ESN Unconventionals 03 January 2012

ESN Oil & Gas

Investment Research Sector Report

Produced & Distributed by the Members of ESN All ESN research is available on Bloomberg “ESNR”, Thomson-Reuters, Capital IQ, TheMarkets.com, FactSet (see last page of this report)

Oil & Gas 03 January 2012

Unconventional Oil & Gas revolution: what is the best investment vehicle in Europe?

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Stoxx Oil & Gas Stoxx TMI (Rebased)Source: Factset Sector Top Picks TP – FV

Repsol Ypf Accumulate EUR 29.93

Total Buy EUR 54.00

Galp Energia Buy EUR 18.70

Report coordinator Jean-Luc Romain CM - CIC Securities France Sector coordinator(s) Jean-Luc Romain CM - CIC Securities France

Sector team Carlos Jesus Caixa Banco de Investimento Portugal Dario Michi Banca Akros Italy Sonia Ruiz De Garibay Bankia Bolsa Spain Henri Parkkinen Pohjola Finland

US and European Oil Majors have been quietly but relentlessly redrawing the Global Energy map in the past few years. For decades, their main development grounds were in ever harder to access conventional resources in the developing world, from the Persian Gulf to the North African deserts, and from the Niger Delta to the Caspian Sea.

In recent years, their focus has undergone a radical geographical change. Western energy majors are increasingly exploring for resources in rich, developed countries. The boom in unconventional resources – hydrocarbons like shale gas, tight oil and oil sands that were once considered too difficult and expensive to tap - is driving this change. These resources are now being exploited on an unprecedented scale, from Australia to Canada, and Argentina...

Fast growing production, Majors' land grab In less than a decade, US Shale Gas production has grown from virtually zero to 9 Bcm/day in 2010, ie 13% of US Gas production (vs 63% for conventional gas production). It is expected to double to 18 Bcm/day by 2020, representing 27% of production (vs 47% for conventional gas). Tight Oil production growth has been even faster, rising from 1.5% of US oil production in 2008 to 5.3% in 2010. It is expected to reach 10.3% by 2012 according to the International Energy Agency.

Vast Unconventional resource availability is not limited to the USA or North America. According to recent Energy Information Administration reports, China, Argentina, South Africa and Europe also have huge technically recoverable resources.

European oil majors have been very active in developing their positions in unconventional resources, both in North America and in the rest of the world, as evidenced by the ENI, Statoil, and Total acquisitions in the USA and elsewhere, from Indonesia to Argentina... They expect to generate huge value by exploiting these resources : over 5$/b NPV in the current price and cost environment, and nearly double that figure with lower drilling costs for the Vaca Muerta oil shale formation in Argentina....

Top Picks With its huge discovery in Argentina - 927 Mboe over an area of 428 square kilometres representing barely 3.5% of its potentially tight oil rich acreage, but a 44% increase in its end 2010 proven reserves, Repsol YPF naturally ranks first in Europe for exposure to unconventional resources.

Total’s Canadian Oil Sands exposure, its CBM to LNG project in Australia, its positions in the Barnett Shale and early January 2012 USD2.3bn acquisition of 25% of Chesapeake’s interests in the Utica shale in the USA, as well as its acreage in Argentina, make the French supermajor an attractive way to play the non conventional hydrocarbons revolution...

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Contents

Recommendations and Target Prices ................................................... 4

Sector valuation ........................................................................................ 4

Limited access to conventional resources drive IOCs' positioning in unconventional plays ...................................................... 5

Limited access to conventional resources... 5

... means that IOCs are struggling to meet production targets 6

What are unconventional hydrocarbons? ............................................. 6

Three main sources of unconventional gas 6

Unconventional oils: extra heavy oil and tight oil 8

How are they produced? ........................................................................ 10

Shale gas, tight gas & oil – one proven technology: multifractured horizontal wells 10

Shale gas, tight gas & oil: environmentally unfriendly? Not so fast! 13

At what cost and profitability? .............................................................. 14

Horizontal drilling and fracturing progress is driving costs down... 14

... shifting the focus of unconventional CAPEX towards liquids... 14

... And dramatically improving profitability 16

Massive resources: The unconventionals’ revolution ...................... 17

USA: Unconventional oil & gas help reverse the decline of production 17

USA: 750Tcf of unconventional gas and +24bn barrels of tight oil 18

Unconventional resources abundant in the Rest of the World 19

Focus on Argentina: Viva la Vaca Muerta! 22

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European majors’ positions: Repsol best placed .............................. 23

Repsol YPF: Vaca Muerta a “dream come true” with more to come 23

Total: a significant oil sands player developing shale positions 27

The acquisition of a stake in Chesapeake’s Barnett shale development was a key step for Total in unconventional gas. 28

Eni’s unconventional E&P strategy 32

Galp: Mostly a conventional hydrocarbons play 33

BP: Strong Vaca Muerta position through Pan American Energy 34

Shell: Appraising South Africa’s Karoo basin, positions in China 35

Statoil: building a large North American unconventional position 37

Performance overview ........................................................................... 42

Upcoming corporate calendar .............................................................. 42

ESN Recommendation System ............................................................. 43

All prices as of 30 December 2011

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Recommendations and Target Prices

Company Country Rec. Price Target Price Upside Market 30-Dec-11 Fair value potential cap EUR (m)

Eni IT Accumulate EUR 16.01 19.70 23.0% 64,126Galp Energia PT Buy EUR 11.38 18.70 64.3% 9,434Neste Oil FI Reduce EUR 7.81 8.80 12.7% 1,997Repsol Ypf ES Accumulate EUR 23.74 29.93 26.1% 28,969Total FR Buy EUR 39.50 54.00 36.7% 88,658Mkt cap total (EUR) & Weighted averages 193,184

Sector valuation Company P/E adj. EV/EBITDA P/BV Div.Yld %

2011 2012 2013 2011 2012 2013 2011 2011Eni 8.5 7.9 8.8 2.6 2.4 2.5 1.2 6.4Galp Energia 39.8 27.0 18.2 15.1 11.2 9.3 3.2 1.8Neste Oil 19.7 10.3 8.2 9.1 6.7 5.9 0.8 3.2Repsol Ypf 13.5 10.9 9.3 4.8 4.1 3.8 1.2 4.9Total 6.1 6.0 6.8 2.2 2.1 2.2 1.3 5.8Weighted average 7.8 7.3 7.9 2.8 2.6 2.7 1.3 5.7Arithmetical Average 15.9 11.6 9.9 6.1 4.9 4.4 1.5 4.6Median 11.0 9.1 8.5 3.8 3.4 3.3 1.2 5.3

Source: ESN estimates

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Limited access to conventional resources drive IOCs' positioning in unconventional plays

Limited access to conventional resources... Over the past 10-15 years, and more generally since the resource nationalisation wave in the 1970s,International Oil Companies (IOCs) have experienced increasing difficulties accessing easy to produce, conventional oil reserves.

To start with, many of the largest oil basins in the world are approaching technological maturity—they are reaching their production limits using conventional technology. This is true of fields from the Persian Gulf countries to Mexico, Venezuela and Russia. In order to maintain their production in the future, new technologies will be required in these fields.

The second factor is the limited access to oil resources for Western oil companies. Today, more than 90% of the world's oil is under the control of producing countries through their national oil companies, state owned behemoths like Saudi Aramco, Iran National Oil Company, PEMEX, Petroleos de Venezuela, OAO Rosneft or OAO Gazprom.... The current wave of resource nationalisation can only worsen this situation, because several important producers are already able to manage the development of their "easy" oil on their own.

Growing State control over resources

Source: IHS Energy

The abundance of unconventional hydrocarbon resources and continuous progress made in exploiting them is reshaping oil companies themselves, as they reallocate their large financial resources to new areas and new kinds of fuel. Indeed, working in OECD countries - with more predictable taxes and investor friendly policies (not always, e.g. French ban on hydraulic fracturing) remove some risks regarding IOCs that are a source of concern for investors, such as resource nationalisation. IOCs can almost eliminate technological risks – which still exist though – but can’t eliminate political risks from countries like Russia (cf. BP, Shell) or Venezuela (Exxonmobil, ConocoPhilips).

While big onshore fields are increasingly the preserve of National Oil Companies, IOCs have responded with a huge push in new areas, both geographical and technological. Over the past few decades, they have developed vast plants to produce liquefied natural gas (LNG). They have drilled for oil, and gas, in ever deeper waters, ever farther offshore. They have worked out how to produce oil from the tar sands of Alberta –unlocking nearly 200 bn barrels of economic oil reserves in Canada’s province of Alberta alone.

And they have deployed technologies like hydraulic fracturing, or fracking, and horizontal drilling to produce gas and oil from shale rock...

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... means that IOCs are struggling to meet production targets Recovering more oil from mature oil fields and discovering it across new, daunting frontiers is the only way to open up new growth opportunities in an otherwise shrinking world for Western oil companies. These increasing difficulties raising production have taken a toll on International Oil Companies' valuations, as they have been generally unable to meet their production targets in the past few years, while some are still at risk of not meeting their current targets.

This is still the case today, and a recurring question is: who’ll be the next company to downgrade its targets?

Plausible answers:

• Statoil, as overseas growth does not fully offset Norway’s decline

• BG Group, which depends on North Sea production (coming back on-line of the Buzzard field after commissioning of new facilities),

• Possibly ENI depending on Kashagan’s ramp up from end 2012 (or in 2013?)

What are unconventional hydrocarbons? The resource triangle: from Conventional to Unconventional

Source: SPE

Three main sources of unconventional gas Conventional and unconventional gases differ not in their chemical compositions (all these resources are natural gas) but rather in the geological characteristics of their reservoir rock. Unconventional gas is trapped in formations that are atypical in terms of their geological location and characteristics. Recovering the resources requires the use of techniques designed to free the gas.

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Different types of unconventional gas – different types of reservoirs

Source: Total There are three types of non-conventional gas:

• Tight Gas or gas from ultra compact reservoirs. The quality of a reservoir depends on two key parameters: its porosity and its permeability. Porosity refers to the volume of tiny spaces in the rock, i.e. the pores, in which hydrocarbons are lodged. Permeability reflects the rate at which hydrocarbon fluids are able to circulate. The oil reserves that are easiest to exploit have good porosity and good permeability. The opposite is the case for tight gas reservoirs, which have low porosity and low permeability and hence it is very difficult to extract the gas.

• Shale Gas. Certain shale rocks also contain methane lodged in their fissures. The gas is formed through the degradation of kerogen (transformed organic material) present in the shale. In the case of gas shale, some or all of the gas released during the transformation of the biomatter stayed in place. To be a candidate for gas extraction, source rocks must have reached sufficient maturity to generate the gas, without yet having expelled it. As for CBM, there are two big differences in relation to conventional gas: 1) the shale is both the source rock of the gas and the reservoir; 2) the accumulation is not discrete (a lot of gas is found in the one area) but is continuous (the gas is present in low concentration across a large volume of the rock), which makes exploitation more difficult. A gas shale therefore is a rock formation that contains shale gas.

The quality of a reservoir rock is determined by its porosity and its permeability. Porosity is the void space between the grains, and thus represents the rock’s capacity to contain fluids (liquid or gaseous hydrocarbons). A highly porous reservoir rock can therefore contain a large volume of oil or gas. But porosity alone is not enough: the fluids must be able to flow, meaning that the pores must be interconnected. This characteristic, called permeability, is the measurement of the rock’s ability to transmit or allow the flow of the oil or gas.

A common feature of shale gas and tight gas is that both are trapped in very low-permeability rock – ultra-compact structures that prevent or sharply limit the migration of the gas. The unit of permeability measurement is the Darcy. Permeability is one of the parameters by which conventional gas reservoirs can be distinguished from unconventional formations. A good-quality hydrocarbon trap will have a permeability of 1 Darcy or more, while tight gas reservoirs, more compact than brick, may have permeability of only a few dozen micro Darcies. The permeability values of gas shales are even lower – up to 1000x less than the permeability of tight gas formations.

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Permeability differentiates conventional gas from unconventional

Source: Total

• Coalbed methane (CBM). Coal naturally contains methane and CO2 within its matrix. Historically, this gas has posed a mortal threat and safety hazard to miners – it is embedded in the collective memory as coal seam gas. Most of the gas is adsorbed on the surface of the coal, which is an excellent "storage vessel": it can contain two to three times more gas per unit of rock volume than conventional gas deposits. Exploitation of this gas is growing, especially in the US and Australia (Gladstone LNG, Total; Queensland Curtiss LNG, BG Group). Exploitation is concentrated on layers of coal that are rich in gas and too deep to be exploited using conventional methods. Trials are also underway in Europe.

Coalbed Methane (CBM): produced from shallower subsurface layers

Source: Total

Unconventional oils: extra heavy oil and tight oil Two kinds of non conventional oils are currently exploited on a fast growing scale:

• Extra-heavy oil is found in extremely large quantities in countries such as Venezuela or Canada,

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• and Tight oil, usually a medium to light oil, is found in very low permeability rock formations such as shales. It is largely present in liquid-rich unconventional shale gas plays. Tight oil should not be confused with oil shale or shale oil. It differs in its API gravity, the viscosity of the fluids, and the method of extraction.

As major sources for replacing global oil reserves, extra-heavy oil and natural bitumen have a pivotal role to play in the oil industry. Tough to produce, they require complex, costly technology chains that are energy and water intensive. The potential resources are Colossal: an estimated 2.6 trillion to 3.8 trillion barrels lie beneath the Earth's surface. Their extreme viscosity heightens their resistance to flow, meaning that they are nearly or completely immobile in their reservoirs. Unevenly distributed across the globe, most extra-heavy oil is found in Venezuela and Canada. Extracting it is a high-stakes game, since it represents 500 billion to 1 trillion barrels of potential reserves, or about 25% of the world's conventional crude oil reserves.

Tight Oil: huge resources, very low recovery factor. Tight oil differs from gas shale only in that the organic matter has transformed into oil instead of turning into natural gas. Indeed, during the thermal generation of hydrocarbons from the organic matter within the shale, a large amount of the oil and/or gas generated is expelled, migrating to a reservoir or possibly escaping to the surface. However in this type of unconventional reservoir, a significant amount of the hydrocarbons generated remain trapped within the low permeability shales and siltstones as a “free” phase within fractures and the pore system.

Tight oil formations include:

• the Bakken Shale, the Niobrara Formation, Barnett Shale, and the Eagle Ford Shale, among many others, in the United States,

• the R'Mah Formation in Syria,

• the Sargelu Formation in the northern Persian Gulf, the Athel Formation in Oman,

• the Bazhenov Formation and Achimov Formation in West Siberia,

• the Vaca Muerta formation in Argentina,

• and the Chicontepec Formation in Mexico

What do tight oil bearing shale formations look like?

Sources: Statoil, Bentek

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How are they produced?

Shale gas, tight gas & oil – one proven technology: multifractured horizontal wells In order to determine the commercial development potential of a gas shale, it is necessary to ascertain the porosity, the saturation level, the permeability and the proportion of organic matter (kerogen), ie the Total Organic Content. Additionally, the thicker the shale formation is, the larger the volume of rock containing organic matter.

The experience of Schlumberger TerraTek in various gas shale basins in the US shows that in order to be commercially viable, gas shale reserves must be equal to or higher than the following parameter levels:

• Porosity > 4%

• Water saturation < 45%

• Oil saturation < 5%

• Permeability > 100 nano darcies

• Total organic content >2%

The evaluation of reserves is made more complicated by the fact that gas shale is produced from formations that are notoriously heterogeneous. Shale quality can vary abruptly in vertical and lateral directions, with intervals of high reservoir potential juxtaposed with lower quality sections. Moreover, shale with good quality reservoirs can see their “useful thickness” expand or contract laterally over short distances, while gross shale thickness remains unchanged.

To bring the gas to the surface, the rock must contain enough “pathways” to favour the gas’s travel to the wellbore. In the shale formations, very low permeability can partly be offset by natural fractures in the source rock. If not, artificial fractures are created using fracking.

To expose more of the wellbore to the gas shale reservoir and take advantage of natural fractures in the rock, operators increasingly use horizontal drilling. Drilling sharply deviated or horizontal wells makes it possible to place the well path within the productive intervals over long distances. Though this technique is not new to the industry, it has been instrumental in the success of shale gas developments.

The role of horizontal drilling is clearly demonstrated by the growth of development in the Barnett Shale in the Fort Worth Basin in central Texas. Starting with a vertical well drilled by Mitchell Energy in 1981, it took 15 years to exceed 300 wells in this play. In 2002, Devon Energy, after acquiring Mitchell, started to drill horizontal wells. Within three years, over 2,000 horizontal wells had been drilled! This technology has kept improving

Furthermore, experience in the Barnett Shale has shown that horizontal wells in this play attain approximately three times the ultimate reserves of vertical wells for only twice the cost.

Other technologies have been vital to the development of gas shales. Using 3D seismic interpretation, operators have been better able to plan horizontal wellbore trajectories. This has helped operators to expand the Barnett Shale's development to areas previously thought unproductive due to the presence of water bearing rock. The use of directional drilling techniques can help to offset torque and drag on the drilling string (composed of resistant seamless pipes).

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Gas Shale and tight gas : A typical well profile

Source: WSJ Research; Al Granberg Chesapeake Energy

Moreover, natural fractures, although beneficial, do not allow sufficient permeability for commercial gas shale development. Most gas shales require hydraulic fracturing (cf. previous chart) in order to be developed profitably. The aim of this process is to create permeability where Nature did not. Injecting highly pressurized water into the rock creates a network of cracks that allow the gas to migrate to the wells. The injection water is mixed with:

• proppants, materials such as sand or ceramics that hold the cracks open once they have formed;

• a very small quantity of additives (around 0.5% of the total injection volume). These additives are mainly bactericides, gelling agents, and surfactants. The composition of the additive package depends primarily on the well conditions: pressure, temperature, proppant quantity. In addition to sterilizing and preventing bacterial contamination of the reservoir, the additives serve to improve the efficiency of the process.

Each well must be fractured in several stages; the less permeable the reservoir, the more stages are needed.

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Shale gas well fracturing – Key figures

• An average of 30 fracs for a 1,000-m well

• For each frac: 300 m3 of water, 30 metric tons of sand and 0.5% of additives

• Typical frac dimensions: lateral distance of about 150m on either side of the well; vertically over a height of a few dozen meters (limited by the formation thickness)

Gas shale wells have a fast exhaustion rate: up to 80% of production is generated in year one, which means that new wells must constantly be drilled to maintain production levels.

Barnett Shale: target profile for annual decline in production of a typical well

Source: Chesapeake Energy

Some well-known tight oil plays in North America are Bakken/The Williston Basin, Niobrara and Eagle Ford. Tight oil reservoirs can consist of shale or other tight rocks.

In the Bakken formation, the oil is extracted from tight carbonate. In the Three Forks formation the oil is extracted from tight dolomite.

To unlock the oil from these tight rocks, the reservoir is stimulated using the same technologies as in shale gas production. Horizontal wells are drilled into the oil bearing formation and the reservoirs are fractured to allow the oil to flow into the well.

Tight oil wells have production profiles similar to those of shale gas wells – they have an initial and relatively short lived peak, before stabilizing at a lower output level that can continue for decades.

Commercial tight oil extraction is a relatively new activity and has increased significantly in the last couple of years.

The oil produced from tight oil plays is of a light crude grade, ie above 30-32° API.

Tight oil should not be confused with oil shale, which is very different with regards to oil quality and extraction methods. Oil production from Brigham’s assets in Bakken is Co2 efficient, with emissions per barrel below the average level for oil produced on the Norwegian Continental Shelf.

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Shale gas, tight gas & oil: environmentally unfriendly? Not so fast! The very fast growth of shale gas production and widespread use of hydraulic fracturing – as tested and proven and which has been used in over one million wells over the last 50 years – has sparked many debates over the potential hazards it may cause to the environment. The main claims against gas shale production and the associated hydraulic fracturing techniques are:

• Risks of contamination of aquifers by gas leaks from the wells or due to the artificially created fractures in the rock by the chemical products injected in the well at high pressure,

• Large use of water potentially diminishing the availability of this rare resource for other users,

• Impact on the landscape due to high number of wells required,

Although risk is inherent to any industrial or extractive activity, we would argue that the risks entailed by unconventional gas production are well identified and integrated in the processes of most Oil & Gas companies or service companies working to produce unconventional resources.

True, in a few, rare instances, sub-standard companies have performed bad well cementation jobs when isolating aquifers from the wellbore, resulting in gas leaks. Nevertheless, no water contamination resulting directly from hydraulic fracturing has ever been documented by the US Environmental Protection Agency, or its equivalent at state level. Otherwise, the risks of contamination due to well integrity issues are well know to the Oil & gas industry and others, and require compliance with regulations and good industry practice. As regards the nature of the chemical products used in the fracturing fluids (0.5% of the total volume), their composition is now mostly public and industry leaders like Halliburton are now using products coming exclusively from the food manufacturing industry (CleanStimTM).

As regards water use and the ‘‘drain’’ on other users, the chart below speaks for itself.

Water use for hydraulic fracturing: example of the Haynesville Shale, USA

Source: All Consulting – Presentation to the Ground Water Protection Council, San Antonio, Texas, Jan. 2009

Landscape protection: wells in an “unconventional” formation drain a smaller volume of rock than wells in a conventional gas reservoir. To limit the physical footprint of the operations, wellheads are grouped together in clusters, with 10 to 30 horizontal wells being drilled from a single point.

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At what cost and profitability?

Horizontal drilling and fracturing progress is driving costs down... The main factor driving the cost of production for unconventional hydrocarbons, whether oil or gas, is the cost of drilling and fracturing the wells in a way that maximises production over the life of these wells. In the last few years, the drilling of wells with longer lateral sections and with more fracturing stages (1 in 2006, up to 42 in 2011) has dramatically driven down per barrel finding and development costs. They were reduced more than 3-fold in barely 4 years in the Bakken and Three Forks shale, as Economic Ultimate Resources (EUR) per well rose from 110,000 barrels in 2006 to 500-700,000 barrels in 2009, while drilling and fracking costs rose from USD3,5m to USD 7.5m.

Bakken / Three Forks Well Performance and Economics

Source: Brigham Exploration, Haliburton

... shifting the focus of unconventional CAPEX towards liquids... The combination of falling production (finding and development) costs, not only in the Bakken shale, but in most US unconventional oil and gas plays, and of rising crude oil prices over the last few years has translated into:

1) very high profitability and rapid paybacks for these kinds of wells;

2) a reorientation of capital expenditures from gas to oil shales by the major US unconventional resources players, such as Chesapeake, Devon or EOG Resources, particularly as US gas prices are at low levels.

Indeed, over the last 3 years, Chesapeake Energy (CHK) has strongly increased the proportion of its capital expenditures directed towards liquid production, from 13% in 2008 to 50% in 2011e, and expects to spend 70-75% of its investments on developing tight oil production over the next two years.

The result of this profound shift in capital expenditure is that liquids (Oil + Natural Gas Liquids like Butane) will represent 30% of CHK’s production by 2013 – ie more than 150 kb/p, vs barely 8% in 2008.

As price realizations per barrel equivalent of liquids – around $85/b currently, are much higher than for natural gas – around $25/boe, liquids should represent 52% of CHKs revenue by 2013 vs 11% in 2008.

[

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Chesapeake Energy: CAPEX …


And production growth is shifting to liquids


The reason for this massive shift towards liquid production is very easy to understand: based on $95/Bbl and $4/Mcf, an Oil Well generates 3 times the cash flow of an equivalent rate Gas Well, ie $176k/day for a 2000 boe/d oil well, vs $60k/d for a 2000 boe/d gas well…

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... And dramatically improving profitability Based on the early November NYMEX crude oil price, a -8$/b realized price differential, the $8.9m cost of a drilled and fracked well, and a $15,000/month OPEX, Brigham Exploration, now acquired by Statoil, estimated the payback period for a typical Bakken Shale well, whose production would start at 1000bopd during the first months, fall to 110-120bopd by the end of the first year and evolve between 90 and 20 bopd during the next 18 years (see table next page). The results are striking, both in terms of payback -1.5 to 2.6 years - and the Internal Rate of Return – between a ‘’ low’’ case of 34% and a best case of 77%.

Williston Basin Reserves & Economics per Well

Reserves per Well NPV @10% PV10%/$ coverage

Rate of Return

Payout (years)

Economic life (years)

500 kboe $5.7m 1.6 34% 2.6 29.7

600 kboe $8.7m 2.0 51% 1.9 31.8

700 kboe $11.7m 2.3 77% 1.5 33.5

Source: Brigham Exploration

As can be seen below, the rate of return of is very sensitive to realized oil prices, with a range of 1 to 9. This tremendous opportunity has driven a very intense exploration and development boom in tight oil rich regions in the USA. It is helping unearth billions of barrels of new resources, in the USA and elsewhere, and reverse the three decades long decline in US oil production…

Return on Investment and IRR of a typical 600 kboe tight oil well

Source: Brigham Exploration

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Massive resources: The unconventionals’ revolution

USA: Unconventional oil & gas help reverse the decline of production In its latest Medium‐Term Oil and Gas Markets report, published in July 2011, the International Energy Agency highlighted how the application of horizontal drilling and hydraulic fracturing techniques, which have been used to access natural gas, could also be used to access liquids from the same tight oil formations. The combination of these techniques with lessons learned producing shale gas has greatly boosted oil recovery rates.

Indeed, light “tight” oil from these newly tapped resources will most probably be the single largest driver of incremental oil production in the USA in the medium‐ (and even long‐) term. Indeed, the number of oil drilling rigs in the United States jumped by 133 during Q4 2011 to 1,193, the highest on record and 56% higher than at end 2010.

In North Dakota, where the Bakken and Three Forks acreage accounts for almost 90% of production, monthly output has risen by 6% on average in the last three months. Fourth quarter 2011 output is forecast to grow by over 60% annually.

The number of rigs drilling for oil in North Dakota jumped nearly 50% to an average of 168 in 2011 vs 2010 (x3.4 vs 2009) and a sharp uptick in development well approvals was noted. These leading indicators are also evident in the Monterey (California), Niobrara (Rockies), and Eagle Ford (Texas) tight oil formations. This has prompted the International Energy Agency to revise its outlook for 2012 light tight oil production by around 120 kb/d to 810 kb/d.

US Total Oil Production by Source (Mb/d)

Source: IEA

The chart above shows that unconventional oil production rose from 1.5% of US oil production in 2008 to 5.3% in 2010 and it is expected to reach 10.3% by 2012 according to the International Energy Agency.

It is true that Tight oil production is not cheap, with some estimates placing per barrel production costs at around $40‐$55, and it requires extensive infrastructure to collect small volumes from dispersed wells. Transporting the oil to the Gulf Coast adds additional costs. But producers can get Louisiana Light Sweet equivalent prices for their oil ($7-10/b more than WTI). As long as oil‐to‐gas price ratios remain at high levels, producers will maximize the liquid output of their resources.

An additional possible constraint could be takeaway capacity, especially in areas of the Williston Basin in North Dakota and eastern Montana. Even though current production exceeds existing pipeline and rail capacity from the area, construction of additional pipeline capacity means there should not be a real constraint until at least the end of 2013. This

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means production should continue to grow massively in the Williston basin over the next few years, as shown in the chart below.

Williston Basin Production and Takeaway capacity forecast (kb/d)

Source: Bentek Energy, October 2011

Takeaway capacity and economics are less of a constraint in the Eagle Ford shale (South west Texas), where producers benefit from close proximity to the Gulf Coast refining centre, high gas liquid content, and high initial oil production rates. Production in the area tripled over the course of 2010. Since then, it has more than doubled in 2011 to over 300 kb/d.

With rising production, trucking and rail takeaway capacity have also ramped up, and 1 mb/d of new transmission and 465 kb/d of processing capacity are planned to handle new crude and associated gas production.

USA: 750Tcf of unconventional gas and +24bn barrels of tight oil This massive production growth from new areas is linked to the unearthing of massive new unconventional resources by oil and gas companies. In a report prepared for the US Department of Energy’s Energy Information Agency (EIA), the INTEK shale resources report estimates the shale gas and shale oil resources for the undeveloped portions of 20 shale plays that have been discovered.

The results of this evaluation estimate a total of 750 trillion cubic feet (Tcf) of technically recoverable shale gas resources, with 86% located in the Northeast, Gulf Coast, and Southwest regions. In these 3 regions, the largest shale gas plays are the Marcellus (410.3 Tcf, 55 % of the total), Haynesville (74.7 Tcf, 10 % of the total), and Barnett (43.4 Tcf, 6 % of the total).

The INTEK shale report’s assessment of technically recoverable shale oil resources amounts to 23.9 billion barrels onshore in the Lower 48 States.

The largest shale oil formation is the Monterey/Santos play in southern California, which is estimated to hold 15.4 bn barrels or 64 % of the total shale oil resources. The Monterey shale play is the primary source rock for the conventional oil reservoirs found in the Santa Maria and San Joaquin Basins in southern California. The next largest shale oil plays are the Bakken and Eagle Ford, which are assessed to hold approximately 3.6bn barrels and 3.4bn barrels of oil, respectively. We should also mention the Utica Shale, a formation lying below

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the Marcellus shale. This deeper-buried formation – lying below the Marcellus shale - might contain over 15Tcf of gas and 5.5bn BOE of crude oil, mainly in the State of Ohio.

These evaluations could be seen as conservative! Indeed, for the Bakken and Three Forks formation in the Williston basin alone (North Dakota and Montana), the recoverable resource estimate is 5-24bn barrels! Moreover, Anadarko very recently estimated its net resources in the Niobrara Shale at between 500Mboe and 1.5Bn boe, of which 60% should be oil and 10% natural gas liquids...

Map of U.S. shale gas and shale oil plays

Source: U.S. Energy Information Administration

According to BENTEK’s report, the Monterrey/Santos tight oil play has the biggest potential in the USA. The depth of the shale ranges from 8,000 to 14,000 ft deep and is between 1,000 and 3,000 ft thick. The shale oil play has an average EUR (Economic Ultimate Resources) of 550 kb per well and approximately 15.42 bn barrels of technically recoverable oil.

With 873 000 net acres of leases, Occidental Petroleum (Oxy) owns nearly 78% of the rights to this play. It has already “de-risked” approximately 200,000 acres as viable for shales. It has stopped short of providing an estimate of its recoverable resources, but recently mentioned California Shale could become Oxy’s largest business unit within 10 years...

Unconventional resources abundant in the Rest of the World Earlier this year, the Energy Information Agency published a report evaluating shale gas resources outside of the US. 48 shale gas basins in 32 countries (excluding Russia and the Middle East), containing almost 70 shale gas formations were assessed. The assessed formations constitute the most prospective shale gas resources in a select group of countries with relatively near-term promise and basins that have a sufficient amount of geological data for resource analysis.

The initial estimate of technically recoverable shale gas resources in the 32 countries examined is 5,760 Tcf. This compares to world proven reserves of natural gas of about 6,609 Tcf. and world technically recoverable gas resources of about 16,000 Tcf, largely excluding shale gas.

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Global Major Shale Gas Basins

Map of 48 major shale gas basins in 32 countries


Shale gas development may appear most attractive in 2 groups of countries:

• those that are currently highly dependent upon natural gas imports, have at least some gas production infrastructure, and whose estimated shale gas resources are substantial relative to their current gas consumption. France – despite its recent ban on hydraulic fracturing - Poland, Turkey, Ukraine, South Africa, Morocco and Chile are in this group;

• the second group consists of countries where the estimated resources of shale gas are considerable (e.g., above 200 Tcf) and where there already exists a significant natural gas production infrastructure for internal use or for export. Canada, Mexico, China, Australia, Libya, Algeria, Argentina, and Brazil are part of this group.

The results of this assessment show that:

1) China may have shale gas resources 30% higher than those of the US;

2) Argentina ranks third and also has large-scale tight oil resources;

3) Europe’s resources may help the continent dramatically reduce its dependence on imports in the long term.

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Assessment of gas shale resources in 32 countries


The success of shale gas and tight oil developments, the soaring production in North America and its very comfortable returns have spurred small, independent E&P companies and global oil majors to secure very large portfolios of mineral rights in the most promising regions for unconventional resources.

In particular, European oil majors have been very active in acquiring or partnering US companies since 2008. They also greatly increased their positions in very promising, open to IOC countries, such as Poland or Argentina.

In a contrary move, France, whose shale oil resources may reach 4-10bn barrels according to various estimates (Repsol YPF analysis, Toreador Resources, etc.) in addition to its large shale potential, decided to ban hydraulic fracking altogether – based on exaggerated environmental concerns – and even went on to cancel some permits.

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Focus on Argentina: Viva la Vaca Muerta! While the EIA’s global report highlighted Argentina’s shale gas potential, ranking the country n°3 in the world, Repsol YPF announced that its exploration drilling campaign of the Vaca Muerta Formation in the Loma La Lata area in Neuquen province (covering only 428km2 out of the 12,000km2 of concessions in this region) had it believe that there are 927 million barrels of recoverable resources, o/w more than 740 million barrels of oil. This is a huge discovery compared to the size of its proven reserves (2,092 mboe).

Vaca Muerta location and source rock maturity map

Source: YPF, * Maturity map code – Red = Dry gas window,Yellow = Wet gas window, Green = Oil window

This discovery and the geological characteristics of the Vaca Muerta shale formation may rank it as one of the best unconventional oil potential resources in the world, on a par with the Bakken shale of the Monterey shale in the US (i.e. multi-billion barrel potential).

The Vaca Muerta shale is present in an area of 30,000km2 (7.4 million acres). Its thickness is greater than 200m which distinguishes it from most of the best US shale plays.

Vaca Muerta: very good properties compared to US shale plays

Vaca Muerta Barnett Haynesville Marcellus Eagle Ford Bakken

Total Organic Content 6% 5% 2% 12% 4% 12% Thickness (m) 200m 91m 76m 61m 61m 30m

Depth (m) 3,000m 2,286m 3;658m 2,057m 2,287m 1,829m

Area (km2) 30,000 16,726 23,310 245,773 5,180 51,800

Reservoir pressure 9,000 psi 3,525 psi 10,800 psi 3,375 4,502 4,200

STOOIP (Mb) ? - - 114,000 200,000

STOOIP/km2 (Mb/km2) 33-58 - - - 22 3.9 (3-5)

OGIP (Tcf) 687 422 717 1,499 - -

OGIP/km2 (Bcf/km2) 168 25,3 30,8 6,1 - -

Sources: SPE, EIA, WM, UG harts, YPF

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European majors’ positions: Repsol best placed

Repsol YPF: Vaca Muerta a “dream come true” with more to come At the beginning of November 2011, Repsol announced the discovery of an unconventional oil resource in the Vaca Muerta formation, in the Loma la Lata area, in Argentina’s Neuquen province. Repsol holds 12,000km2 of exploration rights in that area, with 9,311km2 in the oil window, 670km2 in the wet gas window and 2019km2 in the dry gas window.

Repsol YPF positions on the Vaca Muerta play

Source: YPF

The results obtained in the first area (428km2 in the Loma la Lata and Loma Campana blocks) point to 927 mboe of recoverable resources, of which 741 mboe are liquids and of high quality (40-45º API). This volume of resources is similar to YPF’s reserves at end-2010 (992 mboe) and represents around 45% of Repsol’s total (2,092 mboe).

Likewise, exploration on a second 502km2 area (Bajada de Añelo block) has begun, for which the wells drilled so far (2 completed out of 3) are showing exactly the same results (300-600 b/d) of high quality oil (35º API). Results are expected in early 2012.

Repsol YPF is aiming firstly to step up exploration in this field (it owns rights covering 12,000km2) and is planning to drill 17 additional exploration wells across all the blocks in 2011-2012. When we visited the Loma la Lata well sites in November 2011, 7 wells were being drilled and another 10 were to be drilled on several blocks spanning a large part of Repsol YPF’s acreage in the region.

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Indeed, Repsol’s shale oil discoveries on the Vaca Muerta formation could translate into tens of billions of barrels of recoverable resources if the results on a first area of appraisal are the same elsewhere, which is likely. Loma la Lata discovery – Drilling results by end-September 2011

Source: YPF

Secondly, Repsol will step up the development of its output from this new, “truly colossal” unconventional oil resource. This means that, whereas 8 drill rigs out of the 80 present in Argentina are currently being used for the exploration and development of unconventional oil and gas output, this figure should rise by between 30 and 40 rigs in 3 to 4 years. By then, the target will be to drill several hundred wells per year (vs 36 in 2012e, of which 12 horizontal and 24 vertical) and an oil production target of 50 kb/d, vs 5 kb currently, which would be enough to stop the decline in oil output in Argentina, estimated by YPF at 2.3% in 2010 and 2.7%/year over 1998-2010.

Repsol's Upstream investments in Argentina should therefore reach USD2,600m in 2012 (of which USD400m for the development of unconventional production in Loma la Lata and USD200m for exploration). If the evaluation of the other areas holds its promise, the Capex needed could run into hundreds of billions of dollars in capital expenditures over the next decade, implying that Repsol may need to seek outside partners to develop this massive resource...

Repsol’s fast growing tight oil production was already profitable early on, despite realised oil prices in Argentina of around USD65/b, which are much lower than US realised prices for production in the Bakken shale. With current costs of USD7.5m for vertical wells (4 frac stages) and USD12.5m for horizontals (7 frac stages), an estimated recovery factor of 4% and a 10% WACC, Repsol YPF generates:

• NPV of USD5.2/boe for vertical wells;

• NPV of USD9.1/boe for horizontal wells.

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An 8% recovery factor (i.e. more frac stages) would help increase NPV to 12.75/b With a 40% reduction in the drilling cost per well, which is likely to occur as drilling productivity gains kick in, we calculate that Repsol YPF could generate:

• NPV of USD10.4/boe for vertical wells;

• NPV of USD12.7/boe for horizontal wells.

Repsol YPF’s Shale and Tight Exploration plan in Argentina will continue to focus on the Vaca Muerta formation over the next few years. However, this is just a first step as YPF has a wide shale range and tight portfolio, spanning a dozen geological formations in 5 regions. Repsol YPF Shale and Tight Portfolio

Source: YPF In the Neuquen region, the Los Molles shale formation is estimated to have a very high potential for shale gas resources. Repsol YPF plans to drill a well in the Las Lajas tight formation next year. In the Golfo San Jorge region, two wells targeting the Pozo 129 formation will be drilled during the first quarter of 2012.

While the Parana Chaco basin in North Argentina might have the largest shale gas potential in the country (521 Tcf risked recoverable assessed by the IEA) because of the exceptional thickness of the San Alfredo formation (as much as 12,000ft, of which only 2,000ft were assumed to be organically rich), current government limitations on gas price realisations in the country are resulting in a concentration of exploration projects leaning more towards oil than gas.

Although Argentina is likely to remain by far the most important non-conventional exploration area for Repsol, the company has also mentioned an exploration effort in North Africa. In this region, Repsol has large interests in Libya and Algeria. It is also looking into exploring unconventional themes in the Mediterranean.

On top of this, Repsol announced a USD1bn joint venture with SandRidge Energy to produce unconventional hydrocarbons in the US at the end of December 2011.

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On 22 December 2011, Repsol announced that it had reached an agreement with SandRidge Energy to buy approximately 1,500km2 (363,636 net acres) of the Mississippi Lime play, an area rich in gas and light oil. Repsol will invest USD1bn and will incorporate reserves and production from 2012.

Repsol will participate with a 16% and 25% stake respectively, in two areas within the Mississippian Lime deposit, which spans the US states of Oklahoma and Kansas. Mississippian Lime has a long production history and proven resources and is rich in light oil and gas produced from fractured carbonates. The area, which has been in operation for more than 30 years, has extensive infrastructure which will accelerate the start-up of production and marketing of these hydrocarbons.

Repsol’s SandRidge deal: positioning and learning on a US unconventional oil play

Source: Sand Ridge

Along with some geologic similarities with the Vaca Muerta formation, in particular the thickness of the organic rich rock, we believe that Repsol’s acquisition will help accelerate the company’s acquisition of drilling/fracturing know-how.

Repsol’s share of production is expected to reach a peak of 90 kboe/d in 2019, i.e. 30% of Repsol YPF’s Upstream division’s current hydrocarbon production. According to the agreement, Repsol anticipates drilling more than 200 horizontal wells during 2012 and will exceed 1,000 wells by 2014, in a fractured carbonate-rich area of 6,900km².

Repsol will pay USD250m in cash at the closing of the deal and the remainder in the form of a drilling carry, expected to be completed in three years, according to current development expectations.

We believe that Repsol’s huge discovery of unconventional oil and gas resources in Argentina could not only stop the decline of Repsol YPF's output in this country, but transform it into a platform for growth and radically change Repsol’s profile. This should lead to a continued outperformance for the company and we reiterate our Accumulate recommendation.

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Total: a significant oil sands player developing shale positions

Until 2008, North America remained a minor source of production for Total. With the Surmont project and a number of acquisitions, North America – and especially Canada – has emerged as one of the main regions for producing the “oil of the future” – with a focus on oil sands and gas shales. The acquisition of 25% of Chesapeake’s interests in the Barnett shale in early 2010 confirmed that Total wants to create a real position for its unconventional upstream businesses in North America and elsewhere. Thanks to this acquisition of non-conventional high quality non-gas assets in the best zones of the Barnett shale, Total clearly shored up its position in the US, where it had not been active enough until 2010, with an immediate boost to its production and reserves (+1.5% of proven reserves). Yet the oil sands of Athabasca are the greatest wellspring of growth for Total’s production in North America - this region is expected to contribute 10% of the group’s output in the long run, as opposed to less than 2% at present. With the Surmont project and a number of acquisitions, North America – and especially Canada – has emerged as one of the significant regions for future oil production – with a focus on oil sands, thus marking a strategic turnaround. Total has:

• a 50% stake in the Surmont project (SAGD Steam Assisted Gravity Drainage);

• a 39.2% stake in the Fort Hills project and a 38.25% stake in the Joslyn mining project, after it sold 36.75% of Joslyn to Suncor and paid Suncor C$1,751m in exchange for the 19.2% additional participation in Fort Hills (Total had bought its original 20% share in the UTS Energy acquisition that was finalised in October 2010), and a 49% share in the Voyageur upgrader project.

Total positions in Canada Oil Sands

Source: Total

The strategic partnership signed with Suncor in December 2010 relating to the Fort Hills and Joslyn mining projects and the Voyageur upgrader project allows Total to reorganise the different oil sands assets that it has acquired over the last few years around two major poles:

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• a mining and upgrading pole, which includes the Total-operated Joslyn (38.25%) and Suncor-operated Fort Hills (39.2%) projects as well as the Suncor-operated Voyageur upgrader (49%). These will be developed in parallel and are expected to start up at around the same time: 2016 for Fort Hills and 2017 for Voyageur;

• a SAGD(1) pole focused on Surmont’s (50%) ongoing development.

The group also holds a 50% interest in the Northern Lights (operator) mining project and 100% of a number of Oil Sand leases acquired through several auctions. Both companies have also confirmed the Joslyn North Mine timetable, with production of 100,000 b/d commencing in 2017-2018, subject to receiving the necessary permits (they were granted by Canada’s government in early December 2011). With this common upgrader, Total no longer needs to proceed with the planned construction of its own upgrader in Edmonton. Total expected production from Canada Oil Sands

Source: Total These projects are expected to represent C$10bn in investments for Total’s share over the next 10 years. They will make a significant contribution to Total’s production growth in North America as they have long production plateaus and are due to be launched before end-2012. Total had delayed the launch of these projects in 2009 so that it could make the most of the expected drop in construction costs in this field, as well as to find a solution that would allow the group to avoid building its own upgrader. Total had also farmed-in an oil sands project in 2008 in Madagascar, with a 60% interest. There is an estimated median volume of ~1.2bn barrels of mineable bitumen present, but development costs of $60-100/b for handling the ore, bitumen extraction and upgrading and shipping did not merit proceeding with the mining project. Total is now focusing on deeper conventional plays on the block, while the mine will continue to be evaluated for potential improvements in extraction and upgrading technology. The acquisition of a stake in Chesapeake’s Barnett shale development was a key step for Total in unconventional gas.

At the start of January 2010, the announcement of the acquisition of a 25% stake in Chesapeake’s Barnett Shale development confirmed Total’s wish to create a solid upstream position in North America. On 4 January, Total announced that it had signed a joint-venture agreement with Chesapeake to acquire 25% of its asset portfolio in the Barnett Shale in the US state of Texas for USD800m and USD1.45bn in commitments to invest in drilling for Chesapeake.

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Total 25% in Chesapeake’s interests in the Barnett Shale


These assets are already in the production phase. Total production per day is 700 million cubic feet and the zone in which Total is taking a 25% stake has a total surface area of 270,000 acres (net), of which 90% is located in the main production zone of the Barnett Shale (Tarrant and Johnson counties), where the productivity of the wells and the recoverable reserves per well have been the highest.

Total’s share of current production will be 175m cubic feet per day (i.e. 30k boed). In the next few years, this is likely to gradually increase to exceed 250m cubic feet per day (roughly 43k boed). 60% of the surface area included in the joint venture is already developed and 40% will be developed over the next few years via drilling at 3,100 wells. The production growth expected by Chesapeake and Total at the Barnett Shale will come, in addition to new drilling, from extending the distance over which horizontal drilling is carried out. According to Chesapeake’s production manager in this region, each additional foot of horizontal drilling increases the final production and reserves of each well, the horizontal drilling limit being that over which the mining rights extend (no drilling in neighbouring concessions).

This acquisition, effective as of October 1 2009, brought Total 0.75 Tcf (130 mboe) of proven gas reserves and an asset portfolio which included non-proven reserves (i.e proven and probable, with a 50% degree of certainty that these resources will produce oil) of 1.6 Tcf (270 mboe) for Total. Over and above the USD800m paid to finalise the acquisition, Total had also agreed to pay USD1.45bn over 2010-2012 tofinance 60% of Chesapeake’s future drilling investments on assets covered by these agreements. The total cost of the proven and probable (2P) reserves, acquired by Total was therefore USD5.625/boe and USD17.3/b based only on proven reserves. This level is close to that paid by ExxonMobil to acquire XTO Energy – the transaction price (EV/barrel) reached USD4.8/boe of resources, USD7.7/boe of 2P reserves and USD15.6/b of proven reserves.

This acquisition was also seen by Total as a way to gain experience in gas shale production, in order to apply this particular production development method (“industrialised” drilling of hundred of wells...) to other areas where Total intends to develop its non-conventional hydrocarbon production.

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In 2010, Total acquired three exploration licenses in Europe (one in France – currently suspended after France banned Hydraulic Fracturing - and two in Denmark) as well as operatorship on two additional permits in Argentina. In 2011, the group further enhanced its position in Argentina by acquiring interests in four additional exploration licences. Also in 2011, Total announced its acquisition of a 49% interest in the Chelm and Werbkowice concessions in Poland.

Total is the second-largest gas producer in Argentina and operator on the Aguada Pichana field in the Neuquén basin. The field is characterised by highly complex geology with both conventional and tight gas reservoirs.

Argentina: Total’s main assets in unconventional gas

Source: Total, CM-CIC Securities The production of conventional gas in Argentina was initiated in 1996 and since 2009 has been supplemented by the start-up of part of the tight gas zone of the field. In 2008, Total deployed a large-scale pilot to monitor the fracturing of these wells in order to test various microseismic acquisition designs. The ability to map the network of fractures artificially created in the reservoirs by the injection of pressurized water is key to the effectiveness of this well stimulation technique. In the Neuquen Basin, the most promising permits for Shale gas, and possibly tight oil after Repsol’s announcement in early November 2011 are:

• the Aguada Pichana permit (Total operator, 27.27%);

• and the San Roque permit (Total operator, 24.71%).

In order to extend its non-conventional hydrocarbon potential in Argentina, Total has acquired participations in 6 permits (4 operated) in the last 2 years, and now has around 1,500km2 of exploration rights in the oil and liquid-rich areas of the Vaca Muerta formation. Repsol’s discoveries could lead to an acceleration of Total’s exploration activities in Argentina. In late 2010, Total deepened its commitment to the unconventional gas segment by acquiring a 27.5% non-operated interest in the Australian project Gladstone LNG, the world’s first coal seam gas liquefaction venture, operated by Santos (30%). In addition to consolidating Total’s prominence in the liquefied natural gas sector, the move will enable the group to benefit from Santos expertise in coal seam gas, which it has been producing in Australia since 2002.

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Australia: Total’s main assets in unconventional gas

Source: Total, CM-CIC Securities The Final Investment Decision for the AU$16bn Gladstone LNG project was announced in early 2011. This huge integrated project spans the extraction of coalbed methane, transmission of the gas via a 420-km pipeline and the construction of a liquefaction plant on Curtis Island in Gladstone Harbour. Coal seam gas will be produced from the Fairview, Arcadia, Roma and Scotia fields located in the Bowen and Surat plays. The combined resources from these fields are estimated at 250Gm3. Several thousand more wells will be drilled at a rate of 200 to 300 per year.

We believe that Total’s exposure to unconventional hydrocarbons may rise significantly over the next few years, particularly if its operated exploration acreage there proves to be as oil and liquid rich as that of Repsol (although not on the same scale as Repsol given the difference in exploration acreage). Should this happen, we believe that Total’s share price could rise significantly.

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Eni’s unconventional E&P strategy

Eni is a major integrated company, committed to the growth in the activities of finding, producing, transporting, transforming and marketing oil and gas. In order to diversify its E&P portfolio and to increase its know-how the company is penetrating the unconventional resources business. This venture started in H1-2009. Eni signed a strategic alliance with Quicksilver Resources Inc., an independent US natural gas producer, by acquiring a 27.5% stake in the “Alliance” area in the Fort Worth Basin, Texas. This acquisition gave Eni recoverable net reserves of 40 mboe, o/w 23 mboe are proved and 17 mboe are probable and possible reserves, at an implied cost of USD 7 per barrel. In 2009, Eni’s net production quota from the acquired assets was 4kboe/d. The development plan foresees additional drilling and completion of nearly 300 wells by 2013. The development of the area is going forwards and a production plateau of 10kboe/d for the company is expected in 2012. The company expects to increase its production over the next decade by also leveraging unconventional resources. Benefiting from the competencies and experience acquired in the joint venture with Quicksilver in the Barnett Shale, the company built up a portfolio of promising prospects outside the US. In particular, Eni is focusing on areas where there are synergies with existing operations, where infrastructure is already in place and where the gas market is strong or growing. ENI’s ~5,500km2 of unconventional acreage in the US, North Africa (Libya and Tunisia), Eastern Europe (Poland and Ukraine) and China may represent over 1bn boe of prospective resources.

ENI Unconventional resources positions

Source: ENI

A very strategic area in this sense is North Africa, where Eni is the leading producer and where domestic demand is growing exponentially. In this area, the company expanded its presence by signing the cooperation agreement with Sonatrach in Algeria for shale gas and

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by continuing to explore opportunities in Tunisia. In Congo, the company is committed to tar sand oil exploration.

Meanwhile, in Europe, Eni is one of the largest players in gas. The company is making good progress in Poland, where it is expected to drill the first well (out of 6) by the end of 2011 and in Ukraine, where the company signed MOUs with the state-owned company to start (Cadogan Petroleum) an initiative in conventional and unconventional oil and gas.

The Far East is also a key growth area for the company’s unconventional portfolio, as well as conventional gas. In addition to the CBM (coal-bed methane) project in Indonesia and tight gas exploration in Pakistan, Eni entered China with two MOUs, one with CNPC Petrochina and the other with Sinopec to gain access to the vast shale gas resources in the country.

Over the next 4 years, the company aims to invest at least EUR 30m in unconventional exploration and more than EUR 500m in its development (around 2% of the company’s 2011-2014 E&P development capex). Total unconventional prospective resources are expected to amount to over 1bn barrels by 2014. The focus on unconventional assets and the increasing position in core areas is turning the company into one of the international oil companies with the lowest costs, with a breakeven price of USD 45 per barrel.

Galp: Mostly a conventional hydrocarbons play

The bulk of Galp Energia’s resources are located in Brazil’s Santos basin pre-salt play. Galp also has 5-10% interests in already operational deep offshore blocks in Angola and in a huge gas discovery offshore Mozambique. Its presence in unconventional hydrocarbon resource plays is limited to Venezuela, where Galp Energia entered into two projects in 2007-2008, including an LNG project. Galp Energia signed agreements in May 2008 with PDVSA to study the development of block Boyacá 6 in the Orinoco Belt. In Boyacá's block 6, research indicated the existence of 70 to 80bn barrels of oil in place. The 2nd research phase started at end 2008 with the drilling of the first of six appraisal wells in order to obtain a more precise evaluation of existing oil volumes. The last phase will consist in reserve certification, to be followed by a feasibility study for the development of Boyacá 6's heavy oil. Among the companies not currently covered by ESN, we would like to emphasize three notable facts: • BP’s aborted sale of its remaining share in Pan American Energy • Shell’s appraisal plan of South Africa’s giant Karoo basin and positions in China • Statoil’s build up of significant North American shale gas and tight oil positions

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BP: Strong Vaca Muerta position through Pan American Energy

BP has strong non conventional gas and oil positions in North America, particularly in gas and in Canadian Oil sands (3 in situ oil sands projects). With nearly 90 % of the company’s onshore resources in tight gas, shale and coal-bed methane, BP operates across the spectrum of unconventional gas plays. Since 2008, BP has made major moves into shale gas plays with its acquisition of the Woodford Shale in the Arkoma Basin and a jv with Chesapeake in the Fayetteville Shale in Arkansas. In 2009, BP formed a strategic partnership with Lewis Energy in the Eagle Ford Shale (S. Texas). Combined with its existing Haynesville Shale position in East Texas, shale represents a large and increasing share of BP’s US portfolio. In Argentina, BP had an agreement to sell its 60% stake in Pan American Energy (PAE) to Bridas for USD7bn. This deal was cancelled on 5th November 2011, and the company has stated several times that it is “happy to return to long term ownership of these valuable assets. Indeed, Pan American Energy has interests in 4 blocks lying over the Vaca Muerta Formation, with one operated and three not operated: • Lindero Atravesao, Pan American operator, 62.5%, 511.5 km2 (320 km2 net), • Banduria, PAE 18.2%, Repsol operator, 931.2km2, (170 km2 net), • Aguada San Roque, PAE 16.5%, Total operator, 1040km2, (171 km2 net), • Aguada Pichana, PAE 18.2%, Total Operator, 1371km2 ‘(250km2 net)

Concession Map of the Neuquen Province: Main industry participants

Source: Secretaria Hidrocarburos, Provincia de Neuquen

After Repsol’s 927 Mboe discovery, we believe BP will maintain its 60% interest in PAE and evaluate its unconventional oil potential before deciding either to participate in its development or to find a better owner for these assets...

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Shell: Appraising South Africa’s Karoo basin, positions in China

Over the last decade, Shell has had a head start in building very solid non-conventional gas and oil positions in North America, notably with the acquisition of Duvernay, particularly in gas and in Canadian Oil sands, where the company was the first to start producing from oil sands with an upgrader in 2001. With further acquisitions in 2010, the Shell portfolio includes about 3.6 million acres of mineral rights with the potential to yield 40Tcf of natural gas, the energy equivalent of nearly 7bn barrels of oil.

Unconventional Gas: Key SHELL positions

Source: Shell Shell has also developed non-conventional resource positions on a global basis, particularly in China and in South Africa.

What’s striking in South Africa is the sheer size of Shell’s exploration area. At end-2009, the South African Petroleum Authorities awarded Shell a Technical Cooperation Permit for a one-year study to determine the hydrocarbon potential in parts of the Karoo Basin in central South Africa. The permit covered an area of approximately 185,000 km2, nearly half of France’s size! Indeed, the Karoo basin potential is huge: the US Energy Administration World Shale Gas resource report estimates that the Karoo Basin holds significant volumes of shale gas resources. The Lower Ecca Group shales in this basin contain 1,834 Tcf of risked gas in-place, with risked recoverable shale gas resources of 485 Tcf.

In December 2010, Shell submitted three separate exploration licence applications for areas of around 30,000 km2 each. These areas are in the Western Cape, Eastern Cape and Northern Cape provinces of South Africa. Although South Africa decreed a moratorium on the award of these shale gas exploration licences, Shell confirmed that it remains committed to its proposed shale gas exploration project in the Karoo. If Shell is granted these exploration licences, exploration would involve drilling up to 24 wells over 3 years. Shell has committed to disclosing the fracturing fluids at each drilling location, and consulting with communities as part of the development of hydraulic fracturing plans. The company will implement any relevant recommendations that may arise from a study of hydraulic fracturing by the US Environmental Protection Agency, which is currently under way and will continue until 2014. Any possible development in South Africa’s Karoo basin is at least 9 years away...

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Shell: shale gas exploration permits in South Africa

Sources: Shell, US DOE Shell’s unconventional gas development outside of North America may materialise faster in a country like China. China has more shale gas resources than any other country in the world, with 1,275Tcf of recoverable shale gas resources, according to estimates from the US Energy Information Administration. In addition, the country’s official target is to raise the share of Natural Gas in its total energy consumption from 4% today to 20% in 20 years. In this context, the PetroChina and Shell JV’s discovery of shale gas in the Sichuan province announced on 6th December 2011 is encouraging. This JV was formed in March 2010. The companies have submitted a production-sharing contract to the Chinese central government for approval. Under the 30-year contract, Shell and CNPC will appraise and potentially develop tight gas reservoirs in an area of approximately 4,000m2 in the Jinqiu block of central Sichuan Province.

Shell –Petrochina JV blocks in the Sichuan province of China

Source: RD Shell So far, the PetroChina / Shell JV has drilled about 20 wells in its shale gas acreage in southern Sichuan province and the initial results have been positive, with a production rate of more than 10,000m3/d/well. Nevertheless, this is not a very large initial production compared to the results obtained in the largest US gas shales. It is therefore not clear how quickly China could make shale gas production profitable given the lack of pipeline infrastructure and the relatively low price of natural gas in China.

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Statoil: building a large North American unconventional position

Over the last four years, Statoil has acquired a very solid position in US non conventional hydrocarbons. One of the reasons for this build up is that the Norwegian company has been struggling in recent years to meet its production growth targets, which have been regularly revised downwards. Statoil’s first move came at the end of 2008, when it acquired a 32.5% interest in the Marcellus shale gas acreage from Chesapeake Energy Corporation for a consideration of USD 1,250m in cash and a further USD 2,125m in the form of a 75% carry on the drilling and completion of wells during the period 2009 to 2012. With this transaction Statoil acquired future, recoverable equity resources in the order of 2.5-3.0bn boe. Statoil’s equity production from the Marcellus shale gas play is expected to increase to at least 50kboe/d in 2012 and at least 200kboe/d after 2020. In March 2010, the company signed an agreement with Chesapeake, adding approximately 59000 net acres to Statoil's current 600000 net acre positions in the Marcellus Shale. 2008-10: Statoil acquisitions in the Marcellus Shale

Source: Statoil A few months after increasing its positions in the Marcellus Shale, while US natural gas prices were dwindling, Statoil announced the strengthening of its US Onshore portfolio by forming a joint venture with Talisman Energy, which involved the simultaneous acquisitions of Enduring’s South Texas Assets together with Talisman (50/50) and of a 50% stake in the existing Talisman Eagleford acreage, for a total consideration of USD843m (USD663m for Enduring’s acreage and USD180m for Talisman’s) Statoil holds 67,000 acres and an option to become an operator within 2013. The company estimates the recoverable resources in these leases to be 550-650m boe. At the time of the acquisition, Statoil estimated that 60% of the revenue generated in the Eagleford shale would come from liquids. The Statoil Talisman JV has since increased its positions on the Eagleford shale and Statoil had ~75800 acres by mid 2011, with 5 rigs drilling and an expected 8 rigs by end 2011.

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2010: Statoil acquisition in the Eagleford Shale

Source: Statoil For these two acquisitions, the price per acre was in the low to middle range of the price paid by other industry players for acquisitions in the same areas. Indeed, along with BP, Statoil was among the first International Majors to buy resources in the US shale plays.

Statoil's entry into the Marcellus...

Source: Statoil

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...and Eagleford shales

Source: Statoil

This ‘’first mover’’ advantage has allowed Statoil to gain significant positions in some of the lowest post-tax breakeven areas.

Statoil First Mover Advantage: Premium US Unconventional positions

Source: Statoil

Statoil has made clear it wouldn’t stop there and has outlined a clear growth strategy:

• Incrementally growing around the Marcellus assets

• Growing the Eagleford position

• Adding new material unconventionals through M&A

• Leveraging operating capacity

• Exercising immature options

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For Statoil, there are multiple reasons for going after more growth in unconventionals: 1) they offer a large reserve and near term production potential; after the strong rates of decline of the first two years, production offers stability over a long lifetime, 2) hedging possibilities offer commodity price protection. 3) the strong technology upside allows production at ever lower costs (industrialisation of the drilling process) and the cash generated allows these developments to fund themselves over time... In October 2011, Statoil put its money where its mouth is as it announced it had entered into a merger agreement with Brigham Exploration Company to acquire all of the outstanding shares of Brigham for USD 36.5 per share through an all-cash tender offer. The total equity value of the deal is around USD 4.4 billion, reflecting an enterprise value of approximately USD 4.7 billion, based on 30 June 2011 net debt. The transaction will provide Statoil with more than 375,000 net acres in the Williston Basin, which holds potential for oil production from the Bakken and Three Forks formations. Brigham also holds interests in 40,000 net acres in other areas. At this early stage of development the risked resource base is estimated at 300-500m boe, on an equity basis. Current equity production is approximately 21,000 kboe:d. Statoil’s acquisition of Brigham: attractive Bakken Acreage

Source: Statoil The attractiveness off Brigham’s bakken acreage resides in • a potential to ramp up to 60-100kboe/day equity production over a five year period • a breakeven price of USD55/boe. • the positions in large contiguous acreage blocks, which provide operational efficiency, • and production development expected to be self-financed by 2013/14 Indeed, Brigham looks to have been the leading innovator and operator in the basin, as reflected by its results over the last five quarters. The company has drilled six of the ten highest IP rate Bakken wells in the play to date, and developed a near optimal drilling and completion process allowing it to unlock value.

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Bakken Oil Shale: Brigham outperforms peers in terms of Initial Production (IP)

1Q10 2Q10 3Q10 4Q10 1Q11

Operator N of

wells

IP Avg.

(boe/d)

N of

wells

IP Avg.

(boe/d)

N of

wells

IP Avg.

(boe/d)

N of

wells

IP Avg.

(boe/d)

N of

wells

IP Avg.

(boe/d)

Brigham 8 2,855 11 3,012 12 2,938 4 3,591 3 2,681

Peer total / Avg 90 1,293 153 1,312 178 1,240 89 1,424 19 1,590

Outperformance 121% 130% 137% 152% 69%

Source: Bakken Shale Weekly 03/22/2011

In all, over the last 4 years, Statoil has invested nearly USD 8bn in building a 4bn boe position in US non-conventional hydrocarbons, which is set to produce 150 to 200kboe/d by 2014, net to the company. This should help support the ambitious company target of growing its production from 1.9 Mboe/d in 2010 to more than 2.5 Mboe/d by 2020, with production growth accelerating from 2014 onwards, and then from 2016, compared to possibly lower than expected growth over 2010-2012.

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Performance overview Company Currency Absolute performance(ordered by 1 week performance) 1 week 1 month 3 months 12 months YTDTotal EUR 2.2 3.0 18.9 -1.5 -0.4Eni EUR 1.7 2.1 21.1 -2.0 -2.0Neste Oil EUR 1.5 -15.6 19.4 -34.7 -34.7Repsol Ypf EUR 1.3 6.0 18.8 13.8 13.8Galp Energia EUR -3.2 -8.4 -17.2 -21.6 -20.6

Performances % 1 week 1 month 3 months 12 months YTDOil & Gas Producers 1.0% 4.3% 19.4% 2.3% 2.9%Stoxx TMI 1.1% 1.9% 8.1% -11.9% -11.5% Source: Factset (*) ordered by weekly performance

Upcoming corporate calendar Company Country Bloomberg

code Date Event Type Description

ENI Italy ENI IM 10/03/12 Results Full year 2011 Results Italy ENI IM 14/02/12 Results Full year 2011 Preliminary results

GALP ENERGIA Portugal GALP PL 06/03/12 Capital Markets Day Capital Markets Day Portugal GALP PL 10/02/12 Results Full year 2011 Earnings conference call / Webcast Portugal GALP PL 10/02/12 Results Full year 2011 Results Portugal GALP PL 27/01/12 Trading Update Q4 2011 Trading statement

NESTE OIL Finland NES1V FH 28/03/12 AGM Full year 2011 AGM Finland NES1V FH 03/02/12 Results Full year 2011 Results

REPSOL YPF Spain REP SM 10/01/12 Dividend Payment Interim 2011 Dividend payment date EUR 0.58TOTAL France FP FP 10/02/12 Results Full year 2011 Results Source: AMI

Sector coordinator

Jean-Luc Romain CM - CIC Securities France +33 1 45 96 77 36 [email protected]

Sector team Carlos Jesus Caixa Banco de

Investimento Portugal +351 21 389 6812 [email protected] Dario Michi Banca Akros Italy +39 02 4344 4237 [email protected] Sonia Ruiz De Garibay Bankia Bolsa Spain +34 91 436 7841 [email protected] Henri Parkkinen Pohjola Finland +358 10 252 4409 [email protected]

Coverage Company Analyst Analyst Second ESN

initials name Analyst name memberEni DM Dario Michi Banca AkrosGalp Energia CJ Carlos Jesus Caixa Banco de InvestimentoNeste Oil HP Henri Parkkinen PohjolaRepsol Ypf SRG Sonia Ruiz De Garibay Bankia BolsaTotal JLR Jean-Luc Romain CM - CIC Securities

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ESN Recommendation System The ESN Recommendation System is Absolute. It means that each stock is rated on the basis of a total return, measured by the upside potential (including dividends and capital reimbursement) over a 12 month time horizon.

The ESN spectrum of recommendations (or ratings) for each stock comprises 5 categories: Buy, Accumulate (or Add), Hold, Reduce and Sell (in short: B, A, H, R, S).

Furthermore, in specific cases and for a limited period of time, the analysts are allowed to rate the stocks as Rating Suspended (RS) or Not Rated (NR), as explained below.

Meaning of each recommendation or rating:

• Buy: the stock is expected to generate total return of over 20% during the next 12 months time horizon

• Accumulate: the stock is expected to generate total return of 10% to 20% during the next 12 months time horizon

• Hold: the stock is expected to generate total return of 0% to 10% during the next 12 months time horizon.

• Reduce: the stock is expected to generate total return of 0% to -10% during the next 12 months time horizon

• Sell: the stock is expected to generate total return under -10% during the next 12 months time horizon

• Rating Suspended: the rating is suspended due to a capital operation (take-over bid, SPO, …) where the issuer of the document (a partner of ESN) or a related party of the issuer is or could be involved or to a change of analyst covering the stock

• Not Rated: there is no rating for a company being floated (IPO) by the issuer of the document (a partner of ESN) or a related party of the issuer

ESN Ratings Breakdown

History of ESN Recommendation System Since 18 October 2004, the Members of ESN are using an Absolute Recommendation System (before was a Relative Rec. System) to rate any single stock under coverage.

Since 4 August 2008, the ESN Rec. System has been amended as follow.

• Time horizon changed to 12 months (it was 6 months)

• Recommendations Total Return Range changed as below:

BEFORE

-15% 0% 5% 15%SELL REDUCE HOLD ACCUMULATE BUY

TODAY


BEFORE


BEFORE


TODAY


TODAY


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ESN Unconventionals 03 January 2012

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