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Copyright 2018 Cornerstone Macro. All rights reserved. This report is prepared exclusively for the use of Cornerstone Macro institutional clients and may not be redistributed, retransmitted or disclosed, in whole or part, or in any form or manner, without the express written consent of Cornerstone Macro.

Energy Macro: Oil & US Natural Gas

CSIS Shale Workshop, Washington DC, 27 February 2018

Triangulating the Business of US Shale:A Profitable Growth Story

1

FULL DISCLOSURE: WE’RE CONSTRUCTIVE ON OIL FUNDAMENTALS

Our core view on 2018• Oil has been trending higher, driven by a persistent global supply deficit• Sensibly, oil should stay close to $60 (i.e. in a perfect market with good short term reaction functions,

supply growth accelerates & demand growth decelerates once oil prices exceed the ‘goldilocks’ level)• The wonderful world of Oil is far from perfect – so oil prices most likely will overshoot moreEffectively, Opec is contributing to this overshoot (It alone can add to supply immediately, but says it won’t.)• Next up are the US shale producers• And thus this year should be US Centric

o Key question: Will US oil production grow too much or too littleo Answer = both too little in the near term, then too much for another spell

Recurring overshoot in 2018 is all the more likely since in the background:• Oil demand growth should benefit from accelerating growth in most of the world’s big economies• And since it seems that indeed Nopexus (non-Opec ex US) is NOT growing

Risks (ordered subjectively by likelihood, but not exhaustive):

1. Accelerating demand growth U (under appreciated)

2. Conflict(s) leading to supply disruption(s) and/or loss(es) U3. Greater declines in mature oil provinces U4. US oil production outperforms our (already relatively) high forecasts O (over appreciated)

5. Opec discord resurfaces, incriminations fly, price war ensues O6. Global economic growth decelerates significantly in 2018-’19 -

2

OIL’S DOWN CYCLE: IT WAS (AND IS NEARLY) ENTIRELY ABOUT SUPPLYFundamentals matter, even in an age of machines: After the 2013-’14 supply surge tipped balances into surplusand prices collapsed, growth momentum was lost only in H2 of 2015; surpluses began to shrink and inventoriesfinally begin their trek toward normal in H2 2016. But a large persistent supply-deficit emerged only last year.

88

90

92

94

96

98

100

102

104

Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

Mb/d Global Supply and Demand (3mma)

supply (3 mma)demand (3 mma)

2,000

2,200

2,400

2,600

2,800

3,000

3,200mbs OECD Commercial Inventories

OECD commercial inventory

Opec target

Source: IEA, JODI, BP, Rystad Energy, Petrologistics, Country Data, The BLOOMBERG PROFESSIONALTM Service, CSM Research

3

SUPPLY / DEMAND DATA IN A BALANCE THAT BROADLY WORKS

-2.5

-2.0

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

3.0


Mb/d

S/D Balance Surplus and Deficit

s/d implied inventory change (3 mma)

reported inventory change (3 mma)

Even the best numbers on oil demand and supply are of poor quality – they lag, have gaps and are prone torevisions. And they measure the wrong things too. But if a balance consistently broadly balances then itsmessages at the very least paint a useful market background.


52

54

56

58

60

62

64

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

days cover Global Inventory Demand Cover

5 yr range 2010-'14 avg 5 yr avg2016 2017 fcst

Our balances work. They foretell further inventorydraws. Inventory has already drifted below normal.Opec will likely continue to overtighten things.

4

SHAPE SHIFTING OIL-FUTURES: BRENT CURVES “TORQUED” AROUND LAST YEAR

The front of the Brent curve reacts like a whip-end to NT fundamentals

• In 2017, as the global balances shifted into deficit, the short end of the Brent curve pivoted around

Arguably three quarter ($15 of the $47/b to $67) of the H2-2017 price rally was about the NT shape shift

The long end of the curve is about projected marginal cost of supply and has deflated to ~$52-58 since 2014

• We built medium-term scenarios (2020-’22) to frame an outlook for the Brent Curve’s pivot-point (36mthcontract)

We think there is value at the long-end; the market thinks not.

Source: The BLOOMBERG PROFESSIONALTM Service, CSM Research

45

47

49

51

53

55

57

59

61

63

65

67

69

71

1 4 7 10 13 16 19 22 25 28 31 34

$/b

Brent futures

1/30/2018 6/30/2017 1/3/2017

-6%

-5%

-4%

-3%

-2%

-1%

0%

1%

2%

3%

4%

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

$/bShape of the Brent Futures Curve (month 1-6)

2014 2017

backwardation= supply deficit

contango = supply surplus

Big swings in supply/demand fundamentals -> lead to bigswings in inventory -> lead to shifts in the front of thefutures curve. We track structure of mth 1-6 , which arethe best signals on the direction of prompt futures prices.

5

STILL VALID: A KEY MARKET SIGNAL, AND US WEEKLIES

-6

-4

-2

0

2

4

6

8

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

$/b Shape of the Brent Futures Curve (month 1-6)

2013 2014 2017 2018

backwardation= supply deficit

contango = supply surplus

On any given day, oil prices can be jolted for manydifferent reasons, but over time fundamentals matterthe most. So we pay real attention when futurescurves change shape.

IF our view is broadly correct THEN the Brentbackwardation should broadly stay in place this year.

Source: EIA, The BLOOMBERG PROFESSIONALTM Service, CSM Research

0

50

100

150

200

250

300

Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18

US Inventory Surplus to simple 5yr ma

Crude Gasoline Middle Distillate Residual Fuel Oil

Separately, the large nominal surplus of crude oil in theUS inventory should keep on shrinking.

SO, if the backwardation switches to acontango, or the US surplus of inventoryreflates we will get really worried really fast

6

NEAR TERM GLOBAL OIL BALANCE

Source: IEA, JODI, BP, Rystad Energy, Petrologsitics, Country Data, The BLOOMBERG PROFESSIONALTM Service, CSM Research

Global Oil Balances 2014 2015 2016 Q1-'17 Q2-'17 Q3-'17 Q4-'17 2017 Q1-'18 Q2-'18 Q3-'18 Q4-'18 2018 2019

Supply 94.3 97.2 97.7 97.2 97.5 98.4 98.9 98.0 99.4 99.9 100.5 100.5 100.1 102.4

Opec 37.3 38.6 39.8 39.0 39.2 39.9 39.4 39.4 39.4 39.6 39.8 39.7 39.6 40.8

Opec crude 31.3 32.1 33.0 32.4 32.5 33.1 32.7 32.7 32.7 32.9 33.1 33.0 32.9 34.0

yoy -0.3 0.8 0.9 -0.3 0.0 0.0 -1.0 -0.3 0.3 0.3 -0.1 0.3 0.2 1.1

Non Opec 54.4 55.9 55.2 55.5 55.4 55.8 56.8 55.9 57.3 57.5 57.9 58.1 57.7 58.8

yoy 2.3 1.5 -0.7 0.0 0.9 0.8 1.0 0.7 1.8 2.1 2.1 1.3 1.8 1.1

US crude 8.8 9.4 8.9 9.0 9.1 9.3 9.9 9.3 10.4 10.6 10.7 10.9 10.7 11.4

yoy 1.3 0.7 -0.6 -0.2 0.3 0.6 1.1 0.5 1.4 1.5 1.4 1.0 1.3 0.8

Demand 93.3 95.3 97.0 97.1 98.8 99.7 99.2 98.7 99.2 100.5 101.5 100.9 100.5 102.2

yoy % 1.0% 2.1% 1.8% 1.2% 2.2% 1.9% 1.7% 1.8% 2.2% 1.7% 1.8% 1.7% 1.8% 1.6%

Non-OECD 47.6 48.9 50.1 50.1 51.7 52.1 51.3 51.3 51.5 53.1 53.4 52.6 52.6 53.9

yoy 1.3 1.3 1.3 1.0 1.2 1.5 1.1 1.2 1.4 1.3 1.4 1.3 1.3 1.3

OECD 45.8 46.4 46.9 47.0 47.1 47.6 47.9 47.4 47.7 47.4 48.1 48.4 47.9 48.3

yoy -0.4 0.7 0.5 0.2 0.9 0.3 0.5 0.5 0.7 0.4 0.4 0.4 0.5 0.4

Implied Inventory Change 1.0 1.9 0.7 0.1 -1.3 -1.3 -0.4 -0.7 0.2 -0.5 -1.0 -0.4 -0.4 0.3

Reported Inventory Change 1.0 1.7 0.5 1.4 -0.3 -0.9 -2.1 -0.5

52

54

56

58

60

62

64


days cover Global Inventory Demand Cover

5 yr range 2010-'14 avg 5 yr avg2016 2017 fcst

4500

5000

5500

6000

6500


mbs global inventories ex govt stocks

5 yr range 2010-2014 avg 5 yr avg

2016 2017 fcst

7

0

25

50

75

100

125

150

J-99 J-01 J-03 J-05 J-07 J-09 J-11 J-13 J-15 J-17

$/b Brent generic 36 month futures price

0

25

50

75

100

125

150

J-92 J-94 J-96 J-98 J-00 J-02 J-04 J-06 J-08 J-10 J-12 J-14 J-16 J-18

$/b WTI 36

PRICE ANCHORS: LONG DATED FUTURES / EXPECTATIONS … BREAK OUT (?)Far out futures prices tend to reflect “new normal”

In the bad old days (1986 through late-’03) $20/b was the normo Properly pricing markets emerged only in the 1980so Opec had strenuously held on to official prices in the low $30s for

too long from the late 1970s through the early 1980s. Stagflation and recessions were seared in memory: “$30 oil = unsustainable”

Spare capacity is drained, costs inflate the anchor comes into playo After demand growth drains spare capacity from the system

[Opec had 17 Mb/d of spare capacity in 1986, today it’s less than 2.0 Mb/d, similar to the level reached in 2003] the EM supercycle of the last decade drags expectations for oil prices up as well

o Liquidity of long-dated oil futures grows tenfold, as prices inflate to near $30 in late 2003; $40 in late ’04; and $60 in late ’05.

o Fears of scarcity and system bottlenecks created a classic squeeze and a run up through $140/b by the middle of 2008

High prices post GFC (zero-spare capacity, demand growth and the ‘Arab Spring’) which incubates the US Shale boom and its busto Prices subsequently collapse, and within a few quarters US

growth momentum fades, US production begins to fall (mom). The other measurable effect of low prices in the shorter run was the sharp downturn in industry spend outside the US.

Current new normal is a one way “Tesla” and “abundance” tradeo Without spare capacity and given looming bottle necks upside

risk is creeping back into conversations and debateso Short-cycle supply governs LT upside potential [cap at $70, or so]


8

FIVE YEAR OUTLOOK: SHALE ALONE CANNOT BALANCE THE MARKET AT $60/BIn our central scenario, 2019-20 looks a bit soft. By 2021-22, the picture is more bullish and shale has trouble keeping up with demand growth and Nopexus declines.

Additional Nopexus project sanctions are required (and fast) to balance the market in 2022.

Key assumptions in our central scenario include:• Demand recession in 2020• Opec production rises in 2018-19, then stays roughly flat

as decliners balance growers• No production for the next 5 years from yet to be

sanctioned Non-Opec ex shale new projects• Shale grows ~1.5 Mb/d pa ($60 WTI pace of growth)


-800

-600

-400

-200

0

200

400

600

800

-2.0

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

million barrelsmillion barrels

per day

s/d implied stock change

end year inventorysurplus (rhs)

Central Scenario

million barrels per day 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Call on Shale and FIDs 12.3 15.0 18.1

yoy 0.8 2.6 3.1

Demand 91.1 92.4 93.3 95.3 97.0 98.7 100.5 102.2 102.7 103.9 105.0

yoy 1.2 1.3 1.0 2.0 1.7 1.7 1.8 1.6 0.5 1.2 1.1

Supply 91.6 92.2 94.3 97.2 97.7 98.0 100.1 102.4 103.7 103.9 103.4

yoy 2.3 0.6 2.1 2.9 0.5 0.3 2.1 2.3 1.3 0.2 -0.5

Shale Crude* 2.1 3.0 4.1 4.8 4.5 5.0 6.5 7.5 8.8 10.1 11.2

yoy 0.8 0.9 1.1 0.7 -0.3 0.6 1.5 1.0 1.3 1.3 1.1

Shale NGLs* 2.0 2.2 2.5 2.9 3.1 3.3 3.7 4.0 4.4 4.8 5.1

yoy 0.3 0.2 0.3 0.4 0.1 0.2 0.4 0.3 0.3 0.4 0.4

Non-Opec ex Shale ex FIDs 49.1 49.6 50.5 50.9 50.4 50.3 50.3 50.1 49.5 48.1 46.4

yoy -0.4 0.5 0.9 0.4 -0.5 -0.1 0.0 -0.2 -0.6 -1.4 -1.7

Russia 10.6 10.8 10.8 11.0 11.2 11.2 11.2 11.5 11.7 11.8 12.0

yoy 0.1 0.1 0.1 0.1 0.3 0.0 0.0 0.3 0.2 0.2 0.2

Brazil 2.5 2.5 2.8 3.0 3.0 3.2 3.3 3.5 3.7 3.7 3.6

yoy 0.0 0.0 0.3 0.3 0.0 0.1 0.2 0.2 0.2 0.0 -0.1

Canada 3.7 4.0 4.3 4.4 4.5 4.8 5.0 5.0 5.0 4.9 4.9

yoy 0.2 0.3 0.3 0.1 0.1 0.3 0.3 0.0 0.0 -0.1 0.0

North Sea** 2.9 2.7 2.8 2.9 3.0 3.0 3.1 3.0 2.9 2.8 2.5

yoy -0.3 -0.2 0.0 0.2 0.1 0.0 0.1 -0.1 0.0 -0.1 -0.3

Other LatAm*** 5.0 5.0 4.9 4.7 4.4 4.1 3.9 3.8 3.5 3.2 2.9

yoy 0.0 0.0 0.1 0.0 -0.1 0.1 0.0 0.0 -0.3 -0.3 -0.3

Asia 8.8 8.8 8.9 9.0 8.6 8.3 8.1 7.9 7.6 7.1 6.6

yoy 0.1 0.0 0.1 0.1 -0.3 -0.3 -0.3 -0.2 -0.3 -0.5 -0.5

Africa 1.7 1.7 1.8 1.8 1.7 1.7 1.7 1.7 1.5 1.4 1.3

yoy -0.3 0.0 0.1 0.0 -0.1 0.1 0.0 0.0 -0.1 -0.1 -0.1

Other 13.9 14.1 14.3 14.2 14.0 14.0 14.0 13.7 13.5 13.1 12.7

yoy -0.2 0.2 0.2 -0.1 -0.2 0.0 0.0 -0.3 -0.2 -0.4 -0.3

Opec Crude 32.8 31.6 31.3 32.1 33.0 32.7 32.9 34.0 34.3 34.3 34.0

yoy 1.2 -1.2 -0.3 0.8 0.9 -0.3 0.2 1.1 0.3 0.0 -0.3

Mideast Crude 22.8 22.4 22.6 23.5 24.9 24.7 25.0 26.2 26.6 26.9 27.0

yoy 0.4 -0.4 0.3 0.9 1.4 -0.3 0.3 1.2 0.5 0.3 0.1

Other Crude 10.0 9.3 8.7 8.6 8.1 8.0 7.9 7.8 7.7 7.3 7.0

yoy 0.9 -0.7 -0.6 -0.1 -0.5 -0.1 -0.1 -0.1 -0.2 -0.4 -0.4

Opec NGLs 5.7 5.9 5.9 6.5 6.8 6.7 6.7 6.8 6.8 6.7 6.6

yoy 0.4 0.2 0.1 0.6 0.3 -0.1 0.0 0.1 0.0 0.0 -0.1

inventory (million barrels)

end year level 6,780 6,841 7,208 7,843 8,013 7,837 7,723 7,860 8,228 8,240 7,671

end year surplus**** -54 -56 107 606 514 73 -123 1 288 239 -390

*$60/b WTI; $2.85/MMBtu Henry Hub

**UK and Norway

***Includes Mexico

****Based on commercial inventory demand cover relative to 2010-2014 average

9

MEDIUM TERM SCENARIOS: DEMAND IS KEYIn addition to our central scenario, we consider three alternative scenarios for the 2018-2022 balances.

• In the upper left, Opec production underperforms, balanced by an earlier recession (2019 instead of 2020). The picture is moderately bullish relative to our central scenario.

• In the lower left, demand outperforms and Opec boosts production somewhat to compensate. A large supply deficit opens up and an extremely bullish scenario emerges.

• In the bottom right, demand underperforms by ~800 kb/d on average over 5 years. Markets wind up oversupplied.

-2,000

-1,500

-1,000

-500

0

500

1,000

1,500

-4.0

-3.0

-2.0

-1.0

0.0

1.0

2.0

3.0

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

million barrelsmillion barrels per day



Alt Scenario: Supply Cannot Keep Pace

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0

500

1,000

1,500

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2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

million barrelsmillion barrels

per day



Alt Scenario: Demand Outperforms

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0

500

1,000

1,500

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2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

million barrelsmillion barrels per day



Alt Scenario: Bearish Consensus


10

CSM OIL PRICE FORECAST: NEAR-TERM BASE CASE AND REAL SCENARIOS

Scenario Assumptions

Central case: $60 WTI in 2018-’19 (monthly averages, narrow range)o Extended demand growth -- no recession until 2020 or later;o Opec cohesion and ongoing co-operation from Russia et al;o Shale growth accelerates moderately ~1.0 Mb/d of black oil;o Nopexus flatlines before turning down; as underlying decline rates are no longer offset by new projectso In 2019 further support arises from tightening refining capacity – e.g. IMO

The premium of Brent to WTI widened in H2-2017, and we now think that it will remain relatively wide


annual crude prices quarterly crude prices Brent Scenarios ($/b)

$/b Brent WTI Diff $/b Brent WTI Diff Lo-S Hi-D Cons

2005 55 57 -1 2016 45 43 2

2006 66 66 0 Q1-'17 55 52 3

2007 73 72 0 Q2-'17 51 48 3

2008 99 100 -1 Q3-'17 52 48 4

2009 63 62 1 Q4-'17 61 55 6

2010 80 80 1 2017 55 51 4

2011 111 95 16 Q1-'18e 64 58 6 64 68 60

2012 112 94 18 Q2-'18e 66 60 6 66 70 60

2013 109 98 11 Q3-'18e 68 62 6 70 70 57

2014 99 93 7 Q4-'18e 67 60 7 72 72 55

2015 54 49 5 2018e 66 60 6 68 70 58

2016 45 43 2 Q1-'19e 66 60 6 70 72 55

2017 55 51 4 Q2-'19e 66 60 6 70 75 59

Q3-'19e 66 60 6 70 75 59

2018e 66 60 6 Q4-'19e 66 60 6 70 78 55

2019e 66 60 6 2019e 66 60 6 70 75 57

20

30

40

50

60

70

80

90

J-15 J-16 J-17 J-18 J-19

$/b Month Average Brent Spot Prices and CSM Forecast Range

Brent historycentral scenariodelayed supplydemand outperformsbear consensus

11

HOW WE THINK ABOUT FUTURE OIL PRICES


$50

$55

$60

$65

$70

$75

$80

1 6 11 16 21 26 31 36

$/b

Contract Month

Where Scenario Elements Excert Upside/Downside Pressure on Today's Brent Curve

Supply outlook sharply deteriorates. Nopexus declines accelerate more. Sovereign producers collapses

. Shale more limited than we thinkDemand . Peaks later than expected. Trend growth is higher than assumed

Low inventory & high util ization raise sensitivity to supply risk. Opec overtightens

. Shale underperforms

. Supply disruptionDemand outperforms NT

Shale outperforms We are part wrong. 2017 supply deficit is

overstated. Smaller than expected '18 stock drawsOpec deal breaks up

High Spec length unwinds

Demand outlook deteriorates structurally & faster. EV adaptation accelerates;. Battery tech breakthrough;

. Other new energy disruptionSupply more abundant:. Shale technology improves. Shale companies outspend stil l more

. Sovereigns stabilize &/or improve terms

. Nopexus $/b costs collapse

12

ROOM TO GROW … FOR THE US (SHALE)

13

NON-OPEC EX US: NOT QUITE TAPPED OUT, BUT STARVED FOR CAPITAL

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nd

s

Mb/d Total Nopexus Production (all liquids)

yoy (3 mma; rhs)total liquids (12 mta)fcst

-2.5

-2.0

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

17.5

18.5

19.5

20.5

21.5

22.5


Tho

usa

nd

sMb/d Key Nopexus Growers

Russia, Canada, Brazil, Kazakhstan Production

yoy (3 mma; rhs)

nopexus growers (12 mta)

fcst

-2.5

-2.0

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

18.5

19.5

20.5

21.5

22.5

23.5


Tho

usa

nd

sMb/d Other Nopexus Production

Adds up to declines

yoy (3 mma; rhs)nopexus decliners (12 mta)fcst

Outside the shale, industry driven oil production hinges on big projects with long, very long, lead-times, which require higher prices and sustained demand

• Most of Nopexus is already declining. The decline has been mitigated by a slew of new projects that recently came online, but were FID’ed in the high price era.

• Of the growers, only Russia and Brazil keep on growing• Higher prices fund smaller, incremental projects that

can/should mitigate declines in producing basins

Source: IEA, JODI, BP, Rystad Energy, Country Data, The BLOOMBERG PROFESSIONALTM Service, CSM Research

14

OIL DEMAND: WITHOUT A RECESSION – MORE, BETTER GROWTH

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Mb/d Total Global Oil Demand (13 mma)

global oil demand (13 mma)fcst

40

42

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46

48

50

52

54

56


Mb/d OECD vs Non-OECD Oil Demand (13 mma)

non-oecd oil demand (13 mma)non-oecd fcstoecd oil demand (13 mma)oecd fcst

-2.0

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2011 2012 2013 2014 2015 2016 2017E 2018E 2019E

Mb/dGlobal Oil Demand Growth by Region

Africa Mideast CISEurope LatAm North AmericaAsia 2012-2016 avg

Another year of above trend growth in 2017 (third)o Another year without significant regional drags on total

global oil demand (see below)

DM cyclical upturn again compensates for EM decelerationo After North America’s recovery of oil demand growth,

which started in 2013, Europe’s growth has been a “surprising” tailwind for the third year in a row

o DM demand growth extends through 2018 in our view

The 100 Mb/d milestone seems to be in reach

Source: IEA, JODI, BP, Country Data, The BLOOMBERG PROFESSIONALTM Service, CSM Research

15

TRANSPORT FUELS: DEMAND GROWTH CRITICAL TO REFINERS

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

2011 2012 2013 2014 2015 2016 2017 2018 2019

Mb/dReported Product Demand Growth

LPG +naphtha

gasoline

middledistillates

others

fuel oil

2012-2016avg

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62

80

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88

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Tho

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nd

s

Mb/d Oil Product Demand Largely Driven by Transport Fuels

reported product demand (13 mma)reported product fcsttransport fuel demand (13 mma; rhs)transport fcst (rhs)

Incremental demand for gasoline, diesel and jet kero is especially significant since manufacturing these products nearly always involves refining crude oil – in contrast, growing consumption of lighter liquids (e.g. LPG or ethane) is often supplied by NGL producers and condensate splitterso In 2016, for instance, refiner margins underperformed

when consumption of the core products grew by much less than 1 Mb/d …

While road-transport fuels and jet kero drive much of total oil demand growth, they are also the target of the next wave of substitution (e.g. electric vehicles)

Source: IEA, JODI, BP, Country Data, The BLOOMBERG PROFESSIONALTM Service, CSM Research

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Mb/d OECD vs Non-OECD Transport Demand

oecd transport demand (13 mma)oecd fcstnon-oecd transport demand (13 mma; rhs)non-oecd fcst (rhs)

Weight** 2017:3Q 2018:4Q e

U.S. 16% 2.3% 3.0%

Eurozone 11% 2.6% 2.5%

Japan 5% 2.1% 1.5%

U.K. 2% 1.7% 1.0%

Other Developed 6% 2.9% 2.5%

Developed 40% 2.4%* 2.5%*

China 16% 6.8% 6.3%

India 7% 6.3% 7.0%

Brazil 3% 1.4% 3.0%

Russia 3% 2.0% 2.0%

Other Emerging 31% 4.6% 3.5%

Emerging 60% 5.1%* 4.6%*

Global 100% 4.0% 3.7%

Global Real GDPs Y/Y %

Using PPP**

-20

-15

-10

-5

0

5

10

15

98 00 02 04 06 08 10 12 14 16 18

2018:4Q: 8.5% Model

2017:3Q: 4.6%

U.S. Real Capex Y/Y%

16

COINCIDENT GLOBAL GROWTH ACCELERATES

Source: CSM Economics Team

Weight** 2017:3Q e 2018:4Q e

U.S. 16% 4.1% 5.0%

Eurozone 11% 3.9% 3.5%

Japan 5% 2.1% 2.0%

U.K. 2% 3.4% 3.2%

Developed 40% 3.9%* 4.0%*

China 16% 11.2% 9.3%

India 7% 9.5% 10.7%

Brazil 3% 4.3% 6.5%

Emerging 60% 8.6%* 7.7%*

Global 100% 6.7%* 6.2%*

* Wtd. Avg.

** IMF 2013 weights

Global Nominal GDPs Y/Y%

17

US OIL PRODUCTION GROWTH TAKES CENTER STAGE

0

1

2

3

4

5

6

7

8

9

10

11

12

1920 1930 1940 1950 1960 1970 1980 1990 2000 2010

Mb/d US Crude Oil Production Long History (12 mma)

5

6

7

8

9

10

11

12

13

'10 '11 '12 '13 '14 '15 '16 '17 '18 '19

Mb/d

Tho

usa

nd

s

US Crude Oil Production (3 mma)

History

fcst

Source: EIA, CSM Research

US crude oil production grew at a steady clip for 50+ years and famously “peaked” in 1972

• An event that much later spawned the fallacious peak oil theories that rose to prominence last decade

Crude oil production here broadly flatlined through the late 1980s – suspended if you will by new production from Alaska and then the deepwater.

Then came the steady, or “inexorable” decline.

The US Shale industry is turning all this around

Short cycle investments from tight rocks found all across the North American land mass had yielded gas for a few years before similar technology was brought to bear on oil layers.

• First from the Eagle Ford and Bakken plays

• And then the Permian Basin plays of West Texas started, More may follow

The US is again the fastest growing oil exporter

18

US SHALE GROWTH: “GIVE US THE PRICE, WE’LL GIVE YOU …”

Source: EIA, HPDI, Company Estimates, Rystad Energy, CSM Research

2

3

4

5

6

7

8

9

10

Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19

Mb/dSensitivity of US Shale Crude Oil Production to WTI Prices

$45$50$55$60$65

Price Shale Crude Oil + NGLs Shale Crude Oil

Scenario Y/Y Growth (kb/d) Q4/Q4 Growth (kb/d) Y/Y Growth (kb/d) Q4/Q4 Growth (kb/d)

WTI 2018 2019 2018 2019 2018 2019 2018 2019

$45 260 -370 -290 -260 280 -390 -330 -290

$50 690 50 220 110 590 -60 90 20

$55 1,200 580 800 650 950 390 560 440

$60 1,760 1,150 1,440 1,170 1,330 820 1,050 850

$65 2,350 1,800 2,080 1,780 1,690 1,320 1,530 1,290

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2018 2019

Mb/dShale Crude + NGLs vs Y/Y Growth Sensitivity

$45

$50

$55

$60

$65

19

SHALE DRIVES LONG-RUN GAS PRICES BELOW $3/MMBTU

• It’s been nearly 10-years since fast growing volumes of natural gas flowing from the Barnett shale in the Dallas Fort Worth area began to undermine US natural gas markets. Where this millennium began with California’s utilities going bankrupt amidst gas prices in the $10-$14 per MMBtu range and project designers scrambling all over Washington looking for permits to build brand new multi-billion dollar import terminals for LNG; the efficient market for natural gas in the US has ratcheted down its expectations for ‘normal’ or ‘fair value’ or ‘mid-cycle’ prices from about $8 MMBtu in 2009 to $5 by the end of 2011 and as low as $4/MMBtu in the high oil price era of late 2011 through 2014. Since then that price has deflated to $3/MMBtu, which is the equivalent of about ~$20 per barrel of oil in terms of energy content.

• To blame, or to thank is the US shale industry. In short order ever more prolific basins, from the Haynesville to the Eagle Ford in Texas; to the Marcellus and Utica in Pennsylvania and Ohio added ever more natural gas to the US market.

• Abundance forces change: Power-generation was turned upside down, with gas gaining prime of place and coal backed into a corner. Imports were backed out -- the US became a net gas exporter this year; industrial demand began to grind up again, reversing a 10+ year long slide; and now a slew of big LNG Export terminals will usher in more change still.

55

60

65

70

75

80

85

90

'09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19

Bcf/d US Dry Gas Production

history

fcst

2

3

4

5

6

7

8

9

Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18

$/MMBtu Henry Hub Long Dated Futures Price

3 year out December contract

Source: The BLOOMBERG PROFESSIONALTM Service, EIA, HPDI, Company Estimates, CSM Research

20

HOW MUCH SHALE IS ENOUGH, WHAT’S ITS COST

Key to our forecast is the Proprietary CSM-Energy Shale Model

• We have a client-facing version of our shale model, newly available

Rather than driving natural gas (or oil supply) form a projected rig count, our model is built around cash-recycling and accounts for productivity per lateral foot, a spectrum of type-curves on the sub-basin level, and representative cost assumptions up to the corporate level. • In our base case we project $60 WTI which generates strong p/a growth of

dry gas production “associated” with oil-targeted drilling (e.g. the Permian). The higher the oil price the less room that’s left in our s/d framework for growth from the dry gas basin heroes – based of course on normal weather.

• Those dry gas basins are so prolific, and the industry has developed so far, that the sweet spot range of sufficient p/a growth can be supplied easily between HH prices of $2.85 / MMBtu to $3.00 / MMBtu.

17

22

27

32

37

42

47

52

57

62

67

Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19

Bcf/d Sensitivity of Dry Gas Production to Henry Hub Prices

$2.50 HH$2.65 HH$2.75 HH$2.85 HH$3.00 HH$3.25 HH

-5

0

5

10

15

20

$2.50 HH $2.65 HH $2.75 HH $2.85 HH $3.00 HH $3.25 HH

Bcf/d Production Growth from Key Dry Gas Basins (y/y) Sensitivity to Henry Hub Prices

2018E

2019E

-5

0

5

10

15

20

$45 WTI $50 WTI $55 WTI $60 WTI $65 WTI

Bcf/d Call on Dry Gas Basins (y/y production growth) Sensitivity to WTI Prices

2018E

2019E

Source: The BLOOMBERG PROFESSIONALTM Service, EIA, HPDI, Company Estimates, CSM Research

21

SUPPLY SIDE STORIES: “ASSOCIATED” GAS IS NEARLY FREE

It’s also highly sensitive to oil prices. The difference between $55/b and $60/b WTI is slightly more than ~3.5 Bcf/d of annual average growth 2019 vs 2017 from associated gas production in the Permian, Eagle Ford, etc.

Less drilling activity leaves a lot more room for dry gas basins, especially the Marcellus, and $55/b WTI could push Henry Hub prices toward the higher end of our $2.85-3.00/MMBtu range.

Conversely, $65/b WTI leads to run away associated gas supply and very little room for Northeast and Haynesville production growth. Permian gas takeaway infrastructure would potentially constrain this growth relative to our model, but the outcome is still very bearish.

Our central scenario calls for $60/b WTI prices starting in 2018 We think falling inventories provide support for oil next year (link).

0

5

10

15

20

25

30

'09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19

Bcf/dOil/NGLs Driven Shale Associated Gas Production

($55 WTI)Permian Hz

Eagle Ford Hz

Anadarko Hz

Niobrara Hz

Bakken

0

5

10

15

20

25

30

'09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19

Bcf/d Oil/NGLs Driven Shale Associated Gas Production

($60 WTI)

Permian Hz

Eagle Ford Hz

Anadarko Hz

Niobrara Hz

Bakken

15

17

19

21

23

25

27

29

31

33

Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19

Bcf/d Sensitivity of Associated Gas Production to WTI Prices

$45 WTI$50 WTI$55 WTI$60 WTI$65 WTI

Source: EIA, HPDI, Company Estimates, CSM Research

http://cornerstonemacro.com/wp-content/plugins/wp-pdf-stamper/stamped-files/20171003_EM_oil_initiation_59f8db517c996.pdf

Edward Westlake Chandra Meenaga(646) 517-1333 (646) 517 1336

[email protected] [email protected]

ALICE’S THOUGHTS ON ENERGY EQUITIES

Copyright 2018 Cornerstone Macro. All rights reserved. This report is prepared exclusively for the use of Cornerstone Macro institutional clients and may not be redistributed, retransmitted or disclosed, in whole or part, or in any form or manner, without the express written consent of Cornerstone Macro.

Please refer to the end of the report for an Appendix on Disclaimers and Disclosures

mailto:[email protected]


23

Performance of Energy Subsectors Since the Summer of 2014

IF SHALE IS A GREAT BUSINESS, WHY DON’T INVESTORS CARE

Source: CSM Research

24

INVESTORS ARE PREFERRING STABILITY LATE IN THE ECONOMIC CYCLE, WHICH MAKES SENSE BUT…


25

WELL PRODUCTIVITY MEANS SHALE CAN BE GROWTHIER


PXD Production Potential per QuarterALICE’s production forecasts at any time period are based on a cash recycle model i.e.- The strip commodity price- Corporate cash costs- D&C costs of a well- The revenue coming from a well- Non-shale capex burdenYou can see in this chart to the right that the production

potential at 3Q17 was almost as strong as 2014, when oil was $100/bbl at the front end of the curve.Well productivity continues to improve

26

COSTS HAVE FALLEN, CAPEX AND OPEX


PXD Cash costs should fall as HZ production becomes a larger part of the mix.We include 17% cost inflation – PXD are offsetting some of this through efficiency gain

Upper quintile operators keep finding more efficient ways to get more oil out of a given lateral foot of the horizontal well bore. Those who control costs the best will be advantaged further.

27

BALANCE SHEETS HAVE IMPROVED IN THE $50’S/BBL WTI


28

SO A CHANGE IS COMING


Over the course of 2016-1H17, volumes hardly moved and capex was greater than EBITDA. Going forward, volumes are rising. Inflation suggests consensus capex may need to rise, but capex hikes have not been concerning thus far. At the same time the E&Pmultiple is now below its long run median at 7.1x EV/EBITDA

Production for 42 E&P Companies Set to Grow

The E&P Sector is Trades on 7.1x EV/t+1 EBITDA, Versus Its Median Since 2010 of 7.7x

EBITDA Should More Closely Match Capex

E&P : SECTOR SPECIFIC RANKING (*)

29

The Ranking Below Uses 4 E&P Factors (Net Asset Value, Balance Sheet, Reinvestment IRR, Debt Adjusted Production Per Share) to Rank Stocks

New Ranking (As Of 01/26/2018)

Old Ranking (As Of 12/29/2017)

Source: CSM Research. (*) Equities are ranked according to a weighted average factor on a weekly basis.

DISCLAIMERAnalyst CertificationI, Ed Westlake, certify that the views expressed in this research report accurately reflect my personal views about the subject securities or issuers In addition, I certify that no part of my compensation was, is, or will be directly or indirectly related to the specific recommendations or views expressed in this research report.

I, Chandra Meenaga, certify that the views expressed in this research report accurately reflect my personal views about the subject securities or issuers In addition, I certify that no part of my compensation was, is, or will be directly or indirectly related to the specific recommendations or views expressed in this research report.

For important disclosure information regarding securities covered in this report by Cornerstone Macro LLC please contact Compliance at 212-257-4947 or at [email protected]

Ratings SystemCornerstone Macro assigns each Energy equity two ranks : (1) the fractile in which it ranks against its Energy subsector peers (subsectors are currently defined as Exploration and Production, Oilfield Services, Majors, Independent Refiners) and (2) the fractile in which it ranks within Cornerstone Macro’s Energy Equity coverage overall. These fractiles are based on a variety of valuation, operational efficiency, profitability, governance, and custom factors. Stocks in the most attractive fractile for these factors may have delivered a higher total return (defined as share price appreciation plus dividend paid) than those stocks in less attractive fractiles in weekly rebalanced historical back-tests. Fractile 1 = the most attractive in historical back-tests. A fractile is a generic word for splitting group of companies into n fractions (n=1 or higher). Although, the factor ranks are updated on a monthly or quarterly time schedule, stocks may move in and out of different fractiles on a weekly basis depending on share price movements. Back-tests indicate the historical returns from investing based on CSM factor rankings - but this may not be an indicator of future performance.

Restricted (R): In certain circumstances, Cornerstone Macro’s policy and/or applicable law and regulations preclude certain types of communications, including an investment recommendation, in certain circumstances.

30Source: CSM Research


DISCLAIMER

Source : Cornerstone Macro

Ratings DistributionCornerstone Macro’s distribution of stock ratings is based on a factor ranking system. Each subsector is ranked according to factors and sub-divided into a fractile. The number of fractiles will vary with the number of stocks in a sector.

E&P No.Stocks % of Total Quintile Sector Name

Quintile 1 8 19% 1 E&P





Integrated Oils No.Stocks % of Total

Quartile 1 3 25% 1 Majors




Oilfield Services No.Stocks % of Total

Quintile 1 6 27% 1 OFS





Independent Refiners No.Stocks % of Total

Fractile 1 2 29% 1 Refiners



31

DISCLAIMERE&P Ranking Methodology and Risks

We outline below the ranking method and risks for the following stocks in the E&P Sector :

APA APC CLR COG CXO DVN ECA EOG

EQT HES MRO NBL PXD XEC AR CDEV

CHK CPE EGN FANG GPOR JAG LPI MTDR

MUR NFX OAS PDCE PE QEP RRC RSPP

SWN WPX XOG CRZO EPE REN SM SN

SRCI WLL

Ranking Method

Cornerstone Macro updates a variety of financial and operational factors and ranks its E&P and Energy coverage. For E&P, some of the key factors include: IRR, Debt Adjusted Production Growth, Valuation, Net-Debt to Cashflow growth and Net-Debt to EBITDA. These factors are derived by CSM. To rank E&P against the broader Energy universe, we use a common set of four factors, namely Valuation, CFROIC, Growth and Net-Debt to Cashflow.

Risks

E&P companies face a number of risks that could lead to different performance outcomes. Oil

and gas companies are subject to changes in global commodity supply/demand, the economy, accidents, pollution,

equipment malfunctions, changes in taxation, geological risk. Balance sheet risks vary across the group


DISCLAIMERMajors Ranking Methodology and Risks

We outline below the ranking method and risks for the following stocks in the Integrated Oil Sector

XOM CVX OXY COP SU CNQ

IMO CVE BP RDS TOT STO

Ranking Method

Cornerstone Macro updates a variety of financial and operational factors and ranks its Majors and Energy coverage. For Majors, some of the key factors include: Valuation, CFROIC, Net-Debt to Cashflow, Free Cash Yield and Cash Flow Growth. These factors are derived by CSM. To rank Majors against the broader Energy universe, we use a common set of four factors, namely Valuation, CFROIC, Growth and Net-Debt to Cashflow.

Risks

The Majors face a number of risks that could lead to different performance outcomes. Oil

and gas companies are subject to changes in global commodity supply/demand, the economy, accidents,

pollution, equipment malfunctions, changes in taxation, geological risk. Balance sheet risks vary across the group.

With global businesses, there can be the risk from hosting activities in a particular country


DISCLAIMEROilfield Services Ranking Methodology and Risks

We outline below the ranking method and risks for the following stocks in the Oilfield Services Sector

BHGE CJ DO ESV FMSA FRAC HAL

HP NBR NCSM NE NOV PTEN PUMP

RES RIG SLB SLCA SPN TUSK WFT

CLB

Ranking Method

Cornerstone Macro updates a variety of financial and operational factors and ranks its Oilfield Services and Energy coverage. For Oilfield Services, some of the key factors include: Valuation, CFROIC, Net-Debt to Cashflow and EBITDA Growth. These factors arederived by CSM. To rank Oilfield Services companies against the broader Energy universe, we use a common set of four factors,namely Valuation, CFROIC, Growth and Net-Debt to Cashflow.

Risks

Oilfield Service companies face a number of risks that could lead to different performance outcomes. Oil


pollution, equipment malfunctions, changes in taxation, geological risk. Balance sheet risks vary across the group.

With global businesses, there can be the risk from hosting activities in a particular country


DISCLAIMERIndependent Refiner Ranking Methodology and Risks

We outline below the ranking method and risks for the following stocks in the Independent Refiners

ANDV DK HFC MPC PBF PSX VLO

Ranking Method

Cornerstone Macro updates a variety of financial and operational factors and ranks its Independent Refiners and Energy coverage. For the Refiners, some of the key factors include: Momentum, Valuation, CFROIC, Net-Debt to Cashflow and EBITDA Growth. These factors are derived by CSM. To rank the Refiners against the broader Energy universe, we use a common set of four factors, namely Valuation, CFROIC, Growth and Net-Debt to Cashflow.

Risks

The Independent Refiners face a number of risks that could lead to different performance outcomes. Oil


pollution, equipment malfunctions, changes in taxation. Balance sheet risks vary across the group.

Energy efficiency and changes in long term transportation technology could impair

the value of assets over time.


DISCLAIMERFor important disclosure information regarding securities covered in this report by Cornerstone Macro LLC please contact Compliance at 212-257-4947 or at [email protected]

Other Important Disclosures :

The content of this report is to be used solely for informational purposes. Neither the information nor any opinion expressed constitutes an offer, or an invitation to make an offer, to buy or sell any securities or other financial instrument or any derivative related to such securities (e.g. options, futures, warrants, swaps and contracts). This report is not intended to provide personal investment advice, and it does not take into account the specific investment objectives, financial situation and the particular needs of any specific investor. Investors should seek financial advice regarding the appropriateness of investing in the financial instruments and investment strategies discussed. Statements regarding future prospects may not be realized. Past performance is not a guide to, indicator of, nor assurance of future performance.

The value of investments may fluctuate, and investments that are denominated in foreign currencies may fluctuate in value as a result of exposure to exchange rate movements.

The information contained in this report (with the exception of Cornerstone Macro disclosure information) was obtained from various sources that Cornerstone Macro considers to be reliable, but neither Cornerstone Macro nor its affiliates guarantee its completeness or accuracy. Assumptions, opinions and recommendations contained herein are subject to change without notice, and Cornerstone Macro is not obligated to update the information.

The report may contain links to third-party websites. Cornerstone Macro is not responsible for content contained on a third-party website, nor is inclusion of the link an endorsement of that particular website.

Copyright 2018, Cornerstone Macro. All rights reserved. This report is prepared exclusively for the use of Cornerstone Macro institutional clients and may not be redistributed, retransmitted or disclosed, in whole or in part, or in any form or manner, without the express written consent of Cornerstone Macro.


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