Annual Report • Apr 30, 2019
Annual Report
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Panoro Energy ASA is an independent exploration and production (E&P) company headquartered in London and listed on the Oslo Stock Exchange with ticker PEN. The Company holds production, development, and exploration assets in North and West Africa. The North African portfolio comprises the Sfax Offshore Exploration Permit (SOEP), the Ras El Besh concession and a participating interest in five producing oil field concessions in the region of the city of Sfax, onshore and shallow water offshore Tunisia. The operations in West Africa include the Dussafu License offshore southern Gabon and OML 113 offshore western Nigeria.
In addition to discovered hydrocarbon reserves and resources, the assets also hold significant exploration potential.
| Page | |
|---|---|
| Company Overview | 02 |
| CEO Letter | 05 |
| Annual statement of reserves 2018 | 06 |
| Annex reserves statement | 09 |
| Directors' report 2018 | 10 |
| Board of Directors | 23 |
| Senior Management | 25 |
| Consolidated statement of comprehensive income |
26 |
| Consolidated statement of financial position as at December 31, 2018 |
27 |
| Consolidated statement of changes in equity as at December 31, 2018 |
29 |
| Consolidated cash flow statement for the year ended December 31, 2018 |
30 |
| Notes to the consolidated financial statements |
31 |
| Panoro Energy ASA parent company income statement |
77 |
| Panoro Energy ASA parent company balance sheet |
78 |
| Panoro Energy ASA parent company statement of cash flow |
79 |
| Panoro Energy ASA notes to the financial statements |
80 |
| Declaration from the board of directors of panoro energy asa on executive remuneration policies |
88 |
| Statement of directors' responsibility | 91 |
| Auditor's report | 92 |
| Statement on corporate governance in Panoro Energy ASA |
96 |
| Corporate social responsibility/ | 101 |
| Ethical code of conduct | |
| Glossary and definition | 103 |
| Key Figures | 2018 | 2017 |
|---|---|---|
| EBITDA (USD million) | (1.9) | (5.3) |
| EBIT (USD million) | (5.8) | (36.0) |
| Net profit/(loss) (USD million) | (7.0) | (36.6) |
| 2P Reserves (MMBOE) | 28.8 | 21.6 |
| 2C Contingent Resources (MMBOE) | 5.9 | 2.6 |
| Share price at end of financial year (NOK) | 12 | 6.20 |
Completion of transactions in Tunisia and first oil at Dussafu have materially transformed Panoro
6-fold increase in net production from January 2018 to January 2019. Current net group production of approximately 2,500 bopd (prior to royalty and tax)
London (UK) Oslo (Norway) Nigeria Tunisia Gabon
| Interest in TPS assets, current production stable at circa. 1,200 bopd net to Panoro |
29.4% |
|---|---|
| Interest in the Sfax Offshore Exploration Permit ("SOEP") – Operator |
52.5% |
| Non-operated interest in the Hammamet Offshore Exploration Permit (under relinquishment) |
27.6% |
| Gabon: | |
| Interest in Dussafu Marin permit, offshore |
8.33% |
| Nigeria: |
Detailed information on all the assets is included in the Operations section of the Directors report on page 10.
The Company maintains its registered address in Oslo with offices in London (Headquarter) and Tunis.
2018 has been a transformational year for Panoro Energy. In line with our announced strategy, we have completed both organic and external growth initiatives that have transitioned Panoro into a full-cycle exploration and production company. We have delivered two major steps in the execution of Panoro's strategy of value creation. First, Dussafu, offshore Gabon, was brought onstream in September 2018, and we completed two consecutive acquisitions in Tunisia in the second half of the year.
Achieving first oil at Tortue in Gabon has been a material milestone for Panoro, having been involved in the progression of the Dussafu PSC, from oil discoveries, to seismic acquisition and interpretation, and now to first commercial production. The Phase 1 development at Dussafu was completed on time and on budget and we are now moving forward with Phase 2. We have also been able to materially increase our reserves and resources in addition to de-risking the significant exploration potential through the drilling of a successful appraisal well at Tortue and an exploration well at Ruche North East. Focus now continues into Tortue Phase 2 and planning for the Phase 3 development in the Ruche area.
During the year we have diversified our portfolio by entering Tunisia, with the successive acquisitions of DNO Tunisia AS and then OMV Tunisia Upstream GmbH, both companies holding high quality assets together with a first-class operating organisation. These acquisitions represent a substantial milestone and the continuation of Panoro's strategy to build a full-cycle independent E&P company.
The key asset in DNO Tunisia AS (now renamed Panoro Tunisia Exploration AS) is the Sfax Offshore Exploration Permit (SOEP), a 3,228 km2 exploration permit offshore Tunisia with 400 million barrels already produced in surrounding blocks, and close to existing infrastructure and producing fields. Panoro is working with ETAP, the Tunisian national oil company, to plan to drill the Salloum West-1 well before the end of 2019. The in-country skilled team provides us with a fully functional and sizeable organisation to take advantage of future low-cost producing growth opportunities.
Following the acquisition of DNO Tunisia AS, we expanded further into Tunisia with the purchase of OMV Tunisia Upstream GmbH (now renamed Panoro Tunisia Production GmbH) which has a 49% interest in five oil producing concessions in Tunisia, Guebiba/El hajib, Rhemoura, El Ain, Cercina and Cercina South, all adjacent to SOEP. These five high-quality oil producing concessions hold net 2P reserves of 4.7 million barrels and net production to Panoro of approximately 1,200 bopd. The acquired company also owns 50% of Thyna Petroleum Services S.A. ("TPS"), which serves as the operating company for the five oil producing concessions.
In addition to the strong support of our shareholders, we have been able to establish two strategic partnerships, with Beender Petroleum and Mercuria Energy, to manage and finance the consecutive Tunisian acquisitions.
Following the 2018 events, we now hold offshore and onshore producing assets in three countries, across many different wells. We also have material exploration potential upside that we intend to unlock. And importantly, we are now an operator with a skilled and experienced team to assist in achieving our ambitious growth objectives.
Headline numbers speak for themselves. Panoro's production has increased 6-fold year on year while oil reserves have increased 4-fold (33% on total 2P reserves). With current production at approximately 2,500 bopd net to Panoro we have established an attractive platform to continue pursuing selective deals.
Finally, we would like to wholeheartedly thank our existing and new shareholders, our strategic partners, our dedicated staff and more generally all our stakeholders for their continued support.
John Hamilton CEO, Panoro Energy ASA
Panoro's classification of reserves and resources complies with the guidelines established by the Oslo Stock Exchange and are based on the definitions set by the Petroleum Resources Management System (PRMS), sponsored by the Society of Petroleum Engineers/ World Petroleum Council/ American Association of Petroleum Geologists/ Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) as issued in June 2018.
Reserves are the volume of hydrocarbons that are expected to be produced from known accumulations:
Reserves are also classified according to the associated risks and probability that the reserves will be actually produced.
1P – Proved reserves represent volumes that will be recovered with 90% probability
2P – Proved + Probable represent volumes that will be recovered with 50% probability
3P – Proved + Probable + Possible volumes that will be recovered with 10% probability.
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 recognized as subjective processes of estimating hydrocarbon volumes that cannot be measured in an exact way.
It should also be recognized that results of recent and future drilling, testing, production and new technology applications may justify revisions that could be material.
Certain assumptions on the future beyond Panoro's control have been made. These include assumptions made regarding market variations affecting both product prices and
investment levels. As a result, actual developments may deviate materially from what is stated in this report.
The estimates in this report are based on third party assessments prepared by Netherland Sewell and Associates Inc. (NSAI) in January 2019 for Dussafu, by Gaffney Cline & Associates Limited (GCA) in November 2018 for the TPS assets and by AGR TRACS International Ltd. (AGR TRACS) in March 2019 for Aje.
As of year-end 2018, Panoro had three assets with reserves and contingent resources, OML 113, the TPS Assets and the Dussafu Permit. A summary description of these assets with status as of year-end 2018 is included below. In addition we refer to the company's web-site for background information on the assets. Unless otherwise specified, all reserves figures quoted in this report are net to Panoro's interest.
Dussafu is a development and exploitation license covering an area containing several oil fields, the most recent discoveries being the Ruche, Tortue and Ruche North East fields. In 2014 an Exclusive Exploitation Authorization (EEA) for an 850.5 km2 area within the Dussafu PSC was awarded.
A Field Development Plan for the EEA area was subsequently approved and a final decision to start developing the license was taken in 2017. The first field in the EEA area, Tortue, started oil production in 2018.
Production from the Tortue field during 2018 amounted to 1.2 MMbbls gross, which is approximately 0.08 MMbbls net to Panoro.
In January 2019 NSAI certified (3rd party) gross 1P Proved Reserves of 25.9 MMbbls in the Gamba and Dentale reservoirs of the Tortue field. Gross 2P Proved plus Probable Reserves at Tortue amounted to 35.1 MMbbls in the same reservoirs. Gross 3P Proved plus Probable plus Possible Reserves at Tortue amounted to 48.3 MMbbls.
In addition to these Reserves NSAI also certified gross 1C Contingent Resources of 1.3 MMbbls, gross 2C Contingent Resources of 13.6 MMbbls, and gross 3C Contingent Resources of 20.6 MMbbls in the Tortue field. The remaining Dussafu fields excluding Tortue have gross 2C Contingent Resources of approximately 37.4 MMbbls (taken from Panoro's 2017 ASR and Operator's estimates).
These evaluations yield 1P Proved Reserves net to Panoro of 1.74 MMbbls, 2P Proved plus Probable Reserves net to Panoro of 2.20 MMbbls and 3P Proved plus Probable plus Possible Reserves net to Panoro of 2.86 MMbbls. Additional Contingent Resources net to Panoro are approximately 0.1 MMbbls 1C, 0.9 MMbbls 2C and 1.3 MMbbls 3C. The remaining Dussafu fields excluding Tortue have net 2C Contingent Resources of approximately 2.4 MMbbls (taken from Panoro's 2017 ASR and Operator's estimates). These Reserves and Contingent Resources are Panoro's net volumes after deductions for royalties and other taxes, reflecting the production and cost sharing agreements that govern the asset.
The TPS Assets comprise five oil field concessions in the region of the city of Sfax, onshore and shallow water offshore Tunisia. The concessions are Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba.
The oil fields were discovered in the 1980's and early 1990's and have produced a total of around 54 million barrels of oil to date. The current production is stable at around 4,000 barrels of oil per day gross.
In November 2018 GCA certified (3rd party) reserves and resources from the fields which, after taking account of 2018 production, amount to 1P Proved Reserves of 8.4 MMbbls, 2P Proved plus Probable Reserves of 18.4 MMbbls and 3P Proved plus Probable plus Possible reserves of 25.0 MMbbls. Panoro's net entitlement 1P Proved reserves are 2.1 MMbbls, 2P Proved plus Probable are 4.7 MMbbls and 3P Proved plus Probable plus Possible are 6.4 MMbbls.
In addition to these reserves, GCA also certified gross 1C Contingent Resources of 1.4 MMbbls, 2C Contingent Resources of 5.0 MMbbls and 3C Contingent Resources of 10.3 MMbbls, all assigned to the Cercina oil field. Panoro's net entitlement 1C Contingent Resource is 0.4 MMbbls, net entitlement 2C Contingent Resource is 1.3 MMbbls and net entitlement 3C Contingent Resource is 2.6 MMbbls.
The OML 113 license, close to the border with Benin, contains the Aje field which is predominantly a Turonian age gas discovery with significant condensate and an oil rim but also contains a separate Cenomanian age oil leg. The Cenomanian oil has been on production since 2016, and the Turonian oil rim since 2017.
Production during 2018 from the Aje field amounted to 1.0 MMbbls gross which equates to approximately 0.1 MMbbls net to Panoro.
A Field Development Plan (FDP) for Aje Gas was submitted to the Nigerian Government for consideration in 2017. The FDP
comprises four or five production wells in the Turonian tied back to existing and new infrastructure.
In March 2019 AGR TRACS certified (3rd party) gross total 1P Proved Reserves of 82.4 MMBOE in the Aje field. Gross 2P Proved and Probable reserves for the field amounted to 138.2 MMBOE. Gross 3P Proved, Probable and Possible reserves for the field amounted to 220.8 MMBOE. Panoro's net entitlement 1P Proved Reserves was 12.8 MMBOE, net entitlement 2P Proved and Probable Reserves was 21.9 MMBOE and net entitlement 3P Proved, Probable and Possible Reserves was 31.2 MMBOE.
AGR TRACS further sub-categorized these reserves as Developed Producing (reserves from existing wells in the field) and Justified for Development.
In addition to these reserves AGR TRACS also certified gross 1C Contingent Resources of 4 MMBOE, 2C Contingent Resources of 9 MMBOE and 3C Contingent Resources of 17.5 MMBOE. Panoro's net entitlement 1C Contingent Resources is 0.5 MMBOE, net entitlement 2C Contingent Resources is 1.1 MMBOE and net entitlement 3C Contingent Resources is 2.1 MMBOE.
Panoro uses the services of NSAI, GCA and AGR TRACS for 3rd party verifications of its reserves and resources.
All evaluations are based on standard industry practice and methodology for production decline analysis and reservoir modelling based on geological and geophysical analysis. The following discussions are a comparison of the volumes reported in previous reports, along with a discussion of the consequences for the year-end 2018 ASR:
Dussafu: In 2018, the Tortue field started production from 2 wells as phase 1 of the project. A decision was made in 2019 to drill an additional 4 wells in the field, which will constitute phase 2. The revised NSAI reserves report assumes production from the phase 1 and phase 2 wells, for a total of 6 development wells in the field. The remaining fields in Dussafu (Ruche, Ruche North East, Walt Whitman and Moubenga) are still classified as Contingent Resources. A decision to develop these fields will trigger a re-assignment of these resources as reserves and a possible re-determination of their volumes.
TPS: There are Contingent Resources associated with the Cercina field in the TPS assets. These resources may be reassigned as reserves if a development decision is taken to drill certain un-drilled compartments within the Cercina field.
Aje: The first phase of the Aje Cenomanian oil development started in 2016 with production from two wells. In 2017 the Aje-5 well workover and side-track campaign resulted in a recompletion of the well in the Turonian oil rim. The previous estimates of reserves in Aje were revised by AGR TRACS in 2018 and 2019. The revisions incorporate the 2018 historical production data from the Aje-4 and Aje-5ST2 wells. The result is an increase in net 2P reserves of 2.0 MMbbls compared to the year-end 2017 Annual Statement of Reserves ASR.
The commerciality and economic tests for the Dussafu reserves volumes were based on an average oil price over the field life of USD83/Bbl.
The commerciality and economic tests for the TPS assets reserves volumes were based on an average oil price over the life of the field of USD78/Bbl.
The commerciality and economic tests for the Aje reserves volumes were based on an oil and condensate price of USD60/Bbl, a LPG price of USD39/Bbl, and a gas price of USD4/MMBtu.
| 2P Reserves Development | (MMBOE) |
|---|---|
| Balance (previous ASR –December 31, 2017) | 21.6 |
| Production 2018 | (0.2) |
| New developments since previous ASR | 4.7 |
| Revisions of previous estimates | 2.7 |
| Balance (revised ASR) as of December 31, 2018 | 28.8 |
Panoro'stotal1P reservesatendof2018 amountto16.6 MMBOE. Panoro's 2P reserves amount to 28.8 MMBOE and Panoro's 3P reserves amount to 40.4 MMBOE. Thisreflects the March 2019 reserve report for the Aje field, conducted by AGR TRACS, the January 2019 reserve report for the Dussafu field, conducted by NSAI and the November 2018 reserve report for the TPS assets conducted by CGA.
Panoro's Contingent Resource base includes discoveries of varying degrees of maturity towards development decisions. By end of 2018, Panoro's assets contain a total 2C volume of approximately 5.9 MMBOE.
April 30, 2019
John Hamilton CEO
| December 31, 2018 | Interest | 1P (Low Estimate) | 2P (Base Estimate) | 3P (High Estimate) | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| % | Liquids | Gas | Total | Net | Liquids | Gas | Total | Net | Liquids | Gas | Total | Net | |
| MMbbl | Bcf | MMBOE MMBOE | MMbbl | Bcf | MMBOE MMBOE | MMbbl | Bcf | MMBOE | MMBOE | ||||
| On Production | |||||||||||||
| Aje Field Oil | 12.1913 | 2.05 | - | 2.05 | 0.25 | 2.25 | - | 2.25 | 0.27 | 2.43 | - | 2.43 | 0.30 |
| Tortue Field | 8.333 | 25.86 | - | 25.86 | 1.74 | 35.12 | - | 35.12 | 2.20 | 48.32 | - | 48.32 | 2.86 |
| Cercina Field | 29.4 | 3.13 | - | 3.13 | 0.81 | 7.43 | - | 7.43 | 1.93 | 9.73 | - | 9.73 | 2.53 |
| El Hajeb / Guebiba Field |
29.4 | 5.05 | - | 5.05 | 1.25 | 8.25 | - | 8.25 | 2.04 | 11.75 | - | 11.75 | 2.91 |
| Gremda / El Ain Field | 29.4 | 0.00 | - | 0.00 | 0.00 | 2.10 | - | 2.10 | 0.55 | 2.70 | - | 2.70 | 0.70 |
| Rhemoura Field | 29.4 | 0.27 | - | 0.27 | 0.06 | 0.67 | - | 0.67 | 0.16 | 0.87 | - | 0.87 | 0.21 |
| Total | 36.36 | - | 36.36 | 4.12 | 55.82 | - | 55.82 | 7.16 | 75.80 | - | 75.80 | 9.51 | |
| Aje Field Oil | 12.1913 | 1.11 | - | 1.11 | 0.17 | 2.48 | - | 2.48 | 0.38 | 4.17 | - | 4.17 | 0.61 |
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Aje Field Cond. | 12.1913 | 10.32 | - | 10.32 | 1.58 | 17.41 | - | 17.41 | 2.73 | 27.87 | - | 27.87 | 4.05 |
| Aje Field LPG | 12.1913 | 20.11 | - | 20.11 | 3.14 | 33.86 | - | 33.86 | 5.38 | 54.39 | - | 54.39 | 7.66 |
| Aje Field Gas | 12.1913 | - | 292.70 | 48.78 | 7.62 | - | 492.80 | 82.13 | 13.12 | - | 791.90 | 131.98 | 18.58 |
| Total | 31.54 | 292.70 | 80.32 | 12.51 | 53.75 | 492.80 | 135.88 | 21.61 | 86.43 | 791.90 | 218.41 | 30.90 |
| Total Reserves | 67.90 | 292.70 | 116.68 | 16.63 | 109.57 | 492.80 | 191.70 | 28.77 | 162.23 | 791.90 | 294.21 | 40.41 | ||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| -- | ---------------- | -- | ------- | -------- | -------- | ------- | -------- | -------- | -------- | ------- | -------- | -------- | -------- | ------- |
| 2P Reserves Development | (MMBOE) |
|---|---|
| Balance (previous ASR –December 31, 2017) | 21.6 |
| Production 2018 * | (0.2) |
| Acquisitions/disposals since previous ASR ** | 4.7 |
| Extensions and discoveries since previous ASR | 0.0 |
| New developments since previous ASR | 0.0 |
| Revisions of previous estimates *** | 2.7 |
| Balance (revised ASR) as of December 31, 2018 | 28.8 |
| Asset | 2C MMBOE (as of YE2017) |
2C MMBOE (as of this report) |
|---|---|---|
| Aje | 1.1 | 1.1 |
| Dussafu | 1.5 | 3.3 |
| Cercina | - | 1.5 |
| Totals | 2.6 | 5.9 |
* Represents Aje and Tortue field production in 2018
** Acquisition of TPS Assets, reserves as of year end 2018
*** Revisions to Aje and Tortue reserve estimates
Panoro Energy ASA is an independent E&P company based in London and listed on the Oslo Stock Exchange with ticker PEN. The Company holds high quality exploration and production assets in Africa, with oil production from fields in Tunisia, Gabon and Nigeria.
During the fourth quarter in 2018, the Company entered into a joint arrangement through a shareholder agreement with Beender Petroleum Tunisia Limited ("Beender"), whereby Panoro and Beender jointly own and control 60% and 40% respectively of Sfax Petroleum Corporation AS ("Sfax Corp"). Sfax Corp, through its subsidiaries holds 100% shares of Panoro Tunisia Production AS ("PTP") and Panoro Tunisia Exploration AS ("PTE"). These two companies (PTP and PTE) hold between them the investments in Tunisia. As such, all numbers and volume information relating to the Company's Tunisian operations and transactions represents the Group's 60% interest, unless otherwise stated.
In July 2018, Panoro acquired DNO Tunisia AS and as a consequence Panoro is now the Operator of the Sfax Offshore Exploration Permit ("SOEP"), an exploration license offshore Tunisia. Panoro's current interest in the license is 52.5%. SOEP lies in the prolific oil and gas Cretaceous and Eocene carbonate platforms of the Pelagian Basin offshore Tunisia. In the vicinity of the Permit area are numerous existing producing fields with infrastructure and spare capacity in pipelines and facilities. There are three oil discoveries on the permit, Salloum, Ras El Besh, and Jawahra, with gross recoverable oil estimated by the former operator of 20 million barrels. In addition to these discoveries there is considerable exploration potential in the Permit, and the previous operator's P50 unrisked gross estimate was 250 million barrels. Panoro also has a 52.5% interest in the Ras El Besh Concession which is within the area of the SOEP.
The 1st renewal period of SOEP expired in December 2018 and, as a precondition to entry into a 2nd renewal period for an additional 3 year term, Panoro has agreed to fulfil the outstanding drilling obligation in 2019. Consequently, Panoro is proposing to drill the Salloum West-1 well ("SAMW-1") in order to fully satisfy the commitment well. Panoro is currently working closely with its partner ETAP regarding the technical program and the formalisation of drilling plans including the well planning, location and necessary approvals for drilling.
The primary target of the SAMW-1 well is the Bireno formation, at approximately 3,200 metres vertical depth, where Panoro has identified, on 2D and 3D seismic data, what it believes to be an independent block located west of the discovered Salloum structure. The SAMW-1 well will target an independent fault compartment up-dip from the Salloum-1 well, which was drilled by British Gas in 1992 and had a short test in the Bireno formation at a rate of 1,846 bopd.
The objective of the SAMW-1 well is to prove up additional resources in the vicinity of the Salloum-1 well and to aggregate them in order to fast-track the development of Salloum through a tie-in to existing adjacent oil infrastructure. Therefore, following successful drilling, options are also being considered for bringing the SAMW-1 well on stream as an extended well test.
In December 2018, Panoro acquired the TPS Assets from OMV. The TPS Assets comprise five oil field concessions in the region of the city of Sfax, onshore and shallow water offshore Tunisia. The concessions are Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba.
The oil fields were discovered in the 1980's and early 1990's and have produced a total of around 54 million barrels of oil to date. The current gross production is stable at around 4,000 barrels of oil per day. Approximately 50 wells have been drilled in the TPS fields to date, whilst some of these wells have been abandoned, 14 remain on production with 5 wells currently shut-in awaiting workovers or reactivation. Two wells are used for disposal of produced water. Production facilities consist of the various wellhead installations, connected via intra-field pipelines to processing, storage and transportation systems. Crude is transported to a storage and export terminal about 70 km south of the Assets at La Skhira.
PTP indirectly owns a 49% interest in the fields and a 50% interest in the TPS operating company. The remaining
interests are held by the Tunisian State Oil Company, ETAP. Panoro's net interest in TPS operations is 29.4%.
In November 2018, GCA (3rd party) certified gross reserves and resources from the fields which, after taking account of 2018 production, amount to 1P Proved Reserves of 8.4 MMbbls, 2P Proved plus Probable Reserves of 18.4 MMbbls and 3P Proved plus Probable plus Possible reserves of 25.0 MMbbls. Panoro's net entitlement 1P Proved reserves are 2.1 MMbbls, 2P Proved plus Probable are 4.7 MMbbls and 3P Proved plus Probable plus Possible are 6.4 MMbbls.
In addition to these reserves, GCA also certified gross 1C Contingent Resources of 1.4 MMbbls, 2C Contingent Resources of 5.0 MMbbls and 3C Contingent Resources of 10.3 MMbbls, all assigned to the Cercina oil field. Panoro's net entitlement 1C Contingent Resource is 0.4 MMbbls, net entitlement 2C Contingent Resource is 1.3 MMbbls and net entitlement 3C Contingent Resource is 2.6 MMbbls.
Panoro Energy are partners in the Dussafu block, a production and development license in southern Gabon, operated by BW Energy Gabon. Panoro's current interest in the license is 8.333%.
The Dussafu block lies at the southern end of the South Gabon sub-basin in water depths ranging from 100 – 500 metres. The block contains a producing field and multiple discoveries and undrilled structures lying within a proven oil and gas play fairway within the Southern Gabon Basin. Most of the block lies in less than 200 m of water and has been explored since the 1970s. To the north west of the block is the Etame-Ebouri trend, a collection of fields producing from the pre-salt Gamba and Dentale sandstones, and to the north are the Lucina and M'Bya fields which produce from the syn-rift Lucina sandstones beneath the Gamba.
In 2014 a 850 km2 area of the Dussafu exploration block was converted into an Exclusive Exploitation Authorisation ("EEA") area, the remaining area outside of the EEA was subsequently relinquished. There are five oil fields within the Dussafu EEA area: Moubenga, Walt Whitman, Ruche, Ruche North East and Tortue. The latter three fields were discovered by Panoro and JV partners in the last 7 years.
The first field to be developed in the Dussafu EEA area is the Tortue field. Development activities started in 2018 with the drilling of two horizontal oil production wells, DTM-2H and DTM-3H in the Gamba and Dentale reservoirs. The installation of subsea production equipment at Tortue and commissioning of a Floating Production, Storage and Offloading (FPSO) vessel, the BW Adolo, was carried out in Q3 2018. First oil was achieved at the field in September 2018 and production performance has been in line with expectations and at year end had stabilised at approximately 12,500 bopd (gross). Total cumulative gross oil produced from the Tortue field amounted to 1.23 million barrels from production startup in September to the end of 2018.
As part of the Tortue field development well drilling campaign, an appraisal sidetrack, DTM-3, was drilled in May 2018 and successfully appraised the northern flank of the Tortue field in both the Gamba and Dentale reservoirs. In addition, in August 2018, the Ruche North East Marin-1 ("DRNEM-1") exploration well was drilled to the north east of the Ruche field and discovered oil in the Gamba and Dentale reservoirs.
In early 2019, following the success of the phase 1 activities at Tortue, a decision was taken to commence phase 2 of the development. Tortue phase 2 will consist of four additional horizontal production wells in the Gamba and Dentale reservoirs to bring the total production well count to 6. It is estimated that phase 2 production will commence in early 2020 and once all wells are on-stream the Operator estimates that field will have peak production of between 15,000 and 25,000 bopd (gross).
The second field planned to be developed in the Dussafu EEA is the Ruche Complex. The Ruche field, discovered by Panoro in 2011, together with the Ruche North East field, newly discovered in 2018, form the Ruche Complex. The Operator now estimates that the Ruche Complex holds a total of approximately 30 million barrels of recoverable reserves. A plan for developing this oil via a wellhead platform tied back to the BW Adolo FPSO at Tortue is being conceptualised. It is expected that a decision will be taken to develop the Ruche Complex by early 2020.
Following the successful 2018 development and appraisal drilling campaign at Tortue, production startup at the field, and planned phase 2 development activities, Netherland, Sewell and Associates, Inc. (NSAI), the reserves auditors for the project, have now updated their estimates for recoverable reserves at the field. The Contingent Resources from the western flank of the field have been re-classified as reserves. After taking account of 2018 production and, as of end of 2018, the gross 1P Proved Reserves at Tortue are now 25.9 MMbbls in the Gamba and Dentale reservoirs of the Tortue field. Gross 2P Proved plus Probable Reserves at Tortue
amount to 35.1 MMbbls and the gross 3P Proved plus Probable plus Possible Reserves at Tortue amount to 48.3 MMbbls. Reserves have therefore increased by approximately 50% compared to year end 2017. These Reserves estimates are for a total of 6 wells at Tortue. In addition to these Reserves NSAI also certified year-end 2018 gross 1C Contingent Resources of 1.3 MMbbls, gross 2C Contingent Resources of 13.6 MMbbls and gross 3C Contingent Resources of 20.6 MMbbls in the Tortue field.
At year end Panoro's net entitlement fraction of the gross Tortue field reserves, after deduction of Government share of production and royalties, was 2P Proved plus Probable Reserves of 2.2 MMbbls with additional 2C Contingent Resources of 0.9 MMbbls for Tortue field and 2.4 MMbbls for the rest of the licence excluding Tortue.
Covering an area of 840 km2 , OML 113 is operated by Yinka Folawiyo Petroleum Limited and is located in the western part of offshore Nigeria, adjacent to the Benin border. The license contains the producing Aje field as well as a number of exploration prospects. The Aje field was discovered in 1996 in water depths ranging from 100-1,000 metres. Unlike the majority of Nigerian Fields which are productive from Tertiary age sandstones, Aje has multiple oil, gas and gas condensate reservoirs in the Turonian, Cenomanian and Albian age sandstones. Five wells have been drilled to date on the Aje field. Aje-1 and Aje-2 tested oil and gas condensate at high rates from the Turonian and Cenomanian reservoirs and Aje-4 confirmed the productivity of these reservoirs and discovered an additional deeper Albian age reservoir. Aje-5 was drilled in 2015 as a development well to produce from the Aje oil reservoirs. The OML 113 license has full 3D seismic coverage from surveys acquired in 1997 and 2014.
Production at the Aje field started in 2016. Aje currently has 2 wells on production, Aje-4 and Aje-5, which were completed as producers in the Cenomanian reservoir in 2015. Aje-5 was side-tracked and re-completed as a producer in the Turonian
oil rim in 2017. Oil is processed, stored and exported at the Front Puffin FPSO via a subsea production system. These two wells comprise the first phase of the Aje field development project. During 2018 the Aje field produced a total of 131,000 barrels net to Panoro at an average rate of approximately 358 bopd net.
In 2017, a Turonian Gas Field Development Plan (FDP) was submitted to Nigerian regulators for consideration. The FDP comprises four or five production wells in the Turonian tied back to existing and new infrastructure. The OML 113 lease was renewed in June 2018 for a period of twenty years, subject to the satisfaction of customary financial conditions and a commitment to exploit the Turonian gas potential.
In March 2019, AGR TRACS International (TRACS) prepared an updated CPR for the Aje field. The stronger than expected production from the Aje-4 and Aje-5 wells has resulted in an increase in oil reserves at the field.
TRACS has estimated gross 1P Reserves of 82.4 MMBOE, gross 2P Reserves of 138.2 MMBOE and gross 3P reserves of 220.8 MMBOE.
At year-end 2018, 2P Reserves net to Panoro's interest related to OML 113, after deduction of royalties and other adjustments, stood at 21.9 MMBOE and 2C Contingent Resources stood at 1.1 MMBOE. This is an increase in 2P reserves of 1.9 MMBOE compared to year-end 2017.
In Brazil, termination agreements for the surrender of Coral and Cavalho Marinho licences have been signed between the JV partners and Brazilian Regulator ANP. The next steps involve various regulatory clearances before dissolution of JV operations. The Company's formal exit from its historical Brazilian business is still ongoing with slow progress towards the approval of abandonment by the Brazilian regulators. Management is working actively with the operator Petrobras to bring matters to a close and to ensure that the ongoing costs are kept to a minimum. However, the timing and eventual costs of such conclusion is uncertain at this stage.
The Board of Directors confirms that the annual financial statements have been prepared pursuant to the going concern assumption, in accordance with §3-3a of the Norwegian Accounting Act, and that this assumption was realistic as at the balance sheet date. The going concern assumption is based upon the financial position of the Company and the development plans currently in place. In the Board of Directors' view, the annual accounts give a true and fair view of the group's assets and liabilities, financial position and results. Panoro Energy ASA is the parent company of the Panoro Group. Its financial statements have been prepared on the assumption that Panoro Energy will continue as a going concern and realization of assets and settlement of debt in normal operations.
2018 has been a transformation year for the Company with two significant acquisitions in Tunisia. Refer to Note 12 for details of the acquisitions. The Tunisian acquisitions have been structured through a shareholder agreement with Beender Petroleum Tunisia Limited ("Beender"), whereby Panoro and Beender jointly own and control 60% and 40% respectively of Sfax Petroleum Corporation AS ("Sfax Corp"). Sfax Corp, through its subsidiaries, holds 100% shares of Panoro Tunisia Production AS ("PTP") and Panoro Tunisia Exploration AS ("PTE"). As such, all numbers and volume information relating to the Company's Tunisian operations and transactions represents the Company's 60% interest, unless otherwise stated. Details are referred to in Note 12.
The Company on a consolidated basis, had USD 23.4 million in cash and cash equivalents as of December 31, 2018 and debt of USD 28.9 million. In July 2018, the Company successfully completed a Private Placement ("Placement 1") in conjunction with the DNO Transaction, through issue of 4,250,219 new shares and 1,000,000 treasury shares each at NOK 12.82 per share and raising USD 8.3 million (NOK 67 million) in gross proceeds. In December 2018, to fund the acquisition of producing assets in Tunisia from OMV and ongoing Dussafu operations, the Company successfully completed another private placement ("Placement 2") by issuing 15,580,000 new shares each at NOK 16.10 per share to the subscribers. The Placement 2 raised USD 30 million (NOK 250 million) in gross proceeds.
This was also supplemented by debt financing of USD 16.2 million through Mercuria, a world leader in trading of physical energy products and dry bulk commodities. More details of both of these events can be found below in the Funding section of this report.
Panoro Energy ASA prepares its financial statements in accordance with the International Financial Reporting Standards (IFRS), as provided for by the EU and the Norwegian Accounting Act.
The consolidated accounts are presented in US dollars.
The below analysis compares 2018 with 2017 figures:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Continuing operations | ||
| Oil revenue | 12,090 | 6,021 |
| Other revenue | 877 | 497 |
| Total revenues | 12,967 | 6,518 |
| Expenses | ||
| Operating costs | (8,595) | (6,858) |
| Exploration related costs | (661) | (343) |
| Non-recurring costs | (965) | (995) |
| General and administrative costs | (4,655) | (3,655) |
| Total operating expenses | (14,876) | (11,851) |
| EBITDA | (1,909) | (5,333) |
| Depreciation | (3,568) | (1,898) |
| Asset write-off and impairment | - | (28,576) |
| Share based payments | (331) | (149) |
| EBIT | (5,808) | (35,956) |
| Net financial items | (279) | (360) |
| Loss before taxes | (6,087) | (36,316) |
| Income tax benefit / (expense) | (877) | 4 |
| Net loss from continuing operations | (6,964) | (36,312) |
| Net income / (loss) from discontinued operations |
(143) | (277) |
| Net income / (loss) for the year | (7,107) | (36,589) |
From a financial statements perspective, the closure of operations in Brazil is disclosed as "discontinued operations" and as such has been reported separately from the "continuing business activities".
Panoro Energy reported an EBITDA of negative USD 1.9 million for the year ended December 31, 2018, compared to negative USD 5.3 million in the same period in 2017.
EBITDA includes the oil and gas revenue from three liftings from the Aje field and one lifting from Dussafu during 2018 with the associated operating costs.
Oil revenue during the year ended December 31, 2018 was USD 12.1 million generated through the sale of net volume of 142,761 bbls at Aje and 45,853 bbls at Dussafu. This compares to revenue of USD 6.0 million in the same period of 2017 from the sale of 113,367 bbls at Aje. Under the terms of the Dussafu PSC, the State profit oil is shown as revenue (USD 0.9 million), this is reflected in other revenue in 2018, with a corresponding amount as income tax (Note 6). Other revenue in 2017 related to the gain on disposal of the sale of 25% stake in Dussafu.
Panoro Energy reported a net loss of USD 7.0 million from continuing operations for the year ended December 31, 2018, a decrease in loss of USD 29.3 million compared to a loss of USD 36.3 million in the same period in 2017. USD 28.5 million of this decrease was due to net impairment charges recognised in 2017.
Exploration related costs increased to USD 0.7 million in the year ended December 31, 2018, up from USD 0.3 million for the same period in 2017.
General & Administrative (G&A) costs from continuing operations were USD 4.7 million in the year ended December 31, 2018, up from USD 3.7 million for the same period in 2017, reflecting the inclusion of new business activities undertaken during 2018. Non-recurring costs of USD 1 million in 2018 primarily relate to acquisition projects which has been expensed as incurred. Non-recurring costs of USD 1 million during the year ended December 31, 2017 were costs directly attribute to the Aje dispute.
Depreciation for the year was USD 3.6 million, increasing from USD 1.9 million in the same period in 2017, predominantly relating to the depreciation of the Aje Cenomanian oil field in both periods. 2018 also includes the depreciation for the Tortue oil field, following first oil in September 2018.
EBIT from continuing operations was thus a negative USD 5.8 million for the year ended December 31, 2018, compared to a negative USD 36.0 million for the same period of 2017. The change predominantly relates to the inclusion of impairment charges on Aje field in 2017.
Net financial items amounted to an expense of USD 0.3 million for the year compared to an expense of USD 0.4 million in the same period in 2017. Net financial items include forex loss of USD 0.5m (2017: gain of USD 0.3 million), accretion of notional interest on the Aje and Dussafu Asset Decommissioning Liability and finance charges, offset by an unrealised gain on
fair valuation of commodity hedges of USD 0.8 million in 2018 (2017: nil).
Loss before tax from continuing activities was USD 6.1 million for the year ended December 31, 2018, compared to the loss of USD 36.3 million for the same period in 2017. The higher loss in 2017 resulted from impairment charges on Aje field.
Net loss for the year from discontinued operations in Brazil was USD 0.1 million for the current period, compared to a net loss of USD 0.3 million for the same period in 2017.
The total net loss for the year ended December 31, 2018 was USD 7.1 million, compared to a net loss of USD 36.6 million for the same period in 2017.
Minor movement in respective periods to other comprehensive income was a result of currency translation adjustments for reporting purposes.
Non-current assets amounted to USD 89.3 million at December 31, 2018, an increase of USD 63.9 million from December 31, 2017.
A significant portion of the movement in total non-current assets relates to the assets acquired through the acquisition of Panoro TPS (see Note 12.3). Capital additions during the year include USD 17.8 million for Dussafu and USD 1.6 million related to Aje licence renewal cost, partially offset by the effect of the Dussafu and Aje depreciation charge of USD 3.5 million.
Other non-current assets increased to USD 0.2 from USD 0.1 million mainly relates to the tenancy deposit for UK office premises and the addition of Tunisian assets through acquisition.
Current assets amounted to USD 35.7 million as of December 31, 2018, compared to USD 9.8 million at December 31, 2017.
During the period, the Company completed the acquisitions of Panoro TPS (Note 12.3) and PTE (Note 12.2) and as such, assets across all line items have changed significantly.
During the year, two Equity Private Placements of Panoro's share capital were completed, raising gross proceeds of approximately USD 38.3 million, including the sale of the Company's treasury shares.
In addition, trade and other receivables stood at USD 5.6 million, an increase from USD 0.6 million at the end of December, 2017. This increase includes USD 2.6 million of a receivable from BW Energy from the first lifting at Dussafu, USD 0.2 million due to an underlift position at Dussafu at year end and USD 2.0 million of trade receivables acquired as noted in Note 12.3. USD 2.3 million has been accumulated and held as the cash cost of Dussafu and Aje crude oil inventory, also including USD 0.5 million for TPS concessions (Note 12.3). Materials inventory of USD 4.1 million comprises inventory of USD 0.9 million acquired as part of the acquisition of DNO
Tunisia AS (Note 12.2) and USD 2.7 million acquired as part of the OMV Tunisia Upstream GmbH acquisition (Note 12.3), and an additional USD 0.5 million being materials inventory held at Dussafu. As at December 31, 2018 USD 0.4 million was recognised in the Statement of Financial Position as current portion of fair value of the commodity hedges; there were no equivalent balances at December 31, 2017.
Consequently, cash and cash equivalents stood at USD 23.4 million at December 31, 2018, compared to USD 6.3 million at December 31, 2017.
Equity amounted to USD 46.3 million as of December 31, 2018, compared to USD 17.3 million at the end of December 2017. The change reflects completion of two Private Placements, the sale of the Company's treasury shares and the loss for the period.
Total non-current liabilities of USD 55.9 million as at December 31, 2018, compared to USD 11.1 million as at December 31, 2017.
The increase includes the non-recourse loan from BW Energy on Dussafu, which has now been split and reclassified into non-current (USD 9.4 million) and current (USD 3.7 million). As of December 31, 2018, Panoro's drawdown on the nonrecourse loan was at the loan facility's ceiling of USD 12.5 million, with an additional USD 0.6 million of accumulated interest, compared to USD 2.2 million as at December 31, 2017. The non-recourse loan became repayable through Panoro's allocation of the cost oil in accordance with the Dussafu PSC, after paying for the proportionate field operating expenses, following First Oil on Dussafu, achieved during the period. During the repayment phase, Panoro will still be entitled to its share of profit oil, as defined in the PSC, from the Dussafu operations.
Non-current liabilities also include the long-term portion of the Mercuria Senior Loan facility of USD 13.2 million (Note 5.1)
A decommissioning liability of USD 17 million has also been recognised following the acquisition of the TPS assets (Note 12.2). The remainder of the Decommissioning liability is for both the Aje and Dussafu fields, amounting to USD 3.7 million, following the oil production start-up at Dussafu during the period.
Other non-current liabilities include USD 6.8 million associated with historic cash calls on Aje, which will be settled from surplus funds, and where available, from Aje crude sales after paying for current costs and JV liabilities.
Current liabilities amounted to USD 22.8 million at December 31, 2018, compared to USD 6.8 million at the end of December 2017.
USD 3.7 million reflects the current portion of the Dussafu non-recourse loan, USD 2.5 million is the current portion of the Mercuria Senior Loan facility (Note 5.1). USD 1.9 million of other current liabilities and USD 5.8 million of corporation tax liabilities were both acquired as part of the acquisitions in Tunisia during 2018 (Note 12). Accruals and other liabilities
amounted to USD 7.5 million, compared to USD 6.7 million at the end of December 2017. This is due to an increase in the operational and corporate accruals.
Net cash flow from operating activities amounted to negative USD 5.3 million in 2018, compared to negative USD 2 million in 2017. The increase is primarily explained by higher costs throughout 2018 brought about by the significant acquisitions during the year and increased activity at Dussafu.
Net cash flow from investing activities was an outflow of USD 31.3 million compared to an inflow of USD 5.1 million in 2017. The net outflow on acquisitions during 2018 amounted to USD 44.4 million (net of cash acquired through acquisitions), partially offset by increase in non-recourse loan by USD 10.9 million. The net cash inflow in 2017 mainly related to the disposal of a 25% stake in Dussafu, offset by investment in oil and gas assets.
Net cash flow from financing activities during 2018 represented a cash inflow of USD 53.7 million predominantly comprising gross proceeds from equity placements of USD 38.4 million and net proceeds of USD 15.7 million from loans and borrowings. This compared to an outflow of USD 1.6 million in 2017.
Cash and cash equivalents thus increased to USD 23.4 million (December 31, 2017: USD 6.3 million).
| (Amounts in USD 000) | 2018 | 2017 |
|---|---|---|
| Total revenues | - | - |
| Operating expenses | ||
| General and administrative costs | (1,203) | (1,751) |
| Impairment of investment in subsidiary | (100) | (335) |
| Provision for Doubtful Receivables* | (11,520) | (32,885) |
| Total operating expenses | (12,823) | (34,971) |
| Earnings before interest and tax (EBIT) | (12,823) | (34,971) |
| Net interest and financial items | 9,037 | 9,293 |
| Loss before taxes | (3,786) | (25,678) |
| Income tax benefit / (expense) | - | - |
Net loss attributable to equity holders (3,786) (25,678)
*Provision for doubtful receivables owed from loans provided to subsidiaries. See Note 7 in the Parent Company Financial Statements
The Company on a consolidated basis, had USD 23.4 million in cash and cash equivalents as of December 31, 2018 and debt of USD 28.9 million. In July 2018, the Company successfully completed a Private Placement ("Placement 1") in conjunction with the DNO Transaction, through issue of 4,250,219 new shares and the sale of 1,000,000 treasury shares each at NOK 12.82 per share and raising USD 8.3 million (NOK 67 million) in gross proceeds. In December 2018, to fund the OMV Transaction and to fund ongoing Dussafu operations, the Company successfully completed another Private Placement ("Placement 2") by issuing 15,580,000 new shares each at NOK 16.10 per share to the subscribers. The Placement 2 raised USD 30 million (NOK 250 million) in gross proceeds.
Pursuant to the joint arrangement between Beender and Panoro discussed in the Tunisian Operations update section of this report, both parties contributed their respective share of investment in cash through subscribing equity shares of Sfax Corp.
Following this, on December 13, 2018, the Company entered into an agreement with Mercuria, whereby Mercuria provided a 60% owned subsidiary of the Company an acquisition loan facility comprising: i) a Senior Secured Loan facility of USD 27 million ("Senior Loan"), and ii) an additional Junior Loan facility for a further USD 8 million ("Junior Loan"). The net borrowing to Panoro at 60% ownership is USD 16.2 million in the Senior Secured Loan facility. The Junior Loan facility still remains undrawn at USD 4.8 million net to Panoro. The Senior and Junior facilities include financial covenants which are listed in Note 5.1.1. below. These are required to be tested at the end of every 3-month period. The Company was not in breach of any financial covenants as at the balance sheet date, nor at the date of approval of these financial statements by the Board.
In addition to this, the Phase 1 activities on Dussafu permit have been funded through the utilisation of non-recourse loan from BW Energy which has increased from USD 2.2 million to USD 12.5 million in principal since 2017, Please also see Note 5.1, Loans and borrowings.
Looking ahead, the Company through its group companies, is committed to a drilling obligation of one well on SOEP in Tunisia, in addition to the Dussafu Capex. In support of the SOEP drilling obligation, in January 2019, Panoro Tunisia Exploration AS has issued a bank guarantee of USD 16.6 million (Panoro's net share is USD 10 million).
Although the Company is well funded to undertake the upcoming Capex, there is risk that additional funding may be required to conclude such activities. Should additional funding be required in the future for additional capital expenditure for new development phases or working capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. Options include, amongst others, offtake
prepayment structures, utilization of undrawn financing facility and the issuance of shares. As a result, these financial statements have been prepared under the assumption of going concern and realization of assets and settlement of debt in normal operations.
The Group's, results of operations, cash flow and financial condition depend significantly on the level of oil and gas prices and market expectations to these, and may be adversely affected by volatile oil and gas prices and by the general global economic and financial market situation.
The Group's profitability is determined in large part by the difference between the income received from the oil and gas produced and the operational costs, taxation costs relating to recovery (which are assessable irrespective of sales), as well as costs incurred in transporting and selling the oil and gas. Lower prices for oil and gas may thus reduce the amount of oil and gas that the Group is able to produce economically. This may also reduce the economic viability of the production levels of specific wells or of projects planned or in development to the extent that production costs exceed anticipated revenue from such production.
The economics of producing from some wells and assets may also result in a reduction in the volumes of the Group's reserves. The Group might also elect not to produce from certain wells at lower prices. These factors could result in a material decrease in net production revenue, causing a reduction in oil and gas acquisition and development activities. In addition, certain development projects could become unprofitable because of a decline in price and could result in the Group having to postpone or cancel a planned project, or if it is not possible to cancel the project, carry out the project with negative economic impact.
In addition, a substantial material decline in prices from historical average prices could reduce the Group's ability to refinance its outstanding credit facilities and could result in a reduced borrowing base under credit facilities available to the Group, including the Senior Secured loan facility in place. Changes in the oil and gas prices may thus adversely affect the Group's business, results of operations, cash flow, financial condition and prospects.
As a result of the increased activity of the Group during 2018, the Board has reassessed its risk management policies and has initiated a commodity hedging program, whereby approximately 600 bopd, representing approximately 25% of current production, have been hedged over a three-year period using "zero cost collars" to protect the downside in oil price of below USD 55 per bbl. The hedging program will continue to be closely monitored and adjusted according to the Company's risk management policies and cashflow
requirements. Part of the hedging strategy was executed in December 2018 and some in January 2019. Please also see Note 18, Financial instruments.
Developing oil and gas resources and reserves into commercial production involves risk. The Group's exploration operations are subject to all the risks common in the oil and gas industry. These risks include, but are not limited to, encountering unusual or unexpected rock formations or geological pressures, geological uncertainties, seismic shifts, blowouts, oil spills, uncontrollable flows of oil, natural gas or well fluids, explosions, fires, improper installation or operation of equipment and equipment damage or failure. Given the nature of offshore operations, the Group's exploration, operating and drilling facilities are also subject to the hazards inherent in marine operations, such as capsizing, sinking, grounding and damage from severe storms or other severe weather conditions, as well as loss of containment, fires or explosions.
The oil and gas industry is very competitive. Competition is particularly intense in the acquisition of (prospective) oil and gas licenses. The Group's competitive position depends on its geological, geophysical and engineering expertise, financial resources, the ability to develop its assets and the ability to select, acquire, and develop proven reserves.
The Group currently plans to be involved in developments in its oil and gas licences. Developing a hydrocarbon production field requires significant investment over a long period of time, to build the requisite operating facilities, drilling of production wells along with implementation of advanced technologies for the extraction and exploitation of hydrocarbons with complex properties. Making these investments and implementing these technologies, normally under difficult conditions, can result in uncertainties about the amount of investment necessary, operating costs and additional expenses incurred as compared with the initial budget, thereby negatively affecting the business, prospects, financial condition and results of operations of the Group. Further, with respect to contingent resources, the amount of investment needed may be prohibitive, such that conversion of resources into reserves may not be commercially viable. The Group may be unable to obtain needed capital or financing on satisfactory terms. If the Group's revenues decrease, it may have limited ability to obtain the capital necessary to sustain operations at current levels. If the Group's available cash is not sufficient to fund its committed or planned investments, a curtailment of its operations
relating to development of its business prospects could occur, which in turn could lead to a decline in its oil and natural gas production and reserves, or if it is not possible to cancel or stop a project, be legally obliged to carry out the project contrary to its desire or with negative economic impact. Further, the Group may inter alia fail to make required cash calls and thus breach license obligations, which again could lead to adverse consequences. All of the above may have a material adverse effect on the Group and its financial position.
The Group's license interests for the exploration and exploitation of hydrocarbons will be subject to fixed terms, some of which will expire before the economic life of the asset is over. For example, the licences relating to the interest in five oil production concessions in Tunisia acquired in the OMV Transaction may expire prior to the end of their economic life, and uncertainty surrounding the renewal of SOEP which requires an exploration well to be drilled prior to entering into the next operation phase.
The Group plans to extend any permit or license where such extension is in the best interest of the Group. However, the process for obtaining such extensions is not certain and no assurances can be given that an extension in fact will be possible. Even if an extension is granted, such extension may only be given on conditions which are onerous or not acceptable to the Group.
If any of the licenses expire, the Group may lose its investments into the license, charged penalties relating to unfulfilled work program obligations (such as at Hammamet in Tunisia) and forego the opportunity to take part in any successful development of, and future production from, the relevant license area, which could have a material adverse effect on the Group's financial position and future prospects.
The Group's license interests for the exploration and exploitation of hydrocarbons will typically be subject to certain financial obligations or work commitments as imposed by local authorities. The existence and content of such obligations and commitments may affect the economic and commercial attractiveness for such license interest. No assurance can be given that local authorities do not unilaterally amend current and known obligations and commitments. If such amendments are made in the future, the value and commercial and economic viability of such interest could be materially reduced or even lost, in which case the Group's financial position and future prospects could also be materially weakened.
The Group's reserve evaluations have been prepared in accordance with existing guidelines. These evaluations include many assumptions relating to factors such as initial production rates, recovery rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of oil and gas, operating costs, and royalties and other government levies that may be imposed over the producing life of the reserves and resources. Actual production and cash flows will vary from these evaluations, and such variations could be material. Hence, although the Group understands the life expectancy of each of its assets, the life of an asset may be shorter than anticipated. Among other things, evaluations are based, in part, on the assumed success of exploration activities intended to be undertaken in future years. The reserves, resources and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploration activities do not achieve the level of success assumed in the evaluations, and such reductions may have a material adverse effect on the Group's business, results of operations, cash flow and financial condition.
Several of the Group's license interests concern fields which have been in operation for years and which, consequently, will have equipment which from time to time will have to be decommissioned. In addition, the Group plans and expects to take part in developments and investments on existing and new fields, which will increase the Group's future decommissioning liabilities.
There are significant uncertainties relating to the estimated liabilities, costs and time for decommissioning of the Group's current and future licenses. Such liabilities are derived from legislative and regulatory requirements and require the Group to make provisions for such liabilities.
Therefore, it is difficult to forecast accurately the costs that the Group will incur in satisfying decommissioning liabilities. No assurance can be given that the anticipated cost and timing of removal are correct and any deviation from current estimates or significant increase in decommissioning costs relating to the Group's previous, current or future licenses, may have a material adverse effect on the Group.
All phases of oil and gas activities present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and national laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, and releases or emissions of various substances. The legislation also requires that wells and facility sites are operated, maintained and abandoned to the satisfaction of applicable
regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties in addition to loss of reputation. Any pollution may give rise to material liabilities and may require the Group to incur material costs to remedy such discharge. No assurance can be given that current or future environmental laws and regulations will not result in a curtailment or shut down of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Group.
There is no assurance that future political conditions will not result in the host governments adopting different policies for petroleum taxation. In the event there are changes to such tax regimes, it could lead to new investments being less attractive, increase costs for the Group and prevent the Group from further growth. In addition, taxing authorities could review and question the Group's historical tax returns leading to additional taxes and tax penalties which could be material.
The Group faces the risk of litigation and other proceedings in relation to its business. The outcome of any litigation may expose the Group to unexpected costs and losses, reputational and other non-financial consequences and diverting management attention away from operational matters, all of which could have a material adverse effect on the Group's business and financial position.
The Group will in its ordinary course of business provide guarantees and indemnities to governmental agencies, joint venture partners or third-party contractors in respect of activities relating to its subsidiaries, inter alia for such subsidiaries working and abandonment obligations under licences or obligations under the relevant terms of agreements with third party contractors.
Should any guarantees or indemnities given by the Company be called upon, this may have a material adverse effect on the Group's financial position.
Financial risk is managed by the finance department in line with the policies approved by the Board of Directors. The overall risk management program seeks to minimize the potential adverse effects of unpredictable fluctuations in financial and commodity markets on financial performance, i.e., risks associated with currency and interest rate exposures, debt servicing and oil and gas prices. Financial instruments such as derivatives, forward contracts and currency and commodity swaps are continuously being evaluated for the hedging of such risk exposures.
The Group has incurred and may in the future incur debt or other financial obligations which could have important consequences to its business including, but not limited to:
The Group's debt financing requires the establishing of a subsidiary to be a new holding company for the Tunisian assets in order to remove the need for an Austrian entity within a stated period of time. Failure to do so within the stated time may result in default under the financing and/or require additional security.
The Group's ability to make payments on, or repay or refinance, any debt and to fund working capital and capital investments, will depend on its future operating performance and ability to generate sufficient cash. This depends on the success of its business strategy and on general economic, financial, competitive, market, legislative, regulatory, technical and other factors as well as the risks discussed in these "Risk Factors", many of which are beyond the Group's control. The Group cannot assure that its business will generate sufficient cash flow from operations or that future debt and equity financings will be available to it in an amount sufficient to enable it to pay its debt, or to fund its other liquidity needs. The Group cannot give assurance that it will be able to refinance any debt on commercially reasonable terms or at all. Any failure by the Group to make payments on debt on a timely basis would likely result in a reduction of its credit rating, which could also harm its ability to incur additional indebtedness. There can be no assurance that any assets that
the Group may elect to sell can be sold or that, if sold, the timing of such sale will be acceptable and the amount of proceeds realized will be sufficient to satisfy its debt service and other liquidity needs.
If the Group is unsuccessful in any of these efforts, it may not have sufficient cash to meet its obligations, which could cause an event of default under any debt arrangements and could result in the debt being accelerated, lending reserves and certain bank accounts being frozen, triggering of cross-default provisions, enforcement of security and the companies of the Group, including the Group being forced into bankruptcy or liquidation.
The Group's long-term debt is primarily based on floating interest rates. An increase in interest rates can therefore materially adversely affect the Group's cash flows, operating results and financial condition and make it difficult to service its financial obligations. The Group has, and will in the future have, covenants related to its financial commitments. Failure to comply with financial obligations, financial covenants and other covenants may entail several material adverse consequences, including the need to refinance, restructure, or dispose of certain parts of, the Group's businesses in order to fulfil the financial obligations and there can be no assurances that the Group in such event will be able to fulfil its financial obligations.
Due to the international nature of its operations, the Group is exposed market fluctuations in foreign exchange rates due to the fact that the Group repots profit and loss and the balance sheet in US Dollars (USD). The risks arising from currency exposure are primarily with respect to USD, the Norwegian Kroner (NOK), the Tunisian Dinar (TND) and, to a lesser extent, the Pound Sterling (GBP) and Brazilian Reals (BRL).
The Tunisian petroleum ministry, Entreprise Tunisienne D' Activites Petrolieres (ETAP), is the Company's primary partner and counterparty in Tunisia. A general downturn in financial markets and economic activity may result in a higher volume of late payments and outstanding receivables, which may in turn adversely affect the company's business, operating results, cash flows and financial condition.
For risk factors pertaining to the Company and its operations, reference is also made to the prospectus dated December 14, 2018 which is available on the Group's website www.panoroenergy.com.
The management of the Company is led by CEO John Hamilton. Mr. Hamilton has considerable experience from various positions in the international oil and gas industry. He is supported by CFO, Qazi Qadeer, Technical Director, Richard Morton, both are also based in London. From January 2019, Nigel McKim, also based in London, has joined Panoro as Projects Director.
Since the beginning of 2018, Panoro Energy has been employing five individuals, all of which are based in London. Following the acquisitions in Tunisia, the Group employed 31 full time employees as of December 31, 2018. These however do not include part-time contractors and personnel directly employed by joint ventures where Panoro is a non-operated partner.
The Company and its management have long emphasised the importance of maintaining a good working environment in order to achieve Company goals and objectives. With the changing scope of the organisation this focus has naturally expanded and strengthened. As a partner in the TPS operated assets and Operator for the Sfax offshore project, the Company sees that undertaking its business activities to the highest safety and environmental standards as being paramount to delivering upon its business objectives.
2018 has been a transformational year for Panoro operationally, transitioning from an enterprise with an office in London employing five people and holding interests in two non-operated assets in Nigeria and Gabon to one where the company is now an operator in Tunisia. The scope of this change is significant: net production has increased from 300 to 2,500 bopd, employees from five to 31 and during the course of 2019 the company will be gearing up to operate its first exploration drilling project.
Health, Safety, Security and Environment (HSSE) policies are essential for Panoro with the goal to avoid accidents and incidents and minimize the impact of its activities on the environment. Panoro performs all its activities with focus on and respect for people and the environment. The Board believes this is a key condition for creating value in a very demanding business. The Company's objective for health, safety, security and the environment (HSSE) is zero accidents and zero unwanted incidents in all activities. The Company strives towards performing all its activities with no harm to people or the environment. Panoro experienced no major accidents, injuries, incidents or any environmental claims during the year with respect to its existing and recently acquired businesses in Tunisia form the respective acquisition dates Sickness absence in the years 2018 and 2017 was less than 1%.
The Company has established a set of operational guidelines building on its principles of Corporate Governance, covering critical operational aspects ranging from ethical issues and practical travel advice to delegation of authority matrices. With oil and gas assets located in North and West Africa, travel arguably presented the greatest risk to its employees
historically, and the Company sought to ensure adequate safety levels whilst travelling. An emergency preparedness organization was established, in which membership in International SOS is a key factor. International SOS provides updated risk assessments, medical support and evacuation services worldwide.
With the acquisition of the Sfax Offshore Exploration Permit and the TPS Assets, the Company is maintaining a safety conscious culture in all areas of operation in Tunisia. Panoro now recognises a need to build on this past effort, to integrate these initiatives with its own standards and procedures and thereby ensure that there continues to be a focus on and a high performance in this area of the business.
In Nigeria and Gabon, Panoro as a non-operator, is dependent on the efforts of the operators with respect to achieving physical results in the field. However, the Company has chosen to take an active role in all license committees with the conviction that high safety standards are the best means to achieve successful operations. Through this involvement, the Company can influence the choice of technical solutions, vendors and quality of applied procedures and practices. The Company's operations have been conducted by the operators on behalf of the licensees, at acceptable HSSE standards. No accidents that resulted in loss of human life or serious damage to people or property have been reported.
Panoro's corporate governance policy is based on the recommendations of the Norwegian Code of Practice for Corporate Governance. The main objective for Panoro Energy ASA's Corporate Governance is to develop a strong, sustainable, competitive and a successful E&P company acting in the best interest of all the stakeholders, within the laws and regulations of the respective countries. The Board and management aim for a controlled and profitable development and long-term creation of growth through well-founded governance principles and risk management.
Panoro Energy acknowledges that successful value-added business is profoundly dependent upon transparency and internal and external confidence and trust. Panoro Energy believes that this is achieved by building a solid reputation based on our financial performance, our values and by fulfilling our commitments. Thus, good corporate governance practices combined with Panoro Energy's Code of Conduct is an important tool in assisting the Board to ensure that we properly discharge our duty.
The composition of the Board ensures that the Board represents the common interests of all shareholders and meets the Company's need for expertise, experience, capacity and diversity. The members of the Board represent a broad range of experience including oil and gas, energy, banking and investment. The composition of the Board ensures that it can operate independently of any special interests. Members of the Board are elected for a maximum period of two years. However, in the last election, the Board was appointed for one year. Recruitment of members of the Board will be phased so
that the entire Board is not replaced at the same time. The Chairman of the Board of Directors is elected by the General Meeting.
The Board may be given power of attorney by the General Meeting to acquire the Company's own shares. Any acquisition of shares will be carried out through a regulated marketplace at market price, and the Company will not deviate from the principle of equal treatment of all shareholders. If there is limited liquidity in the Company's share at the time of such transaction, the Company will consider other ways to ensure equal treatment of all shareholders. The Company currently holds shareholder authorisation approved in the 2018 Annual General Meeting to acquire its own shares to a maximum of 4,250,000 shares, each with a Nominal value of NOK 0.05. From the current year's authorisation, which is due to expire prior to the 2019 Annual General Meeting, the Company has purchased 166,162 own shares in December 2018 and transferred/re-allotted them to settle the equity-based fees agreed under the Mercuria loan arrangement. In addition, 1,000,000 own shares held in treasury at the start of the year, were re-allotted during the June 2018 equity issue. Details of transaction in own shares is discussed in Note 15 to the annexed financial statements.
The Board may also be given a power of attorney by the General Meeting to issue new shares for specific purposes. Any decision to deviate from the principle of equal treatment by waiving the pre-emption rights of existing shareholders to subscribe for shares in the event of an increase in share capital will be justified and disclosed in the stock exchange announcement of the increase in share capital. Such deviation will be made only if it is in the common interest of the shareholders and the Company.
The Company has not granted any loans or guarantees to anyone in the management or any of the directors.
The Board acknowledges the Norwegian Code of Practice for Corporate Governance and the principle of comply or explain. Panoro Energy has implemented this Code and uses its guidelines as the basis for the Board's governance duties. A report on the corporate governance policy is incorporated in a separate section of this report and is also posted on the Company's website at www.panoroenergy.com.
The Company has implemented a policy for Ethical Code of Conduct and work diligently to comply with these guidelines. The full policy is enclosed in this annual report (see section Ethical Code of Conduct).
Panoro Energy is an equal opportunity employer, with an equality concept integrated in its human resources policies. A diversified working environment is embraced, and the Company'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 Panoro Energy's Code of Conduct, to ensure uniformity in behaviour across a workforce representing 3 different nationalities.
Panoro Energy is a knowledge-based company 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.
81% of the permanent employees were men and 19% women at the end of 2018 and for 2017, the group comprised of 80% men and 20% women. There are currently no women in Panoro Energy's senior management. These statistics exclude employments at joint venture level where assets are jointly controlled and Panoro is not an operator.
According to its articles of association, the Company shall have a minimum of three and a maximum of eight directors on its Board. The number of Board members was five at year end 2018, all non-executive directors. The members have various backgrounds and experience, offering the Company valuable perspectives on industrial, operational and financial issues. Two of the five Board members as at year end 2018 are female. The Board held 10 meetings during the year which includes meetings held through circulation of documents and by phone calls.
Panoro Energy has prepared a report of government payments in accordance with Norwegian Accounting Act § 3-3 d) and accordance with Norwegian Securities Trading Act § 5- 5a. It states that companies engaged in activities within the extractive industries shall annually prepare and publish a report containing information about their payments to governments at country and project level.
The report is provided on page 21 of this annual report and on Company's website www.panoroenergy.com.
Panoro looks forward to 2019, where it can build and capitalise on its transformational acquisitions in Tunisia and further develop our Dussafu licence into a world class producing asset. Panoro's balanced, full cycle E&P portfolio provides the platform to consider opportunities to grow the asset base.
The Board wishes to thank the staff and shareholders for their continued commitment to the Company.
| JULIEN BALKANY |
GARRETT SODEN |
TORSTEIN SANNESS |
|---|---|---|
| Chairman of the Board |
Non-Executive Director |
Non-Executive Director |
| ALEXANDRA | HILDE | JOHN HAMILTON |
| HERGER Non-Executive |
ÅDLAND Non-Executive |
Chief Executive |
| Director | Director | Officer |
Non-Executive Director
JULIEN BALKANY Julien Balkany is a French citizen and a resident in London, who since 2014 has been Chairman of the Norwegian oil & gas exploration and production company Panoro Energy ASA. Alongside this, since 2008, Julian also serves as a Managing Partner of Nanes Balkany Partners, a group of investment funds that focuses on the oil & gas industry. Concomitantly, he is also Non-Executive Director of Amromco Energy, the largest privately held independent gas producer in Romania as well as of two private mining companies, Sarmin Bauxite Ltd, and Pan-African Diamonds Limited. Julien was previously a Non-Executive Director of several publicly listed oil & gas companies including Norwegian Energy Company (Noreco), Gasfrac Energy Services,and Toreador Resources). Julien started his career as an oil and gas investment banker and studied at the Institute of Political Studies (Strasbourg) and at UC Berkeley.
TORSTEIN SANNESS Mr. Torstein Sanness is a Norwegian Citizen Torstein residing in Norway. He has extensive experience and technical expertise in the oil and gas industry. Mr. Sanness became the Chairman of Lundin Petroleum Norway in April 2015. Prior to this position Mr. Sanness was Managing Director of Lundin Petroleum Norway from 2004 to April 2015. Under his leadership Lundin Norway has turned into one of the most successful players on the NCS and added net discovered resources of close to a billion boe to its portfolio through the discoveries of among others E. Grieg and Johan Sverdrup. Before joining Lundin Norway Mr. Sanness was Managing Director of Det Norske Oljeselskap AS (wholly owned by DNO at the time) and was instrumental in the discoveries of Alvheim, Volund and others. From 1975 to 2000, Mr. Sanness was at Saga Petroleum until its sale to Norsk Hydro and Statoil, where he held several executive positions in Norway as well as in the US, including being responsible for Saga's international operations and entry into Libya, Angola, Namibia, and Indonesia. Currently, Mr. Sanness is serving as Board member of International Petroleum Corp. (a Ludlin Group E&P company with a portfolio of assets in Canada, Europe and South East Asia), Magnora ASA (a company managing certain royalty rights and licence arrangements) and TGS (the world's largest geoscience data company). Mr. Sanness is a graduate of the Norwegian Institute of Technology in Trondheim where he obtained a Master of Engineering (geology, geophysics and mining engineering). Mr. Sanness is also the Chairman of the Board of Magnora ASA.
Non-Executive Director
Non-Executive Director
Non-Executive Director
ALEXANDRA HERGER Ms. Alexandra (Alex) Herger, a US citizen based in Maine, has extensive senior leadership and board experience in worldwide exploration and production for international oil and gas companies. Ms. Herger has 40 years of global experience in the energy industry, currently serving as an Independent director for Tortoise Capital Advisors, CEFs, based in Leawood, Kansas, Tethys Oil based in Stockholm, Sweden, as well as Panoro Energy. Her most recent leadership experience was as interim Vice President for Marathon Oil Company until her retirement in July 2014. Prior to this position, Ms. Herger was Director of International Exploration and New Ventures for Marathon Oil Company from 2008 - 2014, where she led five new country entries and was responsible for adding net discovered resources of over 500 million boe to the Marathon portfolio. Ms. Herger was at Shell International and Shell USA from 2002- 2008, holding positions as Exploration Manager for the Gulf of Mexico, Manager of Technical Assurance for the Western Hemisphere, and Global E & P Technical Assurance Consultant. Prior to the Shell / Enterprise Oil acquisition in 2002, Ms. Herger was Vice President of Exploration for the Gulf of Mexico for Enterprise Oil, responsible for the addition of multiple giant deep water discoveries. Earlier, Ms. Herger held positions of increasing responsibility in oil and gas exploration and production, operations, and planning with Hess Corporation and Exxonmobil Corporation. Ms. Herger holds a Bachelor's Degree in Geology from Ohio Wesleyan University and post-graduate studies in Geology from the University of Houston. Ms. Herger is a member of Leadership Texas, the foundation for women's resources, and was on the advisory board of the Women's Global Leadership Conference in Houston, Texas from 2010 to 2013. Ms. Herger will be serving on the nomination committee for PGS (based in Norway) effective May 2019.
GARRETT SODEN Mr. Garrett Soden has extensive experience as a senior executive and board member of various public companies in the natural resources sector. He has worked with the Lundin Group for over a decade. Mr. Soden is currently President and CEO of Africa Energy Corp., a Canadian oil and gas exploration company focused on Africa. He is also a Non-Executive Director of Etrion Corporation, Gulf Keystone Petroleum Ltd. and Phoenix Global Resources plc. Previously, he was Chairman and CEO of RusForest AB, CFO of Etrion and PetroFalcon Corporation and a Non-Executive Director of Petropavlovsk plc and PA Resources AB. Prior to joining the Lundin Group, Mr. Soden worked at Lehman Brothers in equity research and at Salomon Brothers in mergers and acquisitions. He also previously served as Senior Policy Advisor to the U.S. Secretary of Energy. Mr. Soden holds a BSc honours degree from the London School of Economics and an MBA from Columbia Business School.
HILDE ÅDLAND Mrs. Hilde Ådland, a Norwegian citizen, and has extensive technical experience in the oil and gas industry. She has leadership experience in field development, engineering, commissioning, and field operations. Mrs. Ådland held several senior positions in Gas de France/GDF SUEZ/ENGIE/Neptune including Head of Operation and Asset manager for the operated Gjøa field. She also spent 11 years with Statoil (now Equinor) in a number of senior engineering and operational roles, including Offshore Installation Manager at the Kristin field, and 6 years with Kvaerner. She has been active in the Norwegian Oil and Gas association and have in the period from autumn 2015 to spring 2019 also been the chairman of the Operation Committee. She has a Bachelor's degree in chemical engineering and a Master's degree in process engineering. She is also board member of Magnora ASA.
Chief Executive Officer
Technical Director
JOHN HAMILTON John Hamilton, Chief Executive Officer, has considerable experience from various positions in the international oil and gas industry. Most recently, John was Chief Executive Officer of UK AIM listed President Energy PLC, a Latin American focused exploration company, which opened up a new onshore basin in Paraguay. Before joining President, John was Managing Director of Levine Capital Management, and oil and gas investment fund. He was also Chief Financial Officer of UK FTSE 250 listed Imperial Energy PLC, until its sale for over USD 2 billion in 2008. John also spent 15 years with ABN AMRO Bank in Europe, Africa, and the Middle East. The majority of his time with ABN AMRO was spent in the energy group, with a principal focus on financing upstream oil and gas. John is also a member of the Board of Magnora ASA. John has a BA from Hamilton College in New York, and an MBA from the Rotterdam School of Management and New York University. He is a British citizen and resides in London, UK.
QAZI QADEER Qazi Qadeer, Chief Financial Officer is a Chartered Accountant with a Fellow membership of Institute of Chartered Accountants of Pakistan. Qazi joined Panoro at its inception in 2010 as Group Finance Controller. Previously he has worked for PriceWaterhouseCoopers in Karachi, Pakistan and briefly served as Internal audit manager in Pak-Arab Refinery before relocating to London, where he has spent more than five years with Ernst & Young's energy and extractive industry assurance practice; working on various projects for large and small oil & gas and mining companies. He has worked on several high profile projects including the divestment of BP plc's chemicals business in 2005 and IPO of Gem Diamonds Limited in 2006. He is a British citizen and resides in London, UK.
RICHARD MORTON Richard Morton, Technical Director has 25 years of experience in exploration, production, development and management in the oil and gas industry. Originally a highly qualified geophysicist, he has expanded his portfolio of skills progressively into operational and asset management. He has worked in a number of challenging contracting and operating environments, including as Centrica Energy's Exploration Manager for Nigeria. He has been with Panoro Energy since 2008 with responsibilities for project and technical management of Panoro's African exploration and development assets. Richard obtained a B.Sc. in Physics from Essex University in 1989 and went on to complete a M.Sc. in Applied Geophysics from the University of Birmingham the following year. He is a British citizen and resides in London, UK.
FOR THE YEAR JANUARY 1, 2018 TO DECEMBER 31, 2018
| USD 000 | Note | 2018 | 2017 |
|---|---|---|---|
| CONTINUING OPERATIONS | |||
| Revenue | |||
| Oil and gas revenue | 3 | 12,090 | 6,021 |
| Other revenue | 3 | 877 | 497 |
| Total revenue | 12,967 | 6,518 | |
| Expenses | |||
| Operating costs | (8,595) | (6,858) | |
| Exploration related costs and operator G&A | (661) | (343) | |
| Non-recurring costs | 4 | (965) | (995) |
| General and administrative costs | 4 | (4,655) | (3,655) |
| Impairment /reversal of Impairment of assets | 9.4 | - | (28,576) |
| Depreciation | 9 | (3,568) | (1,898) |
| Share based payments | 17 | (331) | (149) |
| Total operating expenses | (18,775) | (42,474) | |
| Operating loss | 4 | (5,808) | (35,956) |
| Net foreign exchange (loss)/gain | (547) | 30 | |
| Unrealised gain / (loss) on commodity hedges | 5 | 756 | - |
| Interest costs net of income | 5 | (322) | (254) |
| Other financial costs | 5 | (166) | (136) |
| Loss before income taxes | (6,087) | (36,316) | |
| Income tax benefit / (expense) | 6 | (877) | 4 |
| Net loss from continuing operations | (6,964) | (36,312) | |
| Net income / (loss) from discontinued operations | 13 | (143) | (277) |
| Net loss for the period | (7,107) | (36,589) | |
| Exchange differences arising from translation of foreign operations | (3) | (3) | |
| Other comprehensive income / (loss) for the period (net of tax) | (3) | (3) | |
| Total comprehensive income / (loss) | (7,110) | (36,592) | |
| Net loss attributable to: | |||
| Equity holders of the parent | (7,107) | (36,589) | |
| Total comprehensive income / (loss) attributable to: | |||
| Equity holders of the parent | (7,110) | (36,592) | |
| Earnings per share | 7 | ||
| (USD) – Basic and diluted - Income/(loss) for the period attributable to equity holders of the parent - Total |
(0.16) | (0.86) | |
| (USD) – Basic and diluted - Income/(loss) for the period attributable to equity holders of the parent – Continuing operations |
(0.15) | (0.85) |
The annexed notes form an integral part of these financial statements.
| ASSETS Non-current assets Intangible assets Licenses and exploration assets 8 15,197 13,596 Production rights 12.3 31,082 - Fair value of commodity hedges 18 392 - Investment in associate/joint-venture 38 - Total intangible assets 46,709 13,596 Tangible assets Production assets and equipment 9 41,612 9,902 Development assets 8 632 1,694 Property, furniture, fixtures and equipment 9 134 102 Other non-current assets 9 245 134 Total tangible assets 42,623 11,832 Total non-current assets 89,332 25,428 Current assets Crude oil inventory 2,255 1,398 Materials inventory 4,086 - Trade and other receivables 10 5,577 615 Fair value of commodity hedges 18 364 - Cash and cash equivalents 11 23,367 6,317 Restricted cash 11 76 1,500 Total current assets 35,725 9,830 TOTAL ASSETS 125,057 35,258 EQUITY AND LIABILITIES Equity Share capital 15 423 299 Share premium 333,090 297,490 Treasury shares 15 - (503) Additional paid-in capital 122,078 122,205 Total paid-in equity 455,591 419,491 Other reserves 15 (43,405) (43,405) Retained earnings (365,874) (358,766) Total equity attributable to shareholder of the parent 46,312 17,320 Non-current liabilities Decommissioning liability 14 20,739 2,039 |
USD 000 | Note | 2018 | 2017 |
|---|---|---|---|---|
| USD 000 | Note | 2018 | 2017 |
|---|---|---|---|
| Senior secured loan | 5.1 | 13,191 | - |
| Non-recourse loan | 5.1 | 9,392 | 2,197 |
| Licence obligations | 12.2 | 4,726 | - |
| Other non-current liabilities | 16 | 7,877 | 6,892 |
| Total non-current liabilities | 55,925 | 11,128 | |
| Current liabilities | |||
| Accounts payable and accrued liabilities | 16 | 7,551 | 6,737 |
| Non-recourse loan – Current portion | 5.1 | 3,751 | - |
| Licence obligations – Current portion | 12.2 | 1,166 | - |
| Senior secured loan – Current portion | 5.1 | 2,539 | - |
| Other current liabilities | 12 | 1,943 | - |
| Other current financial liabilities | 66 | - | |
| Corporate tax liability | 12.3 | 5,804 | 73 |
| Total current liabilities | 22,820 | 6,810 | |
| TOTAL EQUITY AND LIABILITIES | 125,057 | 35,258 |
The annexed notes form an integral part of these financial statements.
Attributable to the equity holders of the parent
| USD 000 | Note | Issued capital |
Share premium |
Treasury shares |
Additional paid-in capital |
Retained earnings |
Other reserves |
Currency translation reserve |
Total |
|---|---|---|---|---|---|---|---|---|---|
| At January 1, 2017 | 305 | 297,502 | - | 122,101 | (322,175) | (37,647) | (5,758) | 54,328 | |
| Net income/(loss) – Continuing Operations |
- | - | - | - | (36,312) | - | - | (36,312) | |
| Net income/(loss) – Discontinued Operations |
- | - | - | - | (277) | - | - | (277) | |
| Other comprehensive income/(loss) |
- | - | - | - | - | - | - | - | |
| Total comprehensive income/(loss) |
- | - | - | - | (36,589) | - | - | (36,589) | |
| Purchase of own shares | (6) | - | (503) | - | - | - | - | (509) | |
| Transaction costs on share buy back |
- | (13) | - | - | - | - | - | (13) | |
| Employee share options | 17 | - | - | - | 149 | - | - | - | 149 |
| Employee share options grant charge/(benefit) |
- | - | - | (44) | - | - | - | (44) | |
| At December 31, 2017 | 299 | 297,490 | (503) | 122,206 | (358,766) | (37,647) | (5,758) | 17,320 | |
| At January 1, 2018 | 299 | 297,490 | (503) | 122,206 | (358,766) | (37,647) | (5,758) | 17,320 | |
| Net income/(loss) – Continuing Operations |
- | - | - | - | (6,964) | - | - | (6,964) | |
| Net income/(loss) – Discontinued Operations |
- | - | - | - | (143) | - | - | (143) | |
| Other comprehensive income/(loss) |
- | - | - | - | - | - | (3) | (3) | |
| Total comprehensive income/(loss) |
- | - | - | - | (7,107) | - | (3) | (7,110) | |
| Sale of own shares | - | (503) | 503 | - | - | - | - | - | |
| Share issue for cash | 124 | 37,783 | - | - | - | - | - | 37,907 | |
| Transaction costs on share issue |
- | (1,680) | - | - | - | - | - | (1,680) | |
| Share buyback | - | - | 240 | - | - | - | - | 240 | |
| Share re-issue (Mercuria loan fee) |
- | - | (240) | - | - | - | - | (240) | |
| Employee share options | 17 | - | - | - | 331 | - | - | - | 331 |
At December 31, 2018 423 333,090 - 122,078 (365,875) (37,647) (5,761) 46,312
The annexed notes form an integral part of these financial statements.
| USD 000 | 2018 | 2017 | |
|---|---|---|---|
| Cash flows from operating activities | |||
| Net (loss) / income for the year before tax – Continuing operations | (6,087) | (36,316) | |
| Net (loss) / income for the year before tax – Discontinued operations | (102) | (203) | |
| Net (loss) / income for the year before tax | (6,189) | (36,519) | |
| Adjusted for: | |||
| Depreciation | 4 | 3,568 | 1,898 |
| Exploration related costs and Operator G&A | 661 | 343 | |
| Impairment and asset write off | 9.4 | - | 28,576 |
| Unrealised loss / (gain) on commodity hedges | 18 | (756) | - |
| Net finance costs | 488 | 390 | |
| Share-based payments | 331 | 149 | |
| Foreign exchange loss / (gain) | 547 | (30) | |
| Increase/(decrease) in trade and other payables | 121 | 4,084 | |
| (Increase)/decrease in trade and other receivables | (2,854) | 463 | |
| (Increase)/decrease in oil inventory | (318) | (1,235) | |
| Taxes paid | (936) | (71) | |
| Net cash flows from operating activities | (5,337) | (1,952) | |
| Cash flows from investing activities | |||
| Cash outflow relating to acquisitions | 12.3 | (33,601) | - |
| Net cash acquired at acquisitions | 12 | 9,067 | - |
| Investment in exploration, production and other assets | (17,727) | (9,882) | |
| Proceeds from disposal of assets | - | 12,737 | |
| Increase / (decrease) in non-recourse loan | 5.1 | 10,946 | 2,197 |
| Net cash flows from investing activities | (31,315) | 5,052 | |
| Cash flows from financing activities | |||
| Gross proceeds from loans and borrowings | 5.1 | 16,200 | - |
| Borrowing costs, including arrangement fees | 5.1 | (471) | - |
| Gross proceeds from Equity Private Placement and Treasury Shares | 15 | 38,410 | - |
| Cost of Equity Private Placement and Treasury Shares Issued | ` | (1,680) | - |
| Share buyback | (240) | (509) | |
| Net financial income (net of charges paid) | (14) | (65) | |
| Movement in restricted cash balance | 1,500 | (980) | |
| Net cash flows from financing activities | 53,705 | (1,554) | |
| Effect of foreign currency translation adjustment on cash balances | (3) | 3 | |
| Change in cash and cash equivalents during the period | 17,050 | 1,549 | |
| Cash and cash equivalents at the beginning of the period | 6,317 | 4,768 | |
| Cash and cash equivalents at the end of the period | 23,367 | 6,317 |
The annexed notes form an integral part of these financial statements.
The parent company, Panoro Energy ASA ("the Company"), was incorporated on April 28, 2009 as a public limited company under the Norwegian Public Limited Companies Act. The registered organization number of the Company is 994 051 067 and its registered office is c/o Advokatfirma Schjødt, Ruseløkkveien 14, P.O. box 1444 Solli, 0201 Oslo, Norway.
The Company and its subsidiaries ("Panoro" or the "Group") are engaged in the exploration and production of oil and gas resources in North and West Africa. The consolidated financial statements of the Group for the year ended December 31, 2018 were authorised for issue by the Board of Directors on April 30, 2019.
The Board of Directors confirms that the annual financial statements have been prepared pursuant to the going concern assumption, in accordance with §3-3a of the Norwegian Accounting Act, and that this assumption was realistic as at the balance sheet date. The going concern assumption is based upon the financial position of the Company and the development plans currently in place. In the Board of Directors' view, the annual accounts give a true and fair view of the group's assets and liabilities, financial position and results. Panoro Energy ASA is the parent company of the Panoro Group. Its financial statements have been prepared on the assumption that Panoro Energy will continue as a going concern.
The Company had USD 23.4 million in cash and cash equivalents as of December 31, 2018 and debt of USD 28.9 million. In addition to Dussafu capital expenditure, the Company is committed to a drilling obligation of one well on SOEP in Tunisia. In support of this obligation, Panoro Tunisia Exploration AS issued a bank guarantee of USD 16.6 million (Panoro's net share is USD 10 million) subsequent to the balance sheet date in January 2019. Although the Company is well funded to undertake upcoming capital expenditure, there is risk that additional funding may be required to conclude such activities. Should additional funding be required in the future for additional capital expenditure for new development phases or working capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. Options include, amongst others, offtake prepayment structures, utilization of undrawn financing facility and the issuance of shares. As a result, these financial statements have been prepared under the assumption of going concern and realization of assets and settlement of debt in normal operations.
The Company's shares are traded on the Oslo Stock Exchange under the ticker symbol PEN.
The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union ("EU"). The consolidated financial statements are prepared on a historical cost basis, except for certain financial instruments which have been measured at fair value.
The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all years presented, unless otherwise stated.
The consolidated financial statements are presented in USD, which is the functional currency of Panoro Energy ASA. The amounts in these financial statements have been rounded to the nearest USD thousand unless otherwise stated.
The consolidated financial statements include Panoro Energy ASA and its subsidiaries as of December 31 for each year.
Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases.
The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.
All intra-group balances, transactions and unrealised gains and losses resulting from intra-group transactions and dividends are eliminated in full.
Non-controlling interests in subsidiaries are identified separately from the Group's equity therein. Total comprehensive income is attributed to non-controlling interests even if this results in the non-controlling interests having a deficit balance.
A change in the ownership interest of a subsidiary, without a loss of control, is accounted for as an equity transaction. If the Group loses control over a subsidiary, it:
• reclassifies the parent's share of components previously recognised in other comprehensive income to profit or loss or retained earnings, as appropriate.
The purchase method of accounting is applied for business combinations. The cost of the acquisition is measured as the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed, and equity instruments issued by the acquirer, in exchange for control of the acquirer.
If the initial accounting for a business combination can only be determined provisionally, then provisional values are used. However, these provisional values may be adjusted within 12 months from the date of the combination.
On December 11, 2018, the Company entered into a joint arrangement through a shareholder agreement with Beender Petroleum Tunisia Limited ("Beender"), whereby Panoro and Beender jointly own and control 60% and 40% respectively of Sfax Petroleum Corporation AS ("Sfax Corp"). Sfax Corp, through its subsidiaries holds 100% shares of Panoro Tunisia Production AS ("PTP") and Panoro Tunisia Exploration AS ("PTE"). As such, all numbers and volume information relating to the Company's Tunisian operations and transactions represents the Group's 60% interest, unless otherwise stated. Details are referred to in Note 12.
The preparation of the financial statements in conformity with IFRS as adopted by the EU requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of the consolidated financial statements and reported amounts of revenues and expenses during the reporting period. Estimates and judgments are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. However, actual outcomes can differ from these estimates.
In particular, significant areas of estimation uncertainty considered by management in preparing the consolidated financial statements are as follows:
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 Group estimates and reports hydrocarbon reserves in line with the principles contained in the SPE Petroleum Resources Management Reporting System (PRMS) framework and generally obtains independent evaluations for each asset whenever new information becomes available that materially influences the reported results. As the economic assumptions used may change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may change. Such changes may impact the Group's reported financial position and results, which include:
The application of the Group's accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely, from future either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is itself an estimation process that requires varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalised, information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalised amount is written off in the statement of profit or loss and other comprehensive income in the period when the new information becomes available.
The Group recognises the net future tax benefit related to deferred income tax assets to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of deferred income tax assets requires the Group to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in each jurisdiction, to the extent that future cash flows and taxable income differ significantly from estimates. The ability of the Group to realise the net deferred tax assets recorded at the date of the statement of financial position could be impacted.
In addition, future changes in tax laws in the jurisdictions in which the Group operates could limit the ability of the Group to obtain tax deductions in future periods.
In the process of applying the Group's accounting policies, the directors have made the following judgments, apart from those involving estimates, which have the most significant effect on the amounts recognised in the consolidated financial statements:
On January 2, 2018, Panoro announced that Pan-Petroleum Aje Limited ("PPAL") had entered into a definitive and binding settlement agreement (the "Agreement") with the other OML 113 joint-venture partners. The Agreement resolved and settled the dispute between the OML 113 joint-venture partners in relation to drilling of new development wells. Since the settlement, the Group has performed a review of historical costs incurred and recognised the liabilities associated with such expenditures in the balance sheet. The proportionate joint venture liabilities resulting from the workover and side-tracks at Aje-5 had been higher than anticipated and in combination with the operational accruals have resulted in proportional liabilities of USD 5.8 million as of December 31, 2018.
In addition to these, USD 6.8 million is classified as long-term liabilities. As per the terms agreed between OML 113 Joint Venture partners, certain transitional arrangements were introduced whereby unpaid cash calls will not be immediately payable. During the transition period, any excess funds from Panoro's entitlement of crude liftings after paying for its share of operating expenditure shall be used to repay unpaid cash calls.
The Group does not anticipate any use of its cash resources and expect to fund any cash requirements from the sale of its share of Aje crude.
The Group assesses each cash-generating unit annually to determine whether an indication of impairment exists. When an indication of impairment exists, a formal estimate of the recoverable amount is made.
The recoverable amounts of cash-generating units and individual assets have been determined based on the higher of value-in-use calculations and fair values less costs to sell, or if relevant, a combination of these two models. These calculations require the use of estimates and assumptions. It is reasonably possible that the oil price assumption may change which may then impact the estimated life of the field and may then require a material adjustment to the carrying value of tangible assets. The Group monitors internal and external indicators of impairment relating to its tangible and intangible assets.
The development of the oil and gas fields, in which the Group has an ownership, is associated with significant technical risk and uncertainty with regards to timing of additional production from new development activities. Risks include, but are not limited to, cost overruns, production disruptions as well as delays compared to initial plans laid out by the operator. Some of the most important risk factors are related to the determination of reserves, the recoverability of reserves, and the planning of a cost efficient and suitable production method. There are also technical risks present in the production phase that may cause cost overruns, failed investment and destruction of wells and reservoirs.
Judgements have been made after taking into account information available to management and factors in unknown uncertainties as of the date of the balance sheet.
Asset retirement costs will be incurred by the Group at the end of the operating life of some of the Group's facilities and properties. The Group assesses its retirement obligation at each reporting date. The ultimate asset retirement costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing, extent and amount of expenditure can also change, for example in response to changes in reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for asset retirement obligation. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The provision at reporting date represents management's best estimate of the present value of the future asset retirement costs required.
By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events.
A joint arrangement is an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control.
Associated companies are those entities in which the Group has significant influence, but not control or joint control over the financial and operating policies. Joint arrangements, which are arrangements of which the Group has joint control together with one or more parties, are classified into joint ventures and joint operations. Joint ventures are joint arrangements in which the parties that share control have rights to the net assets of the arrangement. Joint operations are joint arrangements in which the parties that share joint control have rights to the assets, and obligations for the liabilities, relating to the arrangement.
For joint operations, the Group's share of all assets, liabilities, income and expenses is included in the consolidated financial statements. Acquisitions of interests in a joint operation, in which the activity of the joint operation constitutes a business, are accounted for according to the relevant IFRS 3 principles of accounting for business combinations.
A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement.
In relation to its interests in joint operations, the Group recognises its:
A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group's investment in its joint venture is accounted for using the equity method.
Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group's share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment.
The statement of profit or loss reflects the Group's share of the results of operations of the joint venture. Unrealised gains and losses resulting from transactions between the Group and the joint venture are eliminated to the extent of the interest in the joint venture.
The aggregate of the Group's share of profit or loss of the joint venture is shown on the face of the statement of profit or loss and other comprehensive income as part of operating profit and represents profit or loss after tax and NCI in the subsidiaries of the joint venture.
The financial statements of the joint venture are prepared for the same reporting period as the Group. When necessary, adjustments are made to bring the accounting policies in line with those of the Group.
At each reporting date, the Group determines whether there is objective evidence that the investment in the joint venture is impaired. If there is such evidence, the Group calculates the amount of impairment as the difference between the recoverable amount of the joint venture and its carrying value, and then recognises the loss as 'Share of profit of a joint venture' in the statement of profit or loss and other comprehensive income.
On loss of joint control over the joint venture, the Group measures and recognises any retained investment at its fair value. Any difference between the carrying amount of the joint venture upon loss of joint control and the fair value of the retained investment and proceeds from disposal is recognised in the statement of profit or loss and other comprehensive income.
When the Group, acting as an operator or manager of a joint arrangement, receives reimbursement of direct costs recharged to the joint arrangement, such recharges represent reimbursements of costs that the operator incurred as an agent for the joint arrangement and therefore have no effect on profit or loss.
When the Group charges a management fee (based on a fixed percentage of total costs incurred for the year) to cover other
general costs incurred in carrying out the activities on behalf of the joint arrangement, it is not acting as an agent. Therefore, the general overhead expenses and the management fee are recognised in the statement of profit or loss and other comprehensive income as an expense and income, respectively.
Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates ('the functional currency').
The functional currency of the Group's subsidiaries and jointly controlled companies incorporated in Gabon, Nigeria, Cyprus, Netherlands, Norway, Austria and the Cayman Islands is the US dollar ('USD'). The functional currency of the Group's Brazilian subsidiary is Reais ('BRL') and for the British subsidiaries is the Pound Sterling ('GBP').
In the consolidated financial statements, the assets and liabilities of non-USD functional currency subsidiaries are translated into USD at the rate of exchange ruling at the balance sheet date. The results and cash flows of non-USD functional currency subsidiaries are translated into USD using applicable average rates as an approximation for the exchange rates prevailing at the dates of the different transactions. Foreign exchange adjustments arising when the opening net assets and the profits for the year retained by non-USD functional currency subsidiaries are translated into USD are taken to a separate component of equity.
| 2018 | 2017 | ||||
|---|---|---|---|---|---|
| Average rate |
Reporting date rate |
Average rate |
Reporting date rate |
||
| Norwegian Kroner/USD |
8.1373 | 8.6788 | 8.2654 | 8.1993 | |
| Brazilian Real/USD | 3.6555 | 3.8745 | 3.1922 | 3.3077 | |
| USD/British Pound | 1.3353 | 1.2769 | 1.2888 | 1.3510 | |
| USD/TND | 2.6468 | 2.9944 | N/A | N/A |
The foreign exchange rates applied were:
Transactions in foreign currencies are initially recorded at the functional currency spot rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency spot rate of exchange ruling at the reporting date. All differences are taken to the income statement. Non-monetary items that are measured in terms of historical cost in foreign currency are translated using the spot exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined.
In order to consider an acquisition as a business combination, the acquired asset or groups of assets must constitute a business (an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). The combination consists of inputs and processes applied to these inputs that have the ability to create output. Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the Group achieves control over the financial and operating assets. This date may differ from the actual date on which the assets are transferred. Comparative figures are not adjusted for acquired, sold or liquidated businesses. On acquisition of a licence that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any non-controlling interest (NCI) in the acquiree. For each business combination, the Group elects whether to measure NCI in the acquiree at fair value or at the proportionate share of the acquiree's identifiable net assets. Acquisition related costs are expensed as incurred and included in administrative expenses.
When the Group acquires a business, it assesses the assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. Those acquired petroleum reserves and resources that can be reliably measured are recognised separately in the assessment of fair values on acquisition. Other potential reserves, resources and rights, for which fair values cannot be reliably measured, are not recognised separately, but instead are subsumed in goodwill.
Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments is measured at fair value, with changes in fair value recognised either in the statement of profit or loss or as a change to other comprehensive income. If the contingent consideration is not within the scope of IFRS 9, it is measured in accordance with the appropriate IFRS. Contingent consideration that is classified as equity is not remeasured, and subsequent settlement is accounted for within equity.
Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for NCI over the fair value of the identifiable net assets acquired and liabilities assumed. If the fair value of the identifiable net assets acquired is in excess of the aggregate consideration transferred (bargain purchase), before recognising a gain, the Group reassesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognised in the statement of profit or loss and other comprehensive income.
After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group's cash generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.
Where goodwill forms part of a CGU and part of the operation in that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed of in these circumstances is measured based on the relative values of the disposed operation and the portion of the CGU retained.
The Group applies the 'successful efforts' method of accounting for Exploration and Evaluation ('E&E') costs, in accordance with IFRS 6 'Exploration for and Evaluation of Mineral Resources'. E&E expenditure is capitalised when it is considered probable that future economic benefits will be recoverable. Costs that are known at the time of incurrence to fail to meet this criterion are generally charged to expense in the period they are incurred.
E&E expenditure capitalised as intangible assets includes license acquisition costs, and exploration drilling, geological and geophysical costs and any other directly attributable costs.
E&E expenditure, which is not sufficiently related to a specific mineral resource to support capitalization, is expensed as incurred.
E&E assets are carried forward, until the existence, or otherwise, of commercial reserves have been determined subject to certain limitations including review for indications of impairment. If no reserves are found the costs to drill exploratory wells, including exploratory geological and geophysical costs and costs of carrying and retaining unproved properties, are written off.
Once commercial reserves have been discovered, the carrying value after any impairment loss of the relevant E&E assets is transferred to development tangible and intangible assets. No depreciation and/or amortisation are charged during the exploration and development phase. If however, commercial
reserves have not been discovered, the capitalised costs are charged to expense after the conclusion of appraisal activities.
Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of commercially proven development wells, is capitalised within property, plant and equipment and intangible assets according to nature. When development is completed on a specific field, it is transferred to production assets. No depreciation or amortisation is charged during the Exploration and Evaluation phase.
The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements, but redesignates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.
Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within oil and gas properties.
Development and production assets are accumulated on a cash-generating unit basis and represent the cost of developing the commercial reserves discovered and bringing them into production together with E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined in accounting policy above.
The cost of development and production assets also includes the cost of acquisitions and purchases of such assets, directly attributable overheads and the cost of recognising provisions for future restoration and decommissioning.
Where major and identifiable parts of the production assets have different useful lives, they are accounted for as separate items of property, plant and equipment. Costs of minor repairs and maintenance are expensed as incurred.
Oil and gas properties and intangible assets are depreciated or amortised using the unit-of-production method. Unit-ofproduction rates are based on proved and probable 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. Depreciation and amortisation is expensed in the income statement except for on the amount attributable to produced but unsold volumes as of the date of preparation of the financial statements, which is expensed at the time of sale.
Field infrastructure exceeding beyond the life of the field is depreciated over the useful life of the infrastructure using a straight- line method.
Depreciation/amortisation on assets held for sale is ceased from the date of such classification.
E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount and when they are reclassified to PP&E assets. For the purpose of impairment testing, E&E assets are grouped by concession or field with other E&E and PP&E assets belonging to the same CGU. The impairment loss will be calculated as the excess of the carrying value over recoverable amount of the E&E impairment grouping and any resulting impairment loss is recognized in profit or loss. The recoverable amount of a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In assessing fair value less costs to sell, the estimated future cash flows are discounted to their present value using a pretax discount rate that reflects current market assessments of the time value of money and the risk specific to the asset. Fair value less costs to sell is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.
Proven oil and gas properties and intangible assets are reviewed annually for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The carrying value is compared against the expected recoverable amount of the asset, generally by net present value of the future net cash flows, expected to be derived from production of commercial reserves or consideration expected to be achieved through the sale of its interest in an arms-length transaction, less any associated costs to sell. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped together where there are common facilities.
The Group classifies non-current assets and disposal groups as held for sale or for distribution to equity holders of the parent if their carrying amounts will be recovered principally through
a sale or distribution rather than through continuing use. Such non-current assets and disposal groups classified as held for sale or as held for distribution are measured at the lower of their carrying amount and fair value less costs to sell or to distribute. Costs to distribute are the incremental costs directly attributable to the distribution, excluding the finance costs and income tax expense.
The criteria for held for distribution classification is regarded as met only when the distribution is highly probable and the asset or disposal group is available for immediate distribution in its present condition. Actions required to complete the distribution should indicate that it is unlikely that significant changes to the distribution will be made or that the distribution with be withdrawn. Management must be committed to the distribution expected within one year from the date of the classification. Similar considerations apply to assets or a disposal group held for sale.
Production assets, property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale or as held for distribution.
Assets and liabilities classified as held for sale or for distribution are presented separately as current items in the statement of financial position.
A disposal group qualifies as discontinued operation if it is:
Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss.
The Group enters into derivative financial instruments to manage its exposure to volatility in the commodity prices realised for a proportion of its crude oil production. All derivative financial instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re-measured at their fair value at each period end. Apart from those derivatives designated as qualifying cash flow hedging instruments, all changes in fair value are recorded as financial income or expense in the year in which they arise, otherwise they are recognised in other comprehensive income.
For derivatives not designed as qualifying for cash flow hedging, the fair value at balance sheet date is based on fair value provided by the counterparties with whom the trades have been entered into. The derivatives are valued using a Black-Scholes based methodology. The inputs to these valuations include price of oil and its volatility. Fair value is the amount for which a financial asset, liability or instrument could be exchanged between knowledgeable and willing parties in an arm's length transaction. It is determined by reference to quoted market prices adjusted for estimated transaction costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models and estimated discounted values of cash flows.
Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the financial asset is transferred to a third party. This includes the derecognition of receivables for which discounting arrangements are entered into. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics of the financial asset.
Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are derecognized or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade and other receivables.
Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortized cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets measured at amortised cost.
Restricted cash relates to resources or collateral held by the Group which can only be accessed through fulfilment of conditions imposed by third parties. Funds are only classified from restricted cash status to cash equivalents when funds are transferred to and under the control of the Group.
Trade receivables, loans and other receivables that have fixed or determinable payments that are not quoted in an active market are classified as loans and receivables. Loans and receivables are measured at amortised cost using the effective interest method, less any impairment. Interest income is recognised by applying the effective interest rate, except for short-term receivables when the recognition of interest would be immaterial.
The group assesses on a forward looking basis the expected credit losses associated with financial assets classified as measured at amortized cost at each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit risk. Since this is typically less than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group's in-scope financial assets. The measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is estimated as the difference between the asset's carrying amount and the present value of the future cash flows the group expects to receive discounted at the financial asset's original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain or loss recognized in the income statement. A financial asset or group of financial assets classified as measured at amortized cost is considered to be credit-impaired if there is reasonable and supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.
The measurement of financial liabilities depends on their classification as follows:
Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
Other financial liabilities, including borrowings, are initially measured at fair value, net of transaction costs. Other financial liabilities are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis. This category of financial liabilities includes trade and other payables and finance debt.
The Group measures derivatives at fair value at each balance sheet date and, for the purposes of impairment testing, uses fair value less costs of disposal to determine the recoverable amount of some of its non-financial assets.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place either:
The principal or the most advantageous market must be accessible by the Group.
The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest.
A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use.
The Group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximising the use of relevant observable inputs and minimising the use of unobservable inputs.
All assets and liabilities for which fair value is measured or disclosed in the financial statements are categorised within the fair value hierarchy, described as follows, based on the lowest-level input that is significant to the fair value measurement as a whole:
For assets and liabilities that are recognised in the financial statements on a recurring basis, the Group determines whether transfers have occurred between levels in the hierarchy by reassessing categorisation (based on the lowestlevel input that is significant to the fair value measurement as a whole) at the end of each reporting period.
For the purpose of fair value disclosures, the Group has determined classes of assets and liabilities based on the nature, characteristics and risks of the asset or liability and the level of the fair value hierarchy as explained above.
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Group expects some or all of the provision to be reimbursed, for example under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is recognised through profit and loss net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as interest expense. The present obligation under onerous contracts is recognised as a provision.
An asset retirement liability is recognised when the Group has a present legal or constructive obligation as a result of past events, and it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made. A corresponding amount equivalent to the obligation is also recognised as part of the cost of the related production plant and equipment. The amount recognised in the estimated cost of asset retirement, discounted to its present value. Changes in the estimated timing of asset retirement or asset retirement cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to production plant and equipment. The unwinding of the discount on the asset retirement provision is included as a finance cost.
Income tax expense represents the sum of the tax currently payable and movement in deferred tax.
Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the reporting date, in
the countries where the Group operates and generates taxable income.
Current income tax relating to items recognised directly in equity is recognised in equity and not in the income statement. Management periodically evaluates positions taken in the tax returns with respect to situations which applicable tax regulations are subject to interpretation and established provisions where appropriate.
Deferred tax is provided using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.
Deferred income tax liabilities are recognised for all taxable temporary differences, except:
Deferred tax assets are recognised for all deductible temporary differences; carry forward to unused tax credits and unused tax losses, to the extent that it is probable that future taxable profit will be available against which the deductible temporary differences and the carry forward of unused tax credits and unused tax losses can be utilized except:
The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient future taxable profit will be available to allow all or part of the deferred tax asset to be utilized. Unrecognized deferred tax assets are reassessed at each reporting date and are recognized to the extent that it has
become probable that future taxable profit will allow the deferred tax asset to be recovered.
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date.
Deferred tax relating to items recognized directly in equity is recognized in equity and not in the income statement.
Deferred tax assets and deferred tax liabilities are offset, if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.
Tax benefits acquired as part of a business combination, but not satisfying the criteria for separate recognition at that date, would be recognised subsequently if new information about facts and circumstances arose. The adjustment would either be treated as a reduction to goodwill (as long as it does not exceed goodwill) if it occurred during the measurement period or in profit or loss.
According to the production-sharing arrangement (PSA) in certain licenses, the share of the profit oil to which the government is entitled in any calendar year in accordance with the PSA is deemed to include a portion representing the corporate income tax imposed upon and due by the Group. This amount will be paid directly by the government on behalf of Group to the appropriate tax authorities. This portion of income tax and revenue are presented net in income statement.
Revenues, expenses and assets are recognised net of the amount of sales tax except:
Where the sales tax incurred on a purchase of assets or services is not recoverable from the taxation authority, in which case, the sales tax is recognised as part of the cost of acquisition of the asset or as part of the expense item as applicable.
Receivables and payables that are stated with the amount of sales tax included
The net amount of sales tax recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the statement of financial position.
Revenue from the sale of crude oil is recognised when a customer obtains control ("sales" or "lifting" method), normally this is when title passes at point of delivery. Revenues from production of oil properties are recognised based on actual volumes lifted and sold to customers during the period. Where the Group has lifted and sold more than the ownership interest, an accrual is recognised for the cost of the overlift. Where the Group has lifted and sold less than the ownership interest, costs are deferred for the underlift. Overlift and underlift on the Consolidated statement of financial position date are valued at production costs. Lifting imbalances are a part of the operating cycle and as such classified as other current liabilities/assets. Under a production sharing contract, where the group is required to pay profit oil tax on production of crude oil, such payment can either be settled (i) in kind (where the government lift the crude it is entitled to); or (ii) in cash (where the Group sells the crude and pays the taxes in cash). The group presents a grossup of the profit oil tax as an income tax expense with a corresponding increase in oil and gas revenues.
Revenue from test production is recognised as a direct off-set to the capitalised cost of the exploration and evaluation asset.
Interest income is recognized on an accruals basis. For all financial instruments measured at amortised cost and interest-bearing financial assets classified as available for sale, interest income or expense is recorded using the effective interest rate (EIR), which is the rate that exactly discounts the estimated future cash payments or receipts through the expected life of the financial instrument or a shorter period, where appropriate, to the net carrying amount of the financial asset or liability. Interest revenue is included in finance income in income statement.
The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at inception date: whether fulfilment or the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys a right to use the asset.
For arrangements entered into prior to January 1, 2005, the date of inception is deemed to be January 1, 2005 in accordance with the transitional requirements of IFRIC 4.
Finance leases, which transfer to the Group substantially all the risks and benefits incidental to ownership of the leased item, are capitalized at the inception of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are reflected in the income statement.
Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset and the lease term, if there is no reasonable certainty that the Group will obtain ownership by the end of the lease term.
Operating lease payments are recognized as an expense in the income statement on a straight-line basis over the lease term.
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% |
Inventories, consisting of crude oil, and drilling and maintenance materials, are stated at the lower of cost and net realisable value. Costs comprise costs of purchase, costs of conversion and other costs incurred in bringing the inventories to their present location and condition. Weighted average cost is used to determine the cost of ordinarily interchangeable items.
The Group pays contributions into a defined contribution plan. Obligations for contributions to defined contribution pension plans are recognised as an expense in the income statement in the periods during which services are rendered by employees.
Employees (including senior executives) of the Group may receive remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments (equity-settled transactions).
The cost of equity-settled transactions is recognised, together with a corresponding increase in additional paid in capital reserve in equity, over the period in which the performance and/or service conditions are fulfilled. The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The income statement expense or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period and is recognised in sharebased payments expense.
No expense is recognised for awards that do not ultimately vest, except for equity-settled transactions for which vesting are conditional upon a market or non-vesting condition. These are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are satisfied.
When the terms of an equity-settled transaction award are modified, the minimum expense recognised is the expense as if the terms had not been modified, if the original terms of the award are met. An additional expense is recognised for any modification that increases the total fair value of the sharebased payment transaction, or is otherwise beneficial to the employee as measured at the date of modification.
When an equity-settled award is cancelled, it is treated as if it vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. This includes any award where non-vesting conditions within the control of either the entity or the employee are not met. However, if a new award is substituted for the cancelled award, and designated as a replacement award on the date that it is granted, the cancelled and new awards are treated as if they were a modification of the original award, as described in the previous paragraph.
The dilutive effect of outstanding options is reflected as additional share dilution in the computation of diluted earnings per share.
Assets that are subject to amortisation or depreciation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Goodwill is assessed for impairment on an annual basis. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows (cash-generating units). Non-financial assets that were previously impaired are reviewed for possible reversal of the impairment at each reporting date.
A previously recognised impairment loss is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such a reversal is recognised in the income statement. After such a reversal the depreciation charge is adjusted in future periods to allocate the asset's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
If there is objective evidence that an impairment loss on assets carried at amortised cost has been incurred, the amount of the loss is measured as the difference between the assets' carrying amount and the present value of estimated future cash flows (excluding future expected credit losses that have not been incurred) discounted at the financial asset's original effective interest rate (i.e. the effective interest rate computed at initial recognition). The carrying amount of the asset is reduced through use of an allowance account. The amount of the loss shall be recognised in the income statement.
If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed, to the extent that the carrying value of the asset does not exceed its amortised cost at the reversal date, any subsequent reversal of an impairment loss is recognised in the income statement.
The Group presents assets and liabilities in the statement of financial position based on current/non-current classification. An asset is current when it is either:
All other assets are classified as non-current.
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.
There were a number of amended standards and interpretations, effective from January 1, 2018 that the Group has applied for the current period.
The group has adopted IFRS 2 from January 1, 2018 which has resulted in additional disclosure around the nature of sharebased payments settled in cash to cover taxes. Disclosure has also been added to clarify the nature of cash settlement at the Group's discretion.
IFRS 15 supersedes IAS 11 Construction Contracts, IAS 18 Revenue and related Interpretations and it applies, with limited exceptions, to all revenue arising from contracts with customers. IFRS 15 establishes a five-step model to account for revenue arising from contracts with customers and requires that revenue be recognised at an amount that reflects the consideration to which an entity expects to be entitled in exchange for transferring goods or services to a customer.
IFRS 15 requires entities to exercise judgement, taking into consideration all of the relevant facts and circumstances when applying each step of the model to contracts with their customers. The standard also specifies the accounting for the incremental costs of obtaining a contract and the costs directly related to fulfilling a contract. In addition, the standard requires relevant disclosures.
The Group applied this standard to all contracts for the period under review. The Group has adopted IFRS 15 from January 1, 2018, using the permitted modified retrospective approach, which resulted in changes in accounting policies; however no adjustments were required to the amounts recognised in the financial statements.
IFRS 9 replaces the provisions of IAS 39 that relate to the recognition, classification and measurement of financial assets and financial liabilities, derecognition of financial instruments, impairment of financial assets and hedge accounting. The adoption of IFRS 9 has changed the Group's accounting for impairment losses for financial assets by replacing IAS 39's incurred loss approach with a forward-looking expected credit loss (ECL) approach. IFRS 9 requires the Group to recognise an allowance for ECLs for all debt instruments not held at fair value through profit or loss and contract assets.
The adoption of IFRS 9 from January 1, 2018 resulted in changes in accounting policies; however no adjustments were required to the amounts recognised in the financial statements.
The standards and interpretations that are issued, but not yet effective, up to the date of issuance of the Group's financial statements are disclosed below. The Group intends to adopt these standards, if applicable, when they become effective.
IFRS 16 was issued in January 2016 and it replaces IAS 17 Leases, IFRIC 4 Determining whether an Arrangement contains a lease, SIC-15 Operating Leases-Incentives and SIC-27 Evaluating the Substance of Transactions involving the Legal Form of a Lease. The new standard sets out principles for recognition, measurement, presentation and disclosure of leases for both parties in a lease, i.e. the customer (lessee) and the provider (lessor). The new standard requires that the lessee recognises 'right-of-use' assets and liabilities for most leases. The Group will implement IFRS 16 on January 1, 2019. Upon implementation of IFRS 16, the following implementation and application policy choices have been made by Panoro:
During 2018, the Group performed an impact assessment of IFRS 16. Panoro currently expects that the implementation of IFRS 16 on January 1, 2019 will increase the consolidated statements of financial position by adding lease liabilities estimated at USD 378,000 (see section 7 below) and corresponding right-of-use assets on the asset side. Consequently, equity is not expected to be impacted from the implementation of IFRS 16. The figure is a preliminary estimate, based on Panoro's current policy interpretations.
In the consolidated statements of comprehensive income, operating lease costs will be replaced by depreciation and interest expense. In the consolidated cash flow statement, lease payments will be presented as a cash flow used in financing activities. Previously, operating lease costs were presented within cash generated from operations or cash from/-used in investing activities, respectively, depending on whether the leased asset was used in operating activity or activities that were capitalized.
The Interpretation addresses the accounting for income taxes when tax treatments involve uncertainty that affects the application of IAS 12 and does not apply to taxes or levies outside the scope of IAS 12, nor does it specifically include requirements relating to interest and penalties associated with uncertain tax treatments. The Interpretation specifically addresses the following:
An entity has to determine whether to consider each uncertain tax treatment separately or together with one or more other uncertain tax treatments. The approach that better predicts the resolution of the uncertainty should be followed. The interpretation is effective for annual reporting periods beginning on or after January 1, 2019, but certain transition reliefs are available. The Group will apply the interpretation from its effective date. Since the Group operates in a complex multinational tax environment, applying the Interpretation may affect its consolidated financial statements. In addition, the Group may need to establish processes and procedures to obtain information that is necessary to apply the Interpretation on a timely basis.
The amendments address the conflict between IFRS 10 and IAS 28 in dealing with the loss of control of a subsidiary that is sold or contributed to an associate or joint venture. The amendments clarify that the gain or loss resulting from the
sale or contribution of assets that constitute a business, as defined in IFRS 3, between an investor and its associate or joint venture, is recognised in full. Any gain or loss resulting from the sale or contribution of assets that do not constitute a business, however, is recognised only to the extent of unrelated investors' interests in the associate or joint venture. The IASB has deferred the effective date of these amendments indefinitely, but an entity that early adopts the amendments must apply them prospectively. The Group will apply these amendments when they become effective.
The amendments clarify that an entity applies IFRS 9 to longterm interests in an associate or joint venture to which the equity method is not applied but that, in substance, form part of the net investment in the associate or joint venture (longterm interests). This clarification is relevant because it implies that the expected credit loss model in IFRS 9 applies to such long-term interests.
The amendments also clarified that, in applying IFRS 9, an entity does not take account of any losses of the associate or joint venture, or any impairment losses on the net investment, recognised as adjustments to the net investment in the associate or joint venture that arise from applying IAS 28 Investments in Associates and Joint Ventures.
The amendments should be applied retrospectively and are effective from January 1, 2019, with early application permitted. Since the Group does not have such long-term interests in its associate and joint venture, the amendments will not have an impact on its consolidated financial statements.
These improvements include:
The amendments clarify that, when an entity obtains control of a business that is a joint operation, it applies the requirements for a business combination achieved in stages, including remeasuring previously held interests in the assets and liabilities of the joint operation at fair value. In doing so, the acquirer remeasures its entire previously held interest in the joint operation.
An entity applies those amendments to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 1, 2019, with early application permitted. These amendments will apply on future business combinations of the Group.
A party that participates in, but does not have joint control of, a joint operation might obtain joint control of the joint operation in which the activity of the joint operation constitutes a business as defined in IFRS 3. The amendments clarify that the previously held interests in that joint operation are not remeasured.
An entity applies those amendments to transactions in which it obtains joint control on or after the beginning of the first annual reporting period beginning on or after January 1, 2019, with early application permitted. These amendments are currently not applicable to the Group but may apply to future transactions.
The amendments clarify that the income tax consequences of dividends are linked more directly to past transactions or events that generated distributable profits than to distributions to owners. Therefore, an entity recognises the income tax consequences of dividends in profit or loss, other comprehensive income or equity according to where the entity originally recognised those past transactions or events.
An entity applies those amendments for annual reporting periods beginning on or after January 1, 2019, with early application is permitted. When an entity first applies those amendments, it applies them to the income tax consequences of dividends recognised on or after the beginning of the earliest comparative period. Since the Group's current practice is in line with these amendments, the Group does not expect any effect on its consolidated financial statements.
The amendments clarify that an entity treats as part of general borrowings any borrowing originally made to develop a qualifying asset when substantially all of the activities necessary to prepare that asset for its intended use or sale are complete.
An entity applies those amendments to borrowing costs incurred on or after the beginning of the annual reporting period in which the entity first applies those amendments. An entity applies those amendments for annual reporting periods beginning on or after January 1, 2019, with early application permitted. Since the Group's current practice is in line with these amendments, the Group does not expect any effect on its consolidated financial statements.
The Group has not early adopted any other standard, interpretation or amendment that was issued but is not yet effective.
The Group operated predominantly in two business segments being the exploration and production of oil and gas in West Africa (Nigeria & Gabon) and North Africa (Tunisia). However, for the purpose of comparative information, the Brazilian segment has been included.
The Group's reportable segments, for both management and financial reporting purposes, are as follows:
*Figures only represent net participation interest in proportion to Panoro's equity holding in Sfax Petroleum Corporation AS.
• The 'Corporate and others' category consists of head office and service company operations that are not directly attributable to the other segments. Further, it also includes the residual corporate business in Brazil which is expected to be dormant in the foreseeable future.
Management monitors the operating results of business segments separately for the purpose of making decisions about resources to be allocated and of assessing performance. Segment performance is evaluated based on capital and general expenditure. Details of group segments are reported below.
Details of Group segments are reported below:
| 2018 | ||||||
|---|---|---|---|---|---|---|
| USD 000 | West Africa | North Africa | Corporate | Total – Continuing operations |
Brazil – Discontinued operations |
Total |
| Revenue (net) * | 12,967 | - | - | 12,967 | - | 12,967 |
| EBITDA | 793 | (1,402) | (1,300) | (1,909) | - | (1,909) |
| Depreciation | (3,458) | (65) | (45) | (3,568) | - | (3,568) |
| Impairment | - | - | - | - | - | - |
| Profit /(loss) before tax | (3,135) | (777) | (2,175) | (6,087) | (143) | (6,784) |
| Net profit/(loss) | (4,012) | (777) | (2,175) | (6,964) | (143) | (7,107) |
| Segment assets ** | 47,418 | 65,481 | 12,149 | 125,048 | 9 | 125,057 |
| - Additions to licenses, Production, E&E and development assets |
17,708 | 49,098 | - | 66,806 | - | 66,806 |
| 2017 | ||
|---|---|---|
| USD 000 | West Africa | North Africa | Corporate | Total – Continuing operations |
Brazil – Discontinued operations |
Total |
|---|---|---|---|---|---|---|
| Revenue (net) * | 6,518 | - | - | 6,518 | - | 6,518 |
| EBITDA | (790) | - | (4,543) | (5,333) | - | (5,333) |
| Depreciation | (1,828) | - | (70) | (1,898) | - | (1,898) |
| Impairment | (28,576) | - | - | (28,576) | - | (28,576) |
| Profit /(loss) before tax | (34,423) | - | (1,893) | (36,316) | (203) | (36,519) |
| Net profit/(loss) | (34,423) | - | (1,889) | (36,312) | (277) | (36,589) |
| Segment assets ** | 29,675 | - | 5,452 | 35,127 | 131 | 35,258 |
| - Additions to licenses, Production, E&E and development assets |
16,435 | - | - | 16,435 | - | 16,435 |
* Revenue excludes any intercompany revenue.
** Segment assets for Discontinued Operations as at December 31, 2018 relate to USD 4,000, Cash and USD 5,000, Other Receivables (December 31, 2017 USD 0.1 million, Cash and USD 4,000, Other Receivables).
Revenue from major sources from continuing operations:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Oil revenue (net) | 12,090 | 6,021 |
| Other revenue | 877 | 497 |
| Total Revenue (net) | 12,967 | 6,518 |
There are no differences in the nature of measurement methods used on segment level compared with the consolidated financial statements. The oil revenue in 2018 related to sale of hydrocarbons from two assets, Dussafu in Gabon and Aje in Nigeria. All sales in 2018 arose from one key customer. Oil revenue in 2017 related to one field, Aje in Nigeria and all sales were from one key customer. Under the terms of the Dussafu PSC, the State profit oil is shown as revenue, this is reflected in other revenue in 2018, with a corresponding amount as income tax (Note 6). Other revenue in 2017 related to the gain on disposal of the sale of 25% stake in Dussafu.
Operating profit is stated after charging/ (crediting):
| USD 000 | Note | 2018 | 2017 |
|---|---|---|---|
| Employee benefits expense | 1,718 | 1,548 | |
| Depreciation | 9 | 3,568 | 1,898 |
| Impairment and asset write-off | 9.4 | - | 28,576 |
| Operating lease payments | 236 | 228 | |
| Non-recurring costs (i) | 965 | 995 |
(i) Non-recurring costs incurred during 2018 primarily relate to acquisition projects which has been expensed as incurred and are reported separately from recurring G&A costs for comparative purposes. These costs mainly include transaction related advisory, legal and business integration costs. During 2017, these costs related to the Aje dispute costs.
General and administrative expenses include wages, employers' contribution and other compensation as detailed below:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Salaries | 1,330 | 1,217 |
| Employers contribution | 186 | 156 |
| Pension costs | 110 | 104 |
| Other compensation | 93 | 71 |
| Total | 1,718 | 1,548 |
The number of employees in the Group as at year end is detailed below:
| 2018 | 2017 | |
|---|---|---|
| Number of employees | 31 | 5 |
The number of employees do not include temporary contract staff and personnel employed by joint ventures where the group is participating as non-operated partner.
In accordance with the Norwegian Public Limited Liability Companies Act §6-16a, the Board of Directors must prepare a statement on remuneration of executives. This statement can be referred to on page 88 of this report.
Executive management has in previous years, consisted of the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and Technical Director. Current Executive management remuneration is summarized below:
| 2018 | Short term benefits | ||||||
|---|---|---|---|---|---|---|---|
| USD 000 (unless stated otherwise) | Salary | Bonus | Benefits | Pension costs |
Total | Number of RSUs awarded in 2018 |
Fair value of RSUs expensed |
| John Hamilton, CEO | 375 | 99 | 10 | 36 | 520 | 196,304 | 170 |
| Qazi Qadeer, CFO | 236 | 48 | 5 | 23 | 312 | 63,002 | 67 |
| Richard Morton, Technical Director | 236 | 51 | 5 | 24 | 316 | 63,002 | 60 |
| Total | 847 | 198 | 20 | 83 | 1,148 | 322,308 | 297 |
| 2017 | Short term benefits | ||||||
|---|---|---|---|---|---|---|---|
| USD 000 (unless stated otherwise) | Salary | Bonus | Benefits | Pension costs |
Total | Number of RSUs awarded in 2017 |
Fair value of RSUs expensed |
| John Hamilton, CEO | 380 | 94 | 8 | 36 | 518 | 200,000 | 64 |
| Qazi Qadeer, CFO | 227 | 43 | 4 | 22 | 296 | 100,000 | 32 |
| Richard Morton, Technical Director | 239 | 45 | 4 | 23 | 311 | 80,000 | 26 |
| Total | 846 | 182 | 16 | 81 | 1,125 | 380,000 | 122 |
(i) Under the terms of employment, the CEO, CFO and Technical Director in general is required to give at least six month's written notice prior to leaving Panoro.
Refer to Note 17 for further information on the Restricted Share Units scheme.
The remuneration of the members of the Board is determined on a yearly basis by the Company at its annual general meeting. The directors may also be reimbursed for, inter alia, travelling, hotel and other expenses incurred by them in attending meetings of the directors or in connection with the business of Panoro Energy ASA. A director who has been given a special assignment, besides his/her normal duties as a director of the Board, in relation to the business of Panoro Energy ASA may be paid such extra remuneration as the directors may determine.
Remuneration to members of the Board of Directors is summarized below:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Julien Balkany (Chairman of the Board of Directors) | 69 | 68 |
| Alexandra Herger | 42 | 39 |
| Garrett Soden | 42 | 39 |
| Torstein Sanness | 42 | 39 |
| Hilde Ådland | 42 | 39 |
| Total | 236 | 224 |
The Chairman of the Board of Directors' annual remuneration is NOK 460,000. The remaining Directors' annual remuneration is NOK 240,000. All Board Members also form the Audit Committee and Remuneration Committee for which they each receive NOK 50,000 annually per committee. No loans have been given to, or guarantees given on the behalf of, any members of the Management Group, the Board or other elected corporate bodies.
The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension ("Lov om obligatorisk tjenestepensjon"). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognised in the statement of financial position. As of December 2018, the Company had no employees at parent company level and this pension plan is no longer in operation (2017: nil).
In the UK, the Company's subsidiary that employs staff, contributes a fixed amount per Company policy in an external defined contribution scheme. As such, no pension liability is recognised in the statement of financial position in relation to the Company's London based employees. No occupational pension scheme is mandated in Tunisia. Companies are required to pay a fixed percentage of gross salary of each employee as "social security" to the government authorities, in addition to a fixed deduction from gross monthly salary as employee contribution. As such, no pension liability is recognised in the statement of financial position for these deductions.
Refer to Note 4.1 for the contributions made to the external defined scheme for 2018 and 2017.
Fees, excluding VAT, to the auditors are included in general and administrative expense and are shown below:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Ernst & Young | ||
| Statutory Audit | 160 | 93 |
| Total Audit Services | 160 | 93 |
| Non-audit Services | ||
| Corporate financial services including pre-acquisition due diligence | 358 | - |
| Total non-audit services | 358 | - |
| Total | 518 | 93 |
Interest costs net of (income)/expense
| USD 000 | 2018 | 2017 |
|---|---|---|
| Unrealised (gain) / loss on commodity hedges (Note 18) | (756) | - |
| Interest income from placements and deposits | (49) | (33) |
| Interest expense | 371 | 287 |
| Other financial costs – Bank charges and ARO Interest | 166 | 136 |
| Total – Net (income) / expense | (268) | 390 |
| Lender | Interest | Potential term of repayment |
Balance to be repaid |
Repayable within one year |
Repayable after one year |
|---|---|---|---|---|---|
| USD 000 – As at December 31, 2018 | |||||
| Mercuria Senior Secured Loan (Note 5.1.1) | USD 3-month LIBOR + 6.0% p.a., paid quarterly on drawn amounts |
Up to 5 years |
16,200 | 2,640 | 13,560 |
| Unamortised borrowing costs | (470) | (101) | (369) | ||
| Total - Senior Secured Loan | 15,730 | 2,539 | 13,191 | ||
| BW Energy non-recourse loan (Note 5.1.2) | 7.5% per annum on outstanding balance, compounded annually. |
No fixed term, subject to complete recovery as described below. |
13,143 | 3,751 | 9,392 |
| Total - BW Energy non-recourse loan | 13,143 | 3,751 | 9,392 |
On December 13, 2018 the Group entered into an agreement with Mercuria Assets Holdings (Hong Kong) Ltd ("Mercuria"), whereby Mercuria provided PTP (60% owned by Panoro) an acquisition loan facility comprising: i) a Senior Secured Loan facility of USD 16.2 million (USD 27 million gross), and ii) an additional Junior Loan facility for a further USD 4.8 million (USD 8 million gross). The Senior Secured Loan facility was fully drawn as of December 31, 2018. The Junior Loan facility remains undrawn as of December 31, 2018 and available up to six months from December 17, 2018.
The Senior Loan facility has a term of 5 years with interest charged at USD 3-month LIBOR plus 6% on quarterly amounts drawn, with repayments due each quarter. Interest of USD 0.06 million was accrued up to December 31, 2018.
The Junior Loan facility has a term of 6 years. Interest is charged at USD 3-month LIBOR plus 8% on quarterly amounts drawn, with repayments due each quarter in cash. The Junior
Loan facility also incurs a commitment fee at 40% per annum of the applicable margin on the undrawn amount during the availability period.
In addition, the Senior and Junior Loan facilities include financial covenants, most of which are required to be tested at the end of every 3-month period. These covenants, applicable at levels of the borrower group as defined in the loan documentation, include the following:
The Company was not in breach of any financial covenants as at the balance sheet date, nor at the date of approval of these financial statements by the Board.
The current and non-current portion of the outstanding balance as of December 31, 2018 attributable to Panoro's 60% ownership is as follows (December 31, 2017: Nil):
| Current USD 000 |
Non-current USD 000 |
Total USD 000 |
|
|---|---|---|---|
| Senior Secured Loan facility | 2,640 | 13,560 | 16,200 |
| Unamortised borrowing costs | (101) | (369) | (470) |
| Total carrying value of interest-bearing debt | 2,539 | 13,191 | 15,730 |
Un-amortised borrowing costs include structuring fees of USD 0.35 million and directly attributable legal and other thirdparty costs of USD 0.12 million thereby resulting in an effective interest rate of 10.20% per annum. The unamortised cost will be expensed using the effective interest rate method over the term of the loan.
Security package for the Senior Secured loan comprises of a Guarantee from Panoro Energy ASA, share pledge over shares in Panoro TPS Production GmbH and from Panoro Tunisia Production AS, shareholder and intercompany loans (subordinated at all times), rights under hedging agreements, and the Account Management Agreement (for the Collection Account), negative pledge over the assets.
In an event, the guarantee placed by Panoro Energy ASA is called upon, the shareholders' agreement with Beender for the ownership on Sfax Petroleum Corporation AS provides that Sfax Petroleum Corporation AS shall indemnify Panoro Energy ASA. If Sfax Petroleum Corporation AS is unable to indemnify, Panoro Energy ASA, such indemnification, pro rata to its ownership, shall be made by Beender.
The Company has in place a non-recourse loan from BW Energy in relation to the funding of Phase 1 of the Dussafu development. As of December 31, 2018, Panoro's drawdown on the non-recourse loan had reached its ceiling of USD 12.5 million in principal (2017: USD 2.2 million). Accumulated interest as of December 31, was USD 0.6 million (2017: USD 0.06 million). Following First Oil on Dussafu, achieved during the previous quarter and the first lifting in this quarter, repayment of the non-recourse loan has now commenced. A USD 0.9 million payment has been made in January 2019 towards the loan repayment.
The loan is repayable through Panoro's allocation of the cost oil in accordance with the Dussafu PSC, after paying for the proportionate field operating expenses and as such the loan has now been reclassified into short-term and long-term liabilities in the reporting quarter. During the repayment phase, Panoro will still be entitled to its share of profit oil, as defined in the PSC, from the Dussafu operations.
The major components of income tax in the consolidated statement of comprehensive income are. The income tax disclosures below include items from both continuing and discontinued operations:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Income Taxes | ||
| Current income tax – continuing and discontinued operations | 896 | - |
| Current income tax – Prior years | 46 | - |
| Tax charge / (benefit) for the period | 942 | - |
Under the terms of the Dussafu PSC, the State profit oil is shown as revenue, this is reflected in other revenue in 2018 (Note 3), with a corresponding amount as income tax
A reconciliation of the income tax expense applicable to the accounting profit before tax at the statutory income tax rate to the expense at the Group's effective income tax rate is as follows:
| USD 000 | 2018 | 2017 |
|---|---|---|
| (Loss) before taxation – continuing | (6,087) | (36,316) |
| Profit / (Loss) before taxation – discontinued operations | (102) | (277) |
| Profit /(Loss) before taxation – Total | (6,189) | (36,593) |
| Tax calculated at domestic tax rates applicable to profits in the respective countries | (2,034) | (9,754) |
| Expenses not deductible | 1,509 | 8,197 |
| Expenses deductible for tax | (386) | - |
| Effect of taxes under PSC arrangements | 877 | - |
| Tax effect of losses not utilised in the period | 930 | 1,588 |
| Prior year adjustment | 46 | (4) |
| Tax charge / (benefit) | 942 | 27 |
There are no recognised deferred tax assets in the Group financial statements as of December 31, 2018.
Deferred tax assets are recognised for tax loss carry-forwards to the extent that the realization of the related tax benefits through future taxable profits is probable. The Group did not recognise deferred income tax assets of USD 12 million (2017: USD 14 million) in respect of losses that can be carried forward against future taxable income.
The Group has provisional accumulated tax losses as of year-end that may be available to offer future taxable income in the respective jurisdictions. All losses are available indefinitely except for Cyprus which, effective from the year 2012, expire after a maximum of five years since origination.
| USD 000 | 2018 | 2017 |
|---|---|---|
| Norway | 41,439 | 46,191 |
| UK | 2,471 | 2,431 |
| Cyprus | 10,176 | 10,174 |
| Brazil | - | - |
| Netherlands | 4,186 | 3,962 |
| Total | 58,272 | 62,759 |
The decline in tax losses in Norway is primarily due to the reassessment and reduction of losses by the Norwegian Tax authorities following an assessment ruling on exchange rate translations for the period 2014-2016.
| USD 000, unless otherwise stated | 2018 | 2017 |
|---|---|---|
| Net loss attributable to equity holders of the parent – Total | (7,107) | (36,589) |
| Net loss attributable to equity holders of the parent – Continuing operations | (6,964) | (36,312) |
| Weighted average number of shares outstanding - in thousands | 45,437 | 42,502 |
| Basic and diluted earnings per share - (USD) – Total | (0.16) | (0.86) |
| Basic and diluted earnings per share - (USD) – Continuing operations | (0.15) | (0.85) |
When calculating the diluted earnings per share, the weighted average number of shares outstanding is normally adjusted for all dilutive effects relating to the Company's Restricted Share Units.
The Restricted Share Units had an anti-dilutive effect on earnings per share for both periods presented.
| USD 000 | Licences, exploration and evaluation assets |
Development assets |
|---|---|---|
| At January 1, 2018 | 59,438 | 29,004 |
|---|---|---|
| Additions* | 1,601 | 14,024 |
| Transfer to Production Assets | - | (15,718) |
| Additions through Acquisition (Note 12.3) | - | 632 |
| At December 31, 2018 | 61,039 | 27,942 |
| At January 1, 2018 | 45,842 | 27,310 |
|---|---|---|
| Impairment | - | - |
| At December 31, 2018 | 45,842 | 27,310 |
| Net carrying value at December 31, 2018 | 15,197 | 632 |
|---|---|---|
* the development assets additions for 2018 include capitalised borrowing costs of USD 643,000 (2017: USD 186,000) relating to the BW Energy Non-Recourse loan for the Dussafu development. Also see Note 5.1.
| USD 000 | Licences, exploration and evaluation assets |
Development assets |
|---|---|---|
| Historical cost | ||
| At January 1, 2017 | 64,771 | 31,562 |
| Additions | 2,782 | 1,380 |
| Transfer to Licences, Exploration & Evaluation Assets | 8,246 | (8,246) |
| Transfer to Development Assets | (4,308) | 4,308 |
| Disposal of Dussafu | (12,053) | - |
| At December 31, 2017 | 59,438 | 29,004 |
| Accumulated impairment |
| At January 1, 2017 | 38,800 | 31,562 |
|---|---|---|
| Impairment | 7,042 | (4,252) |
| At December 31, 2017 | 45,842 | 27,310 |
| Net carrying value at December 31, 2017 | 13,596 | 1,694 |
|---|---|---|
Upon commencement of commercial production from the Aje field, offshore Nigeria, historical costs capitalised since inception have been reviewed and bifurcated between costs attributable to Cenomanian Oil field and other gas discoveries on the OML 113 license. As a result, bifurcated costs have been broadly categorised between Exploration & Evaluation ("E&E") assets and Production Assets. E&E asset additions in the fourth quarter include the costs associated with the OML 113 licence renewal at Aje.
The commencement of the Dussafu development led to a review of the Dussafu capitalised costs; this resulted in the bifurcation of costs being rationalised and categorised between E&E and Development activities. Following the commencement of commercial production from Dussafu during the third quarter, costs incurred post-Final Investment Decision of USD 15.7 million have been reclassified as Production Assets which are depreciable in nature.
| Licence area | Panoro's interest Country |
Expiry of current phase | |
|---|---|---|---|
| OML 113 | 6.502% participating interest, 12.1913% entitlement to revenue stream and 16.255% paying interest |
Nigeria | August 2038 |
| Dussafu Marin permit | 8.333% | Gabon | Ten years from commencement of production * |
| Sfax Offshore Exploration Permit |
52.5% (Operator) – excluding Beender's 40% | Tunisia | December 2018 ** |
| Hammamet Offshore Exploration Permit |
27.6% - excluding Beender's 40% | Tunisia | Under relinquishment |
TPS Assets:
| Cercina | February 2024 | ||
|---|---|---|---|
| Cercina South | November 2034 | ||
| Gremda / El Ain | 29.4% - excluding Beender's 40% | Tunisia | December 2018 ** |
| Guebiba | June 2033 | ||
| Rhemoura | January 2023 |
* The third Exploration Phase under the Dussafu Marin Production Sharing Contract ("PSC") expired on May 27, 2016. The Ruche area Exclusive Exploitation Authorization ("EEA") under the Dussafu Marin PSC was granted on July 14, 2014 and is effective from that date until ten years from the date of commencement of production. If, at the end of this ten-year term commercial exploitation is still possible from the Ruche area, the EEA shall be renewed at the contractor's request for a further period of five years. Subsequent to this, the EEA may be renewed a second time for a further period of five years.
** In process of being renewed.
| USD 000 | 2018 | 2017 |
|---|---|---|
| Acquisition cost | ||
| At January 1 | - | - |
| Additions | - | - |
| Additions through Acquisition (Note 12.3) | 31,082 | - |
| At December 31 | 31,082 | - |
Production rights represent the fair value of production rights determined by the Purchase Price Allocation, determined as part of the OMV Transaction – see Note 12.3.
| NOTE 9.1: PRODUCTION ASSETS AND EQUIPMENT | ||
|---|---|---|
| USD 000 | 2018 | 2017 |
| Historical cost | ||
| At January 1 | 62,105 | 49,832 |
| Additions | 2,065 | 12,273 |
| Transfer from Development Assets | 15,718 | - |
| Additions through Acquisition (Note 12.3) | 17,385 | - |
| At December 31 | 97,273 | 62,105 |
| Accumulated impairment | ||
| At January 1 | 48,241 | 22,413 |
| Impairment charge for the year | - | 25,828 |
| At December 31 | 48,241 | 48,241 |
| Accumulated depreciation | ||
| At January 1 | 3,962 | 2,134 |
| Depreciation charge for the year | 3,458 | 1,828 |
| At December 31 | 7,420 | 3,962 |
| Net carrying value at December 31 | 41,612 | 9,902 |
| USD 000 | Leasehold | Furniture, Fixture and Fittings |
Computer Equipment |
Total |
|---|---|---|---|---|
| Historical cost | ||||
| At January 1, 2018 | 55 | 104 | 494 | 653 |
| Additions | - | - | - | - |
| Additions through Acquisition | - | 680 | - | 680 |
| At December 31, 2018 | 55 | 784 | 494 | 1,333 |
| Accumulated depreciation | ||||
| At January 1, 2018 | 25 | 75 | 450 | 550 |
| Depreciation charge for the year | 10 | 80 | 19 | 109 |
| Acquired through Acquisition | - | 540 | - | 540 |
| At December 31, 2018 | 35 | 695 | 469 | 1,199 |
| Net carrying value at December 31, 2018 | 20 | 89 | 25 | 134 |
| USD 000 | Leasehold | Furniture, Fixture and Fittings |
Computer Equipment |
Total |
|---|---|---|---|---|
| Historical cost | ||||
| At January 1, 2017 | 55 | 104 | 490 | 649 |
| Additions | - | - | 4 | 4 |
| Disposals / write-downs | - | - | - | - |
| At December 31, 2017 | 55 | 104 | 494 | 653 |
| Accumulated depreciation | ||||
| At January 1, 2017 | 15 | 46 | 419 | 480 |
| Depreciation charge for the year | 9 | 29 | 32 | 70 |
| Disposals / write-downs | - | - | - | - |
| At December 31, 2017 | 25 | 75 | 450 | 550 |
| Net carrying value at December 31, 2017 | 30 | 29 | 44 | 103 |
| Category | Straight-line depreciation | Useful life |
|---|---|---|
| Furniture, fixtures and fittings | 10-33.33% | 3 - 10 years |
| Computer equipment | 20-33.33% | 3 - 5 years |
Other non-current assets amount to USD 0.2 million. USD 0.1 million relates to the tenancy deposit for the UK office premises; USD 0.1 million was acquired through acquisition and relates to advance income tax paid on the Gremda concession which has not been producing for over a year. These amounts will be utilised once the license on this concession is finalised and production resumes.
The Group has an 8.333% interest in the Dussafu Permit, offshore Gabon. In September 2018, the Phase 1 development on Tortue field was completed and production commenced from two wells. The production operations have largely been on prognosis and on time and budget. Following the year end, a final investment decision was taken on Phase 2 of the project whereby up to four new producing wells will be added to the filed. As a result, the reserves have been upgraded for the Tortue field which, following Phase 2 development is likely to provide higher recoverable amounts on both 1P and 2P profiles. However as of December 31, 2018 no impairment indicators were present, and an impairment review will be conducted in 2019 after considering the early production data, outlook of commodity prices, timing of the Phase 2 investment decision and the available level of the previously impaired costs.
The Group also holds investment in OML 113 license, offshore Nigeria and has a 16.255% participating interest in the field with revenue interest 12.1913%. The carrying value for this asset as at December 31, 2018 was USD 13.6 million, comprising USD 7 million of Exploration & Evaluation (E&E) assets and USD 6.6 million for production related assets.
The OML 113 carrying value included in E&E assets represents the discovered gas reserves on the license, which was extended for another 20 years in 2018. Therefore, no impairment triggers were noted and no impairment charge was recognised in 2018 (2017: USD 13.1 million).
The carrying value of USD 6.6 million for production assets as at December 31, 2018 (2017: USD 9.9 million) comprised production assets and equipment capitalised on the balance
sheet relating entirely to Aje Cenomanian oil field within OML 113 license. In the year 2017, USD 19.7 million was impaired, triggered by multiple factors including; changes in the operational plan following lower than expected production; higher than anticipated costs of Aje-5 workovers and well interventions; and independent reserves report as of December 31, 2017 indicating a decline in Cenomanian oil reserves. Aje field has been performing steadily since 2017 without any meaningful decline in the production rates. Further, effective as of December 31, 2018, there has been higher amount of 2P reserves attributed to the Aje field, increased from 0.25 million bbls in 2017 to 0.27 million barrels net to Panoro (after taking into account 2018 production). On an overall basis, having considered the OML 113 2P reserves of 21.9 mmbbls against the current carrying value, no impairment triggers were noted and no impairment charge was recognised.
During the year the Group has acquired an interest in Sfax Offshore Exploration Permit (SOEP) in Tunisia which was acquired from DNO ASA at no consideration. As a result, the carrying value of the license is nil in the Company's statement of financial position at the date of acquisition. Application for the licenses is pending renewal and capitalisation is expected to commence post licence renewal.
As of December 21, 2018, The Group completed the acquisition of its share of interest in TPS Assets, comprising of Cercina, Cercina Sud, Rhemoura, El Ain/Gremda and El Hajeb/Guebiba concessions. No impairment test has been performed as of December 31, 2018 given the fair value was determined very close to the balance sheet date in the form of Purchase Price Allocation detailed to in Note 12.3.
In general, adverse changes in key assumptions could result in recognition of impairment charges. Since there are no charges during the year, the sensitivities have not been presented in these financial statements. The Group will continue to test its assets for impairment where indications are identified and may in future recognise impairment charges or reversals.
The breakdown of the net impairment expense for continuing operations is:
| 2018 | 2017 | |||||||
|---|---|---|---|---|---|---|---|---|
| USD 000 | Nigeria | Gabon | Corporate | Total | Nigeria | Gabon | Corporate | Total |
| Capitalised licenses, exploration and evaluation assets |
- | - | - | - | 13,142 | (4,252) | - | 8,890 |
| Production assets and equipment | - | - | - | - | 19,686 | - | - | 19,686 |
| Total charge for the year ended December 31, |
- | - | - | - | 32,828 | (4,252) | - | 28,576 |
| USD 000 | 2018 | 2017 |
|---|---|---|
| Accounts receivable | 3,790 | - |
| Other receivables and prepayments | 1,558 | 615 |
| Underlift – Dussafu | 229 | - |
| At December 31 | 5,577 | 615 |
Accounts receivables are non-interest bearing and generally on 30-120 days payment terms. At December 31, 2018 and 2017 the allowance for impairment of receivables was USD nil. Risk information for the receivable balances is disclosed in Note 19.
| USD 000 | 2018 | 2017 |
|---|---|---|
| Cash and cash equivalents | 23,367 | 6,317 |
| Restricted cash | 76 | 1,500 |
| Cash and bank balances at December 31 | 23,443 | 7,817 |
The majority of Panoro's cash balance was denominated in NOK and USD and was held in different jurisdictions including Norway, Austria and Tunis. Restricted cash balance at December 31, 2017 comprised cash collateral supporting the legal case for Aje. This was released back to the Company following signing of the settlement agreement during 2018.
The Group had no bank overdraft facilities as at December 31, 2018 (December 31, 2017: Nil).
The details of the transactions, including the acquisitions in Tunisia and strategic agreement entered into during 2018 are summarised below.
On December 11, 2018, Panoro entered into a strategic agreement with Beender Petroleum Limited ("Beender"), a privately held oil and gas company focused on proven oil fields with upside. The strategic agreement documents Panoro and Beender's participation in Tunisian growth opportunities on a 60/40 basis through a holding company, Sfax Petroleum Corporation AS (hereafter referred to as "Sfax Corp") with an effective date of July 1, 2018. Panoro contributed all shares in PTE to Sfax Corp and consequently, Panoro and Beender respectively hold 60% and 40% of the shares in Sfax Corp. As a result, Panoro's effective participation in the acquired assets, liabilities and work obligations in DNO Tunisia AS has reduced to 60% through ownership in Sfax Corp. The details of the acquisition of DNO Tunisia AS are covered in Note 12.2.
Similarly, the OMV transaction was completed on December 21, 2018 and shares in OMV Tunisia Upstream GmbH was acquired by Panoro Tunisia Production AS, a fully owned subsidiary of Sfax Corp. Details of this acquisition are included in Note 12.3.
As a result, all the assets, liabilities, work obligations and results have been consolidated by Panoro Energy ASA at 60%, on a line by line basis, from the respective dates for:
Panoro Energy AS completed the acquisition of PTE on July 30, 2018 resulting in the acquisition of interests in two offshore Production Sharing Contracts (PSCs) assets, Sfax Offshore Exploration Permit ("SOEP"), and the Ras El Besh Concession, which is within the SOEP area. The acquisition of shares of DNO Tunisia AS was made at no cash consideration paid upon closing.
Following the arrangement with Beender, the consolidation of DNO Tunsia AS as of December 31, 2018 has been included at 60% representing Panoro's share as of the acquisition date of July 30, 2018.
The table below identifies Panoro's share at 60% of the provisional fair values of the identifiable assets and liabilities of DNO Tunisia AS (renamed to Panoro Tunisia Exploration AS) at the date of acquisition of July 30, 2018:
| Gross at 100% USD 000 |
Panoro's share at 60% USD 000 |
|
|---|---|---|
| ASSETS | ||
| Cash and cash equivalents | 8,735 | 5,241 |
| Financial assets | 72 | 43 |
| Tangible and intangibles assets | 234 | 140 |
| Inventories | 1,470 | 882 |
| Total Assets | 10,511 | 6,306 |
| LIABILITIES | ||
| Trade and other liabilities | 691 | 414 |
| License obligations and deferred consideration (i) | 9,820 | 5,892 |
| Total liabilities | 10,511 | 6,306 |
| Net assets acquired with the company | - | - |
| Net loss since acquisition | (1,454) | (872) |
| Cash inflow on acquisition | ||
| Net cash acquired with the transaction | 8,735 | 5,241 |
On December 21, 2018 Panoro Energy ASA's 60% owned subsidiary PTP, acquired 100% of the shares of OMV Tunisia GmbH (renamed to Panoro TPS Production GmbH "Panoro TPS" following acquisition). Panoro TPS owns 49% interest in five oil producing concessions located near the city of Sfax in Tunisia. In addition, Panoro TPS holds 50% of the issued share capital in an operational company, Thyna Petroleum Services
S.A. (TPS) which is a joint operating company managing the operations for these concessions. The remaining stake in TPS is owned by the Tunisian National Oil Company (ETAP) which also holds 51% of the ownership of the five oil field concessions.
The consideration for this acquisition was USD 39 million (USD 65 million gross), paid in cash and adjusted for permitted distributions and other working capital adjustments.
| Gross USD 000 |
Panoro's share at 60% USD 000 |
|
|---|---|---|
| Cash consideration | 65,000 | 39,000 |
| Less: working capital and completion adjustments | (7,998) | (4,799) |
| Cost of business combination / Consideration Paid | 57,002 | 34,201 |
| Net assets acquired | 57,002 | 34,201 |
(i) Purchase Price Allocation of the purchase consideration has been determined based on the values as at December 31, 2018. There were no material changes between closing and the valuation date.
The provisional fair values of the identifiable assets and liabilities of Panoro TPS as at the date of acquisition were as follows:
| Purchase price allocation | Gross USD 000 |
Panoro's share at 60% USD 000 |
|---|---|---|
| Assets | ||
| Production rights | 51,803 | 31,082 |
| Production assets and equipment | 28,975 | 17,385 |
| Materials inventory | 4,400 | 2,640 |
| Development assets | 1,053 | 632 |
| Trade receivables | 1,957 | 1,173 |
| Crude oil inventory | 898 | 539 |
| Other short-term receivables | 1,485 | 891 |
| Other non-recurrent assets | 194 | 116 |
| Investment in associates | 63 | 38 |
| Cash and cash equivalents | 6,376 | 3,826 |
| Total Assets | 97,204 | 58,322 |
| Liabilities | ||
| Decommissioning liability | 28,415 | 17,049 |
| Corporation tax liability | 9,605 | 5,763 |
| Other non-current liabilities | 1,716 | 1,030 |
| Trade payables | 465 | 279 |
| Total liabilities | 40,202 | 24,121 |
| Net assets acquired | 57,002 | 34,201 |
| Cash flow on acquisition | ||
| Net cash acquired with the transaction | 6,376 | 3,826 |
(i) Acquisition related costs included advisory fees which have been recognised in the Company's statement of comprehensive income amounted to USD 0.7 million.
(ii) The completion date was December 21, 2018, results post acquisition have not been included as there was no material activity in the intervening period to December 31, 2018.
Subsequent to the Board of Directors' decision to formally exit Brazil and wind-down the operations, the remaining licences in BS-3 area have been relinquished and abandonment plans have been filed with ANP. The remaining formalities are being managed in Rio de Janeiro by a third-party agent.
The Company intends to keep a low-cost corporate presence for its subsidiary Panoro Energy do Brasil Ltda.
As a result, the operations of Company's subsidiaries in Brazil have been classified as discontinued operations under IFRS 5.
The results of Brazilian segment for the previous year have been carved out of the operating results and presented below as discontinued operations:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Total revenues | - | - |
| Operating costs | - | - |
| General and administration costs | (74) | (71) |
| EBITDA | (74) | (71) |
| Depreciation | - | - |
| Impairment | (23) | (130) |
| EBIT - Operating income / (loss) | (97) | (201) |
| Other financial costs net of income | - | 4 |
| Net foreign exchange gain / (loss) | - | (6) |
| Income / (loss) before tax | (97) | (203) |
| Income tax benefit / (expense) | (46) | (74) |
| Net income / (loss) for the period from discontinued operations | (143) | (277) |
| Earnings per share (basic and diluted) for the period from discontinued operations (USD) | (0.01) | (0.01) |
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 the reserves of the field are depleted. However, based on the existing production profile of the Aje 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 provision is based on the discount rate assumptions between 2.86% - 5.9% and an inflation rate assumption used between 1.5% and 2.20%, applicable to the individual asset profile. 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:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Balance for provision at December 31, | 2,039 | 1,925 |
| Recognised during the year (Gabon) | 1,509 | - |
| Accretion of interest (Nigeria and Gabon) | 142 | 114 |
| Acquired during the year through business combination (OMV Transaction) | 17,049 | - |
| At December 31 | 20,739 | 2,039 |
The total decommission liability of USD 2 million at December 31, 2017 related to the Company's Nigerian asset.
A decommissioning liability of USD 17 million (USD 28 million gross) as of December 31, 2018 was acquired as part of the OMV transaction. Refer to Note 12.3 for details of the OMV transaction including the purchase price allocation.
| Amounts in USD 000 unless otherwise stated | Number of shares | Nominal Share Capital | |
|---|---|---|---|
| As at January 1, 2018 | 42,502,196 | 299 | |
| Issue of shares – Private Placement July 2018 (Note 15.2) | 4,250,219 | 26 | |
| Share issue under RSU Plan (Note 15.3) | 55,185 | - | |
| Issue of shares – Private Placement – November 2018 (Note 15.4) | 15,580,000 | 98 | |
| Purchase of own shares (Note 15.5) | 166,162 | - | |
| Payment of Mercuria loan fee in shares – own shares transferred (Note 14.5) | (166,162) | - | |
| As at December 31, 2018 | 62,387,600 | 423 |
Panoro Energy was formed through the merger of Norse Energy's former Brazilian business and Pan-Petroleum on June 29, 2010. The Company is incorporated in Norway and the share capital is denominated in NOK. The share capital given above is translated to USD at the foreign exchange rate in effect at the time of each share issue. All shares are fully paidup and carry equal voting rights.
In July 2018, the Company has successfully completed a Private Placement resolving to issue 4,250,219 new shares each at NOK 12.82 per share to subscribers. In addition, the Company resolved to allot and sell 1,000,000 treasury shares, at a price of NOK 12.82 per share, which together with the Private Placement raised USD 8.3 million (NOK 67 million) in gross proceeds.
In connection with the Company's Restricted Share Units Plan, announced on August 6, 2018, the Company issued 55,185 new shares to employees.
In November 2018, the Company has successfully completed a Private Placement by issuing 15,580,000 new shares each at NOK 16.10 per share to the subscribers. The Private Placement raised USD 30 million (NOK 250 million) in gross proceeds.
In December 2018, the Company completed the buy-back of 166,162 shares in order to pay the junior loan fee consideration to Mercuria (more details in Note 5.1.1) in accordance with the Secured loan facility agreement. The Company purchased 166,162 shares at an average price of NOK 12.5265 per share and transferred them to Mercuria to settle the fee consideration.
As at December 31, 2018, the Company had a registered share capital of NOK 3,119,380 divided into 62,387,600 shares, each having a nominal value of NOK 0.05 (December 31, 2017: NOK 2,125,109.80 divided into 42,502,196 shares).
The Company's twenty largest shareholders are referenced in the Parent Company Accounts, please refer to Note 9.
| Shareholder | Position | Number of shares | % of total |
|---|---|---|---|
| Julien Balkany(i) | Chairman of the Board of Directors | 3,116,035 | 4.99% |
| Torstein Sanness | Director | 132,111 | 0.21% |
| Garrett Soden (ii) | Director | 10,008 | 0.02% |
| Alexandra Herger | Director | 5,950 | 0.01% |
| Hilde Ådland | Director | 7,005 | 0.01% |
| John Hamilton | Chief Executive Officer | 167,912 | 0.27% |
| Qazi Qadeer | Chief Financial Officer | 77,062 | 0.12% |
| Richard Morton | Technical Director | 122,425 | 0.20% |
Shares owned by the CEO, board members and key management, directly and indirectly, at December 31, 2018:
(i) Mr. Balkany has beneficial interest in Nanes Balkany Partners I LP which owns 600,106 shares in the Company, and Balkany Investments LLC which owns 2,485,120 shares in the Company. In addition, Mr. Balkany directly holds 30,809 shares in the Company.
(ii) Mr. Soden holds directly or indirectly 10,008 shares in the Company.
Share premium reserve represents excess of subscription value of the shares over the nominal amount.
Other reserves represent an item arising on accounting for the historical merger with Company's subsidiary Panoro Energy do Brasil Ltda.
Additional paid-in capital represents reserves created under the continuity principle on demerger. Share-based payments credit is also recorded under this reserve and so is the credit from reduction of share capital by reducing the par value of shares.
The translation reserve comprises all foreign exchange differences arising from the translation of the financial statements of foreign operations.
| USD 000 | 2018 | 2017 |
|---|---|---|
| Accounts payable | 497 | 141 |
| Accruals and other liabilities | 7,054 | 6,669 |
| Other non-current liabilities | 7,877 | 9,089 |
| At December 31 | 15,428 | 15,899 |
Since the settlement of the Aje dispute at the beginning of 2018, the Company has performed a review of historical costs incurred and recognised the liabilities associated with such expenditures in the balance sheet. The proportionate joint venture liabilities resulting from the workover and sidetracks at Aje-5 had been higher than anticipated and in combination with the operation accruals and the inclusion of the cost of the OML 113 20-year licence renewal have resulted in proportional liabilities of USD 5.8 million as of December 31, 2018, compared to USD 6.1 million as of December 31, 2017.
Despite the year-on-year decrease of only USD 0.3 million, the underlying liabilities continue to reduce through the allocation of excess funds from Aje liftings. During 2018, the renewal of the Aje Licence for a further 20 years increased the operational payables (USD 1.6 million net to the Company), since the operations are funded in entirety from field cash flows. Such liabilities continue to be current in nature and are expected to be repaid within 12 months through the 2019 Aje lifting schedule.
In addition to these, USD 6.8 million is classified as long-term liabilities which as per the terms agreed between OML 113 Joint Venture partners, certain transitional arrangements were introduced whereby unpaid cash calls will not be immediately payable. During the transition period, any excess funds from Panoro's entitlement of crude liftings after paying for its share of operating expenditure shall be used to repay unpaid cash calls. We do not currently anticipate any use of Panoro's cash resources and expect it to be funded from the sale of our share of Aje crude.
USD 1.0 million of non-current liabilities form part of the liabilities acquired through the acquisition of Panoro TPS (See Note 12.3).
At the annual general meeting held on May 24, 2018, the existing RSU scheme (as presented and approved in the May 27, 2015 annual general meeting), was approved for another three years up to the general meeting to be held in the year 2021. Under this approved employee incentive scheme, the Company may issue RSUs to executive and key employees. Awards under the RSU scheme will normally be considered one time per year and grant of share-based incentives will, in value (calculated at the time of grant), be capped to 100% of the annual base salary for the CEO and 50% of the annual base salary for other members of the executive management. One RSU will entitle the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. The total number of RSUs available for grant under the RSU program during the period from the 2018 annual general meeting and up to the annual general meeting in 2021 shall not exceed 5% of the number of shares outstanding as per the date of the 2018 annual general meeting (at which point in time the total number of shares in issue were 42,502,196). Grant of RSUs will be subject to a set of performance metrics with threshold and factors reviewed annually by the Board of Directors. Such metrics will be set as objectives based on sustained performance results including mostly share price increases and achievement of specific financial performance measures related to a group of oil and gas exploration and production peers that has been defined and adopted by a committee established by the Board.
The movement of RSUs during the year are tabled below:
| 2018 | 2017 | |
|---|---|---|
| All amounts in Number of units, unless stated otherwise | Number of Units | |
| Outstanding RSUs as of January 1, | 553,334 | 200,000 |
| Add: Grants during the year | 376,333 | 420,000 |
| Less: Vested during the year | ||
| - Settled in cash to cover taxes / settlement through purchase of shares from the market |
(151,482) | (66,666) |
| - Settled through issue of new shares | (55,185) | - |
| Less: Terminated without vesting | (14,277) | - |
| Outstanding RSUs as of December 31, | 708,723 | 553,334 |
The cash settlement of RSUs is the Board of Directors' unilateral decision and such settlement is only to cover employee withholding taxes originating from vesting of RSUs. The Company, at its discretion, may also elect to settle the RSUs by delivering equity shares purchased from the market.
In August 2018, 376,333 Restricted Share Units (RSU) were awarded under the Company's RSU scheme to key employees of the Company under the long-term incentive plan approved by the shareholders. One RSU entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value of the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based. The standard vesting period is 3 years, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period which was the case in August 2018 grants where 1/3 units are vesting in June 2019 (the "First Tranche"), 1/3 vest after 1 year of the vesting of the First Tranche, and the final 1/3 vest after 2 years from vesting of the First Tranche.
RSUs vest automatically at the respective vesting dates, provided the unit holder continues to be an employee throughout the vesting period. The holder will be issued the applicable number of shares as soon as possible thereafter
The Company calculates the value of share-based compensation using a Black-Scholes option pricing model to estimate the fair value of the RSUs at the date of grant. The estimated fair value of RSUs is amortised to expense over the respective vesting period. USD 0.3 million (2017: USD 0.1 million) has been charged to the statement of comprehensive income for the proportion of vesting during the respective years and the same amount credited to additional paid-in capital. Upon vesting, the settlement value is reversed from the additional paid-in capital.
The assumptions made for the valuation of the RSUs granted during the year is as follows:
| Key assumptions | 2018 | 2017 |
|---|---|---|
| Weighted average risk-free interest rate | 1.5% | 1.5% |
| Dividend yield | Nil | Nil |
| Weighted average expected life of RSUs (vesting in Tranches) | 1-3 years | 1-3 years |
| Volatility range based on Company's historical share performance | 63% | 57% |
| Weighted average remaining contractual life of RSUs at year end | 1.2 years | 1.3 years |
| Share price at grant date – per share | NOK 15.80 | NOK 4.90 |
The weighted average fair value of RSUs granted during the period was NOK 15.8 per unit (2017: NOK 4.9 per unit) based on 376,333 units granted (2017: 420,000 units granted).
The following table illustrates the maturity profile and Weighted Average Exercise Price ("WAEP") of the RSUs outstanding as of December 31 and vesting:
| 2018 | 2017 | WAEP | 2018 | 2017 | |
|---|---|---|---|---|---|
| Number of Units | NOK/share | Exercise value in NOK | |||
| Within 1 year | 327,352 | 206,667 | 0.05 | 16,368 | 10,333 |
| Between 1 and 2 years | 260,684 | 206,667 | 0.05 | 13,034 | 10,333 |
| Between 2 and 3 years | 120,687 | 140,000 | 0.05 | 6,034 | 7,000 |
| Total | 708,723 | 553,334 | 35,436 | 27,667 |
As of the year ended 2018 and 2017, the unvested RSUs were outstanding for 4 employees including key management personnel.
| Fair value expensed | ||
|---|---|---|
| Exercise period | USD 000 | |
| 0.05 | June 2019 to June 2021 | 170 |
| 0.05 | June 2019 to June 2021 | 67 |
| 0.05 | June 2019 to June 2021 | 60 |
| 0.05 | June 2019 to June 2021 | 34 |
| 331 | ||
| No of Units 362,972 146,335 129,669 69,747 708,723 |
Exercise price NOK/share |
The distribution of outstanding RSUs as of December 31, 2018 amongst the employees is as follows:
Under the RSU scheme in an event where there is a change of control, all outstanding RSUs will vest immediately and the Company will cash settle by compensating the difference between the fair market value of the RSUs and the exercise value.
A change of control is defined in the RSU scheme terms and means (i) a change of control in the ownership of the Company which gives a person (individual or corporate) the right and the obligation to make a mandatory offer for all the shares in the Company pursuant to the Norwegian Securities Trading Act of 2007, (ii) if (i) is not applicable; a change of control in the ownership of the Company which gives a person (individual or corporate) ownership to or control over more than 50% of the votes in the Company, (iii) a merger in which the Company is not the surviving entity or (iv) a sale of all or substantially all of the Company's assets to another corporation, partnership or other entity that is not a wholly owned Subsidiary of the Company. In the case of (i) and (ii) above, the change of control is deemed to occur at the time when the relevant ownership or control occurs and in the case of (iii) and (iv) above at completion of the merger or the sale.
The Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value. The Group has no material financial assets that are past due. No material financial assets are impaired at the balance sheet date. All financial assets and liabilities with the exception of derivatives are measured at amortised cost.
All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved.
The Group initiated a commodity hedging program in December 2018, which was concluded in January 2019, whereby approximately 600 bopd, representing approximately 25% of the Group's current production, have been hedged over a three-year period using "zero cost collars" to protect the downside in oil price of below USD 55 per bbl. The hedging program continues to be closely monitored and adjusted according to the Group's risk management policies and cashflow requirements.
On December 14, 2018, the Group entered into a derivative contract in the form of a "zero cost collar" which was initially recognised at Nil fair value. The contract was revalued at December 31, 2018 with changes to fair value recognised as finance income or expense in the statement of comprehensive income.
The outstanding contracts at December 31, 2018 of the Group and carrying and fair values of these derivatives were as follows:
| USD 000 | Term | Contract amount – net to Panoro |
Contract price/rate |
Contract price/rate |
Fair value asset / (liability) at December 31, 2018 |
|---|---|---|---|---|---|
| Sell/Put | Buy/Call | ||||
| Zero cost collar | Various maturities over a period of 3 years |
360,007 bbls | USD55/bbl | USD60.65/bbl | 756 |
Maturity profile of fair value at December 31, 2018
| Current | 364 | ||
|---|---|---|---|
| Non-current | 392 |
The above derivate contract matures over the period February 1, 2019 to December 31, 2021. No contracts matured during the year to December 31, 2018 and consequently no realised gains or losses were recognised in the statement of comprehensive income. There were no commodity hedging contracts outstanding as of December 31, 2017.
The fair values of the commodity price options (zero cost collars) were provided by counterparty with whom the trades have been entered into. These consist of put and call options to sell/buy crude oil. The options are valued using a Black-Scholes based methodology. The inputs to these valuations include the price of oil, its volatility.
The following provides an analysis of the Group's financial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable:
All the Group's derivatives are Level 2 (2017: No derivative instruments). There were no transfers between fair value levels during the year. For financial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between levels by reassessing categorisation (based on the lowest-level input which is significant to the fair value measurement as a whole) at the end of each reporting period.
The effect of initially applying IFRS 9 on the Group's financial instruments is described in Note 2.4. For comparison purposes, receivables and cash balances were classified as loans and receivables at year end 2017, these are now classified as financial assets at amortised cost at year end 2018. There is no change in the classification of financial liabilities compared between year end 2017 and year end 2018.
The Group's principal financial liabilities comprise of loans and borrowings and trade and other financial liabilities. The main
purpose of these financial instruments is to finance the Group's operations, including the Group's capital expenditure programme. The Group has various financial assets such as accounts receivable and cash.
The Group manages its exposure to key financial risks in accordance with its financial risk management policy. The objective of the policy is to support the Group's financial targets while protecting future financial security. The Group is exposed to the following risks:
Management reviews and agrees policies for managing each of these risks which are summarised below. The Group's policy is that all transactions involving derivatives must be directly related to the underlying business of the Group and does not use derivative financial instruments for speculative purposes.
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The primary commodity price risks that the Group is exposed to include oil prices that could adversely affect the value of the group's financial assets, liabilities or expected future cash flows. In accordance with the Group's financial risk management framework, the Group enters into various transactions using derivatives for risk management purposes. The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below.
The Group is exposed to the risk of fluctuations in prevailing market commodity prices (primarily crude oil) on the oil and gas it produces. The Group's policy is to manage these risks through the use of derivative financial instruments. The following table summarises the impact on profit before tax for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on profit before tax as these derivative financial instruments have not been designated as hedges and are classified as held-for-trading. The analysis is based on derivative contracts existing at the balance sheet date, the assumption that crude oil price moves 15% over all future periods, with all other variables held constant. Management believe that 15% is a reasonable sensitivity based on forward forecasts of estimated oil price volatility.
| USD 000 | 2018 | 2017 |
|---|---|---|
| 15% increase in the price of oil | (113) | - |
| 15% decrease in the price of oil | 113 | - |
The Company operates internationally and is exposed to risk arising from various currency exposures, primarily with respect to the Norwegian Kroner (NOK), the Tunisian Dinar (TND), and the Pound Sterling (GBP).
The Group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the respective functional currency.
The Group reports its consolidated results in USD, any change in exchange rates between its operating subsidiaries' functional currencies and the USD affects its consolidated income statement and balance sheet when the results of those operating subsidiaries are translated into USD for reporting purposes.
Group companies are required to manage their foreign exchange risk against their functional currency.
The Group evaluates on a continuous basis to use cross currency swaps if deemed appropriate by management in order to hedge the forward foreign currency risk. The group used no derivatives/swaps during 2018 or 2017.
A 20% strengthening or weakening of the USD against the following currencies at December 31, 2018 would have increased / (decreased) equity and profit or loss by the amounts shown below.
The Group's assessment of what a reasonable potential change in foreign currencies that it is currently exposed to have been changed as a result of the changes observed in the world financial markets. This hypothetical analysis assumes that all other variables, including interest rates and commodity prices, remain constant.
| USD 000 | 2018 | 2017 | ||
|---|---|---|---|---|
| USD vs NOK | + 20% | -20% | + 20% | -20% |
| Cash | (1,789) | 1,789 | (27) | 27 |
| Receivables | (94) | 94 | - | - |
| Payables | 142 | (142) | 19 | (19) |
| Net effect | (1,741) | 1,741 | (8) | 8 |
| USD vs TND | + 20% | -20% | + 20% | -20% |
| Cash | (139) | 139 | - | - |
| Receivables | (313) | 313 | - | - |
| Payables | 1,123 | (1,123) | - | - |
| Net effect | 671 | (671) | - | - |
| USD vs GBP | + 20% | -20% | + 20% | -20% |
| Cash | (320) | 320 | (63) | 63 |
| Receivables | (8) | 8 | (5) | 5 |
| Payables | 62 | (62) | 46 | (46) |
| Net effect | (266) | 266 | (22) | 22 |
The Group's exposure to the risk of changes in market interest rates relates primarily to the Group's loans and borrowings and cash balances.
The following table demonstrates the sensitivity of finance revenue and finance costs to a reasonably possible change in interest rates, with all other variables held constant, of the Group's profit before tax through the impact on fixed rate short-term deposits and applicable floating rate bank loans.
| USD 000 | 2018 | 2017 | ||
|---|---|---|---|---|
| +100bps | -100bps | +100bps | -100bps | |
| Loans and borrowings (Senior secured facility) | (162) | 162 | - | - |
| Cash equivalents | 101 | (101) | 46 | (46) |
| Net effect | (61) | 61 | 46 | (46) |
The Group is exposed to credit risk that arises from cash and cash equivalents, derivative financial instruments and deposits with banks and financial institutions, as well as credit exposures to customers, including outstanding receivables and committed transactions.
For banks and financial institutions, only independently rated parties with a minimum rating of "A" are accepted. Any change of financial institutions (except minor issues) are approved by the Group CFO. The Company may engage with counterparties of a lower rating, for commercial reason, or by taking lower exposures in such counterparties to mitigate the risks following necessary approvals.
If the Group's customers are independently rated, these ratings are used. Otherwise, if there is no independent rating, risk control in the operating units assesses the credit quality of the customer, taking into account its financial position, past experience and other factors. The utilization of credit limits is regularly monitored and kept within approved budgets.
Liquidity risk is the risk that the Group will not be able to meet its obligations as they fall due. Prudent liquidity risk management includes maintaining sufficient cash and marketable securities, the availability of funding from an adequate amount of committed credit facilities and the ability to close out market positions.
The table below summarises the maturity profile of the Group's financial liabilities at December 31, 2018 based on contractual undiscounted payments.
| USD 000 | On demand |
Less than 1 year |
Between 2 to 5 years |
Over 5 years |
Total |
|---|---|---|---|---|---|
| Loans and borrowings (Senior secured facility) | - | 2,640 | 13,560 | - | 16,200 |
| Loans and borrowings (Non-recourse loan) | - | 3,751 | 9,392 | - | 13,143 |
| Accounts payable and accrued liabilities | - | 7,551 | 6,847 | 1,030 | 15,428 |
| Total | - | 13,942 | 29,799 | 1,030 | 44,771 |
| USD 000 | On demand |
Less than 1 year |
Between 2 to 5 years |
Over 5 years |
Total |
|---|---|---|---|---|---|
| Accounts payable and accrued liabilities | - | 6,810 | 9,089 | - | 15,899 |
| Loans and borrowings (Non-recourse loan) | - | - | 2,197 | - | 2,197 |
| Total | - | 6,810 | 11,286 | - | 18,096 |
Management considers that the Group has adequate current assets and forecast cash from operations to manage liquidity risks arising from current and non-current liabilities.
The Group had USD 23.4 million in cash and cash equivalents as of December 31, 2018 and debt of USD 28.9 million compared to USD 6.3 million of cash and cash equivalents and USD 2.1 million of debt as at December 31, 2017. In addition to Dussafu capex, the Company is committed to a drilling obligation of one well on SOEP in Tunisia. In support of this obligation, in January 2019, Panoro Tunisia Exploration AS has issued a bank guarantee of USD 16.6 million (Panoro's net share is USD 10 million). Although the Company is well funded to undertake upcoming work programme, there is risk that additional funding may be required to conclude such activities. Should additional funding be required in the future for additional capital expenditure for new development phases or working capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. Options include, amongst others, offtake prepayment structures, utilization of undrawn financing facility and the issuance of shares.
The Group manages its capital structure to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. In order to maintain or change the capital structure, the Group may adjust the amount of dividend payments to shareholders, return capital to shareholders or issue new shares.
The Group's funding requirements are met through a combination of debt and equity and adjustments are made in light of changes in economic conditions. The Group's strategy is to maintain ratios in line with covenants associated with its Senior Secured loan. The Group includes interest bearing loans less cash, cash equivalents and restricted cash in net debt. Capital includes share capital, share premium, other reserves and accumulated profits/losses.
The Group is continuously evaluating the capital structure with the aim of having an optimal mix of equity and debt capital to reduce the Group's cost of capital and looking at avenues to procure that in the forthcoming year.
The Company has provided a performance guarantee to the ANP, in terms of which the Company is liable for the commitments of Coral and Cavalo Marinho licenses in accordance with concession agreements. The guarantee is unlimited.
Under section 479A of the UK Companies Act 2006; two of the Company's indirect subsidiaries Panoro Energy Limited (Registration number: 6386242) and African Energy Equity Resources Limited (Registration number: 5724928) have availed exemption for audit of their statutory financial statements pursuant to guarantees issued by the Company to indemnify the subsidiaries of any losses towards third parties that may arise in the financial year ended December 31, 2018 in such Companies. The Company can make an annual election to support such guarantee for each financial year.
The Company has a guarantee issued to the State of Gabon to fulfil all obligations under the Dussafu Production Sharing Contract.
There is no potential claim against these performance guarantee and all license obligations are already accounted for in the statement of financial position.
Operating leases relate to leases of office space with lease terms between 1 to 10 years.
| USD 000 | 2018 | 2017 |
|---|---|---|
| Not later than 1 year | 252 | 267 |
| Later than 1 year and not later than 5 years | 126 | 401 |
| Later than 5 years | - | - |
| At December 31 | 378 | 668 |
The above table sets out the Group's future commitments of lease payments based on a standard rental period with minimum payments (i.e. fixed rental costs excluding additional lease payments calculated based on revenue) under (1) 1 year, (2) 1-5 years, (3) after 5 years, as of December 31, 2018. The lease rentals primarily relate to office premises in London
which has ten year lease with a break clause in year five. At the end of the initial five year period the lease terms are subject to a mutual review and therefore only minimum payments up to such period are included in the table.
The office premises in London are sub-let from Elan Property B.V. and cover an area of approximately 2,196 square feet. The office space is purely used for office staff and related activities and contains normal office furniture, IT equipment and supplies.
The Group is also contracted through the OML 113 Joint Venture in a ten-year bare-boat charter of the FPSO vessel Front Puffin. The Group's share of lease rentals in the initial three-year contract period started from July 2016. The minimum rentals for the financial year ending December 31, 2019 US\$ 0.9 million up to the completion of the third anniversary from the commencement of commercial production in July 2019. After the initial three years, the lease is cancellable without penalties. The estimated rentals disclosed on this note are based on the Group's net paying interest of 16.255% in Aje Cenomanian oil development.
In Brazil, termination agreements for the surrender of Coral and Cavalho Marinho licences have been signed between the JV partners and Brazilian Regulator ANP. The next steps involve various regulatory clearances before dissolution of JV operations. The Company's formal exit from its historical Brazilian business is still ongoing with slow progress towards the approval of abandonment by the Brazilian regulators. Management is working actively with the operator Petrobras to bring matters to a close and to ensure that the ongoing costs are kept to a minimum. However, the timing and eventual costs of such conclusion is uncertain at this stage.
There were no related party transactions during the year.
Details of the Group's subsidiaries as of December 31, 2018, are as follows:
| Subsidiary | Place of incorporation and ownership |
Ownership interest and voting power |
|---|---|---|
| Panoro Energy do Brasil Ltda | Brazil | 100% |
| Panoro Energy Limited | UK | 100% |
| African Energy Equity Resources Limited | UK | 100% |
| Pan-Petroleum (Holding) Cyprus Limited | Cyprus | 100% |
| Pan-Petroleum Holding B.V. | Netherlands | 100% |
| Pan-Petroleum Gabon B.V. | Netherlands | 100% |
| Pan-Petroleum Gabon Holding B.V. | Netherlands | 100% |
| Pan-Petroleum Nigeria Holding B.V. | Netherlands | 100% |
| Pan-Petroleum Services Holding B.V. | Netherlands | 100% |
| Panoro Energy Tunisia B.V. | Netherlands | 100% |
| Pan-Petroleum AJE Limited | Nigeria | 100% |
| Energy Equity Resources AJE Limited | Nigeria | 100% |
| Energy Equity Resources Oil and Gas Limited | Nigeria | 100% |
| Syntroleum Nigeria Limited | Nigeria | 100% |
| PPN Services Limited | Nigeria | 100% |
| Energy Equity Resources (Cayman Islands) Limited | Cayman Islands | 100% |
| Energy Equity Resources (Nominees) Limited | Cayman Islands | 100% |
| Panoro Energy Gabon Production SA | Gabon | 100% |
| Sfax Petroleum Corporation AS | Norway | 60% |
| Subsidiary | Place of incorporation and ownership |
Ownership interest and voting power |
|---|---|---|
| Panoro Energy AS | Norway | 60% |
| Panoro Tunisia Exploration AS | Norway | 60% |
| Panoro Tunisia Production AS | Norway | 60% |
| Panoro TPS Production GmbH | Austria | 60% |
The reserves of the Tortue field located within Dussafu EEA, with previously reported Contingent Resources from the western flank of the field have now been re-categorized as reserves as of December 31, 2018. Consequently, the 2P gross remaining reserves at Tortue have substantially increased by 11.6 MMbbls, approximately 50% higher as compared to year end 2017. The remaining reserves are calculated after deducting 1.2 million barrels produced during 2018. The NSAI estimates are based on a total of 6 wells at Tortue. Panoro share of the updated 2P reserves is 2.2 MMbbls on an entitlement basis.
The Tunisian Directorate General of Hydrocarbons has also advised that the Tunisian Consultative Hydrocarbons Committee has required Panoro Exploration to post a bank guarantee in relation to the drilling operations on SOEP, which will be released at successive operational stages commencing with the spudding of the well, on track during 2019. Accordingly, PTE has procured a bank guarantee of USD 16.6 million (USD 10.0 million net to Panoro).
The Group has adopted a policy of regional reserve reporting using external third party companies to audit its work and certify reserves and resources according to the guidelines established by the Oslo Stock Exchange ("OSE"). Reserve and contingent resource estimates comply with the definitions set by the Petroleum Resources Management System ("PRMS") issued by the Society of Petroleum Engineers ("SPE"), the American Association of Petroleum Geologists ("AAPG"), the World Petroleum Council ("WPC") and the Society of Petroleum Evaluation Engineers ("SPEE") in June 2018. Panoro uses the services of Gaffney, Cline & Associates ("GCA"), Netherland Sewell & Associates ("NSAI") and AGR TRACS International Limited for 3rd party verifications of its reserves.
The following is a summary of key results from the reserve reports (net of the Group's share):
| Asset | 1P reserves (MMBOE) | 2P reserves (MMBOE) | 3P reserves (MMBOE) |
|---|---|---|---|
| Aje (OML 113) | 12.8 | 21.9 | 31.2 |
| Tortue (Dussafu) | 1.7 | 2.2 | 2.8 |
| TPS Assets | 2.1 | 4.7 | 6.4 |
| Panoro Total | 16.6 | 28.8 | 40.4 |
During 2018, the Group had the following reserve development:
| 2P reserves (MMBOE) | |
|---|---|
| Balance (previous ASR) as of December 31, 2017 | 21.6 |
| Production 2018 | (0.2) |
| Revision of previous estimates | 2.7 |
| New developments since previous ASR | 4.7 |
| Balance (current ASR) as of December 31, 2018 | 28.8 |
Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.
Probable Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.
Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Probable Reserves.
| USD 000 | Note | 2018 | 2017 |
|---|---|---|---|
| Operating income | |||
| Operating revenues | - | - | |
| Total operating income | - | - | |
| Operating expenses | |||
| General and administrative expense | (1,203) | (1,751) | |
| Impairment of investments in subsidiary | 2,6 | (100) | (335) |
| Impairment of loan to subsidiaries | 2,7,8 | (11,520) | (32,885) |
| Depreciation | - | - | |
| Total operating expenses | (12,823) | (34,971) | |
| Operating result | 2 | (12,823) | (34,971) |
| Financial income | 3 | 9,738 | 9,356 |
| Interest and other finance expense | 3 | (151) | (79) |
| Currency gain / (loss) | (550) | 16 | |
| Result before income taxes | (3,786) | (25,678) | |
| Income tax | 5 | - | - |
| Result for the year | (3,786) | (25,678) | |
| Earnings per share (basic and diluted) - USD | 4 | (0.08) | (0.60) |
The annexed notes form an integral part of these financial statements.
| USD 000 | Note | 2018 | 2017 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Investment in subsidiaries | 6 | 18,003 | - |
| Total non-current assets | 18,003 | - | |
| Current assets | |||
| Loans to subsidiaries | 8 | 38,818 | 29,076 |
| Other current assets | 12 | - | |
| Cash and cash equivalent | 10,549 | 4,705 | |
| Restricted cash | - | 1,500 | |
| Total current assets | 49,379 | 35,281 | |
| TOTAL ASSETS | 67,382 | 35,281 | |
| EQUITY AND LIABILITIES | |||
| EQUITY | |||
| Paid-in capital | |||
| Share capital | 9 | 423 | 299 |
| Share premium reserve | 9 | 333,090 | 297,490 |
| Treasury Shares | - | (503) | |
| Additional paid-in capital | 9 | 122,055 | 122,055 |
| Total paid-in capital | 455,568 | 419,341 | |
| Other equity | |||
| Other reserves | 9 | (393,865) | (390,079) |
| Total other equity | (393,865) | (390,079) | |
| TOTAL EQUITY | 61,703 | 29,262 | |
| LIABILITIES | |||
| Current liabilities | |||
| Accounts payable | 144 | 13 | |
| Intercompany payables | 8 | 4,787 | 5,744 |
| Other current liabilities | 10 | 748 | 262 |
| Total current liabilities | 5,679 | 6,019 | |
| TOTAL LIABILITIES | 5,679 | 6,019 | |
| TOTAL EQUITY AND LIABILITIES | 67,382 | 35,281 |
The annexed notes form an integral part of these financial statements
| USD 000 | Note | 2018 | 2017 |
|---|---|---|---|
| CASH FLOW FROM OPERATING ACTIVITIES | |||
| Net income / (loss) for the year | (3,786) | (25,678) | |
| Adjusted for: | |||
| Impairment of investment in subsidiary | 6 | 100 | 335 |
| Provision for Doubtful Receivables | 7,8 | 11,520 | 32,885 |
| Financial Income | 3 | (9,738) | (9,356) |
| Financial Expenses | 3 | 151 | 79 |
| Foreign exchange gains/losses | 550 | (16) | |
| (Increase)/decrease in trade and other receivables | (12) | 277 | |
| Increase/(decrease) in trade and other payables | 431 | (413) | |
| (Increase)/decrease in intercompany receivables | - | - | |
| Increase/(decrease) in intercompany payables | (957) | 22 | |
| Net cash flows from operating activities | (1,741) | (1,865) | |
| CASH FLOWS FROM INVESTING ACTIVITIES | |||
| Cash outflow relating to acquisitions | (18,000) | - | |
| Loans to subsidiaries | (12,753) | (8,574) | |
| Net proceeds from loans to subsidiaries | 1,000 | 12,737 | |
| Net cash flows from investing activities | (29,753) | 4,164 | |
| CASH FLOWS FROM FINANCING ACTIVITIES | |||
| Net proceeds from Equity Private Placement and Treasury Shares | 36,490 | (509) | |
| Interests paid | (151) | (79) | |
| Interests received | 49 | 32 | |
| Movement in restricted cash | 1,500 | (980) | |
| Net cash flows from financing activities | 37,888 | (1,536) | |
| Effect of foreign currency translation adjustment on cash balances | (550) | 16 | |
| Net increase in cash and cash equivalents | 5,844 | 779 | |
| Cash and cash equivalents at the beginning of the year | 4,705 | 3,926 | |
| Cash and cash equivalents at the end of financial year | 10,549 | 4,705 |
The annexed notes form an integral part of these financial statements.
The annual accounts for the parent company Panoro Energy ASA (the "Company") are prepared in accordance with the Norwegian Accounting Act and accounting standards and practices generally accepted in Norway. The consolidated financial statements have been prepared under International Financial Reporting Standards ("IFRS") as adopted by the European Union ("EU") and are presented separately from the parent company.
The accounting policies under IFRS are described in Note 2 of the consolidated financial statements. The accounting principles applied under NGAAP are in conformity with IFRS unless otherwise stated in the notes below. The joint agreement with Beender Petroleum Tunisia Limited as part of the Group's acquisitions in Tunisia during 2018 represent a significant transaction for the parent company. Details of the joint agreement and the Tunisian acquisitions are noted in Note 12 of the Consolidated financial statements above.
The Company's annual financial statements are presented in US Dollars (USD) and rounded to the nearest thousand, unless otherwise stated. USD is the currency used for accounting purposes and is the functional currency. Shares in subsidiaries and other shares are recorded in Panoro Energy ASA's accounts using the cost method of accounting and reduced by impairment, if any.
Operating result is stated after charging / (crediting):
| USD 000 | 2018 | 2017 |
|---|---|---|
| Employee benefits expense (Note 2.1) | 13 | 14 |
| Impairment of investment in subsidiary (Note 6) |
100 | 335 |
| Impairment of Intercompany Loans (Note 7) |
11,520 | 32,885 |
| Operating lease payments | - | - |
The Company had zero employees at December 31, 2018 and at December 31, 2017. As such, there are no wages and salaries included in general and administrative expenses.
| USD 000 | 2018 | 2017 |
|---|---|---|
| Salaries | - | - |
| Employer's contribution | 13 | 14 |
| Pension costs | - | - |
| Other compensation including severance provision |
- | - |
| Total | 13 | 14 |
For details relating to remuneration of CEO and CFO, refer to note 4.3 in the consolidated financial statements.
Please refer to note 4.2 of the Group financial statements for details on how directors' remuneration is determined.
Remuneration to members of the Board of Directors is summarized below:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Julien Balkany | 69 | 68 |
| Alexandra Herger | 42 | 39 |
| Garrett Soden | 42 | 39 |
| Torstein Sanness | 42 | 39 |
| Hilde Adland | 42 | 29 |
| Total | 236 | 224 |
No loans have been given to, or guarantees given on the behalf of, any members of the Management Group, the Board or other elected corporate bodies.
No pension benefits were received by the Directors during 2018 and 2017.
There are no severance payment arrangements in place for the Directors.
The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension ("Lov om obligatorisk tjenestepensjon"). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognized in the balance sheet.
Fees (excluding VAT) to the Company's auditors are included in general and administrative expenses and are shown below.
| USD 000 | 2018 | 2017 |
|---|---|---|
| Ernst & Young | ||
| Statutory audit | - | 43 |
| Tax services | - | - |
| Total | - | 43 |
Refer to Note 4.6 of the consolidated Financial Statements for the fees paid to the Group's auditors. All fees for 2018 have been billed to a wholly owned subsidiary based in the UK, Panoro Energy Limited and recharged to the Parent Company and respective group companies.
At the annual general meeting held on May 24, 2018, the existing RSU scheme (as presented and approved in the May 27, 2015 annual general meeting), was approved for another three years up to the general meeting to be held in the year 2021. Under this approved employee incentive scheme, the Company may issue RSUs to executive and key employees. Awards under the RSU scheme will normally be considered one time per year and grant of share-based incentives will, in value (calculated at the time of grant), be capped to 100% of the annual base salary for the CEO and 50% of the annual base salary for other members of the executive management. One RSU will entitle the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. The total number of RSUs available for grant under the RSU program during the period from the 2018 annual general meeting and up to the annual general meeting in 2021 shall not exceed 5% of the number of shares outstanding as per the date of the 2018 annual general meeting (at which point in time the total number of shares in issue were 42,502,196). Grant of RSUs will be subject to a set of performance metrics with threshold and factors reviewed annually by the Board of Directors. Such metrics will be set as objectives based on sustained performance results including mostly share price increases and achievement of specific financial performance measures related to a group of oil and gas exploration and production peers that has been defined and adopted by a committee established by the Board.
The movement of RSUs during the year are tabled below:
| All amounts in Number of units, unless stated otherwise |
2018 | 2017 |
|---|---|---|
| Number of Units | ||
| Outstanding RSUs as of January 1, |
553,334 | 200,000 |
| Add: Grants during the year | 376,333 | 420,000 |
| Less: Vested during the year | ||
| -Settled in cash to cover taxes / settlement through |
(151,482) | (66,666) |
| - Settled through issue of new shares |
(55,185) | - |
| Less: Terminated without vesting |
(14,277) | - |
| Outstanding RSUs as of December 31, |
708,723 | 553,334 |
The cash settlement of RSUs is the Board of Directors' unilateral decision and such settlement is only to cover group employees' withholding taxes originating from vesting of RSUs. The Company, at its discretion, may also elect to settle the RSUs by delivering equity shares purchased from the market.
In August 2018, 376,333 Restricted Share Units (RSU) were awarded under the Company's RSU scheme to key employees of the Group under the long-term incentive plan approved by the shareholders. One RSU entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value of the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based. The standard vesting period is 3 years, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period which was the case in August 2018 grants where 1/3 units are vesting in June 2019 (the "First Tranche"), 1/3 vest after 1 year of the vesting of the First Tranche, and the final 1/3 vest after 2 years from vesting of the First Tranche.
RSUs vest automatically at the respective vesting dates, provided the unit holder continues to be an employee throughout the vesting period. The holder will be issued the applicable number of shares as soon as possible thereafter.
The following table illustrates the maturity profile and Weighted Average Exercise Price ("WAEP") of the RSUs outstanding as of December 31 and vesting:
| 2018 | 2017 | WAEP | 2018 | 2017 | |
|---|---|---|---|---|---|
| Number of Units | NOK/share | Exercise value in NOK | |||
| Within 1 year | 327,352 | 206,667 | 0.05 | 16,368 | 10,333 |
| Between 1 and 2 years | 260,684 | 206,667 | 0.05 | 13,034 | 10,333 |
| Between 2 and 3 years | 120,687 | 140,000 | 0.05 | 6,034 | 7,000 |
| Total | 708,723 | 553,334 | 35,436 | 27,667 |
As of the year ended 2018 and 2017, the unvested RSUs were outstanding for 4 group employees including key management personnel. There were no share based payment charges made in the Income Statement of the Company as all costs were recorded in the respective subsidiary.
Under the RSU scheme in an event where there is a change of control, all outstanding RSUs will vest immediately and the Company will cash settle by compensating the difference between the fair market value of the RSUs and the exercise value.
A change of control is defined in the RSU scheme terms and means (i) a change of control in the ownership of the Company which gives a person (individual or corporate) the right and the obligation to make a mandatory offer for all the shares in the Company pursuant to the Norwegian Securities Trading Act of 2007, (ii) if (i) is not applicable; a change of control in the ownership of the Company which gives a person (individual or corporate) ownership to or control over more than 50% of the votes in the Company, (iii) a merger in which the Company is not the surviving entity or (iv) a sale of all or substantially all of the Company's assets to another corporation, partnership or other entity that is not a wholly owned Subsidiary of the Company. In the case of (i) and (ii) above, the change of control is deemed to occur at the time when the relevant ownership or control occurs and in the case of (iii) and (iv) above at completion of the merger or the sale.
The financial expense breakdown is below:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Interest income from subsidiaries | 9,689 | 9,324 |
| Other interest income | 49 | 32 |
| Total | 9,738 | 9,356 |
Interest income from subsidiaries represents an interest on the intercompany loans. Refer to Note 8 for further information on these balances.
The financial expense breakdown is below:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Interest expense on bond loans | - | - |
| Amortisation of debt issue costs | - | - |
| Early redemption penalty on bond loans | - | - |
| Bank and other financial charges | 151 | 79 |
| Total | 151 | 79 |
| USD 000 unless otherwise stated | 2018 | 2017 |
|---|---|---|
| Net result for the period | (3,786) | (25,678) |
| Weighted average number of shares outstanding - in thousands |
45,437 | 42,502 |
| Basic and diluted earnings per share – (USD) |
(0.08) | (0.60) |
When calculating the diluted earnings per share, the weighted average number of shares outstanding is normally adjusted for all dilutive effects relating to the Company's options.
| NOTE 5: INCOME TAX | ||
|---|---|---|
| USD 000 | 2018 | 2017 |
| Tax payable | - | - |
| Change in deferred tax | - | - |
| Income tax expense | - | - |
| USD 000 | 2018 | 2017 |
|---|---|---|
| Result before income tax | (3,786) | (25,678) |
| Effect of permanent differences | 10,507 | 33,168 |
| Tax losses (not utilised) / utilised | (6,721) | (7,490) |
| Basis for tax payable | - | - |
| USD 000 | 2018 | 2017 |
|---|---|---|
| Losses carried forward | 40,467 | 46,191 |
| Taxable temporary differences | - | - |
| Basis for tax payable | 40,467 | 46,191 |
| Calculated deferred tax asset (23% for 2018, 24% for 2017) | 8,903 | 11,086 |
| Unrecognised deferred tax asset | (8,903) | (11,086) |
| Deferred tax recognised on balance sheet | - | - |
The tax losses carried forward are available indefinitely to offset against future taxable profits. The tax losses per return for the year ended December 31, 2017 was NOK 411 million (USD 47.3 million at 2018 closing exchange rate). The 2018 income for tax purposes has been provisionally calculated at NOK 59.4 million (approximately USD 6.8 million).
The deferred tax asset is not recognized on the balance sheet due to uncertainty of income.
Investments in subsidiaries are carried at the lower of cost and fair market value. As of December 31, 2018 USD 18.0 million (2017: USD 3) the holdings in subsidiaries consist of the following:
| Headquarters | Ownership interest and voting rights | |
|---|---|---|
| Panoro Energy do Brasil Ltda (PEdB) | Rio de Janeiro, Brazil | 100% |
| Pan-Petroleum (Holding) Cyprus Ltd (PPHCL) | Limassol, Cyprus | 100% |
| Pan-Petroleum Gabon Holding B.V. (PPGHBV) | Amsterdam, Netherlands | 100% |
| Pan-Petroleum Nigeria Holding B.V. (PPNHBV) | Amsterdam, Netherlands | 100% |
| Pan-Petroleum Services Holding B.V. (PPSHBV) | Amsterdam, Netherlands | 100% |
| Panoro Energy Tunisia B.V. (PET) | Amsterdam, Netherlands | 100% |
| Sfax Petroleum Corporation AS | Oslo, Norway | 60% |
| SFAX | ||||||||
|---|---|---|---|---|---|---|---|---|
| USD 000 | PEdB | PPHCL | PPGHBV | PPNHBV | PPSHBV | PET | Petroleum | Total |
| Investment at cost | ||||||||
| At January 1, 2018 | 95,312 | 129,106 | - | - | - | - | - | 224,418 |
| Investments during the year (Note 6.1) |
100 | - | - | - | - | - | 18,003 | 18,103 |
| At December 31, 2018 | 95,412 | 129,106 | - | - | - | - | 18,003 | 242,521 |
| Provision for impairment | ||||||||
| At January 1, 2018 | (95,312) | (129,106) | - | - | - | - | - | (224,418) |
| Charge for the year (Note 6.2) |
(100) | - | - | - | - | - | - | (100) |
| At December 31, 2018 | (95,412) | (129,106) | - | - | - | - | - | (224,518) |
| Total investment in subsidiaries at December 31, 2018 |
- | - | - | - | - | - | 18,003 | 18,003 |
| Total investment in subsidiaries at December 31, 2017 |
- | - | - | - | - | - | - | - |
On December 11, 2018, Panoro entered into a strategic agreement with Beender Petroleum Limited ("Beender"), a privately held oil and gas company focused on proven oil fields with upside. The strategic agreement documents Panoro and Beender's participation in Tunisian growth opportunities on a 60/40 basis through a holding company, Sfax Petroleum Corporation AS (hereafter referred to as "Sfax Corp") with an effective date of July 1, 2018. Panoro contributed all shares in PTE to Sfax Corp and consequently, Panoro and Beender
respectively hold 60% and 40% of the shares in Sfax Corp. As a result, Panoro's effective participation in the acquired assets, liabilities and work obligations in DNO Tunisia AS has reduced to 60% through ownership in Sfax Corp. The details of the acquisition of DNO Tunisia AS are covered in Note 12.2.
Similarly, the OMV transaction was completed on December 21, 2018 and shares in OMV Tunisia Upstream GmbH was acquired by Panoro Tunisia Production AS, a fully owned subsidiary of Sfax Corp. Details of this acquisition are included in Note 12.3.
Impairment represents loss in value of Company's investment in shares of Panoro Energy do Brasil Ltda of USD 0.1 million (2017: USD 0.3 million). The impairment has been determined by comparing estimated recoverable value of the underlying investment with the carrying amount.
Provision for doubtful receivables owed from loans provided to subsidiaries, is USD 11.5 million (2017: USD 32.9 million). The provision is represented by the following:
The Company's loan to the Dutch subsidiary Pan-Petroleum Gabon B.V was classified as current and amounted to USD 23.9 million as at December 31, 2018 (2017: USD 9.9 million). This loan carries an interest rate of 10% and is repayable on demand.
The Company's loan to the Nigerian subsidiary Pan-Petroleum Aje Limited was classified as current and amounted to USD 13.6 million as at December 31, 2018 (2017: USD 15.3 million). This loan carries an interest rate of 10% and is repayable on demand.
Payable balances on account of intercompany recharges was USD 3.6 million (2017: USD 4.4 million) to Company's indirect subsidiary Panoro Energy Limited, which provides technical services and Pan-Petroleum (Holding) Cyprus Limited was USD 1.2 million (2017: USD 1.4 million). These balances do not carry an interest rate and have no maturity date.
Nominal share capital in the Company at December 31, 2018 amounted to NOK 3,119,380 (USD 422,984) consisting of 62,387,600 shares at a par value of NOK 0.05 As at December 31, 2017 share capital amounted to NOK 2,125,110 (USD 304,838) consisting of 42,502,196 shares at a par value of NOK 0.05. All shares in issue are fully paid-up and carry equal voting rights.
The Board may be given a power of attorney by the General Meeting to issue new shares for specific purposes.
The table below shows the changes in equity in the Company during 2018 and 2017:
| USD 000 | Share capital |
Share premium reserve |
Treasury shares |
Additional paid-in capital |
Other equity |
Total |
|---|---|---|---|---|---|---|
| At January 1, 2017 | 305 | 297,503 | - | 122,055 | (364,402) | 55,461 |
| Loss for the year | - | - | - | - | (25,678) | (25,678) |
| Purchase Own shares | (6) | - | (503) | - | - | (509) |
| Transaction Costs on Share buyback | - | (13) | - | - | - | (13) |
| At December 31, 2017 | 299 | 297,490 | (503) | 122,055 | (390,080) | 29,262 |
| Loss for the year | - | - | - | - | (3,786 | (3,786) |
| Sale of Own Shares | - | (503) | 503 | - | - | - |
| Share issue for cash | 124 | 37,783 | - | - | - | 37,907 |
| Transaction Costs for share issue | - | (1,680) | - | - | - | (1,680) |
| At December 31, 2018 | 423 | 333,090 | - | 122,055 | (393,866) | 61,703 |
In July 2018, the Company has successfully completed a Private Placement resolving to issue 4,250,219 new shares each at NOK 12.82 per share to subscribers. In addition, the Company resolved to allot and sell 1,000,000 treasury shares, at a price of NOK 12.82 per share, which together with the Private Placement raised USD 8.3 million (NOK 67 million) in gross proceeds.
The Company had 4,667 shareholders per December 31, 2018 (2017: 3,729). The twenty largest shareholders were:
| No. | Shareholder | Number of shares | Holding in % |
|---|---|---|---|
| 1 | F2 FUNDS AS | 3,684,229 | 5.91% |
| 2 | J.P. MORGAN SECURITIES LLC | 3,085,226 | 4.95% |
| 3 | DNB NOR MARKETS, AKSJEHAND/ANALYSE | 2,844,320 | 4.56% |
| 4 | DNO ASA | 2,641,465 | 4.23% |
| 5 | SKANDINAVISKA ENSKILDA BANKEN AB | 2,484,472 | 3.98% |
| 6 | DANSKE INVEST NORGE VEKST | 2,120,177 | 3.40% |
| 7 | SUNDT AS | 2,064,906 | 3.31% |
| 8 | HORTULAN AS | 1,446,578 | 2.32% |
| 9 | STOREBRAND VEKST VERDIPAPIRFOND | 1,150,853 | 1.84% |
| 10 | KLP AKSJENORGE | 938,462 | 1.50% |
| 11 | PREDATOR CAPITAL MANAGEMENT AS | 896,024 | 1.44% |
| 12 | MATHIAS HOLDING AS | 848,447 | 1.36% |
| 13 | KOMMUNAL LANDSPENSJONSKASSE | 705,203 | 1.13% |
| 14 | ALDEN AS | 696,894 | 1.12% |
| 15 | KAMPEN INVEST AS | 624,223 | 1.00% |
| 16 | NORDNET BANK AB | 586,523 | 0.94% |
| 17 | NORDA ASA | 574,223 | 0.92% |
| 18 | NORDNET LIVSFORSIKRING AS | 551,124 | 0.88% |
| 19 | TVENGE TORSTEIN INGVALD | 542,857 | 0.87% |
| 20 | SVOREN STEINAR | 526,000 | 0.84% |
| Top 20 shareholders | 29,012,206 | 46.50% | |
| Other shareholders | 33,375,394 | 53.50% | |
| Total shares | 62,387,600 | 100.00% |
Shares owned by the CEO, board members and key management, directly and indirectly, at December 31, 2018:
| Shareholder | Position | Number of shares | % of total |
|---|---|---|---|
| Julien Balkany(i) | Chairman of the Board of Directors | 3,116,035 | 4.99% |
| Torstein Sanness | Director | 132,111 | 0.21% |
| Garrett Soden(ii) | Director | 10,008 | 0.02% |
| Alexandra Herger | Director | 5,950 | 0.01% |
| Hilde Ådland | Director | 7,005 | 0.01% |
| John Hamilton | Chief Executive Officer | 167,912 | 0.27% |
| Qazi Qadeer | Chief Financial Officer | 77,062 | 0.12% |
| Richard Morton | Technical Director | 122,425 | 0.20% |
(i) Mr. Balkany has beneficial interest in Nanes Balkany Partners I LP which owns 600,106 shares in the Company, and Balkany Investments LLC which owns 2,485,120 shares in the Company. Mr. Balkany directly holds 30,809 shares in the Company.
(ii) Mr. Soden holds directly or indirectly 10,008 shares in the Company.
| Amount of shares | # of shareholders | % of total | # of shares | Holding in % | |
|---|---|---|---|---|---|
| 1 - 1,000 | 3,022 | 64.75% | 668,776 | 1.07% | |
| 1,001 - 5,000 | 824 | 17.66% | 2,151,818 | 3.45% | |
| 5,001 - 10,000 | 297 | 6.36% | 2,347,608 | 3.76% | |
| 10,001 - 100,000 | 428 | 9.17% | 13,700,239 | 21.96% | |
| 100,001 - 1,000,000 | 87 | 1.87% | 21,996,933 | 35.26% | |
| 1,000,001 + | 9 | 0.19% | 21,522,226 | 34.50% | |
| Total | 4,667 | 100.00% | 62,387,600 | 100.00% |
Shareholder distribution per December 31, 2018:
The breakdown of other current liabilities is below:
| USD 000 | 2018 | 2017 |
|---|---|---|
| Accruals | 725 | 239 |
| Employee related costs payable (including taxes) | 23 | 23 |
| At December 31 | 748 | 262 |
There were no non-cancellable operating lease commitments in 2018 or 2017.
See details in Note 19 in the consolidated financial statements.
The Company has provided a performance guarantee to the ANP, in terms of which the Company is liable for the commitments of Coral and Cavalo Marinho licenses in accordance with the given concessions of the licenses. The guarantee is unlimited.
Under section 479A of the UK Companies Act 2006; two of the Company's indirect subsidiaries Panoro Energy Limited (Registration number: 6386242) and African Energy Equity Resources Limited (Registration number: 5724928) have availed exemption for audit of their statutory financial statements pursuant to guarantees issued by the Company to indemnify the subsidiaries of any losses towards third parties that may arise in the financial year ended December 31, 2018 in such Companies. The Company can make an annual election to support such guarantee for each financial year.
Subsequent events can be referred to in Note 24 in the consolidated financial statements.
Panoro Energy ASA has established a compensation program for executive management that reflects the responsibility and duties as management of an international oil and gas company and at the same time contributes to add value for the Company's shareholders. The goal for the Board of Directors has been to establish a level of remuneration that is competitive both in domestic and international terms to ensure that the Group is an attractive employer that can obtain a qualified and experienced workforce. The compensation structure can be summarized as follows:
| Compensation Element |
Objective and Rational | Form | What the Element Rewards | |
|---|---|---|---|---|
| Base Salary | A competitive level of compensation is provided for fulfilling position responsibilities |
Cash | Knowledge, expertise, experience, scope of responsibilities and retention |
|
| Short-term Incentives |
To align annual performance with Panoro's business objectives and shareholder interests. Short-term incentive pools increase or decrease based on business performance |
Cash | Achievement of specific performance benchmarks and individual performance goals |
|
| Long-term Incentives | To promote commitment to achieving long term exceptional performance and business objectives as well as aligning interests with the shareholders through ownership levels comprised of share options and share based awards |
Restricted Share Units |
Sustained performance results, share price increases and achievement of specific performance measures based on quantified factors and metrics |
The Remuneration Committee oversees our compensation programs and is charged with the review and approval of the Company's general compensation strategies and objectives and the annual compensation decisions relating to our executives and to the broad base of Company employees. Its responsibilities also include reviewing management succession plans; making recommendations to the Board of Directors regarding all employment agreements, severance agreements, change in control agreements and any special supplemental benefits applicable to executives; assuring that the Company's incentive compensation program, including the annual, short term incentives and long- term incentive plans, is administered in a manner consistent with the Company's strategy; approving and/or recommending to the Board of Directors new incentive compensation plans and equity-based compensation plans; reviewing the Company's employee benefit programs; and recommending for approval all administrative changes to compensation plans that may be subject to the approval of the shareholders or the Board of Directors.
The Remuneration Committee seeks to structure compensation packages and performance goals for compensation in a manner that does not incentivize employees to take risks that are reasonably likely to have a material adverse effect on the Company. The Remuneration Committee designs long-term incentive compensation, including restricted share units, performance units and share options in such a manner that employees will forfeit their awards if their employment is terminated for cause. The Committee also retains the discretionary authority to reduce bonuses to reflect factors regarding individual performance that are not otherwise taken into account.
The Board of Directors, upon the Remuneration Committee's recommendation, has also renewed the previously adopted Share Ownership Guidelines (SOG) Policy for members of the executive management to ensure that they have meaningful economic stake in the Company. This policy was introduced in 2015. The SOG policy is designed to satisfy an individual senior executive's need for portfolio diversification, while maintaining management share ownership at levels high enough to assure the Company's shareholders of
managements' full commitment to value creation. Officers of the Company are required to invest in a number of shares valued at a multiple of their base salary in the amounts ranging from 3 times base salary for the CEO and 1 times the
base salary of any other member of the executive management team. Under the current policy, the share ownership level is to be achieved by the time of the year 2021 Annual General Meeting.
Remuneration for executive management for 2018 consisted of both fixed and variable elements. The fixed elements consisted of salaries and other benefits (health and pension), while the variable elements consisted of a performance-based bonus arrangement and a restricted share unit scheme that was approved by the Board of Directors and the shareholders in the Annual General Meeting in 2018.
| 2018 | Short term benefits and pension costs | Long term benefits | |||||
|---|---|---|---|---|---|---|---|
| USD 000 (unless stated otherwise) |
Salary | Bonus | Benefits | Pension costs |
Total | Number of RSUs awarded in 2018 |
Fair value of RSUs expensed |
| John Hamilton, CEO | 375 | 99 | 10 | 36 | 520 | 196,304 | 170 |
| Qazi Qadeer, CFO | 236 | 48 | 5 | 23 | 312 | 63,002 | 67 |
| Richard Morton, Technical Director |
236 | 51 | 5 | 24 | 316 | 63,002 | 60 |
| Total | 847 | 198 | 20 | 83 | 1,148 | 322,308 | 297 |
For 2018, the following was paid/incurred to the executives:
Any bonuses that were incurred and paid in 2018 were approved by the Board of Directors during 2018. The bonus paid in 2018 related to the achievement of performance standards set by the Board of Directors for the financial year 2017.
Evaluation, award and payment of cash bonuses is generally performed in the year subsequent to financial year end, unless stated otherwise. Any bonuses for 2018 performance will be awarded in the year 2019 and determined based on the criteria set by the remuneration committee that includes meeting milestones of measurable strategic value drivers, progress on portfolio of assets, and certain corporate objectives including reduction of administrative overhead costs and HSE performance.
For 2019, remuneration for executive management consists of both fixed and variable elements. The fixed elements consist of salaries and other benefits (health and pension), while the variable elements consist of a performance-based bonus arrangement and a restricted share unit scheme that was approved by the Board of Directors and the Company's shareholders in 2018.
Any cash bonuses to members of the executive management for 2018 will be capped at 50% of annual base salary. Evaluation, award and payment of cash bonuses is generally performed in the year subsequent to the financial year end 2019. The annual bonus for 2019 performance will be awarded in the year 2020 and determined based on the criteria proposed by the Remuneration Committee and approved by the Board of Directors. Such criteria may include meeting milestones of measurable strategic value drivers, progress on portfolio of assets, and certain corporate objectives including reduction of administrative overhead costs and HSE performance. These criteria will be individually tailored for each member of the executive team and will be determined by the Board of Directors as soon as is practicable after the reporting period.
Per the respective terms of employment, the CEO is entitled to 12 months of base salary in the event of a change of control; whereby a tender offer is made or consummated for the ownership of more than 50% or more of the outstanding voting securities of the Company; or the Company is merged or consolidated with another corporation and as a result of such merger or consolidation less than 50.1% of the outstanding voting securities of the surviving entity or resulting corporation are owned in the aggregate by the persons by the entities or persons who were shareholders of the Company immediately prior to such merger or consolidation; or the Company sells substantially all of its assets to another corporation that is not a wholly owned subsidiary. The CFO and Technical Director are entitled to 6 months of base salary in the event of a change of control.
The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension ("Lov om obligatorisk tjenestepensjon"). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognized in the statement of financial position. Since the Company no longer employs any staff in Norway, this scheme is effectively redundant.
In the UK, the Company's subsidiary that employs the staff, contributes a fixed amount per Company policy in an external defined contribution scheme. As such, no pension liability is recognised in the statement of financial position in relation to Company's subsidiaries either.
In 2018, the executives received base salaries and cash incentive bonuses in line with the executive remuneration policies as presented to the 2018 Annual General Meeting.
In August 2018, 376,333 Restricted Share Units were awarded under and in accordance with the Company's RSU scheme to the employees of the Company under the long-term incentive compensation plan approved by the shareholders. One Restricted Share Unit ("RSU") entitles the holder to receive one share of capital stock of the Company against payment in cash of the par value for the share. The par value is currently NOK 0.05 per share. Vesting of the RSUs is time based. The standard vesting period is 3 years, where 1/3 of the RSUs vest after one year, 1/3 vest after 2 years, and the final 1/3 vest after 3 years from grant. The Board of Directors, at its discretion can grant a non-standard vesting period which was the case in 2018 grants where 1/3 units are vesting in June 2019 (the "First Tranche"), 1/3 vest after 1 year of the vesting of the First Tranche, and the final 1/3 vest after 2 years from vesting of the First Tranche.
RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter.
For 2019 the Board of Directors will only award share based incentives in line with any shareholder approved program. Awards of share based incentives will in value (calculated at the time of grant) be capped to 100% of the annual base salary for the CEO and 50% of the annual base salary for other members of the executive management.
Pursuant to the Norwegian Securities Trading Act section 5-5 with pertaining regulations we hereby confirm that, to the best of our knowledge, the company's financial statements for 2018 have been prepared in accordance with IFRS, as provided for by the EU, and in accordance with the requirements for additional information provided for by the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair picture of the company's liabilities, financial position and results viewed in their entirety.
To the best of our knowledge, the Board of Directors' Report gives a true and fair picture of the development, performance and financial position of the company, and includes a description of the principal risk and uncertainty factors facing the company. Additionally, we confirm to the best of our knowledge that the report "Payments to governments" as provided in a separate section in this annual report has been prepared in accordance with the requirements in the Norwegian Securities Trading Act Section 5-5a with pertaining regulations.
| JULIEN | GARRETT | TORSTEIN | |
|---|---|---|---|
| BALKANY | SODEN | SANNESS | |
| Chairman of the | Non-Executive | Non-Executive | |
| Board | Director | Director | |
| ALEXANDRA | HILDE | ||
| HERGER | ÅDLAND | JOHN HAMILTON | |
| Non-Executive | Non-Executive | Chief Executive | |
| Director | Director | Officer |
Panoro Energy ASA ("Panoro", "Panoro Energy" or "the Company") aspires to ensure confidence in the Company and the greatest possible value creation over time through efficient decision making, clear division of roles between shareholders, management and the Board of Directors ("the Board") as well as adequate communication.
Panoro Energy seeks to comply with all the requirements covered in The Norwegian Code of Practice for Corporate Governance. The latest version of the Code of October 17, 2018 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 main objective for Panoro's Corporate Governance is to develop a strong, sustainable and competitive company in the best interest of the shareholders, employees and society at large, within the laws and regulations of the respective country. The Board of Directors (the Board) and management aim for a controlled and profitable development and longterm creation of growth through well-founded governance principles and risk management.
The Board will give high priority to finding the most appropriate working procedures to achieve, inter alia, the aims covered by these Corporate Governance guidelines and principles.
The Norwegian Code of Practice for Corporate Governance as of October 17, 2018 comprises 15 points. The Corporate Governance report is available on the Company's website www.panoroenergy.com
Panoro Energy ASA is an independent E&P company based in London and listed on the Oslo Stock Exchange with ticker PEN. The Company holds the following production, exploration and development assets in Africa: Dussafu License offshore southern Gabon, OML 113 licence offshore western Nigeria, the TPS operated assets on and offshore Tunisia and the Sfax Offshore Exploration Permit and Ras El Besh Concession, offshore Tunisia.
The Company's business is defined in the Articles of Association §2, which states:
"The Company's business shall consist of exploration, production, transportation and marketing of oil and natural gas and exploration and/or development of other energy forms, sale of energy as well as other related activities. The
business might also involve participation in other similar activities through contribution of equity, loans and/or guarantees".
Panoro Energy currently has two reportable segments with exploration and production of oil and gas, by geographic locations being West Africa and North Africa. In West Africa, the Company participates in a number of licenses in Nigeria and Gabon whereas the North African business is concentrated in Tunisia.
Our vision is to use our experience and competence in enhancing value in projects in Africa to the benefit of the countries we operate in and the shareholders of the Company.
Panoro Energy's Board of Directors will ensure that the Company at all times has an equity capital at a level appropriate to its objectives, strategy and risk profile. The oil and gas E&P business is highly capital dependent, requiring Panoro Energy to be sufficiently capitalized. The Board needs to be proactive in order for Panoro Energy to be prepared for changes in the market.
Mandates granted to the Board to increase the Company's share capital or to purchase own shares will normally be restricted to defined purposes, and are normally limited in time to the following year's Annual General Meeting. Any acquisition of our shares will be carried out through a regulated marketplace at market price, and the Company will not deviate from the principle of equal treatment of all shareholders. If there is limited liquidity in the Company's shares at the time of such transaction, the Company will consider other ways to ensure equal treatment of all shareholders.
Mandates granted to the Board for issue of shares for different purposes will each be considered separately by the General Meeting. Any decision to deviate from the principle of equal treatment by waiving the pre-emption rights of existing shareholders to subscribe for shares in the event of an increase in share capital will be justified and disclosed in the stock exchange announcement of the increase in share capital. Such deviation will be made only in the common interest of the shareholders of the Company.
Panoro Energy is in a phase where investments in the Company's operations are required to enable future growth and is therefore not in a position to distribute dividends. Payment of dividends will be considered in the future, based on the Company's capital structure and dividend capacity as well as the availability of alternative investments.
Panoro Energy has one class of shares representing one vote at the Annual General Meeting. The Articles of Association contains no restriction regarding the right to vote.
All Board members, employees of the Company and close associates must internally clear potential transactions in the Company's shares or other financial instruments related to the Company prior to any transaction. All transactions between the Company and shareholders, shareholder's parent company, members of the Board of Directors, executive personnel or close associates of any such parties, are governed by the Code of Practice and the rules of the Oslo Stock Exchange, in addition to statutory law. Any transaction with close associates will be evaluated by an independent third party, unless the transaction requires the approval of the General Meeting pursuant to the requirements of the Norwegian Public Limited Liabilities Companies Act. Independent valuations will also be arranged in respect of transactions between companies in the same Group where any of the companies involved have minority shareholders. Any transactions with related parties, primary insiders or employees shall be made in accordance with Panoro Energy's own instructions for Insider Trading. The company has guidelines to ensure that members of the Board and executive personnel notify the Board if they have any material direct or indirect interest in any transaction entered into by the Company.
Shares of Panoro Energy ASA are listed on the Oslo Stock Exchange. There are no restrictions on ownership, trading or voting of shares in Panoro Energy's Articles of Association.
Panoro Energy's Annual General Meeting is to be held by the end of June each year. The Board of Directors take necessary steps to ensure that as many shareholders as possible may exercise their rights by participating in General Meetings of the Company, and to ensure that General Meetings are an effective forum for the views of shareholders and the Board. An invitation and agenda (including proxy) will be sent out no later than 21 days prior to the meeting to all shareholders in the Company. The invitation will also be distributed as a stock exchange notification. The invitation and support information on the resolutions to be considered at the General Meeting will furthermore normally be posted on the Company's website www.panoroenergy.com no later than 21 days prior to the date of the General Meeting.
The recommendation of the Nomination Committee will normally be available on the Company's website at the same time as the notice.
Panoro Energy will ensure that the resolutions and supporting information distributed are sufficiently detailed and
comprehensive to allow shareholders to form a view on all matters to be considered at the meeting.
According to Article 7 of the Company's Articles of Association, registrations for the Company's General Meetings must be received at least five calendar days before the meeting is held.
The Chairman of the Board and the CEO of the Company are normally present at the General Meetings. Other Board members and the Company's auditor will aim to be present at the General Meetings. Members of the Nomination Committee are requested to be present at the AGM of the Company. An independent person to chair the General Meeting will, to the extent possible, be appointed. Normally the General Meetings will be chaired by the Company's external corporate lawyer.
Shareholders who are unable to attend in person will be given the opportunity to vote by proxy. The Company will nominate a person who will be available to vote on behalf of shareholders as their proxy. Information on the procedure for representation at the meeting through proxy will be set out in the notice for the General Meeting. A form for the appointment of a proxy, which allows separate voting instructions for each matter to be considered by the meeting and for each of the candidates nominated for elections will be prepared. Dividend, remuneration to the Board and the election of the auditor, will be decided at the AGM. After the meeting, the minutes are released on the Company's website.
The Company shall have a Nomination Committee consisting of 2 to 3 members to be elected by the Annual General Meeting for a two year period. The Annual General Meeting elects the members and the Chairperson of the Nomination Committee and determines the committee's remuneration. The Company will provide information on the member of the Nomination Committee on its website. The Company will further give notice on its website, in good time, of any deadlines for submitting proposals for candidates for election to the Board of Directors and the Nomination Committee.
The Company aims at selecting the members of the Nomination Committee taking into account the interests of shareholders in general. The majority of the Nomination Committee shall as a rule be independent of the Board and the executive management. The Nomination Committee currently consists of three members, whereof all members are independent of the Board and the executive management.
The Nomination Committee's duties are to propose to the General Meeting shareholder elected candidates for election to the Board, and to propose remuneration to the Board. The Nomination Committee justifies its recommendations and the recommendations take into account the interests of shareholders in general and the Company's requirements in respect of independence, expertise, capacity and diversity.
The Nomination Committee is described in the Company's Articles of Association and the General Meeting may stipulate guidelines for the duties of the Nomination Committee.
The composition of the Board ensures that the Board represents the common interests of all shareholders and meets the Company's need for expertise, capacity and diversity. The members of the Board represent a wide range of experience including shipping, offshore, energy, banking and investment. The composition of the Board ensures that it can operate independently of any special interests. Members of the Board are elected for a period of two years. Recruitment of members of the Board may be phased so that the entire Board is not replaced at the same time. The Chairman of the Board of Directors is elected by the General Meeting. The Company has not experienced a need for a permanent deputy Chairman. If the Chairman cannot participate in the Board meetings, the Board will elect a deputy Chairman on an ad-hoc basis. The Company's website and annual report provides detailed information about the Board members expertise and independence. The Company has a policy whereby the members of the Board of Directors are encouraged to own shares in the Company, but to dissuade from a short-term approach which is not in the best interests of the Company and its shareholders over the longer term.
The Board has the overall responsibility for the management and supervision of the activities in general. The Board decides the strategy of the Company and has the final say in new projects and/or investments. The Board's instructions for its own work as well as for the executive management have particular emphasis on clear internal allocation of responsibilities and duties. The Chairman of the Board ensures that the Board's duties are undertaken in efficient and correct manner. The Board shall stay informed of the Company's financial position and ensure adequate control of activities, accounts and asset management. The Board member's experience and skills are crucial to the Company both from a financial as well as an operational perspective. The Board of Directors evaluates its performance and expertise annually. The CEO is responsible for the Company's daily operations and ensures that all necessary information is presented to the Board.
An annual schedule for the Board meetings is prepared and discussed together with a yearly plan for the work of the Board.
The Company has guidelines to ensure that members of the Board and executive personnel notify the Board if they have any material direct or indirect interest in any transaction entered into by the Company. Should the Board need to address matters of a material character in which the Chairman is or has been personally involved, the matter will be chaired
by another member of the Board to ensure a more independent consideration.
In addition to the Nomination Committee elected by the General Meeting, the Board has an Audit Committee and a Remuneration Committee as sub-committees of the Board. The members are independent of the executive management.
Currently the Audit Committee consists of the complete Board. The reason for this is the rather low number of directors in the Company, which has led the Board to conclude that it is currently more efficient for the Board function that all directors also are members of the Audit Committee. This practice will be further assessed in the future.
Financial and internal control, as well as short- and long-term strategic planning and business development, all according to Panoro Energy's business idea and vision and applicable laws and regulations, are the Board's responsibilities and the essence of its work. This emphasizes the focus on ensuring proper financial and internal control, including risk control systems.
The Board approves the Company's strategy and level of acceptable risk, as documented in the guiding tool "Risk Management" described in the relevant note in the consolidated financial statements in the Annual Report.
The Board carries out an annual review of the Company's most important areas of exposure to risk and its internal control arrangements.
For further details on the use of financial instruments, refer to relevant note in the consolidated financial statements in the Annual Report and the Company's guiding tool "Financial Risk Management" described in relevant note in the consolidated financial statements in the Annual Report.
The remuneration to the Board will be decided by the Annual General Meeting each year.
Panoro Energy is a diversified company, and the remuneration will reflect the Board's responsibility, expertise, the complexity and scope of work as well as time commitment.
The remuneration to the Board is not linked to the Company's performance, and share options will normally not be granted to Board members. 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.
The Board has established guidelines for the remuneration of the executive personnel. The guidelines set out the main principles applied in determining the salary and other remuneration of the executive personnel. The guidelines ensure convergence of the financial interests of the executive personnel and the shareholders.
Panoro Energy has appointed a Remuneration Committee (RC) which meets regularly. The objective of the committee is to determine the compensation structure and remuneration level of the Company's CEO. Remuneration to the CEO shall be at market terms and decided by the Board and made official at the AGM every year. Remuneration to other key executives shall be proposed by the CEO to the RC.
The remuneration shall, both with respect to the chosen kind of remuneration and the amount, encourage addition of values to the Company and contribute to the Company's common interests – both for management as well as the owners.
Detailed information about options and remuneration for executive personnel and Board members is provided in the Annual Report pursuant to and in accordance with section 6- 16a of the Norwegian Public Limited Companies Act. The guidelines are normally presented to the Annual General Meeting also as a separate attachment to the Annual General Meeting notice.
The Company has established guidelines for the Company's reporting of financial and other information.
The Company publishes an annual financial calendar including the dates the Company plans to publish the quarterly results and the date for the Annual General Meeting. The calendar can be found on the Company's website, and will also be distributed as a stock exchange notification and updated on Oslo Stock Exchange's website. The calendar is published at the end of a fiscal year, according to the continuing obligations for companies listed on the Oslo Stock Exchange. The calendar is also included in the Company's quarterly financial reports.
All shareholders information is published simultaneously on the Company's web site and to appropriate financial news media.
Panoro Energy normally makes four quarterly presentations a year to shareholders, potential investors and analysts in connection with quarterly earnings reports. The quarterly presentations are held through audio conference calls to facilitate participation by all interested shareholders, analysts, potential investors and members of the financial community. A question and answer session is held at the end of each presentation to allow management to answer the questions of attendees. A recording of the conference call presentation is retained on the Company's website www.panoroenergy.com for a limited number of days.
The Company also makes investor presentations at conferences in and out of Norway. The information packages presented at such meetings are published simultaneously on the Company's web site.
The Chairman, CEO and CFO of Panoro Energy are the only people who are authorized to speak to, or be in contact with the press, unless otherwise described or approved by the Chairman, CEO and/or CFO.
Panoro Energy has established the following guiding principles for how the Board of Directors will act in the event of a takeover bid.
As of today the Board does not hold any authorizations as set forth in Section 6-17 of the Securities Trading Act, to effectuate defence measures if a takeover bid is launched on Panoro Energy.
The Board may be authorized by the General Meeting to acquire its own shares, but will not be able to utilize this in order to obstruct a takeover bid, unless approved by the General Meeting following the announcement of a takeover bid.
The Board of Directors will generally not hinder or obstruct take-over bids for the Company's activities or shares.
As a rule the Company will not enter into agreements with the purpose to limit the Company's ability to arrange other bids for the Company's shares unless it is clear that such an agreement is in the common interest of the Company and its shareholders. As a starting point the same applies to any agreement on the payment of financial compensation to the bidder if the bid does not proceed. Any financial compensation will as a rule be limited to the costs the bidder has incurred in making the bid. The Company will generally seek to disclose agreements entered into with the bidder that are material to the market's evaluation of the bid no later than at the same time as the announcement that the bid will be made is published.
In the event of a take-over bid for the Company's shares, the Board of Directors will not exercise mandates or pass any resolutions with the intention of obstructing the take-over bid unless this is approved by the General Meeting following announcement of the bid.
If an offer is made for the Company's shares, the Board will issue a statement evaluating the offer and making a recommendation as to whether shareholders should or should not accept the offer. The Board will also arrange a valuation with an explanation from an independent expert. The valuation will be made public no later than at the time of the public disclosure of the Board's statement. Any transactions that are in effect a disposal of the Company's activities will be decided by a General Meeting.
The auditor will be appointed by the General Meeting.
The Board has appointed an Audit Committee as a subcommittee of the Board, which will meet with the auditor regularly. The objective of the committee is to focus on internal control, independence of the auditor, risk management and the Company's financial standing.
The auditors will send a complete Management Letter/Report to the Board – which is a summary report with comments from the auditors including suggestions of any improvements if needed. The auditor participates in meetings of the Board of Directors that deal with the annual accounts, where the auditor reviews any material changes in the Company's accounting principles, comments on any material estimated accounting figures and reports all material matters on which there has been disagreement between the auditor and the executive management of the Company.
In view of the auditor's independence of the Company's executive management, the auditor is also present in at least one Board meeting each year at which neither the CEO nor other members of the executive management are present.
Panoro Energy places importance on independence and has established guidelines in respect of retaining the Company's external auditor by the Company's executive management for services other than the audit.
The Board reports the remuneration paid to the auditor at the Annual General Meeting, including details of the fee paid for audit work and any fees paid for other specific assignments.
This report is prepared in accordance with the Norwegian Accounting Act § 3-3d and Securities Trading Act § 5-5a. It states that the companies engaged in the activities within the extractive industries shall annually prepare and publish a report containing information about their payments to governments at country and project level. The Ministry of Finance has issued a regulation (F20.12.2013 nr 1682 - "the regulation") stipulating that the reporting obligation only apply to reporting entities above a certain size and to payments above certain threshold amounts. In addition, the regulation stipulates that the report shall include other information than payments to governments, and provides more detailed rules applicable to definitions, publication and group reporting.
This report contains information for the activity in the financial year 2018 for Panoro Energy ASA.
The management of Panoro has applied judgement in interpretation of the wording in the regulation with regard to the specific type of payments to be included in this report, and on what level it should be reported. When payments are required to be reported on a project-by-project basis, it is
reported on a field-by-field basis. Per management's interpretation of the regulation, reporting requirements only stipulate disclosure of gross amounts on operated licences as all payments within the license performed by Non-operators, normally will be cash calls transferred to the operator and will as such not be payments to government. Panoro Energy ASAs activities within the extractive industries as an Operator are located in Tunisia.
The regulation's Section 2 no. 5 defines the different types of payments subject to reporting. In the following sections, only those applicable to Panoro Energy ASA will be described.
Panoro Group acquired interests and in the Sfax Offshore Exploration Permit (SOPE) in Tunisia during 2018 and assumed Operatorship. Refer to Note 12.1 for details. There were no payments to the government of Tunisia in respect of these assets from acquisition date of July 30, 2018 to December 31, 2018.
No area fees were paid for any of these licences during the period ended December 31, 2018.
Panoro Group acquired an interest in five oil producing concessions in Tunisia on December 21, 2018. Refer to Note 12.2 for details. The operations on these concessions are managed by Thyna Petroleum Services S.A. (TPS), which is a joint operating company. No taxes or other fees were paid to the government of Tunisia from acquisition date to December 31, 2018. As at December 31, 2018, the Group had current corporation tax liability of USD 5.6 million payable to the government of Tunisia for the Group's net share of 2018 production. This is expected to be paid in 2019.
Although Panoro Energy, through its subsidiaries, has extractive activities and ownership interest in two licences in West Africa, namely Dussafu license offshore Gabon and OML-113 offshore Nigeria; both of the licenses are non-operated and as such only cash calls are disbursed to operating partners and therefore none of the payments during 2018 can be construed as payments direct to governments under the regulation. As such, no payment will be disclosed in these cases, unless the operator is a state-owned entity and it is possible to distinguish the payment from other cost recovery items.
Panoro Energy ASA is an independent E&P company based in London and listed on the Oslo Stock Exchange with ticker PEN. The Company holds high quality production, exploration and development assets in Africa, namely the Dussafu License offshore southern Gabon, OML 113 offshore western Nigeria, the TPS operated assets and the Sfax Offshore Exploration Permit and Ras El Besh Concession, offshore Tunisia.
Panoro's main purpose is to capitalize on the value of its assets. However, the Company acknowledges its responsibility for the methods by which this is achieved. The principles set out below seek to ensure that Panoro operates in a socially and environmentally responsible manner, encouraging a positive impact through its activities and those of its partners and other stakeholders.
Being a commercial entity, Panoro is focused on creating shareholder value. Nevertheless, we are mindful of the impact of our activities to achieve this goal; we are firmly committed to embracing our social and environmental responsibility, and to honouring the letter and the spirit of the UN Global Compact principles. We believe that this is the right approach for all our stakeholders, including but not limited to the host countries, the local communities, our shareholders and business partners.
We are committed to ensuring that our presence has a positive impact wherever we work and invest. We have therefore adopted this Ethical Code of Conduct ("ECOC").
Panoro as a company, as well as its individual employees, will commit to follow this ECOC.
Equally, we will work through our stakeholders and partners to ensure that we adhere to the values expressed in the ECOC.
Finally, the ECOC is based on the ten principles expressed in the UN Global Compact.
The UN Global Compact's ten principles in the areas of human rights, labour, the environment and anti-corruption enjoy universal consensus and are derived from:
The UN Global Compact asks companies to embrace, support and enact, within their sphere of influence, a set of core values in the areas of human rights, labour standards, the environment and anti-corruption:
• Principle 10: Businesses should work against corruption in all its forms, including extortion and bribery
In addition to these principles, Panoro is concerned with the responsibility of the Company and its operations to the host country and the local community. Wherever Panoro operates, the Company will be committed to:
encourage the employment of local staff
engage in capacity building, through the transfer of skills and technologies
The stakeholders of Panoro are defined as entities that are influenced by, or have influence on, the development of Panoro's assets. Panoro aims to commit to its ethical principles by working through its stakeholders, as well as monitoring how those stakeholders view Panoro's implementation of its ECOC.
| Stakeholders | Influence | Implementation of ECOC |
|---|---|---|
| Employees | Panoro recognizes its influence and its responsibility to its employees, as well as to their close surroundings. Equally, the Company recognizes the importance of attracting and retaining talent in order to fulfil its business and ethical goals. |
Panoro will consistently train its employees to adhere to company standards and procedures. Each employee is expected to learn about and to undertake training on the ECOC on a regular basis. |
| Partners | Panoro operates and maximizes the value of its assets mainly in partnership with other entities. |
Through partnership agreements, as well as through formal and informal communication, Panoro will seek to use its influence to implement its ECOC throughout its joint operations. |
| Operators | The operators are the entities that conduct the actual operation of the assets. |
Through joint operation agreements, as well as through formal and informal communication, Panoro will seek to maintain the highest ethical standards in all operations; focusing on HS&Q, environment and all other principles listed above in section 4 and 5. |
| Shareholders | The Panoro shareholders, including potential shareholders. |
Panoro will seek to minimize shareholder risk and maximize value creation by adhering to the highest ethical standards in terms of environmental, legal and other risks based on the above principles. Panoro follows a strict code of governance based on international law and business practices. |
| Local Community | The communities in which Panoro assets are placed include national authorities and different government bodies, as well as local unions, tribes and other community members. |
Each asset has formal meeting points and communication lines setup within its operational structure. Panoro will seek to use these to address issues of interests based on the ECOC, including corruption, HS&Q and any other issues listed above. |
| Bbl | One barrel of oil, equal to 42 US gallons or 159 liters |
|---|---|
| Bm3 | Billion cubic meters |
| BOE | Barrel of oil equivalent |
| Btu | British Thermal Units, the energy content needed to heat one pint of water by one degree Fahrenheit |
| M3 | Cubic meters |
| MMbbls | Million barrels of oil |
| MMBOE | Million barrels of oil equivalents |
| MMBtu | Million British thermal units |
| MMm3 | Million cubic meters |
| Natural gas and LNG | To billion cubic meters NG |
Billion cubic meters NG |
Million tonnes oil equivalent |
Million tonnes LNG |
Trillion British thermal units |
Million barrels oil equivalent |
|---|---|---|---|---|---|---|
| From | Multiply by | |||||
| 1 billion cubic meters NG | 1.00 | 35.30 | 0.90 | 0.73 | 36.00 | 6.29 |
| 1 billion cubic feet NG | 0.028 | 1.00 | 0.026 | 0.021 | 1.03 | 0.18 |
| 1 million tonnes oil equivalent |
1.111 | 39.20 | 1.00 | 0.805 | 40.40 | 7.33 |
| 1 million tonnes LNG | 1.38 | 48.70 | 1.23 | 1.00 | 52.00 | 8.68 |
| 1 trillion British thermal units |
0.028 | 0.98 | 0.025 | 0.02 | 1.00 | 0.17 |
| 1 million barrels oil equivalent |
0.16 | 5.61 | 0.14 | 0.12 | 5.80 | 1.00 |
PANORO ENERGY - 2018 ANNUAL REPORT | Page: 104 PANORO ENERGY - 2018 ANNUAL REPORT
Panoro Energy ASA c/o Advokatfirma Schjødt, Ruseløkkveien 14, P.O. box 1444 Solli, 0201 Oslo, Norway
Panoro Energy Ltd 78 Brook Street London W1H 6LY United Kingdom
Tel: +44 (0) 20 3405 1060 Fax: +44 (0) 20 3004 1130
www.panoroenergy.com
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