Implication of Global Trends on Brazil’s E&P Sector · Feb 15: Santos postpones Ande Ande. Aug...

Confidential. © 2017 IHS MarkitTM. All Rights Reserved.

Implication of Global Trends on Brazil’s E&P Sector

Ricardo BedregalHead - Latin America | Upstream Research & [email protected]

Seminário BRITCHAM:

A Competitividade do Mercado de Petróleo e Gás Brasileiro

mailto:[email protected]


Contents

2

Oil Market Dynamics: Short & Medium Term Price Outlook

Global E&P Investment Trends

Development Cost Dynamics

Deepwater Developments: Brazil vs. Others

Seminário BRITCHAM: A Competitividade do Mercado de Petróleo e Gás Brasileiro


Oil market dynamics are driven by multiple, interacting factors

3

Supply growth

Commercial Inventories

Financial players’

expectations

Oil Price

Demand growth

Oil market dynamics interact

© 2017 IHS MarkitSource: IHS Markit

Good Resilient

Coming down

Bearish

Weak



World liquids demand growth is high: 1.7 MMb/d in 2017 and 1.8MMb/d in 2018


4

Global liquids demand growth (MMb/d)2016 2017 2018

OECD 0.5 0.3 0.3Non-OECD 0.9 1.4 1.4Total world 1.4 1.7 1.8

Changes in liquids demand by region (volume change from previous year in million barrels per day)

Notes: Mexico is included in Latin America. The maximum value on the vertical axis for China is 0.6 MMb/d; for the other regions, it is 0.5 MMb/d.Data in table may not add up due to rounding. July 2017Source: IHS Markit

(0.20)(0.10)0.000.100.200.300.400.50

2016 2017 2018

North America

(0.20)

0.30

2016 2017 2018

Europe

(0.20)

2016 2017 2018

OECD Asia Pacific

(0.20)(0.10)0.000.100.200.300.400.500.60

2016 2017 2018

China

(0.20)(0.10)0.000.100.200.300.400.50

2016 2017 2018

Latin America

(0.20)(0.10)0.000.100.200.300.400.50

2016 2017 2018

Africa

(0.20)(0.10)0.000.100.200.300.400.50

2016 2017 2018

Middle East

(0.20)(0.10)0.000.100.200.300.400.50

2016 2017 2018

Non-OECD Asia ex. …

(0.20)(0.10)0.000.100.200.300.400.50

2016 2017 2018

Eurasia

(0.20)(0.10)0.000.100.200.300.400.50

2016 2017 2018

India

© 2017 IHS Markit. All rights reserved. Provided “as is”, without any warranty. This map is not to be reproduced or disseminated and is not to be used nor cited as evidence in connection with any territorial claim. IHS Markit is impartial and not an authority on international boundaries which might be subject to unresolved claims by multiple jurisdictions.


OPEC cuts have started to reduce global crude stocks

-1

0

1

2

3

4

5

6

-50

0

50

100

150

200

250

Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17

Day

s

Mill

ion

barr

els

OECD commercial crude stocks versus rolling five-year average volumes and days of runs cover

© 2017 IHS MarkitNote: Five-year average days of cover = 28; volumes = 1 billion barrels.Source: IHS Markit, IEA; Through 1 April 2017

• Global crude commercial stocks remain well above five-year averages, both in volume terms and in days of demand coverage.

• OECD product stocks days of cover have moved toward the rolling five-year average for the first time since August 2015.

5

Volume

Days of cover

5 year average



Non-OPEC supply resumes net growth of ~500,000 b/d in 2017–18

-0.8-0.6-0.4-0.20.00.20.40.60.81.0

Can

ada

Uni

ted

Stat

esBr

azil

Rus

sia

Uni

ted

King

dom

Kaza

khst

anN

orw

ayO

man

Indi

aAr

gent

ina

Azer

baija

nC

olom

bia

Mex

ico

Chi

na

2016 2017 2018

Annual change in crude oil production for selected non-OPEC countries, 2016–18

July 2017

Mill

ion

barr

els

per d

ay

© 2017 IHS

• After a net decline of 1.1 MMb/d in 2016, non-OPEC resumes growth in 2017

• Many long-lead projects are coming online and ramping up in 2017, 2018, and into 2019

• Canada: new oil sands projects, higher utilization of existing facilities plus offshore Hebron in 2018

• Brazil: new fields and continued ramp-up of already commissioned pre-salt

• Kazakhstan: Kashagan ramps up to 360,000 in 2019

• UK: some new start-ups and lower base decline

• US: short-cycle reactivity to higher prices and lower costs


6


Global crude supply outages have reduced; Nigeria and Libya, exempted from OPEC cuts, have surged production in the last quarter

(6,000)(5,500)(5,000)(4,500)(4,000)(3,500)(3,000)(2,500)(2,000)(1,500)(1,000)

(500)0

Non-OPEC LibyaNigeria Iraq

Global unplanned crude supply disruptions: less 1.5 MMb/d

Source: IHS Markit © 2017 IHS Markit

Thou

sand

b/d

Non-Libya

Iran

Nigeria

0.00.10.20.30.40.50.60.70.80.91.01.1

Nigeria and Libya cumulative change: 700,000 b/d since April

© 2017 IHS Markit

MM

b/d

Source: IHS Markit


7

Nigeria

Libya


US crude supply grows strongly in 2017 but likely to flatten in 2018 with lower price outlook

0123456789

101112

Mill

ion

barr

els/

day

© 2017 IHS MarkitSource: IHS Markit

US crude oil production by play

GOM deepwater

• US production hit a low in September 2016 at 8.56 million b/d

• 2017 is expected to increase ~1 MMb/d b/d entry-to-exit, ending the year at 9.8 MMb/d.

• Operators will add over 15,500 new wells in 2017, or 25% more than 2016. (includes ~1,000 DUCs)

• Further upward movement likely to be stalled by lower prices, keeping US production flat to slightly declined in 2018—about 200,000 b/d lower than previous estimates


8

Permian

Eagle Ford

Bakken

Alaska


A global liquids supply surplus is reemerging

90919293949596979899

100101102

1Q 2

013

3Q 2

013

1Q 2

014

3Q 2

014

1Q 2

015

3Q 2

015

1Q 2

016

3Q 2

016

1Q 2

017

3Q 2

017

1Q 2

018

3Q 2

018

World liquids demand and production by quarter

July 2017Source: IHS Markit © 2017 IHS Markit

Mill

ion

barr

els

per d

ay

• After tightening in 2016 and through mid-2017, market indicators are weakening in spite of the OPEC production cut extension

• Surplus in 2018 implies that global inventories are likely to rise again through 2018 and at higher levels than previously anticipated.

• Global liquids balances now show a larger quarterly average implied stock build in the next six quarters—0.7 MMb/d, about twice as much as our prior outlook


9

Production

Demand

2015 2016 2017


Financial players have turned very bearish and are shorting the market in record numbers


10

$25

$35

$45

$55

$65

$75

$85

$95

$105

$115

-350

-250

-150

-50

50

150

250

350

450

550

$/bb

l

NYMEX WTI Futures: Money Managers’ gross long and short positions

© 2017 IHS Markit

Thou

sand

con

trac

ts

Notes: As of 4 July 2017Source: IHS Markit, CFTC

# Longs

# Shorts

WTI $/bbl

Net length


Outlook for oil prices in 2017 and 2018 reduced as supply keeps coming

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

2010 2011 2012 2013 2014 2015 2016 2017 2018

$ pe

r bar

rel

Short term oil price outlook $ per barrel

July 2017Source: IHS Markit © 2017 IHS Markit

IHS Markit has reduced its oil price outlook for 2017 and 2018 as fundamentals have weakened in spite of OPEC production cuts

• US supply robustness

• Other non-OPEC rising in 2018 and into 2019

• Resumption of Libya and Nigeria production

Price expectations have declined $4/barrel for 2017 and $6/barrel for 2018 since April. Current expectations:

• 2017: $51 Brent/$49 WTI

• 2018: $48 Brent/$45 WTI

The longer-term outlook is also being lowered to reflect more supply at lower cost


11

Brent $/bbl

WTI $/bbl

April

July


Oil price outlook, 2017 versus 2016Brent prices have been adjusted down by $5–10/bbl on average

12

0

20

40

60

80

100

120

140

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040

History Rivalry 2017 Rivalry 2016

Dol

lars

per

bar

rel (

2016

US$

)

Average annual crude oil prices (real), 1990–2040

Note: Dated Brent. © 2017 IHS MarkitSource: IHS Markit

History



Contents

13







Project delays have been pandemic

Jan 15: Premier delays Sea Lion

Mar 15: Statoil delays Castberg+Snorre C Dec 14: ExxonMobil+Rosneft

scrap Arctic deal

Mar 15: BP delays Sullom Voe terminal

2014–15: Brazil corruption scandal

Feb 15: BG delays Lake Charles LNG

Jan 15: Alaska government halt oil infrastructure

Dec 14: PacificNorthwest LNG delayed

Dec 14: Chevron shelves Arctic

Jan 15: Statoil put Greenland on ice

Feb 15: Santos postpones Ande AndeAug 16: FID delayed to second half 2017

Dec 14: Excelerate put Lavaca Bay FLNG on hold

Politically/other relate

Cost/oil price related

Legend

Feb 15: Shell cancels Arrow LNG

Feb 15: Harvest shelves Dussafu

Jan 15: Total retenders Zinia Ph. 2

Jan 15: Shell to retender Bonga Southwest/Aporo

Feb 15: Cobalt delays FID on Cameia

Dec 14: Chevron Rosebank FID pushed further back

Jan 15: Kinder Morgan withdraws application for Lobos CO2 pipeline

May 15: Chevron to slow down FID for Gehem/Gendalo

May 15: BHP said Scarborough is a lower priority project.

Aug 15: JVPC delays Block 15-2, Nam Con Son Basin

Jun 15: Abadi FLNG startup pushed back 3 years

Jun 15: Petronas Nosong tender delayed

Setbacks for selected upstream developments

Note: CO2 = carbon dioxide. Source: IHS Markit, company announcements

Oct 15: Statoil redefines Mariner development

Nov 15: Centrica delays Fogelberg development

Nov 15: ADCO delays Bab project; Jan 16: Shell leaves Bab

Nov 15: Eni Goliat project start-up pushed back

Jan 15: Premier delays Vette

Mar 15: ConocoPhillips cancels Tommeliten A.

Dec 14: Chevron abandon Ukrainian shaleJan 16: Chevron cancels

Buckskin-Moccasin

Jul 16: Shell postpones Kitimat FID

Nov 16: Hess delays Equus indefinitely

Nov 16: Ophir pushes back Fortuna FLNG FID

Jan 17: Petrobras pushes back bid submission for Libra and Sepia FPSOs

Dec 16: Eni still evaluating Coral FLNG

Mar 16: Woodside cancels Browse

14



14


…but several operators are starting to buck the trend

Dec 2016: BP–Mad Dog Ph. II

Aug 2015: Maaersk Oil–Culzean

Nov 2016/Jan 2017: Saudi Aramco awards contracts for Safaniyah, Marjan and Zuluf expansion

Feb 2017: Noble–Leviathan

Feb 2016: Eni–Zohr

Feb 2015: Lundin–Johan SverdrupNov 2016: Statoil–Trestakk

Mar 2017: Statoil–Njord redevelopment and Bauge

Nov 2016: Centrica–Oda

Aug 2016: Statoil–Astero and UtgardOct 2016: DEA–Oda

Jun 2016: Statoil–Peregrino II

Feb 2016: Chevron–Tengiz exp.

Dec 2015: Woodside–Greater Western Flank Ph. 2

Jan 2015: Shell–Coulomb ph. 2

Feb 2016: Woodside–Greater Enfield

Aug 2015: BP–West Nile Delta

Jun 2015: Eni–Cape Three Points

Apr 2015: BP–Thuner Horse SouthJul 2015: Shell–Appomatox

15


Source: IHS Markit, company announcements

Major field development project sanctions (2015, 2016, and 2017 year to date)

15



Shale

Onshore

Subsea tie-back

Shallow water

Deepwater

Spare capacity

0 1 2 3 4 5

Illustrative Capital Flexibility and Project Cycle Times


Project sanction to first production (years)

Cap

ital f

lexi

bilit

y

Short-Cycle (6-12 mo)

Medium-Cycle (1-3 yrs)

Long-Cycle (3-8 yrs)

• US Tight Oil

• High-Potential Gulf Projects (Iraq/Iran/Saudi)• Sustainable Return of Political Barrels (Libya/Nigeria)• EOR, Tie-backs, Brownfield Expansions

• Greenfield Conventional Onshore • Oil Sands• Offshore Development (esp. Deepwater)

• Spare Production Capacity• Global Crude Inventories

Immediate (<6 mo)

Considerations of project cycle times and capital flexibility increasingly impact the decisions on the future of oil supply

Short cycle barrels have fundamentally changed the structure of oil markets and the nature of upstream investment

Capital flexibility rewarded in financial markets – matches up with quarterly expectations. Will operators need to justify to the financial community why long-cycle investments are necessary?

?

Note: Bubble sizes are indicative for unsanctioned volumes through 2023.


16


Total E&P capex expected to rise to previous peaks by the middle of the next decade in nominal terms

$0

$100

$200

$300

$400

$500

$600

$700

$800

Upstream onshore and offshore E&P capex by region


USD

bill

ion

Rising oil price, and lower costs will help industry recover… but it will be a long and drawn out recovery

North America

Middle East

Africa

Asia Pacific

Europe

17



• Overall E&P capex is expected to rise 20% from 2016–18, driven by increased spending in the US unconventionalsand other global onshore.

• Offshore spending is projected to continue its decline in 2017 and remain virtually flat in 2018 followed by a slow recovery in nominal terms.

• Onshore unconventional spending expected to exceed total offshore E&P spending as we head into the next decade

• Nominal dollar spending trends include the impact of lower service costs and structural efficiency changes which reduce overall cost of production.

18


Onshore conventional and unconventional grow in 2017; Offshore slow recovery after bottoming in 2017

0

50

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300

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Onshore conventional Onshore unconventional Offshore E&P spending

E&P capex by onshore conventional, unconventional and offshore


USD

bill

ion


Offshore capex bottoms in 2017 with deepwater beginning to rise in 2018/19

$0

$25

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$100

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$175

$200

Latin America Russia & Caspian North AmericaMiddle East Europe Asia-PacificAfrica

Offshore capex by region ($ billions)

Source: IHS Markit ©

Africa

Asia Pacific

Europe

M. EastN. Am

LatinAmerica

Shallow = <1,000 ft.; Deepwater = 1,000-5,000 ft.; Ultradeep water = >5,000 ft.

$0

$25

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$125

$150

$175

$200

Ultra deepwater Deepwater Shallow

Offshore E&P capex by depth ($ billions)

Source: IHS Markit ©

Shallow water

Deepwater

Ultra-deep

19



Contents

20







Onshore NA versus Offshore – different trajectories

• Offshore drilling is suffering from both low demand and excess supply across all segments.

• Day rates have declined for all segments of the market due to significant excess supply and are likely to continue to decline into 2019.

• Rate recovery will be muted due to continued oversupply and lower than estimated a year ago, in particular for jackups where supply did not leave the market

• As of May-June 2017, there were 100 jackupsand 47 floating rigs under construction, most being built on spec with no charters in place.

• Global deepwater floating rig utilization is expected to remain below 80% until 2023

• Onshore drilling is already rising, fueled by a strong uptick in US unconventional activity.

21

Divergence of cost-curve evolution

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

End-2014 2016 2017 2018

Bakken Wolfcamp Delaware Wolfcamp Midland Eagleford

Drilling and completion costs per well by play onshore US

© 2017 IHS Markit

US$

Mill

ion

per w

ell

Notes: Includes estimated drilling and completion costs.Source: IHS Markit

+24%

+31%

+27%

+25%

Unavailable rigs

Demandcases

Effective floater supply

Floating rig supply and demand forecast


Deepwater costs were impacted by “deflation” (service sector price cuts), project and company efficiencies, and redesign

The impact of redesign efforts in the deepwater has been a small portion of the cost reductions exhibited to date

22

Deepwater cost reductions of 34 projects Q3 2014 to Q3 2016 (including E&A allocation)

Deepwater is > 1,000’; Costs include Exploration & Appraisal allocation, capex, opex, and decommissioning allocationSource: IHS Markit © 2017 IHS Markit

0%5%

10%15%20%25%30%35%40%45%50%

Western Europe GoM All West Africa Brazil Other

Cos

t red

uctio

n

Deflation

EfficiencyNew design

45%

36%35%

29%34%

28%



Contents

23







Norway: offshore Arctic is key to future production

24

• A record number of exploration wells (15) are scheduled to be drilled in Barents Sea in 2017.

• On 21 June, the Ministry of Petroleum and Energy announced that Norway’s 24th oil and gas licensing round will include 102 blocks: 93 in the Barents Sea and 9 in the Norwegian Sea. Deadline is 30 November for submissions and awards planned for first half 2018.

• Johan Castberg FID expected late 2017 according to operator Statoil (50%); Eni (30%); Petoro (20%). IHS Markit estimates

• 500 million barrels of oil

• Capex at $11/bbl; Opex at $9/bbl

• NPV10 of $700 million; IRR ~14%

• Breakeven of $36.60/bbl

• Statoil Korpfjell prospect in eastern Barents has the potential to open a new basin

Location of license EPL 859 and Korpfjell well



US Gulf of Mexico: Deepwater prospects have focused on the Inboard Lower Tertiary sub-play

25

• In spite of high reserves, the Lower Tertiary has been challenged by economics and technology• Low well productivity—as much as 50% lower

than Miocene and Miocene sub-salt

• HPHT reservoirs

• Lack of existing infrastructure and discoveries far from production hubs

• Lack of 20,000 psi production technologies

• The Inboard Lower Tertiary was lacking many of the obstacles and a focus of recent activity

• The recent failure of the Anadarko Shenandoah appraisal well has cast serious doubts on prospectivity


Gulf of Mexico Lower Tertiary sub-plays

Source: IHS Markit



Mexico: E&P opportunities for investment accelerate

26

• President Enrique Pena Nieto is accelerating E&P opportunities to entrench reform before he leaves office end 2018

• Talos Zama-1 discovery of ~2 billion barrels of oil in 546 ft of water

• Eni Amoco discovery in shallow water Campeche may be a fast track development

• New 5 year bid round plan before end 2018 • 2.4: covering deepwater and unconventional

• 3.1: shallow water and onshore conventional

• 3.2: deepwater and unconventional

• PEMEX sets aside 175 blocks for farm-out © 2017 IHS Markit. All rights reserved. Provided “as is”, without any warranty. This map is not to be reproduced or disseminated and is not to be used nor cited as evidence in connection with any territorial claim. IHS Markit is impartial and not an authority on international boundaries which might be subject to unresolved claims by multiple jurisdictions.

Source: IHS Markit

Talos

Eni



• 60 Bn bbl of resource discovered since 2005 (pre-salt only)• 13 Bn bbl commercial pre-salt reserves awaiting development• 49 fields w/ 100+ MMboe yet to be developed

27

Over the last decade, Brazil has been the most prolific deepwater province in the world

Field size distribution and well productivity in the Santos Pre-salt is currently unmatched globally

Together with unconventional, deepwater is set to grow significantly in the global production portfolio, playing a growing role in the global oil market balance on the 2020s.

Brazil’s pre-salt can become one of the most competitive global upstream assets, while post-salt will also remain important. Campos Basin still present opportunities, especially for some pre-salt upsides and EOR activities

0

500

1,000

1,500

2,000

Santos Pre-Salt

CamposPos-Salt

US Gulf ofMexico

Congo Nigeria

Mean Field Size Benchmark for Deepwater Plays

Notes: Deepwater >= 1000mSource: IHS Markit © 2016 IHS

MM

boe

05

1015202530

Santos Pre-Salt

Campos Pre-Salt

US GOMDeepwater

Congo FanDeepwater

Niger DeltaDeepwater

Average Well Productivity Benchmark for Deepwater Basins

Notes: Deepwater >= 1000mSource: IHS © 2016 IHS

kboe

/d

Brazil: Base resources and coming bid rounds can be a magnet for foreign investments



Barents Sea: Norway

Brazil: Post-salt

Brazil: Pre-salt (except Libra)

Brazil: LibraCongo Fan:

Angola

Douala Basin: Equatorial Guinea

East Canada:Grand Banks

West Africa: Equatorial Margin

North Falkland

US GOM: Lower Tertiary

US GOM: Miocene (sub-salt) US GOM:

Miocene

Niger Delta: NigeriaWest Africa:Pre-salt UK:

West of Shetland

Australia deepwater

East Africa: Mozambique

East Africa:Tanzania

South Falkland Indonesia

Malaysia

0

10

20

30

40

50

60

70

80

90

100

0 20 40 60 80 100 120 140 160 180 200

Average development-forward Brent breakeven prices for new projects in selected plays

Source: IHS Global Deepwater and Growth Plays Service © 2015 IHS

Dev

elop

men

t-for

war

d B

rent

bre

akev

en

Average peak production (Mboe/d)

Bubble sizes represent relative cumulative recoverable resource sizes for each play

Brazil’s deep-water is competitive


28


Growth from existing fields provides more new resource than discoveries in many years – Field Growth

• On average, >2,000 conventional fields have their technical resources revised upwards every year

• “Field growth” outpaces new discoveries in most of the past ten years.

• Deepwater fields grew ~35%, shallow water ~27% and onshore 37%

• Re-focus on existing fields is a potential way for companies to mitigate lack of exploration.

0

20

40

60

80

100

120

140

Conventional oil and gas resources from new discoveries and field growth in discoveries made in prior years

Notes: excludes Canada onshore, US Lower-48 onshore, and US shallow water. Also excludes Venezuela Orinoco extra-heavy oil. Includes only those fields with a present-day field size of 50 MMboe or greaterSource: IHS © 2016 IHS

Bill

ion

barr

els

oil e

quiv

alen

t

New discoveriesinitial estimate

Adjustments to prior years’ discoveries

29



We are not alone: Governments Planned Licensing Rounds in 2017

30

Number of opportunities indicate a number of licensing rounds (specific licensing rounds/auctions can be held for different areas (onshore/offshore, brown-fields vs green-fields, type of resource (conventional vs unconventional)

Canada (1 Opportunity)

United States (2 Opportunities)

Mexico (3 Opportunities)

Peru (1 Opportunity)

Suriname (1 Opportunity)

Uruguay (2 Opportunities)

UK (1 Opportunity) Russia (1

Opportunity)

Iran (2 Opportunities)

Iraq (2 Opportunities)

Equatorial Guinea (1 Opportunity)

Lebanon (1 Opportunity)

Israel (1st offshore round)

Australia (3 Opportunities)

Sri Lanka (1 Opportunity)

Thailand (1 Opportunity)

Malaysia (1 Opportunity)

Indonesia (1 Opportunity)

Argentina (1st

offshore round)Brazil (4

Opportunities)

Madagascar (1 Opportunity)

New Zealand (1 Opportunity)

Norway (2 Opportunities)



Takeaways

A global liquids supply surplus is reemerging

Outlook for oil prices in 2017 and 2018 reduced as supply keeps coming

Total upstream capital onshore and offshore spending will recover back to 2014

levels by the middle of the next decade.

Offshore recovery expected to be led by gains for deep-water developments following

the significant cost reset over the past two years

• Deepwater continues to be an important business globally

• Brazil expected to regain its position as a major driver of deep and ultra-deep water

spending.

Brazil has “it” and can be competitive

• But, can Brazil make itself a magnet for conventional exploration capital globally?


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