Credit Suisse Global Energy Research Team Oil and Gas ...

DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, AND THE STATUS

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Credit Suisse Global Energy Research Team

Oil and Gas Primer: Macro

May 2015

Research Analyst

Jan Stuart

[email protected]

(212) 325-1013

mailto:[email protected]



1

Welcome to Global Oil and Natural Gas Markets

Crude Oil

Oil is a different commodity: It has real decline curves; multiple capex cycles; Opec and other political

drivers; and its demand is inelastic in the ‘short run’ – thus oil markets tend to frustrate forecasters

Supply: Overview of where current production comes from, some of the bright spots – ‘e.g. the shale revolution’ and

some of the challenges (decline, complexity and political instability)

Demand: Emerging markets drive the bus over the longer term, but OECD cycles still matter as well

After the fourth oil shock, markets now have to do the rebalancing. Currently, oil supply needs to come down

– “Call on US Shale”: We look in detail at the potential and economics of shale; and feature a “super-contango” story

Natural Gas

In the US, shale has unlocked 100 years of low cost natural gas

We look at the cost curve and discuss bottlenecks getting low cost Marcellus/Utica gas to demand centers in the

south, LNG exports, and rising base-load demand from power generators and industry

LNG: Links regions and price (mostly to oil). Its demand should grow, but new supply options are on the horizon and

the US is coming to the party

Longer Term

We can plot the end of the “oil age” albeit really only from the demand side -- some combination of

natural gas substitution, energy efficiency and breakthrough technology (solar/battery) should do it

Oil -- Deciphering Its Fundamentals and Markets; Supply

3

What are Oil and Natural Gas?

Oil and natural gas (or hydrocarbons) are composed of chains of linked hydrogen and carbon atoms.

Plant and animal remains were covered by layers of sediment (particles of rock and mineral) and over

millions of years of extreme pressure and temperatures these particles were reduced to liquid

hydrocarbons (oil) or gaseous hydrocarbons (natural gas).

Under geologic pressure, oil migrates from its “source rock” into rocks with larger spaces or pores

“reservoir rock.” Limestone and sandstone have with large porosity and are two common types of

“reservoir rock.” Oil is held in these reservoirs by impervious rock structures above called caps or traps.

Source: Earth Science Australia

4

Crude Oil Composition and Value Varies

Crude oils with higher than average sulfur

content are known as “sour.” Those with low

sulfur levels are called “sweet.”

The majority of global reserves are

light/medium and slightly sour.

Crude oil ranges from almost clear water-like fluids to black viscous semi-solids.

Crude oil can be categorized into various API degrees of gravity. The higher the API gravity, the lighter

the crude.

Crude oils with higher API gravity yield greater proportions of lighter petroleum products like gasoline.

Source: DOE

5

What is So Special about Oil Fundamentals and Markets?

The supply side features politics, depletion and pushing at frontiers

Themes:

Reserve distribution: Opec controls access to the low end of the cost curve and remains far and away the largest exporter of oil.

– Its volume policy used to matter greatly, it was the balancer of last resort, stabilizer of price

– Its current a volume maximising strategy means that the group has become a wildcard

Depletion: Each year, the existing productive capacity declines by 4MBD, which needs to be offset by new investments

Some major non-Opec sources of supply have restricted access or otherwise kept production on a tight leash

Costs have been rising in the areas where access to resources is more open (e.g. deepwater)

– While costs will deflate cyclically, to deliver structurally better project management is a challenge

New: The (US) Shale Revolution: aka the instigator of the fourth oil shock

– A whole new play and a the near term balancer or fly-wheel of the supply side

6

Oil Supply: Digging thematically -- general observations

The characteristics of producing basins vary substantially around the world, including differences in the costs of finding, development and production.

The United States is the main beneficiary of the shale revolution. Its oil production has been rising

rapidly. Potential is still only partly understood, ultimate capacity ceiling is function of price mostly. It is

costly and its capital cycle is short.

– In today’s low price world, US shale is the marginal supply.

The Middle East is the most productive region with the largest remaining undeveloped resources.

Russia is the world’s third largest oil producer, much of which flows from two highly mature provinces:

Western Siberia and Volga/Urals. Shale and Arctic are the growth areas to offset base declines.

West Africa is a large source of production with future growth from the offshore, if price allows.

Brazil looks like a huge new resource opportunity with the development of the pre-salt play in the

offshore Santos Basin, but much of the near term growth profile depends on Brasilia.

Frontier areas: Global shale, Arctic, pre-salt Angola, Equatorial Transform Margin, Eastern Siberia,

even deeper Offshore

7

Global Oil Reserve Life or R/P Ratio 55 years …

Reserve Life or R/P Ratio measures year end reserves divided by current production

The regions with the longest R/P ratio include South and Central America (notably Venezuela and

Brazil) and the Middle East, and North America is rising fast

Or, another six decades left to find an alternative transport fuel

Source: BP Stats

R/P Ratio, YE 2013 R/P Ratio Over Time

8

The majority of the world’s current proved oil reserves are in OPEC countries.

The BP Statistical Energy Review states that 1,214 billion barrels (bbs) or 71.9% of the world’s proved

reserves are held by OPEC. 800 billion of these are in the Middle East.

The remaining 474 billion barrels or 28% of the world’s proved reserves are in non-OPEC regions. The

former Soviet Union holds 28% of non-OPEC proved reserves. The Canadian oil sands contain 167.8

bbs of proved reserves. US oil reserves have grown by 56% to 44 bbs from a low of 28 bbs in 2008.

The Mideast Still Has the Dominant Reserve Position

Source: BP Stats

9

OPEC has Frequently Played a Critical Price-setting Role

The Organization of Petroleum Exporting Countries (OPEC, Opec)

is a permanent, intergovernmental organization, created in 1960 by Iran, Iraq, Kuwait, Saudi Arabia, and Venezuela.

The five Founding Members were joined by Qatar (1961); Indonesia (1962, left in 2008); Libya (1962); United Arab Emirates (1967); Algeria (1969); Nigeria (1971); Ecuador (1973 suspended membership from 1992-2007); Angola (joined in 2007), and Gabon (1975, left in 1994).

OPEC’s stated objective is “to coordinate and unify petroleum policies among Member Countries, in order to secure fair and stable prices for petroleum producers; an efficient, economic and regular supply of petroleum to consuming nations; and a fair return on capital to those investing in the industry.”

OPEC’s members in effect attempt to raise the clearing price of crude oil above its “natural” level by

withholding relatively cheap reserves from the market.

Opec grabbed pricing power (the first Oil Shock) after several of its bigger (Arab) members staged a successful boycott of oil exports to the US and a few other supporting countries that had picked the side of Israel during the Yom Kippur war of 1973

A five-fold increase of oil prices was followed by the nationalization of oil firms in key Opec countries in the mid-1970s and after a second oil crisis surrounding the Iranian revolution of 1979, oil prices tripled to $32/b

To sustain these massively inflated prices the group adopted a complex system of quotas, with varying degrees of success in either agreeing to them or complying with them

– The system crashed in 1985 (the Second Oil Shock); in 1998 (the Third Oil Shock) and most recently during the American Thanksgiving holiday of 2014 (the Fourth Oil Shock)

10

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Base $75>$80

Low $60>$70

High Opec $65>$90

High Black Turtle$85>$100Est Govt Budget Req

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SA

Venezuela Iraq Nigeria Algeria

Mb/d

OPEC Remains Wild Card – Even in a “Go Stabilize Yourself World” Oil exporters probably did not think markets would react badly when Saudi Arabia withdrew control of the supply side in late 2014. Many

want to renew interventionist policy, but few have leverage. And Saudi Arabia clearly remains persuaded that markets should “… stabilize

themselves”, so as to weed out weak producers. The question now is: ‘What might persuade the Kingdom to sanction an intervention’?

Put differently, until Saudi Arabia says ‘yes’, the noise about an emergency OPEC is just that, noise.

The question is political. When will the pressure from constituents in the kingdom or pressure from other producers sway the Saudi top?

Financially, the kingdom appears in good shape: it built up reserves of about $750 billion; its sovereign debt is a measly 3% of GDP; and best estimates of its current requirements suggests it could last ~5 years if Brent = $65/b. That said, in April 2015 its ‘cash-burn’ was $16 billion.

Estimated Saudi oil export revenue (= supply – demand x prompt Brent) in ($B/b)

Many Opec members are not in Saudi Arabia’s financial position. Only Qatar, Kuwait, Angola and the UAE have by most estimates a lower budget break-even oil priced than does the Kingdom. At the other extreme, Iran appears to require the highest oil price, which is a different way to illustrate the import of the current nuclear negotiations with the P5+1. Venezuela’s finances are in perilous shape as well.

Cost-curve: Ranges of OPEC government budget break-even-prices ($/b)

Source: Credit Suisse estimates, Country Data

11

OPEC’s Spare Capacity: a Key Measure

Most of the time OPEC withholds existing supply from the market, creating spare capacity’ i.e., oil

which could be produced, but is offline.

We use the classic definition of spare capacity: What can be brought on line within 30-days (so as to be relevant to prompt demand); and sustained for more than 90 days (i.e. not counting the ‘surge capacity’ of reservoirs

Anticipated levels of future spare capacity have important effects on crude prices generating more or

less fear about supply (see markets and pricing section).

Generally, markets since 2002 have had less than 3 Mb/d of spare capacity (except during the GFC)

Source: IEA, Credit Suisse estimates – adjusted for Libya

12

Core OPEC Capacity Should Remain Low in Our MT/LT Forecast

OPEC spare/offline productive capacity (Mb/d)

Crude production (history and forecast) in Libya, Iran and

Saudi Arabia as well as Saudi Arabian production limits

(Mb/d).

Instability and sanctions have taken ~2.1 Mb/d of productive capacity offline in Libya and Iran. By year end we expect Saudi Arabia’s supply push to have brought down the Kingdom’s annual average spare crude production capacity to just 2.26 Mb/d.

Our view of the US and OPEC grabbing market share from non-OPEC ex-US assumes the return of Iranian crude production to ~4.1 Mb/d and Libyan production to 1.4 Mb/d.

Once the markets have ‘Rebalanced,’ if Saudi Arabia doesn’t pair back its production, we would be left without much in the way of spare capacity to balance the market in the event of a supply disruption.

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Saudi Arabia crude production Iran crude production

Libya crude production

Highest recorded level of crude production

Self reported max crude productive capaciity.

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Forecast OPEC spare/offline capacity

Source: Credit Suisse estimates, HPDI, Woodmac

13

Iraq Likely the Main Oil Supply Wild Card

Kurdistan: A vast and underexplored onshore Basin with

>40bn bbls of oil and ~100tcf of gas yet to be discovered

– Wells exhibit strong flow rates and are low cost to

develop allowing rapid production growth

– Issues are above ground, however some progress is

being made – KRG Baghdad breakthrough of late

2014.

– For Turkey, Iraqi Kurdistan is strategic for (a) security

and (b) energy independence/diversification.

– Production capacity is ramping up to 500 kb/d and

should rise to over 1mbd this decade (CS estimates).

Much depends on access to international markets.

Southern Iraq Also Making Progress:

– Iraq has recently increased its production to north of 3.2

Mb/d, due to both infrastructure improvements and field

work in at least some of the nine critical ‘mega’ jv areas.

– Further advancements in production are possible if the

rig count rises and if very large scale joint water injection

investments are made, all subject to stability above

ground.

The biggest single growth prospect

Source: MEES, Credit Suisse

14

Oil Reserves Decline -- a Simple Yet Profound Characteristic

Increasing complexity

Escalating capital intensity

Declining production base

According to SLB, 30% of current production needs replacing by 2020, just 5 Years Away. We note that the decline rates shown below are “unmitigated” and that this chart ignores the investments that are currently underway.

“Primary Decline” by resource type

Source: SLB

15

CVX estimate that around 50mbd of new production will be required by 2035. Total estimate around the mid-40 MBD range. Shale can provide a near term fly-wheel but eventually other types of production will be required.

Each year, new fields are needed to offset decline and rising demand

Oil Decline Is a Real Challenge

Source: CVX

16

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Observed “Project Level” Decline Rates by Country

The decline rates shown below INCLUDE infill drilling capital expenditures

“Mitigated” observed decline rate on declining production, observed project actuals 2005-2014 (a period of

$80’s bbl oil prices)

Source: Wood Mackenzie, Credit Suisse Research. (*) US onshore reflects conventional production rather than shale.

17

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Average Production That Has Been in Decline in 2010-14

Where to Look for Decline?

“Fields that are already declining” seems a good place to start

We observe around 4-5mbd of annual decline on the global fields that are already in decline

This decline gets offset by growth on existing production, shale and the new fields that are being

developed

Observing decline in real time is tricky, but we note decline rates tend to accelerate when industry

cashflows are constrained. We have modeled a 200bps rise in non-OPEC decline in 2015-’17.

Non-OPEC production that has been in decline, 2010-2014 Aggregate decline on non-OPEC and OPEC

“declining production” (KBD)

Source: HPDI, Credit Suisse estimates

18

Introducing A “Declining Production Tracker”

Not yet “declining” on a year over year basis but rolling over

In order to track whether decline is starting to kick in, we focus on the production of a subset of non-

OPEC and OPEC producers which were more prone to decline.

The leading edge of this decline-prone basket of producers is rolling over in non-OPEC

and in OPEC. The pace of decline will play an important role in shaping the futures curve

in 2015/2016.

Non-OPEC seasonally adjusted decline tracker

OPEC seasonally adjusted decline tracker

Note: Includes Russia, Mexico, Kazakhstan, Brazil, Canada, Azerbaijan, Norway, Colombia, Indonesia, US GoM, UK, Egypt, Malaysia, Argentina, Thailand, Equitorial Guinea, Australia

Note: Includes Angola, Nigeria, Algeria, Ecuador, Venezuela

-6.0%

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3 mma mom % change 3 mma yoy % chane

Source: Woodmac, Credit Suisse estimates

19

Global production ex-Saudi Arabia (Mb/d) Non-OPEC production ex – US (rhs) vs. US production (lhs)

Momentum of development is carrying global (ex Saudi) oil production upward. While rig counts have plunged in the US, activity ex-US will react more slowly

US production (crude + NGLs) kb/d (lhs), aggregate rig count (rhs)

Europe production (crude + NGLs) kb/d (lhs), aggregate rig count (rhs)

International Activity Is Falling but Not as Fast as That in the US

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Non-Opec (ex-US) CAGR:2004 - 2010 = 0.70%2011 - Jan. '15 = -0.31%

US CAGR:2004 - 2010 = 1.77%2011 - Jan. '15 = 11.88%

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Source: Credit Suisse Research, IEA, EIA, JODI, Petrologistics, Baker Hughes, Country Data

Oil Supply: US Shale

21

Not All Existing Production is Declining, Some Fields Are Relatively Young and Their Production is Rising

Before We Move To Shale; One Wrinkle

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India US GoM Mexico Canada UKNorway Australia Russia China IndonesiaBrazil Argentina Colombia Oman SyriaYemen Gabon Azerbaijan Sudan CongoGhana Brunei Equatorial Guinea Kazakhstan DenmarkMalaysia Thailand Vietnam Egypt

Production From Fields That Were Online in 2014 With A Higher Peak in 2019

Source: Woodmac, Credit Suisse Research

22

The Big picture of the “US Shale Revolution”

Shale Oil Production From Key Basins Has Grown to 5.45mbd, at a cost of ~$150billion per year

US Shale Oil Production History By Play

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Bakken Eagle Ford Permian Niobrara Utica

Source: EIA Drilling Report

23

Shale Well Productivity Continues to Improve

In coming years, we expect the industry to high-grade its choice of drilling location. We also expect further gains from technology.

90d CUMs Improvement

Source: EIA Drilling Report, Credit Suisse Estimates

24

Technology is Not Yet Fully Deployed Across the Industry

Drilling Execution Efficiency Platform (DEEP)

Cumulative Oil Production

Still room to lower costs AND to maximize the recovery per well

Industry has made great strides in maximizing the number of completions per well and lowering the time

it takes to “Drill and Complete” wells (e.g. PAD drilling)

“Engineered completions” can increase EUR’s substantially e.g. as the industry maps the subsurface to

optimize frac placement with new completions and fluids. New technology can reduce horsepower 50%

per well while increasing IP 20-50%

DUC’s and refracs create a lower cost inventory to work off (though the scale of this opportunity

needs to be placed in context)

Source: COP 2015 Analyst Day

25

Eagle Ford “Half-Cycle” Breakevens of 2014 Wells

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% Production Uneconomic @ $75 WTI (20% Cost Deflation): 11%



Source: HPDI, Credit Suisse estimates

26

Show me a price: Outcomes for the “Call on American Shale”

Shale Volumetric Outcomes Are Highly Dependent on IP Improvements

Industry is high-grading and deploying technology improvements

“40% of perforation clusters do not produce, 40% of fractures do not produce, 40% of the wells are

uneconomical” SLB 2014 Analyst Day. New technologies – 20-50% higher 50 day cum; 50% less

horsepower, 20-50% less water

The required oil price to deliver our projected “Call on American Shale” will depend on the interplay

between deflation, technology gains, and high-grading.

Shale oil production potential from key basins (40-50% improvement in IP

from high-grading and steady technological improvement)

Pace of High Grading and Technology Development Can Have a Large

Impact on Volumetric Forecasting:

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Midpoint Improvement Top QuartileSource: HPDI, Credit Suisse estimates

Near Term Supply Side Developments to Watch in US Shale

28

The US drilling rig count will likely fall by 1,000 units, after years of steep growth The suddenly fast falling horizontal rig count in the big oil plays should matter

NT first movers, data tracking the short-reaction function of the US

The impact on production will not become clear for months yet. We like

keeping an eye on the yoy, and mom shifts volume growth

Plunging rig counts add confidence that real growth will really decelerate Stupendous growth in the US tight oil basins needed massive drilling programs. Less cashflow = less capex = less drilling. A leading indicator of US oil

production growth is the number active drilling rigs. We keep an especially close eye on the active ‘horizontal’ rig count in the key oil plays.

Even the Perm ian, which has the greatest volume of the best rocks and the

best economics is not being spared.

Source: CS Research, Baker Hughes rig count report, US Dept of Energy’s EIA

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29

US Production Momentum – The EIA Shale Productivity Report

Shale production growth is fading

The below chart clearly shows the acceleration

of growth of US shale oil production in 2014

Equally clearly, that growth has begun to roll

The data are imperfect but the idea is clear

Because the rig count has plunged by half

With fewer than 800 rigs drilling for oil in the

four big plays in February new oil additions fell

below legacy decline, for the first time in 5 yrs

US oil supply is probably slipping mom

We like this new tool. It is timely, internally consistent and gives a complete picture of all the key shale basins. Its latest message: Production is rolling …

Source: Department of Energy’s Energy Information Agency

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Legacy Decline Rig Count (rhs)

Changes of aggregate oil production from the Bakken, Eagle

Ford, Niobrara and Permian shale basins (through April, Kb/d)

The monthly count of rigs drilling for oil in these plays set against:

new well output; legacy decline; and the implied monthly addition

/ subtraction of US shale oil supply (through June, Kb/d)

30

Trajectories of yearly US crude oil production 2013-’16e (Mb/d) The mid 2015 US production decline shown sequentially (kb/d)

In our central scenario, the fast plunging rig-count drives a steep decline of US crude oil production -- around which we sketch a RANGE as well

Upside and downside scenarios around our base case (kb/d)

How This Fits into a Rebalancing: The NT “Call on American Shale”

6500

7500

8500

9500

10500

Jan-13 Jan-14 Jan-15 Jan-16

Call on US Crude Oil

Central Scenario

Lower Opec

Less Demand

5000

6000

7000

8000

9000

10000

Elements of our central scenario, and the upside / downside cases:

In our base case, see also the global balance tables, we project that Saudi Arabia’s crude oil production remains at current levels

(~10.3 Mb/d); that Iran’s exports begin to rise marginally in July, and then expand by another 300 kb/d in September and a final 300 kb/d in January 2016.

The upside case simply takes Saudi Arabia’s output down to 10

Mb/d; includes incremental exports from Iran beginning only in H2-2016; and allows for 200 kb/d less growth from Iraq in 2016

The downside case assumes global demand growth this year and next of only 1% (not the ~1.5% growth of our base case).

6.5

7.5

8.5

9.5

Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2013 2014 2015

2015E 2016E

Source: Credit Suisse Research, IEA, EIA, JODI, Country Data, WoodMac

Oil -- Demand

32

Oil Demand Versus Oil Price, a Big Picture of Lagged Elasticity

Oil is a cyclical commodity (with managed characteristics)

Higher oil prices during booms tend to create deeper demand recessions afterwards

And soon we will see if lower prices can generate lasting upside for demand

7.2%

8.2%

8.9%8.4%

5.5%

7.3%

8.0%

-1.5%

1.3%

5.9%

4.2%

3.7%

1.7%

-4.1%

-2.9%-2.3%

-0.5%

1.4%

0.3%

2.7%2.3%

2.9%

1.6%

0.5%

0.6%0.8%0.5%

1.2%0.8%

3.0%

2.1%

1.1%

2.3%

0.9%0.8%

2.2%2.4%

2.8%

1.7%1.4%1.4%

0.4%

-1.0%

3.2%

0.7%

1.5%1.5%

0

10

20

30

40

50

60

70

80

90

100

110

120

130

-6%

-5%

-4%

-3%

-2%

-1%

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

1966

1967

1968

1969

1970

1971

1972

1973

1974

1975

1976

1977

1978

1979

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

Infl

ati

on

ad

juste

d B

ren

t p

rice U

S$ p

er

bb

l

Glo

ba

l O

il D

em

an

d G

row

th

Demand growth Real Brent Oil Price (USD/bbl), 2011

Recovery

Recession Recession

SPIKE

Collapse

Recovery

Saudis change policy

18 years of low and stable oil prices 1986-2004

Recession

Recovery

Boom

Recession

BoomBoom

Recession

Recovery

Boom

SPIKE

The Good Old Days

Recovery

Boom

Source: Credit Suisse Research

33

Increasingly, Oil Is Becoming a Consumer Good

Oil demand grew by a CAGR of 1.2% from 2002 to 2014. We expect global oil demand to rise by about 1.5% in the next few years

Oil demand growth has historically correlated with IP growth, but not exclusively so. Price,

taxation and fuel switching have all driven significant changes in patterns of oil use.

The future of oil demand growth is no longer in the OECD: but in Emerging Markets.

The principal uses for oil are transportation, power generation, heating & chemical feed

The highest value use of oil today is as a transportation fuel and specialty chemical feedstock

As countries become richer they tend to reduce or phase out their industrial uses of oil

Oil demand is price elastic as a rule. Different consuming zones exhibit different elasticity.

This is due to:

– Different end user taxation levels (the US and China have low taxes, Europe has high taxes)

– Political and economic stability and the availability of substitute fuels.

Over time, oil demand becomes more consumer-driven rather than industrial

34

Oil Demand Correlation with Real GDP Growth (1969 - 2008)

Global GDP trends are a clear underlying driver of oil demand.

However, the relationship is uneven and consuming regions exhibit very different demand multipliers

to GDP. A broad rule of thumb maybe ~ 0.7 in emerging economies, ~0.2 ish in the OECD.

– Note as well that US oil consumption can still rise cyclically, after having been decimated by

substitution (cheap natural gas) and again by the GFC of 2008

– Oil consumption across northwest Europe and in Japan is trending down more unambiguously

Relationships like this are obvious but valid really only in a big picture, at best big trend correlations provide a useful backdrop and a signaling function

R2 = 0.5802

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

-6.00% -4.00% -2.00% 0.00% 2.00% 4.00% 6.00% 8.00% 10.00%

Worldwide Oil Consumption Growth

Wo

rld

Real

GD

P G

row

th

Source: BP Stats, Credit Suisse estimates

35

Oil Demand: the Funny Part Is that it Is Still Growing

In the past 20 years, Asia-Pacific has nearly doubled its oil consumption to 32 Mb/d

… few people remember that the combination of Latin America, Africa and the Mideast also doubled its

oil use to ~19 Mb/d, more than a fifth of global oil consumption

North America remains home to fully one quarter of all oil use

Only in northwest Europe and in Japan is oil consumption clearly trending down

Source: BP Stats

36

… Rising Living Standards Across EM Propel that Growth

Source: OECD

37

0

5000

10000

15000

20000

25000

1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

US Total o/w Transport

0

5000

10000

15000

20000

25000

30000

35000

1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

EM ex China Total o/w Transport

0

5000

10000

15000

20000

25000

30000

35000

1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

OECD Ex US Total o/w Transport

0

5000

10000

15000

20000

25000

1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

China Total o/w Transport

OECD Ex-US is declining, but is only one piece to the global demand puzzle (kb/d) China oil demand is trending higher, low oil prices should help (kb/d)

The driver of oil demand growth remains transportation-demand in emerging market economies, including China

US oil demand has not yet gone into trend decline, has cyclical upside (kb/d) Ex China EM oil demand is trending higher, low oil prices should help (kb/d)

Global Oil Demand: We See the Glass as Half Full

Source: BP Statistical Review of World Energy 2014, Credit Suisse Research

Near Term Demand Side Developments to Watch

39

We observed earlier this year that global industrial production had declined sharply through the first nine months of 2014. But in the below picture it is clear

that indeed the momentum trough was reached in August and that growth resumed (and actually accelerated into year-end). Significantly, other measures of

global activity, all based on real data , rebounded alongside

While things more recently have slowed down, indeed global IP momentum peaked in January, we don’t anticipate a rolling over into a new soft-patch.

Longer history and real/ relevant measures of activity: Global Goods Demand, Production and Trade

– in which Goods Demand is Adjusted IP Components from (C + I + G - M)

The NT Demand Outlook: A Fairly Benign Macro

Worries remain, yet global growth remains the most likely outcome 2014 was a materially worse year for global oil demand growth than we anticipated. However, it was not near as bad as many feared, and growth began

to ‘re-accelerate’ in a way that many have only realized quite recently.


5.13

5.18

5.23

5.28

5.33

Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15

log level

Global Goods Demand, Industrial Production, and Trade

Euro Area recession (2011Q4-2013Q1)

Global IP ex-China, nominal IP weights

Demand Partial Data/Estimate

Global Goods Demand x-China, trend-adjusted

World Trade Volume

Goods Demand = Adjusted IP Components from (C + I + G+X-M)

Jan Momentum Peak

40

Global oil demand growth did not roll over … (SA, 3mma of monthly data on a LN scale) Global oil demand momentum, mom and yoy 3 mma % change

The bearish extrapolation of weak 2Q14 demand proved misguided. Demand growth re-accelerated through much of 2H14 and is off to a strong start of 2015

… instead OECD oil demand began to rebound in H2-2014 (SA, 3mma of monthly data on a LN scale) OECD oil demand momentum, mom and yoy 3 mma % change

Oil Macro – the Micro of Seasonally Adjusted Monthly Demand Data

11.30

11.35

11.40

11.45

11.50

J-08 J-09 J-10 J-11 J-12 J-13 J-14 J-15 J-16

10.65

10.70

10.75

10.80

10.85

10.90

J-08 J-09 J-10 J-11 J-12 J-13 J-14 J-15 J-16

-0.5%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

-1%

0%

1%

2%

3%

4%

5%

J-11 J-12 J-13 J-14 J-15

3 mma mom % change 3 mma yoy % change

Source: Credit Suisse Research, IEA, EIA, JODI, Country Data

-1.5%

-1.0%

-0.5%

0.0%

0.5%

1.0%

1.5%

-3%

-2%

-1%

0%

1%

2%

3%

J-11 J-12 J-13 J-14 J-15


41

Non-OECD oil demand growth is not much to write home about (SA, 3mma of monthly data on a LN scale) Non-OECD demand momentum, mom and yoy 3 mma % change

Non-OECD Growth is Respectable, Despite Asia Slowing

EM Asia ex-China ended 2014 a little sluggishly, then gained momentum (SA, 3mma of monthly data on a LN scale) EM Asia ex-China oil demand data, mom and yoy 3 mma % change

Oil Macro – Seasonally Adjusted Demand (con’t)

10.40

10.50

10.60

10.70

10.80

10.90

J-08 J-09 J-10 J-11 J-12 J-13 J-14 J-15 J-16

9.1

9.2

9.3

9.4

9.5

J-08 J-09 J-10 J-11 J-12 J-13 J-14 J-15 J-16

-0.5%

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

0%

2%

4%

6%

J-11 J-12 J-13 J-14 J-15


-1.5%

-0.5%

0.5%

1.5%

2.5%

3.5%

-3%

-1%

1%

3%

5%

7%

J-11 J-12 J-13 J-14 J-15


Source: Credit Suisse Research, IEA, EIA, JODI, Country Data

42

US (SA, 3mma of monthly data on a LN scale) US oil demand data, mom and yoy 3 mma % change

A Recovery in US Oil Demand, With Gasoline In The Lead

US oil demand growth by product (annual averages in kb/d, yoy)

Oil Macro – Seasonally Adjusted Demand, US

9.7

9.8

9.9

10.0

J-08 J-09 J-10 J-11 J-12 J-13 J-14 J-15 J-16

-6%

-4%

-2%

0%

2%

4%

6%

A-11 A-12 A-13 A-14


-500

-300

-100

100

300

500

2012/11 2013/12 2014/2013 2015E/2014E

Others*** LPGs** Fuel oil

Jet fuel Diesel* Gasoline

Source: Credit Suisse Research, IEA, EIA

43

OECD Europe, after 7 lean years … (SA, 3mma of monthly data on a LN scale) OECD Europe oil demand data, mom and yoy 3 mma % change

A Surprisingly Robust EU recovery, and A Strong yoy Rebound in China

China’s oil demand still grows at a +3% pa rate, base effects flatter the first half of this year (3mma of monthly data, kb/d) China oil demand data, mom and yoy 3 mma % change

Oil Macro – Seasonally Adjusted Demand, Europe & China

9.4

9.5

9.6

9.7

9.8

J-08 J-09 J-10 J-11 J-12 J-13 J-14 J-15 J-16-6%

-4%

-2%

0%

2%

4%

J-11 J-12 J-13 J-14 J-15


8,000

8,500

9,000

9,500

10,000

10,500

11,000

11,500

Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15

adjusted demand

3mth average

China's oil product demand adjusted for gasoline and diesel inventory shifts

YoY change

kb/d 2014 2014ytd Feb* 2015 ytd Feb* Feb* 2015 ytd

Gasoline 2,183 2,214 2,365 2,463 2,643 11.8% 11.2%

Kerosene 454 460 488 504 529 8.4% 9.4%

Diesel 3,377 3,303 3,019 3,360 3,262 8.0% 1.7%

MD 3,831 3,763 3,508 3,863 3,791 8.1% 2.7%

Fuel oil 676 688 676 625 641 -5.2% -9.2%

LPG 807 810 841 894 943 12.1% 10.4%

Naphtha 1,064 1,067 1,089 1,108 1,147 5.3% 3.8%

"Drive" 6,014 5,977 5,872 6,326 6,435 9.6% 5.8%

"Burn" 2,547 2,566 2,606 2,627 2,731 4.8% 2.4%

Total 8,561 8,543 8,478 8,953 9,166 8.1% 4.8%

* three month rolling average. "Drive" = gasoline + diesel + kerosene

Source: Credit Suisse Research, IEA, JODI, NBS

Oil Markets

45

Oil Markets: Global in Nature

Oil is produced on nearly every continent. A complex transportation and refining system exists to move

oil to end-user markets.

We estimate that the physical global crude trade is c$2,500-billion-per year at $70/bbl oil and baseline

global demand of 92 MBD.

Variations in the U.S. dollar exchange rate also play a significant role for crude price given that oil is

traded in U.S. dollars. Geopolitics and speculation also influence the price of oil.

Crude oil is largely purchased by refiners to convert into refined products such as gasoline, as well as

by power generation plants.

Futures are traded on major exchanges such as the NYMEX and the ICE.

46

Major Oil Trade Flows (2012, Million Tonnes)

Source: BP Statistical Review

47

Oil Markets: NYMEX

The NYMEX light, sweet crude oil futures contract is the world’s most liquid forum for crude oil trading

and is also the world’s largest-volume futures contract trading on a physical commodity.

The contract trades in units of 1,000 barrels, and the delivery point is Cushing, Oklahoma.

The contract provides for delivery of several grades of domestic and internationally traded foreign

crudes.

850,000 contracts are traded on average per day (futures + options).

Source: BBC

48

Oil Markets: Trading

Futures trading: standardized, exchange-traded contracts in which the contract buyer agrees to take

delivery, from the seller, a specific quantity of crude oil at a predetermined price on a future delivery

date.

Over-the-Counter Swaps etc: instead of trading via a futures exchange, buyers and sellers of crude oil

can enter into an over the counter transaction, often known as a swap. These contacts have become more popular than futures trading in recent years, but can prove difficult to liquidate at times of market

dislocation.

Term contracts: private contracts to buy specified quantities of crude oil at prices based on regional

benchmarks. These contracts are not traded in any form. Most Kuwaiti crude oil is sold on term

contracts, with the price of Kuwaiti crude oil tied to Saudi Arabian Medium (for western customers) and

a monthly average of Dubai and Oman crudes (for Asian buyers).

49

Oil Markets: Data Sources

International Energy Agency (IEA): Every

month, the IEA releases the “Oil Market

Report,” which contains information on supply,

demand, stocks, prices, and refinery activity.

U.S. Department of Energy: The DOE provides

weekly information on crude and principal

petroleum products in regards to factors such

as supply, imports, inventories and refinery

activity.

Market participants utilize these types of data

sources in order to form opinions on companies

as well as the expected direction of the

commodity.

Source: IEA

50

The shape of the 12-month futures curve is often interpreted as an indication of current supply/demand balances.

An upward sloping curve suggests higher expected prices and implicitly higher demand relative to

supply in the future: In practice, Contango is most common with oversupply in the front month.

A downward sloping curve suggests current demand is outpacing current supply with the expectation

that the imbalance will become less pronounced in the coming time period: In practice,

Backwardation is most common with tight supply and demand in the front month.

Futures Curve: Contango Example

Futures Curve: Backwardation vs. Contango

$77.09

$72.04$72.49 $73.04

$73.61$74.11 $74.62

$75.10 $75.60$76.10 $76.47 $76.77

$65

$70

$75

$80

Oct

09

Nov

09

Dec

09

Jan

10

Feb

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Pri

ce p

er b

arre

l

$72.04

$77.09$76.77$76.47 $76.10

$75.60$75.10 $74.62

$74.11 $73.61$73.04

$72.49

$65

$70

$75

$80

Oct

09

Nov

09

Dec

09

Jan

10

Feb

10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0

Aug

-10

Sep

-10

Pri

ce p

er b

arre

l

Futures Curve: Backwardation Example

Source: Bloomberg

51

Effe

ctive

Sale

Price

Spot Market Price

Standard Swap

Unhedged

Tenor Price

Cal 15 $4.20

Cal 16 $4.15

Payout Diagram

NYMEX NG Swap - Calendar Strip pricing

Swap

In order to eliminate its exposure to oil and natural gas prices moving lower, producers may choose to execute commodity

swaps for their anticipated future production

– The producer agrees to receive a fixed price from CS and the producer pays a floating price to CS which would mirror the producer’s physical commodity sales for a specific volume and tenor

– In effect, the producer locks in the price that it will sell its future oil or natural gas supply

Swap is zero-cost at inception

Swap provides full downside protection while avoiding any initial cash outlay. However, a swap also eliminates the producer’s ability to benefit in the event that the price of the underlying rises

Transaction Overview – A WTI Example

Tenor Price

Cal 15 $87.50

Cal 16 $83.00

Note: Pricing is indicative only and subject to prior internal credit approval

Prices are quoted in $/ bbl

WTI Swap - Calendar Strip Pricing



This information reflects the Credit Suisse marks as of March 20, 2014 Source: Credit Suisse Research

52

Payout Diagram

NYMEX NG Put - Calendar Strip pricing

Put Option

The client may consider purchasing a put to protect it from WTI prices moving below the strike price of the put

The client pays an upfront or deferred premium to CS and

receives protection in the event that oil prices fall below the put strike, but also retains the ability to benefit from market prices moving higher

For a specific volume and tenor, CS will pay the client the price

difference should prices fall below the put strike

Due to the volatility of the underlying product, time value, and liquidity in the options market, longer dated puts can become

expensive on both on an upfront and deferred premium basis




WTI Put - Calendar Strip Pricing




Effe

ctive

Price

Spot Market Price

Purchased Put

Unhedged

Tenor $80.00 $85.00

Cal 15 $4.00 $6.00

Cal 16 $6.50 $8.80

Put Strike

Tenor $3.75 $4.00

Cal 15 $0.20 $0.30

Cal 16 $0.25 $0.35

Put Strike

53

Payout Diagram

NYMEX NG Put Spread - Calendar Strip Pricing

Put Spread

As a complement to a purchased put, the client can sell a lower struck put, creating a put spread

The sold put helps to partially offset the cost of the purchased

put, decreasing the initial cash outlay

If the underlying WTI price remains above the purchased put strike, both put options will expire worthless and the client will forfeit the initial upfront or deferred premium to be paid to CS

Client’s downside protection is limited to the difference in the strike price of the purchased and sold put options, but it maintains full upside participation




WTI Put Spread - Calendar Strip Pricing




Tenor$65 - $80

Put Spread

$70 - $85

Put Spread

Cal 15 $3.00 $4.00

Cal 16 $4.50 $6.00

Tenor$3.00 - $4.00

Put Spread

$3.50 - $4.00

Put Spread

Cal 15 $0.25 $0.20

Cal 16 $0.30 $0.25

Eff

ective P

rice

Spot Market Price

Put Spread Unhedged

54

Payout Diagram

NYMEX NG Costless Collar - Calendar Strip

pricing

Costless Collar

Counterparties choosing to enter into a collar participate in both the upside market price move and downside market price risk

between the purchased put and sold call strike prices

The premium of the sold call offsets the premium of the purchased put, reducing or eliminating any initial cash outlay

While the client retains protection in the event that WTI prices fall below the put strike, a collar also limits the client’s ability to

benefit in the event that prices rise above the call strike

Client must consider the volatility in the options market in order to determine if this structure is attractive, as exposure to

downside price movements could be larger than the potential upside from prices rising




WTI Costless Collar - Calendar Strip Pricing




Eff

ective P

rice

Spot Market Price

Collar (Purchased put & Sold call)

Unhedged

Tenor $80.00 $85.00

Cal 15 $94.00 $90.00

Cal 16 $86.50

Put Strike

Tenor $3.75 $4.00

Cal 15 $4.90 $4.50

Cal 16 $4.75 $4.40

Put Strike

Swap

55

Payout Diagram

NYMEX NG Three-Way - Calendar Strip

pricing

Producer Three-Way

As an alternative to the traditional collar, a client may also like a three-way

A producer three-way is a combination of the traditional collar

paired with the sale of a lower struck put

The premium from the sold put can be used to increase either the purchased put or sold call strikes on the collar

This hedging strategy is ideal in low price environments when

the client is fairly confident that underlying prices will not move below the sold put strike. Volatility in the options market will have an impact on the put and call strike prices

Client is fully protected as long as prices do not fall below the sold put strike and retains upside participation up to the call strike




WTI Three-Way - Calendar Strip Pricing




Eff

ective P

rice

Spot Market Price

Three-Way Unhedged

Tenor $3.00 / $4.00 $3.50 / $4.00

Cal 15 $4.60 $4.95

Cal 16 $4.50 $4.90

Put Strikes

Tenor $65 / $80 $70 / $85

Cal 15 $96.75 $93.50

Cal 16 $91.50

Put Strikes

56

Tenor Price

Cal 15 $90.50

Cal 16 $87.10

Tenor Price

Cal 15 $4.40

Cal 16 $4.30

Payout Diagram*

NYMEX NG Double-Volume – Calendar strip

pricing

Double-Volume

To achieve an enhancement above the current market price, producers may be interested in a Double-Volume swap

A producer Double-Volume consists of a sold swap and a call

swaption both at the same price

The premium from the call swaption is used to increase the level of swap

The call swaption has one expiration date. If the underlying

swap settles above the strike price, CS will “Double” the volume of the transaction

This hedging strategy is most suitable for companies who

intend to vary their production based on the market price and

have some flexibility on the % of their production that is hedged


Note: The Double-Volume structures above have call swaption expiration dates on the quadultimate settlement of the January portion of the swap


WTI Double-Volume – Calendar strip pricing

Note: The Double-Volume structures above have call swaption expiration dates on the quadultimate settlement of the January portion of the swap



Eff

ective P

rice

Spot Market Price

Double-Volume Unhedged

*This payout diagram assumes that the transaction volume is not doubled

Near Term Oil Market Backdrop and Developments

58

In prior episodes, the first inflection point came in the third quarter too We think that we will be proved right that prices troughed in 1Q15. To be sure at $80/b Brent; $75/b WTI, our projected recovery would fall far short of

the five -year running average of Brent oil prices, which crept over $100/b in June of 2014.

The 2014-’15 Oil Price Collapse in History

Long history of month 1-6 of Brent futures: deep contango is rare ($/ b)

Overlay of terms of ‘cost of carry’ pricing of Brent futures of two prior crises

The extent and depth of this oil price collapse feels most like that of 1998

(less bad than in 2009) in terms of the attendant collapse in Brent structure.

The 20-year history of the structure of the front end of the futures curve shows

three prior episodes with a deep contango: 1998, 2005 and of course 2008.

While evidently the 2014 price collapse dwarfs anything since 2010, it is

fundamentally different from the acute collapse of oil demand in late 2008.

That said, we are seeing a similarly massive inventory surplus developing

… and we can also see the contango structure persist for another year .

Back in the late 1990s, the Asian Financial Crisis had undermined oil

demand. Weak demand was compounded by Saudi Arabia engaging

Venezuela in a struggle for US market share. Affirmation came at a fateful

Opec meeting in Jakarta, Indonesia late in 1997.

Prior extended stretches of oversupply (contango) ended after five quarters

(1998); two and a half years (2007); and three years (2010).

But in all three episodes, things stopped getting worse after two to

three quarters – and we think that history is repeating itself.

-$12

-$10

-$8

-$6

-$4

-$2

$0

$2

$4

$6

$8

J-97

J-98

J-99

J-00

J-01

J-02

J-03

J-04

J-05

J-06

J-07

J-08

J-09

J-10

J-11

J-12

J-13

J-14

J-15

-2.0

-1.5

-1.0

-0.5

0.0

0.5

- year 1 year 2

May 2008 $126/b 29 July 2014 $106/b

December 1997 $18/b

Source: Credit Suisse Research, Bloomberg

59

Some prompt price recovery and an appreciating long-end

Short term S/D balance + a Shifting Long Term ‘Anchor’

A few assumptions / thoughts / observations about our favorite barometers on the health and direction of crude oil:

Perhaps naively, we look at markets as clearing information timely and efficiently.

Futures markets inform about the short term (structure) and the longer run (level).

Since we expect that markets will remain saddled with very heavy inventories, and that consequently contangoes remain pronounced; more of our projected

2015 price appreciation comes from a shift in the long end of the curve …

… that shift happens in earnest as confidence builds – which happens most likely along with data that show demand growing and supply rolling. It would

help too if markets got a clearer line of sight on the industry ability to compress costs.

Keep an eye on December 2017 futures prices and the shape of the front end of the Brent futures curve.

Oil prices have recovered a bit, Brent has risen some 45% off its January low. A

measure of ‘normal’, the longer dated price fell less, but also recovered less ($/ b). Global crude oil markets remain over-supplied, though less

depressingly so (Brent futures contract month 1 – month 6; $/b)

$40

$50

$60

$70

$80

$90

$100

$110

$120

Jun-14 Nov-14 Apr-15 Sep-15 Feb-16 Jul-16 Dec-16 May-17 Oct-17

Peak 6/19/2014 Trough 1/13/2015

Recent High 5/5/2015 Actual

-$8

-$6

-$4

-$2

$0

$2

$4

$6

$8

D J F M A M J J A S O N D

2012 2013

2014 2015

2011

Backwardation: Bullish

Contango: Bearish


60

Oil is still fundamentally weak, but rebalancing has begun

Traders spent four years ruing the lack of volatility – the one thing we are confident of is more volatility.

What we learned: The oil price collapse of H2-2014 was not a ‘canary in the coal-mine’ type signal of a collapsing global economy. That said, true

strengthening of fundamentals is not likely to begin in earnest until H2 2015 and futures curves will probably not flip backward until well into 2016.

Oil prices should trend up instead on relative improvements of supply/demand fundamentals…

…And on building confidence about the longer run deceleration of supply growth as well as sustained demand growth.

Six Months into a “Go Stabilize Yourself” World

Quarter average WTI oil prices for this year and the next two, including our

forecast, the futures strip and the oil price track of 2008-’10, GFC ($b)

Brent WTI WTI - Brent

Period

Actuals &

CS

Forecast

Prior

Forecast Period

Actuals &

CS

Forecast

Prior

Forecast Period

Actuals &

CS

Forecast

Prior

Forecast

2011 110.91$ 2011 95.11$ 2011 (15.80)$

2012 111.68$ 2012 94.15$ 2012 (17.53)$

2013 108.70$ 2013 98.05$ 2013 (10.65)$

Q1-2014 107.87$ Q1-2014 98.56$ Q1-2014 (9.31)$

Q2-2014 109.76$ Q2-2014 102.99$ Q2-2014 (6.77)$

Q3-2014 103.59$ Q3-2014 97.34$ Q3-2014 (6.25)$

Q4-2014 76.82$ Q4-2014 72.94$ Q4-2014 (3.88)$

2014 99.38$ 2014 92.89$ 2014 (6.49)$

Q1-2015 55.13$ 45.00$ Q1-2015 48.57$ 44.00$ Q1-2015 (6.56)$ 1.00$

Q2-2015f 54.00$ Q2-2015f 53.00$ Q2-2015f (1.00)$

Q3-2015f 62.00$ Q3-2015f 60.00$ Q3-2015f (2.00)$

Q4-2015f 71.00$ Q4-2015f 67.00$ Q4-2015f (4.00)$

2015f 60.53$ 58.00$ 2015f 57.14$ 56.00$ 2015f (3.39)$ 1.50$

Q1-2016f 72.00$ Q1-2016f 67.00$ Q1-2016f (5.00)$

Q2-2016f 74.00$ Q2-2016f 71.00$ Q2-2016f (3.00)$

Q3-2016f 78.00$ Q3-2016f 75.00$ Q3-2016f (3.00)$

Q4-2016f 80.00$ Q4-2016f 75.00$ Q4-2016f (5.00)$

2016f 76.00$ 2016f 72.00$ 2016f (4.00)$

2017f 80.00$ 2017f 75.00$ 2017f (5.00)$

2018f 80.00$ 2018f 75.00$ 2018f (5.00)$

2019f 80.00$ 2019f 75.00$ 2019f (5.00)$

Long-Term 85.00$ Long-Term 80.00$ Long-Term (5.00)$

Trading oil markets has become quite ‘interesting’, if not outright scary.

Since the global recovery has accelerated, however haltingly, energy has been

screening “very cheap” to all manner of investors.

Attendant record high open interest of oil futures, big moves in currency,

rates, equity markets and as yet very low conviction on pure oil fundamental

direction all appear to have created an environment ripe for ubiquitous

algorithmic trading to whipsaw oil prices on any given day.

$35

$45

$55

$65

$75

$85

$95

$105

start Q1 Q2 Q3 Q4 Q5 Q6 Q7 Q8

Current Futures Strip

2009-'11 Trajectory

CS WTI Forecast


North American Crude Oil Markets

62

Phase 1 (2011-12) Phase 2 (2013-14)

Phases of US WTI-Brent Discounts, Amplitude of Swings Reducing

-10

-5

0

5

10

15

20

25

30

35

1/1/2010 1/1/2011 1/1/2012 1/1/2013 1/1/2014 1/1/2015

$/b

bl

Brent-LLS LLS-WTI Brent-WTI Phase 1 (2011-12): Mid-

Con production growth

was filling up inventories

at Cushing (OK) where

WTI is based had no exit

route.

Phase 2 (2013-14):

Pipes arrive to connect

Cushing to the Gulf.

Attention focuses on

super-saturation of light oil

in the medium/heavy

refineries of the Gulf

Coast. Permian discounts

widen due to higher rig

count.

Phase 3 (2015):

Attention turns to the

West Coast as rising

crude volumes flow West,

contango incentivizes

crude inventories to build.

Phase 4 (LT):

Infrastructure or policy

(US exports) will drive

spreads to transport and

quality differentials. Source: Credit Suisse Research, Bloomberg

63

Current Crude Flows and Costs

Source: VLO

64

Gulf Coast Refining Runs (Mb/d)

PADD I-IV ‘East of Rockies’ Crude

Inventories (Mbs)

Gulf Coast Crude Inventories (Mbs)

“Stress” in the Gulf Will Determine LLS Light Crude Oil Discount

Gulf Coast Imports (Mb/d)

Source: CS estimates, EIA

100

125

150

175

200

225

250

275

J F M A M J J A S O N D

5 year average 2014 2015

6

6.5

7

7.5

8

8.5

9



2

3

4

5

6

7

8



250

275

300

325

350

375

400

425

450



65


Crude End-Market

WTI-Gulf Transhipment Shipping Competition Discount WTI-Brent

Exporting to World Markets 3.8 0.5 2.0 LLS vs Medium Imports 0.0 6.3

Clearing at Gulf Refiners 3.8 1.5 LLS vs Medium Imports 5.0 10.3

Clearing into Canada 3.8 1.5 2.0 LLS-Brent 0.0 7.3

Clearing into East Coast 3.8 1.5 4.6 LLS-Brent 0.0 9.9

Backing out Heavy Crude 3.8 1.5 LLS-Maya 7.0 12.3

0

2000

4000

6000

8000

10000

2010 2011 2012 2013 2014 2015 2016 2017

KB

D

Net Inflows to Gulf Coast Eagle Ford condensate Exports PADD 3 Light+Medium Capacity

PADD 3 Light/Medium Capacity + Crude Exports to Canada PADD 3 Light/Medium + Crude Exports to Canada/PADD 1 PADD 3 Total + Crude Exports to Canada/PADD 1

Without Export Clarity, Gulf Coast Will Hit Light Oil Saturation

Gulf Coast Crude Flows and Potential WTI-Brent Spreads

66

Source: VLO

Challenges Processing Light Crudes

67

Tactical Indicators – US Storage Capacity

Source: Credit Suisse Research, EIA

Shell crude storage capacity (thousands of

barrels)

In Operation Idle In Operation Idle In Operation Idle In Operation Idle In Operation Idle In Operation Idle

Refineries 17,443 1,894 23,166 1,213 89,287 2,805 4,614 160 39,207 1,050 173,717 7,122

Tank Farms (excluding SPR) 4,908 1,148 142,063 2,716 242,385 7,235 15,966 76 33,660 1,269 438,982 12,444

Of which at Cushing, OK -- -- 84,969 147 -- -- -- -- -- -- 84969 147Tankers, Barges and Pipes -- -- -- -- -- -- -- -- -- -- 173333 na

SPR (Crude only) - - - - 727,000 - - - - - 727000 0

Total (excluding SPR): 22,351 3,042 165,229 3,929 331,672 10,040 20,580 236 72,867 2,319 786,032 19,566

Working crude storage capacity (thousands of

barrels)

I II III IV V US Total

Refineries 15,408 18,877 75,006 4,006 34,756 148,053

Of which is likely to be max fill in reality 13,082 17,375 58,037 3,461 29,405 121,359

Tank Farms (excluding SPR) 3,974 117,253 210,614 13,139 27,899 372,879

Of which at Cushing, OK 70,812 70,812

Volumes in transit * 4837 33972 71277 4279 15636 130,000

SPR (Crude only) 727,000 727,000

Total (excluding SPR):** 21,893 168,599 339,928 20,878 72,940 624,238

(*) Note: Volumes estimates based on March 4, 2015 note by EIA

(**) Note: Total assumes a level of max fill at refineries below the EIA working capacity number

Crude Oil Stocks (thousands of barrels)

4/24/2015 I II III IV V US Total

Standard EIA stock number 17,624 146,086 243,864 24,618 58,720 490,912

Crude storage capacity utilization (thousands

of barrels)

4/24/2015 I II III IV V US Total

Standard EIA stock number 81% 87% 72% 118% 81% 79%

"Head Room" PADD I - IV East of Rockies 119,106

4/24/2015

Total shell

capacity

(incl. idle

capacity)

Total

operable

shell

capacity

Total

working

capacity *

Current

inventories

"Head

Room" till

working

capacity is

full

Three week

average

build

# of weeks

till full

PADD I - IV "East of Rockies" (excluding SPR): 557,079 539,832 551,298 432,192 119,106 2,651 45

(*) Note: has been adjusted to account for oil in transit as well as a level of max fill at refineries below the EIA working capacity number

PADDs

I II III IV V US Total

PADDs

PADDs

PADDs

68

US gasoline inventories (Mbs)

US middle distillate demand (Mb/d) US finished gasoline demand (Mb/d)

Tactical Indicators – US Product Demand and Inventory

US middle distillate inventories (Mbs)

Source: Credit Suisse Research, EIA

175

185

195

205

215

225

235

245

255



100

110

120

130

140

150

160

170

180



7

7.5

8

8.5

9

9.5

10



2.5

3

3.5

4

4.5

5



69

Finally, A Word on US Crude Export Policy

70

US Light Shale Crude Fits Overseas Refineries Better

A US Crude Export Rationale

0

10000

20000

30000

40000

50000

60000

70000

US Intl (ex-Russia)

Crude Capacity Heavy Yield

<28

28-33

33-40

>40

Almost 40% of Crude Is Medium/Heavy The US Has More Cokers than Rest of World

Source: OGJ, Credit Suisse Research

71

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

kbd

Source: Credit Suisse Research, EIA, VLO

US Refiners Need to Export Surplus Product to Capture Cheap Crude Advantage, Not Immune to World Markets

Diesel Exports Help Gasoline Production Diesel Export Destinations

Gasoline Export Destinations

US Natural Gas: A Supply Revolution Looking for Demand

73

What is Natural Gas?

Natural Gas is a combustible, colorless and odorless gas generally considered the least environmentally unfriendly of the principal hydrocarbon energy sources.

Methane (which is dry gas) is the most commercially marketable component of the natural gas stream.

Other components of the typical well-head natural gas stream (wet gas) include heavier “liquids” such as ethane, propane and butane.

Natural Gas is measured on a unit basis in thousands of cubic feet (Mcf). The benchmark spot price is

Henry Hub, which is quoted on a $ per Millions of British Thermal Units basis (MMBtu). An Mcf is a volume unit, while MMBtu is an energy measurement.

Because of the need for extensive pipeline systems and difficulty in shipping, natural gas is most used

in regions with indigenous supply. Meanwhile, the ability to ship gas in liquid form (LNG) is gaining traction.

Photo Source: Chesapeake Energy

74

Distribution of Proved Gas Reserves

Count on the North America share of proved reserves to rise more

Source: BP Statistical Review of World Energy, Credit Suisse.

75

World Energy: Natural Gas Has Gained Share of the Energy Pie

According to BP Statistical Energy Review, natural gas accounted for 24% of global primary

energy consumption, the highest on record, in 2012.

Source: BP Statistical Review of World Energy, Credit Suisse.

76

Global Natural Gas: Daily Demand By Region (Bcf/d)

Global gas demand growth is currently being driven by Asia and the Middle East (due to a switch away

from oil and slowing growth in coal consumption).

Power demand has been the key driver to gas demand growth globally, while industry has slowed.

Source: BP Statistical Review of World Energy 2013

77

Substitutes for Natural Gas

There are numerous substitutes for natural gas including coal, oil, heating oil, naphtha and

alternative energy (such as wind, solar and nuclear power).

A global movement towards clean energy has put natural gas more in favor versus coal and oil, due to

inherently lower CO2 emissions.

Coal Oil Alternative Energy

Source: www.britishcoalgasification.co.uk.

Source: ecotechdaily.com

Source: www.greengop.org.

78

N. AM. Natural Gas Pricing

North America is mostly a “closed” market with

natural gas prices driven by demand trends

(weather, economic growth) and the cost of

new supply.

Over the past 14 years, NYMEX gas prices

have traded as low as $2 per MMBtu and as

high as $14-15 per MMBtu.

In North America, oil and natural gas do not

exhibit a strong pricing relationship as the two

fuels don't compete much (oil is not used much

for power while gas is not used much for

transportation).

Outside of the U.S., prices tend to be linked to

crude owing to less liquid trading markets.

0

2

4

6

8

10

12

14

16


0

10

20

30

40

50

60


10-yr avg:16.4x

Today: 23x

Historical NYMEX prices ($/Mmbtu)

Historical oil/gas ratios

Source: Bloomberg LP

79

North American Natural Gas: Industry Overview

The process of bringing natural gas to market begins with exploration & production and ends with

the retail distribution of gas to end markets.

Along the way, gas is gathered and processed for removal of oil, water, natural gas liquids (NGLs)

and sulfur. It is then transported and stored while awaiting distribution.

Source: Energy Information Administration

80

Upstream: Where is Natural Gas Located?

Exploration & Production (also known as the upstream) of natural gas is a global venture and

producers operate in both onshore and offshore environments.

Natural gas is located underground and below seabeds.

Producers often drill thousands of feet beneath the surface to reach natural gas reservoirs.

In North America, onshore unconventional resources like shale and tight gas sands have become a growing source of production in recent years as traditional and lower cost sources have matured.

Source: U.S. Geological Survey. Source: StatoilHydro.

Onshore: Shale Onshore: Tight Gas Offshore

Source: Department of Primary Industries, Australia.

81

Upstream: Exploring and Producing Natural Gas

Producers use various techniques to locate and test for the existence of natural gas including geophysical surveys, seismic evaluation, exploratory wells, well logs, core samples and others.

Once commercially viable quantities of natural gas have been discovered and confirmed, producers

will develop the reservoir and commence production.

Produced natural gas is then sent to processing facilities via pipeline.

Please see Upstream section for additional detail on the exploration and production process.

Source: Japan Agency for Marine Earth Science and Technology

Source: www.sm i-online-co.uk

82

Midstream: Processing Natural Gas

Processing natural gas (midstream) involves the removal of oil, water, hydrogen sulfide, carbon dioxide

and NGLs (ethane, butane and propane).

The end goal is to produce dry gas, free of impurities or other non-methane compounds to meet pipeline quality specifications so it can be transported across the US.

Source: Energy Information Administration

83

Midstream: Transporting Natural Gas

Natural gas in the U.S. is delivered via a complex web of interstate and intrastate pipelines estimated to

extend ~2.2 million miles.

Pipeline companies charge regulated fees (tariffs) for moving gas.

Major pipelines include the Transcontinental, Texas Eastern & Rockies Express.

The majority of interstate pipelines were created to move gas from the US gulf coast (traditional supply

center) the Midcontinent and Northeast (demand center)

Source: American Clean Skies Foundation

84

Natural Gas Marketing: What are Basis Differentials?

The NYMEX natural gas price (Henry Hub, Louisiana) is not necessarily what producers receive for

their gas. The actual price received (well-head price) is different throughout the country. The difference

relative to NYMEX is called a basis differential.

Regional prices are a function of local supply and demand balances and the transport cost to reach

consuming markets from production areas.

Historically, Rockies gas traded at the widest discount while Appalachia gas traded at a

premium (given proximity to high demand areas on the east coast). However, differentials have

flipped since 2012 as the Northeast began producing vast amounts of natural gas.

~$4.35/MMBtu

~$4.50 – 4.85 /MMBtu

$4.05-$5.20/MMBtu

Source: www.nafsa.org

85

Natural Gas Storage: The U.S. has a Deep Storage System

Before being transported for local distribution, natural gas is stored in underground facilities such as

depleted reservoirs, salt caverns and aquifers.

Total natural gas storage capacity in the U.S. is spread amongst 400 facilities with a design capacity of

4.68 Tcf (demonstrated capacities are much lower at 4.3 Tcf).

Regulated utilities own and operate the vast majority of US storage sites, with the rest controlled by

merchant power companies or individual storage operators

86

U.S. Weekly Storage Report

Natural gas in storage fluctuates from the withdrawal season (November to March) when cold weather

typically results in storage withdrawals to the refill season (April to October) when lower demand leads

to net storage injections.

Every Thursday at 10:30am ET, the EIA reports the storage injection / draw for the prior week. The

amount of injection or draw can have a material affect on gas prices as it indicates supply / demand

trends relative to previous years.

Source: EIA

87

Industrial

Gas used for heat, power or chemical

feedstock for manufacturing. End products

include petrochemicals, fertilizers, plastics, etc.

Commercial

Gas used by non-manufacturing establishments in

the sale of goods or services

Residential

Gas used in private dwellings for space and water

heating, air conditioning, cooking and other

household uses

Major End Markets for Natural Gas

Electrical Power

Gas used by power plants to generate electricity

Source: EIA

Other smaller end-market uses of natural gas include 1) fuel (natural gas vehicles) and 2) oil & gas

production.

88

U.S. Natural Gas Demand By End Markets

Natural gas demand trends are highly seasonal.

Because natural gas is used as a heating fuel, demand rises materially in the winter/cold weather

months.

0

10

20

30

40

50

60

70

80

90

100


Industrial Electric Power Residential Commercial

Source: EIA

Near Term US Natural Gas Market Observations & Forecast

90

In winter 2014-’15 supply growth easily trumped colder than normal weather

This supply growth, however, is already showing signs of slowing down:

We are more confident of such a slow down than in years past.

Clearly activity is slowing down across the entire US upstream as prices of crude oil,

natural gas liquids and natural gas have all deflated

The low price/constrained-cash-flow issue is compounded by wide, negative basis

diffs in key shale basins – which infrastructure build out is only slowly resolving

Momentum of growth slowed measurably key basins in H2-02014

Rig counts are falling and, we think that that does make a difference

The more so since there is no new emerging champion shale basin ready to surge

Monthly gross natural production we think peaked in December

Summary View: Fundamental Change is Coming

But not likely in time to lift summer prices above $3/MMBtu at the Henry Hub

Any decelerating of supply growth and the ongoing ramping up of demand will, we think, progress too slowly to help lift gas prices this summer. The first

half of the injection season looks especially challenged.

From June/July forward, however, supply growth should begin to deflate faster, while simultaneously yoy demand growth picks up and storage fill should

begin to feel the competition from the first of a string of LNG export terminals.

Marking to market Q1-2015 Bid-week prices averaged $2.96/MMBtu , which was down almost a dollar from last quarter, and nearly 40% lower than in

Q1-2014, despite a similar and considerable assist from colder than normal winter weather.


At these prices, demand is growing too, and in addition, large new tranches of

base-load demand should be added later this year

Help is ongoing from power-generation (~ 2 Bcf/d this summer); industrial use; rising

exports to Mexico; slowing imports from Canada and eventually the startup of the firs

tGulf Coast LNG export facility, which remains on track for Q4

Natural Gas Prices & Forecasts

(Actal bidweek & Henry Hub futures)

Period

Actuals &

CS

Forecast

Prior

Forecast

Current

Futures

2011 4.03$

2012 2.80$

2013 3.67$

Q1-2014 4.90$

Q2-2014 4.56$

Q3-2014 4.07$

Q4-2014 3.96$

2014 4.37$

Q1-2015 2.96$ 2.80$

Q2-2015f 2.70$ -- 2.70$

Q3-2015f 2.90$ -- 2.77$

Q4-2015f 3.20$ -- 2.90$

2015f 2.94$ 2.90$ 2.80$

2016f 4.20$ 4.20$ 3.20$

2017f 4.50$ 4.50$ 3.40$

Long-Term 4.50$ 4.50$

91

Clearly, there was a lot of cold weather, almost as much as in the prior winter

But there was also 6.1 Bcf/d more indigenous dry gas production, driven once by

the northeastern shale gas basins

Offsetting that surge, more exports and less imports helped (0.7 Bcf/d), while

industrial and other demand helped too (0.5 Bcf/d);

But more promising is the growth of gas demand from power-gen (1.4 Bdf/d)

Weekly withdrawals of working gas set in a 15-year range with month-end

labels and our pre-winter ‘normal weather’ projection (Bcf)

Population weighted heating degree days (hdds) ended well above normal

The Winter That Was … Was Cold, Which Is the Worrying Part Lots of inventory left, as production growth of >6 Bcf/d trumped all else That much more production inflated the fundamentally bearish difference this winter to +3.5 Bcf/d, a ‘residual’ three times bigger than we forecast

Source: Credit Suisse Research, Bloomberg, DoE Energy Information Agency

Henry Hub futures prices reset, futures hug our NT forecast ($/MMBtu)

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

$5.50

Jan-12 Jan-13 Jan-14 Jan-15

Actual Monthly

Actual Quartly

Futures

Forecast

3410

3089

2428

1710

1461

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2,750

3,000

3,250

3,500

3,750

4,000

Nov-14 Dec-14 Jan-15 Feb-15 Mar-15

(In Bcf/d) CS Base Case

Production 6.1

Imports/(exports)

LNG 0.0

Mex Exports (0.3)

Canada (0.4)

Demand

Power Gen 1.4

Industrial 0.2

Other 0.3

"Residual" 3.5

Winter 2014-2015 Residual

0

1000

2000

3000

4000

5000

Aug Sep Oct Nov Dec Jan Feb Mar Apr

10 year range

2014-'15

2013-'14

10 yr avg

92

There is no question that US natural gas production surged in the seocnd

half of last year.

In part this was driven by new infrastructure serving the Marcellus shale in

the northeast, and a ‘catch-up’ rally after severe weather in early 2014.

Both factors compounded the very large YoY tallies of this winter

Interestingly, however, the EIA’s accounting of aggregate gross withdrawals

from the US shale basins shows a distinct deceleration in level terms this

last winter, without much of an impact from weather. Apparently,

conventional production surged and then peaked in December.

Tracks for the individual shale basins show that not one of them features

accelerating production growth since October of 2014

We think that further declining rig counts and deep cuts in capital

spending portend further declines and decelerating growth

US natural gas production (“Gross Withdrawals”) probably peaked in

December, we think. Here are monthlies and YoY growth (Bcf/ d) While conventional natural gas production has been on a trend-decline,

shale gas has driven US supplies to record highs (monthly data, Bcf/ d)

We Project Slower Supply Growth, Despite What Happened The “gross withdrawals” hit a record in December and came down in January Part of the surge in H2-2014 came from ‘conventional’ production, by contrast the up-trend in aggregate shale gas production began to curb a bit


Observed and forecast growth rates (Bcf/ d)

-4

0

4

8

12

16

20

24

60

65

70

75

80

85

90

95


Growth YoY(rhs)

US Gross GasSupply

Projected

0

10

20

30

40

50


Conventional

fcst

Unconventional (Shale)

fcst

0

2

4

6

8

10

12

14

16

18

Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15

Eagle Ford Haynesville

Marcellus Utica

Permian Niobrara

93

US Natural Gas – Dare We Say … “Supply Declines”

US gross gas supplies appear to have peaked

In the end price and economics do matter, even for the seemingly endless surge of US shale gas production. We think that it matters that no longer can firms simply ‘subsidize’ gas production

with liquids or oil sales, or simply hope that they’re the last one on a pipe, before others are shut out …

In April, US DoE data began to show this slowdown in its monthly report (through January). A month later the December peak in aggregate US natural gas supply is still evident;

Rig data, scrapes and other indicators point to a slide …

Shale production growth is slowing down fast

The EIA drilling productivity report tracks gross gas supplies from the shale plays. The driver of cheap natural gas in the United States has been the revolutionary progress in the science of shale; which allowed for prodigious supply growth.

It seems as if at least temporarily that engine of growth is

stalling …

If we are right then US natural gas markets may find the kind of fundamentals support that we have not seen in years …

Since 2009 we have learned that to question the duration of stupendous supply growth was wrong; since December however things are pointing south

Source: Credit Suisse Research, DoE Energy Information Agency

-4

0

4

8

12

16

20

24

60

65

70

75

80

85

90

95


Growth YoY (rhs)

Gross Gas Withdrawal (Supply)

Projected

0

2

4

6

8

10

0

10

20

30

40

50


Growth MoM (3 mma, rhs)

Gas Production from Shale

Growth YoY (rhs)

Reported gross natural gas withdrawals through February (Bcf/d) Reported gross natural gas withdrawals through February (Bcf/d)

94

In Texas, the 32% ytd plunge in the number of rigs drilling (all types of rigs,

drilling both gas and oil), will we think leave a mark on the gross gas

production profile, which includes conventional, shale and associated gas.

But the experience in the Haynesville (which fell from star status with a thud

once the Marcellus was proved up late last decade) indicates a meaningfully

longer lag time between a sharp cut in activity and the consequent

production response

In Texas that lag in early 2009 was three months; the much smaller ‘drilling

recession’ of 2012 took effect fully six months later; in the Haynesville the

two year long lag resulted from the interplay of a multitude of forces that

had kept the rig count high through 2010

It’s unclear as yet whether in the Marcellus the rig count will decline much

further, or what will be the impact from the 15% drop in rigs since

December. We project slower growth but no rolling over of its production.

Some think that a lesson learned in the shale revolution is that rig-counts do

not matter. Texas gas production suggests that ‘lesson’ does not always apply Rig counts patently affected Haynesvil le production, albeit with a very long

lag time, about two years from peak activity in early -2010

Why We Have a Little More Confidence in Our Supply Projections A daring thought: Rig counts do matter … “Back in the Day” the effect of a falling rig-count was more direct. But clearly, if the rig counts fall far enough, there will be an effect, it does take longer


The Marcellus rig-count peaked in early 2012, but pad dril l ing and other gains

have kept production rising -- new infrastructure fi l ls very quickly (Bcf/ d)

-

2

4

6

8

10

12

-

50

100

150

200

250

300


All Rigs (lhs)

Gas production (Bcf/d, rhs) 14

16

18

20

22

100

300

500

700

900

1,100

1,300

1,500

1,700


All oil & gas rigs (lhs)

State of Texas dry gas production (rhs, Bdf/d)

-

2

4

6

8

10

12

14

16

18

-

20

40

60

80

100

120

140

160

Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15

All Rigs (lhs)

Gas production (Bcf/d, rhs)

95

The most important forecast component is the year-over-year growth of dry gas

production, which we project will decelerate from 5.4 Bcf/d in April to 0.5 Bcf/d

in October; thus averaging 2.6 Bcf/d this injection season.

The shifts in trade are in line with recent trends: Imports from Canada should fall

-0.4 Bcf/d; Exports to Mexico rise by +0.3 Bcf/d.

We plugged in -0.2 Bcf for the LNG component to reflect a 1 Bcf/d jump in

exports in October – which even if a tanker does not leave, will be a drain on

supply or a diversion from storage just to fill and test facilities

The key demand-variable gas use in power generation

Storage is near normal at end winter, leaving less room to fi l l this summer

With Decelerating Supply Growth, We Model Storage Fill of 3.8 Tcf

Our residual of underlying fundamentals next summer is more bullish than most

To model end of injection-season storage fill, we assess the YoY shifts in the individual components of supply and demand (including trade) for the

period March through October. Summing these shifts yields a one number residual of the underlying YoY difference in Bcf/d, which is either negative

(bullish natural gas prices) or positive (bearish natural gas prices).

We then use a history of weekly degree day totals for each of the last 15 injection seasons, which yields weather driven injection tracks. We eliminate the

extremes to either end and take the average of the remaining thirteen as our central case, or weather normalized forecast for end of season storage.

Source: DoE Energy Information Agency, Bloomberg, Credit Suisse Research

We model a -1.4 Bcf/ d residual, which is the sum of the underlying changes

in supply and demand, and yields a below consensus range of weather

dependent storage tracks (15 years of summer weather history; Bcf)

3778

500

1000

1500

2000

2500

3000

3500

4000

Oct-14 Dec-14 Feb-15 Apr-15 Jun-15 Aug-15 Oct-15

10 yr range

2015e

2014-2015

10 yr avg

2013-2014

1,200

1,600

2,000

2,400

2,800

3,200

3,600

4,000

Apr May May Jun Jul Aug Sep Oct

Summer range Series1

(yoy in Bcf/d) CS Base Case

Production 2.6

Imports/(exports)

LNG -0.2

Mex Exports -0.3

Canada -0.4

Demand

Power Gen 2.1

Industrial 0.8

Other 0.2

"Residual" (1.4)

Summer 2015 Residual

3847

96

2016 2015 Key Drivers of That Greater Gas Demand From Power Generation

Source: Platts, SNL Financial, Company Data, Credit Suisse estimates

-

500

1,000

1,500

2,000

2,500

New Gas Demand RetiredCoal

NuclearShift

NewWind

NewSolar

NetChange

Ch

ange

in

Nat

Gas

Co

nsu

mp

tio

n

(mm

cf/d

ay)

Net Change +1,501 mmcf/d

+ 629

+ 577

+ 937

- 517

+ 91

- 216

-

500

1,000

1,500

2,000

2,500

New Gas Demand RetiredCoal

New Wind New Solar NetChange

Ch

ange

in

Nat

Gas

Co

nsu

mp

tio

n

(mm

cf/d

ay)

Net Change +1,583 mmcf/d

+ 427

+ 582

+ 1,216

- 465- 176

Since we model everything on the power demand side on a monthly

basis as well, we can report that in the second quarter our yoy

power-gen demand growth averages 1.5 Bcf/d.

That is less than the in the first quarter: for which our model had

estimated +1.8 Bcf/d growth, while the actual (low price assisted 2.5

Bcf/d actual increase.

In the second half of the injection seasons , we project that demand

growth accelerates to a 2.6 Bcf/d (yoy) pace.

Drivers of that acceleration include the timing of coal-fired power-plant

retirements and easy yoy weather comps.

You probably recognize the ‘waterfall’ diagrams above from our mid-winter

update note. The green bar for 2015 does not correspond precisely with the

‘residual’ of our storage projection model, which covers the months April

through October, rather than a calendar year.

In addition, we continually update the data and assumptions behind the

diagrams. In fact, we have shaved the impact of coal retirement by ~150

mmcf/d equivalent to adjust for timing and utilization rates.

The diagram remains valid in terms of the rough share of the different

variables affecting underlying shifts in demand for gas from power

Implied in our +2.1 Bcf/d power-gen component of the yoy differences in this

injection season is also our price forecast

So if prices were to fall well below those quarter averages, power demand would

rise, and vice versa (all else equal)

97

US Natural Gas: Simple supply/demand balance

(Data through January & Forecasts)

(Bcfd) 2010 2011 2012 Q1/2013 Q2/2013 Q3/2013 Q4/2013 2013 Q1/2014 Q2/2014 Q3/2014 Q4/2014 2014 Q1/2015 Q2/2015 Q3/2015 Q4/2015 2015

Dry Gas Production* 58.4 62.7 65.7 65.6 66.1 67.4 67.6 66.7 67.8 69.3 71.3 73.3 70.4 73.7 73.5 73.0 72.4 73.1

Conventional** 45.0 43.7 43.1 42.8 41.0 40.3 40.6 41.2 42.2 40.6 38.9 41.9 40.9 41.2 40.7 39.8 39.0 40.2

Offshore (GOM)** 6.2 5.0 4.1 3.9 3.6 3.5 3.4 3.6 3.3 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4

Unconventional** 22.3 29.4 33.5 35.6 37.0 38.1 39.0 37.4 40.4 42.2 44.6 46.0 43.3 47.0 47.2 47.7 47.8 47.4

Barnett 5.0 5.9 6.0 5.8 5.5 5.3 5.2 5.5 5.3 5.2 5.0 4.9 5.1 4.7 4.7 4.5 4.4 4.6

Cana-Woodford 1.4 1.2 1.3 1.2 1.2 1.2 1.2 1.2 1.2 1.1 1.1 1.1 1.1 1.1 1.0 1.0 1.0 1.0

Eagle Ford 0.3 1.1 2.3 3.5 3.9 4.3 4.5 4.1 4.8 5.1 5.3 5.6 5.2 5.5 5.6 5.6 5.7 5.6

Fayetteville 2.1 2.6 2.7 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.7 2.6 2.6 2.7 2.7

Haynesville 4.1 6.7 6.2 5.1 4.7 4.5 4.3 4.7 4.3 4.4 4.8 5.0 4.6 5.0 4.9 4.7 4.7 4.8

Marcellus 1.6 3.8 6.7 8.6 9.8 10.8 11.5 10.2 11.9 12.9 14.0 14.4 13.3 15.4 15.6 15.7 15.8 15.6

Mississippian 0.3 0.5 0.7 0.9 0.9 0.9 1.0 0.9 1.0 1.0 1.0 1.1 1.0 1.1 1.1 1.2 1.2 1.1

Denver-Julesburg 0.8 0.8 0.8 0.7 0.7 0.7 0.6 0.7 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.5 0.6

Niobrara 0.0 0.0 0.2 0.2 0.3 0.2 0.3 0.2 0.3 0.4 0.4 0.5 0.4 0.5 0.6 0.6 0.7 0.6

Permian 4.6 4.3 4.4 4.7 4.8 4.9 5.0 4.8 5.4 5.6 5.6 5.8 5.6 5.9 6.2 6.3 6.5 6.2

Granite Wash 2.2 2.4 2.2 2.1 2.1 2.2 2.2 2.1 2.2 2.1 1.9 1.8 2.0 1.8 1.7 1.6 1.6 1.7

Utica 0.0 0.0 0.0 0.1 0.2 0.3 0.5 0.3 0.7 1.1 2.0 2.5 1.6 2.7 2.5 3.2 3.0 2.8

Canadian Imports (Net) 7.0 6.0 5.4 5.1 4.9 5.2 5.4 5.1 5.6 4.6 4.8 5.4 5.1 5.1 4.3 4.6 5.1 4.8

Mexican Exports (Net) -0.8 -1.4 -1.7 -1.8 -1.9 -1.9 -1.6 -1.8 -1.8 -2.0 -2.2 -1.9 -2.0 -2.1 -2.3 -2.4 -2.2 -2.3

LNG Imports (Net) 1.0 0.8 0.4 0.4 0.2 0.4 0.1 0.3 0.1 0.2 0.1 0.1 0.1 0.1 0.1 0.0 -1.0 -0.2

Total Supply 65.5 68.1 69.8 69.2 69.3 71.1 71.5 70.3 71.7 72.1 74.0 76.9 73.7 76.8 75.6 75.3 74.2 75.5

Industrial 18.7 19.2 19.8 21.7 19.3 18.9 21.4 20.3 22.9 20.0 19.7 21.3 21.0 23.4 20.8 20.4 22.0 21.6

Electric Power 20.2 20.7 24.9 19.9 21.0 27.7 20.6 22.3 19.7 21.1 27.3 21.1 22.3 22.2 22.7 30.0 23.1 24.5

Res/Comm 21.7 21.7 19.3 39.9 13.7 8.2 28.4 22.5 45.2 13.7 8.3 26.7 23.5 37.6 13.1 7.4 27.7 21.4

Other (Lease Fuel, Pipeline Distribution) 5.5 5.6 5.9 7.0 6.1 6.2 6.7 6.5 7.3 6.3 6.5 7.1 6.8 7.6 6.5 6.7 7.3 7.0

Total Demand 66.1 67.1 69.8 88.6 60.0 61.0 77.2 71.7 95.2 61.2 61.7 76.2 73.6 90.7 63.0 64.4 80.0 74.6

*Dry gas production = gross gas production - extraction loss -

processing shrink

**Conventional, Offshore (GOM) and Unconventional are in

gross bcf/d and won't sum to dry gas production

Source: US Department of Energy, Credit Suisse Research

98

… there should be easily enough low cost gas to meet demand

Our old supply cost curve to 2020: a string of question marks, but …

* Supply cost breakeven calculation assumes $90/b oil price

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

-5.6 -2.8 0.0 2.8 5.6 8.4 11.2 14.0 16.8 19.6

NY

ME

X B

rea

ke

ven

fo

r 1

5%

A

TA

X IR

R*

Cumulative production growth 2013-2020 (Bcf/d)

Needed to make up for base declines in conventional and GOM production

? ?

?

Upside risk to supply estimates for low cost-emerging shale plays?

Downside risks to breakeven costs for older shale plays once exploration resumes with higher natural gas prices?

Mississippian NE (dry) Marcellus Niobrara

Utica Eagle Ford Fayetteville

SW (rich) Marcellus Granite Wash Barnett

Permian Cana Woodford Haynesville

? ?


Global LNG: Linking Regional Markets and Often, Gas to Oil

100

Typical LNG Scheme

In order to transport gas, need pipelines or

liquefaction

Liquefaction is expensive

LNG needs dedicated shipping (insulated)

LNG then needs to be “regassed” into usable

natural gas in the end-market

Companies experimenting with LNG vehicles –

which would have LNG instead of gasoline.

Source: Cheniere

101

Liquefied Natural Gas (LNG)

Liquefied Natural Gas (LNG) is natural gas (methane) that is chilled to liquid form.

Natural Gas as a liquid occupies 1/600th of the space versus ambient gas, so it can then be

transported.

LNG can be transported by ship over vast distances, and by truck locally

Source: LNG One World

102

LNG: Industry Overview

LNG is exported from regions that have an abundant surplus supply

of natural gas, and often no local market.

LNG facilities are highly capital intensive ($5-10B) and LNG vessels

are $200-300MM each. Costs can vary widely by project – e.g. off

(on)-shore

While most LNG projects operate under long-term contracts (20-25

years), there is a growing spot market of ~5-6 Bcf/d.

Spot shipments are delivered to regions with the highest netback

prices (i.e., offer the highest bids for LNG cargoes).

Contracted import prices are often based on a oil-indexed contract

(such as Japanese Crude Cocktail [JCC]).

Regasification

Source: Statoil, www.oilonline.com

Liquefaction Transport

103

LNG: Liquefaction

Liquefaction is the process by which natural gas is converted to liquid form.

Methane gas is piped to a liquefaction facility where it is chilled to -260°F, at which point the vapor

condenses to liquid.

The liquefied gas is then loaded on to a carrier and transported to import markets.

Construction of a liquefaction facility can take five to seven years.

Key LNG Supply Markets: Pacific Basin (Australia, Indonesia, Malaysia), Atlantic Basin (Algeria, Nigeria, Trinidad), and Middle East (Qatar, Egypt, Oman).

Source: Statoil

104

LNG: Regasification

Imported LNG is received as shipments at terminals with regasification (“regas” ) capabilities.

Regasification involves bringing natural gas back to its gaseous form through thermal energy. The gas

is then stored and distributed to local end-users through pipelines.

Key Import Markets: Asia (Japan, Korea, Taiwan, India, China), Europe (U.K., Spain, Belgium) and U.S. (bidder of last resort). New markets are emerging in Southeast Asia, Latin America and the

Middle East.

Source: Federal Energy Regulatory Commission

105

LNG: Major Importing Countries – Japan

Japan is currently the largest importer of LNG globally, importing 9.0 Bcf/d in 2010 as the country has few domestic means to satisfy natural gas demand.

Imports primarily come from Australia, Indonesia and Malaysia.

Total regasification capacity is currently approximately 25 Bcf/d with one terminal (Sodegaura) capable of importing 3.9 Bcf/d, one of the largest in the world.

Source: California Energy Commission

106

LNG: Major Importing Countries – South Korea

South Korea is currently the second largest importer of LNG globally, importing 4.3 Bcf/d in 2010.

Current regasification capacity is roughly 10 Bcf/d with imports primarily from Qatar, Indonesia and Malaysia.

Similar to Japan, Korea has minimal domestic natural gas production and relies on LNG to fill the gap.

Source: www.hydrocarbons-technology.com

107

LNG: Major Exporting Countries – Qatar

Qatar is currently the largest exporter of LNG globally, exporting 7.3 Bcf/d in 2010.

Liquefaction capacity currently stands at ~10.2 Bcf/d and should continue to grow as two recently completed projects have yet to reach plateau.

Qatar exports gas to most markets including Japan, Korea, Spain, U.K. and the U.S.

Exported gas is primarily sourced from the large North Field, which has estimated recoverable natural

gas reserves of more than 900 Tcf.

Source: www.hydrocarbons-technology.com

108

LNG: Major Exporting Countries – Indonesia

Indonesia is currently the second largest exporter of LNG globally, exporting 3.0 Bcf/d in 2010.

Liquefaction capacity currently stands at ~4.2 Bcf/d with the majority (3 Bcf/d) from the large Bontang

LNG facility that includes eight processing trains.

Indonesia plans to reduce future LNG exports from traditional LNG trains due to increasing domestic

demand for gas, but recently granted project approval to Tangguh to build a third train, which should

increase capacity by 0.6 Bcf/d.

Like Australia, Indonesia primarily exports LNG to Asian markets.

Source: www.aceproject.org

109

LNG: Major Exporting Countries – Australia

Australia is currently the fourth largest exporter of LNG globally, exporting 2.5 Bcf/d in 2010.

While liquefaction capacity only stands at ~3.2 Bcf/d currently, future projects are set to raise

liquefaction capacity to 10-15 Bcf/d by 2020.

Australia primarily exports its gas to Asian markets such as Japan, China and Korea.

The $37B, 2.0 Bcf/d Gorgon LNG project is currently being developed with first production expected

in 2014 or 2015. Gorgon will be Australia’s largest resources project.

Source: www.lngpedia.com

110

Key LNG Buyers (Asia/Europe) and Producers

0 20 40 60 80 100 120 140

Thailand

Canada

Other S. & Cent America

Brazil

Chile

Other Europe and Eurasia

Belgium

Middle East

Mexico

United States

Argentina

Italy

Turkey

France

United Kingdom

Taiwan

China

India

Spain

South Korea

Japan

LNG Buyers, 2012

0 20 40 60 80 100 120

Brazil

U.S. *

Other Europe*

Norway

Equatorial Guinea

Peru

Egypt

Yemen

United Arab Emirates

Brunei

Oman

Russian Federation

Algeria

Trinidad & Tobago

Indonesia

Nigeria

Australia

Malaysia

Qatar

LNG Producers, 2012

Source: BG

111

LNG Plants Are Capital Intensive

Source: Cheniere

112

Global Gas Prices: Asia LNG; Europe NBP; US Henry Hub

Source: BG

113

Rising Gas Demand in Asia; Will Shale Gas Spoil the Party?

So

urc

e: P

etro

bra

s

Source: BG

114

LNG Markets: Tight Until 2017-2018

0

20

40

60

80

100

0

20

40

60

80

100

2013 2014 2015 2016 2017 2018 2019 2020

Korea Taiwan Singapore China India SE Asia

AU US Canada BG SP port E Africa

(mtpa) (mtpa)

Supply:

Demand:

APAC contestable demand vs. un-contracted supply

Source: Credit Suisse estimates

115

LNG Markets: More Supply Needed Longer Term

Source: CVX

116

Japan Is Critical: LNG Buying Scenarios

Japan > 15MTpa LONG LNG in 2018

If all optioned supply sanctions and arrives on

Japanese shores

Based on 15 nuclear plant fleet from 2016

2020E: 15% of J demand from US

IF all optioned projects sanction

Japanese buyers already re-selling US avails:

Chubu Electric & Osaka Gas said to have re-

sold half of their off-take from Freeport LNG to

LNG buyers in Europe

In Japanese interests to make the US supply

appear as large as possible 60

65

70

75

80

85

90

95

100

2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

High case Base case Low Case

MTpa

Japan: LNG demand under 3 nuclear re-start

scenarios

Japan: un-contracted demand history /

CS forecast

Source: FACTS Global Energy, Credit Suisse estimates

117

LNG Markets: Substantial Supply Potential from US

US Project List Competing for Buyers


118

Significant Premium to Henry Hub Required for US LNG Exports

Source: BG

119

Planned Commercial Offtakers for US LNG Projects


120

Significant Gas Discoveries in Mozambique

So

urc

e: P

etro

bra

s

Source: APC

121

LNG Update – Key Takeaways

Australia – later than advertised

Greenfield project certainty declines in new

crude price world

– We radically reduce our ‘possible’ category

All CS ‘possible’ projects required by mid

2020’s

– 50% of CS ‘possible’ in US

– Failure to sanction US projects would drive

buyer focus in more challenged ‘speculative’

category

US no longer has compelling price proposition

Key buyer increasing focus on energy security

– Japan concerned about South China Sea

delivery and geopolitical interruption risk

– Likely pivot away from East Africa / ME and

toward supply ‘zone’ of AU / PNG

Asian price: one stasis replaces another

– Last 3 years focused on ‘HH’ pricing, now

redundant

– Buyers & sellers will investigate multiple

pricing ideas, floors (and ceilings), higher

constants, ‘new’ S curves

– In reality unlikely either side will commit until

crude price settles

Interim solution? More frequent price

reviews or price at 1st LNG…

122

Greenfield Projects Less Robust in Low Crude Price Environment

‘Full-blown’ FLNG – not in this

environment….

Abadi / Browse

Will FLNG ‘lite’ leapfrog its gold plated

brethren?

Cameroon / Ophir EG

Canada cost re-cycling

PacNorthWest

CVX Kitimat on ‘go slow’

Lavaca Bay – the 1st US casualty?

PNG the attractive postcode in Asia

We move multiple projects from ‘possible’ to ‘speculative’

0

20

40

60

80

100

120

140

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Current Previous

MTpa

US Lake Charles 2019

US Elba Island 2019

US Corpus Christi 2019

US Sabine Pass T5 2019

Papua New Guinea 3rd train in PNG 2020

Canada Shell LNG Canada 2021

Papua New Guinea Elk Antelope 2021

Mozambique Mozambique FLNG 2021

Mozambique Onshore 2022

CS: ‘Possible’ project list

CS: previous vs current ‘Possible’ project

volumes

Source: Credit Suisse Estimates

123

‘Possible’ becomes Necessary…

0

100

200

300

400

500

600

700

2010 2011 2012 20132014 2015 2016 2017 2018 20192020 20212022 20232024 2025

MTPA

Producing Construction Possible

Speculative Demand low Demand base

0

100

200

300

400

500

600

700

2010 2011 2012 20132014 2015 2016 2017 2018 20192020 20212022 20232024 2025

MTPA

Producing Construction Possible

Speculative Demand low Demand base

Current Supply / Demand Balance

-20

-10

0

10

20

30

40

50

60

-20

-10

0

10

20

30

40

50

60

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Current Previous

MTpa

-35

-30

-25

-20

-15

-10

-5

0

5

10

15

20

25

30

35

-35

-30

-25

-20

-15

-10

-5

0

5

10

15

20

25

30

35

2018 2019 2020 2021 2022 2023 2024 2025

Current Current minus US

MTpaMTpa

Previous Supply / Demand Balance

Previous / Current Producing + Under

Construction + Possible vs Demand

CS: Current Producing + Under

Construction + Possible vs Demand (with

and without US projects)


124

LNG Project: Breakeven Economics

Only East Africa and PNG green-fields ‘work’ in new crude price reality

0

5

10

15

20

25

US$mmBtu

New LNG price range (CS forecast)

Source: Wood Mackenzie, Credit Suisse Estimates

125

US Supply no Longer has Compelling Price Point in Asia or Europe

But 50% of our revised ‘possible’ category are US green-fields

0

2

4

6

8

10

12

14

16

Sabine Pass T5 Corpus Christi Lake Charles Elba Island

Capacity Pre-sold

MTpa

As yet unsanctioned US projects capacity vs pre-sales

0

10

20

30

40

50

60

70

2018 2019 2020 2021 2022 2023 2024 2025

Lake Charles Elba Island Sabine Pass T5 Corpus Christi Non US

MTpa

CS ‘Possible’ category – US and non US


126

US LNG: 16MTpa Still Looking for a Home…

Own use Portfolio re-sale Comment

Sabine Pass

Kogas 2.8 0.7 0.7 Total on sale

GAIL 3.5

BG 5.5 5 CNOOC deal

GNF 3.5 0.74 Repsol on sale

Cheniere 2

Total own use 6.3

Total portfolio 11.7

Total re-sold 6.44

Available for re-sale 5.26 18

Freeport Own use Portfolio re-sale Comment

BP 4.4 2 CNOOC deal

Chubu 1.1 1.1 1.1 'EU buyer'

Osaka Gas 1.1 1.1 1.1 'EU buyer'

Total own use 2.2

Total portfolio 6.6

Total re-sold 4.2

Available for re-sale 2.4 8.8

Cameron Own use Portfolio re-sale Comment

Mitsubishi 4.1 1 Tepco, Diamond Gas and Tohok E MOUS

Mitsui 4 1.62 Toho and KE SPA, TG SPA TEPCO MoU

GDF 4 1.07 CPC and Tohoku

Total own use 0

Total portfolio 12.1

Total re-sold 3.69


Cove Point Own use Portfolio re-sale Comment

GAIL 2.3

Sumitomo 2.3 2.2 TG and KE - SPA

Total own use 2.3

Total portfolio 2.3

Total re-sold 2.2


0

10

20

30

40

50

Sabine Pass Freeport Cameron Cove Point Total

Own use Portfolio already sold Portfolio available for re-sale

MTpa


127

CS: Possible & Speculative Project List

Buyers may have to support more speculative projects

US Lake Charles 2019

US Elba Island 2019

US Corpus Christi 2019


Papua New Guinea 3rd train in PNG 2020

Canada Shell LNG Canada 2021

Papua New Guinea Elk Antelope 2021

Mozambique Mozambique FLNG 2021

Mozambique Onshore 2022

Cameroon Cameroon LNG 2020

Canada BC LNG Export 2020

Indonesia Tangguh Expansion T3 2020

Russia Sakhalin 2 T3 2020


Australia Browse LNG 2021

Indonesia Abadi FLNG 2021

US Golden Pass 2021

Russia Far East LNG 2021

Australia Sunrise LNG 2021

Canada Pacific Northwest LNG 2021

Canada Kitimat LNG 2021

Australia Gorgon LNG T4 2021

Mozambique Onshore 4 train 2022

Australia Wheatstone T3 2022

Nigeria Brass LNG 2022

Nigeria Olokola LNG 2022

Tanzania Tanzania LNG 2022

US Jordan Cove 2022

Australia Pluto LNG T2 2023

Australia Scarborough LNG 2023

Iran Iran LNG 2023

Nigeria NLNG Train 7 2023

Angola Angola LNG T2 2023

Cyprus Aphrodite 2023

Australia Fisherman's Landing 2023

US Alaska Valdez 2023

Canada Prince Rupert LNG 2023

Russia Baltic LNG 2023

Australia QCLNG Train 3 2024

Canada Goldboro 2024

Canada Woodfibre LNG 2024

Canada WCC (Exxon) 2024

Australia Gorgon LNG T5 2024

Norway Snøhvit T2 2024

Israel Leviathan 2025

Russia Vladivostok LNG 2025

Equatorial GuineaEG LNG Train 2 2026

Iraq Shell Iraq LNG 2026

Australia Bonaparte FLNG 2028

Russia Shtokman 2028

CS: ‘Speculative’ project list

CS: ‘Possible’ project list


128

Demand: Japan Re-emphasizing Energy Security

60% of Japanese LNG travels through the South China Sea

– A choke point too far? (Hormuz, Malacca, SCS…)

Papua New Guinea an advantaged supply point from an energy security perspective

– And cost to develop….

Japan likely ‘sated’ with US supply already (although Alaska LNG could be a wildcard…)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1975 1985 1995 2005 2015 2025

Indonesia Malaysia Australia PNG US

Canada E Africa Qatar Other / spot

Japan – historic LNG supply distribution & CS

2025 forecast South China Sea – LNG trade flows 2011

Source: EIA, Cedigas, PFC Energy, Credit Suisse estimates

129

Price I – Au revoir Henry Hub pricing

30MT (3.95Bcf/d) commenced construction in 2014

Cameron, Cove Point and Freeport join Sabine Pass in the construction phase for US liquefaction capacity

2000 – 2010 US sourced gas would have been more expensive than Japanese landed prices

2010 – 2014: the HH price ‘gap’ opened, on average US$5.4/mmBtu

Recent crude price correction has closed the HH price ‘gap’ in Asia

The US still provides a new form of supply flexibility to Asian buyers – interrupt ability (at a cost), but the price advantage has disappeared

Japan Delivered ex Ship prices vs. HH vs. HH

(theoretical) into Asia

Overall Japan LNG landed prices vs. HH North Asia

equivalent price

Source: EIA, FACTS Global Energy, CS estimates

130

Back to the Whiteboard

Note the Axis – stops at $80/bbl!

Price floor, wouldn’t work for mid-level break-even projects, but a possibility for PNG / East

Africa

‘Mid’ floor @ $11.5, ‘low’ floor @ $7.5/mmBtu – 5 slope assumed above $60/bbl

Price Floors

130

Typical JCC contract vs Henry Hub in Asia vs price floors Typical JCC contract vs Henry Hub in Asia

0

2

4

6

8

10

12

14

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77

'mid' Floor Typical JCC HH 'low' floor

US$/mmBtu

US$/bbl0

2

4

6

8

10

12

14

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77

Typical JCC contract HH in Asia

US$/mmBtu

US$/bbl

Note: JCC is a 14 slope, $0.5 constant, $1 shipping example, Henry Hub is $3HH * 1.15 + 3(liquefy) + 3 (shipping)


131

Higher constant: in this example we raised the constant to $4/mmbtu and softened the straight

line to a 9 slope (52% correlation)

Pivot point at current crude price

S curve

S curve I – using 2016 futures price as the fulcrum

Unattractive for the buyer

S curve II – using spot as the fulcrum

Still not particularly attractive to the buyer

Back to the Whiteboard

Higher Constants / S’s…

131

0

2

4

6

8

10

12

14

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77

Typical JCC HH High constant

US$/mmBtu

US$/bbl0

2

4

6

8

10

12

14

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77

Typical JCC HH Futures 'S' Spot 'S'

US$/mmBtu

US$/bbl

Typical JCC contract vs Henry Hub in Asia vs S curves Typical JCC contract vs Henry Hub in Asia vs a high

constant

Note: JCC is a 14 slope, $0.5 constant, $1 shipping example, Henry Hub is $3HH * 1.15 + 3(liquefy) + 3 (shipping)


132

Price – Final Thought

Hard to find ‘common ground’ when crude go-forward is so uncertain

Defer the decision?

Brownfield - more frequent price review?

Greenfield - set the price at 1st cargo?

0

2

4

6

8

10

12

14

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77

Typical JCC

1st gen S curve

$15 - $25/bbl

2nd gen S curve

$40 - $90 ish/bbl

'16 Futures S curve

$45 - $75/bbl

Spot S curve

$38 - $63/bbl

US$/mmBtu

US$/bbl


133

CS: Near-term LNG pricing in Asia

Recent S curves likely don’t offer downside protection Price stasis as crude price finds its new trading range

0

2

4

6

8

10

12

14

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77

14 slope, straight Recent S

US$/mmBtu

US$/bbl

CS 1Q '15

Brent forecastCS 4Q '15

Brent forecast

6

8

10

12

14

16

18

Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Sep-16 Jan-17

Japan overall landed price HH @ 3.0 HH @ 4.5

US$/mmBtu

CS N Asia LNG price basis current Brent

price forecast

Typical JCC straight line / S curve vs CS 2105

1 & 4Q Brent forecast


134

LNG Projects

Typically Low Cash Cost Operations

0

5

10

15

20

25

30

35

40

45

All-in pre-tax cash cost ($/bbl)


135

Shell / BG gross and Net Supply Concentrations - Asia

0%

10%

20%

30%

40%

50%

60%

rds gross rdsbg gross rds net rdsbg net0%

10%

20%

30%

40%

50%

60%

70%

rds gross rdsbg gross rds net rdsbg net

Japan Korea

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

rds gross rdsbg gross rds net rdsbg net

China

0%

5%

10%

15%

20%

25%

India

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Singapore


136

RDS / BG share of Greenfield Projects

Lake Charles 14%

Tanzania14%

Elba Island 3%

Shell LNG Canada 16%

Corpus Christi 18%

Sabine Pass T5 6%

3rd train in PNG 5%

Elk Antelope 7%

Mozambique FLNG 3%

Mozambique onshore

14%

Russia Sakhalin 2 T3 4%

Australia Browse

LNG 12%

Indonesia Abadi FLNG 2%

Australia Sunrise LNG 3%

Australia Gorgon T44%

Canada Kitimat LNG

8%

Cameroon Cameroon LNG 3%

Canada BC LNG Export

1%

Indonesia

Tangguh Expansion T3 3%

US Sabine Pass T6 4%

US Golden Pass 13%Russia Far East LNG

4%

Canada Pac NthWest

10%

Mozambique Onshore 4 train 8%

Australia Wheatstone T3 4%

Nigeria Brass LNG 8%

Nigeria Olokola LNG 4%

US Jordan Cove 5%

Possible projects = 47% gross

(33% net)

Speculative projects = 25% gross


An End to the “Oil Age” (and of this primer)

138

Other renewables consumption by region

(Million tonnes oil equivalent) Other renewables share of power generation by

region (Percentage)

Renewables Consumption is Rising Fast and has a Long Runway

Neat trends and milestones

Germany has shifted to around >20% renewables in power generation (think wind)

Solar Costs have fallen and are becoming more competitive in regions with high solar intensity

Strong potential for gas, particularly in coal burning countries e.g. China

Source: BP Statistical Review of World Energy

139

Levelized Cost of Energy, Improvements in Wind and Solar Need Watching


140

Source: McKinsey & Company

Many Ways to Improve Efficiency/Lower GHG Emissions

141


New Transportation Technologies Emerging

142

Source: McKinsey & Company

Strong Demand Outlook for Natural Gas Vehicles

143

Automotive Battery Market Volumes and Cost Reduction Potential

Source: Credit Suisse Estimates, Marklines, Company data

144

Economics: Electric Vehicles


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