OKEA ASA

Investor Presentation • Aug 24, 2023

OKEA ASA

Credit investor update

August 2023

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.

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
• Repeating and successful HY bond issuer since 2017
• Headquartered in Trondheim, operations centres in Kristiansund and Bergen, and offices in Oslo and Stavanger
• Full scale operator organisation with more than 400 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 producing Draugen and Brage fields, and partner shares in the Gjøa, Ivar Aasen, Nova and Yme fields
• In process of closing Statfjord Acquisition from Equinor, adding net 16-20 kboepd in 2024E
• Targeted M&A strategy to drive growth

4 ¹ H1 2023 including the Statfjord Acquisition on pro-forma basis ²As of 31 December 2022 adjusted for Yme impairment, including Statfjord Area ³As per 22 August 2023 ⁴Including fields from the Statfjord Acquisition ⁵Cash flow from operating activities less cash flow from investment activities excluding cash paid for business combinations ⁶ Net debt to EBITDA (LTM) as per Q2 2023. Net debt defined as Total Financial Indebtedness (including i.a. leases, contingent consideration and tax payable) less cash

Delivering in line with growth strategy

More than doubling production volumes since new strategy launch in 2021

Net pro forma production (kboepd)¹

5

+40

33-38²

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

Operator strategy underpinning value creation

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

8

Creating value through active ownership

Mid to late-life operating expertise translated into tangible results at Draugen and Brage

Draugen thriving under OKEA operatorship Revitalisation underway at Brage

• Operated by OKEA since December 2018
• Winner of previous operator Shell's CEO HSSE & SP Award for 2017 and used as a global benchmark within Shell
• Production efficiency improved compared to last years of previous operatorship
• Lifetime extended from 2027 to 2040+ under OKEA operatorship
• Planning 95% reduction in CO² intensity by 2027
• Matured and sanctioned Hasselmus discovery and electrification project

• Operatorship transferred to OKEA in November 2022
• IOR² initiatives, near field exploration and other lifetime extension solutions have already been initiated or are in the planning phase
• Talisker East production commenced in May, increasing production by 60% Q/Q. Additional wells due onstream later this year, expected plateau of ~6 kboepd net to OKEA (~17 kboepd gross)³
• Concept select for developing Brasse as tie-back to Brage in August 2023 (DG2), targeting FID in early 2024
• Experience sharing between Draugen and Brage organisations

Brage gross production (kboepd) Draugen production reliability ¹

Revitalising mid to late-life assets by reducing opex, increasing production efficiency and extending asset lifetime

Step-change in size and diversification through strategic M&A

Two material, strategic acquisitions following updated strategy in 2021, while reducing leverage in the period

10 Note: Chart of changes in production, reserves and resources are illustrative as changes in existing portfolio are also included

¹As of 31 December 2022 adjusted for Yme impairment, including Statfjord Area ² Net debt to EBITDA (LTM) as per Q2 2023. Net debt defined as Total Financial Indebtedness (including i.a. leases, contingent consideration and tax payable) less cash

Statfjord – transformational acquisition of 28% WI in a proven giant

Advancing OKEA to a higher league of producers with more than 40,000 barrels per day in 2024E

Acquiring 28% WI in PL037 (Statfjord Area) •Production numbers ¹

• One of the most prolific areas on the NCS with four producing fields, a strong 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 recoverable²
• Transaction close exp. end-Nov '23. More than half of the remaining purchase price of USD 195m is expected to be covered by cash flow from the acquired assets prior to completion³
• Material increase in production and significant resource upside potential
  • 2P: 41 mmboe net, 2C: 8 mmboe net
  • 14+ mmboe net further upside identified
• Enhanced robustness and diversification
  • Higher number of producing fields
  • More balanced resource mix
• Equinor retains all abex exposure related to Statfjord A platform, and any costs for removal of Statfjord B and C gravity-based structures (if required)

•Strategic partnership with Equinor FLX unit

Statfjord today

• New ways of working
• High drilling activity 100 new wells
• Facility upgrade for high PE and extended life
• Cessation delayed to 2038+⁴

Statfjord in 2019

• Limited basis for investments
• Limited drilling activity, few new wells
• Cessation in 2025

Top 10 NCS fields by originally recoverable liquids reserves (bnbbl) 2 2023 2024 11-13 kboepd 16-20 kboepd ~55% Oil ~15% NGL ~30% Gas Statfjord 4,0 3,6 2,7 2,6 2,5 2,1 2,0 1,3 1,3

Statfjord #2 #3 #4 #5 #6 #7 #8 #9 #10

1,1

11 Includes Statfjord Unit (23.93123%), Statfjord Nord (28%), Statfjord Øst (14%) and Sygna (15.4%) ² Source: NPD (includes crude oil, condensate and NGL) Based on company estimate asset profiles, applying current forward prices and FX rates. See appendix page 27 for more information ⁴ Decommissioning for Statfjord A is scheduled for 2027 Production ranges on full year basis

FLX launched in 2020 – Statfjord ambitions

Production mix 2023-'24 and net production⁵

Material and diversified portfolio of producing assets

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

2P 2C Total 2P + 2C

• Overview of asset portfolio and 2P reserves³

12 ¹Pro-forma production including full-year contribution from acquired assets ² Closing expected in November 2023 ³ As of 31 December 2022 adjusted for Yme impairment, including Statfjord Area

Continuous value-enhancing activity across the portfolio

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

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, 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 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

Production outlook from current portfolio (kboepd) Key growth levers ¹

Target 30% CO² emission reductions by 2030

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

Table of contents

Company and business

Financials

Appendix

Financial strategy and capital allocation framework

Capital discipline – Robust growth – Returns

Conservative financial management

• Moderate debt to equity mix
• Robust and conservative leverage through the cycle
• Active hedging strategy and conservative budgeting
• Robust offshore insurance coverage in line with best industry practice

▪ Maintain sufficient liquidity at all times

Financial flexibility

• Capex flexibility through operatorship of key assets
• Strong near term cash flow from producing fields
• Additional financial flexibility through adding bank RCF to the capital structure

▪ Disciplined growth with focus on value over volume

Robust portfolio

• Risk-cost-benefit evaluations applied in all phases of the company's business activities
• Diversification across assets, type of projects and oil / gas mix

• Sound balance between leverage, investments, and distributions
• Track record of deleveraging and proactive liability management
• Demonstrated capital discipline and fully funded for all sanctioned investments

Strong financial position – snapshot per H1 2023

Reported numbers excluding effects of Statfjord acquisition

18 18 ¹ Conversion based on Norges Bank USD-NOK exchange rates ² Cash flow from operating activities less cash flow from investment activities excluding cash paid for business combinations ³ Net debt defined as Total Financial Indebtedness (including i.a. leases, contingent consideration and tax payable) less cash, Leverage Ratio defined as Net debt to EBITDA (LTM)

Sustained track record of robust financial performance

Reported numbers excluding effects of Statfjord acquisition

Reported interest-bearing debt less cash (NOKm) Free cash flow (NOKm)^{1 2}

Cash flow from operating activities less cash flow from investment activities excluding cash paid for business combinations 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
• Built material liquidity buffer and managed liabilities through opportunistic buybacks
• Voluntary early redemption of the remaining USD 100m of OKEA02 in Q3 2022 after successfully completing a USD 80m buyback in the market

Capitalisation and liquidity per Q2 2023 (NOKbn)

• Funded Wintershall Dea M&A in Q4 2022 without additional financing
• Repaying OKEA03 in connection with new bond issue

20 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 (LTM), net debt defined as Total Financial Indebtedness (including i.a. leases, contingent consideration and tax payable) less cash

Strong cash flow generation driving further deleveraging

Forecast post-tax free cash flow covers all financing costs at oil prices well below USD 50/bbl

• Maintaining conservative financial profile with scope for dividends and M&A

• Based on forward curve prices², assuming contemplated USD 125m bond issue and USD 25m SSRCF financing in September 2023

Summary of outlook & guidance

Production

Capex

Production guidance of 22–25 kboepd in 2023 (excluding effect of Statfjord Acquisition)

• Draugen turnaround completed in Q2
• Maintenance at Gjøa with expected downtime of 4-6 days and 7 days shut-in of the subsea wells (reduces production by ~50% during shut-in) at Draugen scheduled for Q3
• The guiding does not include production volumes from the acquisition of 28% in PL037 (Statfjord Area); expected production volumes net to OKEA are indicatively 11-13 kboepd for 2023

Capex guidance of NOK 1,700–2,100m in 2023

• Comprises completion of the Hasselmus project, Draugen Power from Shore, Brage infill drilling and other activities
• Excludes capitalised interest and exploration capex
• Capex guiding does not include capex related to the acquisition of 28% in PL037 (Statfjord Area)

Table of contents

Company and business

Financials

Appendix

Income statement

Figures in NOKm	Q2 23	Q1 23	Q2 22	H1 2023	H1 2022
Total operating income	1,707	2,954	1,332	4,661	2,845
Production expenses	-495	-518	-381	-1,013	-668
Changes in over/underlift positions and inventory	126	-793	61	-667	94
Depreciation	-362	-327	-165	-689	-323
Impairment (-) /reversal of impairment	-300	-94	0	-394	363
Exploration, general and adm. expenses	-171	-51	-84	-222	-199
Profit / loss (-) from operating activities	506	1,170	763	1,676	2,110
Net financial items	-115	-49	-231	-164	-292
Profit / loss (-) before income tax	391	1,121	532	1,512	1,819
Income taxes	-322	-894	-504	-1,217	-1,578
Net profit / loss (-)	69	226	28	295	241

Q2 2023 comments

Operating income

• Revenue from sales of petroleum products of NOK 1,641m; includes realised gain on forward gas contracts of NOK 137m
• Other income of NOK 66m

Production expenses

• NOK 495m; corresponding to 223 NOK/boe

Impairment

• NOK 300m impairment at Yme driven by lower expected realised prices

Exploration, general and administrative expenses

• NOK 124m in exploration expenses; including NOK 80m in seismic purchases
• NOK 47m in SG&A expenses; including NOK 15m in advisor fees relating to business development activities

Net financial items

• Net currency loss of NOK 110m
• Net expensed interest of NOK 18m
• Interest income of NOK 22m

Income taxes

• NOK 322m; effective tax rate of 82%

Statement of financial position

Figures in NOKm

Assets	30.06.2023	31.03.2023	31.12.2022
Goodwill	1,292	1,292	1,297
Oil and gas properties	6,416	6,496	6,556
Asset retirement reimbursement right	3,486	3,760	3,662
Trade and other receivables	1,362	1,793	1,744
Financial investments	0	0	0
Tax refund, current	0	0	0
Cash and cash equivalents	2,335	1,634	1,104
Other assets	1,171	935	1,258
Total assets	16,062	15,911	15,621
Total equity	2,165	2,200	2,078
Liabilities
Asset retirement obligations	5,715	5,958	5,915
Deferred tax liabilities	2,774	2,594	2,835
Interest bearing bond loans	1,293	1,255	1,179
Other interest bearing liabilities	531	528	508
Trade and other payables	1,961	1,548	2,220
Income tax payable	1,238	1,429	477
Other liabilities	384	398	410
Total liabilities	13,896	13,710	13,543
Total equity and liabilities	16,062	15,911	15,621

Q2 2023 comments

• Goodwill of NOK 1,292m
• Cash and cash equivalents of NOK 2,335m
• Tax payable NOK 1,238m
• Interest-bearing bond loans of NOK 1,293m
• Other interest-bearing liabilities of NOK 531m related to financial lease of the Inspirer rig at Yme
• Asset retirement obligation of NOK 5,715m; partly offset by asset retirement reimbursement right of NOK 3,486m

Cash development YTD per Q2 2023

Key transactions, deferred and contingent payments

• SPA for acquisition of 28.00% WI in PL037 Statfjord Area from Equinor Energy AS entered into on 19 March 2023
• Acquisition of 28% WI in PL037, comprising 23.93123% WI in Statfjord Unit, 28% WI in Statfjord Nord, 14% WI in Statfjord Øst and 15.4% WI in Sygna
• Effective date 1 January 2023 with expected completion in end November 2023
• Initial fixed consideration of USD 220m (USD 25m deposit paid), including tax balances of approximately NOK 300m
• Based on company estimate asset profiles, applying current forward curve prices and FX rates, it is estimated that cash flow from the acquired assets will cover more than half of the remaining USD 195m initial fixed consideration
• Equinor will retain responsibility for 100% of OKEA's share of total decommissioning costs related to Statfjord A, while OKEA will be liable for its share of decommissioning costs related to Statfjord B and C. However, Equinor will retain 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, and for third party transportation infrastructure on certain conditions
• OKEA will pay Equinor USD 48m (real 2023) 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

	Realised price		Profit share		Realised price		Profit share
Year	Crude oil price USD/bbl	Dry gas price p/th	OKEA	Equinor %	Crude oil price USD/bbl	Dry gas price p/th	OKEA	Equinor %
2023	75-96	170-341	10	90	>96	>341	50	50
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 will be paid if the average oil price for each of the six half year periods during 2022-24 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 2023-24
  • No contingent payment structure for gas

Asset retirement obligations

Draugen and Gjøa (Norske Shell transaction)

• 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 YE'22 equals NOK 757m → 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 336m for Draugen and NOK 39m for Gjøa) subject to CPI adjustment
• In sum – zero expected net exposure to OKEA

Brage (Wintershall Dea transaction)

• 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 1,521m subject to CPI adjustment (1 January 2022 value)
• In sum – 20% net expected exposure to OKEA

PL037 Statfjord Area (Equinor transaction)

• 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 (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
• In sum – 100% net exposure to OKEA for Statfjord B and C, limited by scope & GBS removal; zero exposure for Statfjord A

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 BNP for gas exported to UK and PEG for gas transported 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 70/boe for oil, gas and NGL production
  • Statfjord production volumes also insured until deal completion at USD 70/boe
• The insurance has been placed with first class Insurance Companies in the Norwegian Market, European Market and the London Market
• 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
• The Yme licence has in 2021 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
• Litigation: no material litigation is current, pending or threatened.

Draugen (44.56% WI, operator)

Material, long-lived oil producer

• Located on the southeast edge of Haltenbanken in the Norwegian Sea, 140 km northwest of Kristiansund, in water depths of 250 metres
• The platform is a concrete gravity-based structure with full oil stabilisation and storage capabilities
• Oil is exported by shuttle tankers, gas export/import via Åsgard Transport System
• Production from the Jurassic Rogn and Garn formations, with excellent reservoir properties
• Pressure support by aquifer support and water injection
• Since taking over as operator in 2018, OKEA has reduced downtime, optimised production and extended field life
• Hasselmus subsea tieback currently under development, with first gas expected in Q4 2023
• Project ongoing to electrify Draugen with power from shore from 2027, which will reduce emissions, reduce opex and increase gas exports

Licence	PL 093
2P reserves (gross) YE'22	71.5 mmboe
2C resources (gross) YE'22	11.7 mmboe
YTD '231 production (gross)	12.8 kboepd
Discovery year	1984
Production start	1993

Brage (35.20% WI, operator)

Proven asset with high reliability

• Brage is located closed to the Oseberg Area in the northern North Sea, 125 km west of Bergen, in water depths of 137 metres
• Developed as a fixed integrated production, drilling and accommodation facility with a steel jacket
• Oil is exported via the Oseberg Transport System (OTS) to the Sture terminal. The gas is exported via pipeline to Kårstø
• In November 2022, OKEA took over Wintershall Dea's entire share (35.2%) in Brage as well as the operatorship
• Production from the Talisker East well commenced in May 2023 and increased production by 60% compared to previous quarter. Additional wells to come onstream later this year, expected to take gross plateau production to ~17 kboepd
• A PDO for Cook was submitted in Q2 with production start-up expected in Q4 2023

Licence	PL 055
2P reserves (gross) YE'22	10.8 mmboe
2C resources (gross) YE'22	44.0 mmboe
YTD '231 production (gross)	8.0 kboepd
Discovery year	1980
Production start	1993

2P reserves split YTD¹ production split

Gjøa (12.00% WI)

Gas producer with low emissions intensity and tie-in hub in prolific area

• The Gjøa field is located in the northern part of the North Sea, 50 km northeast of the Troll field, in water depths of 360 metres
• Developed with thirteen subsea wells connected to five templates and directed back to a semi-submersible unit with full oil stabilisation capacities
• Oil is exported through the Troll II oil pipeline to the Mongstad terminal, and gas is exported though the FLAGS pipeline to the St. Fergus terminal
• The Gjøa platform was the first floating platform with power form shore and has been partially electrified since startup, resulting in low associated emissions
• The platform is tie-back host to the Vega, Duva and Nova fields
• Further maturation of potential development scenarios of the Hamlet discovery is ongoing. Other IOR targets (earliest production start 2028/2029) are also evaluated within the PL153/153 C licence utilising new reprocessed seismic data. Options to appraise the Aurora discovery and drill the Selene prospect in PL195 west of Gjøa are under review

Licence	PL 153
2P reserves (gross) YE'22	41.0 mmboe
2C resources (gross) YE'22	32.5 mmboe
YTD '231 production (gross)	54.4 kboepd
Discovery year	1989
Production start	2010

Ivar Aasen (9.2385% WI)

Digital oilfield pilot with low emissions and high production efficiency

Asset description Asset overview

• Located in the northern part of the North Sea, 30 km south of the Grane and Balder fields, in water depths of 110 metres
• The development comprises a production, drilling and quarters (PDQ) platform with a steel jacket and a separate jack-up rig for drilling and completion
• In 2019, Ivar Aasen became the first manned platform on the NCS to be operated from an onshore control room – it is operator Aker BP's digital pilot for testing and applying new technology, which has resulted in high production efficiency and increased recovery
• Will serve as tie-in host to the Hanz and Symra fields, which are currently being developed
• Partly processed fluids are transported to the Edvard Grieg platform for final processing and export; Edvard Grieg also provides the Ivar Aasen platform with gas lift and electricity
• The Ivar Aasen platform became supplied with power from shore from 2023 as part of the wider Utsira High electrification project, resulting in low associated emissions
• Plans for an IOR 2024 campaign are progressing towards a concept decision (DG2). In addition, well intervention campaigns are executed approx. three times per year

Licence	PL 338 BS
2P reserves (gross) YE'22	64.0 mmboe
2C resources (gross) YE'22	19.9 mmboe
YTD '231 production (gross)	34.3 kboepd
Discovery year	2008
Production start	2016

2P reserves split YTD¹ production split

Nova (6.00% WI)

Low-cost subsea tie-back to Gjøa

Asset description Asset overview

• Oil and associated gas producer located 120 km northwest of Bergen and 17 km southwest of Gjøa, in water depths of around 370 meters
• The field consists of two subsea templates, one with three oil producers and one with three water injectors, tied back to the Gjøa platform
• Operated with renewable power from shore through Gjøa
• The reservoir contains oil with a gas cap in sandstone, with good reservoir quality
• The field is produced by pressure support from water injection and with gas lift
• Since November 2022, production was lower than expected due to issues with the water injection wells. Some of the issues were resolved rapidly by a well-planned and executed Inspection Maintenance Repair Vessel campaign completed in December last year. While production has improved during Q2, it is still constrained by reduced effectiveness of the water injectors. A side-track drilling operation to improve the location of one of the injector wells has been completed with expected injection start in Q3. A rig has been secured to drill a fourth water injector well in the first half of 2024

Ownership

Licence	PL 418
2P reserves (gross) YE'22	91.4 mmboe
2C resources (gross) YE'22	17.4 mmboe
YTD '231 production (gross)	23.4 kboepd
Discovery year	2012
Production start	2022

Yme (15.00% WI)

Decommissioning project redeveloped into a producing asset

Asset description Asset overview

• Located in the southeastern part of the Norwegian sector of the North Sea, 130 km northeast of the Ula field, in water depths of 100 metres
• Discovered by Equinor in 1987 and originally started producing in 1996. Low oil prices led to the abandonment of the field in 2001. A first redevelopment attempt received PDO approval in 2007, but was unsuccessful due to structural deficiencies in the new MOPU
• OKEA acquired an ownership interest in 2016 and started preparing a new PDO. In March 2018, an amended PDO for the redevelopment was approved, with Repsol as operator, based on a leased jack-up production unit
• The field comprises two separate main structures, Gamma and Beta, which are 12 km apart
• In recent quarters, water-cut from the producing wells has been higher than initially anticipated, resulting in recued expectations for production and recoverable reserves. This has resulted in impairments at Yme for four consecutive quarters
• One producer well has been drilled in the Yme Gamma campaign and is expected to contribute towards lifting plateau production to ~5 kboepd net to OKEA by Q4 2023. Two more producers and one injector are on track for drilling by end-2023. Further infill well opportunities are being evaluated

Licence	PL 316
2P reserves (gross) YE'22	50.3 mmboe
2C resources (gross) YE'22	3.0 mmboe
YTD '231 production (gross)	17.7 kboepd
Discovery year	1987
Production start2	2021

35 ¹ As per H1 2023 ² For Yme New Development Source: OKEA, NPD

Statfjord Unit (23.93123%¹ WI)

Legacy oil giant with substantial remaining running room

• Located in the Tampen area in the northern part of the North Sea, straddling the border between the Norwegian and UK sectors, in water depths of 150 metres. The Norwegian share of the field is 85.47 per cent
• The second-largest oil discovery on the NCS measured by original in place volumes
• Developed with three fully integrated concrete facilities: Statfjord A, B and C. Statfjord A, centrally located on the field, came on stream in 1979. Statfjord B, in the southern part of the field, in 1982, and Statfjord C, in the northern part, in 1985
• A PDO for Statfjord Late Life was approved in 2005. Equinor's Field Life eXtension (FLX) organisation now operates the asset, and work is ongoing to further extend the lifetime of the field. The FLX unit has an ambition to deliver a 200% increase in remaining reserves, 25% cost reduction and 50% CO² reduction in the Statfjord Area by 2030 vs a 2020 base
• Statfjord A is planned to be decommissioned in 2027, whereas Statfjord B and C and satellites are expected to produce until the late 2030s

Licence	PL 037
2P reserves2 (gross) YE'22	101.7 mmboe
2C resources2 (gross) YE'22	21.4 mmboe
YTD '232,3 production (gross)	32.9 kboepd
Discovery year	1974
Production start	1979

Statfjord Satellites (various WI)

Three late-life subsea tie-backs to Statfjord

Asset description Asset overview

Statfjord Nord

• Located 17 km north of the Statfjord field, in water depths of 250-290 metres
• Two production templates and one water injection template tied back to Statfjord C
• Further infill drilling and well intervention work to be carried out in coming years

Statfjord Øst

• Located 7 km northeast of the Statfjord field, in water depths of 150-190 metres
• Two production templates and one water injection template tied back to Statfjord C, in addition to two wells drilled from Statfjord C
• Redevelopment programme underway to maximise recovery and increase production rates, including infill drilling and adding a gas lift solution to both production templates

Sygna

• Located just northeast of the Statfjord field, in water depths of 300 metres
• One subsea template with four well slots, connected to the Statfjord C facility
• Reservoir pressure maintained with water injection, expected to produce until early-2030s

	Statfjord Nord	Statfjord Øst	Sygna
Licence	PL 037	PL 037	PL 037
2P reserves (gross) YE'22	28.2 mmboe	29.1 mmboe	3.0 mmboe
2C resources (gross) YE'22	5.0 mmboe	0.0 mmboe	0.0 mmboe
YTD '231 production (gross)	7.0 kboepd	3.7 kboepd	0.9 kboepd
Discovery year	1977	1976	1996
Production start	1995	1994	2000

NGL

2P reserves split (combined) YTD¹ production split (combined)

79%

Oil

15%

Historical production², gross (kboepd)

Summary of reserves and resources per YE 2022

Net 1P and 2P reserves (mmboe)
		1P/P90 (Low estimate)			2P/P50 (Base estimate)
Asset / Project	OKEA WI (%)	Gross Oil	Gross NGL	Gross Gas	Net OE	Gross Oil	Gross NGL	Gross Gas	Net OE
Reserves - On Production
Draugen	44.6 %	38.0	0.0	0.0	17.0	41.9	0.0	0.0	18.7
Statfjord Unit	28.0 %	22.0	17.6	32.8	20.3	31.5	23.4	46.8	28.5
Statfjord Nord	28.0 %	18.3	0.5	1.0	5.5	26.2	0.7	1.4	7.9
Statfjord Øst	14.0 %	3.4	2.4	4.4	1.4	19.8	3.2	6.0	4.1
Sygna	15.4 %	2.1	0.0	0.0	0.3	3.0	0.0	0.0	0.5
Gjøa	12.0 %	1.0	4.7	16.5	2.7	2.4	8.6	30.0	4.9
Ivar Aasen	9.2 %	37.3	2.1	6.6	4.3	50.4	3.3	10.3	5.9
Brage	35.2 %	4.6	0.6	1.3	2.3	4.9	0.9	1.9	2.7
Nova	6.0 %	45.5	5.8	9.6	3.7	71.1	7.7	12.6	5.5
Yme	15.0 %	24.9	0.0	0.0	3.7	50.3	0.0	0.0	7.6
Total Net					61.1				86.2
Reserves - Approved for Development
Draugen	44.6 %	3.6	1.8	6.2	5.2	4.4	1.9	8.3	6.5
Brage	35.2 %	1.3	0.2	0.4	0.7	2.1	0.3	0.7	1.1
Total Net					5.8				7.6
Reserves - Justified for Development
Draugen	44.6 %	9.9	0.7	3.2	6.2	10.6	0.8	3.6	6.7
Total Net					6.2				6.7
Reserves – Total
Total Net					73.1				100.4

Net contingent resources (mmboe)

Discovery - Project	OKEA WI (%)	Gross Oil equivalents (mmboe)			Net oil equivalents (mmboe)
		Low	Base	High	Low	Base	High
Draugen	44.6 %	5.9	11.7	16.7	2.6	5.2	7.5
Gjøa	12.0 %	16.9	32.5	51.1	2.0	3.9	6.1
Ivar Aasen	9.2 %	9.9	19.9	35.2	0.9	1.8	3.3
Brage	35.2 %	25.2	44.0	62.7	8.9	15.5	22.1
Aurora	65.0 %	10.4	13.3	19.8	6.8	8.7	12.9
Nova	6.0 %	13.0	17.4	22.9	0.8	1.0	1.4
Yme	15.0 %	1.5	3.0	4.5	0.2	0.5	0.7
Calypso	30.0 %	7.0	10.0	13.0	2.1	3.0	3.9
Statfjord Unit	28.0 %	11.6	21.4	26.8	3.3	6.0	7.5
Statfjord Nord	28.0 %	3.9	5.2	6.5	1.1	1.5	1.8
Statfjord Øst	14.0 %	3.0	4.0	5.0	0.4	0.6	0.7
Sygna	15.4 %	0.0	0.0	0.0	0.0	0.0	0.0
Brasse	45.6 %	15.0	30.0	45.0	6.8	13.7	20.5
Total contingent volumes					36.0	61.4	88.3

38 Note: See OKEA Annual statement of reserves and resources 2022 for additional details. Reserves on this page reflect impairments at Yme post year-end. Reserves and resources for the Statfjord Area assets are management estimates. The PL037 (Statfjord Area) acquisition is expected to close in end-November 2023

Licence overview

Producing assets
Licence	Field	Operator	OKEA WI
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 C	Draugen	OKEA	44.56 %
PL 093 D	Draugen	OKEA	44.56 %
PL 153	Gjøa	Neptune Energy	12.00 %
PL 153 B	Gjøa	Neptune Energy	12.00 %
PL 153 C	Gjøa	Neptune Energy	12.00 %
PL 176	Draugen	OKEA	44.56 %
PL 185	Brage/Brasse	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 %

Assets being acquired (Statfjord Area)
Licence	Field	Operator	OKEA WI
PL 037	Statfjord Unit	Equinor	23.93 %
PL 037	Statfjord Nord	Equinor	28.00 %
PL 037	Statfjord Øst	Equinor	14.00 %
PL 037	Sygna	Equinor	15.40 %

Pre-production or exploration phase
Licence	Field/prospect	Operator	OKEA WI
PL 093 B	Hasselmus	OKEA	44.56 %
PL 158	Hasselmus	OKEA	44.56 %
PL 195	Aurora	OKEA	65.00 %
PL 195 B	Aurora	OKEA	65.00 %
PL 938	Calypso	Neptune Energy	30.00 %
PL 958	Rialto	OKEA	50.00 %
PL 1014 B	Arkenstone	Equinor	20.00 %
PL 1014	Arkenstone	Equinor	20.00 %
PL 740	Brasse	OKEA	44.56 %
PL 1108	Struten	DNO	40.00 %
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 1156	Zouq	OKEA	40.00 %
PL 1159	Presidenten	OKEA	50.00 %
PL 1161	Kompis	OKEA	60.00 %
PL 1178	-	OKEA	50.00 %
PL 1180	-	Neptune Energy	30.00 %
PL 1186	-	Equinor	30.00 %
PL 1187	-	OKEA	40.00 %

Introduction to the Norwegian petroleum tax system

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

Summary of the Norwegian petroleum tax system Tax balances and values net to OKEA • 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 NO^x taxes levied separately based on offshore emissions General principles • 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 Overview of key current fiscal terms Cost recovery illustration 71,8 78,0 100 1.0 1.0 1.0 1.0 1.0 1.0 SPT depreciation CT depreciation

Remaining tax balances 01.01.2023 – corporate tax basis 22%
NOKm	2018	2019	2020	2021	2022	Total
Draugen	8	39	75	152	490	764
Gjøa	2	33	187	47	-2	268
Ivar Aasen	14	45	78	86	88	311
Yme	60	177	221	552	223	1,233
Brage	41	120	61	234	293	749
Nova	16	44	81	87	121	348
Total	141	458	704	1,157	1,213	3,674

Remaining tax balances 01.01.2023 – special tax basis 71.8%¹

2018	2019	2020	2021	2022	Total
8	39	0	0	0	47
2	33	0	0	0	36
14	45	0	0	0	59
60	177	0	0	0	238
41	120	0	0	0	161
16	44	0	0	0	60
141	458	0	0	0	600

Tax depreciation and tax values per year
NOKm	2023	2024	2025	2026	2027	Total
Depreciation corporate tax	1,137	996	767	532	243	3,674
Tax value from corporate tax	250	219	169	117	53	808
Depreciation special tax	371	229	0	0	0	600
Tax value from special tax	208	128	0	0	0	336
Total tax value	458	347	169	117	53	1,144

Board of directors

Chaiwat Kovavisarach

Chairman of the board

Non-executive

• President and Group CEO of Bangchak Corporation Public Company Limited since 2015
• Also serves on the board of several listed and nonlisted companies, incl. BCPG, BBGI, Thai-Europe Business Council, Innovation Institute for Industry, the Federation of Thai industries, the Asian Institute of Technology and Intl. Chamber of Commerce for Thailand

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

Elizabeth Williamson Board member Independent, non-executive

▪ Head of energy corporate finance in Rand Merchant

▪ Master in energy, trade and finance from Cass Business School

Bank

Nicola Gordon Board member Independent, non-executive

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

Sverre Nes Board member Employee elected

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

Finn Haugan Board member Independent, non-executive

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

Ragnhild Aas Board member Employee elected

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

Jon Arnt Jacobsen Board member Independent, non-executive

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

Per Magne Bjellvåg Board member Employee elected

• Lead Process Engineer for Process and Technical Safety
• More than 27 years of experience in the oil and gas industry, mostly from Norske Shell

41

OKEA's ESG approach and strategic targets

Top 20 shareholders

Rank	Investor	Geography	Type	%	Shares
1	BCPR PTE. LTD.	Thailand	Ordinary	45.44 %	47,218,098
2	THE BANK OF NEW YORK MELLON	USA	Nominee	3.33 %	3,461,605
3	CLEARSTREAM BANKING S.A.	UK	Nominee	2.95 %	3,063,503
4	MORGAN STANLEY & CO. LLC	USA	Nominee	2.45 %	2,547,797
5	SALT VALUE AS	Norway	Ordinary	2.39 %	2,489,486
6	THE BANK OF NEW YORK MELLON SA/NV	Belgium	Nominee	1.16 %	1,202,768
7	SJÆKERHATTEN AS	Norway	Ordinary	1.07 %	1,120,000
8	J.P. MORGAN SECURITIES PLC	UK	Ordinary	0.80 %	840,623
9	SKANDINAVISKA ENSKILDA BANKEN AB	Sweden	Ordinary	0.79 %	820,456
10	BNP PARIBAS	USA	Nominee	0.78 %	806,389
11	SKJEFSTAD VESTRE AS	Norway	Ordinary	0.75 %	780,617
12	KØRVEN AS	Norway	Ordinary	0.71 %	739,285
13	SILVERCOIN INDUSTRIES AS	Norway	Ordinary	0.68 %	711,282
14	STATE STREET BANK AND TRUST COMP	USA	Nominee	0.61 %	638,669
15	OKEA HOLDINGS LTD.	Bermuda	Ordinary	0.61 %	633,398
16	VERDIPAPIRFONDET DNB NORGE PENSJON	Norway	Ordinary	0.59 %	611,535
17	WAATVIKA AS	Norway	Ordinary	0.54 %	562,489
18	NORDNET LIVSFORSIKRING AS	Norway	Ordinary	0.45 %	472,536
19	INTERACTIVE BROKERS LLC	USA	Nominee	0.45 %	468,903
20	NIMA INVEST AS	Norway	Ordinary	0.42 %	441,017
	Sum Top 20			66.97%	69,630,456
	Total outstanding shares			100.00%	103,910,350