OilVoice Magazine | July 2013

Edition Sixteen – July 2013

Is there a refinery in Batam's future?

Poland's shale gas future going up in smoke?

High oil prices are starting to affect China and India

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Contents Featured Authors Biographies of this months featured authors High oil prices are starting to affect China and India

by Gail Tverberg Recent Company Profiles The most recent companies added to the OilVoice directory Insight: The silent majority!

by David Bamford Results may vary: Beware of kaleidoscopic vision in the oil and gas industry

by Kurt Cobb Is there a refinery in Batam's future?

by Ken Anderberg A futures market for North American LNG exports?

by Keith Schaefer Will Israel's rush to export natural gas turn out to be a mistake?

by Kurt Cobb Review: Kuwait - A mature industry stands at a juncture

by Richie Ethrington Additional Iranian oil sanctions may be counterproductive

by Gail Tverberg Poland's shale gas future going up in smoke?

by Mark Young

3 5 15 16 19 20 25 30 31 34 42

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Featured Authors 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.

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.

Ken Anderberg AIM Communications Vagabond international author Ken Anderberg has visited scores of countries on four continents during his more-than-40-year career in journalism.

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

Keith Schaefer Oil & Gas Investments Bulletin Keith Schaefe is editor and publisher of the Oil & Gas Investments Bulletin.

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Richie Ethrington Finding Petroleum Richard Etherington, 24, works as a freelance journalist. Richard, a BA Hons Political Science graduate, is also a fully trained sub-editor and reporter. He is a former equities reporter and columnist, who specialised in small cap drilling and mining companies – during which time he built up an impressive portfolio of industry contacts.

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

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High oil prices are starting to affect China and India Written by Gail Tverberg from Our Finite World The US Energy Information Administration recently released its report showing oil consumption by country updated through 2012. Based on this report, it appears that at current high oil prices, demand in both China and India is being reduced. Thus, for those who are wondering how high oil prices need to be, to be “too high,” the answer is, “We are already there. In fact, continued high oil prices are a big reason behind the recessionary forces we are now seeing around the world.”

A big part of China and India’s problems is that they, like the United States and most of Europe, are oil importers. In this post, I also explain why there is a big difference in the impact of high oil prices on oil importing countries compared to oil exporting countries.

Figure 1. Liquids (including biofuel, etc) consumption for China, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

Figure 2. Liquids (including biofuel, etc) consumption for India, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

We can see from Figures 1 and 2 that at $100 per barrel prices, there is a definite flattening in per capita consumption for both India and China. Per capita consumption is used in this analysis, because if total oil consumption is rising, but by

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less than population is increasing, consumption on average is falling.

Some Other Countries with Declining Consumption There are many other importing countries with even sharper drops in consumption than China and India. These declines started in the 2005 to 2007 period, as oil prices rose, and continued as oil prices have remained high. One example is Greece: Figure 3. Liquids (including biofuel, etc) consumption of Greece, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

In fact, all of the PIIGS (Portugal, Ireland, Italy, Greece, and Spain, known for their problems with recession) have shown steep drops in oil consumption: Figure 4. Per capita oil (“liquids�) consumption for countries known as PIIGS, based on EIA data.

Europe in total shows a somewhat less steep drop in oil consumption than the PIIGS: Figure 5. Liquids (oil including biofuel, etc) consumption for Europe, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

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The US shows a similar drop in consumption to Europe: Figure 6. Liquids (oil including biofuel, etc) consumption for United States, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

Where is per capita oil consumption rising?

Oil consumption is rising faster than population in many oil exporting countries. If we look at OPEC in total, we see a big upward jump in per capita oil consumption in 2011 and 2012.

Figure 7. Liquids (oil including biofuel, etc) consumption for OPEC, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

In fact, this pattern occurs both in Saudi Arabia, and for OPEC outside Saudi Arabia: Figure 8 Liquids (oil including biofuel, etc) consumption for Saudi Arabia, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

For Saudi Arabia, 2012 oil consumption per capita is more than five times as much as that of Europe. Outside Saudi Arabia, there is a definite upward bump in consumption, both during the 2008 price run-up and corresponding to the higher price in 2011 and 2012.

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Figure 9 Liquids (oil including biofuel, etc) consumption for OPEC ex Saudi Arabia, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

One reason why oil exporters show higher growth in oil consumption than other countries is because oil is becoming more difficult to extract, and because the easiest to extract oil was extracted first. There are often indirect needs for oil as well, such as desalinization to have sufficient water for a growing population, or a new refinery for difficult-to-refine oil. I talk about these issues in my post, Our Investment Sinkhole Problem.

A second reason why oil exporters often show higher growth in oil consumption is because exporters often provide subsidized prices on oil products, so their citizens do not have to pay the full cost of the product. Thus, their citizens do not really experience the high oil prices that most importers do.

A third reason why oil exporters show higher growth when oil high prices are high has to do with all of the money these exporters receive when they sell high-priced oil.

The Economist this week has an article “Saudi Arabia risk: Alert – The next property bubble?” It talks about the huge number of office buildings, schools, low-priced homes, and other building projects underway, thanks to a combination of easy credit availability and lots of oil money. The article indicates that citizens rarely put their new-found wealth into paper investments. Instead, a significant part of their wealth ends up in building projects that require oil use.

Norway is an exporter that does not subsidize oil prices (in fact, it has quite a high tax on oil use in private vehicles). It shows higher per capita oil consumption in the past two years, despite higher world oil prices.

Figure 10. Liquids (oil including biofuel, etc) consumption for Norway, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

Brazil is not an oil exporter, but it has been trying to ramp up its production. Its per capita consumption has been rising recently as well.

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Figure 11. Liquids (oil including biofuel, etc) consumption for Brazil, based on data of US EIA, together with Brent oil price in 2012 dollars, based on BP Statistical Review of World Energy updated with EIA data.

In fact, Africa in total, Central and South America in total, and the Middle East in total, all show oil consumption rising faster than population, in 2011 and 2012. These are areas that, in total, are oil exporters.

Some very low oil-use countries, such as Bangladesh, are showing rising per capita oil consumption in 2011 and 2012, even with higher oil prices. This could indicate that some manufacturing is shifting to even lower cost areas than China and India.

Australia is showing growing per capita oil consumption, perhaps because of oil’s use in resource extraction and transport.

Why would a drop in per capita oil consumption for oil importers matter?

A drop in per capita oil consumption is a likely sign that oil is becoming increasingly unaffordable. We know that oil is used to make and transport goods. If less oil is used, or if oil use is growing less rapidly than in the past, there is a real chance that an economy is slowing.

Figure 12. World growth in energy use, oil use, and GDP (three-year averages). Oil and energy use based on BP’s 2012 Statistical Review of World Energy. GDP growth based on USDA Economic Research data.

There are a number of reasons oil consumption may be down. Fewer goods for sale may be being transported, perhaps because European demand is down. Citizens may be driving less in their free time. Or many young people may be unemployed, and be unable to afford to buy a car or motor scooter. Any of these changes could mean a slowing economy.

Obviously, there are situations in which reduced oil consumption doesn’t mean a slowing economy. A shift from manufacturing to a service economy could lead to lower oil consumption; a shift toward more fuel-efficient cars and trucks could lead to lower oil consumption. But these changes tend to take place slowly over time, not all at once, when oil prices rise.

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Another way oil consumption can be reduced is if a country has in the past generated electricity using oil, and such generation is shifted to another fuel, such as natural gas. This type of change is being made in Greece, but seems unlikely in China and India. Similarly, if homes are heated with oil, sometimes an alternate fuel can be used, reducing oil consumption. China and India aren’t areas where oil has traditionally been used to heat homes, though.

In general, though, sharp reductions in oil consumption in a growing economies, such as China and India, are cause for concern, if one was expecting growth. Are high oil prices stressing the economy?

United States and European Oil Imports The US oil consumption pattern looks very much like that of an oil importing nation, under stress from high oil prices. Recently, there has been a lot of publicity about higher US oil production, but this does not really change the situation. If we look at US oil consumption and production (actually “liquids” production and consumption since all kinds of stuff including biofuels are included), we see that the US remains an oil importer. In fact, it is still a long way from becoming an oil exporter. (And, importantly, oil prices aren’t down by much, and high oil prices are our real problem.)

Figure 13: US Liquids (oil including natural gas liquids, “refinery expansion” and biofuels) production and consumption, based on data of the EIA.

The European oil import situation is worse than the United States liquids situation, and no doubt part of its current economic problems. A graph of its recent production and consumption is as follows: Figure 14: European Liquids (oil including natural gas liquids, “refinery expansion” and biofuels) production and consumption, based on data of the EIA.

Difference Between Oil Importers and Exporters – Additional thoughts The cost of extraction varies widely by country and by field within country. In order to

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provide a large enough quantity of oil in total, the world price of oil has to be high enough to provide an adequate profit for the highest cost producer. Clearly, if every oil company charged the price needed for the highest cost producer, many would be collecting far more than they need for future oil extraction and payment of dividends.

Where does all of this extra money go?

To a significant extent, this money is “latched onto” by governments. In the case of oil exporting countries, governments often own oil companies directly. But even if they don’t, governments tax oil extraction at very high rates, to make certain that the government gets the benefit of any extra revenue available. Sometimes Production Sharing Agreements are used. A chart by Barry Rodgers Oil and Gas consulting (Figure 15 below) shows that for many oil exporting countries, the government “take” is 70% to 90% of operating income (that is, net of direct expenses of extraction).

Figure 15. Chart showing “government take” as a percentage of operating income

by Barry Rodgers Oil and Gas Consulting.

Even in the case of the United States, the government take is significant. Barry Rodgers, in an article in the May issue of Oil & Gas Journal, calculates that for tight oil (such as oil from the Bakken), the average government take is $33.29 per barrel.

This compares to $19.50 per barrel, for tight oil extracted in Canada. These amounts include payments to state governments as well as the federal government. If extraction costs are low, as in the case of Alaska, the state adjusts its tax accordingly.

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Oil importing countries would like the world to have a level playing field with respect to the price of oil. In the real world, this doesn’t happen. Oil exporting countries get huge benefits in the form of the tax they collect from the oil they sell abroad. Often, this tax revenue amounts to 70% or more of a country’s tax budget from all sources.

If oil exporters have small populations, they can afford to offer oil at subsidized rates to their own populations. (If they have large populations relative to exports, offering a subsidized price would soon eliminate all exports!)

Economists would like us to believe that many of the differences between oil exporters and oil importers will even out because money spent by oil exporters to purchase goods and services together with purchases of government bonds from oil importers should mostly make their way back to oil importing countries. There are several differences though: (a) Oil exporting countries can choose to charge their citizens a lower price oil, thus insulating them from the high world oil price, and raising their demand for oil (that is, the amount of oil they can afford). This higher demand allows these countries to increase their oil consumption, even as other countries, subject to higher prices, reduce theirs. Evidence presented in this article suggests that this, in fact, is happening at high prices. (b) Oil exporting countries need not tax the income of individuals and businesses, or institute value added taxes, because their tax needs are mostly met by the taxes they collect on oil that is exported. This gives them a competitive advantage in making goods from oil or natural gas for international trade. (c) Since world oil supply is limited, the oil that the oil exporting countries are able to purchase at subsidized prices (even if to build unneeded office buildings in Saudi Arabia) is removed from the world market, further driving up oil prices, and leaving less for other countries to consume. (d) The money that is spent by oil exporters rarely makes it back to the salaries of individuals in oil importing nations who are faced with buying high-priced oil products. In fact, I have shown that in times of oil prices, Unites States salaries tend to stagnate: Figure 16. High oil prices are associated with depressed wages. Oil price through 2011 from BP’s 2012 Statistical Review of World Energy, updated to 2012 using EIA data and CPI-Urban from BLS. Average wages calculated by dividing Private Industry wages from US BEA Table 2.1

by US population, and bringing to 2012 cost level using CPIUrban.

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At best, the money makes it back to financial institutions and corporations selling products such as exported grain. The higher demand for grain tends to raise food prices, putting another stress on the economy.

View more quality content from Our Finite World

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Recent Company Profiles The OilVoice database has a diverse selection of company profiles, covering new start-up companies through to multi-national groups. Each of these profiles feature key data that allows users to focus on specific information or a full company report that can be accessed online or printed and reviewed later. Start your search today!

Alon USA Energy Refiner Alon is an independent refiner and marketer of petroleum products focused on growth and innovation to meet both the energy and environmental needs of today. With refining, asphalt and retail/branded marketing operations across the western and southcentral regions of the United States, there is a concentrated effort to share best practices and expertise across the Alon family of companies.

Talon Petroleum Oil & Gas Talon Petroleum is a Texas and Gulf Coast focused exploration and appraisal company.

The company strategy is focused on low risk, liquids rich prospects in mature, well serviced areas. Talon expects to add value through utilising modern drilling and fracture stimulation technologies. Talon already has a diversified portfolio of assets which include the non-Eagle Ford shale Texon assets, with two producing wells and 3P reserves of 1.3MMbbls of oil.

Alon USA Energy's OilVoice profile Talon Petroleum's OilVoice profile

SAExploration Service

PostRock Energy Oil & Gas

SAExploration is a geophysical services company offering seismic data acquisition services to the oil and gas industry in North America, South America, and Southeast Asia.

SAE provides a full range of services related to the acquisition of your 2D,3D and 3C (MultiComponent) seismic data project on land, in transition zones and in shallow water.

SAExploration's OilVoice profile

Platino Energy Oil & Gas Platino Energy is a newly formed pure play exploration company focused on oil and gas opportunities in Colombia. The Company was formed in connection with the acquisition of C&C Energia Ltd. ("C&C") by Pacific Rubiales Energy Corp. ("Pacific Rubiales") which closed on December 31, 2012. In that transaction, Pacific Rubiales acquired C&C's Llanos basin assets in Colombia.

Platino Energy's OilVoice profile

With a solid, value-driven leadership team and employee base, PostRock Energy is positioned to create value for all of our stakeholders in the years to come. Currently, we are the leading producer of natural gas in the Cherokee Basin of southeast Kansas and northeast Oklahoma. We also own and operate over 400 oil and gas wells in Appalachia, and 2,200 miles of gathering system supporting our upstream operations.

PostRock Energy’s OilVoice profile

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Insight: The silent majority!

Written by David Bamford from Finding Petroleum My observation remains that the last big innovation or disruptive breakthrough in subsurface interpretation was almost 20 years ago when Geoquest and Landmark 'invented' the 3D seismic interpretation workstation.

My 'silent majority' are the folk who actually do the innovative work in oil & gas companies who are not only ignored, but hamstrung, by the technology and the purchasing policies of their companies!

Since then, improvements have been incremental and the systems have fallen increasingly under the control of IT and supply chain managers who like low risk, competitively priced contracts with major suppliers that define a bundle or 'stack' of hardware, operating systems, master software license agreements, and most importantly, applications, in turn leading to high prices, lock-in and an inability to respond to business needs with innovative new applications.

In the meantime, the amount and diversity of data available to sub-surface specialists has outpaced the ability of available systems and workflow processes to manage, integrate and interpret it whilst what these specialists are trying to do understand basins, define prospects, understand reservoirs, deliver reserves and production - is getting more difficult all the time i.e. requires more and more innovation.

For example in: Exploration 1. Many basins are now assessed, and nearly all offshore wells are nowadays drilled, on the basis of a 3D seismic survey which in its basic form allows sophisticated stratigraphic and structural interpretations, tied to available well logs.

2. Beyond this, lithology and fluid prediction depends on a wide range of derivative seismic attributes - near- and far-stacks, AVO gradients, elastic impedance, phase etc etc.

3. Non-seismic geophysics has its place, especially when such data can be understood and interpreted (integrated with) the geological framework provided by a seismic interpretation i.e. the output of 1. and 2. above. Electromagnetic surveys and Full Tensor Gravity Gradiometry are especially significant in this respect.

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Reservoir Management 1. Most fields will now have a static reservoir description based on all available well data (logs, cores) and a sophisticated interpretation of a 3D seismic survey (deliverables similar to 1. and 2. under Exploration above).

2. Reservoir dynamics are observed by wide-ranging production monitoring, from continuous downhole PLTs to regular 4D towed-streamer seismic to 'asoften-as-you-want' permanent seismic monitoring (either on the surface or downhole).

3. These static and dynamic facts and interpretations have to be integrated into, and with, the reservoir engineers' simulators, sometimes 2D but most often (massively) 3D. I have left out of these lists several things, for example passive seismic (which some would say offers, via attenuation measurements, information on reservoir permeability) and micro-seismic (the observation of seismic events associated with 'fracking'), also newer downhole methodologies such as cross-well seismic, microgravity etc.

The result is that a team of subsurface specialists - whether working on a basin, a prospect a discovery or a field - can in principle access very large amounts of different types of data, each requiring its own conditioning and analysis, before attempting to integrate these many strands into a coherent interpretation, certainly in three dimensions and possibly four. I say 'in principle' and 'attempting' because in reality - as stated earlier - the amount and diversity of data available to sub-surface specialists has outpaced the ability of their systems and workflow processes to manage, integrate and interpret it.

There is a lot missing!

Analysis and interpretation tends to depend either on a lowest-commondenominator (seismic interpretation) workstation or on specialist software operated by specialists. For example, a Major oil & gas company will have several hundred folk who can interpret a 3D seismic survey on a workstation (1. above), no more than a handful who can undertake the analysis to deliver any desired attribute (2. above).

I can count on the fingers of one hand the folk I know who could undertake 1., 2. and 3. above, in either Exploration or Reservoir Management. Of course, companies surmount this problem by having a team of petrotechs working on any one project.

However, any one project may be unique in terms of the data available and the analyses undertaken, meaning that the work processes and software used will be chosen a la carte and - pursuing the restaurant analogue - with every dish cooked by a different chef to a secret recipe!

View more quality content from Finding Petroleum

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Results may vary: Beware of kaleidoscopic vision in the oil and gas industry Written by Kurt Cobb from Resource Insights If you've ever looked at the elements that create the images in a kaleidoscope, they are unremarkable: pebbles, beads and bits of colored glass, all mixed together. But when seen through the viewing end of the device, this mixture creates the illusion of pleasing, colorful and multiple identical designs where, in fact, there are none. It's done with mirrors; and the illusion is convincing to the eye as it looks through the narrow tube that connects it with the mirrors and the colored items on the other end.

Like children looking through a kaleidoscope who are unaware of its actual workings, the media and the public have been misled into believing that early production results in the shale natural gas and tight oil formations in the United States will be repeated again and again across the United States and the world. This has led to exuberant forecasts of energy independence for the United States, an end to the dominance of OPEC in world oil supplies, and fossil fuel abundance for decades to come.

Two important trends cast doubt on this naive view. First, in the United States, home of the hydraulic fracturing "miracle," domestic natural gas production has been flat since January 2012. The shale gas revolution may well be over in the United States as the current production level becomes increasingly difficult to maintain in the face of ferocious decline rates for shale gas wells--rates that range between 79 to 95 percent after just three years according to a comprehensive survey of 65,000 oil and gas wells in 31 U.S. shale plays. This means that at least 79 percent of all shale gas production must be replaced every three years just to keep shale gas production flat!

With shale gas making up more than 34 percent of all U.S. production in 2011, merely keeping overall domestic production stable will be a formidable task and, given these decline rates, one with no historical precedent.

Further undermining the abundance narrative, U.S. crude oil production has gone almost flat since October 2012. This is not a long enough period to indicate anything definitive about the trajectory of domestic crude production. But, it comes at a time when reports from newer tight oil plays in Ohio and Colorado have proved hugely disappointing. Ohio pumped just 700,000 barrels of oil from its tight oil fields for all of 2012, an amount being pumped daily from the same kind of fields in North Dakota. In Colorado several years of development of tight oil have only been able to raise production statewide by about 100,000 barrels per day.

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The U.S. Energy Information Administration recently fanned the flames of exuberance once again with a recent reassessment of the potential for shale gas and tight oil production worldwide. Inattentive readers, however, might miss that this report referred to "technically recoverable" resources, ones that are thought to be recoverable using current technology, but not necessarily profitable to recover at current prices. In addition, the EIA was careful to point out that its estimates are highly uncertain and subject to change once actual drillbits provide better information where little currently exists. Beyond this, it is important to remember that "resources" refer to sketchy estimates of what might be in the ground whereas "reserves" are what can be extracted profitably at today's prices from known fields using existing technology. "Reserves" are and always have been only a tiny fraction of "resources."

Hapless journalists often fail to understand the difference as they did in this case.

A discreetly placed disclaimer reading "result may vary" often appears in television commercials showcasing people who've made millions following the investment advice being touted or who've lost scores of pounds using the exercise machine on offer. A more conspicuous "results may vary" warning ought to come with every new piece of information about the potential of this or that new shale gas or tight oil play.

If the U.S. experience is supposed to forecast the world, then the evidence so far suggests a boomlet followed by frantic efforts just to keep production level. But in some cases, such as Poland, the results have been far worse as heavily touted prospects have turned out to be duds.

View more quality content from Resource Insights

Is there a refinery in Batam's future?

Written by Ken Anderberg from AIM Communications The recent news that Azerbaijan, a major supplier of oil to Indonesia, is planning to build a US$4.8-billion oil refinery in Batam is just the latest in a string of similar announcements that have been made in recent years - with little investment actually happening. Two other partnerships also have laid out plans for Batam refineries,

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including a 300,000-barrel-per-day (bpd) facility at Tanjung Sauh.

In addition, China's Sinopec, Asia's top refiner, has begun work on an $850-million oil storage terminal - Southeast Asia's largest - on 360 hectares of land in Batam's Free Trade Zone. A refinery and petrochemical project are being considered in the second phase of the development.

Given that similar announcements in the past never materialized, there is some skepticism that the current news will pan out.

'My cynicism may be tiresome, but I would not be getting too carried away with these so-called plans,' says Gary Dean of Okusi Associates, a business consulting firm based in Singapore, and with offices in Batam and Jakarta. 'I've lost count of the number of petrochemical plants that have been 'planned' by well-dressed gentlemen from third-tier countries who've jetted into Jakarta for a few days.'

The Batam activity is part of an apparent major effort by the Indonesian government to make the country self-sufficient in its energy production. According to Energy and Minerals Resources minister Jero Wacik, the government had plans to build two 300,000 bpd refineries in East Kalimantan and a third in Palembang, South Sumatra.

The East Kalimantan projects were expected to be completed by 2019, while a 300,000 bpd refinery in Palembang was expected to start construction this year.

Two of those projects, however, have been bogged down as the result of failed negotiations between the Indonesian government and state oil and gas firm Pertamina and two would-be investment partners, Saudi Aramco and Kuwait Petroleum. Those discussions apparently broke down because incentives requested by the foreign investors could not be met.

Recently, Finance Ministry's fiscal agency chief Bambang Brodjonegoro said the government will likely reject fiscal incentives proposed by those foreign investors, despite the lack of capacity of existing domestic refineries to process crude oil. He said his office would recommend the government build its own refineries rather than providing unrealistically huge incentives for foreign firms to do so.

'We strongly deem the incentive package currently proposed is just too much,' he said.

Both Kuwait Petroleum and Saudi Aramco have reportedly demanded a tax holiday for up to 30 years, in addition to an incentive of a price premium for the crude oil supplied to the refineries. The Saudi and Kuwaiti companies also demanded exemption of import duty.

Pertamina chose Kuwait Petroleum as its partner to build a refinery with a fuel production capacity of 300,000 barrels per day (bpd), which would be built in Balongan, West Java, near Pertamina's existing refinery. The crude oil would be provided by Kuwait Petroleum.

In addition, Pertamina selected Saudi Aramco to construct another fuel-processing plant with a production capacity of 300,000 bpd of fuel, which was projected to be

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located either in Tuban, East Java or in Bontang, East Kalimantan.

Those two refineries require a combined investment of around US$20 billion, and were expected to begin operations in 2018.

Bambang said that his agency would not give the incentives the foreign firms had been requesting and that 'if they do not change their position, then it will be difficult for us to approve the request.'

He said their request for a 30-year tax holiday was unrealistically high, as the existing tax breaks given by the government lasted only up to 10 years. 'Therefore, we are pushing to build our own refinery,' he said. 'It is better for us to build one refinery instead of nothing.'

Evita Legowo, who is in charge of oil and gas exhanges at the ministry, agreed. She said the government decided to build the new refinery itself because the demands of investors, such as Saudi Aramco and Kuwait Petroleum, could not be met.

'Even though it is using our own capital, if there are any investors interested in contributing capital, they are welcome to do so, as long as they follow our rules,' Legowo said. She added that Rp 90 trillion was a huge sum and therefore the construction needed to take place in phases.

If the Kuwait Petroleum and Saudi Aramco offers are denied, however, the government might be left with only a single refinery project, one that is entirely funded by the state budget. That project is set to begin in 2015, and the government has allocated Rp 17 billion ($1.7 million) in this year's budget for a feasibility study and another Rp 250 billion for preliminary design. Construction will cost Rp 90 trillion and would be completed in 2018.

The government acknowledges that the profitability of the project is the least of its priorities, said Edi Hermantoro, the director general for oil and gas at the Energy and Mineral Resources Ministry.

'The main idea [of refineries] projects is to meet domestic need,' Edi said.

Indonesia's crude oil resources have slowly been declining in the past 20 years. As of 2011, the nation had 4 billion barrels of oil in reserves, compared to 5.1 billion barrels in 2001 and 5.9 billion barrels in 1991, according to BP in its 2012 Statistical Review of World Energy report.

Malaysia, by comparison, has been increasing its oil reserves, to 5.9 billion barrels in 2011 from 3.7 billion barrels 20 years earlier.

Indonesia's average daily oil output last year was around 840,000 barrels, of which Pertamina's own production was 196,000 barrels per day. The government gets around 85% of oil output produced by private firms, based on the production-sharing contract scheme.

Susilo Siswoutomo, deputy energy and mineral resources minister, said that only

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650,000 barrels per day of crude oil can be processed into gasoline or diesel fuel domestically, and the country needs to import 400,000 barrels of gasoline and diesel to meet local demand.

While Indonesia's refining capacity remains stagnant, consumption has increased significantly.

Part of the reason for the rise in fuel use has been the surge in demand for cars and motorcycles of the past few years, as low borrowing costs and easy down payments made vehicles more affordable to purchase. Car sales topped 1 million units for the first time last year.

About 9.6 million passenger cars were on the road in 2011, an almost threefold increase from 2001, while there were almost 69 million motorcycles, up 350% in the same period.

Consumption in Indonesia climbed to 44 million metric tons of oil equivalent in 2011 from 16.8 million tons in 2001, BP data show.

Imports of petroleum products, including fuel, amounted to $7.3 billion in the first quarter of this year, which led to a current account deficit of $5.3 billion, according to Central Statistics Agency data.

Despite the increase in domestic fuel use, t he last refinery built in Indonesia went on line in 1994, a Pertamina facility in Balongan, West Java. Currently, Pertamina has six refineries operating in Indonesia, producing up to 700,000 bpd of refined fuels.

They are located in Balikpapan, East Kalimantan; Balongan, West Java; Cilacap, Central Java; Dumai, Riau; Kasim, West Papua; and Plaju, South Sumatra.

According to government sources, Indonesia needs at least three new oil refineries in order to bolster the nation's fuel stockpile and ease pressure on the national budget. The refineries will enable the country to cut fuel subsidy spending because the country will no longer need to import fuel.

Current Indonesian refinery production is unable to meet the country's gasoline demand of 1.16 million bpd, resulting in the importing of gasoline to meet the country's needs. Enter Batam as a fertile location for new oil-processing facilities.

The government of Azerbaijan is just the latest entry into the Batam refinery sweepstakes.

'Our state oil company, SOCAR, is in negotiations with Indonesia's OSO Group to build a large oil refinery in Batam,' Azerbaijani Ambassador to Indonesia Tamerlan Karayev recently told The Jakarta Post. 'There is no final decision yet on the project; it is being considered,' he added.

The project details were first unveiled by the OSO Group's CEO, Mariano Asril, in October. OSO would build the 600,000-bpd, $4.8-billion facility in a joint venture with SOCAR, he said. Funding and crude oil would be provided by Azerbaijan, with the project set for completion in 2017. OSO Group is expected to ask for incentives,

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however, perhaps killing the project before it gets off the ground.

Currently, Azerbaijan, an oil-rich nation in South Caucasus, exports around $2 billion worth of oil to Indonesia, $1.23 billion exported directly and the rest via Singapore and other countries.

Meanwhile, Indonesia's Setdco Group and its partner PT Intan Megah have sought permission to build a 300,000-bpd refinery at Tanjung Sauh on Batam.

'The crude oil will be from the Middle East,' said Legowo. She added the government is still in the process of issuing a permit for the development of the planned refinery.

Previously, Gulf Petroleum Ltd., Qatar's largest oil company, announced plans to build a refinery on Batam. Gulf Petroleum was preparing documents needed to seek an investment license from the Indonesian government, but the project still has not materialized.

Gulf Petroleum president Abdul Aziz Abdulaimi and PT Batam Sentralindo president Bang Hawana signed a memorandum of understanding on the project. The Batam Free Trade Zone also had agreed to provide a 250-hectare plot of land for the refinery project, which planned to sell its products in Indonesia and other Southeast Asia nations.

None of the recent refinery announcements indicated how many people would be needed to build the facilities, and only one estimated how many full-time workers would be needed (30). In addition, there is no word as yet as to which companies currently operating in Batam might participate in the engineering and construction of the projects.

For comparison, a similar-sized refinery proposed for South Dakota in the U.S. would need 4,500 construction workers for 4-5 years, and would create 1,800 high paying permanent jobs. For each of those jobs created, economists anticipate that there will be three jobs for each one of those jobs.

A Chevron refinery on 1,200 hectares in Richmond, California, employs more than 1,200 workers. The refinery processes approximately 240,000 barrels of crude oil a day.

While skepticism may be the norm for many Indonesia experts regarding proposed projects in Indonesia, the fact that Asia's top refiner, China's Sinopec, has already started work to build Southeast Asia's largest oil storage terminal at the Batam Free Trade Zone cannot be overlooked; after all, it is an $850-million project.

Sinopec Kantons Holdings, a unit of the Sinopec Group, will hold a stake of 95% in the PT West Point Terminal project covering the construction of storage for up to 16 million barrels of crude and refined fuels, the company told the Hong Kong Exchange. This would be Sinopec's first facility of such a size near Singapore, Asia's oil trading hub, where the Chinese refiner has established its presence over the past 15 years.

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But Sinopec's Batam presence may not signal a refinery is coming to the island any time soon.

'Sinopec has a trading presence in Singapore and I imagine having a storage terminal in Batam, bordering Singapore, would be used to support their trading activity in the region,' said Victor Shum, managing director at IHS Purvin and Gertz in Singapore.

'For the moment, the immediate priority is to get the storage facility built, the refining and petrochemical projects are not at the execution phase yet,' said a second industry official.

The project edges the Chinese oil major closer to domestic rival PetroChina, Asia's largest producer of oil and gas, which has a stake of 35% in the 14-million-barrel Universal Oil Terminal on Singapore's Jurong Island. The new storage facility is likely to take between 18 and 24 months to build, industry sources said.

Whether Sinpac's presence signals that the latest round of refinery proposals will actually result in any deal being approved by the Indonesian government is anyone's guess. There are many government and financing obstacles to overcome, and recent history has not shown that the government is willing, or able, to provide the incentives necessary to make such huge investments viable for foreign firms. As Gary dean says, there is ample reason for cynicism.

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A futures market for North American LNG exports?

Written by Keith Schaefer from Oil & Gas Investments Bulletin Japan spent US$75.4 billion on LNG last year, paying an average price of US$16.60 per million BTU—while gas prices in the United States averaged just US$2.75. No Japanese politician, economist, or grocer thinks that makes sense. So Asia is trying

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to lower prices for Liquefied Natural Gas (LNG) as fast as they can.

Basic supply-demand theory says the pending flood of new supply from around the globe will push prices down over time. But lower prices aren’t just about supply-side growth.

They’re also about transparency.

LNG prices have long been linked to the price of oil—with gas priced at roughly 13% or 1/8th the price of Brent, with the details determined in confidential contract negotiations. Asian consumers are tired of this linkage, especially since it has meant prices that are four times higher in Asia than in North America.

It’s a fact that de-linking LNG prices from oil to Henry Hub makes a BIG difference for Asian buyers. For example Cheniere agreed to sell 1.6 to 1.8 mtpa to Korean Gas for US$3 per MMBTU plus a 15% premium to Henry Hub prices.

Context: On April 30, 13% of Brent would equal $13.47/mcf. On the same day the Cheniere deal would have Korean Gas paying ~$7.51/mcf. That’s a big difference!

Cheniere has signed similar Henry Hub-indexed deals with three other buyers.

But Asia doesn’t just want lower prices in individual deals. No, Asian buyers want the market to determine how much LNG is worth –they are convinced the market will push LNG prices down fast with waves of new supply on the horizon.

They may or may not be right on this one.

Futures contracts are the way markets determine how much a commodity is worth.

For LNG such a system would also improve the credibility of pricing information and act as a valuable hedging tool.

Japan is pushing for a futures market for LNG—and the potential Canadian supply could be the first to get priced this way.

It’s not just talk. In March Japan’s Ministry of Economy, Trade, and Industry (METI) announced plans to launch the first LNG futures contract at the Tokyo Commodity Exchange in two stages starting in 2014.

The first step would be a cash-settled contract, with settlements based on the spot price on the last session of the month. These cash-settled futures could be sold up to one year forward and would be based in US dollars and metric tonnes.

When I heard this, I called Dan Dicker in New York, former floor trader and author of Oil’s Endless Bid—the best book I ever read about the financialization of commodity prices and what it means for retail consumers (it means higher prices and more money out of our pockets).

My overall question was—would a futures market lower prices? Or would the financialization of LNG do what it did for oil: create endless bids and higher prices?

The short answer on both was no.

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“Creating a futures market won’t help create a cheaper pricing mechanism,” he told me. “Yes, it’s going to be less related to Brent and more to nat gas—but more to local/Asian nat gas, where prices are high—not North American natural gas. If I was trading physical, that’s how I would expect the new market to react.”

Dicker is the kind of trader who would play in a LNG futures market – and he thinks Asian prices would stay high.

The problem is that a commodity market needs a full complement of players.

Producers, wanting high prices, are already long in an emerging futures market. To counter, LNG buyers are naturally on the short side. Then traders enter the scene, playing the difference and speculating on the actual supply-demand situation.

Dicker says it took years for this financialization of natural gas to take hold in the US and it was the investment banks who added enough outside players to make that happen.

Japan may want free market LNG, but to financialize LNG it will need a bigger playing field.

Japan has a natural market of LNG buyers—the country’s utilities. What Japan doesn’t have is a natural market of sellers – they don’t have a large homogeneous group of providers, like the United States has with its oil producers.

So the question is: Could financialization of LNG give rise to an endless bid cycle?

Might Japan be putting the cart before the horse?

Not only are the players lacking, but Japan’s proposal has some gaping holes. For one, the futures LNG market it imagines would be for true physical delivery— buyers would actually want to take possession of LNG. In the US, the futures almost never become physical – which is the case with most futures markets. So they – Henry Hub and Japan’s LNG proposal – are very different markets. And there’s little in the way of a blueprint for Japan’s version.

That doesn’t mean we don’t need a better pricing mechanism for LNG. The growing spot market desperately wants one.

The spot LNG market is growing, and fast. Spot trades grew from 10% of global LNG trade in 2003 to 25% in 2011, and volumes continue to climb.

There’s a good reason the spot market is hopping – buyers and sellers want more options. A natural disaster here, a hurricane there – LNG needs can change quickly and so supply flexibility is an increasingly important concept in the LNG world.

For a spot market to hop, however, requires a recognized and reputable spot price…such as a futures market.

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It’s a chicken-or-egg scenario, for sure.

While Japan’s futures market could start next year, it will still take years for global LNG prices to break free from oil indexes and secretive long-term contracts. The next wave of LNG supply to come online will be in Australia, in 2015—and they have sold their gas in long-term contracts at oil-indexed prices.

But the system will change, eventually, because LNG is outgrowing its pricing and trade systems. Such is the cost of success.

It will be very interesting to see how it all pans out – and how LNG proposals in Canada react.

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Exploiting deep water fields ....it's not as easy as explorers think!

London, 19 Sep 2013 Exploring internationally for unconventional oil and gas .......finding the "sweet spots" London, 02 Oct 2013 Applied Deepwater Exploration One day training course London, 09 Oct 2013 Finding petroleum in the South Atlantic ...if there's any left to find!

London, 05 Nov 2013 New technologies for describing and monitoring reservoirs get to know your reservoir better!

London, 26 Nov 2013

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Will Israel's rush to export natural gas turn out to be a mistake?

Written by Kurt Cobb from Resource Insights As the United States contemplates exporting natural gas to the rest of the world, previously energy-poor Israel seems about to jump on the export bandwagon. The current government is seeking approval to export about 40 percent of the production from its newly discovered offshore natural gas fields.

In an era of high volatility in energy prices and supplies and in a country surrounded by unfriendly neighbors, one would think that Israel would want to keep this valuable energy prize all to itself. Current estimates suggest that the remaining 60 percent of production will allow Israel to supply all its needs for 25 years.

My question is: What will the country do after that? Presumably it will need natural gas after 25 years. And, what if estimated reserves turn out to be too optimistic and the supply doesn't last that long? No one really knows what's in a reservoir until it is actually produced.

What if the current steep rise in the rate of natural gas consumption continues for a number of years? Estimates stated in years of supply are usually based on the current rate of consumption. But if the rate of natural gas consumption continues to accelerate, the 25-year supply will shrink to a fraction of that number and the inevitable peak in production from these fields will occur even sooner. Moreover, additional supplies are unlikely to come--at least at favorable prices--from any of Israel's neighbors.

Wouldn't Israel benefit from maintaining a lower rate of natural gas production in line with its domestic needs so as to stretch out supplies as long as possible? Of course, it would. The country's energy security would be greatly enhanced if its natural gas supply could be assured for, say, 40 years instead of 25 (though the period is likely to be quite bit less if consumption continues to rise).

So, who benefits from overproducing natural gas for export? The private companies involved in the drilling and extraction of the gas, of course. It is in their interest to produce as much as they can as soon as they can in order to reward their management and stockholders. As if to put an exclamation point on this interpretation, Bloomberg reported that one of the partners in the project, Delek Group Ltd., is swimming in debt and desperately needs the extra sales that exports represent to make its debt payments.

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Though the Israeli Parliament is expected to act on the proposal to export natural gas, it could just as easily pass legislation that would restrict flow rates from these reservoirs. For a country as sensitive about its security as Israel, it is surprising that no apparent consideration has been given to this approach.

There are dissenting voices. But my guess is that the interests of the private companies involved in natural gas exploration and production will be given precedence over the long-term security needs of Israel. And, I expect this to happen very shortly.

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Review: Kuwait - A mature industry stands at a juncture Written by Richie Ethrington from Finding Petroleum The Gulf state of Kuwait has a history in the oil industry which dates back to 1938, when oil was first discovered in the country's Burgan field. Since then, a lot has changed - except for the fact that 'Burgan No.1', the well which witnessed the birth of the industry in Kuwait, is still producing to this day. Over the years, Kuwait has established itself as a permanent fixture near the top of the oil industry rankings in term of both reserves, production, and exports. Indeed, the country is home to the world's sixth largest quantity of proven oil reserves (fourth in OPEC) and it is one of the ten largest exporters of total oil product. These factors combined help to make it a global heavyweight in the oil industry- albeit one which sits at a juncture in its future outlook.

A look at the numbers shows us that as of January 2011, Kuwait was home to an estimated 101.5 billion barrels (bbl) of proven oil reserves, which equates to around 7% of the world's total - according to the Oil & Gas Journal. But that is not all‌ There are additional reserves located in the Partitioned Neutral Zone (or as it is more

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commonly known, the Divided Zone), which sits between, and is controlled equally by, Kuwait and Saudi Arabia. The Zone has proven oil reserves totalling 5bbl, which brings Kuwait's total oil reserves tally to just over 106bbl. But not everyone agrees with these figures. At the more pessimistic end of the spectrum, some estimates put Kuwait's total reserves at as low as 48bbl - less than half the official tally.

As of the end of 2010, the country's oil output totalled around 2.5 million barrels per day (bbl/d), including its share of approximately 250,000 bbl/d production from the Divided Zone. Of the country's 2010 production, the split was estimated to be 2.3 million bbl/d crude oil and 200,000 bbl/d non-crude liquids. In terms of where the production was coming from, the lion's share came in 2010 came from the Southeast of the country where the Burgan field can be found. While production from the North continues to increase, it still has come catching up to do with the South.

As a signed-up Organisation of Petroleum Exporting Countries (OPEC) member state, Kuwait's total production is constrained by the international group's production targets. In 2010 this translated into the country maintaining around 320,000 bbl/d of spare crude oil production capacity. In early 2011, as one of the few OPEC members with spare capacity, Kuwait has increased oil production to compensate for the loss of Libyan supplies. The country's peak capacity presently sits at around 3.1 million bbl/d but that figure looks to be heading North over the coming years. Indeed according to reports by the KUNA news agency, citing a study by Kuwait-based Diplomatic Centre for Strategic Studies (DCSS), Kuwait's oil production capacity is expected to increase to nearly 3.6 million bbl/d by the end of 2022. How so? Through a focus on the development of unexploited heavy oil reserves and projects to maintain output from existing and mature fields. The Northern region of the country is expected to be an area of growing focus in the pursuit of this gain.

To fully understand the future development of the oil industry in Kuwait, we first need to understand its past. The most significant event in the formation of the modern day Kuwaiti oil sector came back in December 1975 when the industry was nationalised.

Using the same model successfully applied by all of the other Arab oil-producing states around it, Kuwait began negotiations at the start of the 1970s to restore control over its own natural oil resources. Prior to this date, overseas players had a major influence in the country under the first Kuwait Oil Concession Agreement, inked in 1934. Indeed, the powerful Kuwait Oil Company (KOC) was originally formed by the combination of Gulf Oil Corporation (now Chevron Oil) and the AngloPersian Oil Company (now British Petroleum). The State's shareholding in the firm was progressively increased until full control was achieved. Later on in 1980, the Kuwait Petroleum Corporation (KPC) was established in 1980 to bring together the four state-owned companies responsible for Kuwait's oil production, processing and transportation (which included KOC) under one umbrella company. Today, KPC oversees a fully integrated industry with operations spanning six continents, with the government owning and controlling all development of the oil sector. Within this, the Supreme Petroleum Council (SPC) oversees Kuwait's oil sector and sets oil policy.

The SPC is headed by the Prime Minister. The Ministry of Petroleum, meanwhile, supervises all aspects of policy implementation in the upstream and downstream portions of both the oil and natural gas sectors.

Despite its long-history of strained relationships with overseas players, this is not to

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say that the government of Kuwait is not interested in attracting foreign firms to work with in the country in the future. To the contrary, in order to boost production and meet its bulging targets, the Gulf state has started to build relations with a number of international oil companies which possesses the expertise and technical capabilities to raise output from mature fields through a process known as enhanced oil recovery (EOR). Indeed as recently as June 2012, Sami a-Rushaid, Kuwait Oil Company (KOC)'s managing director, informed old attendees at a London conference that they were in communication with a series of international firms. Among the names mentioned were Western industry behemoths such as ExxonMobil, BP, Chevron, and Total.

Alike a number of its oil producing peers, Kuwait's economy is heavily dependent on oil revenues. Export revenues account for over half of its overall gross domestic product (GDP), 95% of total export earnings, and 95% of government revenues. By unilaterally looking on one sector for such a large proportion of its revenues, Kuwait is playing a dangerous game, with dependence on the black gold leading to high volatility in the country's export revenues. With the consensus at the time of writing being that the global economic outlook remains uncertain, and a slowdown in growth widely predicted for the 2013 full-year, further downside risks could materialise.

These could in turn slow demand for Kuwait's oil exports. The state knows this better than anyone, of course, and is always looking to diversify its revenue streams through the vehicle of its active sovereign-wealth fund, the Kuwait Investment Authority, which oversees all state expenditures and international investments. In addition, Kuwait also allocates 10% percent of its state revenues into the Reserve Fund for Future Generations (RFFG), for the day when oil income starts to decline.

Despite complete control over its oil industry, Kuwait has not prospered in the same way as some of its oil-rich peers have. In an attempt to put this to right, Ministers in Kuwait unveiled a plan in April 2013 to overhaul the nation's oil industry in a bid to bring its economic fortunes more into line with those of its neighbours, such as the United Arab Emirates (UAE), Saudi Arabia, and Qatar. While Kuwait's oil wealth has helped transform the country, the rate of development has been slower than elsewhere. This has left Kuwait in a position where it ranks as the least popular destination in the GCC (Gulf Cooperation Council) for foreign investment. It also scored lowest in the region on the World Bank's ease of doing business index for 2012.

However, it is not all bad news for the oil sector in Kuwait. There are plenty of opportunities for upside in the sector too - especially with sanctions on Iran's oil trade set to continue for the remainder of 2013, and perhaps beyond. Kuwait sits well placed to take advantage of reduced availability of Iranian export volumes. What is more, strengthening ties with oil-hungry China have seen Kuwait's crude oil exports to Asia's largest economy increase at a rapid pace. According to Kuwait News Agency (KUNA) reports, total exports to China rose by 31.5% year-on-year to around 207,000 bbl/d, or 847,000 tonnes as of the end of March 2013. Meanwhile from the opposite end of the trade agreement, Chinese General Administration of Customs data shows that Kuwait's slice of the country's total crude oil pie rose to 3.7% in April 2013 from 2.9% in April 2012.

While the improving export figures created by Iran's own diminished exports and

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Kuwait's increasingly important ties with China may prove to be the focus in the nearterm, it seems the long-term future of the oil industry in Kuwait may hang on the hopes of the shale oil sub-sector. In the same way that the shale industry has provided the North American oil sector with a renewed energy over recent years, it is hoped it will have the same impact in Kuwait, where the issue of maturing fields and subsequently long-term sustainability is becoming increasingly acute.

Pencilled in for release in early 2014 - at a time when energy producers in the region are continuing to readdress their strategy - are the results for KOC's results from a planned study of the country's shale oil potential by early 2014. With Kuwait targeting sharp production increases by 2022 and beyond, tapping into the country's shale oil prospects may become an attractive option if sizable resources are confirmed. In the long-run, raising overall output will require gains that are sufficient to offset declines elsewhere. Indeed, new investment will be critical to ensuring reliable supplies, with the majority of Kuwait's current production derived from mature fields discovered in the 1930s and 1950s.

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Additional Iranian oil sanctions may be counterproductive Written by Gail Tverberg from Our Finite World A June 6, 2013, article from Reuters is titled, “Lawmakers in new drive to slash Iran’s oil sales to a trickle.” According to it, U.S. lawmakers are embarking this summer on a campaign to deal a deeper blow to Iran’s diminishing oil exports, and while they are still working out the details, analysts say the ultimate goal could be a near total cut-off.

My concern is that the new sanctions, if they work, will put the United States and

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Europe in a worse financial position than they were before the sanctions, mostly because of a spike in oil prices.

How much reduction in oil exports are we talking about? According to both the EIA and BP, Iranian oil exports were in the 2.5 million barrels a day range, for most years in the 1992 to 2011 period. In 2012, Iran’s oil exports dropped to 1.7 or 1.8 million barrels a day. Recent data from OPEC suggests Iranian oil exports (crude + products) have recently dropped to about 1.5 million barrels a day in May 2013.

Figure 1. Iranian oil exports, based on BP and on EIA data.

If the ultimate goal is “close to total cut-off,” an obvious question we should be asking ourselves is whether it makes sense to handicap world oil production by close to 2.5 million barrels relative to 2011, or close to 1.5 million barrels relative to May 2013.

Oil prices have spiked in the past when there has been an interruption in world oil supply. Why wouldn’t they this time? Furthermore, who are really handicapping: Ourselves or Iran?

Possible Alternative Sources of Oil Supply I would argue that we do not have adequate sources of backup oil supply. We are operating too “close to the edge” when it comes to world oil capacity.

Saudi Arabia likely has some spare capacity. If we go by how much Saudi Arabia in the recent past has been able to increase its production, its short-term spare capacity would appear to be about 600,000 barrels a day–not nearly enough to offset the decline in Iran’s oil exports. The 600,000 barrels a day is calculated by comparing Saudi Arabia’s highest production for individual months of 2012 of 10.0 million barrels of oil a day with its actual production in May 2013 of 9.4 million barrels a day, according to the OPEC’s Monthly Oil Market Report (MOMR). Saudi Arabia claims to have capacity of 12.5 million barrels a day, but its production in recent years has never been anywhere near its claimed capacity, raising questions about the truthfulness of the claim.

How about exports from Iraq? This is a graph of oil exports from Iraq, based on EIA data.

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Figure 2. Iraq oil exports, based on EIA production and consumption data.

Iraq is indeed adding a little bit to world oil exports–about 326,000 barrels a day in oil exports were added in 2012. But the wild fluctuations don’t provide confidence the trend will continue. It is possible to get a rough idea of what future increases in oil exports might amount to. The International Energy Agency (IEA) is targeting 6 million barrels a day of oil extraction for Iraq by 2020. (Dave Summers–also known as Heading Out–isn’t confident even this can be achieved.) Extraction at this level would mean oil exports of about 4.5 million barrels a day in 2020. The expected annual growth in exports from today’s 2.2 million barrels a day of oil exports would be about 283,000 barrels a year, between now and 2020. Even if this rate of increase in oil exports is achieved, it won’t handle the immediate need for close to 1.5 million barrels a day of oil exports if Iranian exports are taken out of the world supply.

How about the supposedly miraculous growth in US oil supplies? If we look at the actual data, we see that the United States is still a major oil importer, even when such sources as “biofuels” are included in the total. (Imports are the gap between the ”consumption” and “production” lines.)

Figure 3: US Liquids (oil including natural gas liquids, “refinery expansion” and biofuels) production and consumption, based on data of the EIA.

At the same time, Europe keeps falling behind farther, so it needs increasing amounts of imports.

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Figure 4: European Liquids (oil including natural gas liquids, “refinery expansion” and biofuels) production and consumption, based on data of the EIA.

Thus, even if the US’ need for imports is declining, Europe’s need for imports is increasing, as is the need for imports to Asia, including China and India. Losing part of the world’s oil supply makes it harder to get enough imports, without oil prices spiking again.

If Oil Supply Cushion is Less Suppose that we somehow, miraculously, take Iranian oil exports off-line and find enough substitute supply without oil prices spiking too badly. We know too well from experience that there is the distinct possibility that part of current oil supply will later be taken off-line, for some unplanned reason. This might be another Arab Spring revolution, or perhaps fighting may break out between two oil producers. Or the United States may have a bad hurricane season. So even if oil prices don’t spike immediately, removing what little spare capacity there is, increases the likelihood that oil prices will spike in the future, from some unrelated cause.

Who gets hurt with an oil price spike?

The countries that are most hurt by high oil prices are the big oil importers–the United States, the European Union, and Japan. We can see this with recent experience, shown in Figure 6 below. Oil prices have been high since 2005. These high oil prices have led to a cutback in consumption by oil importers, even as other countries more-or-less sailed along. The countries with lower oil consumption since 2005 are precisely the ones that have had problem with recession. See my post, Peak Oil Demand is Already a Huge Problem.

Figure 5. Oil consumption based on BP’s 2013 Statistical Review of World Energy.

If oil prices rise, more money will be transferred from oil importers to oil exporters. Oil exporters, such as the members of OPEC, will benefit. Of course, Iran itself will not

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benefit. Oil importing countries that have been having trouble with their debt loads are likely to have even more difficulty, because their citizens are made poorer by high oil prices.

How Badly Do Sanctions Really Hurt Iran?

The sanctions cause Iran to leave its oil in the ground until later. While this hurts the Iranian economy now, the oil will still be there for extraction later. With the fields “rested,” Iran may even be able to increase the amount that can be extracted later. If oil prices are higher later, Iran will get the benefit of the higher prices. The oil supplies of other countries will also be more depleted then, so it will have more of an advantage than it does now.

With all of the sanctions against Iran, the country has been encouraged to ramp up its natural gas production. It has also increased its fleet of natural gas-powered cars, so that it has more such cars than any other country in the world. Iran is also refining more of its oil, making itself less dependent on gasoline imports. Making these changes now makes Iran more self-reliant in the long-run.

A person might think that all of the sanctions to date have significantly reduced the standard of living of a typical Iranian. If this is true, it is not showing up much in the data. Prior to 2012, the economy had grown consistently for two decades. The sanctions led to an estimated decline in real GDP of -1.9% in 2012, according to the CIA World Fact Book. Iran’s per capita use of energy has been rising, and continues to do so, even in 2012. Its per capita energy use is now higher than Italy’s.

Figure 6. Per capita energy consumption for Italy and Iran, based on BP total primary energy consumption from 2013 Statistical Review of World Energy, and EIA population data.

There are obviously any number of other countries that Iran’s energy consumption could be compared to. If we compare Iran’s energy consumption to Israel, Iran’s per capita energy consumption is a little lower.

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Figure 7. Per capita energy consumption for Israel and Iran, based on BP total primary energy consumption from 2013 Statistical Review of World Energy, and EIA population data.

Messing with Iran’s Currency According to Bloomberg News, Useless Rial Is U.S. Goal in New Iran Sanctions, Treasury Says. According to the article: “The idea is to cause depreciation of the rial and make it unusable in international commerce,” he said. “On July 1 we will have the ability to impose sanctions on any foreign bank that exchanges rial to any other currency or that holds rial-denominated accounts.”

The move is intended to toughen sanctions that so far failed to press the Islamic republic to halt its nuclear program. According to the Treasury, the rial has lost more than two-thirds of its value in the past two years, trading at 36,000 per U.S. dollar as of April 30, compared with 16,000 at the start of 2012.

Interesting! Isn’t devaluing the currency exactly what Japan and all of the countries doing Quantitative Easing have been trying to do, perhaps to a lesser degree? As a result, Iran’s stock market has been soaring. Iran is a country that has two export products that other countries want to buy: oil and natural gas. It has little debt, and in the past has been running a budget surplus. Making more rial to the dollar makes imports to Iran more expensive, but exports more competitive in the world marketplace. This is precisely what other countries have been trying to accomplish.

I am skeptical this rial marginalization will work. Will these changes make any difference, in terms of trade with China and Russia? For that matter, will countries that want to buy natural gas from Iran stop trading with Iran? There are ways around any barriers we put up. The US dollar is the world’s reserve currency, but it is already under pressure in that role. Doesn’t all of this messing with the rial lead to more pressure to move away from the US dollar in its role as a reserve currency?

Countries that have products to sell that are in short supply globally can usually find a way to sell them. The countries that seem to have much worse problems are those with nothing that the rest of the world wants to buy–Greece, Spain, etc.

Conclusion All of this posturing looks like a power struggle between the East and the West. The techniques the West has been using so far haven’t been working all that well. The plan is to step up the same techniques, in the hope they will work better. It is not all that clear that they will–if they work, they may quite possibly backfire, because we

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OilVoice Magazine | JULY 2013

are working with world oil supply, in a world where oil supply is still constrained.

Reducing world oil supply by the amount of Iran’s oil exports doesn’t help the West at all.

There have been a lot of exaggerated reports, seeming to suggest all is right now with world oil supply. The danger is that US leaders are now starting to believe what they read.Supply is now available, because of high price. Price is high because of the problem of diminishing returns leading to ever higher prices required to make oil extraction profitable for exporters. Demand is now down in the West, because high prices are leading to job loss and recessionary forces there. Pushing the world further in this direction is hardly helpful.

If we are very lucky, the United States’ stepped up sanctions could get Iran to back down on its nuclear weapons program (assuming it has one). But if we are less lucky, we may find ourselves with spiking oil prices. To make things worse, we may see the role of the United States dollar as the world’s reserve currency destabilized.

It seems to me that we are playing with fire.

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OilVoice Magazine | JULY 2013

Poland's shale gas future going up in smoke?

Written by Mark Young from Evaluate Energy In September 2011, Poland was riding a wave of optimism as state-owned PGNiG lit a flare at the site of its Lubucino-1 well, becoming the first company to extract shale gas in the highly prospective country. This feat, coupled with the high reserves estimates from various sources worldwide meant the energy future for the nation looked positive. Poland appeared to be the country that would lead Europe into a shale gas fuelled future, gaining its independence from the Russian supply monopoly it has been craving for years, but it has been a torrent of bad news ever since. And with recent developments, it appears that bad luck with drilling results is not the only reason things are beginning to go wrong, as Poland may well be shooting itself in the foot.

This week, the Warsaw Business Journal reported that Chevron (CVX) was considering its position in the country as the current state of Polish Oil & Gas legislation would mean the company cannot work to its planned programme without applying for another license at a certain stage, and is pushing for changes to be implemented before the end of 2013. A withdrawal would make Chevron the fourth US shale giant to have pulled out of the country within a year, and for a third different reason.

ExxonMobil (XOM), only nine months after PGNiG’s flaring ceremony, decided two unsuccessful wells and lack of economic promise in further areas was enough for it to withdraw. Talisman Energy (TLM) became the second company to leave following a shift in company focus, completing the sale of its assets to slowly emerging player San Leon Energy (SLE) in May 2013. In the same month, Marathon Oil (MRO) has also initiated proceedings to sell its licenses by 2014, another company citing disappointing well results.

Up to now, Chevron has been determined to continue with Polish operations, and remains arguably the major, non-state owned, driving force in the nascent European shale and unconventional gas market, with other interests in Bulgaria, Lithuania, Romania and Ukraine. If Polish legislation continues to alienate experienced foreign investment, as appears to be happening with Chevron, alongside these disappointing drilling results, then the expertise garnered by companies in the US shale revolution will be near impossible for Poland to take advantage of and development will be markedly slower, as the smaller and/or less experienced companies still involved may be forced to reinvent the wheel, so to speak.

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OilVoice Magazine | JULY 2013

Legislation has been a stumbling block ever since foreign companies began to express interest in the licenses being made available. In March 2013, a long-awaited shale gas tax draft was finally implemented after a six month delay after first being announced (and almost six years after Poland’s first shale gas license was awarded back in 2007), with the aim of positioning Poland as a more attractive investment opportunity than rival markets; it was arguably the delay that made greater headlines than the actual laws. This stands Poland in stark contrast to the UK, where within the first four months following the shale gas moratorium being lifted in December 2012, a new government agency for shale gas was set up, tax breaks were introduced and safety and planning systems were put in place, to name just a few forward steps being quickly made.

Poland clearly can’t be held responsible for unimpressive well results, the explicit reason behind two of the three withdrawals so far, with Talisman’s reason being a bit too vague to jump to a definite conclusion. But more work may well be needed on its oil and gas laws and regulations to keep hold of the much needed expertise and determination of major players like Chevron, so that Poland can quickly and efficiently reach the independence from Russia it is so desperately seeking.

Chevron’s progress in Poland and across its other European shale and unconventional licenses can be tracked using Evaluate Energy’s assets database and emerging shale offering. Evaluate Energy delivers efficient data solutions for worldwide oil and gas company analysis, also providing company financial and operating data and an extensive M&A database.

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