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October 14, 2014

Oil & Gas Global Insight: Is the US shale revolution replicable?

The mega-rise in US shale production had far-reaching implications. However, even with $140 oil prices the chances of a rapid repeat elsewhere look slight. Argentina's improving regulatory framework and favourable below ground fundamentals make it the most promising area.

One trillion barrels of oil and gas: After 20 years of trial-and-error, the US shale revolution exploded in just a few years. The US’ success plus plentiful global shale (10Y oil and 60Y global gas demand) led others to look elsewhere e.g., Argentina, Australia, China and Poland.

However, non-US shale production is likely to be minimal for some time: Crucially, lessons cannot be transferred, plus local costs and prices make speedy replication unlikely any time soon. Likewise, rather than stimulating non-US growth, low and still dropping US shale breakevens (e.g., <$65 per barrel) have conversely marginalized many international shale plays.

Where could we be wrong? To overcome the severe impact of higher costs in non-US plays, generous fiscal terms plus stronger prices must occur. Of crucial importance would be a c50% drop in costs or a similar increase in prices to around $140/barrel, we think.

Argentina’s Vaca Muerta shows the most promise: A high-quality liquid-rich shale (comparable to the Eagle Ford in the US), manageable logistics/costs and a supportive, motivated government drive our above consensus view that Argentina shale production could surpass all assessed regions combined.

Top non-US shale play picks - YPF & Archer: YPF (OW, $50 PT) looks cheap on our estimates (3x 2015 EV/EBITDA) with a free option on the shale upside, which we think could be worth up to $15/ADR. Archer (OW, NKr15 PT) looks cheap relative to US S&MC peers (7x 2015 P/E) and it has plenty of catalysts, including Argentina rig deliveries and new orders.

Morgan Stanley does and seeks to do business with companies covered in Morgan Stanley Research. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of Morgan Stanley Research. Investors should consider Morgan Stanley Research as only a single factor in making their investment decision.

For analyst certification and other important disclosures, refer to the Disclosure Section, located at the end of this report. += Analysts employed by non-U.S. affiliates are not registered with FINRA, may not be associated persons of the member and may not be subject to NASD/NYSE restrictions on communications with a subject company, public appearances and trading securities held by a research analyst account.

Morgan Stanley Australia Limited+ Adam Martin

Morgan Stanley & Co. International plc+

Jamie Maddock, Ph.D.

Igor Kuzmin

OOO Morgan Stanley Bank+ Pavel Y Sorokin

Morgan Stanley & Co. LLC Evan Calio

Ole Slorer

Adam Longson, CFA, CPA

Drew Venker, CFA

Morgan Stanley Asia Limited+ Andy Meng, CFA

Morgan Stanley C.T.V.M. S.A.+ Bruno Montanari

M O R G A N S T A N L E Y R E S E A R C H

A S I A / P A C I F I C

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October 14, 2014 Oil & Gas

Global Oil and Gas Contributors to this report European Exploration & Production Industry view: In-Line

Jamie Maddock, Ph.D.3 +44 20 7425 4405 [email protected]

Aaditya Chintalapati3 +44 20 7425 9761 [email protected]

Australia Energy Industry view: In-Line

Adam Martin1 +61 3 9256 8904 [email protected]

Stuart Baker1 +61 3 9256 8929 [email protected]

EEMEA - Russian Oil & Gas Industry view: In-Line

Pavel Y Sorokin4 +7 495 287 2312 [email protected]

Emerging Euro - Oil & Gas Industry view: In-Line

Igor Kuzmin3 +44 20 7425 8371 [email protected]

China Oil & Gas Industry view: Cautious

Andy Meng, CFA5 +852 2239 7689 [email protected]

Daisy Li5 +852 2239 7822 [email protected]

LatAm Oil & Gas Industry view: No Rating

Bruno Montanari6 +55 11 3048 6225 [email protected]

Sustainable + Responsible Investment

Jessica Alsford3 +44 20 7425 8985 [email protected]

Richard Felton +44 207 425 5930 [email protected]

Commodities

Adam Longson, CFA, CPA2 +1 212 761 4061 [email protected]

Elizabeth Volynsky2 +1 212 761 7201 [email protected]

Stefan Revielle2 +1 212 761 6005 [email protected]

Large-Cap Exploration & Production Industry view: Attractive

Evan Calio2 +1 212 761 6472 [email protected]

Mid-Cap Exploration & Production Industry view: Attractive

Drew Venker, CFA2 +1 212 761 3729 [email protected]

Global Oil Services, Drilling & Equipment Industry view: In-Line

Ole Slorer2 +1 212 761 6198 [email protected]

Connor J, Lynagh2 +1 212 296 8145 [email protected]

1 Morgan Stanley Australia Limited+

2 Morgan Stanley & Co. LLC

3 Morgan Stanley & Co. International plc+

4 OOO Morgan Stanley Bank+

5 Morgan Stanley Asia Limited+

6 Morgan Stanley C.T.V.M. S.A.+

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Table of Contents

Executive summary 4

Key factors in the success of US shale 8

What are the benefits? 10

Where does the opportunity lie? 11

Is the US shale revolution replicable? 12

Environmental and social considerations 14

Summary of our country analysis 16

Argentina 18

Australia 24

China 27

Mexico 34

Poland 35

Russia 40

United Kingdom 48

Equity implications 51

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Executive summary

What is shale oil and gas? As shale rocks have poor flowing and storage properties, oil or gas extraction from them is known as unconventional. This compares with extraction from sandstone and other higher quality (higher porosity and permeability) reservoir formations such as carbonates, which are conventional. Technological advances, however, such as horizontal drilling and hydraulic fracturing, now support unconventional extraction. Shale oil or gas production is unconventional but, following the substantial advancement in technology, the US shale revolution was born.

The US shale revolution reversed 40 years of decline. The US shale revolution (Exhibit 1) has driven gas prices to a historic low, a mega trend with far-reaching implications. This trend has been the primary driver of relative energy performance, supporting master limited partnership (MLP) and midstream outperformance (via re-plumbing in North America), refining performance (via access to cheap crude), US chemical performance (via access to cheap ethane), onshore oilfield services, US and global commodity processes, and US E&P performance. In this report, we assess the prospects of those countries elsewhere most advanced in commercializing their shale potential.

Exhibit 1

Shale transformed the US energy landscape by reversing 40 years of decline. However, can this be replicated elsewhere?

Source: Energy Information Administration (EIA), Morgan Stanley Research

US shale production benefited from a myriad of positive factors. It took 20 years for the US shale revolution to take off. Moreover, and unlike what is happening in other regions globally today, independent operators undertook all the initial activity. Development techniques were refined over time along with advancements in horizontal drilling, Exhibit 2. Additional factors like a cooperative government and landowner rights

were also key drivers, which are not replicated anywhere else globally. The scale of the industry was also important. For example, offset well data was easily available, reducing well costs, and there existed an extensive pipeline network with a large oilfield service sector. Finally, financial markets were also important providers of capital in the early days.

Exhibit 2

Technological advancement was an important driver of the US shale revolution, amongst other factors

Source: EIA, Morgan Stanley Research

Globally there is plenty of non-US shale oil and gas. Global shale represents around a tenth of the world’s oil resources (about 345 billion barrels) and a third of the world’s gas resources (about 7,299 Tcf) or, put another way, around 10 years of global oil consumption and 63 years of global gas consumption; see Exhibit 3. Despite significant challenges, we think that of the regions assessed Argentina and China are most likely to replicate the US success, albeit not to the same degree or before the end of the decade. Likewise, even intra-country success will be highly basin specific.

Exhibit 3

Global shale oil potential; c80% lies outside of the US


However, we see scalability and high breakevens as a headwind to rapid replication.

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Through a combination of our bottom-up (company analysts’) and top-down (commodity analysts’) analysis, we estimate around 200kboed of global non-US shale production by the end of the decade. In short, given the small well size and sharp declines in shale production, drilling intensity is critical for scalability and a major limiting factor, we think.

Further, the global variation in shale rock characteristics means that existing techniques will probably not prove successful when applied elsewhere. Operators use US analogues as local benchmarks but are rarely successful and as in the US, operations are simply a process of trial and error. Likewise, the relative lack of fracturing and horizontal drilling experience in the oilfield service industry is a major issue, too.

Argentina's improving regulatory framework and favourable below ground fundamentals make it the most promising area. We expect the combination of excellent, high-quality liquid-rich shale (comparable to the Eagle Ford in the US), manageable logistics/costs and a supportive, motivated government to drive an increase in Argentina’s shale production. While production is only at about 25kboed, with 200 wells planned for 2014 (far more than anywhere except the US) we think it could increase to about 200kboed before the end of the decade.

Exhibit 4

Argentina’s Vaca Muerta is a high-quality liquid-rich shale, which is comparable to that of the Eagle Ford in the US Shale Plays Vaca Muerta Haynesville Marcellus Eagle Ford WolfcampTOC (%) 3-10 0.5-4 2-12 3-5 3Thickness (m) 30-450 60-90 10-60 30-100 200-300Pressure (psi) 4,500-9,500 7,000-12,000 2,000-5,500 4,500-8,500 4,600Area (km2) 30,000 23,000 250,000 5,000 5,200 Source: Company Data, Morgan Stanley Research

Exhibit 5

Same shale, different country comparisons; breakeven per country based upon unique fiscal terms and costs*

B r e a k e v e n c o s t f o r s h a l e p l a y s ( $ / b o e )

0

2 0

4 0

6 0

8 0

1 0 0

1 2 0

1 4 0

1 6 0

U S - E a g l e f o r d A r g e n t i n a - V a c aM u e r t a

A u s t r a l i a -C o o p e r B a s i n

C h i n a - S i c h u a n

Source: Wood Mackenzie, Morgan Stanley Research estimates *Assuming an Eagle Ford type curve and Wood Mackenzie’s cost estimates

The figures’ relation to one another is defined by the area’s fiscal terms and cost uplifts, so their respective rankings by the breakeven metric may be slightly different to NPV rankings.

Russia has the largest opportunity, but there are few supportive monetisation drivers. Russia has the largest shale potential globally. However, with much of the required technology owned by western oilfield service companies and E&Ps, the recent EU and US sanctions are meaningful headwinds. Likewise, although the government recently loosened fiscal terms to encourage investment, the challenging cost environment and unusual geological properties make the resource economically unattractive.

Australia, China, Mexico, Poland and the UK share similar challenges. Shale production aspirations are high because of the overwhelming success of the US. However, with the exception of China, activity remains muted, with exploration activities continuing at only a modest pace. In general, all these regions share the same issues: relatively poorly-understood geology, wells that cost an order of magnitude more than those in the US, minimal investment and little government incentive. However, China’s Fuling Shale gas play appears to be an exception. Sinopec has demonstrated high flow rates and low well costs and, importantly, China is subsidizing the shale industry, too.

However, the benefits can be meaningful. First, shale production has the potential to redraw the energy map. This is evident in the US where domestic shale oil production has risen significantly over the last few years. Moreover, it has the potential to disrupt OPEC and radically

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change the import/export balance of a country, in turn lowering local energy prices. Clear beneficiaries would be Argentina, with its large energy deficit, and China, with its fast-growing and energy-intensive economy and its goal of increasing natural gas consumption in its energy mix.

Exhibit 6

Rapidly rising US oil production has the potential to dramatically reduce dependence on foreign energy imports


Environmental and social considerations The above ground factors should not be under-estimated either, and we have found these to be far more challenging outside of the US than we expected. These split into environmental and social. For example, having the correct well design and the appropriate management of surface chemicals/materials is the best barrier to protecting water aquifers and providing communities with the assurance the water will remain safe. Moreover, key above ground challenges relate to suitable infrastructure, population density, noise/haze, and road congestion.

A road map to success In the US, oil companies amassed large unconventional acreage positions, then chased the liquid rich plays to maximize returns, and finally boosted productivity via better technology. However, development of non-US shale plays need not follow the same sequence as the US. Consequently, we can envisage several routes to a potential acceleration in non-US global shale oil and gas production. Although country-specific issues are prevalent, economically attractive returns remain the predominant headwind. Shale returns are dependent on well performance given the high intensity drilling that is required; the key elements are 1) realized prices; 2) costs and 3) decline rates over the life of the well. All else being equal, there needs to be a sharp improvement in either one of these variables or, ideally, improvement across all. We estimate the improved

performance required for each variable assuming the other variables are kept constant:

1. c50% increase in oil prices to above $140-150 per barrel for oil shale plays

2. c100% increase in gas prices (i.e. $13-14/mmbtu or circa 3.5x US gas prices) for international gas plays

3. 50% decline in average cost per well driven by a proliferation of oil field service companies, lessons and scale.

4. c100% increase in well productivity. We think a second global shale revolution any time soon is unlikely. However, a rapid improvement in well productivity could prove to be a wildcard, whereas significantly reduced costs or higher commodity prices look unlikely in the short to medium term. YPF – our top ex-US global shale play pick We see YPF as a very attractive long-term investment opportunity, with a free option on the shale upside. The stock trades at undemanding valuation levels (3x 2015 EBITDA). In our base case, we include only the very first cluster being developed in Vaca Muerta (Loma Campana), which gives us a value of about $1/ADR. Therefore, all of our upside is driven by the conventional assets of the company, leaving Vaca Muerta as a free option. Assuming conservative metrics for the development of the oil and gas windows of Vaca Muerta, such as $8m drilling costs and a 40% acreage risk, we believe that the shale assets could be worth about $15/ADR.

Exhibit 7

Bull case: Normalized discount rate and Vaca Muerta shale oil almost doubles our Base Case

50.0

72.0

7.0

11.5

3.5

BASE CASE NORMALIZEDECONOMY

VACA MUERTA(OIL)

VACA MUERTA(GAS)

BULL CASE

US$/ADR

$15/ADR

Source: Morgan Stanley Research estimates

Archer – our top global ex-US oilfield services shale play Archer is an interesting small-cap play on non-US shale, and we see c100% upside to our NKr15 PT (share price: NKr 6.75). Over the next year, we expect Archer to approximately double

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its rig presence in Argentina’s unconventional plays, and we expect earnings upside from these rigs’ higher day rates and high rig utilization. In 2014-16, we forecast that Archer will more than double its LatAm EBITDA (c55% CAGR) and will nearly double its consolidated EBITDA (c40% CAGR). Given YPF’s recent positive commentary on its long-run plans for developing the Vaca Muerta, we see potential for further asset deployments beyond Archer’s announced newbuild plans. Momentum abroad and an underappreciated US operational turnaround will continue to drive Archer’s beat-and-raise story, in our view. Our NKr15 PT is based on 15x our 2015 estimate EPS of $0.16, a slight discount to historical multiples of small cap service peers. Key risks include execution risk, high financial leverage, and commodity price risk. Beach Energy (Equal-weight) – exposed to shale disappointment in Australia Beach Energy has been the leader in shale development in Australia and managed to secure Chevron as a farm-in partner in the Cooper Basin. Well results and drilling costs are not sufficient to demonstrate commerciality at this point. This could change over time with further work but we caution investors applying value to BPT’s shale acreage until results improve. There has been speculation in the financial media (The Australian Financial Review, October 1 2014) regarding Chevron exiting the JV early next year; this is speculation but

should this happen there would be further short-term negative momentum. Sinopec (Equal-weight) has exciting long-term shale potential but shale is a relatively small part of the business today China is second to Argentina in international shale development, with Sinopec’s Fuling shale play demonstrating commercial results. We expect the play to develop quickly over the next few years, adding just under 3% to Sinopec’s PBT in 2015. We see more upside longer term as the play is developed and cost reductions are implemented.

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Key factors in the success of US shale

The extraordinary success of US shale was driven by enormous economic incentives – in a place that already had virtually every necessary resource to develop shale rapidly and efficiently.

The success of shale in North America was nurtured by a confluence of factors, most of all incentives. Within the US, individuals largely own the rights to minerals on their land. There is a long history of oil and gas development, which provides a deep and rich knowledge base of the reservoirs both geographically and stratigraphically. Infrastructure prior to the boom was extensive, in many cases overlapping significantly with new shale discoveries. Regulatory systems were already in place in the vast majority of states that have seen significant unconventional development. North America also has shales that are ideal for horizontal drilling: relatively flat, blanket formations across large areas.

Exhibit 8

Key US tight oil and gas shale regions


Three other key factors were critical to the rapid development of unconventional resources: large, widespread water resources, access to oil field services, and large pools of engineers. While many of these aspects will not or cannot be replicated elsewhere, most certainly individuals holding mineral rights, several key ingredients could be imported from North America.

1. oilfield services and technology could be transferred over time but would be more costly,

2. engineers could immigrate or be educated locally; and

3. regulatory systems could mimic the regimes in North America for unconventional development.

Exhibit 9

US shale oil production now circa 3.5mbod


US shale is moving down the cost curve, making international shale development even harder. Ironically, the success of US shale makes international shale development even more challenging, at least in the short term anyway. Globally oil prices are declining, with capex being reduced as operators focus on the highest returning projects for capital re-investment. At the same time, US oil shale is moving down the cost curve and adding to the global oil production mix as operators continue to improve drilling and fracturing performance – essentially getting more from shale wells for less capex. US shale is now no longer the marginal barrel, with cash breakevens in some major US shale plays having dropped by up to $30/bbl since 2012. For example, cash breakevens now range between $30-60/bbl in the Eagleford, as shown by Exhibit 10.

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Exhibit 10

Eagleford breakevens – now $30-60/bbl

Source: Morgan Stanley Research Estimates

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What are the benefits?

Another shale revolution has implications that stretch far beyond the oil and gas industry. For example, if the US shale revolution is replicable elsewhere, not only could it dramatically alter the world’s energy markets again, but also it could lower consumer and industrial energy input costs, stimulates economic growth, and increase tax revenue and create jobs. From the perspective of national interests, increased domestic energy production generates three obvious benefits.

First, greater domestic production in substitution for imports in turn reduces the vulnerability of the economy to supply disruptions and price shocks. Moreover, as domestic production increases and the country imports less energy, because it produces more at home, less domestic spending power is diverted abroad, Exhibit 11 and 12.

Exhibit 11

Growing US oil production has the potential to dramatically reduce dependence on foreign energy imports


Exhibit 12

Total US energy production and consumption


Second, whatever the source, a greater supply of energy worldwide depresses its relative price. As energy is an important input in the production of many goods and services, more output can be produced. Exhibit 13

The US shale revolution has driven gas prices to a historic low

Source EIA, Morgan Stanley Research

Third, the US is, at best, on equivocal terms with many of our suppliers of oil in terms of joint strategic relationships. Becoming more energy self-reliant could serve the dual purpose of relieving those geopolitical strains somewhat.

For a more comprehensive analysis of the impact of the US shale revolution, see our April 29, 2013 Blue Paper US Manufacturing Renaissance: Is It a Masterpiece or a (Head) Fake?.

https://ny.matrix.ms.com/eqr/article/webapp/0028db33-d2f3-49c6-a41a-65ca9a868f82?ch=rpext�



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Where does the opportunity lie?

Shale oil and shale gas resources are globally abundant Global shale oil and shale gas resources represent 10% of the world's oil and 32% of the world's gas resources. Putting this into context, shale accounts for roughly 10 years of oil and 63 years of global gas consumption. Exhibit 14

Top 10 countries with shale oil and gas Country Shale oil

(bn bbls) Country Shale Gas

(Tcf) Russia 75 China 1,115

US 58 Argentina 802 China 32 Algeria 707

Argentina 27 US 665 Libya 26 Canada 573

Australia 18 Mexico 545 Venezuela 13 Australia 437

Mexico 13 South Africa 390 Pakistan 9 Russia 285 Canada 9 Brazil 245


More than half of the shale oil outside the US is concentrated in Russia, China, Argentina, and Libya, while more than half of the non-US shale gas is concentrated in five countries: China, Argentina, Algeria, Canada, and Mexico. To put into context the scale of what has been developed already, the US is second after Russia for oil and fourth after Algeria for gas; see Exhibit 14. Given the variation across the world's shale in both geology and above-the-ground conditions, the extent to which global resources will prove to be economically recoverable is not clear. The market impact of shale resources outside the US will depend on their own production costs and volumes. For example, a potential shale well that costs twice as much and produces half the output of a typical US well would be unlikely to replace current supply sources of oil or gas. Exhibit 15 highlights the countries with the most shale activity thus far, including some of the companies’ active in those countries.

Exhibit 15

Shale activity for the world’s leading countries

Source: Company Data, Morgan Stanley Research estimates

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Is the US shale revolution replicable?

Exhibit 16

We think Argentina could surprise to the upside, although we are more sanguine than consensus on the potential for a non-US shale revolution to be replicated elsewhere

Least Preferred - - - = + ++ Most Preferred

Argentina 0 0 0 1 0 0 0 0 1 0

Australia 0 0 1 0 0 0 1 0 0 0

China 0 0 0 1 0 0 0 1 0 0

Poland 1 1

Russia 1 1

UK 1 0 1

Rosneft (JV with ExxonMobil), Gazprom Neft (JV with Shell), Lukoil (JV with Total), Surgutneftegaz, Ruspetro

Centrica, GDF, Total, Cuadrilla, Egdon, Igas

How Developed Cost Structure Participants

PGNiG, San Leon, PetroInvest, ConocoPhillips, BNK Petroleum, Chevron, Cuadrilla, Mac Oil Spa, Wisent, Basgas, Grupa, PKN Orlen

Chevron, YPF, Petrobras, Total, ExxonMobil, Wintershall, Petronas, Madalena Energy, Americas Petrogas

Chevron, Statoil, Total, BG, Santos, Origin, Beach, Drillsearch, Senex, AWE, Buru, Mitsubishi, Conoco Phillips, Sasol, Central

Sinopec, PetroChina, Yanchang, Shell plus oilfiled service companies Weatherford in JV with Sinopec, Halliburton with SPT Energy and

Schlumberger with Anton

Source: Morgan Stanley Research

In summary, and while there are several countries with exceptionally large resources, and in several cases larger than those in the US, we think a repeat of the US shale revolution is unlikely anytime soon. Specifically, there are challenges, such as sub-surface variability, the number of active participants, infrastructure, and most crucially, cost/economics, which we think the assessed countries, are some way from overcoming. Alternatively, the next shale revolution requires a unique advancement in economic returns driven by a step change in sub-surface understanding and/or technological leaps. However, to enable us to evaluate the relative winners of these emerging countries we have developed a framework of what we think are the key attributes for success. These are as follows:

Geology The shale potential of each of the emerging countries we have assessed is generally very large, and in several cases, larger than that in the US. However, sub-surface variability poses a meaningful challenge to developments and economics. For

example, shale plays can take years of intense drilling before they are well characterised. For example, simply comparing the average density of wells illustrates how little these relatively frontier plays have been tested.

Participants It is important to consider the types of companies active in shale exploration. Are they small and unfunded, essentially land banking acreage positions in anticipation of the industry becoming commercial, or do they have the appropriate expertise plus, importantly, access to capital to invest.

In the US, for example, the upstream independents were almost entirely responsible for the shale revolution. The industry structure in the US was relatively unique versus the countries with the best economic potential assessed. Essentially those with the most attractive combination of economics and resource are largely controlled by big oil or national oil companies e.g., Argentina, Russia and China.

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Commercialisation Even in the countries where several hundred wells have been drilled, achieving commercial production still remains a significant hurdle. For example, even in the most advanced regions, the focus remains on proving commerciality via pilot programmes with the aim of demonstrating well cost and flow rate repeatability.

After a discovery has proven to be commercial below ground, a lack of appropriate infrastructure and equipment are major above ground commercialisation headwinds for these frontier, emerging plays such as Australia, China and Russia. For example, in Australia the domestic gas market opportunity is too small to support significant development, with LNG exports providing the real long-term opportunity. LNG, however, is capital intensive, requiring large amounts of upfront capital expenditure.

Cost structure Shale exploration is a drilling intensive process that differs from conventional oil and gas production. For example, hundreds of wells are required to commercialise shale plays. Well costs are driven by available oilfield equipment and experience. Often new drilling and completion skills are required. Bringing this technology and expertise from the US is not always as easy as it sounds. Well costs are also impacted by formation-related properties including depth of shale, pressure and temperature regime among other things. Therefore, bringing down drilling costs to acceptable levels over time using a “factory” approach is paramount.

Exhibit 17

Typical shale exploration model


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Environmental and social considerations

The success of the shale gas and oil industry is also partly dependent on the management of environmental and social risk factors. Stringent legislation could impact the economics of shale for energy companies, whilst social and political resistance might prevent licences to operate being granted, in our view. Some of the environmental and social debates are outlined below: Water consumption and contamination: hydraulic fracturing requires significant amounts of water. The process of fracking can use 7m- 23m litres of water according to a study by the Washington DC- based World Resources Institute. The water is pumped down the well and approximately 10- 40% returns to the surface (Waterworld, 2014). This therefore reduces the amount of water available locally for other purposes. This is especially problematic if freshwater is used. It is difficult to conclude what the potential impact might be, since water availability (or scarcity) varies by location. However, it is reasonable to assert that the development of shale gas or oil could be limited by the availability of water in certain locations. 38% of viable shale gas deposits worldwide are in areas where water supplies are a potential problem (FT, 2014). In 2012, Pennsylvania suspended water use for fracking in some parts of the state due to drought. This can cause considerable disruption to production and as a result, oil and gas companies are looking into alternative methods for fracking such as using gels, recycled or saline water. Even the water that does return to the surface cannot be easily used since it is contaminated with residual drilling and fracking fluids, and also water taken from the shale formations themselves. The options available for the operators are (i) underground disposal wells, (ii) recycling and (iii) treatment prior to discharge in public waterways. As regulation develops, there is a risk that the cost of safely treating and disposing of waste water increases, in our view. There have been some incidents regarding the contamination of drinking water:

The Pennsylvania environmental regulators are currently pursuing a $4.5m fine against the fracking company EQT for pollution caused from a leaking waste pit.

High levels of pollution were found around the Barnett

Shale in Texas in 2013. The study performed by the University of Texas found high level of contaminants such as arsenic, although these cannot be conclusively linked to the Barnett Shale. The highest

concentration was 16 times above the Environmental Protection Agency (EPA) safety standards for drinking water.

In 2013, a study performed by Duke University

suggested that there were elevated levels of methane, ethane and propane close to fracking sites due to poorly designed well castings.

In 2011, Crew Energy and GasFrac accidently

fracked into a water table in Alberta. This led to the contamination of the groundwater with toxic hydraulic fracturing agents which remained present in the groundwater a year later.

Climate Change: Shale gas is regarded as a “cleaner” alternative to oil and coal and could be perceived as a transition fuel as society moves more towards renewable sources of energy. The carbon footprint of shale gas compared to coal is significantly less when used for electricity generation approximately 50%, according to DECC. The use of shale gas in the US has contributed to the lowest levels of energy sector emissions since 1994 (DECC). However, methane leakage from shale gas could weaken the benefit to the climate, ‘cancelling out any carbon savings shale gas might offer over coal’ (The Guardian, 2012). Methane gas can have 34 times the warming impact of Carbon dioxide and therefore, provides a considerable risk to the climate. However, the technology does exist for fracking without emissions leakage and further implementation could be encouraged with the right regulatory framework. Local communities: Failure to achieve local support for new shale projects could result in disruption and social unrest. It is normal for energy companies to invest in the local community, in order to achieve and maintain the social licence to operate. However, shale projects can often be in areas that are not used to extractive industries. As such, there may be new challenges for energy companies to assess and resolve. Benefits include the creation of jobs and positive impact on the local economy. But, these could be at least partially offset by concerns over access rights, people’s health and the local environment. In the US, where the greatest growth in projects has been observed, drilling has mainly been developed in sparsely populated areas and therefore, has avoided material risks from local community disruption.

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Seismic activity: Evidence of seismic activity has been a stumbling block for growth in shale projects across the world due to strong community opposition. There have been concerns of seismic activity as a result of shale gas production from both the hydraulic fracturing and the injection of wastewater into disposal wells. In the US as fracking has grown the number of earthquakes has also increased. TIME Magazine has reported 100 recorded earthquakes of magnitude 3.0 or larger each year between 2010 and 2013 in the US (TIME, 2014). These earthquakes are generated when the well or fractures intersect an existing fault. Careful planning is required to reduce the risk of seismic activity. Biodiversity: The nature of drilling of oil means that local biodiversity can be negatively impacted. There is a cost associated with restoring sites back to their original state, and companies would need to ensure that sufficient provisions were made. This is a greater risk for shale gas compared to conventional gas as it tends to extend across much larger geographical areas. For example: the Marcellus Shale in the United States is ten times larger than the Hugoton Gas Area in Kansas (the US largest producing conventional gas zone) (IEA, 2012). As we have outlined above, there are a number of environmental and social issues to consider when exploring the possible development of the shale oil and gas industry. This remains a relatively new type of energy production and as such we expect to see changes and developments in the regulatory landscape. Legislation is likely to remain on a country or state basis. Indeed, in the US shale gas is regulated at the federal, state and local level with the lead role from the state. Stringent regulation could result in material costs for operators which may alter the economics of the industry.

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Summary of our country analysis

Summary Excluding the US, the countries where shale activity is most advanced are, and in descending order, 1) Argentina, 2) China, 3) Australia and 4) Poland. Activity in Russia is also well underway but recent sanctions may materially slow progress. In the UK, the opportunity is large compared with domestic energy needs, but developments are at a very early stage.

Economics Shale projects are vastly more drilling intensive than conventional projects, meaning delivering low well costs is a critical part of making the economics attractive. We observe considerable divergence in well costs (Exhibit 18) across the emerging shale regions due to depth, existing oilfield service sector, well complexity, technical capability and other factors such as the number and type of rigs available.

Drilling costs in China have come down considerably as new techniques are pioneered. For example, the average number of drilling days has dropped by two-thirds to 46 days with wells dropping from $16m to $8-11m per well. Moreover, Australia’s vertical wells in the Cooper Basin cost in excess of $10m. Fracturing and horizontal drilling is on top of this, with well costs greater than $20m common. In Poland the depth of shales, the lack of oilfield service capability and scale have also been key challenges. Well costs have been significant, costing as much as $22m, with similar wells in the US costing up to a third less.

Exhibit 18

Typical shale well costs are up to 3x greater than in the US

Typical shale well costs ($m)

0

5

10

15

20

25

US Argentina China Australia Poland


The Eagleford in the US has become the benchmark for emerging plays around the world. While several of the new

plays are described as being ‘Eagleford like’ e.g., Argentina, Australia and China, they all have very different commercial factors, meaning that economic success is not certain.

In this analysis, Wood Mackenzie model Eagleford like characteristics (i.e. a production profile) in Argentina, Australia and China to estimate the breakeven per country for a hypothetical development assuming country specific costs (each country is inflated on an Eagleford base line Australia 35%, Argentina 60% and 50% China) and fiscal terms; see Exhibit 19. Wood Mackenzie’s cost assumptions are substantially less than those currently observed in each country and, while these may fall, it could take some time. The figures’ relation to one another is defined by the area’s fiscal terms and cost uplifts, so their respective rankings by the breakeven metric may be slightly different to the possible NPV rankings.

Exhibit 19

Same shale, different country comparisons; Argentina has the lowest breakeven of all countries analysed*

B r e a k e v e n c o s t f o r s h a l e p l a y s ( $ / b o e )

0

2 0

4 0

6 0

8 0

1 0 0

1 2 0

1 4 0

1 6 0

U S - E a g l e f o r d A r g e n t i n a - V a c aM u e r t a

A u s t r a l i a -C o o p e r B a s i n

C h i n a - S i c h u a n

Source: Wood Mackenzie, Morgan Stanley Research estimates *Wood Mackenzie breakeven estimates based upon their cost assumptions and a Eagleford type curve

Activity levels China has drilled about 400 shale wells, including 130 horizontals; see Exhibit 20. However, in Argentina, over 250 shale wells have been drilled in the Vaca Muerta. Most wells have been vertical, which means well costs are also lower. The industry plans to move to horizontal wells over time, leading to higher per well expected ultimate recovery and higher decline rates but also ultimately better well economics Potential non-related beneficiaries Each country exploring for shale is at a very different stage of exploitation, and not all regions are being pursued for the

17



same reasons. In Australia, for example, the bulk of activity to date has been focused on the Cooper Basin shale that contains dry gas. Commercialization options include supplying the domestic gas market as well as larger LNG export options. In Argentina, operators are focusing on the Vaca Muerta shale, which produces oil. Argentina’s energy deficit has driven the government to support higher domestic production to decrease the imbalance. The Vaca Muerta’s oil

improves shale well economics, and YPF has demonstrated that commercial well results are achievable, whereas in China shale gas is being pursued for industrial domestic use. .

Exhibit 20

China has been the most active region; however, Argentina is rapidly catching up with about 200 wells expected to be drilled in 2014

Source: Wood Mackenzie, Morgan Stanley Research

Where is big oil? Big oil has have been taking a portfolio approach when it comes to shale exploration. Chevron, for example, has positioned itself in many of the emerging basins. It has acreage in Argentina, Poland, and Australia, plus until recently it had a position in Lithuania. Exxon is also pursuing different plays, including positions in Argentina and Russia.

International oil and gas companies can quickly decide to exit a region as well. Poland, for example, was the European hotspot for shale in 2011-13. However, after some disappointing well results and retrospective fiscal term changes, Eni, Exxon and Total all exited.

Where could we be wrong? We need to be careful about writing off emerging shale regions when only the first few wells have been drilled. China and Argentina have shown that shale can be produced economically and that a rapid decrease in well costs is possible with scale and experience. As commodity prices

increase, shale well economics also improve, taking into account improvements in flow rates and decline curves that should be achievable as different well technologies are applied. Certainly, liquid-rich shales offer more compelling longer-term upside given the clear advantage these shales have in terms of well economics.

Morgan Stanley has agreed to sell its Global Oil Merchanting unit of its Commodities division to a 100 percent subsidiary of Rosneft Oil Company, as announced on December 20, 2013. The proposed transaction is subject to regulatory approvals in the U.S., the E.U., and certain other jurisdictions and other customary closing conditions. Please refer to the notes at the end of the report. Morgan Stanley Asia Limited is acting as the financial advisor to Cinda Sino-Rock International Energy Company Limited (“Cinda Sino-Rock Energy”), an investment subsidiary of China Cinda Asset Management Co, Ltd, in connection to Cinda Sino-Rock Energy’s capital injection in Sinopec Marketing Co., Ltd, a subsidiary of China Petroleum & Chemical Corporation, as announced on September 15, 2014. Please refer to the notes at the end of the report.

18



Argentina

How big is the opportunity?

Argentina is in the early stages of an oil renaissance, which could be similar to the US opportunity in terms of scale. Despite the challenging macro-political situation of the country, the attractiveness of below-ground fundamentals has been enough to spark a wave of investments in the shale story. While this has been led by state-controlled company YPF, renowned international players are also involved.

In its most recent report, the Energy Information Administration/Advanced Resources International, Inc. (EIA/ARI) listed Argentina as possessing the world’s third-largest shale potential. The country has shale gas TRR (technical recoverable resources) of 802Tcf (143Bboe) and a shale oil TRR of 27Bboe.

Vaca Muerta is one the most promising areas in Argentina’s shale formations in terms of both size and hydrocarbon quality, including areas that are more “oily” and thus present better economics. By itself, Vaca Muerta represents c40% of the country’s total shale gas resources and c60% of its shale oil.

Exhibit 21

Argentina’s shale basins Vast potential for the country, with developments focused on the Vaca Muerta formation

.

VACA MUERTA PLAY

Source: YPF

Why has it worked?

1) Energy needs

Of all countries with shale potential, one might wonder why Argentina has jumped the queue, becoming the second country following the US to have achieved commercial-scale shale production.

Although Argentina has been removed from the international capital markets for a while now (which could change with the regime shift we expect in 2014), the country has developed a pressing need for increased hydrocarbon production. Given a decade-long period of underinvestment in the sector, mainly driven by the lack of supportive policies and price controls, the country rapidly developed a ~$7billion energy trade deficit. With declining international reserves, Argentina decided to incentivize a new wave of investments in the oil & gas industry.

We are confident that this new wave will be sustained for a long period, given that eliminating the current energy deficit will likely take close to a decade. Therefore, we think that risks of the implementation of stricter price controls with the ramp-up of shale production are relatively low.

Exhibit 22

Argentina’s energy trade deficit a trigger for the revival of the oil and gas sector

ARGENTINA'S ENERGY TRADE BALANCE (US$B)

(8.0)

(6.0)

(4.0)

(2.0)

0.0

2.0

4.0

6.0

8.0

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 *

Source: Indec, Morgan Stanley Latam Economics * Jan-Jul annualized

2) Geological attractiveness

The prospectivity of the Vaca Muerta play is generally very good and combines the key characteristics in different US shales in one single location, as shown in Exhibit 23. In addition, proprietary data analyzed by our specialized consultant Rystad Energy resulted in the map in Exhibit 24. Cross-referencing four aspects of the play, equally weighted, shows the sweet spot is in Vaca Muerta:

19



i) total organic carbon (TOC), which measures organic content and needs to be at least 2% according to the EIA

ii) vitrinite reflectance (Ro), which indicates the thermal maturity of the shale plays and is key to determining the delineation of the dry gas, wet gas and oil windows

iii) sedimentary thickness, which indicates productivity and potential to use horizontal or vertical wells

iv) formation depth, which indicates reservoir pressure and hydrocarbon concentration

Highlighted on the map are Loma Campana, which is producing over 25Kbbl/d of shale oil (and is run by a JV of YPF and Chevron), as well as Narambuena (a JV of YPF and Chevron) and La Amarga Chica (a recent JV of YPF and Petronas). All of the areas are within the sweet spots of the acreage, according to Rystad.

Exhibit 23

Vaca Muerta shale has the key features present in different basins in the US … Shale Plays Vaca Muerta Haynesville Marcellus Eagle Ford WolfcampTOC (%) 3-10 0.5-4 2-12 3-5 3Thickness (m) 30-450 60-90 10-60 30-100 200-300Pressure (psi) 4,500-9,500 7,000-12,000 2,000-5,500 4,500-8,500 4,600Area (km2) 30,000 23,000 250,000 5,000 5,200 Source: YPF, Morgan Stanley Research Exhibit 24

… and the initial prospects to be developed seem to be near the sweet spot areas of the play

. Vaca Muerta Prospectivity

High

Low

Licensed Blocks

Loma Campana

La Amarga Chica

Narambuena

Source: Rystad Energy, Morgan Stanley Research

3) Location in a proved oil province (Neuquén)

Vaca Muerta is in Neuquén province, which is the core of Argentina’s oil production history. It is in effect an oil & gas province, producing from conventional deposits for over 90 years. As such, the governors and the population are used to the industry’s activities, which is the key income generator for the province.

Moreover, given the lack of investment in the past decade, production of oil in Neuquén has declined over 150Kbbl/d, leaving spare capacity in infrastructure and treatment facilities for the upcoming unconventional production increase.

Finally, given its location by the mountains, there are no constraints with water supply, barring some investments to more efficiently gather water via pipelines. The main constraint is the availability of sand used as fracking proppant, which YPF is importing from Brazil and China. However, the company is finalizing the acquisition of sand mines in Argentina, which it expects to improve operations and lower costs.

Who are the participants?

YPF is the key acreage holder in Vaca Muerta, as well as in other shale-prone basins in Argentina. However, many other companies hold acreage in the formation, either directly or in partnership with other players.

Exhibit 25

YPF owns most of the acreage in Vaca Muerta, but many other participants are in the play

VACA MUERTA TOP HOLDERS (acres)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

YP

F

Plu

spet

rol

Pet

robr

as

Tot

al

GyP

Neu

quén

Cro

wn

Poi

nt

Exx

on

Pan

Am

eric

an

Win

ters

hall

Oth

ers

DRY GAS WET GAS OIL


Among local Argentine companies, key participants are:

YPF (YPF.N): Argentina’s integrated oil & gas company (51% government owned) started producing from unconventional deposits in late 2012. The Loma Campana field produces over 25Kbbld of shale oil in a JV with Chevron.

Pluspetrol: a privately held company operating in Argentina since 1977, Pluspetrol has recently doubled unconventional

20



acreage with the acquisition of part of Apache’s assets in the country.

Gas Y Petroleo de Neuquén – GyP: the provincial oil company was created in 2008, focusing on the unconventional assets of Neuquén. It takes a non-operating 10–15% stake in new licenses awarded in the region and has a number of JVs to foster shale development in the province.

Pan American Energy: originally held by a local family, today Pan American is owned by BP, Bridas (a local group) and CNOOC. Its portfolio is more gas-prone, but it holds interests in four blocks in proximity of YPF’s shale oil discoveries.

International oil companies also hold acreage in Vaca Muerta, with the most relevant being:

Petrobras: the company operates as an integrated producer in Argentina, but holds the third largest acreage in Vaca Muerta. International assets, including Argentina, are not a focus for Petrobras and those will likely be part of the company’s divestment plan in the coming years.

Total: present in Argentina for nearly 25 years, the company has produced tight gas since late 2009 and has exposure to acreage around YPF’s shale oil discoveries, as well as in the less explored wet gas and dry gas windows,

Exxon: the company started activities in Neuquén in 2010 with the acquisition of four exploration blocks and is testing the Vaca Muerta shale in a partnership with Americas Petrogas.

Chevron: a first mover in Argentina, Chevron is a 50% partner of YPF in the Loma Campana JV, and recently extended its partnership to explore the Narambuena prospect.

Wintershall: the company has exposure to three unconventional blocks at Vaca Muerta (San Roque, Aguada Pichana and Bandurria) and recently signed a JV with GyP for the potential development of the Aguada Federal Block, which lies north of YPF’s Loma Campana,

Petronas: while not officially closed, Petronas and YPF have recently signed an MOU for a JV to develop the La Amarga Chica prospect in Vaca Muerta.

Vaca Muerta is also the main area to which a few Canadian junior oil companies are exposed, such as:

Madalena Energy (MVN.V): the company has exposure to three unconventional blocks in Vaca Muerta, being the

operator at Curamhuele (gas window) and a partner at Cortadera (gas window) and Coiron Amargo (oil window), the latter sitting in between YPF’s Loma Campana and La Amarga Chica (a recent JV with Petronas)

Americas Petrogas (BOE.V): the company has been active in the Argentine shale story since 2011. It has exposure to 12 blocks and has already announced four different discoveries in the Vaca Muerta formation on both the oil and gas windows.

Exhibit 26

Vaca Muerta: Main operators

.

Source: YPF, Morgan Stanley Research

What is the cost structure?

With over 250 wells drilled in Loma Campana, costs have come down a long way, to ~$7million per well. Argentina has benefitted, in a way, from the drilling technology and expertise created in the US over the past several years. With this competitive advantage, drilling costs for YPF’s vertical wells have declined from an initial $11million to just under $7million at present.

YPF continues to work on lowering drilling costs, and we believe that in the long term, Argentina could achieve a similar cost as that in the US, at a range of $4–7million. We think the main drivers of this planned cost reduction will be: i) increased scale, with over 400 producer wells by year-end 2015 (from ~160-180 today); ii) more availability of walking rigs, which are able to move much faster within the pad (3-5 days faster) and also increase the number of wells drilled in each pad from 4 to 8-12; iii) conclusion of the acquisition of sand mines in

21



Argentina, replacing expensive and logistically challenging sand imports.

Exhibit 27

Production scale and rig fleet evolution, including modern walking rigs …

YPF RIG COUNT (UNCONVENTIONAL - LOMA CAMPANA)

0

5

10

15

20

25

30

1Q12 Dec '12 Dec '13 1H14 Dec '14 (e) Dec '15 (e)

STANDARD WALKING

Source: YPF, Morgan Stanley Research e = Morgan Stanley Research estimates

Exhibit 28

… have allowed YPF to lower drilling costs by ~36%, to just under $7.0 million

YPF VERTICAL WELL COST (DRILLING & COMPLETION - US$M)

0.0

2.0

4.0

6.0

8.0

10.0

12.0

2011 2012 2013 1H14 2H14 LT *

36% COST REDUCTION

Source: YPF, Morgan Stanley Research * Assuming a range of $4–7million

Moving to horizontal drilling will be a key challenge for Argentina. The initial development of Vaca Muerta has been based on vertical wells, while the traditional shale development in the US is primarily based on horizontal drilling. This choice has been supported by the thickness of the source rock in Argentina, which allows an efficient use of vertical wells. Some of the existing rig fleet in the country might not be suitable for horizontal drilling due to the extra power and torque required for horizontal drilling.

Argentina is starting to move to horizontal drilling, but it is still in very early stages. Year-to-date, only a handful of horizontals have been drilled, with most of them being “test and study” wells. YPF plans to drill an additional 6-8 horizontal wells in 2H14, after which we would expect to have more clarity on results and drilling costs.

The development strategy with vertical wells has essentially involved a reduction of the choke, resulting in a lower initial production rate, but also a lower production decline after the first year. This model would result in the best IRR for the current production. As development shifts to horizontal drilling, we expect to see the traditional high initial production and high decline rate after the first 12 months, with a higher EUR (expected ultimate recovery) being the trade-off. At the sweet spot, EUR could increase from the current vertical type-well ~300Kbbl to nearly 1MMbbl in the best case scenario.

At the current drilling costs and EUR expectation, we see vertical wells’ IRR at 16.4%, which is ~200bps above our estimate of YPF’s cost of equity and ~530bps above its WACC. With efforts to further reduce costs (via greater scale and knowledge of the play, local sourcing of sand and a more modern rig fleet available in the country), we think IRRs could be substantially above that level (see Exhibit 29).

Exhibit 29

YPF: IRRs are very sensitive to drilling costs and recovery rates at Loma Campana

IRR 200 250 300 350 4005.50 14.3% 18.6% 23.1% 28.0% 33.2%6.00 12.6% 16.4% 20.4% 24.8% 29.4%6.50 11.1% 14.6% 18.2% 22.2% 26.3%7.00 9.9% 13.1% 16.4% 19.9% 23.7%7.50 8.8% 11.7% 14.8% 18.1% 21.5%8.00 7.9% 10.6% 13.4% 16.5% 19.6%8.50 7.1% 9.6% 12.2% 15.0% 17.9%

EUR (Kbbl)

Dri

llin

g C

apex

(US

$M)


How is the regulatory framework?

Argentina is due to approve a new hydrocarbon law, which would benefit the investment climate in the sector. The country’s existing law works relatively well, but it is now 45 years old and has not caught up with the recent trends in the industry. A new bill has been sent to Congress and we expect it to be approved before year-end. Most of the requests and suggestions from industry participants were included in the new bill:

Unconventional concessions will be increased to 35 years, with optional 10 years extension periods.

Royalties will be stabilized at 12%, with a 3% increase in each optional 10-year extension, with an 18% cap.

Turnover taxes will be stabilized at 3% (some provinces were looking to increase it to 4–6%)

The decree that incentivizes foreign players to invest in the sector will be turned into law, while the investment

22



threshold will be lowered to $250 million (from $1.0 billion) and the ability to export 20% of production without paying an export tax will be reduced to three years (from five years).

The natural gas pricing incentive level of $7.5/MMBtu will be turned into law, from bilateral contracts previously

While the provinces will continue to conduct the licensing process, they will do it based on defined guidelines established by the Federal Government

The free carry provinces had for new concessions will be removed; they will still be able to choose to take a stake in the blocks, but bidding and investing as a normal partner

The definition of minimum environmental and safety standards will change.

But there is still room for improvement, given that the crude oil export tax remains in place. Argentina still has a $72/bbl price cap for crude oil exports, with the objective of ensuring that the local market counts on local supply. In case of exports (virtually non-existent today), the price difference is retained as an export tax. While this is an improvement from the $42/bbl price cap, it still prevents full realization of prices.

Given that the country has been able to close most of the past gap for gasoline and diesel prices versus international levels, light crude oil in Argentina trades at ~$83/bbl, so moderately above the $72/bbl theoretical cap. We believe that with the transition to a more pro-market regime in the coming years, this price cap is likely to be removed. As long as refiners are able to run at a reasonable profit, there is no reason to keep the artificial control on crude oil prices.

We see YPF (current price $32) as a very attractive long-term investment opportunity, with a free option on the shale upside. The stock trades at undemanding valuation levels (3x 2015 EBITDA, we estimate). In our base case, we only include the very first cluster being developed in Vaca Muerta (Loma Campana), which gives us $1/ADR. Therefore, all of our upside is driven by the conventional assets of the company, leaving Vaca Muerta as a free option.

Assuming conservative metrics for the development of the oil and gas windows of Vaca Muerta, such at $8.0m drilling costs and a 40% acreage risk, we believe that the shale assets could be worth ~$15/ADR.

In a blue-sky scenario, normalized results and $110/bbl oil could generate ~$96/ADR. In this hypothetical case, YPF would recover total production to ~600Kboe/d, with margins

similar to the period before the downward spiral in the Argentine energy sector. The company would also fully develop Vaca Muerta with Brent at $110/bbl with similar economics as in the US. The unconventional potential alone would double the company’s current market cap.

Exhibit 30

Bull case: Normalized Discount Rate and Vaca Muerta Shale Oil Almost Doubles Base Case

50.0

72.0

7.0

11.5

3.5

BASE CASE NORMALIZEDECONOMY

VACA MUERTA(OIL)

VACA MUERTA(GAS)

BULL CASE

US$/ADR

$15/ADR


Exhibit 31

The Blue-Sky Scenario: Normalized EBITDA and Higher Oil Prices Would Yield ~$96/ADR BLUE SKY SCENARIO US$m Multiple EV $/ADRNORMALIZED EBITDA * 6,000 5.1x 30,600 77.8VACA MUERTA (OIL) 10,781 27.4VACA MUERTA (GAS) 1,815 4.6TOTAL 43,196 109.9NET DEBT 5,420 13.8EQUITY VALUE 37,776 96.1

Source: Morgan Stanley Research estimates *EBITDA assuming crude prices at international parity and downstream margins back to the 2007–2011 average.

Valuation & risks

Our mid-2015 PT of $50/ADR is derived from our consolidated DCF model. We project YPF’s FCF for each business segment (upstream, downstream, corporate, and eliminations). For upstream, we forecast cash flows to depletion of reserves, including upside only to the first JV agreement with Chevron at Vaca Muerta. For downstream, we use a perpetuity approach with a 4% nominal long-term growth rate, assuming YPF would source hydrocarbons from third parties in the long-term as feedstock to its refineries.

To reflect our perception of improving macroeconomic scenario in Argentina in the next 12–18 months, we have used a more normalized WACC of 11.1% based on: i) country risk declining to pre-crisis levels of ~500bps; ii) interest rates in US dollar terms at 9%; iii) debt/capital of 40%.

23



Risks to our call and price target: i) lack of access to further funding options; ii) well economics (capex/opex) at Vaca Muerta disappoints, lowering NAVs; iii) slowdown in global

economic growth causing a sharp decline in oil prices; iv) changes to Argentina’s oil sector regulations and level of government take; v) other unforeseen operating disruptions.

24



Australia


Australia has a number of large underexplored basins with shale gas, shale oil and tight gas potential. Australia has shale gas resources of 437Tcf (circa 6% of world shale gas resources) and 19 billon barrels of oil (circa 6% of world oil shale resources), according to the EIA (US Energy Information Administration). While a number of wells have been fractured and tested, there is no commercial production.

In our view, shale gas exploration is being driven by a number of factors, which include: 1) the scale of the opportunity; 2) rising domestic gas prices; and 3) feedstock for greenfield and brownfield LNG expansions. The chase for liquids from shale, however, is at a much earlier stage but represents a large and potential valuable opportunity.

Exhibit 32

Australia’s shale basins account for 6% of the world’s oil and gas shale resources globally

Source: Dug Website, Morgan Stanley Research


Small public and private companies were the early entrants. They have now, however, reduced their exposure by selling their acreage to larger players who have provided sources of funding and expertise. For example, there has been over A$1.5 billion of deals since mid-2010. Big oil has driven a large amount of the surge in interest, including: BG (covered by

Martijn Rats), Mitsubishi, Conoco Phillips (covered by Evan Calio), Hess (subsequently left; covered by Evan Calio), Total (covered by Martijn Rats), Chevron (covered by Evan Calio), Statoil (covered by Haythem Rashed), Sasol and Apache (covered by Evan Calio); see Exhibit 33. Origin Energy (covered by Stuart Baker) has also been active with recent deals that provided entry into the Cooper and Beetaloo basins.

Exhibit 33

A$1.5bn of deals since mid-2010 supported by a surge of big oil interest

Date Farm-in Farm-out Basin AmountJun-10 Mitsubishi Buru Energy Canning A$152.4mJul-11 BG Drillsearch Energy Cooper A$130mJul-11 Conoco New Standard Energy Canning US$109.5mJul-11 Hess Falcon Oil and Gas Beetaloo US$60mNov-12 Total Central Petroleum Georgina US$178mDec-12 Santos Tamboran Resources McArthur US$41mFeb-13 Chevron Beach Energy Cooper US$349mJun-13 Statoil PetroFrontier Georgina US$175mNov-13 Apache Buru Energy Canning A$32.2mFeb-14 Origin Senex Energy Cooper A$211mMay-14 Origin/Sasol Falcon Oil and Gas Beetaloo A$185m

Source: Company Data, Morgan Stanley Research

How developed is the opportunity and timeline to commerciality?

The Cooper Basin is leading the way in terms of unconventional drilling activity. Since the first well in 2011, over 30 shale and tight gas wells have been drilled in the Cooper Basin, Exhibit 35. The initial results from the vertical wells have been encouraging, with gas flows in a range of 1-4 mmscf/d. Given the well depths and complexity, these were below commercial rates but were considered a reasonable start. Despite these relatively modest flow rates, Santos has already connected two shale wells into its gas gathering system. Crucially, there has not been any observable improvement in flow rates; see Exhibit 36.

Exhibit 34

Cooper Basin – Lots of wells stage

Understanding Geology

Initial fraccing

and testingLots of wells

Pilot programmes Commerciality


Initial fraccing




Initial fraccing



Initial fraccing



Initial fraccing




25



Exhibit 35

Unconventional wells drilled by basin has largely been focused on the Cooper basin, onshore Central Australia

0

5

10

15

20

25

30

35

Cooper Perth Canning Beetaloo Georgina SouthNicholson

Otway


Other unconventional gas plays in the Cooper Basin have potential and may overtake shale. Tight gas from sands is the primary target and Origin’s recent deal with Senex is interesting. Likewise, Drillsearch has significant wet gas acreage that with further exploration and appraisal drilling could be commercialized. Similarly, Strike Energy is chasing a resource in the form of shallow coals, which due to their depth need significantly less gas production rates to be potentially economic.

Exhibit 36

Cooper Basin flow results – shale and tight gas

4.5

2.1

2.0

1.3

0.3

0.3

1.3

2.6

1

0.4

1.4

1.5

2.2

1.4

0.2

0.1

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

Halifax-1

Encounter-1

Holdfast-1

Moonta-1

Marble-1

Holdfast-2

Nepean-1

Moomba-191

Gaschnitz-ST1

Roswell-1

Moomba-194

Langmuir-1

Hornet-1

Kingston Rule-1

Sasanof-1

Paning-2

BPT SACB SXY

Source: Company Data, Morgan Stanley Research Note: Some wells include coals, tight sands as well as shale formations. Units MMscf/d

Activity outside of the Cooper Basin is at a much earlier stage. However, the Northern Territory looks as though it could be a particularly interesting frontier play due to the high drilling activity expected over the next 12 months, with focus on the McArthur, Beetaloo and Georgina basins.

While it is early days for these basins, the focus is on understanding the geology and confirming what was found from previous exploration activity. Two important characteristics are present in the basins: 1) the depths of the shale, which are relatively shallow; and 2) the liquids potential of the shales.

Exhibit 37

Northern Territory – Between understanding geology and initial fraccing and testing stages


Initial fraccing




Initial fraccing



Initial fraccing




In Western Australia, activity is now more subdued after some early momentum. The Canning Basin is a large underexplored basin with shale gas and liquids potential. It is a huge and remote basin with a lot of potential. Its challenge is its location, – it is remote, there are large distances involved, wet seasons to tackle and other stakeholder issues to contend with. Buru Energy has done the most work there. It drilled six wells there between 2011 and early 2013, with good flow results from one vertical well that was tested (Yulleroo-2). No new wells have been drilled and a planned drilling plus fracturing campaign has been delayed due to stakeholder issues and government approval processes. ConocoPhillips and PetroChina announced (in October 2014) that they have pulled out of a JV with New Standard Energy.

In the Perth Basin, AWE has drilled its second shale well with the objective of proving up a resource to monetize it via the domestic market in Perth. In 2013, Arrowsmith-2, the first well to be fractured and tested, was initially encouraging and flowed at 3.5 MMscf/d but subsequently dropped to 0.9 MMscf/d. The Drover-1 well was recently drilled as a follow-up but no fracturing or testing was carried out, making the results difficult to interpret. AWE recently drilled the Senecio-3, which was targeting shale and other tight gas formations. It appears to have also found a material conventional gas discovery with follow-up flow testing planned for later in the year.

Exhibit 38

Western Australia - Between understanding geology and initial fracturing and testing stages


Initial fraccing




Initial fraccing



Initial fraccing



Source Morgan Stanley Research

26




Costs are high and pose a significant challenge. Even in the Cooper Basin, which has existing infrastructure and oilfield service capability, costs are a real headwind to commercialization. The wells are expensive due to: 1) limited horizontal drilling experience in the basin; 2) limited fraccing equipment, personnel and experience; 3) the depth of the wells, which are near 4,000m and located in high temperature and pressure environments requiring specialized equipment; and 4) specialized equipment mobilization costs. For example, vertical wells cost up to as much as A$15 million without fracturing, and in some cases, significantly more. An average fracture stage has cost up to A$0.5 million.

However, over time we think costs will eventually come down. In fact, we have already seen new service providers entering the market, which could help drive costs down e.g., Condor Energy, a private specialized cementing, coiled tubing and stimulation company.

Exhibit 39

The new entry of Energy Condor could help lower well costs, lowering commercial thresholds

Source: Condor Energy, Morgan Stanley Research

Cooper Basin flow results are not yet commercial. In Exhibit 40 we estimate the required well costs versus dry gas flow rates. Provided wells costs can come down to c.A$10-15 million (fully fracced and horizontal) and with wellhead gas prices of greater than A$7/mmbtu, we think flow rates of about 5+ MMscf/d are required to be commercial. At this stage, the industry has not demonstrated these metrics are achievable, although further work is underway.

Exhibit 40

We think flow rates of 5mm+cfd are required with a significant drop in well costs to be commercial

Well IRRsWell Costs (A$m)

10 15 20 255 60% 33% 19% 11%4 44% 22% 11% 4%3 27% 11% 3% -3%2 11% 0% -7% -11%

Flo

w R

ates

(M

Msc

f/d

)

Source Morgan Stanley Research estimates

Equity Implications (Beach Energy A$1.32)

Investors need to be cautious on shale valuations in Australia. In the Cooper Basin, we continue to advise investors to pay little for it until there are signs that results are improving. For the smaller Cooper Basin players, we prefer SXY’s strategy of targeting tight gas resources outside the deep Nappamerri Trough. DLS also has a material wet gas position that it may be able to monetize with successful exploration and appraisal activities. In terms of the large cap E&P stocks, shale exposure is relatively small compared with other parts of the business. We view the SACB JV’s infrastructure as a material advantage for any shale development.

In shale basins outside of the Cooper Basin, the Northern Territory looks particularly interesting but is at an earlier stage than the Cooper Basin. Shallow shales (with reduced drilling costs longer term) and oil potential (with better well economics) look attractive. Origin, Santos and some other local and international companies have exposure to this basin.

The Canning Basin looks challenging due to its remoteness and stakeholder issues. A fracturing and testing programme is planned for mid 2015 and will be an important milestone for the basin. In the Perth Basin, AWE is exploring for shale gas and other forms of tight gas. It is early days for shale in this basin, although AWE has discovered a significant gas resource (conventional) that could mean this overtakes its shale activities in the basin.

Outside of the companies that we cover, we prefer smaller players that have exposure to a number of basins with, ideally, oil shale potential (as opposed to shale gas). When assessing management teams we are looking for companies with adequate balance sheets and commercial management teams capable of farming out and using third party capital to develop their resource bases.

27



China


China has abundant shale gas reserves. According to EIA’s latest global shale gas report in January 2014, China has a technically recoverable shale gas reserve of 1,115 trillion cubic feet (~32 trillion cbm), which is the largest in the world. According to the Shale Gas Development Plan for 2011-15 (Shale Gas 12th Five Year Plan), published by the Ministry of Land and Resources (MoLR) in March 2012, it is estimated that China has a recoverable shale gas reserve of 25 trillion cbm, exceeding the country’s reserve of conventional natural gas.

Shale areas can be mainly categorized into three groups, including 1) Paleozoic marine shale area; 2) Meso-Cenozoic lake facies shale area; and 3) Paleozoic transitional facies shale area. Please refer to Exhibit 41 for the distribution of shale areas in China.

By geography, Tarim Basin and Southern Areas (including Sichuan Basin) are typical marine shale areas, while Songliao Basin, Ordos Basin, Junggar Basin and so on are typical terrestrial shale areas. Marine shales tend to have a higher content of carbonates, a higher content of quartz silicates, and a lower content of clay, making the rocks relatively brittle. As a result, marine shales are seen as easier to frack. Thanks to the potentially enormous reserve and marine shale formation, Sichuan Basin and Tarim Basin are considered the most prospective shale plays in China.

Sinopec’s Fuling is China’s first large scale and the most promising shale gas field in China. The field entered commercial development in March 2014, with a target of building production capacity of 5bn cbm per year by 2015.

Exhibit 41

China’s shale gas regions

Source Third National Resources Evaluation, Oil & Gas Journal, Morgan Stanley Research


China’s shale gas development has experienced highs and lows in the past few years. A recap of key events follows:

In June 2011, China conducted the first round action for development rights in four shale blocks. Sinopec and Henan CBM won bids for two, while the other two did not receive enough bids.

In March 2012, MoLR published the Shale Gas Development Plan for 2011-15 (Shale Gas 12th Five-Year Plan), setting a target of developing production capacity of 6.5bn cbm of shale gas by 2015 for the country, which was considered ambitious by the market then.

In September-October 2012, China conducted the second round of auction for 20 blocks, and development rights were granted in 19 blocks. Non-oil and gas companies as well as private companies also won bids. Sentiment for shale gas development reached a high level.

In November 2012, MoLR announced an Rmb0.4/cbm ($1.8/mmbtu) subsidy to encourage shale gas development.

However, with slow investments in 2nd round blocks and lack of major development nationwide, sentiment for shale gas development cooled down. The 3rd round action was also delayed.

In October 2013, the National Energy Administration announced its Shale Gas Industry Policy with key support measures in taxes and subsidies.

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In March 2014, Sinopec announced a breakthrough in Fuling and the target of developing Fuling into the first commercial shale gas field in China. Interests in shale gas investment revitalized, especially in Sichuan Basin. Reaching capacity of 6.5bn cbm in 2015 has also become likely.

According to the Ministry of Land and Resources, as of the end of July 2014, China’s invested Rmb 20bn (~$3.2bn) on shale gas and drilled 400 wells, which includes 130 horizontal wells.

Please refer to Exhibit 42 for a detailed timeline of China’s shale gas development.

Exhibit 42

Summary of China shale gas development

Source: Ministry of Land and Resources, Sinopec, Xinhua, Morgan Stanley Research

Sinopec’s Fuling Shale Gas Fuling is in a mountainous region at the edge of Sichuan Basin. Based on 2D seismic analysis and geological structural evaluation before 2006, it is considered to have little promise for conventional oil and gas. However, in 2009, Sinopec found that the marine shale formation Longmaxi is of high-quality and stable. As a result, in September 2009, Sinopec decided to drill the Jiaoye HF-1 exploration well at Fuling. On November 28, 2011, Sinopec recorded 203k cbm daily production from Jiaoye HF-1, marking a breakthrough in Sinopec’s shale gas E&P. Follow-up analysis suggested that there is a wide and thick

prospective area in the Longmaxi formation in southeast Sichuan Basin that contains organic matters and has good conditions to form gas. After this analysis, shale gas E&P in Sichuan Basin started to focus on the Longmaxi formation in southeast Sichuan.

In 1H13, Sinopec drilled 3 appraisal wells and performed 3D seismic in a region of 600 sqr km. Afterwards, a prospective area of 28.7 sqr km was selected to place 10 drilling platforms and drill 17 test wells. All the 17 wells were successful, with an average daily production of >150k cbm per well (>5.3mmscf/d).

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The large-scale exploration confirmed that Fuling has high-quality shale gas reserves.

On March 24, 2014, Sinopec announced a breakthrough in Fuling shale gas and a target of developing annual production capacity of 5 bn cbm by 2015 and 10 bn cbm by 2017.

Exhibit 43

Sinopec’s Jiaoye HF-1 well at Fuling – the first shale well to achieve commercial production in China

Source: Sinopec

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Exhibit 44

Fuling development summary

Source: Sinopec, Chongqing Government, Morgan Stanley Research

Exhibit 45

Capacity addition to accelerate in 2H14 Shale Gas Annual Capacity at Fuling (bn cbm)

0.5 0.7 1.0

5.0

10.0

0

2

4

6

8

10

12

Nov-13 Feb-14 May-14 2015e 2017e

e = Sinopec targets Source: Sinopec, CNPC, Chongqing Government, Morgan Stanley Research

According to the Chongqing Government, production capacity at Fuling stood at 1.0 bn cbm per annum as of May 2014. With a 2015 target five times current capacity, it is very likely that there will be an investment boom from 2H14. As a result, we believe cost control and efficiency are key to the capacity target achievement and project economics at Fuling.


PetroChina, Sinopec and Yanchang are pioneers in China’s shale gas development. While PetroChina, Sinopec and Yanchang have spent a lot of effort in shale gas development, Sinopec’s breakthrough in Fuling is more significant than efforts by PetroChina and Yanchang considering the production scale. A summary of efforts and achievements made by the Big Four oil and gas companies is as follows:

PetroChina is the first mover in China shale gas E&P, entering this field in 2006. PetroChina’s most prospective project is Changning-Weiyuan. Since 2007, the company has invested more than Rmb 6bn (~$1bn), drilled more than 40 wells and achieved gas flow in more than 30 wells in the project. In April 2012, the Changning-Weiyuan National Shale Gas Demonstration block was established, making it the first national shale gas demonstration block in China. PetroChina is also the first mover in sino-foreign cooperation in China shale gas E&P. The company signed with Shell China’s first joint-evaluation agreement for Fushun-Yongchuan in 2009 and China’s first shale gas PSC for the same block in 2012. PetroChina’s production target in 2015 is 2.6 bn cbm, including 2.0bn cbm from Changning-Weiyuan, 0.5bn cbm from Zhaotong, and 0.1bn cbm from international cooperation. The

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company has lowered average cost per horizontal well from Rmb100mn to Rmb70mn.

Sinopec started shale gas and shale oil exploration in 2008. In the subsequent five years, Sinopec invested billions of RMB and drilled more than 40 shale gas/oil wells in Shandong, Henan, Hubei, Sichuan, Guizhou, Chongqing, and so on. Sinopec’s shale gas development accelerated after recording high industrial volume (203k cbm per day) at Jiaoye 1-HF, the first shale well in Fuling, in November 2012. In 1H13, Sinopec drilled 17 test wells at Fuling and achieved average daily flow of >150k cbm (>5.3mmscf/d) per well, confirming Fuling’s potential to become a commercial shale gas field. In September 2013, the National Energy Administration recognized Fuling as a National Shale Gas Demonstration Block. In March 2014, Sinopec announced a plan to develop Fuling into the first commercial shale gas field in China and a target to build an annual capacity of 5 bn cbm by 2015 and 10 bn cbm by 2017. In addition, Sinopec recently reported good prospects in Dingshan, which is 150km away from Fuling and has an estimated reserve of 608.9bn cbm.

CNOOC started drilling the first shale well on March 1, 2014 and completed drilling on June 5, 2014, after a 91-day cycle. The 3,001m exploration well, Huiye-1, is in Fuhu, Anhui. CNOOC met two layers of high quality shale, and it is performing an exploration evaluation on the well. As a next step, CNOOC will frack the well to test the volume.

Yanchang started shale gas exploration in 2008. With expertise in ultra-low permeability oilfield exploration, Yanchang discovered shale gas in Ordos Basin. In April 2011, Yanchang completed fracturing at Liuping-177 well in Yan’an and recorded gas flow, making it the first terrestrial shale well that produces gas. In September 2012, the National Development and Reform Commission (NDRC) approved the setup of the first National Terrestrial Shale Gas Demonstration Region in Yan’an. Yanchang’s target is to build a proved reserve of >150bn cbm and a production capacity of 0.5bn cbm per annum by the end of the 12th Five Year Plan. As of July 2013, Yanchang has drilled 30 shale gas wells, completed fracturing in 23 wells, and recorded shale gas flow in 21 wells.

As of the end of July 2014, in Fuling, Sinopec has drilled 79 horizontal wells, and 27 of them are in production. Sinopec plans to drill 253 wells in 2013-15 and has a shale gas investment budget of Rmb21.5bn (~$3.5bn), while PetroChina plans to drill 154 wells in 2014-15 and has a shale gas investment budget of Rmb11.2bn (~$1.8bn). Expected production in 2015 is 3.5bn cbm for Sinopec and 2.5bn cbm for PetroChina.

Exhibit 46

Sinopec, PetroChina and Yanchang have shale gas wells Company Demonstration Block Province Geology

Sinopec Fuling Chongqing Marine

PetroChina Changling-Weiyuan Sichuan Marine

Zhaotong Yunnan Marine

Yanchang Yan'an Shaanxi Lake facies


International players International oilfield services (OFS) majors have formed JVs with Chinese OFS to tap into unconventional oil and gas resources in China. Key examples of co-operation include: 1) a JV between Weatherford and SOSC, Sinopec’s OFS subsidiary; 2) a JV between Halliburton and SPT Energy, and the JV has specialization in fracturing; 3) a JV between Schlumberger and Anton.


According to Sinopec, as of March 2014, the company had successfully reduced horizontal drilling time by 20% and decreased cost per well from Rmb90mn (~$14.5mn) to Rmb82mn (~$13.2mn). The company is looking to further lower the cost to Rmb50-60mn (~$8.1-9.7mn) per well in three years. PetroChina has also lowered the average cost per horizontal well from Rmb100mn (~$16.1mn) to Rmb70mn (~$11.2mn). We believe the cost reduction is possible with economics of scale, improved technical know-how and better understanding of the geology. On the other hand, wells at Fuling are able to maintain stable production volume for long periods. For example, the first well, Jiaoye HF-1, has produced gas for more than 500 days. Long well life is also likely to benefit well economics.

To improve efficiency, Sinopec is proactively applying “factory models” at Fuling. “Zipper Frac”, a “Factory Fracturing Model”, has been in used at Fuling since April 2014. “Zipper Frac” is to frack two nearby horizontal wells with one set of pressure pumping trucks. The pressure pumping trucks can operate non-stop, alternating between the two wells. When one well is being fracked, another well is being perforated. This operation can not only reduce movement and increase operating time for on-ground staff and pressure pumping trucks, but it can also maximize the exposure of the new reservoir. Together with the localization strategy, from 2012 to 1H14, Sinopec’s drilling day per well has already decreased from 132 days in 2012 to 78 days in 2013 and further down to 63 days in 1H14. Its fracturing efficiency has also been increased from two stages per day to four stages per day.

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The Ministry of Land and Resources confirmed that, as of September 2014, the cost of a horizontal well in China has lowered from Rmb100mn (~$16.1mn) to Rmb50 -70mn (~US8.1-11.3mn), and the drilling cycle has reduced from 150 days to 46 days. Shale wells in China are mostly >3,000m deep, and some wells have a depth of more than 5,000m. The longest horizontal well in China is 2,130m, with 22 fracking stages.

Exhibit 47

‘Factory drilling model’ has been applied in Fuling

Source: Sinopec, Morgan Stanley Research

Exhibit 48

‘Factory fracturing model’ has also been implemented in Fuling

Source: Sinopec, Morgan Stanley Research

Equity implications – China (Sinopec HKD 9.8)

Sinopec has the most direct exposure to China shale gas. In our view, new projects are likely to enhance Sinopec’s PBT by 0.8-1.0% in 2014 and 2.3-3.0% in 2015. Meanwhile, we see more upside potential in 2017 thanks to a much larger volume, further cost reduction and arrival of ‘sweet spot’.

As recognized by the Ministry of Land and Resources, Fuling’s shale gas proved geological reserve stood at 106.75 bcm, which accounts for 58% of Sinopec’s total 1P gas reserve by 2013. It plans to achieve 1) new capacity building of 2.5 bcm and actual production of >1 bcm in 2014; 2) new capacity building of 2.5 bcm and actual production of 3.2 bcm in 2015; 3) total shale gas capacity of 10 bcm by 2017. Assuming shale gas PBT can achieve Rmb0.8-1.0/cbm, that implies a positive PBT contribution of Rmb0.8-1.0 bn in 2014 and Rmb2.5-3.2 bn in 2015.

In our visit to the Fuling shale gas field in June 2014, we found that service outsourcing was still going on, but the majority still went to Sinopec’s service arm .There were 201 oil service teams working in Fuling, of which, 138 belong to Sinopec, 6 belong to CNPC, 35 are private enterprises and 6 are foreign companies. Management believes >80% of the work load is handled by Sinopec service arms, while <20% is shared by other service partners. As a result, independent OFS are not benefiting from shale gas development as much as Sinopec. However, we see long-term positives for independent OFS.

33



China natural gas price hike

China is experiencing a multi-year and multi-step natural gas price hike, to cover natural gas import losses and provide more incentives for E&P companies to produce natural gas. With this upward gas price trend, shale gas producers are likely to get better prices.

Exhibit 49

China natural gas price for industry

8 9

10 11 12 13 14 15 16 17

Jan-

08

Jul-0

8

Jan-

09

Jul-0

9

Jan-

10

Jul-1

0

Jan-

11

Jul-1

1

Jan-

12

Jul-1

2

Jan-

13

Jul-1

3

Jan-

14

Jul-1

4

US

$/m

mb

tu

China 36 City Average Natural Gas Price for Industry Use

Source: National Development Reform Commission, State Administration Foreign Exchange. Morgan Stanley Research

34



Mexico


Mexico has the 6th largest shale gas resources (545 Tcf) and the 7th largest shale oil resources worldwide (13bn bbls) according to the Energy Information Administration (EIA). Shale activity in Mexico is at an early stage, but activity could accelerate quickly. Until recently, Mexico was closed to international E&P investment. The Mexican government decided to change this and reformed its energy laws with the aim of stimulating oil and gas activity. Significant unconventional acreage is expected to come open for private investment in mid-2015.

Mexico’s unconventional potential is exciting but it is also very early days, with no shale wells drilled and fracced. Mexico is attracting the interest of the industry due to its proximity to the US and the Eagleford and Woodford shales that traverse into Mexico. Mexico also has other shale formations, including the Chihuahua, Sabinas, Burro-Picachos, Burgos, Tampico-Misantla and Veracruz that all appear to be prospective for shale gas and oil (Exhibit 50).

Exhibit 50

Mexico Shale Formations

Source: Oil and Gas Investor, Morgan Stanley Research


The Mexican oil industry is controlled by the national oil company Pemex. Until recently, no international oil companies were allowed to operate in Mexico. Recent reform has changed this, with many new companies expected to enter the industry. In round 1, approximately 70 onshore blocks will become available, with the majority prospective for shale.

Cost structure?

It is too early to quantify the costs, as there is no shale activity in Mexico at this stage. As in other international shale regions, costs are expected to be high at least initially. One advantage Mexico enjoys is its proximity to the largest oilfield service centre in the world (Texas), which means costs should fall over time due to equipment and service capability.

Equity implications?

Oilfield service companies are well positioned given the increased activity in shale as well as conventional oil and gas activity. The big four service companies are particularly well placed given their integrated offering, ability to take upstream risk and technology offerings. It is too early to tell which international E&P companies will be involved in Mexico shale, but we expect interest from smaller entrepreneurial companies including private equity.

35



Poland


The EIA estimate that Poland has shale gas reserves of 146 Tcf (2% of world shale gas resources) and 1.8bn barrels of shale oil (<1% of world oil shale resources). In contrast, however, the PGI (Polish Geological Institute) estimate there is only 20Tcf of gas. The discrepancy relates to the underlying assumptions covering areal extent, geological conditions and economic environment.

For example, the EIA assumes a recovery rate of 15%, while PGI assumes that presently no firm results are available to confirm that the recovery rate would be similar to that in the US. According to the Deputy Environment Minister Slawomir Brodzinski (Polish News Bulletin, July 2014), a new shale gas assessment report will be published in 2015.

Why Poland is pursuing shale gas projects Diversifying the domestic energy fuel mix is part of Poland’s energy policy. One of the three scenarios under the proposed plan assumes a gradual reduction of coal in the country’s fuel mix – while the other two emphasise a continued reliance on coal through 2050 or an increase in nuclear power (SNL Financial News, August 26).

Poland remains interested in supporting its coal mining sector partly due to high exit barriers (related to employment, and decommissioning costs) and the low cost of CO2. However, in the longer term, environmental costs may increase, hence, the need for alternatives.

Finally, Poland is steering towards lower dependency on imported gas (>70% currently), but its efforts are not limited to shale gas projects. Other initiatives include: 1) developing conventional gas fields; 2) a Swinoujscie LNG terminal (with completion expected by mid 2015, according to Bloomberg on August 5); 3) a new pipeline connecting Poland to Denmark and possibly Norway; 4) a strengthening domestic network and interconnections between Poland and the Czech Republic, Germany, Lithuania and Slovakia; plus 5) plans to liberalise the domestic gas market; see Exhibit 51.

Exhibit 51

Gas consumption in Poland, and domestic public opinion about shale gas exploration

Gas consumption in Poland, 2013* 16.7 bcm

Share of imported gas* ~75%

Natural gas consumption** cm / per capita / yr

Poland 361

EU average 1031

Shale Oil and Gas reserves*** Max recoverable / High probability

Gas 1920 tcm / 346 -768 bcm

Oil 535 / 215-268 mt

Source * BP Statistical Review,** Ministry of Economy, *** Polish Geological Institute, Morgan Stanley Research


Several important investors withdrew in the last couple of years (i.e. Marathon Oil (covered by Evan Calio), Talisman, Exxon (covered by Evan Calio), and most recently Eni (covered by Martijn Rats)); see Exhibit 52. In addition, the overall number of active licenses has also reduced since our previous report; see Exhibit 52. However, the local energy companies (PGNiG and PKN Orlen) and several key foreign players (San Leon Energy, Petroinvest, Lane, BNK and so on) continue to pursue their exploration efforts.

Exhibit 52

Holders of Polish shale gas exploration licences

Company # licences (mid 2013)

# licences (now)

PGNiG 16 12

San Leon Energy 17 14

Petrolinvest 9 6

Lane (ConocoPhillips, Moorfoot Trading) 8 6

PKN Orlen 9 9**

Grupa LOTOS 9 8

BNK Petroleum / BNK Poland Holdings 6 3

Basgas Pty 3 3

Chevron Corporation 4 4

Wisent Oil & Gas 4 4

Cuadrilla Resources 2 1

Mac Oil Spa 1 1

EurEnergy Resources 1 1

Eni 3 -

Canadian Oil International 2 -

Total / ExxonMobil 1 -

Dart Energy 1 - Source: Ministry of Environment, Poland; Morgan Stanley Research

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Exhibit 53

Shale gas drilling progress in Poland to date, and forthcoming plans

Total concessions (active) granted 72

Number of wells drilled (by early August 2014) 65*

Vertical 50

Horizontal 15

Undergone hydraulic fracturing* 23

Total wells planned for drilling in 2014 Over 80 Source: Ministry of Environment; * including wells where Diagnostic Fracture Injection Tests were carried out.** Subject to change; Morgan Stanley Research

How the government addressed company concerns. The Polish government recently approved two legislative documents. The first governs the hydrocarbon exploration and production activities (via the amendments to the Geological and Mining Law) and the other governs the financial and licensing aspects. Both have been approved by Parliament (Sejm and Senate) and signed off by the President.

The new tax legislation is to take effect from January 2016, but the new fiscal terms will apply to unconventional hydrocarbon projects from January 2020 (although companies would have to maintain tax related records starting in 2016).

The amendments to the Geological and Mining law are to take effect from January 2015, with some regulations taking effect from January 2016. In general, the government has aimed to create an environment that would incentivize companies to proceed with exploration work as opposed to holding the licenses without making any progress.

New hydrocarbon tax/levies set up: We estimate the overall level of taxes, fees and levies that shale gas projects are likely to face not to exceed about 40% of the project’s gross income (we outline key levies and fees in Exhibit 54).

Exploration license allocation: In the future, only combined exploration and production licenses may be issued. Moreover, all licensees holding licenses already granted under previous or current law will keep all the rights including the right to the geological information and the priority for production license. However, companies transitioning from exploration to production will have to demonstrate financial stability. Leasing of state-owned plots of land on and around drilling sites will now be easier.

Concessions can be granted to a group of companies.

Exhibit 54

Poland’s regulatory authorities involved in regulating shale gas exploration efforts Institution Associated organisations and key relevant

functions

Ministry of the Environment

The scope of responsibilities, among others, includes licensing of exploration and production of hydrocarbon activities. Key contributors - Polish Geological Institute - PGI, State Mining Authority - WUG, General and Regional Directorates for Environmental Protection - GDOS / RDOS, National Water Management Authority - KZGW

Ministry of the Economy Develops and administers energy security policies and regulated tariffs in the energy sector. Key contributor - Energy Regulatory Office

Ministry of Foreign Affairs

Ministry of the Treasury On government's behalf - the shareholder of key domestic companies involved in hydrocarbon activities

Ministry of Finance Key decision-making authority in regards to taxes and levies applicable in the hydrocarbon sector

Plenipotentiary for hydrocarbons (Chief Geologist of the country)

Preparation of economic, legal and strategic concepts, initiating, coordinating and monitoring the modernisation of institutions and regulations related to hydrocarbon E&P activities; coordinating information policy in the prospecting, exploration and extraction of hydrocarbons


More licenses may be granted in the future: Some of the plots associated with a single concession in the future might be broken into smaller fields due to their substantial size. This may lead to new players entering the market, provided there are encouraging exploration experiences.

Environmental assessment: The new draft legislation mandates that applicants may carry out an environmental assessment before a particular drilling, not before granting a production concession. In other words, the environmental assessment can now be carried out for a specific well only.

Additionally, Poland already implemented another amendment to the process a year ago: if the exploration well does not exceed 5,000m (previously 1,000m) and is outside of an environmentally sensitive area (i.e. affecting water supplies and conservation zones) companies are not required to obtain an environmental permit.

37



When might conclusive results materialise, and if they are positive, when may commercial production commence? Timing remains uncertain at this stage and partly depends on the progress of exploration efforts (i.e. the number of wells drilled) and the test results. More specifically, each granted licence has its own documented plan (via the Working Plan and in the licence documentation itself). To qualify for the production concession, a company that already holds an exploration license must get Ministry of Environment approval of the geological documentation of the field. If companies follow the process in the next 2-3 years, some production projects may potentially commence in 2018-20. This could very likely lead to an acceleration of other projects and higher drilling activity (after particular techniques are tested and prove feasible).

Key implementation obstacles: Lack of skilled staff, a backlog of engineering services and equipment.

Managing public opinion and the environment The Polish government has carried out a campaign to inform the population about the technological ramifications of shale gas exploration and production as well as safety standards. The Ministries expect shale gas projects will likely improve employment. The Ministry of the Economy assumes that shale gas projects may create 4,100-8,600 new jobs depending on how successful the exploration and production efforts are and how much foreign capital Poland is able to attract.

Which areas of Poland look most promising? The Polish Geological Institute assumes that the Baltic and Northeast areas of Poland may hold the biggest potential.


We believe the progress that the Polish government has made in 2013-14 in improving hydrocarbon legislation and making it more clearly defined is encouraging. The approval of the amended laws and implementation with no delays should further improve market confidence. A confident decision recently by the state embedded in the legislation that the overall level of taxes/levies applicable to shale gas operations should not exceed 40% should also encourage E&P companies to continue their exploration efforts. However, we remain cautious on the returns, and we do not assign any value stemming from shale gas operations in our valuation of PKN Orlen’s shares.

Commercial viability of shale gas reserves still not clear, and visibility of possible production costs still low: So far

companies have reported mixed results. For example, in mid-August 3Leg Resources (which owns stakes in Lane Energy concessions and Baltic Basin, with the remaining stake in Lane Energy belonging to Conoco Philips) reported that its efforts to bring a test well into production were going “very smoothly” (UPI, August 15). 3Leg Resources announced that it had started a long-term flow test of its Lublewo LEP-1ST1H lateral well following the completion of a 25-stage simulation plan (covering 1,469 out of 1,495 meters of the lateral section). The company reported that as of August 14, the well returned 12% fracking liquid originally injected and the well did not require nitrogen assistance. The positive sentiment around this was echoed by the ConocoPhillips 2Q earnings call. However, later in September the media (Business Monitor International, September 18) reported that the well failed to show commercial rates, flowing at an average of 11,088 cmd. Following that 3Legs Energy decided to transfer its stake in Lane Energy to Conoco Philiips (but will retain three other concessions in the eastern part of the onshore Baltic Basin).

In July, San Leon Energy reported a successful vertical frac at Lewino with the well yielding 45 to 60kcfd after partial frac liquid recovery. The company’s simulation modeling implies a possible clean-up production of 200 to 400kcfd. San Leon exited several concessions earlier but announced that it continues its shale operations in Poland and plans to drill two exploration wells in the Karpaty area and one in the Permian Basin before the end of 2014. The company is also in the advanced engineering planning phase for its Lewino horizontal shale gas well in Northern Poland (Datamonitor Energy/Utilities Wire, August 28).

We believe that the market may need a more consistent and broader rate of exploration successes (i.e. based on a bigger number of wells drilled and a geographic scope covered). Additionally, those companies who have performed vertical and horizontal drilling as well as seismic analysis so far have not fully completed and / or disclosed the results of their assessments. As noted by Jerzy Nawrocki, Director of the Polish Geological Institute, Poland’s geology is different from that in the US (i.e. Polish shale rock is located deeper, its porosity is lower, and the content of clay is higher), which makes it challenging to extrapolate US experiences (PAP Market Insider, July 12). Also, the recovery rate for Polish shale projects may be lower.

Overall, the initial drilling results indicate that extraction costs appear to be higher than those in the US, as Polish shale gas seems to be located deeper and the geology may be more complex than in the US. Shale gas, on average, is 3-4km deep,

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as PGNiG notes in its investor presentation. Drilling a well in the US typically costs $3-10 million, depending on depth and location, and production is profitable at $4/mmbtu (BBC International Reports, July 15). By contrast, in 2013 Wood Mackenzie estimated the breakeven shale gas price in Poland could be about $10/mmbtu, already close to the current level of European LNG prices of $10-11/mmbtu. Also a single vertical well may cost PLN50 million ($16 million at the current FX rate) while the cost of the vertical well and fracturing may add up to PLN70 million ($22 million), according to Kus Grzegorz, a shale gas expert and an attorney at PwC Polska

(BBC International Reports, July 15).

The commercial viability of Poland’s shale gas reserves may be further complicated by issues relating to environmental regulations and the potential impact on residents of areas where reserves may be present.

Revenue line is also uncertain: Government plans to liberalise the domestic gas market add further uncertainty to the profitability equation, as this lowers visibility on the average realized price in Poland. At the same time, we also do not rule out the potential for the cost of Gazprom’s gas supplies to Poland to gradually decrease over time if gas on the hubs in Europe were to trade at a discount to the contract price, which is set as part of the PGNiG / Gazprom Yamal agreement (expiring in 2022). In fact, recently the media reported that PGNiG may push for another cut in the price (potentially by a higher proportion than the discount agreed in 2012 – 15%), at which it is buying gas from Gazprom in November 2014 (Prime, September 3).

Equity implications

Low visibility at this stage, but capex exposure contained

In EEMEA, PKN Orlen and PGNiG appear to be relatively most active in Polish shale exploration activities. Below we provide the details behind the scope of capex commitments and the most recent progress of the companies’ efforts.

PKN Orlen’s progress to date and 2013-17 targets PKN Orlen is pursuing three unconventional (nine concessions) and two conventional projects (nine concessions) domestically. Within the scope of its shale gas initiatives, as of the end of 2Q 2014, the company completed seven vertical and three horizontal wells, and completed two horizontal fracturing with plans to carry out one more vertical, one horizontal and one fraccing in the remaining months of 2014. During the 2Q post results conference call, the CFO mentioned that the company is likely to continue drillings to understand the geology better and adapt the technology

PKN Orlen’s updated strategy assumes that the company may grow its hydrocarbon production from 0.1mboe in 2013 to 6mboe in 2017 (albeit including conventional, unconventional and recently acquired Canadian operations), and spend PLN3.2 billion overall in the upstream segment in 2014-17, about 20% of the total capex planned for 2014-17 at the group level across all divisions. In 2014, the company plans to spend PLN150 million on shale gas projects. Management expects that E&P efforts may contribute PLN 0.4 billion on average in 2014-17 at the EBITDA level.

The company is reserved in its expectations. In early June, the company published a press release among other things pointing out that geological properties of Polish shale and results of the appraisals and test from 2009 to date show that the average estimated gas production from wells drilled may be relatively low. In addition, the cost of exploration activities is high, partly due to the depth of shale formations and inadequate geological database for the region. The company also expressed a concern that the recovery techniques used in North America may not be suitable for immediate use in Poland, as Polish geological conditions differ considerably. In June, local media quoted a local Schlumberger upstream expert (PAP Market insider, June 9) who commented on PKN Orlen’s concessions of Syczyn and Berejow in the Lubelskie region. According to him, these concessions are of medium quality. Their TOC (total organic carbon) of 1.5-2.0% appears low versus the 2-14% TOC in the US shale gas formations (for US - PGNiG data), and so does the permeability and porosity. However, the thickness (75 meters) is globally second only to shale formations in Argentina, which may mean a gas content of up to 1.1bcm compared with up to 2bcm in the US.

In terms of commencing production from shale deposits, PKN Orlen CFO, Mr. Slawomir Jedrzejczyk, was recently quoted by the Polish Press Agency guiding to 2017 but saying that the company needs 2-3 years to conduct the exploration prices limiting the risk of investments.

PGNiG’s concessions, progress to date and capex plans PGNiG holds 12 licenses. It has completed 16 vertical wells since 2010 by August 2014, of which 12 were drilled in the Baltic basin. Two more wells are to be drilled in 2014, including one jointly with Chevron in the Lublin basin. Additionally, the company has completed two fracture stages.

PGNiG’s shale gas exploration efforts may absorb PLN 350 million in 2014. The company plans to focus its efforts primarily in the Pomerania region, in the Baltic basin.

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Exhibit 55

Implications for key fees and charges applicable to hydrocarbon operations in Poland from the proposed amendments to legislation

Overall profitability impact Based on the government estimates, the overall level of the taxes / fees / royalties will amount to around 38% (unconventional hydrocarbons) and 42% (conventional hydrocarbons).

Cash flow tax based (surplus of revenue – expenses)

Tax rates of the special hydrocarbon tax (cash flow tax) will depend on the relation of cumulative revenues to cumulative expenditures (R-factor - the ratio of cumulative revenues to cumulative eligible expenses). In other words, the tax rate depends directly on the profitability of the project, escalating to 25% if revenues exceed costs by a factor of 2 or more: • R-factor < 1.5 (0% of tax base) • 1.5 ≤ R-factor < 2 (12.5%-24.99% of tax base) • R-factor ≥ 2 (25% of tax base) As part of an additional incentive, “R – factor” calculation may account for deductible expenses, which have been spent since January 1, 2012 onwards. The income from sold hydrocarbons is to be accounted for as part of R-factor calculation starting January 1, 2016.

Royalties for gas / oil extraction

• 3% (gas) and 6% (oil) for conventional reservoirs, based of the value of hydrocarbons extracted • 1.5% (gas) and 3% (oil) for unconventional reservoirs, based of the value of hydrocarbons extracted The value of the tax base is to be based on the gas price (for gas) derived monthly based on the previous month average price published by Ministry of Finance based on the TGE spot market price of gas, and for oil – based on the previous month average oil price published by Ministry of Finance based on the OPEC daily Basket Price.

Income tax 19% The law grants special depreciation rates for five years to exploration or production wells as well as to drilling or production platforms, which should be accounted for as part of the income tax calculation.

Real estate tax 2%

Tax exemptions Natural gas or crude oil from low-productive wells (with productivity equivalent of <1100 MWh per month) and crude oil from wells with productivity <80 tons per month) Natural gas or crude oil used for research purposes (for wells with production <11 MWh per month or extracted crude oil <1 ton per month)

Tax loss carry forward Unlimited in time ability to deduct (from the extraction tax) the amount of accumulated losses, not deducted against income taxes (19% of the loss value).

Operating fees 24 PLN/1000m3 (5,73 EUR/1000 m3) for high-methane gas; 20 PLN/1000m3 (4,78 EUR/1000 m3) for other than high-methane gas; 50 PLN/1 tone (11,93 EUR/1 ton) for oil

Legislation details Changes affecting financial and production rules are governed by separate documents. Taxes are covered by a new law developed by the Ministry of Finance. This was approved by the Parliament (both chambers – the Sejm and Senate), and signed off by the President. It is expected to take effect from January 1, 2016. The new taxes (special hydrocarbon tax and royalty concerning gas and crude oil) for conventional as well as for unconventional hydrocarbons exploitation will not be collected until 2020; however, the taxpayers will be obliged to keep the tax register from the beginning of 2016. The undertaking, execution and completion of geological and exploitation works are covered by an amended Geological and Mining Law (and eight other existing laws) approved by the Parliament and signed by the President on August 1, 2014, planned to enter into force as of January 1, 2015 with some regulations taking effect in 2016.

Source: Ministry of Finance, Ministry of Economy, Platts, Polish Press Agency (PAP), Morgan Stanley Research

40



Russia


There is no doubt that Russia has one of the largest non-conventional reserves bases in the world, but there is no consolidated opinion on just how big the opportunity actually is – according to EIA Russia has the biggest shale oil reserves in the world of about 10.3bn tons (75 bn bbls) and the 9th largest shale gas reserves of 285tcf, although estimates vary significantly, oil-in-place in just the Bazhenov deposits could be as high as 965bn boe (EIA), with the ultimate reserve estimate depending on the recovery factor assumption. In any case this comes on top Russia’s conventional oil and gas reserves of 11 billion tons and 1,688tcf respectively, according to EIA.

The Russian shale opportunity has emerged as geologists have gained a better (although still far from full) understanding of the colossal potential Russia’s Bazhenov/Abalak formation offers in terms of reserves. To illustrate this, we just have to look back at the 1991 assessment (included in the US Geological Survey 2006 report) of Russia’s non-conventional oil-in-place, which stood at 248bn boe, before the Bazhenov potential was accounted for, boosting it to almost 965bn boe. This translates into technically recoverable reserves of about 13 billion boe, with the 2011/13 EIA study putting Russia’s technically recoverable shale oil reserves at 75bn boe, implying a recovery ratio of 6%.

Exhibit 56

Russia’s Core Shale Oil Basins

Source: Gazprom Neft,A,Zharkov, MP, 3, 2011; JSC “VNIIZARUBEZHGEOLOGIA”

With the vast conventional reserves, one could question the rationale of going non-conventional before recovery ratios on conventional fields reach those of Western peers – Russia currently enjoys an average recovery ratio of 20-30%, versus 40-50% in the US and over 50% in Norway. This however could be a misleading line of thought – Russia’s conventional output

will decline in 7-10 years, even including the still ramping greenfields, meaning that if no groundwork is laid for involvement of non-conventional resources into the development orbit, Russian total crude output could be at risk. The Russian federal budget is about 50% dependent on oil and gas revenues, making it crucial that oil output is maintained, meaning that replacements for declining production have to be prepared.

Estimating production potential is difficult at the moment, considering the challenging geopolitical environment, with technology sanctions on Russia in place, which could possibly delay development of Bazhenov. Production estimates range from about 20 million tpa to about 75 million tpa (BP Energy Outlook 2030) of crude oil produced from shale deposits in Russia by the end of the next decade, up from the current 1-1.5 million tpa.

Exhibit 57

Russia’s crude production forecast implies that non-conventional developments would need to support output in 3-5 years

6.96

7.58

8.43

9.15 9.

40 9.61 9.

83

9.74 9.87 10

.10

10.2

2

10.2

9

10.3

3

10.4

6

10.5

6

10.4

6

10.4

9

10.5

2

10.5

5

10.5

9

6

7

7

8

8

9

9

10

10

11

11

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

e

2015

e

2016

e

2017

e

2018

e

2019

e

2020

e

mmbbl/d Brownfields Greenfields

Source: Company Data, Morgan Stanley Research Estimates

Shale gas resources are also abundant in Russia, as mentioned earlier. The key difference with crude oil, however, is the availability and ease of access to conventional gas reserves, which are still a long way from being exhausted, as well as fairly cheap to develop. Exhibit 588 shows that there is still significant spare capacity with the current reserve base, as demand for Russian gas remains modest, while greenfields continue to be launched, by both independent gas producers (Sever Energua, Khrampur, Rospan) and Gazprom (Bovanenkovo, Kovykta, Chayanda).

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Exhibit 58

Conventional gas production and low demand growth for Russian gas leave no room for shale gas

500

550

600

650

700

750

800

850

900

2006

2007

2008

2009

2010

2011

2012

2013

2014e

2015e

2016e

2017e

2018e

2019e

2020e

2021e

Spare capacity, bcm Production, bcm

Source: Morgan Stanley Research Estimates


Russia’s shale oil development path is quite different to that followed by the US both in terms of development rationale and participants. As noted previously, Russian shale development efforts are driven from the top (i.e. the government) aimed at avoiding a drop in production in the future, unlike the US bottom-up driven efforts, where independent E&P companies dominated the scene until recently.

As Russia’s shale is primarily in West Siberia, in the same location as the bulk of existing crude oil output, the list of potential shale oil developers largely replicates that of companies developing conventional oil deposits, i.e. existing majors. The high concentration of oil production with the top seven producers (about 80% of Russia’s total output) leaves minimal room for independent players to grab licences or enter the market in non-conventional space, with the situation unlikely to change in the foreseeable future.

According to EIA, Russia has over 75bn boe of shale oil, spread primarily across West Siberia and the Urals region. Rosneft at the moment has the biggest shale oil development plans, estimating its shale oil reserve base at about 365 million tons, although this is a preliminary figure, subject to confirmation.

Exhibit 59

Key shale oil projects of Russian majors Company Project Type Comments

Rosneft Yugansk Bazhnen, Tymen ExxonMobil

N.Khokhryakovsky Achimov Schlumberger

Stavropol, Samara Khadum, Domanic Statoil

Em‐Egovskiy Tyumen Haliburton

Gazprom

Neft

Salym Petroleum Development

JV with Shell Bazhen Shell

Polyanovskoye Bazhnen, Abalak

Lukoil

Galyanovskiy,

Sredne‐Nazymskoye Bazhenov Total

Surgut‐

neftegaz

Ay‐Primskoye field

pilot project Bazhenov

Kamymsky, Ulyanovsky,

Maslikhovsky, Alekhinskiy,

Rogozhnikovsky test projects Bazhenov

Ruspetro

Polyanovsky, E.Inginskiy,

PottymskoInginsky license areas Abalak, Tyumen Schlumberger Source: Company Data, Morgan Stanley Research


Exhibit 60

Bazhenov/Abalak – still understanding geology


Initial fraccing




Initial fraccing



Initial fraccing




Most of Russia’s tight oil potential lies in the so-called Bazhneov formation, primarily in West Siberia, with over 90% of the currently known reserves in the Khanty-Mansiysk autonomous district. The Bazhenov formation covers an area of 2.3mn square km, with is almost 80 times larger than the Bakken formation. It also heavily saturated with oil and gas production and transportation infrastructure, thus easing access for OFS companies and evacuation produced oil in the aftermath. Despite being discovered in the last century (1959), with about 170 deposits of commercial scale discovered and in the vicinity of 1,000 wells drilled, the Bazhenov formation remains insufficiently understood, with the government hoping that tax incentives will incentivize oil companies to do more work on the formation.

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Exhibit 61

Bazhen exposure distribution in Khanti-Mansiysk autonomous district

Source: Gazprom Neft, Morgan Stanley Research

The Bazhneov formation is an oil source rock where the transformation of organic matter (kerogen) into oil has not yet fully completed. Formation deposits occur at depths of 600m to 3,500m, with the majority below a depth of 2,100m. The formation is very heterogeneous, making its development difficult. While the potential of the formation is huge, Russia will need to significantly improve its technological base if it is to boost output from Bazhen. Russian companies are working in two areas:

Thermogas techniques, used by Surgutneftegaz and RITEK, for oil recovery enhancement and extracting oil from kerogen through heating (400 degrees C).

Multi-stage hydrofracturing, by adapting US experience and technology, used by Rosneft-Exxon, Gazprom Neft-Shell and Surgutneftegaz. Although this is generally an effective method, a few challenges have to be addressed with Bazhnen, namely, the non-uniform structure, high temperatures and pressure.

43



Exhibit 62

Columnar sections of Mesozoic rocks of West Siberian basin

Source: USGS, Morgan Stanley Research

The Bazhenov formation shares some similarities with Bakken, although it remains a very different type of formation. While they both possess source rock properties, with large amounts of kerogen and tight rock oil formations, they differ in thickness of pay sediments and distribution across the section. Bazhenov formation reserves are also often characterized by very high pressure and temperature in excess of 50 megapascals (MPA) and over 115 degrees C. Where Bakken can reach 40 metres in thickness, Bazhen reservoirs typically range in the 0.5-3.0 metre range but can reach 20-40 metres as well, thus being thin and at the same disconnected. This makes it more similar to the Green River formation in the US, which at the moment is not being developed, than to Bakken.

Exhibit 63

Bazhnen-Green River comparison

Source: Gazprom Neft, IPNG RAN, Morgan Stanley Research

Surgutneftegaz has the most experience of working on Bazhenov, having drilled more than 600 wells since the 1970s and at the moment producing over 50% of Russia’s output from the formation (8 kbpd out of 15kbpd). Of the 600 only about 157 are producing. Exhibit 644 shows, based on Surgut’s results, how uneven initial production (IP) rates are, even from closely spaced wells, once again underscoring the difficulties with developing the Bazhen formation.

Exhibit 64

Bazhenov wells’ initial well flow: frequency of occurence

0% 5% 10% 15% 20% 25% 30%

<10

10‐20

21‐40

41‐100

101‐200

> 200

cm pd

Frequency of occurrence,%

Source: Surgutneftegaz, Skolkovo Energy Center, Morgan Stanley Research

Tyumen and Domanic formations

The Tyumen formation is at a depth of 2,800-3,200m, i.e. slightly deeper than Bazhnen, but it is estimated to hold significantly smaller reserves, about 1 billion barrels of recoverable reserves, but of higher porosity and permeability.

44



Krasnolenin fields – such as in North Varyogan, Balyk, East and South Surgut and elsewhere – are the most prominent examples of fields with Tyumen formation exposure. We note that at the moment, Tymen formation development is closer to fruition, with Rosneft indicating that about half of what it deems non-conventional output this decade will come from Tyumen.

Domanic shales are in the Volga-Urals and Tim Pechora provinces. The shale formation covers over 200,000 square km, and it has a thickness of 100-200 metres. The reserve estimates vary in size, largely depending on the organic content estimate in the formation. Lukoil estimates the resource potential at over 200 billion barrels.At the moment Rosneft has a JV with Statoil from 2013 to develop Domanik shales on 12 license blocks in the Samara region and an agreement with BP to develop Domanic in the Volga-Urals region in a 51-49% Rosneft-BP JV.

US – EU sanctions could push development back by years. While being highly volatile, sanctions at the moment are in place by both the EU and the US, preventing OFS and oil companies from providing services or technology needed to develop Russian Arctic, deepwater or shale oil reserves. There are a lot of unknowns here in terms of application of sanctions, but if we remain conservative, we believe that they can disrupt development for years to come, unless sanctions are lifted, as Russia has very limited access to technology needed to develop these types of reserves and would take a long time to develop competitive technology.


Shale oil development in Russia is more costly than traditional. Lack of knowledge and experience in such development affects the costs companies incur, as well as the pace of drilling. We note that at the moment much of the cost difference is connected with: 1) using rigs with a higher hook load needed to drill deeper wells with horizontal sections, 2) longer well drilling lead times, due to a lack of experience, and 3) multiple hydrofractures needed to achieve target IP rates, driving up the cost of the well.

Exhibit 65

Bazhenov wells US dollar costs versus conventional: horizontal versus vertical costs per average well versus depth/horizontal section

Source: Gazprom Neft, Rosneft, Skolkovo Energy Center, Morgan Stanley Research Estimates Exhibit 66

Bazhen wells have materially faster decline rates

0

20

40

60

80

100

120

140

160

Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8

Traditional, tpd Bazhenov, tpd


The wells needed to develop shale reserves are more expensive. This is driven by a number of factors, including:

limited experience in the basin in working with the Bazhenov suite

limited understanding, which leads to non-uniform results, requiring a larger number of wells to understand the reservoirs

a limited number of heavy rigs available capable of drilling longer horizontal sections, and higher prices charged for their use

wells that require multiple hydrocfracks to function properly, which also drives up their cost

45



It is thus difficult at the moment to project how well development will progress. At the same time oil companies involved in the development process indicate that the cost per horizontal well with multi stage hydrofracs has already started to decline; in combination with the continuing transfer of global experience, this makes us comfortable in assuming that the trend will continue as experience and rig capacity builds up, in a similar fashion to how the US market evolved. At the same time, we expect improved reservoir understanding to help improve flow rates, thus helping maintain profitability of shale oil wells.

Exhibit 67

Evolution of multi stage hydrofracs in Russia, using the example of Gazprom Neft

0 500 1000 1500 2000 2500

2011

2012

2013

BestPractice

Horizontal length, m

up to 40 stages

9‐10 stages

5‐6 stages

3

Source: Gazprom Neft, Morgan Stanley Research

The good news is that infrastructure investment costs would be limited. Most prospective shale oil development is in traditional oil-bearing regions with a well-developed transport and service infrastructure, which reduces lead times and allows projects to avoid additional costs related to the evacuation of oil. It also means that once sufficient heavy rig capacity appears, mobilization and service costs would be lower, due to a diversified network of bases being in place.

Fiscal burden – government stimulating shale oil development

Fiscal burden has historically been the bane of the Russian crude oil sector. Considering materially higher operating expenses and upfront capex outlays in some cases, shale oil development was not economical in Russia until recent tax changes were passed, which have rekindled interest towards the segment. Recently the Russian government passed an amendment to the tax code, which grants discounts to production from various types of non-conventional reservoirs, including shale oil reservoirs of different permeability and highly viscous oil deposits.

Exhibit 68

Tax and cashflow structures

30

52

77.5

95.2 95

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Conventional Bazhenov(w tax breaks)

Greenfield(E.Siberia,Yamal)

Highlyviscous

Offshore(Cat 4)

Export duty MET Cashflow to company


Preliminary cost estimates (Exhibit 69) shows that Bazhenov development yields a negative FCF with the current cost structure, unless mineral extraction tax (MET) discounts are granted to stimulate development, as has been done with the latest tax reform. Over time, as costs drop (judging from the US experience), the economics are likely to improve.

Exhibit 69

Cost structure assuming $100 per bbl oil

$10

‐$11

$11

$22

$22

$48

$48 $48

$6

$20 $20

$6

$6 $6

$8

$15

$15

‐20%

0%

20%

40%

60%

80%

100%

Conventional Bazhenov (wo taxbreaks)

Bazhenov (w taxbreaks)

Capex

Transport

Opex

Export duty

MET

FCF


Tax discounts that non-conventional developers would get at the moment range from 20% for the Tyumen horizon, which seems to be the closest to full-scale development due to its relatively well-understood structure and geology, to 100% for Bazhen and Abalak, where most of the reserve upside potential is concentrated. We note that the so-called “tax maneuver” is in full swing in Russia, which will reshuffle the tax

46



load in upstream, reducing export duties and increasing MET. It is still unclear how MET tax breaks will eventually be treated as they are calculated as a percentage of MET, which would roughly double by 2017 – our base case is that tax breaks will be retained in absolute size, as the tax system goes through a rebalancing of export duties/MET rates.

Exhibit 70

Russian government has granted material discounts to non-conventional development

Category Duration Discount, % Discount, $ per bbl*

Tyumen horizon 15 20% 4.4Permeability below 0.002md; payzone thickness more than 10m 10 60% 13.2Permeability below 0.002md; payzone thickness less than 10m 10 80% 17.6

Bazhen, Abalk, Khadum, Domanic 15 100% 22.0

High viscosity crude oil** until 2022 100% 22.0

Source: Company Data, Morgan Stanley Research; ** in addition to a 90% discount on export duties

The table above summarizes the magnitude of mineral extraction tax discounts and their duration, which the government agreed to give to various tight oil formations, to stimulate development. Higher operating expenses and capex have led the government to grant MET discounts to cover these for companies, making development feasible. Exhibit 69 shows that tax breaks are necessary to make shale oil development in Russia economically feasible.

Equity Implications – Russia

Non-conventional development in Russia came into the spotlight of market and corporate attention about two years ago, when the government started discussing tax breaks aimed at stimulating this type of activity. The equity and financial implications at the moment are, however, broadly immaterial, due to insufficient understanding of development prospects and the slow pace of development as of now. Unlike the US, Russia lacks a large number of independent E&P companies that which can focus their primary efforts on shale oil development and be impacted by progress there, meaning that it is up to the few majors to do the work, which is not urgent at the moment. The amount of financial resources being allocated to shale development is significantly below the level of media attention (please see Error! Reference source not found. for existing projects and JVs), which somewhat limits potential equity implications for individual stocks.

The difficulty in valuing Russian shale exposure is connected to the lack of pure shale transactions, with most of the prospective

fields being “inherited” with existing licenses. Above we have presented an overview of shale exposure companies in our coverage universe, while here we try to focus on the potential equity implications in the foreseeable future. We note that Western sanctions placed on the transfer of technology to Russian companies working in the Arctic, deepwater or shale oil areas could disrupt any development in this area.

Rosneft – Rosneft has the biggest exposure in Russia in shale oil, partially due to the largest acreage of its fields in West Siberia and partly due to numerous JVs with western majors aimed at giving the company an edge in this area – its partners in shale oil are Exxon, Statoil and possibly BP, joining the Domanic development. Rosneft has estimated that it can expect to produce up to 10-15mn tpa from shale oil (non-conventional) deposits by the end of the decade. We note however that Rosneft includes the Tyumen formation in the non-conventional category, which in our view is somewhat closer to full-scale development.

Lukoil – Lukoil’s exposure to shale oil is minimal, with the company on numerous occasions stating that Bazhenov development is not a top priority. Lukoil has however signed a $120-300 million JV agreement with Total to study Bazhen prospects in West Siberia. Recoverable reserves are estimated at about 70 million tons. The impact is non-material at the moment, with Lukoil expecting just about 0.1 million tons to be produced at Bazhen in 2014. At the same time we note that Lukoil’s subsidiary Ritek has been testing Bazhen development technology, although on a small scale.

Gazprom Neft – The company estimates its shale oil recoverable reserves of its four key subsidiaries involved in non-conventional development at about 0.5 billion tons (3.6bn boe) and has a JV with Shell (Salym Petroluem Development) to develop these. The company believes that it can produce up to 5.5 million tons from the Salym projects eventually.

Surgutneftegaz – Surgutneftegaz, being one of the least transparent companies in the sector, is not disclosing its shale oil results, despite being one of the pioneers in Bazhen development. According to the available press evidence Surgut is producing 0.4mn tpa from Bazhen and could theoretically boost this to over 1-2 million tpa.

Tatneft – Not directly exposed to shale oil development, but working on monetizing large reserves of highly-viscous oil.

Bashneft – According to management’s presentation the company is studying Domanic opportunities in Bashkiria, but it

47



is too early to assess the possible size, commerciality or development schedule of the reserves.

Eurasia Drilling – Russia’s biggest independent driller at the moment is not directly involved in non-conventional development and has openly stated that it is only looking at the possibility of such involvement in the future. We however note that as heavy rigs, which potentially will be needed to drill the shale, are taken from the same pool of rigs as for conventional, extra demand for them will support pricing across the board, thus benefitting EDC.

There are also a few public names in Russia, outside of our coverage universe, which are exposed to the segment.

Ruspetro (not covered) is a small cap independent E&P company, developing the Abalak/Tymen deposit found at the

Polyanovksy, E.Inginskiy and Pottymsko-Inginsky blocks in the Khanti-Mansiyskiy Autonomous district.

CAT Oil (not covered) is the largest provider of fraccing services in Russia with a 30% market share, now also increasing its presence in the mobile rig drilling niche. We note the material growth of demand for fraccing services as a result of non-conventional oil development.

There are also international names with exposure to Russia non-conventional – Exxon, Statoil, Shell, BP and Total – as well as OFS majors – Schlumberger, Halliburton and Baker Hughes.

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United Kingdom


The UK government’s energy agency estimates the shale across Central England contains around 1,329 trillion cubic feet of gas (tcf) in place, although they do not calculate how much is recoverable. Based upon the UK government’s

analysis, industry consultants Wood Mackenzie estimate that around 50tcf is actually recoverable, although they acknowledge that their underlying assumptions are likely too conservative. Using these indicative estimates about 17 years of UK gas demand could be recovered from these shale units alone

.

Exhibit 71

Location and ownership of key UK onshore non-conventional licenses



With the exception of Centrica (covered by Bobby Chada), GDF (covered by Emmanuel Turpin) and Total (covered by Martijn Rats) who were the most recent entrants, the most prospective acreage is controlled by a mixture of public and private independents, such as Cuadrilla (Riverstone owns a controlling stake), Egdon and Igas. Among these, Cuadrilla has attracted significant attention due to its high activity.

However, the most material deal was Centrica’s acquisition of a 25% stake in one of Cuadrilla’s onshore licences for an upfront cash consideration of $63 million but with a total commitment of potentially up to $250 million depending upon reaching certain milestones. Based on the $63 million cash consideration, this implies about $1,000 per acre, which is equivalent to the prices paid around the globe for plays at an

early exploratory stage where commercial recoverable resources are still to be proved.

In 3Q13 and 1Q14, GDF and Total entered Dart Energy’s licences in exchange for a small cash payment and the funding of drilling programmes as part of the deals, respectively.

Exhibit 72



Initial fraccing




Initial fraccing



Initial fraccing



Source Morgan Stanley Research

49



With five wells drilled and only one fractured and tested, UK shale gas exploration is a young industry. Exploration briefly stopped in 2011 when seismic activity was detected during fracturing and it was not until 2012 that the government lifted the drilling moratorium.

The UK’s energy agency governs the award of permits and licences. However, unlike offshore exploration, onshore also requires environment and local land use planning permission. Local land use permissions are contingent on public consultation, and only once approved by the health and safety agency can drilling start.

Nonetheless, and despite being an immature industry, we think shale gas will find a market relatively easily. The UK, for example, has a wide gas infrastructure network, albeit local infrastructure, gathering and compression facilities would possibly be required to connect wells to the major pipelines.

Replicating US drilling intensity in the UK is a challenge

We believe replicating the US’ substantial drilling intensity and expansive plays in the UK could prove challenging, particularly given the difference in average population density and relative size.

For example, Mountrail county, in the centre of the Bakken basin, has a population density of 1 person/km², while Karnes in the Eagle Ford has a population density of 8/km². In contrast, the least densely populated county in the UK, Eden (Cumbria), has a density of 25/km², with only six counties with less than 50/km².

Please click here for the evolution of drilling intensity in the US over time

Exhibit 73

Replicating Eagleford: Devon to The Wash

Source: EIA, Morgan Stanley Research estimates

Exhibit 74

Replicating Bakken: Yorkshire and Lancashire

Source: EIA, Morgan Stanley Research estimates


The UK government introduced a couple of tax incentives to encourage investment and activity. For example, a pad allowance was introduced to improve commercial viability and an allowance was introduced to offset up to 75% of a company’s capital expenditure against the supplementary tax and the government has extended the ring fence expenditure supplement to 10 years.

The initial exploration wells have cost around $17m, however we would expect a cost reduction during the development phase due to an established indigenous supply chain. Assuming analogous plays and cost estimates ($11m per well plus high pre-development capex and high leasing costs) and based upon UK gas prices, Wood Mackenzie estimate a 9% IRR and an $11/mcf breakeven. A 20% reduction in cost or 20% recovery rate improvement would lead to a still marginal 14% IRR.

Equity implications

The development of shale gas could 1) improve security of supply, with the added benefit of lowering energy input costs; 2) increase employment; and 3) drive up investment in other sectors, too e.g., manufacturing and oil field services.

First, increased indigenous gas production would also provide physical security of supply, reducing the requirement to import gas. Development of the shale, for example, could reduce gas import dependence from about 80% to about 60%, providing substantially increased security of supply.

Second, according to consultant Poyry, wholesale gas prices could be up to 4% lower, leading to an average annual saving

https://ny.matrix.ms.com/eqr/research/docs/data/interactive/visual/shale/�

50



for the country of £380m. The difference made to the wholesale electricity price because of this is of a similar magnitude to that seen in the gas price, a reduction between 2% and 4% with an average annual saving on wholesale electricity costs of £430 million per year. In addition to giving energy and heavy industry companies a boost (Centrica, GDF and EDF), this could lift consumer buying power, leading to a positive impact on consumer spending, affecting Marks and Spencer (covered by Geoff Ruddell; 358p), Sainsbury (229p) and Tesco (covered by Edouard Aubin; 229p) and so on.

Third, while some of the offshore experience could be reused, shale gas production in the UK will require the development of an extensive new onshore supply chain for equipment, services and skills. According to Ernst and Young, 64,500 jobs will be needed at peak, including highly-skilled direct site development roles with above-UK average salaries. The companies that could benefit from the increased hiring could be Hays (119p) and Michael Page (417p) (covered by Toby Reeks), Exhibit 75.

Exhibit 75

Percentage category breakdown of direct site development employment at peak

Direct Site Development Costs (%)

0%

20%

40%

60%

80%

100%

Total

Drilling

Opera

tions

Sup

port

Direct

Office

Suppo

rt

Petro

leum

Eng

g. &

Geo

.

Hydra

ulic F

ractu

ring

Plannin

g & P

erm

itting

Constr

uctio

n

Source: Ernst and Young, Morgan Stanley Research

Based upon the average salary ranges for key E&P roles, most of the direct jobs critical to developing shale gas would have above-average UK salaries e.g., drilling and completions £52-126,000.

Finally, the development of UK shale gas could develop opportunities to establish new markets, such as the manufacturing of high-tonnage drill rigs. There will also be an opportunity for suppliers and service providers to supply existing materials, equipment and services to a new industry in the UK. Companies that could benefit would be Weir (covered by Ben Uglow; 2,180p) and Aggreko (covered by Toby Reeks, 1,461p). To understand where the strategic growth opportunities are for the UK supply chain, Ernst and Young mapped key components of the shale supply chain against anticipated level of spend, Exhibit 76.

Exhibit 76

Supply chain category availability and size of spending opportunity

Source: UKOOG, Morgan Stanley Research

51



Equity implications

Below we list publicly quote companies that have a material exposure in shale oil or gas globally. It is not exhaustive, but rather a high-level summary of companies that we have come across in our research.

Company Share PriceArgentina YPF 31.46 USD Petrobras 15.62 USD Total 44.6 EUR ExxonMobil 91.60 USD Chevron 113.89 USD Petronas 6.18 MYR Madalena Energy 0.265 CAD America Petrogas 0.475 CAD Australia Beach Energy 1.29 AUD Senex Energy 0.55 AUD Drillsearch Energy 1.154 AUD Santos 12.59 AUD Origin Energy 14.58 AUD AWE 1.635 AUD FjulyBuru Energy 0.74 AUD Central Petroleum 0.27 AUD Chevron 113.89 USD BG 1039 GBP Statoil 158 NOK Total 44.6 EUR Apache 79.91 USD China Sinopec 6.13 HKD PetroChina 122.7 USD Yanchang 0.41 HKD Shell 2192 GBP Poland PGNiG 4.84 PLN San Leon Energy 2.24 GBP PKN Orlen 41.72 PLN Grupa LOTOS 28.71 PLN BNK Petroleum 0.68 CAD Chevron 113.89 USDRussia Rosneft 226 RUB Gazprom Neft 136 RUB Lukoil 1983 RUB Surgutneftegaz 26.56 RUB Ruspetro 12.50 GBP

52



53



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For disclosure purposes only (in accordance with NASD and NYSE requirements), we include the category headings of Buy, Hold, and Sell alongside our ratings of Overweight, Equal-weight, Not-Rated and Underweight. Morgan Stanley does not assign ratings of Buy, Hold or Sell to the stocks we cover. Overweight, Equal-weight, Not-Rated and Underweight are not the equivalent of buy, hold, and sell but represent recommended relative weightings (see definitions below). To satisfy regulatory requirements, we correspond Overweight, our most positive stock rating, with a buy recommendation; we correspond Equal-weight and Not-Rated to hold and Underweight to sell recommendations, respectively.

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Coverage Universe Investment Banking Clients (IBC)

Stock Rating Category Count % of Total Count

% of Total IBC

% of Rating Category

Overweight/Buy 1113 35% 353 40% 32%Equal-weight/Hold 1390 44% 410 47% 29%Not-Rated/Hold 109 3% 21 2% 19%Underweight/Sell 575 18% 96 11% 17%Total 3,187 880 Data include common stock and ADRs currently assigned ratings. Investment Banking Clients are companies from whom Morgan Stanley received investment banking compensation in the last 12 months.

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