Panoro Energy ASA

Annual Report • Apr 27, 2023

CREATING ONE OF THE WORLD'S LEADING INDEPENDENT LISTED AFRICAN E&Ps

Page: 1

ANNUAL REPORT 2022

APRIL 2023

www.panoroenergy.com

PANORO ENERGY

2022 ANNUAL REPORT | APRIL 2023

INTRODUCTION

Panoro Energy ASA is an independent exploration and production company listed on the main board of the Oslo Stock Exchange with the ticker PEN.

Panoro holds production, exploration and development assets in Africa, namely interests in Block-G, Block S and Block EG-01, offshore Equatorial Guinea, the Dussafu License offshore southern Gabon, the TPS operated assets, Sfax Offshore Exploration Permit and Ras El Besh Concession, offshore Tunisia, and interests in an exploration Block 2B, and Technical Co-operation Permit 218 in South Africa.

INTRODUCTION 2
FINANCIAL AND OPERATIONAL HIGHLIGHTS 4
COMPANY SUMMARY 5
CEO LETTER 6
DIRECTORS' REPORT 20229
ANNUAL STATEMENT OF RESERVES 2022 28
ANNEX RESERVES STATEMENT 32
CORPORATE GOVERNANCE33
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME 37
CONSOLIDATED STATEMENT OF FINANCIAL POSITION 38
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY 40
CONSOLIDATED CASH FLOW STATEMENT 41
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 42
PANORO ENERGY ASA PARENT COMPANY INCOME STATEMENT 91
PANORO ENERGY ASA PARENT COMPANY BALANCE SHEET92
PANORO ENERGY ASA PARENT COMPANY STATEMENT OF CASH FLOW 93
PANORO ENERGY ASA NOTES TO THE FINANCIAL STATEMENTS94
ANNUAL REPORT ON EXECUTIVE REMUNERATION POLICIES 104
STATEMENT OF DIRECTORS' RESPONSIBILITY108
AUDITOR'S REPORT 109
STATEMENT ON CORPORATE GOVERNANCE IN PANORO ENERGY ASA 114
GLOSSARY AND DEFINITION 123

FINANCIAL AND OPERATIONAL HIGHLIGHTS

Financial highlights - continuing operations (in USD 000)	2022	2021
Oil Revenue	180,267	113,708
Underlying operating profit/(loss) before tax	60,522	69,744
EBITDA	127,188	63,701
EBIT	81,223	34,920
Net Profit/(Loss)	18,635	42,312
Operational metrics - continuing operations	2022	2021
Oil sales (bbls) net	1,815,598	1,578,571
Average production - working interest (bopd)	7,498	7,495
		35.8
2P Reserves (MMbbls) net working interest	35.6

OPERATIONAL AND CORPORATE HIGHLGHTS

Working interest production averaged 7,498 bopd

Company controlled safety performance maintained with no major safety incidents for the past four years

35.6 MMbbls 2P reserves at 31/12/22 and 23.9 MMbbls 2C resources

Strong financial performance with reported revenue of USD 188.6 million

Gabon production drilling campaign commenced and well operations completed in Equatorial Guinea and Tunisia

Hibiscus / Ruche Phase 1 development progressing with installation of MaBoMo platform, and first oil achieved in April 2023

Extension of the Block G PSC, Equatorial Guinea, until end of 2040 Awarded 100% interest and operatorship in TCP 218, onshore South Africa Farmed in to 12% interest in Block S offshore Equatorial Guinea Awarded 56% interest and operatorship in Block EG-01 offshore Equatorial Guinea

COMPANY SUMMARY

ASSETS

	Equatorial Guinea:
	Interest in Block G, offshore	14.25%
	Interest in Block S, offshore	12%
	Interest in Block EG-01, offshore	56%
	Gabon:
	Interest in Dussafu Marin permit, offshore	17.4997%
	Tunisia:
	Interest in TPS assets	29.4%
	Interest in the Sfax Offshore Exploration Permit ("SOEP") – Operator	52.5%
	Non-operated interest in the Hammamet Offshore Exploration Permit (under relinquishment)	27.6%
	South Africa:
	Interest in Block 2B, offshore	12.5%

Interest in TCP 218, onshore 100%

Detailed information on all the assets is included in the Operations section of the Directors report on page 9.

PANORO OFFICES

The Company maintains its registered address in Oslo and has offices in London, Malabo, Libreville and Tunis.

CEO LETTER

Dear Fellow Shareholders:

I am pleased to present our Annual Report for 2022, a year in which Panoro consolidated its position as a significant independent oil producer in Africa. Our strong operational and financial performance reflects the underlying quality of our diversified portfolio of producing assets in Equatorial Guinea, Gabon and Tunisia alongside the commitment and focus of the entire Panoro team on achieving results responsibly and in a cost-effective manner. We have continued to invest in organic production and development opportunities that will drive material near term growth and expanded our acreage position selectively around our core production hubs in line with our infrastructure led exploration strategy.

Importantly 2022 was another year of generally very good health, safety and environmental performance. The health and safety of our people, contractors and host communities together with minimising our environmental impact continue to be at the core of how we conduct our business. We promote a strong safety culture at every Panoro location. In Tunisia, where Panoro has joint operating responsibilities alongside the Tunisia national oil company ETAP, we have worked successfully to deliver safe and reliable processes, reacting in the latter part of the year to indications of declining performance with some organisational changes and by introducing a programme of activities to lift performance. Gabon and Equatorial Guinea are non-operated positions for Panoro. Within our role as an active JV partner, we support the respective operators BW Energy and Trident Energy who have also maintained an excellent HSE performance.

Macro Environment

2022 was overshadowed by the Russia - Ukraine war and the shockwaves it sent through the global economy, commodity markets and supply chains meaning that crude oil prices remained extremely volatile during the year. Brent crude started the year at USD 78 per barrel and increased steadily as concerns over a shortage of supply to meet a post-Covid demand recovery dominated sentiment. Brent oil peaked at a high of USD 133 per barrel in March, a level not seen since 2008, as the war in Ukraine and associated geopolitical tensions further exacerbated supply concerns. However, by the second half of the year inflationary pressures and tightening of monetary policies prompted recession fears across major hydrocarbon consuming economies which, combined with sustained draws on strategic crude oil reserves, led to a weaking of prices throughout the remainder of the year with Brent crude exiting 2022 at USD 83 per barrel and averaging USD 101 per barrel over the full year.

Strategic focus on Africa

The events of 2022 put sharply into focus the importance of security of energy supply in order to reliably and affordably meet energy demands, underpin economic stability and social welfare. This inevitably cast a spotlight on Africa as a crucial source of supply, for both international and domestic markets, with its vast remaining oil and gas reserves and large undiscovered potential. African crude oil grades have remained in high demand with refiners and the continent's abundant discovered gas volumes, widely recognised as a key energy transition fuel, have the potential to supply international markets and domestic gas-to-power projects alike long into the future.

However, to unlock Africa's full energy potential significant challenges must be overcome in terms of infrastructure development, capital investment and capacity building. Equally important is the responsible ongoing management of legacy assets that incumbent owners may wish to exit for a variety of reasons such as materiality and capital allocation priorities. Panoro is a specialist Africa focused company that is well positioned to play its part. As a conscientious asset owner with robust corporate governance systems and access to capital Panoro is a credible counterparty to potential sellers of assets that can be trusted to responsibly manage such legacy assets and where possible improve performance over the asset life cycle. Our management and board all posess extensive and relevent industry expertise combined with deep African experience which equips Panoro to deliver its growth strategy in Africa.

Financials and Corporate Activity

The combination of higher year-on-year oil prices and full-year contribution from the enlarged portfolio following the production acquisitions in Equatorial Guinea and Gabon which completed during 2021 drove record financial performance. Revenue in 2022 increased by 58% year-on-year to USD 188.6 million generated from crude sales of 1.8 million barrels sold at an average realised price of USD 99 per barrel after customary adjustments and fees. EBITDA was up 100% at USD 127.2 million while underlying operating profit before tax (after adjusting for certain non-cash and unrealised gains/losses) was down 13% at USD 60.5 million. Reported net profit for the year stood at USD 19.9 million. Cash flow from operations for 2022 stood at USD 113.2 million, an increase of 61% year-on-year, against capital expenditures of USD 68.3 million.

We have maintained a conservative balance sheet and ended the year with cash at bank of USD 32.7 million and gross debt of USD 79.5 million after principal repayments of USD 18.8 million were made, resulting in a net debt position of USD 46.8 million. This represents a net debt to EBITDA ratio of just 0.37x.

2022 corporate activity highlights included completion of the sale of a 6.502% interest in OML 113 offshore Nigeria to PetroNor E&P ASA for an upfront consideration of USD 10 million plus a contingent consideration of up to USD 16.67 million based on future gas production volumes. The upfront consideration was received via the allotment of new PetroNor E&P ASA shares which were distributed as a dividend in specie to Panoro shareholders in August.

In October we expanded our acreage position in Equatorial Guinea through the farm-in to a 12% participating interest in Block S which is located in the immediate vicinty of our producing Ceiba Field and Okume Complex on Block G. Post period end in February 2023 we were also awarded a 56% participating interest and operatorship of Block EG-01 which borders both Block G and Block S. These blocks are a natural and complementary bolt-on to our portfolio in Equatorial Guinea and in line with our infrastructure led exploration strategy, increasing our access to a large inventory of oil prospects and leads within tie back distance of existing production facilities for a modest financial exposure. The Akeng Deep exploration well is planned on Block S in 2024 to test a play in the Albian, targeting an estimated gross mean resource of approximately 180 million barrels of oil equivalent.

In August Panoro was awarded a 100% interest in Technical Co-operation Permit ("TCP") 218 located onshore northern Free State province, South Africa. TCP 218 covers a surface area of approximately 6,608 km² in the highly prospective Northern Karoo Basin which has a proven working natural gas and Helium system with nearby analogues including the producing Virginia gas field and the Smaldeel gas field. The TCP award is for a period of 12 months during which time Panoro will have exclusive rights to undertake desktop studies of existing data sources and field work in order to evaluate the prospectivity of the permit area, after which we will have the option to apply for an Exploration Right covering the permit area. This represents a ground-floor entry at minimal cost which will allow us to incubate a potentially exciting natural gas and Helium play. While the technical fundamentals and market opportunities for both natural gas and Helium in South Africa represent a compelling proposition, the renewable nature of the resource, possibility to displace coal fired power and many applications of Helium make for an equally compelling investment from an ESG perspective.

Operations

Working interest production in 2022 averaged 7,498 bopd compared to 7,582 bopd in 2021 (on a proforma basis). We undertook an active portfolio-wide work programme in 2022.

In Equatorial Guinea well workovers were undertaken including an electrical submersible pump conversion and behind pipe perforations in addition to numerous field life extension and asset integrity projects. In May the Block G Production Sharing Contract was extended until end 2040, increasing the timeframe in which the joint venture can work to unlock the substantial remaining resources we believe to be present. As part of our ongoing efforts in this respect a drilling rig was contracted for a three well infill drilling campaign at Block G which is expected to commence in Q4 2023.

In Gabon activities were primarily focused on delivery of the Hibiscus Ruche Phase I development. The BW MaBoMo production facility was successfully installed on location together with flexible pipelines and risers connecting the new production facility with the FPSO BW Adolo moored at the producing Tortue field. Development drilling commenced post period end with the first of six planned production wells completed and put onstream in April as planned. A new gas lift compressor unit to support production from all six existing production wells on the Tortue field was also delivered and has been installed onboard the FPSO to be commissioned shortly after first oil from Hibiscus Ruche Phase I.

In Tunisia a number of well operations and facilities upgrades to enhance and optimise production were undertaken at the Guebiba, Rhemoura and Cercina fields. A team comprising ETAP and Panoro staff also progressed a subsurface re-modelling exercise for the Guebiba and Rhemoura fields which is expected to lead to further field optimisation and development drilling recommendations. Post period end Panoro jointly with its partner ETAP received initial approval from the Tunisian Consultative Committee on Hydrocarbons (CCH) and is now awaiting Ministerial ratification for an additional period of 16 years.

Inaugural Sustainability Report

We are dedicated to ensuring that the Company's presence has a positive impact for all stakeholders. Our industry plays a vital role in the socioeconomic development of the countries in which we operate, and it is our duty to be a responsible corporate citizen. We are also mindful of the impact the energy transition might have on the economies that rely on oil and gas revenues and will work closely with our host governments and other stakeholders to ensure a steady, safe and effective energy transition can occur in Africa.

In 2022 we formalised our approach to managing ESG matters to meet the expectations of our stakeholders. As part of this the Board constituted a new Sustainability Committee which oversees Panoro's conduct, performance and reporting on ESG and

other sustainability matters. It also serves to integrate the broad spectrum of sustainability considerations into our growth strategy and key business decisions.

In line with good industry practice and in response to stakeholder expectations I am pleased to say that in parallel with our Annual Report we have this year also released our inaugural Sustainability Report which addresses our ongoing activities and provides a baseline of data against which we will similarly report and measure our performance each year.

Delivering Shareholder Returns

I am pleased to report that Panoro's share price closed the year up 26.9%, outperforming the Oslo All Share Index which ended the year up 3.2%.

Consistent with the Company's strategy to create and deliver shareholder value, the Panoro Board is committed to sustainable shareholder returns, balanced alongside future organic and inorganic growth. Our strong performance in 2022 has allowed us to commence dividend payments with Panoro's inaugural cash dividend declared in February 2023 and paid in March 2023.

Outlook

We have now entered an intensive phase of organic growth with continual drilling activity throughout 2023 and into 2024 which will see at least 10 wells being drilled in Gabon and Equatorial Guinea. This drilling programme will materially increase Panoro's working interest oil production and cash flow allowing us to return a substantial amount of cash to shareholders, continue to deleverage the business and at the same time position us to invest in further organic growth projects and opportunistically capitalise on value accretive new business opportunities should they arise.

Finally, we would like to wholeheartedly thank our shareholders, our strategic partners, our dedicated staff and more generally all our stakeholders for their ongoing support.

John Hamilton CEO, Panoro Energy ASA

27 April 2023

DIRECTORS' REPORT 2022

ABOUT PANORO

Panoro Energy ASA is an independent exploration and production (E&P) company listed on the Oslo Stock Exchange with ticker PEN. The Company holds production, development, and exploration assets in North, West and South Africa.

OPERATIONS

Block G

Panoro has a 14.25% interest in the Ceiba field and Okume Complex in Block G.

The Ceiba Field and Okume Complex assets comprise six oil fields offshore Equatorial Guinea. The Ceiba Field is located in 600 to 800 m of water depth on the slope of the southern Rio Muni Basin approximately 35 km offshore. Oil production commenced in 2000 and the field was developed in phases with the production wells tied back to the Ceiba FPSO through a system of six subsea manifolds and flowlines. The produced liquids are processed on the FPSO for export. The field has 13 active production wells and 8 water injectors. By the end of 2022, the field had produced a total of 211.2 MMbbls gross. The Okume Complex consists of five separate oil fields, Okume, Ebano, Oveng, Akom North and Elon, located in 50 to 850 m of water depth. The Okume Complex fields were discovered in 2001 and 2002 and developed utilising four fixed jackets in the Elon field and two tension leg platforms to develop remaining fields. All fields are tied back to a central processing facility at one of the Elon platforms. The processed oil is then transported via a 25 km pipeline to the Ceiba FPSO for export. The Okume Complex fields have 34 active production wells and 8 water injectors. By the end of 2022, the Okume Complex fields had produced a total of 257.9 MMbbls gross.

In 2022, gross production averaged 10,355 bopd on Ceiba and 20,560 bopd on Okume, both increased compared to 2021

A time extension of the Production Sharing Contract ("PSC") until 31 December 2040 covering both the producing Ceiba and Okume Complex Fields was agreed in May 2022. Prior to the extension the PSC expiry for the Ceiba Field was 2029 and for the Okume Complex field 2034. Panoro's net 2P reserves have increased by 2.7 million barrels as a result of the PSC extension.

At Ceiba, maintenance projects continued including key upgrades to subsea systems which will enable the field to operate until the new PSC expiry at the end of 2040.

On Okume, the upgrade project completed increasing the power generation, process treatment and water injection capacity on the field. In addition, a number of well workovers were completed.

Plans for 2023 are focused on an infill well campaign, with drilling expected to commence in the second half of the year. The first well is expected to be online by the end of the fourth quarter with subsequent wells online early in 2024.

In March 2023, NSAI completed a reserves assessment of the Block G assets. As of the end of 2022 Block G was estimated to contain a gross 1P reserve of 62.4 MMbbls, a 2P reserve of 100.0 MMbbls and a 3P reserve of 149.1 MMbbls. In addition to these reserves NSAI also certified gross unrisked 1C Contingent Resources of 42.1 MMbbls, gross unrisked 2C Contingent Resources of 93.0 MMbbls, and gross unrisked 3C Contingent Resources of 154.3 MMbbls in the Block G licence area.

Total 2P+2C reserves and resources in Block G net to Panoro is 27.6 MMbbls.

Block S

Panoro farmed into a 12% interest in Block S in March 2023. Activities in Block S are the planning for a Kosmos Energy operated Akeng Deep exploration well in 2024 to test a play in the Albian. The well is targeting an estimated gross mean resource of approximately 180 million barrels of oil equivalent in close proximity to existing infrastructure at Block G.

Block EG-01

Panoro was awarded a 56% operated interest in Block EG-01 in March 2023 alongside JV partners Kosmos Energy and GEPetrol. Block EG-01 is located in water depths ranging from 30 metres to 500 metres, mainly shallow, and is covered by high quality 3D seismic. The partners have been awarded block EG-01 for an initial period of three years during which they will conduct subsurface studies based on existing seismic data to further define and evaluate the prospectivity of the block. Following this, the partners will have the option to enter into a further two-year period, during which they will undertake to drill one exploration well.

Operations in Gabon2021.

Panoro Energy are partners in the Dussafu license, a production and development license in southern Gabon, operated by BW Energy Gabon. Panoro's interest in the license is 17.5%

The Dussafu Marin Permit lies at the southern end of the South Gabon subbasin in water depths ranging from 100 to 500 m. There are seven oil fields within the EEA: Moubenga, Walt Whitman, Ruche, Ruche North East, Tortue, Hibiscus and Hibiscus North. The latter five fields were discovered by Panoro and JV partners in the last 11 years.

In 2014, an Exclusive Exploitation Authorization (EEA) for an 850.5 km² area within the Dussafu block was awarded. A Field Development Plan for the EEA area was subsequently approved and a final decision to start developing the license was taken in 2017.

The Tortue field started oil production in 2018 from two horizontal development wells. In 2020 a further two wells were drilled and brought onstream with the final two wells coming onstream in 2021. The oil from the Tortue wells is produced via subsea trees and flowlines to a leased FPSO (the "Adolo") for processing, storage and export.

At Tortue, in 2022, gross production averaged 10,582 bopd with a field uptime of 89%. During the year, production was constrained by gas lift capacity limitations pending installation of a second gas lift compressor in 2023.

The current phase of development at Dussafu is focussed on the Ruche and Hibiscus fields. A new offshore installation, the "MaBoMo" platform and a 20km pipeline to the Adolo FPSO, were installed at the Hibiscus field in October 2022. The development will ultimately consist of 12 wells to be drilled from the MaBoMo platform into the Ruche and Hibiscus fields in phases. Oil will be produced and transported via the pipeline for processing, storage and export at the Adolo FPSO. The first of the production wells was completed in March 2023 with first oil achieved early 2Q 2023. Once the initial drilling phase is complete, and the first six wells are online, the fields are expected to deliver approximately 30,000 barrels of oil per day on a gross basis.

In March 2023, Netherland, Sewell and Associates, Inc. (NSAI), the reserves auditors for the project, updated their estimates for recoverable reserves in the Dussafu license. As of the end of December 2022, the Dussafu license contained gross 1P Proved Reserves of 65.3 MMbbls. Gross 2P Proved plus Probable Reserves amounted to 96.7 MMbbls and gross 3P Proved plus Probable plus Possible Reserves amounted to 124 MMbbls.

At year end Panoro's net working interest fraction of the gross Dussafu license reserves, before deduction of Government share of production and royalties was 17.5%, with 2P Proved plus Probable Reserves of 16.92 MMbbls and additional 2C unrisked Contingent Resources of 6.7 MMbbls.

Operations in Tunisia

Tunisia is an established oil and gas producing country with production since 1966. The country benefits from a low OPEX environment with significant presence from oil service providers in the region. Panoro has interests in two contiguous areas onshore and offshore the city of Sfax in the northern part of the Gulf of Gabes. These two areas are the Sfax Offshore Exploration Permit and the TPS Assets which are a collection of five producing fields.

TPS Assets

The TPS Assets comprise five oil field concessions in the region of the city of Sfax, onshore and shallow water offshore Tunisia. The concessions are Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba.

The oil fields were discovered in the 1980's and early 1990's and have produced a total of around 59.5 million barrels of oil to date. Approximately 50 wells have been drilled in the TPS fields to date, whilst some of these wells have been abandoned, 12 remain on production with 7 wells currently shut-in awaiting workovers or reactivation. Three wells are used for disposal of produced water. Production facilities consist of the various wellhead installations, connected via intra-field pipelines to

processing, storage and transportation systems. Crude is transported to a storage and export terminal about 70 km south of the Assets at La Skhira.

The Group, through its subsidiary, Panoro Tunisia Production AS ("PTP"), indirectly owns a 49% interest in the fields and a 50% interest in the TPS operating company. The remaining interests are held by the Tunisian State Oil Company, ETAP. Panoro's net interest in TPS operations is 29.4%.

Production from the TPS assets amounted to 1.54 MMbbls gross, which is approximately 0.45 MMbbls net to Panoro's working interest share, an average annual gross rate of 4,232 bopd.

Well workover operations were completed on two of the asset's fields. At Cercina, the CER-2 ESP failed, the workover to replace this pump was preceded by scale removal and the perforation of an additional reservoir interval resulting in enhanced well productivity. At Guebiba, the GUE-3well was worked over to replace a failed ESP. In addition to these workovers, well washes were undertaken to remove scale buildup on several Guebiba wells.

A series of facility maintenance and upgrade studies and projects were progressed. At the Cercina field, an intelligent pigging program was largely completed during the year, this identified the need to replace sections of the intra-field flowlines and a portion of the pipeline to shore. The offshore chemical management program was overhauled and updated, this action is expected to significantly reduce corrosion rates in the fields pipelines and vessels. A topsides and submarine study of the Cercina facilities was completed as part of a project to extend the life of the facilities, underpinning a forthcoming application to renew the Cercina Concession. An asset wide concept study assessing options to eradicate gas flaring has detailed engineering solutions that are now being progressed.

A team comprising ETAP and Panoro staff progressed subsurface re-modelling work on the Guebiba and Rhemoura fields. The Guebiba studies have now progressed to dynamic simulation modelling and are expected to result in the recommendation to drill additional injection and production wells. A Plan of Development for the Rhemoura field, recommending the drilling of one additional development well, was completed and submitted to the Direction Generale des Hydrocarbures (DGH) in support of the renewal of the Rhemoura Concession.

In March 2023 NSAI assessed reserves and resources from the fields as of end December 2022. These reserves amount to 1P Proved Reserves of 10.5 MMbbls, 2P Proved plus Probable Reserves of 15.1 MMbbls and 3P Proved plus Probable plus Possible Reserves of 19.4 MMbbls. Panoro's net working interest 1P Proved reserves are 3.1 MMbbls, 2P Proved plus Probable are 4.4 MMbbls and 3P Proved plus Probable plus Possible are 5.7 MMbbls.

In addition to these reserves, NSAI also certified gross 1C Contingent Resources of 7.7 MMbbls, 2C Contingent Resources of 13.4 MMbbls and 3C Contingent Resources of 23.0 MMbbls. Panoro's net working interest 1C Contingent Resource is 2.3 MMbbls, net working interest 2C Contingent Resource is 3.9 MMbbls and the net working interest 3C Contingent Resource is 6.7 MMbbls. These Reserves and Contingent Resources are Panoro's net volumes before deductions for royalties and other taxes.

Sfax Offshore Exploration Permit

Panoro is the Operator of the Sfax Offshore Exploration Permit ("SOEP"), an exploration license offshore Tunisia in the northern part of the Gulf of Gabes. Panoro's current interest in the license is 52.5%. SOEP lies in the prolific oil and gas Cretaceous and Eocene carbonate platforms of the Pelagian Basin offshore Tunisia. In the vicinity of the Permit area are numerous existing producing fields with infrastructure and spare capacity in pipelines and facilities. There are three oil discoveries on the permit, Salloum, Ras El Besh, and Jawhara. In addition to these discoveries, there is considerable exploration potential in the Permit, with unrisked gross estimates of 250 million barrels of prospective resources. Panoro also has a 52.5% interest in the Ras El Besh Concession which is within the area of the SOEP and contains the undeveloped Ras El Besh field.

The SOEP license was extended during the year and is now due to expire at the end of 2024. The work program for the license includes 3D seismic re-processing and maturation of the prospect inventory for a potential exploration well before the end of 2024.

Hammamet Offshore Exploration Permit

The Hammamet Offshore Exploration Permit expired in September 2018 and is in the process of being formally relinquished with anticipated associated costs of approximately USD 3 million (USD 1.8 million net to Panoro). The Group has a 27.6% working interest in this permit.

Operations in South Africa

Block 2B

Panoro has a 12.5% interest in Block 2B which is operated by a subsidiary of Eco Atlantic and is located in the Orange Basin in South Africa. The block, in water depths between 50 and 200 metres and covering an area of 3,062 km² , contains the A-J rift graben.

An exploration well, Gazania-1, was drilled in Block 2B in Q4 2022 and showed no evidence of commercial hydrocarbons. An existing well ,A-J 1, drilled by Soekor in 1988 encountered reservoir sandstones between 2,985 metres and 3,350 metres depth. High quality 36 API oil was tested over an interval within these sandstones at a rate of 191 barrels of oil per day. An application for a Production Right for Block 2B was submitted by JV Partners in November 2022 based on the existing AJ-1 oil discovery and potential future operations.

TCP218

In June 2022 Panoro was awarded 100% interest in Technical Co-operation Permit ("TCP") 218 located in northern Free State province, South Africa. TCP 218 covers a surface area of approximately 6,608 Km² in the highly prospective Northern Karoo Basin which has a proven working natural gas and helium system with nearby analogues including the producing Virginia gas field (operated by Renergen) and the Smaldeel gas field.

The TCP award is for a period of 12 months during which time Panoro will have exclusive rights to undertake desktop studies of existing data sources and field work in order to evaluate the prospectivity of the permit area, after which the Company will have the option to apply for an Exploration Right covering the permit area.

Legacy operations in Brazil (Discontinued)

In Brazil, as previously updated, termination agreements for the surrender of Coral and Cavalho Marinho licenses have been signed between the JV partners and Brazilian Regulator ANP. The next steps involve various regulatory clearances before dissolution of JV operations. The Company's formal exit from its historical Brazilian business is still ongoing with slow progress towards the approval of abandonment by the Brazilian regulators and resolution of pending historical corporate items including taxes. Management is working actively with advisors and where relevant, the operator Petrobras to bring matters to a close and to ensure that the ongoing costs are kept to a minimum. However, the timing and eventual costs of such conclusion is uncertain at this stage.

The Accounts

The Board of Directors confirms that the annual financial statements have been prepared pursuant to the going concern assumption, in accordance with §3-3a of the Norwegian Accounting Act. The going concern assumption is based upon the financial position of the Company and the development plans currently in place. In the Board of Directors' view, the annual accounts give a true and fair view of the group's assets and liabilities, financial position and results.

Panoro's participation in its Tunisian assets is structured through a shareholder agreement with Beender Petroleum Tunisia Limited ("Beender"), whereby Panoro and Beender jointly own and control 60% and 40% respectively of Sfax Petroleum Corporation AS ("Sfax Corp"). Sfax Corp, through its subsidiaries, holds 100% shares of Panoro Tunisia Production AS ("PTP") and Panoro Tunisia Exploration AS ("PTE"). As such, all numbers and volume information relating to the Company's Tunisian operations and transactions represents the Company's 60% interest, unless otherwise stated.

In October 2019, the Company entered into an agreement to divest all its operations in Nigeria to PetroNor, thereby resulting in changes to presentation of the results, operations and assets and liabilities of the disposal group comprising of the Divested Subsidiaries. The results and operations of the Divested Subsidiaries have met the criteria of Discontinued Operations under IFRS 5 and were isolated and removed from "Continuing activities" and re-classified and presented as a separate line item "Discontinued Operations" in the statement of comprehensive income. Assets and liabilities pertaining to the Divested Subsidiaries have also been isolated and presented in separate line items in the statement of financial position for years ended 31 December 2019 onwards. The transaction completed on 13 July 2022 at which time Panoro derecognised the assets and liabilities of the Divested Subsidiaries at their carrying amounts and recognised the fair value of consideration received from the transaction, with the resulting difference recognised as a gain on sale of subsidiaries. Details of assets and liabilities held at completion and results of the Discontinued Operations up to completion are disclosed in Note 14: Discontinued Operations. Panoro received upfront consideration of USD 10 million in the form of 96,577,537 newly allotted and issued shares in PetroNor E&P ASA ("Consideration Shares"). A dividend in specie was approved by the Board of Directors on 1 August 2022 in the form of the Consideration Shares. Each Panoro shareholder as at the record date received 0.849 PetroNor shares for each share held in Panoro, rounded downwards to the nearest whole share. Fraction shares were not distributed. See Note 11: Listed Equity Investments for full details.

As of 31 December 2022, the Group had USD 32.7 million in cash and bank balances and debt of USD 79.5 million, resulting in a net debt position of approximately USD 46.8 million.

Panoro Energy ASA prepares its financial statements in accordance with the International Financial Reporting Standards (IFRS), as provided for by the EU and the Norwegian Accounting Act. The consolidated accounts are presented in US dollars. The below analysis compares 2022 with 2021 figures:

Underlying profit/(loss) before tax from continuing operations

Underlying operating profit/(loss) before tax is considered by the Group to be a useful additional measure to help understand underlying operational performance. The foregoing analysis has also been performed including, on an adjusted basis, the underlying operating profit/(loss) before tax from continuing operations of the Group. A reconciliation with adjustments to arrive at the underlying operating profit/(loss) before tax from continuing operations is included in the table below

USD 000	2022	2021
Net income/(loss) before tax - continuing operations	60,424	63,391
Share based payments	1,591	1,231
Acquisition and project related costs	1,054	1,254
Unrealised (gain)/loss on commodity hedges	(2,622)	3,868
Unrealised (gain)/loss on listed equity investments	75	-
Underlying operating profit/(loss) before tax	60,522	69,744

Underlying operating profit/(loss) before tax is a supplemental non-GAAP financial measure used by management and external users of the Company's consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines underlying operating profit/(loss) before tax as Net income (loss) from continuing operations before tax adjusted for (i) Share based payment charges, (ii) unrealised (gain) loss on commodity hedges, (iii) (gain) loss on sale of oil and gas properties, (iv) impairments write-offs and reversals, and (v) similar other material items which management believes affect the comparability of operating results. We believe that underlying operating profit/(loss) before tax and other similar measures are useful to investors because they are frequently used by securities analysts, investors and other interested parties in the evaluation of companies in the oil and gas sector and will provide investors with a useful tool for assessing the comparability between periods, among securities analysts, as well as company by company. Because EBITDA and underlying operating profit/(loss) before tax excludes some, but not all, items that affect net income, these measures as presented by us may not be comparable to similarly titled measures of other companies.

Condensed Consolidated Income Statement

USD 000	2022	2021
CONTINUING OPERATIONS
Oil revenue	180,267	113,708
Other revenue	8,359	5,949
Total revenues	188,626	119,657
Expenses
Operating costs	(51,901)	(41,022)
Exploration related costs and operator G&A	(166)	(6,438)
Acquisition and project related costs	(1,054)	(1,254)
General and administrative costs	(8,317)	(7,242)
EBITDA	127,188	63,701
Depreciation, depletion and amortisation	(35,164)	(27,550)
Exploration costs written off	(9,210)	-
Share based payments	(1,591)	(1,231)
EBIT	81,223	34,920
Gain on acquisition of business	-	46,121
Net financial items	(20,799)	(17,650)
Profit / (loss) before income taxes	60,424	63,391
Income tax expense	(41,789)	(21,079)
Net profit/(loss) from continuing operations	18,635	42,312
Net income/(loss) from discontinued operations	1,258	7,011
Net profit/(loss) for the year	19,893	49,323

From a financial statements' perspective, the sale of the Group's asset in Nigeria, OML 113 Aje, is classified as "discontinued operations" and as such has been reported separately from the "continuing business activities" for both years presented.

Income statement

The discussion and analysis below represent the results from the Group's continuing operations in Equatorial Guinea, Gabon, Tunisia and South Africa.

Panoro Energy reported an EBITDA of USD 127.2 million from continuing operations for the year ended 31 December 2022, compared to USD 63.7 million from continuing operations for the same period in 2021.

EBITDA includes oil revenue from sale of oil of USD 180.3 million from continuing operations for 2022 comprising of one lifting from Block G totalling USD 81 millon (745,069 bbls), one lifting from Dussafu totalling USD 59.2 million (647,111 bbls) and ten liftings (three international and seven domestic) from the Group's Tunisian portfolio making up the remaining revenue of USD 40.1 million (423,418 bbls). This compares to USD 113.7 million from continuing operations for 2021 comprising one lifting from Block G totalling USD 51.6 millon (699,896 bbls), five liftings from Dussafu totalling USD 35.8 million (478,499 bbls) and ten liftings (three international and seven domestic) from the Group's Tunisian portfolio making up the remaining revenue of USD 26.4 million (400,176 bbls).

Under the terms of the Dussafu PSC, State profit oil is shown as revenue and amounted to USD 8.4 million (year ended 31 December 2021: USD 5.9 million). This is reflected in other revenue, with a corresponding amount shown as income tax (Note 6: Income tax).

Panoro Energy reported a net profit of USD 18.6 million from continuing operations for the year ended 31 December 2022, compared to net profit of USD 42.3 million from continuing operations for the year ended 31 December 2021.

Exploration related costs from continuing operations for 2022 are USD 0.2 million compared to USD 6.4 million in 2021 which was mainly related to a settlement of USD 6.3 million with the Tunisian authorities to settle amounts due to historical nonfulfilment of a work programme at Sfax Offshore by the previous operator. Capitalised exploration costs of USD 9.2 million were written off after the Gazania-1 exploration well located at Block 2B offshore South Africa did not encounter commercial hydrocarbons. See Note 4: Operating Result.

G&A costs relating to continuing operations are USD 8.3 million in 2022 compared to USD 7.2 million in 2021, the increase being a result of non-recurring costs related to internal restructure and increased activity levels as COVID-19 restrictions eased.

Depreciation, depletion and amortisation charge for the year for continuing operations of USD 35.2 million compared to the USD 27.6 million in 2021. The increase is mainly a result of the increase in depreciable assets due to the acquisition activity during the year.

EBIT from continuing operations for 2022 was thus USD 81.2 million compared to USD 34.9 million in 2021.

The gain on acquisition of business of USD 46.1 million in 2021 reflect excess of fair value of net assets acquired over the consideration paid in the Dussafu Transaction, refer Note 13: Business Combinations. This significant one-off fair value uplift in excess of purchase consideration was mainly a result of substantial increase in oil prices from the time the deal was agreed for Dussafu Transaction versus the prevailing oil prices at the time of completion of the transaction when the fair value was determined for acquisition purposes.

Net financial items from continuing operations amount to a loss of USD 20.8 million (2021: USD 17.7 million). Net financial items comprise interest on Secured loans facility of USD 9.3 million (2021: USD 6.4 million); interest on BW Energy Non-Recourse loan USD 0.2 million (2021: USD 0.4 million), interest on revenue advance facility USD 0.7 million (2021: Nil); unrealised gain on commodity hedges USD 2.6 million (2021: loss of USD 3.9 million); realised loss on commodity hedges of USD 8.5 million (2021: gain of USD 4.4 million); and foreign exchange loss of USD 0.5 million (2021: gain of USD 0.4 million). The remaining financial items represent realised and unrealised loss on listed equity investments, interest on unwinding of decommissioning provision and unwinding of the discount on right of use asset under IFRS 16 (Note 22: Leases).

Profit before tax from continuing operations for 2022 was USD 60.4 million compared to USD 63.4 million for 2021.

Income taxes of USD 41.8 million in 2022 compared to USD 21.1 million in 2021. The tax charge for 2022 includes USD 17.9 million related to Block G (2021: USD 5.9 milliion), an estimated USD 8.3 million (2021: USD 6 million) representing State profit oil under the terms of the Dussafu PSC and USD 15.5 million (2021: USD 9.2 million) for taxes on profits for the Group's Tunisian Operations. The tax charge also includes a USD 6.5 million (2021: USD 1.8 million) of deferred tax liability reversal.

Net profit after tax for 2022 was therefore USD 19.9 million (2021: USD 49.3 million).

Statement of financial position

Non-current assets amount to USD 444.9 million at 31 December 2022, a decrease of USD 10.8 million from USD 455.7 million at 31 December 2021, a result of additions of USD 46.5 million offset by depreciation of USD 35.2 million and adjustment to asset retirement obligations of USD 22.2 million related to continuing operations.

Current assets amount to USD 94.5 million as of 31 December 2022 compared to USD 100 million at 31 December 2021. Crude inventory decreased from USD 4.3 million at 31 December 2021 to USD 3.4 million at 31 December 2022. Materials inventory was USD 22.8 million at 31 December 2022, compared to USD 15.5 million at 31 December 2021.

Trade and other receivables at 31 December 2022 are USD 35.1 million, a decrease of USD 20.5 million from USD 55.6 million at 31 December 2021. The decrease is mainly due to receivables from oil sales reducing by USD 38.9 million from 2021 due to only one lifting in the forth quarter with previous quarters largely paid, offset by an increased oil underlift and overfund of joint venture accounts of USD 10.3 million and USD 8 million respectively. The remaining USD 0.1 million movement is due to short term receivable items.

At 31 December 2022, the fair value of commodity hedges was less than USD 1 million and was all current based on maturity. This compares to current liability position in 2021 of USD 2.5 million.

The Company shows USD 0.3 million of listed equity investments. This represents listed shares in PetroNor E&P ASA following the completion of the disposal of its Nigerian assets and the declaration of a dividend in specie of these shares to shareholders after which a amount of shares was retained by Panoro to cover withholding taxes and account for rounding. These shares were sold subsequent to year end. Refer Note 14: Discontinued Operations for full details.

Cash and cash equivalents stood at USD 32.7 million, compared to USD 24.5 million at 31 December 2021. The net inflow of USD 8.2 million was mainly a result of cash inflows from operations of USD 112.9 millionoffset by cash ouflow related to investment in exploration and production assets and licence extensions of USD 68 million , repayment of loans of USD 18.8 million principal and USD 8 million financial charges. The remaining items include realised losses on commodity hedges of

USD 8.5 million, with remaining cash outflows of USD 1 million cost to settle RSUs. During 2021, key inflows of cash and cash equivalents included realised gains on commodity hedges of USD 4.5 million, net cash inflow from operations of USD 0.5 million with outflows of investment in exploration and production assets of USD 13.8 million, loan and borrowing cost repayments of USD 5.5 million and cash cost of RSU settlements of USD 0.3 million.

Equity as at 31 December 2022 amounts to USD 206.5 million compared to USD 195.4 million at the end of December 2021.

Total non-current liabilities are USD 261 million as at 31 December 2022 compared to USD 305.7 million at 31 December 2021.

Decommissioning liability decreased from USD 140.8 million in 2021 to USD 123.7 million, a decrease of USD 17.1 million reflecting changes in inflation, discount rate and licence terms of USD 29.1 million, offset by additions and changes in cost estimates of USD 8.4 million and the year's unwinding of discount of USD 3.5 million.

Non-current and current portions of Secured Loans decreased from USD 92.4 million at 31 December 2021 to USD 78.9 million at 31 December 2022 as a result of repayments of principal of USD 14.9 million and interest of USD 8.1 million during the year and offset by accumulation of interest. For further details, refer to Note 5: Finance , interest and other income and expense.

On an overall basis, BW Energy non-recourse loan balance reduced from USD 4.5 million at 31 December 2021 to USD 0.6 million at 31 December 2022, all related to accumulated interest following payment of principal balances in full during the year. The remaining balance was repaid in full on 21 March 2023.

Total licence obligations and estimated contingent consideration was unchanged between the two balance sheet dates presented at USD 5.9 million, of which USD 4.7 is deemed non-current and USD 1.2 million as current. The licence obligations and deferred consideration were acquired by the Group as part of the acquisition of SOEP from DNO in July 2018.

Other non-current liabilities were USD 7 million at 31 December 2022 compared to USD 8.3 million at 31 December 2021, comprising USD 5 million provision for contingent consideration related to the EG Transaction (see Note 13: Business Combinations), USD 1.9 million of provision for long term employment benefits for TPS employees (31 December 2021: USD 3.2 million) and USD 0.1 million of IFRS 16 lease liability described in Note 22: Leases (31 December 2021: USD 0.2 million).

Non-current liabilities at 31 December 2021 also include USD 67.3 million of deferred tax liabilities relating the Group's Equatorial Guinea and Tunisian assets (31 December 2021: USD 74.1 million).

Current liabilities amounted to USD 71.8 million at 31 December 2022 compared to USD 63.2 million at 31 December 2021, an increase of USD 8.6 million.

USD 0.6 million reflects the accrued interest on BW Energy non-recourse loan that was repaid on 21 March 2023 (31 December 2021: USD 4.5 million principal and accrued interest), USD 20.5 million is the current portion of Secured Loan facilities (31 December 2021: USD 14.7 million) and USD 35.6 million of corporation tax liabilities in Equatorial Guinea and Tunisia (31 December 2021: USD 17 million).

Accruals and other payables amounted to USD 9.1 million at 31 December 2022, a decrease of USD 3.6 million from the 31 December 2021 balance of USD 12.7 million. The decrease is primarily due to differences in year-on-year activity levels of joint ventures affecting cash calls.

Other current liabilities were USD 4.9 million at 31 December 2022 (31 December 2021: USD 10.6 million) consisting mainly of a Gabon overlift liability position of USD 1.5 million, USD 1.6 million related to Dussafu historical cost settlement liability taken on as part of the Dussafu Transaction, with the remainder USD 1.3 million representing the Group's share of anticipated costs associated with relinquishment of the Hammamet licence; and the remaining USD 0.5 million representing the current portion of lease liabilities (Note 22: Leases) and other liabilities.

Cash flows

Net cash inflow from operating activities amounted to USD 112.6 million in 2022 (31 December 2021: USD 70.4 million), the increase reflecting a combination of increased production and higher oil prices.

Net cash flow from investing activities was an outflow of USD 67.7 million comprising of cash outflows of USD 3.5 million related licence extensions and investment in oil and gas assets of USD 64.3 million. This compares to an outflow in 2021 of USD 196.1 million comprising of cash outflows of USD 140.5 million related acquisitions from Tullow described in Note 13: Business Combinations and investment in oil and gas assets of USD 55.7 million.

Net cash flow from financing activities was an outflow of USD 36.8 million in 2022 (2021: inflow of USD 144.6 million). Net cash outflow was a result of loan repayments of USD 18.8 million, interest on these loans of USD 8.1 million and realised loss on commodity hedges of USD 8.5 million. The remaining USD 1.3 million outflow included RSU settlements and lease liability payments. Net cash inflow in 2021 was a result of gross proceeds of USD 90 million Secured Loan facility with Trafigura and USD 78.2 million proceeds from the issue of new shares (net of costs of USD 3 million) and USD 3.6 million inflow from release of bank guarantee, offset by debt and borrowing costs repayment and losses on commodity hedges of USD 26.2 million. Other outflows included RSU settlements of USD 0.7 million, lease liability payments of USD 0.3 millon.

Cash and cash equivalents were therefore USD 32.7 million compared to USD 24.5 million at 31 December 2021.

Parent company financial information

USD 000	2022	2021
Total revenues	-	-
Operating expenses
General and administrative costs	(5,164)	(5,024)
Impairment of investment in subsidiary	(90)	(70)
Provision for doubtful receivables*	(1,932)	65,806
Total operating expenses	(7,186)	60,712
Earnings before interest and tax (EBIT)	(7,186)	60,712
Loss on disposal of business	(17,823)	-
Net interest and financial items	2,459	5,681
Loss on fair value of listed equity investments	(727)	-
Profit/(loss) before taxes	(23,277)	66,393
Income tax benefit / (expense)	-	-
Net profit/(loss) attributable to equity holders	(23,277)	66,393

* Provision for doubtful receivables owed from loans provided to subsidiaries. See Note 7: Provision for doubtful receivables in the Parent Company Financial Statements.

Distributable equity and coverage of profit/(loss) in Panoro Energy ASA

The Board of Directors proposes that the loss for the year of USD 23.3 million in the parent company be transferred to other equity.

Dividend

Following the completion of the transaction to divest the group's operations in Nigeria as described in Note 14: Discontinued Operations of the Consolidated Financial Statements, the Company received upfront consideration of USD 10 million in the form of 96,577,537 newly allotted and issued shares in PetroNor E&P ASA ("Consideration Shares"). A dividend in specie was approved by the Board of Directors on 1 August 2022 in the form of the Consideration Shares. Each Panoro shareholder as at the record date received 0.849 PetroNor shares for each share held in Panoro, rounded downwards to the nearest whole share. Fraction shares were not distributed.

On 21 February 2023, the Board of Directors approved a cash dividend of NOK 0.2639 per share to shareholders holding shares in the Company at the end of trading on 7 March 2023. The total dividend was approximately NOK 30 million (approximately USD 3 million) and payment took place on or around 16 March 2023.

FUNDING

The Company, on a consolidated basis, closed the year with a cash position of USD 32.7 million and debt of USD 79.5 million.

No shares were issued (apart from awards under the RSU employee incentive plan) or new debt taken on during the year ended 31 December 2022.

Looking ahead, the Company through its group companies, is committed to activities as described in the Directors' report.

Risks relating to the oil and gas industry

The Group's results of operations, cash flow and financial condition depend significantly on the level of oil and gas prices and market expectations to these, and may be adversely affected by volatile oil and gas prices and by the general global economic and financial market situation

The Group's profitability is determined, in large part, by the difference between the income received from the oil and gas produced and the operational costs, taxation costs, as well as costs incurred in transporting and selling the oil and gas. Lower prices for oil and gas may thus reduce the amount of oil and gas that the Group is able to produce economically. This may also reduce the economic viability of the production levels of specific wells or of projects planned or in development to the extent that production costs exceed anticipated revenue from such production.

The economics of producing from some wells and assets may also result in a reduction in the volumes of the Group's reserves. The Group might also elect not to produce from certain wells at lower prices. These factors could result in a material decrease in net production revenue, causing a reduction in oil and gas acquisition and development activities. In addition, certain development projects could become unprofitable because of a decline in price and could result in the Group having to postpone or cancel a planned project, or if it is not possible to cancel the project, carry out the project with negative economic impact.

In addition, a prolonged material decline in prices from historical average prices could reduce the Group's ability to refinance its outstanding credit facilities and could result in a reduced borrowing base under credit facilities available to the Group, including the Senior Secured loan facility in place. Changes in the oil and gas prices may thus adversely affect the Group's business, results of operations, cash flow, financial condition and prospects.

The Company is operating a commodity hedging program to strategically hedge a portion of its 2P oil reserves to protect against a fall in oil prices and consequently, to protect the Group's ability to service its debt obligations and to fund operations including planned capital expenditure. The hedging program continues to be closely monitored and adjusted according to the Group's risk management policies and cashflow requirements. The Group continues to monitor and optimise its hedging programme on an on-going basis. Also see Note 19: Financial instruments.

Exploration, development and production operations involve numerous safety and environmental risks and hazards that may result in material losses or additional expenditures

Developing oil and gas resources and reserves into commercial production involves risk. The Group's exploration operations are subject to all the risks common in the oil and gas industry. These risks include, but are not limited to, encountering unusual or unexpected rock formations or geological pressures, geological uncertainties, seismic shifts, blowouts, oil spills, uncontrollable flows of oil, natural gas or well fluids, explosions, fires, improper installation or operation of equipment and equipment damage or failure. Given the nature of offshore operations, the Group's exploration, operating and drilling facilities are also subject to the hazards inherent in marine operations, such as capsizing, sinking, grounding and damage from severe storms or other severe weather conditions, as well as loss of containment, fires or explosions.

The market in which the Group operates is highly competitive

The oil and gas industry is very competitive and rapidly changing. Competition is particularly intense in the acquisition of (prospective) oil and gas licenses. The Group's competitive position depends on its geological, geophysical and engineering expertise, financial resources, the ability to develop its assets and the ability to select, acquire, and develop proven reserves.

Access to capital

Concerns surrounding the energy transition have the potential to reduce the appetite of banks and investors to finance hydrocarbon activities. The Group does not anticipate any material change to funding in the short to medium term, but are aware of this risk and will continue to monitor the potential impact of this risk to the business.

Risks relating to the business of the Group

Risk relating to the outbreak of war, including the ongoing invasion in Ukraine

The Group has limited indirect exposure to the war in Ukraine. Recent global macroeconomic and geopolitical developments have supported higher energy prices amid concerns for regional energy shortages. At the same time, project execution risk has increased with supply chain and logistics challenges, inflationary pressures, and higher interest rates. Panoro is focused on mitigating the potential impact from supply chain challenges and commodity inflation. The Group continues to monitor the increasing geopolitical tensions and deepening crisis between Russia and Ukraine and regularly reviews the potential impact on our business activities and assets.

Developing a hydrocarbon production field requires significant investment

The Group currently plans to be involved in developments in its oil and gas licences. Developing a hydrocarbon production field requires significant investment over a long period of time, to build the requisite operating facilities, drilling of production wells along with implementation of advanced technologies for the extraction and exploitation of hydrocarbons with complex properties. Making these investments and implementing these technologies, normally under difficult conditions, can result in uncertainties about the amount of investment necessary, operating costs and additional expenses incurred as compared with the initial budget, thereby negatively affecting the business, prospects, financial condition and results of operations of the Group.

Further, with respect to contingent resources, the amount of investment needed may be prohibitive, such that conversion of resources into reserves may not be commercially viable. The Group may be unable to obtain needed capital or financing on satisfactory terms. If the Group's revenues decrease, it may have limited ability to obtain the capital necessary to sustain operations at current levels. If the Group's available cash is not sufficient to fund its committed or planned investments, a curtailment of its operations relating to development of its business prospects could occur, which in turn could lead to a decline in its oil and natural gas production and reserves, or if it is not possible to cancel or stop a project, be legally obliged to carry out the project contrary to its desire or with negative economic impact. Further, the Group may inter alia fail to make required cash calls and thus breach license obligations, which again could lead to adverse consequences. All of the above may have a material adverse effect on the Group and its financial position.

There are risks and uncertainties relating to extension of existing licenses and permits, including whether any extensions will be subject to onerous conditions

The Group's license interests for the exploration and exploitation of hydrocarbons will be subject to fixed terms, some of which will expire before the economic life of the asset is over. For example, the licences relating to the interest in five oil production concessions in Tunisia may expire prior to the end of their economic life, and uncertainty surrounding the renewal of SOEP which requires an exploration well to be drilled prior to entering into the next operation phase.

The Group plans to extend any permit or license where such extension is in the best interest of the Group. However, the process for obtaining such extensions is not certain and no assurances can be given that an extension in fact will be possible. Even if an extension is granted, such extension may only be given on conditions which are onerous or not acceptable to the Group.

If any of the licenses expire, the Group may lose its investments into the license, charged penalties relating to unfulfilled work program obligations (such as at Hammamet in Tunisia) and forego the opportunity to take part in any successful development of, and future production from, the relevant license area, which could have a material adverse effect on the Group's financial position and future prospects.

Local authorities may impose additional financial or work commitments beyond those currently contemplated

The Group's license interests for the exploration and exploitation of hydrocarbons will typically be subject to certain financial obligations or work commitments as imposed by local authorities. The existence and content of such obligations and commitments may affect the economic and commercial attractiveness for such license interest. No assurance can be given that local authorities do not unilaterally amend current and known obligations and commitments. If such amendments are made in the future, the value and commercial and economic viability of such interest could be materially reduced or even lost, in which case the Group's financial position and future prospects could also be materially weakened.

Oil and gas production could vary significantly from reported reserves and resources

The Group's reserve evaluations have been prepared in accordance with existing guidelines. These evaluations include many assumptions relating to factors such as initial production rates, recovery rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of oil and gas, operating costs, and royalties and other government levies that may be imposed over the producing life of the reserves and resources. Actual production and cash flows will vary from these evaluations, and such variations could be material. Hence, although the Group understands the life expectancy of each of its assets, the life of an asset may be shorter than anticipated. Among other things, evaluations are based, in part, on the assumed success of exploration activities intended to be undertaken in future years. The reserves, resources and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploration activities do not achieve the level of success assumed in the evaluations, and such reductions may have a material adverse effect on the Group's business, results of operations, cash flow and financial condition.

The Company faces risks related to decommissioning activities and related costs

Several of the Group's license interests concern fields which have been in operation for years and which, consequently, will have equipment which from time to time will have to be decommissioned. In addition, the Group plans and expects to take part in developments and investments on existing and new fields, which will increase the Group's future decommissioning liabilities.

There are significant uncertainties relating to the estimated liabilities, costs and time for decommissioning of the Group's current and future licenses. Such liabilities are derived from legislative and regulatory requirements and require the Group to make provisions for such liabilities.

Therefore, it is difficult to forecast accurately the costs that the Group will incur in satisfying decommissioning liabilities. No assurance can be given that the anticipated cost and timing of removal are correct and any deviation from current estimates or significant increase in decommissioning costs relating to the Group's previous, current or future licenses, may have a material adverse effect on the Group.

The Group may be subject to liability under environmental laws and regulations

All phases of oil and gas activities present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and national laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, and releases or emissions of various substances. The legislation also requires that wells and facility sites are operated, maintained and abandoned to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties in addition to loss of reputation. Any pollution may give rise to material liabilities and may require the Group to incur material costs to remedy such discharge. No assurance can be given that current or future environmental laws and regulations will not result in a curtailment or shut down of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Group.

The Group's business and financial condition could be adversely affected if tax regulations for the petroleum industry are amended

There is no assurance that future political conditions will not result in the host governments adopting different policies for petroleum taxation. In the event there are changes to such tax regimes, it could lead to new investments being less attractive, increase costs for the Group and prevent the Group from further growth. In addition, taxing authorities could review and question the Group's historical tax returns leading to additional taxes and tax penalties which could be material.

The Group faces the risk of litigation or other proceedings in relation to its business

The Group faces the risk of litigation and other proceedings in relation to its business. The outcome of any litigation may expose the Group to unexpected costs and losses, reputational and other non-financial consequences and diverting management attention away from operational matters, all of which could have a material adverse effect on the Group's business and financial position.

The Group will have guarantee and indemnity obligations

The Group will in its ordinary course of business provide guarantees and indemnities to governmental agencies, joint venture partners or third-party contractors in respect of activities relating to its subsidiaries, inter alia for such subsidiaries working and abandonment obligations under licences or obligations under the relevant terms of agreements with third party contractors.

Should any guarantees or indemnities given by the Company be called upon, this may have a material adverse effect on the Group's financial position.

Financial risks

Financial risk is managed by the finance department in line with the policies approved by the Board of Directors. The overall risk management program seeks to minimise the potential adverse effects of unpredictable fluctuations in financial and commodity markets on financial performance, i.e., risks associated with currency and interest rate exposures, debt servicing and oil and gas prices. Financial instruments such as derivatives, forward contracts and currency and commodity swaps are continuously being evaluated for the hedging of such risk exposures.

Risks associated with foreign exchange risk, including CEMAC foreign exchange regulations

The Group operates in multiple international jurisdictions and is exposed to various economic uncertainties, including, taxation policies, currency controls, and foreign exchange restrictions that can impose a risk to liquidity. Group's primary source of liquidity is cashflow from production of oil in Block G Equatorial Guinea and Dussafu Gabon both of which are subject to foreign currency regulations of the Central African Economic and Monetary Community (CEMAC). In December 2021, new foreign currency regulations were issued by the Bank of Central African States (BEAC) requiring a share of crude oil sale proceeds to be repatriated in to the CEMAC region. Group evaluated the new regulations and deemed that the impact does not propose a significant threat to its liquidity. However, if the foreign currency restrictions were to be imposed on and enforced against the Group, this could restrict the Group's ability to repatriate earnings from the operations at effected countries, pay dividends from subsidiaries and repay or refinance any future loan facilities, which would entail extensive documentation and fee requirements and increased administrative burdens on the Group's operations.

Existing debt is restrictive on the Group and the Group may have difficulties servicing debt in the future

The Group has incurred and may in the future incur debt or other financial obligations which could have important consequences to its business including, but not limited to:

• making it difficult to satisfy the Group's obligations with respect to such indebtedness,
• increasing the Group's vulnerability to, and reducing its flexibility to respond to, general adverse economic and industry conditions,
• requiring the dedication of a substantial portion of the Group's cash flow from operations to the repayment of the principal of its indebtedness and interest on such indebtedness, thereby reducing the availability of such cash flow,
• limiting the Group's ability to obtain additional financing to fund working capital, capital investments, acquisitions, debt service requirements, business ventures, or other general corporate purposes,
• limiting the Group's flexibility in planning for, or reacting to, changes in its business and the competitive environment and the industry in which the Group does business; and
• adversely affecting the Group's competitive position if its debt burden is higher than that of its competitors.

The Group will require a significant amount of cash to service current and future debt and sustain its operations, and its ability to generate sufficient cash depends on many factors beyond its control

The Group's ability to make payments on, or repay or refinance, any debt and to fund working capital and capital investments, will depend on its future operating performance and ability to generate sufficient cash. This depends on the success of its business strategy and on general economic, financial, competitive, market, legislative, regulatory, technical and other factors as well as the risks discussed in these "Risk Factors", many of which are beyond the Group's control. The Group cannot assure that its business will generate sufficient cash flow from operations or that future debt and equity financings will be available to it in an amount sufficient to enable it to pay its debt, or to fund its other liquidity needs. The Group cannot give assurance that it will be able to refinance any debt on commercially reasonable terms or at all. Any failure by the Group to make payments on debt on a timely basis would likely result in a reduction of its credit rating, which could also harm its ability to incur additional indebtedness. There can be no assurance that any assets that the Group may elect to sell can be sold or that, if sold, the timing of such sale will be acceptable, and the amount of proceeds realised will be sufficient to satisfy its debt service and other liquidity needs.

If the Group is unsuccessful in any of these efforts, it may not have sufficient cash to meet its obligations, which could cause an event of default under any debt arrangements and could result in the debt being accelerated, lending reserves and certain bank accounts being frozen, triggering of cross-default provisions, enforcement of security and the companies of the Group, including the Group being forced into bankruptcy or liquidation.

The Group is exposed to interest rate and liquidity risk associated with its borrowing portfolio and fluctuations in underlying interest rates

The Group's long-term debt is primarily based on floating interest rates. An increase in interest rates can therefore materially adversely affect the Group's cash flows, operating results and financial condition and make it difficult to service its financial obligations. The Group has, and will in the future have, covenants related to its financial commitments. Failure to comply with financial obligations, financial covenants and other covenants may entail several material adverse consequences, including the need to refinance, restructure, or dispose of certain parts of, the Group's businesses in order to fulfil the financial obligations and there can be no assurances that the Group in such event will be able to fulfil its financial obligations.

Changes in foreign exchange rates may affect the company's results of operations and financial position

Due to the international nature of its operations, the Group is exposed market fluctuations in foreign exchange rates due to the fact that the Group reports profit and loss and the balance sheet in US Dollars (USD). The risks arising from currency exposure are primarily with respect to USD, the Norwegian Kroner (NOK), the Tunisian Dinar (TND), the Pound Sterling (GBP) and, to a lesser extent, Brazilian Reals (BRL).

The company is exposed to risk of counterparties being unable to fulfil their financial obligations

A general downturn in financial markets and economic activity may result in a higher volume of late payments and outstanding receivables, which may in turn adversely affect the company's business, operating results, cash flows and financial condition.

For risk factors pertaining to the Company and its operations, reference is also made to the prospectus dated 5 March 2021 which is available on the Group's website www.panoroenergy.com.

Joint arrangement and contractors

Panoro is not the operator on all of our license areas and facilities and do not hold all of the working interests in certain of our license areas. The actions of our partners, contractors and subcontractors could result in legal liability and financial loss for the Group. Many of Panoro's activities are conducted through joint arrangements and with contractors and subcontractors which may limit Panoro's influence and control over the performance of such operations. If operators, partners or contractors fail to fulfil their responsibilities, Panoro can be exposed to financial, operational, safety, security and compliance risks as well as reputational risks and risks related to ethics, integrity and sustainability.

CORPORATE GOVERNANCE

Panoro's corporate governance policy is based on the recommendations of the Norwegian Code of Practice for Corporate Governance. The main objective for Panoro Energy ASA's Corporate Governance is to develop a strong, sustainable, competitive and successful E&P company acting in the best interest of all the stakeholders, within the laws and regulations of the respective countries. The Board and management aim for a controlled and profitable development and long-term creation of growth through well-founded governance principles and risk management.

Panoro Energy acknowledges that successful value-added business is profoundly dependent upon transparency and internal and external confidence and trust. Panoro Energy believes that this is achieved by building a solid reputation based on our financial performance, our values and by fulfilling our commitments. Thus, good corporate governance practices combined with Panoro Energy's Code of Conduct is an important tool in assisting the Board to ensure that we properly discharge our duty.

The composition of the Board ensures that the Board represents the common interests of all shareholders and meets the Company's need for expertise, experience, capacity and diversity. The members of the Board represent a broad range of experience including oil and gas, energy, banking and investment. The composition of the Board ensures that it can operate independently of any special interests. Members of the Board are elected for a maximum period of two years. However, in the last election, the Board was appointed for one year. Recruitment of members of the Board may be phased so that the entire Board is not replaced at the same time. The Chairman of the Board of Directors is elected by the General Meeting.

The Board may be given power of attorney by the General Meeting to acquire the Company's own shares. Any acquisition of shares will be carried out through a regulated marketplace at market price, and the Company will not deviate from the principle of equal treatment of all shareholders. If there is limited liquidity in the Company's share at the time of such transaction, the Company will consider other ways to ensure equal treatment of all shareholders. The Company currently holds shareholder authorisation approved in the 2022 Annual General Meeting to acquire its own shares to a maximum of NOK 566,918.45 of share capital equivalent to 11,338,369 shares, each with a Nominal value of NOK 0.05. From the current year's authorisation, which is due to expire prior to the 2023 Annual General Meeting, the Company has not purchased any shares.

The Board may also be given a power of attorney by the General Meeting to issue new shares for specific purposes. Any decision to deviate from the principle of equal treatment by waiving the pre-emption rights of existing shareholders to subscribe for shares in the event of an increase in share capital will be justified and disclosed in the stock exchange announcement of the increase in share capital. Such deviation will be made only if it is in the common interest of the shareholders and the Company.

The Company has not granted any loans or guarantees to anyone in the management or any of the directors.

The Company has directors' and officers' liability insurance which covers the cost of compensation claims made against the Company's directors and key managers (officers) for alleged wrongful acts.

The Board acknowledges the Norwegian Code of Practice for Corporate Governance and the principle of comply or explain. Panoro Energy has implemented this Code and uses its guidelines as the basis for the Board's governance duties. A report on the corporate governance policy is incorporated in a separate section of this report and is also posted on the Company's website at www.panoroenergy.com.

The Company has implemented a policy for Ethical Code of Conduct and works diligently to comply with these guidelines. In July 2022, the Transparency Act was passed into law and the Company is subject to its requirements. The Group's 2022 Sustainability Report which can be found on the Company's website at www.panoroenergy.com outlines the full Ethical Code of Conduct policy and discloses compliance and activities related to the Transparency Act.

DIRECTORS AND SHAREHOLDERS

According to its articles of association, the Company shall have a minimum of three and a maximum of eight directors on its Board. The number of Board members was six at the end of 2022 and five at year end 2021, all non-executive directors. The members have various backgrounds and experience, offering the Company valuable perspectives on industrial, operational and financial issues. The Board consists of three male and three female members as at year end 2022. The Board held several meetings during the year, which also included meetings held through circulation of documents and by phone calls.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG)

The Board constituted a new Sustainability Committee which was active from the General Meeting in May 2022. Panoro's 2022 Sustainability Report is published as a separate document and contains detailed ESG disclosures. The 2022 Sustainability Report can be found on the Company website at www.panoroenergy.com,

The industry has faced significant challenges in recent years with the Covid pandemic, geopolitical tensions and push for decarbonisation, all influencing capital investment, supply/demand balance and oil prices. Panoro has proven itself to be a resilient business in this often uncertain period and is now well established as a diversified, full cycle oil company with a committed Board of Directors, balance sheet strength, high quality asset base that offers material organic growth opportunities and means to capitalise on inorganic growth opportunities should they arise.

The Board wishes to thank the staff and shareholders for their continued commitment to the Company.

27 April 2023 The Board of Directors Panoro Energy ASA

JULIEN BALKANY	TORSTEIN SANNESS	GARRETT SODEN
Chairman of the Board	Deputy Chairman of the Board	Non-Executive Director
ALEXANDRA HERGER	HILDE ÅDLAND	GRACE REKSTEN SKAUGEN
Non-Executive Director	Non-Executive Director	Non-Executive Director

JOHN HAMILTON

Chief Executive Officer

ANNUAL STATEMENT OF RESERVES 2022

INTRODUCTION

Panoro's classification of reserves and resources complies with the guidelines established by the Oslo Stock Exchange and are based on the definitions set by the Petroleum Resources Management System (PRMS), sponsored by the Society of Petroleum Engineers/ World Petroleum Council/ American Association of Petroleum Geologists/ Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) as issued in June 2018.

Reserves are the volume of hydrocarbons that are expected to be produced from known accumulations:

• On Production
• Approved for Development
• Justified for Development
  • 1P Proved reserves represent volumes that will be recovered with 90% probability
  • 2P Proved + Probable represent volumes that will be recovered with 50% probability
  • 3P Proved + Probable + Possible volumes that will be recovered with 10% probability.

Reserves are also classified according to the associated risks and probability that the reserves will be actually produced.

Contingent Resources are the volumes of hydrocarbons expected to be produced from known accumulations:

• In planning phase
• Where development is likely
• Where development is unlikely with present basic assumptions
• Under evaluation

Contingent Resources are reported as 1C, 2C, and 3C, reflecting similar probabilities as reserves.

DISCLAIMER

The information provided in this report reflects reservoir assessments, which in general must be recognised as subjective processes of estimating hydrocarbon volumes that cannot be measured in an exact way.

It should also be recognised that results of recent and future drilling, testing, production and new technology applications may justify revisions that could be material.

Certain assumptions on the future beyond Panoro's control have been made. These include assumptions made regarding market variations affecting both product prices and investment levels. As a result, actual developments may deviate materially from what is stated in this report.

The estimates in this report are based on third party assessments prepared by Netherland Sewell and Associates Inc. (NSAI).

PANORO ASSETS PORTFOLIO

The Panoro portfolio reported here for year end 2022 is considered to comprise three assets with continuing operations with reserves and contingent resources, these are: Block G license in Equatorial Guinea, the Dussafu license in Gabon and the TPS Assets in Tunisia. A summary description of these assets with status as of year-end 2022 is included below. For additional background information on the assets, refer to the company's website. Unless otherwise specified, all reserves figures quoted in this report are net to Panoro's working interest.

BLOCK G: Offshore Equatorial Guinea Operator: Trident Energy, Panoro 14.25%

The Block G assets comprise a number of oil fields offshore Equatorial Guinea

The Block G license covers an area containing the Ceiba field and the Okume complex. The Okume complex consists of five separate oil fields. The fields in Block G started production in 2000-2002 and oil is produced through a number of wells either subsea or from fixed platforms and tied back to a FPSO.

Production from Block G during 2022 amounted to 11.3 MMbbls gross.

In April 2023 NSAI certified (3rd party) reserves and resources for the Block G licence. As of the end of December 2022, the Block G licence contained gross 1P Proved Reserves of 62.4 MMbbls in the Ceiba and Okume Complex fields. Gross 2P Proved plus Probable Reserves amounted to 100.0 MMbbls in the same fields. Gross 3P Proved plus Probable plus Possible Reserves in these fields amounted to 149.1 MMbbls.

In addition to these Reserves NSAI also certified gross unrisked 1C Contingent Resources of 42.1 MMbbls, gross unrisked 2C Contingent Resources of 93.0 MMbbls, and gross unrisked 3C Contingent Resources of 154.3 MMbbls in the Block G licence area.

These evaluations yield the following Reserves net to Panoro's working interest of 14.25%: 1P Proved Reserves of 8.89 MMbbls, 2P Proved plus Probable Reserves of 14.25 MMbbls and 3P Proved plus Probable plus Possible Reserves of 21.25 MMbbls. Additional unrisked Contingent Resources net to Panoro's working interest of 14.25% are 6.0 MMbbls 1C, 13.1 MMbbls 2C and 22.0 MMbbls 3C. These Reserves and Contingent Resources are Panoro's net working interest volumes before deductions for royalties and other taxes.

Panoro's net entitlement 1P reserves are 7.54 MMbbls, net entitlement 2P reserves are 11.82 MMbbls and net entitlement 3P reserves are 17.20 MMbbls.

DUSSAFU: Offshore Gabon Operator: BW Energy, Panoro 17.4997%

The Dussafu license contains the producing Tortue field and the Hibiscus/Ruche fields

Dussafu is a development and exploitation licence covering an area containing several oil fields, the most recent discovery being the Hibiscus North field. In 2014 an Exclusive Exploitation Authorisation (EEA) for an 850.5 km² area within the Dussafu PSC was awarded. The first field in the EEA area, Tortue, started oil production in 2018. The second set of fields, Ruche and Hibiscus is scheduled to start oil production during Q2 2023.

Production from the Tortue field during 2022 amounted to 3.9 MMbbls gross.

In March 2023 NSAI certified (3rd party) reserves and resources for the Dussafu licence. As of the end of December 2022, the Dussafu licence contained gross 1P Proved Reserves of 65.3 MMbbls. Gross 2P Proved plus Probable Reserves amounted to 96.7 MMbbls. Gross 3P Proved plus Probable plus Possible Reserves in Dussafu amounted to 124.0 MMbbls.

In addition to these Reserves NSAI also certified gross unrisked 1C Contingent Resources of 18.8 MMbbls, gross 2C Contingent Resources of 38.2 MMbbls, and gross 3C Contingent Resources of 68.3 MMbbls in the Dussafu licence area.

These evaluations yield the following Reserves net to Panoro's working interest of 17.5%: 1P Proved Reserves of 11.43 MMbbls, 2P Proved plus Probable Reserves of 16.92 MMbbls and 3P Proved plus Probable plus Possible Reserves of 21.70 MMbbls. Additional unrisked Contingent Resources net to Panoro's working interest of 17.5% are approximately 3.3 MMbbls 1C, 6.7 MMbbls 2C and 12.0 MMbbls 3C. These Reserves and Contingent Resources are Panoro's net working interest volumes before deductions for royalties and other taxes.

Panoro's net entitlement 1P reserves are 8.36 MMbbls, net entitlement 2P reserves are 11.55 MMbbls and net entitlement 3P reserves are 13.95 MMbbls.

TPS ASSETS: Onshore and Offshore Tunisia Operator: TPS, Panoro 29.4%

The TPS Assets comprise five oil field concessions in the region of the city of Sfax, onshore and shallow water offshore Tunisia

The concessions are Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba.

The oil fields were discovered in the 1980's and early 1990's and have produced a total of around 60 million barrels of oil to date. Production from the TPS assets amounted to 1.54 MMbbls gross, which is approximately 0.45 MMbbls net to Panoro's working interest share.

In March 2023 NSAI assessed reserves and resources from the fields as of end December 2022. Gross field reserves amount to 1P Proved Reserves of 10.5 MMbbls, 2P Proved plus Probable Reserves of 15.1 MMbbls and 3P Proved plus Probable plus Possible Reserves of 19.4 MMbbls. Panoro's net working interest 1P Proved reserves are 3.08 MMbbls, 2P Proved plus Probable are 4.44 MMbbls and 3P Proved plus Probable plus Possible are 5.71 MMbbls.

In addition to these reserves, NSAI also assessed gross 1C Contingent Resources of 7.7 MMbbls, 2C Contingent Resources of 13.4 MMbbls and 3C Contingent Resources of 23.0 MMbbls. Panoro's net working interest 1C Contingent Resource is 2.3 MMbbls, net working interest 2C Contingent Resource is 3.9 MMbbls and net working interest 3C Contingent Resource is 6.7 MMbbls. These Reserves and Contingent Resources are Panoro's net volumes before deductions for royalties and other taxes.

Panoro's net entitlement 1P reserves are 2.69 MMbbls, net entitlement 2P reserves are 3.86 MMbbls and net entitlement 3P reserves are 4.94 MMbbls.

MANAGEMENT DISCUSSION AND ANALYSIS

Panoro uses the services of NSAI for third party verifications of its reserves and resources.

All evaluations are based on standard industry practice and methodology for production decline analysis and reservoir modelling based on geological and geophysical analysis. The following discussions are a comparison of the volumes reported in previous reports, along with a discussion of the consequences for the year-end 2022 ASR:

Block G: In 2022, JV partners were awarded an extension to the term of the Block G PSC until the end of 2040. The additional production associated with this longer term has been converted from contingent resources to reserves. The NSAI reserves assessment takes this additional volume of reserves into account and as a result additional working interest 2P 2.7 million barrels of oil have been added compared to year end 2021.

Contingent resources in the Block G fields are associated with projects that have not yet been approved and potential production beyond the license expiry dates of the fields. Some of these contingent resources may be re-assigned as reserves if certain projects are approved or license terms further extended.

Dussafu: Some minor modifications were made to end 2022 reserves based on well performance and phasing of the Hibiscus/Ruche development project.

The remaining fields in Dussafu (Walt Whitman, Moubenga and Hibiscus North) and extensions to the other fields are classified as Contingent Resources. A decision to develop these fields will trigger a re-assignment of these resources as reserves and a possible re-determination of their volumes.

TPS: Minor modifications were made to TPS reserves based on 2022 well performance. Additional Contingent Resources were identified in the El Ain, Guebiba and Rhemoura fields in the TPS assets. These resources may be re-assigned as reserves if certain projects are approved or license terms extended.

ASSUMPTIONS:

The commerciality and economic tests for all of the reserves volumes were based on an oil price of USD80/bbl with 3% escalation.

2022 – 2P DEVELOPMENT (WORKING INTEREST)

2P Reserves Development	(MMBOE)
Balance (previous ASR –31 December 2021)	35.8
Production 2022	(2.8)
New developments since previous ASR	2.7
Revisions of previous estimates	(0.1)
Balance (revised ASR) as of 31 December 2022	35.6

Panoro's total 1P working interest reserves at end of 2022 amount to 23.41 MMbbls. Panoro's 2P reserves amount to 35.61 MMbbls and Panoro's 3P reserves amount to 48.65 MMbbls.

Panoro's Contingent Resource base includes discoveries of varying degrees of maturity towards development decisions. By the end of 2022, Panoro's assets contained a total un-risked 2C working interest volume of approximately 23.9 MMbbls.

27 April 2023

John Hamilton CEO

ANNEX RESERVES STATEMENT

AS OF 31 DECEMBER 2022

		1P (Low Estimate)			2P (Base Estimate)			3P (High Estimate)
		Liquids	Gas	Total	Net	Liquids	Gas	Total	Net	Liquids	Gas	Total	Net
	Interest %	MMbbls	Bcf	MMBOE	MMBOE	MMbbls	Bcf	MMBOE	MMBOE	MMbbls	Bcf	MMBOE	MMBOE
ON PRODUCTION
Dussafu	17.50	18.95	-	18.95	3.32	26.48	-	26.48	4.63	31.45	-	31.45	5.50
TPS	29.40	8.69	-	8.69	2.55	11.83	-	11.83	3.48	14.38	-	14.38	4.23
Block G	14.25	52.53	-	52.53	7.49	78.77	-	78.77	11.22	111.33	-	111.33	15.86
Total		80.16	-	80.16	13.36	117.08	-	117.08	19.34	157.16	-	157.16	25.60
APPROVED FOR DEVELOPMENT
Dussafu	17.50	33.34	-	33.34	5.83	47.86	-	47.86	8.38	58.85	-	58.85	10.30
TPS	29.40	1.02	-	1.02	0.30	1.35	-	1.35	0.40	1.66	-	1.66	0.49
Block G	14.25	8.26	-	8.26	1.18	15.29	-	15.29	2.18	25.87	-	25.87	3.69
Total		42.61	-	42.61	7.31	64.50	-	64.50	10.95	86.38	-	86.38	14.47
JUSTIFIED FOR DEVELOPMENT
Dussafu	17.50	13.02	-	13.02	2.28	22.35	-	22.35	3.91	33.68	-	33.68	5.89
TPS	29.40	0.79	-	0.79	0.23	1.92	-	1.92	0.56	3.37	-	3.37	0.99
Block G	14.25	1.61	-	1.61	0.23	5.94	-	5.94	0.85	11.92	-	11.92	1.70
Total		15.42	-	15.42	2.74	30.21	-	30.21	5.32	48.97	-	48.97	8.58

TOTALS
Total Reserves	138.20	-	138.20	23.41	211.79	-	211.79	35.61	292.51	-	292.51	48.65
Small rounding differences may arise due to rounding to the nearest MMBOE.

RESERVES DEVELOPMENT

2P Reserves Development	(MMBOE)
Balance (previous ASR –31 December 2021)	35.8
Production 20221	(2.8)
New developments since previous ASR2	2.7
Revisions of previous estimates	(0.1)
Balance (revised ASR) as of 31 December 2022	35.6

1. Represents TPS, Dussafu and Block G production in 2022.

2. Block G extension.

CONTINGENT RESOURCES SUMMARY

Asset	2C MMBOE (as of YE 2021)	2C MMBOE (as of this report)
Dussafu	6.8	6.7
TPS	1.6	3.9
Block G	20.9	13.3
Totals	29.3	23.9

CORPORATE GOVERNANCE

BOARD OF DIRECTORS

JULIEN BALKANY

Chairman of the Board

Mr. Balkany is a French citizen and a resident in London, who since 2014 has been Chairman of Panoro Energy ASA Board. Alongside this, since 2008, Mr. Balkany also serves as a Managing Partner of Nanes Balkany Partners, a group of investment funds that focuses on the oil & gas industry. Concomitantly, he is also Non-Executive Director of a private mining company, Pan-African Diamonds Limited. Mr. Balkany was previously a Non-Executive Director of several publicly listed oil & gas companies including Norwegian Energy Company (Noreco), Gasfrac Energy Services and Toreador Resources. He was also until end of 2021 on the Board of Amromco Energy, the largest privately held independent gas producer in Romania and on the Board of Sarmin Bauxite Ltd, another private mining company, until its sale to Lindian Resources. Mr. Balkany started his career as an oil and gas investment banker and studied at the Institute of Political Studies (Strasbourg) and at UC Berkeley.

Deputy Chairman of the Board

TORSTEIN SANNESS Mr. Torstein Sanness is a Norwegian citizen residing in Norway, who serves as the Company's Deputy Chairman of the Board of Directors. Mr. Sanness has served as a Board Member since 2015 and has extensive experience and technical expertise in the oil and gas industry. Mr. Sanness became the Chairman of Lundin Norway in April 2015. Prior to this position Mr. Sanness was Managing Director of Lundin Petroleum Norway from 2004 to 2015. Under his leadership Lundin Norway was turned into one of the most successful players on the ECS and added net discovered resources of close to a billion BOE to its portfolio through the discoveries of among others E. Grieg and Johan Sverdrup. Before joining Lundin Norway, Mr. Sanness was Managing Director of Det Norske Oljeselskap AS (wholly owned by DNO at the time) and was instrumental in discoveries of Alvheim, Volund and others. From 1975 to 2000, Mr. Sanness was at Saga Petroleum until the sale to Norsk Hydro and Statoil, where he held several executive positions in Norway as well as in the US. Currently Mr. Sanness is serving as Board Member of Lundin Energy and International Petroleum Corp. Also he is Executive Chairman of Magnora ASA with a renewable energy strategy in wind and solar. Mr. Sanness is also sitting on the Board of Carbon Transition ASA. Mr. Sanness is a graduate of the Norwegian Institute of Technology in Trondheim where he obtained a Master's Degree in Engineering (geology, geophysics and mining engineering).

GRACE REKSTEN SKAUGEN

Non-Executive Director

Non-Executive Director

Non-Executive Director

Ms. Grace Reksten Skaugen is a Norwegian citizen and is a board member and cofounder of the Norwegian Institute of Directors. She is non-executive director in several listed companies including the Swedish investment company Investor AB, the tanker company Euronav NV, PJT Partners, a 'boutique' US investment bank as well as Orrön Energy, a Nordic, renewable energy company. She is a Trustee of the International Institute for Strategic Studies (IISS) in London. She was deputy chair of Statoil (now Equinor), from 2012 to 2015. She spent several years working in Corporate Finance in the Nordic bank SEB and also held advisory positions in Deutsche Bank and HSBC. Grace is a physicist by education and has a PhD in laser physics from Imperial College in London. She also holds an MBA from BI Norwegian Business School.

ALEXANDRA HERGER Ms. Alexandra (Alex) Herger, a US citizen based in Maine, has extensive senior leadership and board experience in worldwide exploration and production for international oil and gas companies. Ms. Herger has 40 years of global experience in the energy industry, currently serving as an Independent director for Tortoise Capital Advisors, CEFs, based in Kansas, Tethys Oil based in Sweden, the nomination committee for PGS, based in Norway, as well as Panoro Energy ASA. Her most recent leadership experience was as Vice President for Marathon Oil Company until her retirement in July 2014. Prior to this position, Ms. Herger was Director of International Exploration and New Ventures for Marathon Oil Company from 2008 –2014, where she led five new country entries and was responsible for adding net discovered resources of over 500 million BOE to the Marathon portfolio. Ms. Herger was at Shell International and Shell USA from 2002-2008, holding positions as Exploration Manager for the Gulf of Mexico, Manager of Technical Assurance for the Western Hemisphere, and Global E & P Technical Assurance Consultant. Prior to the Shell / Enterprise Oil acquisition in 2002, Ms. Herger was Vice President of Exploration for the Gulf of Mexico for Enterprise Oil, responsible for the addition of multiple giant deep-water discoveries. Earlier, Ms. Herger held positions of increasing responsibility in oil and gas exploration and production, operations, and planning with Hess Corporation and ExxonMobil Corporation. Ms. Herger holds a Bachelor's Degree in Geology from Ohio Wesleyan University and post-graduate studies in Geology from the University of Houston.

GARRETT SODEN Mr. Garrett Soden has worked with the Lundin Group since 2007 and has extensive experience as a senior executive and board member of various public companies in the natural resources sector. Mr. Soden is currently President and CEO of Africa Energy Corp., a Canadian oil and gas exploration company focused on South Africa. He is also a Non-Executive Director of Gulf Keystone Petroleum Ltd. Mr. Soden holds a BSc honours degree from the London School of Economics and an MBA from Columbia Business School.

Non-Executive Director

HILDE ÅDLAND Ms. Hilde Ådland is a Norwegian citizen and has extensive technical experience in the oil and gas industry. She has leadership experience in field development, engineering, commissioning, asset management and field operations. Ms. Ådland is currently Vice President of the Norwegian Sea Area in Vår Energi. Ms. Ådland held several senior positions in Gas de France/GDF SUEZ/ENGIE/Neptune including Head of Operation and Asset manager for the operated Gjøa field during her 11 years in the company. She also spent 11 years with Statoil (now Equinor) in a number of senior engineering and operational roles, including Offshore Installation Manager at the Kristin field, and 6 years with Kvaerner. She has been active in the Norwegian Oil and Gas association and, in the period from autumn 2015 to spring 2019, has also been the chairman of the Operation Committee. She has a Bachelor's degree in chemical engineering and a Master's degree in process engineering. She is also Board Member of Magnora ASA and Chairman of the Board in NOFO (The Norwegian Clean Seas Association for Operating Companies).

SENIOR MANAGEMENT

JOHN HAMILTON Chief Executive Officer

John Hamilton, Chief Executive Officer (CEO), has considerable experience from various positions in the international oil and gas industry. Most recently, John was Chief Executive Officer of UK AIM listed President Energy PLC, a Latin American focused exploration company, which opened up a new onshore basin in Paraguay. Before joining President, John was Managing Director of Levine Capital Management, an oil and gas investment fund. He was also Chief Financial Officer of UK FTSE 250 listed Imperial Energy PLC, until its sale for over USD2 billion in 2008. John also spent 15 years with ABN AMRO Bank in Europe, Africa, and the Middle East. The majority of his time with ABN AMRO was spent in the energy group, with a principal focus on financing upstream oil and gas. John is also a member of the Board of Magnora ASA. John has a BA from Hamilton College in New York and a MBA from the Rotterdam School of Management and New York University. He is a British citizen and resides in London, UK.

QAZI QADEER Chief Financial Officer

Qazi Qadeer, Chief Financial Officer (CFO), is a Chartered Accountant with a Fellow membership of Institute of Chartered Accountants of Pakistan. Qazi joined Panoro at its inception in 2010 as Group Finance Controller. Previously he has worked for PricewaterhouseCoopers in Karachi, Pakistan, and briefly served as Internal audit manager in Pak-Arab Refinery before relocating to London, where he then spent more than five years with Ernst & Young's energy and extractive industry assurance practice, working on various projects for large and small oil & gas and mining companies. He has worked on several high-profile projects including the divestment of BP plc's chemicals business in 2005 and IPO of Gem Diamonds Limited in 2006. He is a British citizen and resides in London, UK.

RICHARD MORTON Technical Director

Richard Morton, Technical Director, has 30 years of experience in exploration, production, development and management in the oil and gas industry. Originally a highly qualified geophysicist, he has expanded his portfolio of skills progressively into operational and asset management. He has worked in a number of challenging contracting and operating environments, including as Centrica Energy's Exploration Manager for Nigeria. He has been with Panoro Energy since 2008 with responsibilities for project and technical management of Panoro's African exploration and development assets. Richard obtained a B.Sc. in Physics from Essex University in 1989 and went on to complete a M.Sc. in Applied Geophysics from the University of Birmingham the following year. He is a British citizen and resides in London, UK.

NIGEL MCKIM Projects Director

Nigel McKim, Projects Director, has over 30 years of experience in field development planning and production in the oil and gas industry. His most recent roles were as Chief Operations Officer for UK AIM listed MX Oil and, prior to that, the privately held Nobel Upstream. In both companies he was responsible for the technical capabilities and management of assets in Nigeria and Mexico in the former case and Texas, the UK and Azerbaijan in the latter. Prior to Nobel Upstream, he held the position of Director Pre-Developments for Hess, based in London and with global responsibilities for appraisal and early field development planning in Hess' conventional oil and gas business. Previously he was employed as West Africa Asset Manager at Vitol, Subsurface Manager for Business Development activities and the Liverpool Bay Project at BHP Billiton and started in the industry working as a Reservoir Engineer for Shell International in Oman and The Netherlands and as an Operations Engineer in Gabon. Nigel holds a BSc (Hons) in Civil Engineering from Bristol University and a MSc in Petroleum Engineering from Imperial College London, he is a Chartered Engineer. He is a British citizen and resides in London, UK.

Page: 36

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

FOR THE YEAR ENDED 31 DECEMBER

Amounts in USD 000, unless otherwise stated	Note	2022	2021
CONTINUING OPERATIONS
Oil revenue	3	180,267	113,708
Other revenue	3	8,359	5,949
Total revenues		188,626	119,657
Operating expenses
Operating costs		(51,901)	(41,022)
Exploration related costs and operator G&A	4	(166)	(6,438)
General and administrative costs	4	(8,317)	(7,242)
Depreciation, depletion and amortisation	8, 9	(35,164)	(27,550)
Acquisition and project related costs	4	(1,054)	(1,254)
Exploration costs written off	4	(9,210)	-
Share based payments	18	(1,591)	(1,231)
Total operating expenses		(107,403)	(84,737)
Operating profit		81,223	34,920
Gain on acquisition of business	13	-	46,121
Net foreign exchange gain / (loss)		(488)	411
Unrealised gain/(loss) on commodity hedges	5	2,622	(3,868)
Realised gain/(loss) on commodity hedges	5	(8,534)	(4,354)
Interest income	5	57	77
Interest costs	5	(10,158)	(7,049)
Realised (gain) / loss on listed equity instruments	5	(652)	-
Unrealised (gain) / loss on listed equity instruments	5	(75)	-
Other financial costs	5	(3,571)	(2,867)
Profit before income taxes		60,424	63,391
Income tax expense	6	(41,789)	(21,079)
Net profit from continuing operations		18,635	42,312
Net income/(loss) from discontinued operations	14	1,258	7,011
Total comprehensive income		19,893	49,323
NET INCOME /(LOSS) FOR THE PERIOD ATTRIBUTABLE TO:
Equity holders of the parent		19,893	49,323
TOTAL COMPREHENSIVE INCOME / (LOSS) FOR THE PERIOD ATTRIBUTABLE TO:
Equity holders of the parent		19,893	49,323
EARNINGS PER SHARE
Basic EPS on profit/(loss) for the period attributable to equity holders of the parent (USD) - Total	7	0.18	0.47
Diluted EPS on profit/(loss) for the period attributable to equity holders of the parent (USD) - Total	7	0.17	0.46
Basic and diluted EPS on profit/(loss) for the period attributable to equity holders of the parent (USD) - Continuing operations	7	0.16	0.40

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

AS AT 31 DECEMBER

USD 000	Note	2022	2021
ASSETS
Non-current assets
Production rights	8	173,975	188,832
Licenses and exploration assets	8	2,595	51,752
Investment in associates and joint ventures		26	26
Goodwill	8, 13	47,762	47,762
Production assets and equipment	9	97,359	120,269
Development assets	8	122,823	46,361
Property, furniture, fixtures and office equipment	9	200	550
Other non-current assets		121	135
Total Non-current assets		444,861	455,687
Current assets
Crude Oil Inventory		3,411	4,284
Materials Inventory		22,819	15,520
Trade and other receivables	10	35,109	55,629
Fair value of derivative financial instruments - current portion	19	133	-
Listed equity investments	11	342	-
Cash and cash equivalents	12	32,670	24,532
Total current assets		94,484	99,965
Assets classified as held for sale	14	-	29,015
Total Assets		539,345	584,667

CONSOLIDATED STATEMENT OF FINANCIAL POSITION – CONTINUED

AS AT 31 DECEMBER

USD 000	Note	2022	2021
EQUITY AND LIABILITIES
Equity
Share capital	16	723	721
Share premium	16	428,503	427,496
Additional paid-in capital		121,834	122,324
Total paid-in equity		551,060	550,541
Other reserves	16	(43,408)	(43,408)
Retained earnings		(301,149)	(311,694)
Total equity attributable to shareholders of the parent		206,503	195,439
Non-current liabilities
Decommissioning liability	15	123,654	140,839
Secured Loans	5	58,382	77,689
Licence Obligations		4,726	4,726
Other non-current liabilities	17	6,956	8,302
Deferred tax liabilities	6	67,283	74,109
Total Non-current liabilities		261,001	305,665
Accounts payable, accruals and other liabilities	17	9,087	12,707
Secured Loans - current portion	5	20,497	14,714
Non-Recourse Loan - current portion	5	632	4,507
Licence Obligations - current portion		1,166	1,166
Fair value of derivative financial instruments - current portion	19	-	2,489
Other current liabilities	17	4,899	10,623
Corporation tax liability	6	35,560	17,018
Total current liabilities		71,841	63,224
Liabilities directly associated with assets classified as held for sale	14	-	20,339
Total Equity and Liabilities		539,345	584,667

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE YEAR ENDED 31 DECEMBER

USD 000	Issued capital	Share premium	Additional paid-in capital	Retained earnings	Other reserves	Currency translation reserve	Total
At 1 January 2022	721	427,496	122,324	(311,694)	(37,647)	(5,761)	195,439
Net income/(loss) for the period - continuing operations	-	-	-	18,635	-	-	18,635
Net income/(loss) for the period - discontinued operations	-	-	-	1,258	-	-	1,258
Total comprehensive income/(loss)	-	-	-	19,893	-	-	19,893
Share issue for cash	-	-	-	-	-	-	-
Share issue for lender fees	-	-	-	-	-	-	-
Transaction costs on share issue	-	-	-	-	-	-	-
Share issue under RSU plan	2	1,007	-	-	-	-	1,009
Employee share options charge/(benefit)	-	-	1,591	-	-	-	1,591
Settlement of RSUs	-	-	(2,081)	-	-	-	(2,081)
Dividends (Note 11)	-	-	-	(9,348)	-	-	(9,348)
At 31 December 2022	723	428,503	121,834	(301,149)	(37,647)	(5,761)	206,503

Attributable to equity holders of the parent

Attributable to equity holders of the parent

USD 000	Issued capital	Share premium	Additional paid-in capital	Retained earnings	Other reserves	Currency translation reserve	Total
At 1 January 2021	459	349,446	122,465	(361,017)	(37,647)	(5,761)	67,945
Net income/(loss) for the period - continuing operations	-	-	-	42,312	-	-	42,312
Net income/(loss) for the period - discontinued operations	-	-	-	7,011	-	-	7,011
Total comprehensive income/(loss)	-	-	-	49,323	-	-	49,323
Share issue for cash	258	79,856	-	-	-	-	80,114
Share issue for lender fees	2	561	-	-	-	-	563
Transaction costs on share issue	-	(3,043)	-	-	-	-	(3,043)
Share issue under RSU plan	2	676	-	-	-	-	678
Employee share options charge/(benefit)	-	-	1,231	-	-	-	1,231
Settlement of RSUs	-	-	(1,372)	-	-	-	(1,372)
At 31 December 2021	721	427,496	122,324	(311,694)	(37,647)	(5,761)	195,439

CONSOLIDATED CASH FLOW STATEMENT

FOR THE YEAR ENDED 31 DECEMBER

USD 000	Note	2022	2021
CASH FLOW FROM OPERATING ACTIVITIES
Net (loss)/income for the period before tax - continuing operations		60,424	63,391
Net (loss)/income for the period before tax - discontinued operations		1,258	7,011
Net (loss)/income for the period before tax		61,682	70,402
ADJUSTED FOR:
Depreciation	4	35,164	27,550
Exploration related costs and Operator G&A		166	12,801
Impairment and asset write-off/(impairment reversal)	9.2	(1,497)	(8,000)
Loss/(gain) on commodity hedges	19	5,912	8,222
Gain on disposal/acquisition of business	14	-	(46,121)
Net finance costs		13,672	9,839
Share-based payments	18	1,591	1,231
Foreign exchange loss/(gain)		(32)	(6)
Increase/(decrease) in trade and other payables		12,490	(7,208)
(Increase)/decrease in trade and other receivables		19,188	18,111
(Increase)/decrease in inventories		(5,655)	6,190
State share of profit oil	3	(8,359)	(5,949)
Taxes paid		(21,714)	(16,664)
Net cash (out)/inflow from operations		112,608	70,398
CASH FLOW FROM INVESTING ACTIVITIES
Cash outflow related to licence extensions/acquisitions		(3,450)	(140,477)
Interest income		57	77
Investment in exploration, production and other assets		(64,312)	(55,736)
Net cash (out)/inflow from investing activities		(67,705)	(196,136)
CASH FLOW FROM FINANCING ACTIVITIES
Gross proceeds from loans and borrowings	5	-	90,000
Repayment of non-recourse loan		(4,065)	(3,106)
Repayment of Secured Loans		(14,730)	(13,384)
Realised gain/(loss) on commodity hedges	19	(8,534)	(4,354)
Borrowing costs, including arrangement fees		(8,140)	(5,450)
Gross proceeds from Share issues	16	-	81,240
Cost of Share issues		-	(3,043)
Cash cost of equity issue on settlement of RSUs		(1,072)	(694)
Lease liability payments	22	(231)	(254)
Financial charges		19	40
Cash held for Bank Guarantee		-	3,597
Net cash (out)/inflow from financing activities		(36,753)	144,592
Change in cash and cash equivalents during the period		8,150	18,854
Cash and cash equivalents – assets held for sale	14	(12)	4
Cash and cash equivalents at the beginning of the period		24,532	5,674
Cash and cash equivalents at the end of the period		32,670	24,532

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: CORPORATE INFORMATION

The parent company, Panoro Energy ASA ("the Company"), was incorporated on 28 April 2009 as a public limited company under the Norwegian Public Limited Companies Act. The registered organisation number of the Company is 994 051 067 and its registered office is c/o Advokatfirmaet Schjødt AS, Tordenskiolds gate 12, P.O. Box 2444 Solli, 0201 Oslo, Norway.

The Company and its subsidiaries ("Panoro" or the "Group") are engaged in the exploration and production of oil and gas resources in North, West and South Africa. The consolidated financial statements of the Group for the year ended 31 December 2022 were authorised for issue by the Board of Directors on 27 April 2023.

The Board of Directors confirms that the annual financial statements have been prepared pursuant to the going concern assumption, in accordance with §3-3a of the Norwegian Accounting Act, and that this assumption was realistic as at the balance sheet date. The going concern assumption is based upon the financial position of the Company and the development plans currently in place. In the Board of Directors' view, the annual accounts give a true and fair view of the group's assets and liabilities, financial position and results. Panoro Energy ASA is the parent company of the Panoro Group. Its financial statements have been prepared on the assumption that Panoro Energy will continue as a going concern.

As of 31 December 2022, the Group had USD 32.7 million in cash and bank balances and debt of USD 79.5 million resulting in a net debt position of approximately USD 46.8 million. In addition to Block G and Dussafu capital expenditure, the Company is committed to progress activities on Block EG-01 and Block S in Equatorial Guinea. Although the Company is well funded to undertake upcoming capital expenditure, there is risk that additional funding may be required to conclude such activities. Should additional funding be required in the future for additional capital expenditure for new development phases or working capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. Options include, amongst others, offtake prepayment structures, utilisation of undrawn financing facility and the issuance of shares. As a result, these financial statements have been prepared under the assumption of going concern and realisation of assets and settlement of debt in normal operations.

The Company's shares are traded on the Oslo Stock Exchange under the ticker symbol PEN.

NOTE 2: BASIS OF PREPARATION

The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union ("EU"). The consolidated financial statements are prepared on a historical cost basis, except for certain financial instruments which have been measured at fair value.

The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all years presented, unless otherwise stated.

The consolidated financial statements are presented in USD, which is the functional currency of Panoro Energy ASA. The amounts in these financial statements have been rounded to the nearest USD thousand unless otherwise stated.

Note 2.1: Changes in significant accounting policies

Standards, amendments to standards, and interpretations of standards, issued but not yet effective, are either not expected to materially impact the Company's consolidated financial statements, or are not expected to be relevant to the Company's consolidated financial statements upon adoption.

Note 2.2: Basis of consolidation

The consolidated financial statements include Panoro Energy ASA and its subsidiaries as of December 31 for each year.

Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases.

The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.

All intra-group balances, transactions and unrealised gains and losses resulting from intra-group transactions and dividends are eliminated in full.

Non-controlling interests in subsidiaries are identified separately from the Group's equity therein. Total comprehensive income is attributed to non-controlling interests even if this results in the non-controlling interests having a deficit balance.

A change in the ownership interest of a subsidiary, without a loss of control, is accounted for as an equity transaction. If the Group loses control over a subsidiary, it:

• derecognises the assets (including goodwill) and liabilities of the subsidiary
• derecognises the carrying amount of any NCI
• derecognises the cumulative translation differences recognised in equity
• recognises the fair value of the consideration received
• recognises the fair value of any investment retained
• recognises any surplus or deficit in profit or loss
• reclassifies the parent's share of components previously recognised in other comprehensive income to profit or loss or retained earnings, as appropriate.

The purchase method of accounting is applied for business combinations. The cost of the acquisition is measured as the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed, and equity instruments issued by the acquirer, in exchange for control of the acquirer.

If the initial accounting for a business combination can only be determined provisionally, then provisional values are used. However, these provisional values may be adjusted within 12 months from the date of the combination.

Note 2.3: Significant accounting judgments, estimates and assumptions

2.3.1. Estimates and assumptions

The preparation of the financial statements in conformity with IFRS as adopted by the EU requires and application of the Group's accounting policies require management to make judgements, estimates and assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of the consolidated financial statements and reported amounts of revenues and expenses during the reporting period. Judgements, estimates and assumptions are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. However, actual outcomes can differ from these estimates.

In particular, significant areas of uncertainty considered by management in preparing the consolidated financial statements are as follows:

Business combinations and goodwill

Acquisitions are accounted for as described in Note 2.4.3 Business combinations and goodwill

Significant areas requiring judgement, estimate and assumption to apply to establish the appropriate accounting treatment of such acquisitions include fair value of contingent consideration, assessment and appropriate classification of assumed assets and liabiliies and recognition of goodwill where fair values cannot reliably be measured.

Hydrocarbon reserve estimates

Hydrocarbon reserves are estimates of the amounts of hydrocarbons that can be economically and legally extracted from the Group's oil and gas properties. The Group estimates its commercial reserves based on information compiled by appropriately qualified persons relating to the geological and technical data on the size, depth, shape and grade of the hydrocarbon body and suitable production techniques and recovery rates. Commercial reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves and the proportion of the gross reserves which are attributable to the host government under the terms of the Production-Sharing Agreements. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities, and other capital costs.

The Group estimates and reports hydrocarbon reserves in line with the principles contained in the SPE Petroleum Resources Management Reporting System (PRMS) framework and generally obtains independent evaluations for each asset whenever new information becomes available that materially influences the reported results. As the economic assumptions used may

change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may change. Such changes may impact the Group's reported financial position and results, which include:

• The carrying value of exploration and evaluation assets; oil and gas properties; property, plant and equipment; and goodwill may be affected due to changes in estimated future cash flows
• Depreciation and amortisation charges in the statement of profit or loss and other comprehensive income may change where such charges are determined using the UOP method, or where the useful life of the related assets change
• Provisions for decommissioning may change where changes to the reserve estimates affect expectations about when such activities will occur and the associated cost of these activities
• The recognition and carrying value of deferred tax assets may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets

Income and deferred taxes

The Group recognises the net future tax benefit related to deferred income tax assets to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of deferred income tax assets requires the Group to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in each jurisdiction, to the extent that future cash flows and taxable income differ significantly from estimates. The ability of the Group to realise the net deferred tax assets recorded at the date of the statement of financial position could be impacted.

In addition, future changes in tax laws in the jurisdictions in which the Group operates could limit the ability of the Group to obtain tax deductions in future periods.

The Group is also subject to taxes under profit sharing contracts which are paid in kind as State share of profit oil. The value assigned to such taxes is subject to estimation, which may be different to the Company's realised oil prices for revenue recognition.

Impairment indicators

The Group assesses each cash-generating unit annually to determine whether an indication of impairment exists. When an indication of impairment exists, a formal estimate of the recoverable amount is made.

The recoverable amounts of cash-generating units and individual assets have been determined based on the higher of valuein-use calculations and fair values less costs to sell, or if relevant, a combination of these two models. These calculations require the use of estimates and assumptions. It is reasonably possible that the oil price assumption may change which may then impact the estimated life of the field and may then require a material adjustment to the carrying value of tangible assets. The Group monitors internal and external indicators of impairment relating to its tangible and intangible assets.

Asset retirement obligations

Asset retirement costs will be incurred by the Group at the end of the operating life of some of the Group's facilities and properties. The Group assesses its retirement obligation at each reporting date. The ultimate asset retirement costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing, extent and amount of expenditure can also change, for example in response to changes in reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for asset retirement obligation. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The provision at reporting date represents management's best estimate of the present value of the future asset retirement costs required.

Technical risk in development of oil and gas fields

The development of the oil and gas fields, in which the Group has an ownership, is associated with significant technical risk and uncertainty with regards to timing of additional production from new development activities. Risks include, but are not limited to, cost overruns, production disruptions as well as delays compared to initial plans laid out by the operator. Some of the most important risk factors are related to the determination of reserves, the recoverability of reserves, and the planning of a cost efficient and suitable production method. There are also technical risks present in the production phase that may cause cost overruns, failed investment and destruction of wells and reservoirs.

Estimates have been made after taking into account information available to management and factors in unknown uncertainties as of the date of the balance sheet.

Contingencies

By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events.

2.3.2. Judgments

In the process of applying the Group's accounting policies, the directors have made the following judgments, apart from those involving estimates, which have the most significant effect on the amounts recognised in the consolidated financial statements:

Risk relating to outbreak of war

The estimation of future oil and gas prices and discount rates is used in determining the recoverable amounts of cashgenerating units, individual assets and the Group's asset retirement costs. Risks related to the outbreak of war could result in higher energy prices amid concerns for regional energy shortages, inflationary pressures, and higher interest rates affecting discount rates.

Exploration and evaluation expenditures

The application of the Group's accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely, from future either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is itself an estimation process that requires varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalised, information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalised amount is written off in the statement of profit or loss and other comprehensive income in the period when the new information becomes available.

Note 2.4: Summary of significant accounting policies

2.4.1 Interests in associated companies and joint arrangements

A joint arrangement is an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control.

Associated companies are those entities in which the Group has significant influence, but not control or joint control over the financial and operating policies. Investments in associated companies are accounted for in the consolidated financial statements using the equity method of accounting. Equity accounting involves recording investments in associated companies initially at cost and recognising the Group's share of its associated companies' post-acquisition results and its share of postacquisition movements in reserves against the carrying amount of the investments. When the Group's share of losses in an associated company equals or exceeds its interest in the associated company, including any other unsecured receivables, the Group does not recognise further losses, unless it has incurred obligations or made payments on behalf of the associated company.

Joint arrangements, which are arrangements of which the Group has joint control together with one or more parties, are classified into joint ventures and joint operations. Joint ventures are joint arrangements in which the parties that share control have rights to the net assets of the arrangement. Joint operations are joint arrangements in which the parties that share joint control have rights to the assets, and obligations for the liabilities, relating to the arrangement.

For joint operations, the Group's share of all assets, liabilities, income and expenses is included in the consolidated financial statements. Acquisitions of interests in a joint operation, in which the activity of the joint operation constitutes a business, are accounted for according to the relevant IFRS 3 principles of accounting for business combinations.

On 11 December 2018, the Company entered into a joint arrangement through a shareholder agreement with Beender Petroleum Tunisia Limited ("Beender"), whereby Panoro and Beender jointly own and control 60% and 40% respectively of Sfax Petroleum Corporation AS ("Sfax Corp"). Sfax Corp, through its subsidiaries holds 100% shares of Panoro Tunisia Production AS ("PTP") and Panoro Tunisia Exploration AS ("PTE"). As such, the arrangement is a joint operation and all numbers and volume information relating to the Company's Tunisian operations and transactions represents the Group's 60% interest, unless otherwise stated.

Joint operations

A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement.

In relation to its interests in joint operations, the Group recognises its:

• Assets, including its share of any assets held jointly
• Liabilities, including its share of any liabilities incurred jointly
• Revenue from the sale of its share of the output arising from the joint operation
• Expenses, including its share of any expenses incurred jointly

Joint ventures

A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group's investment in its joint venture is accounted for using the equity method.

Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group's share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment.

The statement of profit or loss reflects the Group's share of the results of operations of joint ventures. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture.

The aggregate of the Group's share of profit or loss of the joint venture is shown on the face of the statement of profit or loss and other comprehensive income as part of operating profit and represents profit or loss after tax and NCI in the subsidiaries of the joint venture.

The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group.

At each reporting date, the Group determines whether there is objective evidence that the investment in the joint venture is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the joint venture and its carrying value, and then recognises the loss as 'Share of profit of a joint venture' in the statement of profit or loss and other comprehensive income.

On loss of joint control over the joint venture, the Group measures and recognises any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognised in the statement of profit or loss and other comprehensive income.

Reimbursement of costs of the operator of the joint arrangement

When the Group, acting as an operator or manager of a joint arrangement, receives reimbursement of direct costs recharged to the joint arrangement, such recharges represent reimbursements of costs that the operator incurred as an agent for the joint arrangement and therefore have no effect on profit or loss.

2.4.2 Foreign Currency translation

Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates ('the functional currency').

The functional currency of the Group's subsidiaries and jointly controlled companies incorporated in Gabon, Nigeria, Cyprus, Netherlands, Norway, Austria and the Cayman Islands is the US dollar ('USD').

In the consolidated financial statements, the assets and liabilities of non-USD functional currency balances are translated into USD at the rate of exchange ruling at the balance sheet date. The results and cash flows of non-USD functional currency subsidiaries are translated into USD using applicable average rates as an approximation for the exchange rates prevailing at the dates of the different transactions. Foreign exchange adjustments arising when the opening net assets and the profits for the year retained by non-USD functional currency subsidiaries are translated into USD are taken to a separate component of equity

The foreign exchange rates applied were:

		2022	2021
	Average rate	Reporting date rate	Average rate	Reporting date rate
Norwegian Kroner / USD	9.6149	9.8394	8.6002	8.8245
USD / British Pound Sterling	1.2367	1.2039	1.3755	1.3477
USD / Tunisian Dinar	3.0838	3.2482	2.7963	2.8865

Transactions in foreign currencies are initially recorded at the functional currency spot rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency spot rate of exchange ruling at the reporting date. All differences are taken to the income statement. Non-monetary items that are measured in terms of historical cost in foreign currency are translated using the spot exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined.

2.4.3 Business combinations and goodwill

In order to consider an acquisition as a business combination, the acquired asset or groups of assets must constitute a business (an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). The combination consists of inputs and processes applied to these inputs that have the ability to create output. Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the Group achieves control over the financial and operating assets. This date may differ from the actual date on which the assets are transferred. Comparative figures are not adjusted for acquired, sold or liquidated businesses. On acquisition of a licence that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any non-controlling interest (NCI) in the acquiree. For each business combination, the Group elects whether to measure NCI in the acquiree at fair value or at the proportionate share of the acquiree's identifiable net assets. Acquisition related costs are expensed as incurred and included in administrative expenses.

When the Group acquires a business, it assesses the assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. Those acquired petroleum reserves and resources that can be reliably measured are recognised separately in the assessment of fair values on acquisition. Other potential reserves, resources and rights, for which fair values cannot be reliably measured, are not recognised separately, but instead are subsumed in goodwill.

Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments is measured at fair value, with changes in fair value recognised either in the statement of profit or loss or as a change to other comprehensive income. If the contingent consideration is not within the scope of IFRS 9, it is measured in accordance with the appropriate IFRS. Contingent consideration that is classified as equity is not re-measured, and subsequent settlement is accounted for within equity.

Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for NCI over the fair value of the identifiable net assets acquired and liabilities assumed. If the fair value of the identifiable net assets acquired is in excess of the aggregate consideration transferred (bargain purchase), before recognising a gain, the Group reassesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognised in the statement of profit or loss and other comprehensive income.

After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group's cash generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.

Where goodwill forms part of a CGU and part of the operation in that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed of in these circumstances is measured based on the relative values of the disposed operation and the portion of the CGU retained.

2.4.4 License interests, exploration and evaluation assets, and field investments, and depreciation

The Group applies the 'successful efforts' method of accounting for Exploration and Evaluation ('E&E') costs, in accordance with IFRS 6 'Exploration for and Evaluation of Mineral Resources'. E&E expenditure is capitalised when it is considered probable that future economic benefits will be recoverable. Costs that are known at the time of incurrence to fail to meet this criterion are generally charged to expense in the period they are incurred.

E&E expenditure capitalised as intangible assets includes license acquisition costs, and exploration drilling, geological and geophysical costs and any other directly attributable costs.

E&E expenditure, which is not sufficiently related to a specific mineral resource to support capitalisation, is expensed as incurred.

E&E assets are carried forward, until the existence, or otherwise, of commercial reserves have been determined subject to certain limitations including review for indications of impairment. If no reserves are found the costs to drill exploratory wells, including exploratory geological and geophysical costs and costs of carrying and retaining unproved properties, are written off.

Once commercial reserves have been discovered, the carrying value after any impairment loss of the relevant E&E assets is transferred to development tangible and intangible assets. No depreciation and/or amortisation are charged during the exploration and development phase. If however, commercial reserves have not been discovered, the capitalised costs are charged to expense after the conclusion of appraisal activities.

Development tangible and intangible assets

Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of commercially proven development wells, is capitalised within property, plant and equipment and intangible assets according to nature. When development is completed on a specific field, these costs are transferred to production assets. No depreciation or amortisation is charged during the Exploration and Evaluation phase.

Farm-outs – in the exploration and evaluation phase

The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements but redesignates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the Group as a gain on disposal.

Development costs

Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within oil and gas properties.

Oil & gas production assets

Development and production assets are accumulated on a cash-generating unit basis and represent the cost of developing the commercial reserves discovered and bringing them into production together with E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined in accounting policy above.

The cost of development and production assets also includes the cost of acquisitions and purchases of such assets, directly attributable overheads and the cost of recognising provisions for future restoration and decommissioning.

Where major and identifiable parts of the production assets have different useful lives, they are accounted for as separate items of property, plant and equipment. Costs of minor repairs and maintenance are expensed as incurred.

Depreciation/amortisation

Oil and gas properties are not depleted until production commences. Costs relating to each single field cost centre are depleted on a unit of production method based on the commercial proved and probable reserves for that cost centre. The depletion calculation takes account of the estimated future costs of development of management's assessment of proved and probable reserves, reflecting risks applicable to the specific assets. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date.

Field infrastructure exceeding beyond the life of the field is depreciated over the useful life of the infrastructure using a straightline method.

Depreciation/amortisation on assets held for sale is ceased from the date of such classification.

Impairment – exploration and evaluation assets

E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount and when they are reclassified to PP&E assets. For the purpose of impairment testing, E&E assets are grouped by concession or field with other E&E and PP&E assets belonging to the same CGU. The impairment loss will be calculated as the excess of the carrying value over recoverable amount of the E&E impairment grouping and any resulting impairment loss is recognised in profit or loss. The recoverable amount of a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In assessing fair value less costs to sell, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risk specific to the asset. Fair value less costs to sell is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.

Impairment – proved oil and gas production properties and intangible assets

Proven oil and gas properties and intangible assets are reviewed annually for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The carrying value is compared against the expected recoverable amount of the asset, generally by net present value of the future net cash flows, expected to be derived from production of commercial reserves or consideration expected to be achieved through the sale of its interest in an arms-length transaction, less any associated costs to sell. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped together where there are common facilities.

Climate considerations in impairment assessment

Climate change and transition to a lower carbon economy is considered in the impairment assessments. In the context of assessing the potential impact on the book values related to the Group's oil and gas assets, certain climate considerations are factored into the Group's estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation in jurisdictions where the Group has operations and estimation of future levels of environmental taxes, if any. An energy transition is likely to impact the future oil and gas prices which in turn may affect the recoverable amount of the oil and gas assets. Indirectly, climate considerations are also assessed in the forecasting of oil and gas prices where supply and demand are considered. A significant reduction in the Company's oil and gas price assumptions would result in impairments on certain production and development assets including intangible assets that are subject to impairment assessment under IAS 36, but an opposite revision in the price assumptions would lead to limited impairment reversals as most of the impairments recognized were related to impairment of goodwill which cannot be reversed under IFRS.

In the context of testing robustness of the oil and gas assets against the scenarios from the International Energy Agency (IEA), the Company has applied the Net Zero Emissions Scenario, Stated Policies Scenario and Sustainable Development Scenario

as published by the IEA as part of the World Energy Outlook (WEO) reports. These scenarios are commonly applied by peer companies and the Company believes are useful to investors and other stakeholders in assessing portfolio resilience across companies in the industry. For more details, see Note 9.2: Impairment in Oil and Gas Interests.

2.4.5 Non-current assets held for sale or for distribution to equity holders of the parent and discontinued operations

The Group classifies non-current assets and disposal groups as held for sale or for distribution to equity holders of the parent if their carrying amounts will be recovered principally through a sale or distribution rather than through continuing use. Such noncurrent assets and disposal groups classified as held for sale or as held for distribution are measured at the lower of their carrying amount and fair value less costs to sell or to distribute. Costs to distribute are the incremental costs directly attributable to the distribution, excluding the finance costs and income tax expense.

The criteria for held for distribution classification is regarded as met only when the distribution is highly probable and the asset or disposal group is available for immediate distribution in its present condition. Actions required to complete the distribution should indicate that it is unlikely that significant changes to the distribution will be made or that the distribution with be withdrawn. Management must be committed to the distribution expected within one year from the date of the classification. Similar considerations apply to assets or a disposal group held for sale.

Production assets, property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale or as held for distribution.

Assets and liabilities classified as held for sale or for distribution are presented separately as current items in the statement of financial position.

A disposal group qualifies as discontinued operation if it is:

• a component of the Group that is a CGU or a group of CGUs
• classified as held for sale or distribution or already disposed in such a way, or
• a major line of business or major geographical area.

Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss.

2.4.6 Financial instruments

2.4.6.1 Derivative financial instruments and hedge accounting

The Group enters into derivative financial instruments including zero cost collars and commodity swaps to manage its exposure to volatility in the commodity prices realised for a proportion of its crude oil production. All derivative financial instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently remeasured at their fair value at each period end. Apart from those derivatives designated as qualifying cash flow hedging instruments, all changes in fair value are recorded as financial income or expense in the year in which they arise, otherwise they are recognised in other comprehensive income.

For derivatives not designed as qualifying for cash flow hedging, the fair value at balance sheet date is based on fair value provided by the counterparties with whom the trades have been entered into. The derivatives are valued using a Black-Scholes based methodology. The inputs to these valuations include price of oil and its volatility. Fair value is the amount for which a financial asset, liability or instrument could be exchanged between knowledgeable and willing parties in an arm's length transaction. It is determined by reference to quoted market prices adjusted for estimated transaction costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models and estimated discounted values of cash flows.

2.4.6.2 Financial assets

Financial assets are recognised initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below. The group derecognises financial assets when the contractual rights to the cash flows expire or the financial asset is transferred to a third party. This includes the derecognition of receivables for which discounting arrangements are entered into. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.

Financial assets measured at amortised cost

Financial assets are classified as measured at amortised cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortised cost using the effective interest method if the time value of money is significant. Gains and losses are recognised in profit or loss when the assets are derecognised or impaired and when interest is recognised using the effective interest method. This category of financial assets includes trade and other receivables.

Financial assets measured at fair value through profit or loss

Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortised cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives and listed equity investments, other than those designated as effective hedging instruments, are included in this category. Dividends on listed equity investments are recognised as other income in the statement of profit or loss when the right of payment has been established.

Cash equivalents

Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortised cost.

Cash held for Bank guarantee - restricted

Cash held for Bank guarantee relates to resources or collateral held by a bank which can only be accessed through fulfilment of conditions imposed by counter parties. Funds are only classified from restricted cash status to cash equivalents when funds are transferred to and under the control of the Group.

Impairment of financial assets measured at amortised cost

The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortised cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk. Since this is typically less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group's in-scope financial assets. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset's carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset's original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognised in the income statement. A financial asset or group of financial assets classified as measured at amortised cost is considered to be creditimpaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.

2.4.6.3 Financial liabilities

The measurement of financial liabilities depends on their classification as follows:

Financial liabilities measured at fair value through profit or loss

Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognised in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.

Financial liabilities measured at amortised cost

Other financial liabilities, including borrowings, are initially measured at fair value, net of transaction costs. Other financial liabilities are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis. This category of financial liabilities includes trade and other payables and finance debt.

2.4.7 Fair value measurement and hierarchy

The Group measures derivatives at fair value at each balance sheet date and, for the purposes of impairment testing, uses fair value less costs of disposal to determine the recoverable amount of some of its non-financial assets.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place either:

• In the principal market for the asset or liability, or
• In the absence of a principal market, in the most advantageous market for the asset or liability

The principal or the most advantageous market must be accessible by the Group.

The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest.

A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use.

The Group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximising the use of relevant observable inputs and minimising the use of unobservable inputs.

All assets and liabilities for which fair value is measured or disclosed in the financial statements are categorised within the fair value hierarchy, described as follows, based on the lowest-level input that is significant to the fair value measurement as a whole:

• Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities,
• Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and
• Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data.

For assets and liabilities that are recognised in the financial statements on a recurring basis, the Group determines whether transfers have occurred between levels in the hierarchy by reassessing categorisation (based on the lowest-level input that is significant to the fair value measurement as a whole) at the end of each reporting period.

For the purpose of fair value disclosures, the Group has determined classes of assets and liabilities based on the nature, characteristics and risks of the asset or liability and the level of the fair value hierarchy as explained above.

2.4.8 Provisions

General

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Group expects some or all of the provision to be reimbursed, for example under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is recognised through profit and loss net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as interest expense. The present obligation under onerous contracts is recognised as a provision.

2.4.9 Asset retirement obligation

An asset retirement liability is recognised when the Group has a present legal or constructive obligation as a result of past events, and it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made. A corresponding amount equivalent to the obligation is also recognised as part of the cost of the related production plant and equipment. The amount recognised in the estimated cost of asset retirement, discounted to its present value. Changes in the estimated timing of asset retirement or asset retirement cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to production plant and equipment. The unwinding of the discount on the asset retirement provision is included as a finance cost.

2.4.10 Income tax

Income tax expense represents the sum of the tax currently payable and movement in deferred tax.

Current tax

Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the reporting date, in the countries where the Group operates and generates taxable income.

Current income tax relating to items recognised directly in equity is recognised in equity and not in the income statement. Management periodically evaluates positions taken in the tax returns with respect to situations which applicable tax regulations are subject to interpretation and established provisions where appropriate.

Deferred tax

Deferred tax is provided using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

Deferred income tax liabilities are recognised for all taxable temporary differences, except:

• Where the deferred tax liability arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affect neither the accounting profit nor taxable profit or loss; and
• In respect of taxable temporary differences associated with investments in subsidiaries, associates and interest in joint ventures, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future.

Deferred tax assets are recognised for all deductible temporary differences; carry forward to unused tax credits and unused tax losses, to the extent that it is probable that future taxable profit will be available against which the deductible temporary differences and the carry forward of unused tax credits and unused tax losses can be utilised except:

• Where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and
• In respect of deductible temporary differences associate with investments in subsidiaries, associate and interest in joint ventures, deferred income tax assets are recognised only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilised.

The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient future taxable profit will be available to allow all or part of the deferred tax asset to be utilised. Unrecognised deferred tax assets are reassessed at each reporting date and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realised or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date.

Deferred tax relating to items recognised directly in equity is recognised in equity and not in the income statement.

Deferred tax assets and deferred tax liabilities are offset, if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.

Tax benefits acquired as part of a business combination, but not satisfying the criteria for separate recognition at that date, would be recognised subsequently if new information about facts and circumstances arose. The adjustment would either be treated as a reduction to goodwill (as long as it does not exceed goodwill) if it occurred during the measurement period or in profit or loss.

Production-sharing arrangements

According to the production-sharing arrangement (PSA) in certain licenses, the share of the profit oil to which the government is entitled in any calendar year in accordance with the PSA is deemed to include a portion representing the corporate income tax imposed upon and due by the Group. This amount will be paid directly by the government on behalf of Group to the appropriate tax authorities. This portion of income tax and revenue are presented separately in income statement.

Sales tax

Revenues, expenses and assets are recognised net of the amount of sales tax except:

Sales tax is recognised as part of the cost of acquisition of the asset or as part of the expense item as applicable if the sales tax incurred on a purchase of assets or services is not recoverable from taxation authorities.

Receivables and payables that are stated with the amount of sales tax included.

The net amount of sales tax recoverable from, or payable to, taxation authorities is included as part of receivables or payables in the statement of financial position.

2.4.11 Revenue recognition

Revenue from petroleum products

Revenue from the sale of crude oil is recognised when a customer obtains control ("sales" or "lifting" method), normally this is when title passes at point of delivery. Revenues from production of oil properties are recognised based on actual volumes lifted and sold to customers during the period. Where the Group has lifted and sold more than the ownership interest, an accrual is recognised for the cost of the overlift. Where the Group has lifted and sold less than the ownership interest, costs are deferred for the underlift. Overlift and underlift on the Consolidated statement of financial position date are valued at production costs. Lifting imbalances are a part of the operating cycle and as such classified as other current liabilities/assets. Under a production sharing contract, where the group is required to pay profit oil tax on production of crude oil, such payment can either be settled (i) in kind (where the government lift the crude it is entitled to); or (ii) in cash (where the Group sells the crude and pays the taxes in cash). The group presents a gross-up of the profit oil tax as an income tax expense with a corresponding increase in oil and gas revenues.

Interest income and financial instruments measured at amortised cost

Interest income is recognised on an accruals basis. For all financial instruments measured at amortised cost and interestbearing financial assets measured at fair value through profit and loss, interest income or expense is recorded using the effective interest rate (EIR), which is the rate that exactly discounts the estimated future cash payments or receipts through the expected life of the financial instrument or a shorter period, where appropriate, to the net carrying amount of the financial asset or liability. Interest revenue is included in finance income in income statement.

2.4.12 Leases

At contract inception, an assessment is made of all arrangements to determine whether they are, or contain, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Group is not a lessor in any transactions, it is only a lessee.

The Group applies a single recognition and measurement approach for all leases, except for short-term leases of 12 months or less and leases of low-value assets. The Group recognises lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets.

Right-of-use assets

The Group recognises right-of-use assets at the commencement date of the lease (i.e., the date the underlying asset is available for use). Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The only right-of-use asset, the London office lease, is depreciated on a straight-line basis over the lease term.

If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a purchase option, depreciation is calculated using the estimated useful life of the asset.

2.4.13 Property, plant and equipment

Property, plant and equipment not associated with exploration and production activities are carried at cost less accumulated depreciation. These assets are also evaluated for impairment. Depreciation of other assets is calculated on a straight-line basis as follows:

Computer equipment:	20 to 33.33%
Furniture, Fixtures & fittings:	10 to 33.33%

2.4.14 Inventories

Inventories, consisting of crude oil, and drilling and maintenance materials, are stated at the lower of cost and net realisable value. Costs comprise costs of purchase, costs of conversion and other costs incurred in bringing the inventories to their present location and condition. Weighted average cost is used to determine the cost of ordinarily inter-changeable items.

2.4.15 Defined contribution pension plan

The Group pays contributions into a defined contribution plan. Obligations for contributions to defined contribution pension plans are recognised as an expense in the income statement in the periods during which services are rendered by employees.

2.4.16 Share-based payment transactions

Employees (including senior executives) of the Group may receive remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments (equity-settled transactions).

Equity-settled transactions

The cost of equity-settled transactions is recognised, together with a corresponding increase in additional paid in capital reserve in equity, over the period in which the performance and/or service conditions are fulfilled. The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The income statement expense or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period and is recognised in share-based payments expense.

No expense is recognised for awards that do not ultimately vest, except for equity-settled transactions for which vesting are conditional upon a market or non-vesting condition. These are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are satisfied.

When the terms of an equity-settled transaction award are modified, the minimum expense recognised is the expense as if the terms had not been modified, if the original terms of the award are met. An additional expense is recognised for any modification that increases the total fair value of the share-based payment transaction or is otherwise beneficial to the employee as measured at the date of modification.

When an equity-settled award is cancelled, it is treated as if it vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. This includes any award where non-vesting conditions within the control of either the entity or the employee are not met. However, if a new award is substituted for the cancelled award and designated as a replacement award on the date that it is granted, the cancelled and new awards are treated as if they were a modification of the original award, as described in the previous paragraph.

The dilutive effect of outstanding options is reflected as additional share dilution in the computation of diluted earnings per share.

2.4.17 Impairment of non-oil and gas interests

Non-financial assets

Assets that are subject to amortisation or depreciation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Goodwill is assessed for impairment on an annual basis. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows (cash-generating units). Non-financial assets that were previously impaired are reviewed for possible reversal of the impairment at each reporting date.

An assessment is made at each reporting date to determine whether there is an indication that previously recognised impairment losses may no longer exist or may have decreased. If such indication exists, the asset's recoverable amount is estimated. A previously recognised impairment loss is reversed only if there has been a change in the assumptions used to determine the asset's recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such a reversal is recognised in the income statement. After such a reversal the depreciation charge is adjusted in future periods to allocate the asset's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

Financial assets

Assets carried at amortised cost

If there is objective evidence that an impairment loss on assets carried at amortised cost has been incurred, the amount of the loss is measured as the difference between the assets' carrying amount and the present value of estimated future cash flows (excluding future expected credit losses that have not been incurred) discounted at the financial asset's original effective interest rate (i.e. the effective interest rate computed at initial recognition). The carrying amount of the asset is reduced through use of an allowance account. The amount of the loss shall be recognised in the income statement.

If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed, to the extent that the carrying value of the asset does not exceed its amortised cost at the reversal date, any subsequent reversal of an impairment loss is recognised in the income statement.

2.4.18 Current versus non-current classification

The Group presents assets and liabilities in the statement of financial position based on current/non-current classification. An asset is current when it is either:

• Expected to be realised or intended to be sold or consumed in the normal operating cycle
• Held primarily for the purpose of trading
• Expected to be realised within 12 months after the reporting period
• Cash or cash equivalent unless restricted from being exchanged or used to settle a liability for at least 12 months after the reporting period

All other assets are classified as non-current.

A liability is current when either:

• It is expected to be settled in the normal operating cycle
• It is held primarily for the purpose of trading
• It is due to be settled within 12 months after the reporting period
• There is no unconditional right to defer the settlement of the liability for at least 12 months after the reporting period

The Group classifies all other liabilities as non-current. Deferred tax assets and liabilities are classified as non-current assets and liabilities.

Note 2.5: New and amended standards and interpretations

No standard amendments or interpretations of standards effective as of 1 January 2022 and adopted by Panoro, were material to the Group's Consolidated financial statements upon adoption.

Note 2.6: Standards issued but not yet effective

At the date of these Consolidated financial statements, standards amendments to standards, and interpretations of standards, issued but not yet effective, are either not expected to materially impact Panoro's Consolidated financial statements, or are not expected to be relevant to Panoro's Consolidated financial statements upon adoption.

The Group has not early adopted any other standard, interpretation or amendment that was issued but is not yet effective.

NOTE 3: OPERATING SEGMENTS

The Group operated predominantly in four business segments being the exploration and production of oil and gas in Equatorial Guinea, Gabon, Tunisia and South Africa.

As noted above, from December 2019, the business in Nigeria is classified as a "Discontinued Operation" and as an "Asset held for sale". Segment information has therefore been re-arranged in line with reporting requirements for such item.

The Group's reportable segments, for both management and financial reporting purposes, are as follows:

• The Equatorial Guinea segment holds Block G, consisting of the Ceiba Field and Okume Complex in which the Group owns a 14.25% working interest. This interest was acquired from Tullow Overseas Holdings B.V. on 31 March 2021.
• The Gabon segment holds the Dussafu licence representing the Group's 17.4997% working interest in the Dussafu Marin exploration licence in Gabon. This includes an additional 10% working interest acquired from Tullow Oil Gabon SA on 9 June 2021.
• The Tunisia segment holds the following assets:
  • Sfax Offshore Exploration Permit: Panoro Tunisia Exploration AS (Operator, 52.5%* interest net to Panoro)
  • The Hammamet Offshore Exploration Permit: Medco (Operator), Panoro Tunisia Exploration AS (27.6%* interest net to Panoro), under relinquishment
  • TPS Assets: ETAP, 51% and Panoro TPS Production GmbH, 49% (29.4%* interest net to Panoro).

* Figures only represent net participation interest in proportion to Panoro's equity holding in Sfax Petroleum Corporation AS.

• The 'South Africa' segment holds the following assets:
  • The Block 2B licence representing the Group's 12.5% working interest
  • 100% interest in the Karoo Technical Cooperation Permit 218, South Africa
• The 'Corporate and others' category consists of head office and service company operations that are not directly attributable to the other segments. Further, it also includes the residual corporate business in Brazil which is expected to be dormant in the foreseeable future.
• Discontinued Operations and Assets held for sale:
  • OML113-Aje represents the Group's 12.1913% revenue interest, 16.255% paying interest and 6.502% participating interest) in the OML113-Aje exploration licence in Nigeria.

Management monitors the operating results of business segments separately for the purpose of making decisions about resources to be allocated and of assessing performance. Segment performance is evaluated based on capital and general expenditure. Details of group segments are reported below.

Details of Group segments are reported below:

2022

	Equatorial			South		Total - continuing	Aje-OML 113 discontinued
USD 000	Guinea	Gabon	Tunisia	Africa	Corporate	operations	operations	Total
Revenue (net) *	80,953	67,537	40,136	-	-	188,626	1,181	189,807
EBITDA	66,106	37,835	28,780	(596)	(4,937)	127,188	1,498	128,686
Depreciation	(23,778)	(7,068)	(4,002)	-	(316)	(35,164)	-	(35,164)
Impairment (charge)/reversal	-	-	-	-	-	-	1,497	1,497
Profit/(loss) before tax	37,425	30,251	17,877	(10,048)	(15,081)	60,424	1,258	61,682
Net Profit/(loss)	19,500	21,889	2,377	(10,048)	(15,083)	18,635	1,258	19,893
Segment assets **	240,423	219,544	60,849	17	18,512	539,345	-	539,345
Additions to licences, production, E&E and development assets ***	6,985	37,447	597	-	-	45,029	-	45,029

2021

USD 000 Revenue (net) *	Equatorial Guinea 51,563	Gabon 41,734	Tunisia 26,360	South Africa -	Corporate -	Total - continuing operations 119,657	Aje-OML 113 discontinued operations 3,688	Total 123,345
EBITDA	37,702	21,519	10,326	-	(5,846)	63,701	7,455	71,156
Depreciation	(18,236)	(3,807)	(5,271)	-	(236)	(27,550)	-	(27,550)
Impairment (charge)/reversal	-	-	-	-	-	-	8,000	8,000
Profit/(loss) before tax	15,649	63,279	(2,926)	-	(12,611)	63,391	7,011	70,402
Net Profit/(loss)	7,384	57,330	(9,775)	-	(12,627)	42,312	7,011	49,323
Segment assets	286,974	188,392	60,481	-	19,805	555,652	29,015	584,667
Additions to licences, production, E&E and development assets ***	213,315	126,261	568	-	11	340,155	298	340,453

* Revenue excludes any intercompany revenue.

** Refer to Note 14: Discontinued Operations for segment assets related to discontinued operations (OML 113, Aje).

*** Excludes effect on production assets and equipment of the reasessment of decommissioning liabilities of USD 16.9 million in 2022, refer to Note 15: Asset Retirement Obligation. Includes additions from acquisitions, see Note 13: Business Combinations, but excludes reversal of impairment of USD 1.2 million (2021: USD 8 million).

Revenue from major sources from continuing operations:

USD 000	2022	2021
Oil revenue (net)	180,267	113,708
Other revenue	8,359	5,949
Total revenue	188,626	119,657

There are no differences in the nature of measurement methods used on segment level compared with the consolidated financial statements. The oil revenue from continuing operations relates to sale of hydrocarbons from three assets, Block G in Equatorial Guinea, Dussafu in Gabon and TPS in Tunisia. The Group has local obligations in Tunisia and 20% of produced volumes are sold to the Tunisian State Oil Company, Entreprise Tunisienne D' Activites Petrolieres (ETAP) in order to fulfil the Group's domestic market obligations. All international sales of the Group in Tunisia during 2022 were to a single customer, Mercuria Energy Trading SA, through a crude marketing agreement. All sales in 2022 from the Group's production from Block G in Equatorial Guinea and Dussafu in Gabon arose from one key customer each.

Under the terms of the Dussafu PSC, State profit oil is estimated and shown as other revenue with a corresponding amount as income tax, see Note 2.4.10 Income tax. There are no other items included in other revenue for both periods presented.

NOTE 4: OPERATING RESULT

Operating profit is stated after charging/ (crediting):

USD 000	Note	2022	2021
Employee benefits expense		5,332	4,166
Depreciation	8, 9	35,164	27,550
Acquisition and project related costs (i)		1,054	1,254

(i) Acquisition and project related costs in 2022 of USD 0.6 million relate organisational restructure in Tunisia and the remaining USD 0.4 million, to business development activities. In 2021, costs of USD 1.1 million were incurred on the Equatorial Guinea and Dussafu acquisitions as described in Note 13: Business Combinations.

Note 4.1: Exploration related costs

The Gazania-1 exploration well located at Block 2B offshore the Northern Cape in Orange Basin, South Africa, was drilled without incident. The well did not encounter commercial hydrocarbons. As a result capitalised exploration costs of USD 9.2 million were written off during the year.

In 2021 a historical non-fulfilment of a work programme related to Sfax Offshore Exploration Permit by a previous operator was settled during 2021 at a cost of USD 6.3 million. The settlement was made by way of a partial draw on the bank guarantee wih the remaining remaining USD 3.6 million cancelled and cash returned to Panoro. As part of the settlement, the license entered the second renewal period of one year which was later extended a further two years on the condition that a seismic reprocessing project would be completed.

Note 4.2: Employee benefit expenses

General and administrative expenses include wages, employer's contribution and other compensation as detailed below:

Other compensation Total	226 5,332	70 4,166
Pension costs	235	118
Employers' contribution	588	555
Salaries	4,283	3,423
USD 000	2022	2021

The number of employees in the Group as at year end is detailed below:

	2022	2021
Number of employees	25	29

The number of employees does not include temporary contract staff and personnel employed by joint ventures where the group is participating as non-operated partner.

Note 4.3: Board of Directors statement on remuneration of executives

Statement for the current year (2022)

In accordance with the Norwegian Public Limited Liability Companies Act §6-16a, the Board of Directors must prepare a statement on remuneration of executives. These statements can be referred to on page 104 of this report.

Note 4.4: Management remuneration

Executive management consists of the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and two other Named Executives as described below. Current Executive management remuneration is summarised below:

2022	Short term benefits
USD 000 (unless stated otherwise)	Salary	Bonus	Benefits	Pension costs	Total	Number of RSUs awarded in 2022	Fair value of RSUs expensed
John Hamilton, CEO	472	181	11	5	669	131,772	512
Qazi Qadeer, CFO	311	119	5	5	440	64,983	195
Other Named Executives (vi)	596	227	10	12	845	127,014	382
Total	1,379	527	26	22	1,954	323,769	1,089

2021			Short term benefits
USD 000 (unless stated otherwise)	Salary	Bonus	Benefits	Pension costs	Total	Number of RSUs awarded in 2021	Fair value of RSUs expensed
John Hamilton, CEO	484	595	12	5	1,096	166,822	483
Qazi Qadeer, CFO	317	330	5	5	658	54,846	157
Other Named Executives (vi)	606	359	10	13	988	107,198	302
Total	1,407	1,285	27	23	2,742	328,866	942

(i) Under the terms of employment, the CEO and the CFO in general are required to give at least six month's written notice prior to leaving Panoro. Other Named Executives have notice periods between three and six months.

(ii) Per the respective terms of employment, the CEO is entitled to 12 months of base salary in the event of a change of control; whereby a tender offer is made or consummated for the ownership of more than 50% or more of the outstanding voting securities of the Company; or the Company is merged or consolidated with another corporation and as a result of such merger or consolidation less than 50.1% of the outstanding voting securities of the surviving entity or resulting corporation are owned in the aggregate by the persons, by the entities or persons who were shareholders of the Company immediately prior to such merger or consolidation; or the Company sells substantially all of its assets to another corporation that is not a wholly owned subsidiary. The CFO is entitled to 6 months of base salary in the event of a change of control.

• (iii) In July 2022, 487,434 Restricted Share Units were awarded under and in accordance with the Company's RSU scheme to the employees of the Company under the long-term incentive compensation plan approved by the shareholders. One Restricted Share Unit ("RSU") entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years, and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period which was the case in some prior year awards. RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter.
• (iv) All salaries, bonuses and benefit payments have been expensed as incurred. The 2021 bonus included a one-off discretionary cash award to key management by the Board of Directors in recognition of the success of Transformational Tullow acquisitions, which increased Panoro's production and reserves by a factor of 3-4 times.
• (v) All bonuses were approved by the Board of Directors.
• (vi) Remuneration details for Other Named Executives include Mr. Richard Morton (Technical Director) and Mr. Nigel McKim (Projects Director).

Refer to Note 18: Share based payments for further information on the Restricted Share Units scheme.

Note 4.5: Board of Directors remuneration

The remuneration of the members of the Board is determined on a yearly basis by the Company at its Annual General Meeting. The directors may also be reimbursed for, inter alia, travelling, hotel and other expenses incurred by them in attending meetings of the directors or in connection with the business of Panoro Energy ASA. A director who has been given a special assignment, besides his/her normal duties as a director of the Board, in relation to the business of Panoro Energy ASA may be paid such extra remuneration as the directors may determine.

Remuneration to members of the Board of Directors is summarised below:

USD 000	2022	2021
Julien Balkany (Chairman of the Board of Directors)	102	82
Torstein Sanness (Deputy Chairman of the Board of Directors)	68	57
Grace Reksten Skaugen	38	0
Alexandra Herger	62	48
Garrett Soden	61	50
Hilde Ådland	58	48
Total	388	285

The Chairman of the Board of Directors' annual remuneration is USD 88,000 and the annual remuneration for the Deputy Chairman of the Board is USD 55,000. The remaining Directors' annual remuneration is USD 48,000. Members of the Audit Committee, the Remuneration Committee and the Sustainability committee each receive USD 6,000 annually per committee, whereas the Chairman of each committee receives USD 9,000 annually. No loans have been given to, or guarantees given on the behalf of, any members of the Management Group, the Board or other elected corporate bodies.

Note 4.6: Pension plan

The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension ("Lov om obligatorisk tjenestepensjon"). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognised in the statement of financial position. As of 31 December 2022, the Company had no employees at parent company level and this pension plan is no longer in operation (31 December 2021: Nil).

In the UK, the Company's subsidiary that employs staff, contributes a fixed amount per Company policy in an external defined contribution scheme. As such, no pension liability is recognised in the statement of financial position in relation to the Company's London based employees. No occupational pension scheme is mandated in Tunisia. Companies are required to pay a fixed percentage of gross salary of each employee as "social security" to the government authorities, in addition to a fixed deduction from gross monthly salary as employee contribution. As such, no pension liability is recognised in the statement of financial position for these deductions.

For contributions made to the external defined scheme for 2022 and 2021, refer to Note 4.2: Employee benefit expenses.

Note 4.7: Auditors' remuneration

Fees, excluding VAT, to the auditors are included in general and administrative expense and are shown below:

USD 000	2022	2021
Ernst & Young
Statutory Audit	281	280
Total Audit Services	281	280
Non-audit Services
Corporate financial services including pre-acquisition due diligence	-	-
Total non-audit services	-	-
Total	281	175

NOTE 5: FINANCE , INTEREST AND OTHER INCOME AND EXPENSE

USD 000	2022	2021
Unrealised (gain) / loss on commodity hedges (Note 19)	(2,622)	3,868
Realised (gain) / loss on commodity hedges (Note 19)	8,534	4,354
Interest income from placements and deposits	(57)	(77)
Interest expense - Loans and borrowings	9,536	6,895
Interest expense - Bank guarantee	-	199
Unrealised (gain) / loss on listed equity investments (Note 11)	75	-
Realised (gain) / loss on listed equity investments (Note 11)	652
Other financial costs - Bank charges and ARO unwinding	4,193	2,822
Total - Net (income) / expense	20,311	18,061

Note 5.1: Loans and borrowings

[P-

--WSHYG

Note 5.1.1 Mercuria senior secured loan

In 2018, the Group entered into an agreement with Mercuria Assets Holdings (Hong Kong) Ltd ("Mercuria"), whereby Mercuria provided PTP (60% owned by Panoro) an acquisition loan facility comprising a Senior Secured Loan facility of USD 16.2 million (USD 27 million gross) which was fully drawn. The Senior Loan facility initially had term of 5 years with interest charged at USD 3-month LIBOR plus 6% on quarterly amounts drawn, with repayments due each quarter. Interest of USD 0.2 million (USD 0.3 million gross) was accrued up to 31 December 2022 (31 December 2021: USD 0.2 million).

On 25 June 2019, the Group and Mercuria mutually agreed to make minor adjustments to the Facility terms, resulting in the Facility amount increasing by USD 2.5 million (USD 4.1 million gross) to USD 18.7 million (USD 30 million gross). As part of the security package for the enhanced facility size, shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS) have been pledged as collateral. The amended Senior Loan facility has a term of 5 years from 30 June 2019 with interest charged at USD 3-month LIBOR plus 6% on the balance outstanding, with repayments due each quarter.

Key financial covenants were unchanged as a result of the amendment and are required to be tested at the end of every 3 month period. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following:

• (i) Field life coverage ratio (FLCR): 1.50x
• (ii) Minimum cash balance equal to the amount of the next loan and interest repayment, varying as the loan is repaid but typically around USD 1.2 million (USD 2 million gross) to be maintained at all times in the collection account of the borrower.
• (iii) Debt service coverage ratio (DSCR): between 1.15x and 1.25x subject to specifications in the loan agreement.
• (iv) Liquidity Test: Customary to the loan instrument.

Security package for the original Senior Secured loan comprised a Guarantee from Panoro Energy ASA, share pledge over shares in Panoro TPS (UK) Production Limited and Panoro TPS Production GmbH and from Sfax Petroleum Corporation AS, shareholder and intercompany loans (subordinated at all times), rights under hedging agreements, and the Account

Management Agreement (for the Collection Account), negative pledge over the assets. In an event, the guarantee placed by Panoro Energy ASA is called upon, the shareholders' agreement with Beender for the ownership on Sfax Petroleum Corporation AS provides that Sfax Petroleum Corporation AS shall indemnify Panoro Energy ASA. If Sfax Petroleum Corporation AS is unable to indemnify, Panoro Energy ASA, such indemnification, pro rata to its ownership, shall be made by Beender. As part of the amendment in June 2019 as noted above, the security package for the enhanced facility size was amended to also include a pledge over the shares in Panoro Energy AS (holding company for Panoro Tunisia Exploration AS).

The Mercuria loan was repaid in full on 15 March 2023 by the Group and all security held in relation to the loan was released at that date, refer to Note 25: Events subsequent to reporting date.

Current and non-current portion of the outstanding balance of the Mercuria Senior Secured facility as of the date of the statement of financial position attributable to Panoro's 60% ownership is as follows:

USD 000	31 December 2022			31 December 2021
	Current	Non-current	Total	Current	Non-current	Total
Mercuria Senior Secured loan facility
Principal outstanding	5,100	1,740	6,840	4,950	5,820	10,770
Accumulated interest accrued	170	-	170	169	-	169
Unamortised borrowing costs	(55)	(8)	(63)	(103)	(63)	(166)
	5,215	1,732	6,947	5,016	5,757	10,773

Note 5.1.2 Trafigura Secured Borrowing Base facility

On 29 March 2021, Panoro signed a fully underwritten acquisition finance loan facility of up to USD 90 million arranged by Trafigura, one of the world's leading independent commodity trading and logistics houses, with Mauritius Commercial Bank as mandated lead arranger and facility agent, to partially finance the EG Transaction and the Dussafu Transaction as described above.

The loan has been made available in two tranches, Tranche A of up to USD 55 million in respect of the EG Transaction and Tranche B of up to USD 35 million in respect of the Dussafu Acquisition. Tranche A and Tranche B can be drawn separately and are not conditional on each other. The drawn-down amount under the loan will amortise over a period of 5 years and carries an annual interest rate of USD 3-month LIBOR plus 7.5%. An accordion option for an additional USD 50 million is included alongside and in addition to the acquisition finance facilities.

On 30 March 2021, Panoro drew down against Tranche A of the facility, borrowing USD 55 million which was utilised to partially pay for the purchase consideration of the EG Transaction as described above, and the balance funded from the proceeds of the equity private placement of the Company shares that completed in the first quarter of this year.

On 9 June 2021, Panoro drew down against Tranche B of the facility, borrowing USD 35 million which was utilised to partially pay for the purchase consideration of the Dussafu Transaction as described above.

The amended Senior Loan facility has a term of 5 years from 31 March 2021 with interest charged and paid quarterly at USD 3-month LIBOR plus 7.5% on the balance outstanding, with principal repayments due each six months.

Key financial covenants are required to be tested 30 September and 31 March. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following:

• (i) Group Net debt/EBITDA: ≤3.0
• (ii) Minimum cash balance of USD 7.0 million to be maintained in the account of the Borrower
• (iii) Field life coverage ratio: 1.5x
• (iv) Loan life coverage ratio: 1.3x
• (v) Group Liquidity Test: 1.2x (Borrower and subsidiaries)

The Group was not in breach of any financial covenants as at 31 December 2022. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. During the current quarter, these costs are expensed using an effective interest rate of 11.74% per annum over the remaining term of the facility.

Subsequent to year-end, the Company has increased its facility by USD 15 million in conjunction with acquisition of 40% interest in Sfax Petroleum Corporation AS. See Note 25: Events subsequent to reporting date for further details.

Current and non-current portion of the outstanding balance of the Trafigura Secured Borrowing Base facility as of the date of the statement of financial position is as follows:

USD 000	31 December 2022			31 December 2021
	Current	Non current	Total	Current	Non current	Total
Trafigura Secured Borrowing Base facility
Principal outstanding	16,200	57,600	73,800	10,800	73,800	84,600
Accumulated interest accrued	-	-	-	-	-	-
Unamortised borrowing costs	(918)	(950)	(1,868)	(1,102)	(1,868)	(2,970)
	15,282	56,650	71,932	9,698	71,932	81,630

Note 5.1.3 BW Energy non-recourse loan

The Group has in place a non-recourse loan from BW Energy in relation to the funding of the Dussafu development. The loan bears interest at 7.5% per annum on outstanding balance, compounded annually. The balance outstanding at each balance sheet date presented is as below:

USD 000	31 December 2022		31 December 2021
	Current	Non-current	Total	Current	Non Current	Total
BW Energy Non-Recourse loan
Principal outstanding	-	-	-	2,234	-	2,234
Accumulated interest accrued	632	-	632	2,273	-	2,273
	632	-	632	4,507	-	4,507

The loan is repayable through Panoro's allocation of the cost oil in accordance with the Dussafu PSC, after paying for the proportionate field operating expenses and as such the loan is classified as current or non-current based on expected field production and lifting schedule at a reasonable oil price assumption at the time of making such classification. During the repayment phase, Panoro is still entitled to its share of profit oil, as defined in the PSC, from the Dussafu operations.

The remaining balance of the BW Energy loan was repaid on 21 March 2023.

Note 5.2: Changes in liabilities with cash flow movements from Financing Activities

The changes in liabilities whose cash flow movements are disclosed as part of financing activities in the cash flow statement are as follows:

USD 000	2022	2021
At 1 January	99,756	20,392
Cash flows:
Drawdown of Secured Loans, net of fees	-	90,000
Repayment of Secured Loans	(14,730)	(13,384)
Repayment of non-recourse loan	(4,065)	(3,106)
Realised gain/(loss) on commodity hedges	(7,689)	(2,668)
Borrowing costs, including arrangement fees	(8,141)	(4,689)
Lease liability payments	(231)	(254)
Non cash changes:
Unwinding of unamortised borrowing cost and finance charges	1,324	1,123
Interest accrued	8,232	5,812
Movement in unrealised hedges	5,200	6,536
Initial recognition lease under IFRS 16	-	-
Foreign exchange movements	(32)	(6)
At 31 December	79,394	99,756

Income tax

The major components of income tax in the consolidated statement of comprehensive income related to continuing and discontinued operations were:

USD 000	2022	2021
Income Taxes
Current income tax (i)	12,834	6,541
PSC based Profit Oil allocation – current (ii)	8,359	5,949
PSC based income tax - current (iii)	27,420	10,417
Deferred tax expense / (benefit) (iv)	(6,827)	(1,838)
Tax relating to prior years income	3	10
Tax charge / (benefit) for the period	41,789	21,079

(i) Current income tax primarily comprises of tax on income from Tunisian operation.

• (ii) Under the terms of the Dussafu PSC, the estimated value of the State profit oil is reflected in other revenue, with a corresponding amount as income tax. See Note 3: Operating segments
• (iii) PSC based income tax represents tax on income from Block G. See Note 3: Operating segments
• (iv) Deferred tax liability recognised has arisen on temporary differences between tax base and accounting base of the production assets in Equatorial Guinea and Tunisia and have been calculated using the effective tax rate applicable to the concessions.
• (v) Tax rates in Tunisia vary by permit and concession and ranges between 50% to 60% applicable to the respective concession's taxable income.

A reconciliation of the income tax expense applicable to the accounting profit before tax at the statutory income tax rate to the expense at the Group's effective income tax rate is as follows:

USD 000	2022	2021
Profit/ (loss) before taxation – continuing operations	60,721	63,391
Profit / (loss) before taxation – discontinued operations	961	7,011
Profit / (loss) before taxation - total	61,682	70,402
Tax/ (tax loss) calculated at domestic tax rates applicable to profits in the respective countries	54,456	35,423
Expenses not deductible	(43,919)	(29,365)
Expenses deductible for tax	(3)	(669)
Deferred tax arising on taxable temporary differences	(1,088)	313
PSC based Profit Oil allocation	35,779	16,366
Tax effect of prior years' losses utilised in the period	(5,739)	(2,151)
Tax effect of losses not utilised in the period	2,300	1,152
Prior year adjustment	3	10
Tax charge / (benefit)	41,789	21,079

Tax Liabilities

Tax liabilities payable of USD 35.6 million as of 31 December 2022 comprised of taxes payable in Equatorial Guinea of USD 25.8 million and Tunisia of USD 9.7 million for production from various concessions (31 December 2021: USD 17 million comprised of taxes payable in Equatorial Guinea of USD 12.3 million and Tunisia of USD 4.7 million). Advantage was taken in Tunisia of a incentives with a tax value of USD 9.2 million that require investment in government approved projects within four years. Investment plans are being considered and formalised for implementation within the allowed timeframe.

Deferred tax

Deferred tax benefit of USD 6.8 million recognised during the year comprises of USD 9.5 million benefit in Equatorial Guinea, offset by a USD 2.7 million expense in Tunisia arising on taxable temporary differences between accounting and tax bases of property, plant and equipment. Effective tax rate of the respective petroleum concessions has been used to calculate such liability. The deferred tax liability of USD 67.2 million as of 31 December 2022 is classified as non-current based on the current expectation of timing of such taxes. These are ring fenced against taxable income from the respective concessions in Equatorial Guinea and Tunisia.

There are no recognised deferred tax assets in the Group financial statements as of 31 December 2022 (31 December 2021: Nil).

Deferred tax assets are recognised for tax losses carry-forwards to the extent that the realisation of the related tax benefits through future taxable profits is probable. The Group did not recognise deferred income tax assets of USD 6.9 million (2021: USD 6.7 million) in respect of losses that can be carried forward against future taxable income.

The Group has provisional accumulated tax losses as of year-end that may be available to offset against future taxable income; all losses are available indefinitely and have been included in the table below.

USD 000	2022	2021
Panoro Energy ASA	12,839	21,591
Panoro Energy Limited	-	486
Sfax Petroleum Corporation (at 60%)	18,530	8,802
Total	31,369	30,879

NOTE 7: BASIC AND DILUTED EARNINGS PER SHARE

Basic earnings or loss per ordinary share amounts are calculated using net profit or loss for the period attributable to ordinary equity holders of the parent divided by the weighted average number of ordinary shares outstanding during the period.

Diluted earnings per share amounts are calculated using the net profit attributable to ordinary equity holders of the Company divided by the weighted average number of ordinary shares outstanding during the period plus the weighted average number of ordinary shares that would be issued on the conversion of dilutive potential ordinary shares into ordinary shares.

Amounts in USD 000, unless otherwise stated	2022	2021
Net profit/(loss) attributable to equity holders - Total	19,893	49,323
Net profit/(loss) attributable to equity holders - Continuing operations	18,635	42,312
Weighted average number of shares outstanding - in thousands	113,538	105,452
Diluted weighted average number of shares outstanding - in thousands	115,890	106,611
Basic earnings/(loss) per share (USD) - Total	0.18	0.47
Diluted earnings/(loss) per share (USD) - Total	0.17	0.46
Basic earnings/(loss) per share (USD) - Continuing operations	0.16	0.40
Diluted earnings/(loss) per share (USD) - Continuing operations	0.16	0.40

NOTE 8: INTANGIBLE ASSETS

Note 8.1: Licenses, Exploration and Evaluation Assets, Development Assets

2022

USD 000	Licenses and exploration assets	Development assets
Historical cost
At 1 January 2022	51,752	46,361
Additions	168	27,137
Transfer to Development Assets	(49,325)	49,325
At 31 December 2022	2,595	122,823
Net carrying value at 31 December 2022	2,595	122,823

2021

USD 000	Licenses and exploration assets	Development assets
Historical cost
At 1 January 2021	21,070	14,522
Additions	2,058	24,129
Transfer to Production Assets	-	(12,407)
Additions through Acquisition	28,624	20,117
At 31 December 2021	51,752	46,361
Net carrying value at 31 December 2021	51,752	46,361

Licence area	Panoro's interest	Country	Expiry of current phase
Block G	14.25%	Equatorial Guinea	December 2040
Dussafu Marin permit*	17.4997%	Gabon	September 2028*
Sfax Offshore Exploration Permit**	52.5% (Operator) – excluding Beender's 40%	Tunisia	December 2024
Hammamet Offshore Exploration Permit	27.6% - excluding Beender's 40%	Tunisia	Under relinquishment
Block S	12%	Equatorial Guinea	December 2024
Block EG-01	56%	Equatorial Guinea	February 2026
TCP 12/2/218	100%	South Africa	June 2023
Block 2B ***	12.5%	South Africa	November 2022
TPS Assets:
Cercina			February 2024
Cercina South			November 2034
Gremda / El Ain **	29.4% - excluding Beender's 40%	Tunisia	December 2018
Guebiba			June 2033
Rhemoura **			January 2023

* The Ruche area Exclusive Exploitation Authorisation ("EEA") under the Dussafu Marin PSC is effective from commencement of production for a period of 10 years. If, at the end of this ten-year term commercial exploitation is still possible from the Ruche area, the EEA shall be renewed at the contractor's request for a further period of five years. Subsequent to this, the EEA may be renewed a second time for a further period of five years.

** In process of being renewed.

Note 8.2: Production rights

USD 000	2022	2021
Acquisition cost
At 1 January	188,832	26,475
Depreciation charge for the year	(18,307)	(14,319)
Additions through Acquisition	-	172,676
Other additions	3,450	4,000
At 31 December	173,975	188,832

Note 8.3: Goodwill

USD 000	2022	2021
Acquisition cost
At 1 January	47,762	-
Additions through Acquisition	-	47,762
At 31 December	47,762	47,762

The Group acquired a 14.25% working interest in Block G, Equatorial Guinea during 2021, assets and liabilities were taken on at fair value and Goodwill of USD 47.8 million recognised as described in Note 13: Business Combinations.

An annual impairment assessment was carried out in December 2022 at which time the total carrying value of Block G at 31 December 2022 was USD 127.4 million. The net recoverable value was determined on a Value in Use ('VIU') basis using a discounted cash flow model, which exceeded the carrying value. Based on a VIU analysis, performed using the profiles from third party reserves report and using the discount rate of 12% and long-term oil price assumption of USD 80/bbl, inflated by 2% per annum after five years. The resultant recoverable amounts exceed the current carrying value of the asset on the Group's balance sheet. This discount rate was derived from the Group's estimate of discount rates that might be applied by active market participants and adjusted, where applicable, to take into account any risks specific to the asset and the region where the asset is located.

In determining VIU it is necessary to make a series of assumptions to estimate future cash flows including volumes, price assumption and cost estimates. Economically recoverable reserves and resources are based on NSAI and project plans based on Operator sourced information, supported by the evaluation work undertaken by appropriately qualified persons within the Joint Venture. The impairment test is most sensitive to the following assumptions: discount rates, oil and gas prices, reserve estimates and project risk. As of the date of the financial statements there is no expectation of possible changes in any of the above key assumptions that would cause the carrying value of the Block G asset to materially exceed its recoverable amount.

NOTE 9: TANGIBLE ASSETS

Note 9.1: Production Assets and Equipment
USD 000	2022	2021
Historical cost
At 1 January	141,362	40,904
Additions	15,732	10,306
Write-offs	(184)	(417)
Adjustments to asset retirement estimates	(22,163)	(12,047)
Transfer from Development Assets	-	12,407
Additions through Acquisition (Note 12)	-	90,209
At 31 December	134,747	141,362
Accumulated depreciation
At 1 January	21,093	8,601
Write-offs	(184)	(417)
Depreciation charge for the year	16,479	12,909
At 31 December	37,388	21,093

Note 9.2: Impairment in Oil and Gas Interests

Block G, Equatorial Guinea

The Group has a 14.25% working interest in Block G, Equatorial Guinea.

An assessment was performed using an oil price assumtion of USD 80/bbl with a 2% annual inflation after five years. No indication of impairment was identified and no impairment was therefore recognised during the year 2022.

Dussafu, Gabon

The Group has a 17.4997% interest in the Dussafu Permit, offshore Gabon.

An assessment was performed using an oil price assumtion of USD 80/bbl with a 2% annual inflation after five years. No indication of impairment was identified and no impairment was therefore recognised during the year 2022.

Sfax Offshore Exploration Permit, Tunisia

The Group has an interest in Sfax Offshore Exploration Permit (SOEP). Qualifying directly attributable costs have been capitalised as licence and exploration assets during the year in line with Group's intention to drill an exploration well and extend the licence.

TPS Assets, Tunisia

The Group completed the acquisition of its share of interest in TPS Assets, comprising of Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba concessions in December 2018.

The Group assesses each cash-generating unit annually to determine whether an indication of impairment exists

An assessment was performed using the value of TPS assets derived from the agreed purchase of 40% of Sfax Petroleum Corporation AS by the Company as described in Note 25: Events subsequent to reporting date. . No indication of impairment was identified and no impairment was therefore recognised during the year 2022.

OML 113 (Aje), Nigeria (Discontinued)

In 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited ("PetroNor"), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan-Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as "Divested Subsidiaries") as described in Note 14: Discontinued Operations. Following agreement to sell the Divested Subsidiaries, the Group's interest in such subsidiaries were designated as Assets held for sale as of 31 December 2019. The transaction completed on 13 July 2022 at which time the Group derecognised the assets and liabilities of the Divested Subsidiaries at the carrying amounts.

At the date of designation for held for sale during 2019, an assessment was made to determine the fair value of the assets and liabilities of the Divested Subsidiaries. As a result, based on fair value less costs to sell principle, a reversal of historical impairment charges of USD 8 million on account of Aje has been made. Further assessments were made in 2021 and 2022 resulting in a further reversal of USD 8 million and USD 1.2 million respectively of historical impairment charges to carrying value of the Divested Subsidiaries. The impairment reversals has been allocated in proportion of pre-reversal carrying value of licence and exploration assets and production assets and equipment.

Sensitivities to change in assumptions

In general, adverse changes in key assumptions could result in recognition of impairment charges. Since there are no charges during the year, the sensitivities have not been presented in these financial statements. The Group will continue to test its assets for impairment where indications are identified and may in future recognise impairment charges or reversals.

There were no net impairment (reversal)/expense for continuing operations.

Climate considerations in impairment assessment

Certain climate considerations are factored into the Group's estimation of cash flows that are applied in the calculation of recoverable amount. This includes factoring in current legislation (e.g., environmental taxes/fees) and estimation of future levels of environmental taxes. The Group's participation in the current licenses and concessions in various jurisdictions are not currently subject to specific carbon pricing.

At the recent COP26 UN climate conference, member states explicitly acknowledged the importance of limiting global warming to less than 1.5°C, rather than the previous Paris Agreement target of 'well below 2°C'. Despite these targets, global energy demand is projected to continue to grow rapidly, and emerging economies in Africa and other geographies are increasingly looking to their fossil resources to underpin economic growth, finance their own energy transition, and help to pay for urgently needed climate adaptation measures. Our strategy therefore aims to balance environmental, energy security and economic objectives by investing in efficient producing assets in North, West and South Africa, and working with our partners to support the transition to a low-carbon business.

The company has run sensitivities for its West and North African oil assets in order to test the resilience of the Company's business, using three of the four scenarios examining future energy trends published by the International Energy Agency (IEA) in their World Energy Outlook 2022 publication.

The scenarios with their key features are as follows:

Net Zero Emissions (NZE)

NZE requires global greenhouse gas (GHG) emissions to drop by around 50% by 2030, or 7% per year for the next 9 years, implying a rapid drop in oil & gas consumption, a massive push into renewable energy, big gains in energy efficiency, and rapid development and scaling-up of new technologies, including carbon capture. Another major focus is reducing methane emissions from fossil fuel operations. It also demands no further fossil fuel exploration and no new oil and gas production from fields beyond those already approved for development. Oil demand in NZE falls to 72 MMbbls/d in 2030 and 24 mmb/d by 2050.

The decline is led by road transport, where 60% of all passenger cars sold globally are electric by 2030, and no new combustion engine cars are sold anywhere after 2035. Petrochemicals are the only area where demand increases and by 2050 accounts for 55% of all oil consumed. Prices fall along with demand, to USD 36/bbl in 2030 and USD 24/bbl in 2050.

Announced Pledges (APS)

APS assumes full implementation of countries' pledges announced under the Paris Agreement and updated ahead of COP26 in Glasgow, and estimates an average temperature rise of 2.1°C by 2050. Oil prices decline slightly from USD 64/bbl in 2030 to USD 60/bbl in 2050.

Stated Policies (STEPS)

STEPS has demand continuing to rise gradually, levelling off at 104 mmb/d in the mid-2030s; then declining very slightly to 103 mmb/d by 2050. A fall in demand from power generation is offset by increased consumption for road transport (around 6 mmb/d through to 2030) and robust demand from aviation, shipping and petrochemicals. Oil prices rise, reaching USD 82/bbl in 2030 and USD 95/bbl in 2050.

Key findings

Sensitivity analysis conducted show that the Company's portfolio remains resilient under each of the above mentioned scenarios. Even under the most demanding NZE scenario, all segments remain economic, even though NPVs are negatively impacted.

A summary of the impact of the different future oil price scenarios on NPV and reserves are as follows:

		Announced Pledges
Percentage reduction	Net Zero Emissions (NZE)	(APS)	Stated Policies (STEPS)
NPV12	51%	22%	0%
Reserves	30%	11%	2%

These illustrative impairment sensitivities assume no changes to assumptions other than oil and gas prices. However, significant reduction in the oil and gas prices, offset by foreign currency effects, would likely impact the Group's investment levels. The illustrative sensitivities on climate change are not considered to represent a best estimate of an expected impairment impact. Moreover, a significant and prolonged reduction in oil and gas prices would likely result in mitigating actions by the Group and its license partners; for example it could have an impact on drilling plans and production profiles for new and existing assets. Quantifying such impacts is considered impracticable, as it requires detailed evaluations based on hypothetical scenarios and not based on existing business or development plans.

Note 9.3: Property, Furniture, Fixtures and Equipment

2022

USD 000 Historical cost	Leasehold	Furniture, fixtures and fittings	Computer equipment	Right of use asset - London office	Total
At 1 January 2022	138	923	162	946	2,169
Additions	5	23	-	-	28
At 31 December 2022	143	946	162	946	2,197
Accumulated depreciation
At 1 January 2022	14	825	122	658	1,619
Depreciation charge for the year	86	63	38	191	378
At 31 December 2022	100	888	160	849	1,997
Net carrying value at 31 December 2022	43	58	2	97	200

2021

USD 000 Historical cost	Leasehold	Furniture, fixtures and fittings	Computer equipment	Right of use asset - London office	Total
At 1 January 2021	-	830	160	946	1,936
Additions	138	93	2	-	233
At 31 December 2021	138	923	162	946	2,169
Accumulated depreciation
At 1 January 2021	-	783	68	445	1,296
Depreciation charge for the year	14	42	54	213	323
At 31 December 2021	14	825	122	658	1,619
Net carrying value at 31 December 2021	124	98	40	288	550

Depreciation method and rates

Category	Straight-line depreciation	Useful life
Leasehold	Remaining period of lease	Remaining period of lease
Furniture, fixtures and fittings	10 - 33.33%	3 - 10 years
Computer equipment	20 - 33.33%	3 - 5 years
Right of use asset - London office	Period of lease	Period of lease

NOTE 10: ACCOUNTS AND OTHER RECEIVABLES

USD 000	2022	2021
Trade receivables	16,516	54,351
Other receivables and prepayments	8,273	1,278
Underlift - Block G, Equatorial Guinea	10,320	-
At 31 December	35,109	55,629

Accounts receivables are non-interest bearing and generally on 30 to 120 days payment terms.

At 31 December 2022 and 2021, the allowance for impairment of receivables was USD Nil.

Risk information for the receivable balances is disclosed in Note 20: Financial risk management.

Other non-current assets amount to joint venture account balances of USD 7 million, prepayments of USD 1.2 million (31 December 2021: USD 1.2 million) and USD 0.1 million tenancy deposit for the UK office premises for both reporting periods.

NOTE 11: LISTED EQUITY INVESTMENTS

On completion of the disposal of Panoro's fully owned subsidiaries Pan-Petroleum Services Holdings BV and Pan-Petroleum Nigeria Holding BV described in Note 14: Discontinued Operations below, Panoro received upfront consideration of USD 10 million in the form of 96,577,537 newly allotted and issued shares in PetroNor E&P ASA ("Consideration Shares"). The Board of Directors resolved on 1 August 2022 to use its authorisation to approve a dividend in the form of the Consideration Shares. Each Panoro shareholder as at the record date received 0.849 PetroNor shares for each share held in Panoro, rounded downwards to the nearest whole share. Fraction shares were not distributed.

Panoro retains an investment of 4,451,249 PetroNor shares ("Retained Shares"), representing a holding of approximately 0.31% of PetroNor share capital. The Retained Shares were in connection with obligation to withhold tax on dividends and such taxes have since be been settled in cash by the Company. The Retained Shares are accounted for as financial assets at fair value through profit and loss and disclosed as current financial asset, valued at the published market price at the end of the reporting period, with revaluation differences disclosed as other income or expense in the statement of comprehensive income.

NOTE 12: CASH AND BANK BALANCES

USD 000	2022	2021
Cash and cash equivalents	32,670	24,532
At 31 December	32,670	24,532

The majority of Panoro's cash balance was denominated in USD and was held in different jurisdictions including Norway, UK, Tunisia and Mauritius.

Overdraft facilities

The Group had no bank overdraft facilities as at 31 December 2022 (31 December 2021: Nil).

NOTE 13: BUSINESS COMBINATIONS

Note 13.1: EG Transaction

On 31 March 2021, Panoro completed the acquisition of 100% of the shares of Panoro Equatorial Guinea Limited ("PEGL") from Tullow Overseas Holdings B.V. ("EG Seller"), a fully owned subsidiary of Tullow Oil plc, for an initial cash consideration of USD 88.8 million that includes customary completion adjustments. PEGL holds a 14.25% non-operated working interest in Block G that contains the Ceiba and Okume Complex assets, offshore Equatorial Guinea (the "EG Assets").

In addition to the initial cash consideration of USD 88.8 million, the EG Seller was also paid a USD 5 million deferred consideration upon completion of the Dussafu Transaction (see Dussafu Transaction below) in June 2021. EG Seller is also entitled to a potential contingent consideration of up USD 16 million, in aggregate, payable only in years where the average annual net production of the acquired interests is in excess of 5,500 bopd. Once this initial net production threshold has been reached, in that year, and for the four consecutive subsequent annual periods, annual contingent consideration of USD 5.5 million will be payable to EG Seller provided that the production threshold is met in such annual period and the average daily Dated Brent oil prices in respect of the annual period is in excess of USD 60/bbl, subject to the aforementioned cap of USD 16 million. If the combination had taken place at the beginning of the year, total revenue from continuing operations would have been USD 178.8 million and profit before tax from continuing operations for the Group would have been USD 89.9 million.

The purchase consideration, as set out above, is summarised in the following table:

	Shares acquired	USD 000
Cash consideration	100%	87,431
Deferred consideration *		5,000
Contingent consideration **		5,019
Net assets acquired		97,450

* Deferred consideration was paid at the time of completion of the Dussafu Transaction.

** Fair value estimate of the contingent consideration, payable only upon meeting the aforementioned criteria. This amount will be reviewed in conjunction with the criteria on an ongoing basis.

The fair values of the identifiable assets and liabilities of PEGL at the date of acquisition were as follows:

Purchase price allocation	USD 000
Assets
Concessions	132,806
Goodwill acquired	1,280
Goodwill related to step up / deferred tax	46,482
Production assets and equipment	76,367
Materials inventory	9,990
Crude oil inventory	6,904
Trade receivables	59,135
Other current receivables	245
Total Assets	333,209
Liabilities
Decommissioning liability	124,646
Deferred tax liability	58,780
Corporation tax liability	15,410
Crude oil overlift	31,174
Trade payables	5,749
Total liabilities	235,759
Net assets acquired	97,450
Cash flow on acquisition	87,431

For the first quarter of 2021, the operating cashflow of PEGL was USD 10 million before taxes of USD 0.8 million and primarily relates to payments of operating costs. In addition, USD 3.4 million of cash was spent on investing activities in relation to capital expenditure. All these items are already included in the final completion payment of USD 88.8 million.

Since the acquisition date, the acquired business contributed revenue of USD 51.6 million and profit before tax of USD 17.6 million to the consolidated statement of comprehensive income.

Note 13.2: Dussafu Transaction

On 9 February 2021, Panoro and its fully owned subsidiary Pan Petroleum Gabon BV, entered into an agreement with Tullow Oil plc and Tullow Oil Gabon SA to acquire a 10% working interest in the Dussafu Marin Permit, offshore Gabon for an initial cash consideration of USD 46 million based on an effective date of 1 July 2020 which was subject to customary working capital and other customary adjustments to be made at completion. Following completion of Dussafu Transaction in June 2021, Panoro's total working interest in Dussafu has increased to 17.4997% working interest in Dussafu.

At the completion date of 9 June 2021, a total cash consideration of USD 39 million paid to Tullow Oil Gabon SA which included completion and working capital adjustments as of such date. A further contingent consideration of up to USD 24 million (the "Dussafu Contingent Consideration") may also be payable once commercial production commences on Hibiscus and Ruche and achieves daily production equal to or greater than 33,000 bopd gross over any 60-day continuous period. Once this milestone has been met, annual contingent consideration will apply to that year and to each of the subsequent four years where the average daily Dated Brent oil price is in excess of USD 55 per barrel, subject to the USD 24 million cap. Where the oil price threshold has been met, the Dussafu Contingent Consideration payable for that year will be based on 15% of net free cashflow after all taxes, operating and capital costs from the acquired 10% working interest. The contingent payment will be capped for any year at USD 5 million.

Although the Dussafu Transaction has only been an increase in Panoro's working interest in an existing asset, under IFRS 3 the criteria is met for such transaction to be recognised as a business combination which includes recognition of fair value uplift, goodwill and the associated deferred tax under the standard which customary on recognition of such acquisitions. If the combination had taken place at the beginning of the year, total revenue from continuing operations would have been USD 129.5 million and profit before tax from continuing operations for the Group would have been USD 70.3 million.

The purchase consideration, as set out above, is summarised in the following table:

Net assets acquired		39,028
Cash consideration	10%	39,028
	Working Interest acquired in Dussafu Marin Permit	USD 000

The fair values of the identifiable assets and liabilities of PEGL at the date of acquisition were as follows:

Purchase price allocation	USD 000
Assets
Exploration and evaluation assets	28,624
Development assets	20,117
Production reserves	39,859
Goodwill acquired	(60,072)
Goodwill related to step up / deferred tax	13,951
Production assets and equipment	13,843
Inventory	3,456
Other receivable	1,722
Total Assets	61,500

Liabilities

Decommissioning liability	4,171
Deferred tax liability	13,951
Other current liabilities	4,350
Total liabilities	22,472

Net assets acquired 39,028

Cash flow on acquisition 39,028

Under the requirements of IFRS 3 "Business Combinations" any excess of fair value of net assets acquired over the consideration paid is recognised in the income statement as gain on acquisition of business, which was USD 48.5 million for this transaction. Such gain has arisen due to significant increase in oil prices between effective date and completion date of the Dussafu Transaction.

For the first half of 2021, the operating cashflow of the 10% acquired interest under Dussafu Transaction was USD 0.2 million after excluding any value of proportional State Profit oil entitlement and primarily relates to payments of operating costs, capital expenditure and past costs dispute settlement offset by proceeds sale of crude oil entitlement. All these items are already included in the final completion payment of USD 39 million. Since the acquisition date, the acquired business contributed revenue of USD 34.4 million and profit of approximately USD 23.6 million to the consolidated statement of comprehensive income.

NOTE 14: DISCONTINUED OPERATIONS

On 21 October 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited ("PetroNor"), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan-Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as "Divested Subsidiaries") for an upfront consideration consisting of the allotment and issue of new PetroNor shares with a fixed value of USD 10 million (the "Share Consideration") plus a revised contingent consideration agreed in December 2020 of up to USD 16.67 million based on future gas production volumes. The transaction completed on 13 July 2022 (the "Completion Date") with the upfront consideration of USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares (the "Consideration Shares"), determined with reference to the contractually determined 30-day volume weighted average price ("VWAP") of PetroNor's shares which are listed on the Oslo Børs with the Ticker "PNOR".

The operations of the Group's Divested Subsidiaries were classified as discontinued operations under IFRS 5 since 2019 and the results of the Nigerian segment presented as discontinued operations up to the Completion Date are as follows:

Amounts in USD 000, unless otherwise stated	2022	2021
DISCONTINUED OPERATIONS
Oil revenue	1,181	3,688
Total revenues	1,181	3,688
Operating costs	(1,129)	(4,085)
General and administrative costs	(51)	(148)
Depreciation, depletion and amortisation	-	-
(Impairment) / reversal of impairment for Oil and gas assets	1,497	8,000
EBIT - Operating income/(loss)	1,498	7,455
Interest costs net of income	(192)	(351)
Net foreign exchange gain / (loss)	(2)	(2)
Other financial costs net of income	(46)	(91)
Net income/(loss) before tax	1,258	7,011
Income tax benefit/(expense)	-	-
Net income/(loss) for the period from discontinued operations	1,258	7,011
EARNINGS PER SHARE
Basic EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations	0.01	0.07
Diluted EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations	0.01	0.07

The Group's interest in Divested Subsidiaries designated as Assets held for sale as of the Completion Date and 31 December 2021 are summarised below:

Carrying amount after allocation of impairment reversal

USD 000	2022	2021
Assets held for sale
Licence and exploration assets	17,632	16,904
Production assets and equipment	11,450	10,978
Crude oil inventory	317	1,088
Cash and cash equivalents	57	45
Total assets held for sale	29,456	29,015
Liabilities held for sale
Decommissioning liability	(3,768)	(3,723)
Other non-current liabilities	(8,738)	(8,546)
Accounts payable, accruals and other liabilities	(135)	(134)
Other current liabilities	(7,112)	(7,936)
Total liabilities directly associated with assets classified as held for sale	(19,753)	(20,339)

NOTE 15: ASSET RETIREMENT OBLIGATION

In accordance with the agreements and legislation, the wellheads, production assets, pipelines and other installations may have to be dismantled and removed from oil and natural gas fields when the production ceases. The following table presents amounts of the estimated obligations associated with the retirement of oil and natural gas properties:

	Equatorial
USD 000	Guinea	Gabon	Tunisia	Total
At 1 January 2022	113,862	8,150	18,827	140,839
Unwinding of discount	2,848	204	469	3,521
Change in inflation and discount rate	(14,313)	(1,603)	(1,804)	(17,720)
Change in licence term	(11,390)	-	-	(11,390)
Additions	-	1,457	-	1,457
Change in cost estimate	6,947	-	-	6,947
Balance at 31 December 2022	97,954	8,208	17,492	123,654

At 1 January 2021	-	3,096	18,368	21,464
Unwinding of discount	1,998	148	459	2,605
Change in inflation and discount rate (estimate)	(18,282)	-	-	(18,282)
Acquisitions	124,646	4,171	-	128,817
Change in cost estimate	5,500	735	-	6,235
Balance at 31 December 2021	113,862	8,150	18,827	140,839

All amounts are classified as Non-Current. The exact timing of the obligations is uncertain and depends on the rate the reserves of the field are depleted. However, based on the existing production profile of the assets, the following assumptions have been applied in order to calculate the liability:

It is expected that expenditure on retirement is likely to be after more than five years. The current bases for the provision at 31 December 2022 are a discount rate of 4% and an inflation rate of 2% (31 December 2021: 2.5% and 2% respectively).

NOTE 16: SHARE CAPITAL

Share capital

Amounts in USD 000 unless otherwise stated	Number of shares	Nominal Share Capital
As at 1 January 2022	113,383,690	721
Share issue under RSU Plan (Note 18)	305,682	2
As at 31 December 2022	113,689,372	723

Note 16.1

Panoro Energy was formed through the merger of Norse Energy's former Brazilian business and Pan-Petroleum on 29 June 2010. The Company is incorporated in Norway and the share capital is denominated in NOK. The share capital given above is translated to USD at the foreign exchange rate in effect at the time of each share issue. All shares are fully paid-up and carry equal voting rights.

Note 16.2

In connection with the Company's Restricted Share Units Plan, announced on 7 July 2022, the Company issued 305,682 new shares to employees.

As of 31 December 2022, the Company had a registered share capital of NOK 5,684,469 divided into 113,689,372 shares, each with a nominal value of NOK 0.05 (31 December 2021: NOK 5,669,184 divided into 113,383,690 shares, each with a nominal value of NOK 0.05).

The Company's twenty largest shareholders and the shares owned by the CEO, Board Members and key management are referenced in the Parent Company Accounts below, please refer to Note 9: Shareholders' equity and shareholder information.

Reserves

Share premium

Share premium reserve represents excess of subscription value of the shares over the nominal amount.

Other reserves

Other reserves represent an item arising on accounting for the historical merger with Company's subsidiary Panoro Energy do Brasil Ltda.

Additional paid-in capital

Additional paid-in capital represents reserves created under the continuity principle on demerger. Share-based payments credit is also recorded under this reserve and so is the credit from reduction of share capital by reducing the par value of shares.

Currency translation reserve

The translation reserve comprises all foreign exchange differences arising from the translation of the financial statements of foreign operations.

NOTE 17: ACCOUNTS PAYABLE, ACCRUALS AND OTHER LIABILITIES

USD 000	2022	2021
Accounts payable	9,087	12,707
Accrued and other liabilities	4,899	10,623
Other non-current liabilities	6,956	8,302
At 31 December	20,942	31,632

NOTE 18: SHARE BASED PAYMENTS

Restricted Share Unit ("RSU") scheme

At the Annual General Meeting held on 27 May 2021, the existing RSU scheme (as originally presented and approved in the 27 May 2015 Annual General Meeting), was approved for another three years up to the general meeting to be held in the year 2024. Under this approved employee incentive scheme, the Company may issue RSUs to executive and key employees. Awards under the RSU scheme will normally be considered one time per year and grant of share-based incentives will, in value (calculated at the time of grant), be capped levels defined in the plan. One RSU will entitle the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. Grant of RSUs will be subject to a set of performance metrics with threshold and factors reviewed annually by the Board of Directors. Such metrics will be set as objectives based on sustained performance results including mostly share price increases and achievement of specific financial performance measures related to a group of oil and gas exploration and production peers that has been defined and adopted by a committee established by the Board.

The movement of RSUs during the year are tabled below:

All amounts in Number of units, unless stated otherwise	2022	2021
Outstanding RSUs as of 1 January	1,162,434	1,149,150
Add: Grants during the year	487,434	528,356
Less: Vested during the year
- Settled in cash to cover taxes / settlement through purchase of shares from the market	(264,819)	(243,879)
- Settled through issue of new shares	(305,682)	(271,193)
Less: Terminated without vesting	(29,376)	-
Outstanding RSUs as of 31 December	1,049,991	1,162,434

The cash settlement of RSUs is the Board of Directors' unilateral decision and such settlement is only to cover employee withholding taxes originating from vesting of RSUs. The Company, at its discretion, may also elect to settle the RSUs by delivering equity shares purchased from the market.

In June 2022, 487,434 Restricted Share Units (RSU) were awarded under the Company's RSU scheme to key employees of the Company under the long-term incentive plan approved by the shareholders. One RSU entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value of the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based. The standard vesting period is 3 years, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period.

RSUs vest automatically at the respective vesting dates, provided the unit holder continues to be an employee throughout the vesting period. The holder will be issued the applicable number of shares as soon as possible thereafter.

The Company calculates the value of share-based compensation using a Black-Scholes option pricing model to estimate the fair value of the RSUs at the date of grant. The estimated fair value of RSUs is amortised to expense over the respective vesting period of USD 1.6 million (2021: USD 1.2 million) has been charged to the statement of comprehensive income for the proportion of vesting during the respective years and the same amount credited to additional paid-in capital. Upon vesting, the settlement value is reversed from the additional paid-in capital.

The assumptions made for the valuation of the RSUs granted during the year is as follows:

Key assumptions	2022	2021
Weighted average risk-free interest rate	0.75%	0.75%
Dividend yield	Nil	Nil
Weighted average expected life of RSUs (vesting in Tranches)	1-3 years	1-3 years
Volatility range based on Company's historical share performance	58%	61%
Weighted average remaining contractual life of RSUs at year end	1.1 Years	1.1 Years
Share price at grant date – per share	NOK 32.84	NOK 24.70

The weighted average fair value of RSUs granted during the period was NOK 32.84 per unit (2021: NOK 24.70 per unit) based on 487,434 units granted (2021: 528,356 units granted).

The following table illustrates the maturity profile and Weighted Average Exercise Price ("WAEP") of the RSUs outstanding as of 31 December and vesting:

	2022	2021	WAEP	2022	2021
	Number of Units		NOK/share	Exercise value in NOK
Within 1 year	566,229	570,501	0.05	28,311	28,525
Between 1 and 2 years	326,533	415,814	0.05	16,327	20,791
Between 2 and 3 years	157,229	176,119	0.05	7,861	8,806
Total	1,049,991	1,162,434		52,500	58,122

As of the year ended 2022 the unvested RSUs were outstanding for 18 employees including key management personnel (2021: 16 employees).

The distribution of outstanding RSUs as of 31 December 2022 amongst the employees is as follows:

	No of Units	Exercise price NOK/share	Exercise period	Fair value expensed USD 000
John Hamilton, CEO	351,107	0.05	June 2023 to June 2025	512
Qazi Qadeer, CFO	136,285	0.05	June 2023 to June 2025	195
Other Named Executives (i)	267,957	0.05	June 2023 to June 2025	382
Total	755,349			1,089

(i) Other Named Executives include Richard Morton (Technical Director) and Nigel McKim (Projects Director).

Under the RSU scheme in an event where there is a change of control, all outstanding RSUs will vest immediately, and the Company will cash settle by compensating the difference between the fair market value of the RSUs and the exercise value.

A change of control is defined in the RSU scheme terms and means (i) a change of control in the ownership of the Company which gives a person (individual or corporate) the right and the obligation to make a mandatory offer for all the shares in the Company pursuant to the Norwegian Securities Trading Act of 2007, (ii) if (i) is not applicable; a change of control in the ownership of the Company which gives a person (individual or corporate) ownership to or control over more than 50% of the votes in the Company, (iii) a merger in which the Company is not the surviving entity or (iv) a sale of all or substantially all of the Company's assets to another corporation, partnership or other entity that is not a wholly owned Subsidiary of the Company. In the case of (i) and (ii) above, the change of control is deemed to occur at the time when the relevant ownership or control occurs and in the case of (iii) and (iv) above at completion of the merger or the sale.

Share Options to Board of Directors

Pursuant to the recommendation of the Nominations Committee and the resolutions passed in the Annual General Meeting ("2021 AGM") of the Company, held on 27 May 2021, a share option plan to award share options to the Company's existing members of the Board of Directors, were approved and implemented ("Board Options"). One Board Option entitles the holder to receive one share of capital stock of the Company against payment in cash of the Exercise Price of the option which has been set at NOK 17.34 each for 2021 awards and NOK 31.91 for the 2022 award, in line with the mechanism prescribed in the 2021 AGM. Vesting of the Board Options is time based and the vesting period specific to this grant is from 27 May 2021 to 26 May 2025, where 1/3 of the Board Options vest each year, starting one year after award on the date of the Company's AGM which is generally held in the last week of May each year.

The movement of Board Options during the year were are tabled below:

All amounts in Number of units, unless stated otherwise	2022	2021
Outstanding options as of 1 January	144,000	-
Add: Grants during the year	24,000	144,000
Outstanding options as of 31 December	168,000	144,000

The outstanding options as of 31 December 2022 included 48,000 options that had already vested but not exercised (2021: Nil).

The Company calculates the value of share-based compensation using a Black-Scholes option pricing model to estimate the fair value of the Board Options at the date of grant. The estimated fair value of RSUs is amortised to expense over the respective vesting period of USD 0.1 million has been charged to the statement of comprehensive income for the proportion of vesting during the respective years and the same amount credited to additional paid-in capital. Upon vesting, the settlement value is reversed from the additional paid-in capital.

The assumptions made for the valuation of the Board Options granted during the year is as follows:

Key assumptions	2022	2021
Weighted average risk-free interest rate	0.75%	0.75%
Dividend yield	Nil	Nil
Weighted average expected life of RSUs (vesting in Tranches)	1-3 years	1-3 years
Volatility range based on Company's historical share performance	58%	61%
Weighted average remaining contractual life of RSUs at year end	1 Years	1.4 Years
Share price at grant date – per share	NOK 32.40	NOK 19.16

The weighted average fair value of Board Options granted during the period was NOK 32.40 per unit (2021: NOK 19.16 per unit) based on 24,000 units granted (2021: 144,000 units granted).

The following table illustrates the maturity profile and Weighted Average Exercise Price ("WAEP") of the Board Options outstanding as of 31 December and vesting:

	2022	2021	WAEP	2022	2021
	Number of Units		NOK/share	Exercise value in NOK
Within 1 year	104,000	48,000	19.42	2,019,829	832,320
Between 1 and 2 years	56,000	48,000	19.42	1,087,600	832,320
Between 2 and 3 years	8,000	48,000	31.91	255,280	832,320
Total	168,000	144,000		3,362,709	2,496,960

As of the year ended 2022 the unvested Board Options were outstanding for 6 members of the Board of Directors (2021: 5 members of the Board of Directors).

The distribution of outstanding Board Options as of 31 December 2022 amongst the members of the Board of Directors is as follows:

	No of Units - unvested	No of Units - vested and unexercised	Exercise price NOK/share	Exercise period	2022 Fair value expensed USD 000	2021 Fair value expensed USD 000
Julien Balkany	32,000	16,000	17.34	May 2023 to May 2024	19	15
Torstein Sanness	16,000	8,000	17.34	May 2023 to May 2024	9	8
Grace Skaugen	24,000	-	31.91	May 2023 to May 2024	10	-
Alexandra Herger	16,000	8,000	17.34	May 2023 to May 2024	9	8
Hilde Ådland	16,000	8,000	17.34	May 2023 to May 2024	9	8
Garrett Soden	16,000	8,000	17.34	May 2023 to May 2024	9	8
Total	120,000	48,000			65	47

Fair values of financial assets and liabilities

The Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value. The Group has no material financial assets that are past due. No material financial assets are impaired at the balance sheet date. All financial assets and liabilities with the exception of derivatives are measured at amortised cost.

Fair value of derivative instruments

All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved.

The Group strategically hedges a portion of its 2P oil reserves to protect against a fall in oil prices and protect its ability to service its debt obligations and to fund operations including planned capital expenditure. The hedge instruments used include "zero cost collars" (where Panoro is guaranteed to receive no less than the buy/put price, but no more than the sell/call price for the hedged number of bbls) and "commodity swap" (where Panoro is guaranteed the contract price) contracts to protect the downside in 'Dated Brent' oil price.

These hedge contracts are initially recognised at Nil fair value and then revalued at each balance sheet date, with changes in fair value recognised as finance income or expense in the Statement of Comprehensive Income. The hedging program continues to be closely monitored and adjusted according to the Group's risk management policies and cashflow requirements. The Group continues to monitor and optimise its hedging programme on an on-going basis. The outstanding commodity hedge contracts as at the respective balance sheet dates presented were as follows:

Zero cost collar instruments	Remaining term	Remaining contract amount	Average contract price	Average contract price	Fair value Asset / (Liability)	Fair value Asset / (Liability)
		Bbls	Buy Put (USD/Bbl)	Sell Call (USD/Bbl)	Current (USD '000)	Non-Current (USD '000)
At 31 December 2021	Jan 21 - Dec 21	216,000	55	64	(2,489)	-
At 31 December 2022	Dec 22 - Mar 23	50,000	40	47	133	-

The fair values of the commodity price contracts were provided by the counterparty with whom the trades have been entered into. These consist of put and call options to sell/buy crude oil. The options are valued using a Black-Scholes based methodology. The inputs to these valuations include the price of oil, its volatility.

The following provides an analysis of the Group's financial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable:

• Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities,
• Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and
• Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data.

All the Group's derivatives are Level 2 (2021: Level 2). There were no transfers between fair value levels during the year. For financial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between levels by re-assessing categorisation (based on the lowest-level input which is significant to the fair value measurement as a whole) at the end of each reporting period.

Financial risk management objectives

The Group's principal financial liabilities comprise of loans and borrowings and trade and other financial liabilities. The main purpose of these financial instruments is to finance the Group's operations, including the Group's capital expenditure programme. The Group has various financial assets such as accounts receivable and cash.

The Group manages its exposure to key financial risks in accordance with its financial risk management policy. The objective of the policy is to support the Group's financial targets while protecting future financial security. The Group is exposed to the following risks:

• Market risk, including commodity price, foreign currency exchange and interest rate risks
• Credit risk
• Liquidity risk

Management reviews and agrees policies for managing each of these risks which are summarised below. The Group's policy is that all transactions involving derivatives must be directly related to the underlying business of the Group and does not use derivative financial instruments for speculative purposes.

Market risk

Market risk is the risk or uncertainty arising from possible market price movements or prevailing market conditions and their impact on the future performance of a business or the ability to complete deals entered into. The primary commodity price risks that the Group is exposed to include oil prices that could adversely affect the value of the group's financial assets, liabilities or expected future cash flows. In accordance with the Group's financial risk management framework, the Group enters into various transactions using derivatives for risk management purposes. The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below.

Commodity price risk

The Group is exposed to the risk of fluctuations in prevailing market commodity prices (primarily crude oil) on the oil and gas it produces. The Group's policy is to manage these risks through the use of derivative financial instruments. The following table summarises the impact on profit before tax for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on profit before tax as these derivative financial instruments have not been designated as hedges and are classified as held-for-trading. The analysis is based on derivative contracts existing at the balance sheet date, the assumption that crude oil price moves 15% over all future periods, with all other variables held constant. Management believes that 15% is a reasonable sensitivity based on forward forecasts of estimated oil price volatility.

USD 000	2022	2021
15% increase in the price of oil	(20)	373
15% decrease in the price of oil	20	(373)

Increase /(decrease) in profit before tax and equity

Foreign currency exchange risk

The Company operates internationally and is exposed to risk arising from various currency exposures, primarily with respect to the Norwegian Kroner (NOK), the Tunisian Dinar (TND), and the Pound Sterling (GBP).

The Group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the respective functional currency.

The Group reports its consolidated results in USD, any change in exchange rates between its operating subsidiaries' functional currencies and the USD affects its consolidated income statement and balance sheet when the results of those operating subsidiaries are translated into USD for reporting purposes.

Group companies are required to manage their foreign exchange risk against their functional currency.

The Group evaluates on a continuous basis to use cross currency swaps if deemed appropriate by management in order to hedge the forward foreign currency risk. The group used no currency derivatives/swaps during 2022 or 2021.

A 20% strengthening or weakening of the USD against the following currencies at the balance sheet dates presented would have increased / (decreased) equity and profit or loss by the amounts shown below.

The Group's assessment of what a reasonable potential change in foreign currencies that it is currently exposed to have been changed as a result of the changes observed in the world financial markets. This hypothetical analysis assumes that all other variables, including interest rates and commodity prices, remain constant.

USD 000	2022		2021
USD vs NOK	20%	-20%	20%	-20%
Cash	10	(15)	9	(13)
Receivables	7	(10)	7	(11)
Payables	(10)	15	(8)	12
Net effect	6	(9)	8	(12)

USD vs TND	20%	-20%	20%	-20%
Cash	3	(4)	182	(274)
Receivables	133	(200)	1,630	(2,444)
Corporation taxes payable	(1,593)	2,390	(790)	1,185
Payables	(765)	1,148	(593)	889
Net effect	(2,223)	3,334	429	(643)

USD vs EUR	20%	-20%	20%	-20%
Cash	3	(4)	3	(5)
Receivables	1	(2)	(33)	50
Payables	(32)	48	(33)	50
Net effect	(28)	42	(63)	95

USD vs GBP	20%	-20%	20%	-20%
Cash	61	(91)	66	(99)
Receivables	(49)	74	(36)	54
Payables	(18)	26	(55)	83
Net effect	(6)	9	(26)	38

Interest rate risk

The Group's exposure to the risk of changes in market interest rates relates primarily to the Group's loans and borrowings and cash balances.

The following table demonstrates the sensitivity of finance revenue and finance costs to a reasonably possible change in interest rates, with all other variables held constant, of the Group's profit before tax through the impact on fixed rate short-term deposits and applicable floating rate bank loans.

USD 000	2022		2021
	+100bps	-100bps	+100bps	-100bps
Loans and borrowings (Secured loans)	(806)	806	(954)	954
Cash equivalents	32	(32)	51	(51)
Net effect	(774)	774	(902)	902

Credit risk

The Group is exposed to credit risk that arises from cash and cash equivalents, derivative financial instruments and deposits with banks and financial institutions, as well as credit exposures to customers, including outstanding receivables and committed transactions.

For banks and financial institutions, only independently rated parties with a minimum rating of "A" are accepted. Any change of financial institutions (except minor issues) are approved by the Group CFO. The Company may engage with counterparties of a lower rating, for commercial reason, or by taking lower exposures in such counterparties to mitigate the risks following necessary approvals.

If the Group's customers are independently rated, these ratings are used. Otherwise, if there is no independent rating, risk control in the operating units assesses the credit quality of the customer, taking into account its financial position, past experience and other factors. The utilisation of credit limits is regularly monitored and kept within approved budgets.

Liquidity risk

Liquidity risk is the risk that the Group will not be able to meet its obligations as they fall due. Prudent liquidity risk management includes maintaining sufficient cash and marketable securities, the availability of funding from an adequate amount of committed credit facilities and the ability to close out market positions.

The table below summarises the maturity profile of the Group's financial liabilities at 31 December 2022 based on contractual undiscounted payments.

2022

USD 000	On demand	Less than 1 year	Between 2 to 5 years	Over 5 years	Total
Loans and borrowings (Secured loans)	-	21,470	59,340	-	80,810
Loans and borrowings (Non-recourse loan)	-	632	-	-	632
Accounts payable and accrued liabilities	-	9,087	-	-	9,087
Non-current liabilities	-	-	-	1,934	1,934
Corporation tax liabilities	-	35,560	-	-	35,560
Total	-	66,749	59,340	1,934	128,023

2021

USD 000	On demand	Less than 1 year	Between 2 to 5 years	Over 5 years	Total
Loans and borrowings (Senior secured facility)	-	15,919	79,620	-	95,539
Loans and borrowings (Non-recourse loan)	-	4,507	-	-	4,507
Accounts payable and accrued liabilities	-	12,707	-	-	12,707
Non-current liabilities	-	-	1,727	1,553	3,280
Corporation tax liabilities	-	17,018	-	-	17,018
Total	-	50,151	81,347	1,553	133,051

Management considers that the Group has adequate current assets and forecast cash from operations to manage liquidity risks arising from current and non-current liabilities.

As of 31 December 2022, the Group's total debt was USD 79.5 million. The Group closed the year with a cash position of USD 32.7 million.

Although the Company is well funded to undertake upcoming work programmes, there is a risk that additional funding may be required to conclude such activities.

Capital Management

The Group manages its capital structure to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. In order to maintain or change the capital structure, the Group may adjust the amount of dividend payments to shareholders, return capital to shareholders or issue new shares.

The Group's funding requirements are met through a combination of debt and equity and adjustments are made in light of changes in economic conditions. The Group's strategy is to maintain ratios in line with covenants associated with its Secured loans. The Group includes interest bearing loans less cash, cash equivalents and restricted cash in net debt. Capital includes share capital, share premium, other reserves and accumulated profits/losses.

The Group is continuously evaluating the capital structure with the aim of having an optimal mix of equity and debt capital to reduce the Group's cost of capital and looking at avenues to procure that in the forthcoming year.

NOTE 21: GUARANTEES, PLEDGES AND CONTINGENT LIABILITIES

Brazil

The Company has provided a performance guarantee to the Brazilian directorate Agência Nacional do Petróleo,Gás Natural e Biocombustíveis (the "ANP"), in terms of which the Company is liable for the commitments of Coral. Estela do Mar and Cavalo Marinho licenses in accordance with concession agreements. The guarantee is unlimited.

Further, in Brazil, termination agreements for the surrender of all licences have been signed between the JV partners and the ANP to conclude the relinquishment formalities on each licence and as such the guarantee no longer has a significant exposure to the Company.

The Company's formal exit from its historical Brazilian business is still ongoing with slow progress towards the approval of abandonment by the Brazilian regulators. Management is working actively with advisers and where relevant, the operator Petrobras, to bring matters to a close and to ensure that the ongoing costs are kept to a minimum. However, the timing and eventual costs of such conclusion is uncertain at this stage.

Netherlands

Under section 403(1)(f) Book 2 of the Dutch Civil Code, Pan-Petroleum Gabon B.V. (Chamber of Commerce number 27166816), a subsidiary of the Company have availed exemption for audit of its statutory financial statements pursuant to guarantees issued by the Company to indemnify the subsidiary of any losses towards third parties that may arise in the financial year ended 31 December 2022. The Company can make an annual election to support such guarantee for each financial year.

Gabon

The Company has a guarantee issued to the State of Gabon to fulfil all obligations under the Dussafu Production Sharing Contract.

There is no potential claim against these performance guarantee and all license obligations are already accounted for in the statement of financial position.

Other

At 31 December 2022, the Company has issued a parent company guarantee in favour of Mercuria Assets Holdings (Hong Kong) Ltd. to guarantee the obligations of Panoro Tunisia Production AS as borrower. The Mercuria loan was repaid in full on 15 March 2023 and the Company was released from the parent company guarantee. Refer Note 5: Finance , interest and other income and expense.

The Company has issued a parent company guarantee in favour of The Mauritius Commercial Bank Ltd. to guarantee the obligations of Panoro Energy Holding B.V. as borrower. Further details can be found in Note 5: Finance , interest and other income and expense.

The Company has issued a performance guarantee on behalf of its jointly owned company Panoro Energy AS to fulfil the payment obligation of deferred consideration of up to USD 13.2 million to DNO ASA once the milestones as agreed by parties are met.

As part of the farm-in transaction in Block 2B offshore South Africa, on 24 February 2020 the Company entered into deed of guarantee (the "Farmee Guarantee") with Thombo Petroleum Limited whereby the Company has guaranteed all obligations of Panoro 2B Limited (a wholly owned subsidiary) to Thombo Petroleum Limited under the farmout agreement of the same date. In addition, on 24 February 2020 Panoro entered into deed of guarantee with Thombo Petroleum Limited, Panoro 2B Limited and African Energy Corporation whereby the Company guarantee all obligations of Panoro 2B Limited under the farm out agreement, and under the petroleum authorisation as set out in the Farmee Guarantee.

NOTE 22: LEASES

As noted above, Panoro leases certain assets, notably office facilities for operational activities. Panoro is mostly a lessee and the use of leases serves operational purposes rather than as a tool for financing. These lease liabilities are recognised on a gross basis in the balance sheet, income statement and statement of cash flows when Panoro is considered to have the primary responsibility for the full lease payments.

In establishing Panoro's lease liabilities, the incremental borrowing rates used as discount factors in discounting payments have been established based on a consistent approach reflecting the Group's borrowing rate, the currency of the obligation, the duration of the lease term, and the credit spread for the legal entity entering into the lease contract. The London office lease contract has a reasonably certain non-cancellable period was extended to June 2023 and the liability and the right of use asset determined using an incremental rate of return of 8.5% per annum which is deemed appropriate.

Information related to lease payments and lease liabilities

Lease liability is classified as current or non-current depending on maturity profile at balance sheet date. At 31 December 2022, the entire USD 114 thousand was current (31 December 2021: USD 231 thousand current and USD 127 thousand noncurrent).

USD 000	2022	2021
Lease liability recognised at 1 January	358	578
Add: lease interest	19	40
Less: gross lease payments	(263)	(260)
Lease liability at 31 December	114	358

The following table shows the maturity profile of lease liabilities based on contractual undiscounted lease payments.

USD 000	2022	2021
Within 1 year	47	187
2 to 5 years	-	47
After 5 years	-	-
Lease liability at 31 December	47	233

Information related to right of use assets

The right of use assets are included within the line item Property, plant and equipment in the Consolidated balance sheet. See Note 9: Tangible Assets.

USD 000	2022	2021
Right of use asset recognised at 1 January	288	501
Less: depreciation and impairment	(191)	(213)
Net book value of right of use asset at 31 December	97	288

NOTE 23: RELATED PARTIES TRANSACTIONS

Details of related party transactions are set out in the parent stand-alone financial statements, Note 8: Related party transactions and balances.

NOTE 24: SUBSIDIARIES

Details of the Group's subsidiaries as of 31 December 2022 are as follows:

	Place of incorporation and	Ownership interest
Subsidiary	ownership	& voting power
Panoro Energy do Brasil Ltda	Brazil	100%
Panoro Energy Limited	UK	100%
African Energy Equity Resources Limited	UK	100%
Panoro 2B Limited	UK	100%
Panoro EG Exploration Limited	UK	100%
Pan-Petroleum (Holding) Cyprus Limited	Cyprus	100%
Pan-Petroleum Holding B.V.	Netherlands	100%
Pan-Petroleum Gabon B.V.	Netherlands	100%
Panoro Energy Holding B.V.	Netherlands	100%
Panoro Equatorial Guinea Limited	Isle of Man	100%
Panoro Gabon Exploration Limited	Isle of Man	100%
Energy Equity Resources AJE Limited	Nigeria	100%
Energy Equity Resources Oil and Gas Limited	Nigeria	100%
Syntroleum Nigeria Limited	Nigeria	100%
PPN Services Limited	Nigeria	100%
Energy Equity Resources (Cayman Islands) Limited	Cayman Islands	100%
Energy Equity Resources (Nominees) Limited	Cayman Islands	100%
Panoro Energy Gabon Production SA	Gabon	100%
Sfax Petroleum Corporation AS	Norway	60%
Panoro Energy AS	Norway	60%
Panoro Tunisia Exploration AS	Norway	60%
Panoro Tunisia Production AS	Norway	60%
Panoro TPS Production GmbH - in liqui	Austria	60%
Panoro TPS (UK) Production Limited	UK	60%

NOTE 25: EVENTS SUBSEQUENT TO REPORTING DATE

On 21 February 2023, the Board of Directors approved a cash dividend of NOK 0.2639 per share to shareholders holding shares in the Company at the end of trading on 7 March 2023. The total dividend was approximately NOK 30 million (approximately USD 3 million) and payment took place on or around 16 March 2023.

Panoro was awarded a 56 percent participating interest and operatorship of Block EG-01 located offshore Equatorial Guinea. Partners in the block are Kosmos Energy (24 percent pending signature) and GEPetrol (20 percent). Block EG-01 borders both Block G where Panoro has a 14.25 percent non-operated interest (and which contains the producing Ceiba Field and Okume Complex) and Block S where Panoro has agreed to farm-in to a 12 percent non-operated interest.

A 6 percent non-operated 12 percent participating interest in Block S was also acquired from Kosmos Energy and Trident Energy. Panoro's partners at Block S are Kosmos Energy (34 percent, operator), Trident Energy (34 percent) and GEPetrol (20 percent).

On 15 March 2023, the Mercuria loan (refer Note 5: Finance , interest and other income and expense) was repaid in full and all security held in relation to the loan released.

On 24 April 2023, the Company completed an agreement with Beender Tunisia Petroleum Limited ("Beender") to acquire its 40 percent shareholding in Sfax Petroleum Corporation AS ("SPC") for a total consideration of approximately USD 18.2 million in a mix of cash and shares (the "Acquisition"). The Acquisition increases Panoro's current ownership in SPC from 60 percent to

100 percent and SPC is now a fully owned subsidiary of Panoro. The loan facility with Trafigura was increased by USD 15 million in conjunction with the Acquisition.

NOTE 26: RESERVES (UNAUDITED)

The Group has adopted a policy of regional reserve reporting using external third-party companies to audit its work and certify reserves and resources according to the guidelines established by the Oslo Stock Exchange ("OSE"). Reserve and contingent resource estimates comply with the definitions set by the Petroleum Resources Management System ("PRMS") issued by the Society of Petroleum Engineers ("SPE"), the American Association of Petroleum Geologists ("AAPG"), the World Petroleum Council ("WPC") and the Society of Petroleum Evaluation Engineers ("SPEE") in June 2018. Panoro uses the services of Netherland Sewell & Associates ("NSAI") for third party verifications of its reserves.

Please refer to the Annual Statement of Reserves on page 28 for details.

PANORO ENERGY ASA PARENT COMPANY INCOME STATEMENT

FOR THE YEAR ENDED 31 DECEMBER

USD 000	Note	2022	2021
Operating income
Operating revenues		-	-
Total operating income		-	-
Operating expenses
General and administrative expense		(5,164)	(5,024)
Impairment of investments in subsidiary	2,6	(90)	(70)
Reversal of impairment of loan to subsidiaries	2,7,8	(1,932)	65,806
Total operating expenses		(7,186)	60,712
Operating result	2	(7,186)	60,712
Loss on disposal of business	6.1	(17,823)	-
Financial income	3	2,468	5,452
Interest and other finance expense	3	(6)	(3)
Currency gain / (loss)		(3)	232
Loss on fair value of listed equity investments		(727)	232
Result before income taxes		(23,277)	66,393
Income tax	5	-	-
Result for the year		(23,277)	66,393

PANORO ENERGY ASA PARENT COMPANY BALANCE SHEET

FOR THE YEAR ENDED 31 DECEMBER

USD 000	Note	2022	2021
ASSETS
Non-current assets
Investment in subsidiaries	6	179,974	179,974
Total non-current assets		179,974	179,974
Current assets
Listed equity investments		342	-
Loans to subsidiaries	8	33,133	59,252
Other current assets		39	-
Cash and cash equivalents		2,840	6,461
Total current assets		36,354	65,713
TOTAL ASSETS		216,328	245,687
EQUITY AND LIABILITIES
EQUITY
Paid-in capital
Share capital	9	723	721
Share premium reserve	9	428,503	427,496
Treasury Shares		-	-
Additional paid-in capital	9	122,168	122,102
Total paid-in capital		551,394	550,319
Other equity
Other reserves	9	(344,147)	(308,596)
Total other equity		(344,147)	(308,596)
TOTAL EQUITY		207,247	241,723
LIABILITIES
Current liabilities
Accounts payable		516	219
Intercompany payables	8	5,602	3,718
Other current liabilities	10	2,963	27
Total current liabilities		9,081	3,964
TOTAL LIABILITIES		9,081	3,964
TOTAL EQUITY AND LIABILITIES		216,328	245,687

PANORO ENERGY ASA PARENT COMPANY STATEMENT OF CASH FLOW

FOR THE YEAR ENDED 31 DECEMBER

USD 000	Note	2022	2021
CASH FLOW FROM OPERATING ACTIVITIES
Net income / (loss) for the year		(23,277)	66,393
Adjusted for:
Impairment of investment in subsidiary	6	90	70
Provision for Doubtful Receivables	7,8	1,932	(65,806)
Loss on disposal of business		17,823	-
Financial Income	3	(2,468)	(5,452)
Financial Expenses	3	6	3
Foreign exchange gains/losses		3	(232)
Loss on fair value of listed equity investments		(342)	-
(Increase)/decrease in trade and other receivables		(39)	-
Increase/(decrease) in trade and other payables		3,233	(253)
Increase/(decrease) in intercompany payables		(390)	(420)
Net cash flows from operating activities		(3,429)	(5,697)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash outflow relating to acquisitions		-	(50,070)
Loans to subsidiaries		(183)	(17,442)
Net cash flows from investing activities		(183)	(67,512)
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from Equity Private Placement and Treasury Shares		-	78,359
Interest paid		(6)	(3)
Net cash flows from financing activities		(6)	78,356
Effect of foreign currency translation adjustment on cash balances		(3)	232
Net increase in cash and cash equivalents		(3,621)	5,379
Cash and cash equivalents at the beginning of the year		6,461	1,082
Cash and cash equivalents at the end of financial year		2,840	6,461

PANORO ENERGY ASA NOTES TO THE FINANCIAL STATEMENTS

NOTE 1: ACCOUNTING PRINCIPLES

The annual accounts for the parent company Panoro Energy ASA (the "Company") are prepared in accordance with the Norwegian Accounting Act and accounting standards and practices generally accepted in Norway. The consolidated financial statements have been prepared under International Financial Reporting Standards ("IFRS") as adopted by the European Union ("EU") and are presented separately from the parent company.

The accounting policies under IFRS are described in the consolidated financial statements in Note 2: Basis of preparation. The accounting principles applied under NGAAP are in conformity with IFRS unless otherwise stated in the notes below.

The Company's annual financial statements are presented in US Dollars (USD) and rounded to the nearest thousand, unless otherwise stated. USD is the currency used for accounting purposes and is the functional currency. Shares in subsidiaries and other shares are recorded in Panoro Energy ASA's accounts using the cost method of accounting and reduced by impairment, if any.

NOTE 2: GENERAL AND ADMINISTRATIVE EXPENSES

Operating result

Operating result is stated after charging / (crediting):
USD 000	2022	2021
Employee benefits expense (Note 2.1)	85	67
Reversal of impairment of investment in subsidiary (Note 6)	90	70
Intercompany Loans impairment / (impairment reversal) (Note 7)	1,932	(65,806)

2.1: Employee benefits expense

a) Salaries

The Company had no employees at 31 December 2022 and 2021. As such, there are no wages and salaries included in general and administrative expenses.

Employee related expenses:

USD 000	2022	2021
Employer's contribution to payroll taxes	85	12
Total	85	12

Details of CEO and CFO remuneration are set out in the consolidated financial statements, Note 4: Operating Result. Employer's contribution relates to the employer's tax payable on the Company's Board of Directors' fees.

b) Directors' remuneration

The Group financial statements contain detail on how directors' remuneration is determined in Note 4: Operating Result.

Remuneration to members of the Board of Directors is summarised below:

USD 000	2022	2021
Julien Balkany (Chairman of the Board of Directors)	102	82
Torstein Sanness (Deputy Chairman of the Board of Directors)	68	57
Alexandra Herger	62	48
Garrett Soden	61	50
Hilde Ådland	58	48
Grace Skaugen	38	-
Total	388	285

No loans have been given to, or guarantees given on the behalf of, any members of the Management Group, the Board or other elected corporate bodies.

No pension benefits were received by the Directors during 2022 and 2021.

There are no severance payment arrangements in place for the Directors.

c) Restricted Share Unit ("RSU") and Board Share Options

Details of the RSU scheme and Board options are set out in the consolidated Financial Statements, Note 18: Share based payments.

Details of share options issued during the year to members of the Board of Directors, together with fair value expensed are summarised in the table below:

2022

USD 000 (unless stated otherwise)	Number of RSUs awarded	Fair value of RSUs expensed
Julien Balkany (Chairman of the Board)	48,000	19
Torstein Sanness (Deputy Chairman)	24,000	9
Alexandra Herger	24,000	9
Hilde Ådland	24,000	9
Garrett Soden	24,000	9
Grace Skaugen	24,000	10
Total	168,000	65

2021

USD 000 (unless stated otherwise)	Number of RSUs awarded	Fair value of RSUs expensed
Julien Balkany (Chairman of the Board)	48,000	14
Torstein Sanness (Deputy Chairman)	24,000	7
Alexandra Herger	24,000	7
Garrett Soden	24,000	7
Hilde Ådland	24,000	7
Total	144,000	41

d) Pensions

The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension ("Lov om obligatorisk tjenestepensjon"). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognised in the balance sheet.

e) Auditor

Fees (excluding VAT) to the Company's auditors are included in general and administrative expenses and are shown below.

USD 000	2022	2021
Ernst & Young
Statutory audit	-	-
Tax services	-	-
Total	-	-

The consolidated Financial Statements contain details of fees paid to the Group's auditors in Note 4: Operating Result on page 59. Audit fees for 2022 have been billed to a wholly owned subsidiary based in the UK, Panoro Energy Limited and recharged to the Parent Company and respective group companies.

NOTE 3: FINANCIAL ITEMS

The financial income breakdown is below:

USD 000	2022	2021
Interest income from subsidiaries	2,463	5,384
Other interest income	5	68
Total	2,468	5,452

Interest income from subsidiaries represents an interest on the intercompany loans. Note 8: Related party transactions and balances contains further information on these balances.

The financial expense breakdown is below:

USD 000	2022	2021
Bank and other financial charges	6	3
Total	6	3

NOTE 4: EARNINGS PER SHARE

Basic earnings per share

USD 000 unless otherwise stated	2022	2021
Net result for the period	(23,277)	66,393
Weighted average number of shares outstanding - in thousands	68,912	68,912
Basic and diluted earnings per share – (USD)	(0.34)	0.96

Diluted earnings per share

When calculating the diluted earnings per share, the weighted average number of shares outstanding is normally adjusted for all dilutive effects relating to the Company's options.

NOTE 5: INCOME TAX

USD 000	2022	2021
Tax payable	-	-
Change in deferred tax	-	-
Income tax expense	-	-

SPECIFICATION OF THE BASIS FOR TAX PAYABLE:
USD 000	2022	2021
Result before income tax	(23,277)	66,393
Effect of permanent differences	(58,765)	2,300
Effect of timing differences	37,062	65,736
Tax losses utilised	44,980	(134,429)
Basis for tax payable	-	-

SPECIFICATION OF DEFERRED TAX:
USD 000	2022	2021
Losses carried forward	12,839	21,591
Taxable temporary differences	-	-
Basis for tax payable	12,839	21,591
Calculated deferred tax asset (22% for 2022 and 2021)	2,825	4,750
Unrecognised deferred tax asset	(2,825)	(4,750)
Deferred tax recognised on balance sheet - -

The tax losses carried forward are available indefinitely to offset against future taxable profits. The tax losses for the year ended 31 December 2022 was NOK 126.3 million (USD 12.8 million at 2022 closing exchange rate).

The deferred tax asset is not recognised on the balance sheet due to uncertainty of future income.

NOTE 6: INVESTMENT IN SUBSIDIARIES

Investments in subsidiaries are carried at the lower of cost and fair market value. As at 31 December 2022, the carrying value of the investment in subsidiaries was USD 180 million (31 December 2021: USD 180 million) the holdings in subsidiaries consist of the following:

	Headquarters	Ownership interest and voting rights
Panoro Energy do Brasil Ltda (PEdB)	Rio de Janeiro, Brazil	100%
Pan-Petroleum (Holding) Cyprus Ltd (PPHCL)	Limassol, Cyprus	100%
Panoro Energy Holding B.V. (PEHBV)	Amsterdam, Netherlands	100%
Panoro 2B Limited (P2BL)	London, UK	100%
Panoro EG Exploration Limited (PEGEX)	London, UK	100%
Panoro Gabon Exploration Limited (PGEL)	Isle of Man	100%
Sfax Petroleum Corporation AS (Sfax Petroleum)	Oslo, Norway	60%

							SFAX
USD 000	PEdB	PPHCL	PEHBV	P2BL	PEGEX	PGEL	Petroleum	Total
Investment at cost
At 1 January 2022	95,687	129,106	161,971	-	-	-	18,003	404,767
Investments during the year	90	-	-	-	-	-	-	90
At 31 December 2022	95,777	129,106	161,971	-	-	-	18,003	404,857
Impairment provision
At 1 January 2022	(95,687)	(129,106)	-	-	-	-	-	(224,793)
Charge for the year	(90)	-	-	-	-	-	-	(90)
At 31 December 2022	(95,777)	(129,106)	-	-	-	-	-	(224,883)
Total investment in
subsidiaries at 31 December 2022	-	-	161,971	-	-	-	18,003	179,974
Total investment in subsidiaries at 31 December	-	-	161,971	-	-	-	18,003	179,974

Impairment of the Investment represents loss in value of the Company's investment in shares of Panoro Energy do Brasil Ltda. The impairment has been determined by comparing estimated recoverable values of the underlying investment with the carrying amount.

6.1: Discontinued operations

2021

On 21 October 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited ("PetroNor"), an exploration & production oil and gas company listed on the Oslo Axess, to divest all outstanding shares in its fully owned subsidiaries Pan-Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together referred to as "Divested Subsidiaries") for an upfront consideration consisting of the allotment and issue of new PetroNor shares with a fixed value of USD 10 million (the "Share Consideration") plus a revised contingent consideration agreed in December 2020 of up to USD 16.67 million based on future gas production volumes. The transaction completed on 13 July 2022 (the "Completion Date") with the upfront consideration of USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares (the "Consideration Shares"), determined with reference to the contractually determined 30-day volume weighted average price ("VWAP") of PetroNor's shares which are listed on the Oslo Børs with the Ticker "PNOR".

The Company's recognised a loss on disposal of business of USD 17.8 million, a result of the write off of loans receivable from the Divested Subsidiaries group, reduced by the USD 10 million value of Consideration Shares received on completion.

NOTE 7: PROVISION FOR DOUBTFUL RECEIVABLES

Provision for doubtful receivables owed from loans provided to subsidiaries, is USD 230 thousand (2021: USD 162 thousand) related to uncollectible loan provision reflective of the dormant nature of subsidiary, Pan-Petroleum Holding B.V. A loan of USD 9.8 million owing by Panoro 2B Limited was impaired during 2022 following the write off of exporation costs in the subsidiary.

NOTE 8: RELATED PARTY TRANSACTIONS AND BALANCES

During 2020, the Company has entered into an agreement with Africa Energy Corp. ("AEC") in relation to farming-in of 12.5% working interest in Block 2B, offshore South Africa. Mr. Garrett Soden, the Company's non-executive director, holds the position of CEO in AEC, and is also a Director. All decisions taken by the Company in relation to the Block 2B transaction was without any involvement from Mr. Soden and as such the transaction terms were negotiated at arm's length in a competitive process undertaken by AEC to farm-out their interest in the block.

As the ultimate parent company, the Company routinely provides funding to companies within the Group to support operations. The Company also receives technical and management services from its indirect subsidiary, Panoro Energy Limited. The cost of these services is then recharged to the relevant subsidiaries. In addition, the Company also has routine trading accounts and balances with other Companies in the Group.

The Company had the following loans receivable from its subsidiaries at 31 December 2022:

• USD 10.7 million due from its Norwegian jointly controlled entity, Sfax Petroleum Corporation AS ("Sfax") (60% owned) (31 December 2021: USD 10.7 million). Panoro Energy ASA (60%) and Beender Petroleum Corporation (40%) ("Beender") provides loans to Sfax which are non-interest-bearing with maturity dates of 31 January 2025 to fund its operations, in proportion to their respective shareholding.
• Loans of USD 8.7 million and USD 8.3 million due from its Dutch subsidiary, Panoro Energy Holding B.V., carrying interest of 2% and 4% respectively classified as current (31 December 2021: USD 10 million). These loans are classified as current and are repayable on demand.

The Company had the following non-interest-bearing payable balances to companies within the Group at 31 December 2022:

• Payable balances on account of intercompany recharges were USD 2.3 million (2021: USD 2.8 million) owed to Company's indirect subsidiary Panoro Energy Limited, which provides technical services to the Group.
• Payable balance to the Company's subsidiary, Pan-Petroleum (Holding) Cyprus Limited was USD 0.9 million (2021: USD 0.9 million).
• Payable balance to the Company's subsidiary (60% owned), Panoro Tunisia Exploration AS of USD 2.3 million.

Panoro Energy ASA also provides management services to the other companies in the Group under service agreements. The total balances receivable from Group companies for services provided under service agreement and for normal operational purposes at 31 December 2022 were:

• Panoro Energy Holding B.V, total USD 0.2 million (31 December 2021: USD 1.9 million) related to management and technical services provided during the year.
• Pan-Petroleum Gabon B.V, total USD 0.2 million (31 December 2021: USD 0.6 million) related to management and technical services provided during the year.
• Sfax Petroleum Corporation AS (60% owned); total USD 2.2 million (31 December 2021: USD 1.7 million), of which USD 0.3 million related to management and technical services provided during the year.
• Panoro 2B Limited; total USD 0.8 million (31 December 2021: USD 0.2 million)., of which USD 0.5 million related to management and technical services provided during the year.
• Panoro Equatorial Guinea Limited; total USD 2.2 million (31 December 2021: USD 2.9 million), of which USD 0.4 million related to management and technical services provided during the year.
• USD 0.3 million (31 December 2021: USD 0.3 million) from Panoro Energy AS (60% owned), of which USD Nil related to management and technical services provided during the year
• USD 0.1 million (31 December 2021: USD 1 million) from Panoro Tunisia Exploration AS (60% owned), of which USD 0.1 million related to the management and technical services provided during the year.
• USD 0.1 million (31 December 2021: USD 0.7 million) from Panoro Tunisia Production AS (60% owned), of which USD 0.1 million related to the management and technical services provided during the year.
• USD 0.6 million (31 December 2021: USD 0.6 million) from Panoro TPS Production GmbH (60% owned), of which USD nil related to the management and technical services provided during the year.

• USD Nil (31 December 2021: USD 0.6 million) from Panoro TPS (UK) Production Limited (60% owned)

Further, the Company provides funding to its Group companies to fund normal operational activity. The intercompany balances receivable from the companies within the Group at 31 December 2022 were:

• USD 17 million receivable from Panoro Energy Holding B.V which interest at between 2% and 4% and is repayable on demand.
• USD 9.2 million from Panoro 2B Limited. The balance bears interest at 10% and is repayable on demand.

NOTE 9: SHAREHOLDERS' EQUITY AND SHAREHOLDER INFORMATION

As of 31 December 2022, the Company had a registered share capital of NOK 5,684,469 divided into 113,689,372 shares, each with a nominal value of NOK 0.05 (31 December 2021: NOK 5,669,184 divided into 113,383,690 shares, each with a nominal value of NOK 0.05).

All shares in issue are fully paid-up and carry equal voting rights.

The Board may be given a power of attorney by the General Meeting to issue new shares for specific purposes.

The table below shows the changes in equity in the Company during 2022 and 2021:

USD 000	Issued capital	Share premium	Additional paid-in capital	Other equity	Total
At 1 January 2022	721	427,496	122,102	(308,596)	241,723
Net income/(loss) for the year	-	-	-	(23,277)	(23,277)
Dividend distribution	-	-	-	(12,274)	(12,274)
Shares issued under RSU plan	2	1,007	66	-	1,075
At 31 December 2022	723	428,503	122,168	(344,147)	207,247
At 1 January 2021	459	349,446	122,055	(374,989)	96,971
Net income/(loss) for the year	-	-	-	66,393	66,393
Share issue for cash	258	79,856	-	-	80,114
Share issue for lender fees	2	561	-	-	563
Shares issued under RSU plan	2	676	47	-	725

During the year the Company issued 305,682 shares, each at a fair value of NOK 33.0371, under the Company's RSU plan.

Transaction costs on share issue - (3,043) - - (3,043) At 31 December 2021 721 427,496 122,102 (308,596) 241,723

Ownership structure

The Company had 5,943 shareholders on 31 December 2022 (31 December 2021: 5,890). The twenty largest shareholders were:

No.	Shareholder	Number of shares	Holding in %
1	SUNDT AS	13,500,000	11.87%
2	HORTULAN AS	6,400,000	5.63%
3	DNB Markets Aksjehandel/-analyse	5,823,698	5.12%
4	DNB BANK ASA	3,937,310	3.46%
5	ALDEN AS	3,200,000	2.81%
6	SKANDINAVISKA ENSKILDA BANKEN AB	3,000,000	2.64%
7	Citibank Europe plc	2,998,297	2.64%
8	Citibank Europe plc	2,532,084	2.23%
9	J.P. Morgan Securities LLC	2,485,120	2.19%
10	VERDIPAPIRFONDET DNB NORGE	1,888,365	1.66%
11	F2 FUNDS AS	1,700,000	1.50%
12	CLEARSTREAM BANKING S.A.	1,605,691	1.41%
13	MIDELFART CAPITAL AS	1,603,000	1.41%
14	F1 FUNDS AS	1,600,000	1.41%
15	THORSEN, SIMEN	1,510,000	1.33%
16	Danske Invest Norge Vekst	1,235,998	1.09%
17	BNP Paribas	1,181,705	1.04%
18	VERDIPAPIRFONDET DNB SMB	1,165,387	1.03%
19	Nordnet Bank AB	1,122,212	0.99%
20	The Bank of New York Mellon SA/NV	1,083,979	0.95%
	Top 20 shareholders	59,572,846	52.40%
	Other shareholders	54,116,526	47.60%
	Total shares	113,689,372	100.00%

Shares owned by the CEO, Board Members and key management, directly and indirectly, at 31 December 2022:

Shareholder	Position	Number of shares	% of total
Julien Balkany(i)	Chairman of the Board of Directors	3,652,970	3.21%
Torstein Sanness	Deputy Chairman of the Board of Directors	185,289	0.16%
Garrett Soden(ii)	Director	30,000	0.03%
Alexandra Herger	Director	20,950	0.02%
Hilde Ådland	Director	25,322	0.02%
John Hamilton	Chief Executive Officer	638,780	0.56%
Qazi Qadeer	Chief Financial Officer	253,851	0.22%
Richard Morton	Technical Director	293,616	0.26%
Nigel McKim	Projects Director	89,237	0.08%

(i) Mr. Balkany has beneficial interest in Nanes Balkany Partners I LP which owns 664,252 shares in the Company, and Balkany Investments LLC which owns 2,485,120 shares in the Company. Mr. Balkany directly holds 503,598 shares in the Company.

(ii) Mr. Soden holds directly or indirectly 30,000 shares in the Company.

Shareholder distribution per 31 December 2022:

Amount of shares	# of shareholders	% of total	# of shares	Holding in %
1 - 1,000	3,839	64.60%	913,904	0.80%
1,001 - 5,000	1,132	19.05%	2,890,184	2.54%
5,001 - 10,000	334	5.62%	2,578,963	2.27%
10,001 - 100,000	514	8.65%	14,606,369	12.85%
100,001 - 1,000,000	103	1.73%	32,106,783	28.24%
1,000,001 +	21	0.35%	60,593,169	53.30%
Total	5,943	100.00%	113,689,372	100.00%

NOTE 10: OTHER CURRENT LIABILITIES

The breakdown of other current liabilities is below:

USD 000	2022	2021
Accruals	7	5
Employee related costs payable (including taxes)	33	22
Dividend payable	2,923	-
At December 31	2,963	27

NOTE 11: COMMITMENTS AND CONTINGENCIES

There were no commitments and contingencies at 31 December 2022 (31 December 2021: Nil).

NOTE 12: FINANCIAL MARKET RISK AND BUSINESS RISK

Refer to the consolidated financial statements Note 20: Financial risk management.

NOTE 13: GUARANTEES AND PLEDGES

The Company has provided a performance guarantee to the Brazilian directorate Agência Nacional do Petróleo,Gás Natural e Biocombustíveis (the "ANP"),, in terms of which the Company is liable for the commitments of Coral. Estela do Mar and Cavalo Marinho licenses in accordance with concession agreements. The guarantee is unlimited.

Under section 403(1)(f) Book 2 of the Dutch Civil Code, Pan-Petroleum Gabon B.V. (Chamber of Commerce number 27166816), a subsidiary of the Company have availed exemption for audit of its statutory financial statements pursuant to guarantees issued by the Company to indemnify the subsidiary of any losses towards third parties that may arise in the financial year ended 31 December 2022. The Company can make an annual election to support such guarantee for each financial year.

The Company has a guarantee issued to the State of Gabon to fulfil all obligations under the Dussafu Production Sharing Contract. There is no potential claim against these performance guarantee and all license obligations are already accounted for in the statement of financial position.

The Company has issued a parent company guarantee in favour of Mercuria Assets Holdings (Hong Kong) Ltd. to guarantee the obligations of Panoro Tunisia Production AS as borrower. The loan was repaid in full on 15 March 2023 and this security released. Further details can be found in Note 5: Finance , interest and other income and expense of the consolidated financial statements.

The Company has issued a parent company guarantee in favour of The Mauritius Commercial Bank Ltd. to guarantee the obligations of Panoro Energy Holding B.V. as borrower. Refer to Note 5: Finance , interest and other income and expense in the consolidated financial statements.

The Company has issued a performance guarantee on behalf of its jointly owned company Panoro Energy AS to fulfil the payment obligation of deferred consideration of up to USD 13.2 million (USD 7.9 million net to Panoro) to DNO ASA once the milestones as agreed by parties are met.

The Company has guaranteed all obligations of its subsidiary, Panoro 2B Limited as part of the farm-in transaction in Block 2B offshore South Africa. In addition, Panoro entered into deed of guarantee with Thombo Petroleum Limited, Panoro 2B Limited and African Energy Corporation whereby the Company guarantee all obligations of Panoro 2B Limited under the farm out agreement, and under the petroleum authorisation as set out in the Farmee Guarantee.

NOTE 14: EVENTS SUBSEQUENT TO REPORTING DATE

Refer to the consolidated financial statements, Note 25: Events subsequent to reporting date.

ANNUAL REPORT ON EXECUTIVE REMUNERATION POLICIES

(REF. SECTION 6-16B OF THE NORWEGIAN PUBLIC LIMITED LIABILITY COMPANIES ACT)

At the 2022 Annual General Meeting, proposed guidelines for executive remuneration was approved, ref. section 6-16A of the Norwegian Public Limited Liability Companies Act. The guidelines are valid for four years. Pursuant to section 6-16B of the Norwegian Public Limited Liability Companies Act, the Company shall submit an annual report which gives an overall overview of paid and accrued salary and remuneration for the previous financial year and as comprised by the approved guidelines.

The Company hereby presents the following report:

1. INTRODUCTION

1.1. Background

This remuneration report (the "Report") is prepared by the board of directors of Panoro Energy ASA (the "Company") in accordance with the Norwegian Public Limited Liability Companies Act (the "Companies Act") Section 6-16 b with regulations. The Report contains information regarding remuneration to previous, present and future leading personnel of the Company ("Executives") for the financial year of 2022 in line with the applicable requirements.

The Company considers the CEO and the CFO to be comprised by the term leading personnel under the Companies Act. Both the leading personnel are employed in the Company's group subsidiary.

1.2. Highlights summary and overview of the last financial year

2022 has been a good year for the Company. The combination of higher year-on-year oil prices and full-year contribution from the enlarged portfolio following the production acquisitions in Equatorial Guinea and Gabon which completed during 2021 drove record financial performance. The Company continued to invest in organic production and development opportunities that will drive material near term growth and expanded its acreage position selectively around core production hubs in line with Panoro's infrastructure led exploration strategy. The efforts of the management team to deliver strong financial and operational results reflect the valued contribution to the Company and is also reflected in the cash rewards and incentives provided to the Executives.

2. TOTAL REMUNERATION FOR EXECUTIVES

2.1. Introduction

The table in Section 2.2 below contains an overview of the total remuneration received by the Executives, as well as remuneration that were granted/awarded/due but not yet materialized, during the reported financial year. Only remuneration earned on the basis of the Executives' role as a leading person is comprised. Since the Executives do not receive any remuneration directly from the Company, the information in the table in Section 2.2 also represents an overview of the total remuneration which the Executives have received from other companies within the group of companies to which the Company belongs (the "Group").

2.2. Remuneration of Executives for the reported financial year from the Group

	1. Fixed remuneration			2. Variable remuneration
									6. Proportion of
				One	Multi	3. Extra	4.		fixed and
Name and	Base		Fringe	year	year	ordinary	Pension	5. Total	variable
position John Hamilton CEO	salary	Fees	benefits	variable	variable	items	expense	remuneration	remuneration
	472	-	11	181	512	-	5	1,181	41% Fixed
									59% Variable
Qazi Qadeer CFO	317	-	5	119	195	-	5	635	50% Fixed
									50% Variable

One-year variable remuneration for 2022 represents annual bonus of USD 181,000 and USD 119,000 respectively for the CEO and CFO.

Fringe benefits include private medical insurance provided for the employees and their dependants under the Company's policy.

Multi-year variable remuneration includes the Share-based payment charge for 2022 calculated in accordance with IFRS principles and expensed in the Group's 2022 income statement.

3. SHARE BASED REMUNERATION

3.1. Introduction

The table in Section 3.2 below contains information on the number of Restricted Share Units ("RSUs") granted or offered for the reported financial year which also includes the main conditions for the exercise of the rights including the exercise price and date and any change thereof appear.

3.2. RSUs granted or offered to the Executives for the reported financial year

										Information regarding the reported financial year
The main conditions of the RSU							Opening balance	During the year		Closing balance
Name and position	Plan	Performance period	Award date	Vesting Date in years after Award Date	End of holding period	Exercise period	Strike price of share	Share options awarded at the beginning of the year	Share options awarde d	Share options vested and settled	Share options subject to a perform ance conditio n	Share options awarded and unvested	Share options subject to a holding period
John Hamilton, CEO	RSU	3 years	14 June 2022	1/3 after 1 year 1/3 after 2 years 1/3 after 3 years	n/a.	Immediatel y upon vesting	NOK 0.05	448,821	131,772	(229,486)	351,107	351,107	n/a.
Qazi Qadeer, CFO	RSU	3 years	14 June 2022	1/3 after 1 year 1/3 after 2 years 1/3 after 3 years	n/a.	Immediatel y upon vesting	NOK 0.05	145,427	64,983	(74,125)	136,285	136,285	n/a.

4. ANY USE OF THE RIGHT TO RECLAIM VARIABLE REMUNERATION

The Company may demand variable remuneration refunded to the same extent it may demand fixed cash salary refunded following expiry of the employment, typically in the event of erroneous payments or breach of contractual obligations. The Company did not reclaim variable remuneration during the reported financial year.

5. INFORMATION ON HOW THE REMUNERATION COMPLIES WITH THE REMUNERATION POLICY

Please find below an explanation on how the total remuneration complies with the adopted remuneration policy, including how it contributes to the long-term performance of the Company and information on how the performance criteria were applied.

The Company undertakes an evaluation of the Executive remuneration in comparison to the Company policy at least once each year. For the most recent financial year, a review was performed in February 2022.

In order to establish a reasonableness of fixed remuneration, a benchmarking exercise was performed with peer group of external listed companies of a similar set of size and operations. Adjustments to fixed remuneration are made, when necessary, where the Board believes that there is a reasonable adjustment to be made in line with inflation or results of the peer companies comparison. For 2022, a fixed adjustment of a 8% increase was made to each of the CEO and CFO's base salaries.

Variable remuneration was awarded in the form of bonus i.e. short-term cash incentive. The award for 2022 bonus was measured against a performance criteria set by the Board at the beginning of year. A bonus of 45% was awarded to both the CEO and CFO for the initial performance criteria.

Long-term incentives in the form of RSU awards were given to the leadership team based on performance within the maximum limits allowed under the Company's RSU plan.

With respect to the application of the performance criteria, further information is provided in the table below.

Name and position	1 Description of the performance criteria and type of applicable remuneration	2 Relative weighting of the performance criteria	3 Information of performance targets a) Minimum target/ threshold performance and b) Corresponding award	a) Maximum target/ threshold performance and b) Corresponding award	4 a) Measured performance and b) actual award outcome
John Hamilton CEO	Transformational Value drivers – business development activities set by the Board	25%	a) Conclusion of at least two business development activities b) Short-term incentive	a) n/a b) n/a	a) Achieved b) Effective bonus award 12.6%
	Asset level progress including achievement of production milestones and operational targets set by the Board	50%	a) Production and operational milestones on each asset b) Short-term incentive	a) n/a b) n/a	a) Partially achieved due lower actualization of production and limited achievement of some operational milestones. b) Effective bonus award 20.2%
	Organization, HSSE, ESG targets set by the Board	25%	b) Short-term incentive	a) n/a b) n/a	a) Achieved b) Effective bonus award 12.2%
Qazi Qadeer CFO	Transformational Value drivers – business development activities set by the Board	25%	a) Conclusion of at least two business development activities b) Short-term incentive	a) n/a b) n/a	a) Achieved b) Effective bonus award 12.6%
	Asset level progress including achievement of production milestones and operational targets set by the Board	50%	a) Production and operational milestones on each asset b) Short-term incentive	a) n/a b) n/a	a) Partially achieved due lower actualization of production and limited achievement of some operational milestones. b) Effective bonus award 20.2%
	Organization, HSSE, ESG targets set by the Board	25%	b) Short-term incentive	a) n/a b) n/a	a) Achieved b) Effective bonus award 12.2%

6. DEROGATIONS AND DEVIATIONS FROM THE REMUNERATION POLICY AND FROM THE PROCEDURE FOR ITS IMPLEMENTATION

There have been no deviations from the Company's procedure for the implementation of the remuneration policy or the remuneration policy itself.

7. COMPARATIVE INFORMATION ON THE CHANGE OF REMUNERATION AND COMPANY PERFORMANCE

The table below in this Section 7 contains information on the annual change of remuneration of each individual Executive, of the performance of the Company and average remuneration on a full-time equivalent basis of employees of the Company other than Executives over the five most recent financial years.

Annual change	2018 vs 2017	2019 vs 2018	2020 vs 2019	2021 vs 2020	2022 vs 2021	Information regarding the recent financial year (RFY)
Executive's remuneration (in USD 000)
John Hamilton CEO	108	305	93	491	(398)	Decrease mainly due to one-time bonus on exceptional business performance relating to Transactions during 2021.
Qazi Qadeer CFO	51	147	22	265	(179)	Decrease mainly due to one-time bonus on exceptional business performance relating to Transactions during 2021.
Company performance for years 2018 to 2022 – change
EBITDA (in USD million)	3.4	26.5	(18.6)	57.7	63.5	EBITDA for 2019 and onwards excludes results from Discontinued Operations and hence the variance is higher in comparison to 2018.
2P Reserves (mmboe)	7.2	(19.2)	(2.7)	23.5	(0.2)	2P Reserves for 2019 and onwards excludes Assets Held for Sale and hence the variance is higher in comparison to 2018.
Average remuneration on a full-time equivalent basis of employees (in USD 000) – change
Employees of the Company	-	-	-	-	-	No group employees are directly employed by the Company.
Employees of the Group	163	1,253	473	(70)	2,070	Does not include Employer social contributions in order to assist comparison to Executive remuneration in section 2.

STATEMENT OF DIRECTORS' RESPONSIBILITY

Pursuant to the Norwegian Securities Trading Act section 5-5 with pertaining regulations we hereby confirm that, to the best of our knowledge, the company's financial statements for 2022 have been prepared in accordance with IFRS, as provided for by the EU, and in accordance with the requirements for additional information provided for by the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair picture of the company's liabilities, financial position and results viewed in their entirety.

To the best of our knowledge, the Board of Directors' Report gives a true and fair picture of the development, performance and financial position of the company, and includes a description of the principal risk and uncertainty factors facing the company.

27 April 2023

The Board of Directors Panoro Energy ASA

JULIEN BALKANY	TORSTEIN SANNESS	GARRETT SODEN
Chairman of the Board	Deputy Chairman of the Board	Non-Executive Director
ALEXANDRA HERGER	HILDE ÅDLAND	GRACE REKSTEN SKAUGEN
Non-Executive Director	Non-Executive Director	Non-Executive Director

JOHN HAMILTON

Chief Executive Officer

AUDITOR'S REPORT

-

-

-

-

STATEMENT ON CORPORATE GOVERNANCE IN PANORO ENERGY ASA

CORPORATE GOVERNANCE

Panoro Energy ASA ("Panoro", "Panoro Energy" or "the Company", and with its subsidiaries; the "Group") aspires to ensure confidence in the Company and the greatest possible value creation over time through efficient decision making, clear division of roles between shareholders, management and the Board of Directors ("the Board") as well as adequate communication.

Panoro Energy seeks to comply with all the requirements covered in The Norwegian Code of Practice for Corporate Governance (the "Code"). The latest version of the Code of 14 October 2021 is available on the website of the Norwegian Corporate Governance Board, www.nues.no. The Code is based on the "comply or explain" principle, in that companies should explain alternative approaches to any specific recommendation. The Company also seeks to comply with the Oslo Børs Code of Practice for Investor Relation (IR) of 1 March 2021.

Panoro's corporate governance policy is based on the recommendations of the Norwegian Code of Practice for Corporate Governance. The main objective for Panoro Energy ASA's Corporate Governance is to develop a strong, sustainable, competitive and a successful E&P company acting in the best interest of all the stakeholders, within the laws and regulations of the respective countries. The Board and management aim for a controlled and profitable development and long-term creation of growth through well-founded governance principles and risk management.

Panoro Energy acknowledges that successful value-added business is profoundly dependent upon transparency and internal and external confidence and trust. Panoro Energy believes that this is achieved by building a solid reputation based on our financial performance, our values and by fulfilling our commitments. Thus, good corporate governance practices combined with Panoro Energy's Code of Conduct is an important tool in assisting the Board to ensure that we properly discharge our duty.

The composition of the Board ensures that the Board represents the common interests of all shareholders and meets the Company's need for expertise, experience, capacity and diversity. The members of the Board represent a broad range of experience including oil and gas, energy, banking and investment. The composition of the Board ensures that it can operate independently of any special interests. Members of the Board are elected for a maximum period of two years. However, in the last election, the Board was appointed for one year. Recruitment of members of the Board may be phased so that the entire Board is not replaced at the same time. The Chairman of the Board of Directors is elected by the General Meeting.

The Board may be given power of attorney by the General Meeting to acquire the Company's own shares. Any acquisition of shares will be carried out through a regulated marketplace at market price, and the Company will not deviate from the principle of equal treatment of all shareholders. If there is limited liquidity in the Company's share at the time of such transaction, the Company will consider other ways to ensure equal treatment of all shareholders. The Company currently holds shareholder authorisation approved in the 2022 Annual General Meeting to acquire its own shares to a maximum of NOK 566,918.45 of share capital equivalent to 11,338,369 shares, each with a Nominal value of NOK 0.05. From the current year's authorisation, which is due to expire prior to the 2022 Annual General Meeting, the Company has not purchased any shares.

The Board may also be given a power of attorney by the General Meeting to issue new shares for specific purposes. Any decision to deviate from the principle of equal treatment by waiving the pre-emption rights of existing shareholders to subscribe for shares in the event of an increase in share capital will be justified and disclosed in the stock exchange announcement of the increase in share capital. Such deviation will be made only if it is in the common interest of the shareholders and the Company.

The Company has not granted any loans or guarantees to anyone in the management or any of the directors.

The Board acknowledges the Norwegian Code of Practice for Corporate Governance and the principle of comply or explain. Panoro Energy has implemented this Code and uses its guidelines as the basis for the Board's governance duties. A report on the corporate governance policy is incorporated in a separate section of this report and is also posted on the Company's website at www.panoroenergy.com.

The Company has implemented a policy for Ethical Code of Conduct and work diligently to comply with these guidelines. The full policy is enclosed in this Annual Report (see section Corporate Social Responsibility/ Ethical Code of Conduct).

1. IMPLEMENTATION AND REPORTING ON CORPORATE GOVERNANCE

The main objective for Panoro's Corporate Governance is to develop a strong, sustainable and competitive company in the best interest of the shareholders, employees and society at large, within the laws and regulations of the respective country. The Board of Directors (the Board) and management aim for a controlled and profitable development and long-term creation of growth through well-founded governance principles and risk management.

The Board will give high priority to finding the most appropriate working procedures to achieve, inter alia, the aims covered by these Corporate Governance guidelines and principles.

The Code comprises 15 points. The Corporate Governance report is available on the Company's website www.panoroenergy.com

2. BUSINESS

Panoro Energy ASA is an independent exploration and production (E&P) company listed on the Oslo Stock Exchange with ticker PEN. The Company holds production, development, and exploration assets in North, West and South Africa. The North African portfolio comprises a participating interest in five producing oil field concessions, the Sfax Offshore Exploration Permit (SOEP), and the Ras El Besh concession, all in the region of the city of Sfax, Tunisia. The operations in West Africa include the Dussafu License offshore southern Gabon; Block-G production licence in Equatorial Guinea, with post year-end acquisitions in Block S and Block EG-01 offshore Equatorial Guinea. In South Africa, the Company also interests in offshore Block 2B and Technical Co-operation Permit 218.

The Company's business is defined in the Articles of Association §2, which states:

"The Company's business shall consist of exploration, production, transportation and marketing of oil and natural gas and exploration and/or development of other energy forms, sale of energy as well as other related activities. The business might also involve participation in other similar activities through contribution of equity, loans and/or guarantees".

As at 31 December 2022, Panoro Energy currently has four reportable segments with exploration and production of oil and gas, by geographic locations being Equatorial Guinea, Gabon, Tunisia and South Africa.

Vision statement

Our vision is to use our experience and competence in enhancing value in projects in Africa to the benefit of the countries we operate in and the shareholders of the Company.

3. EQUITY AND DIVIDENDS

Panoro Energy's Board of Directors will ensure that the Company at all times has an equity capital at a level appropriate to its objectives, strategy and risk profile. The oil and gas E&P business is highly capital dependent, requiring Panoro Energy to be sufficiently capitalised. The Board needs to be proactive in order for Panoro Energy to be prepared for changes in the market.

Mandates granted to the Board to increase the Company's share capital or to purchase own shares will normally be restricted to defined purposes and are normally limited in time to the following year's Annual General Meeting. Any acquisition of our shares will be carried out through a regulated marketplace at market price, and the Company will not deviate from the principle of equal treatment of all shareholders. If there is limited liquidity in the Company's shares at the time of such transaction, the Company will consider other ways to ensure equal treatment of all shareholders.

Mandates granted to the Board for issue of shares for different purposes will each be considered separately by the General Meeting. Any decision to deviate from the principle of equal treatment by waiving the pre-emption rights of existing shareholders to subscribe for shares in the event of an increase in share capital will be justified and disclosed in the stock exchange announcement of the increase in share capital. Such deviation will be made only in the common interest of the shareholders of the Company.

Following the completion of the transaction to divest the group's operations in Nigeria as described in Note 14: Discontinued Operationsof the Consolidated Financial Statements, the Company received upfront consideration of USD 10 million in the form of 96,577,537 newly allotted and issued shares in PetroNor E&P ASA ("Consideration Shares"). A dividend in specie was approved by the Board of Directors on 1 August 2022 in the form of the Consideration Shares. Each Panoro shareholder as at the record date received 0.849 PetroNor shares for each share held in Panoro, rounded downwards to the nearest whole share. Fraction shares were not distributed.

The Company has announced its intention to pay cash dividends on a regular basis, and on 21 February 2023, the Board of Directors approved a first cash dividend of NOK 0.2639 per share to shareholders, representing a total cash dividend of approximately NOK 30 million (approximately USD 3 million). The Board will consider appropriate timing and size of future dividends.

4. EQUAL TREATMENT OF SHAREHOLDERS AND TRANSACTIONS WITH CLOSE ASSOCIATES

Panoro Energy has one class of shares representing one vote at the Annual General Meeting. The Articles of Association contains no restriction regarding the right to vote.

All Board members, employees of the Company and close associates must internally clear potential transactions in the Company's shares or other financial instruments related to the Company prior to any transaction. All transactions between the Company and shareholders, shareholder's parent company, members of the Board of Directors, executive personnel or close associates of any such parties, are governed by the Code and the rules of the Oslo Stock Exchange, in addition to statutory law. Any transaction with close associates will be evaluated by an independent third party, unless the transaction requires the approval of the General Meeting pursuant to the requirements of the Norwegian Public Limited Liabilities Companies Act. Independent valuations will also be arranged in respect of transactions between companies in the Group where any of the companies involved have minority shareholders. Any transactions with related parties, primary insiders or employees shall be made in accordance with Panoro Energy's own instructions for Insider Trading. The Company has guidelines to ensure that members of the Board and executive personnel notify the Board if they have any material direct or indirect interest in any transaction entered into by the Company.

5. SHARES AND NEGOTIABILITY

Shares of Panoro Energy are listed on the Oslo Stock Exchange. There are no restrictions on ownership, trading or voting of shares in Panoro Energy's Articles of Association.

6. GENERAL MEETINGS

Panoro Energy's Annual General Meeting is to be held by the end of June each year. The Board will take necessary steps to ensure that as many shareholders as possible may exercise their rights by participating in General Meetings of the Company, and to ensure that General Meetings are an effective forum for the views of shareholders and the Board. An invitation and agenda (including proxy) will be sent out no later than 21 days prior to the meeting to all shareholders in the Company. The invitation will also be distributed as a stock exchange notification. The invitation and support information on the resolutions to be considered at the General Meeting will furthermore normally be posted on the Company's website www.panoroenergy.com no later than 21 days prior to the date of the General Meeting.

The recommendation of the Nomination Committee will normally be available on the Company's website at the same time as the notice.

Panoro Energy will ensure that the resolutions and supporting information distributed are sufficiently detailed and comprehensive to allow shareholders to form a view on all matters to be considered at the meeting.

According to Article 7 of the Company's Articles of Association, registrations for the Company's General Meetings must be received at least five calendar days before the meeting is held.

The Chairman of the Board and the CEO of the Company are normally present at the General Meetings. Other Board members and the Company's auditor will aim to be present at the General Meetings. Members of the Nomination Committee are requested to be present at the AGM of the Company. An independent person to chair the General Meeting will, to the extent possible, be appointed. Normally the General Meetings will be chaired by the Company's external corporate lawyer.

Shareholders who are unable to attend in person will be given the opportunity to vote by proxy. The Company will nominate a person who will be available to vote on behalf of shareholders as their proxy. Information on the procedure for representation at the meeting through proxy will be set out in the notice for the General Meeting. A form for the appointment of a proxy, which allows separate voting instructions for each matter to be considered by the meeting and for each of the candidates nominated for elections will be prepared. Dividend, remuneration to the Board and the election of the auditor, among the matters that will be decided at the AGM. After the meeting, the minutes are released on the Company's website.

7. NOMINATION COMMITTEE

The Company shall have a Nomination Committee consisting of 2 to 3 members to be elected by the Annual General Meeting for a two-year period. The Annual General Meeting elects the members and the Chairperson of the Nomination Committee and determines the committee's remuneration. The Company will provide information on the member of the Nomination Committee on its website. The Company will further give notice on its website, in good time, of any deadlines for submitting proposals for candidates for election to the Board of Directors and the Nomination Committee.

The Company aims at selecting the members of the Nomination Committee taking into account the interests of shareholders in general. The majority of the Nomination Committee shall as a rule be independent of the Board and the executive management. The Nomination Committee currently consists of three members, all of which are independent of the Board and the executive management.

The Nomination Committee's duties are to propose to the General Meeting shareholder elected candidates for election to the Board, and to propose remuneration to the Board. The Nomination Committee justifies its recommendations, and the recommendations take into account the interests of shareholders in general and the Company's requirements in respect of independence, expertise, gender, capacity and diversity.

The Nomination Committee is described in the Company's Articles of Association and the General Meeting may stipulate guidelines for the duties of the Nomination Committee.

8. BOARD OF DIRECTORS – COMPOSITION AND INDEPENDENCE

The composition of the Board ensures that the Board represents the common interests of all shareholders and meets the Company's need for expertise, capacity and diversity. The members of the Board represent a wide range of experience including shipping, offshore, energy, banking and investment. The composition of the Board ensures that it can operate independently of any special interests. Members of the Board are elected for a period of two years. Recruitment of members of the Board may be phased so that the entire Board is not replaced at the same time. The General Meeting elects the Chairman and any Deputy Chairman. The Company's website and annual report provides detailed information about the Board members expertise and independence. The Company has a policy whereby the members of the Board are encouraged to own shares in the Company, but to dissuade from a short-term approach which is not in the best interests of the Company and its shareholders over the longer term.

9. THE WORK OF THE BOARD OF DIRECTORS

The Board has the overall responsibility for the management and supervision of the activities in general. The Board decides the strategy of the Company and has the final say in new projects and/or investments. The Board's instructions for its own work as well as for the executive management have particular emphasis on clear internal allocation of responsibilities and duties. The Chairman of the Board ensures that the Board's duties are undertaken in efficient and correct manner. The Board shall stay informed of the Company's financial position and ensure adequate control of activities, accounts and asset management. The Board member's experience and skills are crucial to the Company both from a financial as well as an operational perspective. The Board will consider evaluating its performance and expertise annually. The CEO is responsible for the Company's daily operations and ensures that all necessary information is presented to the Board.

An annual schedule for the Board meetings is prepared and discussed together with a yearly plan for the work of the Board.

The Company has guidelines to ensure that members of the Board and executive personnel notify the Board if they have any material direct or indirect interest in any transaction entered into by the Company. Should the Board need to address matters of a material character in which the Chairman is or has been personally involved, the matter will be chaired by the Deputy Chairman of the Board to ensure a more independent consideration.

In addition to the Nomination Committee elected by the General Meeting, the Board has an Audit Committee and a Remuneration Committee as sub-committees of the Board. The members are independent of the executive management. The composition of the Remuneration Committee is five members and is chaired by Torstein Sanness; whereas the Audit Committee is chaired by Garrett Soden and comrises five members. During the year, the Board has constituted a Sustainability Committee comprising of four member, led by Grace Skaugen.

10. RISK MANAGEMENT AND INTERNAL CONTROL

Financial and internal control, as well as short- and long-term strategic planning and business development, all according to Panoro Energy's business idea and vision and applicable laws and regulations, are the Board's responsibilities and the essence of its work. This emphasises the focus on ensuring proper financial and internal control, including risk control systems.

The Board approves the Company's strategy and level of acceptable risk, as documented in the guiding tool "Risk Management" described in the relevant note in the consolidated financial statements in the Annual Report.

The Board carries out an annual review of the Company's most important areas of exposure to risk and its internal control arrangements.

For further details on the use of financial instruments, refer to relevant note in the consolidated financial statements in the Annual Report and the Company's guiding tool "Financial Risk Management" described in relevant note in the consolidated financial statements in the Annual Report.

11. REMUNERATION OF THE BOARD OF DIRECTORS

The remuneration to the Board will be decided by the Annual General Meeting each year.

Panoro Energy is a diversified company, and the remuneration will reflect the Board's responsibility, expertise, the complexity and scope of work as well as time commitment.

The remuneration to the Board is not linked to the Company's performance and share options will normally not be granted to Board members, unless recommended by the Nomination Committee and approved by shareholder vote. Remuneration in addition to normal director's fee will be specifically identified in the Annual Report.

Members of the Board normally do not generally take on specific assignments for the Company in addition to their appointment as a member of the Board.

12. REMUNERATION OF THE EXECUTIVE PERSONNEL

The Board has established guidelines for the remuneration of the executive personnel. The guidelines set out the main principles applied in determining the salary and other remuneration of the executive personnel. The guidelines ensure convergence of the financial interests of the executive personnel and the shareholders.

Panoro Energy has appointed a Remuneration Committee (RC) which meets regularly. The objective of the committee is to determine the compensation structure and remuneration level of the Company's CEO. Remuneration to the CEO shall be at market terms and decided by the Board and made official at the AGM every year. Remuneration to other key executives shall be proposed by the CEO to the RC.

The remuneration shall, both with respect to the chosen kind of remuneration and the amount, encourage addition of values to the Company and contribute to the Company's common interests – both for management as well as the owners.

Detailed information about options and remuneration for executive personnel and Board members is provided in the Annual Report pursuant to and in accordance with section 6-16a of the Norwegian Public Limited Companies Act. The guidelines are normally presented to the Annual General Meeting also as a separate attachment to the Annual General Meeting notice.

13. INFORMATION AND COMMUNICATIONS

The Company has established guidelines for the Company's reporting of financial and other information.

The Company publishes an annual financial calendar including the dates the Company plans to publish the quarterly and interim updates and the date for the Annual General Meeting. The calendar can be found on the Company's website and will also be distributed as a stock exchange notification and updated on Oslo Stock Exchange's website. The calendar is published at the end of a fiscal year, according to the continuing obligations for companies listed on the Oslo Stock Exchange. The calendar is also included in the Company's interim reports.

All shareholders information is published simultaneously on the Company's web site and to appropriate financial news media.

Panoro Energy normally makes four quarterly presentations a year to shareholders, potential investors and analysts in connection with quarterly earnings reports. The quarterly presentations are held through webinars to facilitate participation by all interested shareholders, analysts, potential investors and members of the financial community. A question-and-answer session is held at the end of each presentation to allow management to answer the questions of attendees. A recording of the webinar presentation is retained on the Company's website www.panoroenergy.com for a limited number of days.

The Company also makes investor presentations at conferences in and out of Norway. The information packages presented at such meetings are published simultaneously on the Company's web site.

The Chairman, CEO and CFO of Panoro Energy are the only people who are authorised to speak to, or be in contact with the press, unless otherwise described or approved by the Chairman, CEO and/or CFO.

14. TAKE-OVERS

Panoro Energy has established the following guiding principles for how the Board will act in the event of a take-over bid.

As of today, the Board does not hold any authorisations as set forth in Section 6-17 of the Securities Trading Act, to effectuate defence measures if a takeover bid is launched on Panoro Energy.

The Board may be authorised by the General Meeting to acquire its own shares but will not be able to utilise this in order to obstruct a takeover bid, unless approved by the General Meeting following the announcement of a takeover bid.

The Board of Directors will generally not hinder or obstruct take-over bids for the Company's activities or shares.

As a rule, the Company will not enter into agreements with the purpose to limit the Company's ability to arrange other bids for the Company's shares unless it is clear that such an agreement is in the common interest of the Company and its shareholders. As a starting point the same applies to any agreement on the payment of financial compensation to the bidder if the bid does not proceed. Any financial compensation will as a rule be limited to the costs the bidder has incurred in making the bid. The Company will generally seek to disclose agreements entered into with the bidder that are material to the market's evaluation of the bid no later than at the same time as the announcement that the bid will be made is published.

In the event of a take-over bid for the Company's shares, the Board of Directors will not exercise mandates or pass any resolutions with the intention of obstructing the take-over bid unless this is approved by the General Meeting following announcement of the bid.

If an offer is made for the Company's shares, the Board will issue a statement evaluating the offer and making a recommendation as to whether shareholders should or should not accept the offer. The Board will also arrange a valuation with an explanation from an independent expert. The valuation will be made public no later than at the time of the public disclosure of the Board's statement. Any transactions that are in effect a disposal of the Company's activities will be decided by a General Meeting.

15. AUDITOR

The auditor will be appointed by the General Meeting.

The Board has appointed an Audit Committee as a sub-committee of the Board, which will meet with the auditor regularly. The objective of the committee is to focus on internal control, independence of the auditor, risk management and the Company's financial standing.

The auditors will send a complete Management Letter/Report to the Board – which is a summary report of risks faced by the business. The auditor participates in meetings of the Board that deal with the annual accounts, where the auditor reviews any material changes in the Company's accounting principles, comments on any material estimated accounting figures and reports all material matters on which there has been disagreement between the auditor and the executive management of the Company.

In view of the auditor's independence of the Company's executive management, the auditor is also present in at least one Board meeting each year at which neither the CEO nor other members of the executive management are present.

Panoro Energy places importance on independence and has established guidelines in respect of retaining the Company's external auditor by the Company's executive management for services other than the audit.

The Board reports the remuneration paid to the auditor at the Annual General Meeting, including details of the fee paid for audit work and any fees paid for other specific assignments.

16. COUNTRY-BY-COUNTRY REPORT 2022

This report is prepared in accordance with the Norwegian Accounting Act and the Securities Trading Act. It states that the companies engaged in the activities within the extractive industries shall annually prepare and publish a report containing information about investments, revenue, production, cost and the number of employees in each country of operation by subsidiary. Among other requirements, total payments to governmental bodies during the financial year must be broken down by country and by payment type.

Additional information can be found in Note 3: Operating segments of the Panoro consolidated financial statements.

Amounts in USD 000, unless otherwise stated

License, legal entity level and country/region of operation 1	Country of incorporation 2	Royalty 3	Net production (bopd)	Corporate income tax 4	Other tax 5	Invest ments 6	Revenue 7	Expen diture 8	Net inter company interest 9	Profit/ (loss) before tax 7	Tax expense/ (income) 10	Equity 7	No of Empl' yees 11
Panoro Equatorial Guinea Limited	Isle of Man	-	4,402	13,889	3,450	100,500	80,953	37,966	1,072	39,631	17,925	7,906	1
Total Equatorial Guinea		-	4,402	13,889	3,450	100,500	80,953	37,966	1,072	39,631	17,925	7,906	-
Pan-Petroleum Gabon B.V.	Netherlands	3,238	1,852	-	8,359	197,412	67,537	37,437	(8,373)	21,219	8,364	(16,285)	1
Panoro Energy Gabon Production SA	Gabon	-	-	-	-	-	-	-	-	-	-	5	-
Panoro Gabon Exploration Limited	UK	-	-	-	-	-	-	2	-	(2)	-	(2)	-
Total Gabon		3,238	1,852	-	8,359	197,412	67,537	37,437	(8,373)	21,219	8,364	(16,280)	-
Panoro Tunisia Exploration AS 12	Norway	-	-	-	-	2,593	-	1,400	-	(1,432)	-	(7,074)	-
Panoro TPS (UK) Production Limited 12	UK	-	1,244	7,825		37,223	40,136	14,381	-	24,919	15,500	47,093	10
Panoro TPS Production GmbH -in liqui 12	Austria	-	-	-	-	-	-	1	14	13	-	(4,178)	-
Total Tunisia		-	1,244	7,825	-	39,816	40,136	15,782	14	23,500	15,500	35,841	10
Panoro 2B Limited	UK	-	-	-	-	-	-	9,806	(242)	(10,048)	-	(10,292)	-
Total South Africa		-	-	-	-	-	-	9,806	(242)	(10,048)	-	(10,292)	-
Panoro Energy ASA	Norway							34,687	2,464	(32,949)	-	210,169
Sfax Petroleum Corporation AS 12	Norway	-	-	-	-	-	-	244	-	(244)	-	16,640	-
Panoro Energy AS 12	Norway	-	-	-	-	-	-	2	-	(2)	-	(328)	-
Panoro Tunisia Production AS 12	Norway	-	-	-	-	-	-	112	(14)	(6,076)	-	9,430	-
Panoro Energy do Brasil Ltda	Brazil	-	-	-	-	-	-	77	-	(76)	-	(124)	-
Panoro Energy Limited	UK	-	-	-	-	172	-	7,348	-	21	-	579	13
African Energy Equity Resources Limited	UK	-	-	-	-	-	-	-	-	-	-	(84,431)	-
Pan-Petroleum (Holding) Cyprus Limited	Cyprus	-	-	-	-	-	-	41,557	-	(41,557)	-	137,149	-
Pan-Petroleum Holding B.V.	Netherlands	-	-	-	-	-	-	78	(54)	(132)	-	(867)	-
Panoro Energy Holding B.V.	Netherlands	-	-	-	-	-	-	833	6,830	(2,235)	-	155,617	-

License, legal entity level and country/region of operation 1	Country of incorporation 2	Royalty 3	Net production (bopd)	Corporate income tax 4	Other tax 5	Invest ments 6	Revenue 7	Expen diture 8	Net inter company interest 9	Profit/ (loss) before tax 7	Tax expense/ (income) 10	Equity 7	No of Empl' yees 11
Energy Equity Resources AJE Limited	Nigeria	-	-	-	-	-	-	-	-	-	-	15,709	-
Energy Equity Resources Oil and Gas Limited	Nigeria	-	-	-	-	-	-	-	-	-	-	2,122	-
Syntroleum Nigeria Limited	Nigeria	-	-	-	-	-	-	-	-	-	-	30,108	-
PPN Services Limited	Nigeria	-	-	-	-	-	-	-	-	-	-	(57)	-
Energy Equity Resources (Cayman Islands) Limited	Cayman Islands	-	-	-	-	-	-	-	-	-	-	-	-
Energy Equity Resources (Nominees) Limited	Cayman Islands	-	-	-	-	-	-	-	-	-	-	-	-
Total Other		-	-	-	-	172	-	84,938	9,226	(83,250)	-	491,716	15
Pan-Petroleum AJE Limited	Nigeria	-	-	-		-	1,181	(106,489)	(1,678)	105,754	-	-	-
Pan-Petroleum Nigeria Holding B.V.	Netherlands	-	-	-		-	-	(243)	(10)	233	-	-	-
Pan-Petroleum Services Holding B.V.	Netherlands	-	-	-		-	-	(217)	(9)	208	-	-	-
Total Nigeria (held-for-sale)		-	-	-	-	-	1,181	(106,949)	(1,697)	106,195	-	-	-
Eliminations / Intercompany						106,840	(1,181)	28,489	-	(36,823)	-	(302,390)
Grand total		3,238	7,498	21,714	11,809	444,740	188,626	107,471	-	60,422	41,789	206,499	25

1. Country/region of operation is the country where the company carries out its main activity.

2. Country of incorporation is the jurisdiction in which the legal entity is registered.

3. Royalty represents payments made in cash that exclude in-kind royalties which are not part of Panoro's entitlement under respective PSCs.

4. Corporate tax received/-paid during the year.

5. Other tax represent a statutory payments to the Equatorial Guinea Government on extension of the licence term and the monetary value of the State profit oil under the Dussafu PSC, which is paid in kind.

6. Investments as presented in the consolidated financial statements and include estimate changes in asset retirement obligations.

7. Revenues, expenditure, profit/-loss before tax and equity at entity level in accordance with the accounting principles in the consolidated financial statements and include intercompany transactions. Audit of statutory financial statements has not been completed at the time of issuing this report.

8. Expenditure as presented in accordance with the accounting principles in the consolidated financial statements and includes cost of goods sold, administrative expenses, other operating expenses and exploration costs expensed including intercompany transactions.

9. Net intercompany interest income /-expense to/from Group companies incorporated in another jurisdiction.

10. Tax income/-expense for the year.

11. Number of employees at year-end.

12. Represents the Panoro group's 60% interest.

GLOSSARY AND DEFINITION

Bbl	One barrel of oil, equal to 42 US gallons or 159 litres
Bcf	Billion cubic feet
Bm3	Billion cubic meters
BOE	Barrel of oil equivalent
bopd	Barrels of oil per day
Btu	British Thermal Units, the energy content needed to heat one pint of water by one degree Fahrenheit
M3	Cubic meters
MMbbls	Million barrels of oil
MMBOE	Million barrels of oil equivalents
MMBtu	Million British thermal units
MMm3	Million cubic meters
TRIR	Total Recordable Incident Rate

CONVERSION FACTORS

Natural gas and LNG	To billion cubic meters NG	Billion cubic meters NG	Million tonnes oil equivalent	Million tonnes LNG	Trillion British thermal units	Million barrels oil equivalent
From			Multiply by
1 billion cubic meters NG	1.00	35.30	0.90	0.73	36.00	6.29
1 billion cubic feet NG	0.028	1.00	0.026	0.021	1.03	0.18
1 million tonnes oil equivalent	1.111	39.20	1.00	0.805	40.40	7.33
1 million tonnes LNG	1.38	48.70	1.23	1.00	52.00	8.68
1 trillion British thermal units	0.028	0.98	0.025	0.02	1.00	0.17
1 million barrels oil equivalent	0.16	5.61	0.14	0.12	5.80	1.00

COMPANY ADDRESSES

Panoro Energy ASA c/o Advokatfirma Schjødt AS , Tordenskiolds gate 12, P.O. Box 2444 Solli, 0201 Oslo, Norway

Panoro Energy Ltd 78 Brook Street London W1 K 5EF United Kingdom

Tel: +44 (0) 20 3405 1060 Fax: +44 (0) 20 3004 1130

2 ANNUAL REPORT | APRIL 202

3

Page: 124

www.panoroenergy.com

PANORO ENERGY

20 2