Annual Report • May 6, 2022
Annual Report
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| PetroNor E&P in brief4 | |
|---|---|
| CEO letter 8 | |
| Portfolio10 | |
| Reserves 16 | |
| ESG report 23 | |
| Corporate governance 30 | |
| Board of Directors 36 | |
| Management 38 | |
| Board of Directors' report 43 | |
| Financial statements 62 | |
| Contact 117 |
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 its reserve base, production and cash flow. PetroNor E&P is committed to the highest standards of corporate governance, to safely and efficiently deliver operational excellence.
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. To reflect growth ambitions, the Board has set a revised target of achieving 2P reserves in excess of 100 MMbbl and net production in excess of 30,000 barrels of oil equivalent per day (boepd) by the end of 2024. In addition, the goal is to drill two high impact exploration wells by the end of 2023.
We are an independent oil and gas exploration and production company with multiple licences in countries in West Africa – Republic of Congo, Guinea-Bissau, Senegal, The Gambia and Nigeria. The Company has amassed a diverse and highquality portfolio comprising economically-robust production, development upside, and high-impact exploration in the MSGBC basin.
In 2020 PetroNor held a 10.5 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.
On 25 January 2021, the indirect participation interest in the venture increased to 11.9 per cent after 9,900 shares in Hemla E&P Congo awarded by the court in Congo were registered for the benefit of the Company.
On 12 March 2021, a transaction to increase the indirect participation interest in the venture
to 16.83 per cent by acquisition of the noncontrolling interest shares in Hemla Africa Holding AS. The transaction was approved by an Extraordinary General Meeting held 4 May 2021.
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.
DEVELOPMENT
In 2019, PetroNor acquired a 13.1 per cent economic interest in Aje Field through two transactions with Panoro Energy ASA and Yinka Folawiyo Petroleum. In January 2022, the acquisition was granted formal governmental
consent, which has allowed PetroNor to re-engage financial and industrial partners with a target to mature the project towards a final investment decision (FID).
78.57 per cent interest of the Sinapa (Block 2) and Esperança (Blocks 4A and 5A) is held by the Group through the purchase of PetroNor E&P AB (previously SPE Guinea Bissau AB) from Svenska Petroleum Exploration AB in November 2020. The transaction was formally approved by Guinea-Bissau in April 2021.
In September 2020, under the terms of the settlement agreement, a new A4 licence was awarded providing a 90 per cent interest and operatorship of the A4 licence to the Group. The remaining 10 per cent interest of the new licence is held by the government of The Gambia.
This 'farm-out' phase of the licence was extended by the government of The Gambia until 18 October 2022. Continuation past this date requires a firm well commitment and bonus payment.
In Senegal, African Petroleum Senegal Ltd. reserve its rights to a 90 per cent operated interest in the ROP and SOSP licences with the National Oil Company, Petrosen, holding the remaining 10 per cent. The Company is in arbitration with the government of Senegal to protect its interests in the licences.
3
20.6 mmbbl Net 2P reserves
~3.7k bopd Net oil production
2
1
31.3 MMbbl Net 2C resources (of which Aje represents
19.0)
>2.3 bnbbl Net unrisked prospective resource
2021 was the year when a global pandemic and a severe drop in oil price were replaced by increased geopolitical tension, a global energy crisis and a sharp increase in the oil price. For PetroNor, 2021 was a year marked by strong operational performance and preparations for becoming a listed company on the main list of the Oslo Stock Exchange.
By the end of 2021, the world economy had experienced a sharp increase in the demand for energy, as more and more countries reduced the strict infection control measures that were introduced to limit Covid-19. This fuelled the world economy with optimism as the pandemic gradually began to let go. At the beginning of 2022, the energy crisis became even worse due to Russia's aggressive invasion in Ukraine.
For PetroNor, the combination of strong markets, organic growth and solid operational performance resulted in strong revenue growth and solid earnings in 2021.
On 16 December, the board asked me to assume the CEO role of PetroNor on an interim basis to maintain continuity of the business while my predecessor is under investigation in Norway for alleged corruption. I was, until then, a non-executive member of the board, and had previously been the CEO for African Petroleum and PetroNor until February 2020.
Økokrim, the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway, has confirmed that the investigation is currently focused on individuals and that neither PetroNor nor any company is under investigation.
The Company takes anti-corruption and the matter at hand very seriously. As a natural early step, a Compliance Action Plan to further implement our compliance program has been developed and approved by the board in 2022, building on the work that the company has previously undertaken in preparation for the successful redomicile of the company to Norway. This effort has involved an update of our Code of Conduct and related policies consistent with the Norwegian legislation, best practice and governance model. The action plan includes provision for dedicated resources for
compliance, increased focus on governance, and independent audit of compliance going forward.
I would like to extend my thanks to the PetroNor team for the way they have handled this situation. I am grateful for the support and professionalism which they have all shown in this challenging time for the company.
The key strategy of PetroNor is, in addition to developing existing assets and organic growth, to acquire additional oil and gas licences and pursue acquisition opportunities. The company holds exploration and production assets offshore West Africa.
PetroNor's indirect ownership interest in the offshore PNGF Sud production licences in Congo is the Company's core production licence. The operator of the licences is Perenco, a world-class operator of mature assets in emerging markets, which holds a 40 per cent interest in the PNGF Sud licences.
In February 2021, PetroNor increased its indirect ownership in PNGF Sud from 10.5 up to 16.83 per cent. We successfully completed a capital raise of NOK 340 million to fund the acquisition of additional ownership in PNGF Sud and to fund the PetroNor share of costs for the next phase of drilling. In addition, we raised NOK 51 million in a subsequent share offering in Q3 2021.
In October 2019, PetroNor entered into an agreement with Panoro Energy for the acquisition of 45 per cent holding interests in Offshore Mining Lease no. 113 offshore Nigeria, containing the Aje oil and gas field. After more than two years of waiting, we finally, in January 2022, received consent from the Nigerian government for the transaction.
The Aje field has a strong ESG profile. It is focused on producing and commercialising gas, and has the potential to provide low emission energy corresponding to five per cent of the total power production of Nigeria.
Aje will at re-development become a significant contributor to the CO2 emission reduction for Nigeria.
In February 2022, the world was shocked and saddened by the acts of war taking place in Ukraine. While the human suffering is clearly our main concern, we must also acknowledge that economic sanctions towards Russia and the economic uncertainty may have an impact on our business and our markets going forward. This in spite of the immediate effects in increasing oil and gas prices.
We have several ongoing and identified M&A initiatives. We are actively looking for value accretive transactions to meet our production target goal of 30,000 boepd by end 2024. The company has a supportive strategic shareholder in Petromal, which owns a 36 perc ent share of the Company , and is
– The key strategy of PetroNor is, in addition to developing existing assets and organic growth, to acquire additional oil and gas licences and pursue acquisition opportunities.
part of National Holding in Abu Dhabi. Petromal will support in providing access to further growth capital if the right accretive opportunities are identified.
An important milestone for PetroNor was the redomicile from Australia to Norway and the listing on the main list of Oslo Stock Exchange on 28 February 2022. I believe that this will enhance the Company's profile with investors, business partners, suppliers and customers, facilitate a more diversified shareholder base and allow for a more liquid market for the shares. These are all important factors for PetroNor's future growth and value creation.
Sincerely, Jens Pace Interim CEO PetroNor E&P
Numbers above are 20.6 mmbbl and 12.3 (without Aje, and 31.3 including Aje).
The Republic of Congo (Congo Brazzaville) is a leading producer of crude oil, representing around 90 per cent of the exports of the country. The majority of the production in Congo is located offshore, approximately half of which taking place in deep water.
Congo Brazzaville is an established oil producing country and a core country for PetroNor, both for production and for regional development.
PNGF Sud is operated by Perenco, a world leading specialist in low-cost optimisation of mature production assets like PNGF Sud.
The reserves have increased year-on-year and the production has continued to grow and the operating cost has been significantly reduced, all achieved through improving maintenance routines and field integrity in a stepwise and prudent manner.
The licence partnership has now embarked on a growth
plan to drill more than 17 new wells with a three-year investment program of some USD 350 million.
Since the entry of the new contractor group in 2017, low-cost incremental improvements via workovers, surface production process improvements, structural integrity, and HSE improvements have resulted in year by year growth in both production and reserves.
The average gross PNGF production was 20,636 bopd in 2021 with a continued low lifting cost of \$10.4/bbl. The continuous and low cost workover programme continued successfully in 2021, albeit hampered by
Covid-19 and logistical issues arising from difficulties getting surface and subsurface production equipment into the country in Q2 and in part of Q3. The logistics improved through Q3 and were fully normalised in Q4. At the end of 2021, the number of active producers increased to 67. The debottlenecking programme with its focus on total liquids will continue in 2022 and will be strengthened by further initiatives on power generation and intra-field power handling.
In November 2021, the licence partners started drilling the previously announced but six-month delayed (due to Covid-19) infill drilling programme, starting with the four wells on Litanzi. The drilling programme has been expanded to include jack-up installation and development drilling of two producers on Tchibeli NE to follow the Litanzi wells. Tchibeli resources for this development will be converted to reserves, accelerating the PNGF production profile. Infill and development drilling now comprises 17 sanctioned wells. The gross development programme including new platforms and intra-field pipelines, production debottlenecking and power handling is expected to amount to approximately USD 350 million (gross) and will result in a significant production increase for the PNGF Sud licence.
These reserves and resources are results of a successful workover and infill drilling planning programme in all the PNGF fields. The remaining 2P reserves have more than doubled since 1 January 2017. Taking account of the 60 per cent increase in PetroNor equity and production in the period, the reserves have increased by a factor of 3.8.
A two well development programme is planned.
Estimated reserves of 9.6 mmbo.
Located North-West of PNGF Sud, PNGF Bis licence 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, which would enable PetroNor to 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 tieback 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 coutry's primary reserves are concentrated in and around the Niger Delta. Nigeria is one of the few major oil producting nations still capable of increasing its oil output.
Aje Production was created as a joint venture between PetroNor and the operator Yinka Folawiyo Petroleum ("YFP"), and will lead the technical and management efforts in the next phase of the Aje field development.
The Aje Project targets production of gas, condensate, LPG, and electricity 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 related to the acquisition of a 13.1 per cent interest in the Aje Field. This transaction is thus on schedule to be completed with Panoro within the second quarter of this year. An SPV has been setup with the operator Yinka Folawiyo Petroleum where PetroNor is technically responsible for the upcoming development of the Aje gas discovery.
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 100 m to 1,500 m. 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 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.
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 have progressed significantly and given proper engagement with the licence partners, the plan is to proceed toward an FID involving changeout of the existing FPSO, drilling further gas and oil development wells, and 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 arrangements for gas and LPG products. The existing FPSO will be removed from the field as it has reached the end of economic field life and does not have the proper ratings for gas development.
Aje development plans are being finalised and will be presented to the joint venture partners following the Nigerian government's approval of the transactions.
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 Gas.
The consent from the Nigerian Upstream Petroleum Regulatory commission has allowed PetroNor to re-engage financial and industrial partners with a target to mature the project towards and FID later in 2022. The Nigerian government encourages stop-flaring programs and the country is in dire need of electrical power.
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) licences offshore Guinea Bissau in May 2021, through the purchase of SPE Guinea Bissau AB from Svenska Petroleum Exploration. PetroNor assumed operatorship and an interest of 78.57 per cent of the two licences with 78.57 per cent in each. In total, they cover an area of 4,963 km², and, are located on a highly prospective trend in the MSGBC. The two prospects, Atum and Anchova are commercially attractive low risk prospects with net unrisked, combined summed mean recoverable prospective resources of 306 MMbbl for Upper and Lower Albian targets (PetroNor estimate).
PetroNor has completed interpretation of 3D seismic data and is seeking Partners with a view of participating in a combined Guinea-Bissau – The Gambia drilling campaign in 2023.
The purchase of SPE Guinea Bissau AB from Svenska Petroleum Exploration AB received formal governmental approval in late April 2021. Subsequently, in May 2021, PetroNor assumed operatorship of the Sinapa (Block 2) and Esperança (Blocks 4A and 5A) licences through the renamed Svenska subsidiary acquired, PetroNor E&P AB. The current Exploration phases of the Guinea-Bissau licences were extended for three years in October 2020 and are valid until October 2023.
PetroNor intends to build on the work of the previous operator, and re-initiate planning for drilling of the Atum-1X well, to test a highly attractive and material prospect on the Sinapa licence called Atum/Anchova in 2023. These prospects are analogous to the Sangomar field in Senegal. Long lead items required for drilling operations have been secured and a number of pre-drill studies completed. Well planning can be recommenced at short notice.
Recently reprocessed seismic has been interpreted as part of the ongoing evaluation of both licences. The whole portfolio will be re-evaluated across both licences including the Sinapa-2 discovery.
In September 2020, 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. Prior Sunk costs associated with A4 will be carried into the new agreement for tax breaks and an enhanced commercial model. The Government of The Gambia extended the longstop date of the A4 licence until 18 October 2022.
PetroNor has completed interpretation of 3D seismic PSDM data (TGS Jaan 3D) and is seeking a partner to join the Company in drilling one exploration well in this highly attractive acreage that is on trend with the Sangomar field, 40 km to the North in Senegal. PetroNor aims to participate in any future well at an equity level of 30-50 per cent and hopes to drill in 2023 as part of a combined drilling campaign with Guinea-Bissau.
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 licences.
The arbitration proceedings were halted between May 2020 and April 2021 to allow discussions between the parties to try and reach a mutually beneficial solution, disappointingly to no avail.
The Company remains confident in its legal position and awaits a final arbitration decision.
Area in km2: 15,796
Operator:
African Petroleum Senegal Ltd
Net unrisked prospective resources (bbl):
1.8Bn
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 April 2022 for PNGF Sud and PNGF Bis.
The Group holds exploration and production assets in Africa through subsidiaries and joint ventures, namely the offshore PN GF Sud production licences in the Republic of Congo, the Sinapa (Block 2) and Esperança (Blocks 4A and 5A) licences offshore Guinea-Bissau, the A4 licence 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. Further, following receipt of in-country governmental approval from the Nigeria Upstream Petroleum Regulatory Commission (NUPRC replacing the DPR) for the Aje Transaction, the Group will hold indirect interests in the OML-113 which includes the Aje Field offshore Nigeria. This transaction is not yet completed and is not part of this Annual Statement of Reserves ("ASR").
The exploration assets in Guinea-Bissau, The Gambia and Senegal only constitute prospective resources, and are therefore not considered part of this ASR.
PNGF Sud is a development and exploitation licence comprising three (3) production licence agreements (Tchibouela II, Tchendo II and Tchibeli-Litanzi II), which contain five oil fields: Tchibouela Main, Tchibouela East, Tchendo, Tchibeli and Litanzi.
PetroNor E&P's indirect subsidiary, HEPCO, holds a 20 per cent (16.83 per cent net to PetroNor) non-operated interest in the PNGF Sud licences offshore Congo. The operator of the licences is Perenco which holds a 40 per cent interest in the PNGF Sud licences.
Effective since 1 January 2017, the ownership of the licences has an expiry date after 20 years plus a 5-year extension period.
Since granting of the licences, 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. Production is expected to ramp up significantly in 2022 in response to the drilling programme.
In March and April 2022, 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 at 31 December 2021.
Gross production during 2021 was 7.53 MMbbls of oil and 1.0 Bcf of gas. This corresponds to an average of 20,636 bopd and 2.7 mmscfd.
As per the PRMS/SPE guidelines, only the portion of gas is contributing to power generation (on Tchibouela 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 2022 AGR CPR yielding Reserves and Resources as per 31 December 2021. As the only product sold is oil, the text below will mainly refer to oil and term these with the unit MMbbls.
At 31 December 2021, AGR evaluated that gross 1P Proved Reserves yield 84.9 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 122.2 MMbbls in the same reservoirs. Gross 3P Proved plus Probable plus Possible Reserves at PNGF Sud amounted to 154.8 MMbbls.
Gross 1C Resources yield 20.6 MMbbls in all of the PNGF Sud fields in the Cenomanian, Turonian, Senonian and Albian reservoirs. Gross 2C Resources at PNGF Sud amounted to 32.7 MMbbls in the same reservoirs. Gross 3C Resources at PNGF Sud amounted to 58.4 MMbbls.
These evaluations yield 1P Proved Reserves net to PetroNor of 14.3 MMbbls, 2P Proved plus Probable Reserves net to PetroNor of 20.6 MMbbls and 3P Proved plus Probable plus Possible Reserves net to PetroNor of 26.6 MMbbls.
Additional potentially recoverable resources net to PetroNor are approximately 3.5 MMbbls 1C, 5.5 MMbbls 2C and 9.8 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 licence 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 is a likely scenario. 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 third party verifications of its reserves and resources.
All evaluations are based on standard industry practice and methodology for production decline analysis and reservoir modelling based on geological and geophysical analysis. The following discussions are a comparison of the volumes reported in previous reports, along with a discussion of the consequences for the year-end 2021 ASR:
During all the years from 2017 to 2020, production levels have grown from the initial c. 15,000 bopd when Perenco and partners took over. This has materialized through revitalizing existing producers via replacements or upsizing of Electrical Submersible Pumps (ESP's), acidising, 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 have yielded a production level during 2021 of 20,636 bopd, slightly down from 2020 due to Covid-related delays. 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. In addition to this, significant infill drilling potential has been identified in all fields and justified for investment, so far in three of these, the Litanzi, Tchendo and Tchibeli. The start of infill drilling has in 2021 also been delayed by Covid-19 to a drilling start in November, however, significant investments were made in 2020-2021 for infill drilling infrastructure to accommodate offtake, process and well slots. 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 has been maintained with a significant 2C potential as well as a slight increase in the 2C resources in Tchibouela East.
In summary for all fields, the conversion of 2C to 2P and increase in 2P reserves between 2020 and 2021 constitutes ca 9.5 MMbbls. With gross produced volumes during 2021 of 7.53 MMbbls, this represents a reserve replacement ratio of 126 100 per cent.
Once investment decisions are made 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.
| 2021 – 2P Reserves Balance (gross AGR, PNGF Sud – 31.12.2021) |
122.2 |
|---|---|
| Balance 31.12.2021 – 2P net, PNGF Sud | 20.6 |
| 2P and 2C Reserves and Resources Status Balance 31.12.2021 – 2P/2C gross, PNGF Sud |
154.9 |
| Balance 31.12.2021 – 2P/2C net, PNGF Sud | 26.1 |
| Balance 31.12.2021 – 2P/2C gross, Sud+Bis | 183.8 |
| Balance 31.12.2021 – 2P/2C net, Sud+Bis | 32.9 |
PetroNor's total 1P Reserves at the end of 2021 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 2021, PetroNor's assets contain a total 2C volume of approximately 12.3 MMbbl.
29 April 2022
JENS PACE Interim CEO
| 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 | 45.28 | 11.32 | 47.30 | 57.30 | 16.72 | 60.28 | 69.23 | 24.76 | 73.64 |
| Tchibouela East | 1.40 | 1.40 | 1.87 | - | 1.87 | 2.35 | 2.35 | ||
| Tchendo | 19.19 | - | 19.19 | 26.42 | - | 26.42 | 34.06 | - | 34.06 |
| Tchibeli | 7.00 | - | 7.00 | 17.00 | - | 17.00 | 25.63 | - | 25.63 |
| Tchibeli NE | 4.94 | - | 4.94 | 9.57 | - | 9.57 | 14.62 | - | 14.62 |
| Litanzi | 7.08 | - | 7.08 | 10.01 | - | 10.01 | 12.16 | - | 12.16 |
| Subtotal | 84.89 | 11.32 | 85.50 | 122.17 | 16.72 | 123.28 | 158.06 | 24.76 | 160.12 |
| 100% PNGF Bis Loussima (Bis) |
- | - | - | - | - | - | - | - | - |
| Total | 84.89 | 11.32 | 85.50 | 122.17 | 16.72 | 123.28 | 158.06 | 24.76 | 160.12 |
| 1P | 2P | 3P | |||||||
|---|---|---|---|---|---|---|---|---|---|
| Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo |
Gas bcf |
Boe mmboe |
Oil mmbo | Gas bcf |
Boe mmboe |
|
| 10.50% PNGF Sud | |||||||||
| Tchibouela | 13.60 | 8.90 | 15.19 | 21.20 | 13.80 | 23.66 | 34.10 | 22.30 | 38.07 |
| Tchibouela East | 1.61 | - | 1.61 | 2.34 | - | 2.34 | 5.06 | - | 5.06 |
| Tchendo | 5.40 | - | 5.40 | 9.14 | - | 9.14 | 19.20 | - | 19.20 |
| Tchibeli | - | - | - | - | - | - | - | - | - |
| Tchibeli NE | - | - | - | - | - | - | - | - | - |
| Litanzi | - | - | - | - | - | - | - | - | - |
| Subtotal | 20.61 | 8.90 | 22.20 | 32.68 | 13.80 | 35.13 | 58.36 | 22.30 | 62.34 |
| 14.70% PNGF Bis Loussima (Bis) |
22.40 | - | 22.40 | 28.90 | - | 28.90 | 35.80 | - | 35.80 |
| Total | 43.01 | 8.90 | 44.60 | 61.58 | 13.80 | 64.03 | 94.16 | 22.30 | 98.14 |
| 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 | 7.62 | 1.90 | 7.96 | 9.64 | 2.81 | 10.15 | 11.65 | 4.17 | 12.39 |
| Tchibouela East | 0.24 | - | 0.24 | 0.32 | - | 0.32 | 0.40 | - | 0.40 |
| Tchendo | 3.23 | - | 3.23 | 4.45 | - | 4.45 | 5.73 | - | 5.73 |
| Tchibeli | 1.18 | - | 1.18 | 2.86 | - | 2.86 | 4.31 | - | 4.31 |
| Tchibouela East | 0.83 | - | 0.83 | 1.61 | - | 1.61 | 2.46 | - | 2.46 |
| Litanzi | 1.19 | - | 1.19 | 1.69 | - | 1.69 | 2.05 | - | 2.05 |
| Subtotal | 14.29 | 1.90 | 14.63 | 20.56 | 2.81 | 21.06 | 26.60 | 4.17 | 27.34 |
| 16.83% PNGF Sud Loussima (Bis) |
- | - | - | - | - | - | - | - | - |
| Total | 9.05 | 1.90 | 14.63 | 20.56 | 2.81 | 21.06 | 26.60 | 4.17 | 27.34 |
| 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 | 2.29 | 1.5 | 2.56 | 3.57 | 2.32 | 3.98 | 5.74 | 3.75 | 6.41 |
| Tchibouela East | 0.27 | - | 0.27 | 0.39 | - | 0.39 | 0.85 | - | 0.85 |
| Tchendo | 0.91 | - | 0.91 | 1.54 | - | 1.54 | 3.23 | - | 3.23 |
| Tchibeli | - | - | - | - | - | - | - | - | - |
| Tchibouela East | - | - | - | - | - | - | - | - | - |
| Litanzi | - | - | - | - | - | - | - | - | - |
| Subtotal | 3.47 | 1.5 | 3.74 | 5.50 | 2.32 | 5.91 | 9.82 | 3.75 | 10.49 |
| 14.70% PNGF Bis | |||||||||
| Loussima (Bis) | 5.28 | - | 5.28 | 6.81 | - | 6.81 | 8.44 | - | 8.44 |
| Total | 8.75 | 1.5 | 9.01 | 12.31 | 2.32 | 12.72 | 18.26 | 3.75 | 18.93 |
PetroNor strongly believes that the ability to create long-term, lasting value rests on maintaining high standards of governance, sustainable business practices and operations. The Company is committed to acting responsibly, and endeavours to enrich the local communities in which it operates.
Part of PetroNor`s vision is to create value for the shareholders in a sustainable manner where due regard is given to economical, social and environmental issues. The Company values of honesty, integrity and transparency are leading the Company as it is working towards a vision of improving the future and the aim of sustainable resource development in all operations.
The theme of the energy transition has gained momentum through the last year. Further climate change poses tangible risks to the planet and humanity. PetroNor is embracing the topic, but also sees that the transition poses its very own immediate risk to the environmental and socioeconomic development of the countries and people in Africa.
It is well known that hundreds of millions of Africans do not have access to reliable electricity and the continent will not be transitioning to a greener economy at the same pace as more developed nations. As such, the Company believes that credible operators such as PetroNor have a key role to play in enabling a smooth and steady transition that enables the continent to continue to benefit from its natural resources until a more viable and sustainable solution is ready. Given our strong network and growing reputation as a responsible operator, we are positioning ourselves as a partner of choice, and will be engaging with governments and International Oil Companies to see how we can help them deliver on their respective agendas.
According to the UN sustainability goals, gas is an important transition fuel for Africa. PetroNor's Aje transaction seeks to close down existing gas flaring in the field and pipe gas to shore creating a lower carbon solution for the region.
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.
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. The environmental policy provides a framework for decision making and project implementation. In that regard, PetroNor strives to conduct all operations in an environmentally responsible manner.
The synergies between the Company`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.
PetroNor recognises that climate change is of increasing political importance, and through regulation could have a material impact on the Group's business. The Company always aims to minimise any adverse impact on the environment.
Further, 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 Company's costs and/or revenues. For example, sustained lower oil and gas prices or price declines may inter alia lead to a material decrease in net production revenues.
Climate risk will be an important aspect of financial and internal control going forward, as well as shortand long-term strategic planning and business development. In 2022, PetroNor will integrate climate risk to its risk management system.
PetroNor seeks to minimize any adverse impact on the environment. Environmental Social Impact Assessments (ESIA) are carried out prior to all major activities and the Company communicates the results to all government agencies and other relevant stakeholders. 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. Further, contingency plans are in place to swiftly mitigate any potential damage to the environment.
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 2021, there have been no significant known breaches of the environmental regulations in place for the Company's exploration licences.
PetroNor is committed to conducting business in a manner which respects human rights as set out in the UN Universal Declaration of Human Rights and seeks business partners and contractors who follow equivalent standards. The Company has a zero-tolerance approach to modern slavery and child labour in any part of the organization and supply chains. All workers shall be ensured 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.
PetroNor management must ensure that all PetroNor Representatives 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 recognized human rights and adhere to our ethical standards when conducting business with or on behalf of PetroNor. The Companys standard services agreement obliges the contractor to comply with the Companys Code of Conduct where standards regarding human rights are declared.
In November 2021, the Company updated its Know Your Supplier Policy to help make sure that it only does business with firms 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.
During the year, there were no cases identified in the company nor its supply chains that were in violation of human rights.
Health and Safety policies are essential for PetroNor. The Company`s objective for health, environment, safety, and quality (HSEQ) is zero accidents and zero unwanted incidents in all activities.
The oil and gas assets located in West Africa imply frequent travel, and the Company seeks to ensure adequate safety levels for employees travelling.
With its non-operated licences, PetroNor is dependent on the efforts of the operators with respect to achieving physical results in the field. However, PetroNor has chosen to take an active role in all licence 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.
The Group's operations have been conducted by the operators on behalf of the licencees, at acceptable HSE standards and the operator of PNGF Sud is reporting regularly on all key HSE indicators.
No accidents that resulted in loss of human lives or serious damage to people or property have been reported in 2021.
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.
The Company has a strong focus on CSR as well as an ethical code of conduct. The Company founders have established a separate CSR project, Power to Educate, and is supporting the CSR projects in the subsidiary in the Republic of Congo as well as the projects organized by the Operator in the PNGF Sud licence group. During 2020, the Company registered as a supporting company with the Extractive Industries Transparency Initiative, EITI.
PetroNor aims to work closely alongside local partners to improve the lives of the communities in which it operates. To ensure the Company`s efforts are sustainable, corporate social investments are primarily focused on project work in the following key areas:
PetroNor values each member of the team and is committed to providing an environment recognised for its positive energy, equality and professionalism, and will treat everyone with fairness, respect and dignity. Further, PetroNor aims to maintain a work 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.
The Company is an equal opportunity employer, with an equality concept integrated in its human resources policies. A diversified work environment is embraced, and the Group's personnel policies promote equal opportunities and rights and prevent discrimination based on gender, ethnicity,
colour, language, religion or belief. All employees are governed by PetroNor's Code of Conduct, to ensure anti-discrimination and a good work environment 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-recognized skills and qualifications specific to their job requirements. Employees are remunerated exclusively based upon skill level, performance and position.
During 2021, the monthly average number of employees and long-term consultants was 35.
| Actual | Objective | |
|---|---|---|
| Staff | 61% | 50% |
| Board | Nil | +20% |
| Proportion of women | ||
| Actual | Objective | |
| Staff | 36% | +20% |
| Executive management team | Nil | +20% |
1) Prior to the redomicile of PetroNor to Norway the percentage of the board that were female was 29 per cent.
Courtesy and respect are important aspects of a sound work environment and business dealings. PetroNor does not tolerate discrimination of colleagues or others affected by its business and will not tolerate any verbal or physical conduct that may lead to the harassment of others, disrupts others work performance or creates a hostile work environment. The Company expect all employees to treat everyone they come into contact with through work or work-related activities in a respectful manner.
There were no reported instances of harassment or intimidation during 2021.
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 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.
PetroNor's Board of Directors are responsible for establishing the Corporate Governance framework of the Company. Further, PetroNor Code of Practice for Corporate Governance (the "Code").
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 for life, health, or the environment. They are also encouraged to report any instances of unsafe practices and/or any dangerous working situations.
In 2021, there were no matters identified in the Company that were in violation of HSE management.
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 summarizes the company`s values and standards and further describes what is expected of both the company and its employees. The Company expects all 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 our activities.
The Code of Conduct is part of the overall framework of environmental, social and governance (ESG) and is of strategic importance to the business. 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.
It is PetroNor's policy to conduct all of its business in an honest and ethical manner. The Company takes a zero-tolerance approach to bribery
City of Banjul in The Gambia.
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.
It is strictly illegal to engage in any activity considered as bribery or corruption. PetroNor and its directors have zero tolerance for any form of bribery, corruption, fraud, dishonesty or deception. 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.
The current shareholders and all of PetroNor's representatives are required to comply with Norwegian laws, the UK Bribery Act and the US
FPCA and local laws in the jurisdictions where we conduct business.
PetroNors Anti-Bribery and Corruption policy can be found on the Companys website.
The Company is aware of an ongoing investigation by Økokrim, the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway, regarding alleged corruption. The investigation is focused on individuals, and neither PetroNor nor any company has been charged with legal offense.
PetroNor believes in openness and transparency for all its business dealings and activities. Illegal or unethical matters may negatively impact the work environment and the business in general. It is important that the Company deals with such matters properly, and all PetroNor representatives, current
and former, who have concerns about any aspect of our business are encouraged to raise them and to disclose any information which relates to improper, unethical or illegal conduct in the workplace.
Every PetroNor representative has a right and an obligation to raise their concerns about our business including matters such as:
Whistleblowers must 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/.
No cases were reported during the year.
The Board will evaluate the Group'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 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.
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 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 non-discrimination, 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 own shares will normally be restricted to defined purposes and are normally limited in time to the following year's annual general meeting. Any acquisition of 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 Chairperson 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 chairperson of the Nomination Committee as well as other directors 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. Members of the Board 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 Chairperson 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 held a total of eight meetings in 2021. The attendance rate for the Members of the Board can be found in the Board of Directors' report on page 62.
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 Chairperson 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 Chairperson 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.
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 remuneration to the Board will be decided by the Annual General Meeting each year.
PetroNor is a diversified company, and the remuneration will reflect the Board's responsibility, expertise, the complexity and scope of work as well as time commitment.
The remuneration to the Board is not linked to the Company's performance and share options shall not be granted to directors. Remuneration in addition to normal director's fee will be specifically identified in the Annual Report.
Members of the Board normally do not take on specific assignments for the Company in addition to their appointment as a member of the Board. Any exemptions shall be clarified with the full board.
The Board has established guidelines for the remuneration of the executive personnel. The guidelines will be presented to the Annual General Meeting each year and shall set out the main principles applied in determining the salary and
other remuneration of the executive personnel. The guidelines ensure convergence of the financial interests of the executive personnel and the shareholders. The guidelines shall be clear and transparent and contribute to the Company's strategy, long term interests and financial viability.
The remuneration shall, both with respect to the chosen kind of remuneration and the amount, encourage addition of values to the Company and contribute to the Company's common interests – both for the management as well as the owners.
Remuneration based on performance will normally be capped upwards.
The Company has established guidelines for the Company's reporting of financial and other information. The Chairperson 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 four quarterly presentations per year to shareholders, potential investors and analysts in connection with quarterly earnings reports or trading updates. The quarterly 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, a subsidiary of National Holding in Abu Dhabi.
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 20 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 director of private equity spearheading and managing EIIC's investments. 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 Masters degree in Management Programs, with strong focus on interaction, and 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.
Mrs Kielland is an independent director.
Mr Pace holds a BSc in Geology and Oceanography from the University of Wales and an MSc in Geophysics from Imperial College, London, UK.
Mr Pace is a highly regarded geoscientist, who has had a successful career at BP Exploration Operating Company Limited ("BP"), and its heritage company Amoco (UK) Exploration Company, spanning over 30 years. Mr Pace has held senior positions at BP for over 10 years, gaining substantial exploration and production experience in Africa, namely Algeria, Angola, Congo, Gabon and Libya, having also extended experience in Europe, Russia and Trinidad. He has contributed to a number of BP's exploration discoveries over his career, and has managed a very large and active exploration portfolio for BP in Africa. Additionally, Mr Pace has gained highly sought-after experience in the areas of field development and as a commercial manager, dealing with national oil companies and African governments.
Following the merger with PetroNor E&P Ltd (Cyprus) on 30 August 2019, Mr Pace resigned as Chief Executive Officer of PetroNor E&P Limited (Australia) on 29 February 2020, but remains on the Board of the Australian company as a Non-Executive Director.
Mr Frimann-Dahl holds a 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 and African Petroleum.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, volumetric analysis, commercial evaluation and portfolio management. Mr. Barrett also brings added strength to the team with his background in quantitative geophysics, stratigraphic interpretation workflows and 3D visualisation.
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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.
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 16 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.
PetroNor exited the year having attained solid revenue growth driven by strong market conditions with production improving as forecasted. The share placement and subsequent offering strengthened the Group's balance sheet. PetroNor successfully redomiciled to Norway and up-listed to the main list of the Oslo Stock exchange, giving shareholders access to a more liquid market for shares. With the self-funded Infill drilling programme in Congo progressing as planned and the recent approval of the Aje transaction, PetroNor is well positioned 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") for the year ended 31 December 2021.
until the date of this report are as follows. Directors were in office for this entire period unless otherwise stated.
the names of Directors of the ultimate parent entity of the Group in office during the financial year and
| PetroNor E&P Limited | Role | Appointed | Resigned |
|---|---|---|---|
| E Alhomouz | Non-Exec Chair | - | - |
| J Iskander | Non-Exec Director | - | - |
| J Pace | Non-Exec Director | 1 March 2020 | - |
| I Smines Tybring-Gjedde | Non-Exec Director | 29 May 2020 | - |
| G Kielland | Non-Exec Director | 1 February 2021 | - |
| A Neuling | Non-Exec Director | 6 April 2020 | |
| R Steinepreis | Non-Exec Director | 6 April 2020 | |
| G Ludvigsen | Executive Director | 29 May 2020 | 31 January 2021 |
| A Hicks | Company Secretary | - | - |
The names of the directors of PetroNor E&P ASA, since incorporation to the end of the financial year 2021, are as follows:
| PetroNor E&P ASA | Role | Appointed | Resigned |
|---|---|---|---|
| E Alhomouz | Chair of the Board | 1 October 2021 | - |
| J Iskander | Director | 8 October 2021 | - |
| J Pace | Director | 1 October 2021 | 9 February 2022 |
| I Tybring-Gjedde | Director | 1 October 2021 | - |
| G Kielland | Director | 1 October 2021 | - |
The board of directors' report for the PetroNor 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. We are an independent oil and gas exploration and production company with our portfolio of assets in countries offshore West Africa (Republic of Congo, The Gambia, Guinea-Bissau, Senegal and Nigeria).
The Company holds, through its Congo subsidiary, 2P reserves of 20.6 MMbbls and a production
averaging around 3,473 bopd as of year-end 2021.In addition, PetroNor holds a portfolio of exploration licences in Guinea-Bissau, The Gambia and Senegal with net unrisked prospective resources of approximately 4 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, the UK, the UAE and multiple locations in Africa. 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 Abu Dhabi and Norway, PetroNor will look to capitalise on 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 Board aims to build a substantial oil and gas company within three years with a target reserves base of 300 mmboe and production of 30,000 barrels of oil equivalent per day.
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 Abu Dhabi, as well as 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 on the Norwegian continental shelf, 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.
subsequent offering in September 2021.
The Company's principal activity during the year was oil and gas exploration and production.
On 15 December 2021, the National Authority for Investigation and Prosecution of Economic and Environmental Crime (Nw.: Økokrim) in Norway announced in a press release that they had entered the Company's premises in Oslo in relation to suspicion of a criminal offence committed by individuals related to the Group, including its previous CEO and his business partner who together hold shares in the Company. On the same day, the Group announced that it had no reason to believe that there were any suspicions against itself.
Hangar previously built by Comapny in Banjul, The Gambia.
On the subsequent day, 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-corrution and the matter at hand seriously and adopted a series of remediation steps. The individuals charges by Okokrim in December were removed from business operations.
On 16 December 2021, Jens Pace was appointed interim CEO of PetroNor E&P Ltd. and on 9 February 2022, Mr. Pace stepped down from his position as Director of PetroNor E&P ASA following his election as interim CEO of the Norwegian company.The Board engaged independent legal counsel to support their 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 seperate board subcommittee to support the Board with the matter at hand. These measures are designed to assure the further implementation of an effective anticorruption 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 sub-committee which does not comprise any persons subject to the charges or any investigations.
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.
Following the shareholders' approval, 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.
Following the 1 to 1 share swap, PetroNor E&P ASA began trading on Oslo Stock Exchange 28 February 2022.
Following the successful redomicile of the Company, the two Australian Directors and the Company secretary were not reappointed to PetroNor E&P ASA to streamline the Board and management structure.
Following these changes, the Board consists of four Directors, two of which are considered to be independent.
The key strategy of the Group is, in addition to developing existing assets and organic growth, to acquire additional oil and gas licences and pursue acquisition opportunities. The Group continuously considers such opportunities.
The Company has three production licence agreements (Tchbouela II, Tchendo II, and Tchibeli-Litanzi II), which cover five oil fields located in 80-100 m water depths approximately 25 km off the coast of Pointe-Noire: TM, TE, T, TL. 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 in January 2017 to an average production in 2021 of 20,636 bopd.
Production is expected to further ramp up significantly in 2022 in response to the 17 well infill programme commenced on PNGF Sud in November 2021 with four infill wells on Litanzi.
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 and April 2022, AGR Petroleum prepared a Competent Person's Report ("CPR") whereby the reserves were calculated as at 31 December 2021.
Congo - PNGF Sud.
Using the CPR and adjusting for 2021 production, as well as transferring Tchibeli NE from resources to reserves (as announced on 7 December 2022) as at 31 December 2021:
| Participation Interest | 16.83% |
|---|---|
| 1P reserves (MMbbls) | 14.3 |
| 2P reserves (MMbbls) | 20.6 |
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 total 2C volume of approximately 15.5 MMbbls assuming a 16.83 per cent participation interest.
PNGF Sud ended the year with a Q4 production of 22,016 bopd (net 3,705), constituting the highest quarterly production of the year. Q2 and Q3 were affected by COVID-19 and logistical challenges getting workover and production equipment into the country. The average production for the year was 20,636 bopd (net 3,473). Production is expected to ramp up significantly in 2022 in response to the agreed 17-well infill drilling programme started in November 2021 with four wells on the Litanzi field.
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 (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 2C resources of 28.9 MMbbl including verification of the tieback scenario given above.
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, and for the transfer of OML 113 to Aje Production AS ("Aje Production"). The ownership of Aje
Production is to be shared between the OML 113 operator, Yinka Folawiyo Petroleum ("YFP") and PetroNor on the basis of a 55 per cent and 45 per cent shareholding respectively, with PetroNor assuming the role of the technical operator.
As previously announced, following completion of the transaction, Panoro's intention is to declare a special dividend and distribute to its shareholders USD 10 million equivalent in PetroNor shares in order for Panoro shareholders to retain a direct listed exposure to Aje / OML 113.
Also in 2019, PetroNor entered into separate agreements with the OML 113 operator 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.
PetroNor and Panoro have also taken the opportunity to review the deferred contingent element of the transaction, reflecting the changed macro-economic background since the original announcement in 2019.
Under the amended terms, once PetroNor recovers all of its costs related to future investments to bring Aje gas into production, the Company is to pay to Panoro an additional consideration USD 0.10 per 1,000 cubic feet, USD 0.05 per 1,000 cubic feet lower than under the original agreement. The additional consideration, initially capped at USD 25 million, is capped at USD 16.67 million under the amended terms.
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.
PetroNor continues work to update the field development plan ("FDP") to expedite gas development and engaged with potential off takers and partners. PetroNor is now engaging with the JV partners in these efforts to progress the venture.
In September 2020, PetroNor E&P Gambia Ltd was awarded a new 30-year lease for the A4 licence. The award was part of a settlement agreement with the government of The Gambia connected to the arbitration of the A1 and A4 licences previously issued in 2006.
The terms of the new licence are based on the newly developed Petroleum, Exploration and Production Licence Agreement (PEPLA). 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. The initial six years exploration period is divided into three periods of two years during which exploration activities are to be completed. 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 government of The Gambia extended the longstop date of the 'farm-out' phase of the A4 licence until 18 October 2022.
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 460Mmbbl Sangomar field, 30 km to the North in Senegal.
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.
In early May 2021, the Company completed the purchase of SPE Guinea Bissau AB from Svenska Petroleum Exploration AB. The licences have been recently extended for three years and are valid until 2 October 2023 maintaining the same attractive fiscal terms.
Svenska Petroleum Exploration AB was in the advanced stages of planning for the drilling of the Atum-1X well to test the Atum prospect prior to delays in gaining partner approvals due to the disputed presidential elections in late 2019 early 2020. Long lead items required for drilling operations have been secured and a number of pre-drill studies completed. Well planning can be recommenced at short notice.
The Atum-1x well will test a highly attractive and material prospect on the Sinapa 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. On 5 April 2021, the Company announced that the arbitration proceedings for the Group's interests in Senegal were to resume despite numerous progressive meetings with the relevant authorities to reach a mutually beneficial solution during the halt in proceedings during 2020 and Q1 2021.
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. Per the detailed disclosure in Note 2 to the consolidated financial statements conditions exist which indicate a material uncertainty that may cast a significant doubt about the entity's ability to continue as a going concern and, therefore, that it may be unable to realise its assets and discharge its liabilities in the normal course of business. This financial report has been prepared on the going concern basis which 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 \$ 21.1 million for the year ended 31 December 2021, with strong production from the Congo assets generating 3,614bopd in first quarter of 2022. As at 31 December 2021 the Group had a cash balance of USD 31.8 million (2020 USD 14.1 million). The Company has entered into a new offtake agreement with a new partner, listed the Company on the main Oslo Børs and continued to host data rooms for potential partners to join the Company on its exploration portfolio, demonstrating that the business has continued to operate effectively, and businesses are willing to engage with the Company.
This has enabled 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 Limited 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 2021.
The consolidated financial statements are presented in US dollars.
Key consolidated income statement figures
For the year ended 31 December
| Amounts in USD million | 2021 | 2020 |
|---|---|---|
| Revenue from sales of petroleum products | 57.6 | 40.6 |
| Assignment of tax oil | 33.1 | 17.1 |
| Assignment of royalties | 15.8 | 9.8 |
| Revenue | 106.5 | 67.5 |
| EBITDA | 61.9 | 34.4 |
| Net profit/(loss) | 11.0 | 11.2 |
| Quantity of oil lifted (barrels) Average selling price (USD per barrel) Quantity of net oil produced after royalty, cost oil and tax oil (barrels) |
831,089 69.31 821,536 |
993,574 40.90 999,522 |
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 34.4 million for the year.
The Group generated a net profit for the year of USD 21.1 million (2020: USD 11.2 million). These figures are due to an improving global market price for oil and to steady production from PNGF Sud
These figures are due to the steady oil production of the PNGF Sud during the quarter and throughout the year that have come about from the workover program. In fact, since the Group first entered the licences in 2016, it has seen a 37 per cent increase in the gross field production and the OPEX reduced by 56 per cent from 25.0 USD/bbl to less than 11 USD/bbl in the same timeframe.
During 2021, there were only 7 liftings of oil, with a 16.4 per cent decrease on the 993,574 barrels lifted in 2020. Increased oil prices during 2021 resulted in the Group achieving higher revenues over lower volumes. The Group achieved an average selling price of USD 69.31/bbl for the year, compared to the 41.0 USD/bbl in 2020. As a consequence, the group reports USD 106.5 million in revenue, a 57.6 per cent increase on 2020 USD 67.5 million.
With the acquisition of the licences interests in Guinea-Bissau and the extension of The Gambia licence, exploration expenses for the year were USD 2.3 million. Under PetroNor's accounting policy, seismic data costs are expensed and not capitalised to intangible assets.
Throughout the year, the Group maintained cost disciplined. The administrative expense in 2021 of USD 13.1 million were higher than in 2020 (USD 12,4 million), however this included third party costs of USD 1.4 million in business development costs (USD 0.7million 2020). This year, the Group incurred non-recurring third-party costs of approximately USD 0.4 million relating to the redomicile project. The Company believes that the redomicile will streamline the Group's corporate structure and reduce corporate overheads. 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.
At 31 December
| Amounts in USD million | 2021 | 2020 |
|---|---|---|
| Current assets | 51.8 | 27.1 |
| Non-current assets | 73.4 | 51.9 |
| Total assets | 125.2 | 79.0 |
| Current liabilities | 39.2 | 26.4 |
| Non-current liabilities | 20.2 | 30.3 |
| Total liabilities | 59.4 | 56.7 |
| Net assets | 65.8 | 22.3 |
| Capital and reserves attributable to owners of the parent | 59.3 | 7.9 |
| Non-controlling interests | 6.5 | 14.4 |
| Total equity | 65.8 | 22.3 |
With the extension of the A4 licence in The Gambia during the year, the Group retained USD 3.5 million of intangible licence costs on the balance sheet. 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 2021. 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.
The level of material inventories has increased to USD 5.7 million in 2021 versus USD 2.9 million last year. This reflects the acquisition of materials with the Guinea-Bissau licence with the venture planning to progress to drilling. The level of materials carried in Congo has also increased by USD 0.9 million due to the infill drilling programme in progress at year-end.
The level of trade receivables is high when compared to the 2020 closing position. This is due to a lifting on the PNFG Sud assets occurring late in the year.
The capital programme on-going at year-end on the Congo assets has led to a high level of trade payables of USD 22.0 million 2021 (USD 5.2 million 2020). The level of liabilities to related parties has been substantially reduced in 2021 with USD 3.4 million at year-end (USD 11.7 million 2020) This is the result of the unwinding for the MGI related party loan.
The Asset Retirement Obligation ("ARO"), a provision of USD 26.8 million cash is presented as a Non-Current Asset in a change to the presentation since 2020. Although in 2019, the contractor group agreed to refund previous surplus cash set aside for the ARO back into the operating cash pool. The current cash projection does not anticipate the same situation in the short term.
On 11 March 2021, PetroNor successfully raised NOK 340 million of new equity through a private placement of 309,090,909 new shares in the Company (PetroNor E&P Limited). The placement generated NOK 187.4 million (USD 22.1 million) in cash and NOK 152.6 million
(USD 18.0 million) as in-kind consideration for contingent acquisition of all of Symero Limited's ("Symero") shares in Hemla Africa Holding AS ("HAH") (the "Symero Transaction"). The private placement was divided into two tranches: Tranche 1 ("Tranche 1") consisting of offer shares worth NOK 92.8 million have been allocated to existing and new investors, including Petromal. The remaining offer shares have been subscribed by and allocated to Symero (for an amount equal to NOK 152.6 million (USD 18 million) ("Tranche 2a") and Petromal (for an amount equal to NOK 94.6 million) in order to retain its ~38.28 per cent ownership ("Tranche 2b").
The net cash proceeds from the private placement are being used to finance drilling of infill wells and other increased oil recovery initiatives on PNGF Sud and general corporate purposes.
During the year, the Company repaid USD 5.8 million of the short-term debt facility of USD 15.0 million from Rasmala (London and Dubai based investor group).
In Q3 2020, the subsidiary company Hemla Africa Holding AS paid a USD 3.9 million dividend to minority interest and related party Symero Ltd ("Symero"). An amount equal to the dividend was immediately loaned to the Company by Symero with interest rates matching those already provided by the external financing from Rasmala, and no security was provided for the loan. The maturity date is matched to the USD 15 million facility from Rasmala. The Group exits the year with a reduction in the level of debt on the balance sheet of USD 5.8 million.
These debts mature towards the end of 2022 and are accordingly classified as current liabilities.
Net cash flow generated from the funding activities described in the preceding paragraph generated USD 20.4 million.
The adjusted net cash flows from operations were USD 23.4 million (2020 negative USD 2.9 million)
Investing activities consumed USD 20.6 million (2020 USD 7.6 million) with incremental contributions to the ARO being USD 5.6 million (2020 6.6 million)
The Group exits the accounting period with a cash balance of USD 31.8 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 six thousand to be transferred from other equity. The company was incorporated on 1 October 2021 and so has had limited activity over the period. The company's financial activities were purely corporate. Going forward, it corporate costs related to the remuneration for the board and legal and professional services will incur.
During the year, no dividend was paid or recommended.
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 (i) effective legal redress in the courts of such jurisdictions, whether in respect of a breach of law or regulation, or in an ownership dispute, being more difficult to obtain; (ii) a higher degree of discretion on the part of governmental authorities; (iii) the lack of judicial or administrative guidance on interpreting applicable rules and regulations; (iv) inconsistencies or conflicts between and within various laws, regulations, decrees, orders and resolutions; or (v) relative inexperience of the judiciary and courts in such matters. 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 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 and Guinea-Bissau. In addition, the Group has entered into a definitive agreement to acquire assets in Nigeria (which is subject to completion). 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 Aje Transaction, if completed, will add a producing asset in Nigeria. Under any circumstance, 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, including but not limited to risks relating to:
capacity constraints and cost inflation in the service sector and lack of availability of required services and equipment;
legal disputes and legal proceedings the Group may be involved in in order to defend or enforce any of its rights or obligations under its licences, agreements or otherwise, which may be costly and time consuming;
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 growing 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 2021, the Company's share capital consisted of 1,326,991,006 ordinary shares, with 99.7 per cent of the Company's ordinary shares admitted for trading on Oslo Euronext Expand (Norway). 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 VPS and have ISIN NO 001 1157232.
At 26 April 2022, the Company had 4,032 shareholders and 1,326,991,006 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 | 36.28% |
| 2 | Symero Ltd | 138,763,636 | 10.46% |
| 3 | NOR Energy AS 2 | 135,070,623 | 10.18% |
| 4 | Ambolt Invest AS | 87,583,283 | 6.60% |
| 5 | Gulshagen III AS 3 | 45,000,000 | 3.39% |
| 6 | Gulshagen IV AS 3 | 45,000,000 | 3.39% |
| 7 | Energie AS | 27,000,650 | 2.03% |
| 8 | Nordnet Livsforsikring AS | 22,760,494 | 1.72% |
| 9 | Enga Invest AS | 15,772,775 | 1.19% |
| 10 | Nordnet Bank AB | 15,027,953 | 1.13% |
| 11 | ENG Group Soparfi S.A. | 10,000,000 | 0.75% |
| 12 | Pust For Livet AS | 8,697,609 | 0.66% |
| 13 | Omar Al-Qattan | 7,645,454 | 0.58% |
| 14 | Leena Al-Qattan | 7,645,454 | 0.58% |
| 15 | UBS Switzerland AG | 6,462,993 | 0.49% |
| 16 | Danske Bank A/S | 5,974,026 | 0.45% |
| 17 | Sandberg JH AS | 5,653,951 | 0.43% |
| 18 | Avanza Bank AB | 3,960,244 | 0.30% |
| 19 | Geir Håkon Dahle | 3,803,877 | 0.29% |
| 20 | Knutshaug Invest AS | 3,386,161 | 0.26% |
| Subtotal | 1,076,862,113 | 81.15% | |
| Others | 250,128,793 | 18.85% | |
| Total | 1,326,991,006 | 100.00% | |
1 Non-Executive Chair, Mr. Alhomouz is the CEO of Petromal LLC.
2 NOR Energy AS is a company controlled jointly by Mr. Søvold and Mr. Ludvigsen through indirect beneficial interests.
3 Gulshagan III AS and Gulshagan IV AS are companies controlled by Mr. Søvold through an indirect beneficial interest.
At the date of the publishing of this report there are 1,176,070 unissued ordinary shares with an exercise price of NOK 7.75 each and an expiry date of 31 May 2022.
In the current year, no ordinary shares were issued on the exercise of options (2020: nil).
No other current directors hold shares or options.
On 31 January 2021, NOR Energy AS held 233,555,857 shares when Mr Ludvigsen resigned as a Director. Furthermore, Mr Ludvigsen held 45,000,000 shares through an indirect beneficial interest in Nedi Hagan AS. In addition, 15,000,000 shares were held by Pust For Livet AS, a company controlled by immediate family of Mr Ludvigsen.
On 16 December 2021, NOR Energy AS held 139,555,857 shares and Symero Ltd held 138,763,636 shares when Mr Søvold was replaced as CEO. Furthermore, Mr Søvold held 90,000,000 shares through an indirect beneficial interest in Gulshagen III AS and Gulshagen IV AS.
The number of directors' meetings (including committees) of PetroNor E&P Limited, held during the period where each director held office during the financial year and the number of meetings attended by each director is as follows:
| Audit Committee Meetings | Directors' Meetings | |||
|---|---|---|---|---|
| Eligible to attend | Attended | Eligible to attend | Attended | |
| Current | ||||
| E Alhomouz | - | - | 8 | 8 |
| J Pace | 1 | 1 | 8 | 8 |
| J Iskander | 1 | - | 8 | 3 |
| A Neuling | 1 | 1 | 8 | 8 |
| R Steinepreis | - | - | 8 | 8 |
| I Smines Tybring-Gjedde | - | - | 8 | 7 |
| G Kielland | - | - | 8 | 8 |
In addition to meetings of directors held during the year, due to the number and diversified location of the directors, a number of matters are authorised by the board of directors via circulating resolutions. During the current year, 17 circulating resolutions were authorised by the board of directors. There were no Remuneration Committee or Continuous Disclosure Committee meetings during the year,
as any relevant matters were discussed during the Directors' Meetings.
The number of directors' meetings of PetroNor E&P ASA held during the period where each director held office during the financial year and the number of meetings attended by each director was as follows:
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 23.
Good corporate governance provides the foundation for long-term value creation, to the benefit of shareholders, employees and other stakeholders. The board of directors of PetroNor has established a set of governance principles in order to ensure a clear division of roles between the board of directors, 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 website. The annual statement on corporate governance for 2021 has been approved by the board and can be found on page 30 in this annual report.
The Group made no investments in research and development in 2020 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-for-land rapportering".
In 2021, 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 land-for-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 | 15,760 | 33,102 | 1,227 | 50,089 |
| Total Congo | 15,760 | 33,102 | 1,227 | 50,089 |
| A4 | Nil | Nil | 500 | 500 |
| Total The Gambia | Nil | Nil | 521 | 500 |
| Sinapa | Nil | Nil | 299 | 299 |
| Esperanca | Nil | Nil | 291 | 291 |
| Total Guinea-Bissau | Nil | Nil | 590 | 590 |
As the Company is waiting for Government approval of the Aje transaction, no payments were made in relation to this project during 2021.
Due to the arbitration status of the ROP and SOSP licences in Senegal, no payments were made in relation to these projects during 2021.
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.
| Main country of | Interest paid or payable | ||
|---|---|---|---|
| In USD thousand | operations | EEs 1) | to a group entity |
| Australia | |||
| PetroNor E&P Ltd | United Kingdom | 2 | - |
| Cyprus | |||
| PetroNor E&P Ltd | Cyprus | 1 | 1,563 |
| Norway | |||
| PetroNor E&P ASA | Norway | - | - |
| PetroNor E&P AS | Norway | 3 | - |
| Hemla Africa Holding AS | Norway | - | - |
| Republic of Congo | |||
| Hemla E&P Congo SA | Republic of Congo | 3 | 1,182 |
| United Kingdom | |||
| PetroNor E&P Services Ltd | United Kingdom | 4 | - |
| Nigeria | |||
| PetroNor E&P Ltd | Nigeria | 4 | - |
| 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 | - |
1) Average number of employees' during the year
Just before the year-end, 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.
On 23 February 2022: PetroNor E&P ASA announced that at an extraordinary general meeting of the Company, the PetroNor E&P ASA had issued 1,326,991.006 ordinary shares as part of the implementation of the Scheme of Arrangement and listing of its shares on the Oslo Stock Exchange main list. PetroNor E&P ASA's issued capital is 1,326,991,006 shares. On 25 February 2022, PetroNor E&P ASA announced that the Financial Supervisory Authority of Norway (Nw. Finanstilsynet) had approved a prospectus prepared by the Company for listing of all its outstanding shares on Oslo Stock Exchange. On 28 February 2022 PetroNor E&P ASA's shares were listed and began trading on Oslo Stock Exchange.
In January 2022, PetroNor received the consent from the Nigeria Upstream Petroleum Regulatory Commission (formerly the Nigerian Department of Petroleum Resources) for the transactions signed in 2019. Through the two transactions signed in 2019, the Company acquired a 13.1 per cent economic interest in the Aje Field through two transactions with Panoro and YFP. This consent has allowed PetroNor to reengage financial and industrial partners with a target to mature the project towards an FID. It is expected that this will complete in April 2022.
A CPR update prepared by AGR Petroleum Services AS on the Company's PNGF Sud asset in Congo was released on 6 April 2022. The update represented an increase of approximately 2 per cent and 4 per cent for 2P and 2C respectively on a gross basis.
On 11 April 2022 PetroNor announced that they had signed a pre-payment sales agreement with ADNOC Trading during the quarter and has invoiced against entitlement production. Furthermore, PetroNor announced that it had received a notification from Økokrim that the Company's Chairman of the Board, Mr. Eyas Alhomouz (US citizen), had been made subject to the ongoing investigations carried out by Økokrim and been given the status as suspect, and that the U.S. Department of Justice had opened a separate investigation into these allegations, based on information from Økokrim.
At the beginning of 2022, Russia's invasion of Ukraine deepened the energy crisis and led to an immediate effect in increasing oil and gas prices. Economic sanctions towards Russia and the economic uncertainty may have an impact on our business and our markets going forward.
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 gains momentum, the Company looks forward to seeing the 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 recent hearing in Paris for the arbitration matter associated with the Senegalese licences, a decision is expected from the Tribunal in the later half of the year. Unless the matter is resolved by the parties independently of ICSID before then.
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 2021 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, 29 April 2022 The board of directors and CEO – PetroNor ASA
Eyas Alhomouz Gro Kielland Joseph Iskander Ingvil Smines Tybring-Gjedde Chair Director Director Director Interim CEO
Jens Pace
| Consolidated statement of comprehensive income 64 | ||
|---|---|---|
| Consolidated statement of financial position 65 | ||
| Consolidated statement of changes in equity 66 | ||
| Consolidated statement of cash flows67 | ||
| Notes to the consolidated financial statements 68 | ||
| Note 01 | Corporate information68 | |
| Note 02 | Basis of preparation68 | |
| Note 03 | Significant accounting judgements, estimates and assumptions 69 | |
| Note 04 | Revenue 70 | |
| Note 05 | Cost of sales70 | |
| Note 06 | Other operating income70 | |
| Note 07 | Exploration expenses 70 | |
| Note 08 | Administrative expenses71 | |
| Note 09 | Finance expense 72 | |
| Note 10 | Tax expense 72 | |
| Note 11 | Earnings per share72 | |
| Note 12 | Inventories 73 | |
| Note 13 | Trade and other receivables 73 | |
| Note 14 | Cash and cash equivalents74 | |
| Note 15 | Segment information74 | |
| Note 16 | Property, plant, and equipment74 | |
| Note 17 | Intangible assets75 | |
| Note 18 | Leases 76 | |
| Note 19 | Trade and other payables76 | |
| Note 20 | Loans and borrowings 77 | |
| Note 21 | Provisions77 | |
| Note 22 | Share capital78 | |
| Note 23 | Reserves 79 | |
| Note 24 | Related party transactions 80 | |
| Note 25 | Acquisition of subsidiaries 85 | |
| Note 26 | Risk management86 | |
| Note 27 | Financial instruments – Fair values 89 | |
| Note 28 | Commitments and contingencies89 | |
| Note 29 | Events subsequent to reporting date 89 | |
| Note 30 | Summary of accounting policies90 |
| Company statement of comprehensive income – Petronor E&P ASA 100 | ||
|---|---|---|
| Company statement of financial position – PetroNor E&P ASA 101 | ||
| Company statement of changes in equity – PetroNor E&P ASA101 | ||
| Company statement of cash flow – PetroNor E&P ASA 102 | ||
| Notes to the financial statements – PetroNor E&P ASA 103 | ||
| Note 01 | Corporate information103 | |
| Note 02 | Basis of preparation103 | |
| Note 03 | Employee benefit expenses103 | |
| Note 04 | Auditors' remuneration104 | |
| Note 05 | Cash and cash equivalents 104 | |
| Note 06 | Equity 104 | |
| Note 07 | Risk management104 | |
| Note 08 | Financial instruments – Fair values 105 | |
| Note 09 | Commitments and contingencies105 | |
| Note 10 | Group arrangements and redomicile process 105 | |
| Note 11 | Summary of significant accounting policies 109 | |
| Note 12 | Financial instruments 109 | |
| Note 13 | Events after the reporting period110 | |
| Statement of Directors' responsibility111 | |
|---|---|
| Auditor's report111 | |
| Glossary and definitions114 | |
| Corporate directory115 |
Following the completion of a scheme of arrangement on 24 February 2022, PetroNor E&P ASA replaced PetroNor E&P Ltd as the parent company of the Group. This arrangement will be treated as a continuation of the original Group for accounting purposes. PetroNor E&P ASA have chosen to voluntarily include in their annual report the Consolidated Financial Statements, for the year ended 31 December 2021, of PetroNor E&P Limited for completeness of information.
For the year ended 31 December
| Amounts in USD thousand | Note | 2021 | 2020 |
|---|---|---|---|
| Revenue | 4 | 106,463 | 67,543 |
| Cost of sales | 5 | (34,585) | (25,885) |
| Gross profit | 71,878 | 41,658 | |
| Other operating income | 6 | 866 | 45 |
| Exploration expense | 7 | (2,270) | - |
| Administrative expenses | 8 | (13,131) | (12,376) |
| Profit from operations | 57,343 | 29,327 | |
| Finance expense | 9 | (3,041) | (2,606) |
| Foreign exchange gain/(loss) | (56) | 1,507 | |
| Profit before tax | 54,246 | 28,228 | |
| Tax expense | 10 | (33,102) | (17,078) |
| Profit/(loss) for the year | 21,144 | 11,150 | |
| Other Comprehensive income: Exchange losses arising on translation of foreign operations |
(364) | (1,050) | |
| Total comprehensive income/(loss) | 20,780 | 10,100 | |
| Profit/(Loss) for the year attributable to: | |||
| Owners of the parent | 12,314 | 2,373 | |
| Non-controlling interest | 8,830 | 8,777 | |
| Total | 21,144 | 11,150 | |
| Total comprehensive income/(loss) attributable to: | |||
| Owners of the parent | 12,208 | 1,417 | |
| Non-controlling interest | 8,572 | 8,683 | |
| Total | 20,780 | 10,100 | |
| Earnings per share attributable to members: Basic profit/(loss) per share (USD cents) |
11 | 1.06 | 0.24 |
| Diluted profit/(loss) per share (USD cents) | 11 | 1.06 | 0.24 |
The accompanying notes form part of these consolidated financial statements.
At 31 December
| Amounts in USD thousand | Note | 2021 | 2020 |
|---|---|---|---|
| ASSETS | |||
| Current assets | |||
| Inventories | 12 | 6,227 | 3,578 |
| Trade and other receivables | 13 | 13,820 | 9,397 |
| Cash and cash equivalents | 14 | 31,755 | 14,113 |
| Total | 51,802 | 27,088 | |
| Non-current assets | |||
| Property, plant and equipment | 16 | 39,397 | 23,483 |
| Intangible assets | 17 | 7,172 | 6,935 |
| Right-of-use assets | 18 | 44 | 212 |
| Other receivables | 12 | 26,837 | 21,260 |
| Total | 73,450 | 51,890 | |
| Total assets | 125,252 | 78,978 | |
| LIABILITIES | |||
| Current liabilities | |||
| Trade and other payables | 19 | 29,996 | 22,238 |
| Lease liability | 18 | 58 | 170 |
| Loans and borrowings | 20 | 13,079 | 4,000 |
| Total | 43,133 | 26,408 | |
| Non-current liabilities | |||
| Loans and borrowings | 20 | - | 14,912 |
| Lease liability | 18 | - | 55 |
| Provisions | 21 | 16,302 | 15,307 |
| Total | 16,302 | 30,274 | |
| Total liabilities | 59,435 | 56,682 | |
| NET ASSETS | 65,817 | 22,296 | |
| Issued capital and reserves attributable to owners of the parent | |||
| Share capital | 22 | 62,115 | 17,735 |
| Reserves | 23 | (1,421) | (956) |
| Retained earnings | 23 | (1,390) | (8,853) |
| Total | 59,304 | 7,926 | |
| Non-controlling interests | 24a | 6,513 | 14,370 |
| TOTAL EQUITY | 65,817 | 22,296 | |
The accompanying notes form part of these consolidated financial statements.
The consolidated financial statements were approved and authorised for issue by the Board of Directors on 29 April 2022.
| Foreign | ||||||
|---|---|---|---|---|---|---|
| currency | Non | |||||
| Share | translation | Retained | controlling | |||
| Amounts in USD thousand | Note | capital | reserve | earnings | interest | Total |
| For the year ended 31 December 2021 | ||||||
| Balance at 1 January 2021 | 17,735 | (956) | (8,853) | 14,370 | 22,296 | |
| Profit 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 | 22 | 45,943 | - | - | - | 45,943 |
| Share issue costs | 22 | (1,563) | - | - | - | (1,563) |
| Acquisition of equity interest from NCI | - | (359) | (4,851) | (16,429) | (21,639) | |
| Balance at 31 December 2021 | 62,115 | (1,421) | (1,390) | 6,513 | 65,817 | |
| For the year ended 31 December 2020 | ||||||
| Balance at 1 January 2020 | 17,735 | - | (11,226) | 14,749 | 21,258 | |
| Profit/(loss) for the year | - | - | 2,373 | 8,777 | 11,150 | |
| Other comprehensive income | - | (956) | - | (94) | (1,050) | |
| Total comprehensive loss for the year | - | (956) | 2,373 | 8,683 | 10,100 | |
| Transactions with owners in their capacity as | ||||||
| owners: | ||||||
| Issue of capital | 22 | - | - | - | - | - |
| Dividends paid during the year | 23, 24a | - | - | - | (9,062) | (9,062) |
| Balance at 31 December 2020 | 17,735 | (956) | (8,853) | 14,370 | 22,296 | |
The accompanying notes form part of these consolidated financial statements.
For the year ended 31 December
| Amounts in USD thousand | Note | 2021 | 2020 |
|---|---|---|---|
| Cash flows from operating activities | |||
| Profit for the year | 54,246 | 28,228 | |
| Adjustments for: | |||
| Depreciation and amortisation | 4,422 | 4,475 | |
| Amortization of right-of-use asset | 168 | 169 | |
| Unwinding of discount on decommissioning liability | 995 | 934 | |
| Net foreign exchange differences | (364) | (1,050) | |
| Total | 59,467 | 32,756 | |
| (Increse)/Decrease in trade and other receivables | (8,062) | 729 | |
| Increase in advance against decommissioning cost | 13 | (5,577) | (6,614) |
| Increase in inventories | 12 | (2,649) | (345) |
| (Decrease)/increase in trade and other payables | 7,758 | (12,363) | |
| Cash (used in)/generated from operations | 50,937 | (18,593) | |
| Income taxes paid | 10 | (33,102) | (17,078) |
| Net cash flows from operating activities | 17,835 | (2,915) | |
| Investing activities Purchases of property, plant and equipment |
16 | (19,759) | (4,615) |
| Purchases of intangible assets | 17 | (814) | (3,007) |
| Net cash flows from investing activities | (20,573) | (7,622) | |
| Financing activities | |||
| Issue of ordinary shares Proceeds from loans and borrowings |
22 20 |
27,943 (1,563) |
- 18,912 |
| Repayment of loans and borrowings | 20 | (5,833) | (12,941) |
| Repayment of principal portion of lease liability | 18 | (159) | (131) |
| Repayment of interest portion of lease liability | 18 | (8) | (19) |
| Dividends paid to non-controlling interest | - | (9,062) | |
| Net cash (used in)/from financing activities | 20,380 | (3,241) | |
| Net increase/(decrease) in cash and cash equivalents | 17,642 | (13,778) | |
| Cash and cash equivalents at beginning of year | 14,113 | 27,891 | |
| Cash and cash equivalents at end of year | 14 | 31,755 | 14,113 |
The accompanying notes form part of these consolidated financial statements.
The consolidated financial statements of PetroNor E&P Limited and its subsidiaries (together the "Group") for the year ended 31 December 2021 was authorised for issue in accordance with a resolution of the Directors on 29 April 2022.
PetroNor E&P Limited is a 'for profit entity' and is a company limited by shares incorporated in Australia. During 2021 its shares were publicly traded on the Oslo Euronext Expand under ticker PNOR, a regulated marketplace of the Oslo Stock Exchange, Norway, and subsequently delisted on 24 February 2022. On 28 February 2022, under a scheme of arrangement,
PetroNor E&P ASA replaced PetroNor E&P Ltd as the top company of the Group. As at the date of this report PetroNor E&P ASA is now the ultimate parent entity for the Group. The consolidated financial statements of PetroNor E&P ASA will be accounted as a continuity of the Group. The consolidated financial statements of PetroNor E&P Limited have been prepared for inclusion in the annual report of PetroNor E&P ASA. The shares of PetroNor E&P ASA are now traded on the main list of Oslo Stock Exchange, which is the main regulated marketplace in Norway. The principal activities of the Group are the exploration and production of crude oil.
Petronor E&P Limited's consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) which have been adopted by the EU. The consolidated financial statements have been prepared on a historical cost basis, and on the basis of uniform accounting principles for similar transactions and events under otherwise similar circumstances. The accounts of PetroNor E&P Limited were historically prepared in accordance with the requirements of the Australian Corporations Act of 2001, Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board, which also complies with International Financial Reporting Standards (IFRS). There is no requirement for comparative restatement. It is important to note that In the previous year the consolidated financial statements complied with IFRS as issued by the International Accounting Standards Board.
The consolidated financial statements are presented in United States Dollars, which is also the functional currency for the Company and all material subsidiaries, and all values are rounded to the thousand dollars unless otherwise stated.
The consolidated financial statements have been prepared on a going concern basis. Under the going concern assumption, an entity is ordinarily viewed as continuing in business for the foreseeable future. The Group recognises that in order to fund on-going operations and pursue organic and inorganic growth opportunities it will need additional funding. This funding may be sourced through joint venture equity or share issues or through debt finance.
As at the signing date of this report, the pooling agreement between two third parties necessary to enable the new offtaker to lift first quarter 2022 oil production is believed to be close to completion. The Group is currently advancing potential contingency arrangements to improve working capital should further significant delays to completion of the pooling agreement and lifting schedule eventuate. As at the date of this report it is not yet clear whether any such arrangement
will be necessary and no new binding arrangements have been entered into. Global macroeconomic factors are considered to be strongly in the Company's favour at present with high demand leading to high oil prices, and the Board is confident a solution to any short-term working capital requirements will be implementable as necessary.
There are outstanding amounts due to related party shareholders Petromal and NOR Energy for the remaining cash consideration of the 2019 reverse takeover transaction of USD 1.3 million and USD 2.1 million respectively. Plus, the Group has a USD 3.9 million debt facility with related party shareholder Symero that is due to be repaid in November 2022, and a USD 5.6 million debt facility with Rasmala that will be repaid in equal instalments up to November 2022 (Note 20). In addition the Group has material potential capital commitments associated with its exploration portfolio as detailed in Note 28 Settlement of the borrowings detailed above would leave the Group debt free . However, the Group plans to refinance and consolidate its various debt positions before the year-end, to provide additional working capital and strengthen its balance sheet. While it is acknowledged that the recent Økokrim investigation as detailed in Note 28 Commitments and Contingencies may complicate refinancing initiatives and extend timetables , the Board is confident that refinancing measures will be able to be completed as necessary.
These conditions indicate a material uncertainty that may cause significant doubt about the entity's ability to continue as a going concern and, therefore, that it may be unable to realise its assets and discharge its liabilities in the normal course of business. These consolidated financial statements have been prepared on the going concern basis which assumes the continuity of normal business activity, 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 21.1 million for the year ended 31 December 2021, with strong production from the Congo assets generating 3,614 bopd in the first quarter of 2022. At 31 December 2021,
the Group had a cash balance of US 31.8 million. The Company has entered into a new offtake agreement with a new partner, listed the Company on the main of Oslo Stock Exchange, continued to host data rooms for potential partners to join the Company on its exploration portfolio, demonstrating that the business has continued to operate effectively, and that businesses are willing to engage with the Company.
This has enabled 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 Directors evaluate estimates and judgements incorporated in the consolidated financial statements based on historical knowledge and 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.
The 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 periods.
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 70/bbl. The carrying amount of oil and gas properties and licences at 31 December 2021 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 30M.
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. All hydrocarbon related activities are related to investments in jointly controlled arrangements. Even if the investments are not jointly controlled they are accounted for in the same way. Please see detailed disclosure in Note 30 describing the treatment of joint operations.
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Revenue from contracts from customers | ||
| Revenue from sales of petroleum products1 | 57,601 | 40,635 |
| Other Revenue | ||
| Assignment of tax oil | 33,102 | 17,078 |
| Assignment of royalties | 15,760 | 9,830 |
| Total Revenue | 106,463 | 67,543 |
| Quantity of oil lifted (barrels) | 831,089 | 993,574 |
| Average selling price (USD per barrel) | 69.31 | 40.90 |
| Quantity of net oil produced after royalty, cost oil and tax oil (barrels) | 821,536 | 999,522 |
1 All revenue from the sales of petroleum products in 2021 is generated from a single customer and 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.
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Operating expenses | 4,385 | 11,357 |
| Royalty | 15,760 | 9,830 |
| Depreciation and amortisation of oil and gas properties | 14,302 | 4,429 |
| Closing oil inventory | 137 | 269 |
| Total | 34,585 | 25,885 |
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Other | 865 | 45 |
| Total | 865 | 45 |
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Seismic data acquisition | 2,270 | - |
| Total | 2,270 | - |
| Amounts in USD thousand | Note | 2021 | 2020 |
|---|---|---|---|
| Employee benefit expenses | 8A | 5,435 | 5,108 |
| Termination benefits | - | 795 | |
| Legal and professional expenses | 3,106 | 3,121 | |
| Corporate social responsibility | 1,500 | 900 | |
| Provision for diversified investment | 1,051 | 662 | |
| Travelling expenses | 218 | 282 | |
| Office rent | 36 | 87 | |
| Depreciation and amortisation | 36 | 46 | |
| Amortisation on right-of-use assets | 168 | 169 | |
| Other expenses | 1,581 | 1,206 | |
| Total | 13,131 | 12,376 |
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Salaries | 4,792 | 4,486 |
| Short-term non-monetary benefits | 304 | 319 |
| Defined contribution pension cost | 41 | 104 |
| Social-security contributions and similar taxes | 297 | 199 |
| Total | 5,434 | 5,108 |
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 to an
externally 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.
The average number of employee man-years for the year is nineteen.
| Amounts in USD thousand 2021 |
2020 |
|---|---|
| Paid or payable to BDO | |
| Audit review of financial reports | |
| BDO Audit (WA) Pty Ltd 40 |
90 |
| BDO Network firms 90 |
76 |
| Total 130 |
166 |
| Other non-assurance services | |
| BDO related practices 12 |
40 |
| Total 12 |
206 |
| Paid or payable to other audit firms | |
| Audit or review of financial reports 138 |
40 |
| Other non-assurance services 141 |
120 |
| Total 279 |
160 |
Fees, excluding VAT, to the auditors are included in administration expenses.
| Amounts in USD thousand | Note | 2021 | 2020 |
|---|---|---|---|
| Unwinding of discount on decommissioning liability | 21 | 995 | 934 |
| Loan structuring fee | - | 150 | |
| Finance cost on lease liabilities | 17 | 8 | 19 |
| Interest on loan | 19 | 2,038 | 1,493 |
| Other interest | - | 10 | |
| Total | 3,041 | 2,606 |
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Petroleum revenue tax expense | ||
| Current income tax charge | 33,102 | 17,078 |
| Total tax expense reported in the consolidated statement of comprehensive income | 33,102 | 17,078 |
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 position in both 2021 and 2020. Average effective tax rate for the year was 31 per cent (2020: 25 per cent) based on gross revenue of the Group.
Deferred tax assets have not been brought to account in respect of tax losses and unrecognised capital allowances because at 31 December 2021, it was uncertain when future taxable amounts would be available to utilise those temporary differences and losses. At 31 December 2021, the carried forward gross tax loss is USD 116 million (2020: USD 110 million).
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Profit / (loss) attributable to ordinary shareholders | ||
| Profit / (loss) from continuing operations attributable to the ordinary equity holders used in calculating basic / diluted profit per share |
12,314 | 2,373 |
| Profit / (loss) attributable to the ordinary equity holders used in calculating basic / diluted profit per share |
12,314 | 2,373 |
| Weighted average number of ordinary shares outstanding during the period used in the calculation of profit / (loss) per share |
||
| Basic | 1,161,827,723 | 971,665,288 |
| Diluted | 1,160,438,253 | 974,229,968 |
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 1,389,470 options at 31 December 2021 (2020: 1,389,470).
The implementation of the redomicile scheme of arrangement whereby PetroNor E&P ASA became the parent entity for the Group resulted in a one for one share swap, accordingly, this change does not affect the earnings per share calculation.
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Crude oil inventory | 554 | 689 |
| Materials and supplies Total |
5,673 6,227 |
2,889 3,578 |
Crude oil inventory is valued at cost of USD 22.84 per bbl (2020: USD 17.79 bbl).
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.
| Amounts in USD thousand | Note | 2021 | 2020 |
|---|---|---|---|
| Recoverability less than one year | |||
| Trade receivables | 13,431 | 5,408 | |
| Due from related parties | 24d | - | 3,639 |
| Other receivables | 389 | 350 | |
| Total | 13,820 | 9,397 | |
| Recoverability more than one year | |||
| Advance against decommissioning cost 1 | 26,837 | 21,260 | |
| Total | 26,837 | 21,260 |
1 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 3.68 per barrel produced (2020: USD 3.70 per barrel). Although the JV partnership in 2019 agreed to refund previous surplus cash set aside for the decommissioning cost back into the operating cash pool, the current cash projection does not anticipate the same situation in the next 12 months. Refer to Note 21 for further details on the decommissioning liability.
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 and amounts due from related parties 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 debtor's 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. The trade receivables of USD 13.4 million is due from one customer only which is not past due yet. The Group considered whether there had been a significant increase in credit risk on its trade receivables and amounts due from related parties and estimates that no ECL is required as at 31 December 2021.
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Cash in bank | 31,755 | 14,113 |
| Total | 31,755 | 14,113 |
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 the 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 | 2021 | 2020 |
|---|---|---|
| Congo | 69,564 | 48,677 |
| Gambia | 3,507 | 3,007 |
| Nigeria | 3 | 1 |
| Norway | 62 | 205 |
| Senegal | - | - |
| Guinea-Bissau | 314 | - |
| Total | 73,450 | 51,890 |
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Production assets and equipment | ||
| Cost | ||
| At 1 January | 33,445 | 28,830 |
| Additions | 19,759 | 4,615 |
| Disposals | - | - |
| At 31 December | 53,204 | 33,445 |
| Depreciation | ||
| At 1 January | 9,962 | 6,243 |
| Charge for the year | 3,845 | 3,719 |
| Depreciation on disposals | - | - |
| At 31 December | 13,807 | 9,962 |
| Net carrying amount | ||
| At 31 December | 39,397 | 23,483 |
| Production assets and equipment cost includes the following: | ||
| Decommissioning costs | 11,899 | 11,899 |
| Oil & gas CAPEX | 41,305 | 21,546 |
| Total | 53,204 | 33,445 |
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Cost | ||
| At 1 January | 10,396 | 7,389 |
| Addition | 814 | 3,007 |
| At 31 December | 11,210 | 10,396 |
| Accumulated amortisation and impairment | ||
| At 1 January | 3,461 | 2,698 |
| Amortisation | 577 | 763 |
| Impairment | - | - |
| At 31 December | 4,038 | 3,461 |
| Net carrying value | ||
| At 1 January | 6,935 | 4,691 |
| At 31 December | 7,172 | 6,935 |
In 2017, subsidiary company Hemla E&P Congo SA acquired interest 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 extension for 5 years. All these three licences are collectively called "PNGF Sud" and cover an area of 482.28km2. The operator of the licences is Perenco, and the carrying value at 31 December 2021 was USD 3.3 million.
There were no indicators of impairment identified under IAS 36 and IAS 38 at 31 December 2021 for the licence cost and property plant and equipment.
In September 2020, under the terms of the settlement agreement, a new A4 licence was awarded . The A4 licence area is of 1,376km2 and is operated by Company subsidiary PetroNor E&P Gambia Ltd. At 31 December 2021, the carrying value of the A4 licence was USD 3.5 million. In 2021, the Government of The Gambia extended the 'farm-out' phase of the A4 licence until 18 October 2022. Continuation past this date requires a firm well commitment and bonus payment.
There were no indicators of impairment identified under IAS 38 at 31 December 2021 for the licence cost.
78.57 per cent interest of the Sinapa and Esperança licences are held by the Group through the purchase of SPE Guinea Bissau AB from Svenska Petroleum Exploration AB on 4 May 2021. The licences are operated by PetroNor, and the remaining equity is held by FAR Ltd
At the signing date of this report, the Company's subsidiary African Petroleum Senegal Limited had registered a request for arbitration proceedings with the International Centre for the Settlement of Investment Disputes (ICSID) to protect its 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 15,796 km2 and due to the arbitration process they have nil carrying value in the financial statements at 31 December 2021.
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. The Group uses the services of AGR Petroleum Services AS for third party verifications of its 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 | 14.3 | 20.6 | 26.6 |
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.
3P) Proved plus Probable plus 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 2021 | 212 | 225 |
| Additions | - | - |
| Amortization expense | (168) | - |
| Interest expense | - | 8 |
| Payments made | - | (175) |
| At 31 December 2021 | 44 | 58 |
| Ageing of lease liabilities Current Non-current |
58 - |
| Amounts in USD thousand | 31 December 2021 |
|---|---|
| Amortization expense on right-of-use assets | 168 |
| Interest expense on lease liabilities Expense relating to short-term lease |
8 - |
| Total | 176 |
The total cash outflow for leases amount to USD 175,000 for the year.
| Amounts in USD thousand | Note | 2021 | 2020 |
|---|---|---|---|
| Trade payables | 22,014 | 5,226 | |
| Due to related parties | 24D | 3,449 | 11,694 |
| Taxes and state payables | 120 | 348 | |
| Other payables and accrued liabilities | 4,472 | 4,970 | |
| Total | 30,055 | 22,238 |
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| At 1 January | 18,912 | 12,941 |
| Received | - | 18,912 |
| Principal repayment | (5,833) | (12,941) |
| Interest on loan accrued | 1,539 | 1,493 |
| Interest on loan paid | (1,539) | (1,493) |
| At 31 December | 13,079 | 18,912 |
| Ageing of loans payable Current Non-current |
13,079 - |
4,000 14,912 |
| Total | 13,079 | 18,912 |
In 2020, the short-term debt facility of USD 12.9 million from Rasmala (London and Dubai based investor group) was replaced with a USD 15 million facility with 12 months grace period and final maturity date in November 2022. The loan is repaid in monthly instalments after the initial grace period and carries an interest rate of 9 per cent plus one-month LIBOR payable monthly if the oil price is below USD 40 per bbl and 12.5 per cent if the oil price is above \$40 per bbl. The loan is secured against:
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 PetroNor E&P Limited by Symero Ltd with interest rates matching those already provided by external
financing and no security was provided for the loan. The maturity date is matched to the USD 15 million facility from Rasmala.
The Rasmala loan has the following covenants and undertakings:
All covenants were complied with and there were no breaches during the year for both loans payable to Rasmala and Symero.
In accordance with the agreements and legislation, the wellheads, production assets, pipelines and other installations may have to be dismantled and removed from oil and natural gas fields when the production ceases. The exact timing of the obligations is uncertain and depends on the rate with which the reserves of the field are depleted. However, 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 (2020: 6.0 per cent) and an inflation rate of 1.6 per cent (2020: 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 2021 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.
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 | 2021 | 2020 |
|---|---|---|---|
| At 1 January Arising during the year |
15,307 - |
14,373 - |
|
| Unwinding of discount on decommissioning | 9 | 995 | 934 |
| At 31 December | 16,302 | 15,307 |
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 | 2021 | 2020 |
|---|---|---|
| Balance at the beginning of the year Issue of shares |
971,665,288 355,325,718 |
971,665,288 - |
| Balance at end of the year | 1,326,991,006 | - |
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Balance at beginning of the year Issue of shares Share issue costs |
17,735 45,943 (1,563) |
17,735 - - |
| Share capital at end of the year | 62,115 | 17,735 |
In March 2021, the PetroNor E&P Ltd completed a Private Placement divided into two tranches. For Tranche 1, 84,363,636 ordinary shares were issued for no par value and a subscription price of NOK 1.10 to existing and new investors.
For Tranche 2a and 2b 224,727,273 new ordinary shares have been issued in Q3 2021. A further 46,234,809 new ordinary shares for no par value and a subscription price of NOK 1.10 were issued pursuant to the subsequent offering in September 2021. Following the subsequent offering, PetroNor had an issued and outstanding share capital of 1,326,991,006 shares of no par value
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. The Group has no externally imposed capital requirements.
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 PetroNor E&P Limited.
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. Ten year Australian government bond rates were used as an equivalent to risk free rate and the expected volatility was determined with reference to the Company's share price. All options are fully vested and so no costs were charged in the current accounting period (2020 nil).
The following reconciles the outstanding share options granted, exercised and forfeited during the year:
| 2021 | 2020 | ||||
|---|---|---|---|---|---|
| Weighted average Number of exercise price options equivalent USD 1 |
Number of options 1 |
Weighted average exercise price equivalent USD 1 |
|||
| Balance at beginning of the period | 1,389,470 | 0.81 | 3,266,470 | 0.53 | |
| Awarded | - | - | - | - | |
| Lapsed | - | - | (1,877,000) | 0.34 | |
| Forfeited during the year | - | - | - | - | |
| Balance at end of the year | 1,389,470 | 0.79 | 1,389,470 | 0.81 | |
| Exercisable at end of the year | 1,389,470 | 0.79 | 1,389,470 | 0.81 |
1 The USD equivalent weighted average exercise price at31 December 2021
| Grant Date |
Expiry date |
Number of Options |
Expected life of Options (Years) |
Rate (%) | Volatility (%) |
Dividend Yield (%) |
Exercise price Nok |
Exercise price equivalent USD |
Fair value at grant date NOK |
Fair value at grant date USD |
|---|---|---|---|---|---|---|---|---|---|---|
| 03 Jul 2017 03 Jul 2017 |
11 Jan 2022 31 May 2022 |
213,400 1,176,070 |
5 5 |
2.97 2.97 |
125 125 |
– – |
2.50 7.75 |
0.28 0.88 |
2.82 2.82 |
0.34 0.34 |
The value of options capitalised during the year was nil (2020: nil).
The share options outstanding at the end of the year had a weighted average remaining contractual life of 129 days (2020: 494 days).
The principal subsidiaries of the PetroNor E&P Limited group, all of which have been included in these consolidated financial statements, are as follows:
| interest at 31 December | ||||
|---|---|---|---|---|
| Name | Country of incorporation |
Principal place of business |
2021 | 2020 |
| PetroNor E&P ASA | Norway | Norway | 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% | - |
| PetroNor E&P Nigeria Ltd | Nigeria | Nigeria | 100% | 100% |
| AJE Production AS | Norway | Norway | 100% | 100% |
| Hemla Africa Holding AS | Norway | Norway | 100% | 70.707% |
| Hemla E&P Congo SA | Congo | Congo | 84.15% | 52.5% |
| African Petroleum Corporation Ltd | Cayman Islands | United Kingdom | 100% | 100% |
| PetroNor E&P Gambia Ltd | Cayman Islands | The Gambia | 100% | 100% |
| African Petroleum Senegal Ltd | Cayman Islands | Senegal | 90% | 90% |
| African Petroleum Senegal SAU | Senegal | Senegal | 100% | 100% |
| APCL Gambia BV | Netherlands | The Gambia | 100% | 100% |
Set out below is summarised financial information for each subsidiary that has non-controlling interests that are material to the group. The amounts disclosed for each subsidiary are before inter-company eliminations.
Proportion of effective ownership
| Hemla E&P Congo SA | Hemla Africa Holding AS | |||
|---|---|---|---|---|
| Amounts in USD thousand | 2021 | 2020 | 2021 | 2020 |
| Current asset | 37,936 | 42,019 | 19,644 | 30,514 |
| Current liabilities | 31,130 | 19,054 | 9,187 | 4,026 |
| Current net assets | 6,806 | 22,965 | 10,457 | 26,488 |
| Non-current assets | 69,577 | 27,417 | 4,827 | 1,188 |
| Non-current liabilities | 16,302 | 21,986 | - | 11,000 |
| Non-current net assets/(liabilities) | 53,275 | 5,431 | 4,827 | (9,812) |
| Net assets | 60,081 | 28,396 | 15,284 | 16,676 |
| Accumulated NCI | 9,523 | 7,312 | - | 4,885 |
| Hemla E&P Congo SA | Hemla Africa Holding AS | |||
|---|---|---|---|---|
| Amounts in USD thousand | 2021 | 2020 | 2021 | 2020 |
| Revenue | 106,464 | 67,543 | - | 150 |
| Profit for the period | 31,685 | 18,034 | (36) | 15,957 |
| Other comprehensive income | - | - | (1,356) | (316) |
| Total comprehensive income for the year | 31,685 | 18,034 | (1,392) | 15,641 |
| Profit allocated to NCI | 8,714 | 8,556 | (312) | 4,674 |
| Dividends paid to NCI | - | 5,150 | - | 3,912 |
| Hemla E&P Congo SA | Hemla Africa Holding AS | |||
|---|---|---|---|---|
| Amounts in USD thousand | 2021 | 2020 | 2021 | 2020 |
| Cash flows from operating activities | 39,360 | 8,245 | 6,505 | 2,877 |
| Cash flows from investing activities | (25,331) | (4,606) | - | - |
| Cash flows from financing activities | (6,047) | (8,047) | (5,833) | (11,295) |
| Net (decrease)/increase in cash and cash | ||||
| equivalents | 8,312 | (4,408) | 672 | (8,418) |
On 18 February 2021 PetroNor E&P Ltd announced that the Company's ownership interest in Helma Africa Holdings Ltd ("HAH") had increased to 100 per cent following the acquisition of the share interest of Symero Limited in HAH.
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 9, 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 |
At the approval date of this report the base salary and fees for the following members of key management is as follows:
| Base salary and fees | Total base salary and | ||
|---|---|---|---|
| Title | Group Entity | /per annum | fees USD equivalent |
| Chair 1 | PetroNor E&P Services AS | USD 174,000 | 360,000 |
| Non-Executive Director | Hemla E&P Congo SA | USD 120,000 | |
| Interim Chief Executive Officer | PetroNor E&P Ltd | GBP 412,500 | 412,500 |
| Non-Executive Director | Nil | Nil | |
| Non-Executive Director | PetroNor E&P Ltd | AUD 48,000 | 37,300 |
| Non-Executive Director | PetroNor E&P Ltd | AUD 48,000 | 37,300 |
| Non-Executive Director | PetroNor E&P Services AS | NOK 250,000 | 28,750 |
| Non-Executive Director | PetroNor E&P Services AS | NOK 250,000 | 28,750 |
| Strategy & Contracts Manager 1 | PetroNor E&P Services AS | USD 204,000 | 204,000 |
| Chief Technical Officer | PetroNor E&P Services AS | NOK 2,500,000 | 287,500 |
| Exploration Director | PetroNor E&P Services Ltd | GBP 215,000 | 283,800 |
| Group Financial Controller | PetroNor E&P Services Ltd | GBP 140,000 | 184,800 |
| Company Secretary | PetroNor E&P Ltd | AUD 24,000 | 18,650 |
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
FX rates used: NOK 1.00 : USD 0.115 GBP 1.00 : USD 1.32
| Post | ||||||
|---|---|---|---|---|---|---|
| Salary and | Other cash | employment | Termination | |||
| Amounts in USD | Designation | fees | benefits | benefits | fees | Total |
| Management | ||||||
| K Søvold | Exec Director & CEO | 288,118 | 821 | 21,721 | - | 310,659 |
| J Pace 1 | Exec Director & CEO | 21,281 | - | - | 21,281 | |
| G Ludvigsen 4 | Business Development Manager | 357,710 | 110 | - | - | 357,820 |
| C Frimann-Dahl | Chief Technical Officer | 221,648 | 780 | 20,732 | - | 243,160 |
| M Barrett | Exploration Director | 296,475 | 2,598 | - | - | 299,073 |
| C Butler | Group Financial Controller | 174,825 | 3,724 | 17,483 | - | 196,032 |
| E Sultan | Strategy & Contracts Manager Related party fees 3 |
168,000 | - | - | - | 168,000 |
| A Hicks | Company Secretary | 27,035 | - | - | - | 27,035 |
| Sum | 1,555,093 | 8,033 | 59,935 | - | 1,623,061 |
| remuneration | ||||||
|---|---|---|---|---|---|---|
| E Alhomouz | Chair 3 | 174,000 | - | - | - | 174,000 |
| J Iskander | Non-Exec Director | - | - | - | - | - |
| Jens Pace 1 | Non-Exec Director | 26,628 | - | - | - | 26,628 |
| A Neuling | Non-Exec Director | 26,787 | - | - | - | 26,787 |
| R Steinepreis | Non-Exec Director | 32,546 | - | - | - | 32,546 |
| I Smines Tybring Gjedde | Non-Exec Director | 38,001 | - | - | - | 38,001 |
| G Kielland 2 | Non-Exec Director | 25,994 | - | - | - | 25,994 |
| Sum | 297,169 | - | - | - | 297,169 | |
| Post | ||||||
|---|---|---|---|---|---|---|
| Salary and | Other cash | employment | Termination | |||
| Amounts in USD | Designation | fees | benefits | benefits | fees | Total |
| E Alhomouz | Non-Exec for HEPCO | 120,000 | - | - | - | 120,000 |
| K Søvold | Non-Exec for HEPCO | 66,000 | - | - | - | 66,000 |
| G Ludvigsen | Non-Exec for HEPCO | 27,500 | 27,500 | |||
| Sum | 213,500 | - | - | - | 213,500 | |
| TOTAL | 2,065,762 | 8,033 | 59,935 | 2,133,730 |
1 On 16 December 2021, Mr Pace was appointed as interim CEO and subsequently resigned as a Non-Exec Director. 2 Appointed 1 February 2021.
3 Remuneration is not paid to the individual, as 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.
4 Following his resignation as a director G Ludvigsen continued to provide services charged on an arms-length by a related party Hagan AS.
| Post | ||||||
|---|---|---|---|---|---|---|
| Salary and | Other cash | employment | Termination | |||
| Amounts in USD | Designation | fees | benefits | benefits | fees | Total |
| Management | ||||||
| K Søvold | Exec Director & CEO | 254,107 | 832 | 22,114 | - | 277,053 |
| J Pace 1 | Exec Director & CEO | 83,039 | 1,318 | - | 448,618 | 532,975 |
| S West 2 | Exec Director & CFO | 58,884 | 2,030 | 5,888 | 346,077 | 412,879 |
| G Ludvigsen | Exec Director & Business | |||||
| Development Manager | 254,107 | 832 | 23,471 | - | 278,410 | |
| C Frimann-Dahl | Chief Technical Officer | 200,432 | 747 | 18,962 | - | 220,141 |
| M Barrett | Exploration Director | 246,595 | 2,131 | - | - | 248,726 |
| C Butler | Group Financial Controller | 147,766 | 5,766 | 14,777 | - | 168,309 |
| E Sultan | Strategy & Contracts Manager | |||||
| Related party fees 3 | 232,500 | - | - | - | 232,500 | |
| A Hicks | Company Secretary | 23,995 | - | - | - | 23,995 |
| Sum | 1,501,425 | 13,656 | 85,212 | 794,695 | 2,394,988 |
| Post | |||||||
|---|---|---|---|---|---|---|---|
| Salary and | Other cash | employment | Termination | ||||
| Amounts in USD | Designation | fees | benefits | benefits | fees | Total | |
| E Alhomouz | Non-Exec Chair | ||||||
| Related party fees 3 | 255,000 | - | - | - | 255,000 | ||
| J Iskander | Non-Exec Director | - | - | - | - | - | |
| Jens Pace 1 | Non-Exec Director | - | - | - | - | - | |
| A Neuling 4 | Non-Exec Director | 24,403 | - | - | - | 24,403 | |
| R Steinepreis 4 | Non-Exec Director | 22,600 | - | - | - | 22,600 | |
| I Smines Tybring Gjedde 5 | Non-Exec Director | 17,565 | - | - | - | 17,565 | |
| T Turner 6 | Non-Exec Director | 1,760 | - | - | - | 1,760 | |
| D King 7 | Non-Exec Director | (3,000) | - | - | - | (3,000) | |
| Sum | 318,328 | - | - | - | 318,328 | ||
| Amounts in USD | Designation | Salary and fees |
Other cash benefits |
Post employment benefits |
Termination fees |
Total |
|---|---|---|---|---|---|---|
| E Alhomouz | Non-Exec for HEPCO | 120,000 | - | - | - | 120,000 |
| K Søvold | Non-Exec for HEPCO | 66,000 | - | - | - | 66,000 |
| G Ludvigsen | Non-Exec for HEPCO | 66,000 | - | - | - | 66,000 |
| Sum | 252,000 | - | - | - | 252,000 | |
| TOTAL | 2,071,753 | 13,656 | 85,212 | 794,695 | 2,965,316 |
1 On 29 February 2020 Mr Pace resigned as CEO but remained on the board as a Non-exec Director. Mr. Pace agreed to waive his Non-Exec Director remuneration for one year in recognition of the termination fees agreed for resigning as CEO.
2 Resigned 29 February 2020.
3 Remuneration is not paid to the individual, as fees 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.
4 Appointed 6 April 2020.
5 Appointed 29 May 2020.
6 Resigned 8 February 2020.
7 Resigned 1 February 2020.
| Balance 1 January 2021 |
Shares purchased |
Granted as remuneration |
Net change other |
Balance 31 December 2021 |
|
|---|---|---|---|---|---|
| K Søvold jointly with G Ludvigsen 1 | 233,555,857 | - | - | 44,763,636 | 278,319,493 |
| K Søvold 2 | 45,000,000 | - | - | 45,000,000 | 90,000,000 |
| G Ludvigsen 3 | 60,000,000 | - | - | 50,439,418 | 9,560,582 |
| J Pace | 1,498,938 | - | - | 80 | 1,498,858 |
| M Barrett | 1,151,667 | 20 | - | - | 1,151,687 |
| C Butler | 234,296 | 20 | - | - | 234,316 |
| C Frimann-Dahl 4 | 50,000 | 554,545 | - | - | 604,545 |
| Total | 341,490,758 | 554,585 | - | 140,203,134 | 381,369,481 |
1 Shares are held by NOR Energy AS, a company controlled jointly by K Søvold and G Ludvigsen through an indirect beneficial interest, and Symero Ltd, a company held 100 per cent by NOR Energy AS.
2 Shares are held by Gulshagen III AS and Gulshagen IV AS, a company controlled by K Søvold through an indirect beneficial interest along with a close associate of K Søvold.
3 Shares are held by Pust for Livet AS, a company controlled by a close associate of G Ludvigsen.
4 Shares are held by Snake Oil AS, a company controlled by C Frimann-Dahl
At 31 December 2021, Eyas Alhomouz held no shares personally but holds influence over 481,481,666 shares (2020: 371,961,246 shares) as the CEO of significant shareholder Petromal LLC.
Other members of key management not included in the above table held no shares during the current year
No warrants or options were held by Directors and other Key Management Personnel during the current year.
| Shareholder | Place of incorporation | Ownership 31 December 2021 |
Ownership 31 December 2020 |
|---|---|---|---|
| Petromal LLC – Sole Proprietorship LLC | UAE | 36.28% | 38.28% |
| NOR Energy AS | Norway | 10.14% | 24.03% |
| Symero Ltd | Cyprus | 10.46% | - |
On 18 February 2021 PetroNor announced that the Company's net indirect interest in PNGF Sud, PetroNor's core asset, had increased from 10.5 per cent to 16.83 per cent following a USD 18 million contingent acquisition of all of Symero Limited's ("Symero") shares in Hemla Africa Holding AS ("HAH") (the "Symero Transaction"), and a court ruling in Congo related to parts of MGI International S.A.'s ("MGI") indirect share in PNGF Sud (the "MGI Ruling"). Symero's shares in HAH represented 29.293 per cent of all issued and outstanding shares in HAH, and following completion of the Symero Transaction, the
Company owns 100 per cent of all issued and outstanding shares in HAH. Symero is a company owned by NOR Energy AS, which in turn is controlled by former CEO of PetroNor, Knut Søvold, and former Director of PetroNor, Gerhard Ludvigsen, and therefore the Symero Transaction was considered a related party transaction at the time of completion, and as such was subject to the approval by the shareholders of the Company by ordinary resolution at an Extraordinary General Meeting of the Company having had the benefit of an independent valuation report.
Transactions with related parties included in the consolidated statement of comprehensive income:
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Petromal – Sole Proprietorship LLC | 554 | 587 |
| Administrative expenses | 554 | 587 |
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 | 2021 | 2020 |
|---|---|---|
| Loan receivable from MGI International S.A. 1 | - | 3,639 |
| Total receivables from related parties (Note 13) | - | 3,639 |
| Other payable to Nor Energy AS Other payable to Petromal – Sole Proprietorship LLC Other payable to Symero Ltd. Other payable to MGI International S.A. |
2,136 1,281 32 - |
3,378 2,030 108 6,178 |
| Total payables to related parties (Note 19) | 3,448 | 11,694 |
| Loan payable Symero Ltd Loan payable to related parties (Note 20) |
3,912 3,912 |
3,912 3,912 |
1 During 2018, Hemla Africa Holding AS (HAH AS) provided a loan of USD 7 million to MGI International SA, (minority shareholder in Hemla E&P Congo SA (HEPCO). The loan repaid directly by HEPCO to HAH AS from its yearly dividends being 25 per cent of MGI's share of dividend in the first year and 40 per cent thereafter. The loan did not carry any interest .
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.
On 28 September 2020, subsidiary company Hemla Africa Holding AS paid a USD 3.9 million dividend to minority interest and related party Symero Ltd. An amount equal to the dividend
On 28 April 2021 PetroNor completed the acquisition of the entire issued share capital of SPE Guinea-Bissau AB from Svenska Petroleum Exploration AB. The transaction allowed PetroNor to assume the operatorship and 78.57 per cent interest in both the Sinapa (Block 2) and Esperanca (Blocks 4A and 5A) licences in Guinea-Bissau.
was immediately loaned to PetroNor E&P Limited by Symero Ltd with interest rates matching those already provided by external financing and no security was provided for the loan.
This strategic acquisition broadens PetroNor's portfolio in the MSGBC basin , and we are currently completing interpretation of data with a view to participating in a combined Guinea-Bissau - The Gambia drilling campaign in 2023.
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:
| Amounts in USD thousand | |
|---|---|
| Inventories | 1,665 |
| Trade and Other Receivables | 14 |
| Cash and bank balances | 534 |
| Sum | 2,213 |
| Non current assets | |
| Intangible assets | 157 |
| Sum | 157 |
| Total assets | 2,370 |
| Current liabilities Trade and other payables |
2,320 |
| Total Liabilities | 2,320 |
| Net Assets | 50 |
USD'000 50
The SEK 434,238 consideration paid for the transaction was calculated to be SEK 1 greater than the SEK book value of the net assets of SPE Guinea- Bissau on completion. As the fair
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 ended 31 December 2021, 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 summarized 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 ended 31 December 2021 using the amounts of debt and other financial assets and liabilities held at those reporting dates.
value of the net assets acquired equalled to the consideration paid no goodwill was recognised.
Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group. At 31 December 2020, 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 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 | Notes | External credit rating |
Internal credit rating |
12-month or lifetime ECL |
Gross carrying amount |
Loss allowance |
Net carrying amount |
|---|---|---|---|---|---|---|---|
| 31 December 2021 | |||||||
| Trade receivables | 13 | N/a | (i) | Lifetime ECL | 13,431 | - | 13,431 |
| Due from related parties | 13, 24d | 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 |
| 31 December 2020 | |||||||
| Trade receivables | 13 | N/a | (i) | Lifetime ECL | 5,408 | - | 5,408 |
| Due from related parties | 13, 24d | N/a | - | Lifetime ECL | 3,639 | - | 3,639 |
| Advance against decommissioning cost | 13 | N/a | - | Lifetime ECL | 21,260 | - | 21,260 |
| Cash and cash equivalents | 14 | Aa3/B | N/a | 12-month ECL | 14,113 | - | 14,113 |
(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 2020 based on contractual undiscounted payments.
| 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 | 24d | 3,449 | - | - | - | - | 3,912 |
| Loan payable | 20 | - | - | 2,500 | 10,579 | - | 13,079 |
| Total | 3,449 | 21,944 | 2,500 | 10,579 | 65 | 38,542 |
| 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 2020 | |||||||
| Trade accounts payable | 19 | 544 | 479 | 4,203 | - | - | 5,226 |
| Amounts due to related parties | 24d | 11,986 | - | - | - | - | 11,986 |
| Loan payable | 20 | - | - | - | 4,000 | 14,912 | 18,912 |
| Total | 12,530 | 479 | 4,203 | 4,000 | 14,912 | 36,124 |
The Company had USD 31.8 million (2020: 14.1 million) in unrestricted cash at 31 December 2021. 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.
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 2021 | 31 December 2020 | ||||
|---|---|---|---|---|---|
| Amounts in USD thousand | +150bp | -150bp | +150bp | -150bp | |
| Loans payable | (196) | 196 | (284) | 284 |
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 2021 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 2021 | 31 December 2020 | |||
|---|---|---|---|---|
| Amounts in USD thousand | +20% | -20% | +20% | -20% |
| USD vs NOK | ||||
| Cash | 1,040 | (1,044) | 58 | (58) |
| Receivables | - | - | 61 | (61) |
| Payables | (92) | 92 | (25) | 25 |
| Total | 948 | (952) | 94 | (94) |
| USD vs GBP | ||||
| Cash | 3 | (3) | 4 | (4) |
| Receivables | 8 | (8) | 2 | (2) |
| Payables | (6) | 6 | (42) | 42 |
| Total | 5 | 5 | (36) | 36 |
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 2022 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 has no significant debt arrangements in place and has the flexibility to source conventional debt capital from the markets. 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 year.
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 | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 |
| Financial Assets | ||||||
| Cash and cash equivalents | - | - | 31,755 | 14,113 | - | - |
| Trade and other receivables | - | - | 13,820 | 9,397 | - | - |
| Other Receivables | 26,837 | 21,260 | ||||
| Total | - | - | 72,412 | 44,770 | - | - |
| Financial Liabilities | ||||||
| Trade and other payables | - | - | 30,055 | 22,238 | - | - |
| Loans and borrowings | - | - | 13,079 | 18,912 | - | - |
| Total | - | - | 43,134 | 41,150 | - | - |
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 2021, the Group had approved the budget for PNGF Sud operations in Congo that included planned capex expenditure for coming year of USD 50.6 million (2020 USD 33.8 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 at 31 December
| Amounts in USD thousand | 2021 | 2020 |
|---|---|---|
| Within one year 1 | 40,000,000 | 40,000,000 |
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) opened investigations into criminal charges and allegations of corruption brought against individuals related to the Company.
At the signing date of this report, Økokirm has confirmed that neither PetroNor nor any of its subsidiaries is under investigation. As outlined in the directors' report the board has taken a series of remediation steps to assure the further implementation of anti-corruption measures. While the Company has continued to operate effectively since the investigations started, it has used significant resources to address this matter at a cost to the business. Furthermore, it is uncertain how long the investigations into the individuals may continue and how the outcome of those investigations may indirectly impact the business. At this stage, the only certainty is that while the investigations continue, it may raise the perceived risk profile of the Company thus, potentially impacting the Group's capacity to transact with new and existing partners. Whilst the reputational cost cannot be quantified, this may increase work required by partners to mitigate concerns about the risk profile.
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, and for the transfer of OML 113 to Aje Production AS ("Aje Production"). As previously announced, following completion of the Transaction, Panoro's intention is to declare a special dividend and distribute to its shareholders USD\$ 10 million equivalent in PetroNor shares in order for Panoro shareholders to retain a direct listed exposure to Aje/OML 113. It is expected that the transaction will complete in Q2 2022. The Group successfully completed the redomicile process in February 2022. The implementation of the scheme of arrangement on 24 February 2022 resulted in PetroNor E&P ASA replacing PetroNor E&P Ltd as the top company of the Group. PetroNor E&P Ltd was delisted from the Oslo Euronext Expand on the same day and on 28 February 2022 the shares of PetroNor E&P ASA were listed and began trading on the main Oslo Stock Exchange. The financial statements are presented as a continuance of the business of PetroNor E&P Ltd.
During March 2022, the 1,366,564 shares that had not been transferred to the VPS in Norway prior to the scheme of arrangement were sold back into the market and the sales proceeds were distributed to the former predominantly Australian investors.
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.
No change in IFRS effective for the 2021 financial statements are relevant this financial year
In August 2020, the IASB issued Phase 2 of its project which amends IFRS 9 Financial Instruments, IAS 39 Financial Instruments: Recognition and Measurement, IFRS 7 Financial Instruments: Disclosures, IFRS 4 Insurance Contracts and IFRS 16 Leases. Phase 2 finalises the Board's response to the ongoing reform of interbank offer rates (IBOR) and other interest rate benchmarks.
The amendments complement Phase 1 issued in 2019 and focus on the effects of financial statements when a company replaces the old interest rate benchmark with an alternative
A CPR update prepared by AGR Petroleum Services AS on the Company's PNGF Sud asset in Congo was released on 6 April 2022. The update represented an increase of approximately 2 per cent for 2P and an increase of 4 per cent for 2C on a gross basis.
On 11 April 2022 PetroNor announced that they had signed a pre-payment sales agreement with ADNOC Trading during the quarter and has invoiced against entitlement production. On the same date it was announced that PetroNor had received a notification from Økokrim that the Company's Chairman of the Board, Mr. Eyas Alhomouz (US citizen), had been made subject to the ongoing investigations carried out by Økokrim and been given the status as suspect, and that the U.S. Department of Justice had opened a separate investigation into these allegations, based on information from Økokrim.
At the beginning of 2022, Russia's invasion of Ukraine deepened the energy crisis and led to an immediate effect in increasing oil and gas prices. Economic sanctions towards Russia and the economic uncertainty may have an impact on our business and our markets going forward.
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.
benchmark rate as a result of the reform.
The Phase 2 amendments mainly consist of the following:
In March 2021, the IASB issued Covid-19-related rent concessions beyond 30 June 2021 to extend the relief period by another year. The International Accounting Standards Board amended IFRS 16 Leases to provide relief to lessees from applying the IFRS 16 guidance on lease modifications to rent concessions arising as a direct consequence of the Covid-19 pandemic. The amendment does not affect lessors.
The amendment exempts lessees from having to consider individual lease contracts to determine whether rent concessions occurring as a direct consequence of the Covid-19 pandemic are lease modifications and allows lessees to account for such rent concessions as if they were not lease modifications. It applies to Covid-19-related rent concessions that reduce lease payments due on or before 30 June 2022.
Lessees must apply the practical amendment retrospectively, recognizing the cumulative effect of initially applying the
amendment as an adjustment to the opening balance of retained earnings (or other component of equity, as appropriate) at the beginning of the annual reporting period in which the amendment is first applied. The extension of the amendment is effective for annual periods beginning on or after 30 June 2021, but earlier application is permitted.
This amendment had no effect on the Group.
Standards and interpretations that are issued up to the date of issuance of the consolidated financial statements, but not yet effective are disclosed below. The Group's intention is to adopt the relevant new and amended standards and interpretations when they become effective, subject to EU approval before the consolidated financial statements are issued.
At the date of authorisation of these financial statements, the Group has not applied the following new and revied IFRS standards that have been issued are not yet effective :
| Amendment to IAS 1 | Classification of liabilities as current or non-current |
|---|---|
| Amendments to IAS 16 | Proceeds before intended use |
| Amendments to IAS 37 | Onerous contracts , costs of fulfilling a contract |
| Amendments to IAS 8 | Definition of account estimates |
| Amendments to IAS 1 and IFRS practise statement 2 |
Disclosure of accounting policies |
| Amendments to IAS 12 | Deferred tax related to assets and liabilities arising from a single transaction |
| Annual improvements 2018-2020 cycle |
Amendments to IFRS 1 first time adoption of international financial reporting standards, IFRS 9 financial instruments, IFRS 16 leases, and IAS 41 agriculture |
The consolidated financial statements comprise the financial statements of PetroNor E&P Limited ("the Company") and its subsidiaries (together "the Group") for the year ended 31 December 2021.
An entity has been assessed as being controlled by the Group when the Group 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:
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 a 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 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 decided to use United States Dollars as its presentation currency, being the functional currency of all major subsidiaries in the Group. 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 Limited is United States Dollars.
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 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 in 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 are therefore 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 expenses, 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 the 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.
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.
(i) Revenue from petroleum products
Revenue from the sale of crude oil is recognised when a customer obtains control ("sales" or "lifting" method). Normally this is when title passes at point of delivery. Revenues from production of oil properties are recognised based on actual volumes lifted and sold to customers during the period.
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 revenue 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:
rate or a change in expected payment under a guaranteed residual value, in which cases the lease liability is remeasured by discounting the revised lease payments using the initial discount rate (unless the lease payments 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 in total amount reported.
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 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 derecognises financial assets when the contractual rights to the cash flows expire or the financial asset is transferred to a third party. This includes the derecognition of receivables for which discounting arrangements are entered into. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.
For purposes of subsequent measurement, financial assets are classified in 4 categories:
■ The contractual terms of the financial asset give rise to 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.
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 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 measured at their nominal amount when the effect of discounting is not material.
Foreign exchange gains and losses 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 Fair Value through profit and loss , 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, the 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:
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, and 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:
■ Expenses, including its share of any expenses incurred jointly.
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 gains 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 upon the acquisition date.
| For the period | |
|---|---|
| Note | ended 31 December 2021 |
| (6) | |
| (6) | |
| - | |
| (6) | |
| - | |
| (6) | |
| - | |
| (6) | |
| (6) | |
| (6) | |
| - | |
| - | |
| - - |
|
The accompanying notes form part of these financial statements.
| Amounts in USD thousand | Note | At31 Dec 2021 |
|---|---|---|
| ASSETS | ||
| Current assets | ||
| Trade and other receivables | - | |
| Cash and cash equivalents | 5 | 114 |
| Total | 114 | |
| Non-current assets | ||
| Investments | - | |
| Total | - | |
| Total assets | 114 | |
| LIABILITIES | ||
| Current liabilities | ||
| Trade and other payables | 6 | |
| Total | 6 | |
| Total liabilities | 6 | |
| NET ASSETS | 108 | |
| Issued capital and reserves attributable to owners of the parent | ||
| Share capital | 6 | 114 |
| Reserves | - | |
| Retained earnings | (6) | |
| TOTAL EQUITY | 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 29 April 2022.
| Share | Other paid | Retained | |||
|---|---|---|---|---|---|
| Amounts in USD thousand | Note | capital | in capital | earnings | Total |
| 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 year | - | - | (6) | (6) | |
| BALANCE AT 31 DECEMBER 2021 | 114 | - | (6) | 108 |
The accompanying notes form part of these financial statements.
| For the period ended | ||
|---|---|---|
| (Amounts in USD thousand) | Note | 31 December 2021 |
| Cash flows from operating activities | ||
| Loss for the year | (6) | |
| Total | (6) | |
| (Increse)/Decrease in trade and other receivables | - | |
| (Decrease)/increase in trade and other payables | 6 | |
| Cash (used in)/generated from operations | - | |
| Income taxes paid | - | |
| Net cash flows from operating activities | - | |
| Financing activities | ||
| Issue of ordinary shares | 114 | |
| Proceeds from loans and borrowings | - | |
| Net cash (used in)/from financing activities | 114 | |
| Net increase/(decrease) in cash and cash equivalents | ||
| Cash and cash equivalents at beginning of year | 5 | - |
| Cash and cash equivalents at end of year | 114 | |
The accompanying notes form part of these financial statements.
Petronor E&P ASA is a public limited company, incorporated in Norway.
Frøyas gate 13 0243 Oslo Norway Tel +47 22 55 46 07
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 | Non-Exec Chair | 1 October 2021 |
| I Tybring-Gjedde | Non-Exec Director | 1 October 2021 |
| G Kielland | Non-Exec Director | 1 October 2021 |
| J Iskander | Non-Exec Director | 8 October 2021 |
Pace was appointed to the Board 1 October 2021 and resigned 9 February 2022.
The Company was established on 1 October 2021, and these financial statements prepared for Petronor E&P ASA and cover the period ended 31 December 2021. The financial statements were approved by resolution of the Board on 29 April 2022.
The Company and PetroNor E&P Limited ("PetroNor Australia") entered into a Scheme Implementation Agreement on 7 October 2021. Under the Scheme, all of PetroNor Australia shares held by PetroNor Australia shareholders were transferred to the Company. In exchange PetroNor Australia shareholders received one new Company share for every one PetroNor Australia share held. 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. This arrangement will be accounted as a continuance of the business of PetroNor E&P Limited . Please see note 10 for an extended disclosure.
Following the shareholders' approval, 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.
Following the 1 to 1 share swap, PetroNor E&P ASA began trading on Oslo Stock Exchange 28 February 2022.
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 2021. 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 the 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 a Going Concern basis, under the going concern assumption an entity is ordinarily viewed as continuing in business for the foreseeable future. The Company recognises that in order to fund on-going operations and pursue organic and inorganic growth opportunities for the wider PetroNor Group it will require additional funding. This funding may be sourced through joint venture equity or share issues or through debt finance.
As at the signing date of this report, the pooling agreement between two third parties necessary to enable the new offtaker to lift first quarter 2022 oil production is believed to be close to completion. The Group is currently advancing potential contingency arrangements to improve working capital should further significant delays to completion of the pooling agreement and lifting schedule eventuate. As at the date of this report, it is not yet clear whether any such arrangements will be necessary and no new binding arrangements have been entered into. Global macro-economic factors are considered to be strongly in the Company's favour at present with high demand leading to high oil prices and the Board is confident a solution to any short-term working capital requirements will be implementable as necessary.
There are Group outstanding amounts due to related party shareholders Petromal and NOR Energy for the remaining cash consideration of the 2019 reverse takeover transaction of USD 1.3 million and USD 2.1 million respectively. Plus, the Group has a USD 3.9 million debt facility with related party shareholder Symero that is due to be repaid in November 2022, and a USD \$5.6 million debt facility with Rasmala that will be repaid in equal instalments up to November 2022. In addition the Group has material potential capital
commitments associated with its exploration portfolio. Settlement of the borrowings detailed above would leave the Group debt free. However, the Group plans to refinance and consolidate its' various debt positions before the year end, to provide additional working capital and strengthen its balance sheet, . While it is acknowledged that the recent Økokrim investigation as detailed in Note 9 Commitments and Contingencies may complicate refinancing initiatives and extend timetables, the Board is confident that refinancing measures will be able to be completed as necessary.
These conditions indicate a material uncertainty that may cast a significant doubt about the entity's ability to continue as a going concern and, therefore, that it may be unable to realise its assets and discharge its liabilities in the normal course of business. This financial statments have been prepared on the going concern basis which 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 PetroNor Group created a consoldidated net profit after tax of USD 21.1 million for the year ended 31 December 2021, with strong production from the Congo assets generating 3,614 bopd in first quarter of 2022. As at 31 December 2021 the Group had a cash balance
of US 31.8 million. The Group has entered into a new offtake agreement with a new partner, listed the Company on the main Oslo Børs and continued to host data rooms for potential partners to join with the Group on its exploration portfolio, demonstrating that the business has continued to operate effectively, and businesses remain willing to engage with the Group.
This has enabled 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 Company not continue as a going concern.
The financial statements have been prepared on the basis of uniform accounting principles for similar transactions and events under otherwise similar circumstances.
The financial report is presented in United States Dollars.
The Company has no employees
No audit fees have been incurred for the period.
| (Amounts in USD thousand) | At 31 December 2021 |
|---|---|
| Cash in bank | 114 |
All shares have equal rights and are freely transferable Share capital
| At 31 December 2021 | |
|---|---|
| Issue of shares 1 | 114 |
| Balance at end of the period | 114 |
1 On 1 October 2021, the Company issued 100,000 shares at NOK 10 each. All the shares are owned by PetroNor E&P Ltd, the immediate parent company registered in Australia and listed on Oslo Euronext Expand.
The risk management disclosures reflect the status of the Company as at the balance sheet date. As the ultimate parent of the PetroNor Group in 2022, risk policies and disclosures will reflect the risk profile of the extended Group. Please refer to Note 26 to the Consolidated financial statements of PetroNor E&P Limited as included in this annual report.
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 2021, 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 | 114 |
| Loss allowance | - |
| Net carrying amount | 114 |
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 October 2021 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 2021 Other payables |
- | - | - | 6 |
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.
In December 2021 the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway (Økokrim) opened investigations into criminal charges and allegations of corruption brought against individuals related to the Company.
At the signing date of this report, Økokirm has confirmed that neither PetroNor nor any of its subsidiaries is under investigation. As outlined in the directors' report the board has taken a series of remediation steps to assure the further implementation of anti-corruption measures. While the Company has continued to operate effectively since the
investigations started, it has used significant resources to address this matter at a cost to the business. Furthermore, it is uncertain how long the investigations into the individuals may continue and how the outcome of those investigations may indirectly impact the business. At this stage, the only certainty is that while the investigations continue, it may raise the perceived risk profile of the Company thus, potentially impacting the Group's capacity to transact with new and existing partners. Whilst the reputational cost cannot be quantified, this may increase work require As of the period ended 31 October 2021 the Company had no commitments or contingencies.
On 24 February 2022, the Company announced that it had issued 1,326,991.006 ordinary shares as part of the implementation of the Scheme of Arrangement and re-domicile from Australia to Norway. The Scheme of Arrangement involved establishing a new entity (being the Company) for the purposes of carrying out the Share Swap whereby shares in PetroNor E&P Ltd. ("PetroNor Australia") were to be swapped for shares in the Company. The shares in PetroNor Australia were to be delisted in conjunction with the listing of the Company PetroNor E&P ASA. PetroNor E&P ASA submitted its application for its shares to be listed on Oslo Stock Exchange 27 October 2021.
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. Following the shareholders' approval, 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. Following the 1 to 1 share swap, PetroNor E&P ASA began trading on Oslo Stock Exchange 28 February 2022. Under the Australian scheme, all of the shares held by PetroNor E&P Ltd. (Australia) shareholders were transferred
to PetroNor E&P ASA. The shareholders are thus, in all material respects, identical before and after the transaction. Therefore, this will be treated as a continuance of business under the Company (being the new listing entity). The financial statements for the Company going forward will be presented as a continuance of the activities of the Australian company PetroNor Australia. The financial statements of PetroNor Australia have been prepared on the assumption that the Group will continue as a going concern with the realisation of assets and settlement of debt in normal operations. Accounts will be prepared in compliance with International Financial Reporting Standards (IFRS) as issued by the Accounting Standards Board and in accordance with the requirements of applicable Norwegian laws.
As the financial statements of the Company going forward will be treated as a continuance of the business of PetroNor E&P Limited , the results presented below would represent the group consolidated results of PetroNor E&P ASA for the year ended 31 December 2021.
| (Amounts in USD thousand) | |
|---|---|
| Revenue | 106,463 |
| Cost of sales | (34,585) |
| Gross profit | 71,878 |
| Other operating income | 866 |
| Administrative expenses | (13,131) |
| Profit from operations | 57,343 |
| Finance expense | (3,041) |
| Foreign exchange gain / (loss) | (56) |
| Profit before tax | 54,246 |
| Tax expense | (33,102) |
| Profit/(Loss) for the year | 21,144 |
| Other Comprehensive income: | |
| Exchange losses arising on translation of foreign operations | (364) |
| Total comprehensive income/(loss) | 20,780 |
| Profit/(Loss) for the year attributable to: | |
| Owners of the parent | 12,314 |
| Non-controlling interest | 8,830 |
| Total | 21,144 |
| Total comprehensive income/(loss) attributable to: | |
| Owners of the parent | 12,208 |
| Non-controlling interest | 8,572 |
| Total | 20,780 |
(Amounts in USD thousand)
| ASSETS | |
|---|---|
| Current assets | |
| Inventories | 6,227 |
| Trade and other receivables | 13,820 |
| Cash and cash equivalents | 31,755 |
| Total current assets | 51,802 |
| Non-current assets | |
| Property, plant and equipment | 39,397 |
| Intangible assets | 7,172 |
| Right-of-use assets | 44 |
| Other receivables | 26,837 |
| Total non-current assets | 73,450 |
| Total assets | 125,252 |
| LIABILITIES | |
| Current liabilities | |
| Trade and other payables | 29,996 |
| Lease liability | 58 |
| Loans and borrowings | 13,079 |
| Total current liabilities | 43,133 |
| Non-current liabilities | |
| Loans and borrowings | - |
| Lease liability | - |
| Provisions | 16,302 |
| Total non-current liabilities | 16,302 |
| Total liabilities | 59,435 |
| NET ASSETS | 65,817 |
| Issued capital and reserves attributable to owners of the parent | |
| Share capital | 62,115 |
| Reserves | (1,421) |
| Retained earnings | (1,390) |
| Total | 59,304 |
Non-controlling interests 6,513
TOTAL EQUITY 65,817
(Amounts in USD thousand)
| Cash flows from operating activities | |
|---|---|
| Profit for the year | 54,246 |
| Adjustments for: | |
| Depreciation and amortisation | 4,422 |
| Amortization of right-of-use asset | 168 |
| Unwinding of discount on decommissioning liability | 995 |
| Net foreign exchange differences | (364) |
| Total cash flows from operating activities | 59,467 |
| (Increse)/Decrease in trade and other receivables | (8,062) |
| Increase in advance against decommissioning cost | (5,577) |
| Increase in inventories | (2,649) |
| (Decrease)/increase in trade and other payables | 7,758 |
| Cash (used in)/generated from operations | 50,937 |
| Income taxes paid | (33,102) |
| Net cash flows from operating activities | 17,835 |
| Investing activities | |
| Purchases of property, plant and equipment | (19,759 |
| Purchases of intangible assets | (814) |
| Net cash flows from investing activities | (20,573) |
| Financing activities | |
| Issue of ordinary shares | 27,943 |
| Proceeds from loans and borrowings | (1,563) |
| Repayment of loans and borrowings | (5,833) |
| Repayment of principal portion of lease liability | (159) |
| Repayment of interest portion of lease liability | (8) |
| Dividends paid to non-controlling interest | - |
| Net cash (used in)/from financing activities | 20,380 |
| Net increase/(decrease) in cash and cash equivalents | 17,642 |
| Cash and cash equivalents at beginning of year | 14,113 |
| Cash and cash equivalents at end of year | 31,755 |
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 and other payables are carried at amortised cost and due to their short-term nature, they are not discounted.
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.
Incremental costs directly attributable to the issue of new shares are shown in equity as a deduction, net of tax, from the proceeds.
As per Note 01 (Corporate Information) and Note 10 (Group Arrangements and redomicile process), following the completion of the redomicile process PetroNor E&P ASA has become the ultimate parent entity for the PetroNor Group. Accordingly a more extended set of accounting policies for the Company will be adopted commencing 1 January 2022. These policies will mirror the previous policies of PetroNor E&P Limited as disclosed in Note 30 to the Consolidated financial statements of PetroNor E&P Limited which have been disclosed in this annual report.
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
The Company successfully completed the redomicile process in February 2022 as disclosed in Note 10. The implementation of the scheme of arrangement on 24 February 2022 resulted in PetroNor E&P ASA replacing PetroNor E&P Ltd as the top company of the PetroNor Group. PetroNor E&P Ltd was delisted from the Oslo Euronext Expand on the same day and on 28 February 2022 the shares of PetroNor E&P ASA were listed and began trading on the main Oslo Stock Exchange. The financial statements are presented as a continuance of the business of PetroNor E&P Ltd.
During March 2022, the 1,366,564 shares that had not been transferred to the VPS in Norway prior to the scheme of arrangement were sold back into the market and the sales proceeds were distributed to the former predominantly Australian investors.
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.
The redomicile process as disclosed in note 10 completed post period.
At the beginning of 2022, Russia's invasion of Ukraine deepened the energy crisis and led to an immediate effect in increasing oil and gas prices. Economic sanctions towards Russia and the economic uncertainty may have an impact on our business and our markets going forward.
Events after the reporting period that do not affect the company's financial position on the end of the reporting period but which will affect the company's financial position in the future are disclosed if significant.
Pursuant to the Norwegian Securities Trading Act section 5-5 with pertaining regulations we hereby confirm that, to the best of our knowledge, the company's financial statements for 2021 have been prepared in accordance with IFRS, as provided for by the EU, and in accordance with the requirements for additional information provided for by the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair picture of the Company's liabilities, financial position and results viewed in their entirety.
To the best of our knowledge, the Board of Directors' Report gives a true and fair picture of the development, performance and financial position of the business, and includes a description of the principal risk and uncertainty factors facing the Company and its subsidiaries. Additionally, we confirm to the best of our knowledge that the "Payments to governments" included in the Directors's Report has been prepared in accordance with the requirements in the Norwegian Securities Trading Act Section 5-5a with pertaining regulations.
29 April 2022 The Board of Directors PetroNor E&P ASA
Eyas Alhomouz Chair of the Board
Joseph Iskander Director
Gro Kielland Director
Ingvil Smines Tybring-Gjedde Director
BDO AS Munkedamsveien 45 P.O. Box 1704 Vika N-0121 Oslo
To the Board of Directors in PetroNor E&P Limited
We have audited the special purposeconsolidated financial statements of PetroNor E&P Limited.
The special purpose consolidated financial statements comprise:
• The financial statements of the group, which comprise the balance sheet as at 31 December 2021, and income statement, statement of comprehensive income, statement of changes in equity and cash flows for the year then ended, and notes to the financial statements, including a summary of significant accounting policies.
• The accompanying financial statements give a true and fair view of the financial position of the group as at 31 December 2021, and its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards as adopted by the EU.
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 laws and regulations and 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.
Material uncertainty regarding the Groups's ability to continue as a going concern
We draw attention to Note 2 and the Board of Director's report, which state that the Group is currently advancing potential contingent arrangements to improve working capital in the event this will be necessary. Furthermore, it is stated that the Group has outstanding amounts due to related party shareholders, plus other debt facilities due in 2022, and material potential capital commitments associated with its exploration portfolio. The Group plans to refinance and consolidate its various debt positions before year-end, but acknowledges that the recent Økokrim investigation as detailed in Note 28 may complicate refinancing initiatives and extend timetables. As stated in Note 2 and the Board of Directors' report, these events or conditions, along with other matters as set forth in note Note 2 and the Board of Directors' report, indicate that a material uncertainty exists that may cast significant doubt on the Groups's ability to continue as a going concern. Our opinion is not modified in respect of this matter.
The Board of Directors and the Managing Director (management) is responsible for the other information. The other information comprises the Board of Directors' report and other information
Independent Auditor's Report PetroNor E&P Limited - 2021 page 1 of 2
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.
Responsibilities of the Board of Directors and the Managing Director for the Financial Statements
Board of Directors and the Managing Director (management) are 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
BDO AS
Børre Skisland State Authorised Public Accountant (This document is signed electronically)
Independent Auditor's Report PetroNor E&P Limited - 2021 page 2 of 2
BDO AS Munkedamsveien 45 P. O. Box 1704 Vika N-0121 Oslo
To the General Meeting in PetroNor E&P ASA
• The balance sheet as at 31 December
• The income statement, statement of comprehensive income for 2021 • Statement of changes in equity • Statement of cash flows for the year that ended 31 December 2021 • Notes to the financial statements, including a summary of significant
Report on the Audit of the Financial Statements
We have audited the financial statements of PetroNor E&P ASA.
The financial statements comprise:
accounting policies
2021
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 as required by laws and regulations and 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 1 year from the incorporation of the company on 1 October 2021.
We draw attention to Note 2 and the Board of Director's report, which state that the Group is currently advancing potential contingent arrangements to improve working capital in the event this will be necessary. Furthermore, it is stated that the Group has outstanding amounts due to related party shareholders, plus other debt facilities due in 2022, and material potential capital commitments associated with its exploration portfolio. The Group plans to refinance and consolidate its various debt positions before year-end, but acknowledges that the recent Økokrim
Independent Auditor's Report PetroNor E&P ASA - 2021 page 1 of 4
investigation as detailed in Note 9 may complicate refinancing initiatives and extend timetables. As stated in Note 2 and the Board of Directors' report, these events or conditions, along with other matters as set forth in Note 2 and the Board of Directors' report, indicate that a material uncertainty exists that may cast significant doubt on the Company's ability to continue as a going concern. Our opinion is not modified in respect of this matter.
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.
| Description of the key audit matter | How the key audit matter was addressed in the audit |
|---|---|
| Scheme of Arrangement and redomicile from Australia to Norway |
|
| PetroNor E&P ASA was incorporated in October 2021 with the purpose of becoming the new parent company of the PetroNor Group following the implementation of a Scheme of Arrangement and successful completion of a process to redomicile from Australia to Norway. The Scheme of Arrangement involved establishing PetroNor E&P ASA for the purpose of carrying out a share swap whereby shares in PetroNor E&P Limited were to be swapped for shares in PetroNor E&P ASA. On 24 February 2022, PetroNor E&P Limited delisted its shares on Euronext Expand in conjunction with the listing of PetroNor E&P ASA shares on the Oslo Stock Exchange on 28 February 2022. Under the Scheme of Arrangement, the shares held by PetroNor E&P Limited shareholders were transferred to PetroNor E&P ASA, and in all material respects the shareholders are identical before and after this 1:1 share swap. The share swap transaction will be accounted for as a continuance of business in the PetroNor Group, with PetroNor E&P ASA as new parent company. In the following reporting periods, the consolidated financial statements |
Our audit procedures have included an assessment of management's proposed accounting treatment of the Scheme of Agreement and process to redomicile from Australia to Norway. We have also evaluated the adequacy of the information provided in the notes and the Board of Directors' report concerning the Scheme of Arrangement and process to redomicile from Australia to Norway. |
| of PetroNor E&P ASA will be presented as a |
Independent Auditor's Report PetroNor E&P ASA - 2021 page 2 of 4
continuation of the activities in PetroNor E&P Limited.
As at 31 December 2021, PetroNor E&P ASA was not a parent company and has therefore not prepared consolidated financial statements for 2021. However, for information purposes the annual report for PetroNor E&P ASA for 2021, includes audited special purpose consolidated financial statements for PetroNor E&P Limited for 2021.
Due to the material impact on the presentation of the financial statements for PetroNor E&P ASA for 2021, we have considered the Scheme of Arrangement and redomicile process a key audit matter in the audit of the Company.
See Note 10 and the Board of Directors' report for detailed information about the Scheme of Arrangement and redomicile process.
The Board of Directors and the Managing Director (management) is responsible for the other information. The other information comprises the Board of Directors' report. 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 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
The Board of Directors and the Managing Director (management) are 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.
Independent Auditor's Report PetroNor E&P ASA - 2021 page 3 of 4
In preparing the financial statements, management is responsible for assessing the Company'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 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
We have performed an assurance engagement to obtain reasonable assurance that the financial statements with file name 984500AEEH2D2AK42C11-2021-12-31-en.xhtml have been prepared in accordance with Section 5-5 of the Norwegian Securities Trading Act (Verdipapirhandelloven) and the accompanying Regulation on European Single Electronic Format (ESEF).
In our opinion, the financial statements have been prepared, in all material respects, in accordance with the requirements of ESEF.
Management is responsible for preparing and publishing the financial statements in the single electronic reporting format required in ESEF. This responsibility comprises an adequate process and the internal control procedures which management determines is necessary for the preparation and publication of the financial statements.
For a description of the auditor's responsibilities when performing an assurance engagement of the ESEF reporting, see: https://revisorforeningen.no/revisjonsberetninger
BDO AS
Børre Skisland State Authorised Public Accountant (This document is signed electronically)
Independent Auditor's Report PetroNor E&P ASA - 2021 page 4 of 4
| 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 |
| CPP | Production sharing contract, "Contrat de Partage de Production" in French |
| CPR | Competent Person's Report |
| Group or PetroNor Group | PetroNor E&P Limited and its subsidiaries |
| IOR | Improved oil recovery |
| MMbbl | Million barrels of oil |
| MMBOE | Million barrels of oil equivalent |
| Mmscfd | Million standard cubic feet per day |
| PDP | Proven Developed Producing (reserves) |
| PSC | Production sharing contract |
| SNPC | Société National des Pétroles du Congo |
Eyas Alhomouz, Chair Joseph Iskander Gro Kielland Ingvil Smines Tybring-Gjedde
Frøyas gate 13 0243 Oslo Norway Tel +47 22 55 46 07
Oslo Børs Ticker: PNOR ISIN: NO0011157232
Verdipapirservice Dronning Eufemias gate 30 0191 Oslo Norway
BDO AS Munkedamsveien 45, Vika Atrium 0121 Oslo Norway Tel +47 23 11 91 00
PetroNor E&P ASA petronorep.com
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