OKEA ASA

Investor Presentation • Apr 25, 2024

OKEA ASA

Credit investor update

25 April 2024

Forward looking information

This presentation contains certain statements and information that constitutes "forward-looking information" and relates to future events, including the Company's future performance, business prospects or opportunities. Forward-looking information is generally identifiable by statements containing words such as "expects", "believes", "estimates" or similar expressions and could include, but is not limited to, statements with respect to estimates of reserves and/or resources, future production levels, future capital expenditures and their allocation to exploration, development and production activities.

Forward-looking information reflects current views about future events and is, by its nature, subject to known and unknown risks and uncertainties because it relates to events and depend on circumstances that will occur in the future. There are a number of factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. Such risks include but are not limited to operational risks (including exploration and development risks), productions costs, availability of equipment, reliance on key personnel, reserve estimates, health, safety and environmental issues, legal risks and regulatory changes, competition, geopolitical risk, and financial risks.

Neither the Company or any officers or employees of the Company provides any warranty or other assurance that the assumptions underlying such forward-looking information are free from errors, nor does any of them accept any responsibility for the accuracy and completeness of the forwardlooking information. Any forward-looking information speaks only as of the date on which such statement is made, and the Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable law.

The presentation is subject to Norwegian law.

Table of contents Company and business Financials

Appendix

OKEA at a glance

A leading independent E&P company operating on the Norwegian continental shelf

Introduction

• Founded in 2015 and listed on the Oslo Stock Exchange since June 2019
• Repeat and successful bond issuer since 2017
• Headquartered in Trondheim, operations centres in Kristiansund and Bergen, and offices in Oslo and Stavanger
• Full scale operator organisation with ~450 employees on- and offshore
• Diversified asset portfolio with core focus on mid- to late-life assets in the North Sea and Norwegian Sea
• Operator of the Draugen, Brage and Bestla fields, and partner shares in Gjøa, Ivar Aasen, Nova, Yme and Statfjord area
• Targeting growth through organic developments and M&A
• Completed three acquisitions last two years

4 ¹ As per Q1 2024. A true-up of gas volumes produced in the fourth quarter from Hasselmus increases production by equivalent to 1.145 kboepd in the first quarter ²Based on Annual Statement of Reserves (YE'23). Bestla included in 2P reserves (FID March 2024), in addition to 0.6 mmboe additional reserves at Brage due to longer field life with Bestla ³Pro forma for EBITDA from Statfjord area LTM ⁴Cash flow from operating activities less cash flow from investment activities excluding cash paid for business combinations. Pro forma for Statfjord area cash flow LTM ⁵As per 22 April 2024 ⁶ Net debt to EBITDA (LTM) as per Q1 2024. Net debt per definition in the Bond Terms, including net tax payable

Several milestones reached since last bond issue

Further increased diversification of portfolio following completion of Statfjord area acquisition from Equinor – OKEA currently has 10 producing assets

Continued increase in production, with total production in Q1'24 of 42.1 kboepd¹, up from 22.3 kboepd in Q2'23, driven by both organic initiatives such as first gas from Hasselmus and new wells at Brage, and inorganic growth through closing of the Statfjord acquisition YE'23

EBITDA in Q1'24 increasing to NOK 2,159m, up from NOK 1,167m in Q2'23, with corresponding strong operational cash flow

Final investment decision made for Bestla. Estimated to add 9 mmboe of net reserves and produce 10 kboepd (net) at peak Production commenced at Hasselmus in October 2023

Approval for extension of Draugen license from the Ministry of Energy, ensuring long-term production

Collaborating closely with Equinor at Statfjord with key focus on unlocking the assets' potential and dedicating significant resources to establish and realise extensive improvement plan

Delivering in line with growth strategy

6

0.0

5.0

10 .0

15 .0

20 .0

25 .0

30 .0

35 .0

40 .0

45 .0

¹ Pro-forma production including full-year contribution from acquired assets. ²Net debt per definition in the Bond Terms, including net tax payable. The illustrative 2024E Leverage Ratio has been

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

Strategic pillars

The leading mid- to late-life operator on the NCS

Profitable growth

Pursuing accretive organic and inorganic growth initiatives

Strategy focused on proven mid- to late-life assets on the NCS

Targeting the right assets where we have a competitive advantage

Value creation

Continuously working for value maximisation in existing portfolio

Finding value where others divest, rejuvenating mature assets

Leveraging operator capabilities to capture upside and create value

Capital discipline

Maintaining financial flexibility and robust balance sheet

Focused on lower risk investments with robust economics

Balanced capital allocation framework

Management with broad operational and financial expertise

Team with extensive track record and varied experience on the NCS

Material and diversified portfolio of producing assets

Production spread across ten individual fields, with footprint covering the North Sea and Norwegian Sea

• 2P reserves + 2C resources (mmboe)²

9 ¹Pro-forma production including full-year contribution from acquired assets. A true-up of gas volumes produced in the fourth quarter from Hasselmus increases production by equivalent to 1.145 kboepd in the first quarter ² As per 31 December 2023 Annual Statement of Reserves adjusted for FID at Bestla

Creating value through active operatorship – Draugen case study

Efficiency improved and production at highest level in since Q3'19

Draugen thriving under OKEA operatorship Draugen gross production

• Draugen was winner of previous operator Shell's CEO HSSE & SP Award kboepd for 2017 and used as a global benchmark within Shell
• After taking operatorship in December 2018, OKEA has:
  • Improved production efficiency
  • Extended lifetime from 2027 to >2040, formalised in approval by Ministry of Energy in March 2024 of license extension till end 2040
  • Sanctioned electrification project will reduce CO2 intensity by 95% and production expense by 2027
  • Increased production to a 4.5-year high in Q1'24 driven by solid operational performance and Hasselmus tie-back on stream Q4'23
• Hasselmus was completed on budget and ahead of schedule, with first gas achieved on 1 October 2023
  • Key project to extend lifetime and reduce unit costs
  • 4.8 kboepd gross at plateau, enabling restart of gas & NGL exports, and exceeding expected plateau production
  • Estimated 1.5 year payback from production start
• OKEA continuously focus on adding further volumes more infill opportunities and discoveries currently being assessed

10 Note: Hasselmus first gas in October 2023, hence FY2023 not reflecting current run rate production. Majority of production increase in Q1'24 attributable to Hasselmus

Creating value through active operatorship – Brage case study

Increasing production through infill drilling, increased reliability and Bestla development

• Since becoming operator in November 2022, OKEA has increased production by 3.8x to highest level since 2011 as a result of:
  • High production reliability 96% in 2023
  • Successful infill drilling campaign, delivering above expectations
• Tangible benefits from experience sharing between Draugen and Brage organisations
• Bestla tie-back to Brage will add significant volumes, synergies and economics of scale
  • FID made Q1'24 with first oil expected H1'27
  • Adding 26 kboepd at peak and 24 mmboe reserves (gross)
  • ~USD 40/bbl NPV10 breakeven
  • CO2 intensity reduced by around 60% at Brage
  • Bestla triggers an immediate lifetime extension at Brage, and opens the door for additional projects to extend lifetime further
• Showcases OKEA's strategy to create additional value in areas close to existing infrastructure by identifying cost-effective solutions that enable extraction of further volumes

Bestla – attractive subsea tie-back to Brage

• Bestla (previously Brasse) will be developed as a two well subsea tie-back to the Brage platform, 13km to the North, which will function as host facility for production, processing, and export
• Largely unitised ownership in Bestla and Brage, with OKEA operator of both assets, reducing complexity and supporting a low-cost development
• Further, use of standard solutions, well-proven technology, and close cooperation with strategic partners ensure an efficient and cost-effective development and reduce risk
• Expected gross capex of NOK 6.3bn
  • Contracts awarded to Aker Solutions for the topside scope at Brage, and Subsea7 and OneSubsea for the subsea scope
  • Contracts for rig and drilling services will be awarded in Q2'24
• Attractive economics with expected payback within the first year after start-up, and unlocks synergies and economics of scale with Brage
• Plan for Development and Operation to be submitted to the authorities 30 April 2024 – approval anticipated during 2024

Summary of Bestla Field overview (gross)

• Partners: OKEA (op., 39.2788%), DNO (39.2788%), Lime Petroleum (17%), M Vest Energy (4.4424%)
• Discovered: 2016
• Status: FID made in March 2024
• Production start: H1 2027

• 2P reserves: 24 mmboe (76% liquids) • Peak production: 26 kboepd • Capex: NOK 6.3bn (USD 26/boe) • Break even (NPV10): ~USD 40/boe

Focus on unlocking value potential in the Statfjord area

Transaction closed YE 2023

• One of the most prolific areas on the NCS with four producing fields, a solid track record for improved oil recovery, and substantial remaining running room
• Statfjord is the largest liquids field on the NCS with ~4.0 bnboe originally recoverable¹
• Provides OKEA a significantly larger, more robust and diversified portfolio
  • Four producing fields with 10.8 kboepd net to OKEA in 2023
  • 32 mmboe 2P + 13 mmboe 2C (YE'23) net to OKEA
  • Balanced commodity mix
• Equinor retains all abandonment exposure related to the Statfjord A platform, and any costs for removal of Statfjord B and C gravitybased structures (if required)

•Transaction close and improvement program Acquired 28% in WI Statfjord area •Overview

• RNB 2024² numbers from the operator indicated 10-15% reduction in volume estimates over the assets' lifetime and an increase in estimated costs compared to RNB 2023²
• Volume reduction most significant near term and mainly due to production regularity and well performance
• OKEA is collaborating closely with the operator with key focus on unlocking the area's full potential
• Current improvement plan:
  • Increase production reliability
  • Maturing well targets and drilling performance
  • Revisiting drainage strategy to increase liquid offtake and maximise recoverable resources
• 10-15 production wells planned for 2024

Top 10 NCS fields by originally recoverable liquids reserves (bnbbl) 1

Continuous value-enhancing activities across the portfolio

Core focus on incremental development to maximise value of the asset base

Draugen

• Hasselmus tie-back completed on budget and ahead of schedule in Oct 2024, adding 4.8 kboepd gross at plateau
• License extension till 2040 secured. Maturing new infill and sidetrack opportunities
• Executing power from shore concept to reduce emissions and costs
• Mature and drill new infill targets
• Approval of concept selection of Bestla tie-back in August 2023, with FID made in March 2024 - production start scheduled for H1 2027
• Statfjord C FLX Future Energy project to start in 2026 with the scope to reduce annual CO2 emissions by 25% (95,000 tonnes)
• Gjøa application for lifetime extension until 2040+; production optimalisation activities; several tie-in candidates approaching Gjøa as potential host
• Ivar Aasen Mature and drill new IOR¹ targets
• Mature discoveries (including Calypso as potential tie-back to Draugen and Hamlet as potential tie-back to Gjøa)

Production outlook and key growth initiatives

Simultaneously working three growth levers to deliver profitable and robust growth

+ +

Base production

Actively pursue further value creation in producing assets and maximising potential of asset base through i.a. life extensions, Improved Oil Recovery ("IOR"), cost reductions and efficiency measures

Development projects

Organic developments as complementary growth lever. Focus on development projects adjacent to existing hubs with robust economics and short payback. Selective Infrastructure-Led Exploration ("ILX")-focused exploration

Inorganic initiatives

Mergers and acquisitions to further strengthen core areas and add new portfolio legs. Capitalise on OKEA's operator organisation and capabilities in sourcing deals, executing transactions and integrating assets

Net production outlook from current portfolio (kboepd) Key growth levers ¹

Table of contents

Company and business

Financials

Appendix

Financial strategy and capital allocation framework

Financial flexibility

Capital discipline – Robust growth – Returns

Conservative financial management

• Prudent leverage through the cycle
• Active hedging strategy and conservative budgeting
• Robust offshore insurance coverage in line with best industry practice
• Maintain robust liquidity at all times
• Material production base generating solid cash flow from operations
• Additional financial flexibility through RCF for working capital management
• Control pace of investments with operatorship of key capex projects, including the Bestla development
• Robust portfolio
• Diversification across assets, type of projects and oil / gas mix
• Risk-cost-benefit evaluations applied in all phases of the company's business activities
• Disciplined growth with focus on value over volume

• Balanced capital allocation
• Track record of deleveraging and proactive liability management
• Sound balance between leverage, investments, and distributions
• Demonstrated capital discipline with stringent criteria for new investment

Strong financial position – snapshot per Q1 2024

18 18 ¹ Conversion based on daily average Norges Bank USD-NOK exchange rates for the period ² Pro forma for EBITDA from Statfjord area LTM ³ Cash flow from operating activities less cash flow from investment activities excluding cash paid for business combinations ⁴ Net debt per definition in the Bond Terms, including net tax payable, Leverage Ratio defined as Net debt to EBITDA (LTM)

Sustained track record of robust financial performance

2

Reported interest-bearing debt less cash (NOKm) Free cash flow (NOKm ³ )

19 ¹Pro forma for EBITDA from Statfjord area LTM; ²Cash flow from operating activities less cash flow from investment activities excluding cash paid for business combinations ³Reported interest-bearing debt includes bond debt and Yme jack-up bareboat charter liability (note: not including tax payable)

Consistent deleveraging in recent years

Substantially growing the portfolio whilst reducing leverage

Leverage ratio development Conservative approach to financing and liquidity management ²

• Demonstrated consistent track record of deleveraging in recent years
• Strong cash generation from robust asset base, investments focused on production and short-cycle projects
• Managed liabilities through buybacks
• Voluntary early redemption of the remaining USD 100m of OKEA02 in Q3 2022 after successfully completing a USD 80m buyback in the market
• Funded the asset acquisitions from Wintershall Dea in Q4 2022 and Equinor in Q4 2023 without incremental financing
• On current forward curve oil and gas prices, cash generation from the underlying business keeps the projected leverage ratio steady at a low level through the investment phase on Bestla, with deleveraging ahead of bond maturity

Interest-bearing debt and cash per Q1 2024 (NOKbn)

¹ Other interest-bearing debt is related to the Company's bareboat charter arrangement of the Yme Inspirer drilling and production unit, owned by Havila Sirius AS; ² Leverage ratio defined as net debt to EBITDA (pro forma for Statfjord area acquisition from Q1'23) (LTM), net debt per definition in the Bond Terms, including net tax payable. Estimated leverage ratio includes contemplated USD 125m bond issue and is based on forward curve prices for brent crude and NBP gas as of 19 April 2023

20

Summary of outlook and guidance

Production	Production guidance for 2024 of 35–40 kboepd • Guidance remains unchanged Planned turnaround at Statfjord A with expected downtime of 5 weeks in Q2 • • Other major turnarounds planned: Brage – 3 weeks Q3; Ivar Aasen – 3 weeks Q3
Capex	Capex guidance for 2024 updated to NOK 3.2 – 3.7 billion (from NOK 2.8–3.3 billion), following FID on the Bestla development project • ~1/3 of capex relates to infill and production drilling at Brage and Statfjord • In addition, capex comprises Statfjord area drilling lifetime extension programme, Statfjord Øst gaslift project, Draugen Power from Shore, and other investments Capex guidance does not include capitalised interest, exploration spending or projects not yet sanctioned •
Financing	Expect to increase the revolving credit facility (RCF) from USD 25 million to USD 37.5 million • • The contemplated financing in combination with the RCF upsize provides liquidity and financial flexibility and aligns maturities with the extended cash flow profile post Bestla sanctioning

Table of contents

Company and business

Financials

Income statement

The first quarter with Statfjord activities included in income statement

Q1 2024 figures						Q1 2024 comments
Figures in NOK million	Q1 24	Q4 23	Q1 23	2023
Total operating income	3,474	2,118	2,954	8,885		petroleum products.
Production expenses	-839	-606	-518	-2,084
Changes in over/underlift positions and inventory	-385	208	-793	-684
Depreciation	-778	-580	-327	-1,695	•	Impairments of NOK 158 million
Impairment (-) /reversal of impairment	-158	-1,876	-94	-2,745		Goodwill related to Statfjord asset of NOK 260 million –
Exploration, general and adm. expenses	-91	-58	-51	-360
Profit / loss (-) from operating activities	1,223	-795	1,170	1,316
Net financial items	-144	-78	-49	-217		Exploration expenses of NOK 50 million –
Profit / loss (-) before income tax	1,080	-873	1,121	1,099		SG&A expenses of NOK 41 million –
Income taxes	-1,129	-390	-894	-2,034	•	Net financial expense of NOK 144 million – primarily due to;
Net profit / loss (-)	-49	-1,263	226	-935		Net FX loss of NOK 76 million –
						Net expensed interest of NOK 40 million –
EBITDA	2,159	1,661	1,592	5,756

• Operating income of NOK 3,474 million of which NOK 3,421 million from sale of petroleum products.
• Production expenses of NOK 839 million; corresponding to 198 NOK/boe
• Impairments of NOK 158 million
  • Goodwill related to Statfjord asset of NOK 260 million
  • Reversal of previous impairment at Yme asset of NOK 102 million
• Exploration, general and administrative expenses of NOK 91 million
  • Exploration expenses of NOK 50 million
  • SG&A expenses of NOK 41 million
• Net financial expense of NOK 144 million primarily due to;
  • Net FX loss of NOK 76 million
  • Net expensed interest of NOK 40 million
• Income tax expense of NOK 1,129 million
  • Effective tax rate of 105% mainly due to goodwill impairment

Statement of financial position

	01 2024 figures

Assets	31.03.2024	31.12.2023	31.03.2023
Goodwill	2,049	2,295	1,292
Oil and gas properties	7,130	7,199	6,496
Asset retirement reimbursement right	4,072	4,163	3,760
Trade and other receivables	1,932	1,211	1,793
Cash and cash equivalents	2,130	2,301	1,634
Other assets	1,286	1,331	935
Total assets	18,599	18,500	15,911
Total equity	676	726	2,200
Liabilities
Asset retirement obligations	9,258	9,535	5,958
Deferred tax liabilities	1,013	888	2,594
Interest bearing bond loans	1,327	1,246	1,255
Other interest bearing liabilities	494	477	528
Trade and other payables	2,935	2,997	1,548
Income tax payable	2,358	2,141	1,429
Other liabilties	538	489	398
Total liabilities	17,923	17,774	13,710
Total equity and liabilties	18,599	18,500	15,911

Q1 2024 figures Q1 2024 comments

• Goodwill of NOK 2,049 million of which NOK 756 million related to Statfjord asset
• Oil & gas properties of NOK 7,130 million
• Trade and other receivables of NOK 1,932 million; increase due to liftings late in the quarter
• Cash and cash equivalents of NOK 2,130 million exceeding interest-bearing bond loans of NOK 1,327 million
• The asset retirement obligation of NOK 9,258 million is partly offset by the asset retirement reimbursement right of NOK 4,072 million
• Interest-bearing bond loans of NOK 1,327 million
• Other interest-bearing liabilities of NOK 494 million relating to financial lease of the inspire rig at Yme
• Income tax payable of NOK 2,358 million

Cash development Q1 2024

Key transactions, deferred and contingent payments

• OKEA acquired a 28.00% WI in PL037 Statfjord area from Equinor Energy AS (SPA signed 19 March 2023 with effective date 1 January 2023, completed on 29 December 2023)
• PL037 comprises 23.93123% WI in Statfjord Unit, 28% WI in Statfjord Nord, 14% WI in Statfjord Øst and 15.4% WI in Sygna
• Initial fixed consideration of USD 220m including tax balances of approximately NOK 300m. USD 60 million of the initial fixed consideration was deferred and paid in January 2024
• Equinor retains responsibility for 100% of OKEA's share of total decommissioning costs related to Statfjord A, while OKEA is liable for its share of decommissioning costs related to Statfjord B and C. However, Equinor retains responsibility for any decommissioning costs relating to a full or partial removal of the Statfjord B and C gravity-based structures, should it be required. Equinor is further responsible for the costs related to any possible decommissioning costs related to third-party transportation infrastructure (including onshore terminals) and/or pipelines used by Equinor or its predecessors until the effective date, based on Equinor's or its predecessors' historical throughput.
• OKEA will pay Equinor USD 48m (real 2023 terms) in 2028 as decommissioning security which will be repaid to OKEA at 4% p.a. real interest in accordance with OKEA's actual payment of its share of decommissioning costs until abandonment is completed
• In addition, the agreement contains a contingent consideration structure based on profit sharing on crude oil and dry gas, as summarised below. All numbers are in real 2023 terms and realised prices are based on annual averages. No contingent payment structure for NGL
• Contingent payments for 2023 of NOK ~25 million will be paid in June 2024

	Realised price		Profit share		Realised price		Profit share
Year	Crude oil price	Dry gas price	OKEA	Equinor	Crude oil price	Dry gas price	OKEA	Equinor
	USD/bbl	p/th		%	USD/bbl	p/th		%
2024	64-85	125-248	10	90	>85	>248	50	50
2025	53-72	37-75	10	90	>72	>75	100	0

Statfjord acquisition – Key terms Brage acquisition – Contingent payment

• OKEA ASA completed the transaction with Wintershall Dea Norge AS 31 October 2022, acquiring 35.2% operated WI in Brage, partner-operated 6.4615% WI in Ivar Aasen and 6.0% WI in Nova, with a contingent payment structure;
  • The contingent consideration for 2024 will be paid if the average oil price for each of the two half year periods exceeds USD 80/bbl. The split on the price exceeding 80 USD/bbl is 57.5% to OKEA and 42.5% to Wintershall Dea in 2024
  • No contingent payment structure for gas
• Contingent payments for H2-2023 of NOK ~20 million will be paid in June 2024

Asset retirement obligations

Abandonment spending is fully tax deductible against corporate tax and special petroleum tax

Draugen and Gjøa (Norske Shell transaction, Nov 2018)

• Seller covers abandonment and removal cost for equipment installed as of completion of the transaction (30 November 2018). Two-fold structure:
  • 80%: Shell reimburses OKEA up until a CPI-adjusted post-tax liability cap of NOK 572m for Draugen and NOK 66m for Gjøa
    • The CPI adjusted cap by 31 December 2023 equals NOK 711m → any cost exceeding the cap (CPI adjusted going forward) or for equipment installed after 1 January 2018 will be OKEA's liability
  • 20% of the expected removal cost as per 1 January 2018 was paid to Shell at completion of the transaction and will be repaid in 3 instalments pursuant to completion progression of removal execution (NOK 418m for Draugen and NOK 48m for Gjøa) subject to CPI adjustment
• In sum – zero expected net exposure to OKEA

PL037 Statfjord area (Equinor transaction, Dec 2023)

• Seller retains responsibility for decommissioning/removal of the Statfjord A platform
• OKEA has responsibility for decommissioning/removal of the Statfjord B and C platforms
  • All potential cost for full or partial removal of the gravity-based structures (GBS) will be covered by seller
  • OKEA to pay USD 48m (real 2023 terms, subject to CPI adjustment) by 1 February 2028 to seller as a guarantee. The deposit will be repaid with interest of 4% based on actual progress (real terms)
• In sum – 100% net exposure to OKEA for Statfjord B and C, limited by scope & GBS removal; zero exposure for Statfjord A

Brage (Wintershall Dea transaction, Nov 2022)

• Seller retains responsibility for 80% of OKEA's share of total decommissioning costs related to the Brage Unit, limited to a pre-tax cap of NOK 1,592m subject to CPI adjustment (31 December 2023 value)
• In sum – 20% net expected exposure to OKEA

Yme, Ivar Aasen and Nova

• 100% exposure with OKEA

Overview of material contracts and agreements

Oil and gas sales

• Crude Oil is sold on term contracts (yearly and multi-year) where underlying benchmark is Dated Brent
• Gas sales are annual contracts where underlying benchmark is NBP for gas exported to UK and the respective price index according to delivered hub for gas delivered to continental Europe

Insurances

• Market standard offshore insurance program in place, including Loss of Production Income (LOPI)
• 100% net volume from all assets are payable at USD 60/boe for oil and USD 45/boe for gas and NGL production
• The insurance has been placed and syndicated with Standard & Poor A rated (or higher) international insurance companies
• Insurance includes other standard coverage, e.g., physical damage, re-drilling of wells, oil in storage, third-party liability etc

Other material contracts, legal disputes

• Joint Operating Agreement (JOA): The Company has several production licences on the NCS in various stages of maturity. In connection to these production licences, the Company has entered into joint operating agreements (JOAs). The JOAs are provided by the Ministry of Petroleum and Energy. The JOAs contain voting rules, with two elements for a decisive vote: number of companies and a passmark (usually 50 % or more). Thus, OKEA may risk to be voted into arrangements. Each production licence is issued with a work obligation and may have conditions for drill/drop or PDO/drop decisions
• Yme: In 2021, the Yme licence entered into a financial lease agreement and a 10-year bareboat charter with Havila for the lease of the Inspirer rig. The bareboat charter includes a purchase obligation for the Yme licence partners at the end of the charter period
• Statfjord closing: Closing of the Statfjord transaction took place on 29 December 2023, following OKEA's previous decision to postpone the closing to assess the situation after RNB24 forecasted a 10-15% reduction in volume estimates for the assets' lifetime, coupled with increased cost estimates. As previously reported, the changes in volume estimates and cost estimates led to a NOK 1,363 million goodwill impairment in Q4 2023
• Statfjord arbitration: Considering the Company's duty to its owners and other stakeholders to thoroughly examine the circumstances surrounding the transaction, OKEA decided to initiate legal actions against Equinor Energy AS as a time-barring action in accordance with the SPA regulations. This step was essential to safeguard the Company's legal position and to investigate the basis for any potential breaches of the SPA. At this stage, no concrete or defined claim has been made, as further investigations are necessary to determine the facts
• Litigation: No other material litigation is current, pending or threatened

Operator strategy underpinning value creation

Fully-fledged operator organisation with long track record of operational excellence

Target 30% CO² emission reductions by 2030

Firm and ambitious ESG strategy with Draugen electrification project leading the way

OKEA's ESG approach and strategic targets

Summary of reserves and resources per YE 2023

		1P/P90 (Low estimate, mmboe)				2P/P50 (Base estimate, mmboe)
Asset/Project	OKEA WI	Gross Oil	Gross NGL	Gross Gas	Net OE	Gross Oil	Gross NGL	Gross Gas	Net OE
		Reserves –	On Production
Brage	35.20 %	2.0	0.2	0.6	1.0	4.5	0.7	1.9	2.5
Draugen	44.56 %	37.5	1.8	7.1	20.7	41.7	2.0	9.4	23.6
Gjøa	12 %	0.7	4.2	17.7	2.7	1.1	5.4	22.9	3.5
es Ivar Aasen	9.2385 %	32.3	1.9	5.8	3.7	38.5	3.0	9.1	4.7
v Nova	6 %	30.4	5.8	11.3	2.8	47.5	7.8	14.7	4.2
er Statfjord Unit	28 %	16.3	6.9	18.9	11.8	27.9	12.5	34.3	20.9
es Statfjord Nord	28 %	12.1	0.3	0.7	3.7	23.4	0.6	1.4	7.1
R Statfjord Øst	14 %	11.4	1.4	3.6	2.3	19.2	2.3	5.9	3.8
P Sygna	15.4 %	1.4	0.0	0.0	0.2	2.3	0.0	0.0	0.4
2 Yme	15 %	16.1	0.0	0.0	2.4	23.0	0.0	0.0	3.4
d Total Net n					51.3				74.2
		Reserves –	Approved for Development
P a Brage - Talisker East	35.20 %	0.8	0.0	-0.1	0.2	1.3	0.0	0.0	0.4
1 Draugen - Power from Shore	44.56 %	0.0	0.4	4.0	1.9	0.0	0.4	4.0	1.9
Draugen - Lifetime to 2040	44.56 %	10.1	0.4	0.7	5.0	11.1	0.5	0.8	5.5
Gjøa - LLP	12 %	0.2	0.9	4.0	0.6	0.3	1.5	6.9	1.1
IAA - Back out from Hanz	9.2385 %	0.7	0.0	0.1	0.1	0.7	0.0	0.1	0.1
Total Net					7.9				9.0
			Reserves – Total
Total Net					59.2				83.2

Discovery – Project			Gross Oil equivalents (mmboe)		Net Oil equivalents (mmboe)
	OKEA WI	1C/P90	2C/P50	3C/P10	1C/P90	2C/P50	3C/P10
	Aurora	65 %	10.2	13.0	19.3	6.6	8.4	12.5
es	Brage	35.2 %	19.5	41.1	64.9	6.9	14.5	22.8
urc	Bestla	39.2788 %	19.3	27.6	33.9	7.6	10.9	13.3
o	Calypso	30 %	11.4	15.2	18.9	3.4	4.5	5.7
	Draugen	44.56 %	7.7	13.5	18.4	3.5	6.0	8.2
nt res	Gjøa	12 %	11.8	21.3	28.5	1.4	2.6	3.4
	Ivar Aasen	9.239 %	7.4	14.8	23.8	0.7	1.4	2.2
e g	Nova	6 %	21.3	33.2	49.6	1.3	2.0	3.0
n	Statfjord	28 %	23.8	41.3	58.8	6.7	11.6	16.5
nti	Statfjord Nord	28 %	3.3	5.6	7.9	0.9	1.6	2.2
o C	Statfjord Øst	14 %	-	-	-	-	-	-
	Sygna	15.4 %	-	-	-	-	-	-
	Yme	15 %	2.3	8.3	9.5	0.3	1.2	1.4
	Total Contingent Volumes					39.2	64.6	91.3

32 Note: See OKEA Annual statement of reserves and resources 2023 for additional details. Reserves on this page does not reflect FID at Bestla, i.e. Bestla is part of contingent resources and not reserves. In addition, 0.6 mmboe additional reserves at Brage due to longer field life with Bestla are not included in the table above

Licence overview

		Producing assets
Licence	Field	Operator	OKEA WI
PL 037	Statfjord	Equinor	28.00 %
PL 053 B	Brage	OKEA	35.20 %
PL 055	Brage	OKEA	35.20 %
PL 055 B	Brage	OKEA	35.20 %
PL 055 D	NE of Brage	OKEA	35.20 %
PL 055 E	Brage / 30/6-14	OKEA	35.20 %
PL 093	Draugen	OKEA	44.56 %
PL 093 B	Hasselmus	OKEA	44.56 %
PL 093 C	Draugen	OKEA	44.56 %
PL 093 D	Draugen	OKEA	44.56 %
PL 153	Gjøa	Vår Energi	12.00 %
PL 153 B	Gjøa	Vår Energi	12.00 %
PL 153 C	Gjøa	Vår Energi	12.00 %
PL 158	Hasselmus	OKEA	44.56 %
PL 176	Draugen	OKEA	44.56 %
PL 185	Brage/Bestla	OKEA	35.20 %
PL 316	Yme	Repsol	15.00 %
PL 316 B	Yme	Repsol	15.00 %
PL 338 BS	Ivar Aasen / 16/1-14 (Apollo)	Aker BP	20.00 %
PL 418	Nova	Wintershall Dea	6.00 %
PL 418 B	Nova	Wintershall Dea	6.00 %
PL 457 BS	Ivar Aasen	Aker BP	14.71 %

Pre-production or exploration phase
Licence	Field/prospect	Operator	OKEA WI
PL 195	Aurora	OKEA	65.00 %
PL 195 B	Aurora	OKEA	65.00 %
PL 938	Calypso	Vår Energi	30.00 %
PL 958	Rialto	OKEA	50.00 %
PL 1014 B	Arkenstone	Equinor	20.00 %
PL 1014	Arkenstone	Equinor	20.00 %
PL 740	Bestla	OKEA	39.2788%
PL 1108	Struten	DNO	40.00 %
PL 1113	West of Draugen	Harbour Energy	30.00 %
PL 1115	April	Wintershall Dea	40.00 %
PL 1117	Fagn	OKEA	50.00 %
PL 1119	Mistral	Equinor	30.00 %
PL 1125	Falk	OKEA	50.00 %
PL 1150 S	Sol	Sval Energi	30.00 %
PL 1159	Presidenten	OKEA	50.00 %
PL 1178	West of Brage	OKEA	50.00 %
PL 1180	South of Gjøa	Vår Energi	30.00 %
PL 1186	West of Njord	Equinor	30.00 %
PL 1187	North of Draugen	OKEA	40.00 %
PL 1214	East of Statfjord N	Equinor	28.00%
PL 1222	South of Draugen	Equinor	30.00%
PL 1223	West of Draugen	OKEA	44.56%

Introduction to the Norwegian petroleum tax system

78% total cost recovery on investments with majority recouped in year of investment

General principles	• NCS petroleum taxation based on taxation of net profit with ordinary corporate tax ("CT") and a special petroleum tax ("SPT"); royalties no longer part of the tax system • The combined marginal tax rate has remained stable at 78% since 1992 • No ringfencing between different fields/licences (consolidation is allowed) • Norm pricing applied for tax on crude oil sales, whereas gas is based on actual sales prices • Neutral system whereby an investment that is profitable pre-tax is also profitable after tax • SPT adjusted to be cash flow based effective from the income year 2022 • CT losses can be carried forward, whereas tax losses under SPT are reimbursed annually • Carbon and NOx taxes levied separately based on offshore emissions
Overview of key current fiscal terms	• In deriving taxable profit, deductions are allowed for all relevant costs, including costs associated with exploration, research and development, operations, decommissioning, and financing (CT only); calculated CT payable is deducted to derive the SPT tax base • The CT rate is currently 22% and the SPT rate is 71.8%, giving a total marginal tax rate of 78% when accounting for the deductibility of CT (22% + [71.8% x (1-22%)] =78%) • For CT, investments are written off using straight-line depreciation over six years, whereas for SPT the full amount is depreciated immediately • Development projects with PDO delivered before 1 Jan 2023 and approved before 1 Jan 2024 benefit from temporary tax treatment until planned start of production, including full depreciation plus 17.69% uplift in the investment year
Cost recovery illustration	78.0 1.0 1.0 1.0 1.0 1.0 1.0 100.0 SPT depreciation CT depreciation 71.8
	Capex Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total

Summary of the Norwegian petroleum tax system Tax balances and values net to OKEA (note: preliminary)

Remaining tax balances 01.01.2024 – corporate tax basis 22%
NOKm	2019	2020	2021	2022	2023	Total
Draugen	19	50	114	392	879	1,455
Gjøa	17	125	35	(2)	9	184
Ivar Aasen	22	52	64	70	49	258
Yme	89	148	414	178	98	926
Brage	60	40	175	235	411	922
Nova	22	54	65	97	75	313
Bestla	-	-	-	-	39	39
Statfjord Unit	38	149	291	479	839	1,796
Statfjord North	2	1	16	145	79	243
Statfjord East	2	3	19	73	341	438
Sygna	0	1	2	4	4	11
Total	270	623	1,196	1,671	2,823	6,583

Remaining tax balances 01.01.2024 – special tax basis 71.8%¹ NOKm 2019 2020 2021 2022 2023 Total

Draugen	19	-	-	-	-	19
Gjøa	17	-	-	-	-	17
Ivar Aasen	22	-	-	-	-	22
Yme	89	-	-	-	-	89
Brage	60	-	-	-	-	60
Nova	22	-	-	-	-	22
Bestla	-	-	-	-	-	-
Statfjord Unit	38	-	-	-	-	38
Statfjord North	2	-	-	-	-	2
Statfjord East	2	-	-	-	-	2
Sygna	0	-	-	-	-	0
Total	270	-	-	-	-	270

Tax depreciation and tax values per year
NOKm	2024	2025	2026	2027	2028	Total
Depreciation corporate tax	1,963	1,693	1,381	982	565	6,583
Tax value from corporate tax	432	372	304	216	124	1,448
Depreciation special tax	270	-	-	-	-	270
Tax value from special tax	151	-	-	-	-	151
Total tax value	583	372	304	216	124	1,600

Board of directors

Chaiwat Kovavisarach

Chairman of the board

Non-executive

• President and Group CEO of Bangchak Corporation Public Company Limited since 2015
• Aalso serves on the board of several listed and nonlisted companies and is chairman of the Thai-Europe Business Council, vice chairman of the Federation of Thai industries, executive chairman of the Board of Trustees of the Asian Institute of Technology, director of the Government Pension Fund, director of Bank of Thailand's Credit Information Protection Committee and board of trustee of KMITL

Mike Fischer Vice chair Non-executive

• Nearly 40 years' experience in the oil & gas industry
• Currently an Executive Advisor to the Natural Resources business unit of Bangchak

Phatpuree Chinkulkitnivat

Board member Non-executive

• Group CFO at Bangchak Corporation
• More than 20 years experience in banking industry prior to joining Bangchak Group

Rune Olav Pedersen Board member Independent, non-executive

• President & CEO of PGS ASA since 2017
• Previously partner of the law firm Arntzen de Besche

Nicola Gordon Board member Independent, non-executive

• Broad experience within oil & gas, including several positions at Shell
• Holds several board positions in the industry

Finn Haugan Board member Independent, non-executive

• CEO of SpareBank 1 SMN from 1991 to 2019
• Currently holds several board positions

Jon Arnt Jacobsen Board member Independent, non-executive

• +30 years' experience in the oil & gas industry
• Broad experience within finance, trading and shipping, procurement and supply chain, internal audit

Elizabeth Williamson Board member Independent, non-executive

• Head of energy corporate finance in Rand Merchant Bank
• Master in energy, trade and finance from Cass Business School

Sverre Nes Board member Employee elected

• Discipline Responsible for Process at Brage
• Worked in Hydro between 1991 and 2012 and joined Wintershall from 2013

Ragnhild Aas Board member Employee elected

• VP technology & development with more than 25 years' experience in the oil & gas industry
• Experience as Board member and Employee Representative

Per Magne Bjellvåg Board member Employee elected

• Lead Process Engineer for Process and Technical Safety
• Nearly 30 years of experience in the oil and gas industry, mostly from Norske Shell

Top 20 shareholders

Rank	Investor	Geography	Type	%	Shares
1	BCPR PTE. LTD.	Thailand	Ordinary	45.58%	47,362,377
2	CLEARSTREAM BANKING S.A.	Luxembourg	Nominee	3.84%	3,987,941
3	SALT VALUE AS	Norway	Ordinary	2.61%	2,713,034
4	TINDRA EIENDOM AS	Norwayway	Ordinary	1.46%	1,512,496
5	SJÆKERHATTEN AS	Norway	Ordinary	1.05%	1,093,000
6	SKANDINAVISKA ENSKILDA BANKEN AB	Sweden	Ordinary	0.77%	797,109
7	KØRVEN AS	Norway	Ordinary	0.76%	789,285
8	SKJEFSTAD VESTRE AS	Norway	Ordinary	0.75%	780,617
9	INTERACTIVE BROKERS LLC	USA	Nominee	0.61%	637,633
10	SPAREBANK 1 MARKETS AS MARKET-MAKING	Norway	Ordinary	0.61%	636,870
11	NORDNET LIVSFORSIKRING AS	Norway	Ordinary	0.61%	633,557
12	UBS AG	UK	Nominee	0.60%	624,660
13	NORDNET BANK AB	Sweden	Nominee	0.47%	492,012
14	NIMA INVEST AS	Norway	Ordinary	0.46%	479,517
15	GH HOLDING AS	Norway	Ordinary	0.45%	468,000
16	MATHIASSEN LARS PETTER	Norway	Ordinary	0.45%	467,524
17	SPECTATIO FINANS AS	Norway	Ordinary	0.42%	433,862
18	ESPEDAL & CO AS	Norway	Ordinary	0.41%	425,908
19	PERSHING LLC	USA	Nominee	0.40%	420,062
20	NORDEA BANK ABP	Denmark	Nominee	0.40%	410,922
	Sum Top 20				65,166,386
	Total outstanding shares				103,910,350