Annual Report • Apr 28, 2022
Annual Report
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2021 ANNUAL REPORT | APRIL 2022 Page: 1
ANNUAL REPORT 2021
APRIL 2022
www.panoroenergy.com
PANORO ENERGY
Panoro Energy ASA is an independent exploration and production (E&P) company headquartered in London and listed on the Oslo Stock Exchange with ticker PEN.
The Company holds production, development, and exploration assets in West and North Africa. Operations in West Africa include Block G consisting of the Okume Complex and Ceiba Field in Equatorial Guinea, the Dussafu License offshore southern Gabon and OML 113 offshore western Nigeria, which is classified as held for sale.
The North African portfolio comprises a participating interest in five oil field concessions (TPS), the Sfax Offshore Exploration Permit (SOEP), and the Ras El Besh concession, all in the region of the city of Sfax, Tunisia.
Additionally, a farm-in to exploration Block 2B, offshore South Africa, completed in April 2021.
| INTRODUCTION 2 | |
|---|---|
| FINANCIAL AND OPERATIONAL HIGHLIGHTS 4 | |
| COMPANY SUMMARY 5 | |
| CEO LETTER 6 | |
| DIRECTORS' REPORT 20219 | |
| ANNUAL STATEMENT OF RESERVES 2021 36 | |
| ANNEX RESERVES STATEMENT 40 | |
| CORPORATE GOVERNANCE41 | |
| CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME 44 | |
| CONSOLIDATED STATEMENT OF FINANCIAL POSITION 45 | |
| CONSOLIDATED STATEMENT OF CHANGES IN EQUITY 47 | |
| CONSOLIDATED CASH FLOW STATEMENT 48 | |
| NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 49 | |
| PANORO ENERGY ASA PARENT COMPANY INCOME STATEMENT 98 | |
| PANORO ENERGY ASA PARENT COMPANY BALANCE SHEET99 | |
| PANORO ENERGY ASA PARENT COMPANY STATEMENT OF CASH FLOW 100 | |
| PANORO ENERGY ASA NOTES TO THE FINANCIAL STATEMENTS101 | |
| DECLARATION FROM THE BOARD OF DIRECTORS OF PANORO ENERGY ASA ON EXECUTIVE REMUNERATION POLICIES111 |
|
| STATEMENT OF DIRECTORS' RESPONSIBILITY115 | |
| AUDITOR'S REPORT 116 | |
| STATEMENT ON CORPORATE GOVERNANCE IN PANORO ENERGY ASA 121 | |
| GLOSSARY AND DEFINITION 130 |
| Financial highlights - continuing operations (in USD 000) | 2021 | 2020 |
|---|---|---|
| Oil Revenue | 113,708 | 24,167 |
| Underlying operating profit/(loss) before tax | 69,745 | 1,470 |
| EBITDA | 63,702 | 6,042 |
| EBIT | 34,921 | (1,818) |
| Net Profit/(Loss) | 42,312 | (2,195) |
| Operational metrics - continuing operations | 2021 | 2020 |
|---|---|---|
| Oil sales (bbls) net | 1,578,571 | 622,638 |
| Average production - working interest (bopd) | 7,495 | 2,440 |
| 2P Reserves (MMbbls) net working interest | 36 | 12 |
| 2C Contingent Resources (MMbbls) net working interest | 29.3 | 4.3 |
Working interest production averaged 7,582 bopd (pro forma basis)
Company controlled safety performance maintained with no major safety incidents for the past four years
35.8 MMbbls 2P reserves at 31/12/21 and 29.3 MMbbls 2C resources
Strong financial performance with reported revenue of USD 119.7 million
Production drilling campaigns safely completed in Equatorial Guinea and Gabon with multiple well operations and facilities upgrades completed in Equatorial Guinea and Tunisia
Hibiscus / Ruche Phase 1 development progressing with first oil expected by year end 2022
Completed acquisition of interests in Block G, Equatorial Guinea, and additional 10% interest in Dussafu Permit Farmed in to 12.5% interest in Block 2B offshore South Africa
Provisionally awarded 25% interest in two exploration blocks as part of Gabon's 12th offshore licensing round
Participating interest (12.1913% revenue interest and 16.255% paying interest) in OML 113 Aje field, offshore – Held for sale 6.502%
Detailed information on all the assets is included in the Operations section of the Directors report on page 9.
The Company maintains its registered address in Oslo with offices in London (headquarters), Malabo and Tunis.
The over-riding lesson we can draw from our experience of the past two years is that we operate in a volatile, uncertain environment, and a key responsibility of the Board and management is to ensure we have a comprehensive and effective risk management framework in place to protect the business and underpin our growth-oriented strategy. Our risk management framework has been stress-tested to the extreme during this time and I am pleased to say its effectiveness is evidenced in how we have emerged from this period. Our operations and finances remained robust and we were able to grow a substantially larger production business with a strong growth outlook following the acquisition of a 14.25% working interest in Block G, offshore Equatorial Guinea, and an additional 10% working interest in Dussafu Marin Permit, offshore Gabon. These transactions completed in March and June respectively, adding approximately 6,500 bopd of working interest production and 24 million barrels of 2P reserves and firmly establish Panoro as a leading Africa focussed independent listed E&P company.
I am also pleased to report continued excellent health, safety and environmental performance ("HSE") throughout the year. The health and safety of our people, contractors and host communities together with minimising our environmental impact are 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, we have been working successfully to deliver safe and reliable processes since we acquired the TPS Assets from OMV in 2018. 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 each delivered drilling campaigns and numerous other production optimisation projects with an excellent HSE performance.
While the social and economic strain created by the COVID-19 pandemic persisted in 2021, the efficacy of vaccines and increasing vaccination rates permitted the loosening of pandemic related restrictions as the year progressed. This resulted in crude oil demand increasing faster than supply which placed upwards pressure on prices. Brent crude oil started the year at USD 50 per barrel and increased to a high of USD 86 per barrel in late October, before retreating in the final weeks of the year to exit 2021 at USD 77 per barrel. The slower increase in crude oil production was largely attributable to OPEC+ production cuts that were initiated in 2020 and limits applied to production increases in the year to support higher prices. This combination of increasing demand and lower supply meant there was a consistent draw on global petroleum and fuel inventories, with analysts estimating that global crude oil inventories decreased by 469 million barrels, the largest annual inventory draw since 2007.
The combination of higher year-on-year production and oil prices drove strong financial performance with revenue, EDITDA and cash flow from operations at record levels. The strengthening macro environment also gave us the confidence to increase capital expenditures to USD 36 million in the year with production drilling campaigns undertaken in Gabon and Equatorial Guinea alongside numerous production optimisation projects across the portfolio. Work on the Hibiscus / Ruche Phase I development in Gabon also continued, keeping us on track to achieve first oil by year end 2022.
2021 saw high levels of corporate activity, most notably the Tullow acquisitions I have already detailed. These transactions were financed with the key support of existing and new shareholders who supported a heavily over-subscribed USD 80 million equity private placement, and a USD 90 million underwritten debt facility by a company within the Trafigura group of companies. These transactions demonstrate Panoro's ability to execute acquisitions and identify us as a viable counterparty in future deals, particularly as incumbent IOC's are implementing global divestment programmes that include assets in Africa.
In April 2021 we completed the farm-in to Block 2B offshore South Africa for a 12.5% working interest, providing Panoro with access to prospective acreage and modest financial exposure. Post period end we were also pleased to receive government approvals in Nigeria for the sale of Panoro's interest in OML 113 to PetroNor E&P Limited, satisfying the key condition precedent for the completion of the transaction. At final completion, the divestment of OML 113 will unlock value for our shareholders through the issuance and distribution of new PetroNor shares and will represent a maiden shareholder distribution for Panoro.
Working interest production in 2021 on a proforma basis averaged 7,582 bopd compared to 2,200 bopd in 2020. After development projects and capital expenditure were put on hold in 2020, we stepped up activity in 2021. In Equatorial Guinea two new production wells were drilled and completed at the Okume Complex while a third well was plugged for re-entry at a later date. At the Ceiba field a new gas lift distribution unit was installed which will provide increased production reliability for years to come. In Gabon two new production wells were drilled and completed at the Tortue field while the Hibiscus North exploration well made an oil discovery that can be incorporated into future development planning. 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 is also progressing a subsurface re-modelling exercise for the Guebiba field and have just started a similar study for the Rhemoura field. This is expected to lead to further field optimisation and development drilling recommendations.
As a result of these portfolio-wide development activities undertaken in the year we saw our net working production reach levels in excess of 8,500 bopd in December and have line of sight on organic production growth to levels in excess of 12,500 bopd during 2023 from our current budgeted work programme.
As our production portfolio has expanded we have developed our organisational structure to reflect our enlarged footprint. I was delighted to welcome Ghislain Boukoubi (Country Manager Gabon since March 2022) and Antonino Edjang Ondo (Country Manager Equatorial Guinea) to Panoro, who alongside Sofiane Gaied (Country Manager Tunisia since 2018) will ensure that Panoro has a permanent local management presence in each country where we have production operations. It is vital to Panoro's long-term success that we attract and retain high calibre local talent, helping to ensure that we have the platform in country to invest in our assets, contribute positively to our host nations and communities and engage constructively with our stakeholders and partners.
Panoro's Country Managers are nationals and permanent residents of the respective countries of operation. They are responsible for Panoro's day-to-day oil and gas operational activities, working with joint venture partners, host governments and regulators to optimise production levels and asset performance, capital and operational budgets and managing the allocation of resources to meet the priorities of the business. Each Country Manager is also responsible for implementation of social investments that Panoro may undertake in association with joint venture initiatives or its own corporate social responsibility undertakings.
We are dedicated to ensuring that the Company's presence has a positive impact on every stakeholder. 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 transition can occur in Africa.
We continually develop our approach to managing ESG matters to meet the expectations of our stakeholders. As part of this the Board is constituting a new formal Sustainability Committee which will be active from the Annual General Meeting of May 2022. The Sustainability Committee will oversee Panoro's conduct, performance and reporting on ESG and other sustainability matters and formalise the integration of sustainability considerations with our growth strategy and key business decisions.
We have also engaged a specialist consultant to support our continued progression in appreciating ESG risks, from location based HSSE, financial and wide-ranging operational risk, to capture additional strategic risks such as climate change as outlined in the TCFD recommendations and support us with the delivery of our maiden sustainability report for full year 2022. We are expanding our awareness, monitoring and reporting of climate-related risks and its potential impact on our operations.
Through 2021, the Company made good progress against numerous ESG objectives, both with the TPS operating company in Tunisia and at the operations run by our partners in Gabon and Equatorial Guinea. We have established good relationships with our partners and are strengthening our lines of communication comprising operating activity, production, health, safety, emissions and other environmental performance analysis and evaluation. This includes enhancing our investment strategy in line with global decarbonisation commitments.
Our experience is that the industry is aligned in its need to deliver energy safely and responsibly to meet the aim of the Paris Agreement. With our partner in Tunisia, we continue to define our scope 1 and 2 emissions reduction investment strategies. Our operating partners in Gabon and Equatorial Guinea are detailing specific decarbonisation roadmaps that support a just and responsible energy transition in Africa.
I am pleased to report that Panoro's share price closed the year up 41.3%, outperforming the Oslo All Share Index which ended the year up 24.8%.
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. The commitment we have made to initiate sustainable cash dividends, perhaps significantly earlier than mid-2023 guidance issued at the time of the Tullow acquisitions, clearly demonstrates the Board's strong alignment with shareholders and prioritisation of shareholder returns through the oil cycle.
We head into 2022 and beyond with Panoro firmly established as a significant and growing oil producer in Africa. Panoro today benefits from a strongly cash generative, diversified low-cost and long-life oil production base efficiently managed by a lean organisational structure. We are fully funded through our future work programmes to unlock the considerable organic upside potential across the portfolio and maintain a conservative capital structure with an undemanding leverage profile. Our growing cash flow will allow us to start returning cash to shareholders, and at the same time positions us to 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
28 April 2022
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 and West Africa.
In 2021 Panoro acquired 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 2021, the field had produced a total of 207.4 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 2021, the Okume Complex fields had produced a total of 250.4 MMbbls gross.
In 2021, gross production averaged 9,382 bopd on Ceiba and 20,522 bopd on Okume.
Production on Ceiba was impacted during 2021 by hydrate issues. Installation of a new gas lift distribution unit (GLDU) and interconnecting flowlines was completed in October 2021 and uptime has improved significantly.
On Okume, two new Elon development wells, OG-01 and OB-14, were drilled and brought on-stream; OG-01 in November and OB-14 in December 2021. OG-01 has been producing at around 700 bopd and OB-14 at around 1,600 bopd. The Okume upgrade project was also nearing completion at year end. This has increased the power generation, process treatment and water injection capacity on the field and will also facilitate the installation of nine additional ESPs.
Plans for 2022 include a number of workovers on existing production wells including an acid stimulation campaign. The OB-15 well, drilled but not completed in 2021, is planned to be sidetracked and put on production in 2022.
In March 2022, TRACS International completed a reserves assessment of the Block G assets. As of the end of 2021 Block G was estimated to contain a gross 1P reserve of 54.6 MMbbls, a 2P reserve of 92.5 MMbbls and a 3P reserve of 124.07 MMbbls. In addition to these reserves TRACS also certified gross unrisked 1C Contingent Resources of 39 MMbbls, gross unrisked 2C Contingent Resources of 146.4 MMbbls, and gross unrisked 3C Contingent Resources of 311.8 MMbbls in the Block G licence area.
Panoro Energy are partners in the Dussafu license, a production and development license in southern Gabon, operated by BW Energy Gabon. Panoro's current interest in the license is 17.5% after the acquisition of a 10% interest from Tullow Oil plc in 2021.
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 10 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 first field in the EEA area, Tortue, started oil production in September 2018 from two horizontal development wells. In 2019/2020 a further two wells were drilled and brought onstream with the final two wells 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 2021, gross production averaged 11,300 bopd. During the year, production was impacted by issues with the gas lift compressor (GLC) system on the FPSO and unplanned shutdowns and restarts of the production wells. Production was shut-in for a week in May for maintenance and upgrades to the GLC which have improved reliability and performance.
Two new development wells, DTM-6H and DTM-7H, commenced production in late October 2021 and have each been producing at around 3,500 bopd. However, DTM-5H and DTM-3H were shut-in due to a lack of gas lift. Nitrogen lift trials are ongoing with intermittent production from DTM-5H. A second gas lift compressor is planned to be installed on the FPSO during 2H 2022 after which the six wells at Tortue are expected to reach full potential.
The next phase of development in the Dussafu license is at the Ruche and Hibiscus fields. An FID was taken for the project in 2019 and the development will consist of 6 wells in phase 1, followed by a further 6 wells in phase 2. The project consists of an offshore installation, from which the development wells will be drilled and tied back to the Adolo FPSO, via a 20 km subsea pipeline, for storage and export. Installation of the facilities is expected to be completed in 2H 2022 with the first development wells drilled in 3Q 2022 and first oil from Hibiscus/Ruche expected by the end of the year.
In March 2022, 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 2021, the Dussafu license contained gross 1P Proved Reserves of 71.5 MMbbls in the Tortue, Ruche, Ruche North East and Hibiscus fields. Gross 2P Proved plus Probable Reserves amounted to 99.7 MMbbls in the same fields. Gross 3P Proved plus Probable plus Possible Reserves in these fields amounted to 131.3 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 17.44 MMbbls and additional 2C unrisked Contingent Resources of 6.8 MMbbls.
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.
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 58 million barrels of oil to date. The current gross production is stable and ranging between 4,500 and 5,000 barrels of oil per day. Approximately 50 wells have been drilled in the TPS fields to date, whilst some of these wells have been abandoned, 14 remain on production with 5 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 1.66 MMbbls gross, which is approximately 0.49 MMbbls net to Panoro's working interest share, an average annual gross rate of 4,550 bopd. This is a 17% increase compared to the 2020 production average of 3,890 bopd due to the increased drilling and workover activities carried out by the TPS partners during the year.
Well workover operations were completed on three of the asset's fields. The El Ain field is now producing on a continuous basis following an ESP installation in the EL AIN-3SD well. At Cercina, the CER-3 ESP workover was preceded by a scale removal and acid stimulation resulting in enhanced well productivity. At Guebiba, GUE-2 and GUE-14 workovers were completed to replace failed ESPs. The GUE-14 workover included an acid stimulation again demonstrating the benefits of stimulation activities undertaken in conjunction with ESP replacements where the well productivity was boosted by some 50%. In total these well workover operations resulted in a 500 bopd production increase.
A series of facility maintenance and upgrade projects were completed, including the installation of additional water injection capacity at the GUE-8 well, augmenting pressure support to the Douleb reservoir of the Guebiba field, and the replacement of the Cercina 3 Power Generation Platform.
A team comprising ETAP and Panoro staff formed to undertake a subsurface re-modelling exercise for the Guebiba and Rhemoura fields. This work is expected to lead to further field optimisation and development drilling recommendations on both fields.
In March 2022 GaffneyCline assessed reserves and resources from the fields as of end December 2021. These reserves amount to 1P Proved Reserves of 10.9 MMbbls, 2P Proved plus Probable Reserves of 17.7 MMbbls and 3P Proved plus Probable plus Possible Reserves of 23.1 MMbbls. Panoro's net working interest 1P Proved reserves are 3.22 MMbbls, 2P Proved plus Probable are 5.20 MMbbls and 3P Proved plus Probable plus Possible are 6.79 MMbbls.
In addition to these reserves, GaffneyCline also certified gross 1C Contingent Resources of 1.6 MMbbls, 2C Contingent Resources of 5.3 MMbbls and 3C Contingent Resources of 10.0 MMbbls, all assigned to the Cercina oil field. Panoro's net working interest 1C Contingent Resource is 0.5 MMbbls, net working interest 2C Contingent Resource is 1.6 MMbbls and the net working interest 3C Contingent Resource is 2.9 MMbbls. These Reserves and Contingent Resources are Panoro's net volumes before deductions for royalties and other taxes.
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 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.
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. In 1988 the A-J 1 well drilled by Soekor 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.
Significant upside potential exists with the A-J graben with a total of 1 billion barrels of gross unrisked prospective resources identified. Six prospect areas at depths of up to 1,000 metres shallower than the reservoirs in A-J 1 have been mapped on the 686 square kilometres of 3D seismic data covering the A-J graben area. The Joint Venture partners intend to test this potential with the Gazania-1 well, targeting a relatively low risk oil play up dip of the A-J 1 discovery. The well is expected to be drilled by the end of 2022.
Additional potential exists in separate rift grabens to the north and south of the A-J graben and there is potential for significant gas discoveries in the shallower sequences above the rift graben succession over the whole block.
Panoro announced in October 2019 that it had 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 contingent consideration, as amended, of up to USD 16.67 million based on future gas production volumes. PetroNor has an option to pay a portion of the Share Consideration in cash.
In January 2022 all government approvals were received, satisfying the last key condition precedent for the transaction. Upon closing, it is Panoro's intention to declare a special dividend and distribute the Share Consideration, to the extent received in shares, to its shareholders.
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 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 and realisation of assets and settlement of debt in normal operations.
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 have therefore been isolated and removed from "Continuing activities" and re-classified and presented as a separate line item "Discontinued Operations" in the statement of comprehensive income. Group comparatives for the periods presented, pertaining to Discontinued Operations, have also been re-classified in accordance with the accounting standards. Furthermore, 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. Details of assets and liabilities held for sale and the Discontinued Operations can be referred to in Note 13: Discontinued Operations and assets held for sale.
As of 31 December 2021, the Group had USD 24.5 million in cash and bank balances and debt of USD 96.8 million, resulting in a net debt position of approximately USD 72 million. Receivables from December 2021 liftings of USD 39.8 million was received post year-end.
On 11 February 2021, the Company successfully completed a private placement of NOK 570 million of new equity with the support of new and existing shareholders. A subsequent offering of new equity of NOK 85.5 million was completed on 29 March 2021. The net proceeds of the private placement and subsequent offering were used to partially finance the acquisitions in Equatorial Guinea and Gabon and for general corporate purposes.
In March 2021, the Group completed acquisitions of Tullow Equatorial Guinea Limited (the "EG Transaction") for a cash consideration of USD 88.8 million paid on completion. The acquisition of an additional 10% working interest in Dussafu Marin permit (the "Dussafu Transaction"), offshore Gabon, completed on 9 June 2021 at which time a cash payment of USD 39 million was made.
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.
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 2021 with 2020 figures:
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 | 2021 | 2020 |
|---|---|---|
| Net income/(loss) before tax - continuing operations | 63,392 | 2,308 |
| Share based payments | 1,231 | 897 |
| Acquisition and project related costs | 1,254 | 725 |
| Unrealised (gain)/loss on commodity hedges | 3,868 | (2,460) |
| Underlying operating profit/(loss) before tax | 69,745 | 1,470 |
Underlying operating profit/(loss) before tax is a supplemental non-GAAP financial measures 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.
| USD 000 | 2021 | 2020 |
|---|---|---|
| CONTINUING OPERATIONS | ||
| Oil revenue | 113,708 | 24,167 |
| Other revenue | 5,949 | 2,689 |
| Total revenues | 119,657 | 26,856 |
| Expenses | ||
| Operating costs | (41,022) | (14,742) |
| Exploration related costs and operator G&A | (6,438) | (272) |
| Acquisition and project related costs | (1,254) | (725) |
| General and administrative costs | (7,242) | (5,075) |
| EBITDA | 63,701 | 6,042 |
| Depreciation, depletion and amortisation | (27,550) | (6,963) |
| Share based payments | (1,231) | (897) |
| EBIT | 34,920 | (1,818) |
| Gain on acquisition of business | 46,121 | - |
| Net financial items | (17,650) | 4,126 |
| Profit / (loss) before income taxes | 63,391 | 2,308 |
| Income tax expense | (21,079) | (4,503) |
| Net profit/(loss) from continuing operations | 42,312 | (2,195) |
| Net income/(loss) from discontinued operations | 7,011 | (3,138) |
| Net profit/(loss) for the year | 49,323 | (5,333) |
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.
The discussion and analysis below represent the results from the Group's continuing operations in Equatorial Guinea, Gabon and Tunisia.
Panoro Energy reported an EBITDA of USD 63.7 million from continuing operations for the year ended 31 December 2021, compared to USD 6.0 million from continuing operations for the same period in 2020.
EBITDA includes oil revenue from sale of oil of USD 113.7 million from continuing operations for 2021 comprising of 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). This compares to USD 24.2 million from continuing operations for 2020 comprising of five liftings from Dussafu totalling USD 11.4 million (266,065 bbls) and nine liftings (three international and six domestic) from the Group's Tunisian portfolio making up the remaining revenue of USD 12.8 million (356,573 bbls).
Under the terms of the Dussafu PSC, State profit oil is shown as revenue and amounted to USD 5.9 million (year ended 31 December 2020: USD 2.7 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 42.3 million from continuing operations for the year ended 31 December 2021, compared to net loss of USD 2.2 million from continuing operations for the year ended 31 December 2020.
Exploration related costs from continuing operations for 2021 are USD 6.4 million compared to USD 0.3 million in 2020. The increase was due 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 (see Note 4: Operating Result).
G&A costs relating to continuing operations are USD 7.2 million in 2021 compared to USD 5.1 million in 2020, the increase being a result of non-recurring costs related to increased activity levels as COVID-19 restrictions eased and non-recurring costs related to acquisitions (see Note 12: Business Combinations).
Depreciation, depletion and amortisation charge for the year for continuing operations of USD 27.6 million compared to the USD 7 million in 2020. The increase is mainly a result of the increase in depreciable assets due to the acquisition activity during the year.
An impairment reversal of USD 8 million related to discontinued operations was recognised in 2021 relating to the Group's interest in the Aje permit to reflect the increased certainty of completion of the sale to PetrNor, following the grant of final governmental approval for sale by the Nigerian authorities..There were no impairment charges or reversals for the year ended 31 December 2020.
EBIT from continuing operations for 2021 was thus USD 34.9 million compared to a a negative USD 1.8 million in 2020.
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 12: 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 17.7 million for 2021 compared to an income of USD 4.1 million for 2020. Net financial items comprise interest on Secured loans facility of USD 6.4 million (2020: USD 1.2 million); interest on BW Energy Non-Recourse loan USD 0.4 million (2020: USD 0.5 million); unrealised loss on commodity hedges USD 3.9 million (2020: gain of USD 2.5 million); realised loss on commodity hedges of USD 4.4 million (2020: gain of USD 4.5 million); and foreign exchange loss of USD 0.4 million (2020: gain of USD 0.4 million). The remaining financial items represent interest on unwinding of decommissioning provision and unwinding of the discount on right of use asset under IFRS 16 (Note 21: Leases).
Profit before tax from continuing operations for 2021 was USD 63.4 million compared to USD 2.3 million for 2020.
Income taxes of USD 21.1 million in 2021 compared to USD 4.5 million in 2020. The tax charge for 2021 includes USD 8.3 million related to Block G, an estimated USD 6 million (2020: USD 2.7 million) representing State profit oil under the terms of the Dussafu PSC and USD 6.9 million (2020: USD 1.8 million) for taxes on profits for the Group's Tunisian Operations. The tax charge also includes USD 1.8 million (2020: USD 1.2 million) of deferred tax liability.
Net profit after tax from continuing operations for 2021 was therefore USD 49.3 million, compared to a net loss after tax of USD 5.3 million for 2020.
Non-current assets amount to USD 455.7 million at 31 December 2021, an increase of 360.5 million from USD 95.2 million at 31 December 2020, mainly a result of the EG Transaction and Dussafu Transaction (see Note 12: Business Combinations) which contributed USD 363.2 million, with additions of USD 42.3 million offset by depreciation of USD 27.6 million and adjustment to asset retirement obligations of USD 12 million related to continuing operations.
Current assets amount to USD 100 million as of 31 December 2021, compared to USD 33.8 million at 31 December 2020. Crude inventory increased from USD 1.7 million at 31 December 2020 to USD 4.3 million at 31 December 2021. Materials inventory was USD 15.5 million at 31 December 2021, compared to USD 4.3 million at 31 December 2020.
Trade and other receivables at 31 December 2021 are USD 55.6 million, an increase of USD 44.7 million from USD 10.9 million at 31 December 2020. The increase is mainly due to an increase in uncollected proceeds from oil sales of USD 40.3 million due to liftings close to period end, the overfund position of joint venture accounts of USD 3.7 million with the remaining USD 0.7 million movement due to short term receivable items.
At 31 December 2021, the fair value of commodity hedges shows a current liability position of USD 2.5 million and was all current based on maturity. This compares to current asset positions in 2020 of USD 1.4 million.
At 31 December 2020, the Group had a bank guarantee against which a deposit of USD 10 million (net to Panoro) was placed. During 2021, USD 6.3 million of this bank guarantee was called by the Tunisian authorities to settle a historical non-fulfilment of a work programme obligation related to Sfax Offshore Exploration Permit by a previous operator. The remaining remaining USD 3.6 million was cancelled and cash returned to Panoro. As part of the settlement, the license period was renewed for a year with a single well commitment.
Cash and cash equivalents stood at USD 24.5 million, compared to USD 5.7 million at 31 December 2020. The net inflow of USD 18.8 million was mainly a result of cash inflows from operations of USD 70.4 million, gross proceeds from new secured loan of USD 90 million, proceeds from issue of new shares of USD 80 million, offset by cash ouflow related to acquisitions of USD 140.5 million and investment in exploration and production assets of USD 55.7 million, repayment of loans of USD 16.5 million principal and USD 4.8 million financial charges. The remaining items include realised losses on commodity hedges of USD 4.4 million, offset by USD 3.6 millon release of a portion of the bank guarantee not used to settle work program obligations. During 2020, 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 1 million with outflows of investment in exploration and production assets of USD 14 million, loan and borrowing cost repayments of USD 5.5 million and cash cost of RSU settlements of USD 0.8 million.
Equity as at 31 December 2021 amounts to USD 195.4 million compared to USD 67.9 million at the end of December 2020.
Total non-current liabilities are USD 305.7 million as at 31 December 2021 compared to USD 44.3 million at 31 December 2020.
Decommissioning liability increased from USD 21.5 million in 2020 to USD 140.8 million, an increase of USD 119.3 million reflecting increase due to acquisitions of USD 128.8 million, the year's unwinding of discount of USD 2.6 million offset by an adjustment to asset retirement obligations of USD 12.1 million.
Non-current and current portions of Secured Loans increased from USD 14 million at 31 December 2020 to USD 92.4 million at 31 December 2021 as a result of a new USD 90 millon facility that was fully drawn down during the year, offset by repayments of principal of USD 8.7 million and interest of USD 4.7 million during the year and offset by accumulation of interest. For further details, refer to Note 5: Finance income, interest expense and other charges.
On an overall basis, BW Energy non-recourse loan balance reduced from USD 7.2 million at 31 December 2020 to USD 4.5 million at 31 December 2021. The remaining non-current portion of the loan of USD 3 million was transferred to current portion reflecting the anticipated acceleration in repayments, and improvement in production and forward-looking oil price assumptions.
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 8.3 million at 31 December 2021 compared to USD 2.2 million at 31 December 2020. Non-current liabilities at 31 December 2021 comprise USD 5 million provision for contingent consideration related to the EG Transaction (see Note 12: Business Combinations), USD 3.2 million of provision for long term employment benefits for TPS employees (31 December 2020: USD 1.8 million) and USD 0.2 million of IFRS 16 lease liability described in Note 21: Leases.
Non-current liabilities at 31 December 2021 also include USD 74.1 million of deferred tax liabilities relating the Group's Equatorial Guinea and Tunisian assets (31 December 2020: USD 3.2 million).
Current liabilities amounted to USD 63.2 million at 31 December 2021 compared to USD 18.2 million at 31 December 2020, an increase of USD 45 million.
USD 4.5 million reflects the current portion of the BW Energy non-recourse loan including accrued interest (31 December 2020: USD 4.1 million), USD 14.7 million is the current portion of Secured Loan facilities (31 December 2020: USD 4.3 million) and USD 17 million of corporation tax liabilities in Equatorial Guinea and Tunisia (31 December 2020: USD 1.3 million).
Accruals and other payables amounted to USD 12.7 million at 31 December 2021, an increase of USD 6.7 million from the 31 December 2020 balance of USD 6 million. The increase primarily reflects levels of the larger group after the 2021 acquisitions.
Other current liabilities were USD 10.6 million at 31 December 2021 (31 December 2020: USD 1.3 million) consisting mainly of an Equatorial Guinea overlift liability position of USD 7.7 million, USD 1.8 million related to Dussafu historical cost settlement liability taken on as part of the Dussafu Transaction, with the remainder representing USD 1 million represents the Groups share of anticipated costs associated with relinquishment of the Hammamet licence; and USD 0.1 million represents the current portion of lease liabilities (Note 21: Leases).
Net cash inflow from operating activities amounted to USD 70.4 million in 2021 (31 December 2020: USD 0.5 million), the increase reflecting increased production due to acquisitions, higher oil prices and uptake in activities related to COVID-19 restrictions reducing.
Net cash flow from investing activities was an outflow of USD 196.1 million comprising of cash outflows of USD 140.5 million related acquisitions from Tullow described in Note 12: Business Combinations and investment in oil and gas assets of USD 55.7 million. This compares to an outflow in 2020 of USD 13.8 million comprising of investment in oil and gas assets.
Net cash flow from financing activities was an inflow of USD 144.6 million in 2021 (2020: outflow of USD 1.5 million). The inflow was as a result of gross proceeds of USD 90 million Secured Loan facility with Trafigura and USD 78.2 million proceeds from isue of new shares (net of costs of USD 3 million) and USD 3.6 million inflow from release of bank guarantee. These are offset by debt and borrowing costs repayment and losses on commodity hedges of USD 26.2 million. Other outflows include RSU settlements of USD 0.7 million, lease liability payments of USD 0.3 millon. Net cash outflow from financing activities during 2020 was a result of debt and borrowing cost repayments of USD 5.5 million, RSU settlements USD 0.3 million and lease liability payments of USD 0.2 million, offset by realised gains on commodity hedges of USD 4.5 million.
Cash and cash equivalents were therefore USD 24.5 million compared to USD 5.7 million at 31 December 2020.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Total revenues | - | - |
| Operating expenses | ||
| General and administrative costs | (5,024) | (1,281) |
| Impairment of investment in subsidiary | (70) | (45) |
| Provision for doubtful receivables* | 65,806 | (173) |
| Total operating expenses | 60,712 | (1,499) |
| Earnings before interest and tax (EBIT) | 60,712 | (1,499) |
| Net interest and financial items | 5,681 | 10,910 |
| Profit/(loss) before taxes | 66,393 | 9,411 |
| Income tax benefit / (expense) | - | - |
| Net profit/(loss) attributable to equity holders | 66,393 | 9,411 |
*Provision for doubtful receivables owed from loans provided to subsidiaries. See Note 7: Provision for doubtful receivables in the Parent Company Financial Statements.
The Board of Directors proposes that the profit for the year of USD 41.3 million in the parent company be transferred to other equity.
The Company on a consolidated basis, closed the year with a cash position of USD 24.5 million and debt of USD 96.8 million.
On 10 February 2021, the Company successfully completed a private placement and subsequent offering of USD 77 million (approximately NOK 652 million) of new equity with the support of new and existing shareholders. On 26 May 2021, the Company issued 307,578 shares of USD 0.6 million (approximately NOK 4.8 million) to Mauritius Commercial Bank Limited as payment of the underwriting fee in accordance with the provisions of the USD 90 million Secured Borrowing Base facility.
The Company entered into a USD 90 million Secured Borrowing Base facility on 29 March 2021 with a consortium led by The Mauritius Commercial Bank Ltd for funding of up to USD 90 million. The full facility was drawn-down during the year.
The net proceeds of the share issue and acquisition loan facility drawdowns were and are being used for general corporate purposes and to fund the acquisitions in Equatorial Guinea and Gabon as described below in Note 12: Business Combinations.
Looking ahead, the Company through its group companies, is committed to activities as descirbed in the Directors' report.
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 18, Financial instruments.
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 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.
While the social and economic strain created by the COVID-19 pandemic eased due to the efficacy of vaccines and increasing vaccination rates and the resulting loosening of pandemic related restrictions, uncertainty related to operations and financial position of the Group is still subject to uncertainty
While oil prices increased due to crude oil demand increasing faster than supply which placed upwards pressure on prices, they remain volatile which makes key assumptions applied in the valuation of the Group's assets and measurement of its liabilities difficult.
Panoro announced the sale of its interest in OML 113 to PetroNor in October 2019 (the "Aje Transaction"). Completion of Aje has been delayed considerably due local regulatory approvals and disruptions caused by the current macro environment. Furthermore, like any other transaction, there is an implicit risk around when or if the Aje Transaction would complete with the longstop date recently revised to 30 April 2022. In the event that the Aje Transaction is not completed, it may result in a risk of reassessment of recoverable amount of the OML 113 assets and re-evaluation of the designation of the related assets and liabilities as held-for-sale and the results and operations as discontinued items.
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.
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.
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.
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.
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.
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.
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 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 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 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.
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.
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:
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'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.
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).
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.
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 2021 Annual General Meeting to acquire its own shares to a maximum of NOK 563,993.55 of share capital equivalent to 11,279,871 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 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. The full policy is enclosed in this annual report (see section Corporate Social Responsibility/ Ethical Code of Conduct).
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 five at year end 2020 and 2021, all non-executive directors. The members have various backgrounds and experience, offering the Company valuable perspectives on industrial, operational and financial issues. Two of the five Board members as at year end 2021 are female. The Board held seven meetings during the year which includes meetings held through circulation of documents and by phone calls (year ended 31 December 2020: eight meetings).
The Board is constituting a new formal Sustainability Committee which will be active from the General Meeting of May 2022.
The Board believes it to be in the best interest of the Company and in line with industry best practice to establish a Sustainability Committee in order to assist the Board to monitor the performance and key risks that the Company faces in relation to ESG, ethical, health and safety matters.
The Sustainability Committee's responsibility is to:
The Board may establish a further charter for the committee's work and tasks. The members of the Sustainability Committee shall be elected by the Board following the 2022 Annual General Meeting and the committee shall thereafter commence its work.
In line with our aim to have a positive impact wherever we work in the world, we seek to achieve sustainable operations, continue to be an influential partner and to act in a socially responsible manner.
Our culture is one premised on setting high ethical standards and professionalism, characterised by the values of respect, honesty, transparency and trust throughout all levels of the organisation. The Company, bound by its Code of Conduct, is committed to acting in a transparent manner and expects the same of our host governments, partners, employees, contractors, and customers.
The information incorporated within this ESG review is the result of the Company's continued engagement with internal and external stakeholders and is informed by the reporting guidelines of the Global Reporting Initiative, IPIECA, SASB and Euronext.
As a joint venture operator and non-operating partner in oil and gas assets across Africa, our ability to influence and execute on operational matters varies. As such, we have designed our ESG strategy to comprise three elements all in support of our corporate objectives: that of sustainable operations; acting as an influential partner; and being a socially responsible investor.
The following table outlines our key commitments in our approach to ESG management and neatly maps our alignment to our three identified pillars which we believe encapsulate the interests of our stakeholders. Further discussion of these areas can be found throughout this Report.
| Sustainable Operations |
Influential Partner |
Socially Responsible Investor |
|
|---|---|---|---|
| Commitment | Alongside our partners at ETAP, we are committed to excellent standards of health, safety and environmental management and we actively engage the communities surrounding the operations to understand the implications of our activities on wider society. |
Leveraging our industry expertise, we will work closely with our partners to safely and responsibly operate our assets and support a just and sustainable energy transition for the continent of Africa. |
We continue to work towards mitigating our social and environmental impacts and are now focused on working with our JV partners to develop and implement projects that support and enable/provide livelihoods. |
| 2021 Activity | Two Panoro secondees to • TPS embedded themselves further in the operations. Our new Deputy General • Manager brings significant production and ESG expertise gained with other operators across a number of jurisdictions. Enhanced data gathering • system established at TPS to ensure IOGP compatible data was being sourced. Engaged operating partners for EG and Gabon to gain access to similarly benchmarked data. |
Company staff placed a • significant focus on asset integrity management for the TPS and EG mid-life facilities. At TPS an overhaul of the chemical management program and facility topsides and subsea inspections are leading to remediation activity where required, together with improved operational performance. Trident progressed very extensive facility upgrade projects at both Ceiba and Okume resolving long standing integrity issues in these assets with Panoro's full support. Senior Reservoir • Engineer and Technical Assistant added to the team in London to provide improved management of assets in all countries. Continued active • engagement with Government and ministries. |
The EG Block G Corporate • Social Responsibility Programme has to date reached over 500,000 people from vulnerable communities. More frequent participation • in technical and operating committee meetings in Equatorial Guinea. We have invested in an in • country manager in EG who we have tasked with building our presence. Covid equipment supplied • to support local healthcare system in Tunisia. 30 total employees, of • these 18 are located in Tunisia, only 2 are expatriates. Our employee in Equatorial Guinea is local staff. 75% of annual spend was • on local suppliers in Tunisia, 62% in Equatorial Guinea. |
| 2022 Activity | Through TPS: Enable gas valorisation • programme to reduce emissions and increase efficiencies. Commence Phase 3 of • Safety Culture development programme, implementing findings from TPS audit. |
Seek greater • involvement with JV partners in Gabon and EG to shape emissions reduction strategies. Actively engage in • assessment of optimal gas management strategy for the EG asset so as to reduce gas |
Appoint a local staff Gabon • country manager. Development of CSR • strategy in Gabon and Equatorial Guinea. Seek greater involvement • and engagement with NGOs in Equatorial Guinea. |
| Perform gap analysis, • design and implement Quality and Environment Management system as per ISO 9001 & 14001. Continue implementing • findings from potential Major Accident Event (MAE) study. Strengthen community and • local authority ties. Engage specialist contractor • to conduct Security Risk Assessment across all sites and pipelines. |
energy usage. Closely monitor • striving to achieve necessary. |
flaring and optimise • execution and start-up of Ruche Phase 1 project, industry best practice through timely advice and intervention as |
Deliver training program that will provide local populous with skillsets that will facilitate TPS supply chain. |
|---|---|---|---|
| ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------ | ----------------------------------------------------------------------------------------------------------------------------- |
The expectations of our stakeholders are very important for us and influence what we seek to achieve through our strategy and the manner in which we work. We consistently engage with our stakeholders to manage the social and environmental impact of our activities in the different markets in which we are present.
The stakeholders of Panoro are defined as entities that are influenced by, or have an influence on, the development of Panoro's assets. Our target remains to increase engagement opportunities with stakeholders, as well as collaborate to make our value chain more sustainable.
Throughout this ESG review, Panoro addresses the management of stakeholder priorities and refines its scope to the following priorities going forward.
| Stakeholder | Priorities | Engagement |
|---|---|---|
| Employees | Workplace Health and Safety • Training and Development • Remuneration • Job Security • Equal opportunities employer • Diversity and inclusion • |
We recognise the importance of retaining our highly skilled employees, it is therefore key that we engage our workforce regularly and offer opportunities to develop their skillsets. In addition, each employee is expected to learn about and undertake training on the Code Of Conduct on a regular basis. |
| Investors and Financial Institutions |
Governance • Climate Change • Emissions management • Financial Performance • ESG Performance • Board remuneration • Risk management • IT Security • |
Panoro will seek to minimise shareholder risk and maximise value creation by adhering to the highest ethical standards in terms of environmental, legal and other risks based on the above principles. To maintain transparency, we engage through meetings, our website and reporting. |
| Local Communities | Social Investments • Community Health • Environmental Management • Local Content • Employment Opportunities • |
We seek to maintain positive relationships with communities at each asset. We have in place formal communication lines and seek to develop social programmes based on community requirements. |
| Joint Venture Partners | Asset integrity • Technical Expertise • Governance • Ethical Business Practices • Financial Performance • |
Through partnership agreements, as well as through formal and informal communication, Panoro will seek to have a positive influence on partners to enable the seamless running of operations. |
|---|---|---|
| Host Governments | Regulatory Compliance • Employment Opportunities • Emissions management • Business ethics • Social Investments • Financial Performance • |
Developing and sustaining positive and transparent relationships with governments and regulators is crucial. Communications are maintained through meetings and regulatory and legal filings. |
Alongside our partners at ETAP, we are committed to excellent standards of health, safety and environmental management and we actively engage the communities surrounding operations to understand the implications of our activities on wider society.
Panoro's organisational structure, Code of Conduct, standards and culture together form a system of internal controls that govern how we manage associated risks. Our risk management system is designed to be a consistent and clear tool for managing and reporting risks from the group's operations to management and to the board on a quarterly basis.
Through our Enterprise-Wide Risk Management (EWRM) process, we identify, monitor and address ESG and climate-related risks to our business. Panoro maintains a risk register in which we can monitor these risks to the company with a potential financial impact. Risks are then assessed by severity and relevant mitigation actions are established.
Panoro is committed to effectively managing all aspects of risk for the business to reduce any negative effect to as low as reasonably practical (ALARP).
Day to day risk management seeks to promote safe, compliant and reliable operations as well as greater efficiencies, with our standards taking into account applicable laws and regulations.
TPS are required to report safety and environmental incidents on an urgency basis dictated by their significance, whilst daily production reports with health, safety and environmental highlights are provided from our assets. In addition, routine conversations allow deeper probing and understanding of any potential issues that arise.
Panoro acknowledges that ethical, sustainable and responsible operating policies and practices are essential when conducting business and support our ability to preserve and create value for our stakeholders. It is therefore critical that each and every one of us always keep in mind how we behave and how we conduct our business. We shall at all times strive to exercise good judgment, care and consideration in our sincere intention to obtain the best possible result for all parties involved.
In 2022, Panoro will seek to establish a longer-term emissions target based on industry standards, our ambition is to reduce flaring across our assets and use the gas effectively.
Our Code of Conduct explains, in general terms, the ethical standards we request in all our business behaviour, attitude and performance, and shall reflect as well as promote our core values and promises in our actions towards colleagues, business partners and the society at large.
Panoro takes environmental management very seriously and is committed to managing the environmental impact of its activities. We are firmly committed to embracing our environmental responsibility, and to honouring the spirit of the UN Global Compact principles. We believe that this is the right approach for all our stakeholders, including but not limited to the host countries, the local communities, our shareholders and business partners.
Where Panoro is not the operator, we engage our operating partners so they understand our performance expectations and work together to improve performance.
As a partner in the TPS operated assets and operator for the Sfax Offshore Exploration Permit, TPS places great emphasis on conducting its business activities in strict compliance with national regulations in order to deliver upon its business objectives. In line with its commitment to continuous improvement and raising environmental performance management, consideration was given to strengthening TPS' environmental management sytem. Consequently, TPS is preparing for ISO 14001 certification, the internationally recognised environmental management system, aiming for conclusion in 2022.
During the course of the year, numerous air emissions assessments were conducted by an external expert across all operating sites, no non-compliance emissions anomalies were identified. This program served a dual purpose in that it allowed us to reinvigorate the focus on a gas valorisation program that would reduce the flared emissions at Cercina, Guebiba and at TPS' Tank Battery. We explain this further in our energy transition section.
An energy audit was also completed at the Tank Battery which outlined recommendations to optimise the cost of electricity consumed and bill monitoring by the maintenance team in order to avoid any discrepancies.
In the context of a transition to a low carbon economy, achieving the highest environmental standards is enshrined in the Company HSSE policy, under that we are in the process of developing a sustainability framework standard and an environmental data reporting guideline at an executive level. We have already implemented a system to identify, understand and assess Panoro's emissions footprint as a pre-cursor to develop plans that mitigate our impact and outline opportunities to reduce emissions from established baselines.
Process safety involves making sure facilities are well designed, safely operated and appropriately maintained to prevent leaks of hazardous materials. We carefully plan our operations, with the aim of identifying potential hazards and having rigorous operating and maintenance practices to manage risks at every stage.
TPS employ a dedicated Process Safety Engineer and hold monthly management meetings to track process safety actions. We are confident in the management by TPS of the monitoring of the condition of onshore and offshore pipelines.
Where our operations are located in shallow water which is used for fishing, we are proactively ensuring the integrity of pipelines. In 2021 we continued our intelligent pigging program, an exercise designed to verifythat the production system is being managed and monitored to prevent any leaks. We have a target to complete a full analysis of the state of internal corrosion of our pipelines and expect completion of the intelligent pigging of all the asset's pipelines by the end of 2022.
Panoro is a small organisation of 28 office-based employees in London and Tunisia. In addition, as at end 2021 we have a single-person office in Equatorial Guinea. Our teams are made up of experienced personnel with broad and complementary skill sets that enable the growth ambitions of the business.
| Category | Number |
|---|---|
| Direct Employees | 28 |
| TPS Total Employees | 171 |
We provide training for all Panoro employees on an ad hoc basis or as appropriate to meet with regulations.
Our open-door policy promotes an inclusive and transparent culture where management is approachable and willing to discuss matters as they arise. This facilitates clear communication and enables our close working relationships.
Within Tunisia, we comply with strict labour and social security laws, which include a maximum of 48 working hours per week. We maintain an ongoing dialogue between the Company and the unions.
At Panoro, safety is our number one priority. Our goal is to achieve zero harm to people, zero lost-time incidents and zero incidents.
All of our employees and contractors working at Panoro have a role to play in identifying, assessing and managing risks within the Company. The Company's Health, Safety, Security and Environment (HSSE) Policy demonstrates a commitment to identifying, assessing and managing HSSE Risks.
Our board is responsible for deciding which level of risk is acceptable for the business. It annually reviews strategic risks to the business and, on a quarterly basis, reviews the top ten risks documented in the Risk Register. The Board's focus is to provide oversight of risk mitigation strategies and to consider if adequate risk mitigation plans are in place.
We operate in a manner that helps protect our employees, contractors, partners, suppliers and the communities in which we operate. As the Company continues to grow and evolve from non-operator to operator the focus has naturally expanded and strengthened.
Company controlled safety performance remains unchanged in 2021, recording no major safety incidents for the past four years. Sickness absence in 2021 was less than 1%.
As a 50% JV partner in TPS, we take equal responsibility for the health, safety and welfare of our 171 TPS employees. It is our top priority. Our health and safety management system sets clear operating parameters and all H&S data is reported in line with IOGP standards. TPS provides health and safety updates to Panoro at the quarterly TOCMs (Technical and Operating Committee Meetings).
In 2021, we kick-started a proactive programme focused on process and occupational safety. Panoro continues to influence its JV partner and the TP operating business on the need to be proactive and on the front foot in managing potential safety and environmental incidents. As a consequence, TPS was instructed to carry out a potential Major Accident Event ('MAE') audit. This MAE hazard program comprises controls designed to ensure that MAE risks are minimised to ALARP. The audit was carried out to account for numerous projects, process modifications and asset lifecycles. Six major scenarios were modelled through the program which presented numerous findings and a list of recommendations that are being implemented.
TPS Total Recordable Injury Rate (TRIR)
Due to one medical incident, one restricted work incident and one lost-time incident at TPS, our TRIR in 2021 was 2.74 (2020: 1.27). Assessments were carried out on each of these incidents in order to establish good safety behaviours. Following the investigation, TPS has since implemented a safety culture program. The program comprises three phases, with phase 1
consisting of introduction training to safety culture, completed by 46% of employees at year end. During Phase 2, TPS is working to refine its approach to safety and implement positive improvements to the culture and enhance monitoring and reporting protocols.
In Q1 2021, there were 3 security matters identified and effectively responded to with the support of third parties as necessary. Whilst TPS have strong relationships with communities and authorities, the socio-economic conditions of Tunisia can drive civil unrest. It experienced two events in Q1 whereby local communities protested at two of its operating sites. Its response measures with support of the National Guard, peacefully resolved each situation and the driving factors behind these protests are informing combined Panoro, ETAP and TPS community engagement programs that can be read about on page 27
In May 2021, TPS carried out an exercise to test the Emergency Response Plan (ERP), platform arrangements, resources and people preparedness through a Cercina Medevac Drill. We are pleased to report the robustness of our existing ERP plans and that the speed of sea transpotation met required standards. The exercise highlighted an issue with accessbility which we are seeking to address in 2022.
Panoro prides itself on its ability to attract high-calible industry professionals that champion leading industry practices. As part of our concerted effort to raise performance standards at TPS, two Panoro personnel were seconded to TPS. The Development Manager and Deputy General Manager have supported improvements to the business, both operationally and culturally, and will be instrumental in supporting TPS execute its ESG development plans on numerous fronts.
Our business success depends on how well we manage those who work on our behalf. All staff and contractors working for Panoro have a vital role in identifying, assessing and managing risks within the Company.
Road safety awareness and safe driving are of utmost importance to us. Whether delivering equipment to projects or travelling to meetings, we work hard to keep all our drivers safe around the world.
At our operations in TPS, we have more than 20 contractor companies, and if necessary, Panoro will seek additional information to satisfy itself that third parties share the same values and will perform to similar safety standards.
Panoro is fully committed to taking action on climate change. This commitment will be delivered through establishing initiatives to minimise our GHG emissions. Throughout 2022, we will be working with a third party to define and implement these processes which we will be reporting on in 2023.
Alongside ETAP and TPS, the Panoro team have been assessing a number of studies to reduce the amount of gas flaring in line with our ambition to reduce our environmental impact. A gas valorisation feasibility study commenced in 2021 to assess the use of microturbines or gas engines to power infrastructure across our operations. We expect this study to be completed in Q2 2022. The objective of the study is to investigate and recommend optimum option(s) for the valorisation of flared gas in TPS onshore and offshore fields. As a result, the business has modelled gas production from our assets extending to 2030 to analyse the environmental and financial benefits of this program.
We recognise our role in the energy transition with regard to Africa to ensure positive socioeconomic development while the continent transitions at a more gradual rate. Oil and gas will continue to play an important role in the energy mix under even the most demanding low-carbon scenarios until clean and affordable alternatives are developed.
We baseline our data against IOGP standards and continue to do so to help informed decision making and investment into existing and potential future assets. Our focus is to understand our performance and plan activities to improve.
Leveraging our industry expertise, we will work closely with our partners to safely and responsibly operate our assets, and support a just and sustainable energy transition for the continent of Africa.
We believe that communication is key. Being a respected and trusted partner to our operating and JV partners is crucial to our business objectives.
Across our assets, we actively work alongside other recognised industry partners as both an operator and non-operator. In both of these scenarios, we have an active and vocal participation in seeking to exert a positive influence over our partners and offer support.
As a non-operator, we must uphold robust governance policies and processes and clearly communicate with our partners to ensure they are meeting our expectations and high standards. It is the responsibility of the team to challenge the capabilities of the operator and to regularly analyse the operating, safety and environmental performance of the joint venture.
The Panoro team has a long history of contributing significant technical expertise to influence developmental work. We meet with our partners on a quarterly basis to ensure our ambitions are aligned. Panoro is constantly assessing and ensuring it has the right skills to influence operators to minimise risks, to continue to be able to fulfil this requirement we added a Senior Reservoir Engineer and Technical Assistant to our team.
As part of our 2022 Equatorial Guinea Action Plan, we have formed strategic partnerships in order to effectively gather, analyse and report on information. We have developed comprehensive internal reporting of Political, Social, Environmental and Legal information to help inform in-country decision making.
In line with our commitment to safety and seeking the highest standards, we maintain joint oversight of the assets and the FPSO. A critical consideration is understanding the integrity of the FPSO, preventing any spills through hull integrity, asset integrity and ship collision avoidance, and we monitor this closely at our Technical and Operating Committee Meetings and track on our risk register.
Our operating partner in Gabon, BW Energy, produced its maiden Sustainability Report for 2021. Framed by the UN Sustainable Development Goals, it articulates their approach to ESG management and performance.
At asset level, BW Energy provide its partners with quarterly ESG performance analysis and health, safety and environmental data captured in alignment with IOGP guidance.
In 2021, there were no environmental incidents reported. Through 2022, a major focus for BW Energy is on flared and total emissions. Areas for investment have been identified for which Panoro is very supportive.
Flared and greenhouse gas emissions are tracked against global, UK and Africa 2019 averages, this makes it clear that there is work to be done to improve performance. Oil in water concentration for BW Energy produced water is ahead of Africa, Global and World Bank average for 2021.
Trident Energy has put in place advanced systems that have allowed them to set targets during the course of the year. Trident recognises strong positive inputs will lead to positive outcomes and continue to keenly track leading and lagging indicators. Leading indicators saw a strong positive increase in 2021 due to inspections and audits, site inductions and training and emergency response drills. Despite this, high potential incidents and environmental releases increased in 2021. Alongside our JV partners, we are supporting our operating partner and providing our industry expertise to influence corrective actions.
We recognise the importance of having open and transparent relationships with government authorities in the countries in which we operate.
In Tunisia, we maintain good working relationships, keeping them informed of our activities, ongoing projects and key concerns as well as engaging in a wide range of policy and regulatory compliance.
Payments to Governments are based on three main aspects, royalties on production, tax and the Domestic Market Obligation (DMO) discount. Contractually, these payments may be made in cash or in barrels of oil. Other payments are related to services and dependent on the activity.
Panoro Energy has prepared a report of payments to governments in accordance with the Norwegian Accounting Act 3-3d and Securities Trading Act 5-5a. It states that the companies engaged in the activities within the extractive industries shall annually prepare and publish a report containing information about their payments to governments at country and project level.
Developing and sustaining positive and transparent relationships with governments and regulators is crucial to our license to operate, helping to maintain confidence in our management capacity and performance. We maintain good working relationships keeping host Governments informed of our activities, ongoing projects and key concerns as well as engaging in a wide range of policy and regulatory compliance.
Panoro's Code of Conduct details our responsibility to our broad stakeholders including shareholders, customers, employees, partners and communities. We aim to act with the highest integrity and operate with the highest ethical standards.
Panoro is committed to acting professionally, fairly, and with integrity in all business dealings and relationships, in whatever country we operate. We do not tolerate any discrimination, harassment, or assault in the workplace and we base employment on the principle of equal opportunity and fair treatment.
Equatorial Guinea is considered a country with a high degree of corruption, it is therefore essential that Panoro ensure all transactions are processed with respect to the UK Bribery Act and FCPA.
Panoro is an equal opportunity employer and has enshrined this within its policies. We have a responsibility to ensure that all employees feel safe and supported. The Company embraces a diversified working environment, and the Company's personnel policies promote equal opportunities and rights and prevent discrimination based on gender, ethnicity, colour, language, religion or belief. Stated in our Code of Conduct, we focus on high ethical standards, professionalism, respect, honesty, transparency, loyalty and trust throughout all levels of the organisation.
Panoro had 28 permanent employees at the end of 2021 of which 75% were male and 25% were female. These statistics exclude employment at a joint venture level where assets are jointly controlled and Panoro is not the operator.
Understanding and addressing the interests of societies and communities is an important component of maintaining a successful business. Our approach is to engage with our neighbours, community leaders, non-governmental organisations and charities with respect and dignity to understand the implications of our activities and changes in the industry and wider society.
Our vision is to create more jobs in-country and help diversify the local economy. We always encourage the employment of local staff and engage in capacity building through the transfer of skills and technologies. Our aim is to support local companies' growth and expand their participation in the local economy, to generate local value for people and communities. We always strive to source from companies locally, for example, in 2021, 75% of our spending at TPS and 62% in Equatorial Guinea was devoted to local suppliers.
Wihtin Tunisia, there is frequent demand from the local populous to provide direct jobs. We recognise the importance of creating an ecosystem of employment opportunities that can expand beyond TPS. We have a engaged number of local bodies to establish a considered training program that will provide people with right skillsets that will facilitate upskilling of local indidividuals to allow them to create businesses and fulfil rolls in the TPS supply chain.
We work closely with local communities by contributing to improve their health, education and welfare. During the height of the COVID-19 pandemic, we donated oxygen tanks to a local hospital in the Sfax area in order to support the local healthcare system.
We aim to enhance our visibility in Equatorial Guinea through appropriate CSR projects and more frequent participation in technical and operating committee meetings. We have made investments into an in-country manager who we have tasked with building our presence. Our CSR strategy focuses on building a well governed, well defined in-country engagement programme to support our objectives and those of local communities and host governments.
The Corporate Social Responsibility Programme dates to August 2000, with funds originating under the Block G Production Sharing Agreement (PSC) provision. Today, the programme has reached over 500,000 people from vulnerable communities, primarily located in the interior of the mainland.
In partnership with Trident, Kosmos Energy, the Ministry of Mines and Hydrocarbons (MMH) and GEPetrol, \$2.5m has been invested to support local projects in the region, focusing on sustainable long-term initiatives and visible benefits to local people.
The commitment toward Equatorial Guinea communities is ongoing and has been recognised by the Equatorial Guinea government, partners, and members of the communities.
In 2021, given the impact of the COVID-19 pandemic and the Bata explosions devastation, the USD 650,000 initial budget was exceeded for the following initiatives: water access for remote communities; Infosalud health-orientated programme; support for a school for deaf children in Bata; construction of a community meeting room; construction of bridges in Handje community; support to MMH 100-day fisherman project; and TEGI actions in support of the Bata explosions and COVID-19 response.
The outlook for our industry has changed dramatically in the past year. Despite these changes, Panoro has transformed in this period and is now well established as a diversified, full cycle oil company with a committed Board of Directors, balance sheet strength, and its strategy will ensure that the Company is well placed once macro conditions improve.
The Board wishes to thank the staff and shareholders for their continued commitment to the Company.
| JULIEN BALKANY |
TORSTEIN SANNESS |
GARRETT SODEN |
|---|---|---|
| Chairman of the Board | Deputy Chairman of the Board | Non-Executive Director |
| ALEXANDRA HERGER | HILDE ÅDLAND |
JOHN HAMILTON |
| Non-Executive Director | Non-Executive Director | Chief Executive Officer |
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:
1P – Proved reserves represent volumes that will be recovered with 90% 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:
Contingent Resources are reported as 1C, 2C, and 3C, reflecting similar probabilities as reserves.
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) for Dussafu, by Gaffney Cline & Associates Limited (GaffneyCline) for the TPS assets and by TRACS International for Block G.
The Panoro portfolio reported here for year end 2021 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. The Aje field is held for sale and is not included in
this report. A summary description of these assets with status as of year-end 2021 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 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 2021 amounted to 10.9 MMbbls gross.
In March 2022 TRACS certified (3rd party) reserves and resources for the Block G licence. As of the end of December 2021, the Block G licence contained gross 1P Proved Reserves of 54.6 MMbbls in the Ceiba and Okume Complex fields. Gross 2P Proved plus Probable Reserves amounted to 92.5 MMbbls in the same fields. Gross 3P Proved plus Probable plus Possible Reserves in these fields amounted to 124.1 MMbbls.
In addition to these Reserves TRACS also certified gross unrisked 1C Contingent Resources of 39 MMbbls, gross unrisked 2C Contingent Resources of 146.4 MMbbls, and gross unrisked 3C Contingent Resources of 311.8 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 7.78 MMbbls, 2P Proved plus Probable Reserves of 13.18 MMbbls and 3P Proved plus Probable plus Possible Reserves of 17.68 MMbbls. Additional unrisked Contingent Resources net to Panoro's working interest of 14.25% are 5.56 MMbbls 1C, 20.86 MMbbls 2C and 44.43 MMbbls 3C. These Reserves and Contingent Resources are Panoro's net working interest volumes before deductions for royalties and other taxes.
DUSSAFU: Offshore Gabon Operator: BW Energy, Panoro 17.4997%
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, Hibiscus and Ruche North East is scheduled to start oil production by the end of 2022.
Production from the Tortue field during 2021 amounted to 4.1 MMbbls gross.
In March 2022 NSAI certified (3rd party) reserves and resources for the Dussafu licence. As of the end of December 2021, the Dussafu licence contained gross 1P Proved Reserves of 71.5 MMbbls in the Tortue, Ruche, Ruche North East and Hibiscus fields. Gross 2P Proved plus Probable Reserves amounted to 99.7 MMbbls in the same fields. Gross 3P Proved plus Probable plus Possible Reserves in these fields amounted to 131.3 MMbbls.
In addition to these Reserves NSAI also certified gross unrisked 1C Contingent Resources of 16.6 MMbbls, gross 2C Contingent Resources of 38.7 MMbbls, and gross 3C Contingent Resources of 66.8 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 12.51 MMbbls, 2P Proved plus Probable Reserves of 17.44 MMbbls and 3P Proved plus Probable plus Possible Reserves of 22.97 MMbbls. Additional unrisked Contingent Resources net to Panoro's working interest of 17.5% are approximately 2.9 MMbbls 1C, 6.8 MMbbls 2C and 11.7 MMbbls 3C. These Reserves and Contingent Resources are Panoro's net working interest volumes before deductions for royalties and other taxes.
The TPS Assets comprise five oil field concessions in the region of the city of Sfax, onshore and shallow water offshore Tunisia.se in 2021.
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 57 million barrels of oil to date. The current production is stable at around 4,700 barrels of oil per day gross.
Production from the TPS assets amounted to 1.66 MMbbls gross, which is approximately 0.49 MMbbls net to Panoro's working interest share.
In March 2022 GaffneyCline assessed reserves and resources from the fields as of end December 2021. Gross field reserves amount to 1P Proved Reserves of 10.9 MMbbls, 2P Proved plus Probable Reserves of 17.7 MMbbls and 3P Proved plus Probable plus Possible Reserves of 23.1 MMbbls. Panoro's net working interest 1P Proved reserves are 3.22 MMbbls, 2P Proved plus Probable are 5.20 MMbbls and 3P Proved plus Probable plus Possible are 6.79 MMbbls.
In addition to these reserves, GaffneyCline also assessed gross 1C Contingent Resources of 1.6 MMbbls, 2C Contingent Resources of 5.3 MMbbls and 3C Contingent Resources of 10.0 MMbbls, all assigned to the Cercina oil field. Panoro's net working interest 1C Contingent Resource is 0.5 MMbbls, net working interest 2C Contingent Resource is 1.6 MMbbls and net working interest 3C Contingent Resource is 2.9 MMbbls. These Reserves and Contingent Resources are Panoro's net volumes before deductions for royalties and other taxes.
Panoro uses the services of NSAI, TRACS and GaffneyCline 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 2021 ASR:
Block G: In 2021, Panoro acquired a 14.25% interest in the Block G license. Two infill wells were drilled and brought on stream in 2021 and a third infill well is expected to come online in 2022. In 2023 it is expected that a further 3 infill wells will be drilled in the Okume complex. The TRACS reserves report takes these field development plans into account.
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 extended.
Dussafu: In 2021 Panoro acquired an additional 10% interest in the Dussafu license. The final 2 production wells at the Tortue field were brought online in 2021, to bring the total well count to 6. Lack of available gas lift capacity at the field meant that production in 2021 was mainly from 4 wells. This is being addressed in 2022 with additional gas lift capacity being installed. The next development phase, consisting of the development of the Ruche and Hibiscus fields, has commenced and is expected to start production by year end 2022. The NSAI reserves report takes these field development plans into account and assumes production from a total of 6 development wells in Tortue, and from a total of 12 wells in Hibiscus/Ruche phase 1 and phase 2.
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 2021 well performance and potential identified for additional drilling at the Rhemoura field. There are Contingent Resources associated with the Cercina field in the TPS assets. These resources may be re-assigned as reserves if a development decision is taken to drill certain un-drilled compartments within the Cercina field.
The commerciality and economic tests for the Dussafu reserves volumes were based on an average oil price over the field life of USD73/Bbl.
The commerciality and economic tests for the TPS assets reserves volumes were based on an average oil price over the life of the field of USD76/Bbl.
The commerciality and economic tests for the Block G assets reserves volumes were based on an average oil price over the life of the field of USD73/Bbl.
| 2P Reserves Development | (MMBOE) |
|---|---|
| Balance (previous ASR –31 December 2020) | 12.3 |
| Production 2021 | (2.8) |
| Acquisitions/disposals since previous ASR | 23.9 |
| New developments since previous ASR | 2.4 |
| Balance (revised ASR) as of 31 December 2021 | 35.8 |
Panoro's total 1P working interest reserves at end of 2021 amount to 23.50 MMbbls. Panoro's 2P reserves amount to 35.82 MMbbls and Panoro's 3P reserves amount to 47.45 MMbbls.
Panoro's Contingent Resource base includes discoveries of varying degrees of maturity towards development decisions. By the end of 2021, Panoro's assets contained a total un-risked 2C working interest volume of approximately 29.3 MMbbls.
28 April 2022
John Hamilton CEO
AS OF 31 DECEMBER 2021
| 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 | 19.17 | - | 19.17 | 3.35 | 26.78 | - | 26.78 | 4.69 | 36.60 | - | 36.60 | 6.41 |
| TPS | 29.40 | 8.74 | - | 8.74 | 2.57 | 14.25 | - | 14.25 | 4.19 | 18.45 | - | 18.45 | 5.42 |
| Block G | 14.25 | 41.02 | - | 41.02 | 5.85 | 67.16 | - | 67.16 | 9.57 | 89.62 | - | 89.62 | 12.77 |
| Total | 68.92 | - | 68.92 | 11.77 | 108.19 | - | 108.19 | 18.45 | 144.67 | - | 144.67 | 24.60 | |
| APPROVED FOR DEVELOPMENT | |||||||||||||
| Dussafu | 17.50 | 52.30 | - | 52.30 | 9.15 | 72.87 | - | 72.87 | 12.75 | 94.68 | - | 94.68 | 16.57 |
| Block G | 14.25 | 5.40 | - | 5.40 | 0.77 | 12.67 | - | 12.67 | 1.80 | 19.19 | - | 19.19 | 2.73 |
| Total | 57.69 | - | 57.69 | 9.92 | 85.54 | - | 85.54 | 14.56 | 113.87 | - | 113.87 | 19.30 | |
| JUSTIFIED FOR DEVELOPMENT | |||||||||||||
| TPS | 29.40 | 2.21 | - | 2.21 | 0.65 | 3.43 | - | 3.43 | 1.01 | 4.66 | - | 4.66 | 1.37 |
| Block G | 14.25 | 8.16 | - | 8.16 | 1.16 | 12.70 | - | 12.70 | 1.81 | 15.26 | - | 15.26 | 2.17 |
| Total | 10.37 | - | 10.37 | 1.81 | 16.12 | - | 16.13 | 2.82 | 19.92 | - | 19.92 | 3.54 |
| Total Reserves |
136.99 | - | 136.99 | 23.50 | 209.86 | - | 209.86 | 35.82 | 278.46 | - | 278.46 | 47.45 |
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Small rounding differences may arise due to rounding to the nearest MMBOE. |
| 2P Reserves Development | (MMBOE) |
|---|---|
| Balance (previous ASR – 31 December 2020) | 12.3 |
| Production 20201 | (2.8) |
| Acquisitions/disposals since previous ASR2 | 23.9 |
| New developments since previous ASR3 | 2.4 |
| Balance (revised ASR) as of 31 December 2021 | 35.8 |
Represents TPS, Dussafu and Block G production in 2021 on a pro-forma basis
Acquisition of Block G and 10% of Dussafu as of end 2020
Additional projects in TPS and Block G
| Asset | 2C MMBOE (as of YE 2020) | 2C MMBOE (as of this report) |
|---|---|---|
| Dussafu | 2.7 | 6.8 |
| TPS | 1.6 | 1.6 |
| Block G | - | 20.9 |
| Totals | 4.3 | 29.3 |
Chairman of the Board
Mr. Balkany is a French citizen and a resident in London, who since 2014 has been Chairman of the Norwegian oil & gas exploration and production company Panoro Energy ASA. 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
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).
Non-Executive Director
Non-Executive Director
Non-Executive Director
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. 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.
Mr. Garrett Soden has worked with the Lundin Group for more than a decade 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.
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, and field operations. Ms. Ådland is currently Maintenance & Logistics Manager 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.
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 an 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 (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, 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, 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.
FOR THE YEAR ENDED 31 DECEMBER
| Amounts in USD 000, unless otherwise stated | Note | 2021 | 2020 |
|---|---|---|---|
| CONTINUING OPERATIONS | |||
| Oil revenue | 3 | 113,708 | 24,167 |
| Other revenue | 3 | 5,949 | 2,689 |
| Total revenues | 119,657 | 26,856 | |
| Operating expenses | |||
| Operating costs | (41,022) | (14,742) | |
| Exploration related costs and operator G&A | 4 | (6,438) | (272) |
| General and administrative costs | 4 | (7,242) | (5,075) |
| Depreciation, depletion and amortisation | 8, 9 | (27,550) | (6,963) |
| Acquisition and project related costs | 4 | (1,254) | (725) |
| Share based payments | 17 | (1,231) | (897) |
| Total operating expenses | (84,737) | (28,674) | |
| Operating profit / (loss) | 34,920 | (1,818) | |
| Gain on acquisition of business | 12 | 46,121 | - |
| Net foreign exchange gain / (loss) | 411 | (366) | |
| Unrealised gain/(loss) on commodity hedges | 5 | (3,868) | 2,460 |
| Realised gain/(loss) on commodity hedges | 5 | (4,354) | 4,522 |
| (Loss)/gain on disposal | 8 | - | - |
| Interest income | 5 | 77 | 59 |
| Interest costs | 5 | (7,049) | (1,696) |
| Other financial costs | 5 | (2,867) | (853) |
| Profit / (loss) before income taxes | 63,391 | 2,308 | |
| Income tax expense | 6 | (21,079) | (4,503) |
| Net profit/(loss) from continuing operations | 42,312 | (2,195) | |
| Net income/(loss) from discontinued operations | 13 | 7,011 | (3,138) |
| Net profit/(loss) for the year | 49,323 | (5,333) | |
| Exchange differences arising from translation of foreign operations | - | - | |
| Other comprehensive income/(loss) for the year (net of tax) | - | - | |
| Total comprehensive income/(loss) | 49,323 | (5,333) | |
| NET INCOME /(LOSS) FOR THE PERIOD ATTRIBUTABLE TO: | |||
| Equity holders of the parent | 49,323 | (5,333) | |
| TOTAL COMPREHENSIVE INCOME / (LOSS) FOR THE PERIOD ATTRIBUTABLE TO: |
|||
| Equity holders of the parent | 49,323 | (5,333) | |
| EARNINGS PER SHARE | |||
| Basic EPS on profit/(loss) for the period attributable to equity holders of the parent (USD) - Total |
7 | 0.47 | (0.08) |
| Diluted EPS on profit/(loss) for the period attributable to equity holders of the parent (USD) - Total |
7 | 0.46 | (0.08) |
| Basic and diluted EPS on profit/(loss) for the period attributable to equity holders of the parent (USD) - Continuing operations |
7 | 0.40 | (0.03) |
AS AT 31 DECEMBER
| USD 000 | Note | 2021 | 2020 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Production rights | 8 | 188,832 | 26,475 |
| Licenses and exploration assets | 8 | 51,752 | 21,070 |
| Fair value of derivative financial instruments | 18 | - | - |
| Investment in associates and joint ventures | 26 | 26 | |
| Goodwill | 12 | 47,762 | - |
| Production assets and equipment | 9 | 120,269 | 32,303 |
| Development assets | 8 | 46,361 | 14,522 |
| Property, furniture, fixtures and office equipment | 9 | 550 | 640 |
| Other non-current assets | 135 | 135 | |
| Total Non-current assets | 455,687 | 95,171 | |
| Current assets | |||
| Crude Oil Inventory | 4,284 | 1,666 | |
| Materials Inventory | 15,520 | 4,254 | |
| Trade and other receivables | 10 | 55,629 | 10,857 |
| Fair value of derivative financial instruments - current portion | 18 | - | 1,380 |
| Cash and cash equivalents | 11 | 24,532 | 5,674 |
| Cash held for Bank guarantee | 11 | - | 9,960 |
| Total current assets | 99,965 | 33,791 | |
| Assets classified as held for sale | 13 | 29,015 | 20,445 |
| Total Assets | 584,667 | 149,407 |
| USD 000 | Note | 2021 | 2020 |
|---|---|---|---|
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Share capital | 15 | 721 | 459 |
| Share premium | 15 | 427,496 | 349,446 |
| Treasury Shares | - | - | |
| Additional paid-in capital | 122,324 | 122,465 | |
| Total paid-in equity | 550,541 | 472,370 | |
| Other reserves | 15 | (43,408) | (43,408) |
| Retained earnings | (311,694) | (361,017) | |
| Total equity attributable to shareholders of the parent | 195,439 | 67,945 | |
| Non-current liabilities | |||
| Decommissioning liability | 14 | 140,839 | 21,464 |
| Secured Loans | 5 | 77,689 | 9,660 |
| Non-Recourse Loan | 5 | - | 3,078 |
| Licence Obligations | 4,726 | 4,726 | |
| Other non-current liabilities | 16 | 8,302 | 2,172 |
| Deferred tax liabilities | 6 | 74,109 | 3,217 |
| Total Non-current liabilities | 305,665 | 44,317 | |
| Accounts payable, accruals and other liabilities | 16 | 12,707 | 6,020 |
| Secured Loans - current portion | 5 | 14,714 | 4,322 |
| Non-Recourse Loan - current portion | 5 | 4,507 | 4,133 |
| Licence Obligations - current portion | 1,166 | 1,166 | |
| Fair value of derivative financial instruments - current portion | 18 | 2,489 | - |
| Other current liabilities | 16 | 10,623 | 1,291 |
| Corporation tax liability | 6 | 17,018 | 1,302 |
| Total current liabilities | 63,224 | 18,234 | |
| Liabilities directly associated with assets classified as held for sale | 13 | 20,339 | 18,911 |
| Total Equity and Liabilities | 584,667 | 149,407 |
| 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 |
| 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 2020 | 458 | 349,193 | 122,131 | (355,684) | (37,647) | (5,761) | 72,690 |
| Net income/(loss) for the period - continuing operations |
- | - | - | (2,195) | - | - | (2,195) |
| Net income/(loss) for the period - discontinued operations |
- | - | - | (3,138) | - | - | (3,138) |
| Total comprehensive income/(loss) |
- | - | - | (5,333) | - | - | (5,333) |
| Share issue under RSU plan | 1 | 253 | - | - | - | - | 254 |
| Employee share options charge/(benefit) |
- | - | 897 | - | - | - | 897 |
| Settlement of RSUs | - | - | (563) | - | - | - | (563) |
| At 31 December 2020 | 459 | 349,446 | 122,465 | (361,017) | (37,647) | (5,761) | 67,945 |
FOR THE YEAR ENDED 31 DECEMBER
| USD 000 | Note | 2021 | 2020 |
|---|---|---|---|
| CASH FLOW FROM OPERATING ACTIVITIES | |||
| Net (loss)/income for the period before tax - continuing operations | 63,391 | 2,308 | |
| Net (loss)/income for the period before tax - discontinued operations | 7,011 | (3,138) | |
| Net (loss)/income for the period before tax | 70,402 | (830) | |
| ADJUSTED FOR: | |||
| Depreciation | 4 | 27,550 | 6,963 |
| Exploration related costs and Operator G&A | 12,801 | 272 | |
| Impairment and asset write-off/(impairment reversal) | 9.2 | (8,000) | - |
| Loss/(gain) on commodity hedges | 18 | 8,222 | (6,982) |
| Gain on acquisition of business | 12 | (46,121) | - |
| Net finance costs | 9,839 | 2,490 | |
| Share-based payments | 17 | 1,231 | 897 |
| Foreign exchange loss/(gain) | (6) | (130) | |
| Increase/(decrease) in trade and other payables | (7,208) | 4,616 | |
| (Increase)/decrease in trade and other receivables | 18,111 | 460 | |
| (Increase)/decrease in inventories | 6,190 | (307) | |
| State share of profit oil | 3 | (5,949) | (2,689) |
| Taxes paid | (16,664) | (4,310) | |
| Net cash (out)/inflow from operations | 70,398 | 450 | |
| CASH FLOW FROM INVESTING ACTIVITIES | |||
| Cash outflow related to acquisition(s) | (140,477) | - | |
| Interest income | 77 | 59 | |
| Investment in exploration, production and other assets | (55,736) | (13,852) | |
| Net cash (out)/inflow from investing activities | (196,136) | (13,793) | |
| CASH FLOW FROM FINANCING ACTIVITIES | |||
| Gross proceeds from loans and borrowings | 5 | 90,000 | - |
| Repayment of non-recourse loan | (3,106) | (1,408) | |
| Repayment of Secured Loans | (13,384) | (2,880) | |
| Realised gain/(loss) on commodity hedges | 18 | (4,354) | 4,522 |
| Borrowing costs, including arrangement fees | (5,450) | (1,207) | |
| Gross proceeds from Share issues | 15 | 81,240 | - |
| Cost of Share issues | (3,043) | - | |
| Cash cost of equity issue on settlement of RSUs | (694) | (310) | |
| Lease liability payments | 21 | (254) | (191) |
| Financial charges | 40 | - | |
| Cash held for Bank Guarantee | 11 | 3,597 | - |
| Net cash (out)/inflow from financing activities | 144,592 | (1,474) | |
| Change in cash and cash equivalents during the period | 18,854 | (14,817) | |
| Cash and cash equivalents – assets held for sale | 13 | 4 | (2) |
| Cash and cash equivalents at the beginning of the period | 5,674 | 20,493 | |
| Cash and cash equivalents at the end of the period | 24,532 | 5,674 |
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 Advokatfirma Schjødt, Ruseløkkveien 14, P.O. box 1444 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 and West Africa. The consolidated financial statements of the Group for the year ended 31 December 2021 were authorised for issue by the Board of Directors on 28 April 2022.
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 2021, the Group had USD 24.5 million in cash and bank balances and debt of USD 96.8 million resulting in a net debt position of approximately USD 72 million. Receivables from December 2021 liftings of USD 39.8 million were received post year-end. In addition to Block G and Dussafu capital expenditure, the Company is committed to a drilling obligation of one well on Block 2B in South Africa. 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.
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.
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.
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:
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.
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:
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 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 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.
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 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.
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.
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.
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:
While the social and economic strain created by the COVID-19 pandemic eased due to the efficacy of vaccines and increasing vaccination rates and the resulting loosening of pandemic related restrictions, uncertainty related to operations and financial position of the Group is still subject to uncertainty
While oil prices increased due to crude oil demand increasing faster than supply which placed upwards pressure on prices, they remain volatile which makes key assumptions applied in the valuation of the Group's assets and measurement of its liabilities difficult.
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.
On 21 October 2019, the Company entered into a sale and purchase agreement with PetroNor E&P Limited to divest all outstanding shares in its fully owned subsidiaries Pan-Petroleum Services Holding BV and Pan-Petroleum Nigeria Holding BV (together, the "Divested Subsidiaries") which met the criteria and was classified as held for sale at that date.
Final governmental approvals, the final key condition precedent for the completion of the transaction, was received on 27 January 2022. It is expected that the transactions will complete during the second quarter 2022. As a result, the operations of the Group's Divested Subsidiaries have been classified as discontinued operations under IFRS 5 in 2019, 2020 and 2021.
For more details on the discontinued operation, refer to Note 13: Discontinued Operations and assets held for sale.
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.
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:
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.
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.
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
| 2021 | 2020 | ||||
|---|---|---|---|---|---|
| Average rate | Reporting date rate | Average rate | Reporting date rate | ||
| Norwegian Kroner / USD | 8.6002 | 8.8245 | 9.4201 | 8.5189 | |
| USD / British Pound Sterling | 1.3755 | 1.3477 | 1.2836 | 1.3649 | |
| USD / Tunisian Dinar | 2.7963 | 2.8865 | 2.8220 | 2.7047 |
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 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 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.
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:
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.
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.
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 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 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, other than those designated as effective hedging instruments, are included in this category.
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 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.
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.
The measurement of financial liabilities depends on their classification as follows:
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.
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.
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:
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:
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.
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.
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.
Income tax expense represents the sum of the tax currently payable and movement in deferred 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 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:
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:
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.
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.
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.
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 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.
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.
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.
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% |
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.
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.
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).
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.
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.
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.
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:
All other assets are classified as non-current.
The Group classifies all other liabilities as non-current. Deferred tax assets and liabilities are classified as non-current assets and liabilities.
No standard amendments or interpretations of standards effective as of 1 January 2021 and adopted by Panoro, were material to the Group's Consolidated financial statements upon adoption.
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.
The Group operated predominantly in three business segments being the exploration and production of oil and gas in Equatorial Guinea, Gabon and Tunisia.
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:
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.
2021
| Aje-OML | |||||||
|---|---|---|---|---|---|---|---|
| Total - | 113 | ||||||
| Equatorial | continuing | discontinued | |||||
| USD 000 | Guinea | Gabon | Tunisia | Corporate | operations | operations | Total |
| Revenue (net) * | 51,563 | 41,734 | 26,360 | - | 119,657 | 3,688 | 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 | 336,155 | 298 | 348,453 |
| Aje-OML | |||||||
|---|---|---|---|---|---|---|---|
| Total - | 113 | ||||||
| Equatorial | continuing | discontinued | |||||
| USD 000 | Guinea | Gabon | Tunisia | Corporate | operations | operations | Total |
| Revenue (net) * | - | 14,094 | 12,762 | - | 26,856 | 2,307 | 29,163 |
| EBITDA | - | 6,905 | 3,982 | (4,845) | 6,042 | (2,670) | 3,372 |
| Depreciation | - | (2,856) | (4,025) | (82) | (6,963) | - | (6,963) |
| Impairment (charge)/reversal | - | - | - | - | - | - | - |
| Profit/(loss) before tax | - | 3,447 | 4,679 | (5,818) | 2,308 | (3,138) | (830) |
| Net Profit/(loss) | - | 758 | 2,864 | (5,817) | (2,195) | (3,138) | (5,333) |
| Segment assets ** | - | 50,513 | 75,031 | 3,418 | 128,962 | 20,445 | 149,407 |
| Additions to licences, production, E&E and development assets |
- | 8,861 | 6,841 | - | 15,702 | - | 15,702 |
* Revenue excludes any intercompany revenue.
** Refer to Note 13: Discontinued Operations and assets held for sale for segment assets related to discontinued operations (OML 113, Aje).
*** Includes additions from acquisitions, see Note 12: Business Combinations, but excludes reversal of impairment of USD 8 million.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Oil revenue (net) | 113,708 | 24,167 |
| Other revenue | 5,949 | 2,689 |
| Total revenue | 119,657 | 26,856 |
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 in 2021 relates to sale of hydrocarbons from three assets, Block G in Gabon, Dussafu in Gabon and TPS in Tunisia (2020: Dussafu and TPS). 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 2021 were to a single customer, Mercuria Energy Trading SA, through a crude marketing agreement. All sales in 2021 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. There are no other items included in other revenue for both periods presented.
| USD 000 | Note | 2021 | 2020 |
|---|---|---|---|
| Employee benefits expense | 4,166 | 3,659 | |
| Depreciation | 8, 9 | 27,550 | 6,963 |
| Impairment and asset write-off/(reversal) | 9 | - | - |
| Acquisition and project related costs (i) | 1,254 | 725 |
(i) Acquisition and project related costs in 2021 of USD 1.1 million relate to costs incurred on the Equatorial Guinea and Dussafu acquisitions as described in Note 12: Business Combinations (2020: USD 0.6 million). The remaining USD 0.1 million (2020: USD 0.1 million) relate to business development and organisational restructure and integration activities in Tunisia.
A historical non-fulfilment of a work programme related to Sfax Offshore Exploration Permit by a previous operator was settled during the year 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 period was renewed for a year.
General and administrative expenses include wages, employer's contribution and other compensation as detailed below:
| USD 000 | 2021 | 2020 |
|---|---|---|
| Salaries | 3,423 | 3,058 |
| Employers' contribution | 555 | 400 |
| Pension costs | 118 | 114 |
| Other compensation | 70 | 87 |
| Total | 4,166 | 3,659 |
| 2021 | 2020 | |
|---|---|---|
| Number of employees | 29 | 25 |
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.
In accordance with the Norwegian Public Limited Liability Companies Act §6-16a, the Board of Directors must prepare a statement on remuneration of executives. Theses statements can be referred to on page 111 of this report.
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:
| 2021 | Short term benefits | ||||||
|---|---|---|---|---|---|---|---|
| Number of | |||||||
| RSUs | Fair value | ||||||
| Pension | awarded | of RSUs | |||||
| USD 000 (unless stated otherwise) | Salary | Bonus | Benefits | costs | Total | in 2021 | 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 |
2020 Short term benefits
| Number of | |||||||
|---|---|---|---|---|---|---|---|
| RSUs | Fair value | ||||||
| Pension | awarded | of RSUs | |||||
| USD 000 (unless stated otherwise) | Salary | Bonus | Benefits | costs | Total | in 2020 | expensed |
| John Hamilton, CEO | 454 | 182 | 11 | 13 | 660 | 324,358 | 428 |
| Qazi Qadeer, CFO | 289 | 102 | 5 | 13 | 409 | 104,215 | 139 |
| Other Named Executives (vi) | 570 | 205 | 9 | 14 | 798 | 208,430 | 243 |
| Total | 1,313 | 489 | 25 | 40 | 1,867 | 637,003 | 810 |
(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.
Refer to Note 17: Share based payments for further information on the Restricted Share Units scheme.
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.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Julien Balkany (Chairman of the Board of Directors) | 82 | 66 |
| Torstein Sanness (Deputy Chairman of the Board of Directors) | 57 | 47 |
| Alexandra Herger | 48 | 40 |
| Garrett Soden | 50 | 40 |
| Hilde Ådland | 48 | 40 |
| Total | 285 | 233 |
The Chairman of the Board of Directors' annual remuneration is NOK 460,000 and the annual remuneration for the Deputy Chairman of the Board is NOK 300,000. The remaining Directors' annual remuneration is NOK 250,000. All Board Members also form the Audit Committee and Remuneration Committee for which they each receive NOK 50,000 annually per committee. 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.
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 2021, the Company had no employees at parent company level and this pension plan is no longer in operation (31 December 2020: 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 2021 and 2020, refer to Note 4.2: Employee benefit expenses.
Fees, excluding VAT, to the auditors are included in general and administrative expense and are shown below:
| USD 000 | 2021 | 2020 |
|---|---|---|
| Ernst & Young | ||
| Statutory Audit | 280 | 175 |
| Total Audit Services | 280 | 175 |
| Non-audit Services | ||
| Corporate financial services including pre-acquisition due diligence | - | - |
| Total non-audit services | - | - |
| Total | 280 | 175 |
| USD 000 | 2021 | 2020 |
|---|---|---|
| Unrealised (gain) / loss on commodity hedges (Note 18) | 3,868 | (2,460) |
| Realised (gain) / loss on commodity hedges (Note 18) | 4,354 | (4,522) |
| Interest income from placements and deposits | (77) | (59) |
| Interest expense - Loans and borrowings | 6,895 | 1,691 |
| Interest expense - Bank guarantee | 199 | 220 |
| Other financial costs - Bank charges and ARO unwinding | 2,822 | 638 |
| Total - Net (income) / expense | 18,061 | (4,492) |
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 2021 (31 December 2020: 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:
The Group was not in breach of any financial covenants as at 31 December 2021. Waivers obtained from the lender with respect to forward looking FLCR and DSCR covenants were in place at 31 December 2020 to cover the quarter ending on that date. Un-amortised borrowing costs include structuring fees and directly attributable third-party costs. These costs are expensed using an effective interest rate of 6.95% per annum over the term of the remaining term of the facility (effective interest rate 31 December 2020: 6.95%).
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).
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 2021 | 31 December 2020 | ||||
|---|---|---|---|---|---|---|
| Current | Non current |
Total | Current | Non current |
Total | |
| Mercuria Senior Secured loan facility | ||||||
| Principal outstanding | 4,950 | 5,820 | 10,770 | 4,200 | 9,900 | 14,100 |
| Accumulated interest accrued | 169 | - | 169 | 224 | - | 224 |
| Unamortised borrowing costs | (103) | (63) | (166) | (102) | (240) | (342) |
| 5,016 | 5,757 | 10,773 | 4,322 | 9,660 | 13,982 |
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 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:
The Group was not in breach of any financial covenants as at 31 December 2021. 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 9.46% per annum over the remaining term of the facility.
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 2021 | 31 December 2020 | ||||
|---|---|---|---|---|---|---|
| Current | Non current |
Total | Current | Non-current | Total | |
| Trafigura Secured Borrowing Base facility | ||||||
| Principal outstanding | 10,800 | 73,800 | 84,600 | - | - | - |
| Accumulated interest accrued | - | - | - | - | - | - |
| Unamortised borrowing costs | (1,102) | (1,868) | (2,970) | - | - | - |
| 9,698 | 71,932 | 81,630 | - | - | - |
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 2021 | 31 December 2020 | ||||
|---|---|---|---|---|---|---|
| Current | Non-current | Total | Current | Non Current |
Total | |
| BW Energy Non-Recourse loan | ||||||
| Principal outstanding | 2,234 | - | 2,234 | 2,262 | 3,078 | 5,340 |
| Accumulated interest accrued | 2,273 | - | 2,273 | 1,871 | - | 1,871 |
| 4,507 | - | 4,507 | 4,133 | 3,078 | 7,211 |
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 changes in liabilities whose cash flow movements are disclosed as part of financing activities in the cash flow statement are as follows:
| USD 000 | 2021 | 2020 |
|---|---|---|
| At 1 January | 20,392 | 25,858 |
| Cash flows: | ||
| Drawdown of Secured Loans, net of fees | 90,000 | - |
| Repayment of Secured Loans | (13,638) | (2,880) |
| Repayment of non-recourse loan | (3,106) | (510) |
| Realised gain/(loss) on commodity hedges | (2,668) | 4,522 |
| Borrowing costs, including arrangement fees | (4,689) | (1,207) |
| Lease liability payments | (254) | (191) |
| Non cash changes: | ||
| Unwinding of unamortised borrowing cost and finance charges | 1,123 | 156 |
| Interest accrued | 5,812 | 1,590 |
| Movement in unrealised hedges | 6,536 | (6,982) |
| Initial recognition lease under IFRS 16 | - | - |
| Foreign exchange movements | (6) | 35 |
| At 31 December | 99,502 | 20,392 |
The major components of income tax in the consolidated statement of comprehensive income related to continuing and discontinued operations were:
| USD 000 | 2021 | 2020 |
|---|---|---|
| Income Taxes | ||
| Current income tax (i) | 6,541 | 622 |
| PSC based Profit Oil allocation – current (ii) | 5,949 | 2,689 |
| PSC based income tax - current (iii) | 10,417 | |
| Deferred tax expense / (benefit) (iv) | (1,838) | 1,192 |
| Tax relating to prior years income | 10 | - |
| Tax charge / (benefit) for the period | 21,079 | 4,503 |
(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 | 2021 | 2020 |
|---|---|---|
| Profit/ (loss) before taxation – continuing operations | 63,391 | 2,308 |
| Profit / (loss) before taxation – discontinued operations | 7,011 | (3,138) |
| Profit / (loss) before taxation - total | 70,402 | (830) |
| Tax/ (tax loss) calculated at domestic tax rates applicable to profits in the respective countries |
29,901 | (1,517) |
| Expenses not deductible | (23,843) | 4,829 |
| Expenses deductible for tax | (669) | - |
| Deferred tax arising on taxable temporary differences | 313 | 1,192 |
| PSC based Profit Oil allocation | 16,366 | 2,689 |
| Tax effect of prior years' losses utilised in the period | (2,151) | - |
| Tax effect of losses not utilised in the period | 1,152 | (2,690) |
| Prior year adjustment | 10 | - |
| Tax charge / (benefit) | 21,079 | 4,503 |
Tax liabilities payable of USD 17 million as of 31 December 2021 comprised of taxes payable in Equatorial Guinea of USD 12.3 million and Tunisia of USD 4.7 million for production from various concessions (31 December 2020: USD 1.3 million relating to Tunisia). Advantage was taken in Tunisia of a incentives with a tax value of USD 5.5 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 benefit of USD 1.8 million recognised during the year comprises of USD 2.2 million benefit in Equatorial Guinea related offset by USD 0.4 million 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 74.1 million as of 31 December 2021 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 2021 (31 December 2020: 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 6.7 million (2020: USD 5.6 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 | 2021 | 2020 |
|---|---|---|
| Panoro Energy ASA | 21,591 | 26,835 |
| Panoro Energy Limited | 486 | 770 |
| Sfax Petroleum Corporation (at 60%) | 8,802 | 4,387 |
| Total | 30,879 | 31,992 |
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 | 2021 | 2020 |
|---|---|---|
| Net profit/(loss) attributable to equity holders - Total | 49,323 | (5,333) |
| Net profit/(loss) attributable to equity holders - Continuing operations | 42,312 | (2,195) |
| Weighted average number of shares outstanding - in thousands | 105,452 | 68,912 |
| Diluted weighted average number of shares outstanding - in thousands | 106,611 | 68,912 |
| Basic earnings/(loss) per share (USD) - Total | 0.47 | (0.08) |
| Diluted earnings/(loss) per share (USD) - Total | 0.46 | (0.08) |
| Basic earnings/(loss) per share (USD) - Continuing operations | 0.40 | (0.03) |
| Diluted earnings/(loss) per share (USD) - Continuing operations | 0.40 | (0.03) |
| 2021 | ||
|---|---|---|
| USD 000 Historical cost |
Licenses and exploration assets |
Development assets |
| 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 |
| Net carrying value at 31 December 2021 | 51,752 | 46,361 |
| USD 000 Historical cost |
Licences, exploration and evaluation assets |
Development assets |
|---|---|---|
| At 1 January 2020 | 19,760 | 5,915 |
| Additions | 1,310 | 8,607 |
| Net carrying value at 31 December 2020 | 21,070 | 14,522 |
| Licence area | Panoro's interest | Country | Expiry of current phase |
|---|---|---|---|
| OML 113 | 6.502% participating interest, 12.1913% entitlement to revenue stream and 16.255% paying interest (Held for Sale) |
Nigeria | August 2038 |
| Dussafu Marin permit | 17.4997% | Gabon | September 2028* |
| Sfax Offshore Exploration Permit** |
52.5% (Operator) – excluding Beender's 40% |
Tunisia | December 2022 |
| Hammamet Offshore Exploration Permit |
27.6% - excluding Beender's 40% | Tunisia | Under relinquishment |
| 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 | 2021 | 2020 |
| Acquisition cost | ||
| At 1 January | 26,475 | 28,876 |
| Depreciation charge for the year | (14,319) | (2,401) |
| Additions through Acquisition | 172,676 | |
| Other additions | 4,000 | - |
| At 31 December | 188,832 | 26,475 |
| Note 8.3: Goodwill | ||
|---|---|---|
| USD 000 | 2021 | 2020 |
| Acquisition cost | ||
| At 1 January | - | - |
| Additions through Acquisition | 47,762 | - |
| At 31 December | 47,762 | - |
The Group acquired a 14.25% working interest in Block G, Equatorial Guinea during the year, assets and liabilities were taken on at fair value and Goodwill of USD 47.8 million recognised as described in Note 12: Business Combinations.
An annual impairment assessment was carried out in December 2021 at which time the total carrying value of Block G at 31 December 2021 was USD 106.7 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 70/bbl, 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 TRACS 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 9.1: Production Assets and Equipment | ||
|---|---|---|
| USD 000 | 2021 | 2020 |
| Historical cost | ||
| At 1 January | 40,904 | 35,266 |
| Additions | 9,472 | 4,212 |
| Write-offs | 417 | - |
| Adjustments to asset retirement estimates | (12,047) | 1,426 |
| Transfer from Development Assets | 12,407 | - |
| Additions through Acquisition (Note 12) | 90,209 | - |
| At 31 December | 141,362 | 40,904 |
| Accumulated depreciation | ||
| At 1 January | 8,601 | 4,287 |
| Write-offs | (417) | - |
|---|---|---|
| Depreciation charge for the year | 12,909 | 4,314 |
| At 31 December | 21,093 | 8,601 |
| Net carrying value at 31 December | 120,269 | 32,303 |
|---|---|---|
* Production assets at 31 December 2021 include capitalised borrowing costs of USD 376 thousand (31 December 2020: USD 252 thousand) relating to the BW Energy Non-Recourse loan for the Dussafu development.
The Group has a 14.25% working interest in Block G, Equatorial Guinea.
An assessment was performed in December 2021 and no indication of impairment was identified. No impairment was therefore recognised during the year 2021.
The Group has a 17.4997% interest in the Dussafu Permit, offshore Gabon.
An assessment was performed in December 2021 and no indication of impairment was identified. No impairment was therefore recognised during the year 2021.
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.
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 in December 2021 and no indication of impairment was identified. No impairment was therefore recognised during the year 2021.
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") 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. PetroNor has an option to pay a portion of the Share Consideration in cash.
Following agreement to sell the Divested Subsidiaries, the Group's interest in such subsidiaries have also been designated as Assets held for sale as of 31 December 2019. See Note 13: Discontinued Operations and assets held for sale.
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. A further assessment was made in 2021 resulting in a further reversal of USD 8 million historical impairment charge was made 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.
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.
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.
The Company has run sensitivities for its West and North African oil assets with the CO2 tax assumptions as described in the scenarios outlined by the International Energy Agency (IEA) in their World Energy Outlook (WEO) reports, namely the Stated Policies Scenario and the Sustainable Development Scenario. 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 of goodwill and on certain production and development assets in the Group's portfolio including intangible assets that are subject to impairment assessment under IAS 36, but an opposite revision in the price assumptions would not trigger any impairment reversals as the recently acquired assets in EG and Gabon and the existing assets in Tunisia have no impairment recognised from previous years that has not already been reversed.
To assess the robustness of the Group's oil and gas assets, the Company has run sensitivities with the oil and gas price assumptions described by scenarios outlined by the IEA, namely the Stated Policies Scenario and the Sustainable Development Scenario. These scenarios are commonly applied by peer companies and the Company believes that these are useful for investors and other stakeholders in assessing portfolio resilience across companies in the industry. The oil and gas price assumptions in the scenarios have been provided by the IEA for the years 2030 and 2050 (in 2020 real terms), and for the sensitivity calculation a linear development between average actual 2021 and 2030, as well as between 2030 and 2050 have been applied. A calculation of a possible effect of using the oil and gas prices in the Sustainable Development Scenario (oil price: USD 56 per barrel in 2030 and USD 50 per barrel in 2050 indicates no impairment on a post-tax basis for any of the Group's oil and gas interests. As the oil and gas price assumptions in the Stated Policies Scenario are at higher levels (oil price: USD 77 per barrel in 2030 and USD 88 per barrel in 2050, compared to the Group's long-term price assumption of USD 70 per barrel, no impairments or significant reversals are expected, but the estimated headroom in the impairment testing would increase.
A significant reduction in the oil and gas price assumptions could also have effect on the estimated economic cut-off of the projects. Based on the Group's scenario analysis, no significant impact was identified with regards to estimated economic cutoff dates. 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 as occurred following significant changes in oil and gas prices during the Covid-19 pandemic in 2020. 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.
2021
| Right of | |||||
|---|---|---|---|---|---|
| Furniture, | use asset - | ||||
| fixtures and | Computer | London | |||
| USD 000 | Leasehold | fittings | equipment | office | Total |
| Historical cost | |||||
| At 1 January 2021 | - | 830 | 160 | 946 | 1,936 |
| Additions | 138 | 93 | 2 | - | 233 |
| Disposals and write-offs | - | - | |||
| 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 |
| Disposals and write-offs | - | - | - | - | |
| At 31 December 2021 | 14 | 825 | 122 | 658 | 1,619 |
| Net carrying value at 31 December 2021 | 124 | 98 | 40 | 288 | 550 |
2020
| Furniture, fixtures and |
Computer | Right of use asset - London |
|||
|---|---|---|---|---|---|
| USD 000 | Leasehold | fittings | equipment | office | Total |
| Historical cost | |||||
| At 1 January 2020 | 55 | 815 | 666 | 946 | 2,482 |
| Additions | - | 15 | - | - | 15 |
| Disposals and write-offs | (55) | - | (506) | - | (561) |
| At 31 December 2020 | - | 830 | 160 | 946 | 1,936 |
| Accumulated depreciation | |||||
| At 1 January 2020 | 44 | 753 | 490 | 247 | 1,534 |
| Depreciation charge for the year | - | 30 | 19 | 198 | 247 |
| Disposals and write-offs | (44) | - | (441) | - | (485) |
| At 31 December 2020 | - | 783 | 68 | 445 | 1,296 |
| Net carrying value at 31 December 2020 | - | 47 | 92 | 501 | 640 |
| 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 |
| USD 000 | 2021 | 2020 |
|---|---|---|
| Trade receivables | 54,351 | 10,046 |
| Other receivables and prepayments | 1,278 | 811 |
| At 31 December | 55,629 | 10,857 |
Accounts receivables are non-interest bearing and generally on 30 to 120 days payment terms.
At 31 December 2021 and 2020, the allowance for impairment of receivables was USD Nil.
Risk information for the receivable balances is disclosed in Note 19: Financial risk management.
Other non-current assets amount to prepayments of USD 1.2 million at 31 December 2021 and (31 December 2020: USD 0.7 million) and USD 0.1 million tenancy deposit for the UK office premises for both reporting periods.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Cash and cash equivalents | 24,532 | 5,674 |
| Cash held for Bank guarantee | - | 9,960 |
| At 31 December | 24,532 | 15,634 |
The majority of Panoro's cash balance was denominated in NOK and USD and was held in different jurisdictions including Norway, Austria and Tunisia.
The Group had no bank overdraft facilities as at 31 December 2021 (31 December 2020: Nil).
During January 2019, the Tunisian Directorate General of Hydrocarbons advised that the Tunisian Consultative Hydrocarbons Committee had required Panoro Tunisia Exploration ("PTE", 60% owned by Panoro) to post a bank guarantee in relation to the drilling operations on SOEP. Accordingly, the Group procured a bank guarantee of USD 16.6 million (USD 10 million net to Panoro) through its group company, PTE.
During the year, USD 6.3 million of the bank guarantee was partially drawn to settle amounts due to historical non-fulfilment of a work programme at Sfax Offshore by the previous operator. The remaining USD 3.6 million was cancelled and cash returned to Panoro. As part of the settlement, the license period was renewed for a year.
This amount was classified as restricted cash and disclosed under current assets as at 31 December 2020.
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"). The EG Assets comprise six producing oil fields in water depths of 50-850 metres, approximately 35 kilometres from shore. The EG Assets hold net working interest 2P reserves of 14.2 MMbbl and net workiing interest 2C resources of 25.6 MMbbl as of 30 June 2020.
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:
| Net assets acquired | 97,450 | |
|---|---|---|
| Contingent consideration ** | 5,019 | |
| Deferred consideration * | 5,000 | |
| Cash consideration | 100% | 87,431 |
| Shares acquired | USD 000 |
* 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.
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. Upon completion of the Dussafu Transaction, Panoro's net working interest 2P reserves at Dussafu increased to approximately 19 MMbbls, and net working interest production from the field increased from 1,200 bopd to approximately 2,800 bopd.
At the completion date of 9 June 2021, a total cash consideration of 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 |
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.
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 final regulatory approvals were received on 27 January 2022, marking the last key condition precedent and both parties are currently working on final completion steps.
PetroNor has an option to pay a portion of the Share Consideration in cash. The sale transaction is conditional upon execution and completion of the agreements between PetroNor and YFP, the authorisation of the Nigerian Department of Petroleum Resources and the consent of the Nigerian Minister of Petroleum Resources. As a result, the operations of the Group's Divested Subsidiaries have been classified as discontinued operations under IFRS 5 since 2019.
The results of the Nigerian segment presented as discontinued operations are as follows:
| Amounts in USD 000, unless otherwise stated | 2021 | 2020 |
|---|---|---|
| DISCONTINUED OPERATIONS | ||
| Oil revenue | 3,688 | 2,307 |
| Total revenues | 3,688 | 2,307 |
| Operating costs | (4,085) | (4,820) |
| General and administrative costs | (148) | (157) |
| Depreciation, depletion and amortisation | - | - |
| (Impairment) / reversal of impairment for Oil and gas assets | 8,000 | - |
| EBIT - Operating income/(loss) | 7,455 | (2,670) |
| Interest costs net of income | (351) | (366) |
| Net foreign exchange gain / (loss) | (2) | |
| Other financial costs net of income | (91) | (102) |
| Net income/(loss) before tax | 7,011 | (3,138) |
| Income tax benefit/(expense) | - | - |
| Net income/(loss) for the period from discontinued operations | 7,011 | (3,138) |
| EARNINGS PER SHARE | ||
| Basic EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations |
0.07 | (0.05) |
| Diluted EPS on profit for the period attributable to equity holders of the parent (USD) from discontinued operations |
0.07 | (0.05) |
The Group's interest in Divested Subsidiaries designated as Assets held for sale as of 31 December 2021 and 31 December 2020 are summarised below:
| Carrying amount after allocation of impairment reversal | ||
|---|---|---|
| USD 000 | 2021 | 2020 |
| Assets held for sale | ||
| Licence and exploration assets | 16,904 | 12,179 |
| Production assets and equipment | 10,978 | 7,405 |
| Crude oil inventory | 1,088 | 812 |
| Cash and cash equivalents | 45 | 49 |
| Total assets held for sale | 29,015 | 20,445 |
| Liabilities held for sale | ||
| Decommissioning liability | (3,723) | (3,334) |
| Other non-current liabilities | (8,546) | (8,196) |
| Accounts payable, accruals and other liabilities | (134) | (119) |
| Other current liabilities | (7,936) | (7,262) |
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 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 |
| At 1 January 2020 | - | 2,213 | 16,698 | 18,911 |
| Unwinding of discount | - | 84 | 496 | 580 |
| Change in inflation and discount rate (estimate) | - | 253 | 1,174 | 1,427 |
| Change in cost estimate | - | 546 | - | 546 |
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:
Balance at 31 December 2020 - 3,096 18,368 21,464
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 2021 are a discount rate of 2.5% and an inflation rate of 2% (31 December 2020: 2.5% and 2% respectively). The Nigerian asset for the Group is designated as Discontinued operation and an asset held for sale as discussed in Note 13: Discontinued Operations and assets held for sale.
| As at 31 December 2021 | 113,383,690 | 721 |
|---|---|---|
| Share issue under RSU Plan (Note 17) | 277,402 | 2 |
| Secured Loan arrangement fee share issue | 307,578 | 2 |
| Private placement and subsequent offering | 43,776,451 | 258 |
| As at 1 January 2021 | 69,022,259 | 459 |
| Amounts in USD 000 unless otherwise stated | Number of shares | Nominal Share Capital |
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.
In connection with the Company's Restricted Share Units Plan, announced on 24 June 2020, the Company issued 277,402 new shares to employees.
As of 31 December 2021, the Company had a registered share capital of NOK 5,669,184 divided into 113,383,690 shares, each with a nominal value of NOK 0.05 (31 December 2020: NOK 3,451,113 divided into 69,022,259 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.
Share premium reserve represents excess of subscription value of the shares over the nominal amount.
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 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.
The translation reserve comprises all foreign exchange differences arising from the translation of the financial statements of foreign operations.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Accounts payable | 12,707 | 6,020 |
| Accrued and other liabilities | 10,623 | 1,291 |
| Other non-current liabilities | 8,302 | 2,172 |
| At 31 December | 31,632 | 9,483 |
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:
| 2021 | 2020 | |
|---|---|---|
| All amounts in Number of units, unless stated otherwise | ||
| Outstanding RSUs as of 1 January | 1,149,150 | 878,808 |
| Add: Grants during the year | 528,356 | 719,087 |
| Less: Vested during the year | ||
| - Settled in cash to cover taxes / settlement through purchase of shares from the market |
(243,879) | (193,971) |
| - Settled through issue of new shares | (271,193) | (221,401) |
| Less: Terminated without vesting | - | (33,373) |
| Outstanding RSUs as of 31 December | 1,162,434 | 1,149,150 |
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 2021, 528,356 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. USD 0.8 million (2020: USD 0.8 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 | 2021 | 2020 |
|---|---|---|
| Weighted average risk-free interest rate | 0.75% | 1.20% |
| 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 | 61% | 61% |
| Weighted average remaining contractual life of RSUs at year end | 1.1 Years | 1.2 Years |
| Share price at grant date – per share | NOK 24.70 | NOK 11.32 |
The weighted average fair value of RSUs granted during the period was NOK 24.65 per unit (2020: NOK 11.32 per unit) based on 528,356 units granted (2020: 719,087 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:
| 2021 | 2020 | WAEP | 2021 | 2020 | |
|---|---|---|---|---|---|
| Number of Units | NOK/share | Exercise value in NOK | |||
| Within 1 year | 570,501 | 515,072 | 0.05 | 28,525 | 25,754 |
| Between 1 and 2 years | 415,814 | 394,382 | 0.05 | 20,791 | 19,719 |
| Between 2 and 3 years | 176,119 | 239,696 | 0.05 | 8,806 | 11,985 |
| Total | 1,162,434 | 1,149,150 | 58,122 | 57,458 |
As of the year ended 2021 the unvested RSUs were outstanding for 16 employees including key management personnel (2020: 8 employees).
The distribution of outstanding RSUs as of 31 December 2021 amongst the employees is as follows:
| No of Units | Exercise price NOK/share |
Exercise period | Fair value expensed USD 000 |
|
|---|---|---|---|---|
| John Hamilton, CEO | 448,821 | 0.05 | June 2022 to June 2024 | 483 |
| Qazi Qadeer, CFO | 145,427 | 0.05 | June 2022 to June 2024 | 157 |
| Other Named Executives (i) | 287,740 | 0.05 | June 2022 to June 2024 | 302 |
| Total | 881,988 | 942 |
(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.
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 plan to award share options to the Company's existing members of the Board of Directors whereby the following options ("Board Options") were awarded:
| Options awarded |
Fair value expensed USD 000 |
|
|---|---|---|
| Julien Balkany | 48,000 | 14 |
| Torstein Sanness | 24,000 | 7 |
| Hilde Adland | 24,000 | 7 |
| Alexandra Herger | 24,000 | 7 |
| Garrett Soden | 24,000 | 7 |
| Total | 144,000 | 42 |
One Board Option will entitle 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, 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 May 27, 2021 to May 27, 2024, where 1/3 of the Board Options vest on the date of the Company's 2022 AGM, 1/3 vest on the date of the Company's 2023 AGM, and the final 1/3 vest on the date of the Company's 2024 AGM. The Annual General Meeting of the Company is generally held in the last week of May each year.
Valuation of Board Options for reporting purposes was performed using Black Scholes method.
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.
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.
During December 2018, the Group initiated 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 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 2020 | Jan 20 - Dec 21 | 243,432 | 55 | 61 | 1,380 | - |
| At 31 December 2021 | Jan 21 - Dec 21 | 216,000 | 55 | 64 | (2,489) | - |
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:
All the Group's derivatives are Level 2 (2020: 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.
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:
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 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.
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.
Increase /(decrease) in profit before tax and equity
| USD 000 | 2021 | 2020 |
|---|---|---|
| 15% increase in the price of oil | 373 | (207) |
| 15% decrease in the price of oil | (373) | 207 |
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 2021 or 2020.
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 | 2021 | 2020 | ||
|---|---|---|---|---|
| USD vs NOK | 20% | -20% | 20% | -20% |
| Cash | 9 | (13) | 17 | (26) |
| Receivables | 7 | (11) | 1 | (1) |
| Payables | (8) | 12 | (2) | 3 |
| Net effect | 8 | (12) | 16 | (24) |
| USD vs TND | 20% | -20% | 20% | -20% |
|---|---|---|---|---|
| Cash | 182 | (274) | 3 | (5) |
| Receivables | 1,630 | (2,444) | 796 | (1,194) |
| Corporation taxes payable | (790) | 1,185 | (192) | 288 |
| Payables | (593) | 889 | (1,028) | 1,542 |
| Net effect | 429 | (643) | (421) | 631 |
| USD vs EUR | 20% | -20% | 20% | -20% |
|---|---|---|---|---|
| Cash | 3 | (5) | 5 | (8) |
| Receivables | (33) | 50 | 1 | (1) |
| Payables | (33) | 50 | (32) | 47 |
| Net effect | (63) | 95 | (26) | 38 |
| USD vs GBP | 20% | -20% | 20% | -20% |
|---|---|---|---|---|
| Cash | 66 | (99) | 43 | (65) |
| Receivables | (36) | 54 | (60) | 90 |
| Payables | (55) | 83 | (87) | 130 |
| Net effect | (26) | 38 | (103) | 154 |
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 | 2021 | 2020 | ||
|---|---|---|---|---|
| +100bps | -100bps | +100bps | -100bps | |
| Loans and borrowings (Secured loans) | (954) | 954 | (85) | 85 |
| Cash equivalents | 51 | (51) | 1 | (1) |
| Net effect | (902) | 902 | (84) | 84 |
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 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 2021 based on contractual undiscounted payments.
| USD 000 | On demand | Less than 1 year |
Between 2 to 5 years |
Over 5 years | Total |
|---|---|---|---|---|---|
| Loans and borrowings (Secured loans) | - | 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 |
| USD 000 | On demand | Less than 1 year |
Between 2 to 5 years |
Over 5 years | Total |
|---|---|---|---|---|---|
| Loans and borrowings (Senior secured facility) |
- | 4,424 | 9,900 | - | 14,324 |
| Loans and borrowings (Non-recourse loan) |
- | 4,133 | 3,078 | - | 7,211 |
| Accounts payable and accrued liabilities |
- | 6,020 | - | - | 6,020 |
| Non-current liabilities | - | - | 363 | 1,809 | 2,172 |
| Corporation tax liabilities | - | 1,302 | - | - | 1,302 |
| Total | - | 15,879 | 13,341 | 1,809 | 31,029 |
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 2021, the Group's total debt was USD 96.8 million. The Group closed the year with a cash position of USD 24.5 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.
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.
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.
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 2021. 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. Further details can be found in Note 5: Finance income, interest expense and other charges.
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 income, interest expense and other charges.
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.
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.
Lease liability is classified as current or non-current depending on maturity profile at balance sheet date. At 31 December 2021, USD 231 thousand was current and USD 127 thousand was non-current (31 December 2020: USD 216 thousand and USD 362 thousand respectively).
| USD 000 Lease liability recognised at 1 January |
2021 578 |
2020 679 |
|---|---|---|
| Add: lease interest | 40 | 55 |
| Less: gross lease payments | (260) | (156) |
| Lease liability at 31 December | 358 | 578 |
The following table shows the maturity profile of lease liabilities based on contractual undiscounted lease payments.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Within 1 year | 187 | 187 |
| 2 to 5 years | 47 | 233 |
| After 5 years | - | - |
| Lease liability at 31 December | 233 | 420 |
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 | 2021 | 2020 |
|---|---|---|
| Right of use asset recognised at 1 January | 501 | 699 |
| Less: depreciation and impairment | (213) | (198) |
| Net book value of right of use asset at 31 December | 288 | 501 |
Details of related party transactions are set out in the parent stand-alone financial statements, Note 8: Related party transactions and balances.
Details of the Group's subsidiaries as of 31 December 2021 are as follows:
| Subsidiary | Place of incorporation and ownership |
Ownership interest & 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% |
| 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% |
| Pan-Petroleum Nigeria Holding B.V. | Netherlands | 100% |
| Pan-Petroleum Services Holding B.V. | Netherlands | 100% |
| Panoro Equatorial Guinea Limited | Isle of Man | 100% |
| Pan-Petroleum AJE Limited | Nigeria | 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% |
The ongoing conflict between Russia and Ukraine may have implications on commodity prices and potential interruptions of supply chains and third-party services. Panoro is monitoring the situation, taking into account international sanctions and trade control legislation in order to mitigate any potential impact on the Company's operations.
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 Gaffney, Cline & Associates ("GCA"), Netherland Sewell & Associates ("NSAI") and AGR TRACS International Limited for 3rd party verifications of its reserves.
Please refer to the Annual Statement of Reserves on page 36 for details.
FOR THE YEAR ENDED 31 DECEMBER
| USD 000 | Note | 2021 | 2020 |
|---|---|---|---|
| Operating income | |||
| Operating revenues | - | - | |
| Total operating income | - | - | |
| Operating expenses | |||
| General and administrative expense | (5,024) | (1,281) | |
| Impairment of investments in subsidiary | 2,6 | (70) | (45) |
| (Impairment) / reversal of impairment of loan to subsidiaries | 2,7,8 | 65,806 | (173) |
| Total operating expenses | 60,712 | (1,499) | |
| Operating result | 2 | 60,712 | (1,499) |
| Financial income | 3 | 5,452 | 10,928 |
| Interest and other finance expense | 3 | (3) | (2) |
| Currency gain / (loss) | 232 | (16) | |
| Result before income taxes | 66,393 | 9,411 | |
| Income tax | 5 | - | - |
| Result for the year | 66,393 | 9,411 | |
| Earnings per share (basic and diluted) - USD | 4 | 0.96 | 0.14 |
FOR THE YEAR ENDED 31 DECEMBER
| USD 000 | Note | 2021 | 2020 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Investment in subsidiaries | 6 | 179,974 | 18,003 |
| Total non-current assets | 179,974 | 18,003 | |
| Current assets | |||
| Loans to subsidiaries | 8 | 59,252 | 82,523 |
| Other current assets | - | - | |
| Cash and cash equivalents | 6,461 | 1,082 | |
| Total current assets | 65,713 | 83,605 | |
| TOTAL ASSETS | 245,687 | 101,608 | |
| EQUITY AND LIABILITIES | |||
| EQUITY | |||
| Paid-in capital | |||
| Share capital | 9 | 721 | 459 |
| Share premium reserve | 9 | 427,496 | 349,446 |
| Treasury Shares | - | - | |
| Additional paid-in capital | 9 | 122,102 | 122,055 |
| Total paid-in capital | 550,319 | 471,960 | |
| Other equity | |||
| Other reserves | 9 | (308,596) | (374,989) |
| Total other equity | (308,596) | (374,989) | |
| TOTAL EQUITY | 241,723 | 96,971 | |
| LIABILITIES | |||
| Current liabilities | |||
| Accounts payable | 219 | 478 | |
| Intercompany payables | 8 | 3,718 | 4,138 |
| Other current liabilities | 10 | 27 | 21 |
| Total current liabilities | 3,964 | 4,637 | |
| TOTAL LIABILITIES | 3,964 | 4,637 | |
| TOTAL EQUITY AND LIABILITIES | 245,687 | 101,608 |
FOR THE YEAR ENDED 31 DECEMBER
| USD 000 | Note | 2021 | 2020 |
|---|---|---|---|
| CASH FLOW FROM OPERATING ACTIVITIES | |||
| Net income / (loss) for the year | 66,393 | 9,411 | |
| Adjusted for: | |||
| Impairment of investment in subsidiary | 6 | 70 | 45 |
| Provision for Doubtful Receivables | 7,8 | (65,806) | 173 |
| Financial Income | 3 | (5,452) | (10,928) |
| Financial Expenses | 3 | 3 | 2 |
| Foreign exchange gains/losses | (232) | 16 | |
| (Increase)/decrease in trade and other receivables | - | 1 | |
| Increase/(decrease) in trade and other payables | (253) | 40 | |
| Increase/(decrease) in intercompany payables | (420) | (539) | |
| Net cash flows from operating activities | (5,697) | (1,779) | |
| CASH FLOWS FROM INVESTING ACTIVITIES | |||
| Cash outflow relating to acquisitions | (50,070) | (45) | |
| Loans to subsidiaries | (17,442) | (8,745) | |
| Net cash flows from investing activities | (67,512) | (8,790) | |
| CASH FLOWS FROM FINANCING ACTIVITIES | |||
| Net proceeds from Equity Private Placement and Treasury Shares | 78,359 | 255 | |
| Interest paid | (3) | (2) | |
| Net cash flows from financing activities | 78,356 | 253 | |
| Effect of foreign currency translation adjustment on cash balances | 232 | (16) | |
| Net increase in cash and cash equivalents | 5,379 | (10,332) | |
| Cash and cash equivalents at the beginning of the year | 1,082 | 11,414 | |
| Cash and cash equivalents at the end of financial year | 6,461 | 1,082 |
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.
| Operating result is stated after charging / (crediting): | ||
|---|---|---|
| USD 000 | 2021 | 2020 |
| Employee benefits expense (Note 2.1) | 67 | 12 |
| Reversal of impairment of investment in subsidiary (Note 6) | 70 | 45 |
| Intercompany Loans impairment / (impairment reversal) (Note 7) | (65,806) | 173 |
The Company had no employees at 31 December 2021 and 2020. As such, there are no wages and salaries included in general and administrative expenses.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Employer's contribution to payroll taxes | 67 | 12 |
| Total | 67 | 12 |
Details of CEO and CFO remuneration of CEO and CFO 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.
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 | 2021 | 2020 |
|---|---|---|
| Julien Balkany (Chairman of the Board) | 82 | 66 |
| Torstein Sanness (Deputy Chairman) | 57 | 47 |
| Alexandra Herger | 48 | 40 |
| Garrett Soden | 50 | 40 |
| Hilde Ådland | 48 | 40 |
| Total | 285 | 233 |
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 2021 and 2020.
There are no severance payment arrangements in place for the Directors.
Details of the RSU scheme and Board options are set out in the consolidated Financial Statements, Note 17: 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:
| Number of RSUs | Fair value of | |
|---|---|---|
| USD 000 (unless stated otherwise) | awarded | 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 |
There were no options issued to the Board of Directors prior to the year 2021.
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.
Fees (excluding VAT) to the Company's auditors are included in general and administrative expenses and are shown below.
| USD 000 | 2021 | 2020 |
|---|---|---|
| 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 66. Audit fees for 2021 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.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Interest income from subsidiaries | 5,384 | 10,872 |
| Other interest income | 68 | 56 |
| Total | 5,452 | 10,928 |
Interest income from subsidiaries represents an interest on the intercompany loans. Note 8: Related party transactions and balances contains further information on these balances.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Bank and other financial charges | 3 | 2 |
| Total | 3 | 2 |
| USD 000 unless otherwise stated | 2021 | 2020 |
|---|---|---|
| Net result for the period | 66,393 | 9,411 |
| Weighted average number of shares outstanding - in thousands | 68,912 | 68,912 |
| Basic and diluted earnings per share – (USD) | 0.96 | 0.14 |
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.
| USD 000 | 2021 | 2020 |
|---|---|---|
| Tax payable | - | - |
| Change in deferred tax | - | - |
| Income tax expense | - | - |
| USD 000 | 2021 | 2020 |
|---|---|---|
| Result before income tax | 66,393 | 9,411 |
| Effect of permanent differences | 2,300 | (103) |
| Effect of timing differences | 65,736 | - |
| Tax losses utilised | (134,429) | (9,308) |
| Basis for tax payable | - | - |
| USD 000 | 2021 | 2020 |
|---|---|---|
| Losses carried forward | 21,591 | 21,178 |
| Taxable temporary differences | - | - |
| Basis for tax payable | 21,591 | 21,178 |
| Calculated deferred tax asset (22% for 2021 and 2020) | 4,750 | 4,659 |
| Unrecognised deferred tax asset | (4,750) | (4,659) |
| 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 2021 was NOK 191 million (USD 21.6 million at 2021 closing exchange rate).
The deferred tax asset is not recognised on the balance sheet due to uncertainty of future income.
Investments in subsidiaries are carried at the lower of cost and fair market value. As at 31 December 2021, the carrying value of the investment in subsidiaries was USD 180 million (31 December 2020: USD 18 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% |
| Pan-Petroleum Nigeria Holding B.V. (PPNHBV) | Amsterdam, Netherlands | 100% |
| Pan-Petroleum Services Holding B.V. (PPSHBV) | Amsterdam, Netherlands | 100% |
| Panoro 2B Limited (P2BL) | London, UK | 100% |
| Sfax Petroleum Corporation AS (Sfax Petroleum) | Oslo, Norway | 60% |
| USD 000 Investment at cost |
PEdB | PPHCL | PEHBV | PPNHBV | PPSHBV | P2BL | SFAX Petroleum |
Total |
|---|---|---|---|---|---|---|---|---|
| At 1 January 2021 | 95,647 | 129,106 | - | - | - | - | 18,003 | 242,756 |
| Investments during the year | 40 | - | 161,971 | - | - | - | - | 162,011 |
| At 31 December 2021 | 95,687 | 129,106 | 161,971 | - | - | - | 18,003 | 404,767 |
| Impairment provision | ||||||||
| At 1 January 2021 | (95,647) | (129,106) | - | - | - | - | - | (224,753) |
| Charge for the year | (40) | - | - | - | - | - | - | (40) |
| At 31 December 2021 | (95,687) | (129,106) | - | - | - | - | - | (224,793) |
| Total investment in subsidiaries at 31 December 2021 |
- | - | 161,971 | - | - | - | 18,003 | 179,974 |
| Total investment in subsidiaries at 31 December 2020 |
- | - | - | - | - | - | 18,003 | 18,003 |
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.
Provision for doubtful receivables owed from loans provided to subsidiaries, is USD 162 thousand (2020: USD 173 thousand) related to uncollectible loan provision reflective of the dormant nature of subsidiary, Pan-Petroleum Holding B.V. A loan of USD 112 million owing by Pan-Petroleum Gabon B.V, was assigned to Panoro Energy Holding B.V. in exchange for the issue of 93,998,316 ordinary shares of the same value in Panoro Energy Holding B.V. The historical impairments of USD 65.9 million on the assigned loan was therefore reversed.
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 2021:
The Company had the following non-interest-bearing payable balances to companies within the Group at 31 December 2021:
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 2021 were:
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 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
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 2021 were:
As of 31 December 2021, the Company had a registered share capital of NOK 5,669,184 divided into 113,383,690 shares, each with a nominal value of NOK 0.05 (31 December 2020: NOK 3,451,113 divided into 69,022,259 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 2021 and 2020:
| Share | Additional | ||||
|---|---|---|---|---|---|
| USD 000 | Issued capital | premium | paid-in capital | Other equity | Total |
| 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 |
| Transaction costs on share issue | - | (3,043) | - | - | (3,043) |
| At 31 December 2021 | 721 | 427,496 | 122,102 | (308,596) | 241,723 |
| At 1 January 2020 | 458 | 349,193 | 122,055 | (384,400) | 87,306 |
| Net income/(loss) for the year | - | - | - | 9,411 | 9,411 |
| Shares issued under RSU plan | 1 | 253 | - | - | 254 |
| At 31 December 2020 | 459 | 349,446 | 122,055 | (374,989) | 96,971 |
During the year the Company issued 277,402 shares, each at a fair value of NOK 20.4944, under the Company's RSU plan.
In 2021, the Company completed private placements through issuing 43,776,451 new shares at an average of NOK 14.91 per share to subscribers. A further 307,578 new shares were issued to Trafigura at NOK 15.50 per share, as settlement of transaction costs related to the USD 90 million Secured Borrowing Base facility described in Note 5: Finance income, interest expense and other charges in the consolidated accounts above.
The Company had 5,890 shareholders on 31 December 2021 (31 December 2020: 4,752). The twenty largest shareholders were:
| No. | Shareholder | Number of shares | Holding in % |
|---|---|---|---|
| 1 | SUNDT AS | 14,700,000 | 12.96% |
| 2 | DNB Markets Aksjehandel/-analyse | 8,745,682 | 7.71% |
| 3 | HORTULAN AS | 5,350,000 | 4.72% |
| 4 | Citibank Europe plc | 3,702,040 | 3.27% |
| 5 | VERDIPAPIRFONDET DNB SMB | 3,432,693 | 3.03% |
| 6 | ALDEN AS | 3,200,000 | 2.82% |
| 7 | Citibank Europe plc | 2,881,383 | 2.54% |
| 8 | J.P. Morgan Securities LLC | 2,485,120 | 2.19% |
| 9 | F2 FUNDS AS | 1,650,000 | 1.46% |
| 10 | F1 FUNDS AS | 1,600,000 | 1.41% |
| 11 | BNP Paribas Securities Services | 1,516,145 | 1.34% |
| 12 | DnB NOR Bank ASA | 1,500,353 | 1.32% |
| 13 | THORSEN, SIMEN | 1,450,000 | 1.28% |
| 14 | Nordnet Bank AB | 1,246,479 | 1.10% |
| 15 | Danske Invest Norge Vekst | 1,235,998 | 1.09% |
| 16 | MIDELFART CAPITAL AS | 1,230,000 | 1.08% |
| 17 | TIGERSTADEN INVEST AS | 1,200,000 | 1.06% |
| 18 | TIGERSTADEN AS | 1,100,000 | 0.97% |
| 19 | KING KONG INVEST AS | 976,825 | 0.86% |
| 20 | VERDIPAPIRFONDET STOREBRAND VEKST | 970,899 | 0.86% |
| Top 20 shareholders | 60,173,617 | 53.07% | |
| Other shareholders | 53,210,073 | 46.93% | |
| Total shares | 113,383,690 | 100.00% |
| Shareholder | Position | Number of shares | % of total |
|---|---|---|---|
| Julien Balkany(i) | Chairman of the Board of Directors | 3,652,970 | 3.22% |
| 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 | 520,020 | 0.46% |
| Qazi Qadeer | Chief Financial Officer | 215,491 | 0.19% |
| Richard Morton | Technical Director | 255,471 | 0.23% |
| Nigel McKim | Projects Director | 51,414 | 0.05% |
(ii) 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.
(iii) Mr. Soden holds directly or indirectly 30,000 shares in the Company.
| Amount of shares | # of shareholders | % of total | # of shares | Holding in % |
|---|---|---|---|---|
| 1 - 1,000 | 3,595 | 61.04% | 873,232 | 0.77% |
| 1,001 - 5,000 | 1,212 | 20.58% | 3,141,445 | 2.77% |
| 5,001 - 10,000 | 372 | 6.32% | 2,873,954 | 2.53% |
| 10,001 - 100,000 | 583 | 9.90% | 17,253,059 | 15.22% |
| 100,001 - 1,000,000 | 110 | 1.87% | 31,016,107 | 27.35% |
| 1,000,001 + | 18 | 0.31% | 58,225,893 | 51.35% |
| Total | 5,890 | 100.00% | 113,383,690 | 100.00% |
The breakdown of other current liabilities is below:
| USD 000 | 2021 | 2020 |
|---|---|---|
| Accruals | 5 | 4 |
| Employee related costs payable (including taxes) | 22 | 17 |
| At December 31 | 27 | 21 |
There were no commitments and contingencies at 31 December 2021 (31 December 2020: Nil).
Refer to the consolidated financial statements,Note 19: Financial risk management.
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 2021. 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. Further details can be found in Note 5: Finance income, interest expense and other charges.
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 income, interest expense and other charges 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.
Refer to the consolidated financial statements, Note 24: Events subsequent to reporting date.
(REF. SECTION 6-16A OF THE NORWEGIAN PUBLIC LIMITED COMPANIES ACT)
These guidelines regarding remuneration to the executive management have been prepared by the Board of Directors of Panoro Energy ASA ("Panoro" or the "Company") in accordance with the Norwegian Public Limited Liability Companies Act (the "Companies Act") Section 6-16a and related regulations. The guidelines have been prepared for approval by the Company's annual general meeting in 2022, and shall apply until the Company's annual general meeting in 2026, unless amended or replaced earlier.
The guidelines apply to the executive management of the Company as defined in Section 6-16a of the Companies Act.
With support of the remuneration committee as a basis, the Board of Directors shall prepare a proposal for guidelines for resolution by the annual general meeting at least every fourth year. The annual general meeting shall decide on such proposals. Resolved guidelines may also be amended by way of resolution of subsequent general meetings.
A separate remuneration committee has for many years been in place in the Company. The remuneration committee is a subcommittee of the Board of Directors. The objective is to serve as a preparatory and advisory body for the Board of Directors' consideration of matters concerning remuneration and compensation of management. Responsibilities include overseeing and approving the determination of performance criteria of variable remuneration. It will also preside in other matters including any potential deferral periods or Company's claims to a refund of variable compensation. The committee is only responsible to the whole Board of Directors of Panoro and only has recommendatory authority with regard to that body. There are separate instructions for the remuneration committee.
In order to reduce the risks of conflict of interests, no senior executive shall participate in the preparation or resolution regarding remuneration-related matters in which they are directly affected.
These guidelines constitute a framework for which remuneration to senior executives may be decided by the Company during the period for which the guidelines are in force. As a leading company within its industries, and with its primary executive team in London with offices in several other jurisdictions, Panoro must offer salaries and other compensation that ensure that it can recruit and retain capable managers and key personnel. These guidelines strive to support Panoro's competitiveness as an employer in all locations.
The Company's remuneration principles are designed to ensure responsible and sustainable remuneration decisions that support the Company's business strategy, long-term interests, and sustainable business practices. To this end, salaries and other employment terms shall support the Company's efforts to retain, develop and recruit skilled senior executives with relevant experience and competence. The remuneration shall be on market terms, competitive, and reflect the performance and responsibilities of individual senior executives. Principles for incentives and performance are designed to be aligned with the interests of the Company's shareholders and ensure the most capable execution of defined business strategies, short and long-term, while ensuring the Company's going-concern.
As there are no employees who are formally and directly employed with the Company (but rather with local subsidiaries), the remuneration and employment conditions for employees of the Panoro group have been taken into account in the preparation of these guidelines by including information on employees' total income, forms of remuneration and other salary components in the remuneration committee's and the Board of Directors' basis for decision when evaluating whether the Company's remuneration practices, and guidelines and limitations set out herein are adequate and reasonable.
The remuneration to the senior executives covered by these guidelines may consist of fixed cash salary, variable cash salary, benefits, and stock-based incentive programs as further described below.
Fixed cash salary allows the Company to attract and recruit senior executives that are necessary for the long-term profitability and sustainability of the Company.
It is the Company's policy that base salaries shall reflect the individual's position and degree of responsibility. The size of the fixed cash salary shall be in line with market conditions, be competitive with comparable businesses within the industry at the relevant location, and shall take into account inter alia the scope and responsibility associated with the position, as well as the skills, experience, and performance of each senior executive. The fixed cash salaries have no maximum levels.
Variable cash salary (i.e. cash bonuses) shall be based on a set of predetermined and measurable performance criteria that reflect the key drivers for pursuing the Company's business strategy, long-term interests, and sustainable business practices. Such performance criteria may consist of performance indicators both for the Company's overall and financial performance and for individual performance. Performance indicators may include financial and non-financial performance parameters. Nonfinancial parameters may include a range of strategic objectives including ESG targets. Financial parameters may include performance of revenue, EBITDA, profits and similar, and may also be tied to share price development. The performance achievement, subject to a cap determined at the discretion of the remuneration committee, is applied to fixed percentages of base salary which as the main rule is kept up to 50% . Determination of the extent to which the criteria for variable cash salary are satisfied is determined upon expiry of the relevant measurement period by measuring criteria against actual performance. Special one-time cash bonuses for particular achievements may also be decided upon by the Board of Directors.
The Company firmly believes that performance-based variable cash salaries for executive personnel have a motivational effect and that their implementation is beneficial for the Company and its shareholders in order to reach the Company's business strategy, long-term interests, and sustainable business practices.
The Company may demand variable cash salary 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.
Senior executives shall participate in the relevant local pension schemes in their countries of residence on the same terms as other employees. Pension benefits shall be based on local practices and applicable law.
Senior executives may be eligible for a mobile phone with subscription or reimbursable costs for use of mobile phone for business use and a medical insurance for the employee and his/her spouse and dependants.
Non-financial benefits shall be based on market terms and shall facilitate the duties of senior executives. The Company aims to have sufficiently competitive salary and incentive programs to minimize additional non-financial benefits. Premiums and other costs related to non-financial benefits may not exceed 5% of the annual fixed cash salary of each senior executive.
The Company may continue previous practices with Restricted Share Units (RSUs). In the view of the Board of Directors, such an attractive share-based long-term incentive program may form an important part of the total compensation for executive personnel and may be necessary to allow the Company to retain and hire the talent it needs for further growth.
Any RSUs or other share based incentive program will be subject to the prior approval by the general meeting. Grants of such instruments will be subject to approval by the Board of Directors pursuant to the terms and conditions of such programs.
Under the existing program, one Restricted Share Unit shall entitle the holder to receive one share of capital stock of the Company against payment in cash of the par value for the 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 maximum amount which may be granted in any financial year, under the scheme to any employee is an amount equal to a percentage of base cash salary of up to 100% for the CEO and upto 75% for the rest of the employees.
The executive management, depending on geography and applicable laws and practice, will typically have a three to six months' notice period. The notice period in senior executives' employment agreements shall not exceed six months.
Severance agreements shall be connected to confidentiality and anti-competitive clauses in the individual's employment contract, so that they compensate for restrictions in respect of his or her ability to take new work.
The Board of Directors may, on recommendation from the remuneration committee, in the circumstances described below resolve to deviate from any sections of these guidelines:
Any deviation from these guidelines shall be reported in the remuneration report for the relevant year.
Remuneration for executive management for 2021 consisted of both fixed and variable elements. The fixed elements consisted of salaries and other benefits (health and pension), while the variable elements consisted of a performance-based bonus arrangement and a restricted share unit scheme that was approved by the Board of Directors and the shareholders in the Annual General Meeting in 2021.
For 2021, the following was paid/incurred to the executives:
| 2021 | Short term benefits and pension costs | Long term benefits | |||||
|---|---|---|---|---|---|---|---|
| Amounts in 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 |
| Total | 800 | 926 | 17 | 11 | 1,754 | 221,668 | 640 |
Any bonuses that were incurred and paid in 2021 were approved by the Board of Directors during 2021. The bonus paid in 2021 related to the achievement of performance standards set by the Board of Directors for the financial year 2020. The total bonus includes 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.
Evaluation, award and payment of cash bonuses is generally performed in the year subsequent to financial year end, unless stated otherwise. Any bonuses for 2021 performance will be awarded in the year 2022 and determined based on the criteria set by the remuneration committee that includes meeting milestones of measurable strategic value drivers, progress on portfolio of assets, and certain corporate objectives including reduction of administrative overhead costs and HSE performance.
In 2021, the executives received base salaries and cash incentive bonuses in line with the executive remuneration policies as presented to the 2021 Annual General Meeting.
In June 2021, 528,356 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. 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 and the holder will be issued the applicable number of shares as soon as possible thereafter.
Share-based incentives are awarded in line with any shareholder approved program, and awards of share-based incentives will in value (calculated at the time of grant) be capped to 100% of the annual base salary for the CEO and 75% of the annual base salary for other members of the executive management.
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 2021 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. Additionally, we confirm to the best of our knowledge that the report "Payments to governments" as provided in a separate section in this annual report has been prepared in accordance with the requirements in the Norwegian Securities Trading Act Section 5-5a with pertaining regulations.
| JULIEN BALKANY |
TORSTEIN SANNESS |
GARRETT SODEN |
|||
|---|---|---|---|---|---|
| Chairman of the Board | Deputy Chairman of the Board | Non-Executive Director | |||
| ALEXANDRA HERGER | HILDE ÅDLAND |
JOHN HAMILTON | |||
| Non-Executive Director | Non-Executive Director | Chief Executive Officer |
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 2021 Annual General Meeting to acquire its own shares to a maximum of NOK 563,993.55 of share capital equivalent to 11,279,871 shares, each with a Nominal value of NOK 0.05. From the current year's authorisation, which is due to expire prior to the 2021 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).
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
Panoro Energy ASA is an independent exploration and production (E&P) company headquartered in London and listed on the Oslo Stock Exchange with ticker PEN. The Company holds production, development, and exploration assets in North and West 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 and OML 113 offshore western Nigeria, which is classified as held for sale. In addition, during 2021 the Company through its subsidiary has acquired a working interest in Block-G, offshore Equatorial Guinea that comprises two producing oil fields. The Company through its subsidiary has also entered into a farm-in agreement in Block 2B, offshore South Africa.
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 2021, Panoro Energy currently has three reportable segments with exploration and production of oil and gas, by geographic locations being Equatorial Guinea, Gabon and Tunisia.
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.
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.
Payment of dividends will be considered in the future, based on the Company's capital structure and dividend capacity as well as the availability of alternative investments.
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.
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.
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.
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.
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, whereof all members 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.
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.
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.
Currently the Audit Committee and the Remuneration Committee both consist of the complete Board. The reason for this is the rather low number of directors in the Company, which has led the Board to conclude that it is currently more efficient for the Board function that all directors also are members of committees. This practice will be further assessed in the future.
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.
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.
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.
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.
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.
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.
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.
| 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 | - | 4,219 | 13,313 | 4,000 | 121,212 | 51,563 | 31,491 | 294 | 16,530 | 8,266 | (21,155) | - |
| Total Equatorial Guinea |
- | 4,219 | 13,313 | 4,000 | 121,212 | 51,563 | 31,491 | 294 | 16,530 | 8,266 | (21,155) | - | |
| Pan-Petroleum Gabon B.V. |
Netherlands | 1,377 | 1,938 | - | 5,949 | 167,178 | 41,734 | 24,612 | (7,506) | 55,189 | 5,949 | (29,141) | - |
| Panoro Energy Gabon Production SA |
Gabon | - | - | - | - | - | - | - | - | - | - | 5 | - |
| Total Gabon | 1,377 | 1,938 | - | 5,949 | 167,178 | 41,734 | 24,612 | (7,506) | 55,189 | 5,949 | (29,136) | - | |
| Panoro Tunisia | |||||||||||||
| Exploration AS 12 |
Norway | - | - | - | - | 2,528 | - | 7,256 | - | (7,487) | - | (5,629) | - |
| Panoro TPS (UK) Production Limited 12 Panoro TPS |
UK | - | 1,339 | 3,351 | 42,498 | 26,360 | 14,318 | - | 11,777 | 7,390 | 37,674 | 16 | |
| Production GmbH -in liqui 12 |
Austria | - | - | - | - | - | - | (7) | 14 | 21 | (541) | (4,190) | - |
| Total Tunisia | - | 1,339 | 3,351 | - | 45,026 | 26,360 | 21,567 | 14 | 4,311 | 6,849 | 27,855 | 16 | |
| Panoro 2B Limited |
UK | - | - | - | - | - | - | 244 | - | (244) | - | (244) | - |
| Total South Africa |
- | - | - | - | - | - | 244 | - | (244) | - | (244) | - | |
| Panoro Energy ASA |
Norway | (60,706) | 5,385 | 66,389 | - | 241,719 | |||||||
| Sfax Petroleum Corporation AS 12 |
Norway | - | - | - | - | - | - | 218 | - | (218) | - | 16,884 | - |
| Panoro Energy AS 12 |
Norway | - | - | - | - | - | - | 2 | - | (2) | - | (326) | - |
| Panoro Tunisia Production AS 12 |
Norway | - | - | - | - | - | - | 121 | (14) | (7,603) | - | 15,506 | - |
| Panoro Energy do Brasil Ltda |
Brazil | - | - | - | - | - | - | 71 | - | (71) | - | (138) | - |
| Panoro Energy Limited |
UK | - | - | - | - | 467 | - | 6,878 | - | 64 | - | 1,102 | 12 |
| African Energy Equity Resources Limited |
UK | - | - | - | - | - | - | - | - | - | - | (84,431) | - |
| Pan-Petroleum (Holding) Cyprus Limited |
Cyprus | - | - | - | - | - | - | - | - | - | - | 178,706 | - |
| Pan-Petroleum Holding B.V. |
Netherlands | - | - | - | - | - | - | 120 | (19) | (139) | - | (733) | - |
| Panoro Energy Holding B.V. |
Netherlands | - | - | - | - | - | - | 1,313 | 5,262 | (1,615) | 14 | 157,853 | - |
| Energy Equity Resources AJE Limited |
Nigeria | - | - | - | - | - | - | - | - | - | - | 15,709 | - |
| 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 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 | - | - | - | - | 467 | - | (51,983) | 10,614 | 56,805 | 14 | 574,024 | 12 | |
| Pan-Petroleum AJE Limited |
Nigeria | - | 243 | - | 8,129 | 3,688 | 5,620 | (3,385) | (5,759) | - | (116,987) | - | |
| Pan-Petroleum Nigeria Holding B.V. |
Netherlands | - | - | - | - | - | 42 | (17) | (59) | - | (210) | - | |
| Pan-Petroleum Services Holding B.V. |
Netherlands | - | - | - | - | - | 57 | (14) | (71) | - | (249) | - | |
| Total Nigeria (held-for-sale) |
- | 243 | - | - | 8,129 | 3,688 | 5,719 | (3,416) | (5,889) | - | (117,446) | - | |
| Eliminations / Intercompany |
113,540 | (3,688) | 53,087 | - | (63,311) | - | (238,459) | ||||||
| Grand total | 1,377 | 7,738 | 16,664 | 9,949 | 455,552 | 119,657 | 84,737 | - | 63,391 | 21,078 | 195,439 | 28 |
Country/region of operation is the country where the company carries out its main activity.
Country of incorporation is the jurisdiction in which the legal entity is registered.
| 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 |
| 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 |
Panoro Energy ASA c/o Advokatfirma Schjødt, Ruseløkkveien 14, P.O. box 1444 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
2021 ANNUAL REPORT | APRIL 2022 Page: 131
www.panoroenergy.com
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