Commodities Macro Energy View Sorting through loose balances and the NAM energy revolution…

See Appendix A-1 for Analyst Certification, Important Disclosures and non-US research analyst disclosures

Citi Research is a division of Citigroup Global Markets Inc. (the "Firm"), which does and seeks to do business with companies covered in its research reports. As a result, investors should be

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Certain products (not inconsistent with the author’s published research) are available only on Citi's portals.

This presentation was approved for distribution on 9 November 2015; the disclosures in Appendix A1 are current as of the same date.

Commodities Strategy | November 2015

Aakash Doshi

Vice President

aakash.doshi@citi.com

+1 212 723 3872

New (Oil) World Order

1

Brent crude oil prices ($/bbl, 2000-2015)

Source: Bloomberg, Citi Research

Prices had been range-bound for 3-4 years as new supply balanced lost supply. But ultimately the bearishness

of shale overwhelmed the bullishness of geopolitical disruptions and prices collapsed.

2

0

20

40

60

80

100

120

140

160

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Brent Flat Price 1-yr Avg Price Min Max

Enter the “Shale Era”

● High prices spurred innovation leading to the rapid

growth of deep water, oil sands and shale production.

Production from these three sources grew nearly 5x from

2000 to 2014.

● Quantitative easing and low interest rates provided

access to cheap financing that helped to fund this revolution

in unconventional production.

● The new “suppliers” of oil are the old “consumers”.

This changes the rules of the game as high petroleum

consuming regions like the US increasingly move towards

energy independence.

● The unconventional oils are the new swing producers,

but are slow to move. Behind the scenes, swinging capital

markets are influencing marginal production.

● Now unconventional oil, previously high on the cost

curve, is seeing unprecedented cost deflation,

challenging low cost producers.

● The Saudi response to abandon the role of “central

banker” of global oil has accelerated these underlying

changes.

Global liquids production* from oil sands, shale and deep

water sources has soared since 2000

Source: Woodmac, EIA, Citi Research, *ex-US based on total production in Woodmac company universe

High prices unleashed three areas of production previously off bounds commercially – deep water, oil sands and

shale. Loose monetary policy and liquidity injections from quantitative easing over the last decade provided the

cheap financing conditions which facilitated much of this production growth, revolutionizing the industry.

The Unconventional Energy Revolution: Turning assumptions upside down

0.0

5.0

10.0

15.0

20.0

25.0

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

mboe/d

Oil sands

Shale

Deep water

Regional oil balances (m b/d)

Source: Citi Research, *from “New Economics of Oil” (Spencer Dale, Oct 2015)

1) Oil can no longer be seen as an exhaustive resource – Unconventional supplies are plentiful (i.e. the relative

price of oil won’t increase with real interest rates)

2) Oil supply curves are not price inelastic – taps can be turned off when prices fall and turned on when prices rise

3) Oil no longer primarily flowing from Middle East to East and West – APAC has become a congested sinkhole

and the Atlantic Basin a surplus oil market

4) OPEC is no longer willing or able to balance markets – Oil out of the ground is worth more than oil in the

ground; if its kept in the ground, prices will fall anyway and market share will be lost

Four critical insights*

4

5

Crude Oil Outlook – Summary (2016-2018)

● The oil market remains significantly oversupplied, to the tune of 1-1.5-m b/d, and the fundamental outlook

remains bearish as not only does the overhang persist, but the return of Iranian barrels early next year

materially adds to the overhang.

● US production is falling on a combination of shale cutbacks and stripper well shut-ins, but OPEC

production is rising and non-OPEC (ex-shale) remains stubbornly strong, while the market awaits the

impact of the massive capex cuts in brownfield maintenance to take effect.

● US shale production was slow to fall but the reaction to any price rally is likely to be asymmetrically fast.

Citi expects to see non-OPEC production declines in 2H’16 but the resulting impact on price is likely to be muted

by a combination of huge inventories in stock, hefty pent-up hedging requirements on the part of producers, and

the potential snap back in US production that would bring the large “fracklog” of drilled-but-uncompleted wells

(a.k.a. “DUCs”) to market. However, weak global conditions could keep Brent-WTI from blowing out much despite

unwieldy US inventories, reflecting incentives to move global oversupply into American onshore storage tanks.

Citi is revising the Brent-WTI spread outlook narrower, from $8 to $5 in 4Q’15 and 1Q’16; Brent may see

greater pressure, revised down to $44 in 4Q’15 and 1Q’16. This Brent-WTI outlook is wider than current

sub-$3 levels.

● Despite optimism arising from the shale production slowdown, Citi expects prices to grind lower this

winter as fundamentals weigh, though the hefty short positioning in the market sets us up for outsized

spikes on the way down.

● Citi’s economists have added a significant bearish risk to the mix by putting the odds of a global growth

recession at over 50%. Running more extreme GDP downside shock scenarios through Citi’s demand model

suggests global oil demand growth could fall to below even 0.5-m b/d in 2016; while this should be taken

cautiously, it suggests more bearish scenarios remain.

● On the other hand, sub-$50/bbl oil is wreaking havoc in the non-OPEC non-shale (NONS) oil sector, and

the pieces are being put in place for market tightening as capex falls and projects are cancelled or

deferred. But it remains too early to call for an end to the sector’s suffering.

● All in all, barring a Chinese recession, it looks like markets are unlikely to move back into balance until

end-2016.

0

20

40

60

80

100

120

140

160

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Brent Flat Price 1-yr Avg Price Min Max

After a clearly false recovery in 2Q’15, when Brent rose toward $68 in early May and WTI hit $62, prices have

retreated below their 1Q’15 lows. Going forward, we expect swings based on rapidly changing supply versus

demand balances (either moderated by or reinforced by financial flows).

Source: Bloomberg, Baker Hughes, Citi Research *as tracked by Baker Hughes ** from 4Q’15 Commodities Outlook (Sept 22, 2015) 6

Citi oil price outlook for Brent, WTI, Brent-WTI ($/bbl) **

Brent crude oil prices ($/bbl, 2000-2015)

0

200

400

600

800

1000

1200

2000 2002 2004 2006 2008 2010 2012 2014

Middle East Latin America Asia Pacific Europe Africa

Global* oil rig counts ex-N. America

Price outlook ($/bbl) 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2014 2015 2016 2017

Base case (55%)

Brent 55 64 50 44 44 50 55 60 100 53 52 65

WTI 49 58 45 39 39 46 51 55 93 48 48 60

Brent-WTI 7 6 5 5 5 4 4 5 7 6 5 5

Bear case (30%)

Brent 55 64 50 41 38 35 40 45 100 52 40 43

WTI 49 58 45 33 33 33 38 43 93 46 37 40

Brent-WTI 7 6 5 8 5 2 2 2 7 6 3 3

Bull case (15%)

Brent 55 64 50 55 55 65 75 75 100 56 68 75

WTI 49 58 45 47 49 59 70 70 93 50 62 70

Brent-WTI 7 6 5 8 6 6 5 5 7 6 6 5

Painful rebalancing – a double or triple “W” price path ahead?

Citi Commodities Price Forecasts*

7 Source: Citi Research, *subject to revision; Note: 2017 and 2018 annual updated less frequently.

0-3M 6-12M Q1 2015 Q2 2015 Q3 2015E Q4 2015E Q1 2016E Q2 2016E Q3 2016E Q4 2016E 2012 2013 2014 2015E 2016E 2017E 2018E

Energy 5Y Cyclical

NYMEX WTI USD/bbl 39.0 43.0 70.0 49.0 58.0 45.0 39.0 39.0 46.0 51.0 55.0 94.1 98.0 93.0 48.0 48.0 60.0 70.0

ICE Brent USD/bbl 44.0 47.0 75.0 55.0 64.0 50.0 44.0 44.0 50.0 55.0 60.0 111.7 108.7 100.0 53.0 52.0 65.0 75.0

Henry Hub Natural Gas USD/MMBtu 2.70 2.90 3.50 2.90 2.70 2.70 2.70 2.80 2.90 3.00 3.10 2.75 3.73 4.40 2.70 3.00 3.50 3.50

Base Metals LT Price

LME Aluminum USD/MT 1,580 1,640 2,200 1,813 1,787 1,627 1,590 1,600 1,620 1,650 1,680 2,049 1,888 1,893 1,705 1,640 1,770 1,850

LME Copper USD/MT 5,600 6,000 6,200 5,790 6,044 5,284 5,550 5,600 5,800 6,100 6,200 7,945 7,352 6,829 5,665 5,925 7,000 8,000

LME Lead USD/MT 1,730 1,760 2,200 1,817 1,949 1,733 1,730 1,730 1,750 1,750 1,800 2,072 2,158 2,113 1,805 1,760 1,850 2,060

LME Nickel USD/MT 10,500 14,000 21,000 14,400 13,052 9,759 10,320 11,200 12,500 14,000 14,500 17,592 15,105 16,950 11,885 13,050 15,000 18,500

LME Tin USD/MT 14,500 15,800 20,000 18,423 15,644 15,044 15,400 15,500 15,700 15,900 16,000 21,108 22,340 21,902 16,130 15,775 18,500 20,500

LME Zinc USD/MT 1,790 1,830 2,100 2,092 2,189 1,893 1,770 1,790 1,820 1,850 1,880 1,963 1,940 2,165 1,985 1,835 1,970 2,100

Precious Metals LT Price

COMEX Gold USD/T. oz 1,050 1,025 1,050 1,220 1,194 1,120 1,110 1090.0 1050.0 1050.0 1050.0 1,669 1,416 1,266 1,160 1,060 1,140 1,200

Silver USD/T. oz 14.7 14.5 16.5 16.7 16.4 14.9 14.7 14.5 14.4 14.5 14.6 31.2 24.0 19.1 15.7 14.5 15.0 15.8

Platinum USD/T. oz 990 1,100 1,763 1,195 1,129 999 990 1000.0 1090.0 1100.0 1200.0 1,552 1,490 1,385 1,080 1,098 1,230 1,400

Palladium USD/T. oz 620 680 780 786 759 613 620 630.0 655.0 670.0 690.0 645 728 803 693 660 700 800

Bulk Commodities 5Y Cyclical

Hard Coking Coal (Spot) USD/MT 88 100 125 105 87 84 88 95 100 100 100 191 148 115 91 99 110 120

Thermal Coal Asia (NEWC) USD/MT 56 60 80 65 59 59 56 60 58 57 63 94 84 71 60 60 68 75

Iron Ore Spot (TSI) USD/MT 50 40 55 61 57 54 50 45 40 38 40 128 135 97 56 41 42 40

Agriculture

CBOT Corn USd/bu 370 400 N/A 385 366 405 370 395 405 415 400 695 578 415 382 405 440 N/A

CBOT Soybeans USd/bu 890 910 N/A 990 965 960 890 915 925 900 925 1,465 1,406 1,245 950 915 1,040 N/A

CBOT Wheat USd/bu 490 515 N/A 524 505 510 490 500 515 510 525 750 684 588 508 510 550 N/A

NYB-ICE Cotton USd/lb 63.0 63.0 N/A 61.6 65.0 65.0 63.0 63.0 63.0 63.0 63.0 80.0 84.0 76.2 64.0 63.0 N/A N/A

ICE Coffee USd/lb 125 135 N/A 152 135 125 125 135 135 135 135 175 126 178 135 135 N/A N/A

ICE Cocoa USD/MT 3,100 3,025 N/A 2,889 3,025 3,200 3,100 3025 3025 3100 3050 2,348 2,405 3,010 3,055 3,050 N/A N/A

Point Prices Annuals

Oil stress test: bear case for oil could see Brent in the $30s in 1H’16

8 Source: IEA, Citi Research

● China macro concerns put further emphasis on a bear case for oil (outlined in Citi’s report, “Something’s Gotta

Give”). Chinese demand could be even weaker (+0.2-m b/d in 2016 for the bear case vs. 0.3-m b/d in the base case), as

any hit to consumers damps the fast growth in gasoline demand (though low prices could be an offset), but more importantly,

the hit to industrial activity could hit demand for diesel and LPGs, used in construction, freight, petrochemicals, etc. If

refineries then run at lower utilization, this could decelerate crude import demand growth, although crude imports to fill the

Strategic Petroleum Reserve (SPR) could be ongoing. And if China sneezes, the world could catch a cold – the

negative spillover to global GDP growth could mean oil demand growth in 2016 could further disappoint to the

downside elsewhere around the world

● OPEC over-enthusiasm in the market-share battle could drive prices down further; Saudi, Iraqi and Iranian production

growth could all surprise to the upside. Non-OPEC non-shale production could stay resilient, as could shale.

● In this scenario, global oil inventories would rise significantly, driving a new round of floating storage, and massive

contango in Brent and WTI futures as storage tanks max out in key locations.

Demand 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2013 2014 2015 2016 14' 15' 16'

OECD Demand 46.6 45.1 46.0 46.4 46.6 45.1 46.1 46.7 46.0 45.6 46.0 46.1 -0.41 0.40 0.11

Non-OECD Demand 47.0 48.0 48.3 48.3 47.9 48.9 49.3 49.4 45.8 47.0 47.9 48.9 1.14 0.91 0.98

Total Demand 93.5 93.1 94.2 94.7 94.5 94.0 95.4 96.1 91.9 92.6 93.9 95.0 0.73 1.31 1.10

Supply 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2013 2014 2015 2016 14' 15' 16'

Non-OPEC 54.2 53.3 53.0 53.8 54.0 53.1 53.1 53.9 50.4 52.6 53.6 53.5 2.20 0.98 -0.07

OPEC Crude 30.5 31.5 31.6 32.1 32.8 33.0 33.1 33.3 30.5 30.3 31.4 33.0 -0.18 1.13 1.62

OPEC Unconventional 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.2 0.3 0.3 0.3 0.02 0.01 0.01

OPEC NGLs 6.3 6.4 6.4 6.4 6.5 6.6 6.7 6.6 6.0 6.1 6.4 6.6 0.16 0.26 0.23

OPEC Oil 37.0 38.1 38.3 38.8 39.6 39.8 40.0 40.2 36.6 36.6 38.0 39.9 0.00 1.40 1.85

Processing Gains 2.2 2.2 2.2 2.2 2.3 2.3 2.4 2.3 2.2 2.2 2.2 2.3 0.04 0.00 0.12

Global Biofuels 1.8 2.3 2.6 2.3 1.8 2.3 2.6 2.3 2.0 2.2 2.2 2.3 0.17 0.05 0.01

Total Supply 95.3 95.9 96.1 97.1 97.8 97.4 98.1 98.7 91.2 93.7 96.1 98.0 2.41 2.44 1.91

Implied Stockbuild 1.8 2.8 1.9 2.4 3.3 3.5 2.6 2.6 -0.6 1.1 2.2 3.0

"Call on US Production" 11.0 10.2 10.9 10.5 9.5 9.5 10.5 10.6 11.0 10.8 10.6 10.0 - -0.15 -0.61

Stockbuild adjustments 1.1 1.0 0.7 0.7 0.6 0.5 0.3 0.5 0.7 0.9 0.4

Adj. implied stockbuild 0.6 1.8 1.2 1.7 2.7 3.0 2.3 2.1 0.3 1.3 2.6

Adj. "Call on US production" 12.1 11.2 11.6 11.2 10.2 10.0 10.8 11.1 11.5 11.5 10.5

Price outlook ($/bbl) 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2014 2015 2016

Brent 55 64 50 41 38 35 40 45 100 52 40

WTI 49 58 45 33 33 33 38 43 93 46 37

Brent-WTI 7 6 5 8 5 2 2 2 7 6 3

Demand 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2013 2014 2015 2016 14' 15' 16'

OECD Demand 46.6 45.1 46.0 46.4 46.6 45.1 46.1 46.7 46.0 45.6 46.0 46.1 -0.41 0.40 0.11

Non-OECD Demand 47.0 48.0 48.3 48.3 47.9 48.9 49.3 49.4 45.8 47.0 47.9 48.9 1.14 0.91 0.98

Total Demand 93.5 93.1 94.2 94.7 94.5 94.0 95.4 96.1 91.9 92.6 93.9 95.0 0.73 1.31 1.10

Supply 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2013 2014 2015 2016 14' 15' 16'

Non-OPEC 54.2 53.3 53.0 53.8 54.0 53.1 53.1 53.9 50.4 52.6 53.6 53.5 2.20 0.98 -0.07

OPEC Crude 30.5 31.5 31.6 32.1 32.8 33.0 33.1 33.3 30.5 30.3 31.4 33.0 -0.18 1.13 1.62

OPEC Unconventional 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.2 0.3 0.3 0.3 0.02 0.01 0.01

OPEC NGLs 6.3 6.4 6.4 6.4 6.5 6.6 6.7 6.6 6.0 6.1 6.4 6.6 0.16 0.26 0.23

OPEC Oil 37.0 38.1 38.3 38.8 39.6 39.8 40.0 40.2 36.6 36.6 38.0 39.9 0.00 1.40 1.85

Processing Gains 2.2 2.2 2.2 2.2 2.3 2.3 2.4 2.3 2.2 2.2 2.2 2.3 0.04 0.00 0.12

Global Biofuels 1.8 2.3 2.6 2.3 1.8 2.3 2.6 2.3 2.0 2.2 2.2 2.3 0.17 0.05 0.01

Total Supply 95.3 95.9 96.1 97.1 97.8 97.4 98.1 98.7 91.2 93.7 96.1 98.0 2.41 2.44 1.91

Implied Stockbuild 1.8 2.8 1.9 2.4 3.3 3.5 2.6 2.6 -0.6 1.1 2.2 3.0

"Call on US Production" 11.0 10.2 10.9 10.5 9.5 9.5 10.5 10.6 11.0 10.8 10.6 10.0 - -0.15 -0.61

Stockbuild adjustments 1.1 1.0 0.7 0.7 0.6 0.5 0.3 0.5 0.7 0.9 0.4

Adj. implied stockbuild 0.6 1.8 1.2 1.7 2.7 3.0 2.3 2.1 0.3 1.3 2.6

Adj. "Call on US production" 12.1 11.2 11.6 11.2 10.2 10.0 10.8 11.1 11.5 11.5 10.5

Price outlook ($/bbl) 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2014 2015 2016

Brent 55 64 50 41 38 35 40 45 100 52 40

WTI 49 58 45 33 33 33 38 43 93 46 37

Brent-WTI 7 6 5 8 5 2 2 2 7 6 3

Demand 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2013 2014 2015 2016 14' 15' 16'

OECD Demand 46.6 45.1 46.0 46.4 46.6 45.1 46.1 46.7 46.0 45.6 46.0 46.1 -0.41 0.40 0.11

Non-OECD Demand 47.0 48.0 48.3 48.3 47.9 48.9 49.3 49.4 45.8 47.0 47.9 48.9 1.14 0.91 0.98

Total Demand 93.5 93.1 94.2 94.7 94.5 94.0 95.4 96.1 91.9 92.6 93.9 95.0 0.73 1.31 1.10

Supply 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2013 2014 2015 2016 14' 15' 16'

Non-OPEC 54.2 53.3 53.0 53.8 54.0 53.1 53.1 53.9 50.4 52.6 53.6 53.5 2.20 0.98 -0.07

OPEC Crude 30.5 31.5 31.6 32.1 32.8 33.0 33.1 33.3 30.5 30.3 31.4 33.0 -0.18 1.13 1.62

OPEC Unconventional 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.2 0.3 0.3 0.3 0.02 0.01 0.01

OPEC NGLs 6.3 6.4 6.4 6.4 6.5 6.6 6.7 6.6 6.0 6.1 6.4 6.6 0.16 0.26 0.23

OPEC Oil 37.0 38.1 38.3 38.8 39.6 39.8 40.0 40.2 36.6 36.6 38.0 39.9 0.00 1.40 1.85

Processing Gains 2.2 2.2 2.2 2.2 2.3 2.3 2.4 2.3 2.2 2.2 2.2 2.3 0.04 0.00 0.12

Global Biofuels 1.8 2.3 2.6 2.3 1.8 2.3 2.6 2.3 2.0 2.2 2.2 2.3 0.17 0.05 0.01

Total Supply 95.3 95.9 96.1 97.1 97.8 97.4 98.1 98.7 91.2 93.7 96.1 98.0 2.41 2.44 1.91

Implied Stockbuild 1.8 2.8 1.9 2.4 3.3 3.5 2.6 2.6 -0.6 1.1 2.2 3.0

"Call on US Production" 11.0 10.2 10.9 10.5 9.5 9.5 10.5 10.6 11.0 10.8 10.6 10.0 - -0.15 -0.61

Stockbuild adjustments 1.1 1.0 0.7 0.7 0.6 0.5 0.3 0.5 0.7 0.9 0.4

Adj. implied stockbuild 0.6 1.8 1.2 1.7 2.7 3.0 2.3 2.1 0.3 1.3 2.6

Adj. "Call on US production" 12.1 11.2 11.6 11.2 10.2 10.0 10.8 11.1 11.5 11.5 10.5

Price outlook ($/bbl) 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2014 2015 2016

Brent 55 64 50 41 38 35 40 45 100 52 40

WTI 49 58 45 33 33 33 38 43 93 46 37

Brent-WTI 7 6 5 8 5 2 2 2 7 6 3

● During the last cyclical trough (1981-97) there was a

random correlation between oil and other

commodity prices, a trend that has re-emerged after

2010.

● During the height of the last cycle, correlations

between energy and other commodities were high

including not just steel, but copper, aluminum and other

energy intensive commodities.

● Probably the most critical factor in the recent past

was that energy and non-energy commodities

reached the same condition at the same time for

largely unrelated reasons. Across commodities due to

lack of investment in the years if not decades before

2002, inventories of potentially producing properties

were depleting under the weight of low prices and lack

of incentives to deploy capex. And under the weights of

high prices and complacency of inventories, above

ground stockpiles were likewise depleted. Agricultural

inventories fell as lobbyists in the US and Europe found

a way to foster biofuel use.

● Petroleum prices surged the greatest of all

commodities from 2003-08, lifting the prices of all

commodities, which are to one or another degree

energy intensive, thus forcing an effectively tight

correlation across commodities and raising the costs

and therefore the prices of highly energy intensive

commodities like copper the most.

● For commodities to be correlated tightly again on a

higher path, their investment cycles will have to be

simultaneous or energy prices will have to rise; but

the opposite is now occurring.

Source: Citi Research

Correlation with Oil Prices -

Q1’81 - Q4’97

Energy is a key to a super cycle return…

Correlation with Oil Prices -

Q1’98 - Q4’08

Correlation with Oil Prices -

Q1’09 - Q1’11

Correlation with Oil Prices -

Q2’ 11 - Q3’13

9

Energy prices can materially impact US inflation expectations

3M-Rolling Correlation to Fed 5-Year Breakevens

● Though petroleum products account for less than

5% of consumer CPI directly, crude and petroleum

product prices can materially impact US inflation

expectations as energy prices can have indirect

impacts that filter through to various final

consumption goods from further up the supply

chain. Energy is a cost input in practically any

production/manufacturing process as well as a critical

component in the transportation costs associated with

delivering a product from producer to final consumer.

● The direct impacts on consumer expenditures can

be significant as well. Retail gasoline prices can have

material impacts on household expenditures; we

estimate savings per US household (with vehicles) due

to the oil price collapse of $1,193/household in 2015

versus 2014 and $778/household in 2016 versus 2014

● With fuel costs having far reaching impacts on the

consumer’s wallet, inflation expectations can often

move quite closely with energy prices, particularly

during extreme price moves. This relationship has

certainly manifested in the past year as 5Y forward

breakevens (using Federal Reserve index as opposed to

5y5y forwards) moved almost tick-for-tick with petroleum

prices during the height of the crude oil price slide in

2H’14 and the beginning of 1Q’15 and again in 3Q.

Lower energy prices have had a much larger impact on curtailing US inflation expectations versus lower food

prices. Markets drove this as 5Y BEs had been moving tick-for-tick with lower oil prices since 2H’14 and much of

1H’15. This faded a bit in 2015 but has reemerged since August to temper medium-term inflation expectations…

Correlation of MoM Changes in US Food CPI and

Lagged Retail Diesel Prices

Source: Bloomberg, Citi Research 10

-0.3

-0.2

-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

Oct

-14

Nov

-14

Nov

-14

Dec

-14

Dec

-14

Jan-

15

Jan-

15

Jan-

15

Feb

-15

Feb

-15

Mar

-15

Mar

-15

Apr

-15

Apr

-15

May

-15

May

-15

Jun-

15

Jun-

15

Jul-1

5

Jul-1

5

AAA National Average Retail Gasoline RBOB WTI

New (Oil) World Order

11

An era of cost deflation is setting in

12

Deflationary potential looks strongest for the middle of the curve (2015 vs 2014 cost curve)

Source: Company data, Citi Research

Productivity gains have ticked up significantly this year, as drilling activities focus on most productive areas and

technology and operational efficiency continue to improve.

Source: EIA, Company reports, state data, Citi Research

13

YoY productivity gains (% change in initial production)

have ticked up significantly this year Estimated IRR for an average well (by basin) given 25% cost

reductions and sustained productivity gains (at $60 WTI / $2.8 HH)

Productivity gains are accelerating in US shale

-40%

-20%

0%

20%

40%

60%

80%

100%

120%

Jul-0

9

No

v-0

9

Ma

r-1

0

Jul-1

0

No

v-1

0

Ma

r-1

1

Jul-1

1

No

v-1

1

Ma

r-1

2

Jul-1

2

No

v-1

2

Ma

r-1

3

Jul-1

3

No

v-1

3

Ma

r-1

4

Jul-1

4

No

v-1

4

Ma

r-1

5Oil

Gas

Total

-20%0%

20%40%60%80%

100%120%140%160%

Eagl

e Fo

rd

Bak

ken

Per

mia

n

Nio

bra

ra

An

dar

koM

issi

ssip

pia

n

Uti

ca

Mar

cellu

s

Eagl

e Fo

rd-o

ily

Hay

nes

ville

Gra

nit

e W

ash

IRR

(%

)

Source: EOG Resources

14

EOG Resources Western Eagle Ford Current Returns

vs. 2012

EOG Resources Eagle Ford Completed Well Cost ($ mln)

Shale Returns have Improved, even at Lower Prices. WTI Capped At $65

Citi’s initial forecast of >20% cost deflation in shale well costs this year has long been surpassed, driven largely

by the collapse in drilling and completion costs and declines in steel and diesel inputs.

Source: "U.S. Oil Services: Deflategate (Shale Well Cost) Update” (Scott Gruber, Mar 2015), Citi Research

15

Breakdown of costs for an average shale well in

4Q’14 (upper) and 2Q’15 (lower)

Cost declines by well component are substantial, leading

to overall declines in total well cost of ~26%

Shale well costs have dropped 30% so far

In deep water, lower day rates and both capex and opex deflation improve economics, but companies are still

hesitant to pursue projects near the top of the cost curve. Cost declines could take several years to fully pass

through due to contract cycles and technical project complexity. Offshore breakeven costs might drop ~20%.

Source: Citi Oilfield Services team, ODS, company reports, Citi Research

16

Marginal deep water floater rig day rates are down 50%

from 2014 highs, with potential additional 25% deflation

Offshore costs are continuing to deflate

0

100

200

300

400

500

600

700

800

Jan-

04

Sep

-04

May

-05

Jan-

06

Sep

-06

May

-07

Jan-

08

Sep

-08

May

-09

Jan-

10

Sep

-10

May

-11

Jan-

12

Sep

-12

May

-13

Jan-

14

Sep

-14

May

-15

Jan-

16

Sep

-16

May

-17

Th

ou

san

d $

/ d

ay

Potential 25% further

deflation as utilization

could drop rates

another 8%

?

Deep water F&D cost deflation expected

Capex Type Weight Deflation

Impact

on Cost

Finding Costs

Drilling Rig 30-35% -25% additional? -7.5 to 9%

Well Services 40-45% -10% -4 to 4.5%

Other (seismic, overheads, etc) 20-30%

Total -15 to 20%

Development Costs

Drilling rig 18% -30% -5%

Well services 20% -10% -2%

Facilities 29% -15% -4%

Subsea production hardware 10% -25% -3%

SURF and Pipelines 23% -20% -5%

Total 100% -19%

50%

60%

70%

80%

90%

100%

'98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15E'16E'17E

Utilization, %

Floating drilling rigs Construction vessels Seismic vessels Pressure pumping

Deep water can likely compete with shale going forward

17

The lower oil price range resulting from the emergence of shale supply has led to careful scrutiny of future deep

water projects. Despite declining costs and service sector utilization, competition with shale could become more

intense. Cost deflation in shale is expected to be faster.

Services utilization plummeted for deep water

But shale investment profile more favorable than deep water

Source: Company reports, ODS, Citi Research

Factor Shale Deep water

Investment Dynamics

FID every ~20 days; scales up and down

quickly

Large, lumpy investment schedule;

scales up/down slowly

Cost Deflation

Potential up to 25% up to 20%

Cost Deflation Timing quick- majority of gains in 12mo slow - multiple years

Cost Deflation Pass-

through

high- US production taxes pass benefit to

oil company

variable- in multiple geographies

production sharing contracts pass benefit

to governments

Environmental Risk low- largely localized at well site large- e.g. Macondo

Execution Risk

low - shale manufacturing plus portfolio

effect

high - frequent delays and overruns in

sanctioning and fabrication

Depletion Rate high- ~60% in year 2, ~30% base modest- 0 in first few years, ~20 base

Maintenance easy - install pump, refrac, etc. difficult - expensive to access

Shale the new swing producer: it can rebound quickly with price recovery

In our base case, oil inventories could balance in 4Q’16 and begin to draw down as demand growth joins non-

OPEC non-shale supply declines to tighten markets; prices could rise – how quickly might shale respond?

Source: EIA, Citi Research, *assumes 30-day IP of 600-kb/d 18

2017 oil production growth already positive for all rig

outlooks

Clearing ~1,250 drilled-but-not-producing wells

over a 12-month period can add ~250-kb/d of

additional production for 2 years

…on a monthly basis, production growth

could peak at 400-kb/d

0.00

0.05

0.10

0.15

0.20

0.25

0.30

1 2 3 4 5 6 7 8 9 10

mb

/d

Year

-

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.45

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58

mb

/d

Month

Behind the scenes, financial markets financed the shale boom

19

RBLs are bank revolvers secured by producer reserves. The size of the facility is re-determined twice a year

based on re-estimation of reserve values, which takes into account the latest developments in the forward curve.

Fall re-determinations should adjust price decks to around 10% below the forward curve

Average WTI bank deck pricing for RBLs Average Brent bank deck pricing for RBLs

Source: Tristone’s Quarterly Energy Lender Price Survey, Citi Research

Average Natural gas bank deck pricing for RBLs

45

55

65

75

85

2014 2015 2016 2017 2018 2019

$/B

BL

Q4/14

Q1/15

Q2/15

50

60

70

80

90

2014 2015 2016 2017 2018 2019

$/B

BL

Q4/14

Q1/15

Q2/15

2.5

3.0

3.5

4.0

4.5

2014 2015 2016 2017 2018 2019

$/M

MB

tu

Q4/14

Q1/15

Q2/15

QE, low interest rates buttressed capital markets’ overenthusiasm for shale

20

Equity and credit (HY and IG) issuance for the E&P sector rose steadily over the past several years; issuance

cratered in December ’14 after the OPEC meeting, but spiked in May ’15 as many investors may have been

trying to call the bottom in crude markets, and companies needed capital.

Historical Capital Market Issuance to E&P Sector

Source: S&P, Company reports, Bloomberg, Citi Velocity, Citi Research

Energy Loan issuance ($ millions)

0

20

40

60

80

100

120

140

160

0

5000

10000

15000

20000

25000

30000

Jan

-05

Mar

-05

May

-05

Jul-

05

Sep

-05

No

v-0

5

Jan

-06

Mar

-06

May

-06

Jul-

06

Sep

-06

No

v-0

6

Jan

-07

Mar

-07

May

-07

Jul-

07

Sep

-07

No

v-0

7

Jan

-08

Mar

-08

May

-08

Jul-

08

Sep

-08

No

v-0

8

Jan

-09

Mar

-09

May

-09

Jul-

09

Sep

-09

No

v-0

9

Jan

-10

Mar

-10

May

-10

Jul-

10

Sep

-10

No

v-1

0

Jan

-11

Mar

-11

May

-11

Jul-

11

Sep

-11

No

v-1

1

Jan

-12

Mar

-12

May

-12

Jul-

12

Sep

-12

No

v-1

2

Jan

-13

Mar

-13

May

-13

Jul-

13

Sep

-13

No

v-1

3

Jan

-14

Mar

-14

May

-14

Jul-

14

Sep

-14

No

v-1

4

Jan

-15

Mar

-15

May

-15

$/B

BL

Mill

ion

$

HY - E&P Equity - E&P

IG - E&P 6-mo trailing avg total issuance

WTI Price

0

1000

2000

3000

4000

5000

6000

1-Ja

n-09

1-M

ar-0

9

1-M

ay-0

9

1-Ju

l-09

1-S

ep-0

9

1-N

ov-0

9

1-Ja

n-10

1-M

ar-1

0

1-M

ay-1

0

1-Ju

l-10

1-S

ep-1

0

1-N

ov-1

0

1-Ja

n-11

1-M

ar-1

1

1-M

ay-1

1

1-Ju

l-11

1-S

ep-1

1

1-N

ov-1

1

1-Ja

n-12

1-M

ar-1

2

1-M

ay-1

2

1-Ju

l-12

1-S

ep-1

2

1-N

ov-1

2

1-Ja

n-13

1-M

ar-1

3

1-M

ay-1

3

1-Ju

l-13

1-S

ep-1

3

1-N

ov-1

3

1-Ja

n-14

1-M

ar-1

4

1-M

ay-1

4

1-Ju

l-14

1-S

ep-1

4

1-N

ov-1

4

1-Ja

n-15

1-M

ar-1

5

1-M

ay-1

5

1-Ju

l-15

Energy loan Issuance ($mn)

How much is at risk?

21

In order to assess how much US production might be at risk of becoming distressed, we map key credit metrics

onto production for a second universe of producers*. These distributions indicate that most production is

associated with healthy financials, though the tails cannot be ignored.

Share total group liquids production by leverage (Total debt/EBITDA)

leverage (Total debt

Source: IHS Herold, Citi Research, *universe differs from previous slide

10 3

968 975

2246

693

226360 389

21961 71 72 43 20 24 38

1390 19 44

0%

5%

10%

15%

20%

25%

30%

35%

40%

0.3 or less <0.9 <1.5 <2.1 <2.7 <3.3 <3.9 <4.5 <5.1 <5.7 Greater

% P

rod

uce

r U

niv

ers

e P

rod

uct

ion

Tota

l of

6.6

MM

bo

e li

qu

ids/

day

(Lab

els

: kb

oe

liq

uid

s/d

ay)

Total Debt/EBITDA 2014

860

107222

342

86

434358 386

1433

538

1754

255

21

200

4 34 43 0 0

134 180

0%

5%

10%

15%

20%

25%

30%

2 or less <2.8 <3.6 <4.4 <5.2 <6 <6.8 <7.6 <8.4 <9.2 <10

% P

rod

uce

r U

niv

ers

e P

rod

uct

ion

Tota

l of

6.6

MM

bo

e li

qu

ids/

day

(Lab

els

: kb

oe

liq

uid

s/d

ay)

EV/EBITDA 2014

Producers trading at stressed valuations tend to be smaller, but the

distribution is somewhat wide (EV/EBITDA)

QE has also financed financial flows

22 Source: Bloomberg, Citi Research, *futures equivalent lots; US tickers

(50,000)

0

50,000

100,000

150,000

200,000

250,000

Jan

-14

Mar

-14

May

-14

Jul-

14

Sep

-14

No

v-1

4

Jan

-15

Mar

-15

May

-15

Jul-

15

Sep

-15

Gross Long

Gross Short

Net

Oil ETF Net Length* - a strange support for markets short-term

And here too easy money has been responsible for price and position volatility

23 Source: Bloomberg, CFTC, Citi Research

Managed Money Net Length in WTI and Brent Futures/Options

Meanwhile, oil is losing its importance to the global economy…

Source: EIA, IEA, BP, Citi Research estimates.

24

The oil intensity of GDP Growth continues to decline meaning every unit increase in GDP

growth is translating into less oil demand growth

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010 2013

Non-OECD OECD

…and is losing its importance in China as well

Source: JODI, Citi Research

25

YoY Growth in Chinese Diesel Demand

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

35%

Jan-

03

Oct

-03

Jul-0

4

Apr

-05

Jan-

06

Oct

-06

Jul-0

7

Apr

-08

Jan-

09

Oct

-09

Jul-1

0

Apr

-11

Jan-

12

Oct

-12

Jul-1

3

Apr

-14

Jan-

15

A three-way game of chicken between OPEC,

shale, non-OPEC non-shale - who will blink and

cut back on oil supply?

26

4.00

4.20

4.40

4.60

4.80

5.00

5.20

5.40

5.60

5.80

8.0

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15

STEO Weekly 4WMA PSM DPR - RHS

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

3.0

Jan-11 Aug-11 Mar-12 Oct-12 May-13 Dec-13 Jul-14 Feb-15

Non-OPEC ex-US Crude US Crude OPEC Crude

Shale the First to Slip but OPEC and ex-NAM Production Continue Apace

All buckets of supply continue to grow; in July US crude was up 0.5-m b/d y/y, non-OPEC non-shale was up

0.6-m b/d y/y while OPEC crude was up 1.3-m b/d y/y. US shale production is showing early signs of slowing,

as is US stripper well output, but this is heavily price dependent and more than offset by OPEC’s surge.

Source: IEA, EIA, Bentek, state data, Citi Research 27

Output from the three main buckets of supply

continues to grow strongly y/y (m b/d) US crude is showing signs of rolling-over at lower oil

prices ($/bbl)

US “stripper” well production by production bracket

and state (k b/d) – stripper wells account for ~1.5-m

b/d of US production

Oil production by E&P peer group – weaker

producers more exposed to stress, but account for a

small share of production(m b/d)

0

100

200

300

400

500

600

700

800

10-15 b/d 5-10 b/d 2-5 b/d 1 b/d

Other

WY

UT

TX

PA

OK

NM

ND

LA

KS

FO GULF

CO

CA

2010 2011 2012 2013 2014

LARGE NORTH AMERICAN E&Ps 3.5 3.3 4.3 4.6 5.0

MID-SIZED U.S. E&Ps 0.5 0.6 0.7 0.8 0.9

SMALL U.S. E&Ps 0.1 0.2 0.2 0.3 0.4

SMALLEST U.S. E&Ps 0.0 0.0 0.0 0.0 0.1

U.S. E&P MLPs 0.1 0.1 0.1 0.2 0.2

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

10.2

10.4

10.6

10.8

11.0

Oct

-14

Dec

-14

Feb

-15

Apr

-15

Jun-

15

Aug

-15

Oct

-15

Dec

-15

Feb

-16

Apr

-16

Jun-

16

Aug

-16

Oct

-16

Dec

-16

Feb

-17

Apr

-17

Jun-

17

Aug

-17

Oct

-17

Dec

-17

Case 1 Case 2 Case 3 Case 4

But Shale Can Rebound Quickly If and When Prices Recover

In our base case, oil inventories could balance in 4Q’16 and begin to draw down as demand growth joins non-

OPEC non-shale supply declines to tighten markets; prices could rise – how quickly might shale respond?

Source: EIA, Citi Research * see previous slide for rig count scenarios 28

2016 oil production growth already positive for rig

outlook* (Case 3 is base case, m b/d)

● As markets balance end-2016 and prices pick up,

how quickly and strongly might US production

respond? Productivity gains are already setting up

greater production growth in 2017; working down the

fracklog of drilled but uncompleted wells (DUCs) could

add up to an extra 0.4-m b/d within months (~0.2-m

b/d averaged over years 1-2).

● Crude production might be declining now, but it is

already on track to plateau in 2016, and then grow

again into 2017, although stripper wells could decline

more sharply, offsetting some shale gains.

● This could mean shale output stays robust even as

markets rebalance in 2017, keeping a cap on

upward surges in prices even through 2016 in our

base case.

Working down ~900 oil DUCs could add ~0.2-m b/d in

year 1, but monthly peak could be up to ~0.4-m b/d

OPEC Supply is Going Up Faster Than Shale is Going Down

Source: IEA, Baker Hughes, EIG, Citi Research

Saudi and GCC rig counts have been rising as the

US rig count has collapsed

Total Iraqi crude exports were over 1-m b/d higher y/y in

June, reaching a record 3.7-m b/d

29

● Saudi Arabia and its GCC allies are pursuing a

strategy of revenue maximization. Rig counts are

climbing and crude production is up 0.9-m b/d since

Nov-14 from Saudi Arabia, UAE, Kuwait and the

Neutral Zone.

● OPEC crude output hit 31.8-m b/d in July, well

above its 30-m b/d “quota”. In addition to GGC

growth, Iraqi output is being bolstered by Basrah and

Northern export growth, with October Basrah loadings

set for 3.7-m b/d, a massive 1.2-m b/d y/y increase.

● Iranian barrels are now very likely to hit the market

in 1Q’16.

Saudi and Iraqi crude production has surged since the Nov

27th OPEC meeting pushing output to 31.8-m b/d in July

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

Jan-13 Jun-13 Nov-13 Apr-14 Sep-14 Feb-15 Jul-15

Bashrah Light Basrah Heavy Northern Exports

-400

-200

0

200

400

600

800

1000

0

2

4

6

8

10

12Nov-14 Aug-15 Change - RHS

0

10

20

30

40

50

60

70

80

90

Jan-11 Aug-11 Mar-12 Oct-12 May-13 Dec-13 Jul-14 Feb-15

UAE Oil UAE Gas Kuwait Oil

Kuwait Gas Saudi Oil Saudi Gas

30

North Sea crude loadings (m b/d) Russian oil production (m b/d)

Mexican crude production is proving the

exception and is showing the strain (m b/d)

Brazilian crude production (m b/d)

Source: CDU-TEK, Bloomberg, PEMEX, Petrobras, Citi Research

Non-OPEC Non-Shale Production Not Showing Declines Yet, Except Mexico

1.5

1.7

1.9

2.1

2.3

2.5

2.7

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

2011 2012 2013 2014 2015

10.1

10.2

10.3

10.4

10.5

10.6

10.7

10.8

Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2011 2012 2013 2014 2015

1.7

1.8

1.9

2.0

2.1

2.2

2.3

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

2011 2012 2013 2014 2015

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

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

2011 2012 2013 2014 2015

Non-OPEC non-shale production has been sustained at-or-above year ago levels despite the collapse in oil

prices. Currency depreciation and tax changes have had a bigger impact than expected, helping extend

marginal well life despite sizeable cuts occurring to brownfield capex.

Saudi Arabia: what are they up to, and for how

long?

31

Shale Has Disrupted OPEC’s Ability to Manage Markets

Source: Bloomberg, EIA, JODI, Citi Research

In the early 2000’s the Saudi’s increased crude output

to meet the rapid growth in crude demand (m b/d)

32

But this didn’t address the light sweet shortage and

the Dubai-Dated Brent spread widened out, and as a

% of flat price reached ~-25% at its widest.

The light-sweet crude overhang has pushed Brent

timespreads (1st/12th) into contango ($/bbl)

With US crude imports (m b/d) from Africa almost

all gone, Latam imports could be next to fall

7.0

7.5

8.0

8.5

9.0

9.5

10.0

10.5

11.0

2002 2003 2004 2005 2007 2008 2009 2010 2012 2013 2014

-30%

-25%

-20%

-15%

-10%

-5%

0%

5%

2002 2003 2004 2005 2007 2008 2009 2010 2012 2013 2014

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

Jan-08 Nov-08 Sep-09 Jul-10 May-11 Mar-12 Jan-13 Nov-13 Sep-14

Tho

usan

ds Middle East Latam Canada Africa

-15

-10

-5

0

5

10

15

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

2011 2012 2013 2014 2015

6.0

6.5

7.0

7.5

8.0

8.5

9.0

9.5

10.0

10.5

11.0

Dec

-13

Jan-

14

Feb

-14

Mar

-14

Apr

-14

May

-14

Jun-

14

Jul-1

4

Aug

-14

Sep

-14

Oct

-14

Nov

-14

Dec

-14

Jan-

15

Feb

-15

Mar

-15

Apr

-15

May

-15

Jun-

15

Jul-1

5

Crude output (m b/d) Crude exports (m b/d)

Source: JODI, Saudi Aramco, Cargo Tracking, Citi Research

33

OPEC OSPs to Asia ($/bbl)

Saudi Crude Production and Exports (m b/d)

Saudi Production and Exports Have Ballooned in 2015

-5

-4

-3

-2

-1

0

1

2

3

4

5

Jun-12 Nov-12 Apr-13 Sep-13 Feb-14 Jul-14 Dec-14 May-15

Arab Light (Saudi) Basrah Light (Iraq)

Iran Light Kuwait

Saudi Crude Burn (m b/d)

Saudi Crude Stocks (m bbls)

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

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

2011 2012 2013 2014 2015

220

240

260

280

300

320

340

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

2011 2012 2013 2014 2015

34

Iranian crude and NGL production (m b/d)

Russia overtook Saudi as China’s biggest crude supplier

in May (m b/d)

Source: IEA, Chinese Customs, BP, Citi Research

Will Iran Re-enter Oil Markets with a Bang or a Whimper?

● Returning Iranian production looks very likely now

given recent activity in Congress. Crude exports

could increase by 300-500-k b/d by end-2016 with

perhaps a brief 500-700-k b/d spike at the start.

● Yet placing this crude may prove difficult, more so

in Asia than Europe. Asian buyers are suffering from

an embarrassment of riches as Middle Eastern,

Russian and African sellers compete for the one oil

short region left in the world.

● 500-k b/d of former imports of Iranian crude to

Europe could return post sanctions given historical

ties with refiners in the region. 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

2.5

2.7

2.9

3.1

3.3

3.5

3.7

3.9

4.1

4.3

2000 2001 2002 2004 2005 2007 2008 2009 2011 2012 2014

Crude Oil Natural Gas Liquids - RHS

Regional oil balances: Asia is the main short region

left (m b/d)

-25

-20

-15

-10

-5

0

5

10

15

20

25

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

N America Latin America Europe Mid East Africa Asia

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

2011 2011 2011 2012 2012 2013 2013 2013 2014 2014 2015

Saudi Arabia Russia Iran

-5

-4

-3

-2

-1

0

1

2

3

4

5

Jul-12 Dec-12 May-13 Oct-13 Mar-14 Aug-14 Jan-15 Jun-15

Arab Light (Saudi)Basrah Light (Iraq)Iran LightKuwait

250

270

290

310

330

350

370

390

410

430

Dec

-13

Jan-

14

Feb

-14

Mar

-14

Apr

-14

May

-14

Jun-

14

Jul-1

4

Aug

-14

Sep

-14

Oct

-14

Nov

-14

Dec

-14

Jan-

15

Feb

-15

Mar

-15

Apr

-15

May

-15

Jun-

15

Jul-1

5

Total oil stocks (m bbls) Crude stocks (m bbls)

-25

-20

-15

-10

-5

0

5

10

15

20

25

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

N America Latin America Europe Mid East Africa Asia

-30

-25

-20

-15

-10

-5

0

5

10

15

20

25

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

N America Latin America Europe Mid East Africa Asia

OPEC Market Share Showdown: Asia is a Key Battleground

Under pressure from shale production, OPEC is seeing its member states fight for market share. Iran remains a

weight on the market while Iraq is seeing its vast production growth potential actually play out. The GCC

countries are expanding capacity, preparing for competition, particularly for key Asian demand.

Source: JODI, BP, Citi Research 35

Saudi crude stocks and total crude+product stocks (m bbls)

Regional primary energy balances (m boe/d) Regional primary oil balances (m b/d)

OPEC OSPs to Asia saw sizeable cuts in October as

producers bid for market share ($/bbl)

Can demand come to the salvation of oil

markets?

36

Don’t Expect Demand To Fix This

Demand has responded to lower prices, but only in isolated regions and mainly for gasoline; alone this is not

enough to tighten global oil markets. Outside of the US, India and China, oil demand growth has been more

muted, while oil exporter countries could see further demand headwinds.

Source: EIA, China Customs, PPAC, JODI, Citi Research 37

Big oil importers are seeing

strong y/y demand growth (m b/d)

… but growth elsewhere is

struggling (m b/d)

Mid-East demand has struggled

with recent increases due to y/y

growth in crude burn (k b/d)

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15

India China

US Weekly Total

-600

-400

-200

0

200

400

600

Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15

Iran Iraq KuwaitQatar Saudi Arabia Total

-800

-600

-400

-200

0

200

400

600

Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15

Russia Japan Brazil

South Korea Mexico Total

38

Despite strong product demand, crude demand has

been even stronger (m b/d)

Product stocks at Singapore and ARA trading hubs have

blown out (m bbls) Northwest Europe cracking margins have softened

($/bbl)

Source: IEA, EIA, PAJ, PJK, International Enterprise, EUROIL, Citi Research

Product Demand is Now Being Overshadowed by Crude Demand

● The 1Q’15 bumper 1.8-m b/d y/y growth in

products demand outpaced run rate growth

prompting much stronger margins which were

then buoyed by summer gasoline dynamics.

● This has prompted refiners globally to ramp-up

runs, with crude runs expected to be 2-m b/d

higher y/y. This is now materializing in downstream

stockbuilds.

0.0

0.5

1.0

1.5

2.0

2.5

3.0

1Q15 2Q15 3Q15 4Q15

Petroleum Products Demand Crude Runs

Product Stockbuild

60

65

70

75

80

85

90

95

100

105

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

2011 2012 2013 2014 2015

How Low Could Demand Go (in a Sub-2% GDP Growth World)?

If a China-led global recession were to manifest next year, our estimates indicate that demand growth in 2016

could be even weaker than the disappointing growth seen in 2014 (and 2017 could be weaker still). Declines in

growth would be led be non-OECD Asia, Latin America and Russia.

Source: Citi Research * at market exchange rates 39

● Citi’s chief economist recently outlined a case for a China-led

global recession: China GDP growth declines to roughly 5%

(official forecast) in 2H’16 and stays low for a year before recovering

into 2018. Global growth slows to sub-2%* in this case.

● We estimate that such an event could reduce non-OECD oil

demand growth by ~0.6-m b/d in 2016 and ~1-m b/d in 2017

versus demand growth under base case GDP forecasts. Non-

OECD Asia would see the sharpest impacts. OECD demand growth

could be reduced by ~0.2-m b/d in both 2016 and 2017.

Estimated difference between base case oil

demand growth (m b/d) and growth in a sub-

2% GDP growth (China-led recession) world

2016 2017

OECD -0.19 -0.18

OECD Americas -0.11 -0.12

United States -0.07 -0.05

Canada -0.01 -0.03

Mexico/Chile -0.03 -0.05

OECD Europe -0.03 -0.03

OECD Asia -0.04 -0.03

Japan -0.02 0.00

South Korea -0.02 -0.03

Australia/New Zealand 0.00 0.00

Non-OECD -0.61 -1.02

Non-OECD Asia -0.18 -0.48

China -0.06 -0.19

India -0.06 -0.11

Other Non-OECD Asia -0.06 -0.18

Middle East -0.11 -0.15

Latin America -0.08 -0.14

FSU -0.19 -0.20

Africa -0.05 -0.06

Non-OECD Europe 0.00 0.00

-6.0

-4.0

-2.0

0.0

2.0

4.0

6.0

8.0

10.0

Bas

e C

ase

Glo

bal r

eces

sion

Bas

e C

ase

Glo

bal r

eces

sion

Bas

e C

ase

Glo

bal r

eces

sion

Bas

e C

ase

Glo

bal r

eces

sion

Bas

e C

ase

Glo

bal r

eces

sion

Bas

e C

ase

Glo

bal r

eces

sion

Bas

e C

ase

Glo

bal r

eces

sion

Bas

e C

ase

Glo

bal r

eces

sion

Bas

e C

ase

Glo

bal r

eces

sion

Bas

e C

ase

Glo

bal r

eces

sion

UnitedStates

Japan Euro Area UnitedKingdom

China India Indonesia Korea Russia Brazil

2016 2017

GDP growth in key countries/regions in base case and

global recession case (%)

Cost deflation and what it means for new supply

over the next half-decade

40

Cost Deflation: Lower, Flatter, More Responsive Cost Curve Points to $60-80

● After almost a decade of rampant cost inflation in upstream oil, the ~45% price drop has been

accompanied by and further fostered a decline in the costs of finding, developing oil.

1. Shale – Cost deflation is expected ~30% in 2015, and another 5-10% in 2016, putting shale firmly in 2nd

quartile of costs.

2. Deepwater – a 50% average drop in rig day rates since 2014; lower steel prices further reduce costs, but

drags on costs persist due to: backlog of shipyard orders, production sharing regimes in W. Africa, fiscal

terms elsewhere, and 2-3 year rig contract terms putting ~30% of projects underwater at $75/bbl. ~$76bn of

deepwater projects have been deferred. Yet, with Mexico’s opening, a GoM pickup is expected. Will deep

water costs keep slipping further? What implications for output?

3. Oil sands – With the bulk of projects tenuous >$90/bbl, prospects look constrained with some new projects

canceled/deferred, but oil sands producers have been surprised by cost deflation so far.

41

Deflationary potential strongest in middle of the curve (2015 vs 2014)

Source: Company data, Citi Research

Oil and gas services sector utilization rates have

plummeted…

50%

60%

70%

80%

90%

100%

'98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15E'16E'17E

Utilization, %

Floating drilling rigs Construction vessels Seismic vessels Pressure pumping

Shale well costs this year are set to fall 30% y/y, with another 5-10% expected in 2016. Producers are seeing

significant cost compression due to collapse in drilling and completion and declines in steel and diesel inputs.

Source: "U.S. Oil Services: Deflategate (Shale Well Cost) Update” (Scott Gruber, Sept 2015), Citi Research

42

Breakdown of 2014 costs for an average shale well

– cost base is biased towards drilling and

completion services

Cost declines by well component are substantial, leading

to overall declines in total well cost of ~26%

Shale: Well Costs Have Dropped 30% So Far, With More to Go

Shale’s Next Chapter: Higher Cost of Capital vs. Improving Efficiencies

Source: Citi E&P Research, Company Reports, EIA, Citi Research

Energy Loan Issuance ($ mln)

43

Citi’s HY Energy Index has declined since June, with

YTW on the index spiking relative to other HY sectors

Eagle Ford productivity gains YoY Permian productivity gains YoY

0

1000

2000

3000

4000

5000

6000

1-J

an

-09

1-M

ar-

09

1-M

ay-0

9

1-J

ul-

09

1-S

ep

-09

1-N

ov-0

9

1-J

an

-10

1-M

ar-

10

1-M

ay-1

0

1-J

ul-

10

1-S

ep

-10

1-N

ov-1

0

1-J

an

-11

1-M

ar-

11

1-M

ay-1

1

1-J

ul-

11

1-S

ep

-11

1-N

ov-1

1

1-J

an

-12

1-M

ar-

12

1-M

ay-1

2

1-J

ul-

12

1-S

ep

-12

1-N

ov-1

2

1-J

an

-13

1-M

ar-

13

1-M

ay-1

3

1-J

ul-

13

1-S

ep

-13

1-N

ov-1

3

1-J

an

-14

1-M

ar-

14

1-M

ay-1

4

1-J

ul-

14

1-S

ep

-14

1-N

ov-1

4

1-J

an

-15

1-M

ar-

15

1-M

ay-1

5

1-J

ul-15

Energy loan Issuance ($mn)

4

5

6

7

8

9

10

11

Yie

ld t

o W

ors

t

All HY Index

Energy HY

-60%

-40%

-20%

0%

20%

40%

60%

80%

No

v-0

9

Ma

r-1

0

Ju

l-1

0

No

v-1

0

Ma

r-1

1

Ju

l-1

1

No

v-1

1

Ma

r-1

2

Ju

l-1

2

No

v-1

2

Ma

r-1

3

Ju

l-1

3

No

v-1

3

Ma

r-1

4

Ju

l-1

4

No

v-1

4

Ma

r-1

5

Ju

l-1

5

Oil

Gas

-50%

0%

50%

100%

150%

200%

De

c-0

8

Ma

y-0

9

Oct-

09

Ma

r-1

0

Aug-1

0

Jan-1

1

Jun-1

1

No

v-1

1

Apr-

12

Sep-1

2

Feb

-13

Jul-1

3

De

c-1

3

Ma

y-1

4

Oct-

14

Ma

r-1

5

Aug-1

5

Oil

Gas

In deepwater, lower day rates and both capex and opex deflation improve economics, but companies are still

hesitant to pursue projects near the top of the cost curve. Cost declines could take several years to fully pass

through due to contract cycles and technical project complexity. Offshore breakeven costs might drop ~20%.

Source: Citi Oilfield Services team, ODS, company reports, Citi Research

44

Marginal deepwater floater rig day rates are down 50%

from 2014 highs, with potential additional 25% deflation

Offshore costs are continuing to deflate – how low can they go?

0

100

200

300

400

500

600

700

800

Jan-

04

Sep

-04

May

-05

Jan-

06

Sep

-06

May

-07

Jan-

08

Sep

-08

May

-09

Jan-

10

Sep

-10

May

-11

Jan-

12

Sep

-12

May

-13

Jan-

14

Sep

-14

May

-15

Jan-

16

Sep

-16

May

-17

Th

ou

san

d $

/ d

ay

Potential 25% further

deflation as utilization

could drop rates

another 8%

?

Deepwater F&D cost deflation expected

Capex Type Weight Deflation

Impact

on Cost

Finding Costs

Drilling Rig 30-35% -25% additional? -7.5 to 9%

Well Services 40-45% -10% -4 to 4.5%

Other (seismic, overheads, etc) 20-30%

Total -15 to 20%

Development Costs

Drilling rig 18% -30% -5%

Well services 20% -10% -2%

Facilities 29% -15% -4%

Subsea production hardware 10% -25% -3%

SURF and Pipelines 23% -20% -5%

Total 100% -19%

Competition for capital is critical over the next

3-5 years

45

Source: WoodMackenzie, EIG, Company Reports, IEA, Citi Research *excluding unconventional North American Projects

46

Big oil projects have slowed in 2015 (US $bn, gross capex)

Competition For Capital Will Be Critical Over Next 3-5 Years

Current prices may not support adequate long-term supply growth from more expensive projects, although

costs are still falling; Opportunities will be where returns are best, and here Mexico will find tough competition.

Brent and WTI deferred prices are currently pointing to

~$60 ($/bbl, futures curves at end-3Q’15)

But many IOC projects break even above $60 (IOC

project cost curve to 2020)

40

45

50

55

60

65

70

Oct

-15

Jan

-16

Ap

r-1

6

Jul-

16

Oct

-16

Jan

-17

Ap

r-1

7

Jul-

17

Oct

-17

Jan

-18

Ap

r-1

8

Jul-

18

Oct

-18

Jan

-19

Ap

r-1

9

Jul-

19

Oct

-19

Jan

-20

Ap

r-2

0

Jul-

20

Oct

-20

Jan

-21

Brent WTI

47

Easy access to capital was the essential “fuel” of the shale revolution as many producers depend on capital

market injections to fund ongoing activity. A larger “funding gap” and tighter capital market conditions in 2015

could see US production drop 500-k b/d by year end. Yet smaller producers tend to have worse free cash flow

and the bulk of producers with negative free cash flow are producing less than 200-k b/d liquids.

Source: Woodmac, Citi Research, *Note: CAPEX is upstream capex and does not include exploration capex or land acquisitions, ** Free cash flow shown is estimated as

operating cash flow less royalties less taxes less CAPEX.

Free cash flows vs. hydrocarbon production* **

-2000

-1000

0

1000

2000

3000

4000

0 200 400 600 800 1000 1200Fre

e C

ash

Flo

w (

$M

M)

Production (kboe/day, liquids & gas )

Total Producer Universe: 135 firms; Total Production: 15.3 MM boe/day (liquids & gas)

A Battle Between OPEC and North American Capital Markets

2010 2011 2012 2013 2014

Oil & gas revenue 150,266$ 181,162$ 180,342$ 198,731$ 217,417$

Lifting costs 39,706 50,552 56,357 59,782 63,912

Exploration expenses 4,786 5,558 6,791 7,561 9,320

DD&A (incl. writedowns/impairment) 43,957 50,680 80,182 72,681 95,386

Other expenses/(income) 2,970 3,653 (154) 5,928 4,612

Pre-tax profit 58,847$ 70,720$ 37,167$ 52,780$ 44,188$

Income tax/(benefit) 20,739$ 24,277$ 12,212$ 18,439$ 15,428$

Net income 38,108$ 46,443$ 24,955$ 34,340$ 28,760$

Operating Cash Flow 87,416$ 103,517$ 112,553$ 115,205$ 134,131$

Free cash flow (operating cash flow less F&D capex) (44,156) (30,435) (46,538) (24,492) (37,083)

Free cash flow for the top 50 US producers has been consistently negative and is getting worse creating a “funding gap”

M&A and Sector Consolidation Could Lead to a Healthier Industry

48

A stronger sector could emerge from the fire of distress with fewer, stronger firms as M&A picks up. M&A is now

cheaper than organically finding and developing reserves and enough distress should eventually entice buyers

off the sidelines. Major integrated firms, large E&Ps and private equity are all potential buyers.

Buying production is cheaper than organically

finding and producing it

Source: HIS Herold, , Citi Research

NAM unconventional upstream deal value by primary

resource segment

$0

$5

$10

$15

$20

$25

2009 2010 2011 2012 2013 2014 1H 2015

Three-yearweighted averageUS finding &development perboe

Total weighted-average 1P USdeal pricing

Gap between organic US reserve

$/b

oe

Source: IHS

0%

20%

40%

60%

80%

$0.0

$20.0

$40.0

$60.0

$80.0

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 1H2015

Unconventional-diversified

Heavy oil & EOR

Coalbed methane

Oil sands/bitumen

Tight oil/shale oil

Tight gas/shale gas

% of North America upstream deal value

% of North America upstream deal value (including Shell/BG North America allocation)

Tra

ns

acti

on

va

lue

($ b

illi

on

)

%o

f N

ort

h A

me

ric

a u

ps

tre

am

de

al

Source: IHS. Notes: Includes about $600 million from the $7 billion North America allocation of the Shell/BG deal

0

5

10

15

20

25

30

35

40

20

10

-01

2010-0

3

20

10

-05

20

10

-07

20

10

-09

20

10

-11

20

11

-01

20

11

-03

20

11

-05

20

11

-07

20

11

-09

20

11

-11

20

12

-01

20

12

-03

2012-0

5

20

12

-07

20

12

-09

20

12

-11

20

13

-01

20

13

-03

20

13

-05

20

13

-07

20

13

-09

20

13

-11

20

14

-01

20

14

-03

20

14

-05

20

14

-07

20

14

-09

20

14

-11

20

15

-01

20

15

-03

20

15

-05

20

15

-07

$/b

oe

Oil Weighted Average Implied Reserves Value

Gas Weighted Average Implied ReservesValue

0

2

4

6

8

10

12

14

Tra

nsa

ctio

n V

alu

es (

$ B

illio

ns)

Asset

Corporate

US implied reserve values from M&A transactions;

oil reserves have gotten much cheaper to acquire US M&A transaction activity has dropped off sharply

in 2015 as the “bid-ask” spread has widened

50%

60%

70%

80%

90%

100%

'98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15E'16E'17E

Utilization, %

Floating drilling rigs Construction vessels Seismic vessels Pressure pumping

Deepwater Could Increasingly Compete with Shale Going Forward

49

The lower oil price range resulting from the emergence of shale supply has led to careful scrutiny of future

deepwater projects. Despite declining costs and service sector utilization, competition with shale could become

more intense. Cost deflation in shale is expected to be faster.

Service sector utilization has plummeted

But shale investment profile more favorable than deepwater

Source: Company reports, ODS, Citi Research

● Deepwater cost compression should continue as utilization along

the supply chain remains under pressure.

● Complexity of deepwater projects may make cost compression

less responsive globally than for the shale sector. With the,

emergence of shale and the drop in oil prices to the $60 level, some

30% of deepwater projects now may not be sanctioned but Mexico’s

opening could boost deepwater in both US and Mexican GoM.

● As shale remains more attractive than deepwater (below right), it

would take a larger share of overall investment flows and a larger share

of output.

● As deepwater costs decline, lower costs of infill drilling could slow

deepwater decline rates

Factor Shale Deepwater

Investment Dynamics

FID every ~20 days; scales up and down

quickly

Large, lumpy investment schedule;

scales up/down slowly

Cost Deflation

Potential up to 25% up to 20%

Cost Deflation Timing quick- majority of gains in 12mo slow - multiple years

Cost Deflation Pass-

through

high- US production taxes pass benefit to

oil company

variable- in multiple geographies

production sharing contracts pass benefit

to governments

Environmental Risk low- largely localized at well site large- e.g. Macondo

Execution Risk

low - shale manufacturing plus portfolio

effect

high - frequent delays and overruns in

sanctioning and fabrication

Depletion Rate high- ~60% in year 2, ~30% base modest- 0 in first few years, ~20 base

Maintenance easy - install pump, refrac, etc. difficult - expensive to access

Global Oil Supply Demand Balance: Light at the End of the Tunnel end-2016?

Source: IEA, Bloomberg, Citi Research

50

Demand 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2013 2014 2015 2016 14' 15' 16' 15%

OECD Americas 24.2 24.1 24.8 25.0 24.6 24.4 25.1 25.3 24.1 24.1 24.5 24.9 0.07 0.40 0.34 1.7%

OECD Europe 13.4 13.5 13.8 13.4 13.5 13.6 13.8 13.5 13.6 13.4 13.5 13.6 -0.21 0.16 0.05 1.2%

OECD Asia 8.8 7.7 7.7 8.3 8.7 7.6 7.6 8.3 8.4 8.2 8.1 8.1 -0.20 -0.05 -0.04 -0.6%

OECD Demand 46.5 45.3 46.3 46.7 46.8 45.6 46.6 47.1 46.0 45.7 46.2 46.5 -0.34 0.51 0.35 1.1%

China 10.8 11.2 10.8 11.2 11.1 11.5 11.1 11.5 10.3 10.6 11.0 11.3 0.34 0.38 0.30 3.6%

India 3.9 4.0 4.0 4.2 4.2 4.3 4.2 4.4 3.7 3.8 4.0 4.3 0.07 0.26 0.25 0.07

Other Asia 8.5 8.5 8.4 8.6 8.6 8.7 8.5 8.7 8.1 8.3 8.5 8.6 0.15 0.23 0.15 0.03

Africa 4.1 4.1 4.0 4.0 4.2 4.2 4.1 4.1 3.9 4.0 4.0 4.1 0.07 0.08 0.10 0.02

Non-OECD Europe 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.02 0.01 0.00 0.02

FSU 4.6 4.8 4.8 4.8 4.6 4.7 4.7 4.7 4.7 4.9 4.7 4.7 0.17 -0.14 -0.08 -0.03

Latin America 6.7 6.9 7.0 7.0 6.8 6.9 7.0 7.0 6.7 6.8 6.9 6.9 0.16 0.06 0.04 0.01

Middle East 7.7 8.3 8.7 8.1 8.0 8.6 9.0 8.4 7.9 8.1 8.2 8.5 0.18 0.14 0.25 0.02

Non-OECD Demand 47.1 48.4 48.4 48.6 48.1 49.5 49.4 49.6 45.9 47.0 48.1 49.1 1.16 1.09 1.01 2.3%

Total Demand 93.5 93.7 94.7 95.3 94.9 95.1 96.1 96.7 91.9 92.7 94.3 95.7 0.82 1.60 1.36 1.7%

1.77 1.81 1.43 1.41

Supply 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2013 2014 2015 2016 14' 15' 16' 15%

US 12.7 13.0 12.8 12.7 12.6 12.6 12.5 12.6 10.3 12.0 12.8 12.5 1.69 0.83 -0.23 7.0%

Canada 4.5 4.1 4.3 4.4 4.6 4.1 4.4 4.5 4.0 4.3 4.3 4.4 0.27 0.07 0.05 1.5%

Mexico 2.7 2.6 2.7 2.6 2.5 2.5 2.5 2.5 2.9 2.8 2.6 2.5 -0.09 -0.19 -0.11 -6.8%

Brazil 2.5 2.5 2.5 2.6 2.7 2.6 2.6 2.8 2.1 2.4 2.5 2.7 0.23 0.20 0.11 8.4%

North Sea 3.0 3.1 2.9 3.0 2.9 3.0 2.7 2.8 2.9 2.9 3.0 2.9 0.04 0.10 -0.16 3.4%

Russia 11.0 11.0 10.9 11.1 11.1 11.1 11.0 11.1 10.8 10.9 11.0 11.1 0.11 0.10 0.05 0.9%

Other Non-OPEC 17.6 17.5 17.3 17.2 17.1 17.1 17.1 17.0 17.5 17.4 17.4 17.1 -0.03 -0.04 -0.34 -0.2%

Non-OPEC 54.1 53.7 53.4 53.6 53.4 53.0 52.8 53.2 50.4 52.6 53.7 53.1 2.21 1.07 -0.62 2.0%

Algeria 1.1 1.1 1.1 1.1 1.1 1.1 1.0 1.0 1.1 1.1 1.1 1.0 -0.03 -0.01 -0.07 -

Angola 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.7 1.7 1.8 1.8 -0.06 0.10 0.00 -

Ecuador 0.5 0.5 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.6 0.5 0.4 0.03 -0.08 -0.07 -

Iraq 3.5 3.9 4.2 4.1 4.1 4.2 4.2 4.2 3.1 3.3 3.9 4.2 0.25 0.60 0.23 -

Iran 2.8 2.9 2.8 2.9 3.3 3.2 3.3 3.4 2.7 2.8 2.9 3.3 0.13 0.04 0.45 -

Kuwait 2.8 2.8 2.8 2.8 2.9 2.9 2.9 2.9 2.8 2.8 2.8 2.9 -0.01 -0.01 0.11 -

Libya 0.4 0.5 0.4 0.4 0.4 0.4 0.4 0.4 0.9 0.5 0.4 0.4 -0.44 -0.05 -0.01 -

Nigeria 1.8 1.8 1.8 1.7 1.7 1.7 1.7 1.7 2.0 1.9 1.8 1.7 -0.05 -0.13 -0.07 -

Qatar 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 -0.02 -0.02 0.02 -

Saudi 9.9 10.3 10.2 10.2 10.2 10.2 10.2 10.2 9.7 9.7 10.1 10.2 0.06 0.43 0.05 -

U.A.E 2.8 2.9 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 0.00 0.07 -0.03 -

Venezuela 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.5 2.5 2.4 2.4 -0.03 -0.06 -0.03 -

OPEC Crude 30.5 31.5 31.4 31.3 31.8 31.7 31.7 31.8 30.5 30.3 31.2 31.7 -0.18 0.89 0.57 2.9%

OPEC Unconventional 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.2 0.3 0.3 0.3 0.02 0.01 0.01 5.5%

OPEC NGLs 6.2 6.3 6.3 6.4 6.5 6.5 6.6 6.6 6.0 6.1 6.3 6.5 0.16 0.19 0.25 3.1%

OPEC Oil 36.9 38.1 38.0 38.0 38.5 38.5 38.6 38.7 36.6 36.6 37.7 38.6 0.00 1.09 0.82 3.0%

Processing Gains 2.2 2.2 2.2 2.2 2.3 2.3 2.4 2.3 2.2 2.2 2.2 2.3 0.04 0.00 0.12 0.0%

Global Biofuels 1.8 2.4 2.8 2.4 1.9 2.4 2.8 2.4 2.0 2.2 2.3 2.4 0.17 0.15 0.03 6.8%

Total Supply 95.0 96.3 96.4 96.2 96.1 96.1 96.5 96.6 91.3 93.7 96.0 96.3 2.41 2.31 0.34 2.5%

Implied Stockbuild 1.5 2.6 1.7 0.9 1.2 1.0 0.4 -0.1 -0.6 1.0 1.7 0.6

"Call on US Production" 11.2 10.4 11.1 11.8 11.4 11.5 12.1 12.7 11.1 11.0 11.1 11.9 - 0.13 0.79 -

Stockbuild adjustments 1.1 1.0 0.7 0.7 0.6 0.5 0.3 0.5 0.7 1.0 0.4

Adj. implied stockbuild 0.3 1.6 1.0 0.2 0.6 0.6 0.1 -0.6 0.2 0.8 0.2

Adj. "Call on US production" 12.3 11.4 11.8 12.5 12.0 12.0 12.4 13.1 11.7 12.0 12.4

Price outlook ($/bbl) 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 2014 2015 2016

Brent 55 64 50 44 44 50 55 60 100 53 52

WTI 49 58 45 39 39 46 51 55 93 48 48

Brent-WTI 7 6 5 5 5 4 4 5 7 6 5

In the long-run, we are all dead…

51

52

Fuel-Efficiency/Fuel-Substitution Remain A Threat To Oil Demand Growth

Oil demand growth – the end is nigh? Transportation is only 1/3 of oil demand

Source: Citi Research

Natural gas substituting for oil, coupled with the increasing car and truck fuel economies already in play, is

enough to mean an end to global oil demand growth is closer than the market seems to think

88

90

92

94

96

98

100

2012 2013 2014 2015 2016 2017 2018 2019 2020

Business As Usual

After vehicle efficiency gains

After gas substitution

0 5 10 15 20 25

Rail

Shipping

Other transport

Aviation

Electricity

Petrochemicals

Residential

Trucks

Other industrials

Cars

52

Increasing Efficiency Is a Threat to All Forms of Energy Demand

Source: EIA, The International Council for Clean Transportation, Citi Research

53

Global fuel economy mandates should drive

improvements in efficiency.

As improvements are made in demand management and

efficiency, US electricity demand growth is decoupling

from GDP growth.

-4%

-3%

-2%

-1%

0%

1%

2%

3%

4%

5%

6%

1996 1998 2000 2002 2004 2006 2008 2010 2012 2014

Electricity Demand Growth Real GDP Growth

The majority of global gas contracts are linked to oil prices, often by a 15% slope and a 3-month lag. Spot LNG

and 3-month-out oil-linked prices at ~$8/MMBtu make Australian and even some US projects uneconomical. But

much like oil, weak demand and impending new supply will keep near-dated prices down.

Source: EIG, WoodMackenzie, Citi Research

Spillover Effects: Oil Linkage Has Crashed Global Gas Prices

54

Spot Asian LNG Price ($/MMBtu) LNG Project Breakevens ($/MMBtu)

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

$18.00

$20.00

Ras

Gas

I

Ras

Gas

II

AD

GA

S

Aru

n

Bru

nei L

NG

Qal

hat L

NG

Atla

ntic

LN

G 4

Gol

den

Pas

s E

xpor

t

Dar

win

NLN

G B

ase

Dam

ietta

ELN

G 1

Levi

atha

n F

LNG

Bra

ss L

NG

Tan

gguh

Pha

se 2

DS

LN

G

Ang

ola

LNG

PN

G L

NG

LNG

Can

ada

Kiti

mat

LN

G

Bro

wse

Sak

halin

2

Aus

tral

ia P

acifi

c LN

G

PE

TR

ON

AS

FLN

G 1

FO

B B

reak

even

Pric

e (U

S$/

mm

btu)

0

5

10

15

20

25

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

2011 2012 2013 2014 2015

Source: Platts, Citi Research

55

Premium Asian LNG market contracts vs demand JKM premium vs NBP and HH has closed recently

Contracted Asian Supplies Should Keep Spot LNG Prices Subdued

Source: Woodmac, Citi Research

56

Global LNG supply/demand, supply by project

progress, showing many projects in FEED face delays

Global LNG supply/demand, supply forecast by country,

North American proposed exports dominate the

landscape

LNG Oversupply is Expected to Persist this Decade

Source: Bloomberg, company reports, Citi Research 57

As N. American LNG projects get closer to coming online, slow load growth and competition from renewables

may hamper demand growth. Additionally, low oil prices put the delivered price of US LNG into Asia in tighter

competition with oil-indexed prices, even with the help of the Panama Canal opening in 2016.

The clear advantage of US LNG exports to Asia over

oil-indexed LNG is much-eroded (based on oil futures)

6

7

8

9

10

11

Jul-1

5

Nov

-15

Mar

-16

Jul-1

6

Nov

-16

Mar

-17

Jul-1

7

Nov

-17

Mar

-18

Jul-1

8

Nov

-18

Mar

-19

Jul-1

9

Nov

-19

Mar

-20

Jul-2

0

Nov

-20

$/M

MB

tu

Oil Index 13.5%

Delivered HH Asia- Panama Canal RT

Demand growth looks weaker-than-expected

● Japan, South Korea and China make up ~60% of the

global LNG market and the current consumption

weakness continuing into 2016 could sharply reduce

the need for additional LNG imports.

– In China and Korean, a macro slowdown and low oil

prices are all affecting gas demand growth.

– In Japan, 2016 should also be the first full year with

nuclear generation coming back into service since the

complete shutdown of nuclear.

● Europe makes up ~16% of the global LNG market. The

long-term decline in weather-normalized gas demand

looks to continue. Looking ahead, relying on Europe as a

destination for US LNG will likely intensify price-

competition against other LNG sources and Russian

supply. Such competition should weaken the netback of

future US LNG exports.

● Middle East and North Africa should see strong gas

demand growth, but some of the demand would be

sourced from domestically produced gas and the

absolute size of growth pales in comparison to other

regions in the world.

● Hence, global LNG prices could stay low and range-

bound in the $6 to $8/MMBtu range from now to 2020.

Low oil prices also threaten competitiveness of US LNG

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

2014

Elec

tric

ity G

ener

atio

n G

row

th (%

)

Total Middle East Total Asia Pacific

An electricity demand growth deceleration in key LNG

markets and low oil prices reducing LPG prices should

limit gas demand growth potential

Global LNG: new projects confront softer demand, lower prices

58

US LNG projects moving ahead despite looming oversupply

Source: DOE, BP, IEA, Exxon, EIA, Woodmac, Citi Research

US should contribute majority of LNG supply growth

post-2015… but supply shortage possible post-2023

-

10

20

30

40

50

60

20

00

20

02

20

04

20

06

20

08

20

10

20

12

20

14

20

16

20

18

20

20

20

22

20

24

Bcf

/d

West Africa

South America

South & East Africa

North America

North Africa

Middle East

Europe

Asia Pacific

Global LNG demand growth may be more limited

Source: BP, Citi Research

59

Regional Primary Energy Balances in Mboe/d

Asia is the Only Energy Short Left

-30

-25

-20

-15

-10

-5

0

5

10

15

20

25

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

N America Latin America Europe Mid East Africa Asia

-25

-20

-15

-10

-5

0

5

10

15

20

25

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

N America Latin America Europe Mid East Africa Asia

Regional Primary Oil Balances in M b/d

Source: EIG, Citi Research

Developing Asia LCOE ($/MWh)

Japanese LCOE ($/MWh) European LCOE ($/MWh)

60

Solar is becoming increasingly competitive globally

US LCOE ($/MWh)

0

50

100

150

200

250

300

Dec-09 Jul-10 Feb-11 Sep-11 Apr-12 Nov-12 Jun-13 Jan-14 Aug-14 Mar-15

Coal with CCS Gas CCGT Large Hydro

Large Solar PV Nuclear Wind Onshore

0

50

100

150

200

250

300

Jan-10 Aug-10 Mar-11 Oct-11 May-12 Dec-12 Jul-13 Feb-14 Sep-14 Apr-15

Coal with CCS Gas CCGT

Large Hydro Large Solar PV

Nuclear Wind Onshore

0

50

100

150

200

250

300

350

400

Dec-09 Jul-10 Feb-11 Sep-11 Apr-12 Nov-12 Jun-13 Jan-14 Aug-14 Mar-15

Coal with CCS Gas CCGT Large Hydro

Large Solar PV Nuclear Wind Onshore

0

100

200

300

400

500

600

700

Dec-09 Jul-10 Feb-11 Sep-11 Apr-12 Nov-12 Jun-13 Jan-14 Aug-14 Mar-15

Coal with CCS Gas CCGTLarge Hydro Large Solar PVNuclear Wind Onshore

Source: Citi Research estimates

61

Asia is Set to Lead the way in Solar Capacity Additions

0

100

200

300

400

500

600

2007A 2008A 2009A 2010A 2011A 2012A 2013A 2014A 2015E 2016E 2017E 2018E 2019E 2020E

ROW

South Africa

Australia

Other Asia

India

Korea

China

Japan

Rest of Latam

Chile

Canada

USA

ROE

UK

France

Spain

Germany

Italy

Expected Solar Capacity by Region (GW)

● 2015 – Depression: In addition to lower oil prices putting downward pressure on NGL prices, strong NGL production growth

momentum and a shortage of LPG ships hindering exports contribute to an oversupplied environment, even with export

facilities ready to operate. See Citi’s report “US Gas/LPG: Exit Strategy Needed” (June 2015).

● 2016 – Resurgence: Fundamentals should tighten and prices should recover on (a) a necessary slowdown in gas production

due to concerns on storage capacity, (b) a possible further slowdown in NGL production growth because of low prices in 2015,

and (c) a surge of LPG ships to match export capacity and facilitate exports.

● 2017 – Stabilization: Continued production growth amid a lack of robust domestic demand growth could add to oversupply

again. Rising global inter-fuel competition may reduce the appeal of additional US-sourced NGLs in the global market.

Combined, they should weaken NGL prices again, but likely not to the extent of the 2015 fall, as the export supply-chain should

have worked out its kinks.

Going forward, NGL pricing is likely to evolve in three phases, with 2015 looking bleak before markets reach a

recovery by 2017.

62

World liquids supply outlook by type: NGLs to

gain sizeable share in the year to come

NGL prices at Mont Belvieu, TX, keep falling

and diverge vs. oil in 2015

The NGL price ratio to WTI fell from the 40%

range to at times below 30%

30

40

50

60

70

80

90

100

30

40

50

60

70

80

90

100

Sep

-14

Oct-

14

No

v-1

4

De

c-1

4

Ja

n-1

5

Fe

b-1

5

Ma

r-15

Apr-

15

Ma

y-1

5

Ju

n-1

5

Bre

nt

($/b

bl)

Ce

nts

/ga

llo

n

NGL basket (Mont Belvieu TX) Brent Oil

20

30

40

50

60

70

80

90

25%

30%

35%

40%

45%

Dec-1

4

De

c-1

4

Ja

n-1

5

Fe

b-1

5

Ma

r-15

Ma

r-15

Apr-

15

Ma

y-1

5

Ma

y-1

5

Ju

n-1

5

Bre

nt

pri

ce

($/b

bl)

NG

L b

as

ke

t p

ric

e v

s. B

ren

t o

il

% Brent-MB CO-ICE

Source: Exxon, Platts, Citi Research

New industry paradigm from new NGL pricing

● Citi is forecasting lower US NGL production growth out to 2020 – we revise NGL production in 2020 to

5.2-mb/d versus 6.1-mb/d as presented in Citi GPS “Out of America” (Nov’14) – in response to lower levels of

oil and gas drilling, less favorable NGL vs dry gas pricing dynamics, and lower gas production required in the

years ahead.

● In the past, NGL production was boosted by strong natural gas production and the expectation that

higher NGL prices could give production economics a lift. Around 80% of US NGL production comes

from natural gas fields, with the remainder coming from crude oil wells. A bullet point that contains a series of

sentences requires a period at the end of every sentence, except the last one.

● Gas production growth should slow in 2016, as expected natural gas inventory could reach unrealistically

high levels beyond storage capacity if the current rate of growth were to continue. Along with lower oil

prices reducing NGL prices and NGL’s own oversupply depressing their value, NGL production

growth should slow sharply in 2016.

While still seeing oversupply, Citi revises down its NGL production forecast due to three reasons: (1) lower levels

of oil and gas drilling, (2) less favorable NGL versus dry gas pricing dynamics, and (3) lower gas production

required in the years ahead.

63

NGL 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Production 2.7 2.8 3.0 3.2 3.6 4.1 4.2 4.4 4.7 5.0 5.2

Ethane 0.9 0.9 1.0 1.0 1.1 1.3 1.3 1.5 1.6 1.7 1.8

Propane 1.1 1.2 1.3 1.4 1.6 1.7 1.7 1.8 1.8 1.9 2.0

Butane+Isobutane 0.4 0.4 0.5 0.5 0.6 0.7 0.7 0.7 0.8 0.8 0.8

Pentane+ 0.26 0.27 0.30 0.33 0.37 0.43 0.44 0.47 0.50 0.54 0.6

Net demand 2.7 2.7 2.8 3.0 2.9 3.0 3.1 3.2 3.4 3.6 3.8

Production - Demand 0.0 0.1 0.2 0.2 0.7 1.1 1.1 1.2 1.2 1.4 1.5

Citi NGL supply/demand balance to 2020

Source: Citi Research

Oversupply defines the US market

64

Source: EIA, Citi Research

Ethane supply-demand forecasts (not including rejected ethane of

around 0.3-mb/d) – demand appears to almost match supply, but

ethane rejection should widen the “true” gap

Propane supply-demand forecasts – modest demand growth, with new

PDHs, can’t keep the pace with the supply boom

Butane + Isobutane supply-demand forecasts – flat demand growth

expected while supply growth should take-off

Pentane+ supply-demand forecasts – flat to slightly negative demand

growth expected while supply growth should take-off

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

2.002

01

0

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

mb

/d

PADD 5

PADD 4

PADD 3

PADD 2

PADD 1

Demand

0.00

0.50

1.00

1.50

2.00

2.50

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

mb

/d

PADD 5

PADD 4

PADD 3

PADD 2

PADD 1

Demand

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

mb

/d

PADD 5

PADD 4

PADD 3

PADD 2

PADD 1

Demand

0.00

0.10

0.20

0.30

0.40

0.50

0.60

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

mb

/dPADD 5

PADD 4

PADD 3

PADD 2

PADD 1

Demand

All NGLs look oversupplied, but to varying degrees

● Export capacity is growing: In April 2014, only limited terminal capacity for waterborne LPG exports of ~0.4-mb/d was online.

However, by April of this year, ~0.8-mb/d of LPG export capacity was available. By the end of 2018, this number could rise to 1.7-

1.8-mb/d if all proposed projects proceed. Even if only sanctioned projects are completed, LPG export capacity would rise to 1.6-

mb/d by 4Q’16.

● Due to more favorable transport/storage economics, most export capacity expansions only accommodate LPG; Heavier

NGLs, such as propane and butane (or LPG), are easier and cheaper to transport and store due to their higher boiling point, while

lighter ethane requires costly refrigeration. However, some ethane export capacity is also expected to come online.

● Much of this expected export capacity expansion will help to ease the Northeast regional glut by transporting NGLs

from the Marcellus and Utica plays to export facilities in the Northeast and Gulf Coast. In particular, Sunoco’s Mariner East

pipeline should have a total of ~70-kb/d of capacity online by the end of this year (Phase I), and expand a further 275-kb/d in 2016

(Phase II) to bring total export capacity to 345-kb/d.

Export capacity expansions are poised to relieve some of the glut as the landscape for NGL exports is set to

change dramatically.

65

Source: Company reports, Citi Research

Propane and butane exports have risen in line with export capacity

expansions

LPG export capacity scheduled to come online in the next several years

could potentially increase US exports of LPG to 1.8-mb/d

0

100

200

300

400

500

600

700

800

900

1/1/

2013

2/1/

2013

3/1/

2013

4/1/

2013

5/1/

2013

6/1/

2013

7/1/

2013

8/1/

2013

9/1/

2013

10/1

/201

3

11/1

/201

3

12/1

/201

3

1/1/

2014

2/1/

2014

3/1/

2014

4/1/

2014

5/1/

2014

6/1/

2014

7/1/

2014

8/1/

2014

9/1/

2014

10/1

/201

4

11/1

/201

4

12/1

/201

4

1/1/

2015

2/1/

2015

3/1/

2015

4/1/

2015

Export capacity Propane Export Butane Export

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2014 2015 2016 2017 2018 2019 2020

mb/d Current Sanctioned Proposed

Propane and butane exports have risen in line with export capacity

expansions

Exports become a key response to domestic oversupply

66

Source: Clarksons, Llyods, EIA, Citi Research

LPG vessel fleet growing in recent years (cubic meters)

LPG vessel fleet growing in recent years (number of vessels)

16,500,000

17,000,000

17,500,000

18,000,000

18,500,000

19,000,000

19,500,000

20,000,000

20,500,000

21,000,000

2010 2011 2012 2013 2014 2015

cub

ic m

ete

rs

1,150

1,200

1,250

1,300

1,350

1,400

1,450

1,500

1,550

2010 2011 2012 2013 2014 2015

nu

mb

er

of

vess

els

Cumulative LPG ship additions

Cumulative LPG ship additions after adjusting for voyage time (over 50

days roundtrip with additional days for loading/unloading)

0

1

2

3

4

5

6

7

0

10

20

30

40

50

60

Jun

-15

Au

g-1

5

Oct

-15

Dec

-15

Feb

-16

Ap

r-16

Jun

-16

Au

g-1

6

Oct

-16

Dec

-16

Feb

-17

Ap

r-17

Jun

-17

Au

g-1

7

Oct

-17

Dec

-17

Feb

-18

Ap

r-18

Dea

dw

eigh

t (m

t)

Esti

mat

ed c

apac

ity

(mb

)

Thousand BBLs Sum of DWT

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

Jun

-15

Au

g-1

5

Oct

-15

Dec

-15

Feb

-16

Ap

r-16

Jun

-16

Au

g-1

6

Oct

-16

Dec

-16

Feb

-17

Ap

r-17

Jun

-17

Au

g-1

7

Oct

-17

Dec

-17

Feb

-18

Ap

r-18

mb

/d

After infrastructure arrives, shipping capacity key to watch

Source: EIA, Platts, Citi Research

Key supply-demand drivers

● US: Exports should drive

“demand” growth, led by LNG

exports and exports to Mexico.

Domestic demand growth may be

driven by industrials only, as soft

power load growth and the rise of

renewables reduce the need for gas-

fired generation.

● Hence, the US production growth

does not need to be as strong as

we thought, thereby keeping prices

low.

● Canada: Limited internal demand,

other than industrials and oil sands

processing, and strong US

production should limit Canadian

gas production growth, but Canada

could act as the swing supplier

should US demand rise more. LNG

exports from Canada are unlikely

before 2020.

● Mexico: Imports of US gas should

grow, as expensive LNG is backed

out, enhanced oil recovery raises

demand, fuel oil as a power

generation fuel is substituted and

power load growth is met by gas

plants, and as industry expands.

67

US 2012 2013 2014 2015 2016 2017 2018 2019 2020

Total Supply 69.2 70.1 74.4 77.6 76.5 76.4 77.0 78.0 78.9

Production* 64.9 66.2 70.7 75.0 76.4 79.4 82.8 86.4 88.7

LNG Imports 0.4 0.2 0.2 0.2 0.1 0.1 0.1 0.0 0.0

Exports to Mexico (1.6) (1.9) (2.0) (2.8) (3.7) (4.6) (5.1) (5.5) (6.1)

Imports from Canada 5.5 5.6 5.5 5.4 4.8 4.3 4.3 4.3 4.3

LNG Exports - - - (0.1) (1.1) (2.7) (5.0) (7.2) (8.1)

Demand 69.7 71.7 73.8 76.6 75.7 76.4 77.0 78.0 78.9

Industrials 19.5 20.4 21.2 22.0 22.7 23.7 24.5 25.3 26.1

ResComm 19.3 22.9 23.7 23.3 22.5 22.7 22.9 23.1 23.2

Electricity Generation 25.0 22.4 22.8 24.9 24.1 23.3 22.8 22.6 22.3

Pipe Use 1.9 2.0 2.1 2.1 2.1 2.1 2.1 2.2 2.2

Lease and Plant Fuel 3.8 3.8 3.9 4.0 4.0 4.2 4.3 4.5 4.6

Transport 0.1 0.1 0.2 0.2 0.3 0.3 0.4 0.4 0.5

Growth

Production* 1.3 4.5 4.3 1.5 2.9 3.4 3.6 2.3

GDP 2.30% 1.90% 2.30% 3.25% 2.80% 2.50% 2.50% 2.50% 2.50%

Canada 2012 2013 2014 2015 2016 2017 2018 2019 2020

Total Supply 8.6 8.2 8.6 8.5 9.4 9.4 9.7 9.9 10.1

Production 13.9 13.8 13.8 13.6 14.0 13.6 13.9 14.1 14.4

LNG imports 0.2 0.1 0.0 0.1 0.0 0.0 0.0 0.0 0.0

Pipe imports (5.4) (5.6) (5.2) (5.2) (4.7) (4.3) (4.3) (4.3) (4.3)

Total Demand 7.9 8.3 8.5 8.8 9.0 9.2 9.5 9.7 10.0

Industrials 3.7 4.0 4.1 4.4 4.7 4.9 5.2 5.4 5.6

Electricity 1.5 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3

Residential/Commercial 2.7 3.0 3.0 3.1 3.0 3.0 3.0 3.0 3.0

Transportation - - - - - - - - -

Other 0.1 0.3 (0.1) 0.4 0.2 0.2 0.2 0.2 0.2

Mexico 2012 2013 2014 2015 2016 2017 2018 2019 2020

Total Supply 6.8 7.5 8.0 8.8 9.3 9.5 9.9 10.3 10.8

Production 4.6 4.8 4.9 4.7 4.6 4.5 4.5 4.6 4.6

Pipe imports 1.7 1.9 2.0 2.8 3.7 4.6 5.1 5.5 6.1

LNG imports 0.5 0.8 1.1 1.3 1.0 0.4 0.3 0.2 0.1

Total Demand 6.7 7.5 8.0 8.8 9.3 9.5 9.9 10.3 10.8

Petroleum 2.3 2.4 2.4 2.8 2.9 2.8 2.8 2.8 2.8

Industrial 1.2 1.2 1.4 1.5 1.6 1.7 1.7 1.8 1.9

Power 3.1 3.8 4.1 4.4 4.6 4.9 5.2 5.6 5.9

ResComm 0.1 0.1 0.1 0.1 0.1 0.1 0.2 0.2 0.2

Transport - - - - - - - - -

Long-term North American balances: lower demand growth

68 Source: State data, Company reports, EIA, Citi Research

A partial recovery in rigs (+100 by Dec’15) would keep

production rising, but this would overwhelm storage

For now, Northeast production continues to edge higher

(6.0)

(4.0)

(2.0)

0.0

2.0

4.0

6.0

8.0

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

Bcf

/d

Bakken

Utica

Marcellus

Fayetteville

Woodford

Anadarko

Eagle Ford

Haynesville

Barnett

Production ex-key basins

● Growth paths of gas production may be hitting a

critical juncture: when counts again increase depends

on the price outlook, the financing environment, and

local conditions.

● The oversupply condition looks to worsen if there is

any rig rebound. Producers may actually need to drop

rigs to balance the market in 2016 and avoid pushing up

against October storage limits.

● Weak NGL pricing also affects production

economics, particularly in the Utica. This could

further constrain production in the coming months as

NGL prices have declined substantially

● For now, production is continuing to climb in the

Northeast, but a slow down may be on the horizon

Utica well-level returns can be dramatically affected by

NGL prices (different cases of oil prices)

-15%

-10%

-5%

0%

5%

10%

20% 30% 40% 50%

IRR (%)

NGL Price Ratio to Oil (%)

50 60 70

US gas growth slowdown may be too little too late

There are many other lessons:

69

Source: Citi Research

● The winners and losers are a lot less clear-cut as

producers become consumers and need to increase

efficiency via price liberalization and as large consumers

became significant producers

● Declining oil prices is no longer as zero-sum as it used to

be, but does that mean collusion is still possible?

● Oil in the ground appears to be worth more than oil

produced

● With producers maximizing production, relying on financial

markets and non-OPEC production to balance markets

spells volatility

And, even so, there are lots of uncertainties:

70

Source: Citi Research

● How resilient are shale and deep water?

● How will shale and deep water output respond in the

future? Will they respond before markets tighten

significantly?

● Are there market substitutes for Saudi spare capacity?

● Will growing inventories eventually bring prices way

down?

● Will the “failure of the petro-state” create more disruptions

and more price spikes?

● Will “failed petro-states” bring back 3-m b/d of existing

‘disrupted’ supply?

● Will the end of quantitative easing rein in the impact of

financial markets on supply and price volatility?

71

Appendix A-1

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