Aker BP

Earnings Release • Oct 30, 2024

QUARTERLY REPORT Q3 2024

THIRD QUARTER 2024 RESULTS

Aker BP delivered strong results in third quarter 2024, driven by high production efficiency, low costs, and low emissions. With production guidance raised, early project completions, and robust cash flow generation, we continue to create value and return it to shareholders through dividends.

Highlights

• • Efficient operations: Oil and gas production averaged 415 (444) thousand barrels of oil equivalent per day (mboepd) during the quarter. Full-year guidance has been raised to 430-440 (previously 420-440) mboepd.
• • Low cost: Production cost was USD 6.6 (6.4) per barrel. Full-year guidance has been lowered to USD ~6.5 (previously ~7) per barrel.
• • Low emissions: Greenhouse gas emission intensity averaged 2.4 (2.6) kg CO2e per boe (scope 1 & 2), ranking among the lowest in the global oil and gas sector.
• • Projects on track: All field development projects are progressing on schedule and within budget.
• • Tyrving on stream: The Tyrving field in the Alvheim area commenced production five months ahead of the original plan.
• • Strong financial performance: Aker BP reported an EBITDA of USD 2.6 (3.0) billion, net profit of USD 173 (561) million, and record-high cash flow from operations of USD 2.8 (1.5) billion.
• • Improved debt profile: Average debt maturity extended by three years following an issuance of new 10- and 30-year bonds (completed in October).
• • Returning value: Quarterly dividend of USD 0.60 per share.

Comment from Karl Johnny Hersvik, CEO of Aker BP:

"We are pleased to report another quarter of high production efficiency, supported by smooth execution of our maintenance program. This performance has allowed us to increase our production guidance for 2024 and reinforces our position as an industry leader in both low costs and low emissions.

The execution of our development projects is progressing well. This quarter, we celebrated the early production start from the Tyrving field, which came on stream in September – five months ahead of schedule, thanks to the outstanding efforts of our project team and alliance partners. Delivering with quality, on time, and within budget is a key priority as we continue developing new fields that will support future profitable growth.

Our strong financial position was further enhanced by the issuance of 10- and 30-year bonds, extending our debt maturity and underscoring the capital markets' confidence in our strategy. This financial flexibility ensures we are well-positioned not only to deliver on current projects but also to seize future opportunities and navigate potential challenges in an evolving macroeconomic and industry landscape.

In summary, Aker BP continues to generate value through operational excellence, strategic investments in profitable growth, and disciplined financial management. We remain fully committed to delivering value to our shareholders through consistent dividends and long-term growth."

Forward-looking statements in this report 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 may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.

Key figures

	UNIT	Q3 2024	Q2 2024	Q3 2023
INCOME STATEMENT
Total income	USD million	2 858	3 377	3 513
EBITDA	USD million	2 612	2 966	3 174
Net profit/loss	USD million	173	561	588
Earnings per share (EPS)	USD	0.27	0.89	0.93
CASH FLOW STATEMENT
Cash flow from operations	USD million	2 757	1 147	2 101
Cash flow from investments	USD million	(1 402)	(1 430)	(944)
Cash flow from financing	USD million	(491)	308	(488)
Net change in cash and equivalent	USD million	864	25	669
OTHER FINANCIAL KEY FIGURES
Net interest-bearing debt	USD million	3 286	4 104	2 833
Leverage ratio		0.21	0.27	0.19
Dividend per share	USD	0.60	0.60	0.55
PRODUCTION AND SALES
Net petroleum production	mboepd	414.7	444.1	449.8
Over/underlift Net sold volume	mboepd mboepd	(23.4) 391.3	16.7 460.9	0.3 450.0
- Liquids	mboepd	345.0	398.2	389.6
- Natural gas	mboepd	46.4	62.7	60.5
REALISED PRICES
Liquids	USD/boe	80.3	83.1	87.6
Natural gas	USD/boe	63.5	57.2	60.5
AVERAGE EXCHANGE RATES
USDNOK		10.71	10.74	10.49
EURUSD		1.10	1.08	1.09

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q3 2024	Q2 2024	Q3 2023
Total income	2 858	3 377	3 513
EBITDA	2 612	2 966	3 174
EBIT	1 695	2 295	2 618
Pre-tax profit	1 627	2 279	2 565
Net profit/loss	173	561	588
EPS (USD)	0.27	0.89	0.93

Total income in the third quarter amounted to USD 2,858 (3,377) million. The decrease was driven by lower production due to planned maintenance, combined with lower volumes sold due to underlift and a decrease in realised prices. Sold volumes decreased by 15 percent to 391.3 (460.9) mboepd. The average realised liquids price was reduced by three percent to USD 80.3 (83.1) per boe, while the average price for natural gas increased by 11 percent to USD 63.5 (57.2) per boe.

Production expenses for oil and gas sold in the quarter amounted to USD 186 (290) million, with change in over/underlift being the main reason for the decrease from the previous quarter. The average production cost per barrel produced was USD 6.6 (6.4). See note 2 for further details on production expenses. Exploration expenses amounted to USD 40 (108) million, with lower dry well expenses as the main reason for the decrease from the previous quarter.

Depreciation amounted to USD 614 (588) million, equivalent to USD 16.1 (14.5) per boe. The change from last quarter is mainly driven by an increase in the abandonment provision as a result of decreased interest rates during the quarter,

which is directly charged to depreciation on the Ula/Tambar field. Impairments totalled USD 304 (83) million, consisting of technical goodwill on Grieg/Aasen, Johan Sverdrup and Valhall. For more information, see note 7.

Operating profit for the third quarter was USD 1,695 (2,295) million.

Net financial expenses increased to USD 68 (16) million, primarily due to developments in currency exchange rates and the related impact on currency loss and gains on currency derivatives. For more details, see note 4.

Profit before taxes amounted to USD 1,627 (2,279) million. Tax expense was USD 1,454 (1,718) million, resulting in an effective tax rate of 89 (75) percent, impacted by the impairment of technical goodwill with no tax impact. See note 5 for further details on tax.

This resulted in a net profit of USD 173 (561) million for the quarter.

Balance sheet

12 757 19 803	13 060	13 554
	18 620	16 123
3 362	3 307	3 166
4 147	3 233	3 375
1 625	1 997	1 909
41 693	40 218	38 127
12 477	12 685	12 524
6 673	6 589	5 754
17 488	16 426	14 271
2 904	2 512	4 070
2 152	2 007	1 509
41 693	40 218	38 127
3 286	4 104	2 833
0.21	0.27	0.19

At the end of the third quarter, total assets amounted to USD 41.7 (40.2) billion, of which non-current assets were USD 35.9 (35.0) billion.

Equity amounted to USD 12.5 (12.7) billion at the end of the quarter, corresponding to an equity ratio of 30 (32) percent.

Bond debt totalled USD 6.7 (6.6) billion, and the company's bank facilities remained undrawn. Other long-term liabilities amounted to USD 17.5 (16.4) billion.

Tax payable increased by USD 0.4 billion to USD 2.9 (2.5) billion as only one tax instalment was paid during the quarter. At the end of the third quarter, the company had total available liquidity of USD 7.5 (6.6) billion, comprising USD 4.1 (3.2) billion in cash and cash equivalents and USD 3.4 (3.4) billion in undrawn credit facilities.

On 1 October, Aker BP issued a new USD 750 million 10-year bond with a coupon rate of 5.125% and a new USD 750 million 30-year bond with a coupon rate of 5.8%. A portion of the proceeds was used to repurchase existing bonds maturing in 2025 and 2026, totalling USD 668 million in principal amount.

Cash flow

(USD MILLION)	Q3 2024	Q2 2024	Q3 2023
Cash flow from operations	2 757	1 147	2 101
Cash flow from investments	(1 402)	(1 430)	(944)
Cash flow from financing	(491)	308	(488)
Net change in cash & cash equivalents	864	25	669
Cash and cash equivalents	4 147	3 233	3 375

Net cash flow from operating activities was USD 2,757 (1,147) million in the quarter. Net taxes paid amounted to USD 424 (2,086) million. Net cash used for investment activities was USD 1,402 (1,430) million, of which investments in fixed assets amounted to USD 1,258 (1,261) million.

Net cash outflow from financing activities was USD 491 million compared to a net cash inflow of 308 million the previous quarter. The main item in the third quarter was dividend disbursements of USD 379 (379) million.

Dividends

The Annual General Meeting authorised the Board to approve the distribution of dividends pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.

During the third quarter 2024, the company paid a dividend of USD 0.60 per share. The Board has resolved to pay a similar dividend of USD 0.60 per share in the fourth quarter, scheduled for disbursement on or about 13 November 2024. The Aker BP shares will trade ex-dividend on 4 November 2024.

Hedging

The company uses several types of economic hedging instruments. Commodity derivatives may be used to mitigate the financial consequences of potential significant negative movements in oil and gas prices. Aker BP currently has limited exposure to fluctuations in interest rates, but generally manages such exposure by using interest rate derivatives. Foreign exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR, and GBP. Derivatives are marked to market with changes in market value recognised in the income statement.

The company had no material commodity derivatives exposure as of 30 September 2024.

OPERATIONAL REVIEW

Aker BP continued to demonstrate strong operational performance in the third quarter of 2024, characterised by low costs and low emissions. All field development projects progressed as planned, and Tyrving was successfully put on production ahead of schedule.

Aker BP's net production was 38.2 mmboe, down from 40.4 in the previous quarter. This corresponds to a daily average of 414.7 mboepd, compared to 444.1 mboepd last quarter.

The net sold volume reached 391.3 mboepd, down from 460.9 mboepd in the previous quarter. Of this, 88 percent was liquids and 12 percent was gas. The sales were impacted by an underlift of 23.4 mboepd, compared to an overlift of 16.7 mboepd in the previous quarter.

Average production efficiency across the portfolio decreased to 88 percent from 95 percent last quarter. This was primarily due to planned maintenance activities at several fields, which were executed as scheduled. Consequently, production is expected to recover in the fourth quarter.

The strong operational performance was reflected in low production cost and greenhouse gas emission intensity, which stood at USD 6.6 per boe and 2.4 kg CO2e per boe, respectively.

Considering year-to-date performance and the outlook for the rest of the year, the full-year production forecast for 2024 has been revised to 430-440 mboepd, up from the previous guidance of 420-440 mboepd.

All field development projects continued to progress according to plan in the third quarter. The total capital expenditure (capex) estimates remain in line with previous guidance. The Tyrving project was successfully put on production during the third quarter, five months earlier than the original plan.

Alvheim Area

KEY FIGURES	AKER BP INTEREST	Q3 2024	Q2 2024	Q1 2024	Q4 2023	Q3 2023
Production, mboepd
Alvheim	80%	37.6	46.3	46.9	24.3	22.9
Bøyla (incl. Frosk)	80%	4.2	5.2	5.6	4.9	6.3
Skogul	65%	2.2	2.1	2.4	1.4	0.3
Tyrving	61.26%	3.2	-	-	-	-
Vilje	46.904%	1.2	1.2	1.3	1.1	1.8
Volund	100%	1.2	2.1	0.8	1.4	2.5
Total production		49.5	57.0	57.1	33.1	33.8
Production efficiency		90 %	97 %	96 %	63 %	81 %

Production from the Alvheim area in the third quarter was 49.5 mboepd net to Aker BP. Production efficiency decreased to 90 percent due to a four-week planned maintenance of the SAGE gas export system. In this period, the produced gas was reinjected, allowing oil production to continue, though at a reduced rate. To maximize the efficiency of the downtime, maintenance and upgrades were also carried out on the Alvheim FPSO.

The Tyrving development project started production 3 September 2024, five months ahead of original plan. The project includes three wells and two new subsea manifolds, which are connected to the existing infrastructure at East Kameleon and further linked to the Alvheim FPSO. Tyrving is operated by Aker BP, with Petoro and ORLEN Upstream Norway as partners.

Grieg/Aasen Area

KEY FIGURES	AKER BP INTEREST	Q3 2024	Q2 2024	Q1 2024	Q4 2023	Q3 2023
Production, mboepd
Edvard Grieg Area	65%	39.4	46.1	54.7	61.8	70.8
Ivar Aasen	36.1712%	10.8	11.7	11.1	12.1	11.2
Total production		50.1	57.8	65.8	74.0	82.0
Production efficiency		93 %	94 %	99 %	99 %	97 %

Aker BP's net production from the Grieg/Aasen area averaged 50.1 mboepd in the third quarter. The decline from the previous quarter was primarily due to natural reservoir depletion and scheduled maintenance of the SAGE gas export system.

The Utsira High project is progressing as scheduled, with fabrication, engineering, and procurement activities well underway. Preparations are ongoing for subsea installation and drilling campaigns, set to begin in 2025. The project includes two subsea tiebacks: Symra, which will connect to the Ivar Aasen platform, and Solveig Phase 2, which will tie into the Edvard Grieg platform. Production from both fields is expected to commence in 2026.

The planning of a new infill drilling programme on the Edvard Grieg field is advancing according to plan. The two-well drilling campaign is scheduled to begin in the first quarter of 2025.

Johan Sverdrup

KEY FIGURES	AKER BP INTEREST	Q3 2024	Q2 2024	Q1 2024	Q4 2023	Q3 2023
Production, mboepd
Total production	31.5733%	237.2	241.0	236.9	244.9	246.5

The Johan Sverdrup field delivered strong performance in the third quarter, maintaining high production efficiency, a strong safety record, and low costs and emissions. In September, planned maintenance of the P2 processing platform was successfully completed over four days, resulting in minimal production impact. Aker BP's share of production averaged 237.2 mboepd during the quarter.

Gas export was halted for three and a half weeks during a scheduled turnaround at Kårstø. During this period, the produced gas was reinjected into two water injection wells. This operation was closely monitored to gather insights for the upcoming WAG (Water Alternating Gas) enhanced oil recovery program, set to commence in 2026.

Drilling activities continued as planned, now focused exclusively on the field centre following the completion of the Phase 2 subsea drilling campaign in early July. Four new production wells were brought online during the third quarter, with two additional wells scheduled for the fourth quarter of 2024 and the first quarter of 2025. This will increase the total number of production wells to 41.

Planning is advancing for continued drilling from the field centre in 2025, including a campaign to add new lateral branches to four existing production wells. Meanwhile, the Johan Sverdrup Phase 3 project is progressing towards concept selection. The project aims to introduce new subsea wells tied back to existing infrastructure.

Skarv Area

KEY FIGURES	AKER BP INTEREST	Q3 2024	Q2 2024	Q1 2024	Q4 2023	Q3 2023
Production, mboepd
Total production	23.835 %	23.8	37.2	38.3	36.5	37.6
Production efficiency		64 %	98 %	98 %	95 %	91 %

Production from the Skarv area averaged 23.8 mboepd net to Aker BP in the third quarter, representing a 36 percent reduction due to a planned shutdown at Skarv, coinciding with a turnaround at the Kårstø gas processing facility. Production has since been successfully ramped up in October.

During the shutdown, Skarv completed its largest turnaround to date, focusing on essential maintenance, integrity work, and project preparations to support the ongoing Skarv Satellite Project.

Significant progress was made on the Skarv Satellite Project (SSP) during the third quarter. Key milestones included the successful completion of a subsea rock installation campaign, pipelaying operations, and the completion of the first two vertical X-mas trees. Subsurface and drilling preparations remain on track, while the critical modification scope was finalised during the planned maintenance period.

In parallel to the SSP project, other measures to increase recovery in the Skarv area are being evaluated and executed. Currently, a two-well infill drilling campaign is nearing completion, with both wells expected to be brought on stream by the end of the year.

Ula Area

KEY FIGURES	AKER BP INTEREST	Q3 2024	Q2 2024	Q1 2024	Q4 2023	Q3 2023
Production, mboepd
Ula	80 %	3.4	4.0	4.1	4.7	5.0
Tambar	55 %	0.7	1.4	0.6	1.2	1.4
Oda	15 %	1.0	1.1	1.0	1.4	1.3
Total production		5.2	6.5	5.7	7.3	7.7
Production efficiency		60 %	76 %	62 %	71 %	73 %

Production from the Ula area averaged 5.2 mboepd net to Aker BP in the third quarter. The reduction was caused by planned well maintenance activity on Ula and Tambar.

A late-life strategy is being implemented for the Ula area to ensure safe and profitable operations until production ceases in 2028. Simultaneously, a field decommissioning study is underway to develop a work program for well plugging and platform removal.

A new side-track well in the Tambar area is scheduled to be drilled in the fourth quarter.

Valhall Area

KEY FIGURES	AKER BP INTEREST	Q3 2024	Q2 2024	Q1 2024	Q4 2023	Q3 2023
Production, mboepd
Valhall	90%	40.2	36.9	36.5	37.7	32.5
Hod	90%	8.7	7.9	7.7	10.8	9.6
Total production		48.9	44.8	44.1	48.5	42.1
Production efficiency		90%	80%	77 %	84 %	74 %

Aker BP's net production from the Valhall area increased to 48.9 mboepd in the third quarter, with a high production efficiency of 90 percent.

During the quarter, the rig Noble Invincible successfully completed a campaign to permanently plug and abandon (P&A) eight legacy wells at the Hod A platform. The final phase of the P&A project – removal of the conductors – is scheduled for 2025. Additionally, the Hod A platform is now prepared for full decommissioning and removal, planned for completion next year.

Valhall PWP-Fenris

Detailed engineering, procurement, and fabrication for the Valhall PWP-Fenris project progressed as planned across all sites during the third quarter. Offshore hook-up and commissioning activities for the Fenris jacket and pre-drill module also commenced, while offshore modification work at Valhall continued throughout the period.

Drilling operations on the Fenris field began in July. During the initial campaign, the upper sections of all four wells were batch drilled in July. In mid-September, the first well was successfully drilled through the reservoir. Additionally, offshore campaigns for the MEG pipeline pipelay and bundle installation were successfully completed during the quarter.

Yggdrasil

The Yggdrasil area, currently under development by Aker BP and partners, is estimated to contain around 700 mmboe in recoverable resources. This development features a central processing platform (Hugin A), two unmanned platforms (Munin and Hugin B), extensive subsea infrastructure, and a total of 55 planned wells. To ensure minimal emissions, the facilities will be powered from shore. Production is planned to commence in 2027.

Key activities are progressing across all facets of the project. Engineering efforts are primarily focused on the completion of construction and piping drawings, while construction activities are underway at sites both in Norway and internationally. Aker Solutions has initiated the assembly of the Hugin A utility module in Egersund, while the jacket's second roll-up has been completed in Verdal, and the living quarters have been fully assembled in Stord. In Haugesund, assembly of the Munin topsides has begun, with sections arriving from Thailand, while the jacket is currently being assembled in the Netherlands. Meanwhile, the transformer and compensation station are under construction in Samnanger and Fitjar, and production of the power cable is in progress in Sweden.

The Subsea Alliance has successfully installed water injection and MEG pipelines in the Yggdrasil area, in addition to the five templates installed earlier this year.

Furthermore, extensive data from ocean bottom node (OBN) seismic surveys and exploration wells has further enhanced the understanding of reservoir characteristics in the Yggdrasil area, effectively reducing risks and optimising well placement. Detailed planning for the production wells commenced in the third quarter.

Concurrently, progress is also being made on the oil discovery at Øst Frigg Beta/Epsilon, made in 2023. It is under consideration for development as part of the Yggdrasil development project, with efforts now directed towards concept selection.

Court of Appeal Ruling on Temporary Injunction

As outlined in previous reports, the Oslo District Court ruled on 18 January 2024 that the Ministry of Energy's approvals of the Plans for Development and Operation (PDO) for the Breidablikk, Tyrving, and Yggdrasil fields were invalid due to procedural errors. The court found that the state had failed to assess the effects of end-user combustion emissions in its final PDO decisions. Additionally, a temporary injunction was issued, preventing the state from granting new approvals or permits based on these PDOs until their legality was fully determined.

Both the main judgment and the temporary injunction were appealed by the state to the Borgarting Court of Appeal. On 14 October, the Court of Appeal dismissed the request for a temporary injunction, allowing the state to proceed with permitting activities for the Yggdrasil, Tyrving, and Breidablikk developments. The legality of the PDO approvals will be addressed in the main proceedings, and the Court of Appeal has requested an advisory opinion from the EFTA Court, with a decision expected in the first half of 2025.

Aker BP, which operates the Yggdrasil and Tyrving developments, is not a party to the court case, and the PDO approvals remain valid in relation to Aker BP. The company continues to execute both projects as planned. Tyrving commenced production on 3 September 2024, and the Yggdrasil development is progressing according to schedule.

EXPLORATION

Total exploration spend in the third quarter was USD 127 (148) million, while USD 40 (108) million was recognised as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation, and G&G costs.

In the third quarter, an appraisal well was successfully completed in production licence 261. The well, situated around 12 kilometres west of the Skarv Field, was drilled to confirm the size of the previous discovery made in 2022 in Storjo and explore potential upsides. The well confirmed the original estimate of 13-55 million barrels of oil equivalent and proved an additional 8-12 million barrels of oil equivalent in the second target. The partnership will consider developing Storjo as a tie-back to Skarv following the current Skarv Satellite project.

During the third quarter, Aker BP conducted one licence transaction, acquiring a 20 percent interest in production licence 1109 from OMV. The transaction is subject to government approval.

HEALTH, SAFETY, SECURITY AND ENVIRONMENT

HSSE is always the number one priority in all of Aker BP's activities. The company strives to ensure that all its operations, drilling campaigns and projects are carried out under the highest HSSE standards.

KEY HSSE INDICATORS	UNIT	Q3 2024	Q2 2024	Q1 2024	Q4 2023	Q3 2023
Total recordable injury frequency (TRIF) L12M	Per mill. working hours	2.0	1.6	2.5	2.4	2.8
Serious incident frequency (SIF) L12M	Per mill. working hours	0.7	0.6*	0.5	0.3	0.3
Acute spill	Count	0	0	0	1	0
Process safety events Tier 1 and 2	Count	0	0	2	1	0
GHG emissions intensity, equity share (scope 1&2)	Kg CO2e/boe	2.4	2.6**	3.0	2.8	2.8

*Adjusted from 0.5 in the Q2 report due to the reclassification described below

**Adjusted from 2.9 in the Q2 report, mainly as a result of actual emissions for June being lower than estimated at the time of Q2 reporting

Health & Safety

The injury frequency trended up in the third quarter. The twelve months rolling average for the Total Recordable Injury Frequency (TRIF) increased to 2.0, while the Serious Incident Frequency (SIF) increased to 0.7.

During the quarter, there were eleven reported injuries affecting TRIF, one of which has been classified as serious. The serious incident was related to a leg injury on the drill floor. Medical examination revealed no fractures, and a full recovery is expected.

The Serious Incident Frequency (SIF) for the previous quarter has been updated. Although no injuries were sustained, the assessment of a tilted container on the Hod B platform has resulted in a reclassification of an incident as serious.

Environment

No spills or process safety events were reported in the third quarter.

Aker BP's greenhouse gas (GHG) emissions intensity for the third quarter was 2.4 (2.6) kg CO2e per boe. The reduction in emission intensity compared to the previous quarter is mainly due to the production halt during the planned turnaround activities at Skarv.

OUTLOOK

The Board believes Aker BP is uniquely positioned for long-term value creation, leveraging several core strengths.

Aker BP's portfolio of world-class producing assets features high operational efficiency and low costs, generating substantial cash flow and providing a solid foundation for further value through increased recovery and near-field exploration.

The company is also an industry leader in emissions efficiency, with one of the lowest greenhouse gas emission intensities in the oil and gas sector and a well-defined pathway towards achieving net-zero Scope 1 and Scope 2 emissions.

Aker BP is driving industrial transformation through a comprehensive improvement agenda, emphasising strategic alliances and digitalisation to enhance operational excellence and sustainable growth. These initiatives aim to strengthen competitiveness and productivity across the entire value chain.

With its substantial resource base and extensive portfolio of exploration acreage, Aker BP holds compelling opportunities for profitable investments under a capital-efficient tax framework. The company is advancing several large-scale field developments set to significantly boost production from 2027. These projects are progressing on schedule, within budget, and demonstrate robust economics.

Additionally, Aker BP has established a resilient financial framework that supports its ambitious investment programme while enabling steady dividend increases for shareholders.

Collectively, these strengths position Aker BP to deliver significant long-term value.

Updated guidance for 2024

• Production of 430-440 mboepd (previously 420-440 mboepd)
• Production cost of USD ~6.5 per boe (previously USD ~7 per boe)
• Capex of USD ~5 billion
• Exploration spend of USD ~500 million
• Abandonment spend of USD ~250 million
• Quarterly dividends of USD 0.60 per share, equivalent to an annualised level of USD 2.40 per share

Disclaimer

Forward-looking statements in this report 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 may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.

FINANCIAL STATEMENTS WITH NOTES

15 · Aker BP Quarterly Report · Q3 2024

INCOME STATEMENT (UNAUDITED)

	Group
		Q3	Q2	Q3		01.01.-30.09.
(USD million)	Note	2024	2024	2023	2024	2023
Petroleum revenues		2 822.4	3 342.0	3 480.1	9 217.1	10 038.2
Other income		35.2	34.5	32.8	94.6	75.6
Total income	1	2 857.6	3 376.6	3 512.9	9 311.7	10 113.8
Production expenses	2	186.1	289.7	251.8	687.3	762.1
Exploration expenses	3	40.0	107.6	74.3	215.8	199.3
Depreciation	6	613.9	588.0	556.9	1 794.3	1 800.9
Impairments	6,7	303.5	82.7	-	386.2	474.7
Other operating expenses		19.2	13.2	12.3	43.4	41.1
Total operating expenses		1 162.8	1 081.1	895.4	3 127.0	3 278.2
Operating profit/loss		1 694.9	2 295.4	2 617.5	6 184.7	6 835.7
Interest income		42.8	35.7	38.5	115.2	91.4
Other financial income		68.1	94.2	106.3	153.4	461.5
Interest expenses		24.2	22.7	41.1	79.8	125.8
Other financial expenses		154.4	123.2	156.5	376.8	667.1
Net financial items	4	-67.8	-16.0	-52.8	-188.0	-239.9
Profit/loss before taxes		1 627.1	2 279.5	2 564.7	5 996.7	6 595.7
Tax expense (+)/income (-)	5	1 453.7	1 718.2	1 976.5	4 730.8	5 423.8
Net profit/loss		173.4	561.3	588.2	1 265.9	1 171.9
Weighted average no. of shares outstanding basic and diluted		630 786 689	631 156 391	630 520 302	631 077 878	631 364 202
Basic and diluted earnings/loss USD per share		0.27	0.89	0.93	2.01	1.86

STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)

	Group
	Q3	Q2	Q3	01.01.-30.09.
(USD million) Note	2024	2024	2023	2024	2023
Profit/loss for the period	173.4	561.3	588.2	1 265.9	1 171.9
Total comprehensive income/loss in period	173.4	561.3	588.2	1 265.9	1 171.9

STATEMENT OF FINANCIAL POSITION (UNAUDITED)

		Group
(USD million)	Note	30.09.2024	30.06.2024	31.12.2023	30.09.2023
ASSETS
Intangible assets
Goodwill	6	12 756.6	13 060.1	13 142.8	13 554.0
Capitalised exploration expenditures	6	486.1	397.4	325.4	312.9
Other intangible assets	6	1 990.8	2 036.4	2 123.4	2 163.7
Tangible fixed assets
Property, plant and equipment	6	19 802.6	18 620.0	17 449.8	16 123.5
Right-of-use assets	6	673.4	674.4	655.3	420.8
Financial assets
Long-term receivables		80.7	78.8	69.1	166.6
Other non-current assets		104.7	104.4	102.9	98.2
Long-term derivatives	13	26.1	15.9	38.1	3.3
Total non-current assets		35 921.0	34 987.4	33 906.8	32 843.0
Inventories
Inventories		255.3	243.0	202.3	180.4
Financial assets
Trade receivables		676.4	1 143.6	875.7	1 252.3
Other short-term receivables	8	668.6	597.6	525.3	461.9
Short-term derivatives	13	24.5	13.1	148.1	14.5
Cash and cash equivalents
Cash and cash equivalents	10	4 147.4	3 233.3	3 388.4	3 375.2
Total current assets		5 772.0	5 230.5	5 139.7	5 284.2
TOTAL ASSETS		41 693.0	40 217.9	39 046.5	38 127.2

STATEMENT OF FINANCIAL POSITION (UNAUDITED)

		Group
(USD million)	Note	30.09.2024	30.06.2024	31.12.2023	30.09.2023
EQUITY AND LIABILITIES
Equity
Share capital		84.3	84.3	84.3	84.3
Share premium		12 946.6	12 946.6	12 946.6	12 946.6
Other equity		-554.2	-346.4	-668.8	-507.4
Total equity		12 476.8	12 684.5	12 362.2	12 523.6
Non-current liabilities
Deferred taxes	5	12 363.2	11 691.4	10 592.3	10 181.6
Long-term abandonment provision	12	4 584.6	4 180.9	4 304.1	3 618.5
Long-term bonds	11	6 577.7	6 493.8	5 798.2	5 753.6
Long-term derivatives	13	1.2	1.9	0.5	36.4
Long-term lease debt	9	538.1	550.8	555.5	352.2
Other non-current liabilities		1.0	0.9	1.0	82.4
Total non-current liabilities		24 065.7	22 919.6	21 251.5	20 024.7
Current liabilities
Trade creditors		355.3	224.3	291.0	139.9
Short-term bonds	11	95.2	95.0	-	-
Accrued public charges and indirect taxes		37.1	32.5	38.8	34.8
Tax payable	5	2 903.8	2 512.0	3 599.9	4 069.8
Short-term derivatives	13	28.0	65.6	32.8	89.2
Short-term abandonment provision	12	125.4	157.4	250.6	167.8
Short-term lease debt	9	222.1	197.9	148.7	102.0
Other current liabilities	14	1 383.7	1 329.2	1 071.0	975.4
Total current liabilities		5 150.5	4 613.8	5 432.9	5 578.9
Total liabilities		29 216.2	27 533.4	26 684.3	25 603.7
TOTAL EQUITY AND LIABILITIES		41 693.0	40 217.9	39 046.5	38 127.2

STATEMENT OF CHANGES IN EQUITY - GROUP (UNAUDITED)

				Other equity
				Other comprehensive income
					Foreign currency
		Share	Other paid-in	Actuarial	translation	Accumulated	Total other
(USD million)	Share capital	premium	capital	gains/losses	reserves	deficit	equity	Total equity
Equity as of 31.12.2022	84.3	12 946.6	573.1	-0.1	179.8	-1 356.3	-603.5	12 427.5
Dividend distributed	-	-	-	-	-	-695.2	-695.2	-695.2
Profit/loss for the period	-	-	-	-	-	583.7	583.7	583.7
Equity as of 30.06.2023	84.3	12 946.6	573.1	-0.1	179.8	-1 467.8	-715.0	12 316.0
Dividend distributed	-	-	-	-	-	-347.6	-347.6	-347.6
Profit/loss for the period	-	-	-	-	-	588.2	588.2	588.2
Purchase of treasury shares	-	-	-	-	-	-33.1	-33.1	-33.1
Equity as of 30.09.2023	84.3	12 946.6	573.1	-0.1	179.8	-1 260.3	-507.4	12 523.6
Dividends distributed	-	-	-	-	-	-347.6	-347.6	-347.6
Profit/loss for the period	-	-	-	-	-	163.8	163.8	163.8
Sale of treasury shares	-	-	-	-	-	22.5	22.5	22.5
Other comprehensive income for the period	-	-	-	-0.1	-	-	-0.1	-0.1
Equity as of 31.12.2023	84.3	12 946.6	573.1	-0.2	179.8	-1 421.6	-668.8	12 362.2
Dividend distributed	-	-	-	-	-	-758.4	-758.4	-758.4
Profit/loss for the period	-	-	-	-	-	1 092.6	1 092.6	1 092.6
Purchase of treasury shares	-	-	-	-	-	-12.2	-12.2	-12.2
Share-based payments	-	-	-	-	-	0.4	0.4	0.4
Equity as of 30.06.2024	84.3	12 946.6	573.1	-0.2	179.8	-1 099.2	-346.4	12 684.5
Dividend distributed	-	-	-	-	-	-379.2	-379.2	-379.2
Profit/loss for the period	-	-	-	-	-	173.4	173.4	173.4
Purchase of treasury shares	-	-	-	-	-	-2.2	-2.2	-2.2
Share-based payments	-	-	-	-	-	0.3	0.3	0.3
Equity as of 30.09.2024	84.3	12 946.6	573.1	-0.2	179.8	-1 307.0	-554.2	12 476.8

STATEMENT OF CASH FLOWS (UNAUDITED)

		Group
		Q3	Q2	Q3	01.01.-30.09.
(USD million)	Note	2024	2024	2023	2024	2023
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		1 627.1	2 279.5	2 564.7	5 996.7	6 595.7
Taxes paid	5	-458.2	-2 085.9	-862.0	-3 597.9	-5 247.9
Taxes refunded	5	34.3	-	-	34.3	-
Depreciation	6	613.9	588.0	556.9	1 794.3	1 800.9
Impairment	6,7	303.5	82.7	-	386.2	474.7
Expensed capitalised dry wells	3,6	3.8	68.9	46.6	114.8	115.4
Accretion expenses related to abandonment provision	4,12	46.0	47.2	41.9	139.5	122.2
Total interest expenses	4	24.2	22.7	41.1	79.8	125.8
Changes in unrealised gain/loss in derivatives	1,4	-59.9	-83.8	-94.6	131.5	212.0
Changes in inventories and trade creditors/receivables		585.9	100.3	-271.7	210.7	69.2
Changes in other balance sheet items		36.0	127.5	78.2	70.0	-363.6
NET CASH FLOW FROM OPERATING ACTIVITIES		2 756.5	1 147.0	2 101.1	5 360.0	3 904.5
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	12	-66.5	-68.6	-44.5	-191.8	-121.5
Disbursements on investments in fixed assets (excluding capitalised interest)	6	-1 257.5	-1 261.1	-856.9	-3 501.6	-2 117.8
Disbursements on investments in capitalised exploration expenditures	6	-77.5	-100.1	-43.1	-255.4	-186.7
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-1 401.6	-1 429.9	-944.5	-3 948.8	-2 426.0
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment/fees related to revolving credit facility		-1.5	-	-	-1.5	-1.0
Repayment of bonds		-	-	-	-	-1 000.0
Net proceeds from bond issue		-	806.6	-2.3	806.6	1 486.1
Interest paid (including interest element of lease payments)		-66.9	-67.2	-70.0	-207.0	-186.3
Payments on lease debt related to investments in fixed assets		-11.1	-13.3	-23.2	-41.7	-56.5
Payments on other lease debt		-30.5	-26.8	-11.6	-76.8	-42.1
Paid dividend		-379.2	-379.2	-347.6	-1 137.6	-1 042.8
Net purchase/sale of treasury shares		-2.2	-12.2	-33.1	-14.4	-33.1
NET CASH FLOW FROM FINANCING ACTIVITIES		-491.4	308.0	-487.8	-672.4	-875.7
Net change in cash and cash equivalents		863.5	25.1	668.9	738.9	602.7
Cash and cash equivalents at start of period		3 233.3	3 215.3	2 688.8	3 388.4	2 756.0
Effect of exchange rate fluctuation on cash and cash equivalents		50.5	-7.1	17.4	20.1	16.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	4 147.4	3 233.3	3 375.2	4 147.4	3 375.2
SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits and cash		4 125.1	3 216.7	3 354.0	4 125.1	3 354.0
Restricted bank deposits		22.3	16.6	21.2	22.3	21.2
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	4 147.4	3 233.3	3 375.2	4 147.4	3 375.2

NOTES (unaudited)

(All figures in USD million unless otherwise stated)

These unaudited condensed consolidated interim financial statements ("interim financial statements") have been prepared in accordance with the IFRS® Accounting Standards as adopted by the EU IAS 34 "Interim Financial Reporting", thus the interim financial statements do not include all information required by IFRS and should be read in conjunction with the group's 2023 annual financial statements. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. These interim financial statements have been subject to a review in accordance with the International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity.

These interim financial statements were authorised for issue by the company's Board of Directors on 29 October 2024.

Note 1 Income

	Group
	Q3	Q2	Q3	01.01.-30.09.
Breakdown of petroleum revenues (USD million)	2024	2024	2023	2024	2023
Sales of liquids	2 548.0	3 011.4	3 140.5	8 307.7	8 709.5
Sales of gas	271.0	326.5	336.3	898.7	1 316.7
Tariff income	3.3	4.1	3.3	10.7	12.0
Total petroleum revenues	2 822.4	3 342.0	3 480.1	9 217.1	10 038.2
Sales of liquids (boe million)	31.7	36.2	35.8	101.1	107.6
Sales of gas (boe million)	4.3	5.7	5.6	15.8	17.7
Other income (USD million)
Realised gain (+)/loss (-) on commodity derivatives	-0.0	-	-	0.3	-0.0
Unrealised gain (+)/loss (-) on commodity derivatives	-0.8	-0.1	2.6	-1.0	1.0
Other income1)	36.0	34.6	30.2	95.3	74.6
Total other income	35.2	34.5	32.8	94.6	75.6

1) The figure includes partner coverage of assets recognised on gross basis in the balance sheet and used in operated activity.

Note 2 Production expenses

	Group
	Q3	Q2	Q3	01.01.-30.09.
Breakdown of production expenses (USD million)	2024	2024	2023	2024	2023
Cost of operations	185.9	177.2	173.9	533.8	527.8
Shipping and handling	53.5	68.7	59.2	185.6	207.6
Environmental taxes	10.8	11.8	13.5	35.4	46.8
Production expenses based on produced volumes	250.3	257.7	246.6	754.8	782.1
Adjustment for over (+)/underlift (-)	-64.1	32.0	5.3	-67.4	-20.0
Production expenses based on sold volumes	186.1	289.7	251.8	687.3	762.1
Total produced volumes (boe million)	38.2	40.4	41.4	119.3	125.9
Production expenses per boe produced (USD/boe)	6.6	6.4	6.0	6.3	6.2

Note 3 Exploration expenses

	Group
	Q3	Q2	Q3	01.01.-30.09.
Breakdown of exploration expenses (USD million)	2024	2024	2023	2024	2023
Seismic	8.9	9.8	7.9	21.7	22.0
Area fee	4.3	4.5	4.0	10.2	13.2
Field evaluation	10.3	10.5	3.3	28.3	7.4
Dry well expenses	3.8	68.9	46.6	114.8	115.4
G&G and other exploration expenses	12.7	13.8	12.6	40.8	41.3
Total exploration expenses	40.0	107.6	74.3	215.8	199.3

Note 4 Financial items

		Group
	Q3	Q2	Q3		01.01.-30.09.
(USD million)	2024	2024	2023	2024	2023
Interest income	42.8	35.7	38.5	115.2	91.4
Realised gains on derivatives	7.0	9.8	14.4	51.9	70.1
Change in fair value of derivatives	61.0	83.9	91.9	4.8	7.9
Net currency gains	-	-	-	96.1	339.5
Other financial income	0.0	0.5	-	0.5	44.0
Total other financial income	68.1	94.2	106.3	153.4	461.5
Interest expenses	68.3	55.6	60.7	183.6	156.1
Interest on lease debt	9.5	9.9	6.1	28.6	17.3
Amortised loan costs1)	11.7	11.6	11.5	34.8	37.8
Capitalised borrowing costs, development projects	-65.4	-54.4	-37.2	-167.2	-85.4
Total interest expenses	24.2	22.7	41.1	79.8	125.8
Net currency loss	60.5	52.1	51.5	-	-
Realised loss on derivatives	47.3	22.8	61.6	100.3	317.5
Change in fair value of derivatives	0.4	-	-	135.4	220.9
Accretion expenses related to abandonment provision	46.0	47.2	41.9	139.5	122.2
Other financial expenses	0.2	1.1	1.6	1.6	6.5
Total other financial expenses	154.4	123.2	156.5	376.8	667.1
Net financial items	-67.8	-16.0	-52.8	-188.0	-239.9

1) The figure mainly consists of the amortisation of the difference between fair value and nominal value on the bonds acquired in the Lundin transaction in 2022.

Note 5 Tax

	Group
	Q3	Q2	Q3	01.01.-30.09.
Tax for the period (USD million)	2024	2024	2023	2024	2023
Current year tax payable/receivable	781.3	1 143.1	1 520.1	3 024.2	4 582.4
Change in current year deferred tax	671.8	632.5	457.1	1 771.5	790.9
Prior period adjustments	0.7	-57.5	-0.7	-64.9	50.5
Tax expense (+)/income (-)	1 453.7	1 718.2	1 976.5	4 730.8	5 423.8

		Group
	2024	2024	2023
Calculated tax payable (-)/tax receivable (+) (USD million)	Q3	01.01.-30.06.	01.01.-31.12.
Tax payable/receivable at beginning of period	-2 512.0	-3 599.9	-5 084.1
Current year tax payable/receivable	-781.3	-2 243.0	-6 136.4
Net tax payment/refund	423.9	3 139.7	7 455.2
Prior period adjustments and change in estimate of uncertain tax positions	-0.7	55.5	-58.4
Currency movements of tax payable/receivable	-33.6	135.6	223.9
Net tax payable (-)/receivable (+)	-2 903.8	-2 512.0	-3 599.9
		Group
	2024	2024	2023
Deferred tax liability (-)/asset (+) (USD million)	Q3	01.01.-30.06.	01.01.-31.12.
Deferred tax liability/asset at beginning of period	-11 691.4	-10 592.3	-9 359.1
Change in current year deferred tax	-671.8	-1 099.7	-1 200.5

Prior period adjustments	0.0	0.6	-32.7
Deferred tax charged to other comprehensive income (mainly foreign currency translation)	-	-	-0.0
Net deferred tax liability (-)/asset (+)	-12 363.2	-11 691.4	-10 592.3

	Group
	Q3	Q2	Q3	01.01.-30.09.
Reconciliation of tax expense (USD million)	2024	2024	2023	2024	2023
78 % tax rate on profit/loss before tax	1 269.2	1 778.1	2 000.6	4 677.7	5 144.9
Tax effect of uplift	-98.2	-95.4	-56.5	-267.3	-140.4
Permanent difference on impairment	236.8	64.5	0.0	301.2	297.2
Foreign currency translation of monetary items other than USD	46.9	39.8	39.7	-73.4	-262.7
Foreign currency translation of monetary items other than NOK1)	5.1	10.0	15.1	-16.7	-31.5
Tax effect of financial and other 22 % items1)	24.3	-11.7	-3.3	152.8	260.1
Currency movements of tax balances	-20.9	-11.2	-21.4	27.9	93.2
Other permanent differences, prior period adjustments and change in estimate of	-9.4	-55.9	2.3	-71.4	62.9
uncertain tax positions
Tax expense (+)/income (-)	1 453.7	1 718.2	1 976.5	4 730.8	5 423.8

1) Prior to Q1 2024, the foreign currency translation of monetary items other than NOK was calculated based on 78 % tax rate, while parts of this adjustment was reversed in the next line due to limited tax deduction on currency items. From Q1 2024 the applicable tax rate has been applied to avoid the grossing effect in these two lines. Prior periods have been adjusted accordingly.

The financial statements of the company are presented in USD, its functional currency. However, as per statutory regulations, current taxes are calculated as if NOK was the functional currency. Consequently, when determining taxable income, currency gains and losses from the financial statements are replaced with the translation effect of monetary items other than NOK. Tax balances are maintained in NOK and converted to USD using the period-end exchange rate. These adjustments can influence the effective tax rate, due to fluctuations in the exchange rate between NOK and USD.

Note 6 Tangible fixed assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

Property, plant and equipment		Production	Fixtures and
	Assets under	facilities	fittings, office
(USD million)	development	including wells	machinery	Total
Book value 31.12.2023	3 522.9	13 872.3	54.5	17 449.8
Acquisition cost 31.12.2023	3 556.9	22 565.8	281.2	26 404.0
Additions	1 962.7	200.2	13.1	2 176.0
Disposals/retirement	-	-	-	-
Reclassification	-186.3	230.8	-0.1	44.5
Acquisition cost 30.06.2024	5 333.4	22 996.9	294.2	28 624.5
Accumulated depreciation and impairments 31.12.2023	34.0	8 693.5	226.6	8 954.2
Depreciation	-	1 037.0	13.3	1 050.3
Impairment/reversal (-)	-	-	-	-
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 30.06.2024	34.0	9 730.5	240.0	10 004.5
Book value 30.06.2024	5 299.3	13 266.4	54.2	18 620.0
Acquisition cost 30.06.2024	5 333.4	22 996.9	294.2	28 624.5
Additions	1 255.6	454.0	9.1	1 718.7
Disposals/retirement	-	-	-	-
Reclassification1)	-366.6	376.0	0.1	9.5
Acquisition cost 30.09.2024	6 222.4	23 826.9	303.4	30 352.7
Accumulated depreciation and impairments 30.06.2024	34.0	9 730.5	240.0	10 004.5
Depreciation	-	538.4	7.2	545.7
Impairment/reversal (-)	-	-	-	-
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 30.09.2024	34.0	10 268.9	247.2	10 550.2
Book value 30.09.2024	6 188.4	13 558.0	56.2	19 802.6

1) The reclassification is mainly related to the Tyrving project in the Alvheim area, which entered into production phase during Q3 2024.

Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straightline method over their useful life, i.e. 3 - 5 years. Estimated future Removal and decommissioning costs are included as part of cost of production facilities or fields under developement. The additions in Q3 is impacted by increased abandonment provision as a result of updated discount rate, as described in note 12.

Right-of-use assets

	Vessels and
(USD million)	Drilling Rigs	Boats	Office	Other	Total
Book value 31.12.2023	561.4	37.4	55.1	1.4	655.3
Acquisition cost 31.12.2023	591.0	51.2	95.5	2.3	740.0
Additions	138.9	-	-	-	138.9
Allocated to abandonment activity	-17.4	-	-	-	-17.4
Disposals/retirement	-	-	20.7	-	20.7
Reclassification	-49.7	-	-	-	-49.7
Acquisition cost 30.06.2024	662.8	51.2	74.8	2.3	791.1
Accumulated depreciation and impairments 31.12.2023	29.7	13.8	40.4	0.9	84.7
Depreciation	26.8	3.3	8.1	0.1	38.3
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-6.3	-	-6.3
Accumulated depreciation and impairments 30.06.2024	56.5	17.1	42.1	1.0	116.7
Book value 30.06.2024	606.3	34.1	32.7	1.3	674.4
Acquisition cost 30.06.2024	662.8	51.2	74.8	2.3	791.1
Additions	52.8	-	-	-	52.8
Allocated to abandonment activity	-7.5	-	-	-	-7.5
Disposals/retirement	-	-	-	-	-
Reclassification1)	-24.4	-	-	-	-24.4
Acquisition cost 30.09.2024	683.7	51.2	74.8	2.3	812.0
Accumulated depreciation and impairments 30.06.2024	56.5	17.1	42.1	1.0	116.7
Depreciation	16.6	1.7	3.5	0.0	21.9
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2024	73.1	18.8	45.7	1.0	138.5
Book value 30.09.2024	610.6	32.4	29.1	1.3	673.4

1) Reclassified to tangible and intangible assets in line with the activity of the right-of-use asset.

Right-of-use assets are depreciated linearly over the lifetime of the related lease contract.

INTANGIBLE ASSETS - GROUP

		Capitalised	Other intangible assets
(USD million)	Goodwill	exploration expenditures	Depreciated	Total
Book value 31.12.2023	13 142.8	325.4	1 342.0	781.4	2 123.4
Acquisition cost 31.12.2023	15 014.1	544.3	2 440.4	947.6	3 388.1
Additions	-	177.9	-	4.9	4.9
Disposals/retirement/expensed dry wells	-	111.1	-	-	-
Reclassification	-	5.2	22.3	-22.3	-
Acquisition cost 30.06.2024	15 014.1	616.3	2 462.7	930.3	3 393.0
Accumulated depreciation and impairments 31.12.2023	1 871.4	218.9	1 098.4	166.3	1 264.7
Depreciation	-	-	91.9	-	91.9
Impairment/reversal (-)	82.7	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 30.06.2024	1 954.0	218.9	1 190.3	166.3	1 356.5
Book value 30.06.2024	13 060.1	397.4	1 272.4	764.0	2 036.4
Acquisition cost 30.06.2024	15 014.1	616.3	2 462.7	930.3	3 393.0
Additions	-	77.5	-	0.7	0.7
Disposals/retirement/expensed dry wells	-	3.8	-	-	-
Reclassification	-	14.9	105.8	-105.8	-
Acquisition cost 30.09.2024	15 014.1	705.0	2 568.5	825.2	3 393.7
Accumulated depreciation and impairments 30.06.2024	1 954.0	218.9	1 190.3	166.3	1 356.5
Depreciation	-	-	46.3	-	46.3
Impairment/reversal (-)	303.5	-	-	-	-
Disposals/retirement depreciation	-	-	30.8	-30.8	-
Accumulated depreciation and impairments 30.09.2024	2 257.5	218.9	1 267.4	135.5	1 402.9
Book value 30.09.2024	12 756.6	486.1	1 301.1	689.7	1 990.8

Other intangible assets include both planned and producing projects on various fields. The producing projects are depreciated in line with the unit-of-production method for the applicable field.

	Group
	Q3	Q2	Q3	01.01.-30.09.
Depreciation in the income statement (USD million)	2024	2024	2023	2024	2023
Depreciation of tangible fixed assets	545.7	523.6	502.6	1 596.0	1 624.5
Depreciation of right-of-use assets	21.9	18.7	12.4	60.2	33.9
Depreciation of other intangible assets	46.3	45.7	41.9	138.2	142.5
Total depreciation in the income statement	613.9	588.0	556.9	1 794.3	1 800.9
Impairment in the income statement (USD million)
Impairment/reversal of tangible fixed assets	-	-	-	-	30.9
Impairment/reversal of other intangible assets	-	-	-	-	42.9
Impairment/reversal of capitalised exploration expenditures	-	-	-	-	19.9
Impairment of goodwill	303.5	82.7	-	386.2	381.0
Total impairment in the income statement	303.5	82.7	-	386.2	474.7

Note 7 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment/reversal triggers are identified, and goodwill is tested for impairment at least annually. In Q3 2024, impairment tests has been performed for fixed assets and related intangible assets, including technical goodwill.

Impairment is recognised when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. Correspondingly, a reversal of impairment is recognised when the recoverable amount exceeds the book value. Prior period impairment of goodwill is not subject to reversal. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. The impairment testing for Q3 has been performed in accordance with the fair value method (level 3 in fair value hierarchy) and based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years.

For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 30 September 2024.

Prices

Future price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil and gas prices are therefore based on the forward curve from the beginning of Q4 2024 to the end of Q3 2027. From Q4 2027, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil price assumption is unchanged from previous quarter. Long-term gas price assumption is updated from 0.68 GBP/therm to 0.70 GBP/therm.

The nominal oil prices applied in the impairment test are as follows:

	2024	2024
Nominal oil prices (USD/BOE)	Q3	Q2
2024	71.9	84.5
2025	71.0	80.0
2026	70.4	76.0
2027	71.7	74.8
From 2028 to 2035 (in real 2024 terms)	71.4	71.4
From 2036 (in real 2024 terms)	66.3	66.3

The nominal gas prices applied in the impairment test are as follows:

	2024	2024
Nominal gas prices (GBP/therm)	Q3	Q2
2024	0.96	0.90
2025	0.95	0.96
2026	0.85	0.85
2027	0.74	0.76
From 2028 (in real 2024 terms)	0.70	0.68

Oil and gas reserves

Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable reserves including potentially additional risked volumes.

Future expenditure

Future capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of the related cost. The cost profiles include an estimated impact of the currently high cost escalation in the industry.

Discount rate

The post tax nominal discount rate used is 8.9 percent, consistent with the rate applied at Q2 2024.

Currency rates

	2024	2024
USD/NOK	Q3	Q2
2024	10.55	10.68
2025	10.56	10.61
2026	10.55	10.56
2027	10.03	9.50
From 2028	8.50	8.50

The long-term currency rate is unchanged from previous quarters.

Inflation

The long-term inflation rate is assumed to be 2.0 percent. The currently high cost escalation in the industry is reflected in the cash flows rather than in the inflation rate.

Impairment testing of assets including technical goodwill

The technical goodwill recognised in previous business combinations is allocated to each CGU for the purpose of impairment testing. Hence, the impairment test of technical goodwill is included in the impairment testing of assets, and the technical goodwill is written down before the asset. The carrying value of the assets is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. In line with the methodology described in the annual report, deferred tax (from the date of acquisitions) reduces the net carrying value prior to the impairment charges. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable.

Below is an overview of the impairment charge and the carrying value per cash generating unit where impairment has been recognised in Q3 2024:

	Johan Sverdrup		Edvard Grieg &
Cash-generating unit (USD million)	CGU	Valhall CGU	Ivar Aasen CGU
Net carrying value	10 400.7	6 526.3	3 525.8
Recoverable amount	10 286.3	6 501.5	3 361.4
Impairment/reversal (-)	114.4	24.8	164.4
Allocated as follows:
Technical goodwill	114.4	24.8	164.4
Other intangible assets/licence rights	-	-	-
Tangible fixed assets	-	-	-

The impairment in Q3 is mainly related to decrease in short-term oil prices and decrease of deferred tax liabilities as described above.

Year to date impairment charge

For the nine months period ended 30 September 2024 a total impairment charge of USD 386.2 million has been recognised. The impairment is allocated to the Edvard Grieg & Ivar Aasen CGU (USD 218.8 million), Valhall CGU (USD 53.1 million) and Johan Sverdrup CGU (114.4 million) and is related to technical goodwill. Also see note 6.

Sensitivity analysis

The table below shows how the recorded impairment or reversal of impairment for the current period would be affected by changes in the various assumptions, given that the remaining assumptions are constant. The figures in the table below are in all material respect related to impairment of technical goodwill, which would have no impact on deferred tax.

			Change in impairment after
Assumption (USD million)	Change	Increase in assumptions	Decrease in assumptions
Oil and gas price forward period	+/- 50 %	-303.5	2 649.2
Oil and gas price long-term	+/- 20 %	-303.5	1 711.5
Production profile (reserves)	+/- 5 %	-232.7	620.1
Discount rate	+/- 1 % point	250.6	-177.2
Currency rate USD/NOK	+/- 2.0 NOK	-225.3	846.8
Inflation	+/- 1 % point	-217.2	508.9

Note 8 Other short-term receivables

	Group
(USD million)	30.09.2024	30.06.2024	31.12.2023	30.09.2023
Prepayments	344.2	333.3	279.7	227.0
VAT receivable	18.3	16.1	18.8	9.6
Underlift of petroleum	111.6	51.1	41.7	78.3
Other receivables, mainly balances with licence partners	194.5	197.1	185.1	146.9
Total other short-term receivables	668.6	597.6	525.3	461.9

Prior to Q1 2024, accrued income from sale of petroleum products was included in other short-term receivables. From Q1 2024, these receivables have been presented as part of trade receivables. Previous periods have been adjusted accordingly.

Note 9 Leasing

The incremental borrowing rate applied in discounting of the nominal lease debt is between 2.4 percent and 6.9 percent, dependent on the duration of the lease and when it was initially recognised.

	Group
	2024	2024	2023
(USD million)	Q3	01.01.-30.06.	01.01.-31.12.
Lease debt as of beginning of period	748.6	704.2	134.4
New lease debt recognised in the period2)	52.8	138.9	704.5
Payments of lease debt1)	-51.1	-96.0	-160.4
Lease debt derecognised in the period	-	-14.5	-
Interest expense on lease debt	9.5	19.1	26.9
Currency exchange differences	0.4	-3.1	-1.2
Total lease debt	760.2	748.6	704.2
Short-term	222.1	197.9	148.7
Long-term	538.1	550.8	555.5
1) Payments of lease debt split by activities (USD million):
Investments in fixed assets	11.1	38.2	95.7
Abandonment activity	8.0	18.0	8.3
Operating expenditures	1.5	3.7	11.3
Exploration expenditures	13.5	9.4	12.0
Other income	16.9	26.7	33.1
Total	51.1	96.0	160.4

2) New lease debt recognised in Q3 2024 is mainly related to update of future rig rate assumptions.

	Group
	2024	2024	2023
Nominal lease debt maturity breakdown (USD million):	Q3	01.01.-30.06.	01.01.-31.12.
Within one year	256.1	297.5	220.2
Two to five years	571.5	643.4	528.4
After five years	2.0	4.5	11.8
Total	829.5	945.4	760.4

The identified leases have no significant impact on the group`s financing, loan covenants or dividend policy. The group does not have any residual value guarantees. Extension options are included in the lease liability when, based on management's judgement, it is reasonably certain that an extension will be exercised.

Note 10 Cash and cash equivalents

The item 'Cash and cash equivalents' consists of bank accounts and time deposits that constitute parts of the group's available liquidity.

	Group
Breakdown of cash and cash equivalents (USD million)	30.09.2024	30.06.2024	31.12.2023	30.09.2023
Bank deposits	4 125.1	3 216.7	3 366.9	3 354.0
Restricted bank deposits1)	22.3	16.6	21.5	21.2
Cash and cash equivalents	4 147.4	3 233.3	3 388.4	3 375.2
Undrawn RCF facility	3 400.0	3 400.0	3 400.0	3 400.0

1) Tax deduction account

The RCF is undrawn as at 30 September 2024 and the remaining unamortised fees of USD 13.3 million related to the facility are therefore included in other non-current assets.

The senior unsecured Revolving Credit Facility (RCF) of USD 3.4 billion was established in May 2019 and consists of two tranches: (1) Working Capital Facility with a committed amount of USD 1.4 billion until 2025 and USD 1.3 billion until 2026, and (2) Liquidity Facility with a committed amount of USD 2.0 billion until 2025 and USD 1.65 billion until 2026.

In November 2023, Aker BP signed a new USD 1.8 billion RCF with 9 banks. The new facility will have a forward date (availability date) at the same time as the existing RCF expires in 2026 and has a maturity in 2029. The facility includes one extension option with potential final maturity in 2030.

The interest rate for the Working Capital Facility is Term SOFR plus a margin of 1.00 percent and for the Liquidity Facility Term SOFR plus a margin of 0.75 percent. The new RCF with forward start in 2026 will have an interest rate of Term SOFR plus a margin of 0.85 percent.

Drawing under the Liquidity Facility and new RCF will add a utilisation fee. A commitment fee of 35 percent of applicable margin is paid on the undrawn part of the Working Capital Facility and Liquidity Facility. Commitment fee will not be relevant for the new RCF before available in 2026. The financial covenants are as follows:

• Leverage Ratio: Net interest-bearing debt divided by twelve months rolling EBITDAX (excluding any impacts from IFRS 16) shall not exceed 3.5

• Interest Coverage Ratio: Twelve months rolling EBITDA divided by Interest expenses (excluding any impacts from IFRS 16) shall be a minimum of 3.5

The financial covenants in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements. See reconciliations of Alternative Performance Measures for detailed information.

As at 30 September 2024 the Leverage Ratio is 0.21 and Interest Coverage Ratio is 88.8 (see APM section for further details).

Note 11 Bonds

	Outstanding	Group
Senior unsecured bonds (USD million)	amount	30.09.2024	30.06.2024	31.12.2023	30.09.2023
Senior Notes 3.000% (Jan 20/Jan 25)1)	USD 95.5 mill	-	-	94.5	94.3
Senior Notes 2.875% (Sep 20/Jan 26)1)	USD 129.7 mill	128.8	128.6	128.3	128.1
Senior Notes 2.000% (Jul 21/Jul 26)1) 2)	USD 707.1 mill	674.0	669.5	660.4	655.9
Senior Notes 5.600% (Jun 23/Jun 28)	USD 500 mill	497.3	497.1	496.8	496.6
Senior Notes 1.125% (May 21/May 29)	EUR 750 mill	836.3	786.0	824.8	790.4
Senior Notes 3.750% (Jan 20/Jan 30)	USD 1,000 mill	995.8	995.6	995.2	995.0
Senior Notes 4.000% (Sep 20/Jan 31)	USD 750 mill	746.3	746.2	745.9	745.7
Senior Notes 3.100% (Jul 21/Jul 31)2)	USD 1,000 mill	873.2	868.6	859.3	854.7
Senior Notes 4.000% (May 24/May 32)	EUR 750 mill	832.5	808.9	-	-
Senior Notes 6.000% (Jun 23/Jun 33)	USD 1,000 mill	993.5	993.4	993.0	992.8
Long-term bonds - book value		6 577.7	6 493.8	5 798.2	5 753.6
Long-term bonds - fair value		6 555.7	6 249.6	5 629.4	5 268.2
Senior Notes 3.000% (Jan 20/Jan 25)	USD 95.5 mill	95.2	95.0	-	-
Short-term bonds - book value		95.2	95.0	-	-
Short-term bonds - fair value		94.8	93.8	-	-

1) The following principal amounts were repurchased in Q2 2023:

• USD 404.5 million on USD Senior Notes 3.000% (Jan 2025)

• USD 370.3 million on USD Senior Notes 2.875% (Jan 2026)

• USD 292.9 million on USD Senior Notes 2.000% (Jul 2026)

The fair value of these bonds were lower than the book value at the time of repurchase. This resulted in a net gain of USD 43.7 million presented as other financial income in Q2 2023.

2) Prior to the repurchase mentioned above, these bonds had a nominal value of USD 1 billion and were recognised at fair value in connection with the Lundin Energy transaction in 2022. The difference between fair value and nominal value is linearly amortised over the lifetime of the bonds (see note 4).

Interest is paid on a semi annual basis, except for the EUR Senior Notes which are paid on an annual basis. None of the bonds have financial covenants.

Subsequent to Q3 2024, Aker BP issued two new bonds, with parts of the net proceeds used to buy back the following principle amounts:

• USD 32 million of the 3.000% Senior Notes maturing in Jan 2025

• USD 34 million of the 2.875% Senior Notes maturing in Jan 2026

• USD 602 million of the 2.000% Senior Notes maturing in Jul 2026

The loans issued were a 10-year USD Senior Notes of USD 750 million at a coupon rate of 5.125% due in 2034, and a USD 750 million 30-year Senior Notes with a coupon rate of 5.800% due in 2054.

Note 12 Provision for abandonment liabilities

	Group
	2024	2024	2023
(USD million)	Q3	01.01.-30.06.	01.01.-31.12.
Provisions as of beginning of period	4 338.3	4 554.7	4 165.6
Incurred removal cost	-74.0	-142.7	-160.2
Accretion expense	46.0	93.5	166.3
Impact of changes to discount rate	367.9	-232.5	-101.2
Change in estimates and new provisions	31.8	65.2	484.1
Total provision for abandonment liabilities	4 709.9	4 338.3	4 554.7
Short-term	125.4	157.4	250.6
Long-term	4 584.6	4 180.9	4 304.1

The nominal pre-tax discount rate (risk-free) at end of Q3 is between 3.5 percent and 4.1 percent, depending on the timing of the expected cashflows.The corresponding range at end of Q2 was 4.3 to 5.1 percent. The calculations assume an inflation rate of 2.0 percent.

Note 13 Derivatives

	Group
(USD million)	30.09.2024	30.06.2024	31.12.2023	30.09.2023
Unrealised gain currency contracts	26.1	15.9	38.1	3.3
Long-term derivatives included in assets	26.1	15.9	38.1	3.3
Unrealised gain commodity derivatives	-	-	0.2	1.0
Unrealised gain currency contracts	24.5	13.1	147.9	13.4
Short-term derivatives included in assets	24.5	13.1	148.1	14.5
Total derivatives included in assets	50.6	28.9	186.2	17.7
Fair value of option related to sale of Cognite	-	-	-	8.1
Unrealised losses currency contracts	1.2	1.9	0.5	28.3
Long-term derivatives included in liabilities	1.2	1.9	0.5	36.4
Fair value of option related to sale of Cognite	-	0.8	4.8	-
Unrealised losses commodity derivatives	0.8	0.0	-	-
Unrealised losses currency contracts	27.2	64.8	28.0	89.2
Short-term derivatives included in liabilities	28.0	65.6	32.8	89.2
Total derivatives included in liabilities	29.2	67.4	33.3	125.6

The group uses various types of financial hedging instruments. Commodity derivatives may be used to hedge the price risk of oil and gas and foreign exchange derivatives are used to hedge the group's currency exposure, mainly in NOK, EUR and GBP.

The derivative portfolio is revalued on a mark to market basis, with changes in value recognised in the income statement. The nature of the derivative instruments and the valuation method are consistent with the disclosed information in the annual financial statements as of 31 December 2023. All derivatives are measured at fair value on a recurring basis (level 2 in the fair value hierarchy, except for Cognite put option which is considered level 3).

As of 30 September 2024, the company has entered into foreign exchange contracts to secure USD value of NOK cashflows for future tax payments and capital expenditure.

Note 14 Other current liabilities

	Group
Breakdown of other current liabilities (USD million)	30.09.2024	30.06.2024	31.12.2023	30.09.2023
Balances with licence partners	117.2	61.6	30.9	36.1
Share of other current liabilities in licences	882.9	904.4	692.5	597.3
Overlift of petroleum	45.2	48.9	42.8	35.6
Accrued interest	90.9	80.0	85.8	84.5
Payroll liabilities and other provisions	247.5	234.2	219.2	221.9
Total other current liabilities	1 383.7	1 329.2	1 071.0	975.4

Note 15 Contingent liabilities and assets

During the normal course of its business, the group will be involved in disputes, including tax disputes. The group has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37 and IAS 12.

Note 16 Subsequent events

Except for the bond issue described in note 11, the Group has not identified any events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report.

Note 17 Investments in joint operations

Total number of licences	30.09.2024	30.06.2024
Aker BP as operator	130	129
Aker BP as partner	61	61

Changes in production licences in which Aker BP is the operator:			Changes in production licences in which Aker BP is a partner:
Licence:	30.09.2024	30.06.2024 Licence:		30.09.2024	30.06.2024
PL 338F¹)	65.000%	0.000%	PL 782S¹)	40.000%	20.000%
PL 869B¹)	80.000%	0.000%	PL 1123¹)	20.000%	30.000%
PL 1008¹)	71.918%	80.000%
PL 1139¹)	0.000%	40.000%
Total	3		2 Total	2	2

1) Part of asset transactions

End of financial statement

Alternative Performance Measures

Aker BP may disclose alternative performance measures as part of its financial reporting as a supplement to the financial statements prepared in accordance with IFRS. Aker BP believes that the alternative performance measures provide useful supplemental information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Aker BP's business operations and to improve comparability between periods.

Abandonment spend (abex) is payment for removal and decommissioning of oil fields1)

Capex is disbursements on investments in fixed assets1)

Depreciation per boe is depreciation divided by number of barrels of oil equivalents produced in the corresponding period

Dividend per share (DPS) is dividend paid in the quarter divided by number of shares outstanding

EBITDA is short for earnings before interest and other financial items, taxes, depreciation and amortisation and impairments

EBITDAX is short for earnings before interest and other financial items, taxes, depreciation and amortisation, impairments and exploration expenses

Equity ratio is total equity divided by total assets

Exploration spend (expex) is exploration expenses plus additions to capitalised exploration wells less dry well expenses1)

Free cash flow (FCF) is net cash flow from operating activities less net cash flow from investment activities

Interest coverage ratio is calculated as twelve months rolling EBITDA, divided by interest expenses, excluding any impacts from IFRS 16.

Leverage ratio is calculated as Net interest-bearing debt divided by twelve months rolling EBITDAX, excluding any impacts from IFRS 16

Net interest-bearing debt is book value of current and non-current interest-bearing debt less cash and cash equivalents

Operating profit/loss is short for earnings/loss before interest and other financial items and taxes

Production cost per boe is production expenses based on produced volumes, divided by number of barrels of oil equivalents produced in the corresponding period (see note 2)

1) Includes payments of lease debt as disclosed in note 9.

		Q3	Q2	Q3	01.01.-30.09.	01.01.-30.09.
(USD million)	Note	2024	2024	2023	2024	2023
Abandonment spend
Payment for removal and decommissioning of oil fields		66.5	68.6	44.5	191.8	121.5
Payments of lease debt (abandonment activity)	9	8.0	8.8	0.9	26.0	6.0
Abandonment spend		74.5	77.5	45.4	217.8	127.5
Depreciation per boe
Depreciation	6	613.9	588.0	556.9	1 794.3	1 800.9
Total produced volumes (boe million)	2	38.2	40.4	41.4	119.3	125.9
Depreciation per boe		16.1	14.5	13.5	15.0	14.3
Dividend per share
Paid dividend		379.2	379.2	347.6	1 137.6	1 042.8
Number of shares outstanding		630.8	631.2	630.5	631.1	631.4
Dividend per share		0.60	0.60	0.55	1.80	1.65
Capex
Disbursements on investments in fixed assets (excluding capitalised interest)		1 257.5	1 261.1	856.9	3 501.6	2 117.8
Payments of lease debt (investments in fixed assets)	9	11.1	16.5	27.2	49.3	66.4
CAPEX		1 268.6	1 277.7	884.1	3 550.8	2 184.2
EBITDA
Total income	1	2 857.6	3 376.6	3 512.9	9 311.7	10 113.8
Production expenses	2	-186.1	-289.7	-251.8	-687.3	-762.1
Exploration expenses	3	-40.0	-107.6	-74.3	-215.8	-199.3
Other operating expenses		-19.2	-13.2	-12.3	-43.4	-41.1
EBITDA		2 612.2	2 966.1	3 174.4	8 365.3	9 111.3
EBITDAX
Total income	1	2 857.6	3 376.6	3 512.9	9 311.7	10 113.8
Production expenses	2	-186.1	-289.7	-251.8	-687.3	-762.1
Other operating expenses		-19.2	-13.2	-12.3	-43.4	-41.1
EBITDAX		2 652.2	3 073.7	3 248.8	8 581.0	9 310.7
Equity ratio
Total equity		12 476.8	12 684.5	12 523.6	12 476.8	12 523.6
Total assets		41 693.0	40 217.9	38 127.2	41 693.0	38 127.2
Equity ratio		30%	32%	33%	30%	33%
Exploration spend
Disbursements on investments in capitalised exploration expenditures		77.5	100.1	43.1	255.4	186.7
Exploration expenses	3	40.0	107.6	74.3	215.8	199.3
Dry well	3	-3.8	-68.9	-46.6	-114.8	-115.4
Payments of lease debt (exploration expenditures)	9	13.5	9.3	1.3	22.9	11.7
Exploration spend		127.3	148.0	72.2	379.3	282.3

		Q3	Q2	Q3	01.01.-30.09.	01.01.-30.09.
(USD million)	Note	2024	2024	2023	2024	2023
Interest coverage ratio
Twelve months rolling EBITDA		11 539.6	12 101.8	12 602.7	11 539.6	12 602.7
Twelve months rolling EBITDA, impacts from IFRS 16	9	-62.3	-55.1	-39.0	-62.3	-39.0
Twelve months rolling EBITDA, excluding impacts from IFRS 16		11 477.3	12 046.7	12 563.8	11 477.3	12 563.8
Twelve months rolling interest expenses	4	240.1	232.5	204.2	240.1	204.2
Twelve months rolling amortised loan cost	4	46.3	46.1	50.8	46.3	50.8
Twelve months rolling interest income	4	157.2	152.9	104.9	157.2	104.9
Net interest expenses		129.3	125.7	150.2	129.3	150.2
Interest coverage ratio		88.8	95.8	83.6	88.8	83.6
Leverage ratio
Long-term bonds	11	6 577.7	6 493.8	5 753.6	6 577.7	5 753.6
Short-term bonds	11	95.2	95.0	-	95.2	-
Other interest-bearing debt		-	-	-	-	-
Cash and cash equivalents	10	4 147.4	3 233.3	3 375.2	4 147.4	3 375.2
Net interest-bearing debt excluding lease debt		2 525.5	3 355.5	2 378.4	2 525.5	2 378.4
Twelve months rolling EBITDAX		11 822.4	12 418.9	12 834.1	11 822.4	12 834.1
Twelve months rolling EBITDAX, impacts from IFRS 16	9	-61.5	-54.5	-38.2	-61.5	-38.2
Twelve months rolling EBITDAX, excluding impacts from IFRS 16		11 760.9	12 364.4	12 795.9	11 760.9	12 795.9
Leverage ratio		0.21	0.27	0.19	0.21	0.19
Net interest-bearing debt
Long-term bonds	11	6 577.7	6 493.8	5 753.6	6 577.7	5 753.6
Other interest-bearing debt		-	-	-	-	-
Long-term lease debt	9	538.1	550.8	352.2	538.1	352.2
Short-term bonds	11	95.2	95.0	-	95.2	-
Short-term lease debt	9	222.1	197.9	102.0	222.1	102.0
Cash and cash equivalents	10	4 147.4	3 233.3	3 375.2	4 147.4	3 375.2
Net interest-bearing debt		3 285.7	4 104.1	2 832.6	3 285.7	2 832.6
Free cash flow
Net cash flow from operating activities		2 756.5	1 147.0	2 101.1	5 360.0	3 904.5
Net cash flow from investment activities		-1 401.6	-1 429.9	-944.5	-3 948.8	-2 426.0
Free cash flow		1 355.0	-282.9	1 156.6	1 411.3	1 478.5

Operating profit/loss see Income Statement

Production cost per boe see note 2

To the Shareholders of Aker BP ASA

Report on Review of Interim Financial Information

Introduction

We have reviewed the accompanying condensed consolidated statement of financial position of Aker BP ASA as at 30 September 2024, and the related condensed consolidated income statement, the statement of comprehensive income, the statement of changes in equity and the statement of cash flows for the three-month and nine-month periods then ended, and a summary of significant accounting policies and other explanatory notes. Management is responsible for the preparation of this interim financial information in accordance with IAS 34 Interim Financial Reporting. Our responsibility is to express a conclusion on this interim financial information based on our review.

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (ISAs), and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the accompanying consolidated interim financial information is not prepared, in all material respects, in accordance with IAS 34 Interim Financial Reporting.

Stavanger, 29 October 2024 PricewaterhouseCoopers AS

Gunnar Slettebø State Authorised Public Accountant

Aker BP ASA

Fornebuporten, Building B Oksenøyveien 10 1366 Lysaker

www.akerbp.com

CONTACT

Postal address: P.O. Box 65 1324 Lysaker, Norway

Telephone: +47 51 35 30 00 E-mail: post@akerbp.com