OilVoice Magazine | December 2012

Edition Nine – December 2012

Did oil decide the last three American elections?

LNG in Asia: Let the renegotiations begin International labour implications of the China shale plays

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OilVoice Magazine | DECEMBER 2012

Adam Marmaras Chief Executive Officer Issue 9 – December 2012 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 Chief Executive Officer Adam Marmaras Email: adam@oilvoice.com Social Network Facebook Twitter Google+ Linked In Read on your iPad You can open PDF documents, such as a PDF attached to an email, with iBooks.

Welcome the ninth edition of the OilVoice magazine.

This year has been a fantastic year for OilVoice. Our content and readership has grown month on month.

It's always rewarding when I'm at an industry event and someone remarks "I check OilVoice every day". It puts a human face on our audience. We study the traffic numbers religiously, but it's easy to forget that these numbers are real people who rely on the site for news and information.

Meeting you in person makes running the site a lot more worthwhile.

One area of notable growth this year has been the jobs board. We've continually tweaked and improved it, and it now carries a total of 800 active oil and gas jobs for you to browse. So if you're thinking of a career change in 2013 it's a great place to look.

Enjoy the ninth edition of the magazine. We have some advertising slots available if you'd like to run an advert. Our editions are digital only (no printing costs) so we're able to offer very favourable advertising rates.

Happy Holidays!

Adam Marmaras CEO OilVoice

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OilVoice Magazine | DECEMBER 2012

Contents Featured Authors Biographies of this months featured authors

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Canadians could free themselves from oil imports, but will they?

by Kurt Cobb

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

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IEA oil forecast unrealistically high; Misses diminishing returns

by Gail Tverberg

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Predictive analytics methods begin to take hold in E&P

by Murray Roth and Jim Hollis

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A pipeline reversal in the North American oil & gas markets

by Keith Schaefer

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LNG in Asia: Let the renegotiations begin

by Robert Joiner

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Did oil decide the last three American elections?

by Kurt Cobb

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International labour implications of the China shale plays

by John McGoldrick

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Oil the St Swithins day massacre

by Andrew McKillop

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The best place to find petroleum

by David Bamford

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OilVoice Magazine | DECEMBER 2012

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

Robert Joiner Wikborg Rein Robert Joiner is a partner in the Singapore-based Shipping and Offshore team at the international law firm Wikborg Rein. Robert has advised clients on English law aspects of shipping trade and marine insurance for over 20 years.

His work has been recommended by both Chambers and Legal 500.

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. In addition, he writes columns for the Paris-based science news site Scitizen, and his work has been featured on Energy Bulletin, The Oil Drum, OilPrice.com, Econ Matters, Peak Oil Review, 321energy, Common Dreams, Le Monde Diplomatique, and many other sites.

Gail Tverberg Our Finite World Gail Tverber 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.

Jim Hollis NEOS Prior to joining NEOS in 2010 as president and CEO, Jim Hollis served as president and COO of ION Geophysical where he established growth strategies and supervised financial execution of all ION business units. He also worked previously in management and technology roles for Landmark Graphics. He holds a BS in geophysics from the University of California, Santa Barbara, and an MS in geophysics from the University of Utah.

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OilVoice Magazine | DECEMBER 2012

Murray Roth Transform Software and Services Murray Roth is president and co-founder of Transform, headquartered in Littleton, Colorado. After graduating with a degree in astrophysics from the University of Calgary, he began his career at Geophysical Services Inc., working in seismic acquisition, seismic processing and special project groups.

He joined Landmark Graphics in 1989, serving as executive vice president of research and development and marketing until he departed the company in 2004 to found Transform.

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

David Bamford Finding Petroleum David Bamford is non-executive director of Tullow Oil, and a past head of exploration, West Africa and geophysics with BP.

John McGoldrick Dart Energy John, a chemical engineer by training, has 32 years experience in the upstream oil and gas business, and has lived and worked in the UK, France, Ireland and the USA.

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OilVoice Magazine | DECEMBER 2012

Canadians could free themselves from oil imports, but will they?

Written by Kurt Cobb from Resource Insights You are not alone if you think it's odd that Canada--the world's ninth largest exporter of crude oil and petroleum products and the main supplier of oil imports to the United States--is itself a longtime oil importer, importing more than 40 percent of its oil needs this year. The situation results from historical pipeline development which has left Canada without a major east-west pipeline to bring the huge surplus of oil produced in the western provinces--now primarily from tar sands--to the eastern part of the country. The country's provinces from Ontario eastward currently import a little more than 60 percent of their oil needs from overseas. That may be set to change.

Winston Churchill once said, "You can always count on Americans to do the right thing--after they've tried everything else." It seems he could have been talking about the Canadians and their oil predicament. Earlier this year TransCanada, a major pipeline company, proposed expanding the current pipeline system known as Keystone to carry more western Canadian crude to America's Gulf Coast. But, the pipeline giant was rebuffed by the Obama Administration in an election-year gambit to satisfy environmentalists concerned about the impact of tar sands development on climate change and water quality. Enbridge, another Canadian pipeline company, has proposed the so-called Northern Gateway pipeline route from the tar sands to the British Columbia coast. From there the oil would be exported to satisfy growing Asian demand. But practically everyone along the Northern Gateway route has lined up against it including the British Columbian premier.

Now, yet another route is being considered, one that would allow TransCanada to live up to its name. The company's latest proposal would take an east-west natural gas pipeline which is now being underused and convert it into an oil pipeline to bring western Canadian crude to currently import-dependent eastern Canada. The plan, which will require regulatory approval, may not face the stiff opposition that the other two projects faced since this pipeline is largely complete. It would require only some additional work to convert it and link it to refineries and storage depots.

The result would be a flow of up to 1 million barrels per day of oil to eastern Canada, more than enough to displace all of Canada's current imports and possibly allow for exports of crude oil from the eastern seaboard. Canadians would still be subject to world oil prices since oil would remain a global commodity that can be shipped to the highest bidder. But, the country would no longer be vulnerable to supply disruptions from abroad and would be in a position to prevent exports if a national emergency warranted it.

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With this change Canada would move closer to true energy independence. It currently exports electricity to the United States and imports only a tiny amount of U.S. electricity due to historical infrastructure or regional rate differentials. Canada is the world's second largest producer of uranium, providing 17 percent of global supply in 2011. Therefore, the country does not need to import any for use in its own nuclear power plants. In 2011 Canada was the world's 14th largest producer of coal and exported about 30 percent of its production. Some imports were recorded. The long border with the United States, a major coal producer, sometimes makes U.S. imports more economical depending on the type of coal and the shipping distances.

When it comes to natural gas, however, Canada's National Energy Board reports that while the country produces 70 percent more than it needs, it still imports the equivalent of 31 percent of its consumption--even as it exports the equivalent of 100 percent of Canadian consumption to the United States. As with oil, historical pipeline infrastructure dictates this unusual arrangement. But that is a story for a future piece.

The oil industry has been working on a way to get growing volumes of oil out of western Canada cheaply for some time. And, the cheapest way is via pipeline.

Producers have been suffering steep discounts to world prices with Western Canadian Select crude oil futures trading in New York at a discount of about $20 per barrel compared to American Light Sweet Crude which itself has been trading at approximately a $20 discount to Brent Crude in Europe. So, the total discount to prevailing world prices for western Canadian crude is currently around $40. It's easy to see why the industry is anxious for a pipeline that will allow it take advantage of higher world prices.

With opposition running strong against the two alternatives, the oil industry may be forced to consider the TransCanada pipeline conversion proposal to ship oil to eastern Canada, a proposal that happens to coincide with Canada's national interest.

But don't expect to hear industry executives whistling "O Canada" at their desks just yet. It's not clear how much support the project will find among those executives.

That support will be critical because the current Canadian government, which must approve the project, has shown itself congenitally incapable of distinguishing between the national interest and the interests of international oil companies.

Therefore, the government isn't likely to force the project on the industry even if the pipeline would be a good idea for Canada as a whole. However, if the oil industry ends up embracing the project, the Canadian government will almost certainly rubber-stamp it. And thus, the government and the industry may inadvertently end up doing what has for a very long time been within Canada's grasp and in its best interest, namely, to free the country from imported oil.

View more quality content from Resource Insights

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OilVoice Magazine | DECEMBER 2012

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!

Relentless Resources Ltd.

Sembcorp Marine Ltd.

Oil & Gas

Service

The company’s primary corporate objective is to achieve non-dilutive growth and enhance shareholder value through internal prospect development, strategic production acquisitions and prudent financial management.

With facilities with 5,800 megawatts of gross power capacity and over seven million cubic metres of water per day in operation and under development, Sembcorp is a trusted provider of essential energy and water solutions to both industrial and municipal customers. It is also a world leader in marine and offshore engineering as well as an established brand name in urban development.

Visit Relentless Resources' OilVoice profile

MATRRIX Energy Technologies Inc. Service MATRRIX steers wellbores to hydrocarbonbearing reservoirs that deliver returns for our Oil and Gas Clients. Horizontal and directional drilling is both an art and a science.

Visit MATRRIX's OilVoice profile

Pembina Pipeline Corporation

Visit Sembcorp Marine’s OilVoice profile

Ironhorse Oil & Gas Inc. Oil & Gas Ironhorse Oil & Gas Inc. is a Calgary-based junior oil and natural gas exploration and production company with an interest in producing/developed acreage in southwest Saskatchewan and west central Alberta.

Transport Visit Ironhorse Oil & Gas' OilVoice profile

Calgary-based Pembina Pipeline Corporation is a leading transportation and midstream service provider that has been serving North America's energy industry for nearly 60 years.

Visit Pembina's OilVoice profile

Phere Energy Inc. Oil & Gas

After becoming involved in the oil & gas exploration industry, Phere Energy Inc. participated in the development of fields throughout the entire state of Texas.

Starting in west Texas, then migrating to east Texas developing several Cotton Valley Woodbine wells, and now operating in south Texas developing several leases.

Visit Phere Energy's OilVoice profile

Trans Energy, Inc. Shale Trans Energy, Inc. is a pure play Marcellus Shale producer that engages in the acquisition, exploration, development, exploitation, and production of oil and liquidsrich natural gas. The Company and its JV Partner, Republic Energy, own interests in, and operate approximately 62,000 gross acres in West Virginia.

Visit Trans Energy's OilVoice profile

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OilVoice Magazine | DECEMBER 2012

IEA oil forecast unrealistically high; Misses diminishing returns Written by Gail Tverberg from Our Finite World The International Energy Agency (IEA) provides unrealistically high oil forecasts in its new 2012 World Energy Outlook (WEO). It claims, among other things, that the United States will become the world’s largest oil producer by 2020, and will become a net oil exporter by 2030.

Figure 1. Author’s interpretation of IEA Forecast of Future US Oil Production under “New Policies” Scenario, based on information provided in IEA’s 2012 World Energy Outlook.

Figure 1 shows that this increase comes solely from the expected rise in tight oil production and natural gas liquids. The idea that we will become an exporter in later years occurs despite falling production, because “demand” will drop so much.

The oil price forecasts underlying these and other forecasts in the report are approximately as follows: Figure 2. Author’s interpretation of future average world oil prices, as provided by IEA in their 2012 WEO report. (Forecast provided by IEA is more “concave downward”.) Historical amounts are based on BP 2012 Statistical Review of World Energy amounts.

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One reason the WEO 2012 estimates are unreasonable is because the oil prices shown are unrealistically low relative to the production amounts forecast in the report. This seems to occur because the IEA misses the problem of diminishing returns. As the easy-to-produce oil becomes more depleted, and we need to move to more difficult reservoirs, the cost of extraction increases.

In fact, there is evidence that the “tight” oil referenced in Exhibit 1 is already starting to reach production limits, at current prices. The only way these production limits might be reasonably overcome is with higher oil prices–much higher than the IEA is assuming in any of its forecasts.

Higher oil prices cause a huge problem because of their impact on the world economy. The IEA in fact mentions that current high oil prices are already acting as a brake on the global economy in its first slide for the press. Higher oil prices also mean that investment costs required to reach target production levels will be even higher than forecast by the IEA, adding another impediment to reaching its forecast production levels.

If higher prices put the economies of oil importing nations into recession, then oil prices will drop lower, reducing the incentive to invest in new oil production infrastructure. In fact, we could find ourselves reaching “peak oil” because of an economic dilemma: while there seems to be plenty of oil available, the cost of extracting it may be reaching a point where it is more expensive than consumers can afford. As a result, some oil that we know about, and have been counting as reserves, will have to be left in the ground.

The IMF has recently done modeling that is relevant to this issue in a working paper called “Oil and the World Economy: Some Possible Futures.” This analysis may provide some insight as to what the real situation will be.

The Problem of Diminishing Returns One issue that the IEA has not properly modeled is the issue of declining resource quality, leading to diminishing returns and a rising “real” (inflation adjusted) cost of production. This situation is often described as reflecting declining Energy Return on Energy Invested (EROEI).

The reason diminishing returns are a problem is because when a producer decides to extract oil, or gas or coal, the producer looks for the cheapest, easiest to extract, resource first. It is only when this resource is mostly depleted that the producer will seek locations where more expensive, harder to extract resource is available. Thus, over time, the inflation adjusted cost of extracting a resource tends to increase.

Figure 3. Author’s illustration of impacts of declining resource quality.

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In terms of the triangle shown, producers tend to start at the top, with the “best” of the resource, and work their way toward the bottom. One result of this approach is that the cost per unit of production tends to rise, even as there are technology advances and efficiency gains, because the quality of the resource is declining.

Reserves tend to increase over time with this approach, because as producers work their way down the triangle in the diagram, they always see an increasing quantity of lower quality resources. The new reserves are increasingly expensive to extract, in inflation adjusted terms. There is no flashing light that says, “Above this price, customers won’t be able to afford to purchase this resource any more,” though. As a result, the increasingly low quality reserves get added to reported amounts, even though in some cases, the cost of products made with these reserves (say gasoline or diesel) will send economies into recession.

It should be noted that the issue of diminishing returns exists for almost any kind of resource. It exists for uranium extraction, since there is always more available, just harder to reach, or in lower concentration. Diminishing returns exists for gold, copper, and for nearly any other kind of metal. This means we often need more oil for metal extraction and processing, as we dig deeper or find ore that is mixed with a higher proportion of waste product.

The problem of diminishing returns also seems to hold for renewables. The first biofuel developed was ethanol from corn, since the process of making alcohol from corn has been known for ages. Newer approaches, such as ethanol from biomass and biofuel from algae, tend to be much more expensive. As a result, when we add new biofuel production, it is likely to be more expensive, and thus harder for the customer to afford. If we want it, we will need increasingly high subsidies.

Wind energy is also subject to diminishing returns. Onshore wind was developed first, and it is far less expensive than offshore wind, which was developed later. Early units of wind added to an electric grid do not disturb the electric grid to too great an extent. Later units of wind energy add increasingly large costs: long distance transmission lines, electrical storage, and other balancing–something that is generally overlooked in making early cost analyses.

Diminishing returns seem even to happen for energy efficiency. We have been working on energy efficiency a very long time. We have a tendency to pick the lowhanging fruit first. Later expenditure for efficiency may be less cost-effective.

Why Light Tight Oil Won’t Increase as in Figure 1 Tight oil, also referred to as “shale oil,” is supposed to be the United States’ oil savior, if we believe the IEA. The Bakken and Eagle Ford plays are the best known examples.

Rune Likvern of The Oil Drum has shown that drilling wells in the Bakken already seems to be reaching diminishing returns. The choicest locations appear to have been drilled first, and the locations being drilled now give poorer yields. He has also shown that the average well in the Bakken now requires a price of $80 to $90 barrel, which is close to the recent selling price. If increased production is desired, the price

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of oil will need to start increasing (and keep increasing) to provide the incentive needed to drill wells in less-choice location.

There are other issues as well. If there is a need to drill an increasing number of wells just to stay even, or an even larger number, to increase the amount of oil produced, we start to reach limits on many kinds: number of rigs available, number of workers available, miles driven for water to be used for fracking. Perhaps the issue that will limit production first, though, is limits on debt available to producers.

Rune Likvern has also shown that cash flows from tight oil extraction tend to run “in the red,” so an increasing amount of debt financing is needed as operations ramp up. At some point, companies hit their credit limit and have to stop adding new wells until cash flow catches up.

Evidence Regarding Rate of Growth of Oil Extraction Costs Bernstein Research recently published information showing that the marginal cost of oil production was $92 barrel in 2011 for non-OPEC, non Former Soviet Union oil producers at the 90th percentile of production. This cost is increasing at 14% per year (or about 12% a year in inflation adjusted terms). Even at the median marginal cost level, costs appear to be increasing at a compound annual growth rate of 9% (or about 7% in inflation adjusted terms). See also this FTAlphaville post.

If we take the $92 barrel cost in 2011 at the 90th percentile of production and increase it by 7% a year (arguably we should be using 12% per year), the real cost will be $169 barrel in 2020, and $467 a barrel in 2035. These are far in excess of the IEA oil price estimates shown on Figure 2. There is no reason to believe that Bakken and other tight oil production costs would be substantially cheaper.

Other Issues That Appear Not to be Handled Well by IEA WEO 2012 There are three other issues that the IEA has not handled well, in my opinion.

1. Rising Real Need for Fuels of Some Sort WEO 2012 shows falling “demand” for fuel. Demand, as economists define demand, has to do with how much customers can afford. It is quite possible that demand will fall because people can’t afford the fuel.

It seems to me would be better to start by analyzing how the real need for fuels is changing. Once this is determined, adjustments can be made to reflect other ways the same benefits can be provided, assuming this is possible.

Regarding the real need for fuel, if we look at species that are in some ways similar to humans, such as chimpanzees and gorillas, we find that these animals have no need for fuels, because they live in the way that they are biologically adapted: There are only a relatively small number of them (less than 1,000,000 per species) living in territory which is restricted to their biological adaptation. They do not need their food cooked, or spears or other tools to keep away predators, or shelter from the elements.

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Humans don’t live in the way that we are biologically adapted. Because there are so many of us, we need to grow our own food, and gather water from natural sources.

Because we do not have big heavy jaws because there is little easy-to-chew food available, we need to cook much of our food. Because we live in diverse areas of the world, we need shelter and adaptive clothing. As humans move to cities, we have even greater needs. We need antibiotics and immunizations to prevent epidemics.

We need fuel for commuting, unless we sleep on the floor of the factory where we work. We need fossil fuel for cooking, because traditional fuels such as dung or twigs are not available in sufficient quantities in urban areas.

Another need for fuel, besides directly responding to human needs, is to offset the continued degradation (entropy) of built infrastructure. As the number of humans expands, so do the miles of roads, the number of bridges, the miles of pipelines, the number of homes and schools, and many other kinds infrastructure. All of this infrastructure wears out. Roads need to be repaired almost every year, especially in cold climates. Electrical transmission lines need to be put back in place after every major storm.

Population is also, of course, rising. When we put these issues together (rising fuel need with urbanization, rising population, and increasing entropy), it is clear that the services humans need from fuels will continue to rise, whether or not “demand” as economists measure it appears to rise.

Most of these fuel services will need to come from fossil fuels, rather than renewables, for two reasons: (1) This is the way our infrastructure now is built, and it is expensive and time-consuming to change it. (2) Biological sources are quite limited compared to the needs of 7 billion humans. According to Chew in The Recurring Dark Ages, deforestation started to occur in multiple locations 6,000 years ago, when the world population was about 20 million people.

2. Substitution for Oil The IEA seems to err in the direction of assuming that substitution can be made more quickly than it really can be. In general, whenever substitution is done, new devices need to be created that use the new fuel, or new plants need to be developed that transform one type of fuel to another type of fuel. Doing either of these things will temporarily add to demand for fossil fuels. There is also a cost involved.

Only the heavier portion of natural gas liquids can be added directly to gasoline supply. Most natural gas liquids are used for other purposes, such as making plastics, or propane for home heating, or making liquid petroleum gas (LPG). LPG is used for cooking in some parts of the world and for operating vehicles that have been designed to use it.

3. Efficiency Gains The IEA seems to assume that efficiency gain can have a big impact on the need for oil. The issue it seems to lose sight of is that efficiency gains are a two-edged sword.

When a device is made more efficient, the usual effect is that it can be operated

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more cheaply. This means that more people can afford it, and demand may increase. In the early days, electricity was very expensive. As its cost came down with efficiency gains, its use went up dramatically.

Putting All of These Issues Together It is very clear to me that the IEA oil estimates way too high, unless prices are much higher. Of course, prices can’t really be much higher, or the economy will go into recession. As a result, production both for the US and the rest of the world is likely to be much lower than forecast by the IEA. It would be useful to have a better estimate of exactly where the world is headed.

One way this might be done is by adapting the indications of a new IMF working paper called Oil and the World Economy: Some Possible Futures. The working paper considers some unknown time, between now and 2020, when the rate of increase in oil supply is assumed to decrease by 1%. While it is not stated in the report, it appears to me that this is similar to what actually happened about 2005, when the rate of oil production increase dropped from 1.3%” annual increase to 0.1%, a 1.2% decrease. (Figure 4, below).

Figure 4. World crude oil production (including condensate) based primarily on US Energy Information Administration data, with trend lines fitted by the author.

I have a few observations regarding such an adaption: (a) The model could be adjusted to consider the fact that a drop in the trend rate of about 1.2% actually took place in 2005, rather than simply assuming that a 1% decrease will happen at some unspecified point in the future. It appears to me that shift in the oil extraction trend line underlies many of the world’s problems in the last several years. (b) The treatment in the model of diminishing returns should be adjusted. It is my understanding that this is currently handled assuming a 2% annual increase in real costs of production. The model could be adjusted to reflect a more realistic (higher) annual cost in oil production, and indirectly, required selling price. (c) The authors of the IMF report suggest building a more resource-based model, and I would agree that this would be helpful. There are many interlinkages that the current model cannot adequately capture. A more resource-driven model, especially one that considers balance sheets of world governments, would appear to be better.

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My View of What is Happening Now As noted above, world crude oil production seems to have hit a plateau, starting about 2005. This is working its way through the economy with varying effects over time. The major effect at this point of time seems to be on the finances of governments that import oil, although it started earlier, with different aspects more apparent.

In general, what happens as we reach a situation of diminishing returns, and thus rising real oil prices, seems to be as follows: As the price of oil rises, the price of food and commuting tend to rise. Both of these are considered essential by most consumers, so consumers cut back in discretionary spending, to have sufficient funds for the essentials. This leads to layoffs in discretionary industries, such as vacation travel and restaurant eating. The rise in laid off workers leads to an increase in debt defaults, and problems for banks.

Housing and commercial real estate prices tend to fall, because of reduced demand, further adding to debt default problems.

Governments of oil importers get drawn into this in many ways: (1) Their revenues are reduced, because they receive less tax revenue from people who are laid off from work and from businesses with fewer sales. (2) They are asked to prop up failing banks, and to stimulate the economy. (3) They are also asked to pay workers who have been laid off from work. The net of all of this is that the governments of many oil importers find themselves with huge budget deficits, and declining ability to fix these deficits. This pattern is precisely what we are seeing today in many of Eurozone countries, the United States, Japan.

The statements about rising oil production in the US are just a distraction.

Diminishing returns mean that US oil production will never increase very much. Oil costs will remain high, and this will be the real issue disturbing economies around the world.

View more quality content from Our Finite World

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OilVoice Magazine | DECEMBER 2012

Predictive analytics methods begin to take hold in E&P Written by Murray Roth and Jim Hollis from NEOS Twenty years ago, predictive analytics was a buzz phrase little heard by those outside of academia. Ten years ago, the concept began to emerge prominently within the financial sector, as investment managers started to leverage powerful, software-driven analytical programs to assess investment alternatives given the interplay of a complex set of variables, including historical performance, asset correlations, relative risk, and projections of future economic conditions. More recently, companies ranging from Wal-Mart to United Airlines have been analyzing reams of product and consumer data to determine what products are selling, to whom, where, and why, and thereafter using the insights derived to make future decisions about offerings, pricing levels, and promotional packages.

Thanks to Billy Beane, general manager of Major League Baseball's Oakland Athletics, and the book and movie, Moneyball, predictive analytics has erupted into the mainstream. Moneyball describes how Beane and his assistant, Paul Podesta, shackled with both a restricted budget and the limitations of a mid-level regional market, managed to assemble a competitive and highly successful baseball team capable of defeating opponents with deeper pockets, larger markets, and star-laden rosters. By using predictive analysis to interpret and integrate a vast pool of multivariate statistics and performance attributes, the duo was able to quantify and leverage hidden reserves of talent and capability. For a time, they had access to asymmetric information that allowed them to field a winning team at a fraction of the cost and, in the process, change the face of modern sports.

Today, it is becoming commonplace for companies across many industries to apply advanced mathematical methods to mine extremely large datasets, searching for distal correlations and associations. Pharmaceutical companies are mining patient histories and treatment regimens to determine which combinations of drugs are most effective. Online retailers are analyzing and influencing product purchase behavior given highly individualized web site presentations, direct marketing campaigns, and bundled promotions. A new battleground is being established, built upon the emerging foundations of advanced software and applications that enable deep, rapid, highly reliable insight into complex variables and conditions. The practice of information-driven decision making is establishing a new threshold for performance and driving companies to identify new strategies that capitalize upon previously unknown insights more readily than their competitors.

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THE CHALLENGE Many of these new challenges are currently being identified and confronted within the E&P industry. In recent years, oil & gas leaders have increasingly leveraged predictive statistical methodologies to blend geophysical, geological and engineering data to estimate reservoir properties between well locations, This work is an extension of historical techniques that relied upon geological mapping and geostatistical computations to infer what occurs between drilled well locations; while these techniques integrate geophysical and geologic data, the predictive power of the outcome is largely based upon effective, or smart, interpolation and a fairly limited set of G&G inputs, namely seismic and well log data. E&P predictive analytics are extending beyond traditional G&G data to incorporate innovative multi-spectral and potential field measurements and a breadth of engineering information.

To better understand the current needs and requirements, let's consider a pair of typical E&P scenarios. At the basin scale, explorers might be looking for indications of which areas are the most prospective to lease, either because they are more likely to contain commercially producible fields or, in the case of unconventional plays, the most productive portions of the reservoir for prioritized development. At the reservoir scale, explorers would typically be looking for localized sweet spots that contribute to the most productive wells.

Let's take it a bit deeper with the case of an unconventional shale play. Successful exploitation depends on understanding the complex interplay among a host of subsurface variables including total organic content (TOC), thermal regimes, insitu hydrocarbon distributions, brittleness, fracture density, regional stress fields, reservoir thickness and proximity to faults. Understanding the interplay requires a rich analysis of numerous seismic and non-seismic measurements.

A real world example includes liquid and gas producing reservoirs such as the Bakken, Eagle Ford, Permian and Barnett plays. These fields present variable profitability for current and prospective operators. To meet the challenge, they utilize quantitative analytics to churn through vast quantities of historic and new data to identify trends and best engineering practices. The data sets can include thousands of well log records for thousands of well bores, in conjunction with copious engineering measurements, 3D seismic volumes and, more recently, regional nonseismic measurements, attributes, and derivatives.

In virtually any E&P scenario within today's oil and gas environment, the datasets are numerous and extremely large, often constituting multiple terabytes. And project data only continues to expand in both size and amount. It's an increasingly complex engagement that has begun to outstrip the processing capacity of the human brain and, in recent years, has mandated the development of deep algorithmic tools simply to keep pace. We can see how these datasets lend themselves to nothing short of the most advanced quantitative analysis, in order to achieve optimal interpretation and understanding.

THE RESPONSE In many industries, predictive analytics is used in a behavioral context. That is,

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practitioners leverage analytically derived information to monitor and predict consumer behavior based on previous behaviors and tendencies. It makes sense.

However, in the E&P world, and in particular seismic exploration, analytical tools, whether we classify them as predictive or otherwise, serve a more complex, workflow-driven purpose. They are used to not only improve and optimize subsurface interpretation and understanding, but equally to predict lifecycle performance and future variations in facies conditions as they relate to well planning, drilling and reservoir management.

This response is predictable (no pun intended) given the emergence of advanced software and data processing technologies as extraordinarily valuable means of gaining even deeper and better insight into subsurface conditions. As the tools and methodologies have advanced, equally so has the competitive need to apply them in areas of critical business decision-making.

The increasing complexity of hydrocarbon reservoirs places continuous strain on E&P workforces and technology processes; many reservoirs, particularly unconventional shale plays, require astute planning and subsurface visibility in order to achieve profitable (and optimally efficient) commercial-grade environments.

Reservoir analytics can estimate the correlation of production and production declines with reservoir and engineering parameters, delivering very high prediction levels for identifying optimal engineering parameters and prospective sweet spot locations.

There are also many existing wells and reservoirs that have exceeded prime or optimal production conditions and require meticulous and integrated analysis, including reliable forecasting, in order to achieve continuous profitability. In the past, most producers would routinely abandon these wells and reservoirs as production margins diminished below certain levels. Today, with the advantages provided by advanced interpretation and predictive analytics, it's no longer 'standard operating procedure' to withdraw simply because existing configurations and reservoir conditions have reached certain thresholds or limitations. From a business standpoint, this type of decision-making can now be deemed perfunctory, premature and costly. Interpreters and operators are now faced with new issues of how to manage new and maturing assets and access harder to reach and harder to visualize regions in and around the reservoir. With a few adjustments, a sweet spot can continue to be a sweet spot. Or another previously undetermined sweet spot might emerge. Whatever the case, as we can all agree, it's a good problem to have.

Currently, a small number of innovative companies are developing a de facto emerging methodology, of sorts, that provides E&P operators with deep integration of advanced analytics with modern interpretation approaches and methodologies.

Visionary companies are establishing leadership roles in this area.

NEOS GeoSolutions provides distinct expertise in multi-measurement interpretation, integrating a broad spectrum of geological and geophysical datasets (both seismic and non-seismic) - including data available via public domain, owned by clients, or acquired using proprietary platforms - to produce a highly constrained 3D model of the subsurface.

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This enables interpreters and operators to determine which portions of a basin might be the most prospective and, at the lease level, what areas are most likely to contain commercial quantities of hydrocarbons or minerals.

Transform focuses on reservoir analytic interpretation and modeling, an approach designed to improve the operator's understanding of reservoir characteristics and conditions. The company's innovative software suite simplifies interpretation challenges by automating the integration and visualization of microseismic, well log, seismic and other E&P data types. By combining geophysical, geological, and engineering workflows in a streamlined and quantified manner, asset teams are well positioned to better characterize unconventional oil and gas, heavy and enhanced oil, and most conventional reservoirs.

Applied Example #1

Bakken optimized production pattern Reservoir analytics seek a cause-and-effect relationship between the reservoir parameters that an interpreter or explorer inherits, and the engineering parameters that are applied in order to achieve a particular quantity or threshold of well production. Let's take a look at the Bakken unconventional play in North Dakota and Montana as an example of how analytical interpretation can provide remarkable benefits in today's E&P world.

This predominantly oil and water producing play is notorious for presenting substantial challenges when predicting, or attempting to forecast, well production from a myriad of engineering and geologic data. For oil producers, the Middle Bakken and Three Forks formations are key determinant objectives for effectively calibrating geologic conditions with variable hydraulic fracture effectiveness. For example, by analyzing microseismic data, interpreters can generate volumetric estimates of simulated reservoir volumes for each fracture stage, in addition to

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determining the degree of fracture zone overlap.

Drilling and completions engineering decisions are a major determinant of relative well production in unconventional plays. Well performance in these plays is driven by: well length, fracture stage spacing, fluid and proppant rates and amounts, completion techniques and more. However, well engineering is not the complete story, as sweet spot locations in the Bakken and Three Forks formations are driven by many geologic factors. Foremost are the geochemistry of the Upper and Lower Bakken formations, specifically thermal maturity and organic content, coupled with depth and thickness of the Bakken and Three Forks reservoirs. And so, well production is dependent upon spatial location within the play and well construction and trajectory through reservoir rock. However, with increased proximity of wells, and the emerging multi-bench development of the Three Forks, interwell completion and production interference are increasing in importance.

How do we begin to unravel the intertwined complexity of what creates a good and bad well in this play? Predictive analytics are undaunted by the size, amount and relationship of rock prospectivity and well parameters - which is good, as leading operators are collating databases of 50 or more attributes for thousands of wells.

Setting initial production or ultimate recovery estimates as prediction targets, nonlinear multi-attribute statistics build a model to relate cause-and-effect. More than creating a prediction model, often with very high accuracy, reservoir analytics highlight the relative importance and relationship of geology and engineering on well production. As operators endeavor to optimize field development strategies and operations, reservoir analytics provide a roadmap as to what choices are more important and effective.

Applied Example #2

Marcellus sweet spot map. Tioga County, Pennsylvania – Appalachian Basin, USA. In Pennsylvania's Marcellus Shale, a predictive analytics methodology has been

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used to identify the most promising areas to lease and drill at the county scale (roughly 1,000 square miles). The technique involves comparing nearly 100 individual measurements, attributes, and derivatives from both legacy and newly acquired geophysical datasets - the latter generally acquired using airborne gravity, magnetic, electro-magnetic, radiometric, and hyperspectral sensors - to those associated with the most productive wells in the area.

While the geostatistical techniques used are highly objective and algorithmic, the inputs to the predictive modeling effort generally all have high levels of explainable geological relevance. For instance, gravity data might feed regional subsurface models, resulting in 'horizon thickness' isopach maps for targeted reservoir intervals.

Magnetic data might provide indications about proximity to faults or fracture systems that enhance well deliverability. EM resistivity data might feed hydrocarbon distribution maps both within (and above) prospective reservoir intervals, providing an indication of the relative 'charge' in different parts of the hydrocarbon system. And hyperspectral data might highlight direct (and indirect) hydrocarbon indicators on the surface, which could be associated with micro-seepage from nearby reservoirs within the subsurface. In the Marcellus example, twenty measurements, attributes, and derivatives were identified as highly correlative with the best wells in the county.

These twenty measurements can be grouped in four categories: structural context; size and composition of the 'tank'; reservoir plumbing; and the 'halo' above the reservoir intervals of interest.

Predictive analytics allows the geoscientist to map the correlative anomalies throughout the county, with hot colors showcasing the sweet spots the methodology suggests would be most prospective for leasing and drilling or, at a minimum, for further investigation by the informed and experienced interpreter. To date, an analysis of drilling results suggests a strong correlation between the sweet spots that were predicted and those that were actually encountered by the bit.

Summary The E&P industry is emerging as a rapid adopter of predictive analytics methods to identify subtle patterns and correlations across multiple G&G and engineering datasets. The sheer number and sizes of these datasets creates an opportunity to apply analytically driven, multi-measurement interpretation methods to predict exploration and drilling sweet spots at both regional and local scales. The business advantages related to successfully leveraging these analytics include more efficient use of both human and capital resources; superior understanding of subsurface conditions and reservoir performance; and deeply integrated, highly-informed project decision-making.

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OilVoice Magazine | DECEMBER 2012

A pipeline reversal in the North American oil & gas markets Written by Keith Schaefer from Oil & Gas Investments Bulletin It’s hard to believe how North America’s oil and gas industry—a conservative bastion—has been turned upside down in such a short period of time. And it’s all because of the Shale Revolution.

Look at pipelines. They cost billions, take years to plan, get approvals, sign up committed customers with take-or-pay provisions etc.—and now some are being made redundant within a few years.

GAS PIPELINES I think the BIGGEST change in pipelines is happening because the industry discovered a massive new shale gas deposit in the northeast US—the Marcellus Shale.

For decades, western North America has produced gas and shipped it to the populated east coast.

But now—they don’t need it. They have their own source.

They used to buy Canadian gas, and shipments from the U.S. Gulf Coast, and had LNG imports. However, the highly-populated northeast U.S. now has enough local production to keep the lights and heat on with no help.

In fact, they’re exporting gas now.

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Marcellus production clocked 9 billion cubic feet per day (bcf/d) in September, from under 2bcf/d a couple years ago, and almost none in 2006. Today it is 22% of U.S. natural gas production—up from just 5% in 2011. That’s remarkable!

It also means less need for long-haul pipelines and more demand from localized systems. All told, new pipeline projects in the Northeast region are expected to add about 3.2 bcf/d capacity by December, taking Marcellus shale to mid-Atlantic markets, Canada and even Florida.

Only two years ago, Kinder Morgan (KMP-NYSE) finished spending over $4 billion building the 1.8 bcf/d Rockies Express (REX) pipeline to take more western gas from Colorado into Ohio. At the same time, Canadian production was dropping because of increased domestic demand and natural declines of aging fields.

The 2,700 kilometre line now is running far below capacity because of the unexpected explosion of Marcellus shale volumes reducing the call for western gas.

TransCanada Corp. (TRP-NYSE; TRP-TSX), which operates the largest natural gas pipeline in Canada, is already reversing its Niagara pipeline in southern Ontario as a result of the cheaper American shale gas coming onstream. The switch, expected to be active in November, will move about 0.4 bcf/d of U.S. gas north to Ontario, instead of flowing Western Canadian gas south to Pennsylvania.

That’s the east coast. In the west, two new natural gas pipelines in 2011 changed market conditions for both Canadian and U.S. producers. One was the Ruby pipeline, which flows “Rockies” gas west from Wyoming to Oregon and into California markets.

The second—Bison—also started in Wyoming, but flows gas east to the Midwest—a traditional market for Canadian natural gas.

Since its start up, Ruby has been moving about 1 bcf/d, and taking an average 700 million cubic feet per day in natural gas sales from Canada.

But demand for natural gas in California is flat because power demand growth is being met by renewables, said Ed Kallio with Ziff Energy in Calgary.

Canadian natural gas used to be cheaper and more desirable before Ruby, but now it has to be sold at a discount to Rockies gas, Kallio said.

“The Canadian gas is being pushed back into Western Canada and has to find other export routes since demand from the oil sands can only take so much,” he noted.

“So producers have tapped into Alliance, and Northern Border pipelines to U.S. Midwest and eastern markets.”

OIL AND CONDENSATE PIPELINES Pipeline flows aren’t just being changed—so are the commodities that flow inside them!

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Condensate flows are also being affected by shifting supply. Kinder Morgan plans to reverse its Cochin pipeline flow between Kankakee County Illinois and facilities near Fort Saskatchewan, Alberta.

The plan would also involve changing the commodity. Now it ships propane from Canada to the US. Soon it will flow to condensate from the U.S. to Canada— because Canada needs it to dilute the fast-growing heavy oil production out of the oilsands.

On the oil side, pipeline disruptions and reversals are also happening because of fast growing production in the huge new Bakken shale oil deposit in North Dakota, and in Alberta’s oilsands.

Enbridge Inc. and Enterprise Product s Partners’ changed their Seaway pipeline— which used to run south-to-north from Houston to Cushing Oklahoma—to northsouth, to help respond to a price-crushing glut of crude at Cushing.

New production out of the Bakken and Alberta’s oil sands are now flooding Cushing, which had few pipelines going OUT. That created another upside down event in the global energy patch: The American benchmark oil price, called WTI for West Texas Intermediate, started to trade $10-$15 a barrel cheaper than Europe’s Brent crude pricing. WTI always used to trade at a small premium.

“Because of the recent development of new oil supplies from the Bakken but also from Western Canada… there was a lot of new crude supply arriving in Cushing with essentially nowhere to go,” said Patricia Mohr, vice-president, economic and commodity specialist at the Bank of Nova Scotia.

And in an upcoming story, I’ll tell you why I think that discount is here to stay for a lot longer than the market expects.

But there are more oil pipeline reversals happening: Further east, Enbridge will be reversing a portion of its 250, 000 bopd Line 9 from Sarnia, Ontario to Montreal, Quebec.

The plans will see a section between Sarnia and Westover, Ontario reversed to serve Imperial Oils’ Nanticoke refinery with Western Canadian crude, rather than pricier imports. Enbridge is considering a full reversal to Montreal in the future.

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Are you dizzy yet?

And the change is still happening.

But I have to say I’m impressed with how fast the industry is adapting at almost every new turn of events. At the end of the day consumers and investors should have a more efficient energy grid and lower energy prices.

But right now, the pace of change makes it hard for investors to figure out medium to long term trends and consequences. New technology and new supply basins seem to be popping up across the continent, flipping pricing scenarios on their heads.

View more quality content from Oil & Gas Investments Bulletin

Health, Safety, Environment and Risk Management RPS Energy is a global multi-disciplinary consultancy, providing integrated technical, commercial and project management support services in the fields of geoscience, engineering and HS&E.

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

rpsgroup.com/energy

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OilVoice Magazine | DECEMBER 2012

LNG in Asia: Let the renegotiations begin Written by Robert Joiner from Wikborg Rein There have been numerous references in the world's press recently about the increasing globalisation of the LNG market. The growth of supply has increased the Asian demand for greater pricing and contract length flexibility. With Singapore also developing LNG bunkering facilities and increasing its terminal's storage capacity, a bigger spot market for LNG appears to be fast approaching.

To put this roughly into context, the amount of LNG traded last year was about about 300 million mt oil equivalent, (of which about 25% is said to be in the spot market) as against oil traded of about 2,600 million mt. In Asia, LNG was about 4% of the total energy consumed in 2011, with oil at about 27% and coal at about 53%.

However, energy as a whole is an expanding market in Asia (unlike Europe and US), and the LNG sector is one of the fastest growing segments, helped in the short-term by the Japanese move away from nuclear power.

Limiting factors There are limiting factors to this growth. First, access to gas sources, such as the US shale plays, requires considerable investment in LNG plants and export terminals.

The conversion of the existing Sabine Pass LNG terminal in Louisiana by Cheniere Energy is projected to cost in the region of USD5 billion, Shell's Prelude floating plant is budgeted for at least USD10 billion, and an entirely new land facility such as the one in Wheatstone Australia is reported to cost about USD30 billion.

However, funding for such projects is being found, with a mixture of sovereign and commercial capital. GIC, Temasek, RRJ Capital, CIC and Blackstone, reportedly, have all provided funds to Cheniere Energy. The international aspect to this funding reveals both the significance of the sector, and the role that Asia is playing in financing it. However, such financing remains very specialised and still requires considerable expertise.

The second limiting factor is the current bespoke nature of the LNG sale and purchase contracts. With the significant investments required, long-term supply and transportation commitments have been made to provide the necessary reassurance for the projects.

This means much of the current market is locked into long term contracts at costs linked to the price of oil. However, supplies are expanding and new customers arriving, mainly in Asia, and they are looking for greater freedom in their contractual

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terms, shorter lock-in periods, and lower prices. This may impact on the older contracts, and already discussion is being generated about the link to oil for pricing.

As the stability of supply becomes less of a premium item in the face of a developing open market, the pressure for change will only increase. These pressures will lead to more attention being given to contract details and the leverage these provide for renegotiation. Those in the shipping industry will have seen this before, and will understand that renegotiations often come with a very sharp edge.

The third limiting factor is the maritime transportation of LNG. At the moment, there is minimal spot trading of ships capable of carrying LNG. This is due to a general shortage of LNG carriers, and little prospect of newbuildings arriving until 2015. As such, it is hard to supply new customers via LNG ships Some owners are therefore considering converting newbuild orders for ore carriers to LNG to meet this demand.

This is another area where some intensive negotiations are likely to take place given the significant extra costs involved - assuming the yards have the required expertise.

LNG as a marine fuel New LNG carriers are also likely to be consumers in their own right, as the number of ships using LNG for fuel is set to increase significantly. This is predicted by DNV, who have developed various models for LNG fuel systems. While the costs of converting vessels is high (over USD20M for a large product tanker), building LNG fuel systems into newbuilds is less costly, and the benefits in CO2 reduction and fuel costs would be significant (as high as 30%). Hence the good timing of the proposed new bunker facility and terminal expansion in Singapore.

A bright future With the arrival of more ships, transportation capacity will ease and further reduce the costs of gas for Asia, making it more accessible as an alternative energy source.

Projections vary, but the consensus is that current market levels will double sometime between 2020-2025. However, there remain pinch points for negotiation along the way. Financing, supply and pricing, and shipbuilding/conversion contracts, and vessel performance expectations are all areas of potential dispute. .As the economics of LNG change, companies will need to ensure - legally - their house is in order.

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OilVoice Magazine | DECEMBER 2012

Did oil decide the last three American elections?

Written by Kurt Cobb from Resource Insights Was the most recent American election outcome determined by the presidential debates, changing demographics, voter views on issues, Hurricane Sandy (and the president's reaction to it) or voter turnout? Probably all of these contributed to the result. Energy was actually one of the issues discussed during the campaign, particularly domestic production of oil and natural gas. But, it's not the debate over energy issues that interests me here so much as the price and supply of oil and their effects on voter attitudes. Let's go back to the summer of 2008. The price of oil had been climbing all year reaching its highest level ever (even adjusted for inflation) at $147.27 a barrel on July 11. From there the price began to decline. Though few people knew it, an economy beleaguered by years of rising oil prices was already in recession. The financial markets eventually crashed that fall. And, the worst slump in the world economy since the Great Depression followed.

The bursting of the U.S. real estate bubble in the previous year was frequently cited as the cause of the crash. And, there is little doubt that stresses in the financial industry combined with the real estate collapse to create a financial meltdown. But, the work of economist James Hamilton suggests that high oil prices were also a significant factor in precipitating the bust and therefore the economic pain felt by American voters. All of this implies that the solid victory of Democrats and Barack Obama in 2008 resulted at least in part from discontent among voters over high oil prices. The conclusion seemed obvious even then.

After dipping into the $30 range in late 2008, oil prices rebounded to around $80 by the beginning of 2010 and remained in the $70 to $80 range through election day that year. If we accept Hamilton's work, then high oil prices produced a significant drag on the economy and may have caused swing voters, frustrated by a slow economic recovery and high unemployment, to hand the party out of power a huge victory. They gave Republicans control of the U.S. House and of many additional governorships and state legislatures.

Fast forward to 2012. Oil prices spent much of the year between $90 and $110 a barrel. As high oil prices continued to put a drag on the still slow economic recovery, the year seemed designed to give Republicans a decisive victory--but only if voters perceived that the Republican Party was still the party out of power. In fact, the flamboyance of the Republican-dominated U.S. House and its defiance of the president combined with the swift passage of the Republican agenda in a large number of states may have made the Republican Party seem to many voters like the

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party in power--put there to solve the problems not adequately addressed by Democratic politicians which voters had only just installed during the 2008 elections.

As I indicated, there are certainly other factors besides oil prices that determined this year's election outcome. But I can't help thinking that many voters--still frustrated by slow growth due in part to high oil prices--decided that Republican politicians had not acted to address their economic anxieties. So, those voters simply went the opposite direction and voted for Democrats.

If the pattern I see holds, then continuing high oil prices would lead to a resurgence of the Republican Party in the 2014 elections. Naturally, if prices decline and stay down, oil will not be a central issue. But here is the problem. If oil supplies are going to be constrained in the long term, as I believe they will be, then waiting for supply to rise and for prices to fall will not be a useful strategy for either party. Neither will touting the temporary and overhyped gains in domestic oil production that are, in any case, being offset by declines abroad. Keep in mind that oil is a worldwide market, so Americans will continue to pay world prices whether or not domestic production rises.

The party that addresses constraints in worldwide oil supplies by intensifying efforts to reduce U.S. consumption and speeding a transition to alternative energy would probably likely break the cycle of rapid swings from one party to the other every two years--but not in the way that that party would like. Broaching the subject of limits with voters and acting to address those limits could spell political suicide for the party that does it. Surely, during the next election the opposition party would say that we have plenty of oil and offer a vague plan, however preposterous, to overcome production constraints.

It is true that Democrats have emphasized renewable energy and conservation more than Republicans. And yet, President Obama has repeatedly asserted that he is working to increase permitting of oil and natural gas exploration on federal land as quickly as possible. That's hardly the equivalent of grasping the nettle and giving the voters the bad news, namely, that world oil production has been stagnant since 2005 and that there is little prospect that world production--which is what determines the oil price--will grow much from here.

It's possible that the myth of oil abundance and the powerful oil industry lobby behind it has locked us into a politics which will provide neither party with the decisive majority needed to enact the difficult agenda that would move us toward a more sustainable energy economy. But then, that's the way the oil industry must like it-high prices with promises that eventually, someday, perhaps just around the corner, prices will come down. All you have to do is trust us!

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OilVoice Magazine | DECEMBER 2012

International labour implications of the China shale plays Written by John McGoldrick from Dart Energy In a three part series, John McGoldrick, CEO of Dart Energy International, looks at the developing state of Chinese shale gas projects, and some of the implications these might have on the international industry.

China has recently announced the second round of 20 shale block tenders. Like the first round, this only is open to local companies-many are experienced operators, but others are new to the business. This will open up a range of opportunities as those new to the shale gas sector look to partner with foreign unconventional E&P companies. As China develops its shale gas and CBM resources, the demand for global O&G technical expertise will increase. Many specialists will take up opportunities in the Chinese industry and I expect this trend to have an impact on other countries who are trying to develop shale gas and CBM resources.

Numerous commentators have gone into great depth as to how the Chinese shale gas sector will develop and which local and international companies are planning to be involved. But the scale of the proposed development-both in terms of the estimated reserves and the number of operators looking to be involved, means that there could be far-reaching consequences for those companies who do not plan ahead. If the EIA's figures come even close to being right and there are 1,275 trillion cubic feet (tcf) of shale gas reserves-the global shale and CBM industries will be in for another shake up.

Yes, there are many uncertainties relating to the sector's development (which have been pointed on numerous occasions)-pipeline infrastructure, new geological challenges, gas prices, and developing the right domestic-foreign partnerships.

Additionally, there is the question as to how all of these projects are going to be effectively and efficiently staffed.

But what cannot be denied is that, in true Chinese fashion, there will be pragmatic solutions to these problems. Few other countries have the ability to undertake and support ventures of such scale. Over 80 Chinese public and private sector companies participated in the second round of block tenders for shale gas exploration rights. For those of us who have worked in the Chinese CBM/Shale business, our local expertise and experience is where we have our biggest advantage, and the most to share with local partners.

The reality is, relatively speaking, there have not been many wells put down in

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China. In the US they talk about 'thousands' of wells - in China, it is more like dozens. For domestic companies new to the business, it will be crucial that they either partner with experienced foreign operators or be given time by key industry stakeholders to learn the geological and technical 'ropes' to unlock gas resources.

Foreign companies will also need to learn quickly-both technically and commercially speaking. Companies like Dart Energy International, who already have significant drilling experience and a well established local presence, will have a real advantage.

We already have the people and systems in place.

With numerous countries looking to replicate the US shale gas boom, it is safe to say it is only going to get harder to get quality people onto projects. China's appetite for expertise is famous and can be seen in numerous other industries.

Every major gas producer is facing the same problem. The Australian press has already highlighted access to labour as a major issue and, as China steps up its efforts, competition for the best people will increase. Again, for those of us with China experience, this could be seen as a competitive advantage. Dart Energy International has the ability to bring in key people and skills from across our international operations, and to leverage off the experience we already have on the ground in China. The need to develop local expertise is an issue all players in China will need to address if they are to deliver on the sector's potential.

With China's goal being to produce 6.5 billion cubic meters of shale gas by 2015 and as much as 100 bcm by 2020 there are significant opportunities, in every aspect of the shale gas supply chain. Developing high quality, long-term, local relationships will be an important part of developing the industry, getting results, and building up an effective workforce.

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Oil the St Swithins day massacre Written by Andrew McKillop from OilVoice The subtitle to this story is almost logical, we can call it Frankenstorm and the Oil Patch, because the continuing US storm event throws up so many twists and turns in

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both US oil and energy, and global oil and energy. For oil in particular, we stay logical by noting that the US still consumes around 20% of global oil output, and its oil imports although declining still take about 23% of global traded export supply, estimated at a total near 50 - 52 million barrels/day.

However, from that point on we have the Halloween factor, including unexpected numbers like the ever-growing export supply of mostly refined oil products, and some crude, from the US, where the actual numbers are a complex minestrone soup. What oil traders mostly and firstly trade are ideas, views, opinions, fears and hopes - which the Hurricane Sandy event has supplied in large doses.

Early oil analyst newsbytes (or opinion bytes) were that the storm would or could bump up oil prices because it would bump up demand, at least in the US Northeast.

Within a few days this was disproven by the real world, even if gasoline prices rose due to a mix of factors in no way led or dominated by rising demand and consumption of gasoline. What we will likely find in the US is rising inventories led by rising crude oil stocks - because oil demand has declined. The price bump came, of course, but it disappeared faster than a Halloween pumpkin after the party.

FRANKENSTEIN ECONOMICS IN EUROPE The global macroeconomic picture is about as bad for oil prices as any witch could imagine, even in the heartlands of Eastern Europe's Frankenstein country. Europe in 2012 "celebrates" its sixth straight consecutive year of declining oil consumption: it only goes down. Arguments that the euro "is a strong currency" can still be heard, and a weak dollar is always good for bidding up oil prices in dollars, but the length of forward time that the "euro - dollar premium" holds up, like the "Brent - WTI premium", is counted. Convergence on a downward tilted playfield is the story going forward.

Adding up the Three Horrors of the global macroeconomy today - the US fiscal cliff, Europe's ongoing and intensifying recession, and China rebalancing - all of these are bad for oil and almost anything else. At one time, Bernanke had a headstart on others. His QE was the only show in town and had no rivals, but that has completely changed, today. This in fact made it really unimportant who won the recent US presidentials - whoever won, the US dollar would tend to strengthen and oil prices (and gold prices) would tend to weaken. Europeans were counting on an Obama win, to help rationalize their own massive ECB version of QE featuring the same unbridled money printing effort, targeted at sovereign debt buying, and the economic trick-or-treat mix of swingeing austerity cures for most, and huge handouts of public cash for some, in the always-stricken bank and finance sector across Europe.

Why the euro should command a 28% premium on the US dollar is Halloween-esque questioning (rather than philosophical). Asking why Brent oil should have a 26% premium on WTI grade oil remains philosophical, but the real world moves on. Even Goldman Sachs has now done its mea culpa (in October) regarding the famous Brent/WTI premium, announcing this could shrink to "about $5" by the end of Q1 13.

How come these strange premiums and held sway for so long?

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GEOPOLITICAL HORRORS Today, oil boomers looking and hoping for something that can boost prices, even on a few-days-only basis, have to scrape around in the geopolitical warchest. Syria's civil war might overflow Syria's borders, possibly triggering a kind of Arab Spring-2 in the Gulf Petromonarchies by Q2 13. Obama, with newfound confidence and crossparty support might get back on the Iran bombing trail, also. Anything is possible but these are frail hopes for the oil boomers.

The real action will come from Russia and Saudi Arabia when crude oil prices have sufficiently shrunk to ring warning bells among Kremlin and Wahabite powerbrokers, the Motley Crue which dominates global oil export price setting - for the moment.

The probable outcome is possibly surprising to some, and certainly disappointing to the oil boomers. Both of these secret-and-sinister oil price setter powers are likely to accept without serious qualms that oil supply/demand fundamentals and global energy fundamentals dictate a New Normal "equilibrium price" for oil of around $75 per barrel for Brent.

Lower than that however, they are likely to get irritated or hostile, which both of them know how to do. Also irritated or highly stressed, the CEOs of almost any major Big Energy corporation worldwide will be anxiously looking for the floor price that oil hits on the downside. The stakes are mighty high: below oil prices as high as $75 a barrel - sky high compared with any other form and type of energy - oil exploration and development (E&P) spending will go into a tailspin and the heavily overstretched, overleveraged oil sector will be in a very tight financial situation.

Prices below about $60 a barrel will make this party nastier than a bad Halloween, for Big Energy producers and oil exporter countries.

To be sure, none of this might happen. Oil prices might tremble along and down, slowly, as the background noise of news and views continue to rumble. Crash scenarios for prices, we can suggest are possible but are not likely, but the witches are watching.

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OilVoice Magazine | DECEMBER 2012

The best place to find petroleum Written by David Bamford from Finding Petroleum

There is an old adage that runs "The best place to find oil is in an oil field!"

As global exploration gets more difficult, there is a major prize to be gained by increasing flow rates and improving recovery factors in existing fields. In any petroleum province which is very mature in exploration terms, such as the North Sea, it would be better for companies to stop 'wildcat' exploring and focus on enhancing production in and around existing oil & gas fields.

Statoil has said recently that it plans to increase the average oil recovery rate from its fields on the Norwegian Continental Shelf (NCS) to 60 percent.

Broadly speaking, we can divide the technologies that can help achieve this into two, namely those to do with the reservoir and wells, and those to do with the top-sides: Reservoir and Wells: Themes include: 1. Recognising where there are reserves of undeveloped or unswept hydrocarbons - key technologies are reservoir monitoring (using 4D seismic/permanent seismic monitoring), production monitoring, reservoir simulation, history matching.

2. Mobilising these reserves towards the well bores - key technologies include fraccing, enhanced recovery (EOR) mechanisms (Microbial, WAG, CO2 floods etc).

Top-sides: The broad themes are improving operational efficiency (including 'debottle-necking'), monitoring and improving operational integrity, safety and cost reduction.

The Digital Oil Field then provides an enabling framework in which these key technologies can be deployed for optimal efficiency and effectiveness - key aspects

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include automation and collaborative working environments.

Especially offshore, delivering both production performance and recovery factor improvements requires an integrated field development plan: it is not a matter of simply introducing a single technology.

How big is the prize to be gained by increasing recovery factors?

Sandrea and Sandrea estimate the global recovery factor, the percentage of the total conventional oil volume likely to be produced in the world's oil fields, to be 22% of the oil in place. Using a value of 2158 billion barrels of oil for the ultimate recoverable volume and a 22% recovery factor, the estimate global STOIIP is 9800 Billion barrels. This 22% global recovery factor compares to previously published estimates in the range of 27% to 35%, which were probably over-optimistic.

Typical recovery factors vary world-wide. Average recovery factors for the North Sea are stated to be ~45-46%, the highest in the world, compared with 39% for the USA and 23% and for Saudi Arabia. Examples of individual fields with high recovery factors are Statfjord (North Sea) and Prudhoe Bay (Alaska) with 66% and >47% respectively.

Turning to Enhanced Oil Recovery in particular, Awan et al. have surveyed all North Sea EOR projects initiated in the 30 years 1975 to 2005, and have also reviewed all microbial EOR projects undertaken world-wide. Approximately 63% of the North Sea projects were on the NCS, 32% in the UKCS, the rest in Danish waters: Statoil has been the leader in conducting EOR field operations in the North Sea. Awan et al. conclude that microbial processes, CO2 injection and water-alternating-gas (WAG) injection are the most relevant technologies. Moving the current recovery factor for the NCS of ~45% to the 50% target (for oil; the target is 75% for gas) established by the Norwegian Ministry of Petroleum and Energy would yield approximately an additional 4 billion barrels of oil.

A 22% recovery factor means that 78% of the world's oil will be left behind once all the oil fields are shut in and abandoned, and only 3% of the world's oil is currently produced as a result of Enhanced Oil Recovery (EOR) technologies. Yet experience with one EOR method, the injection of CO2 in the USA and elsewhere, shows that this can result in increases of recovery of between 7 and 15% following initial recoveries using water-flooding.

Hence, for the UKCS, Gluyas has estimated, by comparing the UKCS with West Texas, that an additional 2.7 – 8 billion barrels of technical reserves could result from CO2 injection, corresponding to an increase of recovery factor in the range of 4 to 12%.

Provided the CO2 supply can be found, the US Department of Energy has estimated a minimum of 30 billion barrels is recoverable with CO2-EOR in the USA. It should be emphasised that increasing recovery factors depends on a range of technologies – surveillance, ‘smart’ wells, EOR etc. Nevertheless, worldwide, just a 1% increase in the global recovery factor represents almost 90 billion barrels of oil,

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equivalent to replacing roughly 3 years of production at current levels.

Wherever serious studies have been undertaken, truly astonishing volumes of oil can be contemplated from increasing recovery factors using technologies that are known today. Oil & gas companies can of course chose from many investment options, economically distinguishable from one another by their net margin per barrel (or per Mcf) at some ‘benchmark’ price, for example $70/barrel. The available options include service contracts in Iraq; EOR projects on existing fields; improved primary/secondary recovery projects in existing fields; ‘full cycle’ deep water projects (from exploration through to production); ‘full cycle’ Shale Oil (for example onshore in the USA).

Certainly, it seems reasonable to believe that the current ~10% of all existing discovery volumes that has actually made it to production is very much a lower limit.

In many instances, a rising oil price will ensure that primary/secondary/tertiary recovery projects are economic although in some instances it may be necessary for governments to give tax incentives to help improved recovery projects, for example those based on CO2-EOR, to bring them into existence.

However, for major economic players such as the USA and western Europe, such support would have the significant political advantage of reducing both dependence on imported oil and the outwards flow of funds.

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