Slides
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Second quarter 2025 15 July 2025 Aker BP ASA
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2 Second quarter highlights Delivering on our strategy ▪ Strong operational performance ▪ Field developments on track ▪ Exploration success at Yggdrasil ▪ Stable financial delivery
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3 Strong production driven by high efficiency Production 1,000 barrels oil equivalents per day (mboepd) 444 415 449 441 415 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Johan Sverdrup Valhall Alvheim Grieg/Aasen Skarv Strong performance in Q2 ▪ 95% production efficiency (97% in Q1) ▪ Stable production from Johan Sverdrup ▪ One month planned shutdown at Valhall and Ula Full-year guidance lifted to 400-420 mboepd ▪ Previously 390-420 mboepd
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▪ Continued high production ▪ The first retrofit multilateral well drilled in Q2 ▪ Three additional wells to be drilled this year ▪ Phase 3 sanctioned in Q2 ▪ Two new subsea templates and eight additional wells ▪ Start-up planned for Q4-2027 Johan Sverdrup 4
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5 Low cost – a competitive advantage Industry peers total operational cost1 USD per boe, 2024 1) Source Wood Mackenzie. Companies included: Aker BP, BP, Chevron, ConocoPhillips, Diamondback Energy, DNO, Eni, EOG Resources, Equinor, ExxonMobil, Galp Energia, Harbour Energy, Hess Corp., Marathon Oil, OKEA, Pioneer, Shell, TotalEnergies, Tullow Oil, Vår Energi Aker BP production cost USD per boe 0 5 10 15 20 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 12.0 7.3 7.2 7.2 5.6 6.0 6.2 6.1 6.4 6.6 5.7 6.5 7.3 Q2-22 Q3-22 Q4-22 Q1-23 Q2-23 Q3-23 Q4-23 Q1-24 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Base opex Tariff & transport Projects Power & environment tax
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0 20 40 60 80 100 120 140 250 largest producing upstream companies Industry emission intensity 2024 kg CO2e per boe, equity share2 20% 40% 60% 80% 100% A global leader in low-emission oil and gas production 6 Decarbonising our business Aker BP emission intensity, kg CO2e per boe1 1) Scope 1 & 2 2) Source: Wood Mackenzie – Global upstream CO2 emissions 5.3 3.8 3.2 2.9 2.6 2.8 2.8 3.0 2.6 2.4 2.5 2.8 2.8 Q2-22 Q3-22 Q4-22 Q1-23 Q2-23 Q3-23 Q4-23 Q1-24 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25
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- 100 200 300 400 500 600 700 800 900 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Maintaining production above 500 mboepd into the 2030s Base production and ongoing projects secure high production into the 2030s Base production and ongoing/planned named projects1 1,000 mboepd IOR/discoveries/ ILX Stand-alone discoveries Improved base (IOR, etc.) M&A (Asset & corporate) Near-field exploration (ILX) Projects (Discoveries, 2C) Levers for value accretive growth post-2030 Efficient base production M&A and exploration~525 71) Includes producing fields, ongoing projects, and mature non-sanctioned projects, as well as ordinary IOR/infill activities.
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Tie-back projects at Alvheim, Skarv and Grieg Aasen Net ~170 mmboe Field developments driving growth and value creation Yggdrasil Net ~450 mmboe Valhall PWP/Fenris Net ~190 mmboe ▪ New area hub with several discoveries ▪ Significant exploration upside potential. East Frigg discovered and added to plan ▪ Capex (pre-tax) USD 12.1bn ▪ Start-up in 2027 ▪ New platform at Valhall and UI at Fenris ▪ Modernising Valhall field centre and enabling development of Fenris gas field ▪ Capex (pre-tax) USD 5.9bn ▪ Start-up in 2027 ▪ Nine tie-backs to existing infrastructure – four of which already completed ▪ Low break even, high returns, rapid payback ▪ Capex (pre-tax) USD 3.5 bn ▪ Start-up in 2023/2024/2026/2027 Net volume ~800 mmboe | Net capex USD ~3.2 billion after tax | Portfolio BE at USD 35-40 per barrel1 81) Break-even oil price using 10% discount rate
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Development projects on track ▪ On track for first oil according to schedule ▪ Engineering and procurement largely complete ▪ High construction activity ▪ Jackets installation this summer ▪ Extensive subsea campaigns underway ▪ Drilling activity ramping up ▪ Investments in ongoing projects revised up by ~6% 9
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East Frigg development sanctioned in Q2 ▪ Discovered in 2023 (gross ~75 mmboe) ▪ Included in the Yggdrasil development project New oil discovery in ongoing Omega Alfa well1 ▪ Multi-target well with five prospects ▪ Oil discovered in two of the first three structures (20-40 mmboe) ▪ Operations progressing to the other prospects (pre-drill 30-70 mmboe) Significant upside potential in the area ▪ Natrudstilen prospect scheduled for drilling in H2-2025 ▪ Further exploration potential in the Frigg area – acreage secured 10 Unlocking new volumes at Yggdrasil Towards our 1-billion-barrel ambition Current exploration drilling Yggdrasil development Frigg field and other 1) Further details will be disclosed when drilling is completed and the data have been analysed.
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Exploration programme 11 Licence Prospect Operator Aker BP share Volume est. (mmboe) Status PL1005 Rondeslottet Aker BP 40% Dry PL554 Skrustikke Equinor 30% 25 - 100 Ongoing Omega/Alfa/Sigma/etc.1 Aker BP 38%/48% Discovery, drilling ongoing PL1140 Lofn Equinor 40% 10 - 60 Q3-25 PL1140 Langemann Equinor 40% 10 - 50 Q3-25 PL873 Natrudstilen Aker BP 48% 15 - 60 Q3-25 PL1086 Page DNO 20% 10 - 55 Q3-25 PL554 Avbitertang Equinor 30% 20 - 75 Q4-25 PL554E Narvi Equinor 30% 10 - 65 Q4-25 PL1014 Arkenstone Equinor 10% 65 - 300 Q4-25 PL979 Svarteknippa Aker BP 60% 20 - 70 Q1-26 PL1148 Carmen Appr Wellesley 10% 20 - 50 Q1-26 PL1153 Alpehumle Aker BP 40% 10 - 180 Q2-26 PL782S Linga Equinor 40% 5 - 50 Q2-26 PL1139 Gere Aker BP 60% 10 - 55 Q3-26 1) Drilled as one operation in the Yggdrasil area (PL873 / PL873B / PL 1249) Natrudstilen Narvi Skrustikke Avbitertang Aker BP partner Aker BP operator Upcoming wells Omega/Alfa/etc Arkenstone Page Rondeslottet Alpehumle Gere Svarteknippa Carmen Appr Linga Langemann Lofn
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Second quarter 2025 Financial highlights ▪ Operational performance reflected in financial results ▪ Delivering on our value creation plan ▪ Strong financial position ▪ Dividend USD 0.63 per share 12
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Second quarter 2025 performance 13 Produced and sold volume (1,000 boepd) Production cost (USD per boe) Net cash flow from investments (USD bn)1Net cash flow from operations (USD bn) 444 415 449 441 415 461 391 439 458 414 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Production Sales 6.4 6.6 5.7 6.5 7.3 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 1.4 1.4 1.4 1.4 1.9 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 1.1 2.8 1.1 2.1 1.2 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Includes capex, expex & abex $67 per boe (76) Net realised price $-1.0 (1.1) FCF per share $0.63 (0.63) Dividend per share 1) Adjusted for Investments in financial assets
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Sales of oil and gas Volume sold mboepd Total income USD million Realised prices USD/boe 398 345 374 394 356 63 46 66 64 58 461 391 439 458 414 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Liquids Natural gas 3,011 2,548 2,545 2,659 2,170 326 271 477 487 360 3,377 2,858 3,068 3,201 2,584 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Liquids Natural gas Other 83 80 74 75 67 57 64 79 85 69 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Liquids Natural gas 14
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Income statement Q2 2025 Q1 2025 Before impairment Impairments Actual Before impairment Impairments Actual Total income 2 584 2 584 3 201 3 201 Production costs 285 285 278 278 Other operating expenses 16 16 14 14 EBITDAX 2 283 2 283 2 908 2 908 Exploration expenses 60 60 107 107 EBITDA 2 223 2 223 2 801 2 801 Depreciation 591 591 691 691 Impairments 717 717 189 189 Operating profit (EBIT) 1 632 (717) 915 2 110 (189) 1 921 Net financial items (63) (63) 14 14 Profit/loss before taxes 1 569 (717) 852 2 123 (189) 1 935 Tax (+) / Tax income (-) 1 176 1 176 1 619 1 619 Net profit / loss 393 (324) 505 316 EPS (USD) 0.62 (0.51) 0.80 0.50 Effective tax rate 75% 138% 76% 84% USD million 414 mboepd (458) Oil and gas sales $67 per boe (76) Net realised price $7.3 per boe (6.5) Production cost 15
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Cash flow statement USD million $-1.0 (1.1) FCF per share $0.63 (0.63) Dividend per share $1.2 bn (2.1) Cash flow from operations Q2-25 Q1-25 Q4-24 Q3-24 Op. CF before tax and WC changes 2 331 2 852 2 935 2 610 Net taxes paid (1 571) (718) (1 164) (424) Changes in working capital 480 (25) (708) 571 Cash flow from operations 1 240 2 109 1 063 2 757 Adj. Cash flow from investments1 (1 899) (1 424) (1 366) (1 402) Free cash flow (658) 685 (304) 1 355 Investments in financial assets (300) - - - Net debt drawn/repaid - (64) 836 - Dividends (398) (398) (379) (379) Interest, leasing & misc. (247) (125) (68) (112) Cash flow from financing (645) (587) 388 (491) Net change in cash (1 603) 98 85 864 Cash at end of period 2 745 4 283 4 147 4 147 161) Adjusted for Investments in financial assets
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Assets 30.06.25 31.03.25 30.06.24 PP&E 22 421 21 091 18 620 Goodwill 11 851 12 568 13 060 Other non-current assets 3 501 3 063 3 307 Cash and cash equivalent 2 745 4 283 3 233 Other current assets 2 358 2 293 1 997 Total Assets 42 877 43 297 40 218 Equity and liabilities Equity 11 851 12 609 12 685 Financial debt1 7 627 7 532 6 652 Deferred taxes 14 447 13 470 11 691 Other long-term liabilities 4 939 4 701 4 734 Tax payable 1 781 3 049 2 512 Other current liabilities1 2 232 1 935 1 944 Total Equity and liabilities 42 877 43 297 40 218 Balance sheet USD million $6.0 bn ($7.7) Total available liquidity 0.43 (0.29) Leverage ratio 28% (29%) Equity ratio 1) Prior to 2025 accrued interest on bonds was presented as other current liabilities but is presented as short-term bonds from Q1 2025. Previous periods have been adjusted accordingly 17
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18 Maintaining a strong balance sheet and financial capacity Debt increase primarily due to significantly higher tax payment in Q2 than actual tax liability incurred Net interest-bearing debt1 + tax payable Excl. leases, USD billion Available liquidity3 USD billion Leverage ratio2 Targeting below 1.5 over time 3.4 2.6 3.4 3.2 4.6 2.5 2.9 2.4 3.0 1.8 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 NIBD Tax payable end of quarter 6.6 7.5 7.5 7.7 6.0 3.2 4.1 4.1 4.3 3.0 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Liquidity Cash and cash eq./Fin. Inv. 0.9 0.6 0.3 0.1 0.5 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.3 0.2 0.3 0.3 0.4 Q2-21 Q2-22 Q2-23 Q2-24 Q2-25 1) Prior to 2025 accrued interest on bonds was presented as other current liabilities but is presented as short-term bonds from Q1 2025. Previous periods have been adjusted accordingly 2) Leverage ratio: Net interest-bearing debt excluding lease debt divided by EBITDAX last 12 months, excluding effects of IFRS16 Leasing 3) Available liquidity: Cash andcash equivalents, financial investments and undrawn RCF facility
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- 1 2 3 4 5 6 7 2023 2024 2025 2026 2027 2028 Actual Total capex Capex after tax Investing in high return projects In a supportive fiscal regime Aker BP est. capex before and after tax1 USD billion ▪ Investment plan updated to reflect recent project reviews ▪ PDO projects are progressing on schedule ▪ Investment estimates up ~6% (USD ~1.2 bn) compared to original guidance ▪ Projects eligible for the 2020 tax system with 86.9% tax deduction ▪ After-tax FCF impact of change in investment estimates USD 150-200 million 191) All capex related to “Base production and ongoing/planned named projects” are included
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20 Creating substantial shareholder value Aker BP value creation plan 2023-2028 Cumulative free cash flow1 USD billion Leverage ratio2 After dividends 0 2 4 6 8 10 12 14 16 2023 2024 2025 2026 2027 2028 $90/boe $65/boe $90/boe $65/boe Stress-test at $50/boe Illustrative calculations. 2023 and 2024 as reported. Scenario from February 2025 updated with capex estimates per July 2025.1) Free cash flow: Net cash flow from operating activities less Net cash flow from investment activities 2) Leverage ratio: Net interest-bearing debt divided by EBITDAX last 12 months, excluding effects of IFRS16 Leasing. Assuming a 5% annual increase in dividend from 2025 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 2023 2024 2025 2026 2027 2028
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1.18 1.35 2.00 2.20 2.40 2.52 2020 2021 2022 2023 2024 2025 ▪ Low-cost production and strong cash flow provide resilient dividend capacity ▪ Distributions reflect capacity through the cycle ▪ Ambition to grow the dividend with minimum 5% per year Resilient dividend growth Dividends USD per share 21 Q1 Q2 Q3 Q4 Planned Paid
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Near-term tax payments Sensitivity for H1-2026 USD million 0 500 1 000 1 500 2 000 2 500 Q1-24 Q2-24 Q3-24 Q4-24 Q1-25 Q2-25 Q3-25 Q4-25 Q1-26 Q2-26 $80 22 1) New process for tax payments: Tax for the year is paid in ten monthly instalments plus a final settlement in Q4 following year. First payment in August, and no payment in January and July. Initial tax estimate for the year is made in Q2, the H2-instalments are then fixed in NOK. Option for voluntary addition payment will be spread over three instalments (September, October and November) – normally only relevant if initial estimate was too low. At year-end, the upcoming five instalments (Feb-June) may be adjusted to reflect latest estimate. $60 $80 $60 Adjusted payment schedule from Q3-251 ▪ Number of tax instalments increased to ten from six per year, with no payment in January and July H1-26 sensitivity analysis ▪ Two oil price scenarios illustrated (avg. H2-25) ▪ Gas price: USD 13.0 per MMBtu ▪ USDNOK: 10.0
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2025 guidance 23 Previous guidance Actual Jan-June New guidance Production mboepd 390-420 428 400-420 Production cost USD/boe ~7.0 6.9 ~7.0 Capex USD billion 5.5-6.0 3.1 ~6.5 Exploration USD billion ~0.45 0.25 ~0.45 Abandonment USD billion ~0.15 0.06 ~0.10
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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. 24 Disclaimer
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