Annual Report • Apr 28, 2023
Annual Report
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| PetroNor E&P in brief 4 | |
|---|---|
| CEO letter 6 | |
| Portfolio8 | |
| Annual statement of reserves16 | |
| ESG report 25 | |
| Corporate governance 34 | |
| Board of directors 40 | |
| Management 44 | |
| Board of directors' report 47 | |
| Statement of remuneration 64 | |
| Financial statements 66 | |
| Statement of directors' responsibility 117 | |
| Independent auditor's report118 | |
| Contact 124 | |
16.83 per cent indirect participating interest in PNGF Sud offshore licence group.
13.1 per cent economic interest in Aje Field in licence OML113.
The Gambia A4 licence 90 per cent interest.
Guinea-Bissau Bissau 100 per cent interest in the Sinapa (Block 2) and Esperança (Blocks 4A and 5A) licences.
90 per cent operated interest in the Senegalese ROP and SOSP licences subject to arbitration.
PetroNor E&P ASA, listed on the Oslo Stock Exchange (PNOR), is an independent oil and gas company led by an experienced board and management team, with substantial experience in oil and gas exploration, appraisal, development, and production.
Our mission is to generate shareholder value by leveraging the technical and commercial skillset of the company to enhance our reserve base, production, and cash flow.
PetroNor E&P is committed to the highest standards of corporate governance, and to deliver operational excellence safely and efficiently.
Our strategic vision is to steadily build the company into a full cycle, Africa-focused exploration and production company with an emphasis on producing and developing assets with upside potential.
We are an independent oil and gas exploration and production company with multiple licenses in countries in West Africa – the Republic of the Congo, Guinea-Bissau, Senegal, The Gambia, and Nigeria. The company has amassed a diverse and highquality portfolio comprising economically robust production, development upside, and highly prospective exploration targets in West Africa.
During 2022, PetroNor has delivered several foundational milestones in our business. The ongoing infill drilling programme at the PNGF Sud field generated increased production capacity and, going into 2023, we report production levels not seen in the field for more than a decade. Our redevelopment plans for the Aje field advanced following the completion of our acquisition of Panoro's Energy ASA's interests, and our exploration portfolio made good progress.
As part of the infill drilling programme in Congo, four infill wells in the Litanzi field were successfully added during the year, producing with rates significantly above expectations. The rig subsequently drilled two infill producers in Tchibeli Northeast. The final allocated average net production from the PNGF Sud field complex during 2022 was 4,021 bopd, but following the addition of the increased well capacity from the infill program, average working interest increased to consistently greater than 5,200 bopd during 1st quarter 2023.
Separately, one Tchibeli NE well includes a deeper exploration target that discovered an oil column in the Vandji sandstones that is being evaluated to understand future regional potential.
The Dagda jack-up rig that successfully drilled four Litanzi wells and two Tchibeli wells during 2022 is now being repurposed and converted to a permanent production platform. Meanwhile the Axima jack-up rig that will take over drilling responsibilities on the infill drilling programme is currently operating for another partnership and is expected to return to work on the Tchibeli field in Q2 2023.
During the year, to mitigate delays to implementing a new oil sales agreement with ADNOC, the company re-established lifting arrangements with operators at the Djeno terminal. These arrangements delivered the lifting and sale of more than 800 thousand bbls during the 4th quarter at an average oil price of USD 90.99/bbl, generating fullyear revenue of USD 146 million, compared with USD 106 million in the previous year. The increase is driven by higher oil prices.
As a result, the group reported an EBITDA of USD 96.4 million for the year ended 31 December 2022, compared to USD 61.9 million in the same period in 2021. Net profit attributable to the equity holders of the parent more than doubled, from USD 12.3 million in 2021 to USD 26.9 million for the year ended 31 December 2022.
Strong cash flow from operating activities and new debt facilities resulted in a cash position of USD 24.8 million at year-end.
The long-awaited acquisition of Panoro's interest in Oil Mining Lease no. 113 offshore Nigeria was completed during the year, and PetroNor now has a seat at the licence group table. The acquisition of the ownership interest in the Aje field is strategically attractive and supports our stated growth strategy of acquiring assets that add production, material reserves, and resources to the company. The planned gas deliveries to onshore West Africa also represent opportunities within the ESG space. We are continuing with the work to finalise elements of the transaction with the licence operator, YFP. Meanwhile, work progresses on the Aje field re-development plan with partners and gas off-takers.
PetroNor has a portfolio of large scale exploration prospects in addition to those surrounding its fields in the Congo and Nigeria. In October 2022, the A4 licence in The Gambia was awarded to the Company and its partner, the Gambia National Petroleum Corporation (GNPC). PetroNor is the operator with a participating interest of 90 per cent, with GNPC holding 10 per cent.
The PetroNor exploration team have been consistent and passionate advocates for the potential of this part of the Atlantic margin. It is our shared objective
with our partner that these efforts will lead to a future drilling program.
Well planning for the Atum-1X exploration well are being advanced for the licences in Guinea-Bissau, based on encouragement from farm-out discussions.
In Senegal, the arbitration process to resolve the legacy licence dispute is completed and awaiting ruling.
With this as the backdrop, I would like to thank our team and our partners for their great efforts in 2022.
Although 2022 has been a year with good progress for PetroNor, the ongoing investigations from the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway and the Department of Justice in the US continue to represent a difficult backdrop for the company. As previously stated, the charges are brought against individuals and neither PetroNor nor other group companies have been charged.
I want to reiterate that the company takes compliance very seriously and has refreshed it's internal procedures consistent with a Norwegian governance model. The company has set up a dedicated board sub-committee to manage the company's response to the investigations and has engaged an independent law firm. Part of the agreed remit for this independent advisor has been to conduct a targeted fact-finding process. A summary from this process is being reviewed by the PetroNor board and has been shared with the investigating authorities consistent with the company's stated policy of co-operation. At the time of writing this report, there are no further updates in relation to the progress of the investigations.
– PetroNor E&P is well positioned to deliver shareholder value from both its existing portfolio and new opportunities.
The success of our infill well investments achieved during 2022 has given evidence to the longterm reserve growth that is possible from our producing assets. The cash flow from oil sales funds these investments and supports our development and exploration assets. In addition the company continues to consider inorganic growth opportunities. As our production is largely unleveraged, we have an opportunity to leverage further to execute on value-accretive M&A opportunities. The board is also considering other approaches to deliver value for shareholders as our cash position strengthens.
Sincerely, Jens Pace Interim CEO PetroNor E&P
The Republic of Congo (Congo Brazzaville) is the third largest producer of crude oil in Sub-Saharan Africa after Nigeria and Angola, representing around 90 per cent of the exports of the country. The majority of the production in Congo is located offshore, with approximately half in deep water. Congo Brazzaville is an established oilproducing country and a core country for PetroNor, both for production as well as for regional development.
PetroNor holds a 16.83 per cent indirect participation interest in the licence group of PNGF Sud (Tchibouela II, Tchendo II and Tchibeli-Litanzi II) through Hemla E&P Congo SA. In addition, the group holds a right to negotiate, in good faith, along with the contractor group of PNGF Sud, the terms of the adjacent licence of PNGF Bis. If the group is able to secure entry into a production sharing contract, the group expects to be granted a 23.6 per cent indirect interest in PNGF Bis.
PNGF Sud is operated by Perenco, a world-leading specialist in low-cost brownfield optimisation of mature production assets like PNGF Sud.
Production has continued to grow and operating cost per unit production has been significantly reduced, all achieved through improving maintenance routines, production processing capacities along with field integrity investments in a stepwise and prudent manner.
Tchendo debottlenecking adding (40 kbwpd) water treatment capacity and export pumps (3x20 kbfpd) to allow additional fluids from both Tchendo and Litanzi.
The license partnership is now well underway on its announced 17 well infill drilling programme with a three-year investment programme of some USD 400 million to deliver increased production and reserves.
Since the entry of the new contractor group in early 2017, incremental improvements via well workovers, surface production process improvements and structural integrity and HSE improvements have resulted in year-on-year growth in production at a
relatively low CAPEX spending. The goal has been to optimise the existing well stock by re-activating producers and injectors, re-allocating production intervals, increasing well lift capacities as well as increasing and managing production capacities and intra-field power consumption between the 8 wellhead-platforms in PNGF-Sud.
The average gross PNGF production was 23,891 bopd in 2022 with a continued low lifting cost of \$12.4/bbl. The workover programme continued successfully in 2022. On the surface side, significant investments were made on additional water handling capacity, additional export pumps plus starting the commissioning on additional generators for intra-field power generation. Correspondingly, integrity improvements were made on several steel structures.
The 17 well infill drilling programme started in 2021. A total of 6 wells on Litanzi and Tchibeli NE were drilled between November 2021 and November 2022. Drilling progress was initially significantly delayed due to failure of equipment such as the top-drive system and generators. The effect of these delays on the field was however offset by significantly better production performance than expected including the addition of an exploration discovery in the pre-salt (Vanji) in Tchibeli NE which was immediately put on production.
Production capacity thus increased from an average 20.6 kbopd in 2021, via an average 2022 production of 23.9 kbopd to a current production capacity significantly above 30 kbopd in the initial period of 2023. The drilling rig used for the drilling of these two campaigns, Petrofor Dagda, has now been converted to a production platform in Tchibeli NE and the derrick has been removed. Another jack-up rig, the Petrofor Axima, is currently drilling a four well campaign for Perenco before returning to continue the planned infill drilling programme on Tchibeli and Tchendo expected to start in the second quarter of 2023. Also planned in 2023 is the commissioning of a refurbished 14 slot production jack-up to be added to Tchendo in the second half of the year.
Located North-West of PNGF Sud, PNGF Bis license contains two discoveries, Louissima and Loussima SW. The two discoveries are proven by three wells drilled between 1985 and 1991. The partnership has a right to negotiate the licence on given terms, such negotiations would see PetroNor receive a 23.6 per cent indirect participation in PNGF Bis.
The three discovery wells tested from 1,150 to 4,700 bopd of light, good quality oil. Perenco has recently made a detailed reinterpretation, 3D modelling and facilities study for the Loussima SW discovery, yielding >100 MMbbl of in-place resources and a possible tie-back to PNGF Sud via pipeline.
AGR Petroleum Services warrants 2C resources of 29 MMbbl including verification of the tie-back scenario given above.
Nigeria is one of the most petroleum-rich nations in the world. Nearly all of the country's primary reserves are concentrated in and around the Niger Delta. Nigeria is one of the few major oil producing nations still capable of increasing its oil output.
The Aje field is located close to the Lagos shores of Nigeria, a populated area in dire need of affordable electrical power. It is estimated that Nigeria produces electrical power from some 20-30 million diesel generators around the country and the Lagos area alone has a population exceeding 27 million people. The Aje field constitutes a significant gas discovery which has the potential of supplying cleaner, reliable and more affordable gas to power to this region of the country. Additional LPG products extracted from the gas yields cooking gas for the local area replacing wood burning for cooking.
The Aje Project targets production of oil, gas, condensate, and LPG., which will replace approximately 500MW currently generated by diesel power and also provide 10 per cent of the country's cooking gas. As such, it has an attractive ESG profile consistent with PetroNor's values and longer-term goals.
In January 2022, PetroNor received from the Nigeria Upstream Petroleum Regulatory Commission (NUPRC replacing the DPR) the approval for the transaction between Panoro Energy and PetroNor for the acquisition of all its interest in the Aje Field asset. This transaction was completed with Panoro in July 2022. PetroNor now directly holds 6.502 per cent participating interest, with a 16.255 per cent cost-bearing interest, representing an economic interest between 12.1913 per cent and 16.255 per cent in OML 113, containing the Aje oil and gas field.
Aje Production AS is being created as a joint venture between PetroNor and Yinka Folawiyo Petroleum Deep Water Limited ("YFP-DW") and this venture will lead the technical and management efforts in the next phase of the Aje field development. PetroNor will contribute the acquired interest in Aje, and YFP-DW will contribute all interest in Aje to the Aje Production JV.
PetroNor's ownership will be 52 per cent in Aje Production which will hold a 15.5 per cent participating interest and an economic interest in the order of 38.755 per cent in OML 113 during the majority of the project period. YFP has undertaken to align its voting rights with Aje Production's objectives in the development of the Aje field.
The Aje Field was discovered after drilling of the Aje-1 well in 1996. The OML-113 block covers 835 km² with water depths ranging from 100m to 1,500m. Five wells have been drilled; oil production is from Turonian and Cenomanian age reservoirs. Overlying the Turonian oil rim is a significant gas-condensate discovery which has not been developed.
The development plans will target the gas, condensate, and oil in a low-risk development plan. Wet gas will be brought to shore for further processing and extraction of LPG. The Nigerian government encourages stop-flaring programmes and the country is in dire need of electrical power.
According to the UN sustainability goals, gas is an important transition fuel for Africa. Thus, in addition to closing down existing gas flaring in the field and piping additional gas to shore, this is in sum a particularly ESG-friendly project in these parts of the world.
Development plans for the Aje gas condensate and additional oil are under discussion jointly with the license partners. The plan is to proceed toward an FID involving changeout of the FPSO, drilling further gas and oil development wells, building a 30 km pipeline to shore to a receiving LPG plant close to the export compressor station of the West African Gas Pipeline (WAGP). Condensate and oil will be produced and offloaded offshore while offtake agreements will include gas sales and swap arrangement for gas and LPG products. The previous FPSO was released from the field as it has reached the end of economic field life and does not have the proper ratings for gas development.
Albeit delayed, significant progress has been made on negotiations of gas offtake contracts and the company is moving forward both in our discussions with license partners and relevant financing institutions.
PetroNor hopes to progress the project toward final investment decision late 2023.
The landmark Lagos bridge in Nigeria.
PetroNor has amassed a highly attractive exploration portfolio across the MSGBC (Mauritania-Senegal-The Gambia-Guinea-Bissau-Conakry) basins.
Following acquisition of the Sinapa (Block 2) and Esperança (Blocks 4A and 5A) licenses offshore Guinea Bissau in May 2021. PetroNor assumed operatorship and an interest of 78.57 per cent in both licenses. The two main prospects, Atum and Anchova, are commercially attractive, low risk prospects, with net unrisked, combined summed mean recoverable, prospective resources of 467 MMbbl for upper and lower Albian targets (PetroNor estimate). Oil has already been discovered on the Sinapa licence, Atum and Anchova prospects are analogous to the Sangomar field to the North along the margin in Senegal. Success at Atum-1X will be a highly significant play extending well and will open up further exploration activity in the country.
PetroNor has completed interpretation of the 3D seismic data across both licences and is seeking partners to participate in the drilling of the Atum-1X well.
The purchase of SPE Guinea Bissau AB from Svenska Petroleum Exploration AB received formal in-country governmental approval in late April 2021. Subsequently, in May 2021, the Svenska subsidiary was formally renamed PetroNor E&P AB. The current exploration phase of both Guinea-Bissau licences end in October 2023. All minimum financial commitments have been met but the drilling obligation is outstanding.
PetroNor has re-initiated planning for drilling the Atum-1X well, building on extensive preparation work carried out by the previous operator, supported by EXCEED Energy based in Aberdeen. Long lead items required for drilling operations were already secured before PetroNor took over operatorship and a number of key pre-drill studies have now been completed and more are underway. EXCEED and PetroNor are fully engaged in drilling preparations whilst continuing efforts to secure a partner.
In November 2022, the company was awarded a new 30-year lease for the A4 licence with terms based on the newly developed Petroleum, Exploration and Production Licence Agreement – PEPLA model. A proportion of prior sunk costs associated with Block A4 have been carried into the new agreement. The first three-year period of the licence has been split into two 18 month periods. The first period involves an extensive work program with a drill or drop decision in May 2024.
PetroNor has licenced additional 3D PSDM seismic data (TGS Jaan 3D) to give an enhanced regional perspective and to better understand recent well results both successes and failures in this part of the MSGBC Basin. PetroNor is seeking a partner to join the company in drilling one exploration well in this highly attractive acreage 40kms to the South of the Sangomar fieldin Senegal. The key prospects in A4 are the 'Lamia-South' prospect (net mean prospective recoverable resource 295mmbo) and the 'Rosewood' prospect (net mean prospective recoverable resource 350 mmbo), both with commercial volumes and attractive probability of success. PetroNor considers Lamia South to be a genuine analogue for the Sangomar Field (unlike recent wells in adjacent acreage). PetroNor aims to participate in any future well at an equity level of 30-50 per cent and hopes to drill in 2024 upon entering the second phase of the first exploration period.
The Senegal Offshore Sud Profond and Rufisque Offshore Profond licences were awarded to the company in 2011. In July 2018, the company registered arbitration proceedings with the International Centre for Settlement of Investment Disputes (ICSID) (case ARB/18/24) to protect its interests in the licenses. The arbitration was held in Paris in March 2022. The company awaits the final arbitration ruling.
Senegal
Net working interest:
Area in km2:
15,796
Petroleum Senegal Ltd
PetroNor'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-2007), sponsored by the Society of Petroleum Engineers / World Petroleum Council / American Association of Petroleum Geologists/ Society of Petroleum Evaluation Engineers (SPE/PRMS) from 2007 and 2011.
Reserves are the volume of hydrocarbons that are expected to be produced from known accumulations:
Reserves are also classified according to the associated risks and probability that the reserves will be 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 PetroNor'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 AGR Petroleum Services AS ("AGR") in March 2023 for PNGF Sud and PNGF Bis (2023 AGR CPR). For OML113 (Aje), reserves and resources are based on a CPR from AGR/Tracs from March 2019.
The group holds exploration and production assets in Africa through subsidiaries and joint ventures, namely the offshore PNGF Sud production licenses in the Republic of Congo, the Sinapa (Block 2) and Esperança (Blocks 4A and 5A) licenses offshore Guinea-Bissau, the A4 license offshore The Gambia. The group reserves its rights to the Rufisque Offshore Profond and Senegal Offshore Sud Profond licences offshore Senegal, which are currently in arbitration. In July 2022, PetroNor completed the purchase of Pan-Petroleum Nigeria Holding BV and Pan- Petroleum Services Holdings BV that together hold 100 per cent of the shares in Pan-Petroleum Aje Ltd ("Pan Aje"), representing an economic interest between 12.1913 per cent and 16.255 per cent in OML 113. This transaction is now part of this annual statement of reserves ("ASR").
The exploration assets in Guinea-Bissau, The Gambia and Senegal only constitute prospective resources, therefore are not considered part of this ASR.
PNGF Sud is a development and exploitation license comprising three (3) production license agreements (Tchibouela II, Tchendo II and Tchibeli-Litanzi II), which contain six oil fields: Tchibouela Main, Tchibouela East, Tchendo, Tchibeli, Tchibeli North East and Litanzi.
PetroNor E&P's indirect subsidiary, HEPCO, holds a 20 per cent (16.83 per cent net to PetroNor) nonoperated interest in the PNGF Sud licenses offshore Congo. The operator of the licenses is Perenco which holds a 40 per cent interest in the PNGF Sud licenses. Effective since 1 January 2017, the ownership of the licenses has an expiry date after 20 years plus a 5-year extension period.
Since granting of the licenses, Perenco, with partner support has been committed to strict HSE compliance while growing production, improving maintenance routines and field integrity in a stepwise and prudent manner.
In November 2021, the 17 well infill programme commenced on PNGF Sud with four infill wells on Litanzi. In November 2022, two wells were completed in Tchibeli North East. Production ramped up significantly in 2022 in response to the infill drilling programme. The year ended with a December production of 30.344 bopd (5,107 net to PetroNor). Three or four wells are expected to be drilled on Tchibeli in the second quarter of 2023.
Gross production during 2022 was 8.72 MMbbls of oil and 8.3 Bcf of gas. This corresponds to average 23.891 bopd and 22.7 mmscfd.
In March 2023, AGR performed a full competent persons report (CPR) covering the reserves (1P, 2P and 3P) and resources (1C, 2C and 3C) in both PNGF Sud and PNGF Bis. The above figures were evaluated as of 31 December 2022.
As per the PRMS/SPE guidelines, only the portion of gas is contributing to power generation (on Tchibouela and Tchendo only) and is included in the overall reserves in the AGR CPR. The gas is being used centrally in the field complex as fuel for power-generating turbines which is subsequently transmitted to the individual field platforms via electrical power cables. For the purpose of this report, the numbers quoted below as MMbbls do not include the oil equivalent gas but are included in the appendix reserves and resource tables.
This PetroNor ASR uses as the basis the reserves and resources from the 2023 AGR CPR yielding reserves and resources as per 31 December 2022. As the only product sold is oil, PetroNor will in the text below when referring to reserves and resources mainly refer to oil and term these with the unit MMbbls or including condensate, LPG and gas as oil equivalents MMboe.
As at 31 December 2022, AGR evaluated that gross 1P proved reserves yield 74.5 MMbbls in all of the PNGF Sud fields in the Cenomanian, Turonian, Senonian and Albian reservoirs. Gross 2P proved plus probable reserves at PNGF Sud amounted to 110.0 MMbbls in the same reservoirs. Gross 3P proved plus probable plus possible reserves at PNGF Sud amounted to 146.5 MMbbls.
Gross 1C resources yield 25.5 MMbbls in all of the PNGF Sud fields in the Cenomanian, Turonian, Senonian and Albian reservoirs. Gross 2C resources at PNGF Sud amounted to 42.0 MMbbls in the same reservoirs. Gross 3C resources at PNGF Sud amounted to 72.3 MMbbls.
These evaluations yield 1P proved reserves net to PetroNor of 12.5 MMbbls, 2P proved plus probable reserves net to PetroNor of 18.5 MMbbls and 3P proved plus probable plus possible reserves net to PetroNor of 24.7 MMbbls.
Additional potentially recoverable resources net to PetroNor are approximately 4.3 MMbbls 1C, 7.1 MMbbls 2C and 12.2 MMbbls 3C.
These reserves and contingent resources are PetroNor's net volumes before deductions for royalties and other taxes, reflecting the production and cost sharing agreements that govern the assets.
Located North-West of PNGF Sud, PNGF Bis license contains two discoveries, Louissima and Loussima SW. The two discoveries are proven by three wells including DST's drilled from 1985-1991. The primary potential is identified in the pre-salt Vanji formation with promising DST rates, but the exploration and appraisal wells also include an oil column in the post-salt Senji fm (not tested).
The contractor group of PNGF Sud has not yet secured the rights to carry out petroleum activities on PNGF Bis however a likely scenario comprises a long-term test production period with a rented jack-up with a purchase option and an 11 km pipeline tie-back to one of the existing Tchibouela process platforms. This would allow cost recovery of the investments during the test production and allows upscaling the production levels with additional producers as resources are matured to reserves.
Net to PetroNor 1C contingent resources yield 5.3 MMbbls in the Loussima SW Vanji and Senji fm. Net 2C at PNGF Bis Loussima SW amounts to 6.8 MMbbls in the same reservoirs. Net 3C amounts to 8.4 MMbbls.
PetroNor uses the services of AGR Petroleum Services for 3rd party verifications of its reserves and resources.
All evaluations are based on standard industry practice and methodology for production decline analysis and reservoir modelling based on geological and geophysical analysis. The following discussions are a comparison of the volumes reported in previous reports, along with a discussion of the consequences for the year-end 2022 ASR:
During the years from 2017 to 2022, production and reserves have grown from the initial c. 15,000 bopd and 62 mmbo when Perenco and partners took over. An additional c. 47 mmbo has been produced in the period, thus representing a reserve replacement ratio of more than 200 per cent for the period. This has materialised through revitalising existing producers via replacements or upsizing of electrical submersible pumps (ESP's), acidizing, clean up or reperforating wells or converting wells from the Cenomanian to the Turonian (less depleted) formations. Significant surface debottlenecking is also taking place, projects ranging from improved power generation, gas-lift compressor upgrades, pump replacements and other surface process improvements. Production from Tchibeli has been routed to Tchendo by installing a new pipeline to avoid third party processing tariffs previously paid to the Nkossa FPSO. These brick-by-brick improvements together with infill drilling have yielded a production level during 2022 of 23,891 bopd. The production improvements alone have yielded more than a 100 per cent reserves replacement each year at a cost of less than 1 USD/bbl. An infill drilling program was decided for the Litanzi field in 2019 and in 2020 for Tchendo and Tchibeli. Development drilling of the Tchibeli NE discovery was further sanctioned in 2021. Consequently, the 2C resources in these fields have been converted to 2P reserves. Development of 3D static and dynamic models has been and will continue to form the basis of further infill drilling programmes on PNGF Sud. As part of the commitment to infill drilling, significant 2C resources have been transferred to 2P reserves on Litanzi, (in 2019), Tchendo, Tchibeli and further in Tchibeli NE. The infill potential in Tchibouela and Tchendo has been maintained with a significant 2C potential. Further gross/net 2C resources of 9.3/1.6 mmbo were added in the 2023 AGR CPR in Tchibouela East in response to identifying infill drilling potential for another 5 wells in the field.
Gross produced volumes during 2022 constituted net/gross 1.5/8.7 MMbbls. Only minor adjustments were made to 2P reserves for 2022, with a decrease of net/gross -0.6/-3.4 mmbo attributed to production adjustments. 2C resources have increased by 1.6/9.3 to 13.9/70.9 MMbbls, primarily for additional infill potential in Tchibouela East.
The PNGF partnership is investing in additional power generation facilities on Tchiboela and Tchendo. According to PRMS, gas reserves for this should be classified as reserves. Total gas reserves attributed to power generation has been estimated at 9.9/59.0 bcf, corresponding to 1.8/10.5 mmboe in the reserve's balances.
Production rates are reported by AGR to increase significantly in 2023 and 2024 to respectively 32,550 and 33,100 bopd.
Subject to agreement with the government and investment decisions on the Loussima SW project, these reserves may become reserves approved for development. The 2C resources in PNGF Bis have been reaffirmed by AGR as part of this years' reserves and resource audit without change to the numbers. It is expected that these discoveries will have priority following the infill drilling programmes in PNGF Sud.
Given a successful Loussima SW, a similar development potential is also likely for the Loussima Discovery.
As part of the completion with Panoro on this transaction, reserves and resources from this license are included in PetroNor's balances. Reserves and resources are based on a CPR from AGR/Tracs from March 2019. As the bulk of these are 2P reserves based on a Field Development Plan (FDP) submitted to and approved by the Nigerian Upstream Petroleum Regulatory Commission (NUPRC, formerly DPR) in 2018 and the current development plan will need a resubmission and approval, PetroNor assumes the same reserves now to be contingent resources. The relatively insignificant production in the period 2019 to 2021 are subtracted from these numbers. Revenue and cost-bearing interests vary through the development production period from 12.2 per cent and 16.3 per cent and net resources have been modelled and listed in the tables below. The 2C resources net to PetroNor are 9.7 mmbo of liquids and 79 bcf of gas, in total 22.8 mmboe. (AGR Tracs use 6 mscf/boe).
The commerciality and economic tests for the PNGF Sud, PNGF Bis and Aje reserves and resources volumes were based on an oil and condensate price of 70 USD/bbl, although the reserves and resources are not very sensitive to this parameter as OPEX levels are currently at 10-12 USD/bbl in PNGF and estimated at ca 7 USD/bbl in Aje on plateau production.
| (MMboe) | 2021 | 2022 | 2022 PN Net |
|---|---|---|---|
| Balance – gross AGR, PNGF Sud | 123.3 | 120.5 | 20.3 |
| 2P and 2C Reserves and Resources Status | |||
| (MMboe) | 2021 | 2022 | 2022 PN Net |
| 158.4 | 164.9 | 27.8 |
|---|---|---|
| 187.3 | 193.8 | 34.6 |
| 339.0 | 57.3 | |
PetroNor's total 1P Reserves at the end of 2022 amounted to 14.3 MMbbls. PetroNor's 2P Reserves amount to 20.6 MMbbls and PetroNor's 3P Reserves amount to 26.61 MMbbls. This reflects the 6 April 2022 reserve report for the PNGF Sud field, conducted by AGR Petroleum Services AS and production since the field start-up.
PetroNor's Contingent Resource base includes discoveries of varying degrees of maturity towards development decisions. By the end of 2022, PetroNor's assets contain a total 2C volume of approximately 12.3 MMbbl.
28 April 2023
JENS PACE Interim CEO PetroNor E&P
| 1P 2P |
3P | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo |
Gas bcf |
Boe mmboe |
||||||
| 100% PNGF Sud | ||||||||||||||
| Tchibouela | 38.02 | 31.50 | 43.63 | 48.52 | 37.85 | 55.26 | 59.87 | 43.68 | 67.65 | |||||
| Tchibouela East | 2.39 | 2.39 | 3.29 | - | 3.29 | 4.30 | 4.30 | |||||||
| Tchendo | 14.48 | 13.03 | 16.80 | 23.53 | 21.17 | 27.30 | 31.75 | 21.51 | 35.58 | |||||
| Tchibeli | 7.12 | - | 7.12 | 14.02 | - | 14.02 | 21.57 | - | 21.57 | |||||
| Tchibeli Northeast | 4.87 | - | 4.87 | 9.56 | 9.56 | 14.86 | - | 14.86 | ||||||
| Litanzi | 7.64 | - | 7.64 | 11.06 | - | 11.06 | 14.16 | - | 14.16 | |||||
| Subtotal | 74.52 | 44.53 | 82.45 | 109.98 | 59.02 | 120.49 | 146.51 | 65.19 | 158.12 | |||||
| 100% PNGF Bis Loussima (Bis) |
- | - | - | - | - | - | - | - | - | |||||
| Total | 74.52 | 44.53 | 82.45 | 109.98 | 59.01 | 120.49 | 146.51 | 65.19 | 158.12 |
| 1C 2C |
3C | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo | Gas bcf |
Boe mmboe |
|
| 100% PNGF Sud | |||||||||
| Tchibouela | 13.60 | 8.90 | 15.19 | 21.20 | 13.80 | 23.66 | 34.10 | 22.30 | 38.07 |
| Tchibouela East | 6.45 | - | 6.45 | 11.61 | - | 11.61 | 18.93 | - | 18.93 |
| Tchendo | 5.40 | - | 5.40 | 9.14 | - | 9.14 | 19.20 | - | 19.20 |
| Tchibeli | - | - | - | - | - | - | - | - | - |
| Tchibeli Northeast | - | - | - | - | - | - | - | - | - |
| Litanzi | - | - | - | - | - | - | - | - | - |
| Total | 25.45 | 8.90 | 27.04 | 41.95 | 13.80 | 44.41 | 72.23 | 22.30 | 76.20 |
| 100% PNGF Bis Loussima (Bis) |
22.40 | - | 22.40 | 28.90 | - | 28.90 | 35.80 | - | 35.80 |
| OML 113 | |||||||||
| Aje | 35.65 | 292.70 | 84.43 | 63.05 | 492.80 | 145.18 | 104.45 | 791.90 | 236.43 |
| Total | 83.50 | 301.60 | 133.87 | 133.90 | 506.60 | 218.49 | 212.48 | 814.20 | 348.43 |
| 1P | 2P | 3P | |||||||
|---|---|---|---|---|---|---|---|---|---|
| Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo | Gas bcf |
Boe mmboe |
|
| 16.83% PNGF Sud | |||||||||
| Tchibouela | 6.40 | 5.30 | 7.34 | 8.17 | 6.37 | 9.30 | 10.08 | 7.35 | 11.39 |
| Tchibouela East | 0.40 | - | 0.40 | 0.55 | - | 0.55 | 0.72 | - | 0.72 |
| Tchendo | 2.44 | 2.19 | 2.83 | 3.96 | 3.56 | 4.59 | 5.34 | 3.62 | 5.99 |
| Tchibeli | 1.20 | - | 1.20 | 2.36 | - | 2.36 | 3.63 | - | 3.63 |
| Tchibouela East | 0.82 | - | 0.82 | 1.61 | - | 1.61 | 2.50 | - | 2.50 |
| Litanzi | 1.29 | - | 1.29 | 1.86 | - | 1.86 | 2.38 | - | 2.38 |
| Subtotal | 12.55 | 7.49 | 13.88 | 18.51 | 9.93 | 20.27 | 24.65 | 10.97 | 26.61 |
| 23.56% PNGF Bis Loussima (Bis) |
- | - | - | - | - | - | - | - | - |
| Total | 12.55 | 7.49 | 13.88 | 18.51 | 9.93 | 20.27 | 24.65 | 10.97 | 26.61 |
| 1C | 2C | 3C | |||||||
|---|---|---|---|---|---|---|---|---|---|
| Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo | Gas bcf |
Boe mmboe |
|
| 16.83% PNGF Sud | |||||||||
| Tchibouela | 2.29 | 1.5 | 2.56 | 3.57 | 2.32 | 3.98 | 5.74 | 3.75 | 6.41 |
| Tchibouela East | 1.09 | - | 1.09 | 1.95 | - | 1.95 | 3.19 | - | 3.19 |
| Tchendo | 0.91 | - | 0.91 | 1.54 | - | 1.54 | 3.23 | - | 3.23 |
| Tchibeli | - | - | - | - | - | - | - | - | - |
| Tchibouela East | - | - | - | - | - | - | - | - | - |
| Litanzi | - | - | - | - | - | - | - | - | - |
| Subtotal | 4.29 | 1.5 | 4.56 | 7.06 | 2.32 | 7.47 | 12.16 | 3.75 | 12.83 |
| 23.56% PNGF Bis | |||||||||
| Loussima (Bis) | 5.28 | - | 5.28 | 6.81 | - | 6.81 | 8.44 | - | 8.44 |
| OML 113 | |||||||||
| Aje | 5.35 | 45.70 | 12.97 | 9.66 | 78.70 | 22.78 | 14.49 | 111.50 | 33.08 |
| Total | 14.92 | 47.20 | 22.81 | 23.53 | 81.02 | 37.06 | 35.09 | 115.25 | 54.35 |
As PetroNor continues to grow and develop, we will continue to work to ensure that our business is aligned with ESG objectives, addressing both the legal requirements and the expectations of our stakeholders. PetroNor strongly believes that the ability to create long-term and lasting values is based on maintaining high standards in governance, operations, and business practices.
During 2023, PetroNor will further strengthen its ESG-strategy, and will report according to international standards also common in the oil & gas industry, such as GRI (Global Reporting Initiative) and TCFD (Task Force on Climate-Related Financial Disclosures), to ensure that the company's efforts are documented in a reliable and accessible manner. The company will also commit to global guidelines, such as the UN Sustainable Development Goals.
To enable the above, the company has started a structured process to assess the sustainability reporting, acknowledging new and strengthened legislation in ESG. This process shall ensure that policies, internal systems, and procedures comply with the requirements of relevant acts.
As Russia invaded Ukraine in 2022, energy security became a part of the equation to create a sustainable energy system for the world and created disruption in the energy supply to Europe in particular. The energy transition continues its momentum though, as policies for replacing hydrocarbons with renewables help make each country less dependent on imported energy. Further, climate change poses tangible risks to the planet and humanity.
Nations in Africa have been less exposed to the turmoil in energy prices in Europe. However, affordable clean energy for the environmental and socioeconomic development of the countries in Africa remains a priority. This was also part of the discussions in COP27 in Sharm El-Sheik in Egypt in December 2022. COP 27 had high on its agenda the financing of sustainable energy systems in
developing countries, including Africa. One result is the establishment of a fund to aid countries facing severe damage from climate change.
PetroNor's current operations are all located in West Africa. The company believes that credible operators such as PetroNor have a key role to play in delivering a smooth and steady transition that enables the African continent to continue to benefit from its natural resources until a more viable and fully sustainable solution is ready.
Natural gas is recognised as an important transition fuel for Africa. In that context, PetroNor's ownership and instrumental role in the Aje license offshore Nigeria are expected to contribute positively in ESG terms for countries connected to the West African Gas Pipeline (WAGP). The Aje field ceased production and thus gas was flared in 2022. PetroNor is seeking to provide technical advice to the partnership, and aims to re-develop the field providing natural gas into the WAGP, as well as LPG to the Nigerian market. By engaging in these activities, PetroNor will assist in lowering harmful emissions in the region.
Debt financing of the oil and gas industry has gradually become more demanding. Any energy company in the sector has to demonstrate a track record of sound operations with regards to ESG to secure debt financing. PetroNor is taking this challenge seriously, conducting its operations in a prudent manner and so addressing these demands, as well as diligently reporting on the same.
The integrity of the capital markets is based on full and fair disclosure of information. The company treats all shareholders equally and seeks to provide consistent and transparent information to ensure fair treatment of all stakeholders.
On 1 July 2022, Norway enacted a new Transparency Act. The main purpose of the Transparency Act is to promote enterprises' respect for fundamental human rights and decent working conditions in connection with the production of goods and the provision of services. The Act shall also ensure the general public's access to information regarding how enterprises address adverse impacts on fundamental human rights and decent working conditions. As a result, the company shall publish the required statement in accordance with the guidelines of the Act. Further, the company will provide adequate measures and arrangements to support the requirements of the Act.
PetroNor will publish a statement on due diligence in accordance with the Norwegian Transparency Act by June 2023. The statement will be published on the company website.
PetroNor endeavours to conduct all operations in an environmentally responsible manner. As an operator of offshore concessions, it is the duty of PetroNor to minimise any adverse impact on the environment. It is the company's policy to manage all activities in a responsible manner, in accordance with the principles of sustainable development.
PetroNor is well aware that climate change is high up on the political agenda. As a consequence, new laws and regulations could have a material impact on the company's business. Additional legal and/or regulatory measures could result in project delays or cancellations, a decrease in demand for fossil fuels and additional compliance obligations. Each of these issues could materially and adversely impact the company's costs and/or revenues. Another example would be sustained lower oil and gas prices or price declines which may inter alia lead to a material decrease in net production revenues.
As part of an overall structured process to strengthen its ESG efforts, PetroNor will integrate climate risk to its risk management system and report according to TCFD. Climate risk will be an important aspect of financial and internal control going forward, as well as short- and long-term strategic planning and business development.
Carrying out environmental impact assessments (EIA) prior to all major activities is one way
PetroNor seeks to minimise any adverse impact on the environment. The company communicates the results to all government agencies and other relevant stakeholders. This later effort is also part of the obligations in the new Norwegian Transparency Act.
Further, PetroNor will ensure that environmental management plans are in place and that their implementation is regularly monitored. The company will continually review and update procedures regarding protection of the environment to ensure they are valid and appropriate. Contingency plans are in place to swiftly mitigate any potential damage to the environment. As a part of the management plans, PetroNor will establish a plan for climate accounting and start reporting on the company's emissions.
To the best of the company's knowledge, all operations have been conducted within the limits set by approved environmental regulatory authorities. The company is aware of its environmental obligations with regards to its exploration activities and ensures that it complies with the relevant environmental regulations when carrying out any exploration work.
During 2022, there have been no significant known breaches of the environmental regulations in place for the group's exploration and production licenses.
As stated in its published code of conduct, PetroNor is committed to conducting business in a manner which respects human rights as set out in the UN Universal Declaration of Human Rights. The company seeks business partners and contractors who follow equivalent high standards, which is also part of the obligations in the new Norwegian Transparency Act. In 2023, the company will establish a tactical plan on how to verify that partners and suppliers are prudent in the protection of human rights.
The company has a zero-tolerance approach to modern slavery and child labour in any part of the organisation and supply chains. PetroNor strives to ensure that all workers have safe, secure, and healthy working conditions. The workplace shall be free from any form of harsh or inhumane treatment.
PetroNor's customers, contractors, subcontractors, and suppliers shall not engage in or use child labour. Applicable national laws shall be complied
with, and only workers who meet the applicable minimum legal age requirement shall be employed.
The PetroNor management must ensure that all PetroNor representatives (employees, directors, consultants, etc.) are treated fairly. It is the responsibility of the management to monitor practices and attitudes that may lead to acts of harassment in the workplace.
We expect our business partners and suppliers to comply with applicable laws, respect internationally recognised human rights and adhere to our ethical standards when conducting business with or on behalf of PetroNor. The company's standard service agreement oblige the contractor to comply with the company's code of conduct where standards regarding human rights are declared.
The company continues to follow-up its "know your supplier policy", using adequate judgement and appropriate software to help make sure that it only does business with organisations and individuals that share its standards for compliance and integrity.
PetroNor must refuse to do business with, and provide no assistance to, those who engage in illegal conduct related to PetroNor's business.
In 2022, there were no cases identified in the group nor its supply chains that were in violation of human rights.
Health and safety policies are essential for PetroNor with the goal of avoiding accidents and incidents and performing all its activities with focus on and respect for people. The company's objective for health, environment, safety, and quality (HSEQ) is zero accidents and zero unwanted incidents in all activities.
PetroNor's representatives frequently travel to hold meetings or visit installations in connection with held and prospective oil and gas assets. The company focuses on oil and gas assets located in West Africa. The group seeks to ensure adequate safety levels for management and employees travelling whether in Africa or elsewhere.
As part of the efforts to achieve social acceptability, PetroNor aims to work closely alongside local partners to improve the lives of the communities it operates in.
With its non-operated licenses, PetroNor is dependent on the efforts of the operators with respect to achieving prudent ESG-performance. However, the company has chosen to take an active role in all license committees with the conviction that high safety standards are the best means to achieve successful operations. Through this involvement, PetroNor can influence the choice of technical solutions, vendors and quality of applied procedures and practices.
In 2022, no accidents that resulted in loss of human lives or serious damage to people or property have been reported. Time lost due to employee illness or accidents was negligible. Employee safety is of the highest priority, and the company is continuously working towards identifying and employing administrative and technical solutions that ensure a safe and efficient workplace.
PetroNor has a strong focus on corporate social responsibility (CSR) as well as an ethical code of conduct. Social acceptability is a foundation for conducting the company's business.
E&P has an equality concept integrated in its human resources policies.
Petronor
As part of the efforts to achieve social acceptability, PetroNor aims to work closely alongside local
partners to improve the lives of the communities it operates in. To ensure the company's efforts are sustainable, corporate social investments were and are primarily focused on project work in the following key areas:
The company is supporting the CSR projects through its subsidiary in the Republic of Congo such as drilling water wells to provide drinking water to communities, as well as the projects organised by the operator in the PNGF Sud license group.
During 2022 this Congolese subsidiary allocated USD 1.5 million (2021 USD 1.5 million) of its annual profits as a provision towards CSR projects.
PetroNor aims to maintain a working environment with equal opportunities for all based on performance; irrespective of gender, age, religion, ethnicity, sexual preference, political belief, disability, or any other protected status. PetroNor values each member of the team and is committed to providing an environment recognised for its positive energy, equality, and professionalism, and that treats everyone with fairness, respect, and dignity.
The company has an equality concept integrated in its human resources policies. A diversified working environment is embraced, and the group's personnel policies promote equal opportunities and rights, and prevents discrimination based on gender, ethnicity, colour, language, religion or belief. All employees are governed by PetroNor's code of conduct, to ensure uniformity in behaviour across a workforce representing a multitude of nationalities.
PetroNor is a knowledge-based group in which a majority of the workforce has earned college or university level educations; or has obtained industry-recognised skills and qualifications specific to their job requirements. Employees are remunerated exclusively based upon skill level, performance, and position.
| 2022 actual |
2021 actual |
|
|---|---|---|
| Staff | 59% | 61% |
| Board | Nil | Nil |
| 2022 actual |
2021 actual |
|
|---|---|---|
| Staff | 37% | 36% |
| Executive management team | Nil | Nil |
| Board | 50% | 50% |
1) Prior to the redomicile of PetroNor to Norway the percentage of the board that were female was 29 per cent.
During 2022, the monthly average number of employees and long-term consultants was 34 (2021: 35).
Courtesy and respect are important aspects of a sound working environment and business dealings. PetroNor does not tolerate discrimination of colleagues or others affected by its business. The company will not tolerate any verbal or physical conduct that may lead to the harassment of others,
disrupts the work performance of others, or conduct that creates a hostile work environment. The company expects all employees to treat everyone they come into contact with through work or work-related activities in a respectful manner.
In 2022, there were no reported instances of intimidation or harassment .
The main objective of PetroNor's corporate governance framework 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.
PetroNor's board of directors are responsible for establishing the Corporate Governance framework of the company. Further, PetroNor seeks to comply with all the requirements covered in The Norwegian Code of Practice for Corporate Governance (the "Code").
The company has implemented corporate values, ethical guidelines and guidelines for corporate social responsibility. These values and guidelines are described in PetroNor's Code of Conduct with further details in internal policies.
In accordance with the Norwegian Accounting Act, the company annually reports on matters relating to environmental and social issues, labour environment, equality and non- discrimination, the compliance with human rights and the combat of corruption and bribery.
The board of directors and management aim for a controlled and profitable development and longterm 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 company has in this respect initiated a structured process to ensure its adherence to changes in legal requirements resulting in an improved ESG strategy and corresponding results thereof. The 2022-enacted Transparency Act is particularly noted, and the board of directors has actioned plans, as per the captioned Act, to publish a statement for due diligence before end of June 2023.
To avoid negative impact on the environment, local communities and the workforce, the company integrates technical, economic and
HSE considerations into decision making and operational processes to achieve long-term sustainability of the business and to reduce risk.
The company strives for continuous improvement as lessons learned from past operations are incorporated into business practices going forward.
The company endeavours to comply with international and local HSE standards. The health, safety and welfare of all personnel involved and of the general public is the highest priority.
All employees and business partners are encouraged to speak up and stop any work if they feel it is or could be unsafe to life or the environment. Further to report any instances of unsafe practices and/or any dangerous working situations.
In 2022, there were no matters identified that were in violation of HSE management in the group.
A prudent code of conduct is of strategic importance to the business, and part of the overall framework of environmental, social and governance (ESG). It has been approved by the board of directors and is to be revised from time to time to reflect the activities as the company develops and as laws and regulations may change. The code of conduct is available on the company's website. The code of conduct will be updated on a yearly basis, and there will be periodic training to ensure all representatives are up to date on how PetroNor expects them to act when representing the company.
PetroNor shall conduct business with integrity, respecting the cultures, dignity, and rights of
individuals everywhere it operates. The company shall always strive to maintain high ethical standards and conduct its business in a way that makes people proud to work for PetroNor. Further, PetroNor shall strive to ensure that activities also create local growth in a sustainable manner in each of the countries in which it operates, both through local partnerships and competence transfer.
The code of conduct is based on PetroNor's fundamental principles of business ethics. It summarises the company's values and standards and further describes what is expected of both the company and its employees. The company expects all its representatives to comply with the code of conduct. PetroNor also expects all business partners, joint venture partners and suppliers to act in a manner that is consistent with the principles of the code of conduct.
Further, compliance with national, regional, and international laws and regulations is mandatory for all activities in the company.
In 2022, no cases have been identified in the group, its supply chains or in its business relations that are in violation of the code of conduct.
PetroNor has a zero-tolerance approach to bribery and corruption and is committed to acting professionally, fairly and with integrity in all its business dealings and relationships. The company complies with all applicable anti-corruption laws and regulations. Overall, the company's policy is to conduct all of its business in an honest and ethical manner.
PetroNor's representatives must not accept, make, seek, or offer bribes or monetary advantages of any kind. This includes money, benefits, entertainment or services or any material benefit to or from public officials or other business partners, which are given with the intent of gaining improper business or personal gain. In this respect, the company has established a gift & hospitality register to ensure compliance with the policy.
The current shareholders and all of PetroNor's representatives are required to comply with Norwegian laws, the UK Bribery Act and the US FCPA as well as local laws in the jurisdictions where the company conduct business.
PetroNor's anti-bribery and corruption policy can be found on the company's website. The policy will be updated annually, with periodic training of company representatives. Each representative of the company signs the code of conduct, stating they have read it and will comply with it.
The company is aware of an ongoing investigation by Norwegian Økokrim (National Authority for Investigation and Prosecution of Economic and Environmental Crime) regarding alleged corruption. As per press release from Økokrim, the investigation is focused on individuals, and neither PetroNor E&P ASA nor any of its subsidiary companies have had charges brought against them.
In 2022, no cases have been identified in the group, its supply chains or in its business relations that are in violation with laws and/or the anti-bribery and corruption policy.
The company registered in 2020 as a supporting company with the Extractive Industries Transparency Initiative, EITI.
PetroNor believes in openness and transparency for all its business dealings and activities.
Over 50 countries have committed to strengthening transparency and accountability of their extractive sector management by implementing the EITI Standard. Currently, of the countries PetroNor has oil & gas operations in, the Republic of Congo, Nigeria and Senegal have committed to the EITI standard. Norway and the UK are also signatories to the initiative.
Countries are assessed on their progress in meeting the requirements of the EITI Standard through Validation, progress of "very high" demonstrating best progress in the three juristictions in the EITI's quality assurance mechanism:
| Country | Current status | Latest validation | |
|---|---|---|---|
| Republic of Congo | Moderate | 2023 | |
| Nigeria | Satisfactory progress | 2019 | |
| Senegal | Very high | 2021 | |
PetroNor supports the EITI Association in its objective to make the EITI Principles and the EITI requirements the internationally accepted standard for transparency in the oil, gas and mining sectors, recognising that strengthened transparency of natural resource revenues can
reduce corruption, and the revenue from extractive industries can transform economies, reduce poverty, and raise the living standards of entire populations in resource-rich countries.
The company discloses taxes and payments to governments in connection to its oil and gas licences in accordance with the legal requirements in the Norwegian Security Trading Act. This country-bycountry reporting is included in the directors' report.
Supporting companies uphold the EITI Standard through reporting in EITI implementing countries where they operate. Supporting companies are expected to meet a lot of expectations. Many of these expectations are also covered by the rules of companies listed on the Oslo Stock Exchange. Where relevant, PetroNor will make efforts to satisfy all expectations.
PetroNor believes in openness and transparency for all its business dealings and activities. Illegal or unethical matters may negatively impact the working environment and the business in general. It is important that the company deals with such matters properly. All current and former PetroNor representatives, who have concerns about any aspect of the company's business are encouraged to raise them and to disclose any information which relates to improper, unethical or illegal conduct with regards to the activities of the company.
Every PetroNor representative has a right and an obligation to raise their concerns about our business including matters such as:
Whistleblowers shall not suffer any detrimental treatment from either the company or colleagues as a result of raising a genuine concern. An independent disclosure service is available at: https://petronor. integrity.complylog.com/. ComplyLog is part of Euronext Corporate Services making the service available to listed companies on any of their stock exchanges. If a case is reported, the independent disclosure service will contact the correct person within the company to start dealings with the disclosure. Also, if a disclosure is made directly to a management representative, or to a member of the board, the person receiving the disclosure is obligated to follow up the disclosure according to the agreed procedures.
No cases were reported during 2022.
The CEO is responsible for the company's daily operations. Further, the CEO ensures that all necessary information is presented to the board of directors. The board will evaluate the company's vision and strategy at least on a yearly basis.
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 is the ultimate decision taker in new projects and/ or investments.
PetroNor E&P ASA ("PetroNor" 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 the shareholders, the management, and the board of directors ("the board") as well as adequate communication.
PetroNor seeks to communicate clearly with all stakeholders.
PetroNor 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 Stock Exchange Code of Practice for Investor Relation (IR) of 1 July 2019.
The main objective for PetroNor'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.petronorep.com.
PetroNor is a full cycle oil and gas exploration and production company listed on the Oslo Stock Exchange with the ticker PNOR. PetroNor holds exploration and production assets in Africa.
The company's business is defined in the Articles of Association §3, which states:
"The company's business is to invest in companies and entities that are involved in the energy industry and the oil and gas industry worldwide, as well as investment activities and other related activities."
The company is focused on growing production and reserves by leveraging existing assets to capitalise on new venture opportunities combined with targeted high impact exploration. With strategic and long-term large shareholders from Abu Dhabi and Norway, PetroNor will look to capitalise on the industry experience and government relations in these jurisdictions.
PetroNor's vision is to:
The oil and gas exploration and production industry is a high-risk-high-reward industry where PetroNor is exposed to the fluctuations in the oil price, risks involved in petroleum production as well as drilling of production, appraisal and exploration wells. The company will seek opportunities across its core region but may opportunistically invest outside of its core area.
PetroNor will aim to steadily build and increase its reserve base while using free cash flow to
pursue defined exploration targets in selected and highly prospective basins with a view to delivering significant value to its shareholders from high impact wells whilst being a good corporate citizen and promoting excellence in operations and innovation.
PetroNor has implemented corporate values, ethical guidelines, and guidelines for corporate social responsibility. These values and guidelines are described in PetroNor's Code of Conduct with further details in internal policies. In accordance with the Norwegian Accounting Act, the company annually reports on matters relating to environmental and social issues, labour environment, equality and nondiscrimination, the compliance with human rights, and the combat of corruption and bribery.
The board of directors evaluates the company's objectives, strategies, and risk profiles yearly.
The oil and gas E&P business is highly capital dependent, requiring PetroNor to be sufficiently capitalised. PetroNor'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 board needs to be proactive in order for PetroNor to be prepared for changes in the market.
Mandates granted to the board to increase the company's share capital or to purchase PetroNor 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 PetroNor 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.
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.
PetroNor 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.
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.
Transactions in PetroNor shares will be made over the stock exchange or by other means at market prices. If there is a limited liquidity in the PetroNor shares, the board will consider other ways of dealing with equal treatment of shareholders when making transactions in the PetroNor shares.
The shares of PetroNor are listed on the Oslo Stock Exchange. There are no restrictions on ownership, trading or voting of shares in PetroNor's Articles of Association.
PetroNor'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. The company shall arrange the general meetings so that the shareholders can attend by electronic means, unless there is a reason to refuse.
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.petronorep.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.
PetroNor 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 annual general meeting must be received at least five calendar days before the meeting is held.
The chair of the board, as well as the company auditor and CEO of the company, shall be present at the general meetings, unless the circumstances preclude such. The chair of the nomination committee as well as other board members should attend the general meetings. 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, are among the matters that will be decided at the annual general meeting. After the meeting, the minutes are released on the company's website.
According to Article 8 of the company's Articles of Association, the company shall have a nomination committee of up to three members, to be elected by the general meeting. The nomination committee shall present proposals to the general meeting regarding (i) election of the chair of the board, directors and any deputy members, and (ii) election of members of the nomination committee. The nomination committee shall also present proposals to the general meeting for remuneration of the board and the nomination committee, which is to be determined by the general meeting. The general meeting shall adopt instructions for the nomination committee. Due to the company's current shareholder composition, the nomination committee will not necessarily be independent of the major shareholders and the company will continuously consider this matter and whether to later propose a more independent appointment 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 upstream E&P industry, oil service, energy politics and finance. The composition of the board ensures that it can operate independently of any special interests. Board members are normally 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 chair and deputy chairperson (if any). The company's website and annual report provide detailed information about the directors' 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 is to be composed of at least 2 members who are independent of the company's major shareholders, and more than half of the members are to be independent of the company's management and material business relations.
The board has the overall responsibility for the management and supervision of the activities in general. The CEO is responsible for the company's daily operations and ensures that all necessary information is presented to the board.
The board decides the strategy of the company and is the final decision 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 chair of the board ensures that the board's duties are undertaken in efficient and correct manner.
The board has established separate rules of procedures for its work. Such rules of procedure also address how the board and management shall deal with agreements with related parties, and in particular whether independent valuations of such agreements should be obtained. In addition, the board will report on such agreements in its annual report.
The board shall stay informed of the company's financial position and ensure adequate control of activities, accounts, and asset management. The director's experience and skills are crucial to the company both from a financial as well as an operational perspective.
An annual schedule for the board meetings is prepared and discussed together with a yearly plan for the work of the board. The board will consider evaluating its performance and expertise annually.
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 chair is or has been personally involved, the matter will be chaired by an independent member of the board to ensure a more independent consideration.
The board has established an audit & risk committee and a remuneration committee as association, of the board.
The audit & risk committee shall consist of at least three members appointed by and among the board. All members of the audit & risk committee must be non-executive directors, a majority of the members should be independent of the management and the company, and there must be adequate accounting and finance competence among the members of the committee. The audit & risk committee's role is to supervise the group's accounting and financial performance, as well as ensuring that adequate internal control and reporting requirements exist. The role is further detailed in a separate audit & risk committee charter.
The remuneration committee shall consist of up to three members appointed by and among the board.
All members shall be independent of the management. The remuneration committee's role is to assist and advise the board on matters relating to the remuneration of the board and management, as well as salary, bonus and benefit policies for the employees in general. The role is further detailed in a separate remuneration committee charter.
In addition, the board created a further subcommittee to support the board with the independent fact finding process relating to Økokrim matter. The committee does not comprise any persons subject to the charges or any investigations.
PetroNor has established guidelines for reporting
Financial and internal control, as well as shortand long-term strategic planning and business development, all according to PetroNor'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 company has established guidelines for the company's reporting of financial and other information. The chair and CEO are authorised by the board to speak to, or be in contact with the press.
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 the fiscal year, according to the continuing obligations for companies listed on the Oslo Stock Exchange.
All information to shareholders is published simultaneously on the company's website and to appropriate financial news media.
PetroNor normally makes two half-year presentations per year to shareholders, potential investors and analysts in connection with halfyear quarterly earnings reports or trading updates, in addition to four quarterly production updates. The half-year presentations are held through webinars to facilitate participation by all interested
shareholders, analysts, potential investors, and members of the financial community. A questionand-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.petronorep.com for a limited number of days.
The company also makes investor presentations at conferences in Norway and internationally. The information packages presented at such meetings are published simultaneously on the company's website.
PetroNor has established the following guiding principles for how the board will act in the event of a take-over bid. In a bid situation, the board shall help to ensure that shareholders are treated equally, and that the company's business activities are not disrupted unnecessarily. The board shall ensure that shareholders are given sufficient information and time to form a view of relevant offers.
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 PetroNor.
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.
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 the time of the publishing of the announcement that the bid will be made.
In the event of a take-over bid for the company's shares, the board 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 & risk committee as a sub-committee of the board, which will meet with the auditor regularly. The auditor shall on an annual basis submit an additional report to the audit committee in which it declares its independence and explains the results of the statutory audit carried out by providing a range of information about the audit.
The auditor 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. The board shall on an annual basis review the internal control procedures jointly with the auditor, including weaknesses identified by the auditor and assess proposals for improvement.
PetroNor 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.
Mr Alhomouz graduated from Brigham Young University in Provo, UT with a degree in Chemical Engineering and from the Colorado School of Mines, in Golden, CO with a master's degree in Mineral and Energy Economics.
Mr Alhomouz has a strong experience from the oil and gas sector covering the US, North Africa, and the GCC. He began his career with Schlumberger Oilfield Service as a wireline engineer in Midland, Texas. From there he went on to work for Cromwell Energy in Denver, Colorado, as international business development manager. Then, as a COO and financial director of Prism Seismic, he oversaw the growth of the Colorado based consulting and oil and gas software development firm and later the acquisition of the company by Sigma Cubed, where, post-acquisition of Prism Seismic, he went on to serve as a director of business development, Middle East. Mr. Alhomouz's career then took him to Qatar as a general manager of Jaidah Energy, an Omani-Qatari owned company servicing the oil and gas sector in Qatar. Mr. Alhomouz is currently the CEO of Petromal Sole Proprietorship LLC.
Mr Alhomouz is not independent of the main shareholding.
Mr Iskander holds a Degree in Accounting and Finance with high distinction from Helwan University, Egypt.
Mr Iskander brings over 25 years of experience in the financial services industry, covering asset management, private equity, portfolio management, financial restructuring, research, banking, and audit. He began his career at Deloitte & Touche (Egypt) as an auditor. Mr. Iskander served as non-executive director on the boards of EFG Hermes in Egypt, Oasis Capital Bank in Bahrain, Sun Hung Kai & Co in Hong Kong, Qalaa Holdings in Egypt, Emirates Retakaful in UAE, Marfin Laiki Bank in Cyprus and Marfin Investment Group in Greece. Mr. Iskander headed the research team at Egypt's Prime Investments and was earlier an investment advisor at Commercial International Bank (CIB) He then went on and joined Dubai Group as an investment manager in 2004 and has worked on a range of M&A transactions, advisory services, asset management, and private equity transactions with a collective value in excess of USD 8 billion. Mr. Iskander was managing director of asset management at Dubai Group and the former head of research at Dubai Capital Group until 2009. He joined Emirates International Investment Company in July of 2017 as the head of investments spearheading and managing EIIC's investments. He is also the chief executive officer of Entrust Capital Limited an EIIC company. EIIC is a subsidiary of National Holding in Abu Dhabi.
Mr Iskander is not independent of the main shareholding.
Ms Smines Tybring-Gjedde graduated from BI Norwegian Business School with a Master's degree in Management Programs, with strong focus on interaction, leadership, and strategy.
Experienced former Norwegian minister of national public security with overall responsibility of public safety, emergency planning, and cybersecurity. Mrs Tybring Gjedde was also minister of Svalbard and the Norwegian polar regions. Before her position as minister, she served as deputy minister in the Ministry of Petroleum and Energy for 4 years, with a portfolio of exploration policy, development, operations, exploration activity, the Ministry's contact with other petroleumproducing countries and international forums, in addition to the government's national climate policy, global environmental issues, and the government's CCs full-scale project. Mrs Tybring Gjedde has a demonstrated history of working in the O&G, energy, and renewable industry in private and state-owned companies in various leading positions for more than 20 years.
Ms Smines Tybing-Gjedde is an independent director.
Mrs Kielland holds an MSc in Mechanical Engineering from the Norwegian University of Science and Technology (NTNU).
Mrs Kielland has over 30 years of experience having held a number of leading positions in the oil and gas industry both in Norway and abroad, among others as CEO of BP Norway. Her professional experience includes work related to both operations and field development, as well as HSE. She has been holding non-executive roles for the last 15 years, mainly within the energy industry, working with different ownership structures, including listed companies, privately owned, PE owned and start-up companies.
Mrs Kielland is an independent director.
Ms Fawzi holds a B.S.B.A, Finance from American University Kogod School of Business.
Mrs. Fawzi is a former Shell finance executive where her areas of responsibility included the US, Qatar, Brazil, Nigeria, Egypt, Oman, UAE, Malaysia, Mexico, and India, contributing to the business turnaround of Deep Water in the US Gulf of Mexico. As a senior finance leader, she works not only to ensure that the appropriate control framework are in place but also to provide strategic direction and ensure value maximisation for shareholders. She is an international oil and gas finance executive with global board, audit, and executive leadership experience.
Mrs Fawzi is an independent director.
Mr Norman-Hansen holds a Bachelor's degree in Economics from BI Norwegian Business School and an ICFA from The Norwegian School of Economics.
Mr. Norman-Hansen has more than 30 years of experience from the Nordic property and capital markets overseeing acquisitions and asset management of multibillion investments as well as acting as advisor to many of Scandinavia's largest real estate capital markets transactions.
Mr Norman-Hansen is not independent of shareholding.
Mr Pace holds a BSc in Geology and Oceanography from the University of Wales and an MSc in Geophysics from Imperial College, London, UK.
Jens Pace has over 40 years of industry experience gained initially with major companies, BP, and Amoco, and since 2012, with African Petroleum Corporation and PetroNor. With a background in geoscience, Jens has held senior leadership positions in E&P for the past 20 years, operating in a wide variety of international jurisdictions. Jens was CEO of African Petroleum and following the merger with PetroNor, he served as a director. On 9 February 2022, Jens stepped down from the board and was appointed as interim CEO.
Mr Frimann-Dahl holds a BSc in Petroleum Engineering from Texas A&M University and an MSc from the University of Trondheim (NTH).
Mr. Frimann-Dahl has 30 years' experience from the oil and gas industry, with managerial and technical roles. His experience covers operational roles with Phillips Petroleum, Norsk Hydro, and Hess in the North Sea Norway and Denmark, Russia, Egypt and the US. He was the co-founder of Ener Petroleum which was later acquired by Dana Petroleum and KNOC.
Mr. Barrett has a BSc in Geology & Geophysics from Durham University and a MSc in Petroleum Geology & Geophysics from Imperial College, Royal School of Mines.
Mr. Barrett has over 30 years global exploration experience from his career at Chevron Corporation, and more recently at Addax/Sinopec International African Petroleum and PetroNor. Mr. Barrett has held a variety of technical roles covering exploration and new ventures, and was part of Chevron's global Exploration Review Team, specialising in play and prospect risk assessment, and volumetric assessment. He has extensive experience in portfolio management and commercial evaluation of oil and gas opportunities. Mr. Barrett also brings added strength to the team with his background in quantitative geophysics, stratigraphic interpretation workflows and 3D visualisation.
Mr. Butler is a Fellow of the Institute of Chartered Accountants in England and Wales and has a BSc in Physics from Warwick University.
Mr. Butler has over 18 years of financial and corporate experience from positions in public practice, oil & gas, and mining spread over Africa, Asia, and Europe, with roles that included financial reporting, contract negotiations, M&A, due diligence, treasury and system implementations.
Mr. Sultan holds a BSc Mechanical Engineering degree from the University of Washington.
Mr. Sultan has 20 years of international exploration and production experience. He has held multiple operation and marketing management positions with international oil field services companies. He has also worked in a number of technical, contracting and strategy management roles with major oil and gas operators.
PetroNor E&P has reached several operational and strategic milestones with the ongoing infill drilling programme at the PNGF Sud field resulting in production levels not seen for over a decade. Our redevelopment plans for the Aje field advanced following the completion of the acquisition of the Panoro interest, and our exploration portfolio made good progress. With the up-listing to the main Oslo stock exchange, our restructured board, and a successful refinancing at year-end, PetroNor is well structured to fulfil its ambitious growth strategy from both its existing portfolio and new opportunities.
The board of directors' report is presented for PetroNor E&P ASA ("PetroNor" or "the company") and its subsidiaries for the year ended 31 December 2022.
The names of directors of the ultimate parent entity of the group in office during the financial year and until the date of this report are as follows. Directors were in office for this entire period unless otherwise stated.
| PetroNor E&P ASA | Role | First appointed | Resigned |
|---|---|---|---|
| E Alhomouz | Non-exec chair | 1 October 2021 | - |
| J Iskander | Non-exec director | 8 October 2021 | - |
| J Pace | Non-exec director | 1 October 2021 | 9 February 2022 |
| I Smines Tybring-Gjedde | Non-exec director | 1 October 2021 | - |
| G Kielland | Non-exec director | 1 October 2021 | - |
| J Norman-Hansen | Non-exec director | 26 January 2023 | - |
| A Fawzi | Non-exec director | 26 January 2023 | - |
The names of the directors of PetroNor E&P Limited (Australia), up to completion of the redomicile from Australia to Norway and the company ceasing to be the parent company of the group in February 2022, are as follows:
The management team at PetroNor has in-depth industry experience from the oil and gas upstream industry.
The board of directors' report for the PetroNor group ("the group") comprises PetroNor E&P ASA ("the parent company") and all subsidiaries and associated companies.
PetroNor E&P ASA is a Norwegian publicly listed liability company with its head office in Oslo, Norway.
The company is an independent oil and gas exploration and production company with a portfolio of assets in countries offshore West Africa (Republic of Congo, The Gambia, Guinea-Bissau, Senegal and Nigeria).
As of 31.12.2022, the company holds, through its Congo subsidiary, 2P oil reserves of 18.5 MMbbls and an average net production in 2022 of 4,021 bopd. In addition, PetroNor holds a portfolio of exploration licences in Guinea-Bissau, The Gambia, and Senegal with net unrisked prospective resources of approximately 3.3 billion barrels
of oil (from multiple prospects, based upon ERC Equipoise Competent Persons Report Letter March 2015 and management updates).
The asset portfolio as described in the portfolio section is supported by staff in Norway, multiple locations in Africa, the UK, and the UAE. The management team at PetroNor has in-depth industry experience from the oil and gas upstream industry. Together they have built a broad network of industry contacts, and developed strong relationships with governments, institutions and trusted partners fostered over many years of valued collaboration.
PetroNor is a full cycle, Sub-Saharan oriented E&P company focused on growing production and reserves by leveraging existing assets to capitalise on new venture opportunities combined with targeted high impact exploration.
With strategic and long-term shareholders from Norway and Abu Dhabi, PetroNor will look to leverage its industry experience and government relations in these jurisdictions.
PetroNor will aim to steadily build and increase its reserve base while using free cash flow to pursue defined exploration targets in selected and highly prospective basins, with a view to delivering significant value to its shareholders from high impact wells whilst being a good corporate citizen and promoting excellence in operations and innovation.
The synergies between PetroNor's business model and the latest technologies developed in the offshore of the Norwegian Continental Shelf allow for the maximum commercial outcome with the least environmental impact. The transfer of technology and excellence to the company's partners or host countries ensures long term collaborations and development.
PetroNor looks at creating value through application of cutting edge and smart technology but always aims to strike the right balance between innovations and proven technology. PetroNor E&P gives special interest to IOR (improved oil recovery) for improved and efficient operations.
The company's area of focus is on Sub-Saharan Africa and, more specifically, proven and producing assets in the region with development and IOR potential.
We leverage on our background and experience from the oil and gas industry in Norway, the country with the highest oil recovery rate in the world, in our operations. The PetroNor team has a proven track record from both IOR in the North Sea, as well as from direct, day-to-day, on the ground operations in Africa. The company's flat structure and assumed strict focus on execution and delivery enable it to move rapidly to take advantage of opportunities.
With many years of experience working in the international oil and gas business, the management and technical staff are able to apply and utilise cutting edge industry innovations and technologies to PetroNor's projects globally in order to maximise their potential value. With access to the Norwegian equity market with sophisticated investors in the energy sector coupled with a strong cornerstone investor from Abu Dhabi, the company is well positioned to access capital both for smaller and larger transaction opportunities.
The company's principal activity during the year was oil and gas exploration and production.
On 7 October 2021, PetroNor E&P Limited and PetroNor E&P ASA entered into an agreement whereby shares in PetroNor E&P Limited (previously listed on Euronext Expand) were swapped for shares in PetroNor E&P ASA as part of the process to redomicile the company from Australia to Norway. Subsequently, PetroNor E&P ASA submitted its application for its shares to be listed on Oslo Stock Exchange.
On 29 November 2021, an extraordinary general meeting was held in PetroNor E&P Ltd by order of the Supreme Court of Western Australia where the shareholders of the company approved the proposed Scheme of Arrangement.
PetroNor E&P Ltd received the final approval from the supreme court of Western Australia on 17 February 2022, followed by delisting of its shares from Euronext Expand on 24 February 2022 in conjunction with the listing of PetroNor E&P ASA. PetroNor E&P ASA began trading on Oslo Stock Exchange 28 February 2022 following the 1 to 1 share swap. The two Australian directors and the company secretary were not reappointed to PetroNor E&P ASA after the redomicile. In
January 2023, following an extraordinary general meeting, two additional directors were appointed to the board so that the board now consists of six directors, three of which are considered to be independent.
In December 2021, the National Authority for Investigation and Prosecution of Economic and Environmental Crime (Nw.: Økokrim) in Norway brought charges against individuals related to the company. Økokrim announced that the investigations were related to the individuals in question on suspicion of corruption concerning undisclosed projects in Africa, in addition to confirming that no charges had been brought against the group or other companies. The company takes anti-corruption and the matter at hand seriously and adopted a series of remediation steps.
The individuals charged by Okokrim in December were removed from business operations and Jens Pace was appointed interim CEO of PetroNor.
The board engaged independent legal counsel to support its governance and compliance steps, initiating an independent fact finding process, to identify any misconduct, to analyse the causes of the underlying conduct, and setting up a separate board sub-committee to support the board with the matter at hand. These measures are designed to assure the further implementation of an effective anti-corruption and compliance programme, founded on its existing code of conduct, governing documents and related policies. The board will instigate any other remedial action deemed relevant to the situation. The measures taken by the company are led by the board subcommittee which does not comprise any persons subject to the charges or any investigations.
On 13 July, PetroNor announced the completion of the purchase of the Panoro Energy ASA ("Panoro") wholly owned subsidiaries Pan-Petroleum Nigeria Holding BV (renamed "Aje Nigeria Holding BV" ) and Pan-Petroleum Services Holdings BV (renamed "Aje Services Holding BV") that together hold 100 per cent of the shares in Pan-Petroleum Aje Ltd ( renamed "Aje Production Ltd"). Pan Aje participates in the exploration for and production of hydrocarbons in Nigeria and holds a 6.502 per cent participating interest, with a 16.255 per cent cost bearing interest, representing an economic interest of between 12.1913 per cent and 16.255 per cent in OML 113, containing the Aje oil and gas field. The upfront consideration to Panoro for the transaction was USD 10 million which was paid via the allotment and issue of 96,577,537 new PetroNor shares ("the consideration shares"). The consideration shares were issued and subsequently registered with the Norwegian Register of Business Enterprises (Brønnøysundregistrene) on 26 July 2022.
The company has three production licence agreements (Tchbouela II, Tchendo II, and Tchibeli-Litanzi II), which cover six oil fields located in 80-100 m water depths approximately 25 km off the coast of Pointe-Noire. The complex oil field was discovered in 1979, commenced production in 1987, and is called PNGF Sud.
Since granting of the licences in January 2017, Perenco, with partner support has been committed to strict HSE compliance while growing production, improving maintenance routines and field integrity in a stepwise and prudent manner. This led to an increase in gross production from c. 15,000 bopd gross in January 2017 to an average gross production in 2022 of 23,891 bopd.
The 17-well drilling campaign targeting PNGF Sud that commenced in 2021 led to six new wells in 2022 adding to the production. The drilling programme will continue in 2023 with work scheduled to commence in April 2023 to add four planned new wells.
The PNGF Sud fields are developed with eight wellhead platforms and currently produce from 67 active production wells, with oil exported via the onshore Djeno terminal. With its long production history, substantial well count and extensive infrastructure, PNGF Sud offers well diversified and low risk production and reserves with low breakeven cost.
In March 2023, AGR Petroleum prepared a competent person's report ("CPR") whereby the reserves were calculated as at 31 December 2022.
Using the CPR and adjusting for 2022 production as at 31 December 2022:
| Participation Interest | 16.83% |
|---|---|
| 1P reserves (MMbbls) | 12.5 |
| 2P reserves (MMbbls) | 18.5 |
PetroNor's contingent resource base includes discoveries of varying degrees of maturity towards development decisions. At the end of the year, PNGF Sud contains a net 2C volume of approximately 7.1 MMbbls assuming a 16.83 per cent participation interest.
Gross production during 2022 was 8.72 MMbbls, corresponding to 1.47 MMbbls net to the company.
The current indirect participation interest is 16.83 per cent following transactions during 2021.
PNGF Bis is located next to PNGF Sud and contains two discoveries from 1985-1991 in the structures of Loussima SW and Loussima. The company and its PNGF Sud partners have a right to negotiate the licence agreement.
The three discovery wells tested from 1,150 to 4,700 bopd of light, good quality oil. Perenco has made a detailed reinterpretation, 3D modelling and facilities study for the Loussima SW discovery, yielding >100 MMbbl of in-place resources and a possible tie-back to Tchibouela.
AGR Petroleum Services warrants gross 2C resources of 28.9 MMbbl including verification of the tieback scenario given above. PetroNor's indirect participation interest is 23.56 per cent following transactions in 2021.
As announced on 27 January 2022, the Nigeria Upstream Petroleum Regulatory Commission (formerly the Nigerian Department of Petroleum Resources) provided its consent to PetroNor's acquisition of Panoro's ownership interest in Oil Mining Lease no. 113 ("OML 113") offshore Nigeria, containing the Aje oil and gas field. The acquisition transaction completed in July 2022. PetroNor now holds a 6.502 per cent participating interest with a 16.255 per cent cost bearing interest, representing between 12.1916 per cent and 16.255 per cent in the OML 113 licence area which contains the Aje oil and gas field.
Aje Production was created as a joint venture between PetroNor and Yinka Folawiyo Petroleum Deep Water ("YFP-DW") will lead the technical and management efforts in the next phase of the Aje field development. PetroNor will contribute the acquired interest in Aje, and YFP-DW will contribute all interest in Aje to the Aje Production JV.
PetroNor entered into separate agreements with the OML 113 operator in 2019 to create a holding company to exploit the substantial gas and liquids reserves at Aje. The regulatory process for this agreement was aligned with the transaction and was approved concurrently with the Panoro transaction. Petronor and YFP-DW are working towards completing the formation of the jointly owned Aje Production. PetroNor's ownership will be 52 per cent in Aje Production which will
hold a 15.5 per cent participating interest and an economic interest in the order of 38.755 per cent in OML 113 during the majority of the project period. YFP has undertaken to align its voting rights with Aje Production's objectives in the development of the Aje field.
PetroNor continues work to update the field development plan ("FDP") to expedite gas development and engaged with potential offtakers and partners. The consent from the Nigeria Upstream Petroleum Regulatory Commission has allowed PetroNor to re-engage financial and industrial partners with a target to mature the project towards an FID. Development plans for the Aje gas condensate and additional oil is progressing jointly with the license partners. The plan is to proceed toward an FID involving changeout of the FPSO, drilling further gas and oil development wells, building a 30 km pipeline to shore to a receiving LPG plant close to the export compressor station of the West African Gas Pipeline (WAGP). Condensate and oil will be produced and offloaded offshore while offtake agreements will include gas sales and swap arrangement for gas and LPG products.
Following positive discussions with the Gambian Government, PetroNor announced that it has decided to exercise its right to continue with the Petroleum, Exploration, Development and Production Licence Agreement ("PEPLA") for the A4 licence in The Gambia.
PetroNor and Gambia National Petroleum Corporation ("GNPC") have also signed a Joint Operating Agreement ("JOA") for the A4 Licence offshore Gambia. GNPC, as Government licensee, has been assigned a 10 per cent participating interest in the license.
The first exploration period is for three years, the first 18 months of which are for additional prospect technical maturation work. The well commitment is made upon entry to the second 18-month period. This highly prospective block lies 30 km South of the Senegal "Sangomar" field which will start production in 2023 at 100,000 bopd. The block contains multiple low risk commercial size prospects.
PetroNor E&P Gambia Ltd will be able to carry approved prior sunk costs associated with A4 into the new agreement.
The PEPLA is a royalty plus tax system valid for 30 years with an option of a 10-year extension. Post
discovery, the licence moves into an exploration/ appraisal phase where the commercial potential of the discovery is ascertained and a development decision taken, followed by a development and subsequent production phase.
The A4 licence is located offshore within the Mauritania-Senegal-Gambia-Bissau-Conakry Basin. Hydrocarbons are proven throughout the basin, the most local and notable is the 460 MMbbls Sangomar field, 30 km to the North in Senegal due to produce first oil in late 2023, operated by Woodside Petroleum.
PetroNor continues to seek partners to drill one exploration well in this highly attractive acreage and aims to participate in any future well at an equity level of 30-50 per cent.
PetroNor is continuing to advance plans to drill the Atum prospect within the Sinapa 2 licence. Following the publication, post period, in the Official Gazette of Guinea-Bissau (Boletim Oficial 45), the FAR Ltd 21.43 per cent equity interest has officially been transferred to PetroNor E&P AB. FAR had formally applied to withdraw from the licences following an announcement on the 15 March 2022. Petronor now holds 100 per cent equity.
Drilling preparation was restarted with EXCEED in the third quarter of 2022. Long lead items required for drilling operations have been secured and pre-drill studies and detailed well planning and preparation are under way.
The Atum-1x well will test a highly attractive and material prospect on the Sinapa 2 licence. Recently reprocessed seismic data has been interpreted as part of the ongoing evaluation of both licences and as preparation to drilling.
In July 2018, the company's subsidiary African Petroleum Senegal Limited registered arbitration proceedings with the International Centre for Settlement of Investment Disputes (ICSID) (case ARB/18/24) to protect its interests in the Senegal Offshore Sud Profond and Rufisque Offshore Profond blocks. We await the outcome of the ICSID Tribunal which held a hearing on jurisdiction and the merits in Paris during March 2022.
The board of directors ("the board") confirms that the annual financial statements have been prepared pursuant to the going concern assumption, and that this assumption was realistic at the balance sheet date. The going concern assumption is based upon the financial position of the group and the development plans currently in place. The group recognises that in order to fund on-going operations and pursue organic and inorganic growth opportunities it will require additional funding. This funding may be sourced through joint venture equity or share issues or through debt finance.
The going concern basis assumes the continuity of normal business activity and the realisation of assets and the settlement of liabilities in the normal course of business. The underlying business of the group created a net profit after tax of USD 34.3 million for the year ended 31 December 2022, with strong production from the Congo assets generating 5,206 bopd in first quarter of 2023. As at 31 December, 2022 the group had a cash balance of USD 24.8 million (2021 USD 31.8 million). The company has listed on the main exchange of Oslo Børs, successfully refinanced its debt, achieved high production levels following a successful in-fill drilling campaign and continues to seek for potential partners to join the company on its exploration portfolio. This demonstrates that the business has continued to operate effectively, and businesses are willing to engage with the company and this has enabled the directors of PetroNor ("the directors") to form the opinion that the company will be in a position to continue to meet its liabilities and obligations for a period of at least twelve months from the date of signing this report.
This financial report does not include any adjustments relating to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities that might be necessary should the group not continue as a going concern.
The following financial review is based on the financial statements of PetroNor E&P ASA and its subsidiaries. The statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the EU as well as Norwegian accounting legislation.
In the view of the board, the statement of comprehensive income, statement of changes in equity, statement of financial position and cashflow provide satisfactory information about the operations, financial results and position of the group and the parent company at 31 December 2022.
The consolidated financial statements are presented in US dollars.
| For the year ended 31 December | ||
|---|---|---|
| Amounts in USD million | 2022 | 2021 |
| Revenue from sales of petroleum products | 72.8 | 57.6 |
| Assignment of tax oil | 47.6 | 33.1 |
| Assignment of royalties | 25.7 | 15.8 |
| Revenue | 146.1 | 106.5 |
| EBITDA | 96.4 | 61.9 |
| Net profit/(loss) | 34.3 | 21.1 |
| Quantity of oil lifted (barrels) | 800,177 | 831,089 |
| Average selling price (USD per barrel) | 90.99 | 69.31 |
| Quantity of net oil produced after royalty, cost oil and tax oil (barrels) | 900,495 | 821,536 |
PetroNor is continuing to advance plans to drill the Atum prospect within the Sinapa 2 licence.
The directors are pleased to report that favourable market conditions and the on-going corporate focus on cost control have resulted in EBITDA of USD 96.4 million for the year.
The group generated a net profit for the year of USD 34.3 million (2021: USD 21.1 million). These figures are due to an improving global market price for oil and to a steady production from PNGF Sud throughout the year as a result of the workover program. In fact, since the group first entered the licences in 2017, it has seen a 59 per cent increase in the gross field production.
During 2022, there were only 2 liftings of oil, with a 3.7 per cent decrease on the 831,089 barrels lifted in 2021. Increased oil prices during 2022 resulted in the group achieving higher revenues over lower volumes. The group achieved an average selling price of USD 90.99/bbl for the year, compared to the USD 69.31/bbl in 2021. As a consequence, the group reports USD 146.1 million in revenue, a 37.2 per cent increase on 2021 USD 106.5 million.
Exploration expenses for The Gambia licence for the year were USD 0.5 million with licence costs for Guinea-Bissau being USD 0.3 million. Under PetroNor's accounting policy, seismic data costs and time writing are expensed and not capitalised to intangible assets.
The administrative expense in 2022 of USD 14.4 million were higher than in 2021 (USD 13.1 million) and included business development costs of
At 31 December
USD 0.5 million (USD 0.5 million 2021). The group also incurred non-recurring third-party costs of approximately USD 0.4 million relating to the redomicile project, in addition to excess personnel costs and legal fees relating to the Økokrim matter. The company believes that the redomicile was a first step to further streamlining the group's corporate structure and further reduce corporate overheads in the longer term. Listing on the Oslo Stock Exchange will enhance the group's profile with investors, business partners, suppliers and customers, giving the group better access to capital markets. The move gives shareholders access to a more liquid market for shares and will facilitate a more diversified shareholder base and additional investors.
The group continues to build the strength of the balance sheet with condensed statement of financial position below.
| Amounts in USD million | 2022 | 2021 |
|---|---|---|
| Current assets | 44.8 | 51.8 |
| Non-current assets | 139.6 | 73.4 |
| Total assets | 184.5 | 125.2 |
| Current liabilities | 26.4 | 43.1 |
| Non-current liabilities | 48.2 | 16.3 |
| Total liabilities | 74.6 | 59.4 |
| Net assets | 109.9 | 65.8 |
| Capital and reserves attributable to owners of the parent | 97.6 | 59.3 |
| Non-controlling interests | 12.3 | 6.5 |
| Total equity | 109.9 | 65.8 |
The OML 113 assets acquired have been fully consolidated onto the balance sheet, which has resulted in an addition to intangible assets of USD 34.3 million. The infill drilling programme on the PNFG Sud asset has added USD 35.7 million to property plant and equipment ("PPE") and along with the acquisition of the OML 113 PPE of USD 0.9 million added USD 36.5 million to tangible assets. With the award of the A4 licence in The Gambia during the year, licence costs of USD 1.0 million were added to intangible assets in accordance with PetroNor's capitalisation policy. The past costs of the former A4 licence are allowed to be carried over to the new licence, the past cost pool is far in excess of the carrying value of the asset as at 31 December 2022.
Historic expenditure on the Guinea-Bissau licences had been impaired prior to acquisition by PetroNor; in accordance with PetroNor accounting policies only those costs relating directly to the licences have been capitalised to intangible assets. Drilling inventories were written back up to cost in the period reflecting conditions in the drilling market. The prior impairment to inventory values was unwound increasing the value of inventories in Guinea-Bissau by USD 2.5 million. Material inventories for the PNGF Sud assets have also increased by USD 1.7 million as a result of the ongoing infill drilling campaign. There was minimal stock at the end of 2021 as a lifting had occurred just before year end on 31 December 2021, consequently crude oil inventories have increased by USD 6.9 million in 2022.
The group has advanced USD 29.4 million (2021: USD 26.8 million) in cash to the operator towards the asset retirement obligation ("ARO") of PNGF Sud, this is considered a non-current "Other receivable".
The level of trade receivables has reduced as compared to the 2021 closing position. This was due to the lifting on the PNFG Sud assets at year end, trade receivables being USD 1.1 million at year end 2022 versus USD 13.8 million in 2021.
The addition of joint venture payables for the OML 113 asset, USD 2.7 million is offset by the early payment of joint interest billings for the PNGF asset so that trade payables of USD 20.8 million are USD 9.2 million lower than the 2021 closing position of USD 30.0 million. In addition, the level of liabilities to related parties has been substantially reduced in 2022 with the payment of USD 1.3 million prior to year-end.
The level of provisions has increased due to the addition of an asset retirement obligation for OML 113 of USD 3.8 million . In addition, funds set aside for CSR projects in the PNFG Sud assets have been reclassified as provisions USD 3.6 million. Provisions, net of the unwinding of discount, were USD 24.6 million versus USD 16.3 million in 2021.
At the year end, PetroNor closed on a debt refinancing facility of USD 11 million, repayable over 24 months. The funding was put in place at an interest rate of 11 per cent and on similar terms to the previous facility. Loan proceeds were received net of a facility arrangement fee of 1.5 per cent. The previous facility had been completed and expunged in Q4 2022 in addition a separate USD 3.9 million "Symero" loan was also repaid. PetroNor therefore exit the year with a restructured balance sheet.
Cash generated from operations were USD 81.9 million, however the inflows were seen in the last part of the year due to the timing of the liftings. The investment in PNGF Sud assets consumed USD 35.7 million in cash in the period but the benefits in increased production were already being yielded in record production levels by the end of the year. Repayment of loans and borrowings were USD 13.1 million in the period with the addition of a new financing facility at the year-end of USD 11.0 million giving a net reduction in loan debt of USD 2.1 million.
The group exits the accounting period with a cash balance of USD 24.8 million.
At the presentation date of the financial statements, the parent entity of the group was PetroNor E&P ASA, a company domiciled in Norway.
The company reported a loss for the period of USD 5.8 million. The company's financial activities were
purely corporate and include professional fees and fees for the services of the board directors.
During the year, no dividend was paid or recommended at group level.
The group participates in oil and gas projects in countries in West Africa with emerging economies, such as Congo Brazzaville, Nigeria, The Gambia, Senegal, and Guinea-Bissau.
Oil and gas exploration, development and production activities in such emerging markets are subject to significant political and economic uncertainties that may include, but are not limited to, the risk of war, terrorism, expropriation, nationalisation, renegotiation or nullification of existing or future licences and contracts, changes in crude oil or natural gas pricing policies, changes in taxation and fiscal policies, imposition of currency controls and imposition of international sanctions. Travel bans, asset freezes or other sanctions may be imposed and have historically been imposed on countries in which the group operates.
The jurisdictions in which the group operates may also have less developed legal systems than more established economies which could result in risks such as:
In certain jurisdictions, the commitment of local business people, government officials and agencies, and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to the company's licences and agreements for business. These may be susceptible to revision
Under applicable laws relating to the group's assets, local participation is or may be required in the oil and gas sector.
or cancellation and legal redress may be uncertain or delayed. There can be no assurance that joint ventures, licences, licence applications or other legal arrangements will not be adversely affected by the actions of government authorities or others and the effectiveness of and enforcement of such arrangements in these jurisdictions cannot be assured. The jurisdictions in which the group has operations have a low score on the Transparency International's Corruption Perception Index, which implies that these countries are perceived as jurisdictions where there is a higher risk of corruption. The group's current assets are located in Congo, the Gambia, Senegal, Nigeria and Guinea-Bissau.
The group may also target acquisitions in other countries in Africa. The production sharing or other licencing contracts in such jurisdictions may provide for payments to the governments and/or national oil companies (farm-in fees, signature bonuses, taxes, training budgets, equipment budgets, carry of certain expenditures etc.). Furthermore, the group has a number of consultants working for it in the area. Although the group believes all its consultancy agreements are entered into on clear and transparent terms, there is a risk that
agents or other persons acting on behalf of the group may engage in corrupt activities without the knowledge of the group. Under applicable laws relating to the group's assets, local participation is or may be required in the oil and gas sector, but it may prove difficult to always receive final confirmation as to who the ultimate owners and affiliations of such local partners are. Through the group's investigation, it has not been possible to substantiate ultimate ownership and affiliations of all, current local partners in Congo and there can be no assurance that there are no government affiliations within the ultimate shareholders of the local partners in Congo. Corrupt practices of third parties or anyone working for the group or any of its affiliated parties, or allegations of such practices, may have a material adverse effect on the reputation, performance, financial condition, cash flow, prospects and/or results of the group.
While the Økokrim personal investigation into individuals associated with the company continues without resolution, business partners may be required to perform enhanced KYC procedures on PetroNor before they can engage with the group. This may cause delays to new operations or even
stop possible relationships depending on the risk profiles of individual businesses.
The group's business, results of operations, value of assets, reserves, cash flows, financial condition and access to capital depend significantly upon, and may be adversely affected by, the level of oil and gas prices, which are highly volatile.
The group's revenues, cash flow, reserve estimates, profitability and rate of growth depend substantially on prevailing international and local prices of oil and gas. Prices for oil and gas may fluctuate substantially based on factors beyond the group's control. Consequently, it is impossible to accurately predict future oil and gas price movements. Oil and gas prices are volatile and have witnessed significant changes in recent years, for many reasons, including, but not limited to, changes in global and regional supply and demand, geopolitical uncertainty, availability of equipment and new technologies, weather conditions and natural disasters, terrorism as well as global and regional economic conditions. Sustained lower oil and gas prices or price declines may inter alia lead to a material decrease in the group's net production revenues.
Currently, all of the group's production comes from fields in the PNGF Sud asset in Congo Brazzaville. The group's operations and cash flow will be restricted to a very limited number of fields. If mechanical or technical problems, storms, shutdowns or other events or problems affect the current or future production of the current producing assets of the group, or new fields coming into production, it may have direct and significant impact on a substantial portion of the group's production and hence the group's revenue, profits and financial position as a whole.
Rising climate change concerns have led and could lead to additional legal and/or regulatory measures which could result in project delays or cancellations, a decrease in demand for fossil fuels and additional compliance obligations, each of which could materially and adversely impact the group's costs and/or revenues.
In general, the group's operations are subject to risks which are typical for the offshore oil and gas industry, all of which may have a material adverse effect on the group's operations, cash flow and financial position, relating (but not limited) to the following:
■ extension of existing licences and permits, including whether any extensions will be subject to onerous conditions;
The overall risk management program seeks to minimise the potential adverse effects of unpredictable fluctuations in financial markets on financial performance, i.e., risks associated with currency exposures and debt servicing. Financial instruments such as derivatives, forward contracts and currency swaps are continuously being evaluated for the hedging of such risk exposures.
Due to the international nature of its operations, the group is exposed to risk arising from currency exposure, primarily with respect to the Norwegian Kroner (NOK), and the Great British Pound (GBP).
The group's activities are and will continue to be capital intensive. The group expects future investments into existing and new hydrocarbon assets to be served by cash flow from ongoing operations. However, it is also expected that the group will look to raise debt to part-fund future growth. Such debt may not be timely available, or only be available at terms which are unattractive or makes investments less profitable than first expected. Restrictions in raising, or the unavailability of debt may prevent the group from grosing as planned and may make the group to forego or lose attractive opportunities which in turn could have a negative impact on the group's financial position and future prospects.
PetroNor E&P ASA is listed on the Oslo Stock Exchange where it trades under the ticker symbol PNOR. At 31 December 2022, the company's
share capital consisted of 1,423,568,543 ordinary shares. At an extraordinary general meeting on 23 February 2022, PetroNor E&P ASA issued new shares in a ratio of 1:1 to the existing shareholders of PetroNor E&P Limited.
The company has one class of shares in issue, and in accordance with the Norwegian Public Limited Companies Act, all shares in that class provide equal rights in the company. Each of the shares carries one vote. The shares are freely transferrable. The Articles of Association do not provide for any restrictions on the transfer of shares, or a right of first refusal for the shares. Share transfers are not subject to approval by the board of directors. The shares are registered in book-entry form with the Norwegian Central Securities Depository (VPS) and have ISIN NO0011157232.
At 31 March 2023, the company had 8,352 shareholders and 1,423,568,543 shares. The table below shows the 20 largest shareholders in the company:
| # | Shareholder | Number of shares | Per cent |
|---|---|---|---|
| 1 | Petromal LLC 1 | 481,481,666 | 33.82% |
| 2 | Symero Limited 2 | 138,763,636 | 9.75% |
| 3 | NOR Energy AS 3 | 135,070,623 | 9.49% |
| 4 | Ambolt Invest AS 4 | 87,583,283 | 6.15% |
| 5 | Gulshagen III AS 5 | 45,000,000 | 3.16% |
| 6 | Gulshagen IV AS 5 | 45,000,000 | 3.16% |
| 7 | Energie AS | 24,313,630 | 1.71% |
| 8 | Nordnet Livsforsikring AS | 21,722,952 | 1.53% |
| 9 | Nordnet Bank AB | 20,356,061 | 1.43% |
| 10 | Enga Invest AS | 10,722,775 | 0.75% |
| 11 | Omar Al-Qattan | 7,645,454 | 0.54% |
| 12 | Leena Al-Qattan | 7,645,454 | 0.54% |
| 13 | Pust For Livet AS | 7,497,609 | 0.53% |
| 14 | Danske Bank A/S | 7,001,749 | 0.49% |
| 15 | UBS Switzerland AG | 6,920,643 | 0.49% |
| 16 | Avanza Bank AB | 4,175,551 | 0.29% |
| 17 | Helge Holdhus | 4,014,000 | 0.28% |
| 18 | Sandberg JH AS | 4,000,000 | 0.28% |
| 19 | Spit Air AS | 4,000,000 | 0.28% |
| 20 | Kjell Rygg | 3,399,200 | 0.24% |
| Subtotal | 1,066,314,286 | 74.90% | |
| Others | 357,254,257 | 25.10% | |
| Total | 1,423,568,543 | 100.00% |
1) Non-Executive Chairman, Mr. Alhomouz is the CEO of Petromal LLC. 109,520,419 of the shares held by Petromal LLC are recorded in the name of nominee company, Clearstream Banking S.A. on behalf of Petromal LLC.
2) Symero Ltd is the 100 per cent owned subsidiary of NOR Energy AS
3) NOR Energy AS is a company controlled jointly by former CEO, Mr. Søvold, and former subsidiary company director, Mr. Ludvigsen through indirect beneficial interests.
4) Ambolt Invest AS is a company controlled by board member Mr.Norman-Hansen.
5) Gulshagan III AS and Gulshagan IV AS are companies controlled by Mr. Søvold through an indirect beneficial interest.
Unissued shares under option
At the date of the publishing of this report there were no share options in the company.
213,400 options with an exercise price of NOK 2.50 each in PetroNor E&P Limited (Australia) expired on 11 January 2022 before the redomicile to Norway. Further 1,176,070 options with an exercise price of NOK 7.75 each expired on 31 May 2022.
No ordinary shares were issued on the exercise of options in 2022 (2021: nil).
No other current directors hold shares or options.
The board of PetroNor E&P ASA held a total of 11 board meetings and 2 extraordinary meetings in 2022. The number of directors' meetings of PetroNor E&P Limited (Australia) held during the period where each director held office during the financial year was five.
The group has taken out an insurance policy to indemnify the directors and officers of the group against liability when acting for the group.
PetroNor is required to report on its corporate responsibility and selected related issues under §3-3a and §3-3c of the Norwegian Accounting Act. The detailed reporting on all relevant topics can be found in the separate ESG report, which is included in this Annual Report on page 25.
Outside the PetroNor head office in Oslo following listing on the Oslo Bors.
Good corporate governance provides the foundation for long-term value creation, to the benefit of shareholders, employees and other stakeholders. The Board of PetroNor has established a set of governance principles in order to ensure a clear division of roles between the Board, the executive management and the shareholders. The principles are based on the Norwegian Code of Practice for Corporate Governance.
PetroNor EP& ASA is subject to annual corporate governance reporting requirements under section 3-3b of the Norwegian Accounting Act and the Norwegian Code of Practice for Corporate Governance, cf. section 7 on the continuing obligations of stock exchange listed companies.
The Accounting Act may be found (in Norwegian) at www.lovdata.no. The Norwegian Code of Practice for Corporate Governance, which was last revised on 14 October 2021, may be found at www.nues.no.
PetroNor revised its Code of Conduct due to the change in legal legislation as a consequence of installing a Norwegian entity as the new Parent company of the group. The full policy is available on the company's website. The annual statement on corporate governance for 2022 has been approved by the board and can be found on page 34 in this Annual Report.
The group made no investments in research and development in 2022 or 2021.
This country-by-country report has been developed to comply with the legal requirements in the Norwegian Security Trading Act ("Verdipapirhandelloven") § 5-5a. The detailed regulation can be found in the regulation "Forskrift om land-forland rapportering".
In 2022, the company was engaged in extracting activities encompassed by the legislation above in the following countries: Republic of Congo, Nigeria, The Gambia, Guinea-Bissau and Senegal. This report discloses relevant payments to governments for extractive activities in the countries above,
in addition to some contextual information as required by the regulation in the "Forskrift om landfor-land rapportering".
The report includes direct payments to governments from subsidiaries, joint operations, and joint ventures. In some cases, however, certain payments to governments may be made by an operator on behalf of a partnership. This is often the case for area fees. In such cases, the company will report their paying interest share of the payment made by the operator.
Government – In the context of this report, a government means any national, regional, or local authority of a country. It includes a department, agency or undertaking controlled by that authority.
Project – For this reporting, a project is defined as an investment in a concession agreement.
Licence fees – Typically levied on the right to use a geographical area for exploration, development, and production, and include rental fees, area fees, entry fees, severance tax, concession fees and other considerations for licences and/or concessions. Administrative government fees that are not specifically related to the extractive sector, or to access extractive resources, are excluded.
Materiality – As per the "Forskrift om land-for-land rapportering", payments made as a single payment, or as a series of connected payments that equal or exceed Norwegian Kroner (NOK) 800,000 during the year are disclosed.
Reporting currency – Payments to governments are converted from the functional currency of each legal entity into the presentation currency, United States Dollars (USD). The payments for entities whose functional currencies are other than USD are converted into USD at the foreign exchange rate at the average annual rate.
The consolidated overview below discloses the sum of the company's payments to governments in each individual country where extractive activities are performed, per country/project.
| In USD thousand | Royalties | Oil tax | Other amounts | Total |
|---|---|---|---|---|
| PNGF Sud | 25,650 | 46,803 | 1,987 | 74,440 |
| Total Congo | 25,650 | 46,803 | 1,987 | 74,440 |
| A4 | Nil | Nil | 1,000 | 1,000 |
| Total The Gambia | Nil | Nil | 1,000 | 1,000 |
| Sinapa Esperanca |
Nil Nil |
Nil Nil |
111 111 |
111 111 |
| Total Guinea-Bissau | Nil | Nil | 222 | 222 |
| OML 113* | Nil | Nil | 1,000 | 1,000 |
| Total Nigeria | Nil | Nil | 1,000 | 1,000 |
* From the point of acquisition in July 2022.
Other amounts includes payroll, payments under licence obligations, and other local taxes. Due to the arbitration status of the ROP and SOSP licences in Senegal, no payments were made in relation to these projects during 2022.
As per the "Forskrift om land-for-land rapportering" it is required that the company report on certain contextual information at a corporate level. This includes information on localisation of subsidiary, employees per subsidiary, and interests paid or payable to other legal entities within the group.
Active legal corporate structure of the group during 2022 is set out below:
| Main country of | Interest paid or payable | ||
|---|---|---|---|
| In USD thousand | operations | EEs 1 | to a group entity |
| Norway | |||
| PetroNor E&P ASA | Norway | - | - |
| PetroNor E&P Services AS | Norway | 3 | - |
| Hemla Africa Holding AS | Norway | - | - |
| Aje Production AS | Norway | - | - |
| Australia | |||
| PetroNor E&P Pty Ltd | Australia | - | - |
| Cyprus | |||
| PetroNor E&P Ltd | Cyprus | 1 | 360 |
| Republic of Congo | |||
| Hemla E&P Congo SA | Republic of Congo | 3 | 304 |
| United Kingdom | |||
| PetroNor E&P Services Ltd | United Kingdom | 4 | - |
| Nigeria | |||
| PetroNor E&P Ltd | Nigeria | 4 | - |
| Aje Production Ltd | Nigeria | - | - |
| Netherlands | |||
| Aje Services Holding BV | The Netherlands | - | - |
| Aje Nigeria Holdings BV | The Netherlands | - | - |
| Cayman Islands | |||
| Petroleum E&P Gambia Ltd | The Gambia | 3 | - |
| African Petroleum Senegal Ltd | Senegal | - | - |
| Senegal | |||
| African Petroleum Senegal SAU | Senegal | 2 | - |
| Sweden | |||
| PetroNor E&P AB | Guinea-Bissau | - | - |
1) Average number of employees' during the year excluding directors.
Just before the year-end in 2021, the company refreshed its code of Conduct and associated policies in anticipation of becoming subject to the laws and regulations of Norway with the redomicile project and intention to move the listing to the main Oslo Stock Exchange. The redomicile was completed in February 2022 resulting in PetroNor E&P ASA becoming the parent entity of the Group and listing on the Oslo Børs.
On 26 January 2023, two new directors were appointed to the board. The appointments were pursuant to recommendations from the nomination committee. The two new directors, Mrs. Azza Fawzi and Mr. Jarle Norman-Hansen, take the company's board to a total of six directors.
In the Official Gazette of Guinea-Bissau (Boletim Oficial 45), it was announced that following the withdrawal of FAR Limited from the Sinapa and Esperança licences offshore Guinea-Bissau, their equity interest had been awarded to PetroNor.
At the start of February, 317,904 bbls of oil were lifted from the Djeno Terminal. This sale generated a cash inflow of USD 24.1 million. At the end of March, a further 260,362 bbls of oil were lifted generating USD 21.2 million of cash inflow.
In a CPR update prepared by AGR Petroleum Services AS on the company's PNGF Sud asset in Congo, the 2P reserves were updated to 18.5 MMbbls with 2C reserves updated to 23.5 MMbbls on a gross basis.
Except for the above, the company has not identified any events with significant accounting impacts that have occurred between the end of the reporting period and the date of the publishing of this report.
As the infill drilling program for Litanzi and Tchendo continues with the drilling rig returning in the second quarter, the company looks forward to seeing the continued impact of this significant three year CAPEX investment program on the production levels of the PNGF Sud licence as these new wells come into operation.
The company will continue to seek partners for its high equity exploration portfolio to share in the value creation through the drill bit.
After the 2022 hearings in Paris for the arbitration matter associated with the Senegalese licences, a decision is expected from the Tribunal.
The board wishes to thank the staff, consultants, services providers and shareholders for their continued commitment to the company.
We hereby confirm that, to the best of our knowledge, the consolidated annual financial statements for 1 January to 31 December 2022 have been prepared in accordance with applicable accounting standards and that the information in the financial statements give a true and fair view of the assets, liabilities, financial position and profit or loss of the company. We confirm that the financial statements give an accurate and fair view of the development, profit, and position of the company, as well as a description of the principal risks and uncertainties it is facing.
Oslo, Norway, 28 April 2023 The board of directors and CEO – PetroNor ASA
Eyas Alhomouz Gro Kielland Joseph Iskander Ingvil Smines Tybring-Gjedde Chair Director Director Director
Azza Fawzi Jarle Norman-Hansen Jens Pace Director Director Interim CEO
Pursuant to the Norwegian Public Limited Liability Companies Act (the "Companies Act") Section 6-16a and related regulations, the board will present the following statement regarding remuneration to the 2022 annual general meeting.
The committee must at least annually review and re-assess its terms of reference and the instructions relating to the review and determination of remuneration of the executives and senior management team. Any recommended changes must be proposed to the board, which must have sole authority to amend the terms of reference of the remuneration committee.
The committee must be appointed by the board to:
The committee may hold meetings at such time and location as the committee may determine, but in no event must the committee meet less frequently than annually. When it deems it appropriate, the committee may meet immediately before or after any meeting of the board, but should otherwise meet separately from the board.
At any meeting of the committee, a majority of its members must constitute a quorum. When a quorum is present at any meeting, a majority of committee members present may take any action.
The committee may establish rules and procedures for the conduct of its meetings that are consistent with its charter.
The members and the chair of the committee must be appointed and replaced by the board. The committee must be composed of three members. The majority of the members of the committee should be independent of the company's management.
The chair of the committee must be elected by the committee among those of its members who are independent of the company's management.
The chair of the committee must report annually to the board in an executive session on the committee's activities. Such annual reports must include a review of the committee's performance.
The committee must annually review its own performance.
The committee's duties and responsibilities must be to:
In determining the long-term incentive component of the CEO compensation, if any, the committee may consider the company's performance and relative shareholder return, the value of similar incentive awards given to CEO's at comparable companies and the awards given to the CEO in past years;
and provisions when, and if, appropriate, as well as any special supplemental benefits; and
■ review major organisational and staffing matters.
The committee has the authority to retain and terminate compensation consultants or firms to assist in the evaluation of the compensation of the executive management team and the board, including the authority to approve such consultants' or firms' fees and other retention terms, which must be borne by the company.
As an international player in its industry, the company is determined to compete in a market that is at the top management level internationally when determining salaries for managers in the company.
It is the board's policy that in order to ensure the best possible leadership, salaries must be offered at satisfactory levels for the individual, and that are competitive in an international market. Due to the company's international business, the level of executive pay may, as a starting point, be relatively high in a national context.
It is the company's policy that executive salaries should mainly be expressed in a fixed monthly salary that reflects the person's position and experience.
Pension schemes shall in principle be the same for managers as stipulated in general for employees in the company. The board may, however, determine additional pensions and/or insurance schemes for certain executives.
Severance pay schemes established upon resignation will normally be seen in connection with confidentiality clauses and anti-competitive clauses in the individual employment contract, so that they only compensate for such restrictions in the person's right to take up new work. As a starting point, severance pay schemes shall have deductions for income elsewhere.
Currently, the company does not have any share based incentive schemes, nor any bonus schemes. The board will consider to introduction of such schemes in the future.
Any deviations from these principles will be reported in the remuneration report for the relevant year.
Detailed information about the individual remuneration to the members of the board and senior executives in 2022 and their share ownership is detailed in the consolidated financial statements note 25B Related Parties – Board and key management personnel remuneration.
Oslo, Norway, 28 April 2023 The board of directors – PetroNor ASA
Eyas Alhomouz Gro Kielland Joseph Iskander Ingvil Smines Tybring-Gjedde Chair Director Director Director
| Consolidated statement of comprehensive income 68 | ||
|---|---|---|
| Consolidated statement of financial position 69 | ||
| Consolidated statement of changes in equity70 | ||
| Consolidated statement of cash flows71 | ||
| Notes to the consolidated financial statements 72 | ||
| Note 01 | Corporate information72 | |
| Note 02 | Basis of preparation72 | |
| Note 03 | Significant accounting judgements, estimates, and assumptions 73 | |
| Note 04 | Revenue 74 | |
| Note 05 | Cost of sales74 | |
| Note 06 | Other operating income74 | |
| Note 07 | Exploration expenses 75 | |
| Note 08 | Administrative expenses75 | |
| Note 09 | Finance expenses 76 | |
| Note 10 | Tax expense 76 | |
| Note 11 | Earnings per share77 | |
| Note 12 | Inventories 77 | |
| Note 13 | Trade and other receivables 78 | |
| Note 14 | Cash and cash equivalents78 | |
| Note 15 | Segment information79 | |
| Note 16 | Property, plant, and equipment79 | |
| Note 17 | Intangible assets80 | |
| Note 18 | Leases 81 | |
| Note 19 | Trade and other payables82 | |
| Note 20 | Loans and borrowings 82 | |
| Note 21 | Provisions83 | |
| Note 22 | Deferred tax liabilities84 | |
| Note 23 | Share capital84 | |
| Note 24 | Reserves 85 | |
| Note 25 | Related party transactions 86 | |
| Note 26 | Acquisition of subsidiaries 90 | |
| Note 27 | Risk management92 | |
| Note 28 | Financial instruments 95 | |
| Note 29 | Commitments and contingencies95 | |
| Note 30 | Events subsequent to reporting date 96 | |
| Note 31 | Summary of accounting policies96 |
| Statement of directors' responsibility 117 | |
|---|---|
| Alternative performance measures 123 | |
| Glossary and definitions124 | |
| Corporate directory124 |
For the year ended 31 December
| Amounts in USD thousand | Note | 2022 | 2021 |
|---|---|---|---|
| Revenue | 4 | 146,066 | 106,463 |
| Cost of sales | 5 | (46,210) | (34,585) |
| Gross profit | 99,856 | 71,878 | |
| Other operating income | 6 | - | 866 |
| Exploration expense | 7 | 1,630 | (2,270) |
| Administrative expenses | 8 | (14,378) | (13,131) |
| Profit from operations | 87,108 | 57,343 | |
| Finance expense | 9 | (3,322) | (3,041) |
| Foreign exchange gain/(loss) | (1,932) | (56) | |
| Profit before tax | 81,854 | 54,246 | |
| Tax expense | 10 | (47,579) | (33,102) |
| Profit/(loss) for the year | 34,275 | 21,144 | |
| Other comprehensive income: Exchange losses arising on translation of foreign operations |
1,418 | (364) | |
| Items that may subsequently be reclassified to profit or loss | 1,418 | (364) | |
| Total comprehensive income/(loss) | 35,693 | 20,780 | |
| Profit/(loss) for the year attributable to: | |||
| Owners of the parent | 26,887 | 12,314 | |
| Non-controlling interest | 25a | 7,388 | 8,830 |
| Total | 34,275 | 21,144 | |
| Total comprehensive income/(loss) attributable to: | |||
| Owners of the parent | 28,305 | 12,208 | |
| Non-controlling interest | 25a | 7,388 | 8,572 |
| Total | 35,693 | 20,780 | |
| Earnings per share attributable to members: | USD cents | USD cents | |
| Basic profit/(loss) per share | 11 | 1.96 | 1.06 |
| Diluted profit/(loss) per share | 11 | 1.96 | 1.06 |
The accompanying notes form part of these consolidated financial statements.
At 31 December
| Amounts in USD thousand | Note | 2022 | 2021 |
|---|---|---|---|
| ASSETS | |||
| Current assets | |||
| Inventories | 12 | 18,824 | 6,227 |
| Trade and other receivables | 13 | 1,171 | 13,820 |
| Cash and cash equivalents | 14 | 24,816 | 31,755 |
| Total | 44,811 | 51,802 | |
| Non-current assets | |||
| Property, plant, and equipment | 16 | 67,479 | 39,397 |
| Intangible assets | 17 | 42,283 | 7,172 |
| Right-of-use assets | 18 | 462 | 44 |
| Other receivables | 13 | 29,432 | 26,837 |
| Total | 139,656 | 73,450 | |
| Total assets | 184,467 | 125,252 | |
| LIABILITIES | |||
| Current liabilities | |||
| Trade and other payables | 19 | 20,751 | 29,996 |
| Lease liability | 18 | 179 | 58 |
| Loans and borrowings | 20 | 5,500 | 13,079 |
| Total | 26,430 | 43,133 | |
| Non-current liabilities | |||
| Loans and borrowings | 20 | 5,500 | - |
| Lease liability | 18 | 280 | - |
| Provisions | 21 | 24,563 | 16,302 |
| Deferred tax liabilities | 22 | 9,031 | - |
| Other payables | 19 | 8,738 | - |
| Total | 48,112 | 16,302 | |
| Total liabilities | 74,542 | 59,435 | |
| Net assets | 109,925 | 65,817 | |
| Issued capital and reserves attributable to owners of the parent | |||
| Issued capital | 23 | 72,115 | 62,115 |
| Reserves | 24 | (3) | (1,421) |
| Retained earnings | 24 | 25,497 | (1,390) |
| Total | 97,609 | 59,304 | |
| Non-controlling interests | 25a | 12,316 | 6,513 |
| Total equity | 109,925 | 65,817 |
The accompanying notes form part of these consolidated financial statements.
The financial statements were approved and authorised for issue by the board of directors on 28 April 2023.
| Foreign currency |
Non | ||||||
|---|---|---|---|---|---|---|---|
| Share | Share | translation | Retained | controlling | |||
| Amounts in USD thousand | Note | capital | premium | reserve | earnings | interest | Total |
| For the year ended 31 December 2022 | |||||||
| Balance at 1 January 2022 | 62,115 | - | (1,421) | (1,390) | 6,513 | 65,817 | |
| Profit for the year | - | - | - | 26,887 | 7,388 | 34,275 | |
| Other comprehensive income | - | 1,418 | - | - | 1,418 | ||
| Total comprehensive loss for the year | - | - | 1,418 | 26,887 | 7,388 | 35,693 | |
| Unwinding PetroNor E&P Ltd (Australia) share capital | (62,115) | - | - | - | - | (62,115) | |
| Issue of shares in PetroNor E&P ASA | 23 | 149 | 61,966 | - | - | - | 62,115 |
| Issue of ordinary shares as consideration for business combination |
23 | 10 | 9,990 | - | - | - | 10,000 |
| Dividends to non-controlling interest | - | - | - | - | (1,585) | (1,585) | |
| Balance at 31 December 2022 | 159 | 71,956 | (3) | 25,497 | 12,316 | 109,925 | |
| For the year ended 31 December 2021 | |||||||
| Balance at 1 January 2021 | 17,735 | - | (956) | (8,853) | 14,370 | 22,296 | |
| Profit/(loss) for the year | - | - | - | 12,314 | 8,830 | 21,144 | |
| Other comprehensive income | - | - | (106) | - | (258) | (364) | |
| Total comprehensive loss for the year | - | (106) | 12,314 | 8,572 | 20,780 | ||
| Issue of capital | 23 | 45,943 | - | - | - | - | 45,943 |
| Share issue costs | 23 | (1,563) | - | - | - | - | (1,563) |
| Acquisition of equity interest from non-controlling interest |
- | - | (359) | (4,851) | (16,429) | (21,639) | |
| Balance at 31 December 2021 | 62,115 | - | (1,421) | (1,390) | 6,513 | 65,817 | |
The issued share capital for PetroNor E&P Ltd (Australia) formerly the parent entity in 2021 is adjusted to reflect historic fair value adjustments on two reverse takeover events so as to reflect group share capital. The like for like share exchange and relisting on the Oslo Børs is a continuation of the business and so group share capital remains unchanged following the issue of 1,326,991,006 shares.
The accompanying notes form part of these consolidated financial statements.
For the year ended 31 December
| Amounts in USD thousand | Note | 2022 | 2021 |
|---|---|---|---|
| Cash flows from operating activities | |||
| Profit for the year | 81,854 | 54,246 | |
| Adjustments for: | |||
| Depreciation and amortisation | 9,152 | 4,422 | |
| Amortisation of right-of-use asset | 146 | 168 | |
| Unwinding of discount on decommissioning liability | 842 | 995 | |
| Impairment reversal – inventory | (2,519) | - | |
| Net foreign exchange differences | 1,418 | (364) | |
| Finance expense | 2,444 | 2,038 | |
| Total | 93,337 | 61,505 | |
| Decrease/(increase) in trade and other receivables | 12,631 | (8,062) | |
| Decrease/(increase) in advance against decommissioning cost | 13 | (2,595) | (5,577) |
| Increase in abandonment provision | 3,652 | - | |
| Increase in inventories | 12 | (10,078) | (2,649) |
| (Decrease)/increase in trade and other payables | (11,875) | 7,758 | |
| Cash (used in) / generated from operations | 85,072 | 52,975 | |
| Income taxes paid | 10 | (47,579) | (33,102) |
| Net cash flows from operating activities | 37,493 | 19,873 | |
| Investing activities | |||
| Purchases of property, plant, and equipment | 16 | (35,756) | (19,759) |
| Purchases of intangible assets | 17 | (2,353) | (814) |
| Net cash flows from investing activities | (38,109) | (20,573) | |
| Financing activities | |||
| Issue of ordinary shares | 23 | (52) | 27,943 |
| Share issue costs | - | (1,563) | |
| Proceeds from loans and borrowings | 20 | 11,000 | - |
| Repayment of loans and borrowings | 20 | (13,079) | (5,833) |
| Interest on loans and borrowings | 20 | (2,444) | (2,038) |
| Repayment of principal portion of lease liability | 18 | (127) | (159) |
| Repayment of interest portion of lease liability | 18 | (36) | (8) |
| Dividends paid to non-controlling interest | (1,585) | - | |
| Net cash (used in) / from financing activities | (6,323) | 18,342 | |
| Net (decrease)/increase in cash and cash equivalents | (6,939) | 17,642 | |
| Cash and cash equivalents at beginning of year | 31,755 | 14,113 | |
| Cash and cash equivalents at end of year | 14 | 24,816 | 31,755 |
The accompanying notes form part of these consolidated financial statements.
The consolidated financial statements of the company and its subsidiaries (together "the group") for the year ended 31 December 2022 was authorised for issue in accordance with a resolution of the directors on 28 April 2023.
PetroNor E&P ASA is a 'for profit entity' and is a company limited by shares incorporated in Norway. Its shares are publicly traded on the Oslo Børs (code: PNOR), the main regulated marketplace of the Oslo Stock Exchange, Norway. The principal activities of the group are the exploration and production of crude oil.
PetroNor E&P ASA's consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) which have been adopted by the EU and are mandatory for financial years beginning on or after 1 January 2022, and Norwegian disclosure requirements listed in the Norwegian Accounting Act as of 31 December 2022. The consolidated financial statements have been prepared on a historical cost basis. The consolidated financial statements have been prepared on the basis of uniform accounting principles for similar transactions and events under otherwise similar circumstances.
The consolidated financial statements are presented in United States Dollars, which is the functional currency for all the material subsidiaries, and all values are rounded to the thousand dollars unless otherwise stated.
The board of directors confirms that the consolidated financial statements have been prepared pursuant to the going concern assumption, 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. PetroNor E&P ASA is the parent company of the PetroNor Group. Its consolidated financial statements have been prepared on the assumption that PetroNor will continue as a going concern. The group recognises that in order to fund on-going operations and pursue organic and inorganic growth opportunities it will require additional funding. This funding may be sourced through joint venture equity or share issues or through debt finance.
The going concern basis assumes the continuity of normal business activity and the realisation of assets and the
settlement of liabilities in the normal course of business. The underlying business of the group created a net profit after tax of USD 34.3 million for the year ended 31 December 2022, with strong production from the Congo assets in the first quarter of 2023. As at 31 December 2022, the group had a cash balance of USD 24.8 million (2021 USD 31.8 million). The company has listed on the main exchange of Oslo Børs, successfully refinanced its debt, achieved high production levels following a successful in-fill drilling campaign and continues to seek for potential partners to join the company on its exploration portfolio. This demonstrates that the business has continued to operate effectively, and businesses are willing to engage with the company and this has enabled the directors of PetroNor ("the directors") to form the opinion that the company will be in a position to continue to meet its liabilities and obligations for a period of at least twelve months from the date of signing this report.
These consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities that might be necessary should the group not continue as a going concern.
The following financial review is based on the consolidated financial statements of PetroNor E&P ASA and its subsidiaries. The statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the EU as well as Norwegian accounting legislation.
In the view of the board, the statement of comprehensive income, statement of changes in equity, statement of financial position and cashflow provide satisfactory information about the operations, financial results and position of the group and the parent company at 31 December 2022.
The directors evaluate estimates and judgements incorporated in the consolidated financial statements based on historical knowledge and the best available current information. Estimates assume a reasonable expectation of future events and are based on current trends and economic data, obtained both externally and within the group.
Management has identified the following critical accounting policies for which significant judgements, estimates, and assumptions are made. Actual results may differ from these estimates under different assumptions and conditions and may materially affect financial results or the financial position reported in future period.
Further details of the nature of these assumptions and conditions may be found in the relevant notes to the financial statements.
Hydrocarbon reserves are estimates of the amount of hydrocarbons that can be economically and legally extracted from the group's oil and gas properties. The group estimates its commercial reserves and resources 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 current longterm Brent oil price assumption used in the estimation of commercial reserves is USD 60/bbl. The carrying amount of oil and gas properties and licenses at 31 December 2022 are shown in note 16 and 17.
The group estimates and reports hydrocarbon reserves in line with the principles contained in the Society of Petroleum Engineers (SPE) Petroleum Resources Management Reporting System (PRMS) framework. 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 operates in several tax jurisdictions, and consequently, its income is subject to various rates and rules of taxation. As a result, the company's effective tax rate may vary significantly depending upon the profitability of operations in the different jurisdictions.
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.
Additionally, 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.
Additional information on the accounting policy for taxes is explained further in note 10 and 31M.
Decommissioning 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 decommissioning 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 decommissioning costs. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The provision at reporting date represents the management's best estimate of the present value of the future decommissioning costs required. Additional information is provided in note 21.
Management must determine whether there are circumstances indicating a possible impairment of the group's oil and gas assets. Changes in the circumstances or expectations of future performance of an individual asset or a group of assets may be an indicator that the asset is impaired, requiring the carrying amount to be written down to its recoverable amount. Assessment for indicators of impairment includes assessments of expected future cash flows, future oil and gas prices, cost profiles, indicators that the asset will be uneconomic to develop, geological evaluation and the date of expiration of the licences. Impairments other than impairments of goodwill are reversed where impairment indicators are no longer present.
PetroNor has recognised "technical goodwill" arising on the OML 113 business combination. Technical goodwill is commonly used in the oil and gas industry to describe a category of goodwill arising as an offsetting amount to deferred tax recognised in business combinations. The technical goodwill has been allocated to the OML 113 Nigeria cash generating unit (CGU) and will be assessed for impairment where there are indications that the CGU is impaired. Goodwill is not depreciated and hence, impairment of technical goodwill is expected on a recurring basis,
unless there are positive changes in underlying economic assumptions for the asset. When performing the impairment test for technical goodwill, deferred tax recognised in relation to the acquired assets in a business combination reduces the net carrying value prior to the eventual impairment charges. When deferred tax from the initial recognition decreases, more goodwill is exposed for impairment. After initial recognition, depreciation of values calculated in the purchase price allocations from business combinations will result in decreased deferred tax liability.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Revenue from contracts with customers Revenue from sales of petroleum products |
72,837 | 57,601 |
| Other revenue Assignment of tax oil Assignment of royalties |
47,579 25,650 |
33,102 15,760 |
| Total revenue | 146,066 | 106,463 |
| Quantity of oil lifted (barrels) Average selling price (USD per barrel) Quantity of net oil produced after royalty, cost oil and tax oil (barrels) |
800,177 90.99 900,495 |
831,089 69.31 821,536 |
All revenue from the sales of petroleum products in 2022 is generated, recognised and transferred at a point in time. Invoices are due for settlement thirty days from the bill of lading, the point at which crude oil had been loaded onto vessel for shipment. All group revenue is derived from production in the Republic of Congo from the PNGF
Sud offshore asset. The group presents profit oil tax and royalties on a grossed-up basis as an income tax expense with corresponding increase in oil and gas revenues and any associated royalties are included in cost of sales. Refer to note 31K for additional information.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Operating expenses | 16,636 | 14,303 |
| Royalty | 25,650 | 15,760 |
| Depreciation and amortisation of oil and gas properties | 9,134 | 4,385 |
| Provision for diversified investment | 1,710 | - |
| Movement in oil inventory | (6,920) | 137 |
| Total | 46,210 | 34,585 |
Provision for diversified investment expenditure has been reclassified from administrative expenses to cost of sales in 2022.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Other | - | 865 |
| Total | - | 865 |
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Impairment reversal Seismic data acquisition |
(2,519) 889 |
- 2,270 |
| Total | (1,630) | 2,270 |
Impairment on inventory was reversed in the period to reflect current market conditions in the drilling sector (refer to note 12). Costs not capitalised to intangible assets under group policies are expensed including seismic costs and the allocated time writing costs.
| Amounts in USD thousand | Note | 2022 | 2021 |
|---|---|---|---|
| Employee benefit expenses | 8A | 5,581 | 5,435 |
| Travelling expenses | 559 | 218 | |
| Legal and professional expenses | 5,209 | 2,620 | |
| Corporate social responsibility | 1,500 | 1,500 | |
| Provision for diversified investment | - | 1,051 | |
| Business development | 478 | 486 | |
| Other expenses | 1,051 | 1,821 | |
| Total | 14,378 | 13,131 |
Provision for diversified investment expenditure has been reclassified from administrative expenses to cost of sales in 2022.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Salaries | 4,834 | 4,793 |
| Short-term non-monetary benefits | 490 | 304 |
| Defined contribution pension cost | 43 | 41 |
| Social-security contributions and similar taxes | 214 | 297 |
| Total | 5,581 | 5,435 |
PetroNor is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension ("Lov om obligatorisk tjenestepensjon"). The Norwegian subsidiary that employs staff PetroNor E&P Services AS contributes to an external defined contribution scheme and therefore no pension liability is recognised in the statement of financial position.
Under the Pensions Act 2008, every employer in the UK must put certain staff into a workplace pension scheme and contribute towards it,
PetroNor E&P Services Limited the subsidiary that employs staff in the UK, contributes into an external defined contribution scheme. As such, no pension liability is recognised in the statement of financial position in relation to the company's UK-based employees.
There are currently no share-based payment incentive schemes in place for employees.
The cost of non-cash benefits to employees is disclosed as short-term non-monetary benefits above.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Paid or payable to BDO | ||
| Audit review of financial statements | ||
| BDO AS | 178 | - |
| BDO Network firms | 131 | 130 |
| Total | 309 | 130 |
| Other non-assurance services BDO related practices |
19 | 12 |
| Total | 19 | 12 |
| Paid or payable to other audit firms Audit or review of financial reports Other non-assurance services |
47 104 |
138 141 |
| Total | 151 | 279 |
Fees, excluding VAT, to the auditors are included in administration expenses.
| Amounts in USD thousand | Note | 2022 | 2021 |
|---|---|---|---|
| Unwinding of discount on decommissioning liability | 21 | 842 | 995 |
| Loan structuring fee | 165 | - | |
| Finance cost on lease liabilities | 18 | 36 | 8 |
| Interest on loans | 20 | 1,042 | 2,038 |
| Other interest | 1,237 | - | |
| Total | 3,322 | 3,041 |
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Petroleum revenue tax expense | ||
| Current income tax charge | 47,579 | 33,102 |
| Total tax expense reported in the consolidated statement of comprehensive income | 47,579 | 33,102 |
The income tax expense is only related to the subsidiary in Congo and represents the assignment of tax oil on the revenue from sales of petroleum products, note 4. There was no income tax expense in the other subsidiaries' jurisdictions nor
in the parent's jurisdiction as these companies are in taxable loss positions in both 2022 and 2021. Average effective tax rate for the year was 33 per cent (2021: 31 per cent) based on gross revenue of the group.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Profit attributable to ordinary shareholders | ||
| Profit from continuing operations attributable to the ordinary equity holders used in | ||
| calculating basic/diluted profit per share | 26,887 | 12,314 |
| Profit attributable to the ordinary equity holders used in calculating | ||
| basic/diluted profit per share | 26,887 | 12,314 |
| Weighted average number of ordinary shares outstanding during the period used in the calculation of earnings per share |
||
| Basic | 1,372,236,921 | 1,160,438,253 |
| Diluted | 1,372,729,890 | 1,161,827,723 |
| Earnings per share | ||
| Basic | 1.96 | 1.06 |
| Diluted | 1.96 | 1.06 |
Options on issue are considered to be potential ordinary shares and have been included in the determination of diluted loss per share only to the extent to which they are dilutive. There are nil options as at 31 December 2022 (2021: 1,389,470).
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Crude oil inventory Materials and supplies |
7,475 11,349 |
554 5,673 |
| Total | 18,824 | 6,227 |
Crude oil inventory is valued at cost of USD 29.43 per bbl (2021: USD 22.84 bbl). This is derived from the direct production costs USD 51.2 million (2021: 34.6 million) and the unit production cost USD 1.74 million (2021: 1.51 million).
The crude oil inventory and the material and supplies inventory are valued at the lower of cost and net realisable value. Cost is determined using the weighted average method. Net realisable value is the estimated selling price, less applicable selling expenses. The cost of inventory includes all
costs related to bringing the inventory to its current condition, including processing costs, labour costs, supplies, direct and allocated indirect operating overhead and depreciation expense, where applicable, including allocation of fixed and variable costs to inventory.
In the current accounting period inventory for the Guinea-Bissau drilling campaign was written back up to cost as current market conditions indicate that the net realisable value exceeds the cost.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Recoverability less than one year | ||
| Trade receivables | - | 13,431 |
| Other receivables | 1,171 | 389 |
| Total | 1,171 | 13,820 |
| Recoverability more than one year | ||
| Advance against decommissioning cost | 29,432 | 26,837 |
| Total | 29,432 | 26,837 |
In addition to the booking of decommissioning cost asset and liability, the contractors group and the Congolese Government have decided to set up funds for the decommissioning cost in an escrow account which is managed by the operator. The advances of the funds for the year are made on the basis of an average rate of USD 1.60 per barrel produced (2021: USD 3.68 per barrel). Refer to note 21 for further details on the decommissioning liability.
The group has adopted the simplified approach allowable under IFRS 9 Financial Instruments where the group measures the provision for impairment for trade receivables and amounts due from related parties at an amount equal to lifetime ECL. The ECL on trade receivables are estimated using a provision matrix by reference to past default experience of the debtor and an analysis of the debtors' current financial position, adjusted for factors that are specific to the debtors' general economic conditions and forward looking elements of the industry in which the debtors operate and an assessment of both the current as well as the forecast direction of conditions at the reporting date.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Cash in bank Restricted cash |
24,775 41 |
31,673 82 |
| Total | 24,816 | 31,755 |
Restricted cash at 31 December 2022 represents ringfenced cash payable to Norwegian authorities.
The following table represents the changes in liabilities arising from financing activities through cash flows and non-cash changes:
| Non-current | Current | ||
|---|---|---|---|
| Amounts in USD thousand | borrowings | borrowings | Total |
| At 1 January 2022 | - | 13,079 | 13,079 |
| Cash flows | 5,500 | (7,579) | (2,079) |
| Non-cash flows | - | - | - |
| As at 31 December 2022 | 5,500 | 5,500 | 11,000 |
| At 1 January 2021 | 14,912 | 4,000 | 18,912 |
| Cash flows | (1,833) | (4000) | (5,833) |
| Non-cash flows | - | - | - |
| Movement non-current to current | (13,079) | 13,079 | - |
| As at 31 December 2021 | - | 13,079 | 13,079 |
For management purposes, the group is organised into one main operating segment, which involves exploration and production of hydrocarbons. All of the group's activities are interrelated, and discrete financial information is reported to chief operating decision maker as a single segment. Accordingly, all significant operating decisions are based upon analysis of the group as one segment. The financial results from this segment are equivalent to the financial statements of the group as a whole.
The group only has one operating segment, being exploration and production of hydrocarbons.
The analysis of the location of non-current assets is as follows:
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Congo | 98,876 | 69,564 |
| The Gambia | 4,507 | 3,507 |
| Guinea-Bissau | 667 | 314 |
| Nigeria | 35,226 | 3 |
| Norway | 380 | 62 |
| Total | 139,656 | 73,450 |
| PRODUCTION ASSETS AND EQUIPMENT | ||
|---|---|---|
| --------------------------------- | -- | -- |
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Cost | ||
| At 1 January | 53,204 | 33,445 |
| Additions | 36,681 | 19,759 |
| Disposals | - | - |
| At 31 December | 89,885 | 53,204 |
| Depreciation At 1 January |
13,807 | 9,962 |
| Charge for the year Depreciation on disposals |
8,599 - |
3,845 - |
| At 31 December | 22,406 | 13,807 |
| Net carrying amount | ||
| At 31 December | 67,479 | 39,397 |
Production assets and equipment are carried at the following values:
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Oil & gas CAPEX | 62,544 | 33,968 |
| Decommissioning costs | 4,900 | 5,396 |
| Other | 35 | 33 |
| Total | 67,479 | 39,397 |
PPE assets are distributed geographically as follow:
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Congo | 66,542 | 39,377 |
| Nigeria | 927 | - |
| Other | 10 | 20 |
| Total | 67,479 | 39,397 |
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Cost | ||
| At 1 January | 11,210 | 10,396 |
| Additions in relation to business combinations (refer to note 26) | 24,268 | - |
| Additions | 2,353 | 814 |
| At 31 December | 37,831 | 11,210 |
| Accumulated amortisation and impairment | ||
| At 1 January | 4,038 | 3,461 |
| Amortisation | 541 | 577 |
| Impairment | - | - |
| At 31 December | 4,579 | 4,038 |
| Net carrying value | ||
| At 1 January | 7,172 | 6,935 |
| At 31 December | 33,252 | 7,172 |
| GOODWILL | ||
| Amounts in USD thousand | 2022 | 2021 |
| Cost | ||
| At 1 January | - | - |
| Additions in relation to business combinations (refer to note 25) Impairment |
9,031 - |
- - |
| At 31 December | 9,031 | - |
Goodwill of USD 9.0 million at 31 December 2022 consists of technical goodwill related to the acquisition that occurred during the year, note 26. Technical goodwill is subject to impairment testing whenever there is an indicator that the CGU to which it is allocated is impaired. Technical goodwill has been allocated to the OML 113 CGU and impairment assessments will be based on the underlying economics for the asset. When performing the impairment test for technical goodwill, deferred tax recognized in relation to the acquired assets in a business combination reduces the net carrying value prior to the eventual impairment charges. When deferred tax from the initial recognition decreases, more goodwill is exposed for impairment. After initial recognition, depreciation of values calculated in the purchase price allocations from business combinations will result in decreased deferred tax liability.
In 2017, subsidiary company Hemla E&P Congo SA acquired interests in three development and production permits (Tchendo: 20 per cent; Tchibouela: 20 per cent and Tchibeli-Litanzi: 20 per cent) which will respectively end in December 2037, for each of them, with possible extensions for 5 years. All these three licenses are called or named collectively "PNGF Sud" and together comprise an area of 482.28km2. The operator of the licences is Perenco, and the carrying value as
at 31 December 2022 is USD 2.8 million. This number is net of depletion, the Congo intangible assets are the only intangibles in active use and being amortised.
The corporate acquisition from Panoro Energy ASA during year, added an economic interest in the OML 113 field of 12.1913 per cent that is operated by Yinka Folawiyo Petroleum. There were two producing wells prior to suspending production in November 2021 due to the terminated contract with the FPSO, the Aje-4 with oil production and Aje-5ST2 with oil and gas production. The licence was renewed in 2018 and has a twenty-year term. The current strategy is to update the field development plan to expedite gas development and overall redevelopment of the venture. As at 31 December 2022, the carrying value of the licence was USD 24.3 million.
The A4 licence area is 1,376km2 and is operated by company subsidiary PetroNor E&P Gambia Ltd. PetroNor secured a new exploration licence (PEPLA) on 18 November 2022 and entered into the first exploration period which has a duration of three years. PetroNor hold 90 per cent equity with the Gambia National Petroleum Company as partner (10 per cent equity). As at 31 December 2022, the carrying value of the A4 licence is USD 4.5 million.
As at 31 December 2022, 78.57 per cent interest of the Sinapa and Esperança licences are held and operated by PetroNor subsidiary PetroNor E&P AB. Post year end it was confirmed that 21.43 per cent previously held by FAR Ltd had been transferred to PetroNor. The combined licences cover an area of 4,963km2 and have USD 0.6 million carrying value in the financial statements as at 31 December 2022. The current exploration phase runs to October 2023.
As at the date of this report, the company's subsidiary African Petroleum Senegal Limited awaits the decision of the arbitration proceedings with the International Centre for the Settlement of Investment Disputes (ICSID) regarding the interests in the Senegal Offshore Sud Profond and Rufisque Offshore Profond blocks in Senegal (ICSID case ARB/18/24). The combined licences cover an area of 15,796km2 and due to the arbitration process have nil carrying value in the financial statements as at 31 December 2022. Please refer to board director's report for additional information on the arbitration status.
Intangible assets are valued in accordance with group accounting policies and are assessed for indications of impairment in accordance with IAS 36. There were no indicators of impairment as at 31 December 2022 for the licence costs within the group. Refer to note 30I for additional information.
The group has adopted a policy of regional reserve reporting using external third-party companies to audit its work and certify reserves and resources. 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 March 2007. AGR Petroleum Services AS provided the 3rd party verifications of the PNGF Sud reserves. CPR Tracs International Limited provided the 3rd party verification of the Aje reserves.
The following is a summary of key results from the reserve reports (net of the group's share):
| Asset | 1P reserves | 2P reserves | 3P reserves |
|---|---|---|---|
| MMbbls | MMbbls | MMbbls | |
| PNGF Sud | 12.5 | 18.5 | 24.7 |
| Aje | - | - | - |
| Total | 12.5 | 18.5 | 24.7 |
1P) Proved reserves
Proved reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.
Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves.
Possible reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than probable reserves.
| Amounts in USD thousand | Right-of-use assets Office building |
Lease liabilities |
|---|---|---|
| At 1 January 2022 | 44 | 58 |
| Additions | 564 | 492 |
| Amortisation expense | (146) | - |
| Interest expense | - | 36 |
| Payments made | - | (127) |
| At 31 December 2022 | 462 | 459 |
| Right-of-use assets Office building |
Lease liabilities |
|---|---|
| 212 | 225 |
| - | - |
| (168) | - |
| - | 8 |
| - | (175) |
| 44 | 58 |
| - | 58 - |
| - |
| Amounts in USD thousand | 31 December 2022 | 31 December 2021 |
|---|---|---|
| Amortisation expense on right-of-use assets | 146 | 168 |
| Interest expense on lease liabilities | 36 | 8 |
| Expense relating to short-term lease | - | - |
| Total | 182 | 176 |
The total cash outflow for leases amount to USD 163,000 for the year.
| Amounts in USD thousand | Note | 2022 | 2021 |
|---|---|---|---|
| Amounts due less than one year | |||
| Trade payables | 15,437 | 22,014 | |
| Due to related parties | 25D | 2,019 | 3,449 |
| Taxes and state payables | 787 | 120 | |
| Other payables and accrued liabilities | 2,508 | 4,472 | |
| Total | 20,751 | 30,055 | |
| Amounts due more than one year | |||
| Other payables | 8,738 | - | |
| Total | 8,738 | - |
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| At 1 January | 13,079 | 18,912 |
| Received | 11,000 | - |
| Principal repayment | (13,079) | (5,833) |
| Interest on loan accrued | 1,042 | 1,539 |
| Interest on loan paid | (1,042) | (1,539) |
| At 31 December | 11,000 | 13,079 |
| Ageing of loans payable | ||
| Current | 5,500 | 13,079 |
| Non-current | 5,500 | - |
| Total | 11,000 | 13,079 |
In 2020, PetroNor agreed a USD 15 million facility with 12 months grace period and maturity date in October 2022. The loan was to be repaid in monthly instalments after the initial grace period and carried an interest rate of 9 per cent plus one-month LIBOR payable monthly if the oil price was below USD 40 per bbl and 12.5 per cent if the oil price was above USD 40 per bbl. The loan was secured against:
On 29 December 2022, HAH and Acqua Diversified Holdings SPC entered into an amended agreement to advance an additional USD 11.0 million to be repaid in eight quarterly instalments of USD 1.375 million. The remaining principal of USD 2.5 million was repaid along with outstanding interest and arrangement fees for the amended facility. The amended facility carries an interest rate of 11.0 per cent, and due to the group corporate restructure in February 2022, in addition to the previous security provided, a corporate guarantee was provided by the new parent company PetroNor E&P ASA.
The Acqua Diversified Holdings SPC loan has the following covenants and undertakings:
Separately on 28 September 2020, subsidiary company HAH paid a USD 3.9 million dividend to minority interest and related party Symero Ltd. An amount equal to the dividend was immediately loaned to the top company of the group at the time, PetroNor E&P Ltd (Australia), by Symero Ltd with interest rates matching those already provided by external financing and no security was provided for the loan. The maturity date was matched to the USD 15 million facility. On 21 December 2022, the principal balance of USD 3.9 million was repaid to Symero Ltd.
All covenants were complied with and there were no notifications of breaches during the year for both loans payable to Acqua Diversified Holdings SPC and Symero Ltd.
In accordance with joint venture 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 exact timing of the obligations is uncertain and depends on the rate the reserves of the field are depleted.
Based on the existing production profile of the PNGF Sud field and the size of the reserves, it is expected that expenditure on retirement is likely to be after more than ten years. The current bases for the provision are a discount rate of 6.5 per cent (2021: 6.5 per cent) and an inflation rate of 1.6 per cent (2021: 1.6 per cent). The initial decommissioning liability (ARO) study was prepared internally by the operator Perenco
and was presented to ARO committee in 2018. The company reassessed the applicable discount rate during 2022 based on the rates of government bonds issued in the Congo during the year. The impact of the change in discount factor was not considered material.
With the acquisition of the Panoro interest in the OML 113 venture, PetroNor added a decommissioning provision of USD 3.7million. The acquired OML113 assets are discounted at 2.50 per cent with an inflation rate of 2.0 per cent.
The following table presents a reconciliation of the beginning and ending aggregate amounts of the obligations associated with the retirement of oil and natural gas properties:
| Amounts in USD thousand | Note | 2022 | 2021 |
|---|---|---|---|
| At 1 January Arising during the year |
16,302 3,768 |
15,307 - |
|
| Unwinding of discount on decommissioning | 9 | 842 | 995 |
| At 31 December | 20,912 | 16,302 |
| Total | Property, plant, and equipment, Amounts in USD thousand and intangible assets |
|---|---|
| (9,031) | Deferred tax liabilities |
| (9,031) | Net asset/(liability) at 31 December 2022 |
| Property, plant, and equipment, | ||
|---|---|---|
| Amounts in USD thousand | and intangible assets | Total |
| Deferred tax liabilities | - | - |
| Net asset/(liability) at 31 December 2021 | - | - |
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Net deferred tax liability at 1 January Acquisitions and disposals |
- (9,031) |
- - |
| Net deferred tax liability at 31 December | (9,031) | - |
Deferred tax assets have not been brought to account in respect of tax losses and unrecognised capital allowances because as at 31 December 2022 it is uncertain when future taxable amounts will be available to utilise those temporary differences and losses. As at 31 December 2022, the carried forward gross tax loss is USD 132 million (2021: USD 116 million). Tax losses carried forward has increased by USD 16
million year on year, this is predominantly due to tax losses incurred in Norway (USD 10 million), United Kingdom (USD 1.3 million), Sweden (USD 1.1 million), other entities (3.6 million). Carried forward losses from previous periods do not have an expiry date. The deferred tax liability has arisen upon fair value adjustments as part of a business combination (refer to note 26 for additional detail).
Ordinary shares participate in dividends and the proceeds on winding up of the company in proportion to the number of shares held and in proportion to the amount paid up on the shares held.
At shareholders' meetings, each ordinary share entitles the holder to one vote in proportion to the paid-up amount of the share when a poll is called, otherwise each shareholder has one vote on a show of hands.
| Number of fully paid ordinary shares | 2022 | 2021 |
|---|---|---|
| Balance at the beginning of the year Issue of shares |
1,326,991,006 96,577,537 |
971,665,288 355,325,718 |
| Balance at 31 December | 1,423,568,543 | 1,326,991,006 |
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Opening balance | 62,115 | 17,735 |
| Reversal of shares as part of redomicile 1 | (62,115) | - |
| Issue of shares in PetroNor E&P ASA as part of redomicile 1 | 149 | - |
| Share capital issued as consideration for business combination 2 | 10 | - |
| Issue of ordinary shares | - | 45,943 |
| Share issue costs | - | (1,563) |
| Balance at end of the period | 159 | 62,115 |
1) On 24 February 2022, the company issued 1,326,991,006 ordinary shares as part of the implementation of the scheme of arrangement and redomicile from Australia to Norway. Shares are issued at the nominal value of 0.001 NOK and translated to 0.01 USD using the rate of exchange on the day of issue.
2) On 13 July 2022, PetroNor E&P ASA completed the acquisition of Pan-Petroleum Nigeria Holding BV and Pan-Petroleum Services Holdings BV that hold 100 per cent of the shares in Pan-Petroleum AJE Ltd. The upfront consideration was USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares. The shares were issued at the nominal value of 0.001 NOK USD using the daily exchange rate published by the Bank of England. Refer to note 26 for additional information.
Share premium reserve represents excess of subscription value of the shares over the nominal amount.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Opening balance | - | - |
| Issue of shares as part of redomicile | 61,966 | - |
| Share capital issued as consideration for business combination | 9,990 | - |
| Balance at end of the period | 71,956 | - |
The issued share capital for PetroNor E&P Ltd (Australia) formerly the parent entity in 2021 is adjusted downwards to reflect historic fair value adjustments on two reverse takeover events so as to reflect group share capital. The like for like share exchange and relisting on the Oslo Børs is a continuation of the business and so group share capital remains unchanged following the issue of 1,326,991,006 shares.
The management controls the capital of the company in order to maximise the return to shareholders and ensure that the company can fund its operations and continue as a going concern. Capital is defined as issued share capital.
The management effectively manages the company's capital by assessing the company's financial risks and adjusting its capital structure in response to changes in these risks and in the market. These responses include the management of expenditure and debt levels, distributions to shareholders and share and option issues. There have been no changes in the strategy adopted by the management to control the capital of the company since the prior reporting period.
The management monitors capital requirements through cash flow forecasting. The management may seek further capital if required through the issue of capital or changes in the capital structure. To maintain the listing on the Oslo Børs, PetroNor must continue to satisfy requirements on capital set by the Exchange. These requirements include a free float in excess of 25 per cent and a minimum number of shareholders.
The movement in reserves are reflected in the statement of changes in equity.
The foreign currency translation reserve is used to recognise foreign currency exchange differences arising on translation of functional currency to presentation currency.
All other net gains and losses and transactions with owners not recognised elsewhere.
No dividends were declared during the year by the parent company.
Holders of options do not have any voting or dividend rights in relation to the options. Share options are valued using the stochastic Black-Scholes model. The inputs to the model are the weighted average share price, the expected average exercise price, expected life, the risk free rate of return and the expected volatility. All options are fully vested and so no costs were charged in the current accounting period (2021 nil).
The following table reconciles the outstanding share options granted, exercised, and forfeited during the year:
| 2022 | 2021 | |||
|---|---|---|---|---|
| Number of options |
Weighted average exercise price equivalent USD |
Number of options |
Weighted average exercise price equivalent USD |
|
| Balance at beginning of the period Lapsed |
1,389,470 (1,389,470) |
0.79 0.79 |
1,389,470 - |
0.81 - |
| Balance at end of the year | - | - | 1,389,470 | 0.79 |
| Exercisable at end of the year | - | - | 1,389,470 | 0.79 |
As at 31 December 2022, all share options have expired.
The principal subsidiaries of the PetroNor E&P ASA, all of which have been included in these consolidated financial statements, are as follows:
| Proportion of effective ownership | ||||
|---|---|---|---|---|
| interest at 31 December | ||||
| Country of | Principal place | |||
| Name | incorporation | of business | 2022 | 2021 |
| PetroNor E&P Pty Limited | ||||
| (Previously called PetroNor E&P Ltd) | Australia | Australia | 100% | 100% |
| PetroNor E&P Ltd | Cyprus | Cyprus | 100% | 100% |
| PetroNor E&P Services AS | Norway | Norway | 100% | 100% |
| PetroNor E&P Services Ltd | United Kingdom | United Kingdom | 100% | 100% |
| PetroNor E&P AB | Sweden | Guinea-Bissau | 100% | 100% |
| PetroNor E&P Ltd | Nigeria | Nigeria | 100% | 100% |
| PetroNor E&P Gambia Ltd | Cayman Islands | The Gambia | 100% | 100% |
| Hemla Africa Holding AS | Norway | Norway | 100% | 100% |
| Hemla E&P Congo SA | Congo | Congo | 84.15% | 84.15% |
| African Petroleum Corporation Ltd | Cayman Islands | United Kingdom | 100% | 100% |
| African Petroleum Senegal Ltd | Cayman Islands | Senegal | 90% | 90% |
| African Petroleum Senegal SAU | Senegal | Senegal | 90% | 90% |
| Aje Production AS | Norway | Norway | 100% | 100% |
| Aje Services Holding BV (Previously called | ||||
| Pan-Petroleum Services Holding BV) | Netherlands | Netherlands | 100% | - |
| Aje Nigeria Holding BV (Previously called | ||||
| Pan-Petroleum Services Holding BV) | Netherlands | Netherlands | 100% | - |
| Aje Production Ltd (Previously called | ||||
| Pan-Petroleum Aje Ltd) | Nigeria | Nigeria | 100% | - |
Set out below is summarised financial information for the subsidiary that has non-controlling interests that are material to the group. The amounts disclosed for the subsidiary are before inter-company eliminations.
| Hemla E&P Congo SA | ||
|---|---|---|
| Amounts in USD thousand | 2022 | 2021 |
| Current asset | 28,363 | 37,936 |
| Current liabilities | 11,210 | 31,130 |
| Current net assets | 17,153 | 6,806 |
| Non-current assets | 98,876 | 69,577 |
| Non-current liabilities | 20,804 | 16,302 |
| Non-current net assets/(liabilities) | 78,072 | 53,275 |
| Net assets | 95,225 | 60,081 |
| Accumulated NCI | 16,091 | 10,215 |
| Hemla E&P Congo SA | |||
|---|---|---|---|
| Amounts in USD thousand | 2022 | 2021 | |
| Revenue | 146,067 | 106,464 | |
| Profit for the period | 45,503 | 31,685 | |
| Other comprehensive income | - | - | |
| Total comprehensive income for the year | 45,503 | 31,685 | |
| Profit allocated to NCI Dividends paid to NCI |
7,461 1,585 |
8,714 - |
| Hemla E&P Congo SA | ||||
|---|---|---|---|---|
| Amounts in USD thousand | 2022 | 2021 | ||
| Cash flows from operating activities | 41,847 | 39,360 | ||
| Cash flows from investing activities Cash flows from financing activities |
(38,349) (10,028) |
(25,331) (6,047) |
||
| Net (decrease)/increase in cash and cash equivalents | (6,530) | 8,312 |
Key management personnel are those persons having authority and responsibility for planning, directing, and controlling the activities of the group, including the directors listed on page 47, and the following other key personnel:
| Jens Pace | Interim chief executive officer |
|---|---|
| Claus Frimann-Dahl | Chief technical officer |
| Emad Sultan | Strategy and contracts manager |
| Michael Barrett | Exploration manager |
| Chris Butler | Group financial controller |
As at the approval date of this report the base salary and fees for the following members of key management is as follows:
| Individual | Title | Group entity | Base salary and fees /per annum |
Total base salary and fees USD equivalent |
|---|---|---|---|---|
| PetroNor E&P Services AS 1 | USD 174,000 | |||
| E Alhomouz | Chair | Hemla E&P Congo SA | USD 120,000 | 294,000 |
| J Iskander | Director 2 | Nil | Nil | |
| I Tybring-Gjedde | Director | PetroNor E&P Services AS | NOK 250,000 | 26,000 |
| G Kielland | Director | PetroNor E&P Services AS | NOK 250,000 | 26,000 |
| J Norman-Hansen | Director | PetroNor E&P Services AS | NOK 250,000 | 26,000 |
| A Fawzi | Director | PetroNor E&P Services AS | NOK 250,000 | 26,000 |
| J Pace | Interim CEO | PetroNor E&P Services AS | GBP 360,000 | 443,000 |
| E Sultan | Strategy & contracts manager | PetroNor E&P Services AS | USD 240,000 | 240,000 |
| C Frimann-Dahl | Chief technical officer | PetroNor E&P Services AS | NOK 2,500,000 | 253,000 |
| M Barrett | Exploration officer | PetroNor E&P Services Ltd | GBP 215,000 | 264,000 |
| PetroNor E&P Services Ltd | GBP 140,000 | |||
| C Butler | Group financial controller | Hemla E&P Congo SA | USD 66,000 | 238,000 |
1) Fees are charged by related party Petromal LLC and are not paid to the individual; above figures represent the company's fair value estimate of associated costs for the individual's services.
2) J Iskander elected not to be remunerated, as he is not considered an independent director due to connections to the largest company shareholder.
FX rates used: NOK 1.00 : USD 0.1038 | GBP 1.00 : USD 1.23
| Amounts in USD | Designation | Salary and fees |
Bonus | Other cash benefits |
Post-employment benefits |
Total |
|---|---|---|---|---|---|---|
| E Alhomouz 1 | Chair | 294,000 | - | - | - | 294,000 |
| J Iskander | Director | - | - | - | - | - |
| I Smines Tybring Gjedde |
Director | 34,598 | - | - | - | 34,598 |
| G Kielland | Director | 34,598 | - | - | - | 34,598 |
| A Neuling 2 | Director | 5,728 | - | - | - | 5,728 |
| R Steinepreis 2 | Director | 5,728 | - | - | - | 5,728 |
| J Pace | Interim CEO | 443,500 | - | - | - | 443,500 |
| C Frimann-Dahl | Chief technical officer | 253,080 | - | 769 | 20,524 | 274,373 |
| M Barrett | Exploration officer | 279,445 | - | 884 | 2,080 | 282,409 |
| C Butler | Group financial controller | 173,059 | 92,177 | 5,747 | 17,306 | 288,289 |
| E Sultan | Strategy & contracts manager | 233,000 | - | - | - | 233,000 |
| A Hicks 2 | Company secretary | 3,598 | - | - | - | 3,598 |
| Total | 1,760,334 | 92,177 | 7,400 | 39,910 | 1,899,821 |
1) USD 174,000 of the fees above is not paid to the individual, these fees charged on an arms-length basis are included in a monthly lump sum charged by related party Petromal LLC, above figures represent the company's fair value estimate of associated costs for the individual's services.
2) Indviduals are directors or management of the previous Australian top company, the above figure represents their remuneration up until the group restructure on 24 February 2022.
| Post | ||||||
|---|---|---|---|---|---|---|
| Salary and | Other cash | employment | ||||
| Amounts in USD | Designation | fees | Bonus | benefits | benefits | Total |
| E Alhomouz 1 | Chair | 294,000 | - | - | - | 294,000 |
| J Iskander | Director | - | - | - | - | - |
| Jens Pace 2 | Director & Interim CEO | 47,909 | - | - | - | 47,909 |
| I Smines Tybring Gjedde | Director | 38,001 | - | - | - | 38,001 |
| G Kielland 3 | Director | 25,994 | - | - | - | 25,994 |
| A Neuling | Director | 26,787 | - | - | - | 26,787 |
| R Steinepreis | Director | 32,546 | - | - | - | 32,546 |
| G Ludvigsen 4 | Director & business development manager | 385,210 | - | 110 | - | 385,320 |
| K Søvold 5 | Exec director & CEO | 354,118 | - | 821 | 21,721 | 376,659 |
| C Frimann-Dahl | Chief technical officer | 221,648 | - | 780 | 20,732 | 243,160 |
| M Barrett | Exploration officer | 296,475 | - | 2,598 | - | 299,073 |
| C Butler | Group financial controller | 174,825 | - | 3,724 | 17,483 | 196,032 |
| E Sultan | Strategy & contracts manager 3 | 168,000 | - | - | - | 168,000 |
| A Hicks | Company secretary | 27,035 | - | - | - | 27,035 |
| TOTAL | 2,092,548 | - | 8,033 | 59,935 | 2,160,516 |
1) USD 174,000 of salary and fees is not paid to the individual, these fees charged on an arms-length basis are included in a monthly lump sum charged by related party Petromal LLC, above figures represent the company's fair value estimate of associated costs for the individual's services.
2) On 16 December 2021, Mr Pace was appointed as interim CEO and subsequently resigned as a board member.
3) Appointed 1 February 2021
4) Following his resignation as a board member on 1 February 2021, G Ludvigsen continued to provide services charged on an arms-length by a related party Hagan AS.
5) From 16 December 2021, individuals no longer considered key management personnel as decision making responsibilities removed.
| Balance 1 January 2022 |
Shares purchased |
Granted as remuneration |
Net change other |
Balance 31 December 2022 |
|
|---|---|---|---|---|---|
| J Pace | 1,498,858 | - | - | (33,334) | 1,465,524 |
| M Barrett | 1,151,687 | - | - | - | 1,151,667 |
| C Butler | 234,316 | - | - | - | 234,296 |
| C Frimann-Dahl | 604,545 | - | - | - | 604,545 |
| Total | 3,498,406 | - | - | (33,334) | 3,456,072 |
As at 31 December 2022, Eyas Alhomouz held no shares personally but holds influence over 481,481,666 shares (2021: 481,481,666 shares) as the CEO of significant shareholder Petromal LLC. 109,520,419 of the shares held by Petromal LLC are recorded in the name of nominee company, Clearstream Banking S.A. on behalf of Petromal LLC.
Other directors and key management not included in the above table held no shares during the current year. No warrants or options were held by directors or key management personnel during the current year.
| Ownership | Ownership 31 December 2021 |
|
|---|---|---|
| UAE | 33.82% | 36.28% |
| Cyprus | 9.75% | 10.47% |
| Norway | 9.49% | 10.45% |
| Norway | 6.15% | 6.61% |
| Norway | 3.16% | 3.39% |
| Norway | 3.16% | 3.39% |
| Place of incorporation | 31 December 2022 |
Symero Ltd is a company owned by NOR Energy AS, which in turn is controlled jointly by former key management of PetroNor, Knut Søvold, and Gerhard Ludvigsen.
Ambolt Invest AS is a company controlled by Jarle Norman-Hansen who was appointed as a board member on 26 January 2023.
Gulshagen III AS and Gulshagen IV AS are also controlled by Knut Søvold.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Petromal – Sole Proprietorship LLC | 289 | 554 |
| Administrative expenses | 289 | 554 |
Petromal LLC is the largest shareholder in the company and since 2017 has had an agreement to provide technical and project management services to the PetroNor group.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Other payable to NOR Energy AS | 1,283 | 2,136 |
| Other payable to Petromal – Sole Proprietorship LLC | 736 | 1,281 |
| Other payable to Symero Ltd | - | 32 |
| Total payables to related parties (note 19) | 2,019 | 3,449 |
| Loan payable Symero Ltd | - | 3,912 |
| Loan payable to related parties (note 20) | - | 3,912 |
Amounts due from / to related parties included in the consolidated statement of financial position (other than the loans to related parties) are interest-free and have no fixed
repayment terms. The outstanding payable balances as at 31 December 2022 were settled during Q1 2023.
On 13 July 2022, PetroNor completed the corporate acquisition of both Pan-Petroleum Nigeria Holding BV and Pan-Petroleum Services Holdings BV, who together hold 100 per cent of the shares in Pan-Petroleum AJE Ltd, from Panoro Energy ASA. The transaction has allowed PetroNor to assume a 6.502 per cent participating interest, 16.255 per cent cost bearing interest and economic interest of 12.1913 per cent in Offshore Mining Licence no.113 (OML113).
Pan-Petroleum AJE Ltd participates in the exploration and production of hydrocarbons in the Aje oil and gas field. Under IFRS 3 – Business combinations, an acquirer has a
maximum of twelve months from the date of acquisition to finalise the acquisition accounting. The adjustment period ends when the acquirer has gathered all necessary information, subject to the twelve-month maximum. The purchase price allocation is still subject to finalisation pending receipt of further accounting data from counterparties.
The group has assessed and determined the transaction is a business combination under IFRS 3 – Business combinations. Information is respect of the assets and liabilities acquired and the fair value allocations to the assets is as follows:
Amounts in USD thousand
| Current assets | |
|---|---|
| Trade and other receivables | 5 |
| Cash and bank balances | 52 |
| 57 | |
| Non current assets | |
| Intangible assets | 34,299 |
| Production assets and equipment | 926 |
| Sum | 35,225 |
| Total assets | 35,282 |
| Current liabilities | |
| Trade and other payables | (2,745) |
| Non-current liabilities | |
| Provisions | (3,768) |
| Deferred tax liability | (9,031) |
| Other payables | (8,738) |
| Sum | (21,537) |
| Total liabilities | (24,282) |
| Net assets | 11,000 |
| Satisfied by: | |
| Consideration shares | 10,000 |
| Assignment fee | 1,000 |
| Total | 11,000 |
The assets acquired have been acquired with the intention to redevelop the field. The immediate effect on the income statement will not be material to the group. In the current period post acquisition, the charge to the income statement was USD 249,000.
The upfront consideration for the transaction was USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares. The volume of PetroNor shares has been determined with reference to the contractually determined 30-day volume weighted average price ("VWAP") of PetroNor shares listed on the Oslo Børs. The calculation was based on 30 business trading days between 2 May 2022 and 8 July 2022. An additional consideration of USD 0.10 per 1,000 cubic feet of the AJE Natural Gas Sales Volume is to be paid to Panoro Energy ASA once the conditions stipulated within the SPA are met. This conditional consideration shall not exceed USD 16.67 million.
The consolidated statement of cash flows includes a noncash adjustment for the corporate transaction to acquire the interest in OML 113. The acquisition of the subsidiaries has not resulted in cash flows and therefore the statement of cash flows has been adjusted as follows:
| Purchases of property, plant, and equipment | 925 |
|---|---|
| Intangible assets | 33,299 |
| Trade and other payables | (2,630) |
| Other non-current payables | (8,738) |
| Provisions | (3,769) |
| Deferred tax liability | (9,031) |
| Issue of share capital | (10,052) |
The goodwill recognised in the transaction of USD 9 million is classified as technical goodwill due to the requirement to recognise deferred taxes for the temporary differences between the assigned values and the tax bases of assets acquired and liabilities assumed in a business combination. A provision has been made in accordance with IAS 12 for deferred tax corresponding to the tax rate (50 per cent tax oil) multiplied by the difference between the fair values of the acquired assets and the transferred tax depreciation basis. The offsetting entry to this deferred tax is technical goodwill. This goodwill is not deductible for tax purposes.
The group's principal financial liabilities comprise accounts payable and amounts due to related parties. The main purpose of these financial instruments is to manage shortterm cash flow and raise finance for the group's capital expenditure program. The group has various financial assets such as accounts receivable and cash.
It is, and has been throughout the year ending 31 December 2022, the group's policy that no speculative trading in derivatives shall be undertaken.
The main risks that could adversely affect the group's financial assets, liabilities or future cash flows are credit risk, liquidity risk, interest rate risk and foreign currency risk. The management reviews and agrees policies for managing each of these risks which are summarised below.
The following discussion also includes a sensitivity analysis that is intended to illustrate the sensitivity to changes in the market variables on the group's financial instruments and shows the impact on profit or loss and shareholders' equity, where applicable. Financial instruments affected by market risk include accounts receivable, accounts payable and accrued liabilities.
The sensitivity has been prepared for periods ending 31 December 2022 using the amounts of debt and other financial assets and liabilities held as at those reporting dates.
Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the group. As at 31 December 2022, the group's maximum exposure to credit risk without taking into account any collateral held or other credit enhancements, which will cause a financial loss to the group due to failure to discharge an obligation by the counterparties and financial guarantees provided by the group arises from the carrying amount of the respective recognised financial assets as stated in the statement of financial position.
To minimise credit risk, the group has tasked its management to develop and maintain the group's credit risk gradings to categorise exposures according to their degree of risk of default. The credit rating information is supplied by independent rating agencies where available and, if not available, the management uses other publicly available financial information and the group's own trading records to rate its major customers and other debtors. The group's exposure and the credit ratings of its counterparties are continuously monitored, and the aggregate value of transactions concluded is spread amongst approved counterparties.
The company's current credit risk grading framework comprises the following categories:
| Category | Description | Basis for recognising expected credit losses |
|---|---|---|
| Performing | The counterparty has a low risk of default and does not have any past-due amounts |
12-month ECL |
| Doubtful | Amount is >30 days past due or there has been a significant increase in credit risk since initial recognition |
Lifetime ECL – not credit-impaired |
| In default | Amount is >90 days past due or there is evidence indicating the asset is credit-impaired |
Lifetime ECL – credit-impaired |
| Write-off | There is evidence indicating that the debtor is in severe financial difficulty and the company has no realistic prospect of recovery |
Amount is written off |
The group's principal customers are substantial oil and gas companies and as such credit risk is considered to be low. There is no history of credit loss, non-payment or default. The risk on liquid funds is limited because the counterparties are
banks with high credit ratings. The asset retirement obligation cash is held in an Escrow bank account managed by the operator.
The tables below detail the credit quality of the company's financial assets as well as the company's maximum exposure to credit risk by credit risk rating grades.
| Amounts in USD thousand | Note | External credit rating |
Internal credit rating |
12-month or lifetime ECL |
Gross carrying amount |
Loss allowance |
Net carrying amount |
|---|---|---|---|---|---|---|---|
| 31 December 2022 | |||||||
| Trade receivables | 13 | N/a | (i) | Lifetime ECL | 1,174 | - | 1,174 |
| Due from related parties | 13, 25D | N/a | - | Lifetime ECL | - | - | - |
| Advance against decommissioning cost | 13 | N/a | - | Lifetime ECL | 29,432 | - | 29,432 |
| Cash and cash equivalents | 14 | Aa3/B | N/a | 12-month ECL | 24,816 | - | 24,816 |
| 31 December 2021 | |||||||
| Trade receivables | 13 | N/a | (i) | Lifetime ECL | 13,431 | - | 13,431 |
| Due from related parties | 13, 25D | N/a | - | Lifetime ECL | - | - | - |
| Advance against decommissioning cost | 13 | N/a | - | Lifetime ECL | 26,837 | - | 26,837 |
| Cash and cash equivalents | 14 | Aa3/B | N/a | 12-month ECL | 31,755 | - | 31,755 |
(i) For trade receivables and amounts due from related parties, the group has applied the simplified approach in IFRS 9 to measure the loss allowance at lifetime ECL. The expected credit losses are estimated using a provision matrix by reference to past default experience of the debtor and an analysis of the debtor's current financial position, adjusted for factors that are specific to the debtors, general economic conditions of the industry in which the debtors operate and an assessment of both the current as well as the forecast direction of conditions at the reporting date.
The group seeks to limit its liquidity risk by ensuring financial support is available from the shareholders. The group's terms of sales requires amounts to be paid within 45 to 60 days of the date of approval of progress billings. Trade payables are normally settled within 90 to 120 days of the date of receipt of invoice.
The table below summarises the maturity profile of the group's financial liabilities at 31 December 2022 based on contractual undiscounted payments.
| Note | On demand | Less than 1 month |
Between 1 and 3 months |
Between 3 months and 1 year |
More than 1 year |
Total |
|---|---|---|---|---|---|---|
| 19 | - | 18,732 | - | - | - | 18,732 |
| 25D | 2,019 | - | - | - | - | 2,019 |
| 20 | - | - | 1,375 | 4,125 | 5,500 | 11,000 |
| 19 | - | - | - | - | 8,738 | 8,738 |
| 2,019 | 18,732 | 1,375 | 4,125 | 14,238 | 40,489 | |
| Amounts in USD thousand | Note | On demand | Less than 1 month |
Between 1 and 3 months |
Between 3 months and 1 year |
More than 1 year |
Total |
|---|---|---|---|---|---|---|---|
| 31 December 2021 | |||||||
| Trade accounts payable | 19 | 21,944 | - | 5 | 65 | 22,014 | |
| Amounts due to related parties | 25D | 3,449 | - | - | - | - | 3,449 |
| Loan payable | 20 | - | - | 2,500 | 10,579 | - | 13,079 |
| Other payable | 19 | - | - | - | - | - | - |
| Total | 3,449 | 21,944 | 2,500 | 10,584 | 65 | 38,542 |
The company had USD 24.8 million (2021: 31.8 million) in unrestricted cash as of 31 December 2022. 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.
The options include, amongst others, debt financing, offtake prepayment structures. As a result, the financial statements have been prepared under the assumption of going concern and realisation of assets and settlement of debt in normal operations.
As a result of the acquisition of the interest in the OML 113 licence, PetroNor has inherited an other payable of USD 8.7 million which relates to costs not yet agreed. The final amount is not expected to be settled within the next twelve months, therefore this has been classified as a non-current liability.
The group is exposed to interest rate risk on its interestbearing assets and liabilities and seeks to limit this risk by obtaining favourable interest rates.
| 31 December 2022 | 31 December 2021 | |||
|---|---|---|---|---|
| Amounts in USD thousand | +150bp | -150bp | +150bp | -150bp |
| Loans payable | (165) | 165 | (196) | 196 |
The new facility put in place does not include the oil pricing sensitivity previously applied thus providing more certainty to interest costs.
The group operates internationally and is exposed to risk arising from various currency exposures, primarily with respect to the Norwegian Kroner (NOK), and the Great British Pound (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 statement of comprehensive income and statement of
financial position 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.
A 20 per cent strengthening or weakening of the USD against the following currencies at 31 December 2022 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.
| 31 December 2022 | 31 December 2021 | |||
|---|---|---|---|---|
| Amounts in USD thousand | +20% | -20% | +20% | -20% |
| USD vs NOK | ||||
| Cash | 106 | (107) | 1,040 | (1,044) |
| Receivables | 260 | (260) | - | - |
| Payables | (423) | 423 | (92) | 92 |
| Total | (57) | 57 | 948 | (952) |
| USD vs GBP | ||||
| Cash | (17) | 17 | 3 | (3) |
| Receivables | (3) | 3 | 8 | (8) |
| Payables | 7 | (7) | (6) | 6 |
| Total | (13) | 13 | 5 | 5 |
The primary objective of the group's capital management is to continuously evaluate measures to strengthen its financial basis and to ensure that the group is fully funded for its committed 2023 activities. The group manages its capital structure and makes adjustments to it in light of changes in economic conditions. 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 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 capital in the forthcoming years.
Financial instruments comprise financial assets and financial liabilities.
Financial assets consist of bank balances and cash, amounts due from related parties and trade and some other receivables. Financial liabilities consist of amounts due to related parties, loans payable, trade account payables and some other liabilities.
| Fair value through profit or loss |
Amortised cost |
Fair value through other comprehensive income |
||||
|---|---|---|---|---|---|---|
| Amounts in USD thousand | 2022 | 2021 | 2022 | 2021 | 2022 | 2021 |
| Financial assets | ||||||
| Cash and cash equivalents | - | - | 24,816 | 31,755 | - | - |
| Trade and other receivables | - | - | 1,171 | 13,820 | - | - |
| Other receivables | - | - | 29,432 | 26,837 | - | - |
| Total | - | - | 55,419 | 72,412 | - | - |
| Financial Liabilities | ||||||
| Trade and other payables | - | - | 29,489 | 30,055 | - | - |
| Loans and borrowings | - | - | 11,000 | 13,079 | - | - |
| Total | - | - | 40,489 | 43,134 | - | - |
The fair values of the group's financial instruments are not materially different from their carrying amounts at the reporting date largely due to the short-term maturities of these instruments.
As at 31 December 2022, the group had approved the budget for PNGF Sud operations in Congo that included planned capex expenditure for the coming year of USD 45.6 million (2021 USD 50.6 million) representing HEPCO's equity interest funding commitment in the licence.
The company has entered into obligations in respect of its exploration projects. Outlined below are the minimum expenditures required as at 31 December:
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Within one year 1 | 40,000 | 40,000 |
1) The commitment in Senegal includes USD 40 million for an exploration well in each licence, however this assumes that the company is successful in retaining the legal title for these licences and that the company then drills these wells with 90 per cent equity.
In December 2021, the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway (Økokrim) initiated an investigation into allegations of corruption and brought criminal charges against individuals associated with the company. Økokirm has confirmed that neither PetroNor nor any of its subsidiaries has been charged. The US Department of Justice also began its own investigation into the allegations based on information received from Økokrim.
To mitigate potential corporate liability risks, the board has taken various remediation steps, as outlined in the director's report, including obtaining independent legal advice and implementing a compliance action plan. Despite the ongoing investigations, the company has continued to operate effectively, but has incurred costs in addressing this issue and fully cooperating with the investigating authorities. The company is not aware of the status or duration of the investigations into the individuals involved, and the uncertainty surrounding the outcome could potentially impact the group's ability to conduct transactions with both new and existing partners.
As part of the transaction to acquire the interest in OML 113 conditional consideration has been assessed as a potential contingency to the group. An additional consideration of USD 0.10 per 1,000 cubic feet of the AJE Natural Gas
Sales Volume is to be paid to Panoro Energy ASA once the conditions stipulated within the SPA are met. This conditional consideration shall not exceed USD 16.67 million.
On 26 January 2023, two new directors were appointed to the board. The appointments were pursuant to recommendations from the nomination committee. The two new directors, Mrs. Azza Fawzi and Mr. Jarle Norman-Hansen, take the company's board to a total of six directors.
In the Official Gazette of Guinea-Bissau (Boletim Oficial 45), it was announced that following the withdrawal of FAR Limited from the Sinapa and Esperança licences offshore Guinea-Bissau their equity interest had been awarded to PetroNor.
At the start of February, 317,904 bbls of oil were lifted from the Djeno Terminal, this sale generated a cash inflow of USD
Accounting policies are selected and applied in a manner which ensures that the resulting financial information satisfies the concepts of relevance and reliability, thereby ensuring that the substance of the underlying transactions or other events is reported.
The following is a summary of the material accounting policies adopted by the group in the preparation of the consolidated financial statements. The accounting policies have been consistently applied, unless otherwise stated.
IASB has issued several amendments to standards or interpretations to standards effective as of 1 January 2022. PetroNor have adopted these standards in the financial year, the impacts were not material to PetroNor's consolidated financial statements upon adoption.
Impacts of other standards and amendments to standards, and interpretations of standards, issued but not yet effective are under assessment by PetroNor.
The consolidated financial statements comprise the financial statements of PetroNor E&P ASA ("the company", formerly PetroNor E&P Ltd) and its subsidiaries for the year ended 31 December 2022 (together the group).
An entity has been assessed as being controlled by the group when the groups is exposed, or has the rights, to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Specifically, the group controls an entity if and only if the group has:
24.1 million. On 1 April 2023, a further 260,362 bbls of oil were lifted generating USD 21.2 million of cash inflow.
In a CPR update prepared by AGR Petroleum Services AS on the Company's PNGF Sud assets, the end of year 2P reserves were updated to 18.5 Mmbbl with 2C reserves to 23.5 Mmbbl.
Except for the above, the company has not identified any events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report.
When the group has less than a majority of the voting or similar rights of an entity, the group considers all relevant facts and circumstances in assessing whether it has power over an entity, including:
The group reassesses whether or not it controls an entity if facts and circumstances indicate that there are changes to one or more of the three elements of control. Consolidation of a subsidiary begins when the group obtains control over the subsidiary and ceases when the group loses control of the subsidiary. Business combinations are accounted for by using the acquisition method. Assets, liabilities, income, and expenses of a subsidiary acquired or disposed of during the year are included in the statement of comprehensive income from the date the group gains control until the date the group ceases to control the subsidiary.
Profit or loss and each component of other comprehensive income (OCI) are attributed to the equity holders of the parent of the group and to the non-controlling interests, even if this results in the non-controlling interests having a deficit balance. When necessary, adjustments are made to the financial statements of subsidiaries to bring their accounting policies
into line with the group's accounting policies. All intra-group assets and liabilities, equity, income, expenses, and cash flows relating to transactions between members of the group are eliminated in full on consolidation.
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:
A joint arrangement is a joint operation whereby the group and the other parties that have joint control over the arrangement, have contractual rights to the assets and obligation for the liabilities relating to the arrangement. All decisions about the relevant activities require unanimous consent.
When assessing if a joint arrangement is joint operation, the group assesses the structure of the arrangement, the legal form, the contractual agreement and other facts and circumstances.
The group recognises its assets, liabilities, revenue and expenses and its relative share of assets, liabilities, revenue, and expenses of the joint operation.
When the group enters into transactions with a joint operation in which it is a joint operator, the group recognises gains and losses resulting from such a transaction only to the extent of the other parties' interests in the joint operation.
An operating segment is a component of an entity that engages in business activities from which it may earn revenues and incur expenses (including revenues and expenses relating to transactions with other components of the same entity), whose operating results are regularly reviewed by the entity's chief operating decision-makers to make decisions about resources to be allocated to the segments and assess their performance and for which discrete financial information is available. This includes start-up operations which are yet to earn revenues.
Operating segments have been identified based on the information available to chief operating decision-makers – being the board and the executive management team. Information about other business activities and operating segments that are below the quantitative criteria are combined and disclosed in a separate category called "all other segments".
Functional and presentation currency
The company has applied United States Dollars, being the functional currency of all major subsidiaries in the group, as its presentation currency. Where the functional currencies of entities within the consolidated group differ from United States Dollars, they have been translated into United States Dollars. The functional currency of PetroNor E&P ASA is Norwegian Kroner.
Transactions in foreign currencies are initially recorded in the functional currency by applying the exchange rates ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the rate of exchange ruling at the reporting date and any gains or losses are recognised in the income statement.
Non-monetary items that are measured in terms of historical cost in the foreign currency are translated using the exchange rate as at the date of the initial transaction. 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.
On consolidation, the assets and liabilities of foreign operations are translated into United States Dollars at the rate of exchange prevailing at the reporting date and their income and expenditure are translated at exchange rates prevailing at the dates of the transactions. The exchange differences arising on translation for consolidation are recognised in other comprehensive income. On disposal of a foreign operation, the component of other comprehensive income relating to that particular foreign operation is recognised in profit or loss.
Cash and cash equivalents include cash on hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less, and bank overdrafts. Bank overdrafts are shown within short-term borrowings in current liabilities on the Statement of Financial Position.
Trade receivables are amounts due from customers for goods sold or services performed in the ordinary course of business. They are generally due for settlement within 30 to 90 days and therefore are all classified as current. Trade receivables are recognised initially at the amount of consideration that is unconditional unless they contain significant financing components, when they are recognised at fair value. The group holds the trade receivables with the objective to collect the contractual cash flows and therefore measures them subsequently at amortised cost using the effective interest method.
Trade receivables are written off when there is no reasonable expectation of recovery. Indicators that there is no reasonable expectation of recovery include, amongst others, the failure of a debtor to engage in a repayment plan with the group, and a failure to make contractual payments for a period of greater than 120 days past due.
Impairment losses on trade receivables and contract assets are presented as net impairment losses within operating profit. Subsequent recoveries of amounts previously written off are credited against the same line item.
The crude oil inventory and the material and supplies inventory are valued at the lower of cost and net realisable value. Cost is determined using the weighted average method. Net realisable value is the estimated selling price, less applicable selling expenses. The cost of inventory includes all costs related to bringing the inventory to its current condition, including processing costs, labour costs, supplies, direct and allocated indirect operating overhead and depreciation expense, where applicable, including allocation of fixed and variable costs to inventory.
Oil and gas production assets are aggregated exploration and evaluation tangible assets and development expenditures associated with the production of proved reserves.
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 production assets have a finite life.
Oil and gas properties are depreciated using the unit-ofproduction method. Unit of production rates are based on 1P proved reserves, which are oil, gas and other mineral reserves estimated to be recovered from existing facilities using current operating methods. Oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the field storage tank.
Field infrastructure exceeding beyond the life of the field is depreciated over the useful life of the infrastructure using a straight-line method.
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 – 33.33% |
|---|---|
| Furniture, fixtures, & fittings | 10 – 33.33% |
| Motor vehicles | 20% |
Exploration and evaluation activity involves the search for hydrocarbon resources, the determination of technical feasibility and the assessment of commercial viability of an identified resource. For each area of interest, expenditure
incurred in the acquisition of rights to explore and all costs directly associated with holding the licence such as rental, training and corporate and social responsibility are capitalised as exploration and evaluation intangible assets. Signature bonuses required by licence agreements are capitalised as exploration and evaluation intangible assets. Other costs directly associated with the licence are expensed as incurred.
Exploration, evaluation, and development expenditure is recorded at historical cost and allocated to cost pools on an area of interest. Expenditure on an area of interest is capitalised and carried forward where rights to tenure of the area of interest are current and:
Accumulated costs in respect of areas of interest which are abandoned are written off in full against profit in the period in which the decision to abandon the area is made. Projects are advanced to development status when it is expected that further expenditure can be recouped through sale or successful development and exploitation of the area of interest.
All capitalised costs are subject to commercial and management review, as well as review for indicators of impairment at least once a year. This is to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off through the statement of profit or loss and other comprehensive income.
When proved reserves of oil and natural gas are identified and development is sanctioned by management, the relevant capitalised expenditure is first assessed for impairment and (if required) any impairment loss is recognised, then the remaining balance is transferred to oil and gas properties. Proceeds from disposal or farm-out transactions of intangible exploration assets are used to reduce the carrying amount of the assets. When proceeds exceed the carrying amount, the difference is recognised as a gain. When the group disposes of its full interests, gains or losses are recognised in accordance with the policy for recognising gains or losses on sale of plant, property, and equipment.
Generally Intangible assets can be viewed indefinite as they will be retained on the balance sheet until impaired or transferred to oil and gas properties. Certain licence related costs capitalised as intangible assets are deemed to have a finite life and are accreted over the life of the licence area.
Licence related costs capitalised as Intangible assets are depreciated using the unit-of-production method. Unit-of production rates are based on 1P proved reserves, which are oil, gas and other mineral reserves estimated to be recovered from existing facilities using current operating methods. Oil
and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the field storage tank.
Technical goodwill recognised in business combinations is allocated to each CGU for the purposes of impairment testing. Impairment is tested on an annual basis or when there are impairment indicators. Indicators may be specific to an individual CGU or groups of CGUs to which the technical goodwill is related. When conducting impairment testing, deferred tax recognised in relation to the acquired licences reduces the net carrying value prior to the impairment charges.
Impairment is recognised if the recoverable amount of the CGU (or groups of CGUs) to which the technical goodwill relates to is less than the carrying amount. Impairment of goodwill cannot be reversed in future periods.
Borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying noncurrent asset are added to the cost of the asset during the period of time that is required to complete and prepare the asset for its intended use. Borrowing costs are capitalised to the extent that funds are borrowed specifically for the purpose of obtaining a qualifying asset. To the extent that funds are borrowed generally and used for the purpose of obtaining a qualifying asset, the amount of borrowing costs eligible for capitalisation is determined by applying a capitalisation rate to the expenditures on that asset. All other borrowing costs are expensed as incurred.
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.
Under a production sharing contract, where the group is required to pay profit oil tax and royalties on production of crude oil, such payments are settled in kind (where the government lift the crude it is entitled to). 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 and any associated royalties are included in the cost of sales.
The group assesses whether it acts as a principal or agent in each of its revenue arrangements. The group has concluded that in all sales transactions it acts as a principal.
If the consideration in a contract includes a variable amount, the group recognises this amount as revenue only to the extent that it is highly probable that a significant reversal will not occur in the future.
Interest income is recognised on a time-proportional basis using the effective interest method. This is a method of
calculating the amortised cost of a financial asset and allocating the interest income over the relevant period using the effective interest rate, which is the rate that exactly discounts the estimated future cash receipts through the expected useful life of the financial asset to the net carrying amount of the financial asset.
The group assesses whether contract is or contains a lease, at inception of the contract. The group recognises a right-ofuse asset and a corresponding lease liability with respect to all lease arrangements in which it is the lessee, except for shortterm leases (defined as leases with a lease term of 12 months or less) and leases of low value assets. For these leases, the group recognises the lease payments as an operating expense on a straight-line basis over the term of the lease unless another systematic basis is more representative of the time pattern in which economic benefits from the leased assets are consumed.
The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted by using the rate implicit in the lease. If this rate cannot be readily determined, the group uses its incremental borrowing rate.
Lease payments included in the measurement of the lease liability comprise:
The lease liability is presented as a separate line item in the statement of financial position.
The lease liability is subsequently measured by increasing the carrying amount to reflect interest on the lease liability (using effective interest method) and by reducing the carrying amount to reflect the lease payments made.
The group remeasures the lease liability (and makes a corresponding adjustment to the related right-of-use asset) whenever:
change is due to a change in a floating interest rate, in which case a revise discount rate is used).
■ a lease contract is modified, and the lease modification is not accounted for as a separate lease, in which case the lease liability is remeasured by discounting the revised lease payments using a revised discount rate.
The group did not make any such adjustments during the periods presented.
The group measures the right-of use asset at cost, less any accumulated depreciation and impairment losses, adjusted for any remeasurement of lease liabilities. The cost of the right-ofuse asset comprise:
The group applies the depreciation requirements in IAS 16 Property, Plant and Equipment in depreciating the right-of-use asset, except that the right-of-use asset is depreciated from the commencement date to the earlier of the lease term and the remaining useful life of the right-of-use asset.
The group applies IAS 36 Impairment of Assets to determine whether the right-of-use asset is impaired and to account for any impairment loss identified.
Variable rents that do not depend on an index or rate are not included in the measurement of the lease liability and the right-of-use asset. The related payments are recognised as an expense in the period in which the event or condition that triggers those payments occurs and are included in the line 'Administrative expenses' in the statement of profit or loss.
The income tax expense or benefit for the period consists of two components: current and deferred tax.
The current income tax payable or recoverable is calculated using the tax rates and legislation that have been enacted or substantively enacted at year-end in each of the jurisdictions and includes any adjustments for taxes payable or recovery in respect of prior periods.
Deferred tax assets and liabilities are determined using the balance sheet liability method based on temporary differences between the carrying value of assets and liabilities for financial reporting purposes and their tax bases. In calculating the deferred tax assets and liabilities, the tax rates used are those that have been enacted or substantively enacted by year-end in each of the jurisdictions and that are expected to apply when the assets are recovered, or the liabilities are settled.
In addition to corporate income taxes, the group's consolidated financial statements also include and recognise as income taxes, other types of taxes on net income such as certain revenue-based taxes.
According to the production-sharing arrangement (PSA) in certain licences, 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 the group to the appropriate tax authorities.
The current income tax is calculated using the PSA, paid in barrels and booked as income tax and also shown as revenue.
Revenues, expenses and assets are recognised net of the amount of sales tax except:
Where the sales tax incurred on a purchase of assets or services is not recoverable from the taxation authority, in which case, the sales tax is recognised as part of the cost of acquisition of the asset or as part of the expense item as applicable.
Receivables and payables that are stated with the amount of sales tax included.
The net amount of sales tax recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the statement of financial position.
Current and deferred tax balances attributable to amounts recognised directly in equity are also recognised directly in equity.
Provision is made for benefits accruing to employees in respect of wages and salaries, annual leave, and long service leave when it is probable that settlement will be required, and they are capable of being measured reliably. Provisions made in respect of employee benefits expected to be settled within 12 months are measured at their nominal values using the remuneration rate expected to apply at the time of settlement. Provisions made in respect of employee benefits, which are not due to be settled within 12 months are determined using the projected unit credit method.
The group pays contributions into defined contribution plans. 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.
Trade and other payables are carried at amortised cost and due to their short-term nature, they are not discounted.
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.
A decommissioning 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 decommissioning, discounted to its present value. Changes in the estimated timing of decommissioning or decommissioning 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 decommissioning liability is included as a finance cost. An escrow account is maintained by the operator of the PNGF Sud licence and is governed by a joint operating agreement and the Congolese Government rules. The group's share, paid against the decommissioning liability until the balance sheet date, is classified as an advance against decommissioning liability in current assets.
Contributed equity is recognised at the fair value of the consideration received by the group, less any capital raising costs in relation to the issue.
Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds.
Dividend distribution to the company's shareholders is recognised as a liability in the group's financial statements in the period in which the dividends are declared and appropriately authorised or approved by the company's shareholders' general meeting. Interim dividends proposed by the board of directors are recognised as liabilities upon declaration.
A financial instrument is any contract that gives rise to a financial asset of any one entity and a financial liability or equity instrument of another entity.
Financial assets are classified, at initial recognition, as subsequently measured at amortised cost, fair value through other comprehensive income (OCI), and fair value through profit or loss, as appropriate.
The classification of financial assets at initial recognition depends on the financial asset's contractual cash flow characteristics and the group's business model for managing them. With the exception of trade receivables that do not contain a significant financing component or for which the group has applied the practical expedient, the group initially measures a financial asset at its fair value plus, in the case of financial assets not subsequently measured at fair value through profit or loss, transaction costs that are attributable to the acquisition of the financial asset.
In order for a financial asset to be classified and measured at amortised cost or fair value through OCI, it needs to give rise to cash flows that are solely payments of principal and interest (SPPI) on the principal amount outstanding. This assessment is referred to as the SPPI test and is performed at an instrument level.
The group's business model for managing financial assets refers to how it manages its financial assets in order to generate cash flows. The business model determines whether cash flows will result from collecting contractual cash flows, selling the financial assets, or both.
Purchases or sales of financial assets that require delivery of assets within a time frame established by regulation or convention in the marketplace (regular way trades) are recognised on the trade date, i.e., the date that the group commits to purchase or sell the asset.
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 derecognizes financial assets when the contractual rights to the cash flows expire or the financial asset is transferred to a 3rd 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.
■ The contractual terms of the financial asset give rise on
specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding;
Financial assets at amortised cost are subsequently measured using the effective interest (EIR) method and are subject to impairment. Gains and losses are recognised in profit or loss when the asset is derecognised, modified or impaired.
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.
Loans granted that have fixed or determinable payments that are not quoted in an active market are classified as financial assets at amortised cost and are measured at amortised cost using the effective interest method, less any impairment. Interest income is recognised by applying the effective interest rate.
Loans granted to related parties are normally interest-free and do not have a fixed repayment structure. These loans are classified as financial assets at amortised cost and are measured at amortised cost using the effective interest method, less any impairment. Effective interest rate being zero in this case.
A financial asset (or, where applicable, a part of a financial asset or part of a group of similar financial assets) is primarily derecognised (i.e., removed from the group's consolidated statement of financial position) when:
The rights to receive cash flows from the asset have expired or the group has transferred its rights to receive cash flows from the asset or has assumed an obligation to pay the received cash flows in full without material delay to a third party under a 'pass-through' arrangement; and either (a) the group has transferred substantially all the risks and rewards of the asset, or (b) the group has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset.
When the group has transferred its rights to receive cash flows from an asset or has entered into a pass-through arrangement, it evaluates if, and to what extent, it has retained the risks and rewards of ownership. When it has neither transferred nor retained substantially all of the risks and rewards of the asset, nor transferred control of the asset, the group continues to recognise the transferred asset to the extent of its continuing involvement. In that case, the group also recognises an associated liability. The transferred asset and the associated liability are measured on a basis that reflects the rights and obligations that the group has retained.
The group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the group expects to receive, discounted at an approximation of the original effective interest rate. The expected cash flows will include cash flows from the sale of collateral held or other credit enhancements that are integral to the contractual terms.
ECLs are recognised in two stages. For credit exposures for which there has not been a significant increase in credit risk since initial recognition, ECLs are provided for credit losses that result from default events that are possible within the next 12 months (a 12-month ECL). For those credit exposures for which there has been a significant increase in credit risk since initial recognition, a loss allowance is required for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default (a lifetime ECL).
For trade receivables and contract assets, the group applies a simplified approach in calculating ECLs. Therefore, the group does not track changes in credit risk, but instead recognises a loss allowance based on lifetime ECLs at each reporting date. The group has established a provision matrix that is based on its historical credit-loss experience, adjusted for forwardlooking factors specific to the debtors and the economic environment.
The group considers a financial asset in default when contractual payments are 90 days past due. However, in certain cases, the group may also consider a financial asset to be in default when internal or external information indicates that the group is unlikely to receive the outstanding contractual amounts in full before taking into account any credit enhancements held by the group. A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows.
Initial recognition and measurement
Financial liabilities are classified, at initial recognition, as financial liabilities at fair value through profit or loss, financial liabilities at amortised cost, payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate.
All financial liabilities are recognised initially at fair value and, in the case of loans and borrowings and payables, net of directly attributable transaction costs.
The group's financial liabilities include trade and other payables, loans and borrowings including bank overdrafts, and derivative financial instruments.
After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortised cost using the EIR method. Gains and losses are recognised in profit or loss when the liabilities are derecognised as well as through the EIR amortisation process.
Amortised cost is calculated by taking into account any discount or premium on acquisition and fees or costs that are an integral part of the EIR. The EIR amortisation is included as finance costs in the statement of profit or loss.
This category generally applies to interest-bearing loans and borrowings. For more information, refer to note 20.
Payables are measure at their nominal amount when the effect of discounting is not material.
For financial liabilities that are denominated in a foreign currency and are measured at amortised cost at the end of each reporting period, the foreign exchange gains and losses are determined based on the amortised cost of the instruments. These foreign exchange gains and losses are recognised in the 'foreign exchange gain/(loss)' line item in profit or loss for financial liabilities that are not part of a designated hedging relationship. For those which are designated as a hedging instrument for a hedge of foreign currency risk foreign exchange gains and losses are recognised in other comprehensive income and accumulated in a separate component of equity.
The fair value of financial liabilities denominated in a foreign currency is determined in that foreign currency and translated at the spot rate at the end of the reporting period. For financial liabilities that are measured as at FVTPL, the foreign exchange component forms part of the fair value gains or losses and is recognised in profit or loss for financial liabilities that are not part of a designated hedging relationship.
The group derecognises financial liabilities when, and only when, the group's obligations are discharged, cancelled or have expired. The difference between the carrying amount of the financial liability derecognised and the consideration paid and payable is recognised in profit or loss.
When the group exchanges with the existing lender one debt instrument into another one with substantially different terms, such exchange is accounted for as an extinguishment of the original financial liability and the recognition of a new financial liability. Similarly, the group accounts for substantial modification of terms of an existing liability or part of it as an extinguishment of the original financial liability and the recognition of a new liability. It is assumed that the terms are substantially different if the discounted present value of the cash flows under the new terms, including any fees paid net of any fees received and discounted using the original effective rate is at least 10 per cent different from the discounted present value of the remaining cash flows of the original financial liability. If the modification is not substantial, the difference between: (1) the carrying amount of the liability before the modification; and (2) the present value of the cash flows after modification is recognised in profit or loss as the modification gain or loss within other gains and losses.
The group measures derivatives at fair value at each balance sheet date and, for the purposes of impairment testing, uses fair value less costs to sell (FVLCD) to determine the recoverable amount of some of its non-financial assets.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place either:
■ In the principal market for the asset or liability
Or
■ In the absence of a principal market, in the most advantageous market for the asset or liability
The principal or the most advantageous market must be accessible by the group.
The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest.
A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use.
The group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximising the use of relevant observable inputs and minimising the use of unobservable inputs.
All assets and liabilities, for which fair value is measured or disclosed in the financial statements, are categorised within the fair value hierarchy, described as follows, based on the lowest-level input that is significant to the fair value measurement as a whole:
Level 1 – Quoted (unadjusted) market prices in active markets for identical assets or liabilities
Level 2 – Valuation techniques for which the lowest-level input that is significant to the fair value measurement is directly or indirectly observable
Level 3 – Valuation techniques for which the lowest-level input that is significant to the fair value measurement is unobservable
Financial assets and financial liabilities are offset, and the net amount is reported in the consolidated statement of financial position if there is a currently enforceable legal right to offset the recognised amounts and there is an intention to settle on a net basis, to realise the assets and settle the liabilities simultaneously.
Joint arrangements are arrangements of which two or more parties have joint control. Joint control is the contractual agreed sharing of control of the arrangement which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control. Joint arrangements are classified as either a joint operation or joint venture, based on the rights and obligations arising from the contractual obligations between the parties to the arrangement.
To the extent the joint arrangement provides the company with rights to the individual assets and obligations arising from the joint arrangement, the arrangement is classified as a joint operation and as such, the company recognises its:
To the extent the joint arrangement provides the company with rights to the net assets of the arrangement, the investment is classified as a joint venture and accounted for using the equity method. Under the equity method, the cost of the investment is adjusted by the post-acquisition changes in the company's share of the net assets of the venture.
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. A liability is current when either:
The group classifies all other liabilities as non-current. Deferred tax assets and liabilities are classified as non-current assets and liabilities.
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 company 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.
The initial accounting for a business combination can be changed if new information about the fair value at the acquisition date is present. The allocation can be amended within 12 months of the acquisition date [provided that the initial accounting at the acquisition date was determined provisionally]. The non-controlling interest is set to the noncontrolling interest's share of identifiable assets and liabilities [alternative fair value]. The measurement principle is done for each business combination separately. 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.
Goodwill is recognised as the aggregate of the consideration transferred and the amount of any non-controlling interest and deducted by the net of the acquisition-date amounts of the identifiable assets acquired and the liabilities assumed. Goodwill is not depreciated but is tested at least annually for impairment. In connection with this, goodwill is allocated to cash-generating units or groups of cash-generating units that are expected to benefit from synergies from the business combination.
Technical goodwill is recognised due to the requirement to recognise deferred tax for the difference between the assigned fair values and the related tax base. In accordance with IAS 12, a provision is made for deferred tax corresponding to the tax rate multiplied by the difference between the fair values of the acquired assets and the transferred tax depreciation basis.
If the fair value of the equity exceeds the acquisition cost in a business combination, the difference is recognised as income immediately on the acquisition date.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Administrative expenses | (5,753) | (6) |
| Profit from operations | (5,753) | (6) |
| Finance expense | - | - |
| Loss before tax | (5,753) | (6) |
| Tax expense | - | - |
| Profit/(loss) for the year | (5,753) | (6) |
| Other comprehensive income | (97) | - |
| Total comprehensive income/(loss) | (5,850) | (6) |
| (Loss) for the year attributable to: | ||
| Owners of the parent | (5,753) | (6) |
| Total | (5,753) | (6) |
| Total comprehensive income/(loss) attributable to: | ||
| Owners of the parent | (5,850) | - |
| Total | (5,850) | - |
| Loss per share attributable to members: Basic (loss) per share Diluted (loss) per share |
(0.42) (0.42) |
- - |
The accompanying notes form part of these financial statements.
At 31 December
| Amounts in USD thousand | Note | 2022 | 2021 |
|---|---|---|---|
| ASSETS | |||
| Current assets | |||
| Trade and other receivables | 776 | - | |
| Cash and cash equivalents | 5 | 30 | 114 |
| Total current assets | 806 | 114 | |
| Non-current assets | |||
| Investments | 6 | 152,579 | - |
| Total non-current assets | 152,579 | - | |
| Total assets | 153,385 | 114 | |
| Liabilities | |||
| Current liabilities | |||
| Trade and other payables | 1,171 | - | |
| Related party payables | 9 | 6,491 | 6 |
| Total current liabilities | 7,662 | 6 | |
| Total liabilities | 7,662 | 6 | |
| NET ASSETS | 145,723 | 108 | |
| EQUITY | |||
| Issued capital and reserves attributable to owners of the parent | |||
| Share capital | 8 | 159 | 114 |
| Share premium | 8 | 151,420 | - |
| Reserves | (97) | - | |
| Retained earnings | (5,759) | (6) | |
| TOTAL EQUITY | 145,723 | 108 |
The accompanying notes form part of these financial statements.
The financial statements were approved and authorised for issue by the board of directors on 28 April 2023.
| Foreign | ||||||
|---|---|---|---|---|---|---|
| Other | currency | |||||
| Share | Share | paid | translation | Retained | ||
| Amounts in USD thousand | capital | premium | in capital | reserve | earnings | Total |
| For the period ended 31 December 2022: | ||||||
| Balance at 1 January 2022 | 114 | - | - | - | (6) | 108 |
| Loss for the year | - | - | - | - | (5,753) | (5,753) |
| Other comprehensive income | (97) | (97) | ||||
| Total comprehensive loss for the period | - | - | - | (97) | (5,753) | (5,850) |
| Reduction in share capital as part of redomicile | (114) | - | - | - | - | (114) |
| Issue of shares in PetroNor E&P ASA | 149 | 141,430 | - | - | - | 141,579 |
| Issue of ordinary shares as consideration for business combination | 10 | 9,990 | - | - | - | 10,000 |
| Balance at 31 December 2022 | 159 | 151,420 | - | (97) | (5,759) 145,723 | |
| For the period ended 31 December 2021: | ||||||
| Balance at 1 October 2021 | 114 | - | - | - | - | 114 |
| Loss for the year | - | - | - | - | (6) | (6) |
| Other comprehensive income | - | - | - | - | - | - |
| Total comprehensive loss for the period | - | - | - | - | (6) | (6) |
| Balance at 31 December 2021 | 114 | - | - | - | (6) | 108 |
The accompanying notes form part of these financial statements.
| (Amounts in USD thousand) | Note | 2022 | 2021 |
|---|---|---|---|
| Cash flows from operating activities | |||
| Loss for the period | (5,753) | (6) | |
| Total | (5,753) | (6) | |
| Adjustments for: | |||
| Net foreign exchange differences | (97) | - | |
| Total | (97) | - | |
| Increase/(decrease) in trade and other receivables | (776) | - | |
| Increase/(decrease) in trade and other payables | 6,542 | 6 | |
| Cash (used in)/generated from operations | (84) | - | |
| Income taxes paid | - | - | |
| Net cash flows from operating activities | (84) | - | |
| Financing activities | |||
| Issue of ordinary shares | 5 | - | 114 |
| Proceeds from loans and borrowings | - | - | |
| Net cash (used in)/from financing activities | - | 114 | |
| Net increase/(decrease) in cash and cash equivalents | (84) | 114 | |
| Cash and cash equivalents at beginning of period | 114 | - | |
| Cash and cash equivalents at end of period | 30 | 114 |
The accompanying notes form part of these financial statements.
Petronor E&P ASA is a public limited company, incorporated in Norway on 1 October 2021.
Frøyas gate 13 NO-0273 Oslo Norway
The names of directors in office during the financial period and until the date of approval of these financial statements are as follows. Directors were in office for this entire period unless otherwise stated.
| Role | Appointed | ||
|---|---|---|---|
| E Alhomouz | Chair | 1 October 2021 | |
| I Tybring-Gjedde | Director | 1 October 2021 | |
| G Kielland | Director | 1 October 2021 | |
| J Iskander | Director | 8 October 2021 | |
| J Norman-Hansen | Director | 26 January 2023 | |
| A Fawzi | Director | 26 January 2023 | |
J Pace was appointed to the board 1 October 2021 and resigned 9 February 2022.
The financial statements were approved by the board on 28 April 2023.
On 24 February 2022, PetroNor E&P ASA issued 1,326,991,006 ordinary shares as part of the implementation of the scheme of arrangement. The shares of PetroNor E&P Ltd (previously listed on Euronext Expand) were swapped for shares in PetroNor E&P ASA.
Following the 1 to 1 share swap, the group uplisted and PetroNor E&P ASA began trading on the Oslo Børs from 28 February 2022. The shares belonging to historic investors that had never registered their interests in the VPS, were sold back into the market during March 2022 and the proceeds were distributed to these investors (mostly retail investors in Australia).
PetroNor E&P ASA replaces PetroNor E&P Ltd as the parent company of the group, the arrangement will be treated as a continuation of the original group for accounting purposes.
PetroNor E&P ASA's financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the EU and are mandatory for financial years beginning on or after 1 January 2022. Additional disclosures required by the Norwegian Accounting Act are also provided.
The preparation of financial statements in conformity with IFRSs requires the use of certain critical accounting estimates. It also requires management to exercise its judgments in applying the company's accounting policies.
There are no areas involving a high degree of judgment or complexity.
The financial statements have been prepared on the basis of uniform accounting principles for similar transactions and events under otherwise similar circumstances.
The financial statements are presented in US Dollars being the primary currency for group operations, the functional currency of the company is Norwegian Kroner. Conversion of foreign currency transactions are translated at average exchange rates provided that they are a reasonable approximation of exchange rates ruling at the date of transactions. Assets and Liabilities are translated at the rates prevailing at the balance sheet date. Exchange differences arising on translation are recognised in equity.
The company has no employees
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Paid or payable to BDO | ||
| Audit review of financial reports | ||
| BDO AS | 62 | - |
| BDO network firms | - | - |
| Sum | 62 | - |
| Other non-assurance services | ||
| BDO-related practices | - | 12 |
| Sum | - | 12 |
| Paid or payable to other audit firms Audit or review of financial reports |
- | - |
| Other non-assurance services | - | - |
| Total | 62 | - |
| (Amounts in USD thousand) | 2022 | 2021 |
|---|---|---|
| Cash in bank | 30 | 114 |
Non-cash adjustments include the shares issued as part of the implementation of the scheme of arrangement where PetroNor E&P ASA issued 1,326,991,006 ordinary shares as a direct swap with the shares of PetroNor E&P Ltd. The non-cash adjustments are as follows:
| Amounts in USD thousand | 2022 |
|---|---|
| Investment in subsidiaries Trade and other payables |
141,579 (114) |
| Share capital | (141,465) |
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Investment as at 1 January | - | - |
| Net income/(loss) from subsidiaries and other equity accounted investments | - | - |
| Investment in PetroNor E&P Ltd (Australia) | 141,579 | - |
| Investment in Aje Nigeria Holding BV and Aje Services Holding BV | 11,000 | - |
| Investments at 31 December | 152,579 | - |
Investments in subsidiaries are carried at the lower of cost and fair market value. Investments are assessed for impairment on annual basis.
The closing balance of investments at 31 December 2022 of USD 152.6 million, consists solely of investments in subsidiaries. The balance represents PetroNor E&P ASA's 100% ownership in the subsidiaries mentioned in the below table. The increase in 2022 is a result of the direct share swap with PetroNor E&P Ltd (Australia) as part of the implementation
of the scheme of arrangement. In February 2022, PetroNor E&P ASA issued 1,326,991,006 shares in a 1 for 1 swap with PetroNor E&P Ltd (Australia) increasing its share capital by USD 141.6 million. The remaining USD 10 million of share capital issued is in relation to the transaction to acquire an interest in the OML 113 licence via the acquisition of subsidiaries from Panoro Energy ASA. Refer to note 7 for further detail.
The following table shows significant subsidiaries directly held by PetroNor E&P ASA:
| Name | Ownership share | Country of Incorporation |
|---|---|---|
| PetroNor E&P Ltd | 100% | Australia |
| Aje Services Holding BV | 100% | Netherlands |
| Aje Nigeria Holding BV | 100% | Netherlands |
| Aje Production AS | 100% | Norway |
On 13 July 2022, PetroNor completed the corporate acquisition of Pan-Petroleum Nigeria Holding BV and Pan-Petroleum Services Holdings BV that hold 100 per cent of the shares in Pan-Petroleum AJE Ltd. The transaction has allowed PetroNor to assume a 6.502 per cent participating interest, 16.255 per cent cost bearing interest and economic interest of 12.1913 per cent in Offshore Mining Licence no.113 (OML113) Pan-Petroleum AJE Ltd participates in the exploration and production of hydrocarbons in the Aje oil and gas field. Information is respect of the assets and liabilities acquired and the fair value allocations to the assets in accordance with the provisions of "IFRS3 – Business Combinations "is as follows:
| Assets acquired | |
|---|---|
| Current assets | |
| Trade and other receivables | 5 |
| Cash and bank balances | 52 |
| Total current assets | 57 |
| Non-current assets | |
| Intangible assets | 34,299 |
| Production assets and equipment | 926 |
| Total non-current assets | 35,225 |
| Total assets | 35,282 |
| Current liabilities | |
| Trade and other payables | (2,745) |
| Total current liabilities | (2,745) |
| Non-current liabilities | |
| Provisions | (3,768) |
| Deferred tax liabilities | (9,031) |
| Other payables | (8,738) |
| Total non-current liabilities | (21,537) |
| Total liabilities | (24,282) |
| Net assets | 11,000 |
| Satisfied by: | |
| Consideration shares | 10,000 |
| Assignment fee | 1,000 |
| Total | 11,000 |
The upfront consideration for the transaction was USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares. The volume of PetroNor shares has been determined with reference to the contractually determined 30-day volume weighted average price ("VWAP") of PetroNor shares listed on the Oslo Børs. The calculation was based on 30 Business trading days between 2 May 2022 and 8 July 2022.
The consolidated statement of cash flows includes a non-cash adjustment for the corporate transaction with Panoro Energy ASA. The acquisition of the Panoro subsidiaries with shares
has not resulted in cash flows and therefore the statement of cash flows has been adjusted as follows:
Amounts in USD thousand
| Acquisition of subsidiary | 11,000 |
|---|---|
| Trade and other payables | (1,000) |
| Issue of share capital | (10,000) |
All shares have equal rights and are freely transferable share capital.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Opening balance | 114 | - |
| Reversal of shares as part of redomicile 1 | (114) | - |
| Issue of shares as part of redomicile 1 | 149 | - |
| Share capital issued as consideration for business combination 2 | 10 | - |
| Issue of ordinary shares | - | 114 |
| Balance at end of the period | 159 | 114 |
1) On 24 February 2022: The company issued 1,326,991,006 ordinary shares as part of the implementation scheme arrangement and redomicile from
Australia to Norway. Shares are issued at the nominal value of 0.001 NOK and translated to 0.01 USD using the rate of exchange on the day of issue. 2) On 13 July 2022, PetroNor E&P ASA completed the acquisition of Pan-Petroleum Nigeria Holding BV and Pan-Petroleum Services Holdings BV that hold 100 per cent of the shares in Pan-Petroleum AJE Ltd. The upfront consideration was USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares. The shares were issued at the nominal value of 0.001 NOK USD using the daily exchange rate published by the Bank of England.
Share premium reserve represents excess of subscription value of the shares over the nominal amount.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Opening balance | - | - |
| Issue of shares as part of redomicile | 141,430 | - |
| Share capital issued as consideration for business combination | 9,990 | |
| Balance at end of the period | 151,420 | - |
The remuneration for board members is paid by subsidiary company PetroNor E&P Services AS, in addition the chair also receives remuneration through subsidiary company Hemla E&P Congo SA.
Details on the remuneration to individual board members is included in the notes to the consolidated financial statements of PetroNor E&P ASA.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| PetroNor E&P Services AS | 2,373 | - |
| Administrative expenses | 2,373 | - |
PetroNor E&P Services AS is 100 per cent indirectly controlled entity of PetroNor E&P ASA.
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Other payables: | ||
| PetroNor E&P Services AS | 6,253 | - |
| PetroNor E&P Ltd (Australia) | 238 | - |
| Total payables to related parties | 6,491 | - |
| Amounts in USD thousand | 2022 | 2021 |
| Other receivables: | ||
| Aje Services Holding BV | 32 | - |
| Aje Nigeria Holding BV | 32 | - |
| Total receivables from related parties | 64 | - |
Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the company. As at 31 December 2022, the company's maximum exposure to credit risk without taking into account any collateral held or other credit enhancements, which will cause a financial loss to the group due to failure to discharge an obligation by the counterparties and financial guarantees provided by the company arises from the carrying amount of the respective recognised financial assets as stated in the statement of financial position.
To minimise credit risk, the company has tasked its management to develop and maintain the group's credit risk gradings to categorise exposures according to their degree of risk of default. The credit rating information is supplied by independent rating agencies where available and, if not available, the management uses other publicly available financial information and the company's own trading records to rate its major customers and other debtors. The company's exposure and the credit ratings of its counterparties are continuously monitored, and the aggregate value of transactions concluded is spread amongst approved counterparties.
The company's current credit risk grading framework comprises the following categories:
| Category | Description | Basis for recognising expected credit losses |
|---|---|---|
| Performing | The counterparty has a low risk of default and does not have any past-due amounts |
12-month ECL |
| Doubtful | Amount is >30 days past due or there has been a significant increase in credit risk since initial recognition |
Lifetime ECL – not credit-impaired |
| In default | Amount is >90 days past due or there is evidence indicating the asset is credit-impaired |
Lifetime ECL – credit-impaired |
| Write-off | There is evidence indicating that the debtor is in severe financial difficulty and the company has no realistic prospect of recovery |
Amount is written off |
The table below details the credit quality of the company's financial assets as well as the company's maximum exposure to credit risk by credit risk rating grades.
| Other receivables | |
|---|---|
| External credit rating | n/a |
| Internal credit rating | - |
| 12 month or lifetime ECL | Lifetime ECL |
| Gross carrying amount USD'000's | 776 |
| Loss allowance | - |
| Net carrying amount | 776 |
For other receivables, the company has applied the simplified approach in IFRS 9 to measure the loss allowance at lifetime
ECL. The expected credit losses are estimated using a provision matrix by reference to past default experience of the debtor and an analysis of the debtor's current financial position, adjusted for factors that are specific to the debtors, general economic conditions of the industry in which the debtors operate and an assessment of both the current as well as the forecast direction of conditions at the reporting date.
The company seeks to limit its liquidity risk by ensuring financial support is available from the shareholders. Trade payables are normally settled within 90 to 120 days of the date of receipt of invoice.
The table below summarises the maturity profile of the group's financial liabilities at 31 December 2022 based on contractual undiscounted payments.
| (Amounts in USD thousand) | On demand | Between 1 and 3 months |
Between 3 months and 1 year |
Total |
|---|---|---|---|---|
| 31 December 2022 Due to related parties Trade and other payables |
6,491 - |
- 1,171 |
- - |
6,491 1,171 |
| Total | 6,491 | 1,171 | - | 7,662 |
The company operates internationally and is exposed to risk arising from various currency exposures, primarily with respect to the Norwegian Kroner (NOK). The group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the respective functional currency.
The company reports its results in USD; any change in exchange rates between its functional currency and the USD affects its statement of comprehensive income and statement of financial position when the results are translated into USD for reporting purposes.
The company'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.
Financial instruments comprise financial assets and financial liabilities.
Financial assets consist of bank balances and cash. Financial liabilities consist of other liabilities.
The fair values of the group's financial instruments are not materially different from their carrying amounts at the reporting date largely due to the short-term maturities of these instruments.
The following tables present PetroNor E&P ASA's classes of financial instruments and their carrying amounts by the categories as they are defined in IFRS 9 Financial instruments. For financial investments, the difference between measurement as defined by IFRS 9 categories and measurement at fair value is immaterial. For trade and other receivables and payables and cash and cash equivalents, the carrying amounts are considered a reasonable approximation of fair value.
| Amortised | Fair value through | Non-financial | Total carrying | |
|---|---|---|---|---|
| (Amounts in USD thousand) | cost | profit or loss | assets | amount |
| At 31 December 2022 | ||||
| Assets | ||||
| Receivables from subsidiaries | 64 | - | - | - |
| Trade and other receivables | 714 | - | - | - |
| Cash and cash equivalents | 30 | - | - | - |
| Total financial assets | 808 | - | - | - |
| At 31 December 2021 | ||||
| Cash and cash equivalents | 114 | - | - | - |
| Total financial assets | 114 | - | - | - |
The parent company has given a parent company guarantee against an external debt facility for USD 11 million loaned to indirect subsidiary Hemla Africa Holding AS.
In December 2021, the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway (Økokrim) initiated an investigation into allegations of corruption and brought criminal charges against individuals associated with the company. Økokirm has confirmed that neither PetroNor nor any of its subsidiaries has been charged. The US Department of Justice also began its own investigation into the allegations based on information received from Økokrim.
On 26 January 2023, two new directors were appointed to the board. The appointments were pursuant to recommendations from the nomination committee. The two new directors, Mrs. Azza Fawzi and Mr. Jarle Norman-Hansen, take the company's board to a total of six directors.
To mitigate potential corporate liability risks, the board has taken various remediation steps, as outlined in the director's report, including obtaining independent legal advice and implementing a compliance action plan. Despite the ongoing investigations, the company has continued to operate effectively, but has incurred costs in addressing this issue and fully cooperating with the investigating authorities. The company is not aware of the status or duration of the investigations into the individuals involved, and the uncertainty surrounding the outcome could potentially impact the company's ability to conduct transactions with both new and existing partners.
Except for the above, the company has not identified any events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report.
The following is a summary of the material accounting policies adopted by the company in the preparation of the financial statements. The accounting policies have been consistently applied, unless otherwise stated.
Cash and cash equivalents include cash on hand, demand deposits, other short-term highly liquid investments with original maturities of three months or less.
Trade receivables are amounts due from customers for goods sold or services performed in the ordinary course of business. They are generally due for settlement within 30 to 90 days and therefore are all classified as current. Trade receivables are recognised initially at the amount of consideration that is unconditional unless they contain significant financing components, when they are recognised at fair value. The group holds the trade receivables with the objective to collect the contractual cash flows and therefore measures them subsequently at amortised cost using the effective interest method.
Trade and other payables are carried at amortised cost and due to their short-term nature, they are not discounted.
Incremental costs directly attributable to the issue of new shares are shown in equity as a deduction, net of tax, from the proceeds.
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 company 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.
The initial accounting for a business combination can be changed if new information about the fair value at the acquisition date is present. The allocation can be amended within 12 months of the acquisition date [provided that the initial accounting at the acquisition date was determined provisionally]. The non-controlling interest is set to the noncontrolling interest's share of identifiable assets and liabilities [alternative fair value]. The measurement principle is done for each business combination separately. 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.
Goodwill is recognised as the aggregate of the consideration transferred and the amount of any non-controlling interest and deducted by the net of the acquisition-date amounts of the identifiable assets acquired and the liabilities assumed. Goodwill is not depreciated but is tested at least annually for impairment. In connection with this, goodwill is allocated to cash-generating units or groups of cash-generating units that are expected to benefit from synergies from the business combination.
If the fair value of the equity exceeds the acquisition cost in a business combination, the difference is recognised as income immediately on the acquisition date.
A financial instrument is any contract that gives rise to a financial asset of any one entity and a financial liability or equity instrument of another entity.
The company´s financial assets are other receivables and cash and cash equivalents.
The classification of financial assets at initial recognition depends on the financial asset's contractual cash flow characteristics and the company's business model for managing them. The company initially measures a financial asset at its fair value.
The company measures financial assets at amortised cost if both of the following conditions are met:
Financial assets at amortised cost are subsequently measured using the effective interest (EIR) method and are subject to impairment. Gains and losses are recognised in profit or loss when the asset is derecognised, modified, or impaired.
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.
Trade receivables are written off when there is no reasonable expectation of recovery. Indicators that there is no reasonable expectation of recovery include, amongst others, the failure of a debtor to engage in a repayment plan with the group, and a failure to make contractual payments for a period of greater than 120 days past due.
Impairment losses on trade receivables and contract assets are presented as net impairment losses within operating profit. Subsequent recoveries of amounts previously written off are credited against the same line item.
A financial asset (or, where applicable, a part of a financial asset or part of a group of similar financial assets) is primarily derecognised (i.e., removed from the company's statement of financial position) when:
The rights to receive cash flows from the asset have expired or the company has transferred its rights to receive cash flows from the asset or has assumed an obligation to pay the received cash flows in full without material delay to a
third party under a 'pass-through' arrangement; and either (a) the company has transferred substantially all the risks and rewards of the asset, or (b) the company has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset.
Financial liabilities are classified, at initial recognition, as loans and borrowings, payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. Derivatives are recognised initially at fair value. Loans, borrowings and payables are recognised at fair value net of directly attributable transaction costs.
Derivatives are financial liabilities when the fair value is negative, accounted for similarly as derivatives as assets.
After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortised cost using the EIR method. Gains and losses are recognised in profit or loss
when the liabilities are derecognised as well as through the EIR amortisation process.
Amortised cost is calculated by taking into account any discount or premium on acquisition and fees or costs that are an integral part of the EIR. The EIR amortisation is included as finance costs in the statement of profit or loss.
Payables are measured at their nominal amount when the effect of discounting is not material.
A financial liability is derecognised when the obligation under the liability is discharged or cancelled or expires. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as the derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognised in the statement of profit or loss.
Pursuant to the Norwegian Securities Trading Act section 5-5 with pertaining regulations we hereby confirm that, to the best of our knowledge, the group's financial statements for 2022 have been prepared in accordance with IFRS, as provided for by the EU, and in accordance with the requirements for additional information provided for by the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair picture of the group'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 business, and includes a description of the principal risk and uncertainty factors facing the group. Additionally, we confirm to the best of our knowledge that the "Payments to governments" included in the directors' report has been prepared in accordance with the requirements in the Norwegian Securities Trading Act Section 5-5a with pertaining regulations.
Oslo, Norway, 28 April 2023
The board of directors – PetroNor ASA
Azza Fawzi Jarle Norman-Hansen Director Director
Eyas Alhomouz Gro Kielland Joseph Iskander Ingvil Smines Tybring-Gjedde Chair Director Director Director
BDO AS Munkedamsveien 45 PO Box 1704 Vika 0121 Oslo Norway
To the Annual Shareholders meeting of PetroNor E&P ASA
Report on the Audit of the Financial Statements
Opinion
We have audited the financial statements of PetroNor E&P ASA.
The financial statements comprise:
In our opinion:
Our opinion is consistent with our additional report to the Audit Committee.
We conducted our audit in accordance with International Standards on Auditing (ISAs). Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audit of the Financial Statements section of our report. We are independent of the Company and the Group as required by relevant laws and regulations in Norway and the International Ethics Standards Board for Accountants' International Code of Ethics for Professional Accountants (including International Independence Standards) (IESBA Code), and we have fulfilled our other ethical responsibilities in accordance with these requirements.We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
To the best of our knowledge and belief, no prohibited non-audit services referred to in the Audit Regulation (537/2014) Article 5.1 have been provided.
We have been the auditor of PetroNor E&P ASA for 2 years from the election in the Memorandum of Association on 1 October 2021 for the accounting year 2021.
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Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial statements of the current period. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.
| Description of the key audit matter | How the key audit matter was addressed in the audit |
|---|---|
| Valuation of oil and gas assets and related goodwill |
|
| PetroNor E&P ASA has property, plant and equipment with a carrying amount of USD 67,479 thousands at 31 December 2022. In addition, the carrying value of intangible assets (including technical goodwill) was USD 42,283 thousands at 31 December 2022. No impairments have been recognized during 2022 related to oil and gas assets and related goodwill. Due to the materiality, complexity and estimation uncertainty concerning the oil and gas assets and related goodwill, we consider valuation of these assets a key audit matter. Please refer to notes 16 and 17 in the consolidated financial statements. |
We obtained management's impairment tests of oil and gas assets and related goodwill as at 31 December 2022. We evaluated the production volumes and capital expenditures used in the forecasted cash flows against external and internal reserve reports and assessed commodity prices against available market information. We involved specialists in assessing management's estimates of weighted average cost of capital including country risk premiums, and we compared the input against available market information. Furthermore, we evaluated the professional qualifications and objectivity of the external reserve experts used by management. We have also evaluated the adequacy of the disclosures. |
| Acquisition of Pan AJE interests | |
| On 13 July 2022, the Group acquired from Panoro Energy ASA the wholly-owned subsidiaries Pan-Petroleum Nigeria Holding BV and Pan-Petroleum Services Holding BV, who together hold a 100 per cent interest of the shares in Pan-Petroleum AJE Ltd. The agreed purchase price consisted of an upfront consideration of USD 10 million paid via the allotment and issue of 96,577,537 new PetroNor shares, and a conditional |
We have obtained and read the Sale and Purchase Agreement (SPA) between PetroNor E&P ASA and Panoro Energy ASA. We challenged management as to whether there could be other assets and liabilities than those identified in the preliminary PPA. In addition, we performed the following audit procedures: • we compared Sale and Purchase Agreement (SPA) and Purchase Price |
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consideration which shall not exceed USD 16.67 million in cumulated payments.
The acquisition was determined to constitute a business combination and application of the acquisition method of accounting in accordance with IFRS 3 was deemed appropriate.
In relation to the acquisitions, the management has prepared a preliminary purchase price allocation (PPA). The purchase price allocation requires the application of significant judgment by management, in particular with respect to identification and valuation of intangible assets.
Due to the materiality, complexity and estimation uncertainty, we consider accounting for business combinations to constitute a key audit matter in the audit of the group.
The Group's accounting policy regarding business combinations is disclosed in note 31W to the consolidated financial statements.
Allocation (PPA) with respect to consideration amounts
We involved our internal valuation specialists to assist us with our assessment of the appropriateness of the methodology and valuation model used.
Furthermore, we have evaluated the adequacy of the disclosures provided in the notes covering business combinations.
The Board of Directors and the Managing Director (management) are responsible for the other information. The other information comprises the Board of Directors' report and other information in the Annual Report, but does not include the financial statements and our auditor's report thereon. Our opinion on the financial statements does not cover the other information.
In connection with our audit of the financial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.
Based on our knowledge obtained in the audit, in our opinion the Board of Directors' report
Our opinion on the Board of Directors' report applies correspondingly for the statements on Corporate Governance and Corporate Social Responsibility.
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Responsibilities of the Board of Directors and the Managing Director for the Financial Statements
Management is responsible for the preparation of financial statements that give a true and fair view in accordance with International Financial Reporting Standards as adopted by the EU, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, management is responsible for assessing the Company's and the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company or Group or to cease operations, or has no realistic alternative but to do so.
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements.
For further description of Auditor's Responsibilities for the Audit of the Financial Statements reference is made to: https://revisorforeningen.no/revisjonsberetninger
As part of the audit of the financial statements of Petronor E&P ASA we have performed an assurance engagement to obtain reasonable assurance about whether the financial statements included in the annual report, with the file name 984500AEEH2D2AK42C11-2022-12-31-en , have been prepared, in all material respects, in compliance with the requirements of the Commission Delegated Regulation (EU) 2019/815 on the European Single Electronic Format (ESEF Regulation) and regulation pursuant to Section 5-5 of the Norwegian Securities Trading Act, which includes requirements related to the preparation of the annual report in XHTML format and iXBRL tagging of the consolidated financial statements.
In our opinion, the financial statements, included in the annual report, have been prepared, in all material respects, in compliance with the ESEF Regulation.
Management is responsible for the preparation of the annual report in compliance with the ESEF Regulation. This responsibility comprises an adequate process and such internal control as management determines is necessary.
For a description of the auditor's responsibilities when performing an assurance engagement of the ESEF reporting, see: https://revisorforeningen.no/revisjonsberetninger
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Oslo, 28 April 2023
BDO AS
Børre Skisland State Authorised Public Accountant
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PetroNor discloses alternative performance measures (APMs) in accordance with the issued guidelines from the European Securities and Markets Authority (ESMA). PetroNor discloses APMs that we believe provide useful information to management, investors, securities analysts and other
stakeholders. The disclosed APMs assist users of the financial statements to understand operations, financial developments, financing and future prospects. Reconciliations of relevant APMs, definitions and explanations of the APMs are as follows:
| Amounts in USD thousand | 2022 | 2021 |
|---|---|---|
| Cash and cash equivalents | 24,816 | 31,755 |
| Loans and borrowings | 11,000 | 13,079 |
| Net cash/-debt | 13,816 | 18,676 |
| 2022 | 2021 | |
|---|---|---|
| Share price 31 December (NOK) | 0.8925 | 0.7710 |
| No. shares 31 December | 1,326,991,006 | 1,423,568,543 |
| Market capitalisation (USD) | 131,800,000 | 111,400,000 |
FX Rate NOK/USD: 0.101513
Market capitalisation
ESMA issued guidelines on APMs that came into effect on 3 July 2016. PetroNor has defined and explained the purpose of the following APMs:
EBITDA is calculated by excluding the interest, tax, depreciation and amortisation from the group's profit or loss. PetroNor have assessed EBITDA as a key measure to convey the group's ability to fund capital investments and provides useful information as a benchmark for operating performance with those of other companies.
EBIT is calculated by excluding the interest and tax from the group's profit or loss. Management believe EBIT provides useful information to stakeholders as it can be used to analyse the business' operating performance, profitability and potential.
Net debt is calculated as cash and cash equivalents less borrowings and loans. Net debt provides useful information to stakeholders as it provides an indication of the minimum necessary debt financing (if the figure is negative) to which the group is subject to at balance sheet date.
Market capitalisation as reconciled above refers to the total value of a company's shares of stock. Management believe market capitalisation provides useful information to potential investors in understanding the relative size of the company versus others as well as understanding the company's worth, market perceptions and future prospects.
| Bbl | One barrel of oil, equal to 42 US gallons or 159 litres |
|---|---|
| Bcf | Billion cubic feet |
| bopd | Barrels of oil per day |
| boepd | Barrels of oil equivalent per day |
| CGU | Cash Generating Unit |
| CPR | Competent Person's Report |
| GNPC | Gambia National Petroleum Company |
| Group or PetroNor group | PetroNor E&P ASA and its subsidiaries |
| HAH | Hemla Africa Holding AS |
| HEPCO | Hemla E&P Congo SA |
| IASB | International Accounting Standards Board |
| IOR | Improved oil recovery |
| MMbbl | Million barrels of oil |
| MMBOE | Million barrels of oil equivalent |
| Mmscfd | Million standard cubic feet per day |
| NUPRC | Nigerian Upstream Petroleum Regulatory Commission |
| PEPLA | Petroleum, exploration, development and production licence agreement |
| PSC | Production sharing contract |
| SNPC | Société National des Pétroles du Congo |
Eyas Alhomouz Joseph Iskander Gro Kielland Ingvil Smines Tybring-Gjedde Azza Fawzi Jarle Norman-Hansen
Frøyas gate 13 NO-0273 Oslo Norway
Oslo Børs Ticker: PNOR ISIN: NO0011157232
DNB Bank ASA, Verdipapirservice Dronning Eufemias gate 30 0191 Oslo Norway
Munkedamsveien 45, Vika Atrium 0121 Oslo Norway
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