Aker BP

Investor Presentation • Jan 15, 2018

CAPITAL MARKETS DAY 2018 AKER BP ASA

15 January 2018

Disclaimer

This Document includes and is based, inter alia, on forward-looking information and statements that are subject to risks and uncertainties that could cause actual results to differ. These statements and this Document are based on current expectations, estimates and projections about global economic conditions, the economic conditions of the regions and industries that are major markets for Aker BP ASA's lines of business. These expectations, estimates and projections are generally identifiable by statements containing words such as "expects", "believes", "estimates" or similar expressions. Important factors that could cause actual results to differ materially from those expectations include, among others, economic and market conditions in the geographic areas and industries that are or will be major markets for Aker BP ASA's businesses, oil prices, market acceptance of new products and services, changes in governmental regulations, interest rates, fluctuations in currency exchange rates and such other factors as may be discussed from time to time in the Document. Although Aker BP ASA believes that its expectations and the Document are based upon reasonable assumptions, it can give no assurance that those expectations will be achieved or that the actual results will be as set out in the Document. Aker BP ASA is making no representation or warranty, expressed or implied, as to the accuracy, reliability or completeness of the Document, and neither Aker BP ASA nor any of its directors, officers or employees will have any liability to you or any other persons resulting from your use.

CAPITAL MARKETS DAY 2018 Agenda

Session 1: 13:00 – 14:30

• Corporate strategy - Karl Johnny Hersvik, Chief Executive Officer
• Execute Karl Johnny Hersvik, Chief Executive Officer
• Improve Per Harald Kongelf, SVP Improvement

Q&A

Coffee Break

Session 2: 15:00 – 16:00

• Grow Karl Johnny Hersvik, Chief Executive Officer and Gro Gunleiksrud Haatvedt, SVP Exploration
• Finance Alexander Krane, Chief Financial Officer
• Concluding remarks Karl Johnny Hersvik, Chief Executive Officer
• Q&A

CAPITAL MARKETS DAY 2018 Today's speakers

Karl Johnny Hersvik, Chief Executive Officer

Karl Johnny Hersvik (born 1972) has been CEO of Aker BP since May 2014. Prior to joining Aker BP, he served as head of research for Statoil.

Mr Hersvik has held a number of specialist and executive positions with Norsk Hydro and StatoilHydro. He holds a number of directorships and is a member of several boards whose objective is to promote cooperation between industry and academia. Mr Hersvik holds a Cand. Scient. (second cycle) degree in Industrial Mathematics from the University of Bergen.

Alexander Krane, Chief Financial Officer

Alexander Krane (born 1976) took up the position of CFO with Aker BP in 2012. Prior to joining Aker BP, he held the position of Corporate Controller with Aker ASA. He has also worked as a public accountant with KPMG, both in Norway and in the US.

Mr Krane holds a Bachelor of Commerce degree ("siviløkonom") from Bodø Graduate School of Business and an MBA degree from the Norwegian School of Economics in Bergen. He is also a state-authorized public accountant in Norway.

Per Harald Kongelf, SVP Improvement

Per Harald Kongelf (born 1959) is responsible for Aker BP's improvement program. Prior to joining Aker BP, Per Harald Kongelf served as head of the Norwegian operations in Aker Solutions.

Kongelf holds an MSc degree from NTNU in Trondheim and has more than 25 years of industrial experience through numerous technical and management positions in Aker Solutions.

Gro Gunleiksrud Haatvedt, SVP Exploration

Gro Gunleiksrud Haatvedt (born 1957) joined Aker BP in 2014. She came from the position of SVP Exploration for the Norwegian Continental Shelf with Statoil ASA, where she also served as country manager in Libya.

She has held several positions with Norsk Hydro (head of Geology, Technology and Competence). She has been responsible for business development and exploration in Iran, and VP Exploration for NCS. Ms Haatvedt holds a Cand. Scient degree in Applied Geophysics from the University of Oslo.

AKER BP ASA 2017 achievements

AKER BP ASA Aker BP investment case

Well positioned to be profitable across the market cycles

• Purely operating on the NCS: Low political risk and attractive fiscal regime
• Strong balance sheet and capital flexibility: USD 2.9 billion in liquidity
• Robust investment program with average break-even of 18 USD/bbl*
• Substantial cash generation and growing dividends

Extensive improvement agenda to strengthen long-term competitiveness

• Reorganizing the value chain with strategic partnerships and alliances
• Aim to be an industry reference for digital project execution
• Focus on flow efficiency to substantially reduce execution time

Strong platform for future growth

• Materially oil-weighted portfolio (~80% liquids): 2P reserves of 913 mmboe and 2C contingent resources of 785 mmboe at year-end 2017
• Potential to reach 330 mboepd in 2023 (13% CAGR)
• Proven M&A track record targeting further selective inorganic growth

Corporate strategy

Karl Johnny Hersvik Chief Executive Officer

SHAPING THE STRATEGY Oil market volatility calls for resilient strategy

Steady growth in oil demand

Cyclicality is the name of the game

SHAPING THE STRATEGY NCS remains an attractive place to be

CO² emissions per unit oil & gas produced

Source: NPD

STRATEGIC AMBITION Create the leading offshore independent E&P company

CORPORATE STRATEGY Strategic toolbox

CORPORATE STRATEGY Always prioritise safety

2018 HSSE forward agenda

• Safety is our number 1 priority
• Maintain safe and reliable operations with zero HSSE incidents and no cyber attacks with significant impact on performance
• Expand and roll out sustainability and energy efficiency strategies throughout the organization
• Develop new systems for managing barrier health, including operational, organizational and technical barriers to strengthen process safety
• Work towards a climate neutral operations environment

Further develop our HSSE footprint in the Barents region

CORPORATE STRATEGY Targeting significant efficiency improvements

Illustrative project economics (USD/boe)

1. Total CAPEX over Life of field and OPEX for 10 operating years. Current base case assumes 20 years of operation, depending on oil price. All numbers in real terms 2017 2. Illustrative for NCS Projects pre-2014 oil price drop and potential for future projects

Cost leading

CORPORATE STRATEGY Improvement program showing tangible results

Cost leading

CORPORATE STRATEGY Robust balance sheet and strong dividend capacity

Rapid deleveraging over the past two years 3x dividend cover last four quarters

2.5x 2.8x 2.6x 1.9x 1.4x 1.1x 1.0x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x Q1-16 Q2-16 Q3-16 Q4-16 Q1-17 Q2-17 Q3-17

Leverage ratio (Net debt / EBITDAX)

CORPORATE STRATEGY Ambition to increase dividends in the coming years

• Robust balance sheet and strong cash flow generation
• Improvement program yielding better than expected results
• Break-even prices of 18 USD/bbl on average across portfolio for sanctioned projects*
• Accelerated investment profile in coming years will result in improved cash flows post 2020
• Expecting to retain leverage ratio below 1.5x to 2021 based on current business plan

Rationale Aker BP ambition for dividend payments (USDm)

The Board proposes that annual dividend increases to USD 450 million for 2018 with an ambition to increase by USD 100 million per year to 2021

CORPORATE STRATEGY Efficient decision making and execution

Enabled by an entrepreneurial and flexible organization

From farm-down decision at Valhall/Hod to signed agreement 1 month

3 months

From Skarv well shut-in due to damaged X-mas tree to workover started with new rig

From project sanction to start-up of drilling at Tambar 8 months

Reduction in execution time of the Volund infill subsea scope 9 months

Flexible

CORPORATE STRATEGY Profitable growth from existing portfolio

Growth

Strong production base of operated assets

• ~80% liquids / ~20% gas
• Maximize resource utilization from existing hubs
• Data acquisition
• New technology
• Attractive portfolio with potential to reach production above ~330 mboepd from 2023 (13% CAGR from 2017) from existing discoveries
• High quality development projects with low break-evens
• Sanctioned project portfolio has a break-even of 18 USD/bbl* (22 USD/bbl ex. Johan Sverdrup)

2018 CMD illustrative production potential, mboepd net

CORPORATE STRATEGY Year-end 2017 preliminary 2P reserves of 913 mmboe

Development in 2P reserves (mmboe) Proven & probable reserves (2P), end 2017*

CORPORATE STRATEGY More than 300 mmboe added to the resource hopper in 2017

Development in 2C contingent resources (mmboe)

Preliminary year-end 2017 2C contingent resources*

Growth

CORPORATE STRATEGY Ambition to grow through further M&A

Building on a strong M&A track record

Targeting new opportunities:

• Financially accretive
• Operated assets
• Predominantly liquids
• Upside potential

21

Growth

A focused portfolio on the NCS CORPORATE STRATEGY

Skarv / Ærfugl Solid base performance and area upside potential

Alvheim area High production efficiency and low operating cost

Ivar Aasen Production ramp-up and IOR opportunities

Johan Sverdrup

World class development with break even price below 25 USD/bbl*

1 billion barrels produced, ambition to produce additional 1 billion barrels

Alvheim area Ivar Aasen Johan Sverdrup Ula/Tambar Valhall/Hod Ula/Tambar Late life production with significant upside potential Valhall/Hod

Aker BP operator Aker BP partner 2018 exploration wells

Skarv / Ærfugl

Focused

CORPORATE STRATEGY Delivered superior shareholder return* last three years

Maximize shareholder value

Execute

Karl Johnny Hersvik Chief Executive Officer

EXECUTE Alvheim Area status

Operated, ~65%* working interest

• 2017 production of 70.9 mboepd net to Aker BP
• Increased compared to previous year due to new wells at Viper -Kobra and Volund infills
• High operational efficiency with well embedded continuous improvement culture
• Drilling of Volund and Boa infills in 2017
• PDO submitted for Skogul
• More infill wells being matured to arrest the production decline and minimize unit production cost

License:	PL203, PL088BS, PL036C, PL036D, PL150, PL340
Discovery year:	1998
End 2017 2P reserves (net):	111 mmboe
Production start:	2008
Partners:	ConocoPhillips, Lundin, Point (PL340), Statoil (PL036D), PGNiG (PL036D)

EXECUTE The Alvheim FPSO production and Alvheim area reserves

Reserves vs. PDO (2P gross), mmboe

EXECUTE Alvheim – Maximizing area recovery

Development of discoveries in the area

• Skogul (2020), Gekko/Kobra East (2021), Caterpillar (2021)
• Near-infrastructure exploration
• Frosk, Rumpetroll, Deep Alvheim
• New exploration prospects being matured
• Late-life gas blowdown
• Kameleon, Gekko

Priorities

• Safe and reliable operations
• 4D seismic
• Infrastructure debottlenecking

EXECUTE Valhall & Hod status

Operated, 90% working interest

2017 performance

• Production 34.7 mboepd (net)
• Stable opex/boe due to cost reductions

Driving improvement and growth

• Drilling new wells from IP platform
• Plugging abandoned wells
• Two wireline crews performing well interventions
• Valhall Flank West PDO submitted
• Maturing further infill projects

License:	PL006B, PL033, PL033B
Discovery year:	1975
2P reserves per end-2017:	257 mmboe net
Production start:	1982
Partners:	Pandion

0 20 40 60 80 100 120 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 Valhall and Hod production (mboepd, gross) Hod Valhall

EXECUTE Valhall Flank West PDO submitted

Tie-back to Valhall field center

• Unmanned wellhead platform
• Six production wells
• Six additional well slots allowing for future expansion

Robust economics

• 2P reserves 60 mmboe gross / 54 mmboe net
• CAPEX NOK 5.5 billion gross (USD 0.7 billion net)
• Production start Q4-2019 (accelerated from 2021)
• Peak production ~30 mboepd (gross)
• Breakeven oil price of 28.5 USD/bbl

Reserves gross mmboe

7.2

At concept selection

-24%

At PDO submission

5.5

Break-even oil price (USD/bbl)

33.9 -16% At PDO submission 28.5 At concept selection

EXECUTE Valhall & Hod outlook

Valhall is a giant oil field with huge potential

• Initial in-place volume (HCIIP) ~4 billion boe
• Produced ~1 billion boe to date
• Current 2P reserves indicate ~30% recovery rate

Ambition to produce another 1 bn boe from the area

• Drilling more and 'smarter' wells
• Improved reservoir monitoring and modeling = better decisions
• Fishbones technology
• Water injection
• Several digitalization projects initiated

Future opportunities identified

• Valhall Flank West PDO submitted
• Flank North water injection
• Flank South infill wells
• Hod redevelopment
• Lower Hod formation

Valhall & Hod gross resource base (bn boe)

Fishbones technology

Source: http://fishbones.as

EXECUTE Skarv Area status

Operated, 23.84% working interest

• 2017 production of 26.7 mboepd (net)
• Skarv FPSO is anchored to the seabed and has one of the world's largest gas processing plants offshore
• Field developed with subsea wells tied back to Skarv FPSO from five sub-sea templates
• Transport solution:
• 80 km long 26" line to Åsgard Transport System
• Shuttle tanker loading of oil for direct transport to the market
• Ability to process third party gas

License:	PL159, PL212, PL212B PL262
Discovery year:	1998
End 2017 2P reserves (net):	114 mmboe
Production start:	2013
Partners:	Statoil, DEA, PGNiG

EXECUTE PDO submitted for Ærfugl

Two phased subsea tie-back to Skarv FPSO

• 275 mmboe gross reserves
• Gross CAPEX of NOK 8.5 bn (NOK 4.5 bn for phase 1)
• Phase 1: Three new wells tied into the Skarv A template
• Peak production of ~100 mboepd for both phases
• Estimated first gas 2020
• Technology driven project
• Electrically trace heated pipe-in-pipe to prevent hydrate formation and improving production efficiency
• Hybrid Vertical X-mas Tree (VXT) increasing flexibility by allowing for direct wellbore access and reducing future intervention costs

Attractive economics and significant improvements

• Break-even of 18.5 USD/boe for the full-field development
• Significant increase in reserves
• Material reduction in CAPEX primarily related to D&W cost
• Alliance model selected following competitive tendering

At concept selection At PDO submission

CAPEX gross NOKbn (real)

At PDO submission At concept selection

Break-even oil price (USD/bbl)

At PDO submission At concept selection

EXECUTE Skarv area outlook

Focus areas

• Improvement program targeting Skarv FPSO production cost < 7 USD/boe when Ærfugl reaches plateau
• Step -up in exploration activity to appraise attractive area resource potential and utilize significant spare oil capacity
• Drilling of Kvitungen Tumler prospect in Q1 2018
• Follow-on exploration drilling in 2019
• Maturing near -field and infill drilling opportunities to increase oil production and optimize production
• Processing of 4D seismic shot in summer of 2017
• Reservoir work ongoing on Gråsel discovery
• Assessing completion techniques to increase recovery in low permeability Tilje formation
• Re -instate production from shut -in wells
• One well successfully re -completed (on stream in Dec. 2017)
• Firming up plans for re -completion two wells in 2018

Ula / Tambar status EXECUTE

Operated, ~80%* working interest

2017 performance

• Production 8.4 mboepd (net)
• High unit production cost
• Ongoing activities to improve productivity and cost
• Drilling two new Tambar wells
• Oda development ongoing

License:	PL019, PL019B, PL065, PL300
Discovery year:	1976
Production start:	1986
2P reserves per end-2017:	66 mmboe net
Partners:	Aker BP (80%), Faroe Petroleum (20%)

EXECUTE Ula / Tambar outlook

• Tambar (55%) re-development underway
• Two new production wells
• New gas lift module
• Drilling started in October 2017 first oil in 2018
• Will improve understanding of the reservoir

Oda (15%) development underway

• Subsea tie-back to Ula
• Est. CAPEX NOK 5.4 billion
• First oil expected in 2019

Tambar and Oda provides strong synergies

• Increased volumes will drive down unit cost
• Improves availability of injection gas
• Provides capacity for more WAG-wells in Ula

Evaluating further opportunities

• More infill wells at Ula and Tambar
• Expand use of WAG/injection
• Appraisal of Ula North and Ula Triassic
• Near-field exploration

EXECUTE Ivar Aasen and Hanz status

Operated, ~35%* working interest

• 2017 production of 18.1 mboepd (net)
• First oil from Ivar Aasen on December 24, 2016
• Successful start up with production according to agreed delivery commitment to Edvard Grieg
• Achieved excellent production performance with high uptime during first year of production
• Development scope in PDO completed
• Plateau production reached in Q4-2017, one year ahead of plan

License:	PL001B, PL242, PL457, PL338 (Unit), PL028B (Hanz)
Discovery year:	2008
End 2017 2P reserves (net):	59 mmboe
Production start:	2016
Partners:	Statoil, Spirit Energy, Wintershall, VNG, Lundin, OKEA

EXECUTE Ivar Aasen outlook

Aker BP's laboratory for operational improvements

• Drilling of two water injectors in 2018
• Hanz appraisal well planned in 2018
• Area infill drilling opportunities identified, first IOR/infill campaign planned for 2019
• Maturing near-by exploration prospects
• Optimize use of onshore control room to reduce costs and optimize production
• Ivar Aasen to serve as a laboratory for operational improvements across the Aker BP portfolio
• Drive down operation cost by application of technology, digitalization and lean work processes
• Power from shore from 2022

EXECUTE MMO activity to prolong field life

Ula

• Oda tie-in to Ula
• Ula lifeboat project

Tambar • Ula Power • Tambar Artificial Lift

Valhall & Hod

• Topside modifications for tie-in of Flank West platform
• Flank North water Injection

Skarv/Snadd

• Turret modifications for Snadd tie-back
• Topside scope methanol pumps, scale inhibitor package, electrical modifications for flowline heating

Alvheim

• Prepare for new subsea tie-ins including Boa infills and Skogul

Ivar Aasen

• Digitalization projects including remote operations
• Hanz tie-in (non-sanctioned)

EXECUTE 5 operated rigs in 2018

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Improve

Per Harald Kongelf SVP Improvement

IMPROVE Improvement is a strategic imperative

Aker BP is running a comprehensive improvement program to maximise flow efficiency and remove waste

IMPROVE The problems with traditional supplier relationships

	Alliance	Traditional
Time horizon	Long-term	From project to project
No. of suppliers	Minimum sufficient	Several
Risk sharing & Incentives	Aligned incentives and shared upside and downside risk	Dis-aligned incentives, no risk sharing
Team Organization	Integrated team, empowered team, "best person for the job"	Separate organizations with interfaces and hand-overs
Geography	Co-location of teams	Many teams in separate locations
Leadership	Trust-based leadership	Control and transaction based
Documentation	Minimum sufficient	Large documentation (control culture and tailor make)
Improvement	Common improvement language based on Lean	Separate, uncoordinated improvement initiatives
Standardization	Repetition and re-use	Tailor-make

IMPROVE Alliance principles

IMPROVE Alliance delivery: Volund infill project

The first project completed by the subsea alliance – delivered 30% below target

IMPROVE The alliance model continues to deliver

Selected projects currently being worked by the Subsea Alliance (subsea scope only)

Valhall Flank West

Skogul

IMPROVE Digitalization opens up for massive improvements

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IMPROVE It all starts with data

Aker BP has established a data platform in cooperation with Cognite

• Design criteria for the data platform
• Open architecture
• Scaleable, flexible and robust
• Cloud-based

Data feed established from ~200.000 sensors

• Live data from all Aker BP's installations
• Complete historic data

About Cognite

• Norwegian IT company
• Strategy: Develop world-class horizontal industrial data platform, making data a strategic asset in the industrial's own terms
• Aker BP is Cognite's first customer and has 10% ownership

IMPROVE Digitalization in Aker BP

Developing use cases on the data platform… …and progressing key digital initiatives

Remote operations Ivar Aasen

Unmanned Wellhead Platform Concept

PUSH

Automated well design and autonomous drilling

Digital logistics

IMPROVE The Framo story

Sharing operational data with equipment manufacturer

• Framo is a leading supplier of pumping systems
• Framo is using Ivar Aasen as a case for exploring remote operations with live data access (free of charge) through the Cognite system
• The purpose is to develop diagnostic capability and to identify further improvements on its equipment packages for future projects

Illustration source: Framo website

IMPROVE Supporting offshore operations using tablets and AR

Cognite Operations Support

Current features

• Computer vision to read equipment tags
• Live sensor data feed
• Locate failing equipment in interactive 3D model
• Shows all relevant information available

Roadmap for more functionality

• Interactive P&IDs
• Additional information sources continuously added
• Navigation on walk path to equipment
• Augmented reality to overlay equipment data
• Expert support live video feed on tablet
• Work order process integrated into portable device
• Maintenance planning optimization (timing and walking routes)
• Capture images of equipment to enable time lapse of critical equipment
• Update 3D model based on scans from application

IMPROVE Ivar Aasen digital operations model

Aker BP's laboratory for developing the digital oil field

• Digital twin based on live data from the Cognite data platform
• Digital tools, e.g. Cognite Operations Support
• Integrate OEMs in operations, e.g. Framo
• Predictive maintenance based on machine learning on top of Cognite platform
• Automation of repetitive tasks
• New business models for sourcing products and services
• Remote operations to reduce waste and increase quality

IMPROVE PUSH – Digital project execution

• Joint collaboration between Aker Solutions and Aker BP where the objective is to radically improve the way offshore projects are engineered
• Developing digital tools to reduce execution time by 25 percent and reduce costs from discovery to operations
• Initial focus on front end and platform solutions
• PUSH will ultimately provide a digital red thread from engineering to operations
• Generate 3D digital twin of the platform
• Accessing historical data and drawings: Re-using design properties and information to save engineering cost
• PUSH is currently being tested and implemented in the NOAKA project
• Master equipment list for concept studies
• Automated topside weight estimation
• Automated generation of topside 3D layouts

Accellerating the transition to fully digitized field development projects

IMPROVE Data liberation and sharing will improve NCS competitiveness

High degree of rework in subsurface projects and limited ability to benchmark performance of equipment and assets

• Inaccessible data in a world of silos
• Poor quality and not standardized formats
• Locked in applications
• Specialized systems not using open source limit open innovation
• Limited sharing, and "internal data" below critical mass

Current state Desired state

Faster maturation of subsurface projects and faster learning enabled by industry benchmarks

• All data consumable with open API standards feasible for big data analytics
• Separation of data and applications
• Sharing of data across the value chain and between peers
• Open source software
• Sharing of workflows

IMPROVE Improvement is a strategic imperative

Aker BP is running a comprehensive efficiency improvement program

Q&A

Grow

Karl Johnny Hersvik Chief Executive Officer

Gro Gunleiksrud Haatvedt SVP Exploration

GROW Johan Sverdrup development on track

Project progressing according to plan:

• Construction was close to 80% complete by end 2017
• Drilling platform modules integrated on barge in Norway
• Riser platform modules ready for transport to Norway in February
• 9 water injectors pre-drilled and completed

Costs continue to come down

• Phase 1 CAPEX estimated at NOK 92 billion (nom.) with break-even oil price below 20 USD/boe
• Full field CAPEX estimated at NOK 132 147 billion (nom.) with break-even oil price below 25 USD/boe

The project aims to deliver PDO for phase 2 in the second half of 2018

Drilling platform heavy lift at Klosterfjorden

Photo: Arne Reidar Mortensen/Statoil

GROW Targeting an area solution for NOAKA

• Statoil, LOTOS and Aker BP have agreed to establish an area forum to evaluate a joint area development for North of Alvheim* and Krafla/Askja (NOAKA)
• Two area solutions to be evaluated;
• PQ alternative with a field hub with processing platform in the middle of the area
• UPP x 2 alternative with two unmanned processing platforms, one in Krafla/Askja area and one in the North of Alvheim area
• Gross resources in the area estimated to be in excess of 500 mmboe
• Including tie-in from Frigg and Rind
• Concept selection targeted for Q1-18

GROW Aker BP assessment of NOAKA

• Maturing of selected concept towards DG2 should be based on concept that facilitates for highest area resource recovery
• The NOAKA area is prospective with a lot of possible future tie-ins from exploration prospects
• Unrisked exploration resources in the area is estimated to about 400 mmboe
• PQ alternative will include a processing platform located centrally in the area within effective reach of existing and new discoveries
• The PQ alternative have an acceptable break-even price and high value creation
• Low risk development with PQ platform based on conventional design and proven technology
• Area fields developed as subsea or unmanned wellhead platforms with tie-back to the PQ platform
• Power to be supplied from shore

GROW Project inventory provides flexibility

Project	Operator	Aker BP Equity	Gross mmboe	Plateau production (gross)	Est. first oil/gas
Valhall IP wells	Aker BP	90.0%	54	~12 mboepd	2018
Boa infills 2017	Aker BP	57.6%	15	~8 mboepd	2018
Tambar development	Aker BP	55.0%	26	~10 mboepd	2018
Kameleon infill South	Aker BP	65.0%	5	~6 mboepd	2018
Johan Sverdrup	Statoil	11.6%	2 594	~660 mboepd	2019
Oda	Centrica	15.0%	47	~30 mboepd	2019
Ula WAG from Tambar/Oda	Aker BP	80.0%	15	~7 mboepd	2019
Valhall Flank North injector	Aker BP	90.0%	7	~2 mboepd	2019
Valhall Flank West	Aker BP	90.0%	60	~30 mboepd	2019
Valhall Flank South infill	Aker BP	90.0%	14	-	2019
Skogul	Aker BP	65.0%	10	~13 mboepd	2020
Ærfugl	Aker BP	23.8%	275	~108 mboepd	2020
Valhall Lower Hod	Aker BP	90.0%	65	-	2020
Hanz	Aker BP	35.0%	18	~21 mboepd	2021
Gekko/Kobra East	Aker BP	65.0%	35	-	2021
Caterpillar	Aker BP	65.0%	9	-	2021
Garantiana	Statoil	30.0%	73	-	2022
NOAKA*	Aker BP	Various	279	-	2022
Hod re-development	Aker BP	90.0%	71	-	2022
2P reserves	Best estimate contingent resources

• Ula infill drilling
• Gohta & Filicudi

60

Creating the leading explorer GROW | EXPLORATION

61

GROW | EXPLORATION NCS production stable to 2025 – then what?

Decline after 2025 – possible to mitigate?

• Postponement to 2025 by upsides in fields and discoveries
• Yet to Find in known basins and unopened basins

NCS robust in several demand scenarios

• Offshore less hit by global peak demand than unconventionals
• Based on cost curve, NCS more competitive than other offshore

Exploration thriving on the NCS GROW | EXPLORATION

Aker BP 2018 exploration campaign

• Skewed towards frontier prospects
• 12 exploration wells
• Risked pre drill estimates ranging from 50 – 150 mmboe net to Aker BP

Trends

• Exploration well cost reduced by ~50 %
• Development cost reduced significantly
• Increased area of influence for cluster developments
• Digitalisation will further strengthen cost reduction trend

Barents Sea: A long term game GROW | EXPLORATION

• Disappointing exploration wells in 2017
• Continued exploration on new plays/areas in 2018

Barents Sea still above global exploration average:

GROW | EXPLORATION Northern areas - Exploration campaign 2018

Barents Sea

• Stangnestind megaclosure, new play
• Svanefjell possible high-impact well
• Four partner wells, diversified targets

Skarv

Kvitungen Tumler – potential high value creation

GROW | EXPLORATION North Sea: Increasing value of producing assets - Establishing new fields

Twofold Exploration task:

Deliver high value volumes to Aker BP production hubs 1

• Alvheim
• Ula
• Valhall

Reveal hydrocarbon accumulations to establish new core areas 2

• Sleipner Area possible new hub
• Raudåsen
• Possible new APA 2017 well

GROW | EXPLORATION The producing assets – how to create high value

Exploration within tie-in radius to producing assets

• Even small discoveries close to existing fields create large values
• Require unified seismic data sets covering the entire area of interest
• Invested USD 10 million in new 3D data in southern North Sea (out of total USD 50 million)
• Value creation example: Minimum economic field size near Ula is 5 mmboe

GROW | EXPLORATION Summary 2018 exploration wells

License	Prospect name	Operator	Aker BP share	Pre-drill mmboe*	Time
PL340	Frosk	Aker BP	65 %	3 - 21	Q1	A
PL790	Raudåsen	Aker BP	30 %	9 - 74	Q1	B
PL839	Kvitungen Tumler	Aker BP	24 %	37 - 269	Q1	C
PL659	Svanefjell	Aker BP	50 %	17 - 331	Q2	D
PL858	Stangnestind	Aker BP	40 %	30 - 190	H2	E
PL777	Hornet	Aker BP	40 %	17 - 166	Q4	F
PL033	Hod Appraisal	Aker BP	90 %	-	Q4	G
PL857	Gjøkåsen	Statoil	20 %	26 - 1427	Q3	H
PL721	Gråspett	DEA	40 %	32 - 263	Q4	I
PL852	Scarecrow	Spirit	40 %	83 - 245	Q4	J
PL722	Shenzhou	Statoil	20 %	40 - 295	Q4	K
PL405	Cassidy	Spirit	15 %	5 - 48	Q4	L

* Preliminary volume span (gross) L

Finance

Alexander Krane Chief Financial Officer

FINANCE Funding our business

• Strong cash flow generation in the years to come
• USD 2.9 billion in liquidity provides capital flexibility
• Attractive organic reinvestment opportunities
• Inorganic growth opportunities
• Strong support from principal owners Aker ASA (40%) and BP plc (30%)
• Credit rating obtained in 2017

Financial strengths

FINANCE Debt structure

Debt maturity profile (USDbn)

FINANCE Tax regime supportive of growth

Key attractions of the NCS tax system

• ~90% of investments recovered over 6 years
• OPEX, exploration and decommissioning costs 78% immediate tax recovery
• Financial costs recovered ~50%**
• Full tax recovery under all scenarios
• If not in tax position, losses accumulated
• Losses refunded if petroleum activities discontinued

Aker BP considerations

• Gearing considered relative to tax receivable
• Current debt position more than covered by tax receivable
• Tax balances expected to increase going forward due to organic capex program

NCS tax system and implications for Aker BP Tax-adjusted net debt (USDbn) prelim. end 2017

⁽Numbers may not add due to rounding )

FINANCE Financial risk management

Hedging policies in place to mitigate foreign exchange and commodity risks

Foreign Exchange

• Aker BP is a USD-company and is mainly exposed to investments, operating costs in NOK and tax balances nominated in NOK

Commodities

• Policy to secure up to ~30% of production volume (100% of after-tax value)
• Loss of production insurance covered after 45 days at net USD 50/bbl

Interest rate

• Of total gross debt, 22%** is at fixed rate

Hedging Overview of current commodity hedges

Commodity Hedges	2018	2019 →
% Hedged of total oil production	20%	-
Put option strike price	USD 50-60/bbl	-
Cost of hedge (weighted average, pre-tax)	USD 1.82/bbl	-

FINANCE 2018 guidance

AkerBP operator
AkerBP partner

Item	2018 guidance
2018 Production	155 – 160 mboepd
2018 Production cost	USD ~12 per boe
2018 CAPEX	USD ~1.3 billion
2018 EXPEX	USD ~350 million
2018 decommissioning expenditures	USD ~350 million

Note: Guidance based on USD/NOK 8.0

74

FINANCE 2018 guidance - production and production cost

Key activities

• 2018 production expected between 155 – 160 mboepd
• 80% liquids / 20% gas
• 2017 production cost expected to average ~12 USD/boe
• Including tariffs and transportation costs
• Aim to reduce unit costs across the portfolio
• Cost reduction
• Investments to increase production

Comparison of operated hubs, 2018 vs 2017 (9m)

FINANCE 2018 guidance - CAPEX

Key activities

Alvheim area

• Drilling Kameleon infill South and Volund sidetrack North
• Skogul: Construction of subsea systems and flowlines

Valhall area

• IP drilling program (3 wells)
• Flank West: Detailed engineering and start-up of construction
• Flank North water injection: drilling of one well

Ula area

• Tambar and Oda development, Ula power project

Skarv area

• Ærfugl: Fabrication of subsea production systems, control cables and flowlines

Johan Sverdrup

• Offshore installation of platforms and steel jackets
• Construction of the first process platform and living quarter
• Installation of oil and gas export pipelines and power cable
• Engineering and procurement for Phase 2

Split by main project

Assumes USDNOK = 8.0

FINANCE 2018 guidance – EXPEX and Decommissioning

• Drilling of 12 exploration wells (7 operated)
• Field evaluation costs (NOAKA, Hod redevelopment)
• Seismic acquisition on/near existing acreage
• Area fees and other exploration costs

Exploration expenditures Decommissioning expenditures

• Continuous P&A activity on Valhall until 2020
• Decommissioning program for legacy assets (Varg, Jette) and Ula area

Assumes USDNOK = 8.0

FINANCE Cash flow outlook 2018

• 2018 cash flow illustration based on mid-point of production guidance range
• Tax losses from Hess Norge expected to be settled in 2018
• Total investments (CAPEX, EXPEX, DECOM) of USD 2.0 bn equalling 35 USD per boe of estimated 2018 production
• Cash cost (pre-tax) of USD 16 per boe
• Cash break-even in 2018 at a realized hydrocarbon price of approximately USD 29 per boe before dividends

Illustrative 2018 break-even prices

Realized Hydrocarbon Price (USD/boe)	50	60	70	80
Production cost (USD/boe)	(12)	(12)	(12)	(12)
Other OPEX (USD/boe)	(1)	(1)	(1)	(1)
Financial cost (USD/boe)	(3)	(3)	(3)	(3)
Cash taxes (USD/boe)	(4)	(8)	(12)	(16)
Netback (USD/boe)	30	36	42	48
CAPEX (USD/boe)	(23)	(23)	(23)	(23)
EXPEX (USD/boe)	(6)	(6)	(6)	(6)
Decommissioning expenditures (USD/boe)	(6)	(6)	(6)	(6)
Investments (USD/boe)	(35)	(35)	(35)	(35)
Tax refund (USD/boe)	26	26	26	26
Free cash flow (ex. working capital) (USD/boe)	21	27	33	39
Cash flow break-even before dividends (USD/boe)		29
Cash flow B/E post dividends (USD/boe)		37

Assumes USDNOK = 8.0

Concluding remarks

Karl Johnny Hersvik Chief Executive Officer

CONCLUDING REMARKS Aker BP investment case

Well positioned to be profitable across the market cycles

• Purely operating on the NCS: Low political risk and attractive fiscal regime
• Strong balance sheet and capital flexibility: USD 2.9 billion in liquidity
• Robust investment program with average break-even of 18 USD/bbl*
• Substantial cash generation and growing dividends

Extensive improvement agenda to strengthen long-term competitiveness

• Reorganizing the value chain with strategic partnerships and alliances
• Aim to be an industry reference for digital project execution
• Focus on flow efficiency to substantially reduce execution time

Strong platform for future growth

• Materially oil-weighted portfolio (~80% liquids): 2P reserves of 913 mmboe and 2C contingent resources of 785 mmboe at year-end 2017
• Potential to reach 330 mboepd in 2023 (13% CAGR)
• Proven M&A track record targeting further selective inorganic growth

CONCLUDING REMARKS Priorities going forward

Q&A