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Edition Twenty Seven – June 2014

Stirring the pot: the North American energy revolution Offshore regulators talk tough but are oil companies listening? The great imaginary California oil boom: Over before it started Cover image by magnera


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Adam Marmaras Chief Executive Officer Issue 27 – June 2014 OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 208 123 2237 Email: press@oilvoice.com Skype: oilvoicetalk Editor James Allen Email: james@oilvoice.com

Welcome to the 27th edition of the OilVoice Magazine. We introduced our new look 2014 Media Pack at the beginning of the month, updated with current pricing and advertising opportunities. Our cost-effective advertising opportunities place your company in front of 170,000 unique visitors and 700,000 page views per month.

Director of Sales Mark Phillips Email: sales@oilvoice.com

This month we have great articles from Eka, FTI Consulting and Mars Omega LLP. We'd also like to welcome back some of our regular authors, including Gail Tverberg, and Kurt Cobb.

Chief Executive Officer Adam Marmaras Email: adam@oilvoice.com

If you're interested to know more about seeing your articles featured on OilVoice, please get in touch.

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Cover image by magnera

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Adam Marmaras CEO OilVoice


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Contents Featured Authors This month’s featured authors

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Russia and the Ukraine - The worrisome connection to world oil and gas problems by Gail Tverberg

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Stirring the pot: the North American energy revolution by Andy Bout

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The great imaginary California oil boom: Over before it started by Kurt Cobb

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Oil & gas boom 2014: No end in sight by David Blackmon

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Could NAFTA force the Keystone XL pipeline on the United States? by Kurt Cobb

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Offshore regulators talk tough but are oil companies listening? by Loren Steffy

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How much water is used in the Alberta oil sands? by Mark Young

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Iraq and Kurdistan: Oil becomes a source of friction by Anthony Franks OBE

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Featured Authors Gail Tverberg Our Finite World Gail the Actuary’s real name is Gail Tverberg. She has an M. S. from the University of Illinois, Chicago in Mathematics, and is a Fellow of the Casualty Actuarial Society and a Member of the American Academy of Actuaries.

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

Kurt Cobb Resource Insights Kurt Cobb is an author, speaker, and columnist focusing on energy and the environment. He is a regular contributor to the Energy Voices section of The Christian Science Monitor and author of the peak-oil-themed novel Prelude.

Anthony Franks OBE Mars Omega LLP Anthony is responsible for managing and controlling the extensive information networks, as well as directing and working with the analysis team to create reports for clients, and also works with Hamish in the Liaison and Mediation service.

David Blackmon FTI Consulting, Inc. David Blackmon is managing director of Strategic Communications for FTI Consulting, based in Houston.


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Loren Steffy 30 Point Strategies A senior writer for 30 Point Strategies and a writer-at-large for Texas Monthly. Loren worked in daily journalism for 26 years, most recently as an awardwinning business columnist for the Houston Chronicle, and before that, as a senior writer at Bloomberg News.

Andy Bout Eka Andy is based out of Calgary and is responsible for the energy markets served by EKA. He is the founder of EnCompass Technologies and has over 25 years of experience in the commodities market, specifically in the energy trading and risk management areas.


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Russia and the Ukraine - The worrisome connection to world oil and gas problems Written by Gail Tverberg from Our Finite World What is behind the Russia/Ukraine problem? It seems to me that what we are seeing is Russia’s attempt to fix a two-part problem: 1. Some oil and gas exporters, including Russia, are not receiving enough oil and gas revenue to meet their needs. They are not able to collect enough taxes to provide the services they have promised to their citizens, plus allow the amount of reinvestment that is needed to maintain production. Russia is starting to experience economic contraction because of the low revenue situation. This situation very closely related similar problems I have written about previously. In one post I talked about major independent oil companies not producing enough profit to provide the revenue needed for reinvestment, and because of this, cutting back on new investment. In another, I talked about the problem of too low US natural gas sales prices, relative to the cost of extraction. 2. Some oil and gas importers, including the Ukraine, are not using their imported oil and gas in productive enough ways that they are able to afford to pay the market price for oil and gas. Russia gave the Ukraine a lower natural gas price because some of Russia’s pipelines cross the Ukraine, and the Ukraine must maintain the pipeline. But even with this lower natural gas price, the Ukraine is behind on its payments to Russia. If a person thinks about the situation, it looks a lot like a situation where the world is reaching limits on oil and gas production. The marginal producers (including Russia) are being pushed out, at the same time that the marginal consumers (including the Ukraine) are being pushed out. Russia is trying to fix this situation, as best it can. One part of its approach is to make certain that the Ukraine will in fact pay at least the European market price for natural gas. To do this, Russia will make the Ukraine prepay for its natural gas; otherwise it will cut off its gas supply. Russia is also looking for new customers who can afford to pay higher prices for natural gas. In particular, Russia is working on a contract to sell LNG to China, quite possibly reducing the amount of natural gas it has available to sell to Europe. Russia is also signing a $10 billion contract with Iran in which it promises to construct new hydroelectric and thermal energy plants in Iran, in return for oil exports from Iran. This contract will increase the amount of oil Russia has to


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sell, and will increase the oil available on the world market. Russia’s plan will do an end run around US and European sanctions. Gradually, or perhaps not so gradually, Russia’s exports are being redirected to those who can afford to pay higher prices. European Union purchases of natural gas imports have declined since 2008, presumably because they are having difficulty affording the current price of gas, so they are being relied on less for future sales. The Russian approach seems to include building a new axis of power, including Russia, China, Iran and perhaps other countries. This new axis of power may threaten the US dollar’s reserve currency status. With the dollar as reserve currency, the US has been able to buy far more goods from other countries than it sells to others. Putting an end to the US dollar as reserve currency would leave more and oil and gas for other countries. If purchases by the US are cut back, it will leave more oil and gas for other countries. The danger is that prices will drop too low because of the drop in US demand, leading to lower production. It this should happen, everyone might lose out. I am doubtful that Russia’s approach to fixing its problems will work. But if Russia is “between a rock and a hard place,” I can understand its willingness to try something very different. It now has more power than it has had in the past because of its oil and gas exports, and is willing to use that power. The US/European approach to this problem is to loan the Ukraine $17 billion to pay for past natural gas bills. The hope is that with this loan, the Ukraine will be able to make changes that will allow it to afford future natural gas bills. There is also the hope that the United States can step in with large natural gas exports to Europe and the Ukraine. In addition, the US and Europe are trying to impose sanctions on Russia. I find it very difficult to believe that the US/European approach will work. The idea that the United States can start exporting huge amounts of natural gas to Europe in the near future borders on the bizarre. There are many hurdles that would need to be overcome for this to happen. Installing LNG export facilities is among the least of these hurdles. In fact, the West badly needs both the oil and gas that Russia is producing, so it really is in a very precarious position. If Russia cuts off exports, or if Russia is forced to cut off exports because of financial difficulties, both the US and Europe will suffer. It is clear that Europe will suffer because of its dependence on pipeline exports of oil and gas from Russia. But the US will suffer as well, because the US is tied closely to Europe by financial ties, and by import and export arrangements with Europe. Furthermore, the US/European approach involves a great deal of new debt, in an attempt to fix an inherent inability of the Ukrainian economy to afford high energy prices. Without a huge transformation, the Ukraine will be in even more financial difficulty when it comes time to pay back the new debt–it will need make debt payments at the same time that it needs to pay for more expensive future natural gas. More debt doesn’t necessarily fix the situation; it may make it worse.


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The US powers that be do not understand what Russia (and the world) is up against, so the policies they propose are likely to make the situation worse, rather than better. Background We live in a world in which some countries use far more energy products than others. One question that the new proposed axis of power raises is whether this disproportionate share of energy use should be allowed to continue to exist.

Figure 1. Per Capita Energy Consumption, based on BP 2013 Statistical Review of World Energy data and EIA population data. The United States, Europe and Japan got to the position of using a disproportionate share of energy resources by way of being first with industrialization. This early industrialization set up a pattern of using energy for “frivolous” things–large, heated homes; private passenger automobiles for individual citizens; businesses that were not necessarily as energy-efficient as they might be. In the early days, imports were limited and cheap. As local supplies became depleted, imports rose. The cost of imported oil and imported gas (except for natural gas in the US) rose as well, making the imported fuel harder to afford. Now the early users–that is, the US, EU, and Japan, are the ones struggling to keep up past consumption levels. In some ways, the Ukraine is not too different from the EU is this respect. The Ukraine also got to the position of using an above average share of energy resources, by being early in its industrialization, during the era of the Soviet Union. The Ukraine, prior to the collapse of the Soviet Union, was using as much as energy on a per-capita basis as the US-Europe-Japan group (Figure 2), because of its heavy industry.


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Figure 2. Figure similar to Figure 1, but including Ukraine’s per capita energy consumption as well. Once the Soviet Union collapsed, the Ukraine had huge difficulties: Exports of oil and gas from Russia (upon which the Ukraine’s industry depended) collapsed. The Ukraine’s industry had been set up under the Soviet-Era model, and didn’t produce the variety of goods, cheaply, that people outside the Soviet Union expected to buy. The Ukraine also didn’t have alternate sources of energy supply, if Russian supplies were cut off, because a major source of energy was pipelines of both oil and gas from Russia. The Ukraine economy has struggled for many years. Trying to transform it now to be successful competitor in the world economy is likely to be a difficult task. If the Ukraine tries to make goods for the world market, it will find itself in competition with Asian competitors. The Asians are hard to outcompete, in part because their labor costs are low (because it uses workers with little energy use, so they can live on low salaries) and in part because their energy costs are low (often from coal). Safety standards are often low as well, adding to their low-cost structure. If, instead of making goods for the world market, the Ukraine decides to specialize in high-priced services, such as financial, medical, or educational services, it will find that it has a great deal of competition from the EU. It will also find that the EU is having difficulty making the service model work. The service model provides little for export, for one thing. The Russian Energy Situation Russia’s cost of producing oil is among the highest in the world. Mark Lewis, in a presentation at the November 2012 ASP-USA meeting estimated that Russia needed a price of $115.90 a barrel, to cover both its cost of extraction, plus Russian budget needs from taxes. If costs are rising at, say, 10% per year, the current


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required cost today would be about $134 barrel. Current oil prices are not much over $100 barrel, which is too low. Russia is the second largest oil exporter in the world (after Saudi Arabia), exporting approximately 7.2 million barrels a day. We in the rest of the world very badly need Russia’s oil exports to continue, to keep up world oil supply. Without this oil, the world economy would suffer badly. With respect to natural gas, Russia is the single largest exporter in the world (Figure 3, below), exporting more natural gas than all the Middle Eastern countries combined. The cost of producing Russia’s natural gas is likely very high, because Russia is extracting it from more and more difficult locations. Also, Russia is transporting this natural gas greater and greater distances. New pipelines or LNG facilities are necessary to facilitate this transportation, and these are expensive as well.

Figure 3. Natural gas exports by country, with some countries grouped. Exports from the New World are excluded, since they historically have mostly stayed in the New World. For example, Canada exports natural gas to the United States by pipeline. When an oil/natural gas exporter doesn’t get enough revenue, there is a danger of recession, or even collapse. A major part of the problem is that oil and gas exporters depend on tax revenue to fund government services, such as roads, schools, and public health. This tax revenue depends on profitability of the companies selling oil and gas. If prices are not high enough, tax revenue suffers. In fact, the 1991 collapse of the Soviet Union took place after a period of low oil prices made it impossible to justify investment in new more-expensive-to-extract fields. Russia began to recover once oil prices began rising again, making new investment oil investments profitable again. The Ukraine has been a particular problem with respect to natural gas exports for


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Russia, because it has used a significant share of Russia’s natural gas exports, without paying market price for them (Figure 4). In fact, some of the time, it didn’t even pay the below-market price the Ukraine had contracted for, for natural gas exports–the reason for the Ukraine’s debt to Russia.

Figure 4. Ukraine natural gas imports as a percentage of Russia’s natural gas exports. Also, with Russia’s total natural gas exports close to flat (see Figure 3), the high exports to Ukraine have limited the amount available to members of the European Union. If Russia bases its economy on the sale of oil and natural gas, it needs a high enough average price, to fund its overall costs. The Ukraine continues to need Russia, because Russia is the source of its oil and gas supplies. The IMF recently approved a $17 billion loan to the Ukraine, to pay off its debt to Russia and for other purposes. The loan is contingent on fiscal reforms, including a 50% increase in natural gas prices, raising taxes and freezing the minimum wage. My expectation is that the Ukrainian situation will spiral downward, with lower and lower energy use (because citizens won’t be able to afford the high cost of energy). Russia needs the US, because it is having trouble obtaining enough investment capital, because of current low oil prices. It needs to continue relationships with oil companies such as Exxon Mobil, hoping these companies will help provide investment capital. The catch is that they too are having difficulty. Exxon Mobil has reported falling profits for four quarters. The same Exxon article mentions that the company cut capital and exploration costs by 28% as a way of getting income and outgo back into line. So Exxon Mobil is “hurting” as well, for the same reason that Russia is hurting: inadequate oil and gas prices. To keep income in line with necessary expenditures, Russia has essentially no


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choice but to insist on higher prices from the country that is a big consumer, but can’t pay its bills–the Ukraine. These higher prices are likely to push the Ukraine’s economy down further, likely making the IMF loan impossible to repay. To Which Countries Can Russia’s Natural Gas Be Exported? The market for Natural Gas imports is somewhat restricted, as shown in Figure 5, below. This chart includes natural gas imports from all sources, including the Middle East and Africa, not just Russia. I have omitted the Americas, because it currently tends to operate as a separate system, with the US, Canada, and Mexico connected by pipelines.

Figure 5. Natural gas imports (excluding new world) by country grouping. FSU is “Former Soviet Union.” Based on EIA data. Chart omits Switzerland and other nonEU European natural gas importers. When it comes to finding locations for Russia to export natural gas to, the countries of the European Union are a large share of the natural gas market. (In Figure 5, I have omitted a few small European importers that are not part of the EU, and not part of the FSU, such as Switzerland, but this omission should be small.) The Ukraine and other Former Soviet Union countries are gradually being squeezed out, because they cannot afford today’s natural gas prices. Asia is growing in its natural gas use. The prices paid in Asia have tended to be higher than in Europe (Figure 6, below), so it is natural for Russia to look to Asia as a growth area for its natural gas exports. Russia cannot easily walk away from the countries it currently exports to, because it needs natural gas revenue, and the pipelines are already in place.


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Can the United States Actually Help the Ukraine with Natural Gas? The Ukraine’s big problem with natural gas is that it can’t afford to pay market prices for it. This issue is likely to continue to be a huge problem in the future, regardless of which country is planning to export natural gas to it. Greece has had a similar problem, with inability to pay for natural gas imports from Russia. On my view, the Ukraine’s inability to afford natural gas is its number one problem. The problem can be temporarily “papered over” with an IMF loan, but unless there are huge structural changes to the economy, the basic problem won’t be fixed. Let’s suppose that the Ukraine actually finds money to pay for imports. Can the US provide the natural gas imports required? Can it also help with European imports? Many people look at the disparity in natural gas prices around the world (Figure 6), and expect that US can provide natural gas to Europe as well .

Figure 6. Comparison of natural gas prices based on World Bank “Pink Sheet” data. Also includes Pink Sheet world oil price on similar basis. If a person looks at the situation closely, it is hard to see that US exports will happen in large enough quantity, in a fast enough time frame, to make any difference. I recently wrote a post pointing out some of the issues, called The Absurdity of US Natural Gas Exports. I point out in that post that the United States is currently a natural gas importer. Our own natural gas in storage reservoirs is at record low levels, and there is concern that we may not be able to refill them in time for next winter. The amount of natural gas required by Europe is huge, if it were to try to replace Russia’s contribution. So we are talking about the need for a very large change for the US to be able to help Europe and the Ukraine. There is one scenario in which the United States might theoretically be able to help Europe. This scenario would require a lot more than putting LNG export terminals in place. In particular, we would need:


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Much higher US natural gas prices than are currently the case, in order to make it economic to extract shale gas that seems to be present, but that is not economic to extract at this time. US natural gas prices would likely need to rise to two to three times current levels, perhaps to current European levels. The US economy would need to weather the storm that these higher natural gas prices would cause. Homeowners would find that the cost of heating their homes is much higher, but that their salaries are not any higher. Utilities that use natural gas would find that their sales price of electricity needs to be much higher, affecting both homes and businesses. The US economy would suddenly become much less competitive in the world market place, because of its higher cost structure compared to countries using coal as their primary fuel. In order to extract this higher-priced natural gas, we would need to greatly ramp up the number of shale gas wells drilled, perhaps to 10 times the current number of wells drilled per year. Part of the big increase would take place because of the greater total amount of natural gas required. Part of the increase would take place because we would now be drilling wells with lower productivity–partly because of lower monthly output, and partly because of shorter productive lives. Without adding low-productivity wells such as these, there is no way that production can be ramped up as much as required. (This is the reason that higher natural gas prices are needed.) To drill this huge number of wells, we would need many more drilling rigs. We would need many more engineers. We would need many more trucks hauling water for hydraulic fracturing fluid. In dry areas, we would likely need to transport the water required for fracking much longer distances than in the past. We would need to dispose of much more waste material, causing potentially many more problems with pollution and with earthquakes. We would need communities willing to put up with all of these problems, in order to help other countries in need of natural gas imports. Someone would need to build a huge number of LNG transport ships to carry all of this natural gas. It is not clear whether LNG import terminals would be needed as well–the ones currently in place tend to be underutilized. Many more pipelines would be needed, both in the US from the new wells to the terminals, and in Europe, connecting LNG terminals to the new users. Many of these pipelines will be used for only a short period of time, as wells deplete quickly. The cost of LNG the US will be able to send to Europe will likely be more expensive than current European natural gas prices, when the combination of the higher US natural gas cost, plus LNG transport cost, is considered. If there are new European natural gas imports, say from Israel, the additional high-priced natural gas from the US may not be needed. It is also not clear that Europeans will be able to afford the new expensive natural gas, either. The high-priced gas will tend to make the European economy shrink, because salaries will not rise to match the new higher costs.

Conclusion The US approach to the Russia /Ukraine situation reflects a serious misunderstanding of the situation. Russia has little choice but to try to raise the price of products it is selling, any way it can. It needs to cut out those who cannot afford its


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products, including the Ukraine. If Europe increasingly cannot afford its products, Russia needs to find customers who can afford them. There is little chance that the United States is going to be able to help Europe with its natural gas needs in any reasonable timeframe. Our best chance at keeping the global economy “working” for a little longer is to try to keep globalization working as best we can. This will likely require “making nice” to countries we are unhappy with, and putting up with what looks like aggression. Policymakers like to think that the US has more power than it really does, and like to encourage stories suggesting great power in the press. Unfortunately, these stories are not true; we need policymakers who understand our real situation.

View more quality content from Our Finite World


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Stirring the pot: the North American energy revolution Written by Andy Bout from Eka North America is undergoing an energy revolution. Technological advancements – particularly in horizontal drilling and massive hydraulic fracturing – have opened up new and abundant sources of natural gas and crude oil to commercial development, in locations once off-limit to the industry. Andy Bout, Vice President, Energy at EKA explores how this revolution is shaking up the traditional landscape of the sector, and how the resulting uncertainties further underline the need for companies to utilize robust commodity data management processes in order to stay ahead of the pack. The times they are a’ changin’ The numbers speak for themselves. Since the widespread adoption of new fracking technologies in 2007, gas production from shale fields has risen from around 3 BCF a day to 28 BCF. This in turn has increased total US production from 55 BCFD in 2007 to an estimated 72 BCFD in early 2014. Similarly, oil production from shale reserves has helped push US crude production from just over 5 million barrels a day in 2008 (a 50 year plus low) to an estimated 8 million barrels per day in 2013 (a 20 year plus high). This has rightly been feted by industry and the political class alike. It has spurred economic growth in parts of the United States, and promises to reduce US reliance on foreign sources of energy (the ‘Holy Grail’). However as one might expect the sharp transition has also thrown up significant disruption. Much of the new production has been found outside the ‘fairways’ of traditional oil and gas infrastructure, and the industry faces challenges brought about by the lack of adequate pipeline capacity in proximity to new fields, as well as the impact of increased volumes on supply patterns and commodity prices. Looking in more detail at a few examples: the huge increase in oil production resulting from development of the Bakken Shale field in North Dakota has overrun local pipeline capacity. This has necessitated alternative means of moving that crude to refining centers in the Midwest and along the Gulf Coast. Rail has been the most popular option so far, with an average of 950 tanker cars of oil leaving the state by this route every day at present – around 60 per cent of the state’s total oil production. While pipeline is generally considered preferable to rail due to lower costs and operational risk, this increased reliance on rail (thanks in part to delays in the


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construction of new pipeline capacity) has alerted producers to its unique advantages. More flexible routing allows for delivery to the most lucrative markets with the ability to re-route mid-journey in response to market conditions. While there are a number of proposals on the table for new pipeline capacity in this area to pick up the shortfall, the significant investment in local rail infrastructure combined with environmental concerns makes it uncertain if and when this new capacity will actually materialize. The expansion of the Bakken field has also highlighted another problem: the critical shortage of natural gas gathering and transportation capacity in the area. The consequence is that producers are currently forced to flare much of the gas produced as a by-product of crude. Needless to say, this is wasteful and unenvironmentally friendly. Producers looking to address the issue are consequently supporting a number of mid-stream operators – including Tulsa-based Oneok and Hess Corporation – in the development of new gathering, processing and transmission facilities which would allow the excess gas to be captured and sold. As production ramps up, basis differentials between the Gulf Coast and Midwest supply points and the Northeast markets have tightened, reducing the flow of gas from the South. This can be seen with the Marcellus Field in the Appalachian region, where it is making a big and potentially transformational impact on natural gas markets. Southern producers, unable to compete with Marcellus gas in this market, are increasingly having to seek out alternatives, often at lower prices, forcing many to reduce exploration and production budgets for gas projects. Certain tools for uncertain times The upshot of all of this is that the industry is in a major state of flux. The map of North American energy is – literally – being re-drawn, and re-drawn again, on a yearly or even monthly basis. While the impact of the shale revolution is undoubtedly a positive one, it has also created a lot of uncertainty and volatility (as any good business revolution should). Given these rapidly shifting supply patterns, and increasing volumes of oil and gas entering the US markets, wholesale energy traders – particularly natural gas traders – are having difficulty remaining abreast of the changes and adopting to the new dynamics as they emerge. Once-lucrative transportation capacity is often going unused, and long-term supply or sales agreements are becoming increasingly uneconomic. In order to adapt to the impact of new technologies on the energy market, energy traders must adopt new software technologies in the world of information management. Energy organizations need technology that provides advanced, predictive analytics that assist in making informed decisions by transforming large amounts of data into insights. The software must deliver real-time, meaningful and actionable information for traders, schedulers, risk managers, and executives to view and analyze. It must also allow simulation of key performance metrics such as risk exposure, P&L, counterparty limits, budget and forecast variances, and storage and transportation costs.


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If energy businesses hope to meet the challenges of this Brave New World, they must have the information and tools that allow them to react appropriately as supply patterns change, new facilities come online, or when prices spike due to transportation or supply disruptions during extreme weather (such as that seen during the recent cold snaps). For traders with easy access to the ‘big picture’, these market imbalances can offer significant upside. Yet in order to take advantage of opportunities as they arise, traders must utilize systems that consume and aggregate data from multiple markets, and software that can provide the necessary insightgenerating analysis. The US energy market has been flooded with gas. For energy traders, it’s time to sink or swim.

View more quality content from Eka

The great imaginary California oil boom: Over before it started Written by Kurt Cobb from Resource Insights It turns out that the oil industry has been pulling our collective leg. The pending 96 percent reduction in estimated deep shale oil resources in California revealed last week in the Los Angeles Times calls into question the oil industry's premise of a decades-long revival in U.S. oil production and the already implausible predictions of American energy independence. The reduction also appears to bolster the view of long-time skeptics that the U.S. shale oil boom--now centered in North Dakota and Texas--will likely be short-lived, petering out by the end of this decade. (I've been expressing my skepticism in writing about resource claims made for both shale gas and oil since 2008.) California has been abuzz for the past couple of years about the prospect of vast new oil wealth supposedly ready for the taking in the Monterey Shale thousands of


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feet below the state. The U.S. Energy Information Administration (EIA) had previously estimated that 15.4 billion barrels were technically recoverable, basing the number on a report from a contractor who relied heavily on oil industry presentations rather than independent data. The California economy was supposed to benefit from 2.8 million new jobs by 2020. The state was also supposed to gain $220 billion in additional income and $24 billion in additional tax revenues in that year alone, according to a study from the University of Southern California that relied heavily on industry funding. But that was before the revelation by the Times that the EIA will reduce its estimate of technically recoverable oil in California's Monterey Shale by 96 percent--almost a complete wipeout--after taking a close look at actual data for wells drilled there already. The agency now believes that only about 600 million barrels are recoverable using existing technology. The 600 million barrels still sound like a lot, but those barrels would last the United States all of 40 days at the current rate of consumption. Americans had been counting on the seemingly oil-rich Monterey Shale for more than 60 percent of a supposed newfound bounty of domestic oil locked up in deep shale deposits. But it turns out that the Monterey is rich with oil in the same way that seawater is rich in dissolved gold. In both cases the resource is there, but no one can figure out how get it out at a profit. The EIA previously estimated that resources of so-called tight oil, the proper name for oil from deep shale deposits, could reach 23.9 billion barrels for the United States as a whole. Overnight that number shrank to 9.1 billion. The firm hired to do the original estimates, INTEK Inc., was saying as recently as December that it planned to raise its estimate for the Monterey to 17 billion barrels, presumably based on representations made to it by the industry. The firm assumed, apparently without any justification, that the Monterey Shale would be just as productive as other shale deposits such as the Bakken in North Dakota and the Eagle Ford in Texas. But the geology of the Monterey is riddled with folds and far more complex than other U.S. shale deposits, something that wouldn't have been too hard to find out from existing geological studies and well logs. We cannot be sure whether those who wrote the wildly overoptimistic INTEK report were eager to encourage drilling and investment in the Monterey, something the oil industry certainly favored. But the colossal miss suggests the possibility that INTEK and its analysts have grown too close to the industry and are serving it rather than the EIA which commissioned the report. It's no surprise that those who work in the oil industry are perennially optimistic. This high-risk business isn't for the timid. And that optimism is necessary if the industry is going to raise the capital it needs from investors. But it should be obvious that relying on the oil industry for objective information that will form the basis for public policy is a mistake. Independent sources and objective data are important cross-checks on the industry's understandable but often misleading enthusiasm.


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The other explanation for the Monterey miss is that the analysts at INTEK are simply colossally inept. Note that INTEK was also responsible for the overall U.S. assessment of 23.9 billion barrels of technically recoverable oil lodged in deep shale formations. The California miss alone reduced estimated U.S. resources to 9.1 billion barrels, a cut which by itself calls into question the entire premise of renewed American oil abundance. But, the gargantuan misreading of the Monterey Shale's resources also suggests that the firm's estimates for other areas of the country need review as well. A February 2013 comprehensive report on U.S. tight oil and natural gas from deep shales released by the Post Carbon Institute presaged the Monterey disappointment by pointing out how little oil had been extracted per well using advanced techniques in the Monterey Shale. A follow-on report issued in December focused exclusively on the Monterey and concluded that the INTEK/EIA estimate was vastly overblown. Not surprisingly, neither of these independent reports received any oil industry funding. It is well to remember that the above numbers are all just estimates, and that they are for so-called technically recoverable resources. The estimates tell us little about how much oil from the Monterey or elsewhere might actually be economically recoverable, that is, profitably extracted. For that reason, the oil that is ultimately extracted from the Monterey and other deep shale deposits will likely be less than any estimate of technically recoverable resources. That means that even the 600 million barrel estimate for the Monterey may turn out to be too optimistic. The industry counters that improved technology could change what seems unobtainable now into accessible oil. But, it cites no specific developments that are not already in use and therefore reflected in current estimates of what we can hope to extract. And the idea that we should base our public policy on innovations that no one has thought of yet seems more than a little unwise. Moreover, while technology can improve, the laws of physics don't. The industry is already moving from the so-called "sweet spots" in shale deposits to those that are more difficult to exploit. That process will continue until the laws of physics and economics team up to make drilling unprofitable, and that will be the end of the shale boom in the rest of the country. ________________________________________________________ P.S. In a previous piece I asked, "Will anyone who is currently predicting U.S. energy independence be punished if the story turns out to be wrong?" My answer was probably not. Now, we will find out if that turns out to be the case. My guess is that the oil industry will redouble its efforts to convince the public and policymakers to continue to believe something which cannot be supported by the evidence. P.P.S. Tupper Hull, spokesman for the Western States Petroleum Association, told the San Francisco Chronicle the following in response to the Monterey Shale revision: "People forget that the boom taking place in Texas and particularly North Dakota did not happen overnight. There were decades of operators trying to understand the technology and the geology." He seems unable to recognize that in


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the decades that it may take to figure out how to unlock the Monterey Shale, California and the world will be working hard to create an advanced energy infrastructure that will make the Monterey irrelevant. Technology isn't standing still in renewable energy either.

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Oil & gas boom 2014: No end in sight Written by David Blackmon from FTI Consulting, Inc. In February, oil production in Texas hit a 34-year high, with combined oil and condensate volumes exceeding 2.9 million barrels of oil per day. For the first time in memory, Texas now produces more than 36% of all the oil produced in the United States, and if it were a separate country, Texas would now rank as the 8th largest oil producing nation on earth. Wow. We see endless speculation about how long we should expect the current boom in shale oil and natural gas that is happening in Texas and throughout much of the United States to last. Prophets of doom like proponents of “Peak Oil” theory and radical anti-economic growth activists like Bill McKibben say it’s all a “bubble” that will burst at any moment. Others actually involved in the development of shale resources tend to believe the correct answer today will be some variation on the theme: “a very long time.” One presenter at the recent Eagle Ford Consortium Conference in San Antonio, Greg Leveille of ConocoPhillips, told his audience that the 25 county region that makes up the Eagle Ford Shale play should expect to see “decades and decades” of production.


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Credit: Dr. Mark Perry at The American Enterprise Institute People who live in the Eagle Ford region, the Permian Basin of West Texas, and other significant shale plays around the country naturally worry about when the next “bust” will come, which is not an unreasonable concern to have. Previous conventional oil and gas booms have almost always eventually wound down into a bust at some level. But there are many reasons to believe that the shale boom will be different, and the Eagle Ford play provides a very good example why. The differences between today’s situation and that of prior booms are many. Start with the fact that previous booms, like the oil boom of the early 1980s, came about due to high oil prices driven by restrictions in supply. The restrictions in the 1980s were artificially driven by OPEC, and prior booms came about simply due to a failure by the global industry to identify adequate new resources. In every case, you had rising demand and limited supplies to meet it. Today’s boom in the United States is different in that we now have rapidly rising domestic supplies meeting rising demand. Where in the past the United States was forced to rely more and more heavily on imports from OPEC countries to meet its domestic needs, today’s shale boom is enabling our country to actually lower oil imports on a daily basis, having cut them almost in half since 2007. In the meantime, rapidly rising demand in China, Japan, India and the rest of the Pacific Rim is filling the void in U.S. imports, consuming all the oil the OPEC countries and Russia can produce. This all ensures the price of oil will remain healthy enough for the U.S. drilling boom to continue. Some in the environmentalist movement, like McKibben, promote what they call the “stranded carbon” theory, which posits the world will ultimately leave much of the known oil and gas reserves in the ground due to concerns over climate change. But this scenario is unlikely to become reality, because to do that will mean an end to


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economic growth in the developed world, and relegating developing nations who need abundant and affordable energy supplies to improve their economies and help move their people out of abject poverty to simply accept their current lot in life. For at least the next 50 years, fossil fuels are the only available source that is truly scalable to meet those needs. The thought that 4+ billion people who populate developing nations on this planet are going to quietly accept their current fate is unrealistic. Yet, those who promote the “stranded carbon” theory have no real, current alternative to offer to fossil fuels. To sustain economic growth here in the U.S. and to have any hope of helping move the developing world out of squalor, we are going to need all we can get of every source of energy we can develop. Rather than leave the oil and gas in the ground, it is more likely the human race is innovative enough to develop technologies necessary to deal with the carbon dioxide. Writing in the Houston Chronicle on April 27, columnist Bill King warned Texans not to put all our eggs in the oil and gas basket, one reason being the potential for development of a “disruptive technology” related to Solar power that would make it more competitive with fossil fuels. That is great advice – we do need to continue to develop renewable fuel sources, and no state or country has done more to aggressively develop wind power than Texas has over the last decade. But even with that continued renewable development, and even if the long-awaited “disruptive technology” related to solar power or hydrogen cars finally comes about, our reality is that the world is still going to need every bit of every source of fuel we can develop. This isn’t 1984 all over again, and we do not have to live in a world of energy poverty, as some actively advocate. The OPEC nations can still influence the global price of oil to some extent, but the ongoing shale oil boom in the U.S. means they can no longer force Americans to wait in endless lines to fill their tanks with gasoline. We can have a world of energy abundance, and Texas is playing a leading role in making it all happen. God Bless Texas.

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OilVoice Magazine | JUNE 2014

Could NAFTA force the Keystone XL pipeline on the United States? Written by Kurt Cobb from Resource Insights As the Obama administration puts off once again any decision on authorizing the Keystone XL pipeline, there are whispers of another intriguing possibility. If the U.S. government fails to approve the pipeline soon or rejects it outright, the Canadians may challenge the delay or rejection under the provisions of the North American Free Trade Agreement (NAFTA) signed by both countries. This move opens up a politically attractive option not previously available to the Obama administration, something I'll discuss below. I've been wondering about how NAFTA might affect any decision. Under its provisions, Canada is obliged to maintain the same ratio of exports to total production of oil and natural gas as prevailed in the previous 36 months regardless of the situation, that is, emergency or no. The pain of any voluntary restriction by Canada must be borne in proportion to its current consumption. Each party to the treaty would be obliged to suffer the same percentage decline in oil or gas deliveries from Canadian production. So, what if Canada decides to expand oil production from the tar sands and export that oil to Asia? Would that production be included in total Canadian production for the purposes of the treaty? Could the United States proceed against Canada for reducing the proportion that the United States is receiving from total production? Or, what if the Canadians build an eastward-flowing pipeline that simply delivers the extra oil to eastern Canada ending that region's dependence on imported oil? The answers to these questions are not clear to me. The treaty doesn't seem to envision such scenarios. But now it seems that with the U.S. government dithering over the Keystone XL pipeline decision, it is Canada that is the aggrieved party. Still, until recently I couldn't see how the NAFTA rules about export ratios would have any bearing on the Keystone decision. As the importer in the treaty, the United States seems to have an avenue for protesting any reduction or cutoff of oil deliveries, but the Canadians do not seem to have any leverage to force the United States to take more Canadian oil. However, a reader alerted me to the current thinking in Ottawa which includes preparations for a possible challenge to any rejection by the U.S. government of the Keystone XL. Under entirely different provisions of NAFTA the Canadian government is readying itself to claim that the Keystone XL project is being treated differently from other previously approved pipeline projects which now cross the U.S.-Canadian border and that such discrimination is not allowed under NAFTA. It turns out that the company proposing the pipeline, TransCanada, would also have standing under


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NAFTA to bring such a complaint. But the company is at present noncommittal about any such move. Now let me spin a possible interpretation of these events without claiming any inside knowledge about the motives of the parties involved. With Congressional elections coming up later this year, it seems obvious that President Obama is loathe to anger environmentalists--some of whom are large donors--by approving a pipeline which they claim will aggravate climate change by increasing the exploitation of the tar sands. (Of course, oil from the tar sands could simply be shipped elsewhere.) The president has now put off any decision for two elections hoping to placate his supporters. But he has angered the Canadian administration in the process. Now, here is the kind of situation where I've asked myself in the past whether Obama just doesn't see the whole picture or whether he is actually 10 steps ahead of everyone else including me. This is because I fully expected him to approve the pipeline after the 2012 election. I didn't think he could put it off. And, I thought his own supporters would see him as cynical for merely postponing until after the election a decision he had already made. But Obama has successfully delayed once again. So, I began thinking along the same lines as I did in 2012: He'll surely have to approve the pipeline after the 2014 election. He'll have no choice. His own State Department says that it is no less safe than any other pipeline. In fact, it will be safer because the latest safety technology will be applied. And besides, the State Department says explicitly that the oil will simply go elsewhere if the United States doesn't take it. So, the president will finally be forced to exhibit his cynicism on this issue. But with the Canadian move, there is another possibility that would work out perfectly for Obama and the Democratic Party. After the election and seeming to stand on principle, the president rejects the Keystone XL pipeline application. This is hailed as a big win for the environmental movement. After the celebration dies down, the Canadians challenge the decision under the arbitration provisions of NAFTA. Any decision by the arbitration panel is final. The panel then decides that the failure to approve the pipeline is discriminatory under the treaty and reverses President Obama's decision. The president reluctantly complies. What else can he do? His hands are tied by the treaty. Is this what the president wants to have happen? I claim no power to read minds. But, perhaps some people in the administration know the answer. It is possible that they haven't thought of this scenario, but I doubt. And so, just this once the president may not be 10 steps ahead of me. We'll see.

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OilVoice Magazine | JUNE 2014

Offshore regulators talk tough but are oil companies listening? Written by Loren Steffy from 30 Point Strategies Offshore regulators issued a stern warning recently for oil companies and contractors that have poor track records for operating in the Gulf of Mexico: we’ve got our eye on you. The warning came during a panel discussion on the final day of the Offshore Technology Conference, the industry’s mega trade show in Houston. The Coast Guard’s assistant commandant for prevention policy, Rear Adm. Joseph Servidio, and Brian Salerno, director of the Bureau of Safety and Environmental Enforcement, warned that they intend to crack down on companies that cut corners. According to the Houston Chronicle: Servidio said the Coast Guard will consider launching unannounced inspections of oil and gas industry vessels after some logged more than five deficiencies during scheduled probes. “There are significant areas of concern, and we have a ways to go with some vessels and some companies,” Servidio said. Servidio said the Coast Guard may even resort to unannounced inspections of vessels with bad track records, similar to a program it already has in place for some cruise ships. Salerno promised much the same for rig operators, as the Chronicle noted: Salerno said the safety bureau he heads, which regulates offshore drilling, also sees evidence of spotty performance, with a few repeat offenders mingled among companies with deep commitments to the safety and environmental management systems now required to minimize process risks offshore. “There are companies we have encountered that think they can cut corners or regard SEMS as just a plan on a shelf,” Salerno said. “In some tragic cases, lives have been lost — needlessly — for failure to follow established safety processes.” The biggest question, left unanswered, is what will the regulators do when they identify recidivist safety violators? So far, they have shown little desire to boot companies from the gulf for repeated safety infractions. Salerno’s comments seem to refer to the Black Elk Energy accident in late 2012 that killed three workers and injured others. Salerno’s predecessor declared that the


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company “failed to operate in a manner consistent with federal regulations,” and it wasn’t the first time. Black Elk had been cited 315 times in the two previous years for rules violations. Yet even after the 2012 accident, BSEE simply told the company to develop a better safety plan. Black Elk had paid some piddling fines prior to the accident – the biggest was $307,500 for failing to fix a gas leak on one its platforms for 117 days – but the company continued to operate in the Gulf. As OTC attendees were frequently reminded at the conference, the Gulf is one of the most lucrative and active areas for offshore drilling in the world, yet companies that fail to operate safely have little worry of being kicked out of the party. If Servidio and Salerno really want to catch the industry’s attention, they need to come armed with stricter consequences for recidivist safety violators. Fines currently are so low, they aren’t enough to change companies’ behavior. Only the threat of losing access to the Gulf will get their attention. Similarly, the feds need to consider an operator’s safety record when awarding new leases in the Gulf. Instead, as we saw after the Deepwater Horizon disaster, BP – a company with a decade of repeated safety and operating failures — was among the first companies to return to the Gulf, and it now is more active there than it was before the accident. The Environmental Protection Agency, not offshore regulators, briefly banned BP from bidding on new Gulf leases, and, as part of the inevitable lawsuit that BP filed, set up an independent auditor to keep an eye on the company’s operations. BSEE and the Coast Guard should consider a similar program for repeat offenders. Talking tough is a good start, but it needs to be back up with more than finger wagging and penny ante fines.

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OilVoice Magazine | JUNE 2014

How much water is used in the Alberta oil sands? Written by Mark Young from Evaluate Energy It is no secret that to produce any oil from an oil sands project, you need water and lots of it. To create the steam needed to extract oil in oil sands projects, operators mainly recycle water that has already been used in the project over and over again. When this amount of water isn’t sufficient, fresh or brackish, saline water (see notes 1 & 2) is obtained from external sources to make up the shortfall. This water can be taken from surface water sources, such as rivers or lakes, or from underground sources via water wells. CanOils now provides data on how much water from external sources is used by producing oil sands in situ and mining projects each year. Analysing this data, we can see that over time, operators in the Alberta oil sands have been getting their water usage from external sources increasingly under control. Total external water use by in situ projects in 2013 was more than double the amount used in 2002, but high recycle ratios have meant this external water usage total has been relatively flat since 2010 whilst bitumen production has continued to rise. Biggest Water Using Projects in 2013 Of the in situ projects that are currently producing, it is Canadian Natural Resources’ Primrose/Wolf Lake project that used the most water from external sources in 2013, approximately 146,000 barrels per day (bbl/d). Cenovus Energy’s Foster Creek (68,000 bbl/d), Nexen’s Long Lake (56,000 bbl/d) and Imperial Oil’s Cold Lake (46,000 bbl/d) were also amongst the highest water using in situ projects in 2013. Source: The CanOils Oil Sands Database


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Water Use Efficiency Improving Over Time In situ projects use a lot of water at start-up before production really begins to ramp up. If all in situ projects’ production and external water use are combined, we can see that until production really started to increase in 2009, more external water was always being used compared to bitumen being produced. Recycle ratios within projects have improved markedly since 2009 – most in situ projects now have recycle ratios of over 90% – and the overall requirement to source water from external sources has consequently fallen for each barrel of oil produced.

Source: The CanOils Oil Sands Database A Project in Focus: Foster Creek, Cenovus Energy One project that has improved its efficiency in terms of external water use is Cenovus Energy’s 120,000 bbl/d Foster Creek project. In 2002, the project was only 1 year into its producing life, and was using over 2 barrels of water for every barrel of bitumen it produced. Now, 12 years later with a recycle ratio of around 100%, the project only needs to source 0.6 barrels of external water to produce a barrel of bitumen.

Source: The CanOils Oil Sands Database


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Fresh Water Use Falling As well as this increasing efficiency in terms of external water use, it is also important to note that Foster Creek is now using much less fresh water than when it first started producing. From the above graph, we can see that the project is using almost 3 times as much water in 2013 than in 2002, but this is almost all made up of brackish, saline water (see note 2). Fresh water use has in fact been reduced to just 5,000 bbl/d or 7% of the total water used in the project.

Source: The CanOils Oil Sands Database This is a trend that can again be seen across the board for in situ oil sands projects. Brackish water use has increased at a much higher rate than the use of fresh water. In 2002, nearly all external water used by in situ oil sands projects was fresh water, whereas in 2013, brackish water makes up almost 42% of the total external water used.

Source: The CanOils Oil Sands Database An important project to note here is Jackfish, operated by Devon Energy. This


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project started producing in 2007 and is the only producing oil sands in situ project to have never used fresh water in its operations. So not only are in situ operators improving the efficiency with which they use water from external sources in bitumen production, they are also becoming less and less reliant on fresh water sources and using more and more brackish water when available that would not otherwise be suitable for human or agricultural use (see note 3). This report was created using new data now available in Canoils’ Oilsands product. CanOils now provides annual fresh and brackish water usage statistics for 7 producing oil sands mining projects and 24 producing in situ projects. This data complements the already available recycle, steam/oil and water/oil ratios, giving CanOIls Oilsands subscribers a comprehensive picture of water use in the Alberta Oil Sands industry. Notes: 1) Fresh water is either non-saline groundwater, which is groundwater that has total dissolved solids less than or equal to 4000 milligrams per litre, or surface water, which is as defined in Section 1(1)(bb) of the Alberta Water (Ministerial) Regulation as “all water on the ground surface, whether in liquid or solid state. 2) Brackish water is saline groundwater as defined in section 1(1)(z) of the Alberta Water (Ministerial) Regulation as “water that has total dissolved solids exceeding 4000 milligrams per litre.” Such groundwater is defined as “brackish water” in PETRINEX and “saline groundwater” by Alberta Environment and Sustainable Resource Development. Brackish water cannot be used in oil sands mining operations. 3) Most fresh water used in oil sands operations is not immediately suitable for drinking or agricultural use either. It requires treatment after being extracted from deep underground sources. 4) All water usage data available in CanOils is sourced from Alberta Environment

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OilVoice Magazine | JUNE 2014

Iraq and Kurdistan: Oil becomes a source of friction Written by Anthony Franks OBE from Mars Omega LLP According to a Deutsche Bank (DB) analyst’s report this week, the quantity of crude oil sat in storage tanks in Turkey fed through the Kurdistan pipeline, will reach a whopping 2.5M barrels in just a few days. And with oil trading at around $107-110 a barrel that is an awful lot of revenue, and a big political bargaining chip too, as well as a big gamble for the traders. DB confirmed his week that both Genel Energy and Gulf Keystone are now a ‘buy recommendation’. Interestingly, Gulf Keystone struck a note of caution – also this week - warning its revenue outlook was uncertain as it is still owed $24M for oil sales from the field – resulting from a lag in payments for crude from its Shaikan oil field. However, in an associated move, this March - in a sign of growing business confidence - Gulf Keystone moved its shares to the main London Stock Exchange from the Alternative Investment Market, and said it was on track to increase production from Shaikan PF-1 and PF-2 fields by EOY to 40K bpd, which is a huge rise from the current 15-16K bpd. Since January 2014, it says it has received $6.46M for crude oil exports from Shaikan, but it was still owed around $24M for crude already delivered on trucks. In a company statement it said "This therefore gives rise to uncertainty in the timing of revenue recognition and guidance for 2014.” It also gave a full-year revenue guidance of “$150-180M, reflecting cash payments and production outlook” – and possibly even reflects a nuanced understanding of the trajectory of Baghdad/Irbil politics. Both the prime Kurdish Tawke and Taq Taq fields can access export capacity quickly, turning crude into cash equally quickly; and the expertise of the operators means that Kurdistan could - in a perfect world - pump 750K bpd, although the downstream infrastructure can currently only handle 400K bpd (when the pipelines are not blown up, that is.) But there are more export pipelines in the pipeline, and more reserves in the ground. DB reckons that their analysis of the remaining 2014 drilling schedules suggests that reserves could go up by 30%, along with interest of the FDI community, and the potential for Kurdistan to contemplate the finer points of economic independence from the millstone of the federal budget process. Another interesting indicator of possible disengagement is that the US Nasdaq Stock


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Market has invited the Erbil Stock Exchange (ESX) to two international conferences. Nasdaq and ESX have also signed an agreement “to power the ESX with NASDAQ OMX X-stream trading technology to increase market participant involvement, both in the region and internationally” – and of course it could also help Kurdistan it needs to become cashflow independent. Abdullah Ahmad, the head of ESX, said that the Kurdish stock exchange will participate alongside some of the biggest stock markets in two international conferences, in Dubai and Stockholm, and also explained that ESX will work with the Nasdaq system, and will launch at the end of June. In a clear sign of increased frustration, Reuters quoted President Barzani saying in the last few days: "The political decision has been made that we're going to sell oil independently. We will continue producing the oil, pumping it out and selling it. If they continue escalating, we will also escalate from our side." According to Barzani, “If they [Iraq] don't like us to be with them, they should tell us and we will take another path as well. We are going to have a referendum and ask our people. Whatever the people decide". And that referendum is likely to be easier to call than the question of Scotland devolving from the UK.

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OilVoice Magazine | June 2014