OKEA ASA

Quarterly Report • May 4, 2023

OKEA ASA Q1 quarterly report 2023

First quarter 2023 summary

Highlights

• No serious actual incidents at operated assets
• Production of 22,210 (19,887) boepd
• Record high operating income of NOK 2,954 (1,664) million
• EBITDA of NOK 1,591 (1,086) million
• Impairment of NOK 94 (251) million of the Yme asset due to somewhat reduced reserves
• Profit before tax of NOK 1,121 (659) million
• Net profit after tax of NOK 226 (324) million
• Dividend paid of NOK 1.00 (1.00) per share, in total NOK 104 (104) million
• Entered into agreement with Equinor for acquisition of 28% in Statfjord Area (PL037)
• Lifetime extension application for Draugen from 2024 to 2040 submitted

(Amounts in parentheses refer to previous quarter)

Financial and operational summary

	Unit	Q1 2023	Q4 2022	Q1 2022	Full year 2022
Total operating income	MNOK	2,954	1,664	1,513	6,653
EBITDA 1)	MNOK	1,591	1,086	1,143	4,758
EBITDAX 1)	MNOK	1,615	1,277	1,236	5,085
Profit/loss (-) before income tax	MNOK	1,121	659	1,287	3,215
Net profit / loss (-)	MNOK	226	324	213	670
Net cash flow from operations	MNOK	1,318	390	1,072	3,344
Net cash flow used in investments	MNOK	-686	-1,729	-285	-2,434
Net cash flow used in financing activities	MNOK	-134	-189	-336	-1,969
Net interest-bearing debt (IBD) 1)	MNOK	149	583	11	583
Net IBD ex. other int. bearing liabilities1)	MNOK	-378	75	-469	75
Net production	Boepd 2)	22,210	19,887 4)	14,908	16,736 4)
Third-party volumes available for sale 3)	Boepd 2)	448	633	765	596
Over/underlift/inventory adjustments	Boepd 2)	15,283	-4,198	-229	-1,080
Net sold volume	Boepd 2)	37,941	16,322	15,444	16,252
Production expense per boe 1)	NOK/boe	241.8	258.4	191.7	236.8
Realised liquids price	USD/boe	77.7	95.2	89.6	98,4
Realised gas price	USD/boe	116.3	112.6	189.8	138.5

1) Definitions of alternative performance measures are available on page 32 of this report

2) Boepd is defined as barrels of oil equivalents per day

3) Sold volumes include net compensation volumes received from Duva and paid by Nova (tie-in to Gjøa)

4) In the fourth quarter, activities from assets acquired from Wintershall Dea were included in the statement of comprehensive income and key figures for November and December only divided by 92 days in the quarter. Actual production for the fourth quarter amounted to 21,450 boepd

Financial review

Statement of comprehensive income

Total operating income in the first quarter was a record high NOK 2,954 (1,664) million, whereof NOK 2,929 (1,516) million related to revenue from liquids and gas sales. The main driver for the increase was sold volumes of 3,415 thousand boe, an increase of 1,913 thousand boe from previous quarter. This was mainly due to two liftings from Draugen and one lifting from Brage in this first full quarter where revenues from the assets acquired from Wintershall Dea were recognised in the profit and loss statement. Average realised liquids price was USD 77.7 (95.2) per boe and average realised price for gas was USD 116.3 (112.6) per boe. The high realised gas price was partly attributable to forward sales as USD 21.1 per boe of the realised gas price in the quarter was attributable to gain on fixed price contracts.

Other operating income/loss (-) was NOK 25 (149) million consisting of tariff income at Gjøa of NOK 32 (40) million, change in fair value of the contingent consideration to Wintershall Dea of NOK -16 (12) million, income from joint utilisation of logistic resources of NOK 3 (10) million, and a net gain from financial gas forward contracts of NOK 6 (86) million.

Production expenses amounted to NOK 518 (522) million, corresponding to NOK 241.8 (258.4) per boe. Production expense per boe was still somewhat higher than the expected average rate for the year, mainly due to higher expected production from Yme and Brage as new production wells come on stream later this year.

Changes in over-/underlift positions and production inventory amounted to an expense of NOK 793 (income of NOK 222) million. The high expense was mainly due to volumes lifted at Brage in February being recognised at fair value in the purchase price allocation ("PPA") following the completion of the Wintershall Dea transaction in November. In addition, sold volumes exceeded produced volumes by 15,731 (4,198) boepd in the quarter mainly due to two liftings from Draugen and a cargo from Brage allocated to OKEA in the quarter. Net sold volumes from third-party compensation received from Duva and Nova (tie-ins to Gjøa) amounted to 448 (633) boepd.

Exploration and evaluation expenses amounted to NOK 24 (190) million and mainly related to area fees and various field evaluation activities. The high expense in the previous quarter related to seismic purchases of NOK 86 million, and expensing of previously capitalised cost on the Hamlet well of NOK 79 million.

An impairment charge of NOK 94 (251) million was recognised on the Yme asset in the quarter. The impairment was driven by higher water-cut development than expected in the wells already on production, somewhat reducing expected recoverable oil reserves. The relating tax income amounted to NOK 66 (196) million, resulting in a net after tax impact of the impairment of NOK 21 (55) million. Impairment in the previous quarter was mainly due to a re-phasing of production at Yme.

General and administrative expenses amounted to NOK 28 (87) million and represent OKEA's share of costs after allocation to licence activities. The high expense in the previous quarter was mainly due to transition activities relating to the transfer of operatorship of the Brage asset and an annual recalculation of activities distributable to licences including the employee incentive program.

Net financial items amounted to NOK -49 (94) million. Expensed interest amounted to NOK -37 (-23) million. Net foreign exchange gain/loss (-) amounted to NOK -30 (115) million following a weakened (strengthened) NOK compared to USD by ~7% (-~9%) in the quarter. For further details on financial items, reference is made to note 14.

Profit / loss (-) before tax amounted to NOK 1,121 (659) million.

Tax expenses (-) / tax income (+) amounted to NOK -894 (-335) million and represents an effective tax rate of 80% (51%). The deviation from the expected 78% was mainly due to a non-taxable loss on change in fair value of the contingent consideration to Wintershall Dea and loss on financial items taxed at a lower tax rate. This was partly offset by the tax effect of uplift. Deviation from the expected tax rate in the previous quarter was mainly due to gains on financial items and hedging being taxable at the lower tax rate of 22%.

Net profit / loss (-) for the quarter was NOK 226 (324) million. Earnings per share were NOK 2.18 (3.12).

Statement of financial position

Goodwill amounted to NOK 1,292 (1,297) million consisting of NOK 1,129 (1,133) million in technical goodwill and NOK 163 (163) million in ordinary goodwill. Reference is made to note 27 for further information.

Oil and gas properties amounted to NOK 6,496 (6,556) million. The decrease mainly related to impairment of the Yme asset of NOK 94 (251) million and depreciation of producing assets of NOK 316 (262) million. This was partly offset by investments of NOK 405 (433) mainly relating to the Hasselmus development, Draugen power from shore, Draugen modifications and Brage production well drilling.

Right-of-use assets amounted to NOK 225 (233) million and mainly related to logistical resources on operated assets and lease of offices. The decrease in the quarter was due to IFRS 16 depreciation.

Non-current asset retirement reimbursement right amounted to NOK 3,760 (3,662) million and related to Shell's and Wintershall Dea's obligation to cover decommissioning costs for Draugen/Gjøa and Brage, respectively. The increase was due to a decrease in the discount rate applied for estimating the value of the receivables from Wintershall Dea.

Trade and other receivables amounted to NOK 1,793 (1,744) million and comprised accrued revenue, working capital from joint venture licences and underlift of petroleum products.

Cash and cash equivalents amounted to NOK 1,634 (1,104) million. The increase in cash balance was mainly due to the high cash flows from operations which significantly exceeded cash flows used for investment and financing activities.

Spare parts, equipment and inventory amounted to NOK 473 (800) million whereof NOK 193 (512) million related to oil inventory Draugen, Brage and Yme. The decrease were mainly due to two liftings at Draugen in the quarter, in addition to volumes lifted at Brage recognised at fair value.

Equity amounted to NOK 2,200 (2,078) million, corresponding to an equity ratio of 14% (13%). The increase was due to net profit after tax exceeding the dividend payment of NOK 104 million.

Non-current provision for asset retirement obligations amounted to NOK 5,958 (5,915) million. The obligation is largely offset by the asset retirement reimbursement right outlined above.

Interest-bearing bond loans amounted to NOK 1,255 (1,179) million. The increase from previous quarter was due to an unrealised foreign exchange loss on the OKEA03 bond nominated in USD.

Total other interest-bearing liabilities amounted to NOK 528 (508) million, whereof the non-current portion was NOK 479 (462) million and the current portion was NOK 49 (46) million. The amount represents OKEA's share of the net present value of the future obligations under the bareboat charter (BBC) agreement for Yme on the Inspirer rig. Reference is made to note 23 for further details.

The lease liability relating to IFRS 16 is split into a non-current liability of NOK 204 (212) million and a current liability of NOK 50 (50) million and represents the liability of the right-of-use assets as described above.

Trade and other payables amounted to NOK 1,548 (2,220) million and mainly related to payments received under payment quantity agreements, accrued expenses and working capital from joint venture licences.

Income tax payable was NOK 1,429 (477) million, mainly consisting of the remaining accrued tax payable for 2022 and the accrued tax payable for the first quarter of 2023.

Statement of cash flows

Net cash flows from operating activities amounted to NOK 1,318 (390) million, including taxes paid of NOK 166 (1,201) million. The increase in cash flow from operating activities compared to previous quarter was mainly due to higher sold volumes as well as one tax instalment of NOK 166 million for 2022 paid in the first quarter compared to two tax instalments of NOK 509 million each paid in the fourth quarter in addition to remaining tax for 2021. The tax instalments for 2022 payable in the first half of 2023 have been reduced from NOK 509 million paid for the first three instalments in the second half of 2022, to NOK 166 million to be paid for the last three instalments payable in the first half of 2023.

Net cash flows used in investment activities amounted to NOK -686 (-1,729) million. Investments in the quarter include oil and gas properties of NOK -390 (-421) million, mainly relating to the Hasselmus gas development, Draugen power from shore, Draugen modifications and production well drilling at Brage. In addition, exploration drilling amounted to NOK -12 (-169) million. In addition, a deposit of NOK 263 (0) million was paid to Equinor for the acquisition of 28% in PL037 (Statfjord Area). In the previous quarter, a payment of NOK 1,103 million was made to Wintershall Dea for the portfolio of assets acquired.

Net cash flows used in financing activities was NOK -135 (-190) million and mainly related to dividend payments of NOK -104 (-104) million and interest payments of NOK -11 (-64) million.

Financial risk management

OKEA uses derivative financial instruments and forward sales to manage exposures to fluctuations in commodity prices. OKEA realised NOK 133 million on physical and financial forward contracts during first quarter. At the end of the quarter, OKEA had sold forward approximately 8% of the estimated net after tax exposure for natural gas for the second quarter of 2023 at an average price of 505 GBp/th. Following balance sheet date, OKEA has hedged approximately 20% of the net after tax crude exposure for April-December using collars with price floors around 72-75 USD/bbl and ceilings currently around 90-105 USD/bbl.

Operational review

OKEA's net production in the first quarter was 22,210 (19,887) boepd. In the fourth quarter, activity from assets acquired from Wintershall Dea was included in the statement of comprehensive income and key figures for November and December only divided by 92 days in the quarter. Actual production for the fourth quarter amounted to 21,450 boepd. The additional increase in production in the first quarter was due to the Beta Nord campaign at Yme being finalised in January 2023 which increased production from Yme by nearly 50%.

	Unit	Q1 2023	Q4 2022	Q1 2022	Full year 2022
Draugen – production reliability1)1	%	96	96	97	96
Draugen – production availability2)2	%	96	92	96	94
Brage - production reliability3	%	92	99	N/A	N/A
Brage – production availability4	%	91	95	N/A	N/A
Gjøa – production reliability	%	100	97	99	90
Gjøa – production availability	%	99	97	86	92
Yme – production availability	%	55	25	N/A	21
Ivar Aasen – production availability	%	90	97	99	82
Nova - production availability	%	99	73	N/A	81
Draugen – production	Boepd	6,584	6,797	6,877	6,767
Brage – Production4)	Boepd	2,162	1,520	N/A	383
Gjøa – production	Boepd	6,812	6,783	6,478	6,932
Yme – production	Boepd	2,442	1,693	1,345	1,429
Ivar Aasen – production4)	Boepd	3,110	2,544	208	1,086
Nova – production4)	Boepd	1,100	550	N/A	139
Total net production	Boepd	22,210	19,887	14,908	16,736
Draugen – sold volume	Boepd	13,774	6,494	6,592	6,740
Brage – sold volume	Boepd	7,078	109	N/A	27
Gjøa – sold volume	Boepd	7,410	7,926	7,034	7,381
Yme – sold volume	Boepd	3,628	719	1,011	1,157
Ivar Aasen – sold volume	Boepd	4,508	441	42	351
Nova – sold volume	Boepd	933	0	N/A	0
Third-party volumes available for sale3)	Boepd	448	633	765	596
Total net sold volume	Boepd	37,941	16,322	15,444	16,252
Total over/underlift/inventory adj.	Boepd	15,283	-4,198	-229	-1,080

1) Production reliability = Actual production / (Actual production + Unscheduled deferment)

2) Production availability = Actual production / (Actual production + Scheduled deferment + Unscheduled deferment)

Deferment is the reduction in production caused by a reduction in available production capacity due to an activity, an unscheduled event, poor equipment performance or sub-optimum settings

3) Net compensation volumes from Duva and Nova received and sold (tie-in to Gjøa)

4) In the fourth quarter, activity from assets acquired from Wintershall Dea was included in the statement of comprehensive income and key figures for November and December only divided by 92 days in the quarter. Actual production for the fourth quarter amounted to 21,450 boepd

Draugen (operator, 44.56%)

Net production to OKEA from Draugen was 6,584 (6,797) boepd in the quarter. Production availability was 96% (92%) and production reliability was 96% (96%).

The lower production compared to previous quarter was mainly due to natural decline.

A planned maintenance turnaround (TAR) with expected downtime of 21 days commenced on 26 April and will impact production from Draugen in the second quarter.

Topside installation to prepare for the Hasselmus tie-back is progressing according to schedule and production start is planned for the fourth quarter of 2023. The power from shore project is also progressing according to plan. An exploration well on the Springmus East prospect in addition to an observation well on the Garn West area is scheduled for drilling in the third quarter.

An application to extend the Draugen license from 2024 to 2040 was submitted to the Petroleum Safety Agency and the Norwegian Petroleum Directorate in March 2023, which is one year prior to expiry of the existing consent. The submission follows a comprehensive licence extension program launched in 2019 which involved several disciplines across the organisation to document safe production and resource management towards 2040.

Brage (operator, 35.2%)

Net production to OKEA from Brage was 2,162 (1,520) boepd in the quarter. Production availability was 91% (95%) and production reliability was 92% (99%). Production in the first quarter was impacted by an unplanned shutdown of 4 days due to repair work on the gas compressor turbine.

One of the wells at Brage has experienced reduced gas production following the turnaround which was completed in September 2022. This has also impacted the production in the first quarter 2023. Performance from the well has gradually improved and is near planned level.

Drilling of new wells is progressing ahead of plan. Drilling of a production well in Talisker East was completed in the quarter with topside hook-up ongoing and scheduled production start in the second quarter. Drilling of a Sognefjord gas producer has commenced and is expected completed in the second quarter. A well to Fensfjord south is scheduled for the second quarter. Both wells have scheduled production startup in the third quarter. Following completion of the planned wells, production from Brage is expected to reach plateau of approximately 6,000 boepd net to OKEA during fourth quarter.

An observation pilot to the Brage south area was approved in the first quarter and is scheduled for the second quarter. Submission of a development and operation plan (PDO) for a Cook-well is scheduled for second quarter.

Several modification projects to maintain integrity and facilitate possible lifetime extension beyond 2030 have been launched. Assessments for a potential tie-back of Brasse (PL740) to Brage are ongoing.

Gjøa (partner, 12%)

Net production to OKEA from Gjøa was 6,812 (6,783) boepd in the quarter. Production reliability was 100% (97%).

Net delivered and sold compensation volumes from Duva and Nova was 448 (633) boepd in the quarter. Further maturation of potential development scenarios of the Hamlet discovery is ongoing, as a possible tie-back to Gjøa. Evaluations to identify potential synergies with other potential developments to further reduce costs continue.

Options to appraise the Aurora discovery and drill the Selene prospect near Gjøa in 2024 are under review.

Yme (partner, 15%)

Net production to OKEA from Yme was 2,442 (1,693) boepd in the quarter. Production availability was 55% (25%). The increase in production reflects the improved production availability as well as startup of the Beta Nord wells in January.

Development of water-cut in the wells already in production indicates a further reduction in the total expected reserves from the field (around 0.5 mmboe OKEA share) which resulted in an impairment in the quarter. Infill well opportunities are being evaluated.

The Beta Nord drilling campaign, employing the Valaris Viking drilling rig, was finalised in January. Beta Nord is a subsea tie-back to Yme and includes two new production wells and one injector well. Drilling of new production wells and one injector well at Yme Gamma is expected to start in the second quarter of 2023 from Inspirer. There is uncertainty around the in-place oil resources for one of these wells, which is expected to be clarified during drilling. Should the outcome be in the lower range, there is a risk of further impairment at Yme.

Production is expected to reach plateau of approximately 5,000 boepd net to OKEA in mid 2023.

Ivar Aasen (partner, 9.2385%)

Net production to OKEA from Ivar Aasen was 3,110 (2,544) boepd and production availability was 90% (97%).

An increased oil recovery (IOR) campaign with three new development wells was completed as planned in 2022. The D-13 well started production in December 2022. The D-9 and D-8 wells were shut-in due to high water cut and gas oil ratio (GOR). An intervention campaign is planned for the second quarter of 2023.

To mitigate the risk of hydrogen induced stress cracking, 12 subsea clamps were successfully installed in the first quarter. The campaign was executed with downtime of 6 days.

Nova (partner, 6%)

Net production to OKEA from Nova was 1,100 (550) boepd in the quarter.

Production from Nova is still impacted by issues with the water injection wells. A side-track drilling operation is planned to start in the second quarter of 2023 to improve the location of one of the injector wells and increase production from the second half of the year. Actions to further improve the water injection at the field is assessed and a drilling rig to drill a fourth water injector in the first half of 2024 has been secured.

Acquisition of 28% working interest in PL037 (Statfjord Area)

On 20 March, OKEA entered into an agreement with Equinor Energy AS to acquire 28% working interest (WI) in PL037 (Statfjord Area) with effective date 1 January 2023.

The acquired portfolio comprises 23.93123% WI in Statfjord Unit, 28% WI in Statfjord Nord, 14% WI in Statfjord Øst Unit and 15.4% WI in Sygna Unit and adds net 2P reserves of 41 mmboe and net 2C resources of 8 mmboe. Additional upside volume potential estimated to net 14 mmboe, has been identified by OKEA based on drilling beyond 2028 and cost reduction initiatives. Following the acquisition, the expected additional production to OKEA for 2023 is estimated to 13,000 – 15,000 boepd and is expected to grow to 16,000 – 20,000 boepd in 2024.

The agreed initial fixed consideration of USD 220 million includes tax balances of approximately NOK 300 million. In addition, the agreement contains a contingent consideration structure based on profit sharing on crude oil volumes sold as well as on dry gas volumes sold during the period 2023 – 2025. Equinor will retain responsibility for 100% of OKEA`s share of total decommissioning cost related to Statfjord A and OKEA will be liable for its share of costs to related to the decommissioning of Statfjord B and C. However, Equinor retains responsibility for decommissioning costs relating to any full or partial removal of Statfjord B and C gravity-based structures, should it be required.

No new financing is required for funding the transaction as a majority of the purchasing price, based on prevailing forward prices, will be covered by cash flows generated by the assets prior to completion. Completion is expected in the fourth quarter of 2023.

Development projects

Draugen - Hasselmus (operator, 44.56%)

As operator of Draugen, OKEA is currently developing the Hasselmus field as a single subsea gas well with direct tie-back to the Draugen platform for further processing and export. Production start is planned for the fourth quarter of 2023 with gross plateau gas production of more than 4,400 barrels boepd.

The project is progressing according to schedule. The 8 km flowline is planned installed in May. Topside installation at Draugen is currently ongoing with a planned peak activity level during the Draugen turnaround in the second quarter of 2023 along with planned subsea installation programme prior to commissioning and production start-up.

Draugen – power from shore (operator, 44.56%)

OKEA and Equinor in collaboration with the license partners has established a joint project to electrify the Draugen and Njord A platforms.

OKEA is responsible for developing the power infrastructure from shore to Draugen including modifications on Draugen. Equinor is responsible for the cable from Draugen to Njord including modifications on Njord A. Draugen and Njord will be connected to the power grid at Tensio's transformer station at Straum in Åfjord municipality, where Statnett assesses the connection as operationally sound without a need for reinforcement of the power grid.

The PDO and plan for construction and operation was submitted to the Ministry of Petroleum and Energy in the fourth quarter of 2022. Approval is expected in 2023. Following the Ministry of Petroleum and Energy approval of pre-commitments, the project entered into an EPCIC contract with Aker Solutions and a contract with NKT for engineering, production, installation and protection of the power cable from shore to Draugen.

The project will result in annual reduction of CO2 emissions of 200,000 tonnes from Draugen and 130,000 tonnes from Njord. In addition, the project will result in lower cost of operations and extend the economic lifetime of the Draugen field. Expected completion of the project is in the first quarter of 2027.

Brasse (partner, 50%)

In December, OKEA entered into an SPA with DNO Norge AS to enter into the Brasse licence (PL740) with 50% WI and effective date 1 January 2023.

The transaction and extension of the license was approved by the Ministry of Petroleum and Energy in the first quarter of 2023. The target of the new partnership is to undertake a fast-track, low-cost review to assess whether a value accretive development concept can be found for the estimated 30 mmboe recoverable volumes at Brasse, which is located only 13 km from the OKEA-operated Brage field. The transaction itself was at zero cost to OKEA.

A condensed screening phase has been completed during first quarter and a potential development through a tie-back to Brage is currently being assessed.

Exploration licences

In January, OKEA was awarded four new exploration licences in the APA 2022 round by the Norwegian authorities. Two of the licences are OKEA-operated and are located near the Draugen and Brage fields. The other two are located near the Gjøa and Njord fields. Work to detail the work programmes for these licences has commenced.

Planning for a drilling campaign on Draugen continued, with planned execution expected in the third quarter of 2023. An exploration well on the Springmus East prospect will be drilled (with an option to drill Springmus W) together with an observation well on the Garn West South IOR opportunity.

The Equinor-operated Arkenstone exploration well (PL1014) is scheduled for the second half of 2024.

The following exploration licences lapsed in the first quarter as no decision to drill further wells was taken - PL1034 (Fleming), PL973 and PL973 B (Jerv and Ilder).

QHSSE and Environment, Social and Governance

There were no actual serious incidents and no serious acute discharges or emissions in OKEA's operations in the first quarter.

In March, OKEA hosted a major emergency response exercise, where the simulated scenario was related to a major oil spill from drilling activities. More than 800 people participated in the exercise, including participation from other operators on the Norwegian continental shelf, NOFO (The Norwegian clean seas association for operating companies) and OFFB (the operators' association for emergency response). Planning, preparations, and training for the exercise have been ongoing for more than a year and learning points will be outlined in the final evaluation report to be completed in June. These learning points will be considered in future exercises across the industry.

In line with peers and the Norwegian oil and gas industry, OKEA continues to maintain an increased security level. The company is still continuously assessing and monitoring the situation and maintaining close dialogue with relevant parties.

Subsequent events

Announcement of second quarter dividend

On 4 May OKEA announced a dividend payment of NOK 103.9 million (NOK 1 per share) to be paid on or about 15 June. The board also reaffirmed its intention to distribute NOK 1 per share in the last two quarters of 2023. Future dividend payments are subject to an authorisation from the general meeting and may be revised due to changes in the market environment, company situation and/or value accretive opportunities available.

Outlook

The invasion of Ukraine has impacted petroleum prices in a tight energy market with significant volatility at relatively high price levels and unprecedented price differentials in the European gas market over the last year. This critical situation has resulted in high revenues for OKEA but also a significant and heightened focus on security measures.

In March, OKEA entered into an SPA with Equinor to acquire a 28% WI in PL037 (Statfjord Area) with effective date 1 January 2023 and expected completion in the fourth quarter of 2023. This transformational deal represents another step change in production growth as well as diversification and fits very well into OKEA's growth strategy.

In addition to pursuing inorganic growth opportunities, OKEA is also working to mature the portfolio of development projects. The Hasselmus gas project is progressing according to schedule with planned production start in the fourth quarter of 2023 and the approval of the PDO for the power from shore project at Draugen is expected in 2023.

OKEA's production guiding for 2023 remains unchanged at 22,000-25,000 boepd. Capex guiding, for 2023 remains at NOK 1,700-2,100 million. The capex guiding does not include capitalised interest and exploration capex and comprises completion of the Hasselmus project, Draugen power from shore, Brage infill drilling and other investments. All guiding for 2023 excludes effects of the Statfjord acquisition.

In May 2023 two liftings of 67 thousand bbl each from Yme and a lifting of 646 thousand bbl from Draugen are planned. In June 300 thousand bbl from Ivar Aasen and 350 thousand bbl from Brage are expected, in addition to one lifting of 67 thousand bbl from Yme. All volumes are net OKEA.

OKEA continues to deliver according to the dividend plan. In March, OKEA distributed a cash dividend of NOK 103.9 million (NOK 1.00 per share) to its shareholders. On 4 May, OKEA announced a dividend of NOK 1.00 per share to be paid on or about 15 June and the board also reaffirmed its intention to distribute NOK 1.00 per share in the two remaining quarters of 2023.

OKEA has a clear ambition to deliver competitive shareholder returns driven by solid growth, value creation and capital discipline and the strategy will be centred around three growth levers:

actively pursue further value creation in current portfolio,

pursuing mergers and acquisitions to add new legs to the portfolio, and

considering organic projects either adjacent to existing hubs or pursuing new hubs, dependent on financial headroom and attractive risk-reward.

The cash outlook is good, outstanding debt has been reduced, and the board considers that the company is well positioned to continue to execute on the growth strategy.

Statement of comprehensive income

		Q1 2023	Q4 2022	Q1 2022	2022
Amounts in NOK `000	Note	(unaudited)	(unaudited)	(unaudited)	(audited)
Revenues from crude oil and gas sales	6	2 929 405	1 515 809	1 515 627	6 398 654
Other operating income / loss (-)	6, 25	24 701	148 644	-2 634	253 975
Total operating income		2 954 106	1 664 453	1 512 993	6 652 629
Production expenses	7	-517 868	-522 268	-287 294	-1 616 020
Changes in over/underlift positions and production inventory	7	-793 349	221 588	32 594	296 523
Exploration and evaluation expenses	8	-23 561	-190 268	-92 676	-327 506
Depreciation, depletion and amortisation	10	-327 174	-270 243	-157 780	-769 359
Impairment (-) / reversal of impairment	10, 11, 12	-94 417	-251 152	362 597	-497 584
General and administrative expenses	13	-27 726	-87 093	-22 581	-212 602
Total operating expenses		-1 784 095	-1 099 436	-165 140	-3 126 549
Profit / loss (-) from operating activities		1 170 011	565 017	1 347 853	3 526 080
Finance income	14	52 065	46 908	21 872	126 041
Finance costs	14	-71 646	-68 373	-82 715	-334 055
Net exchange rate gain/loss (-)	14	-29 818	115 124	35	-103 101
Net financial items		-49 398	93 660	-60 808	-311 115
Profit / loss (-) before income tax		1 120 613	658 677	1 287 045	3 214 965
Taxes (-) / tax income (+)	9	-894 483	-334 559	-1 073 792	-2 545 357
Net profit / loss (-)		226 130	324 118	213 253	669 608
Other comprehensive income, net of tax:
Items that will not be reclassified to profit or loss in subsequent periods:
Remeasurements pensions, actuarial gain/loss (-)		-	110	-	110

Total other comprehensive income, net of tax	-	110	-	110
Total comprehensive income / loss (-)	226 130	324 228	213 253	669 718
Weighted average no. of shares outstanding basic	103 910 350	103 881 220	103 870 350	103 873 090
Weighted average no. of shares outstanding diluted	103 910 350	103 939 480	103 950 350	103 947 610
Earnings per share (NOK per share) - Basic	2.18	3.12	2.05	6.45
Earnings per share (NOK per share) - Diluted	2.18	3.12	2.05	6.44

Statement of financial position

		31.03.2023	31.12.2022	31.03.2022
Amounts in NOK `000	Note	(unaudited)	(audited)	(unaudited)
ASSETS
Non-current assets
Goodwill	11, 12	1 292 206	1 296 591	804 657
Exploration and evaluation assets	11	192 304	184 317	52 105
Oil and gas properties	10	6 496 242	6 556 314	5 190 899
Furniture, fixtures and office equipment	10	45 699	40 622	10 366
Right-of-use assets	10	224 588	232 901	231 392
Asset retirement reimbursement right	15	3 760 131	3 662 122	2 767 430
Total non-current assets		12 011 171	11 972 868	9 056 850
Current assets
Trade and other receivables	17, 25	1 793 034	1 743 901	996 499
Financial investments	26	-	-	209 326
Spare parts, equipment and inventory	20	472 786	800 333	260 083
Asset retirement reimbursement right, current	15	-	-	65 077
Cash and cash equivalents	18	1 633 594	1 104 026	2 469 576
Total current assets		3 899 415	3 648 261	4 000 562
TOTAL ASSETS		15 910 586	15 621 128	13 057 412
EQUITY AND LIABILITIES
Equity
Share capital	16	10 391	10 391	10 387
Share premium		1 523 397	1 627 307	1 927 859
Other paid in capital		19 140	19 140	19 085
Retained earnings/loss (-)		647 322	421 191	-35 274
Total equity		2 200 250	2 078 030	1 922 057
Non-current liabilities Asset retirement obligations	19	5 958 198	5 915 084	3 958 108
Pension liabilities		46 192	43 255	40 093
Lease liability
	23	204 078	212 409	216 399
Deferred tax liabilities	9	2 594 237	2 835 089	2 091 152
Other provisions	27, 28	51 864	39 107	-
Interest bearing bond loans	22	1 255 250	1 178 610	2 000 577
Other interest bearing liabilities	23	478 502	462 078	440 710
Total non-current liabilities		10 588 321	10 685 633	8 747 039
Current liabilities
Trade and other payables	21, 25	1 547 509	2 219 658	834 070
Other interest bearing liabilities, current	23	49 482	45 874	38 845
Income tax payable	9	1 429 114	476 850	1 364 331
Lease liability, current	24	49 643	49 643	44 106
Asset retirement obligations, current	19	-	-	81 346
Public dues payable		46 267	65 440	25 619
Total current liabilities		3 122 015	2 857 465	2 388 316
Total liabilities		13 710 336	13 543 099	11 135 355
TOTAL EQUITY AND LIABILITIES		15 910 586	15 621 128	13 057 412

Statement of changes in equity

Amounts in NOK `000		Share capital Share premium	Other paid in capital	Retained earnings/loss (-)	Total equity
Equity at 1 January 2022	10 387	1 927 859	19 064	-248 527	1 708 783
Total comprehensive income/loss (-) for the period	-	-	-	213 253	213 253
Share based payment	-	-	21	-	21
Equity at 31 March 2022	10 387	1 927 859	19 085	-35 274	1 922 057
Equity at 1 April 2022	10 387	1 927 859	19 085	-35 274	1 922 057
Total comprehensive income/loss (-) for the period	-	-	-	456 466	456 466
Dividend paid	-	-301 264	-	-	-301 264
Share issues, cash	4	712	-	-	716
Share based payment	-	-	55	-	55
Equity at 31 December 2022	10 391	1 627 307	19 140	421 191	2 078 030
Equity at 1 January 2023	10 391	1 627 307	19 140	421 191	2 078 030
Total comprehensive income/loss (-) for the period	-	-	-	226 130	226 130
Dividend paid	-	-103 910	-	-	-103 910
Equity at 31 March 2023	10 391	1 523 397	19 140	647 322	2 200 250

Statement of cash flows

		Q1 2023	Q4 2022	Q1 2022	2022
Amounts in NOK `000	Note	(unaudited)	(unaudited)	(unaudited)	(audited)
Cash flow from operating activities
Profit / loss (-) before income tax		1 120 613	658 677	1 287 045	3 214 965
Income tax paid/received	9	-166 496	-1 200 739	-193 780	-2 289 373
Depreciation, depletion and amortization	10	327 174	270 243	157 780	769 359
Impairment / reversal of impairment	10, 11, 12	94 417	251 152	-362 597	497 584
Expensed exploration expenditures temporary capitalised	8, 11	4 512	78 491	64 864	141 892
Accretion asset retirement obligations/reimbursement right - net	14, 15, 19	3 191	5 106	939	11 768
Asset retirement costs from billing (net after reimbursement)	15, 19	-106	48	-4 584	-22 525
Interest expense	14	21 200	22 664	50 497	172 369
Gain / loss on financial investments	14	-	-7	634	64
Change in fair value contingent consideration	6, 28	15 631	-12 376	-	-12 376
Change in trade and other receivables, and inventory		536 603	-623 966	48 623	-799 208
Change in trade and other payables		-722 026	1 062 709	8 007	1 425 986
Change in foreign exchange interest bearing debt and other non-current items		83 412	-122 118	14 555	233 567
Net cash flow from / used in (-) operating activities		1 318 126	389 884	1 071 983	3 344 073
Cash flow from investment activities
Investment in exploration and evaluation assets	11	-12 499	-182 695	-106 211	-315 833
Business combinations, cash paid	27, 28, 17	-274 869	-1 103 109	-45 915	-1 239 721
Investment in oil and gas properties	10, 14	-389 618	-421 709	-132 557	-1 052 354
Investment in furniture, fixtures and office machines	10	-9 459	-30 470	-800	-36 422
Cash used on (-)/received from financial investments	26	-	9 107	-	209 896
Net cash flow from / used in (-) investment activities		-686 446	-1 728 876	-285 483	-2 434 433
Cash flow from financing activities
Repayment/buy-back of bond loans	22	-	-	-289 079	-1 401 531
Repayment of other interest bearing liabilities	23	-11 165	-13 352	-10 259	-42 730
Interest paid		-11 276	-64 412	-28 993	-193 729
Payments of lease debt	24	-8 331	-8 823	-7 235	-30 544
Dividend payments		-103 910	-103 910	-	-301 264
Net proceeds from share issues		-	716	-0	716
Net cash flow from / used in (-) financing activities		-134 682	-189 780	-335 567	-1 969 082
Net increase/ decrease (-) in cash and cash equivalents		496 998	-1 528 773	450 933	-1 059 442
Cash and cash equivalents at the beginning of the period
Effect of exchange rate fluctuation on cash held		1 104 026 32 570	2 668 452 -35 653	2 038 745 -20 102	2 038 745 124 723
Cash and cash equivalents at the end of the period		1 633 594	1 104 026	2 469 576	1 104 026

Notes to the interim financial statements

Note 1 General and corporate information

These financial statements are the unaudited interim condensed financial statements of OKEA ASA for the first quarter of 2023. OKEA ASA ("OKEA" or the "company") is a public limited liability company incorporated and domiciled in Norway, with its main office located in Trondheim. The company's shares are listed on the Oslo Stock Exchange under the ticker OKEA.

0

OKEA is a leading mid to late-life operator on the Norwegian continental shelf (NCS). OKEA finds value where others divest and has an ambitious growth strategy built on accretive M&A activities, value creation and capital discipline.

Note 2 Basis of preparation

The interim accounts have been prepared in accordance with IAS 34 Interim Financial Reporting. The interim accounts do not include all the information required in the annual accounts and should therefore be read in conjunction with the annual accounts for 2022. The annual accounts for 2022 were prepared in accordance with EU`s approved International Financial Reporting Standards (IFRS).

The interim financial statements were authorised for issue by the company's board of directors on 3 May 2023.

Note 3 Accounting policies

The accounting policies adopted in the preparation of the interim accounts are consistent with those followed in the preparation of the annual accounts for 2022. New standards, amendments and interpretations to existing standards effective from 1 January 2023 did not have any significant impact on the financial statements.

Note 4 Critical accounting estimates and judgements

The preparation of the interim accounts entails the use of judgements, estimates and assumptions that affect the application of accounting policies and the amounts recognised as assets and liabilities, income and expenses. The estimates, and associated assumptions, are based on historical experience and other factors that are considered as reasonable under the circumstances. The actual results may deviate from these estimates. The material assessments underlying the application of the company's accounting policies, and the main sources of uncertainty, are the same for the interim accounts as for the annual accounts for 2022.

Note 5 Business segments

The company's only business segment is development and production of oil and gas on the Norwegian continental shelf.

Note 6 Income

Breakdown of petroleum revenues

Amounts in NOK `000	Q1 2023	Q4 2022	Q1 2022	2022
Sale of liquids	2 305 721	916 152	696 728	3 621 472
Sale of gas	623 684	599 657	818 899	2 777 182
Total petroleum revenues	2 929 405	1 515 809	1 515 627	6 398 654
Sale of liquids (boe*)	2 892 527	967 625	869 787	3 841 817
Sale of gas (boe*)	522 167	534 008	520 196	2 090 128
Total sale of petroleum in boe*	3 414 693	1 501 633	1 389 984	5 931 945

*Barrels of oil equivalents

Other operating income

Amounts in NOK `000	Q1 2023	Q4 2022	Q1 2022	2022
Gain / loss (-) from put/call options, oil	212	-	-	-
Gain / loss (-) from forward contracts, gas	5 523	86 236	-32 724	72 492
Change in fair value contingent consideration (see note 28)	-15 631	12 376	-	12 376
Tariff income Gjøa	32 061	39 707	24 146	131 596
Joint utilisation of logistics resources	2 537	10 326	5 944	37 512
Total other operating income/loss (-)	24 701	148 644	-2 634	253 975

Note 7 Production expenses & changes in over/underlift positions and production inventory

Production expenses

Amounts in NOK `000	Q1 2023	Q4 2022	Q1 2022	2022
From licence billings - producing assets	436 467	451 451	249 489	1 420 803
Other production expenses (insurance, transport)	74 041	64 407	34 460	179 295
G&A expenses allocated to production expenses	7 361	6 410	3 345	15 922
Total production expenses	517 868	522 268	287 294	1 616 020

Changes in over/underlift positions and production inventory

Amounts in NOK `000	Q1 2023	Q4 2022	Q1 2022	2022
Changes in over/underlift positions	-474 992	82 405	29 531	196 372
Changes in production inventory	-318 357	139 182	3 063	100 151
Total changes income/loss (-)	-793 349	221 588	32 594	296 523

* Reduction in underlift and production inventory in Q1 2023 mainly due large amount of liftet volumes of oil at Draugen, in addition to the expense effect of lifting of underlift position and oil inventory acquired from Wintershall Dea being valued at fair value in the balance sheet following the purchase-price-allocation (PPA).

Note 8 Exploration and evaluation expenses

Amounts in NOK `000	Q1 2023	Q4 2022	Q1 2022	2022
Share of exploration and evaluation expenses from participation in licences excluding dry well impairment, from billing	19 582	22 936	20 810	75 304
Share of exploration expenses from participation in licences, dry well write off, from billing	4 512	78 491	64 864	141 892
Seismic and other exploration and evaluation expenses, outside billing	-1 449	87 794	6 636	108 525
G&A expenses allocated to exploration expenses	916	1 047	365	1 786
Total exploration and evaluation expenses	23 561	190 268	92 676	327 506

Note 9 Taxes

Income taxes recognised in the income statement

Amounts in NOK `000	Q1 2023	Q4 2022	Q1 2022	2022
Change in deferred taxes current year	240 852	-239 559	-333 944	-436 027
Taxes payable current year	-1 135 334	-94 996	-739 848	-2 105 157
Tax payable adjustment previous year	-	-4	-	-4 173
Total taxes (-) / tax income (+) recognised in the income
statement	-894 483	-334 559	-1 073 792	-2 545 357
Reconciliation of income taxes
Amounts in NOK `000	Q1 2023	Q4 2022	Q1 2022	2022
Profit / loss (-) before income taxes	1 120 613	658 677	1 287 045	3 214 965

Effective income tax rate	80 %	51 %	83 %	79 %
Total income taxes recognised in the income statement	-894 483	-334 559	-1 073 792	-2 545 357
Adjustments previous year and other	-	38	-	-8 264
Effect of new tax rates	-	-	-	-104
Financial and onshore items	-20 431	103 250	-51 486	-105 620
Effect of uplift	22 704	31 676	17 974	102 044
Permanent differences, including impairment of goodwill	-22 632	44 272	-36 386	-25 612
Expected income tax at tax rate 78.004% (Q1 2022: 78%)	-874 123	-513 794	-1 003 895	-2 507 802

Specification of tax effects on temporary differences, tax losses and uplift carried forward

Amounts in NOK `000	31.03.2023	31.12.2022	31.03.2022
Tangible and intangible non-current assets	-4 406 969	-4 372 336	-3 343 576
Provisions (net ARO), lease liability, pensions and gain/loss account	2 061 117	2 102 801	1 387 251
Interest bearing loans	-1 397	-1 466	-2 736
Current items (spareparts and inventory)	-246 989	-564 088	-132 091
Tax losses carried forward, onshore 22%	4 887	4 887	4 887
Valuation allowance (uncapitalised deferred tax asset)	-4 887	-4 887	-4 887
Total deferred tax assets / liabilities (-) recognised	-2 594 237	-2 835 089	-2 091 152

Specifiaction of tax payable

Amounts in NOK `000	Total
Tax payable at 1 January 2023	476 850
Tax paid	-166 496
Tax payable current year recognised in the income statement	1 135 334
Tax payable recognised in business combination (see note 27)	-16 574
Tax payable at 31 March 2023	1 429 114

Note 10 Tangible assets and right-of-use assets

Furniture,
Oil and gas properties in	fixtures and	Right-of-use assets	Total
			10 687 398
404 814	9 459	-	414 273
4 492	-	-	4 492
-57 980	-	-	-57 980
-	-2 464	-	-2 464
10 627 373	59 644	358 702	11 045 719
-3 719 732	-12 027	-125 802	-3 857 561
-316 981	-4 382	-5 811	-327 174
-94 417	-	-	-94 417
-	2 464	-	2 464
-	-	-2 501	-2 501
-4 131 130	-13 945	-134 114	-4 279 189
			6 766 530
	production 10 276 046 6 496 242	office machines 52 650 45 699	358 702 224 588

Note 11 Goodwill, exploration and evaluation assets

	Exploration and evaluation assets	Technical goodwill	Ordinary goodwill	Total goodwill
Amounts in NOK `000
Cost at 1 January 2023	184 317	1 642 191	416 415	2 058 607
Additions	12 499	-	-	-
Additions through business combination (see note 27)	-	-4 385	-	-4 385
Expensed exploration expenditures temporarily capitalised	-4 512	-	-	-
Cost at 31 March 2023	192 304	1 637 806	416 415	2 054 221
Accumulated impairment at 1 January 2023	-	-508 818	-253 198	-762 016
Impairment	-	-	-	-
Accumulated impairment at 31 March 2023	-	-508 818	-253 198	-762 016
Carrying amount at 31 March 2023	192 304	1 128 988	163 217	1 292 206

Note 12 Impairment / reversal of impairment

Below is an overview of the key assumptions applied in the impairment test as of 31 March 2023: Tangible and intangible assets are tested for impairment / reversal of impairment whenever indicators are identified and at least on an annual basis. Impairment is i d h th b k l f t h ti it d th bl t Th bl t i th hi h f th t' f i l

Year	Oil USD/BOE*	Gas GBP/therm*	Currency rates USD/NOK
2023	79.0	1.27	10.4
2024	73.8	1.43	10.3
2025	70.3	1.10	9.9
2026	72.0	0.76	9.0
From 2027	72.1	0.75	9.0

* Prices in real terms

Other assumptions

For oil and gas reserves future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves.

Future capex, opex and abandonment cost are calculated based on the expected production profiles and the best estimate of related cost. For fair value testing the discount rate applied is 10.0% post tax unchanged from the Q4 test.

The long-term inflation rate is assumed to be 2.0%.

The valuation of oil and gas properties and goodwill are inherently uncertain due to the judgemental nature of the underlying estimates. This risk has increased due to the current market conditions with rapid fluctuation in supply and demand of oil and gas causing more volatility in prices.

Total cost for CO2 comprises Norwegian CO2 tax and cost of the EU Emission Trading System and is estimated to gradually increase from NOK 1 523 per tonne in 2022 towards a long term price of NOK 2 000 (real 2020) per tonne from 2030 in line with price estimates presented by the Norwegian authorities in late 2021. NOx prices are estimated to increase from approximately NOK 17 per kg in 2022 to a level of approximately 28 NOK per kg from 2030. A future change in how the world will react in light of the goals set in the Paris Agreement could have adverse effects on the value of OKEA's oil and gas assets. Sensitivities on changes to environmental cost is reflected in the table below.

Impairment testing of technical goodwill, ordinary goodwill, fixed assets and ROU assets

Based on the company's impairment assessments NOK 94 millinon in impairment of the Yme asset was recognised in the first quarter. The impairment was mainly driven by indication of reduced well potential.

No impairment of technical and ordinary goodwill or ROU assets was required in the three month period ending on 31 March 2023.

Sensitivity analysis

The table below shows what the impairment pre-tax would have been in the first quarter under various alternative assumptions, assuming all other assumptions

		Alternative calculations of pre tax impairment/reversal (-) Q1 2023 (NOK '000)		Increase / decrease (-) of pre tax impairment Q1 2023 (NOK '000)
Assumptions Change	Increase in assumption	Decrease in assumption	Increase in assumption	Decrease in assumption
Oil and gas price +/- 10%	-376 006	594 578	-470 423	500 161
Currency rate USD/NOK +/- 1.0 NOK	-386 311	576 514	-480 728	482 097
Discount rate +/- 1% point	126 198	62 082	31 781	-32 335
+/- 20% Environmental cost (CO2 and NOx)	164 678	24 155	70 261	-70 261

Note 13 General and administrative expenses

Amounts in NOK `000	Q1 2023	Q4 2022	Q1 2022	2022
Salary and other employee benefits expenses	230 156	225 766	127 897	620 072
Consultants and other operating expenses	142 657	139 524	53 997	336 209
Allocated to operated licences	-336 811	-270 731	-155 315	-725 343
Allocated to exploration and production expenses	-8 276	-7 466	-3 999	-18 336
Total general and administrative expenses	27 726	87 093	22 581	212 602

Note 14 Financial items

Amounts in NOK `000	Q1 2023	Q4 2022	Q1 2022	2022
Interest income	10 122	11 005	1 670	22 165
Unwinding of discount asset retirement reimbursement right
(indemnification asset)	41 943	35 903	20 202	103 876
Finance income	52 065	46 908	21 872	126 041
Interest expense and fees from loans and borrowings	-36 396	-33 407	-53 435	-200 371
Capitalised borrowing cost, development projects	15 196	10 800	2 938	28 059
Interest expense shareholder loan	-	-57	-	-57
Other interest expense	-45	-544	-1 641	-5 268
Unwinding of discount asset retirement obligations	-45 134	-41 009	-21 141	-115 645
Loss on buy-back/early redemption bond loan	-	-	-4 361	-23 535
Loss on financial investments	-	7	-634	-64
Other financial expense	-5 268	-4 162	-4 441	-17 174
Finance costs	-71 646	-68 373	-82 715	-334 055
Exchange rate gain/loss (-), interest-bearing loans and borrowings	-106 329	172 037	18 950	-296 881
Net exchange rate gain/loss (-), other	76 511	-56 913	-18 916	193 780
Net exchange rate gain/loss (-)	-29 818	115 124	35	-103 101
Net financial items	-49 398	93 660	-60 808	-311 115

Note 15 Asset retirement reimbursement right

Asset retirement reimbursement right at 1 January 2023 (indemnification asset)	3 662 122
Changes in estimates	-
Effect of change in the discount rate	57 980
Asset retirement costs from billing, reimbursement from Shell	-1 914
Unwinding of discount	41 943
Asset retirement reimbursement right at 31 March 2023 (indemnification asset)	3 760 131
Of this:
Asset retirement reimbursement right, non-current	3 760 131
Asset retirement reimbursement right, current	-
Asset retirement reimbursement right at 31 March 2023 (indemnification asset)	3 760 131

Asset retirement reimbursement right consists of a receivable from the seller Shell from OKEA's acquisition of Draugen and Gjøa assets in 2018, and a receivable from the seller Wintershall Dea from OKEA's acquisition of the Brage asset in 2022.

Receivable from the seller Shell from OKEA's acquisition of Draugen and Gjøa assets in 2018:

The parties agreed that the seller Shell will cover 80% of the actual abandonment expenses for the Draugen and Gjøa fields up to a predefined after-tax cap amount of NOK 757 million (2022 value) subject to Consumer Price Index (CPI) adjustment. The present value of the expected payments is recognised as a pre-tax receivable from the seller.

In addition, the seller has agreed to pay OKEA an amount of NOK 441 million (2022 value) subject to a CPI adjustment according to a schedule based on the percentage of completion of the decommissioning of the Draugen and Gjøa fields.

The net present value of the receivable is calculated using a discount rate of 3.9% (year end 2022: 3.9%).

Receivable from the seller Wintershall Dea from OKEA's acquisition of the Brage asset in 2022: The parties have agreed that Wintershall Dea will retain responsibility for 80% of OKEA's share of total decommissioning costs related to the Brage Unit, limited to

an agreed pre-tax cap of NOK 1520.6 million subject to index regulation.

The net present value of the receivable is calculated using a discount rate of 5.7% (year end 2022: 6.4%).

Note 16 Share capital

Amounts in NOK `000

Number of shares	Ordinary shares
Outstanding shares at 1 January 2023	103 910 350
New shares issued during 2023	-
Number of outstanding shares at 31 March 2023	103 910 350
Nominal value NOK per share at 31 March 2023	0.1
Share capital NOK at 31 March 2023	10 391 035

Dividend paid in Q1 2023 is NOK 103.9 million.

Note 17 Trade and other receivables

Amounts in NOK `000	31.03.2023	31.12.2022	31.03.2022
Accounts receivable and receivables from operated licences*	666 723	234 811	66 277
Accrued revenue	335 981	422 885	415 786
Prepayments	342 721	79 009	43 739
Working capital and overcall, joint operations/licences	268 722	386 637	223 390
Underlift of petroleum products	163 041	588 934	242 698
VAT receivable	15 342	21 049	3 922
Accrued interest income	-	-	686
Fair value forward contracts, gas	-	10 578	-
Fair value put/call options, oil	505	-	-
Total trade and other receivables	1 793 034	1 743 901	996 499

* There is no provision for bad debt on receivables.

** Prepayments at 31.03.2023 include a prepayment of USD 25 million to Equinor Energy AS in connection with an agreement with Equinor to acquire an 28% working interest in PL037 (Statfjord Area) with effective date 1 January 2023. The transaction is conditional upon Norwegian governmental approval and is expected to be completed in Q4 2023.

Note 18 Cash and cash equivalents

Cash and cash equivalents:

Amounts in NOK `000	31.03.2023	31.12.2022	31.03.2022
Bank deposits, unrestricted	1 547 485	1 010 492	2 038 904
Bank deposit, time deposit	-	-	400 000
Bank deposit, restricted, employee taxes	18 468	31 224	10 856
Bank deposit, restricted, deposit office leases	14 824	14 824	14 810
Bank deposit, restricted, other	52 817	47 486	5 006
Total cash and cash equivalents	1 633 594	1 104 026	2 469 576

Note 19 Asset retirement obligations

Amounts in NOK `000
Provision at 1 January 2023	5 915 084
Additions	-
Changes in estimates	-
Effects of change in the discount rate	-
Asset retirement costs from billing	-2 020
Unwinding of discount	45 134
Asset retirement obligations at 31 March 2023	5 958 198
Of this:
Asset retirement obligations, non-current	5 958 198
Asset retirement obligations, current	-
Asset retirement obligations at 31 March 2023	5 958 198

Asset retirement obligations

Provisions for asset retirement obligations represent the future expected costs for close-down and removal of oil equipment and production facilities. The provision is based on the company's best estimate. The net present value of the estimated obligation is calculated using a discount rate of 3.1% (year end 2022: 3.1%). The assumptions are based on the economic environment at balance sheet date. Actual asset retirement costs will ultimately depend upon future market prices for the necessary works which will reflect market conditions at the relevant time. Furthermore, the timing of the close-down is likely to depend on when the field ceases to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain.

For recovery of costs of decommissioning related to assets acquired from Shell and Wintershall Dea, reference is made to note 15.

Note 20 Spare parts, equipment and inventory

Amounts in NOK `000	31.03.2023	31.12.2022	31.03.2022
Inventory of petroleum products	193 152	511 509	127 321
Spare parts and equipment	279 634	288 824	132 763
Total spare parts, equipment and inventory	472 786	800 333	260 083

Note 21 Trade and other payables

Amounts in NOK `000	31.03.2023	31.12.2022	31.03.2022
Trade creditors	48 428	126 044	18 660
Accrued holiday pay and other employee benefits	110 086	146 858	62 306
Working capital, joint operations/licences	779 796	1 061 014	578 626
Overlift of petroleum products	97 050	47 952	17 455
Accrued interest bond loans	33 003	5 175	27 556
Other provisions, current (see note 28)	32 685	29 810	-
Prepayments from customers	277 748	506 637	3 868
Fair value forward contracts, gas	-	-	3 438
Fair value forward contracts, foreign exchange*	9 245	-	-
Loan from shareholder OKEA Holdings Ltd	1 428	1 428	1 371
Accrued consideration from acquisitions of interests in licences	-	-	10 000
Other accrued expenses	158 040	294 740	110 788
Total trade and other payables	1 547 509	2 219 658	834 070

* OKEA has sold a total of GBP 127.5 million against NOK forward at NOK/GBP rates in the range of 12.81-12.87 with expiry dates in Q2-Q4 2023.

Note 22 Interest bearing bond loans

	Bond loan
Amounts in NOK `000	OKEA03	Total
Interest bearing bond loans at 1 January 2023	1 178 610	1 178 610
Amortisation of transaction costs	1 508	1 508
Foreign exchange movement	75 132	75 132
Interest bearing bond loans at 31 March 2023	1 255 250	1 255 250
Of this:
Interest bearing bond loans, non-current	1 255 250	1 255 250
Interest bearing bond loans, current	-	-
Interest bearing bond loans at 31 March 2023	1 255 250	1 255 250

	Bond loan
Amounts in NOK `000	OKEA03	Total
Interest bearing bond loans at 1 January 2023	1 178 610	1 178 610
Cash flows:
Gross proceeds from borrowings	-	-
Transaction costs	-	-
Repayment/buy-back of borrowings	-	-
Total cash flows:	-	-
Non-cash changes:
Amortisation of transaction costs	1 508	1 508
Foreign exchange movement	75 132	75 132
Interest bearing bond loans at 31 March 2023	1 255 250	1 255 250

Bond loan OKEA03

During 2023 the company has been in full compliance with the covenants under the bond agreements.

From 01.01.2022 the covenants comprise of: (i) Leverage ratio shall not exceed 2:1

(ii) Capital employment ratio above 35%

(iii) Minimum free liquidity of USD 10 million

Maturity date of OKEA03 is 11 December 2024.

Note 23 Other interest bearing liabilities

In October 2021 the Yme licence completed acquisition of the Inspirer jack-up rig through a bareboat charter (BBC) agreement with Havila Sirius AS (Havila). The part of the lease payments to Havila corresponding to the purchase price paid by Havila to Maersk is considered as an investment in a rig with a corresponding liability, while the remaining amount of the total payments is treated as interest expenses. This treatment is based on the underlying assessment that the reality of the transaction is that it is an investment in a rig financed with a interest bearing liability, rather than a lease. OKEA's proportionate share of the investment and corresponding liability is USD 55.95 million.

The Yme licence has the right and the obligation to purchase the rig at the end of the lease period for NOK 1. In addition the Yme licence has the unconditional obligation to purchase the rig from Havila in case of any termination event during the lease period. The purchase price will then be the remaining amount paid by Havila to Maersk plus interest and other costs. The Yme licence also has the option to purchase the rig at any time during the lease period for the same price.

The liability carries a implicit interest rate of 5.21% p.a., and will be repaid with the lease payments to Havila with the last lease payment in October 2031. Repsol S.A. (RSA) is the parent company of the Yme licence operator Repsol Norge AS. On behalf of Yme, RSA has issued a parent company guarantee for the future lease payments to Havila.

	Liability
Amounts in NOK `000	Yme rig	Total
Other interest bearing liabilities at 1 January 2023	507 952	507 952
Repayments	-11 165	-11 165
Foreign exchange movement	31 197	31 197
Other interest bearing liabilities at 31 March 2023	527 985	527 985
Of this:
Other interest bearing liabilities, non-current	478 502	478 502
Other interest bearing liabilities, current	49 482	49 482
Other interest bearing liabilities at 31 March 2023	527 985	527 985
	Liability
Amounts in NOK `000	Yme rig	Total
Other interest bearing liabilities at 1 January 2023	507 952	507 952
Cash flows:
Gross proceeds from borrowings	-	-
Repayment of borrowings	-11 165	-11 165
Total cash flows:	-11 165	-11 165
Non-cash changes:
Foreign exchange movement	31 197	31 197
Other interest bearing liabilities at 31 March 2023	527 985	527 985

Note 24 Leasing

The company has entered into operating leases for office facilities. In addition, as operator of the Draugen field, the company has on behalf of the licence entered into operating leases for logistic resources such as supply vessel with associated remote operated vehicle (ROV), base and warehouse for spare parts and hence gross basis of these lease debts are recognised.

Amounts in NOK `000
Lease liability 1 January 2023	262 052
Additions lease contracts	-
Accretion lease liability	4 216
Payments of lease debt and interest	-12 547
Total lease debt at 31 March 2023	253 721

Break down of lease liability
Short-term (within 1 year)	49 643
Long-term	204 078
Total lease liability	253 721

Undiscounted lease liabilities and maturity of cash outflows:

Amounts in NOK `000	31.03.2023
Within 1 year	50 190
1 to 5 years	164 266
After 5 years	157 806
Total	372 261

Future lease payments related to leasing contracts entered into as an operator of the Draugen field are presented on a gross basis.

Note 25 Commodity contracts

Amounts in NOK `000	31.03.2023	31.12.2022	31.03.2022
Premium commodity contracts	631	-	-
Accumulated unrealised gain/loss (-) commodity contracts included in other operating income / loss(-)	-126	10 578	-3 438
Short-term derivatives included in assets/liabilities (-)	505	10 578	-3 438

The company uses derivative financial instruments (put and call options) to manage exposures to fluctuations in commodity prices. Put options are purchased to establish a price floor for a portion of future production of petroleum products. In addition a price ceiling is established by selling call options, which reduces the net premium paid for hedging.

At 31 March 2023 there are no outstanding financial forward contracts gas (without physical delivery of gas). All outstanding contracts at 31 December 2022 expired in Q1 2023.

In addition OKEA has entered into non-financial contracts with physical delivery of gas in 2023 at fixed price. At 31 March 2023 the outstanding contracts are 2 438 800 therms of gas with delivery in Q2 2023 at fixed price 504.5 GBp/therm. Revenue from these contracts will be recognised at delivery of the gas.

Note 26 Financial investments

Amounts in NOK `000	31.03.2023	31.12.2022	31.03.2022
Investments in money-market funds and combination funds	-	-	209 326
Total financial investments	-	-	209 326

Note 27 Business combinations

Acquisition of a 35.2% interest in Brage, 6.4615% interest in Ivar Aasen and 6% interest in Nova, completed in Q4 2022

On 1 November 2022 OKEA completed the acquisition of a 35.2% working interest in the Brage field, a 6.4615% working interest in the Ivar Aasen field and a 6% working interest in the Nova field from Wintershall Dea Norge AS.

The purchase price allocation (PPA) presented below is based on a updated completion statement from Q1 2023 compared to the PPA presented in Q4 2022. At this stage, the purchase price allocation is preliminary. As a result, the final PPA and the impact on the financial statements from the transaction may differ. The final PPA will be completed within 12 months of the acquisition at the latest.

Amounts in NOK `000	PPA Q4 2022	Changes Q1 2023	Updated PPA
Assets
Oil and gas properties	1 791 614	-	1 791 614
Receivables on seller*	947 255	-	947 255
Net working capital	441 429	-	441 429
Income tax receivable (reduced tax payable)	165 808	16 574	182 382
Right-of-use assets	17 315	-	17 315
Total assets	3 363 421	16 574	3 379 996
Liabilities
Deferred tax liabilities	633 483	-	633 483
Asset retirement obligations	1 926 780	-	1 926 780
Contingent consideration**	116 041	-	116 041
Lease liability	17 315	-	17 315
Total liabilities	2 693 618	-	2 693 618
Total identifiable net assets at fair value	669 803	16 574	686 377
Total consideration	1 165 383	12 189	1 177 572
Goodwill	495 580	-4 385	491 194
Goodwill consist of:
Negative ordinary goodwill	-500 811	-	-500 811
Technical goodwill	996 390	-4 385	992 005
Total goodwill	495 580	-4 385	491 194

Note 28 Other provisions

68 917
-
15 631
84 548
51 864
32 685
84 548

OKEA shall pay to Wintershall Dea an additional contingent consideration based on an upside sharing arrangement subject to oil price level during the period 2022- 2024. The provision for the contingent consideration is measured at fair value with changes in fair value recognised in the income statement. The fair value is estimated using an option pricing methodology, where the expected option payoff is calculated at each future payment date and discounted back to the balance date.

Note 29 Fair value of financial instruments

It is assessed that the carrying amounts of financial assets and liabilities, except for interest bearing bond loans, is approximately equal to its fair values.

For interest bearing bond loan OKEA03, the fair value is estimated to be NOK 1,276 million at 31 March 2023. The OKEA03 bond loan is listed on the Oslo Stock Exchange and the fair value is based on the latest quoted market price (level 2 in the fair value hierarchy according to IFRS 13) as per balance sheet date.

Fair values of put/call options oil and forward contracts foreign exchange are based on quoted market prices at the balance sheet date (level 2 in the fair value hierarchy). The put/call options oil and the forward contracts foreign exchange are carried in the statement of financial position at fair value.

Note 30 Events after the balance sheet date

There are no subsequent events with significant impacts that have occured between the end of the reporting period and the date of this report that are not already reflected or discloused in these financial statements.

Alternative performance measures

Reconciliations

EBITDA	Q1 2023	Q4 2022	Q1 2022	2022
Amounts in NOK `000	3 months	3 months	3 months	12 months
Profit / loss (-) from operating activities	1 170 011	565 017	1 347 853	3 526 080
Add: depreciation, depletion and amortisation	327 174	270 243	157 780	769 359
Add: impairment	94 417	251 152	-362 597	497 584
EBITDA	1 591 602	1 086 412	1 143 036	4 793 024

EBITDAX	Q1 2023	Q4 2022	Q1 2022	2022
Amounts in NOK `000	3 months	3 months	3 months	12 months
Profit / loss (-) from operating activities	1 170 011	565 017	1 347 853	3 526 080
Add: depreciation, depletion and amortisation	327 174	270 243	157 780	769 359
Add: impairment / reversal of impairment	94 417	251 152	-362 597	497 584
Add: exploration and evaluation expenses	23 561	190 268	92 676	327 506
EBITDAX	1 615 163	1 276 680	1 235 712	5 120 530

Production expense per boe	Q1 2023	Q4 2022	Q1 2022	2022
Amounts in NOK `000	3 months	3 months	3 months	12 months
Productions expense	517 868	522 268	287 294	1 616 020
Less: processing tariff income	-32 061	-39 707	-24 146	-131 596
Less: joint utilisation of resources	-2 537	-10 326	-5 944	-37 512
Divided by: produced volumes (boe)	1 998 902	1 829 621	1 341 671	6 108 800
Production expense NOK per boe	241.8	258.4	191.7	236.8

Net interest-bearing debt
Amounts in NOK `000	31.03.2023	31.12.2022	31.03.2022
Interest bearing bond loans	1 255 250	1 178 610	2 000 577
Other interest bearing liabilities	478 502	462 078	440 710
Other interest bearing liabilities, current	49 482	45 874	38 845
Less: Cash and cash equivalents	-1 633 594	-1 104 026	-2 469 576
Net interest-bearing debt	149 640	582 537	10 556

Net interest-bearing debt excl. other interest bearing liabilities
Amounts in NOK `000	31.03.2023	31.12.2022	31.03.2022
Interest bearing bond loans	1 255 250	1 178 610	2 000 577
Less: Cash and cash equivalents	-1 633 594	-1 104 026	-2 469 576
Net interest-bearing debt excl. other interest bearing liabilities	-378 345	74 584	-468 999

Definitions

EBITDA is defined as earnings before interest and other financial items, taxes, depreciation, depletion, amortisation and impairments.

EBITDAX is defined as earnings before interest and other financial items, taxes, depreciation, depletion, amortisation, impairments and exploration and evaluation expenses.

Net interest-bearing debt is book value of current and non-current interest-bearing loans, bonds and other interest-bearing liabilities excluding lease liability (IFRS 16) less cash and cash equivalents.

Net interest-bearing debt excl. other interest bearing liabilities is book value of interest-bearing bond loans less cash and cash equivalents.

Production expense per boe is defined as production expense less processing tariff income and joint utilisation of resources income for assets in production divided by produced volumes. Expenses classified as production expenses related to various preparation for operations on assets under development are excluded.

OKEA ASA is a leading mid- to late-life operator on the Norwegian continental shelf (NCS).

OKEA finds value where others divest and has an ambitious strategy built on growth, value creation and capital discipline.

OKEA ASA Kongens gate 8 7011 Trondheim