Oilvoice Magazine - Edition 43 by OilVoice

Edition Forty Three â&#x20AC;&#x201C; October 2015

It's Insane But Why Not? Oil Back at $100 By Christmas The Top 100 Canadian Oil & Gas Companies Fracking Apart the United Kingdom

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Adam Marmaras Issue 43 â&#x20AC;&#x201C;October 2015

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Welcome to the Forty Third edition of the

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This month we have another batch of 'must read' articles, including David SpencerPerceival, Stephen A. Brown and John Richardson.

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Table of Contents It's Insane But Why Not? Oil Back at $100 By Christmas by John Richardson Fracking debate needs to grow up by David Spencer-Perceival

Fracking Apart the United Kingdom by Peter Strachan and Alex Russell What to do when business dries up at home A thought on tailoring from the world of E&P training By Mark Bentley Five Misunderstandings About Oil And Maybe A Sixth One by John Richardson

The Top 100 Canadian Oil & Gas Companies by Mark Young

General Electric: From Oil to Lithium by Jeff Nevil

ANGOLA: After various set-backs in deep-water Kwanza exploration, attention turns to onshore, with emphasis on local industry participation by Andrew Hayman

How does the Market Value Undeveloped North Sea Reserves by Stephen A. Brown More Gloom on the Horizon for Bakken Companies in Q3 2015 by Mark Young

It's Insane But Why Not? Oil Back at $100 By Christmas Written by John Richardson from ICIS ALBERT Einstein is widely credited with saying this: 'The definition of insanity is doing the same thing over and over again, but expecting different results'. Who cares if it is either paraphrased or he didn't even say it at all? This is a fantastic quote. For me, what makes this quote so fantastic is that it sums-up the behaviour of central bankers the world over since the Global Financial Crisis (and in the case of the US, right back to the dot com bubble of 1995-2000). Essentially, what the central bankers have done is print more and more money, thus keeping the costs of borrowing very low. In the US, as I said, this started with the run-up to the bursting of the dot come bubble. This was followed by the low costs of financing that led to the sub-prime crisis. Subâ&#x20AC;&#x201D;prime had a much greater global effect than the dot com bubble because as we all know, it almost caused the collapse of the global financial system. Since 2008, central bankers - not just in the US now but now also in Europe and Japan - have doubled, or should I say tripled-down, on their insanity: They have created the mother of all investments bubbles, this time in commodities. So what is the mechanism behind all of this? The best explanation I've been able to find was in a post by fellow blogger Paul Hodges in December of last year where, having interviewed a major asset manager, he wrote the following: 'His argument was simple, namely that the Fed and Bank of Japan and others are forcing him to invest in stocks as the money earns nothing sitting in the bank. He is being effectively held hostage by the central banks.' In the case of oil, the asset manager accepted that prices in H1 2014 did not reflect

the real supply and demand fundamentals. But he added he had no choice but to park his money there as he chased yield in a very low interest rate world, wrote Paul. This fantastically cheap money has also incentivised oil and gas, iron ore and petrochemicals producers to bring on-stream or plan vast increases in capacity that are again not justified by the real laws of supply and demand. The case for adding new capacity seemed overwhelming because a.) As I have just said, there was lots of cheap financing around b.) Everyone kept telling you that we were in a 'new paradigm', where China that would boom forever, c.) You had in the case of US shale oil, gas and petrochemicals very, very cheap raw materials and d.) You needed a good investment story to sell to your shareholders to keep your share price up. But now this is all going wrong and the damage from the unwinding of the commodities bubble is having far greater implications than even sub-prime. Countries from Brazil to Indonesia to Australia are waking up to find that because of events in China, the markets for the commodities they produce are simply not there in the volumes that they expected. It also needs to be stressed that China's economic stimulus has played a big role in this bubble. People took China's credit-fuelled growth rates of 2009-2013, extrapolated these in the future and missed the fact that this growth was always unsustainable. Here is a further important point: All the excitement and hype surrounding the commodities bubble has diverted attention from the biggest issue confronting the West, which is the ageing of its populations. So where do we go from here? One of two directions, I think: 1. We go through a long and painful adjustment period, where oil prices will fall to $30 a barrel or below over the long term as the Fed etc. wind back stimulus. Commodities prices in general will be depressed as we work through all this vast oversupply and debt, which will be made a lot harder by the world being caught in a deep deflationary down-spiral. Meanwhile, chemicals companies will need to start the search for new, more sustainable sources of growth built around satisfying basic needs, such as ageing

populations in the West and providing safe drinking water and sanitation in the developing world. And in all regions, another big opportunity will be reducing our carbon footprint. 2. The Fed rolls the dice once more by launching its fourth quantitative easing programme - 'QE4'. And the Fed's actions are backed up by the European Central Bank and the Bank of Japan, which also print lots more money. Let's assume that No2 happens. When might it happen? Perhaps the Fed will kick off this process as soon as 17-18 September, during its next Federal Open Market Committee (FOMC) meeting. Or maybe it will wait for the FOMC meeting after that, which takes place on 27-28 October. And what would No2 mean? It would mean this: 

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Oil might well surge back to $100 a barrel, or thereabouts, by Christmas along with a recovery in petrochemicals prices and other commodities, such as iron ore. The Cassandras will be told, 'You were wrong' as global stock markets also rebound very strongly. Investment analysts will start talking about another new 'growth paradigm' maybe 'the rise of the middle classes' in India, Latin America, Southeast Asia, even Africa - or how about Mars? Many people will believe them, even though the data will always say something else. If this new bubble lasts long enough, more easy financing will find its way into further additions to oil, gas, petrochemicals and iron ore capacity that is surplus to real needs. People in the financial sector will take home fantastic bonuses, Policy makers and chemicals companies will forget about what will really get the global economy back on the right track: Tackling basic needs, some of which I mentioned above.

The end result? Even more deflation and bad debts, making the eventual and inevitable adjustment for the global economy even more painful. And maybe this time around, if QE4 does happen, the global financial system will collapse. We have had enough, surely? No more insanity, please. View more quality content from ICIS

Fracking debate needs to grow up Written by David Spencer-Perceival from Spencer Ogden Energy The fracking debate has become a shouting match. Two diametrically opposed sides hollering hyperbole at each other. Above this din it is now exceedingly difficult to hear any measured, moderate views. However these are exactly what the debate needs. The energy sector is crying out for a reasoned argument around fracking. To quote a conversation with our board member Lord Chris Smith, who heads the Task Force on Shale Gas, 'We simply do not know what fracking's real potential is which is precisely why we should do something to find out.' Exploration needs to happen and it needs to happen quickly. Applications for exploration in Lancashire, Yorkshire and the Midlands should be given the go ahead. We need exploration to better understand the potential of these sites. Of course, this exploration needs to follow tight regulations. This is something well set out in the recent report by Lord's Smith Task Force, which outlined how carefully implemented exploration can avoid the hazards caused by irresponsible practices in America. We need to explore just what is underground to understand what fracking could mean. A report by E&Y report estimates that fracking could create 64,000 jobs in the UK, whilst Peel Holdings have calculated that the industry could be worth ÂŁ30bn to north England and the West Midlands, based on 100 production sites. These jobs would not be focused on drilling, but rather come from the range of supply roles that fracking will require.

It seems blinkered to ignore this potential, particularly at a time when the UK energy jobs market is taking a serious kicking in the North Sea. The jobs problem extends beyond Aberdeen, however. Beyond the City, a recent Oxford Economics report, predicted zero growth in the UK energy and environment over the next five years. The report found that Coventry has been an energy hotspot since 2010, with the sector creating a net 2,213 jobs. The immediate future is less bright. Caerphilly, Wales, is predicted as the next 'hotspot' for the sector - the area is expected to create a net 32 jobs between now and 2020. Clearly, the industry needs support. What's more, fracking could fuel the Northern Powerhouse, providing the concept with something other than hot air. It could initiate jobs, investment and growth for somewhere other than London. Fracking is not the silver bullet. Fracking for oil is pretty much a non-starter, fracked gas is far more responsible. It emits relatively low levels of carbon when burned and is a climate-friendly option when compared to coal, oil or liquefied imported Qatari gas. Still, it is not the long-term answer. It is, though, a potentially brilliant medium-term solution. It offers a strong stop-gap until renewables really provide a workable solution. Surely, this is preferable to our current energy mix? Let's stop being fracked off. Let's at least explore fracking's real potential. We cannot afford to ignore it any longer.

View more quality content from Spencer Ogden Energy

Fracking Apart the United Kingdom Written by Peter Strachan and Alex Russell from Robert Gordon University - Energy Centre Ignorance of the past is bliss The UK government, under Labour, Conservative and Coalition control, has over the past forty years relentlessly pursued a fiscal policy of maximising short-term revenue take from the oil and gas reserves lying in the UK continental shelf (UKCS). Little or no thought was devoted to scheduling the timing of the exploitation of these mineral resources or to the need to invest the taxes gathered in, for example, a sovereign wealth fund to ensure future generations would also benefit from the rape of the North Sea's black gold. In this respect the contrasting policy approaches of Norway and the UK to developing their respective ownership of minerals in the North Sea have produced alarmingly different economic outcomes for which future generations of citizens of the UK may hold Westminster responsible. An example, from a long list of similar asymmetric economic outcomes, occurred in 2012 when ÂŁ348 million was spent from Norway's ÂŁ483 billion (current value) oil fund to take a 50% stake in a shopping centre in Sheffield, just one of many such ownership grabs of UK assets, whilst increasing its wealth by selling gas to the UK to keep our homes warm and lights burning bright. Few objective oil and gas analysts would disagree with the above sentiments. But the points merit restating as the lessons of the past appear totally lost on Prime Minister David Cameron and Chancellor George Osborne and to some extent on the UK oil and gas industry. This lack of appreciation of the need for a long-term energy strategy combined with a well embedded delusional acceptance of what constitutes economic value is vividly illustrated in their declared intent to rush headlong into exploitation of the gas and oil locked in the UK's on-land shale deposits. Westminster has made it clear it is hell bent on fracking apart the shale deposits that lie across the length and breadth of England in the first instance, but no doubt also over all other parts of the UK in due course. Over 1000 square miles of England have been (f)earmarked for fracking activity in as short a time frame as possible. The arguments put forward in support of this approach are so nerve chillingly weak that

they cast doubt on the credibility of the motivations of Westminster and the fracking fraternity. They also might accelerate the almost inevitable march of Scotland towards achieving independent nation status. What are the arguments put forward in favour of fracking apart the UK? Basically, the Chancellor believes fracking will generate substantial fiscal income, generate thousands of new jobs and will be of less damage to the environment than importing gas from Russia. Crazy time to frack apart the UK Osborne is correct. If the UK's plans for fracking become a reality, substantial tax revenues will be paid to Westminster over a number of years and many jobs will be created. Alas, perhaps Osborne has acquired his business acumen through observing ex Chancellor Gordon Brown's fund raising prowess in 1999 when Brown chose to sell 395 tons of the UK's gold reserves at rock bottom prices. Gas prices today are at such a rock bottom price. The UK's shale reserves of gas and oil is like money in the bank. It will not deteriorate through time. It is not the same as ceasing production in the North Sea for ten years, say, then expecting to be able to resume viable production again. Fracking wells are small scale affairs usually drilled from rigs attached to the backs of lorries. Unfortunately they are small scale because their life expectancy is small and the speed at which output declines is steep. In order to maintain production targets huge numbers of wells must be drilled. For example, across the US fracking plays there are possibly one million active oil and gas wells operating. But the first major point here is that the UK can safely delay production from the shale deposits until gas prices increase and a worthwhile return is achieved. If the only rationale for speedy fracking to take place is that the EU might set future climate change targets that ban gas exploitation then, as a country fully onside with respect to stopping global warming, would that be such a bad thing? Would we not be taking a moral lead for once in the energy game? Fracking is the problem not the solution The second major point is that the UK North Sea oil and Gas industry is in its current dire plight precisely because the US over the past ten years chose to implement oil and gas production through fracking as its main energy policy. Directly and indirectly, fracking in the US has forced down the world price of oil and gas. In addition to

causing havoc to the economies of numerous countries including Nigeria and Russia, the US arguably has seriously damaged our biggest industry. Its solution appears to be that the UK should follow the US example and we should all become Olympic class frackers. Judging from the background of some of the successful bidders to the UK's 14th annual licensing round, when we say 'all' we really mean everyone in the UK can have a go at fracking. But that issue can and should be discussed at another time. The point here is that if we go wholesale down the fracking route this will again drive down the price of gas, and probably oil, and further hasten the demise of the North Sea industry. The jobs created through fracking will be eclipsed by a huge factor in the jobs lost in exploiting the UKCS reserves of oil and gas. Is this a case of Westminster promoting fracking jobs in England at the expense of North Sea jobs in Scotland? Surely the arguments and British sentiment are that fracking should be postponed and the focus should be on saving the maximum number of North Sea jobs. The UK can reconsider fracking at a more appropriate point in the future. Fracking saves the environment?? The final argument put forward for commencing on-land fracking now is that it is better for the environment than importing liquefied natural gas from, say, Russia. This myopic one-eyed jack view of the benefits of fracking surely gives the lie to the game. There will be vested interests pulling the levers of decision makers at Westminster, 'twas ever thus. Again the topic is too large to discuss meaningfully in this article. But for the millions of countryside dwellers who will be inconvenienced by the army of fracking lorries that will create noise and pollution and the constant fear of water course and methane air contamination the 'better for the environment argument' is pathetically nonsensical. In addition Co2 emissions from fracking are 45 times greater than those from on-land wind power generation. For observers in Scotland the only logical conclusion to be drawn is that the Westminster fracking policy really has the potential to frack apart the UK!

View more quality content from Robert Gordon University - Energy Centre

What to do when business dries up at home A thought on tailoring from the world of E&P training By Mark Bentley, Director at TRACS Training, AGR ABERDEEN: Low oil prices, shrinking margins (or no margin at all), loss of jobs and perhaps the decline of the industry as a whole – the topic has been hanging around us like a dark cloud for over a year now. One of the most persistent discussions has been whether this is just ‘the cycle’ or whether there is something structurally different about this down-turn for the North Sea – most people conclude it is a little different this time around. Which begs the question – what is the future for the thousands of us working in the North Sea? In the service sector most businesses follow the instinctive desire to hang in, hope for the local upturn and look further afield for work yet keep our companies based in the North East but is this workable in the long term? We suggest yes, but not as we know it today, and offer training as an example. The notion of working globally from North East Scotland is certainly less fanciful than it would have been one or two decades ago. What is fanciful is the notion that Aberdeen can simply export Aberdeen to an eagerly waiting world that just wishes to be, well, more like Aberdeen. The idea of ‘internationalising’ is a simple and obvious one – the tougher question is how to do it well when there are plenty of emerging providers in other regions?

The key would seem to be to avoid simply exporting the North Sea expertise but instead package the same skills in a more tailored way and/or offer unique bespoke products which others simply don’t, or can’t do so well. In our world of training this is readily apparent. AGR’s TRACS Training brand has always worked globally, and the brand distinction is the delivery of tailored courses, rather than off-the-shelf products. These take more time and effort to build and maintain than standard commodity products but they are internationally portable and no one comments on where we’re based. An extreme example of non-tailoring would be a training organisation known to us who designed a course based around the North Sea environment and exported it wholesale to the Middle East. The fact that the case study material embedded in the course was based on offshore projects didn’t seem to phase the course designers – driven by a belief in consistency, the lack of relevance of offshore technology for desert countries was comfortably overlooked. The tailored alternative of course is to drop the marine aspects. The more subtle but necessary effort is the complete deconstruction of the course to pick out the generic aspects relevant to the Middle East client group, add in the locally specific content which would not have been in the North Sea version of the course and rebuild the event around the interests of the new group. This all requires effort, and goes far beyond simply cutting out the ‘bits about the North Sea’, but that effort is necessary to transfer the skills and knowledge of the North Sea based experts to a new domain. This approach is applicable generically. It is our belief that exporting skills and experience from anywhere requires this type of approach, yet not all companies are doing it. It is easier to simply try to export the standard products and activities, and see if that works.

The question for each of us in our respective businesses is therefore to open up the anatomy of our skills and products – literally take them apart and consider what is special or useful about each piece. Some things we have done and learned really probably were for the North Sea only; other things are not and therein lies the value. Rather than simply package up the same products and offer them optimistically to ‘interested others’ elsewhere, we are required to critically think through and isolate the components which carry value internationally. The result may be surprising. It may be just part of an existing product but could equally not be a product at all but rather the thoughts of the people who had the flair to the build the product in the first place. For sure, it is likely to be different, and ‘different’ can still be based in the North East. About the author: Mark Bentley has more than 25 years' experience in the oil and gas industry. He began his professional career with Shell working in London, Aberdeen, Oman and The Hague prior to joining AGR TRACS back in 1998. Mark is a geoscientist by training and has spent most of his career working in petroleum engineering teams on producing assets. AGR's Training division has provided customised learning programmes to more than 25,000 oil and gas professionals in 45 countries.

View more quality content from AGR

Five Misunderstandings About Oil And Maybe A Sixth One Written by John Richardson from ICIS THE first misunderstanding about oil prices, which everyone now accepts was wrong, arose because people took too much notice of existing cost-per-barrel economics and so assumed that from October of last year, the US would close down huge amounts of shale-oil capacity. This didn't happen because a.) Costs were lower than anticipated because of improvements in shale technologies and b.) Because of human nature. The next theory to gain credence late last year, which was very rapidly dismissed, was that Saudi Arabia would cut production in order to drive prices back up to $100 a barrel. Then we had a third misplaced type of thinking: That the early February to end-June 2015 recovery in pricing was about real supply and demand fundamentals. What it was instead about was financial players anticipating a tightening in physical supplies that still hasn't happened. A fourth current idea, which I think is also wrong, is this: Saudi Arabia simply has to cut back production fairly soon in order to balance its budget. But as The Economist first pointed out last year, and repeated again last week, Saudi Arabia has lots of financial leeway to keep on pumping crude at high volumes for a lot longer yet. In its latest edition, The Economist wrote the following about Saudi Arabia and other Gulf States: 'Saudi Arabia, along with the far-richer-per-head satellites of Kuwait, the UAE and Qatar, can keep this up for some time. With the world's lowest debt-to-GDP ratio last year (an enviable 1.6%), it has

enormous room to borrow. It also has room to save. Simple measures such as imposing sales and property taxes, or raising absurdly low local energy prices, could quickly help fund budget shortfalls.' The question then is obviously 'Will Saudi Arabia and the rest of the rich Gulf states maintain today's very high levels of production? I think the answer is a definitive yes because Saudi Arabia and these other rich Gulf states want to make sure that they are not forced to leave oil, their most valuable asset, permanently in the ground because of losing market share to other energy sources - including renewables. The Economist article I've already linked to above is also helpful on this point: 'Based on experience from the 1970s and 1980s, oil producers learned then that when the cartel pushed prices too high, consumers rushed to find other sources of energy. As a result, it took OPEC nearly 20 years to regain the market share it eventually lost.'

And a fascinating interview in last week's Petroleum Intelligence Weekly, Rex Tillerson, chairman and CEO of ExxonMobil, made these other points about Saudi policy:

1. A few years ago, when prices soared to in the region of $140 a barrel, they invested billions of dollars in developing spare capacity of 2 million barrels a day. 2. Now they are wondering whether this was all a big mistake because of the fall in prices. 3. So they are just waiting for the market to reach the point where it becomes crystal clear that this question posed by Tillerson is answered: Where are the marginal barrels and how elastic are they?

This leads us on to a fifth theory on oil, which I don't think anybody now still thinks holds true. This was the notion that these marginal barrels of production would disappear when prices fell to around $60 a barrel. Tillerson never subscribed to this theory because as he said in the same interview: 'A lot of people thought it gets to $60 and everything would become obvious. I never held that view. I commented early on that I thought people would be pretty surprised at just how resilient this thing is, which is what I told the OPEC meeting when I spoke to them in June.' And, returning to how long Saudi Arabia and other countries will have to stick their current strategy, here is Tillerson again: 'I said [when he spoke to OPEC in June] you need to be ready for this to take a while. I think the fact that we have gone through several of these price convulsions this year, shouldn't be a surprise to anyone.' And there is potentially a sixth misunderstanding gaining currency at the moment, which is this: 'OK, we were wrong about $60 a barrel, but we think $45 a barrel is actually now the breakeven price for all these marginal barrels.' Not necessarily in the case of shale oil because as Tillerson points out in the same interview, unit costs of shale production will continue to fall - although he stresses that some fields are more efficient than others. So where does this leave us in forecasting oil prices over the next few years? First of all, let's summarise what we do know, which is this: 1. Saudi Arabia, and quite possibly the other rich Gulf states, are in this for the long haul - and will only reverse policy when they are certain they have regained market share. 2. We also know that nobody still knows what the final breakeven running costs of US shale oil will end up being. What we are equally unsure of it what are the minimum breakeven contributions to paying back capital. This still

depends on a.) The willingness of the financial sector to keep supplying the shale-oil sector with cheap money and b.) The extent of restructuring in the sector. Debts could be written off, thus reducing capital payments. 3. On the demand side of the equation, events in China tell us that global demand growth for oil can only weaken over the next few years.

What we don't know is how Western central banks will react from hereon in to global economic weakness. This is absolutely vital to both understand and constantly monitor as the banks are responsible for today's vast oversupply in crude and so Saudi Arabia's efforts to regain market share.

So here is a repeat of three extreme scenarios for the next few years, with many other potential pricing points in between:

1. No more major Western central bank stimulus and you are looking at prices returning to their long term average of around $30 a barrel.

2. More major Fed etc. stimulus and we could be back to $100 a barrel.

3. Or around $50 a barrel in a world of perhaps some stimulus, but still weak underlying demand.

View more quality content from ICIS

The Top 100 Canadian Oil & Gas Companies Written by Mark Young from CanOils CanOils is pleased to announce the release of its new report, Canada's Top 100 Oil & Gas Companies, which has been compiled using Q2 2015 Canadian oil & gas production results from all TSX and TSX-V listed Canadian oil and gas companies in the CanOils database. Canadian M&A Activity Has Huge Impact on Rankings The quarter saw many acquisitions take place that had major impacts on the Top 100 rankings. The most significant deal was the acquisition of Q1 2015's 4th biggest TSX company, Talisman Energy Inc., by Spain's Repsol. This meant that Talisman was no longer in the rankings and a very high number of companies (65 out of this quarter's 100) were sitting in a higher position in the Top 100 than in Q1. Similar impacts, albeit to a lesser extent, were made by Tourmaline Oil Corp.'s acquisition of Mapan Energy Ltd., Aspenleaf Energy Ltd.'s acquisition of Arcan Resources and, of course, by Crescent Point Energy Corp.'s acquisition of Legacy Oil + Gas Inc... There were many companies out of the 65 who climbed the rankings this quarter that would have climbed regardless of the above acquisitions removing significant companies from positions above them. Kelt Exploration Ltd.'s own M&A activity, for instance, saw the company climb 10 places in the rankings. The company announced the acquisition of Artek Exploration Ltd. in 2014 and this closed in April, and saw a 22% increase in Q2 2015 production compared to Q1 as a result. Freehold Royalties Ltd. also climbed the rankings after an acquisition of two royalty packages from Penn West Petroleum Ltd. in the Viking Light Oil region of Saskatchewan. Many companies also fell in the rankings due to asset sales, full details of which are available in the Top 100 Oil & Gas Companies report.

Maintenance, Turnaround Work and Disruptions Cause Many Companies to Fall Maintenance and production curtailments due to disruptions were the other major influencing factors on this quarter's rankings. Within the Top 20, Canadian Oil Sands Ltd. and MEG Energy Inc. both saw their oilsands outputs limited in Q2 following planned turnaround work at their respective Syncrude and Christina Lake projects. In MEG's case, the related drop in production was bigger than originally expected. Forest fires in Alberta meant that the planned turnaround at Christina Lake could not be completed on schedule. The company eventually posted Q2 production levels 11,000 barrels per day less than Q1. Maintenance periods and unreliability issues impacted many companies throughout the Top 100 ranking. Overall Statistics For the second quarter in a row, UK North Sea-focused Iona Energy Inc. was amongst the biggest climbers, whilst Mart Resources Inc. continued to experience issues with its production and midstream infrastructure in Nigeria, causing the company to again rank amongst the biggest fallers. Granite Oil Corp., the formation of which is extensively looked at in the report with the help of data from CanOils Assets, was the quarter's biggest faller. The company was formerly known as Deethree Exploration Ltd. and lost a significant portion of its production in May when the company was split into two. Boulder Energy Ltd. is the new company that was formed in this reorganisation. 5 Biggest Climbs in Top 100

5 Biggest Falls in Top 100

Iona Energy Inc. (TSX-V:INA) +16

Granite Oil Corp. (TSX:GXO) -13

WesternZagros Resources Ltd. (TSX-V:WZR) +16 Sterling Resources Ltd. (TSX-V:SLG) -8 Oryx Petroleum Corporation Ltd. (TSX:OCX) +15

Perpetual Energy Inc. (TSX:PMT) -7

Kicking Horse Energy Inc. (TSX-V:KCK) +11

Mart Resources Inc. (TSX:MMT) -6

Kelt Exploration Ltd. (TSX:KEL) +10

Terra Energy Corp. (TSX:TT) -5

Source: CanOils via Canada's Top 100 Oil & Gas Companies, June 2015 View more quality content from CanOils

General Electric: From Oil to Lithium Written by Jeff Nevil from Jeff Nevil Despite cutting over 250 jobs recently at its Lufkin oil unit in Texas, which is owed largely to the continued slump in global oil prices, other forms of energy still continue to be profitable for GE as the company announced it had signed its largest battery energy storage deal in the history of the company. The deal, in partnership with Coachella Energy Storage Partners, will see GE manufacturing custom 30-MW battery energy sources to be provided as part of CESP's ongoing supply contract with the Imperial Irrigation District.

GE's lithium batteries won the contract because they provide an all-in-one energy solution at the most competitive price, according to CESP's deal brokers. The deal includes an integrated approach to the provision of an energy storage solution, configured using mostly GE patented technology including MARK VI controllers, Brilliance MW inverters, Prolec transformers, and of course GE's lithium ion batteries, all housed in a custom built ion gauge enclosure.

The deal marks GE's third ion battery based energy storage project since entering the market two months ago. The corporation is now in direct competition with the California based Con Edison Development, and Convergent Energy and Power in Ontario, both of whom have been developing ion based energy projects for years. GE is hoping to take a share of the market by offering custom energy storage solutions at a much lower price-point.

The continued shift of GE's energy strategy, moving away from oil and into more environmentally friendly renewable resources, will be welcomed by green energy campaigners. In response, Anne McEntee, CEO of GE's renewable energy division reiterated that she'd been listening to the growing customer demand for better energy sources, and that part of the responsibility would lie in its client partnerships

and how well they themselves utilised the greener energy options on offer.

After announcing the deal, GE's stock prices rose slowly but surely, with a number of long-term financial analysts advising consumers to buy GE, including UBS analyst Shannon O'Callaghan and William Blair's Nicholas Heymann, both averaging at a target stock price of $31.

Compare this to its struggling oil division, which purchased Lufkin in 2013 for an estimated $3.3 billion. The move was intended to boost its presence in the oil market, which has since hit hard times and is still showing little signs of improvement. Despite the 250 cut jobs only accounting for a small percentage of its 44,000 total, this represents a financial cut of over $600 million, or 1/6 of its initial purchase price. This brings the total job cuts from Lufkin at 800.

'Increasingly challenging market conditions' have been cited as the primary reason for the job cuts by GE. Oil prices currently sit at a six-and-a-half year low, priced at roughly $42 per barrel, which is over 50% less than last years' price of $103 per barrel. To make matters worse, the continued search for viable oil is thought to be becoming far more difficult, contributing to regional instabilities in conflict areas such as Iraq, as well as economic woes in oil rich nations such as Nigeria and Venezuela.

Whilst this drop has put pressure on GE's underperforming oil division, there is hope that the CESP deal with instigate further alternative energy developments. The move away from oil should not only improve the revenues of GE, but also the consumer choice for truly renewable and safer energy resources.

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ANGOLA: After various set-backs in deep-water Kwanza exploration, attention turns to onshore, with emphasis on local industry participation Written by Andrew Hayman from Drillinginfo Angola saw a break-neck rush in deep-water oil and gas exploration through the decade 2002 - 2012, and the ever-increasing cost of upstream operations was counterbalanced by an optimism that massive oil fields were there to be found in deep waters of >1500m. After all, the Kwanza Basin is the conjugate margin to the Santos and Campos Basins offshore Brazil, where Tupi, Marlim, Jubarte and other giant fields have been discovered. In the Kwanza deep water pre-salt licensing awards in 2011 the global IOCs poured in, undaunted by multiple well obligations and signature bonuses. Total, Eni, BP, Statoil, Repsol, ConocoPhillips, and Cobalt piled in. Interestingly, ExxonMobil declined.

A Reality Check 2014-2015 has seen a severe reality check in Luanda. Many of the deep/water wildcats in the Kwanza (drilled at $500-600,000 / rig day), targeting the pre-salt section, have failed to produce tangible results. These include Statoil - Dilolo 1, and JacarĂŠ 1; ConocoPhillips - Kamoxi 1, and most recently Vali 1 ).

Oil discoveries (Repsol - Locosso 1ST) are minor. One well (ConocoPhillips - Omosi 1) was declared a gas discovery, but it is unlikely that deep-water gas will be of commercial interest. The notable exceptions are Cobalt's oil successes in Block 20 & 21 (Cameia 1, Orca 1, Lontra 1). In operational terms, Statoil pulled the last of its well commitments and paid off the drilling ship for US$350 million; ConocoPhillips has deferred the final, fourth well in its programme for a year or so. So, in concert with the global upstream revision, the whole Angolan industry has been obliged to rethink its strategy and objectives. A recent article in 'Expresso' in Portugal, based on internal Sonangol analyses, was highly critical of the state oil company, suggesting it was malfunctioning and on the verge of financial collapse; this sowed panic in government circles and brought about a full Board press conference (July 2015). Chairman Francisco de Lemos JosĂŠ Maria, and his colleagues issued a detailed denial. But, all is not well. Sonangol, as the engine of Angolan industrial development, is misfiring. Tempered in the fires of the Independence Struggles Angola has a proud history dating back to its throwing off the colonial yoke. Its people suffered decades, and the character has been tempered in the fire of the independence struggle followed by the civil war. The Portuguese left Angola (and Mozambique) in 1974 after the Carnation Revolution in Lisbon; but the colonists smashed up what infrastructure there was in Luanda (electricity, telephones, office equipment). Civil war broke out between the rival MPLA and UNITA movements which lasted decades. UNITA was overtly supported by the military in South Africa and Rhodesia in a proxy war between the superpowers. The major turning point in the struggle came at the pitched battle of Cuito Cuanavale, 1987-88. The MPLA's army (FALPA) was on the verge of defeat by the South African Defence Force and UNITA, it was reinforced by 15,000 Cuban troops, T-55 tanks and field guns sent in extremis by Fidel Castro. FALPA subsequently stopped the SADF advance and claimed victory, albeit with heavy casualties. This was the last major battle on African soil. While visiting Cuba in 1991,Nelson Mandela claimed that the battle of Cuito Cuanavale 'marked an important step in the struggle to free the continent.'

The final victory of the MPLA (still in power now) only came with the death of Jonas Savimbi in the bush in 2002. Savimbi, a freedom symbol for many in the West against the 'Marxists', had vowed never to accept MPLA's hegemony. (This writer remembers a conversation in 1988 in Luanda with a senior Sonangol geologist, who avowed with remarkable prescience that the Civil War would only end 'when we kill Savimbi'; this took another 14 years.) After such a history, it is perhaps not surprising that the ruling MPLA is disinclined to share power. Pragmatic Business Links In the 21st Century, business and industry links with Portugal still continue. Many Portuguese have flocked back into Angola, given the poor economic state of their own country. President dos Santos cited 200,000 in 2013; this is probably an underestimate. The Lusophone connection between Portugal, Brazil, Mozambique and Brazil remains strong. Culturally and aspirationally, Angolans look across the South Atlantic to Brazil as their model, and Cubans remain bosom buddies. So it's not surprising that Angolanisation of industry is a major requirement for foreign oil operators. This is not a bar against IOC involvement, as long as the rules of the game are understood. The quality and training of the workforce are improving all the time, and it is spreading outwards from the oil patch into other areas (real estate, commerce). In Sub Saharan Africa there often is a counterpoint between Angola and Nigeria as the big daddies (1.75 MMbo/d plays 2.2 MMbo/d); but, with the severe problems in Nigeria (not least the Petroleum Industries Bill, and the endemic operational problems in the Delta), there's no doubt where big oil would prefer to operate. Stability is the key. A major change brought about by the US revolution in shale oil and shale gas is that oil from these two giant exporters no longer goes predominantly to the U.S. as before; both countries now export oil to Asia. The EIA states that 65% of Angolan oil goes to Asia (of which 49% to China). Angola's pragmatic links with China have been researched and described by Alex

Vine, Valerie Marcel and others at Chatham House. But that's not to say that Western links are not valued: Chevron (and, formerly Gulf) operated throughout the Civil War, pumping over 300,000 bo/d, sales of which enabled the government to succeed in the armed struggle. Angola does not disregard the US oil industry. A Switch of focus to Onshore After the deep water Kwanza licensing round, the next offering was 12 blocks in the onshore Kwanza, launched in 2012. This bid round has two main intentions: the first is to resurrect production from the onshore, in the area where national production first started in 1956 (Benfica field). The Kwanza onshore is close to the market; the Cacuaco field is just 20 km north of Luanda and is where Conoco's office used to be located. The Petrangol refinery, on the north side of Luanda, built by Petrofina in the late 1950s, was fed from these fields. There are some 20 shut-in fields which produced from the pre-salt and, with modern 3D seismic and integrated geothermal modelling, there should be a lot more oil to be found. However field sizes are modest (5 to 20 MMbo initially recoverable) and this is not going to be a bonanza for big oil. The second intention of government is to grow the local industry. Pre-qualified nonoperators (48) and operators (37) have been listed. This comes after months of delay which is thought due to lobbying for inclusion. For the 48 non-operators, the government's intention to draw in and promote new Angolan companies is prevalent, and there is no record of many of these and may be presumed to have been created for this specific purpose. One known company is Obrangol, a geological contractor which worked on the regional geological evaluation of the Kwanza as sub-contractor to Sonangol. A number of IOCs have elected to participate in the round in a restricted way, as non-operators: these include Maersk, Mitsubishi and Petrobras. Each of these has a recent or current participation in Angola but has decided not to expand its involvement. SOCO is absent despite its experience onshore Cabinda (the company SOCOCO has no connection to SOCO International). The criteria for operatorship are stated as follows: 'Any operator of an oil concession a) Must have competence and experience in the management and performance of petroleum operations; b) Must have technical and operational competence; c) Must

have an efficient organizational structure. In support of its application, the operator may also submit other relevant documents relating to its experience in the performance of petroleum operations, namely in the areas of safety, environmental protection and the employment, integration and training of Angolan staff.' Clearly the IOCs (Chevron, Dragon Oil, Eni etc) meet the requirements but there are noteworthy inclusions. A new player seeking entry to Angola is Umbono Capital, an investment group with interests in mining and oil and gas. Some well-established Angolan oil services contractors want to move in to operatorship; these include AIS Integrated, Interserviรงos, Luluoil, and Simples Oil Ldta. A number of Angolan companies already have equity and hence experience in the oil sector including Sonangol Sinopec International (HQ in Hong Kong), ACREP and Somoil. New Angolan companies without an obvious track record include Multiply Oil (established in 2014 by exSonangol petroleum economist Marco Victor) and Socoinfa (civil construction centre). But for half-a-dozen Angolan companies there is simply no public record available. The Ministry of Petroleum has promised a two-year cycle for successive bid rounds, but has been completely unable to meet its own declared timetable. But the next licensing round (probably in 2016, after the awards) is firm and will include the Namibe deep water and the 'North West Ultra Deep' of the Congo Basin. In both these areas multi-client seismic is available. Offshore Developments with oil at $60 Sonangol's proclaimed strategy is to push oil production to 2 MMbo/d by 2020 through bringing new fields on stream (Polo Oeste - Block 15, Kaombo - Block 32, Mafumeira Sul - Block 14) to compensate for decline in existing fields (eg Total's Girassol fields - Block 17). This milestone will be hard to achieve in the time-frame. Operators will hang fire on new projects, and where final investment decisions (FIDs) have not been taken, we are likely to see a 3-5 year moratorium. An exception to this will be the Cameia development by leased FPSO in Block 21. End August, a major surprise saw operator Cobalt International sell up all its Angolan acreage which will revert to Sonangol. Will partner BP take over the deep water field development ? Where deep water facilities have been installed, step-out projects close to existing

infrastructure will continue. One such is the East Pole (Polo Este) in Block 15. One project which may not now see execution is Maersk's Chissonga-Caporolo development (Block 16) where it appears that oil reserves are insufficient for commerciality. Sonangol as operator is also pursuing gas exploration in shallow water areas (Block 2 and Block 3); this may feed an Angola LNG Phase 2 project, although so far there is no indication of sufficient gas volumes for export, commercialisation mentioned in Sonangol's forward strategy is through development of an industrial park at Soyo with fertiliser plant, urea, etc. Downstream In the downstream arena, a chronic lack of refining capacity has meant importation of petroleum products continues. The Petrangol refinery will be augmented; construction work on the new Soyo refinery was officially inaugurated by Francisco de Lemos President of the Board of Directors of Sonangol, jointly with You Hai Ming President of the China International Fund, which is financing the project. The refinery has been under planning for over five years. Capacity will be 120,000 bo/d and it will be compliant to Euro IV emission standard. The current refining capacity in Angola is provided solely by the aged Petrangol, near Luanda (nameplate capacity 37,500 bo/d). A third refinery at Lobito in Benguela province (200,000 bo/d) is being financed by the China Development Bank in a 2014 agreement; overall budget is US$ 8 billion. The construction should start this year. It will process acidic crudes from Girassol. Conclusion Angola has had a reality check with the collapse of oil prices, forcing a re-think on ever-increasing project costs. The Sonangol mantra for 2015 is 'rediscovering efficiency' but this might not be the only improvement that has to be made. The state budget for 2015 was revised in January to $81 oil and has been revised downwards again to $40 oil, and $14 billion was cut from state spending, notably in infrastructure development. But projections of GDP growth are still a very healthy +4-5% for 20152019. The goal of industry diversification from the oil and diamonds (which together make up over 90% of government revenues) has not yet happened. Yet the potential

is there for agriculture. The major contractors (Schlumberger, Halliburton and others) have been forced to re-bid downwards for oil services. Companies are hurting as their operating cost base has scarcely changed. Given the ever-attractive oil geology, what then are the best methods to bring in IOCs and maintain their interest? The Angolan government is authoritarian and brooks no dissent; but it provides a stable framework for inward investment. Given the turmoil and revolution in so many African oil producing countries (Libya, Egypt, and episodes in Algeria) it is easy to conclude that big oil can live with regimes which can maintain law and order.

Angola's stratigraphy and prolific pre- and post-salt source rocks have so far, outweighed the super-demanding PSC contractual terms that have been demanded by the Ministry of Petroleum (MINPET) ever since the early deep-water successes. The oil barons of Luanda have always been convinced that the world industry will come to them - and, until, now they have been quite right. But we note that in the current round there are not really many big IOCs pre-qualified. A lightening of PSC terms and a real financial encouragement for IOCs will sustain involvement in the long term. References for Further Reading ď&#x201A;ˇ

For a more complete history of E&P in Angola see articles by long-term Luanda resident and geologist, Tako Koning (GeoExpro, etc)

ď&#x201A;ˇ

For articles on Angola's complex relations with China please see Marcus Power & Ana Cristina Alves China & Angola: A Marriage of Convenience? and also books and articles by Alex Vine and co-authors (Chatham House)

ď&#x201A;ˇ

For articles on Angolan politics see for example work by Dr Jon Schubert (University of Leipzig).

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How does the Market Value Undeveloped North Sea Reserves Written by Stephen A. Brown from The Steam Oil Production Company Ltd This is a question close to my heart as in The Steam Oil Production Company we have a good few barrels of undeveloped reserves, so I do pay attention to how the AIM market seems to value undeveloped barrels in the ground, especially those in the UK & Ireland. I also pay attention to the industry transaction values for those same kind of barrels, but recently there haven't been too many transactions to follow, not where anyone is paying cash upfront at least. It is a far cry from the heady days of 2011 when Premier and Taqa carved up Encore for values per barrel that lay in the high teens. Then in 2012, Cairn bought Nautical for about $5/bbl and sold a part of the Catcher field to Dyas for about $10/bbl. The oil price collapse has a lot to do with the lack of activity as while companies are busy cancelling development projects on fields they already own, the appetite just isn't there to buy assets which will only be put in the cupboard to await sunnier days. Although that would be a good contrarian strategy the buyers all think 'what's to be lost by waiting, sure the price might get even lower.' So we won't get many clues as to the market value of undeveloped oilfields from the industry. But for those companies that are listed, the stock exchange values their assets every minute of every day, so we can look to that market to derive a valuation. Here are the companies I follow, they are Providence and Lansdowne who are partners in the Barryroe discovery offshore Cork, Independent Oil & Gas whose main project is the Skipper heavy oil field, Hurricane with its Lancaster & Whirlwind discoveries, Xcite with Bentley and Parkmead whose main undeveloped reserves lie in the Perth, Dolphin & Lowlander fields. I have tried to be consistent in the way I calculate the market value of the assets and the barrels in the ground. But all the companies are different and it is sometimes

tricky to be confident that you have captured all the ins and outs of the balance sheet, so I recommend you do your own calculations if you want something you can rely upon. To calculate the enterprise value I take the market capitalisation as posted on the London Stock Exchange website, and to that I add the net debt. I calculate net debt by taking the long term debt adding to it the current liabilities and my estimate of how much money has been spent since the last financial report, finally from that I subtract the current assets. If that turns out negative then that the company has net cash. Only two of the companies are in the fortunate position of having net cash, all the rest have debts or other liabilities on their books. Xcite has a very ominous looking bond liability looming in June 2016, clearing that will be an essential part of any refinancing package to take the Bentley project forward.

Green dots are Enterprise Value divided by 2P + 2C resources, bars to the right of the centre line represent the Enterprise Value split into value of shares and the value of the net debt position, net cash is represented by the bars to the left of the centre line. When all is said and done the values per barrel lie in a range from 18Â˘ to 83Â˘, well down on the valuations of eighteen months ago, which reflects concerns that right now some of the projects might not attract finance or worse still just wouldn't make a profit. However undeveloped barrels do have an option value that persists even if the development project might not quite work at today's oil price. The one thing that is for

sure about the oil price is that it will be different tomorrow and tomorrow that project might work really well, so it is rare that an undeveloped field will actually have no value. That isn't to say that the share price of some of these companies isn't at risk of going to zero, that could happen to any of the companies with net debt rather than net cash on their balance sheet.

Nevertheless, I think it is probably the case that a number of potential development projects are now only being valued as options to develop the field at some point in the future rather than at a discount to the calculated net present value of the development projects. My conclusion from looking at these values is that the option value of a barrel of undeveloped reserves is somewhere between 15¢ and 20¢. As a comparison, in one of the few recent transactions MOL paid 15¢/bbl for 600 mmbbls of unrisked prospective resources in Norway. That's 15¢/bbl for something that hasn't actually been found, in fact MOL would be delighted if they eventually found a half or a third of those 600 mmbbls, and which will be taxed at 78%. Of course MOL will only have to spend 22% of the cost of the wells to find these barrels but that deal reflects the fact that oil companies will pay for the possibility of finding oil.

However, if the market thinks (or hopes) that the project might actually go ahead the value stands a chance of heading towards $1/bbl; and I would expect that if any of these projects were funded and the field development plan blessed by OGA then the market value per barrel would be even higher than that, say between $2/bbl and $5/bbl. Unfortunately none of the companies that I follow are as yet in that position.

So today you can buy hundreds of millions of barrels of reserves for quite a lot less than a dollar per barrel. That is an awful lot less than the average finding cost for reserves pretty much anywhere in the world; and in the North Sea exploration costs came out at about $8/bbl for the period from 2005 to 2013. It really is cheaper drilling for oil on the AIM market than in the treacherous waters of the North Sea.

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More Gloom on the Horizon for Bakken Companies in Q3 2015 Written by Mark Young from Evaluate Energy As commodity prices fell at the end of 2014 and in early 2015, companies that participate in the Bakken shale in North Dakota and Montana were hit the hardest amongst U.S. unconventional operators. The WTI oil benchmark price dropped to below $50 in the first quarter of 2015 and the Bakken companies suffered the biggest drops in netbacks on average than any other major play or producing area. A brief respite was experienced as WTI prices rebounded to an average closer to $60 in Q2, but as of August 25, 2015, the Q3 average WTI price had fallen again, sitting below even the Q1 average. Using Evaluate Energy data from the past 12 months, we can see that Q3 netbacks for Bakken operators should therefore be low again, despite widespread improvements in operational costs per barrel of oil produced. Average WTI Prices per Quarter

Bakken Netbacks Tumble in Q1 2015 In a study of 80 U.S. based companies' pre-hedging operating netbacks (see note 1) for the periods Q3 2014 and Q1 2015, the data shows that the companies in the Bakken suffered the most with the fall in commodity prices. Twelve of the 80 companies have at least a significant portion of their upstream operations located in the Bakken area - Abraxas Petroleum Corp. (AXAS), Continental Resources Inc. (CLR), Emerald Oil Inc. (EOX), Halc贸n Resources Corp. (HK), Hess Corp. (HES), Linn Energy LLC (LINE), MDU Resources Group Inc. (MDU), Northern Oil & Gas Inc. (NOG), Oasis Petroleum Inc. (OAS), QEP Resources Inc. (QEP), Triangle Petroleum Corp. (TPLM) and Whiting Petroleum Corp. (WLL).

These companies' percentage drops in operating netback between Q3 2014 and Q1 2015 has been plotted on the following chart with the percentage drop experienced by every other company in the group of 80, which includes international and multinational operators, Eagle Ford operators, Marcellus operators and Permian Basin operators (see note 2).

Source: Evaluate Energy

Every one of the 80 companies saw its operating netback fall between Q3 2014 and Q1 2015, but on average it is the companies in the Bakken that saw the biggest fall. This was probably to be expected due to the focus on oil production in the Bakken versus output of gas (Marcellus) or gas liquids (Eagle Ford) in some of the other play areas. A dramatic drop in oil price was always going to impact Bakken operators to a greater extent than some of their peers. However, the effect of the falling prices on Bakken operators does still stand out.

Some Respite in Q2 As WTI rebounded somewhat towards an average of almost $60 in the second quarter of 2015, the Bakken companies saw their netbacks rebound in turn.

Source: Evaluate Energy - MDU and TPLM are not included (see note 3).

Whilst Q2 must have been encouraging for the companies in question, there is a definite pattern here and this will be concerning heading into Q3. Of course, in terms of the actual prices and netbacks achieved, some companies have done better than others, but wide swings in oil prices seem to have affected the Bakken companies' netbacks as one, not as individual entities, over the past 12 months. So it is reasonable to assume that Q3's decline in WTI to another quarterly average of under $50 is likely to continue this pattern and significantly impact all Bakken-focused companies in a negative manner. Costs Being Brought Under Control On the whole, however, it looks as if the Bakken companies are in a better place to deal with falling prices in Q3 than they were in Q1. The Bakken company netbacks are looking like they will not fall to Q1 levels if the WTI price for the whole of Q3 ends up averaging at the same price as Q1 ($48.57). This is due to operating expenses per barrel being lower - on average - across the group in Q2 2015 than the previous three quarters, particularly Q1.

Source: Evaluate Energy - MDU and TPLM are not included again

Only Abraxas (due to lower production) and Emerald Oil (due to issues with maintenance, water disposal and regulatory expense increases) saw an increase in their operating expenses per barrel, whilst the other Bakken companies all reduced their expenses per barrel compared with Q1. So whilst Q3 is looking like another gloomy period for company netbacks in the Bakken with a resumption in lower commodity prices, it is likely not to be as bad as Q1 - but only if each company can continue to keep its operating expenses under control as we have seen in Q2. All data here is taken from the Evaluate Energy database, which provides Evaluate Energy subscribers with over 25 years' coverage of the world's biggest and most significant oil and gas companies. Evaluate Energy also has a mergers & acquisitions database, covering all E&P asset, corporate and farm-in deals back to 2008, as well as refinery, LNG, midstream and oil service sector deals. For more on Evaluate Energy and its products, please download our brochure. Notes: 1. Pre-hedging operating netback is calculated by taking each company's E&P revenue, E&P operating costs and transportation expenses and bringing them to a per boe produced level. This calculation excludes any realised hedging gains. 2. The group of 80 companies included in the Q3 2014 - Q1 2015 report is available in the supplemental data booklet to this article - click here to download 3. MDU has started to treats its upstream segment as discontinued operations as it attempts to sell its E&P subsidiary Fidelity Exploration & Production, whilst TPLM has not yet reported (as of time of writing) its results for the second quarter because the company's year end is January, rather than December; the company's Q2 results are due in the second week of September.

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