OilVoice Magazine | February 2013 by OilVoice

Edition Eleven â&#x20AC;&#x201C; February 2013

Will oil prices decline in 2013? The four pillars supporting North Sea Oil & Gas in 2013 Future global LNG flows and the realities of East African Gas

OilVoice Magazine | FEBRUARY 2013

Adam Marmaras Chief Executive Officer Issue 11 â&#x20AC;&#x201C; February 2013 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.

Hello and welcome to the 11th edition of the OilVoice Magazine. As some of you may know, I'm involved with two businesses. One is OilVoice, that you are engaging with now. The other is Finding Petroleum. This year we have around 10 events planned in London. The feedback we receive is that Finding Petroleum events are just the right length (half a day, you can be back in the office after lunch), the right location (The Geological Society in Piccadilly, London), and the right price (free to attend). Take a moment to browse our list of upcoming events, and join the growing network of over 10,000 oil and gas professionals who are involved. It's a great business that I'm proud to be a part of. This month in the OilVoice magazine we're spoilt for choice for articles. We don't have room to include everything our writers send us, and whittling it down is a tough task. Just to make sure we don't miss anything you can check our Featured Authors page and read every article we have on offer. Don't be shy to click through to the websites of the contributors. 2013 is shaping up to be a great year for OilVoice. We currently have over 800 active jobs on the jobs board, and our traffic continues to climb. Thanks for being an important part of the story.

Adam Marmaras CEO OilVoice

OilVoice Magazine | FEBRUARY 2013

Contents Featured Authors Biographies of this months featured authors

Will oil prices decline in 2013? by Andrew McKillop

Recent Company Profiles The most recent companies added to the OilVoice directory

How to win at the board game by Kris Hicks

Future global LNG flows and the realities of East African Gas by Oswald Clint

Scottish independence: What would the implications be for the oil and gas sector? by Charles Livingstone

Natural Gas Liquids: No more running on empty by Robert Kientz

Tapping into emerging markets' potential by Alexandre Pelletier

Iran-Iraq alliance and the right price of oil by Andrew McKillop

The four pillars supporting North Sea Oil & Gas in 2013 by Malcolm Wilson

The price is right for West African E&P by Richie Ethrington

Opportunities for all - creating successful local partnerships in the Chinese shale gas sector by John McGoldrick

Extending the life of ageing Oil and Gas assets by Dr Liane Smith

Where are the exploration opportunities in Africa? by David Bamford

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Featured Authors Andrew MacKillop OilVoice Contributor Andrew MacKillop is an energy and natural resource sector professional with over 30 years experience in more than 12 countries.

Kris Hicks AVA Global Ltd Kris has spent the last 13 years working with senior talent in the energy and infrastructure sectors, initially with a large global FTSE organisation, where he progressed to become one of their leading consultants.

Oswald Clint Bernstein Research Currently he is the Senior Research Analyst covering the European E&P and Russian Oil & Gas sectors. The Bernstein Energy franchise has become well known due to both the provocative commentary on the commodities and oil stocks, as well as the innovative research that forms the core of their frequent publications.

Charles Livingstone Brodies Charles Livingstone is an associate in the public law team of Brodies LLP.

Robert Kientz The Drop Shadow Robert has been an investor for many years and has 8 years experience working as a corporate auditor and 14 years corporate working experience.

Richard Etherington Finding Petroleum Richard Etherington, 24, works as a freelance journalist. Richard, a BA Hons Political Science graduate, is also a fully trained sub-editor and reporter.

OilVoice Magazine | FEBRUARY 2013

Alexandre Pelletier Tata Communications Alexandre is Business Development Director at Tata Communications.

Malcolm Wilson Achilles Malcolm Wilson is Subscriber Support Manager at FPAL, a collaborative community run by Achilles on behalf of the UK, Dutch and Irish oil and gas industry.

John McGoldrick Dart Energy John McGoldrick is CEO of Dart Energy International.

Dr Liane Smith Intetech Liane Smith is an internationally respected engineer within the oil industry, awarded an FREng in 2011.

David Bamford Finding Petroleum David Bamford is 63. He is a non-executive director at Tullow Oil plc and has various roles with Parkmead Group plc, PARAS Ltd and New Eyes Exploration Ltd, and runs his own consultancy.

OilVoice Magazine | FEBRUARY 2013

Will oil prices decline in 2013? Written by Andrew McKillop from OilVoice Recent news from scientists of the British Antarctic Survey and partner research institutions examining ice cores showing the climate record for tens of thousands of years is that ice sheet retreat due to global warming often suddenly stabilises, "for decades to centuries', despite the warming still going on. This is also what is happening in the oil patch: all the supply-demand fundamentals say that prices should decline - but they stay high or go on growing. As far back as October 2012, Goldman Sachs analyst David Greely in what reads like a mea culpa from GS, said that the broker-banker firm's previous oil price forecasts - made in 2011 and repeated many times - that "the right price of oil" in 2012 and 2013 is $125 per barrel for the US marker blend WTI, and $130 for the European and Asian marker blend Brent, were too high and are now history. Not explaining why the previous forecast had been too high, Greely, in his October 2012 review of market fundamentals and forecast of 2013 prices, used oil market traders' coded language for overpriced oil. He said that oil markets are now "cyclically tight but structurally stable". He went on to say that GS now sees long-dated Brent crude oil stabilizing at around $90/bbl in 2013, a price level which is a whopping $40 lower than its previous forecast. As of 22 January 2013, Brent prices are around $112 per barrel. There are no shortage of market analysts who say that $120 and above is easily possible, and plenty others who forecast prices as low as $50 per barrel, or less. With that range of price forecasts, somebody has to be right! CYCLICALLY TIGHT-STRUCTURALLY STABLE The new forecast could or might save face for GS, when oil prices decline, depending how fast and how much they decline - and who pulls the skids away from overpriced oil. To be sure, prices can easily decline a little - in the 10% to 15% range below current levels - but oil producers and exporters would surely take a tougher line on who gets what from global market trading. Crude oil trades, valued at as much as $10 trillion a year, are in fact only the tip of the iceberg. Other trades cover every other possible type of oil-related trading such as arbitrage bets on the spread or premium between Brent and WTI, refined product price bets, crack spreads on the refining value gains from different types of processing, tanker, pipeline and rail transport trades, and others. Total turnover on the oil trading casino probably runs far above $20 trillion a year, about $100 billion every single trading day of the year. This is of course "nominal or paper value": at

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most the ratio of real or "physical" trades on oil and refined products, to paper bets on future prices, is 1-to-80. Financing of this casino is certainly not tight, and is also not structurally stable: it can dry up overnight, and it can surge the next. Goldman Sachs, and a select band of other major international banks, broker-traders, oil producer corporations, refiners, pipeline companies, oil transporters and offset trade operators know all about it. And what they know about oil prices is drastically simple: things are better, for them, when prices stay high. This in fact is "the dirty secret" of global oil trading - and a total reversal of how the straight majority of market actors and players in the oil trading casino operated until about 2005. Previously, they consistently "played low" and acted to push down oil and oil product prices. For at least 8 years, however, they now consistently act to maintain or increase oil and oil product prices. Oil traders and analysts were in no way fooled when they read the October 2012 mea culpa by Greely of GS: if Goldman is now saying it exaggerated "the right price of oil" and prices should now fall in a pretty spectacular way, it is a good time to buy calls on oil futures, because prices will probably rise! That is oil market trading psychology - call it trench warfare. One supporting rationale for this "contrarian" readout was embodied in Greely's published analysis. He said the famous Brent premium feeding huge volumes of arbitrage trades on the unreal mark-up of Brent prices against WTI - hitting highs up to and above $25 a barrel - was now set to almost totally disappear in the same way it was also set to almost disappear, but on the upside, in the previous "high price forecast" of GS. In other words, GS forecasts the premium will disappear whether prices soar or collapse: so the contrarian bet is the premium will stay. Greely claimed he now sees a return to the oil pricing regime that characterized the crude oil market in the 1990s when long-dated Brent prices were anchored at $20/bbl, and although he made a point of not mentioning it, a year average oil price of $11.90/bbl in 1998. We can do the math for him and put that in 2013 dollars: this would mean a price of about $16.75/bbl. In the 1990s, we can add, the Brent-WTI mark up counted for toast, it was close to zero. The potential for that "new-old stability" coming back, today, reads like science fiction or a rather crude attempt to fool rival brokers and traders (and even customers and clients of GS!) into wrongfooting their bets. HELLO OPEC, GOODBYE GS In an interesting exhibit of oil trader schizophrenia and related double talk from high paid oil analysts, Greely of Goldman Sachs now claims that rising OPEC and Russian spare capacity is no longer a mortal threat to global security, a hammer blow for the global economy or a triumph for al Qaeda because it will not, repeat not guarantee high oil prices. In fact the exact opposite. Greely's words penned in the GS Tribeca building in New York are that OPEC and Russian spare capacity anchored longdated prices in the 1990s, keeping them sweet and low, so this can happen again, now. Greely's argument is that future and lower oil prices will be anchored not only by growing OPEC and Russian capacity, but also by "substantial

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growth in crude oil supplies from US shale, Canadian oil sands, and global deepwater oil provinces". Making a point of not adding that world oil demand and demand growth is either close to straight line, or declining not only in the US, Europe and Japan but also in Emerging countries - Greely talks his way around the fact that US WTI grade crude is at present a low-priced snip relative to Brent, "but nobody seems to have noticed". All and any outside observers, which include OPEC and NOPEC producers, can see that at present Brent grade crude costs about $25 more, for each barrel, than WTI. The world economy seems easily able to digest this differential - and high oil prices but as OPEC and NOPEC producer country oil ministers regularly say, they only get a part of this windfall. Slashing their own export prices for crude or for refined products makes no sense at all, to them. Cutting production makes a lot more sense, to them. The GS fairy story to explain why WTI prices trade at a now "traditional" and massive discount against Brent is that barrels delivered to the "basing point" for WTI, located at Cushing, Oklahoma - the Nymex oil pricing "hub" for physical deliveries of the few percent of all paper contracts taken to final delivery - cannot be onward transported south to the US Gulf Coast for refining. They are even less able to be shipped outside of the US, earning an instant $25-a-barrel mark up in Brent-priced markets. Making a pitch for the growing trade of bets based on oil transport, Greely cites the lack of US pipeline and rail transport capacity, truck transport capacity, possibly even a few barrels given a ride in the back of a pick-up! Greely says that what the US needs is the Big Thing of the Seaway pipeline expansion, ramped up from its current capacity of 150 000 barrels/day to its new capacity of 400 000 b/d in 2013. Conversely and in the meantime, the addition of substantial new rail loading and unloading capacity in 2012 has created excess capacity to move Bakken crude, from the north, to the Gulf Coast and especially to the Pacific coast - for export to Asian markets where Brent pricing rules. Outside of the US, these arguments and rationales read like fairy stories: In theory, anybody who can get WTI-priced oil out of the US, to anyplace in Europe and Asia, has a guaranteed winning business plan. The only problem is that if that was possible, the US would at present, and for several years, import even more Brentpriced oil to compensate. For OPEC and NOPEC producers, price decline for both WTI and Brent is no real threat, if the decline is moderate, but the "fraternity" of oil traders, brokers, banksters and fixers like GS are taking too much. For as long as they do, prices have to stay where they are - shown by recent growls from Saudi Arabia and Russia, that these two "players", the world's two biggest oil exporters, will have no problem cutting production - for any number of reasons, they say - and watching prices rise.

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OilVoice Magazine | FEBRUARY 2013

Recent Company Profiles The OilVoice database has a diverse selection of company profiles, covering new start-up companies through to multi-national groups. Each of these profiles feature key data that allows users to focus on specific information or a full company report that can be accessed online or printed and reviewed later. Start your search today! Griffiths Energy Oil & Gas Based in Canada, Griffiths Energy is an international exploration and development company focused on oil and gas exploration, development and production activities in the Republic of Chad, Africa. Griffiths Energy's OilVoice profile

Cisco Energy, LLC

Frontier Energy Group Oil & Gas Frontier Energy Group, LLC serves over 500 customers in the extended Rocky Mountain region through various locations. Frontier serves some of the biggest & smallest companies in the oil & gas industry. A leader in our communities through corporate philanthropy and employment opportunities. Frontier Energy Groupâ&#x20AC;&#x2122;s OilVoice profile

Oil & Gas Cisco Energy, LLC is a privately held independent oil and gas producer headquartered in Plano, Texas. The company is focused on the Mid-Continent Region. Cisco Energy, LLC's OilVoice profile

Welling Resources Oil & Gas Welling Resources is an independent exploration and production company that focuses on the acquisition, development, and exploitation of oil and natural gas reserves. Welling Resources' OilVoice profile

Linde Service

The Linde Group is a world leading supplier of industrial, process and speciality gases and is one of the most profitable engineering companies. Linde products and services can be found in nearly every industry, in more than 100 countries. A success story that began with the separation of air. Linde's OilVoice profile

Northcote Energy Oil & Gas Northcote Energy Ltd is a US focused oil & gas company with a balanced portfolio of new exploration and exploitation opportunities blended with a stable of existing producing wells primed for high impact development. Northcote Energy's OilVoice profile

Amelia Resources Drilling Amelia Resources LLC is a privately-held exploration and production company. The company generates drilling projects in onshore Louisiana. The company was founded in 2003 by Kirk Barrell and has offices in The Woodlands, Texas. It holds a private equity interest and serves as management in Wave Exploration LLC. Amelia is actively engaged in several projects along the Florida Parish Fairway of Louisiana. Amelia Resources' OilVoice profile

OilVoice Magazine | FEBRUARY 2013

How to win at the board game Written by Kris Hicks from AVA Global Ltd In any one day I may have 20-30 conversations or meetings with C-Level executives of global energy and natural resources organisations. These conversations can take many forms yet, at some point, we will always move on to talk about a senior management team of some sort. This may be in their current organisation or forming opinions on a competitor's board structure. Establishing a successful C-Level team is akin to putting a football team together. We all have opinions on whether a team needs more creative midfielders or do they really need a ball winner. Board composition is no different. Could a board survive if every member had a finance background? Similarly would Man United be successful with 11 attacking full backs? When working with organisations to either assess the current capabilities of their board or searching for a new senior executive to join the current team, one of the first areas I focus on is the senior management team. Does this organisation have a viable, proven set of assets? Does the organisation have the senior management team to capitalise on these assets and drive the business forward? Both private and industrial investors are no different in their initial assessment either. The key to driving significant shareholder value is through a strong and well respected management team. This is vital in the FTSE 350 and even more so for AIM listed organisations, where share price volatility is even more extreme. Having recently put together an entire board using our board skills analysis tool (AVA ABC) for a small cap Oil & Gas producer, a number of questions were put to the Group Chairman that he had not fully considered before. What are the organisation's strategic goals and what strategy is in place to reach them? What are the roles and responsibilities of your current board? What are their strengths and weaknesses? How are they aligned to help your organisation achieve its goals? What skills and capability gaps have emerged from this assessment? What are the roles and responsibilities of the new position?

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I have found that a board with a diverse set of functional expertise (M&A, Legal, Finance, etc) industry experiences, educational qualifications, ethnic and gender mix are better equipped to deal with a variety of issues facing the organisation and provide executives with advice and consultation from multiple perspectives. The stronger the mix, the stronger the management team. Over the years I have met thousands of CEO's, CFO's, CIO's etc and have very rarely met a poor one. You have to be good to become a board director of a listed company. So how do you separate the great from the good? Now that would be telling but Headhunters have been trained in such methods, using a variety of tools at our disposal, to select only the very best talent in the industry. However, having seen many boards thrive and grow, several more boast stories of shareholder unrest, unsettling arguments, unhealthy divisions and generally poor corporate governance. So if we assume that all listed board directors are on a scale of good to great, the probability of success at board level can be measured by one single unit cultural fit. Headhunters have strong networks and are able to provide substantial information on all Director and C-Level executives of global listed organisations. As I mentioned earlier we have several 'confidential' conversations on a daily basis so you shouldn't be surprised to know that your name is on one of our lists. You also shouldn't be surprised to know that we have spoken to maybe five or six people about you and you certainly shouldn't be surprised that after a number of conversations and meetings we are able to assess what culture you would thrive in. We deliberately seek to find the person behind the CV, what drives you to achieve, what are your derailers, how you deal with confrontation. The list is endless. As organisations grow and develop, more senior appointments are made to facilitate and capitalise on this growth. I believe, globally, we are entering a period of sustained growth. Organisations will continue to appoint board directors based on their track record, strength of network, how they fair at interview and any psychometrics tests that may have been carried out. Yet, despite all this over 30% of these board appointments will be unsuccessful. Over 80% will cite cultural fit as being the main obstacle for success, yet did they really seek to assess or clarify the correct cultural fit and board composition for the business in the first place? To win the game you need a strong board that collectively have the combined skills and attitude, aligned to the culture and goals of the business, able to see the organisation through a period of growth, transition, change or maybe turnaround. To ensure you win, to maintain that competitive advantage, don't forget cultural fit when you are conducting your next board composition analysis.

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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.

Contact James Blanchard T +44 (0) 20 7280 3200 E BlanchardJ@rpsgroup.com

rpsgroup.com/energy

OilVoice Magazine | FEBRUARY 2013

Future global LNG flows and the realities of East African Gas Written by Oswald Clint from Alliance Bernstein Global LNG flows will be dictated by pricing which has diverged globally since 2008 with Asia, Europe and the US all following different paths. Asia remains the a premium pricing market and therefore the market of choice for all those stranded gas resource holders including East Africa. LNG market fundamentals are attractive with demand set to grow at 6% per year to 2020 after rising by such levels over the last decade. Asia is the largest source of demand led by Japan and South Korea and imports to both nations continue to remain robust and rose strongly in 2011-2012 due to the tsunami. However demand in Asia is set to rise further from new countries. China will have 11 LNG imports terminals by 2015 and imports will double to 30MT annually we estimate. Furthermore, India's LNG imports will increase to 23MT by 2015 from 11MT in 2011 as eight new imports terminals are commissioned. LNG supply comes in waves and the growth of circa 20% witnessed from late 2009 to early 2011 from the Middle East has now slowed. New material LNG supply won't enter the mart until 2016. Consequently LNG market dynamics are positive for the medium term as spare capacity will continue to fall unless new developments are sanctioned. This creates the space for East African LNG but in the way is cheaper North American LNG. Twenty projects are vying for export approval from governments in 2013 and the market will have to wait and see how much is approved. The magnitude and production cost of the this gas leaves it at the low end of the LNG cost curve and hence puts pressure on competing internal LNG projects of which there are many. Indeed, over the last 3 years, 60% of our conventional new discoveries have been natural gas in all terrains and water depths and most prevalent in East Africa where almost 17Bn boe has been discovered. Having analyzed the quality of this resource base, we believe it makes sense to monetize it through LNG and that it remains more viable than competing projects in Russia, Australia, Alaska etc. However, market expectations for East African LNG exports by 2018 are widely optimistic. LNG projects used to take 3-4 years from FID to first LNG. More recently, that has changed to 6-7 years. In particular, Mozambique which is planning 10 LNG trains of 5MT each would leave it double the size of Nigerian LNG which took 12 years to reach 25MT per annum of LNG output. Additionally, cost pressures and inflation are most evident in the LNG sector where everyone single project in Australia has seen 15-40% cost inflation in recent years destroying project returns and investor enthusiasm for such ventures. It will not be

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plain sailing for East African LNG. Global LNG demand has been weak this year on coal to gas switching in Europe, lower global economic growth and shale. Asian demand continues to be robust, although growth has stalled as high prices have impacted consumption in China and India. In Europe however, LNG demand has declined dramatically as high LNG prices have resulted in power companies switching from gas to coal. In North America, LNG imports have almost been fully eliminated by shale. 

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While demand has stalled, supply growth has also been extremely weak with disruption to Middle East supply, maintenance in Indonesia and Trinidad and limited new liquefaction capacity additions. With Angola start-up delayed into 2013, Pluto will be the only LNG project to start up this year. Elsewhere, supply has dropped sharply from Yemen, Egypt, Trinidad and Indonesia on maintenance and terrorism. Demand is starting to come back however and signs are of a market tightening as we head into winter which should support gas prices. We expect that North Asia and European demand should start to pick up over the coming months on seasonal winter demand. The shut-down of two nuclear power plants in Korea and continued problems with the Oi reactor in Japan should mean higher demand this winter. Weak supply from Nigeria and Trinidad could compound these problems driving winter gas prices higher after weakness over the summer months. With limited new capacity additions, the LNG market continues to look structurally tight through to 2014. Over the next 2 years the LNG market is likely to remain structurally tight. Less than 10mtpa of new liquefaction capacity is due to start up in 2013 and Australian projects (PNG LNG and QCLNG) due to start up in 2014 could be delayed. As such we expect global LNG spare capacity to remain low and spot LNG prices to remain high in the near term. Competition for market is increasing however, with over 100mtpa of projects vying for approval next year. Next year could be a record year for the LNG industry with over 100MT of new supply seeking for approval. Australia, Russia, West Africa, and North America have a significant number of projects targeting final investment decision next year. Strong competition from these projects will put pressure on long-term LNG contract prices, in our view. US LNG exports remain the largest source of supply uncertainty, although we think the export volumes approved could be higher than current consensus estimates. The US has the largest number of LNG projects under proposal globally, although it is unclear how much capacity will be approved. Current estimates for US LNG exports approved by 2020 range from 40-50mtpa (consensus) to a high side of 100mtpa (5-12bcf/d). The US DOE report on LNG exports which is scheduled for release in December will provide the first insights into the volumes of LNG that will be approved. Increased exports from North America would be negative for Australian, Russian and Canadian LNG; conversely any decision to limit exports from the US would be positive for LNG exporters in these countries. North America LNG will be more cost competitive than any other country in terms of LNG supply. Greater than expected US LNG exports will displace marginal LNG

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projects in Australia and the Arctic. Conversely, any decision by the US to limit exports will be a positive for the more marginal LNG projects. The biggest question for investors in global LNG markets is how much LNG capacity will the US approve for export? The world needs an additional 80mtpa of LNG to be approved over the next 3 years and while the US could supply this alone, there remains political uncertainty on export approval. In December the DOE will release its much awaited report on US LNG exports. If adopted, the conclusions of this report will have global significance for the LNG industry. If the US approves a large export quota (12bcf/d or more) this will be negative for marginal LNG projects, especially those in Australia and the Arctic which are at the top of the cost curve. If on the other hand the US restricts exports to a low export quota (5bcf/d or less) then this will be a positive for the Canadian, Australian and Russian LNG projects. While consensus estimates for the US are currently around 40-50mtpa of export approval by 2020, we think the number could be larger than this, which poses a risk to Australian LNG. While some of our favorite LNG names have taken a step backward over recent weeks on deferred production and higher costs we still think there is significant upside ahead given the growth in this industry. In the Asia-Pacific region, our top pick is Oil Search which continues to have the best long term organic LNG growth in the region and in Europe our top picks in LNG are TOTAL and BG.

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OilVoice Magazine | FEBRUARY 2013

Scottish independence: What would the implications be for the oil and gas sector? Written by Charles Livingstone from Brodies LLP On 15 October 2012, Alex Salmond and David Cameron signed an agreement providing for a referendum on Scottish independence by the end of 2014, ending the doubt about whether the Scottish Parliament had the power to set up such a vote. This allowed the focus to turn from the process to the issues, which may affect the oil and gas sector more than most. Perhaps the most important issue for the sector is also one of the most controversial for the politicians - the division of the UK's North Sea Exclusive Economic Zone (EEZ). North Sea revenues would be hugely important to the finances of an independent Scotland, and the figures would depend largely on the location of the boundary. However, we are unlikely to have a definitive answer on where this boundary might lie pre-referendum. Recently, the Institute for Fiscal Studies (IFS) reported on the likely fiscal position of an independent Scotland, concluding that a 'geographic' split of North Sea oil would leave an independent Scotland in more or less the same position as at present, though more vulnerable to the volatility of North Sea oil revenues, while a 'population-based' division of the revenues (i.e. Scotland getting about one-tenth of current UK revenues) would require some difficult spending choices to be made. Any assessments of a 'geographic' division must, however, depend largely on the location of the boundary. Unfortunately for the purposes of the debate, that is as much a political question as a legal one and so would probably only be resolved in negotiations between the UK and Scottish Governments in the event of a vote in favour of independence. In any such negotiations, one would expect the Scottish Government to argue for the boundary to be drawn as far south as possible, while the UK Government would want to retain as much of the current UK zone as it could. These two positions would each be underpinned by distinct legal approaches: 1) A line running almost directly east from Berwick, currently used to decide whether Scots or English law applies off-shore. This is favoured by the SNP because the Scottish area contains the overwhelming majority of UK reserves. 2) A line running broadly north-east from Berwick before turning eastwards at about

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level with Carnoustie, based on the principle of equidistance (i.e. if a point in the North Sea is closer to the Scottish coast than the English then it would be in the Scottish zone, and vice versa). This would put a smaller majority of North Sea oil production (and an even smaller majority of gas production) within the Scottish zone. The SNP objected when this approach was used in 1999 to set the limits of the Scottish Parliament's power to regulate fisheries, no doubt with the independence issue in mind. International boundaries are often set using the equidistance principle, which is the 'geographic' approach used in the IFS's report. However, other approaches can be used - the history of the North Sea's division includes a dispute between Denmark and the Netherlands, on the one hand, and Germany on the other. The Germans were unhappy with the boundaries of their zone under the equidistance principle, and ultimately a combination of diplomacy and an International Court of Justice decision resulted in a larger German area. That shows the potential for any division of the UK EEZ to depend at least as much on political issues as legal ones, which in turn suggests that the issue is unlikely to be resolved before the referendum. The UK Government has already said that it will not 'pre-negotiate' in advance of the referendum on the terms on which independence might take place. Wherever the boundary was drawn, all fields on the Scottish side of the line would, of course, be subject to Scottish taxation and regulation. This may be of even more interest to the industry than the boundary itself, so what might the sector expect? In 2011 the Scottish Government criticised the UK Government's increase in the supplementary charge, and proposed several options for reducing the tax burden on marginal fields. These proposals included a Norway-style "extended field allowance", or a guaranteed minimum return on investment before the charge applied. The Scottish Government has also proposed a post-independence fund which would invest a proportion of North Sea revenues for future use (though others claim that all revenue would be needed just to fund current spending). The industry will be aware of the current suggestion that off-shore safety might become an EU responsibility, and the status of EU regulation in an independent Scotland would be a key issue for the sector. Debate is currently raging on whether an independent Scotland would automatically be an EU member or have to apply for membership, but it seems very likely that Scotland would (sooner or later and on one set of terms or another) be a member of the EU. EU regulation would therefore continue to apply, even if Scotland had to temporarily exit the EU on independence (in which case the Scottish Government would want to maintain compliance with EU law pending a decision on its application to re-join). Existing UK legislation and regulations would also have to remain in place until and unless they were replaced by new Scottish equivalents, but one question that may be of real interest to the industry is whether the current decommissioning arrangements would be maintained. In particular, would an independent Scottish Government adopt the agreements entered into by the UK Government on decommissioning tax relief? A successful oil and gas sector would be vital to an independent Scotland, which makes the extent of the 'Scottish zone' and the potential regulation and taxation of

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the industry key issues for both sides of the debate. The industry may therefore have a very strong hand to play over the next two years.

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Natural Gas Liquids: No more running on empty Written by Robert Kientz from Drop Shadow I have written in the past that natural gas is our answer for a potential supply shortage in oil. Natural gas is cleaner than gasoline produced from oil, it is currently cheaper for the same energy output, and it is being produced in abundance in the United States which makes it a good current substitute for potentially stressed oil production. Not only that, but gas reserves are being found in abundance all over the world. To be clear, oil supplies have kept up with demand owing to new discoveries and technology which has allowed economical oil extraction from sands and shales. It also does not hurt to have high oil prices driving recovery from unconventional sources now made profitable. But if global demand keeps growing at current levels, at some point in the future a supply deficit may emerge in oil which will require alternatives to balance energy demands. Please read my analysis of current oil supply and demand factors for background. While natural gas meets the needs for a fuel alternative to oil for the foreseeable future, detractors of natural gas have pointed out that petrochemical production, which in the past have been largely dependent on rich, liquid-heavy content that oil provides, cannot be met by the lighter hydrocarbon profile that natural gas provides. This article will examine the potential petrochemical content provided by natural gas contained in Natural Gas Liquids [NGL's] content. I will attempt to make the argument that this analysis is not zero sum, requiring us to forego one resource for the other; but rather that both resources together provide an

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abundance of options for fuel and petrochemical needs. Understanding the relationship between oil and natural gas for petrochemical production is crucial for investors putting money into any company involved in the energy sector. Indeed, in several future articles we will use this knowledge to assess which companies are the very best candidates to own against the evolving energy landscape. Petrochemical Production Let us start with a quick analysis of petrochemical production. Elmhurst College has provided three diagrams to aid us in tracing feedstock materials to end petrochemical product. Raw Materials

Intermediates and Derivatives

OilVoice Magazine | FEBRUARY 2013

End Use Markets Both natural gas and oil provide resources to a range of end products including plastics, adhesives, papers, textiles, fibers, solvents, chemicals, synthetics, rubber, and foam products. Typical oil cracking leads to butadiene, benzene, toluene, and xylene production while natural gas leads to methanol, ethylene, and propylene production. If we stop our analysis there, then supply issues of one natural resource would imply difficult choices to be made on production of key products. But a deeper analysis suggests that both feedstocks provide a range of petrochemical choices. Olefins Production These include ethylene, propylene and butadiene and have predominantly been produced by catalytic cracking of oil. However, the build-out of steam cracking faciltiies which process both oil and NGLs into olefins are receiving the majority of funds in the industry, largely in response to the increased role natural gas reserves are playing in petrochemical production. Ethylene and propylene account for 50-60% of all petrochemical feedstocks, and as such NGLs are a key component of future supply of these chemicals. Both ethylene and propylene are currently produced about half and half from oil and gas feedstocks. Butadiene can be produced from natural gas liquids but on a smaller scale than oilbased production, and therefore there is a scarcity premium priced in that market. Iâ&#x20AC;&#x2122;ll get to the importance of butadiene production later [think tires]. Aromatics Aromatics includes benzene, toluene, and xylene, often referred to as BTX. Benzene is an intermediate where 80% is used to produce other chemicals. In the US and Europe, about 50% of benzene is used in the production of styrene [ethylbenzene], 20% is used in production of cumene [plastics, adhesives, pharmaceuticals], and 15% is used in production of cyclohexane [think nylon]. Benzene originally came from coal production, but oilâ&#x20AC;&#x2122;s emergence shifted production so that coal produces a very small amount of the world supplies. Toluene can be used to manufacture benzene, and benzene can also be made from ethylene [natural gas] . A lot of benzene comes from pygas [oil].

OilVoice Magazine | FEBRUARY 2013

Image courtesy of Chemsystems.com Toluene is used as a feedstock for production of other petrochemicals, as an octane booster in vehicles, in solvents, as a component of polyurethane foam, and as a disinfectant. This chemical can be produced from NGLs but the majority share is from oil cracking. Xylene products include polyesters including soda bottles and fabrics. Xylene can be produced from NGLs, but also predominantly comes from oil. So which is more important, oil or natural gas? That depends on market factors for each petrochemical product. Typically, oil cracking leads to a more rich diversity of some chemical products, some of which command a premium in the market. Natural gas liquids , however, offer an abundance of supply are are less costly to produce, making them a very attractive feedstock for many chemicals also in high demand in the market. In addition, it depends on the supply of substitute products. For example, while benzene and xyelne are used in the production of nylon and polyester fabrics, cotton is a viable altnerative fabric that is regaining popularity. Ethane, in particular, is very cheap to produce from steam cracking NGLs. Ethane produces critical ethylene [and to a smaller extent propylene] which are used in over half of all petrochemical production.

Image courtesy of Dow.com Butadiene Butadiene, most often used in the production of synthetic rubber, is the one

OilVoice Magazine | FEBRUARY 2013

petrochemical in which oil supply shortages can really drive price quickly. While natural gas feedstocks do produce this important chemical, they make a relatively small dent in the overall world demand for it. The market has tried to find alternatives such as natural rubber, soy, plants, and others but none have been perfected as a true substitute for butadiene. Companies that can capitalize on the premium priced into butadiene stand to gain handsomely in the immediate future. Ethane vs. Propane Debate NGLs give us a key choice in feedstocks for our natural gas steam crackers. Part of the debate within natural gas cracking is which feedstock offers more value. Ethane is currently in such oversupply that the market is rejecting some supplies and companies are investing in storage facilities for the gas. Propane cracking provides a richer portfolio of products which tend to command higher prices in the market. Demand and supply tends to swing from ethane to propane cracking and back again, depending on whether the market needs production of ethylene or butadiene, propylene, etc.. Essentially, we have enough feedstock to satisfy demand and keep a lid on excessive price growth of both of these important petrochemicals. At the end of the day, investors and consumers should feel confident that the rise of natural gas production will satisfy 1) transportation fuel demand 2) petrochemical fuel demand and ultimately 3) solidify supplies of products we use everyday for the immediate term. Without natural gas production, the story would be quite different. As the natural gas industry builds key infrastructure and can provide for transportation of the gas and itâ&#x20AC;&#x2122;s constituent liquids, pressure will be taken off the oil market until the markets for both fuels complement each other. This will reduce the doom and gloom over looming oil supply shortages and allow us more time to develop technologies outside of these fuels for even longer term sustainability. A last point to be made is that current use of natural gas stocks as a grid power solution alongside coal, nuclear, solar, and wind will adversely affect supplies of natural gas for transportation and petrochemical products. We consume so much energy on the grid that we can burn through natural gas supplies in very short order. Luckily, the thorium nuclear revolution has come along just in time to alleviate this potential energy problem.

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OilVoice Magazine | FEBRUARY 2013

Tapping into emerging markets' potential Written by Alexandre Pelletier from Tata Communications A study by Tata Communications highlights growing influence of developing economies on the oil and gas sector. The Connected World report explored the key barriers for investment in emerging markets and senior decision makers’ attitudes towards the opportunities offered by these economies. It surveyed 1,600 business leaders globally, including decision makers in the oil and gas sector. The findings challenge some preconceived ideas and attitudes regarding BRICs and other developing regions, and draw attention to the huge opportunities that they hold when it comes to safeguarding the growth of the oil and gas industry, as fluctuations in energy prices continue and the demand for energy increases globally. The role of developing economies in global economic growth While a sluggish European economy struggles to recover, other regions are proving more resilient. This is putting companies in developed countries under immense pressure to move beyond their comfort zone and find alternatives outside of their home markets. It comes as no surprise that over half of the oil and gas companies surveyed in the Connected World report anticipate huge growth opportunities in emerging economies. Nearly half (45%) of oil and gas organisations are already operating in these markets, with 35% expected to increase their investment by 20%40% in 2012-2013. When it comes to the regions that are attracting the most interest, Asia seems to be leading the way. According to the Oil and Gas Investment Perspectives for Asia report by Ernst & Young[1], Asia accounted for more than half of the world’s increase in oil demand in the last 10 years, and the region is expected to account for more than 80% of the world’s net oil demand growth over the next 25 years. The role that Asia will play in the growth of the global oil and gas industry will continue to grow, which is reflected in the views of the Connected World survey respondents too, whereby 40% of senior decision makers from the oil and gas sector are looking into expanding into China and 27% are considering a move into India. With China and India expected to account for 75% of the world’s net oil demand growth by 2035[2], the Connected World report found that oil and gas companies look to these markets not only for current economic growth (54%) but also future economic growth prospects (77%). However, recognising the importance of not putting all your eggs in one basket, 36% of respondents are also looking into the opportunities offered on the other side of the globe by Brazil. As expansion into developing markets becomes an indication of the global economic shift, some companies are already making the most of growth opportunities offered by these

OilVoice Magazine | FEBRUARY 2013

regions. At the launch of the BP Energy Outlook 2030[3] in 2012, Bob Dudley, the CEO of BP Group, highlighted that global demand for energy will grow by around 40% over the next two decades, with the emerging markets at the forefront of this growth. In light of this, the company has re-aligned its strategy accordingly, with operations ramped up in the fastest growing countries, including Brazil and India. It’s likely that other companies in the oil and gas space will soon follow BP’s example. In fact, Connected World showed that almost a third of oil and gas companies look to expanding into these markets to follow the path of their competitors. Another key driver for investment was – perhaps unsurprisingly – the need to mitigate the impact of the uncertain global economic climate at home. Biggest barriers Despite the growth and expansion opportunities, operating in new markets can prove challenging because of physical factors such as the lack of a robust technology infrastructure and social factors such as differences in governance and political uncertainty. Unlike Connected World respondents from other industries – including professional services, IT and telecoms and retail – which were attracted to assets such as technological innovation and local talent in developing markets, oil and gas sector respondents associated these regions with a lack of local skills (45%). The fact is that the bulk of oil and gas natural resources are located in these economies, oil and gas sector companies have been used to making do with a lack of telecommunication infrastructure, difficulty to hire expertise locally, and complex regulatory constraints. However, it doesn’t have to be the case of ‘making do’ finding technology partners that can help them lower these barriers is essential to increasing productivity while reducing risk. Regardless of the new market you’re looking to move into, it’s crucial that decision makers fully appreciate the challenges unique to each market to maximise the return on your investment. Over half of decision makers from those oil and gas organisations that have already taken the plunge and are operating in emerging markets reported that government regulation in the new economy had proved the biggest challenge, which demonstrates the importance of thorough homework ahead of making an investment. Another considerable deterrent for investment was the lack of a reliable communications backbone, as 34% of oil and gas respondents said that the lack of this business critical infrastructure would actually prevent them from entering a new market altogether. The role of a communications infrastructure was also highlighted in respondents’ comments on the most crucial factors they associate with running a truly global business. Almost half of oil and gas respondents cited reliable communications across all territories (48%) and cost effective communications amongst these territories (47%) as two key factors for success, topped only by a flexible business strategy (56%). The importance of having reliable, high-speed Internet connectivity and the latest communications technologies reflects the increasingly connected society we live in and our expectation to be able to work effectively wherever, whenever and however

OilVoice Magazine | FEBRUARY 2013

we want. That is why businesses need to ensure that their organisation is truly global when they move into a new region, regardless of their location, working effectively together. Recognising that a communication infrastructure plays a key role in businesses looking to create a global presence, the telecommunications industry has invested heavily in bringing the digital infrastructure of developing markets on a level playing field with mature markets. With the foundations of a reliable communications infrastructure gradually taking shape worldwide, for example, Tata Communicationsâ&#x20AC;&#x2122; wholly-owned sub-sea network ring to circle the globe; more and more players in the oil and gas industry can be increasingly confident about future investments in new markets. [1] Ernst & Young, Oil and Gas Investment Perspectives for Asia [2] Chevron, Energy Supply and Demand [3] BP, Energy Outlook 2030 Review

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Iran-Iraq alliance and the right price of oil Written by Andrew McKillop from OilVoice IRAN-IRAQ ALLIANCE INSIDE OPEC According to 'Financial Times' and the WSJ, reporting several times in 2012, Iran and Iraq are "strengthening their alliance inside Opec", raising concerns among Saudi-led moderate Arab Gulf producers that pricing discipline inside Opec will be disrupted. The backdrop to this concern is simple: with the EU sovereign debt crisis worsening, critical uncertainty on what exactly the US fiscal cliff means for the US economy, and growing fears for the global economy, deepening divisions within Opec can undermine the organisation's ability to do its claimed job of managing oil export supply and preventing violent price swings.

OilVoice Magazine | FEBRUARY 2013

One thing is sure. Opec meetings now feature strong disagreements over the acceptable price of oil, the real state of the global supply-demand balance, and recent rising tension on who should replace the current secretary general of the organisation. This is General Abdallah el-Badri of Libya, who has presided the Organization since 2007, and on 12 December was given a 1-year extension of his job, from 1 January 2013. More complicated by its details, this extension was decided by Opec oil ministers in their conference organization, who also elected Abdulaziz Hussain, Minister of Oil of Kuwait as conference president for one year, with Dr Abdel Bari Ali Al-Arousi, Minister of Oil and Gas of Libya as Alternating President, for the same 1-year period from 1 January. The president to Dec 31, 2012 was Abdul-Kareem Luaibi Bahedh, Minister of Oil of Iraq. The 12 December Vienna conference's final statement carefully skirted around the Iran-Iraq 'alliance' or convergence of views - which is basically that speculators profit more from high oil prices than Opec member states - and produced a masterpiece of diplomatic jargon. It said that global oil price volatility in 2012 remained mostly due to "increased levels of speculation in commodities markets", but was exacerbated by geopolitical tensions and also by exceptional weather conditions - with the statement praising Qatar for organizing and hosting what the statement called a "successful" climate summit, COP18 in the series of UN climate meetings. FACING REAL WORLD FACTS The Opec conference has a delicate balancing feat to achieve, but the de facto IranIraq stance on oil prices is shared by many other member states. All the states however must face reality, especially the persistent or mounting pessimism over the global economic outlook, especially the EU and Eurozone crisis, but also the US and Japanese outlook. Again for reasons more closely linked to diplomacy than facing facts, the 12 December meeting's final statement claimed that world oil consumption in 2013 "will increase slightly" but this will be "more than offset" by growth of nonOpec supply, especially US shale oil output growth. Year average demand for or "call on" Opec export supply was forecast at 29.7 Mbd in 2013. This is already a contracton - if a small one - on the probable late 2012 global demand for Opec crude and products, the statement admitted. It is also a certain step back from Opec's growing export surplus or net supply capability - which is especially boosted by Iraq's significantly growing export surplus. Adding in Iran's exposure to US-led oil sanctions, the de facto Iran-Iraq alliance is easy to understand. In another classic diplomatic decision - basically to do nothing, annoying as few delegations as possible - the conference decided to maintain current export production levels which are officially counted as 30.0 Mbd: what they really are is another subject. In a sop to Iran and Iraq, the statement added that "Member Countries would, if necessary, take steps to ensure market balance", with oil prices being used as the yardstick on what constitutes "reasonable price levels" for producers and consumers. More simply this is a call for a new quota system, without saying it. Almost certainly Saudi Arabia and the other Gulf States would be assumed to most and first trim their supply on a voluntary basis.

OilVoice Magazine | FEBRUARY 2013

FACING THE UNREAL LOGIC OF OIL TRADERS Following the 12 December Opec meeting it took around 15 days, stretched by the holiday season, for the message to sink into the minds of traders: by 1 January 2013 prices were at $111.11 per barrel for Brent and over $91 for WTI. The unreal logic is that Opec is by its own admission pumping more oil than the world needs - so prices must rise! The logic is in fact double-stage: if oil prices are pushed up and stay high, Opec will maintain output, and in a certain hard-to-specify period inventories will grow enough to make the already plain fact of oversupply even plainer. At that unspecified time inteval forward from now, prices will fall.Talk about what constitutes the "reasonable price" for oil is rigorously and always talk only: at Opec meetings no figures are ever mentioned. The trader and analyst community supplies the numbers - but these range from below $50 a barrel to around $120 a barrel. The net result is directionless markets tagging along behind the incoming news on growth (and recession) outlooks, currency trends, CPI and purchasing manager forecasts, non-oil energy news, and of course the always intriguing subject of Arab Spring, Syrian civil war, al Qaeda in the Middle East and in Sahel Africa, and other material from the Indiana Jones collection. We therefore have an interesting entry scene to year 2013 oil trading, with current supply/demand most surely and certainly out of balance, with too much supply. To be sure, the Mid East geopolitical scene can unwind at any time, and winter cold can storm across the northern hemisphere - both of which can bolster prices. By late January however, we could expect the accumulated set of problems for overpriced oil to start taking their toll.

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Finding Opportunities in Southern Africa Reviewing the potential oil and gas industry in Southern Africa London, 09 Jan 2013 North Africa - are there any big fields still hiding? Will there be an 'exploration Spring?' to follow the political one? London, 12 Feb 2013 The next generation of exploration technologies Back to the future, returning to the onshore! London, 07 Mar 2013 Finding big oil fields offshore East Africa ..if there are any to be found! London, 09 Apr 2013 Finding big oil & gas fields in South East Asia The Politics may overwhelm the Geoscience! London, 14 May 2013

OilVoice Magazine | FEBRUARY 2013

The four pillars supporting North Sea Oil & Gas in 2013 Written by Malcolm Wilson from Achilles With the UK government's issuing of 167 new oil and gas licences to companies looking to drill in the North Sea attracting 224 applications, the industry is set to experience a period of renewed activity in 2013. Tax allowances also appear to be playing a part in unlocking billions of pounds of investment in mature fields, creating an expectation of increased business for many suppliers to the oil and gas sector in 2013 and beyond. According to Oil and Gas UK, 24bn barrels of oil remain to be extracted from the North Sea. However, this promising stimulus to the industry may not only extend the productive economic life of North Sea fields once thought past their prime, but may also create a surge in demand for equipment and labour resources that are already in short supply. There are four key points to consider for 2013: 1. The balance of taxation Production of oil and gas from the UK's continental shelf has been in decline for a number of years, but its enormous contribution to the UK economy is expected to continue for many more years to come - that is, provided investment is not hindered by over taxation. The recent announcement by the government to create tax allowances for mature fields is merely redressing the negative impact of the Treasury's earlier hike in marginal tax rates for companies operating in the North Sea - which in some cases were as high as 81 per cent. Figures from Oil and Gas UK indicate that the industry paid ÂŁ11.2 billion in corporate taxes on production in 201112, almost 25 per cent of total corporation taxes received by the Exchequer. Hopefully, the government's decision to introduce allowances will tip the balance and spark a renewed vigour in the industry for investing in mature fields. 2. Creating equipment availability As a mature industry, North Sea oil and gas fields are getting smaller and costs per barrel are rising. To stay competitive in a volatile global energy market, operators are going to have to keep costs as low as possible. However, availability of specialist mobile equipment such as drilling rigs, pipe laying vessels and heavy lift barges are in demand the world over - so there may be longer-term contracts on offer in other parts of the world that are more attractive. Once such heavy and slow moving pieces of kit have transferred to other areas of the globe, getting them back again is not so easy. Given the long lead-times involved in building a new drilling rig, planning and investment has to be geared to a long-term vision - something that may be difficult to

OilVoice Magazine | FEBRUARY 2013

achieve with mature fields and volatile oil and gas markets. With aging infrastructure supporting extraction, costs of maintenance will continue to rise. Clearly, a new way of thinking will be required to cost-effectively extend the life of equipment. In 2013 operators will need to look towards greater collaboration on sharing drilling rigs and other assets, perhaps creating collaborative arrangements between two or three competitors. We may well see creative initiatives of this nature on the rise next year and in the years to come. 3. An emphasis on Labour resources The North Sea region is short of good, experienced oil and gas people and this will be an ongoing problem in 2013. The shortage of labour resources may well act as a constraint on the renewed interest in exploiting mature fields. Although experience is always in high demand, there is also a need to encourage young people into the industry. More apprenticeships will be called for next year as operators and suppliers respond to the expected increase in investment to the sector. The demand for high calibre engineering graduates is very strong, particularly in the burgeoning subsea industry in which the UK has renowned expertise. But perception of the industry also needs to change - moving away from an industry associated with wild swings in demand that in the past have lead to volatile jobs markets. As an industry that has a reputation for paying reasonably well, when compared to other sectors, 2013 should be a year for encouraging the young to engage with the industry through exciting apprenticeship and career opportunities. 4. Developing greater collaboration The North Sea oil and gas industry has a cultural history of collaboration, born from the unique challenges of the harsh environment, the pioneering technology and demands of deep-sea drilling. Initiatives on Health & Safety, sharing of resources such as helicopters, and CRINE - the cost reduction initiative for the New Era - have proved that collaboration works in the industry, creating value by sharing resources and costs. Collaborative communities will be the way forward in 2013 as the industry identifies the clear advantages from sharing resources - such as rigs and vessels and work towards creating closer relationships with suppliers and competitors alike. Provided the balance of tax is set to stimulate investment, rather than retard it, and initiatives to attract the best young talent to join the industry are followed through, then 2013 should see an encouraging level of activity that is good for the industry, the UK economy and consumers. However, maintaining profits will be dependent on keeping costs under tight control and that will require greater collaboration across the industry, so that assets can be retained in the region and their use maximised. Sharing costs creates value.

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OilVoice Magazine | FEBRUARY 2013

The price is right for West African E&P Written by Richie Ethrington from Finding Petroleum West Africa makes up one third of the so-called 'golden triangle' of deepwater oil exploration and production (E&P) plays. While the US Gulf of Mexico and offshore Brazil have long been in the limelight, interest in West Africa has taken longer to come to fruition. Over the last few years, however, that has begun to change. And as we move into 2013, upstream attention is set to firmly focus on highly prospective deepwater plays in the region. Indeed, West Africa is fast establishing itself as the hotspot for the global oil industry. The region's growing appeal comes as no surprise. West Africa's Atlantic margin is home to large unexplored offshore acreages that contain significant E&P potential. And where there is growing potential it is normally followed by a strengthening flow of investment, both local and from overseas. In this regard, West Africa is no different. According to a semi-annual report published by Barclays, E&P spending in Africa is set to rise by 4.5% year-on-year in 2013 to reach around US$25bn, with Western Africa and more specifically the Gulf of Guinea attracting the lion's share of that fresh investment. This falls in line with a broader uptick in activity. Indeed, global E&P spending is poised to reach a record US$644 billion by the end of 2013, Barclays forecasts. So, what is fuelling the projected rise in E&P spending both in West Africa and worldwide? The principal bellwether for expanding budgets is the rising price of oil something which is expected to remain strong over the coming quarters. In short, with prices rising the time to drill is now. The price of oil is high and it is expected to remain that way. 2012 closed with Brent averaging at US$111.70 a barrel (bbl) and WTI at US$93.30/bbl. As a result, the rising levels of E&P spending in the region are likely to continue. In terms of geography, the buzz around the industry at present is focused on two nations in particular: Angola and Ghana. Both countries have a strong history in the oil industry, but both look set to eclipse that with an even stronger future. At the time of writing Angola ranks as the more important of the two in the eyes of investors and in E&P focus. The abundance of oil and gas reserves in offshore areas has helped Angola to emerge as one of the most important countries in Africa for the exploration of oil and gas. Crude oil was first discovered in Angola in the offshore Kwanza basin back in the 1970s. Fast-forward to today and Angola is now home to over one third of all discoveries made over the last three years in the region. Of the

OilVoice Magazine | FEBRUARY 2013

52 oil and gas discoveries made in offshore West Africa between 2009 and September 2012, Angola accounted for 18 (or 34.6%) of this tally. While onshore and shallow water pre-salt discoveries in Angola date back decades, current efforts involve the much more difficult task of exploring in pre-salt and ultradeep regions. At present, Angola's reserves are located offshore and onshore along the coast in three main basins: the Namibe basin, the Kwanza basin, and the Lower Congo basin. A fourth basin, the Owango, is also under exploration for reserves. However, doubts are growing as to the latter's prospectively. The basins home to most of the country's reserves are Lower Congo and Kwanza, with the lion's share of production coming from one exclave in particular, Cabinda. It is the Namibe basin, however, that the strongest E&P potential can be found. The Namibe basin has significant potential for exploration, with the US Geological Survey recently estimating that undiscovered reserves of oil totalled around 712 million. This provides strong upside potential for the country's production levels over the coming years. A recent deep-sea pre-salt discovery by Danish firm Maersk Oil, in partnership with Angolan state oil firm Sonangol, in September of last year served to underline this potential. The duo found the Azul-1 well in the Kwanza Basin, drilled to a depth of 5,334 meters, has a potential capacity of more than 3,000 barrels a day. Maersk is, of course, just one of a host of overseas firms conducting E&P activities in Angola. Angola's position as a leading producer of crude oil in Sub-Saharan Africa, and as a member of the Organisation of Petroleum Exporting Countries (OPEC), means that international oil companies are already very familiar with the country's resource endowments. Indeed the stage is set for the first large-scale exploration effort in West Africa's subsalt and ultra-deep region. A number of oil industry majors including Italy's Eni, Norway's Statoil, Spain's Repsol YPF (which had its assets in Argentina seized back in April of last year), US major ConocoPhillips, and French multinational Total were all awarded operatorships for 11 deep-water subsalt blocks back in 2011. To-date the country has delivered several major discoveries to overseas players and there is good reason to believe that there are plenty more to be found. US Energy Information Association (EIA) data shows that as of the end of 2011, Angola had proven reserves of 9.5 billion barrels of crude oil. That figure is the second-largest in Sub-Saharan Africa behind Nigeria, and ranks 18th in the world. Successful exploration in Angola's pre-salt formations continues to drive optimistic oil production forecasts for the country, and the Angolan government is targeting 2 million barrel per day production levels by the close of 2014 as offshore projects come on-stream. With Angola's crude being sweet (low in sulphur) and light, it is well-suited for exports to the United States, China, and other large importers. Given the rising production targets and the quality of crude being produced, the interest of investors and the industry's leading players in the region is entirely understandable. After Angola, Ghana is the next West African nation to appear upon the E&P radar. At the start of 2010, Ghana produced virtually no oil at all. As we move into 2013, the country's outlook looks set to be close to around 80,000 barrels a day. While such levels keep Ghana very much in the 'frontier' category as a producer, the fact that

OilVoice Magazine | FEBRUARY 2013

they country has seen a wave of discoveries in recent years means that this status could well change over the coming years. Of the same 52 oil and gas discoveries made in offshore West Africa between 2009 and September 2012 that we referenced earlier in the article, 13 were made in Ghana during this period. When compared with Angola, E&P in Ghana is very much in its infancy. But things are gathering momentum, with all eyes closely watching the progress of the Jubilee Field. As of the end of 2012, Africa's leading independent oil firm, UK-based Tullow Oil, put crude production levels at Jubilee at 110,000 barrels per day (bpd). The Field is also reported to have produced a little over 50 million barrels of oil since it began commercial production in 2010. The gradual surge in output at Jubilee gives indication of a healthy outlook for the oil sector, which has become an important economic-growth driver and revenue source for government in Ghana. But with Tullow expecting to reach peak production of around 120,000 bpd at Jubilee sometime in 2013, E&P activity will need to begin looking further afield and into deeper waters. Acutely aware of this fact, Tullow has a head start ion the rest of the overseas firms operating in the offshore arena in Ghana. 25 kilometres from the Jubilee Field is where the Tweneboa-Enyenra-Ntomme (TEN) wells can be found. In the second half of 2012, the TEN project made good progress and Tullow and partners submitted the Plan of Development to the Minister of Energy in Ghana in early November 2012. The wells are estimated to hold commercial reserves to 380 million barrels of oil equivalent (mmboe). At least US$4 billion is expected to be invested in TEN's development over the coming years by Tullow - which owns a 49.95% stake in the tree wells - in collaboration with its partners, which includes the Ghana National Petroleum Corporation (GNPC). While Angola and Ghana are the rising stars of the West Africa oil industry at present, there will no doubt be others to follow - especially as long as high oil prices continue to drive the wave of E&P activity in the region. This heightened level of investment is in turn set to force a sustained rise in output levels towards the end of the decade. On the demand side, meanwhile, strong economic growth in the region is likely to see oil and gas consumption continue to grow. As this happens we may see more national governments in the region following Nigeria's lead in reforming expensive fuel subsidies.

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OilVoice Magazine | FEBRUARY 2013

Opportunities for all creating successful local partnerships in the Chinese shale gas sector Written by John McGoldrick from Dart Energy In this three part series, John McGoldrick, CEO of Dart Energy International, looks at the developing state of Chinese shale gas projects, and some of the implications these might have on the international industry. China recently announced the number of bidders in the second round of shale block tenders: 83 companies making 152 bids for 19 exploration blocks. The companies were local, manyare experienced oil and gas operators , and others arerelatively (or totally) new to the business. Some aredownstream players-distributors, generators, or high endusers of gas who are looking secure supply. Others apparently include real-estate firms and investment companies. As part of the tender process, these local companies are required to either demonstrate their own capabilities, or prove that they have partnerships and joint ventures in place with qualified local or foreign E&P companies who can bring in the required knowledge and skills. Foreign partners, however, must be minority shareholders (no more than 49%). China has ambitious plans to maximise production from its CBM and shale gas reserves. However, one of the keys to unlocking this vast potential will be accessing and applyingthe skills and knowledge already developed in other parts of the world, to the operational environment in China. For both local Chinese and foreign companies, developing successful partnerships will require an understanding of how to worktogether, and an appreciation of the relatively undeveloped nature of the shale and CBM industries in China. Developing a track record Although there are many international E&P companies who have shale gas and/or CBM experience, China is different and presents unique challenges. The geology's different, there are different regulations and, with inexperienced partners, there will certainly be different expectations on outcomes. DartEnergy International was an

OilVoice Magazine | FEBRUARY 2013

early mover into the Chinese CBM gas sector, and we are one of the few foreign E&P companies to actually have a track record of drilling multiplewells and moving into pilot commercial production in this highly promising sector. Working on unconventional Chinese projects, DEI has been through a steep learning curve. Having a consistent and compelling presence on-the-ground in China has been a huge advantage. We are seen as being committed to the market, and have developed a reputation as a solid partner who understands where we can add the most value. For those looking to get involved, that is an important lesson: technology can be foreign, but the commercial business needs to be local. Choosing the right partner The challenges have been many. But these are experiences that any foreign company working successfully in China will need to overcome. There are a number of key factors that all sides should consider when entering into partnerships in China, including: Investing in high quality local staff: For foreign businesses, local staff are key to getting projects and partnerships moving - and keeping them going. They will make or break the relationships which are needed to successfully operate on-the-ground. Key local people will also be the commercial drives of these projects. Technical expertise can come from anywhere, but on the commercial side, local experience and expertise is vital. Know your place in the market: Or, know where you can add most value in a partnership. The Chinese O&G majorsmay be less interested in working with smaller E&P companies (NB Dart Energy International has partnered with PetroChina,CUCBM and HCBM). Their deals, exploration blocks, and partners will already be lined up. However, those with less experience-the distributors, generators, or high users of gas who are looking to secure supply-will have a greater appetite for working with smaller foreign E&P partners. The company-to-company fit will be better. Develop a local track-record: Yes, easier said than done. But a key advantage DEI has benefited from is that we have already worked on two local unconventional projects and, additionally, have brought wells into pilot commercial production. In a market where expertise and experience is scarce, this is a real plus and means Dart Energy International has a sound reputation for getting results...and getting projects done is really the true test. Make sure it's mutually beneficial: This may be a little on the 'obvious' side of the ledger, but each partner should ideally bring something to the table. Foreign companies are expected to bring in, and transfer, technical skills. So it should be up to the local partners to bring in the downstream networks. Finding gas is one thing, it is important that the partnership knows what to do with it once they have it. Soft skills It's the soft, intangible, skills that will be needed to develop successful ongoing

OilVoice Magazine | FEBRUARY 2013

Chinese-foreign partnerships. These are, unsurprisingly, best delivered by talented local team members. But all companies working in China (and Chinese companies working with foreign E&P operators) should go in with their eyes wide open. Each side will have a lot to learn, and managing both parties expectations and operational styles will be crucial to running successful projects.

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Extending the life of ageing Oil and Gas assets Written by Dr Liane Smith from Intetech Integrity management and corrosion modelling tools provide a systemic approach to ensuring the safe and reliable operation of ageing assets for oil and gas operators looking to squeeze more from mature reservoirs and facilities. Many oil and gas operators today are extending the operational life of old facilities and equipment. Some are looking to get more out of assets established during the boom of the '60s and '70s. Given that these were built when a barrel of oil traded at $10-12 rather than the $100-120 it trades at today, these assets can still be viable economically even if only 10-20 per cent of the hydrocarbon is being produced. Meanwhile, others are facing changing production conditions. Managing the integrity of assets such as topside plant and equipment, wells, pipelines, and safety-critical elements (SCE) means ensuring they can perform their required function effectively and safely over the course of their design life. However, it becomes more challenging as oil and gas fields mature. Around half of all workovers and shut-ins in mature fields are caused by well integrity problems, while scaling, corrosion and failed well barrier equipment are all common issues that call for great vigilance to minimise the risk of leakage. This is why it has become so important for operators to implement an appropriate

OilVoice Magazine | FEBRUARY 2013

asset integrity management tool to track, monitor and report on the condition of assets in a timely way. Using web-based software with smart functionality, it is possible to acquire information from multiple sources - including third-party databases and legacy systems - and display it in a single management dashboard. This provides an instant view of current well integrity status as well as historical key performance indicators (KPIs) at a well, field or enterprise level. A constant and growing challenge The ageing infrastructure of offshore and onshore installations presents the industry with a constant and growing challenge. There is the cumulative degradation of facilities and equipment over time resulting from corrosion, wear or fatigue, as well as scenarios where like-for-like replacements are no longer suitable due to either obsolescence or changes in engineering standards. There can also be a change in production condition, modification, or introduction of new equipment. At the same time, the operator needs to be sure that making the necessary investment is worthwhile in respect of the additional production they are ultimately going to realise. At well level, there are many risks to consider. External casings deteriorate over time at different depths for a variety of different corrosion mechanisms, and can result in a loss of structural integrity. The risk of well collapse is therefore higher as thinned well casings buckle under the weight of the well. Ageing wells also tend to have more aggressive conditions, normally being higher water cut, and potentially with H2S arising from reservoir changes or microbial activity. Conditions may accelerate attack or introduce corrosion damage where it was considered 'not to happen' before. Furthermore, ageing safety critical valves (SCSSVs and XT valves) have a higher risk of damage in terms of the seal surface, while gradual deterioration of a cement seal arising from thermal and pressure cycling over the years can generate micro annuli in the cement channel around casings. This results in higher risk of a leak path through annuli instead of confining fluids to the correct conduit (tubing). These challenges are compounded by the fact that operators often store or report on asset information in different systems. Not only do these 'silos' of information make it difficult for senior executives and management teams to collate, compare and report on asset integrity data, but the length of time this can take impacts on their ability to identify potential problems, make informed decisions and take remedial action. A unified approach Advanced asset integrity management systems integrate data that is otherwise held in silos and provide an instant overview and drill-down capability, instead of operators having to trawl through masses of information held in non-integrated systems. At the same time, corrosion modelling software can be employed to estimate corrosion rates when assessing the condition of an asset, and inform materials selection when looking to modify or extend its operating remit. Together, these systems can provide the foundation for a robust asset life extension strategy.

OilVoice Magazine | FEBRUARY 2013

The first step is to consider the commercial life of the asset. This means assessing the basic adequacy of the infrastructure in place, local market conditions and the condition of the reservoir. This also means assessing the current condition of the asset and establishing whether or not it is fit to continue operation. Operators will need to evaluate inspection data, logging data (for wells), and perform a review of all monitored production parameters. The latter includes changing water cut, fluid flow rates and pressure profiles over time. A comprehensive understanding is also required of both the current as-built materials, and that of the environment in which they are operating in when compared with their original design conditions. Here, corrosion modelling software provides an ideal starting point, given that collecting inspection and logging data is costly. Specialist services are required to log the well, and production has to be stopped while it is acquired. Therefore, it is perhaps unsurprising how many operators change the use of an old well without giving thorough consideration to whether it is suitable for a new production condition. Only having established the condition of an asset is it possible to confirm the current safe operating envelope. This is done by comparing the latest results against the data specified in the asset's original design document. Key inputs include the estimated and/or measured extent of lifetime damage to date (corrosion, erosion, fatigue), as well as the known metallurgy of construction, which defines the envelope in respect of pressure, temperature, flow rates, and the required chemical injection needed to maintain the status quo. Actionable information Ageing assets will always be vulnerable to changing conditions, so they must be reassessed at regular intervals and compared against a control to ensure that all parameters stay inside their safe operating envelope. Small detailed shifts may be indicators of something more dangerous (e.g. H2S limits creeping above a threshold can result in catastrophic cracking failure), while it may be necessary to adjust the safe operating envelope of an asset over time. Rapid reporting on data provides operators with the capability to make daily assessments on asset conditions. Having this near real-time visibility allows key personnel to make informed decisions on the necessary actions should a problem be identified. At the same time, an inspection regime can be clearly defined within the system to describe how routine checks and testing procedures are performed, who is responsible, how often they should be performed, what should be reported, and next steps should results fall outside acceptance criteria. With the visibility that an integrated asset management system provides, operators are also able to take an informed decision on the actions necessary to prevent the current status of an asset or assets from deteriorating further. Different decisions on mitigation systems are appropriate for different equipment. For example, the use of cathodic protection is a common preventative measure for protection of casings and buried pipelines, while inhibitor can be injected into both the well and surface equipment.

OilVoice Magazine | FEBRUARY 2013

Having all well integrity data at their fingertips helps operators to make the right decision in terms of carrying out maintenance and repairs in a timely fashion, based upon a risk ranking strategy that not only ensures safety, but prioritises resources in an optimum way to lower the overall risk level that an operator is carrying. This is particularly important given that testing and preventative repairs have an associated cost and an impact on the operator's short-term productivity, whilst equipment failures have different costs and perhaps an impact on long-term productivity, or potential safety and environmental consequences. With an increasing dependence on existing infrastructure to act as 'hubs' in the development of new fields or extension of aged fields, and a focus on improving the reliability of existing assets, combining well integrity management and corrosion modelling tools provides a cost-effective and robust approach to extending the use of equipment and infrastructure past the originally anticipated service life. Five founding pillars for asset life extension Ageing assets can operate safely and effectively well beyond their specified design life, provided operators adopt the right management approach. Intetech's Dr Liane Smith outlines five founding pillars for implementing an asset life extension strategy addressing both surface and subsurface facilities: 

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Consider the potential commercial life - in respect of local circumstances such as the remaining reserves, market demand and basic adequacy of the infrastructure, and look for possible bottlenecks Evaluate the current condition - assess whether the asset is fit to continue operation by evaluating inspection data, logging data (for wells) and perform a review of all monitored production parameters Establish the current safe operating envelope - compare results of current condition assessment against data specified in original design document Prevent present status from deteriorating further - select appropriate mitigation systems, namely repairs and means of protection (paint, coatings, cathodic protection, protective chemicals injected) Clearly define and document the inspection regime - outline roles and responsibilities, technical and physical review procedures, instrumentation, data collection and reporting tools, define next steps should issues be identified

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OilVoice Magazine | FEBRUARY 2013

Where are the exploration opportunities in Africa? Written by David Bamford from Finding Petroleum Africa has become a 'magnetic' attractor for explorers. Aside from the nowadays favoured provinces of West Africa, from Angola, Via Nigeria, to Ghana, what can we say about the rest of Africa? North Africa (and the Eastern Mediterranean) What exploration opportunities are there in North Africa, from Morocco via Algeria and Libya to Egypt, and beyond to the Eastern Mediterranean? Below ground, these countries show different stages of exploration maturity. Offshore Morocco has been quite active in leasing terms recently and is perceived as a Frontier province. Algeria has 'always been open' and now most plays and basins look quite Mature in exploration terms. For Libya, one would say that the Offshore is also a Frontier province. Onshore, whilst there is a long history of exploration and production, not all the significant basins have been equally explored, and there is a case to agree that exploration has, for the past several decades, not benefitted from the latest technologies. Similarly to Algeria, Egypt has 'always been open' and most plays look quite Mature in exploration terms, although again there is a case that some modern technologies still have a role to play - for example sub-salt imaging in the Gulf of Suez and Full Tensor Gravimetry onshore. The Eastern Mediterranean was once an almost completely neglected exploration province but has now the reputation of being a major Frontier with huge amounts of gas reportedly discovered. Above ground, of course there are some significant issues to contemplate, in particular with political and security stability still to result in Libya and Egypt in the wake of the 'Arab Spring'. Should we anticipate an imminent 'exploration Spring' in North Africa, in particular can further large discoveries be foreseen, and if so, where?

OilVoice Magazine | FEBRUARY 2013

East Africa East Africa also used to be considered an exploration 'backwater': the thinking went perhaps there is some gas but not enough to ever be commercial, not a place to interest 'serious' explorers! Things are changing. The region is seeing a 'scramble for resources' - in the East African Rift System all the way from Malawi to Somalia, with the Albertine Basin in Uganda exemplifying what might be available, with perhaps (even) more potential in Kenya; in the offshore areas of Kenya, Tanzania and Madagascar; ENI and Anadarko may have made huge gas discoveries in Mozambique; and of course there remains the vast heavy oil potential of Madagascar. Does this region have the potential for the Giant Fields that will unlock its future and propel it to the front rank of hydrocarbon provinces: perhaps ENI and Anadarko have already answered this question for gas but what about oil? If Yes, does the region have the political, regulatory and fiscal systems that can deal with the transformation that would result? Southern Africa Moving south, what is the scope for oil & gas exploration and production in Southern Africa, including Nambia, Mozambique, Tanzania and South Africa? A sensible point to start is to consider the large gas resources that have been reported for Mozambique and Tanzania. When will these be converted to reserves and when might we see production, for the putative LNG schemes? Given the large amount of global LNG-scale gas that has recently been discovered, not least in the USA, perhaps the earliest offshore gas production (from Mozambique) lies beyond 2020 and a categorisation as reserves must await the first signed gas contracts (as Shell discovered, to their cost, in Nigeria almost 10 years ago). Perhaps the earliest gas production will in fact be from onshore South Africa (for example, shale gas, or coal bed methane plays associated with South Africa's massive coal reserves)? Offshore oil discoveries may reach production relatively rapidly. Are there 'oily' exploration opportunities in the region, for example, is the Namibian sub-salt play equivalent to, or at least similar to, the prolific plays offshore Brasil? And what about South Africa itself? Opportunities for UK companies As the oil and gas industry develops in Southern Africa, there will be a need for a range of services, particularly engineering contracting. Additionally, access to large amounts of gas could drive the growth of a domestic chemicals industry. South Africa itself offers access to skills and general infrastructure, including port facilities. UK companies seeking opportunities in South Africa might be able to take

OilVoice Magazine | FEBRUARY 2013

advantage of the bi-lateral UK-South Africa Trade Agreement which aims to double trade between UK and South Africa by 2015.

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