2012-10-24 Classification: Internal

European Credit Investor Update March – April – June 2016

Philippe F. Mathieu, SVP and Head of Finance

Arild Dybvig, Lead Finance - Corporate Financing 1

• Capital Market Update: Resetting costs – capturing opportunities

• 4Q and Full Year 2015 results

• Q1 2016 results – selected material

• Supplemental material:

− One – pager - “Statoil at a glance”

− Funding & Debt Strategy – Activity and strategy, Maturity profile and Rating

− Development & Production Norway (DPN) – “Trend shift for field cost“

− Development & Production International (DPI) – Business- and strategic priorities

− Development & Production USA (DPUSA) – “Three-year plan: Transform“

− Exploration (EXP) – “Disciplined execution of exploration strategy”

− Technology, Projects & Drilling (TPD) - Break-even developments

Agenda

2

2012-10-24 Classification: Internal

Resetting costs – capturing opportunities London, 4 February 2016 Eldar Sætre, President and CEO 3

Safety first

Serious incident frequency Serious incidents per million work-hours

2,2

1,9

1,4

1,1 1

0,8

0,6 0,6

2008 2009 2010 2011 2012 2013 2014 2015

4

Delivering on promises

5

Production increase production by around

2% annually from 2014 to 2016

Organic production

growth of 6% in 2015 “

Promised Delivered

Capex our investment programme for

2015 is reduced by USD 2 billion

Reduced by more than

USD 5 billion “

Efficiency step up efficiency programme to

USD 1.7 billion in 2016

Delivered USD 1.9 billion in

2015 “

Distribution Dividend maintained in 2015 commitment to competitive

capital distribution “

Production postponed Pre-FID, million barrels per day

-3,5

-3,0

-2,5

-2,0

-1,5

-1,0

-0,5

0,0

2017 2019 2021 2023 2025

Source: Wood Mackenzie, Upstream Data Tool

Onshore (conventional)

Oil sands

Shallow water

Deepwater

Industry responding to market forces

6

Rebalancing of markets Million barrels per day

-1,5

-1,0

-0,5

0,0

0,5

1,0

1,5

2,0

2,5

3,0

2011 2012 2013 2014 2015 2016 2017

Source: EIA, Short-Term Energy Outlook, January 2016

Stock reduction

Stock addition

0

20

40

60

80

100

120

140

160

2005 2007 2009 2011 2013 2015

The cyclical nature of oil Brent, USD per barrel

Firm strategy to capture value in the upturn

7

● Efficiency improvements

and market effects

● Strict financial discipline

Faster and deeper cost

reductions Preparing to invest in next-

generation portfolio

● Radically improved

break-evens

● Maintaining dividend,

introducing scrip option

● Sustained efficiency

gains

● Significant new volumes

2018-2022

Capturing the upturn in oil

and gas prices

Johan Castberg Johan Sverdrup

Additional

reduction of

USD 3.3 billion

Measures to improve cash flow

Stepping up efficiency USD billion

1.7

0.8 2.5

1.9

Capital expenditure

Operating expenses

Improved regularity1)

Unplanned losses as percent of production

12%

10%

5% 5%

2012 2014 2013 2015

8

0

5

10

15

20

2016/

2017

2018/

2019

2015

guided

2015

actual

Sanctioned projects

Non-sanctioned projects

US onshore & capitalised exploration

Additional

flexibility of

USD 4-6 billion

Significant capex flexibility USD billion

1) Norwegian Continental Shelf

2014 Target @

CMU 2015

Delivered

2015

Step-up @

CMU 2016

New

target

Capturing value from next-generation portfolio

2013 2016

Production potential to 2022

Production from non-sanctioned1) projects2), mboe/d

29% below

$50/boe

82% below

$50/boe

1) Non-sanctioned projects exclude exploration

2) Includes partner-operated projects

Break-even

per barrel

Capex

Optimised portfolio Operated non-sanctioned projects starting up by 2022, weighted by volume

9

70 USD

41 USD

0

50

100

150

200

250

300

2017/18 2019/20 2021/22

Commitment to shareholders

10

4Q dividend maintained at USD 0.2201 per share 1)

Scrip dividend to be proposed to the AGM

● Two-year window from 4Q 2015

● Discount of 5% for 4Q 2015

● Norwegian government support for the scrip dividend 2)

● State ownership remains at 67%

Option to invest in a company with a high-quality portfolio

Strengthening flexibility to invest in high-value projects

Johan Sverdrup field centre

1) Subject to approval at the Annual General Meeting (AGM)

2) Subject to approval by the Norwegian Parliament

Providing energy for a low-carbon future

Carbon-efficient oil and gas producer CO2 intensity (kg CO2/boe)

18 17 18

9 10 11

10 9

2012 2013 2014 2015 Target 2020

Industry average (IOGP)

Statoil 1)

Gradually building a new energy business

• Leveraging core competence

• Key focus on offshore wind – industrial approach

• Exploring other energy sources

• Established New Energy Solutions (NES)

11

Hywind

1) Excluding Snøhvit/Hammerfest LNG

Resetting costs – capturing opportunities

Faster and deeper cost reductions

Preparing to invest in next-generation portfolio

Capturing the upturn in oil and gas prices

12

1

2

3

2012-10-24 Classification: Internal

Resetting costs - capturing opportunities London, 4 February 2016 Hans Jakob Hegge, Executive Vice President and CFO 13

Faster and deeper cost reductions

...and continue to raise the bar USD billion

We have delivered ahead of time… Percent improvement on selected activities

-25% time

-30% cost

-10% cost

-30% cost

-20% cost

>5.0 pp

Drilling time per

offshore well1)

US onshore cost

per boe

Facility capex

Modification capex

Field cost NCS

Production

efficiency

Existing

targets

Delivery

2015

2013

baseline

Former

2016 target

-30% time

-45% cost

-15% cost

-40% cost

-25% cost

>6 pp

New 2016

targets

2.5 1.9

Capital expenditure

Operating expenses

1.3

Target @

CMU 2014

Step-up @

CMU 15

Delivered

2015 New

target

~50%

step-up

Step-up @

CMU 16

30%

step-up

1) Production wells 14

Turning efficiency improvement into money

Further actions

● Renegotiating supplier contracts

● Implementing new actions to reduce upstream opex

● Stepping up organisational efficiency

Cost competitive new production

● Johan Sverdrup ~30 NOK/boe1)

● Aasta Hansteen ~30 NOK/boe1)

Peer group: Anadarko, BG, BP, Chevron, ConocoPhillips, Eni, ExxonMobil, Petrobras, Repsol, Shell and Total. Based on figures sourced from IHS Herold financial

database. Benchmark on average UPC in USD for the years 2012-2014.

1) Average unit production costs first five years after production start-up

Unit production costs - ahead of peers USD per barrel

Adjusted upstream operating cost and SG&A Percentage improvement – per barrel in underlying currency

0

5

10

15

20

25

30

35

2014 2015 2014 2015

DPN DPI

11% 18%

15

Value over volume – flexible production growth

Very strong production growth in 2015

● Impact future growth rates

● Utilised high prices

Value over volume approach

Several major start-ups in 2018/19

Equity production mboe/d

0

500

1 000

1 500

2 000

2 500

20141) 2015 2017 2019

DPN excluding flex gas

International excluding US onshore

US onshore and DPN flex gas

+6% actual

~1% CAGR

2-4 % CAGR

1) Rebased 2014 of 1868 mboe/d is adjusted with 59 mboe/d for full year impact of transactions with Wintershall and Petronas 16

39 USD

30 USD Projects

sanctioned

since 2013

Radical change in our project portfolio

Improved break-even on operated portfolio Assets starting up by 2022, USD/bbl, weighted by volume

Non-sanctioned projects 2013 2016 Break-even oil price, USD/bbl

-

20

40

60

80

100

120

- 200 400 600 800 1 000 1 200

Volume (mmboe) 2013 2016

Note: Left hand chart covers Statoil’s total non-sanctioned portfolio (operated and non-operated) where projects have been continued since 2013.

All data and graphs cover projects with expected production start by end 2022.

70 USD

41 USD Non-

sanctioned

portfolio

17

0

5

10

15

20

25

0%

10%

20%

30%

40%

2015 2016/17 2018/19

Maintaining flexibility in an improved portfolio

Well positioned to adapt to macro volatility USD billion

$70/bbl

$50/bbl

$40/bbl

$50/bbl

$70/bbl

CFFO CFFO Capex Capex

2016/17 2018/19

USD

~2 bn

USD

4-6 bn

Net cash flow neutral at $60/bbl in 2017 and $50/bbl in 2018, excluding impact of scrip programme

Sanctioned projects

Non-sanctioned projects

US onshore & capitalised expl.

1) For illustrative purposes. Assumes 40% outtake rate for two-year scrip program 4Q15-3Q17

Note: The various scenarios for CFFO also imply different operational assumptions. The higher price scenarios assume lower utilisation of

capex flexibility while the lower price scenarios assume larger utilisation of capex flexibility.

Net debt to capital employed1)

$70/bbl

$50/bbl

$40/bbl

$50/bbl

$70/bbl

$90/bbl

18

Firm strategy to capture value in the upturn

19

● Step up efficiency target to

USD 2.5 billion in 2016

Faster and deeper cost

reductions

Preparing to invest in next-

generation portfolio

● Capex 2016:

USD ~13 billion

● Average break-even of

new portfolio at USD 41

per barrel

● Organic growth:

~1% CAGR 2014-17

~2-4% CAGR 2017-19

● Exploration 2016:

USD ~2 billion

Capturing the upturn in oil

and gas prices

Johan Castberg Johan Sverdrup

2012-10-24 Classification: Internal

4th Quarter and Full Year 2015 London, 4 February 2016 Hans Jakob Hegge, Executive Vice President and CFO 20

Earnings Adjusted earnings of NOK 77.0 billion, negatively impacted by prices

Production 6% YoY organic growth, driven by ramp-ups, efficiency and gas optimisation

Costs Adjusted opex and SG&A down 13% YoY1), continued downward trend

Organic capex USD 14.7 billion

Reserves 88% organic RRR

Resources 265 million boe added from exploration

Projects Sanctioning of Johan Sverdrup. Material improvement in opportunity set

Dividend NOK 1.80 per share for 1Q, USD 0.2201 per share for each of 2Q, 3Q & 4Q2)

2015 | Continued operational progress

21

1) Costs in each upstream segment are equally weighted in underlying main currency: USD for D&P International and NOK for D&P Norway.

2) The dividend for 4Q 2015 of USD 0.2201 /share subject to approval from the Annual General Meeting.

Full year 2015 NOK billion

Financial results impacted by lower prices

(9.2) 1.7 13.5 15.2 (13.6) 1.6

(8.9) 9.0 17.9 26.9 (22.6) 4.3

Fourth quarter 2014 NOK billion

(37.3) 14.9 62.1 77.0 (57.6) 19.5

22.0 109.5 26.7 136.1 (97.0) 39.1

Full year 2014 NOK billion

Fourth quarter 2015 NOK billion

Net income Reported

NOI

Adjustments Adjusted

earnings

Tax on adj.

earnings

Adjusted

earnings

after tax

Net income Reported

NOI

Adjustments Adjusted

earnings

Tax on adj.

earnings

Adjusted

earnings

after tax

22

Reduced costs across the business

23

• Strong operational performance

with production efficiency >90%

• 17% reduction in adjusted opex

and SG&A per boe

• DD&A per boe up 1% due to ramp

up of new fields

D&P International D&P Norway MMP

• Low prices lead to negative

adjusted earnings

• Growing liquids production

• 22% reduction in adjusted opex

and SG&A per boe in USD

• DD&A per boe reduced by 15%

in USD1)

• Solid deliveries across the

business

• Lower earnings in 4Q compared

to very strong results in previous

quarters

• Low tax rate on adjusted earnings

Adj. earnings, NOK billion Pre tax After tax Pre tax After tax Pre tax After tax

4Q’15 17.1 5.4 (5.7) (6.1) 3.6 2.2

4Q’14 24.2 6.8 (2.8) (5.0) 5.1 2.2

FY2015 69.4 21.6 (12.2) (15.0) 21.8 14.1

FY2014 105.5 29.1 13.9 2.6 17.8 8.1

1) DD&A per boe based on entitlement production

1179 1179 1165 1127

867 925

806 801

4Q2015 4Q2014 FY2015 FY2014

Liquids Gas

Strong production growth

6% organic growth YoY

Sustained strong regularity

on the NCS

Optimising gas offtake on the NCS

Growing international liquids

production

2103 1971 1927 2046

Equity production mboe/d

24

Cash flow from operating activities

166 1)

Proceeds from sale of assets

33

Net (18)

Taxes paid (66)

Dividend paid (23)

Cash flow to investments

(129)

1) Income before tax (4) + Non cash adjustments (161)

NOK billion

Tax paid partly reflecting

2014 results

Proceeds from value-

enhancing transactions

Organic investments

reduced due to efficiency

and prioritisation

Net debt to capital employed

at year-end of 27%

Resilient cash flow at materially lower prices

25

Johan Sverdrup adds to new reserves

88% organic RRR, 55% total RRR

5% increase in liquid reserves

110% three-year average organic RRR

Johan Sverdrup main contributor for

new proved reserves

Negative impact from lower commodity

prices on proved reserves

Stable resource base 2014 Production Divestments Discoveries,acquistions and

revisions

2015

Proved reserves (SEC) Reserves and resources

22 21 (0.7) (0.6)

0.8

5.4 5.1 (0.7) (0.2)

0.6

billion boe

26

27

2012-10-24 Classification: Internal

Q1 2016 results – selected material

28

First quarter 2016

• Financial results affected by low price

environment

• Strong operational performance

• Continue to capture cost reductions and

efficiency gains

• Maintaining dividend of USD 0.2201 per

share, with 5% discounted scrip dividend

option1)

1) Subject to approval of the two-year scrip dividend program at the AGM 11 May 29

Outlook 2016

Capex USD ~13 bn1)

Production ~1% organic CAGR (2014-17)

Maintenance 60 mboe per day

55 mboe per day in 2Q

Exploration USD ~2.0 bn1)

1) Assuming NOK/USD of 8.50

2016-

04-18

3

0

Classification:

Internal

30

2012-10-24 Classification: Internal

Supplementary Information

31

Statoil “at a glance” Statoil’s Focus:

Statoil’s Strategy and Global Footprint:

Statoil as a company:

• International energy company with operations in more than 30

countries.

• More than 40 years of O&G experience from the NCS.

• Headquartered in Stavanger, Norway with approximately

21600 employees worldwide.

• Listed on NYSE and OSE - 67 % Norwegian state ownership

Statoil Key Figures:***

* Water Depths > 100 meter.

** Frequency of incidents with actual and potential serious consequences – per million hours worked

*** Per 31.12.2015

• Market Capitalization of ~ NOK 394 Bn and ~USD 45 Bn.

• Equity production of 1.971 Mill. Boed.

• Reserves and resources of 21 Bn boe.

• Organic capital expenditure level of USD 14.7 Bn.

• Serious incident Frequency** is 0.6, down from 1.1 in 2011.

• Upstream focus - World’s largest offshore operator*.

• Operating more than 3 Mill. boed

• Norwegian continental shelf (NCS) legacy position.

• OECD exposure - 50% of resources on NCS

• Leading global exploration company.

• Leading European gas supplier.

• Building strong US gas value chain

• Deepen & prolong NCS position.

• Grow material and profitable

international positions.

• Pursue focused and value- adding

mid- & downstream activities.

• Provide energy for a low carbon future.

32

Issue activity and strategy Key Elements:

Regular issuer since 2009; ~ USD 30 Bn outstanding

Smooth maturity profile - long weighted average maturity

Maintain credit ratings at least within the single A category

on a standalone basis

Updated market tools: EMTN*, US Shelf, US CP

USD 5 bn revolving credit facility - USD 3 bn swing line

Refinanced in June 2015: 5+1+1 years – 21 banks

Bond issued at corporate level

Long term funding raised when a need is identified or when

market conditions are favorable

Access to a diversified investor group

Geographic and investor type

Bonds can be issued in a variety of currencies:

USD, EUR, GBP, CAD, CHF, NOK and JPY

* Updated in February 2016 and expanded to Euro 20 Bn

33

Long-term debt maturity profile

Redemption profile 31.12.2015

34

Rating ambition: Maintain credit ratings at least within the single A category on a stand-alone basis

Recent downgrades driven by oil

price development

S&P*

“Rating downside, which we view

as highly unlikely, would appear if

the weighted-average FFO to debt

moves below 40%.”

“Rating upside would appear if we

saw or gained strong confidence

that FFO to debt would move

toward 60%. This could happen if,

for example, cost

reductions, efficiency measures,

and asset disposals were higher

and taxes lower than in our base

case.”

Limited rating downside concerns by

rating agencies

Moody’s*

“Positive pressure could be placed

on Statoil’s a2 BCA and, by

extension, on Aa3 rating, if it

continues to strongly execute on

the investment programme and

improve its financial profile, with

retained cash flow/net debt

recovering sustainably to 50%

level.

Moody's does not expect downward

pressure on Statoil’s Aa3 rating.”

35 * S&P: Statoil’s A+ rating incorporates a one-notch uplift based on that S&P «...view Statoil as a government-related entity with a moderately high likelihood of extraordinary state support»

* Moody’s: «Statoil’s Aa3 rating incorporates a two-notch uplift based on Moody’s assumption of «Strong» support from the Government of Norway (Aaa stable)»

36

DPN: Trend shift for field cost

External cost

Subsea cost

Maintenance

cost

Field Cost 1) Improved maintenance planning and execution

2015 2013

2015 2013

2015 2013 2013 2011 2014 2012 2015 2016

-45%

-35%

-25%

-25% -19%

1) Norwegian continental shelf field cost = installation subsea and topside operation and maintenance, logistics, catering, administration, HSE and reservoir management

DPI: Business- and strategic priorities

2016 2018

Maximising value from

current portfolio

• Driving operational

performance

• Faster and deeper cost

reduction

• Influencing partners for

enhanced value creation

Building the next-generation

portfolio

• Efficient project execution • Hebron / Mariner / Peregrino

phase 2

• Capturing the upturn • Bressay / Pão de Açúcar /

East Coast Canada / Tanzania

~46 USD/bbl

40-43 USD/bbl

Break-even oil price1)

1) Brent oil price required to have net operating income of 0, excluding exploration expenses.

Break-even oil price1)

37

38

DPUSA: Three-year plan: Transform

Grow with quality Make money Improve

Profitable investments

>50% production growth potential

Double EBITDA/boe

Reduce price needed to achieve

NOI=0

From $90/bbl to $50/bbl 1)

Step up improvements

Reduce costs

One onshore organisation

~ $5

2014 2018

>100%

240

2014 2018

>50%

Production potential

mboe/d

EBITDA $/boe

@ $50 WTI

- 25%

- 25%

- 20%

Onshore capex

$/boe

Onshore opex

$/boe

SG&A costs

$/boe

2015

baseline

90

50

2014 2015 2016 2017 2018

$/b

bl (W

TI)

1) Adjusted NOI; figures exclude exploration and downstream.

Assumes product and gas prices correlate to changes in the WTI price.

Realised price in the US portfolio is significantly lower than WTI due to the mix of gas / oil / products and local market conditions.

100

80

60

40

TPD: Development break-even USD/bbl

0

20

40

60

80

US

D-1

6/b

bl

Current break-even 2013 break-even

1) Alfa Sentral, Bressay, Johan Castberg, Johan Sverdrup phase 1, Johan Sverdrup future, Oseberg Vestflanken, Peregrino II,

Snorre 2040 and Trestakk. Break-even from 1Q2013 used for most projects with exception of newer projects.

2) Non-sanctioned projects with start-up within 2022 in 2013 and currently.

0

10

20

30

40

50

60

70

Category 1 Category 2Trestakk

- 38%

0

10

20

30

40

50

60

70

Category 1 Category 2Oseberg Vestflanken

- 52%

Average break-even price project portfolio 2)

2013

70 USD/bbl

Current

41 USD/bbl

Major project decisions 2015-17 1)

39

Examples of break-even reductions

TPD: Johan Castberg

100

50-60

0

20

40

60

80

100

120

2013 Conceptchange

Drillingand well

Subsea Floater Market CurrentFC

NO

K b

illio

n

40-50%

Capex reductions 1)

Changes in break-even price

2013

above

80 USD/bbl

Current

below

45 USD/bbl

1) Capex numbers in real term NOK 2016 40

TPD: Johan Sverdrup

Phase 1 break-even price

Current

below

30 USD/bbl

170 - 220

160 - 190

Full field development cost 2)

1) Capex numbers in NOK nominal currency adjusted

2) Capex numbers in real NOK 2015

Phase 1 capex reductions1)

123.2

108.5

PDO Simplification Strategy andmarket

Current forecast

NO

K b

illio

n

12%

NO

K b

illio

n

41

Statoil Exploration core area

Countries with Statoil acreage

2016 to 2018 potential play openers

2016

~ USD 2 billion spend, 30% down from 2015

Deepen in core areas

Test five new plays

Continue countercyclical access

Mature discoveries towards development

2017-2018

Test new acreage in core areas

Test new plays

EXP: Disciplined execution of exploration strategy

42

Debt - Investor Relations

Philippe F. Mathieu Senior Vice President phima@statoil.com +47 90 98 97 63

Morten Færevåg Vice President mofae@statoil.com +47 99 22 38 57

Fride Seljevold Mehti Vice President fme@statoil.com +47 95 99 06 59

Arild Dybvig Lead Finance arid@statoil.com +47 95 44 02 10

Equity - Investor Relations (main contacts)

Peter Hutton Senior Vice President phutt@statoil.com +44 788 191 8792

Erik Gonder IR Officer ergon@statoil.com +47 99 56 26 11

Gudmund Hartveit IR Officer guhar@statoil.com +47 97 15 95 36

Investor Relations in Statoil

43

Forward-looking statements

These forward-looking statements reflect current views about future events and are, by their nature, subject

to significant risks and uncertainties because they relate to events and depend on circumstances that will

occur in the future. There are a number of factors that could cause actual results and developments to differ

materially from those expressed or implied by these forward-looking statements, including levels of industry

product supply, demand and pricing; price and availability of alternative fuels; currency exchange rate and

interest rate fluctuations; the political and economic policies of Norway and other oil-producing countries;

EU directives; general economic conditions; political and social stability and economic growth in relevant

areas of the world; the sovereign debt situation in Europe; global political events and actions, including war,

terrorism and sanctions; security breaches; situation in Ukraine; changes or uncertainty in or non-

compliance with laws and governmental regulations; the timing of bringing new fields on stream; an inability

to exploit growth or investment opportunities; material differences from reserves estimates; unsuccessful

drilling; an inability to find and develop reserves; ineffectiveness of crisis management systems; adverse

changes in tax regimes; the development and use of new technology; geological or technical difficulties;

operational problems; operator error; inadequate insurance coverage; the lack of necessary transportation

infrastructure when a field is in a remote location and other transportation problems; the actions of

competitors; the actions of field partners; the actions of governments (including the Norwegian state as

majority shareholder); counterparty defaults; natural disasters and adverse weather conditions, climate

change, and other changes to business conditions; an inability to attract and retain personnel; relevant

governmental approvals; industrial actions by workers and other factors discussed elsewhere in this report.

Additional information, including information on factors that may affect Statoil's business, is contained in

Statoil's Annual Report on Form 20-F for the year ended December 31, 2014, filed with the U.S. Securities

and Exchange Commission, which can be found on Statoil's website at www.statoil.com.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we

cannot assure you that our future results, level of activity, performance or achievements will meet these

expectations. Moreover, neither we nor any other person assumes responsibility for the accuracy and

completeness of the forward-looking statements. Unless we are required by law to update these

statements, we will not necessarily update any of these statements after the date of this report, either to

make them conform to actual results or changes in our expectations.

44

This presentation contains certain forward-looking statements that involve risks and uncertainties. In some

cases, we use words such as "ambition", "continue", "could", "estimate", "expect", "focus", "likely", "may",

"outlook", "plan", "strategy", "will", "guidance" and similar expressions to identify forward-looking statements.

All statements other than statements of historical fact, including, among others, statements regarding future

financial position, results of operations and cash flows; changes in the fair value of derivatives; future

financial ratios and information; future financial or operational portfolio or performance; future market

position and conditions; business strategy; growth strategy; future impact of accounting policy judgments;

sales, trading and market strategies; research and development initiatives and strategy; projections and

future impact related to efficiency programs, market outlook and future economic projections and

assumptions; competitive position; projected regularity and performance levels; expectations related to our

recent transactions and projects, completion and results of acquisitions, disposals and other contractual

arrangements; reserve information; future margins; projected returns; future levels, timing or development of

capacity, reserves or resources; future decline of mature fields; planned maintenance (and the effects

thereof); oil and gas production forecasts and reporting; domestic and international growth, expectations and

development of production, projects, pipelines or resources; estimates related to production and

development levels and dates; operational expectations, estimates, schedules and costs; exploration and

development activities, plans and expectations; projections and expectations for upstream and downstream

activities; oil, gas, alternative fuel and energy prices; oil, gas, alternative fuel and energy supply and

demand; natural gas contract prices; timing of gas off-take; technological innovation, implementation,

position and expectations; projected operational costs or savings; projected unit of production cost; our

ability to create or improve value; future sources of financing; exploration and project development

expenditure; effectiveness of our internal policies and plans; our ability to manage our risk exposure; our

liquidity levels and management; estimated or future liabilities, obligations or expenses and how such

liabilities, obligations and expenses are structured; expected impact of currency and interest rate

fluctuations; expectations related to contractual or financial counterparties; capital expenditure estimates

and expectations; projected outcome, objectives of management for future operations; impact of PSA

effects; projected impact or timing of administrative or governmental rules, standards, decisions, standards

or laws (including taxation laws); estimated costs of removal and abandonment; estimated lease payments,

gas transport commitments and future impact of legal proceedings are forward-looking statements. You

should not place undue reliance on these forward-looking statements. Our actual results could differ

materially from those anticipated in the forward-looking statements for many reasons.