energy investors are familiar with Bankers Petroleum and their heavy

oil play thereits the largest onshore oilfield in all of Europe.

But few people know about Petromanas. I expect that to change in a hurry in Q32014 if their next well hits. They already have one success under their belt.

But even better, theyre getting carried for $100 millionon exploration and seismiccosts on two high-impact Albanian blocks by oil industry super major Royal DutchShell (NYSE:RDS.A). Plus, Shell paid them cash for their sunk costs.

Its rare to see a super major aggressively seek out a partnership with a companythe size of Petromanas. Shells interest is a huge validation of the true potential ofthe assets that Petromanas owns.

However, Shell knew the geology very welltheyre already a partner in two largeproducing properties that are analogous to the Petromanas property in Albania, justacross the Adriatic Sea from Albania in Italy.

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

I was intrigued by Shells interest in this play so I called up Petromanas CEO GlennMcNamara to get some background.

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

McNamara said that Shells joint venture bid was clearly one that Shell knewPetromanas would find attractive. Shell didnt do any beating around the bush. Itwanted these assets.

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

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

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

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

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

A positive needle move issomething Shell shareholderswould welcome. Despitespending $46 billion onexploration and development in2013 Shells production actuallydeclined by 5% to 3.25 million

barrels a day year on year. 2013earnings were also down from2012.

Albanian Blocks 2-3Activityto Date

Shell and Petromanas havealready drilled a well (Shpirag-2)on these blocks.

The result of the drilling was alight 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 smallerdiameter hole at the bottomso the rates of the flow test make it difficult to predicthow 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 hisenthusiasm, but he did say that the Molisht-1 well target could actually prove to bethe same structure as the Shpirag-2 well.

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

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

That is the potential. The challenge with this play is that the wells are verycomplicated 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 inItaly.


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Experience counts, but even after 15 years, these wells arent easy for even Shell todrill.

The complication lies in the fact that the companies are drilling through a flyschshale 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 likewith 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 wellended up being only 4.5 inches in diameter instead of the 6 inches that thecompanies had hoped to use.

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

Shells 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 thatlist

The size of the prize here is huge. We are talking about 500 to 800 million barrels.

And these arent resource-play barrels that require hundreds of wells that declinevery quickly. This is a conventional playprolific wells with lower decline curves.

Little Petromanas could have a 25% interest of a 500 to 800 million barrel field. Thatwould be 125 to 200 million barrels net to them. Based on the analogous fieldsacross the Adriatic in Italy, barrels in this type of field have NPVs (net presentvalues) 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 $60million (market cap less cash on hand).

Now, Petromanas has had to issue a lot of stock for that moneythere is now 694million shares out basic and 890 million fully diluted. Thats 100 million warrants at45 cents due February 2015, 50 million performance shares depending on howmuch 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 agood well, that will mean the stock trades higher, not lower.

And if this Albania play is the real deal Petromanas isnt going to be a double or


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

Thats the potential. Its exciting and why Im interested, but it is very important tonote 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 tankappears to be very large.

What is needed next are a couple of additional wells to provide further detail on thefind 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 resourceappraisers. Since the last resource assessment was done Petromanas has obtainedtwice as much seismic data on the play and drilled a well.

Petromanas believes one interpretation indicates that the structures could be a lotbigger than they appeared the first time around. Now we need to wait and see if theresource 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 backwith a big increase to their original resource assessment.

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

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

That would be a day that Petromanas shareholders would welcome.



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Why none of us canignore the fate ofNorth Sea oil

Written by Economics Editor Ed ConwayfromSky News

Its easy to forget just how important a contribution oil and gas makes to the UKeconomy. Britain, after all, is a large and highly-diverse economy. But while its not apure 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 wereit not for North Sea oil.

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

Oil and gas production fromthe North Sea (DECC)
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Even though the output from UK fields has dropped sharply in recent years Britainstill produces more oil, in absolute terms, than Oman; more oil and gas combinedthan 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 hasboosted Britains fortunes. Since the turn of the millennium the share of Britainsgoods exports accounted for by oil has risen from just over 5% to almost 14%. Thatsthe highest share since the mid-1980s.

And there is plenty of it left. About 42 billion barrels of oil equivalent have beenextracted since 1965; there is probably about 24 billion still left. The problem is thatthe remaining stuff is harder to get hold ofit involves reaching into deeper waters,digging deeper underground and squeezing more resource out of older fields, ratherthan hoping for brand new discoveries. That, in turn, is changing the make-up of thesector. Whereas in the glory days of the 80s and 90s the big players were the oilmajorsShell, BP, Total and so onthe North Sea is increasingly home to so-called scavenger firms which buy old, abandoned fields and attempt to maximisereturn from them.

That change in constituency means its highly sensible for the Government to

consider a shake-up in the regulation of the sector, asSir Ian Woods report into thefuture of the North Sea todayrecommends.

Total reserves in North Sea vsamount recovered (WoodReview)
http://www.woodreview.co.uk/documents/UKCS%20Maximising%20Recovery%20Review%20FINAL%2072pp%20locked.pdfhttp://www.woodreview.co.uk/documents/UKCS%20Maximising%20Recovery%20Review%20FINAL%2072pp%20locked.pdfhttp://www.woodreview.co.uk/documents/UKCS%20Maximising%20Recovery%20Review%20FINAL%2072pp%20locked.pdfhttp://www.woodreview.co.uk/documents/UKCS%20Maximising%20Recovery%20Review%20FINAL%2072pp%20locked.pdfhttp://www.woodreview.co.uk/documents/UKCS%20Maximising%20Recovery%20Review%20FINAL%2072pp%20locked.pdfhttp://www.woodreview.co.uk/documents/UKCS%20Maximising%20Recovery%20Review%20FINAL%2072pp%20locked.pdf


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However, all of this could end up being moot if the Scottish people vote forindependence. Which raises a few vexed questions. First, how much of the existingoutput should go to Scotland? If one were dividing it based on geography, isolatingthe fields of the Scottish coast, around 90% of production would go to anindependent Scotland. However, if one were dividing it based on population, then on

a per capita basis the share would be closer to 8.4%.

Thats 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 analmost 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 ofScottish 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, its hard to see how AlexSalmond could make his sums work.

But the split would also raise some more important long-term questions for bothsides. 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 reallywould 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 themain sources of its exports. The balance of paymentsalready extremely nasty

The oilfields that would go toScotland under potentialIndependence, according to ageographical split (ScottishGovernment)


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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 nations long-termeconomic health. There is no good answer for this, save for that it was a decision ofsuccessive governments (Labour and Conservatives) to use the proceeds for todaysconsumption rather than saving it for tomorrow. It helped support Britain throughwhat 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 ratherthan set aside? Todays younger generation is facing decades of higher taxes to payoff Britains enormous national debt; however, some would argue that this wouldhave been the case whatever the treatment of the oil revenues. Either way, there isno satisfactory answer to this vexed questionsave that it will continue to spark

anger as long as the oil keeps pumping, and probably some years thereafter.

View more quality content fromSky News

The hidden risks ofdevelopment decisions

Written by Hiren SanghrajkafromUpstream Advisors

The pre-decision p rocess is increasingly imp ortant as prod uct ion risk s and

costs escalate for both large and small plays, says Hiren Sanghrajka of

Upst ream Advisors

The commercial landscape for oil and gas production has never beenstraightforward. Early stage planning has always been of paramount importance buttoday it has become increasingly vital to get it right as a range of factors continuallytransform the risk picture.

A study published this month, into project execution and budget overruns by theNorwegian 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 ofprojects that had seen their schedules and budgets balloon.

All projects reviewed that had huge time and cost overruns, had major shortcomingsin the early design work, said NPD's Evaluation of Implemented Projects on the

Norwegian Shelfreport, referring to all engineering work before delivery of theproposed development option (PDO) and before procurement and constructionstarts.

Flaws and faults in the early planning will propagate further in the project. Time spentearly in a project's life is crucial to the success of completing the project within timeand 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 turnputs heat on project managers to make rapid progress and shorten project cyclesbecause their reputations are at stake.

Furthermore, it's easy to under-estimate the number of preliminary decisions thathave 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 obviouslyincreases.

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

There is always a way to make good early stage decisions, no matter how small orbig you are, which fully takes into account all these developing risk factors and anyothers than may come down the track. At Upstream Advisors, we have collaboratedwith many clients in this field and have helped them through a management processthat 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 baddecisions.

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

Of course, attention to detail is key; it's so often the small things you don't thinkabout 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 isno one universal project tick list.


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

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

The increasing complexity of exploration as frontiers are extended into ever morechallenging environments and depths and a background of a chronic skills shortageand 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 scenariosbut to increase efficiency, particularly in production drilling, well completion, andfloating production facilities with subsea wells. The implementation of this newtechnology 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 decisionmaking 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 smalland medium enterprises entering the scene, which, unlike super majors, simply don'thave the experience or permanent in-house capabilities.

Unpicking a decision and building the case for pursuing another option should neverbe seen as anything other than a major 'win' saving an organisation from sometimesinestimable 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.

View more quality content fromUpstream Advisors
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Training Courses

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Events

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the engineering skills gap.

The strategy included 7 million for a new research facility known as the NeptuneNational Centre for Subsea and Offshore Engineering. The new facility will be basedat Newcastle University and will act as a place for industry and academia to interact,

providing crucial infrastructure for emerging research opportunities. The NeptuneCentre will also have a strong element of developing highly-skilled graduates to helpaddress key skill shortages.

With Britains industrial base now recognised as holding as important a place in theeconomy as sectors such as financial and professional services, the government islooking to rebalance the economy, rebuild supply chains and nurture artisan skills.One organisation tasked with furthering these objectives is the Technology StrategyBoard (TSB). Working across business, academia and government to helpcompanies take ideas through to commercialisation, the TSB is currently overseeingthe 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. TheHigh Value Manufacturing Catapult is building on the strength of seven constituentinstitutions, one of which in particular, The University of Sheffields AdvancedManufacturing Research Centre (AMRC) has been a great example of collaborationbetween academia, industry and government.

The Catapults represent a win-win scenario, whereby Britains engineering andscience graduates and apprentices are nurtured in a high-technology and innovativeenvironment that will ensure they are fit-for-purpose when they enter the globaleconomy. A prosperous high-tech UK manufacturing industry depends and thriveson a highly-skilled and knowledgeable workforce, so a strong foundation of trainedstaff and well-educated students will enable Britains manufacturing industries tomaintain their competitive edge and successfully compete on the international stage.

The theme of MACH 2014 is innovation in action. It is the UKs largest event forManufacturing Technologies. Over five days, more than 20,000 visitors will see some500 exhibitors putting their latest technologies and innovations through their paces toregister for the event go to www.machexhibition.com

View more quality content fromManufacturing Technologies Association (MTA)
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