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 [email protected] +47 90 98 97 63
Morten Færevåg Vice President [email protected] +47 99 22 38 57
Fride Seljevold Mehti Vice President [email protected] +47 95 99 06 59
Arild Dybvig Lead Finance [email protected] +47 95 44 02 10
Equity - Investor Relations (main contacts)
Peter Hutton Senior Vice President [email protected] +44 788 191 8792
Erik Gonder IR Officer [email protected] +47 99 56 26 11
Gudmund Hartveit IR Officer [email protected] +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.