ANNUAL REPORT 2017

Panoro Energy

COMPANY OVERVIEW

Company Overview	2
Assets	4
CEO letter	6
Company Operations	8
Annual Statement of Reserves	12
Directors' Report 2017	16
Board of Directors	24
Senior Management	26
Consolidated Statement of Comprehensive Income	28
Notes to the Consolidated Financial Statements	32
Panoro Energy ASA – Parent Company Income Statement	68
Panoro Energy ASA – Notes to the Financial Statements	71
Declaration from the Board of Directors of Panoro Energy ASA on Executive Remuneration Policies	78
Statement of Directors' Responsibility	81
Auditor's Report	82
Statement on Corporate Governance in Panoro Energy ASA	86
Corporate Social Responsibility/ Ethical Code of Conduct	92
Glossary and Definitions	94

FINANCIAL CALENDAR

May 24, 2018 First quarter 2018 results and Annual General Meeting

August 22, 2018 Second quarter 2018 results

November 13, 2018 Third quarter 2018 results Panoro Energy ASA is an independent exploration and production (E&P) company based in London and listed on the Oslo Stock Exchange with ticker PEN. The Company holds production, development, and exploration assets in West Africa, namely the Dussafu License offshore southern Gabon and OML 113 offshore western Nigeria. In addition to discovered hydrocarbon resources and reserves, both assets also hold significant exploration potential.

COMPANY OVERVIEW

KEY FIGURES	2017
EBITDA (USD million)	(5.3)
EBIT (USD million)	(36.0)
Net profit/(loss) (USD million)	(36.6)

2P Reserves (MMBOE)	21.6
2C Contingent Resources (MMBOE)	2.6
Share price December 29, 2017 (NOK)	6.20

2017 HIGHLIGHTS AND SUBSEQUENT EVENTS

Completion of the divestment of a 25% working interest in Dussafu for USD 12.0 million in cash and a non-recourse loan of up to USD 12.5 million.
Final Investment Decision on Tortue field development.
USD 1.5 million returned post-period end following the settlement of legal dispute with Aje JV partners.
Submission of Aje Turonian gas Field Development Plan.
Aje-5-ST2 well completed in Turonian oil rim and started production.
Share buyback completed in August 2017, purchasing 1,000,000 own shares at NOK 4.05 per share.
Updated reserves estimates on Aje and Dussafu material increase in reserves as a result of Tortue FID and Aje gas FDP.
Start of development activities at Tortue Field including successful completion of the production well DTM-2H.
Recurring General and Administration (G&A) costs reduced by approximately 10% year-on-year.

SHARE PRICE DEVELOPMENT

ASSETS

GABON

8.333% interest in Dussafu Marin permit, offshore.*

* Panoro's interest reduced to 8.333% (from 33.333%) as a result of the transaction with BW energy in 2017.

NIGERIA

6.502% participating interest (12.1913% revenue interest and 16.255% paying interest) in OML 113 Aje field, offshore Nigeria.

PANORO OFFICES

The Company maintains its registered address in Oslo and operational headquarters in London.

PANORO OFFICES

Dear Fellow Shareholders:

2017 proved to be a transformational year for Panoro with two distinct halves. The first half was largely dominated by the signature and subsequent closing of the sale purchase agreement of a 25% working interest in the Dussafu PSC to BW Energy, as well by some operational and legal uncertainties surrounding Aje in Nigeria. The second half evolved positively with material development progress at Dussafu in Gabon and the gradual settlement of disagreements in Nigeria. As we entered 2018, Panoro has continued to capitalise on this positive momentum in our asset base, while benefiting of the macro background and the recent increase in oil prices.

In Gabon, Dussafu gained (and continues to gain) momentum with the entry of BW Energy as new Operator on the Dussafu PSC and the farm out transaction which saw Panoro's subsidiary financed through the development of Phase 1. The development of the Tortue oil field at Dussafu is going according to plan. Various installation activities were carried out in preparation for the drilling and main installation phase at Tortue, with drilling commencing post period in January 2018. The first development well, DTM-2H, was completed in April 2018, and a second development well, DTM-3H is expected to complete drilling by the end of June. In addition, an appraisal penetration, DTM-3, is being drilled in the northwest of the Tortue field to confirm the extent of the field and prepare for additional wells which may be part of the second phase of the development. First oil production is anticipated during the second half of 2018.

An independent reserves report was completed by Netherland Sewell & Associates Inc. ("NSAI") which showed a material increase of over 80% of mid-case 2P reserves at Tortue, compared to the previous independent report completed in May 2014, prior to the new seismic data being available. The NSAI reserves review does not yet include the other 3 discovered fields in the Exclusive Exploitation Authorisation ("EEA") area (Ruche, Moubenga and Walt Whitman) which will be updated in due course. In addition, the independent reserves review does not include prospective resources associated with the 27 prospects and leads already identified within the EEA area. The Dussafu PSC is at the start of its 20 year term, and will hopefully become a long term legacy asset for Panoro and the Republic of Gabon.

In Nigeria, production at the Aje field in OML 113 averaged around 300 barrels of oil per day net to Panoro with the Aje-4 and Aje-5 wells producing from the Cenomanian and the Turonian reservoirs, respectively. A Field Development Plan describing the development of the Turonian reservoir has been submitted to the Nigerian regulators for consideration. In parallel, the process for the renewal of the OML 113 lease in June 2018 has commenced. The Turonian gas and liquids development is currently the focus of forward planning by the Joint Ventures partners, as this is where the material future value in OML 113 lies.

During the year, Panoro has continued its focus on cost reduction. General and Administrative costs decreased 10% year on year, following the 16% and 10% reductions achieved in 2016 and 2015, respectively. The Brazilian operations and overhead are now largely unwound, although remedial abandonment and administrative costs are still being incurred. During the year, Panoro also purchased 1 million of its own shares at an average price of NOK 4.05, through an approved buy- back programme.

Panoro continues to use its best endeavours to pursue transformational and accretive M&A transactions in order to strengthen its core position in Africa. The aim is to establish a balanced growth platform with production, development and low cost exploration upside. New opportunities are continually being reviewed and assessed with the objective of creating value for all shareholders.

I would like to thank shareholders for their continued support and commitment.

John Hamilton

CEO, Panoro Energy ASA

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COMPANY OPERATIONS

Panoro Energy currently has production and development assets in West Africa, namely the Dussafu License offshore southern Gabon and OML 113 offshore western Nigeria. In addition to discovered hydrocarbon resources and reserves, both assets also hold significant exploration potential.

GABON

Dussafu Marin Permit (8.333% interest).

The Dussafu block lies at the southern end of the South Gabon sub-basin in water depths ranging from 100 – 500 metres. The Dussafu block is a Development and Exploitation license with 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.

A total of 20 wells have been drilled in the greater Dussafu block to date, of which five have been pre-salt discoveries (four oil and one gas) and oil shows are present in most other wells. Panoro has participated in the last two exploration wells of which both encountered hydrocarbons; Ruche (2011) and Tortue (2013).

In 2014, an Exclusive Exploitation Authorization (EEA) for an 850.5 km2 area within the Dussafu PSC was awarded. A Field Development Plan (FDP) for the EEA area was subsequently approved and a final decision to start developing the license was taken in 2017. The EEA area includes the four oil fields discovered on the license to date and numerous undrilled structures that could be economically and expeditiously developed through the EEA area development infrastructure. The EEA allows the Dussafu joint venture partners to exploit hydrocarbon resources in the area of the EEA for up to 20 years from first oil production. In 2016 the remaining portion of the greater Dussafu license area outside of the EEA area was relinquished. The first field in the EEA area, Tortue, is expected to start oil production in 2018 from two initial horizontal development wells drilled in the first

half of 2018. The oil from the Tortue wells will be produced via subsea trees and flowlines to a leased FPSO for processing, storage and export. It is expected that further development and exploration drilling will follow this first phase of the development.

In February 2018, Netherland, Sewell and Associates, Inc. (NSAI) certified (3rd party) gross 1P Proved Reserves of 15.9 MMbbls in the Gamba and Dentale reservoirs of the Tortue field. Gross 2P Proved plus Probable Reserves at Tortue

amounted to 23.5 MMbbls in the same reservoirs. Gross 3P Proved plus Probable plus Possible Reserves at Tortue amounted to 31.4 MMbbls.In addition to these Reserves NSAI also certified gross 1C Contingent Resources of 3.7 MMbbls and gross 2C Contingent Resources of 11.6 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 1.55 MMbbls with additional 2C Contingent Resources of 1.5 MMbbls.

NIGERIA

OML 113 Aje field (6.502% participating interest, 12.1913% revenue interest and 16.255% paying interest).

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 Aje field as well as a number of exploration prospects. The Aje field was discovered in 1996 in water depths ranging from 100-1,000m. 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 is underway having 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 2017 the Aje field produced a total of 113,000 barrels net to Panoro at an average rate of approximately 300 bopd net.

In July 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 process for the renewal of the OML 113 lease in June 2018 has commenced in 2017.

In April 2018, AGR TRACS International prepared an updated CPR incorporating the 2014 seismic data, the results of the Aje side-track drilling, production history since field start-up and the development plan outlined in the Turonian gas FDP. The Aje-5 results have meant that assessment of oil reserves in the Cenomanian have been materially reduced compared to earlier estimates. However, Turonian gas, LPG and condensate have now been re-classified from contingent status to Reserves Justified for Development as a result of the FDP submission.

TRACS has now estimated gross remaining 2P and 2C resources of 136 million barrels of oil equivalent combined could be produced from the Aje field, with gross 3P and 3C resources of 233 million barrels of oil equivalent.

At year-end 2017, 2P Reserves net to Panoro's interest related to OML 113, after deduction of royalties and other adjustments, stood at 20.0 MMBOE and 2C Contingent Resources stood at 1.1 MMBOE. This is an increase in 2P reserves of 16.9 MMBOE and a decrease in 2C resources of 27.6 MMBOE compared to year-end 2016.

BRAZIL

Operations in Brazil

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.

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INTRODUCTION

Panoro's classification of reserves and resources complies with the guidelines established by the Oslo Stock Exchange and are based on the definitions set by the Petroleum Resources Management System (PRMS-2007), 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 March 2007.

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

On Production
Approved for Development
Justified for Development

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:

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

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

DISCLAIMER

The information provided in this report reflects reservoir assessments, which in general must be 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 February 2018 for Dussafu and by AGR TRACS International (AGR TRACS) in April 2018 for Aje.

PANORO ASSETS PORTFOLIO

As of year-end 2017, Panoro had two assets with reserves and contingent resources, OML 113 and the Dussafu Permit. A summary description of these assets with status as of year-end 2017 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: offshore Gabon, operator BW Energy, Panoro 8.333%.

Dussafu is a development and exploitation license covering an area containing several oil fields, the most recent discoveries being the Ruche and Tortue 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, is expected to start oil production in 2018.

In February 2018 NSAI certified (3rd party) gross 1P Proved Reserves of 15.9 MMbbls in the Gamba and Dentale reservoirs of the Tortue field. Gross 2P Proved plus Probable Reserves at Tortue amounted to 23.5 MMbbls in the same reservoirs. Gross 3P Proved plus Probable plus Possible Reserves at Tortue amounted to 31.4 MMbbls.

In addition to these Reserves NSAI also certified gross 1C Contingent Resources of 3.7 MMbbls, gross 2C Contingent Resources of 11.6 MMbbls, and gross 3C Contingent Resources of 28.9 MMbbls in the Tortue field. The remaining Dussafu fields excluding Tortue have gross 2C Contingent Resources of approximately 17.3 MMbbls (taken from Panoro's 2016 ASR).

These evaluations yield 1P Proved Reserves net to Panoro of 1.07 MMbbls, 2P Proved plus Probable Reserves net to Panoro of 1.55 MMbbls and 3P Proved plus Probable plus Possible Reserves net to Panoro of 1.75 MMbbls. Additional potentially recoverable resources net to Panoro are approximately 0.22 MMbbls 1C, 0.7 MMbbls 2C and 1.73 MMbbls 3C. The remaining Dussafu fields excluding Tortue have net 2C Contingent Resources of approximately 0.8 MMbbls (taken from Panoro's 2016 ASR). 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.

OML 113 Aje: offshore Nigeria, operator Yinka Folawiyo Petroleum (YFP), Panoro 12.1913%.

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 2017 from the Aje field amounted to 0.9 MMbbls gross and 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 April 2018 AGR TRACS certified (3rd party) gross total 1P Proved Reserves of 78.2 MMBOE in the Aje field. Gross 2P Proved and Probable reserves for the field amounted to 127.1 MMBOE. Gross 3P Proved, Probable and Possible reserves for the field amounted to 215.0 MMBOE. Panoro's net entitlement 1P Proved Reserves was 12.1 MMBOE, net entitlement 2P Proved and Probable Reserves was 20.0 MMBOE and net entitlement 3P Proved, Probable and Possible Reserves was 30.9 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 0.49 MMBOE, net entitlement 2C Contingent Resources is 1.10 MMBOE and net entitlement 3C Contingent Resources is 2.13 MMBOE.

MANAGEMENT DISCUSSION AND ANALYSIS

Panoro uses the services of NSAI 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 modeling 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 2017 ASR:

Dussafu: In 2017, a Final Investment Decision to develop the Tortue field was taken in the Dussafu project. The Contingent Resources associated with Tortue are therefore now reported as Reserves Approved for Development. In addition a re-determination of the volumes at Tortue was undertaken by NSAI. The remaining fields in Dussafu (Ruche, 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.

Aje: The first phase of the Aje Cenomanian oil development started in 2016 with production from two wells. The 2017 the Aje-5 well workover and side-track campaign resulted in a re-completion of the well in the Turonian oil rim. The previous estimates of reserves in Aje were revised by AGR TRACS in 2018. The revisions incorporate the 2014 seismic data, the results of the Aje side-track drilling, historical production data and the development plans outlined in the Aje gas FDP. The result is a reduction in net 2P reserves of 2.6 MMbbls and the addition of 19.6 MMBOE of reserves compared to the year-end 2016 ASR. These additional reserves are mainly associated with the Turonian gas development and are sub-classified as Reserves Justified for Development. Once a Final Investment Decision is taken on the Aje field gas development project these reserves may become Reserves Approved for Development.

ASSUMPTIONS

The commerciality and economic tests for the Aje reserves volumes were based on an oil and condensate price of

US\$60/Bbl, a LPG price of US\$39/Bbl, and a gas price of US\$4/MMBtu.

The commerciality and economic tests for the Dussafu reserves volumes were based on an average oil price over the field life of US\$59/Bbl.

2017 – 2P DEVELOPMENT (MMBOE)

2P Reserves Development	(MMBOE)
Balance (previous ASR – December 31, 2016)	3.1
Production 2017	(0.1)
New developments since previous ASR	21.2
Revisions of previous estimates	(2.6)
Balance (revised ASR) as of December 31, 2017	21.6

Panoro's total 1P reserves at end of 2017 amount to 13.2 MMBOE. Panoro's 2P reserves amount to 21.6 MMBOE and Panoro's 3P reserves amount to 32.7 MMBOE. This reflects the April 2018 reserve report for the Aje field, conducted by AGR TRACS and production since the field startup, and the February 2018 reserve report for the Dussafu field, conducted by NSAI.

Panoro's Contingent Resource base includes discoveries of varying degrees of maturity towards development decisions. By end of 2017, Panoro's assets contain a total 2C volume of approximately 2.6 MMBOE.

April 30, 2018

John Hamilton CEO

As of 31
Dec, 2017	Interest			1P (Low Estimate)				2P (Base Estimate)				3P (High Estimate)
	%	Liquids MMbbl	Gas Bcf	Total MMBOE	Net MMBOE	Liquids MMbbl	Gas Bcf	Total MMBOE	Net MMBOE	Liquids MMbbl	Gas Bcf	Total MMBOE	Net MMBOE
							On Production
Aje Field Oil	12.1913	1.66	-	1.66	0.20	2.02	-	2.02	0.25	2.31	-	2.31	0.28
Total		1.66	-	1.66	0.20	2.02	-	2.02	0.25	2.31	-	2.31	0.28
						Approved for Development
Tortue Field	8.333	15.90	-	15.90	1.07	23.50	-	23.50	1.55	31.40	-	31.40	1.75
Total		15.90	-	15.90	1.07	23.50	-	23.50	1.55	31.40	-	31.40	1.75
								Justified for Development
Aje Field Oil	12.1913	0.50	-	0.50	0.07	0.94	-	0.94	0.14	1.76	-	1.76	0.26
Aje Field Cond.	12.1913	9.78	-	9.78	1.49	16.16	-	16.16	2.53	26.61	-	26.61	3.93
Aje Field LPG 12.1913		19.33	-	19.33	3.01	31.51	-	31.51	4.99	53.77	-	53.77	7.71
Aje Field Gas 12.1913		-	282.00	46.92	7.32	-	459.00	76.50	12.12		- 783.00	130.55	18.72
Total		29.61	282.00	76.53	11.89	48.61	459.00	125.11	19.78		82.14 783.00	212.69	30.62
							Totals
Total Reserves		47.17	282.00	94.09	13.16	74.13	459.00	150.63	21.58		115.85 783.00	246.40	32.65

Reserves Development:

2P Reserves Development	(MMBOE)
Balance (previous ASR – December 31, 2016)	3.1
Production 2017	(0.1)
Acquisitions /disposals since previous ASR	0.0
Extensions and discoveries since previous ASR	0.0
New developments since previous ASR	21.2
Revisions of previous estimates	(2.6)
Balance (revised ASR) as of December 31, 2017	21.6

Contingent Resources summary:

Asset	2C MMBOE (as of YE2016)	2C MMBOE (as of this report)
Aje *	28.7	1.1
Dussafu **	6.8	1.5
Totals	35.5	2.6

* The majority of Aje Contingent Resources have been re-classified as reserves in 2018.

** Panoro's share of Dussafu has changed to 8.333% from 33.333% and the majority of Tortue Contingent Resources have been re-classified as reserves in 2018.

OPERATIONS

Operations in Gabon

3P Proved plus Probable plus Possible Reserves at Tortue amounted to 31.4 MMbbls.In addition to these Reserves NSAI also certified gross 1C Contingent Resources of 3.7 MMbbls and gross 2C Contingent Resources of 11.6 MMbbls in the Tortue field.

Operations in Nigeria

In July 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 process for the renewal of the OML 113 lease in June 2018 has commenced in 2017.

Operations in Brazil

THE ACCOUNTS

The Board of Directors confirms that the annual financial statements have been prepared pursuant to the going concern assumption, in accordance with §3-3a of the Norwegian Accounting Act, 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.

During the year, the Company has received USD 12 million plus some working capital adjustments at the closing of the sale of 25% interest in Dussafu permit to BWEG. The Company has in place a non-recourse loan from BW Energy in relation to the funding of the Dussafu development. As of December 31, 2017, Panoro's drawdown on the non-recourse loan was USD 2.2 million. The non-recourse loan is payable through Panoro's proceeds of the cost oil allocation in accordance with the Dussafu PSC, after paying the proportionate field operating expenses. The repayment will start at First oil on Dussafu. During the repayment phase, Panoro will still be entitled to its share of profit oil proceeds from the Dussafu operations.

The Company expects it is fully funded through the development of Phase 1 at Dussafu, from cash balances, cash flow from operations, and the non-recourse loan from BWEG. Should additional funding be required in the future for additional capital expenditure for new development phases or working capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. The options include, amongst others, debt financing, offtake prepayment structures, and the issuance of shares. As a result, the financial statement has been prepared under the assumption of going concern and realization of assets and settlement of debt in normal operations.

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.

FINANCIAL PERFORMANCE AND ACTIVITIES

Condensed Consolidated Income Statement

USD 000	2017	2016

Continuing operations
Oil and gas revenue	6,021	5,461
Other revenue	497	-
Total revenues	6,518	5,461
Expenses
Operating costs	(6,858)	(4,558)
Exploration related costs and operator G&A	(343)	(660)
Non-recurring dispute costs	(995)	-
General and administrative costs	(3,655)	(4,063)
Total operating expenses	(11,851)	(9,281)
EBITDA	(5,333)	(3,820)

Depreciation	(1,898)	(2,231)
Asset write-off and impairment	(28,576)	(55,795)
Share based payments	(149)	(47)
EBIT	(35,956)	(61,893)
Net financial items	(360)	(94)
Loss before taxes	(36,316)	(61,987)
Income tax benefit / (expense)	4	-
Net loss from continuing operations	(36,312)	(61,987)
Net income / (loss) from discontinued operations	(277)	(649)
Net income / (loss) for the period	(36,589)	(62,636)

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".

Income statement

Panoro Energy reported an EBITDA of negative USD 5.3 million for the year ended December 31, 2017, compared to negative USD 3.8 million in the same period in 2016.

EBITDA includes the oil and gas revenue from the four liftings from the Aje field during 2017 and the associated operating costs and the gain on the sale of a 25% stake in Dussafu.

Oil and gas revenue in the period was USD 6.0 million and is based on the Company's entitlement barrels; the revenue was generated by the sale of the net entitlement volume of 113,367 bbls. Other Income in the same period of USD 0.5 million represents the net gain on disposal of the 25% working interest in Dussafu. Oil & gas revenue in the same period of 2016 was USD 5.5 million and was generated by the sale of the net entitlement volume of 110,539 bbls.

Panoro Energy reported a net loss of USD 36.3 million from continuing operations for the year ended December 31, 2017, a decrease in loss of USD 25.9 million, compared to a loss of USD 62.0 million in the same period in 2016. The decrease in loss was a direct result of the lower impairment charges in 2017.

Operator G&A and related overheads decreased to USD 0.3 million in the year ended December 31, 2017, down from USD 0.7 million in same period in 2016.

General and Administration costs from continuing operations were USD 3.7 million for year ended December 31, 2017, down from USD 4.1 million for the same period in 2016. In 2017, USD 1.0 million of costs directly related to the Aje dispute have been reported separately as non-recurring dispute costs; there were no such costs in the same period in 2016. This amount is net of an award of USD 0.4 million reimbursement of costs pursuant to Court orders.

Depreciation for the period was USD 1.9 million decreasing from USD 2.2 million in the same period in 2016 with both periods relating to the depreciation of the Aje Cenomanian oil field. 2017 is a comparatively lower charge following an impairment exercise on Aje.

EBIT from continuing operations was thus a negative USD 36 million for the year ended December 31, 2017, compared to a negative USD 61.9 million in the same period of 2016.

Net financial items amounted to an expense of USD 360 thousand in the current period compared to an expense of USD 94 thousand in the same period in 2016. This is due to accretion of notional interest on the Aje Asset Decommissioning Liability during 2017 and finance charges.

Loss before tax from continuing activities was USD 36.3 million for the year ended December 31, 2017 compared to the loss of USD 62.0 million for the same period in 2016. The decrease in loss in 2017 is predominantly due to the inclusion of impairment provision for Aje and Dussafu in 2016. Net loss for the period from discontinued operations in Brazil was USD 277 thousand for the period, compared to a net loss of USD 649 thousand for the same period in 2016. The total net loss for the year ended December 31, 2017 was USD 36.6 million, compared to a net loss of USD 62.6 million for the same period in 2016.

Minor movement in respective periods to other comprehensive income was a result of currency translation adjustments for reporting purposes.

Statement of financial position

Non-current assets amounted to USD 25.4 million at December 31, 2017, a decrease of USD 26.1 million from December 31, 2016.

The overall decline in total non-current assets was a result of the sale of 25% stake in Dussafu during the period and impairment provisions, offset by capital expenditure on both the assets. Property, furniture, fixtures and equipment remained largely unchanged at USD 0.1 million.

Other non-current assets remained unchanged at USD 0.1 million for both periods and relates mainly to the tenancy deposit for office premises.

Current assets amounted to USD 9.8 million as of December 31, 2017, compared to USD 7.2 million at December 31, 2016.

Trade and other receivables stood at USD 0.6 million, a decrease from USD 1.7 million at the end of December 2016. The movement is due predominantly to the realisation of sale proceeds due for Aje's liftings during the period, offset by Panoro's portion of unspent cash held in Dussafu JV. USD 1.4 million has been accumulated and held on the balance sheet as the cash cost of Aje crude oil inventory.

Cash and cash equivalents stood at USD 6.3 million at December 31, 2017, not including USD 1.5 million cash which was released back to the Company, with interest post-period-end, having been held as collateral against dispute costs by the UK Court Funds Office. This represents an increase from USD 4.8 million cash and cash equivalents at December 31, 2016. The increase is mainly attributed to the collection of the sale proceeds relating to the disposal of 25% stake in Dussafu during the period and proceeds from the Aje liftings during the period. This has been offset by the payment of Aje cash calls of USD 4.0 million and the repurchase of 1,000,000 Panoro shares for USD 0.5 million. USD 1.5 million of Aje dispute cash collateral remains as restricted cash during the period, although released back to Company post-period-end, increasing from USD 0.5 million as at December 31, 2016.

Equity amounted to USD 17.3 million as of December 31, 2017, compared to USD 54.3 million at the end of December 2016. The change reflects the loss for the period and the effect of the repurchase of 1,000,000 Panoro shares in August 2017.

Total non-current liabilities of USD 11.1 million for the year ended December 31, 2017, compared to USD 2.0 million for the same period in 2016 including the decommissioning provision for the Aje field.

There is also the inclusion of the non-recourse loan from BW Energy in relation to the funding of the Dussafu

development. As of December 31, 2017, Panoro's drawdown on the non-recourse loan was USD 2.2 million. The nonrecourse 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. The repayment will start at First Oil on Dussafu. During the repayment phase, Panoro will still be entitled to its share of profit oil, as defined in the PSC, from the Dussafu operations.

Other non-current liabilities include USD 6.8 million associated with historic cash calls on Aje, which will be settled from surplus funds, where available, from Aje crude sales after paying for current costs and liabilities.

Current liabilities amounted to USD 6.8 million at December 31, 2017, compared to USD 2.4 million at the end of December 2016.

Accounts payable, accruals and other liabilities amounted to USD 6.7 million, an increase from USD 2.3 million at the end of December 2016. The increase represents Aje operational accruals and higher corporate trade payables as at December 31, 2017. The tax liability of USD 0.1 million is in relation to historical tax liability in Brazil.

Since the settlement of the Aje dispute, 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 side-tracks at Aje-5 have been higher than anticipated and as such have resulted in proportional liabilities of USD 6.1 million as of December 31, 2017. Such liabilities are current in nature and are expected to be repaid in full by the end of financial year 2018. In addition to these, USD 6.8 million is classified as longterm 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. In addition to this, commercial arrangements agreed as part of the interim settlement measures are expected to have the effect of increasing Panoro's existing revenue interest for the remainder of 2018. It is anticipated that operating costs for OML 113 will be funded in entirety from the sale of our share of Aje crude during 2018.

Cash flows

Net cash flow from operating activities amounted to negative USD 2.0 million in 2017, compared to negative USD 2.6 million in 2016. The decline is primarily explained by lower costs throughout 2017 brought about by cost saving initiatives introduced by Management.

Net cash flow from investing activities was an inflow of USD 5.1 million in 2017, compared to an outflow of USD 11.8 million in 2016. The net cash inflow in 2017 mainly relates to

the disposal of a 25% stake in Dussafu, offset by investment in oil and gas assets.

Net cash flow from financing activities represented a cash outflow of USD 1.6 million in 2017, predominantly comprising USD 1.0 million of movement in restricted cash where USD 1.5 million was held as collateral against our dispute at Aje, however funds were returned to the Company post-period end. In addition to this, the Company purchased 1,000,000 of its own shares for approximately USD 0.5 million. This compares to a cash inflow in 2016 of USD 8.3 million, where proceeds from the Equity Private Placement of USD 8.8 million were offset by USD 520 thousand of restricted cash, held in connection with the dispute at Aje.

Foreign exchange impact on cash balances was a positive USD 30 thousand in 2017 and a negative USD 33 thousand in 2016.

Cash and cash equivalents thus increased to USD 6.3 million (2016: USD 4.8 million).

ALLOCATION OF PROFITS AND LOSSES

Parent company financial information

(Amounts in USD 000)	2017	2016
Total revenues	-	-
Operating expenses
Depreciation	-	-
General and administrative costs	(1,751)	(1,249)
Impairment of investment in subsidiary	(335)	(38,873)
Provision for Doubtful Receivables	(32,885)	(28,311)
Write-down of Intercompany balances	-	-
Total operating expenses	(34,971)	(68,433)
Earnings before interest and tax (EBIT)	(34,971)	(68,433)
Net interest and financial items	9,293	10,048
Loss before taxes	(25,678)	(58,385)
Income tax benefit / (expense)	-	-
Net loss	(25,678)	(58,385)

FUNDING

31, 2017, Panoro's drawdown on the non-recourse loan was USD 2.2 million. The non-recourse loan is payable through Panoro's proceeds of the allocated cost oil in accordance with the Dussafu PSC, after paying the proportionate field operating expenses. The repayment will start at first oil production at Dussafu. During the repayment phase, Panoro will still be entitled to the proceeds of its entire share of profit oil from the Dussafu operations. Consequently, Panoro is likely to receive free cash flow.

Since the settlement of the dispute with the OML 113 partners, USD 1.5 million of collateral is no longer required and has been released back to the Company on completion of legal formalities. In addition to this, commercial arrangements agreed as part of the interim settlement measures are expected to have the effect of increasing Panoro's existing revenue interest for the remainder of 2018. It is anticipated that operating costs for OML 113 will be funded in entirety from the sale of our share of Aje crude during 2018.

RISK FACTORS

Operational risk factors

The development of oil and gas fields in which the Company is involved is associated with technical risk, alignment in consortiums with regards to development plans, and on obtaining necessary licenses and approvals from the authorities. Disruptions of operations might lead to cost overruns and production shortfall, or delays compared to the schedules laid out by the operator of the fields. As a nonoperator, the Company has limited influence on operational risks related to exploration and development of the licenses and fields in which it has interests.

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.

The Company's license in Nigeria OML 113 is due for renewal during the year 2018. Although, the license renewal is expected to be customary, a near-term expiry exposes the Group to short-term uncertainty.

As the Company is exiting Brazil there are potential tax liabilities related among others to the divestment of Rio das Contas. In addition, there are uncertainties related to the final environmental costs of BS-3 licenses.

The Company's ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with third parties will be dependent upon developing and maintaining close working relationships with industry partners, joint operators and authorities, as well as its ability to select and evaluate suitable properties, and complete transactions in a highly competitive environment.

Financial risk factors

Financial risk is managed by the finance department under 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 exposures, debt servicing and oil and gas prices. Financial instruments such as derivatives, forward contracts and currency swaps are continuously being evaluated for the hedging of such risk exposures.

Due to the international nature of its operations, the Company is exposed to risk arising from currency exposure, primarily with respect to the Norwegian Kroner (NOK), the US Dollar (USD), and, to a lesser extent, the Pound Sterling (GBP) and Brazilian Reals (BRL). Most of the cash balance is held in USD with banking institutions of high quality credit ratings and the currency risk exposure is very limited.

The Company has access to a non-recourse loan facility of upto USD 12.5 million from BWEG and as a result is subject to interest rate risk. The Company's cash holdings and bank balances are held in various currencies in different countries and are subject to interest rate risk and credit risk.

The Company has received USD 12 million plus some working capital adjustments on closing of the sale of 25% interest in Dussafu permit to BWEG. As a result and including anticipated cash flow from operations, the Group's liquidity situation has significantly improved. The Company expects it is fully funded through the development of Phase 1 at Dussafu, from cash balances, cash flow from operations, and the non-recourse loan from BWEG. Should additional funding be required in the future for additional capital expenditure for new development phases or working

capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. The options include, amongst others, debt financing, offtake prepayment structures, and the issuance of shares. As a result, the financial statement has been prepared under the assumption of going concern and realization of assets and settlement of debt in normal operations.

Panoro has been entertaining discussions with a number of third parties having expressed interests to purchase part or all of its interests in OML 113. However there can be no assurances that any transaction contemplated under these discussions will be consummated.

For risk factors pertaining to the Company and its operations, reference is also made to the prospectus dated March 11, 2016 which is available on the Company's website.

ORGANISATION AND HEALTH, SAFETY AND ENVIRONMENT (HSE)

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 and Technical Director, Richard Morton, both are also based in London.

Since the beginning of 2017, Panoro Energy has been employing 5 individuals (including part-time employees), all of which are based in London.

The Company emphasizes the importance of maintaining a good working environment in order to achieve Company goals and objectives. The objective is to create a constructive working environment characterized by a spirit where employees' ideas and initiatives are welcome, founded on mutual trust between employees, management and the Board of Directors.

Health, Safety and Environment (HSE) 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, environment, safety and quality (HSEQ) 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.

Company time lost due to employee illness or accidents was less than 1 per cent of total hours worked during the year. Employee safety is of the highest priority, and company policies imply continuous work towards identifying and employing administrative and technical solutions that ensure a safe and efficient work-place.

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.

The oil and gas assets located in West Africa may mean frequent travel, and the Company seeks to ensure adequate safety levels for employees travelling. An emergency preparedness organization has been established, in which membership in International SOS is a key factor. International SOS provides updated risk assessments, medical support and evacuation services worldwide.

As a non-operator, Panoro 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 HSE standards. No accidents that resulted in loss of human lives or serious damage to people or property have been reported.

Panoro Energy is committed to work towards minimising waste and pollution as a consequence of its activities. Operations are centralised in the London office and as such, travel requirements have been greatly reduced.

As described above, all operating activities are being conducted by operators on behalf of the Company, and to the best of the Company's knowledge, all operations have been conducted within the limits set by approved environmental regulatory authorities.

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 longterm 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 period of two years. 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 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).

DISCRIMINATION AND EQUAL EMPLOYMENT OPPORTUNITIES

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.

80% of the employees were men and 20% women at the end of 2017 and 2016. There are currently no women in Panoro Energy's senior management.

DIRECTORS AND SHAREHOLDERS

According to its articles of association, the Company shall have a minimum of three and a maximum of eight directors on its Board. The number of Board members was five at year end 2017, 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 2017 are female. The Board held 8 meetings during the year.

REPORTING OF PAYMENT TO GOVERNMENTS

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 90 of this annual report and on Company's website www.panoroenergy.com.

OUTLOOK

Panoro looks forward to 2018, where it can build and capitalise on a landmark partnership with BWO and achieving production from Dussafu Development. At Aje, Panoro's efforts will be directed towards moving the Turonian gas development forward, renewal of the license and progressing any strategic solutions for OML 113. 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.

April 30, 2018 The Board of Directors Panoro Energy ASA

Julien Balkany Chairman of the Board

Alexandra Herger Non-Executive Director

Garrett Soden Non-Executive Director

Hilde Ådland Non-Executive Director

Torstein Sanness Non-Executive Director

John Hamilton Chief Executive Officer

BOARD OF DIRECTORS

JULIEN BALKANY

Chairman of the Board

Mr. Julien Balkany, Chairman of the Board, is a French citizen resident in London, has been serving as a managing partner of Nanes Balkany Partners, a group of investment funds headquartered in New York and which primarily pursues active value investments in publicly traded oil and gas companies gas companies since 2008. Concomitantly, Mr. Balkany is also non-executive Director of two mining companies, Sarmin Bauxite Ltd. and Pan-African Diamonds limited. Mr. Balkany has been from March 2015 to May 2016 a non-executive Director of Norwegian Energy Company ASA (Noreco), a Norwegian exploration and production company listed on the Oslo Stock Exchange and focused on the North Sea. Mr. Balkany has been from May 2014 to July 2015 a non-executive Director of Gasfrac Energy Services Inc., a Canadian oil and gas fracking

services company. From January 2009 to March 2011, Mr. Balkany served as Vice-Chairman and non-executive Director of Toreador Resources Corp., an oil and gas exploration and production company with operations in Continental Europe (France, Turkey, Hungary and Romania) that was dual-listed on the US NASDAQ and Euronext Paris. Mr. Balkany has been a Managing Director at Nanes Delorme Capital Management LLC, a New York based financial advisory and broker-dealer firm, where he executed several hundred million dollars' worth of oil & gas M&A transactions. Before joining Nanes Delorme, Mr. Balkany worked at Pierson Capital and gained significant experience at Bear Stearns. Mr. Balkany studied at the Institute of Political Studies (Strasbourg) and at UC Berkeley. Mr. Balkany is fluent in French, English and Spanish.

ALEXANDRA HERGER

Non-Executive Director

Ms. Alexandra (Alex) Herger, a US citizen based in Maine, has extensive senior leadership and board experience in worldwide exploration and production for international oil and gas companies. Ms. Herger has 39 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 20022008, 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.

GARRETT SODEN

Non-Executive Director

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., Petropavlovsk plc 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 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

Non-Executive Director

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 is currently Asset Manager for Gjøa and Vega for Neptune Energy in Norway (previously Engie E&P Norges as and GDF SUEZ E&P Norge as). She held several senior positions with Engie/GDF SUEZ in Norway including production and development manager and senior facility engineer. Prior to joining GDF in 2008, she spent 12 years with Statoil in a number of senior engineering and operational roles, including Offshore Installation Manager, and 5 years with Kvaerner. In autumn 2015 she was also elected chairman in the Operation Committee within the Norwegian Oil and Gas Association. She has a Bachelor's degree in chemical engineering and a Master's degree in process engineering.

TORSTEIN SANNESS

Non-Executive Director

Mr. Torstein Sanness, a Norwegian Citizen residing in Norway 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 Lundin Group E&P company with portfolio of assets in Canada, Europe and South East Asia), Sevan Marine ASA, (a specialised marine engineering and design house), 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).

SENIOR MANAGEMENT

JOHN HAMILTON

Chief Executive Officer

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 US\$ 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 has a BA from Hamilton College in New York, and an MBA from the Rotterdam School of Management and New York University.

QAZI QADEER

Chief Financial Officer

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

Technical Director

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.

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For the year January 1, 2017 to December 31, 2017

USD 000	Note	2017	2016
CONTINUING OPERATIONS
Revenue
Oil and gas revenue	3	6,021	5,461
Other revenue		497	-
Total revenue		6,518	5,461
Expenses
Operating costs	3	(6,858)	(4,558)
Exploration related costs and operator G&A		(343)	(660)
Non-recurring dispute costs		(995)	-
General and administrative costs	4	(3,655)	(4,063)
Impairment / reversal of Impairment of assets	9D	(28,576)	(55,795)
Depreciation	9	(1,898)	(2,231)
Share based payments	16	(149)	(47)
Total operating expenses		(42,474)	(67,354)
Operating loss	4	(35,956)	(61,893)
Net foreign exchange (loss) / gain		30	(33)
Interest costs net of income	5	(254)	43
Other financial costs	5	(136)	(104)
Loss before income taxes		(36,316)	(61,987)
Income tax benefit / (expense)	6	4	-
Net loss from continuing operations		(36,312)	(61,987)
DISCONTINUED OPERATIONS
Net income / (loss) from discontinued operations	12	(277)	(649)
Net loss for the period		(36,589)	(62,636)
Exchange differences arising from translation of foreign operations		(3)	(10)
Other comprehensive income / (loss) for the period (net of tax)		(3)	(10)

Total comprehensive income / (loss)		(36,592)	(62,646)
Net loss attributable to:
Equity holders of the parent		(36,589)	(62,636)
Total comprehensive income / (loss) attributable to:
Equity holders of the parent		(36,592)	(62,646)
Earnings per share	7
(USD) – Basic and diluted – Income / (loss) for the period attributable to equity holders of the parent – Total		(0.86)	(1.61)
(USD) – Basic and diluted – Income / (loss) for the period attributable to equity holders of the parent – Continuing operations		(0.85)	(1.60)

As at December 31, 2017

USD 000	Note	2017	2016
ASSETS
Non-current assets
Intangible assets
Licenses and exploration assets	8	13,596	25,971
Total intangible assets		13,596	25,971

Tangible assets
Production assets and equipment	9	9,902	25,285
Development assets	8	1,694	-
Property, furniture, fixtures and equipment	9	102	169
Other non-current assets	9	134	122
Total tangible assets		11,832	25,576
Total non-current assets		25,428	51,547

Current assets
Crude oil inventory		1,398	163
Trade and other receivables	10	615	1,724
Cash and cash equivalents	11	6,317	4,768
Restricted cash	11	1,500	520
Total current assets		9,830	7,175

TOTAL ASSETS		35,258	58,722

EQUITY AND LIABILITIES
Equity
Share capital	14	299	305
Share premium		297,490	297,503
Treasury shares	14	(503)	-
Additional paid-in capital		122,205	122,101
Total paid-in equity		419,491	419,909
Other reserves	14	(43,405)	(43,404)
Retained earnings		(358,766)	(322,177)
Total equity attributable to shareholder of the parent		17,320	54,328

Non-current liabilities
Decommissioning liability	13	2,039	1,925
Long-term liabilities	15	2,197	-
Other long-term liabilities	15	6,892	88
Total non-current liabilities		11,128	2,013

Current liabilities
Accounts payable and accrued liabilities	15	6,737	2,287
Corporate tax liability		73	94
Total current liabilities		6,810	2,381

TOTAL EQUITY AND LIABILITIES		35,258	58,722

As at December 31, 2017

		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, 2016		193	288,858	-	122,054	(259,539)	(37,647)	(5,748)	108,171

Net income / (loss) – Continuing Operations		-	-	-	-	(61,987)	-	-	(61,987)
Net income / (loss) – Discontinued Operations		-	-	-	-	(649)	-	-	(649)
Other comprehensive income / (loss)		-	-	-	-	-	-	(10)	(10)
Total comprehensive income / (loss)		-	-	-	-	(62,636)	-	(10)	(62,646)
Share Issue for cash		112	9,294	-	-	-	-	-	9,406
Transaction costs on Share Issue		-	(650)	-	-	-	-	-	(650)
Employee share based incentives	16	-	-	-	47	-	-	-	47
At December 31, 2016		305	297,503	-	122,101	(322,177)	(37,647)	(5,758)	54,328

At January 1, 2017		305	297,503	-	122,101	(322,177)	(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)		-	-	-	-	-	-	(3)	(3)
Total comprehensive income / (loss)		-	-	-	-	(36,589)	-	(3)	(36,592)
Purchase of own shares		(6)	-	(503)	-	-	-	-	(509)
Transaction costs on share buy back		-	(13)	-	-	-	-	-	(13)
Employee share based incentives	16	-	-	-	149	-	-	-	149
Employee share options grant charge / (benefit)		-	-	-	(44)	-	-	-	(44)
At December 31, 2017		299	297,490	(503)	122,206	(358,766)	(37,647)	(5,761)	17,320

For the year ended December 31, 2017

USD 000	2017	2016

Cash flows from operating activities
Net (loss) / income for the year before tax – Continuing operations	(36,316)	(61,987)
Net (loss) / income for the year before tax – Discontinued operations	(203)	(514)
Net (loss) / income for the year before tax	(36,519)	(62,501)
Adjusted for:
Depreciation	1,898	2,231
Exploration related costs and Operator G&A	343	660
Impairment and asset write off	28,576	56,566
Net finance costs	390	61
Share-based payments	149	47
Foreign exchange loss / (gain)	(30)	33
Increase / (decrease) in trade and other payables	4,084	1,657
(Increase) / decrease in trade and other receivables	463	(1,188)
(Increase) / decrease in oil inventory	(1,235)	(163)
Taxes paid	(71)	(41)
Net cash flows from operating activities	(1,952)	(2,638)

Cash flows from investing activities
Proceeds from disposal of Assets	12,737	-
Investment in exploration, production and other assets	(7,685)	(12,617)
Movement in related non-current assets	-	813
Net cash flows from financing activities	5,052	(11,804)
Cash flows from financing activities
Own shares buy back	(509)	-
Net proceeds from Equity Private Placement	-	8,774
Net financial income (net of charges paid)	(65)	18
Movement in restricted cash balance	(980)	(520)
Net cash flows from financing activities	(1,554)	8,272

Effect of foreign currency translation adjustment on cash balances	3	(10)
Change in cash and cash equivalents during the period	1,549	(6,180)

Cash and cash equivalents at the beginning of the period	4,768	10,948
Cash and cash equivalents at the end of the period	6,317	4,768

NOTE 1. CORPORATE INFORMATION

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 Michelet & Co Advokatfirma AS, Grundingen 3, 0250 Oslo, Norway.

The Company and its subsidiaries ("Panoro" or the "Group") are engaged in the exploration and production of oil and gas resources in West Africa. The consolidated financial statements of the Group for the year ended December 31, 2017 were authorised for issue by the Board of Directors on April 30, 2018.

During the year, the Company has received USD 12 million plus some working capital adjustments at the closing of the sale of 25% interest in Dussafu permit to BWEG. The Company has in place a non-recourse loan from BW Energy in relation to the funding of the Dussafu development. As of December 31, 2017, Panoro's drawdown on the non-recourse loan was USD 2.2 million. The non-recourse loan is payable through Panoro's proceeds of the allocated cost oil in accordance with the Dussafu PSC, after paying the proportionate field operating expenses. The repayment will start at First oil on Dussafu. During the repayment phase, Panoro will still be entitled to its share of profit oil proceeds from the Dussafu operations.

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

NOTE 2. BASIS OF PREPARATION

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

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

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

NOTE 2.1 BASIS OF CONSOLIDATION

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

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

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

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

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

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

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

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

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

NOTE 2.2 SIGNIFICANT ACCOUNTING JUDGMENTS, ESTIMATES AND ASSUMPTIONS

a. Estimates and assumptions

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 reserve and resource estimates

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

Exploration and evaluation expenditures

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

Income taxes

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

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

b. Judgments

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

Dispute and litigation

On November 2, 2017, Panoro announced that its subsidiary Pan Petroleum Aje Limited ("PPAL") had entered into a binding agreement with the other OML 113 joint-venture partners. The agreement in conjunction with other initiatives addresses a number of operational and financial issues. Under the terms of the agreement, certain transitional arrangements were introduced whereby unpaid cash calls will not be immediately payable. Such unpaid cash calls are included in the longterm payable balance as of the end of the quarter. During the transition period, any excess funds from Panoro's entitlement of crude liftings shall be used to pay operational costs incurred in the JV, any remaining liabilities and unpaid cash calls. In addition to this, commercial arrangements agreed as part of the settlement measures are expected to have the effect of increasing PPAL's existing revenue interest until approximately the end of 2018.

On January 2, 2018, post period end, Panoro announced that 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.

The highlights of the Agreement included:

All OML 113 joint-venture partners have agreed to halt and withdraw all litigation and arbitration proceedings among the partners;

PPAL would not pay for any Aje-6 costs that have been incurred by the JV, until such time as the equipment and parts are to be used in any potential future well operations;
Substantial court costs already awarded to PPAL to be retained and any remaining balances credited in favour of PPAL; and
PPAL's USD 1.5 million cash security deposit held with UK Courts Funds Office would be released and returned to it. PPAL completed the formalities post-period end and funds have been returned.

Impairment indicators

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

The recoverable amounts of cash-generating units and individual assets have been determined based on the higher of 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.

Technical risk in development of oil and gas fields

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 obligations

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

Contingencies

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

NOTE 2.3 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

a. Interests in joint arrangements

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

(i) Joint operations

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

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

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

(ii) Joint ventures

A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. The Group's investment in its joint venture is accounted for using the equity method. Under the equity method, the investment in the joint venture is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group's share of net assets of the joint venture since the acquisition date. Goodwill relating to the joint venture is included in the carrying amount of the investment and is not individually tested for impairment.

The statement of profit or loss reflects the Group's share of the results of operations of 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.

(iii) Reimbursement of costs of the operator of the joint arrangement

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

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.

b. Foreign Currency translation

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

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

The foreign exchange rates applied were:

	2017		2016
	Average rate	Reporting date rate	Average rate	Reporting date rate
Norwegian Kroner / USD	8.2654	8.1993	8.3998	8.6051
Brazilian Real / USD	3.1922	3.3077	3.4830	3.2588
USD / British Pound	1.2888	1.3510	1.3542	1.2303

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.

c. Business combinations and goodwill

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

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 IAS 39 Financial Instruments: Recognition and Measurement 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 IAS 39, it is measured in accordance with the appropriate IFRS. Contingent consideration that is classified as equity is not re-measured, and subsequent settlement is accounted for within equity.

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

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

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

d. License interests, exploration and evaluation assets, and field investments, and depreciation

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

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

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

Development tangible and intangible assets

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

Farm-outs – in the exploration and evaluation phase

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

Development costs

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

Oil & gas production assets

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

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

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

Depreciation/amortisation

Oil and gas properties 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.

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.

Impairment – exploration and evaluation assets

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

Impairment – proved oil and gas production properties and intangible assets

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

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

The Group classifies non-current assets and disposal groups as held for sale or for distribution to equity holders of the parent if their carrying amounts will be recovered principally through a sale or distribution rather than through continuing use. Such 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:

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

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

f. Financial assets

Initial recognition and measurement

Financial assets are classified, at initial recognition, as financial assets at fair value through profit or loss, loans and receivables, held-to-maturity investments, restricted cash, available-for-sale (AFS) financial assets, or derivatives designated as hedging instruments in an effective hedge, as appropriate. All financial assets are recognised initially at fair value plus, in the case of financial assets not recorded at fair value through profit or loss, transaction costs that are attributable to the acquisition of the financial asset.

Purchases or sales of financial assets that require delivery of assets in a timeframe established by regulation or convention in the market place (regular way trades) are recognised on the trade date, i.e., the date at which the Group commits to purchase or sell the asset.

The Group's financial assets include cash and cash equivalents and certain trade and other receivables.

Subsequent measurement

For purposes of subsequent measurement financial assets are classified into four categories:
Financial assets at fair value through profit or loss
Trade and other receivables
Held-to-maturity investments the Group has no held-to-maturity investments
AFS financial investments the Group has no AFS financial assets

Financial assets at fair value through profit or loss

Financial assets at fair value through profit or loss include financial assets held for trading and financial assets designated upon initial recognition at fair value through profit or loss. Financial assets are classified as held for trading if they are acquired for the purpose of selling or repurchasing in the near term. Derivatives, including separated embedded derivatives, are also classified as held for trading unless they are designated as effective hedging instruments, as defined by IAS 39. Financial assets at fair value through profit or loss are carried in the statement of financial position at fair value with net changes in fair value presented as finance costs (negative changes in fair value) or finance revenue (positive net changes in fair value) in

the statement of comprehensive income. The Group has not designated any financial assets at fair value through profit or loss.

Derivatives embedded in host contracts are accounted for as separate derivatives and recorded at fair value if their economic characteristics and risks are not closely related to those of the host contracts and the host contracts are not held for trading or designated at fair value though profit or loss. These embedded derivatives are measured at fair value, with changes in fair value recognised in the statement of profit or loss and other comprehensive income. Reassessment occurs only if there is a change in the terms of the contract that significantly modifies the cash flows that would otherwise be required or there is a reclassification of a financial asset out of the fair value through profit or loss category. The group has no embedded derivatives as of December 31, 2016 and December 31, 2017.

Trade and other receivables

This category is most relevant to the Group. Trade and other receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement, such financial assets are subsequently measured at amortised cost using the effective interest rate method, less impairment. Amortised cost is calculated by taking into account any discount or premium on acquisition and fees or costs that are an integral part of the effective interest rate. The effective interest rate amortisation is included in finance income in the statement of profit or loss and other comprehensive income. The losses arising from impairment are recognised in the statement of profit or loss and other comprehensive income in finance costs for loans and in cost of sales or other operating expenses for receivables.

Cash and cash equivalents

Cash and cash equivalents includes cash at hand, and deposits held on call with banks. Cash balances in current accounts, short-term deposits and placement with maturity of six months or less in highly liquid investments are classified as cash and cash equivalents.

Impairment of financial assets

The Group assesses at each reporting date whether a financial asset or group of financial assets are impaired. Details of impairment principles for financial assets is included in note 2.5(q).

g. Financial liabilities

Initial recognition and measurement

Financial liabilities are classified, at initial recognition, as financial liabilities at fair value through profit or loss, loans and borrowings, payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate.

All financial liabilities are recognised initially at fair value and, in the case of loans and borrowings and payables, net of directly attributable transaction costs.

The Group's financial liabilities include trade and other payables, loans and borrowings including bank overdrafts and derivative financial liabilities.

The Group's financial liabilities include trade and other payables, and loans and borrowings.

Subsequent measurement

The measurement of financial liabilities depends on their classification, as described below:

Trade payables

Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.

Loans and borrowings

All borrowings are initially recorded at fair value. Interest-bearing loans and overdrafts are initially recorded at the proceeds received, net of directly attributable issue costs. Finance charges, including premiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement using the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the period in which they arise.

Under the requirements of IAS 39 AG8, any revisions to the estimates of payments or receipts in relation to a financial instrument are adjusted to reflect the actual and revised estimated cashflows. The change in estimated cashflows are remeasured by computing the present value of estimated cashflows at the financial instrument's original effective interest rate. The adjustment is recognised in the statement of comprehensive income as Income or expense.

h. Provisions

General

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it

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

i. Asset retirement obligation

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

j. Income tax

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

Current tax

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

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

Deferred tax

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

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

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

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

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

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.

Production-sharing arrangements

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

Sales tax

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.

k. Revenue recognition

Revenue from petroleum products

Revenue from the sale of petroleum products is recognized as income using the "entitlement method". Under this method, revenue is recorded on the basis of the asset's proportionate share of total crude, gas and NGL produced from the affected fields. Revenue is stated net of value-added tax and royalties.

Revenue from test production is recognised as a direct off-set to the capitalised cost of the exploration and evaluation asset.

Interest income and financial instruments measured at amortised cost

Interest income is recognized on an accruals basis. For all financial instruments measured at amortised cost and interestbearing 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.

Rendering of services

Sales of services are recognized in the accounting period in which the services are rendered, and it is probable that the economic benefits associated with the transaction will flow to the entity, by reference to completion of the specific transaction assessed on the basis of the actual service provided as a proportion of the total services to be provided.

l. Leases

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.

Group as a lessee

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.

m. Property, plant and equipment

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

Computer equipment	20–33.33%
Furniture, Fixtures & fittings	10–33.33%

n. Defined contribution pension plan

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

o. Share-based payment transactions

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

Equity-settled transactions

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

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

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

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

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

p. Fair value measurement

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

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

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

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

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

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

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

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

Level 1 Quoted (unadjusted) market prices in active markets for identical assets or liabilities
Level 2 Valuation techniques for which the lowest-level input that is significant to the fair value measurement is directly or indirectly observable
Level 3 Valuation techniques for which the lowest-level input that is significant to the fair value measurement is unobservable

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

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

q. Impairments of non-oil and gas interests

Non-financial assets

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

Financial assets

Assets carried at amortised cost

If there is objective evidence that an impairment loss on assets carried at amortised cost has been incurred, the amount of the loss is measured as the difference between the assets' carrying amount and the present value of estimated future cash flows (excluding future expected credit losses that have not been incurred) discounted at the financial asset's original effective interest rate (ie 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.

In relation to trade receivables, a provision for impairment is made when there is objective evidence (such as the probability of insolvency or significant financial difficulties of the debtor) that the Group will not be able to collect all of the amounts due under the original terms of the invoice. The carrying amount of the receivable is reduced through use of an allowance account. Impaired debts are derecognised when they are assessed as uncollectible.

r. Current versus non-current classification

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

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

All other assets are classified as non-current.

A liability is current when either:

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

The Group classifies all other liabilities as non-current.

Deferred tax assets and liabilities are classified as non-current assets and liabilities.

NOTE 2.4 NEW AND AMENDED STANDARDS AND INTERPRETATIONS

There were a number of amended standards and interpretations, effective from January 1, 2017 that the Group applied for the first time in the current year. Several other amendments apply for the first time in 2017; however, they do not impact the annual consolidated financial statements of the Group. The nature and the impact of each new relevant standard and/ or amendment that may have an impact on the Group now or in the future is described below. Other than the changes described below, the accounting policies adopted are consistent with those of the previous financial year.

IAS 7 Statement of Cash Flow

The objective of IAS 7 is to require the presentation of information about the historical changes in cash and cash equivalents of the Group by means of a statement of cash flows, which classifies cash flows during the period according to operating, investing and financing activities. The amendments are intended to clarify IAS 7 to improve information provided to users of financial statements about the Group's financing activities. They are effective for annual periods beginning on or after 1 January 2017, with earlier application being permitted.

IFRS 12 Disclosure of Interests in Other Entities

IFRS 12 is a consolidated disclosure standard requiring a wide range of disclosures about the Group's interests in subsidiaries, joint arrangements, associates and unconsolidated 'structured entities'. Disclosures are presented as a series of objectives, with detailed guidance on satisfying those objectives. The objective of IFRS 12 is to require the disclosure of information that enables users of financial statements to evaluate:

the nature of, and risks associated with, its interests in other entities
the effects of those interests on its financial position, financial performance and cash flows.

Where the disclosures required by IFRS 12, together with the disclosures required by other IFRSs, do not meet the above objective, the Group is required to disclose whatever additional information is necessary to meet the objective.

IAS 12 Income Taxes

The objective of IAS 12 is to prescribe the accounting treatment for income taxes. In meeting this objective, IAS 12 notes the following:

It is inherent in the recognition of an asset or liability that that asset or liability will be recovered or settled, and this recovery or settlement may give rise to future tax consequences which should be recognised at the same time as the asset or liability
The Group should account for the tax consequences of transactions and other events in the same way it accounts for the transactions or other events themselves.

NOTE 2.5 STANDARDS ISSUED BUT NOT YET EFFECTIVE

The standards and interpretations that are issued but not yet effective up to the date of issuance of the Group's financial statements are discussed below. These are the changes the Group reasonably expects will have an impact on disclosures, financial position or performance when applied at a future date. The Group intends to adopt these standards and interpretations, if applicable, when they become effective.

IFRS 9 Financial Instruments

In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments which reflects all phases of the financial instruments project and replaces IAS 39 Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. The standard introduces new requirements for classification and measurement, impairment, and hedge accounting. IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early application permitted, and was endorsed by the EU in November 2016. Retrospective application is required, but comparative information is not compulsory. Early application of previous versions of IFRS 9 (2009, 2010 and 2013) is permitted if the date of initial application is before February 1, 2015. The Company does not believe the adoption of IFRS 9 will have any impact as it does not have any financial assets that would be affected by the new standard.

IFRS 15 Revenue from Contracts with Customers

IFRS 15 was issued in May 2014 and establishes a new five-step model that will apply to revenue arising from contracts with customers. Under IFRS 15, revenue is recognized 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.

The principles in IFRS 15 provide a more structured approach to measuring and recognising revenue. The new revenue standard is applicable to all entities and will supersede all current revenue recognition requirements under IFRS. Either a full or modified retrospective application is required for annual periods beginning on or after January 1, 2018 with early adoption permitted, and was endorsed by the EU in September 2016. There have been some early indicators that the entitlement method currently applied by the company will not be allowed under IFRS 15, but this has not yet been concluded. The company has assessed the impact of IFRS 15 and considers there to be no impact due to the fact that the partners share liftings and therefore there is no over / underlift. The Company recognises the revenue when the risk and reward passess to the customer. The Company plans to adopt the new standard on the required effective date.

IFRS 16 Leasing

On January 13, 2016, the IASB issued IFRS 16 Leases ("IFRS 16"), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short term leases (less than 12 months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases. Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded. Having been endorsed by the EU in October 2017, IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 Revenue From Contracts With Customers has been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The new standard changes introduce a single on-balance sheet accounting model for all leases, which will result in the recognition of a lease liability and a right of use asset in the balance sheet. The Company is currently evaluating the impact of adopting these standards on its consolidated financial statements, which will see all current and any future leased vessels or rigs being capitalised in the Company's balance sheet.

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

NOTE 3. OPERATING SEGMENTS

From 2014, the Group operated predominantly in one business segment being the exploration of oil and gas in West Africa. After the Company took a decision to cease all operations in Brazil, the segment has been classified as a discontinued operation. Details of discontinued operations can be referred to in note 12. As such, the segment information for December 31, 2017 does not include Brazilian operations. 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: The West African segment holds the following assets:

The Dussafu licence representing the Group's 8.333% working interest in the Dussafu Marin exploration licence in Gabon.
The OML113-Aje represents the Group's 16.255% paying interest (12.1913% revenue interest) in the OML113-Aje exploration licence in Nigeria.
The 'Corporate and others' category consists of head office and service company operations that are not directly attributable to the other segment.
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 after disposal of subsidiary in Brazil. Details of group segments are reported below.

Details of Group segments are reported below.

2017			Total – Continuing	Brazil – Discontinued
USD 000	West Africa	Corporate	operations	operations	Total
Revenue (net) *	6,518	-	6,518	-	6,518
EBITDA	(790)	(4,543)	(5,333)	(74)	(5,407)
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, exploration and evaluation assets, development assets	16,435	-	16,435	-	16,435

2016			Total –	Brazil –
USD 000	West Africa	Corporate	Continuing operations	Discontinued operations	Total
Revenue (net)	5,461	-	5,461	-	5,461
EBITDA	(49)	(3,771)	(3,820)	(103)	(3,923)
Depreciation	(2,134)	(97)	(2,231)	-	(2,231)
Impairment	(55,608)	-	(55,608)	(419)	(56,027)
Profit / (loss) before tax	(60,286)	(1,701)	(61,987)	(514)	(62,501)
Net profit / (loss)	(60,286)	(1,701)	(61,987)	(514)	(62,501)
Segment assets	52,698	5,901	58,599	123	58,722
– Additions to licenses, exploration and evaluation assets, development assets	13,503	-	13,503	-	13,503

* Revenue excludes any intercompany revenue.

** Segment assets for Discontinued Operations as at December 31, 2017 relate to USD 127 thousand, Cash and USD 4 thousand, Other Receivables (December 31, 2016 USD 4 thousand, Cash and USD 119 thousand, Other Receivables).

Revenue from major sources from continuing operations:

USD 000	2017	2016
Oil revenue (net)	6,021	5,461
Other income	497	-
Total Revenue (net)	6,518	5,461

There are no differences in the nature of measurement methods used on segment level compared with the consolidated financial statements.

NOTE 4. OPERATING PROFIT

Operating profit is stated after charging / (crediting):

USD 000	Note	2017	2016
Employee benefits expense		1,548	1,571
Depreciation	9	1,898	2,231
Impairment and asset write-off	9, 12	28,576	56,027
Operating lease payments		228	241

NOTE 4A. EMPLOYEE BENEFIT EXPENSES

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

USD 000	2017	2016
Salaries	1,217	1,228
Employers contribution	156	153
Pension costs	104	114
Other compensation	71	76
Total	1,548	1,571

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

	2017	2016
Number of employees	5	5

NOTE 4B. BOARD OF DIRECTORS STATEMENT ON REMUNERATION OF EXECUTIVES

Statement for the current year (2017)

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 78 of this report.

NOTE 4C. MANAGEMENT REMUNERATION

Executive management has in previous years, consisted of the Chief Executive Officer (CEO), Chief Financial Officer (CFO) and Chief Operating Officer (COO). Current Executive management remuneration is summarized below:

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

2016		Short term benefits
USD 000 (unless stated otherwise)	Salary	Bonus	Benefits	Pension costs	Total	Number of RSUs awarded in 2016	Fair value of RSUs expensed
John Hamilton, CEO	372	74	7	37	490	100,000	21
Qazi Qadeer, CFO	225	45	4	22	296	50,000	10
Richard Morton, Technical Director	239	24	4	24	290	40,000	8
Total	836	143	15	83	1,076	190,000	39

(i) Under the terms of employment, the CEO in general is required to give at least six month's written notice prior to leaving Panoro; the CFO and Technical Director in general are required to give at least three month's written notice prior to leaving Panoro.

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

(iii) In June 2017, 420,000 Restricted Share Units (RSU) were awarded under the Company's RSU scheme to employees of the Company under the long term incentive compensation plan approved by the shareholders, of which 380,000 units were awarded to Executive Management. 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. RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter.

(iv) All salaries, bonuses and benefit payments have been expensed as incurred.

(v) All bonuses were approved by the Board of Directors.

Refer to note 16 for further information on the Restricted Share Units scheme.

NOTE 4D. BOARD OF DIRECTORS REMUNERATION

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

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

USD 000	2017	2016
Julien Balkany (Chairman of the Board of Directors)	68	66
Alexandra Herger	39	38
Garrett Soden	39	38
Torstein Sanness	39	38
Hilde Ådland (i)	39	28
Total	224	208

The Chairman of the Board of Directors' annual remuneration is NOK 450,000. The remaining Directors' annual remuneration is NOK 225,000. 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.

(i) Pursuant to an Extraordinary General Meeting held on March 2, 2016, Hilde Ådland was elected to the Board of Directors with an effective date of April 1, 2016 to take the Board composition to five members.

NOTE 4E. PENSION PLAN

The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension ("Lov om obligatorisk tjenestepensjon"). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognized in the statement of financial position. As of December 2017, the Company had no employees at parent company level and this pension plan is no longer in operation.

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.

Refer to Note 4a for the contributions made to the external defined scheme for 2017 and 2016.

NOTE 4F. AUDITORS' REMUNERATION

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

USD 000	2017	2016
Ernst & Young
Statutory audit	93	181
Tax services	-	-
Other	-	-
Total	93	181

NOTE 5. FINANCE INCOME, INTEREST EXPENSE AND OTHER CHARGES

Interest costs net of (income) / expense

USD 000	2017	2016
Interest income from placements and deposits	(33)	(52)
Other financial costs	423	113
Total – Net (income) / expense	390	61

NOTE 6. INCOME TAX

Income tax

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	2017	2016
Income Taxes
Current income tax – continuing and discontinued operations	-	-
Deferred income tax	-	-
Tax charge / (benefit) for the period	-	-

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	2017	2016
(Loss) before taxation – continuing	(36,316)	(61,987)
Profit / (Loss) before taxation – discontinued operations	(277)	(649)
Profit / (Loss) before taxation – Total	(36,593)	(62,636)
Tax calculated at domestic tax rates applicable to profits in the respective countries	(9,754)	(17,902)
Expenses not deductible	8,197	2,244
Differences due to functional currency effects in subsidiaries	-	-
Tax effect of losses not utilised in the period	1,588	15,658
Prior year adjustment	(4)	-
Tax charge / (benefit)	27	-

Deferred tax

The analysis of deferred tax assets and deferred tax liabilities is as follows:

USD 000	2017	2016
Deferred tax assets
– to be reversed within 12 months	-	-
– to be reversed after more than 12 months	-	-
Total deferred tax assets	-	-
Deferred tax liabilities
– to be reversed within 12 months	-	-
– to be reversed after more than 12 months	-	-
Total deferred tax liabilities	-	-
Net deferred tax assets / (liabilities)	-	-

The gross movement on the deferred income tax account is as follows:

USD 000	2017	2016
As at January 1	-	-
Movement for the period	-	4,376
As at December 31	-	4,376

The movement in deferred income tax assets and liabilities, without taking into consideration the offsetting balances within the same jurisdiction, is as follows:

2017

Deferred tax assets

USD 000	Tax losses	Oil and gas assets	Provisions and others	Total
As at January 1, 2017	-	-	-	-
(Charged) / credited to the statement of comprehensive income	-	-	-	-
Classified as held for sale	-	-	-	-
As at December 31, 2017	-	-	-	-

Deferred tax liabilities

USD 000	Tangible and production assets	Exploration assets	Provisions and others	Total
As at January 1, 2017	-	-	-	-
Charged / (credited) to the statement of comprehensive income	-	-	-	-
Classified as held for sale	-	-	-	-
As at December 31, 2017	-	-	-	-

2016

Deferred tax assets

USD 000	Tax losses	Oil and gas assets	Provisions and others	Total
As at January 1, 2016	-	-	-	-
(Charged) / credited to the statement of comprehensive income	-	-	-	-
As at December 31, 2016	-	-	-	-

Deferred tax liabilities

USD 000	Tangible and production assets	Exploration assets	Provisions and others	Total
As at January 1, 2016	-	4,376	-	4,376
Charged / (credited) to the statement of comprehensive income	-	(4,376)	-	(4,376)
As at December 31, 2016	-	-	-	-

There are no recognised deferred tax assets in Group the group financial statements as of December 31, 2017.

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 14 million (2016: USD 26 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	2017	2016
Norway	46,191	88,748
UK	2,431	2,444
Cyprus	10,174	10,161
Brazil	-	-
Netherlands	3,962	8,015
Total	62,759	109,368

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.

NOTE 7. BASIC AND DILUTED EARNINGS PER SHARE

Basic earnings per share

USD 000, unless otherwise stated	2017	2016
Net loss attributable to equity holders of the parent – Total	(36,589)	(62,636)
Net loss attributable to equity holders of the parent – Continuing operations	(36,312)	(61,987)
Weighted average number of shares outstanding - in thousands	42,502	38,814
Basic and diluted earnings per share – (USD) – Total	(0.86)	(1.61)
Basic and diluted earnings per share – (USD) – Continuing operations	(0.85)	(1.60)

Diluted earnings per share

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

The share options had an anti-dilutive effect on earnings per share for both periods presented.

NOTE 8. LICENSES, EXPLORATION AND EVALUATION ASSETS, DEVELOPMENT ASSETS

2017

USD 000	Licences, exploration and evaluation assets	Development assets
Acquisition cost
At January 1, 2017	25,971	-
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	20,638	(2,558)
Accumulated impairment
At January 1, 2017	-	-
Impairment	7,042	(4,252)
At December 31, 2017	7,042	(4,252)
Net carrying value at December 31, 2017	13,596	1,694

2016

USD 000	Licences, exploration and evaluation assets	Development assets
Acquisition cost
At January 1, 2016	31,033	70,195
Additions	1,293	10,979
Transfer between Development and Licences, Exploration & Evaluation and Production Assets *	31,562	(80,163)
Transfer of Pre-Commissioning Operating Costs	-	(1,011)
At December 31, 2016	63,888	-
Accumulated impairment
At January 1, 2016	-	-
Impairment	37,917	-
At December 31, 2016	37,917	-
Net carrying value at December 31, 2016	25,971	-

* 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 has been broadly categorised between Exploration & Evaluation assets and Production Assets.

Licence area	Panoro interest	Country	Expiry of current phase
OML 113	6.502% participating interest, 12.1913% entitlement to revenue stream and 16.255% paying interest	Nigeria	June 2018
Dussafu Marin permit	8.333%	Gabon	Ten years from commencement of production *

* 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.

NOTE 9. TANGIBLE ASSETS

NOTE 9A. PRODUCTION ASSETS AND EQUIPMENT

USD 000	2017	2016
Acquisition cost
At January 1	25,285	-
Additions	12,273	1,231
Transfer from Development Assets	-	48,601
At December 31	37,558	49,832
Accumulated impairment
At January 1	-	-
Impairment charge for the year	25,828	22,413
At December 31	25,828	22,413
Accumulated depreciation
At January 1	-	-
Depreciation charge for the year	1,828	2,134
At December 31	1,828	2,134
Net carrying value at December 31	9,902	25,285

NOTE 9B. PROPERTY, FURNITURE, FIXTURES AND EQUIPMENT

2017

USD 000	Leasehold	Furniture, Fixture and Fittings	Computer Equipment	Total
Acquisition cost
At January 1, 2017	55	104	491	650
Additions	-	-	4	4
Disposals / write-downs	-	-	-	-
At December 31, 2017	55	104	494	654
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

2016

USD 000	Leasehold	Furniture, Fixture and Fittings	Computer Equipment	Total
Acquisition cost
At January 1, 2016	55	104	491	650
Additions	-	-	-	-
Disposals / write-downs	-	-	-	-
At December 31, 2016	55	104	491	650
Accumulated depreciation
At January 1, 2016	5	16	363	384
Depreciation charge for the year	10	30	57	97
Disposals / write-downs	-	-	-	-
At December 31, 2016	15	46	420	481
Net carrying value at December 31, 2016	40	58	71	169

Depreciation method and rates

Category	Straight-line depreciation	Useful life
Furniture, fixtures and fittings	10–33.33%	3 – 10 years
Computer equipment	20–33.33%	3 – 5 years

NOTE 9C. OTHER NON-CURRENT ASSETS

Other non-current assets amount to USD 0.1 million. This amount relates the tenancy deposit for the UK office premises.

NOTE 9D. IMPAIRMENT IN OIL AND GAS INTERESTS

Licenses, Exploration and Evaluation Assets, Development Assets

The Group invested in Dussafu Permit, offshore Gabon and holds an 8.333% interest in the block, following the disposal of 25% of its stake in the licence during 2017 to BW Energy Gabon Pte Limited. Furthermore, during the year a final investment decision was taken on the initial development of 2 Tortue wells, coupled with a post-period end independent reserves update, which attributed higher recoverable amounts on both 1P and 2P profiles. As a result, a partial reversal of USD 4.3 million to the previously recognised Dussafu impairment was credited to the income statement. The total carrying value for Dussafu, after taking in to account the impairment reversal is USD 9.9 million as of December 31, 2017. The analysis of the carrying value has been assessed as USD 1.7 million of accumulated costs since the start of the Dussafu development project, USD 3.9 million of exploration and evaluation costs which were capitalised prior to the impairment assessment and subsequent reversal (USD 4.3million). The costs have been attributed to exploration and evaluation activities for Dussafu to reflect the planned phased developments envisaged on the license.

Key assumptions used in the VIU calculations for Dussafu

The key assumptions used in the calculation of recoverable amount for the value in use model are:

1P reserves as certified by NSAI;
Production profiles achieved;
Average USD59/bbl oil price assumption;
Cost of development to plan;
Cost of extraction and processing; and
Discount rate of 13.5%.

Economically recoverable reserves and resources are based on NSAI and project plans based on Operator sourced information, supported by the evaluation work undertaken by appropriately qualified persons within the respective Joint Ventures. The impairment test is most sensitive to changes in commodity prices and discount rates.

Aje

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 of USD 5.4 million as of December 31, 2017 is after taking into account impairment charge of USD 7.0 million as a result of higher than anticipated expenditures on the Aje-5 workovers and sidetracks. The OML 113 carrying value included in exploration and evaluation assets in principle represents the discovered gas reserves on the license.

Production Assets and Equipment (Aje)

The Group has investments in tangible assets with USD 9.9 million of production assets and equipment in Nigeria after taking into account impairment charge of USD 25.8 million for the year ended December 31, 2017. Production assets and equipment capitalised on the balance sheet relate entirely to Aje Cenomanian oil field within OML 113 license. Management has determined the recoverable amount as of year-end through fair value less cost of sale. This approach was adopted to reasonably measure the recoverable amount after taking into account the potential divestment structures under consideration.

The overall impairment loss was USD 32.8 million for OML 113, of which USD 7 million is in relation to exploration and evaluation assets and the remainder for production assets, was triggered by changes in the operational plan following lower than expected production, accumulated costs of Aje-5 workovers and well intervention and a decline in Cenomanian oil reserves in line with the most recent preliminary independent reserves report. To establish the recoverable amount assessed to be fair value less cost of sale for the impaired asset, Panoro made use of indicative values that could potentially result in a transaction to third parties. The data of such estimate was derived from potential transaction structures. The discounted cash flow calculation and appropriate risk factors were taken into consideration when determining the fair value less cost of disposal. The primary basis for arriving at the recoverable amount estimate was the use of unobservable market inputs which is a level 3 valuation as defined in IFRS 13.

Sensitivities to change in assumptions

In general, adverse changes in key assumptions could result in recognition of impairment charges. However, recoverable amount of OML 113 is driven from fair value less cost of sale method, which is not sensitive to oil price assumptions and will only be marginally impacted by a change in discount rates. The Group will continue to test its assets for impairment where indications are identified and may in future recognise impairment charges.

			2017		2016
USD 000	Nigeria	Gabon	Corporate	Total	Nigeria		Gabon Corporate	Total
Capitalised licenses, exploration and evaluation assets	13,142	(4,252)	-	8,890	20,770	17,147	-	37,917
Production assets and equipment	19,686	-	-	19,686	22,413	-	-	22,413
Corporate items	-	-	-	-	-	-	(162)	(162)
Reversal of historic deferred tax liability	-	-	-	-	(4,373)	-	-	(4,373)
Total charge for the year ended December 31	32,828	(4,252)	-	28,576	38,810	17,147	(162)	55,795

The breakdown of the net impairment expense for continuing operations is:

NOTE 10. ACCOUNTS AND OTHER RECEIVABLES

USD 000	2017	2016
Accounts receivable	-	795
Other receivables and prepayments	615	929
At December 31	615	1,724

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

At December 31, 2017 and 2016 the allowance for impairment of receivables was USD nil.

Risk information for the receivable balances is disclosed in note [18].

NOTE 11. CASH AND BANK BALANCES

USD 000	2017	2016
Cash and bank balances	6,317	4,768
Cash and cash equivalents at December 31	6,317	4,768

As at December 31, 2017, the Company held USD 6.3 million in cash and cash equivalents (USD 4.8 million as at December 31, 2016). Following the signing of the settlement agreement on Aje, USD 1.5 million which has been held as cash collateral supporting the legal case at Aje is has been released back to the Company on completion of legal formalities post-period end.

The majority of Panoro's cash was denominated in USD and was held in a high interest account earning 0.75% interest. As at December 31, 2017 the Company held cash denominated in NOK of approximately USD 20 thousand related to the Norwegian withholding tax liability.

Overdraft facilities

The Group had no bank overdraft facilities as at December 31, 2017.

NOTE 12. DISCONTINUED OPERATIONS

Discontinued operations

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, which is entitled to the contingent earn-out from GeoPark over the next year. GeoPark has confirmed through detailed earn-out calculations that no earn-out was due to the Company for 2017.

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	2017	2016
Oil and gas revenue	-	-
Other income	-	-
Total revenues	-	-
Production costs	-	-
Exploration related costs and operator G&A	-	-
Strategic review costs	-	-
Severance and restructuring costs	-	-
General and administration costs	(71)	(103)
EBITDA	(71)	(103)
Depreciation	-	-
Impairment	(130)	(419)
Share based payments	-	-
Gain / (loss) on sale of subsidiary	-	-
EBIT – Operating income / (loss)	(201)	(522)
Interest costs net of income	-	-
Other financial costs net of income	4	13
Net foreign exchange gain / (loss)	(6)	(5)
Income / (loss) before tax	(203)	(514)
Income tax benefit / (expense)	(74)	(135)
Net income / (loss) for the period from discontinued operations	(277)	(649)
Earnings per share (basic and diluted) for the period from discontinued operations (USD)	(0.01)	(0.02)

NOTE 13 ASSET RETIREMENT OBLIGATION

In accordance with the agreements and legislation, the wellheads, production assets, pipelines and other installations may have to be dismantled and removed from oil and natural gas fields when the production ceases. The exact timing of the obligations is uncertain and depend 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 bases for the provision are a discount rate of 5.9% and an inflation rate of 1.5%. 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	2017	2016
Balance for provision at December 31,	1,925	1,856
Recognised during the year on Aje development - accretion of notional interest	114	69
At December 31	2,039	1,925

NOTE 14. SHARE CAPITAL AND RESERVES

Share capital

Amounts in USD 000 unless otherwise stated	Number of shares	Nominal Share Capital
As at January 1, 2017	42,502,196	305
Purchase of own shares	-	(6)
As at December 31, 2017	42,502,196	299

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 paid-up and carry equal voting rights

During 2017, and as part of the Company's share buyback program, the Company resolved to buy back shares, in accordance with the resolution approved by its shareholders at the Company's Annual General Meeting on 24 May 2017. Acceptances received exceeded the 1,000,000 shares limit of the Company's Offer. Following this transaction, Panoro holds a total of 1,000,000 own shares, representing 2.35% of the total issued share capital. The ongoing share buyback program may continue to be carried out in accordance with applicable laws and regulations, in open market transactions or through additional tenders, at the discretion of management based on, among other things, the Company's ongoing capital requirements and the market price of its common share.

As at December 31, 2017 and December 31, 2016, the Company had a registered share capital of NOK 2,125,109.80 divided into 42,502,196 shares with a nominal value of NOK 0.05.

The Company's twenty largest shareholders are referenced in the Parent Company Accounts, please refer to Note 9.

Shares owned by the CEO, board members and key management, directly and indirectly, at December 31, 2017:

Shareholder	Position	Number of shares	% of total
Julien Balkany (i)	Chairman of the Board of Directors	2,356,253	5.54%
Torstein Sanness	Director	35,000	0.08%
Garrett Soden (ii)	Director	10,008	0.02%
Alexandra Herger	Director	5,950	0.01%
John Hamilton	Chief Executive Officer	104,901	0.25%
Qazi Qadeer	Chief Financial Officer	41,850	0.10%
Richard Morton	Technical Director	91,214	0.21%

(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 1,725,338 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.

Reserves

Share premium

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

Other reserves

Other reserves represent items arising on consolidation of PEdB as comparatives and execution of merger.

Additional paid-in capital

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

Currency translation reserve

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

NOTE 15. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

USD 000	2017	2016
Accounts payable	141	254
Accruals and other payables	6,669	2,033
Long-term liabilities	9,089	-
At December 31	15,899	2,287

Long-term liabilities

The Company has in place a non-recourse loan from BW Energy in relation to the funding of the Dussafu development. As of December 31, 2017, Panoro's drawdown on the non-recourse loan was USD 2.2 million. The non-recourse 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. The repayment will start at First Oil on Dussafu. During the repayment phase, Panoro will still be entitled to its share of profit oil from the Dussafu operations.

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. In addition to this, commercial arrangements agreed as part of the interim settlement measures are expected to have the effect of increasing Panoro's existing revenue interest for the remainder of 2018. It is anticipated that operating costs for OML 113 will be funded in entirety from the sale of our share of Aje crude during 2018.

NOTE 16. RESTRICTED STOCK UNITS SCHEME

Restricted Stock Unit scheme ("RSUs")

At the annual general meeting held on May 27, 2015, a new employee incentive scheme was approved whereby the Company may issue restricted stock units ("RSUs") to executive employees. Awards under the new 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 2015 annual general meeting and up to the annual general meeting in 2018 shall not exceed 5% of the number of shares outstanding as per the date of the 2015 annual general meeting (at which point in time the total number of shares was 234,545,786). 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.

In June 2017, 420,000 Restricted Share Units (RSU) were awarded under the Company's RSU scheme to key employees of the Company under the long term incentive compensation 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. RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter.

During the year ended December 31, 2017, 420,000 RSUs had been granted (200,000 granted as at December 31, 2016). All of the 420,000 RSUs were outstanding as of December 31, 2017 and the awards related to permanent employees of the Company. No RSUs were vested, terminated, exercised or expired during the year. The weighted average exercise price of the RSUs granted during the year was NOK 0.05 per unit.

NOTE 17. FINANCIAL INSTRUMENTS

Fair Value

Set out below is a comparison by category of carrying amounts and fair values of all the Group's financial instruments that are carried in the financial statements:

		Carrying amount		Fair value
USD 000	Financial instrument classification	2017	2016	2017	2016	Fair value hierarchy
Financial assets
Cash and bank balances	Fair value through the P&L	6,317	4,768	6,317	4,768	Level 3
Accounts receivable	Loans and receivables	-	795	-	795	Level 3
Financial liabilities
Non-recourse loan	Other financial liabilities	2,197	-	2,197	-	Level 3
Accounts payable and accrued liabilities	Other financial liabilities	6,737	2,469	6,737	2,469	Level 3

Determination of fair value

The carrying amount of cash and bank balances is equal to fair value since no financial instruments were entered into during 2017. Similarly, the carrying amount of accounts receivables and accounts payables is equal to fair value since they are entered into on "normal" terms and conditions.

NOTE 18. FINANCIAL RISK MANAGEMENT

The Group's principal financial liabilities comprise of accounts payables. The main purpose of these financial instruments is to manage short-term cash flow and raise finance for the Group's capital expenditure program. The Group has various financial assets such as accounts receivable and cash.

It is, and has been throughout the year ending December 31, 2017 and December 31, 2016, the Group's policy that no speculative trading in derivatives shall be undertaken.

The main risks that could adversely affect the Group's financial assets, liabilities or future cash flows are interest rate risk, foreign currency risk, liquidity risk and credit risk. The management reviews and agrees policies for managing each of these risks which are summarized below.

The following discussion also includes a sensitivity analysis that is intended to illustrate the sensitivity to changes in the market variables on the Group's financial instruments and show the impact on profit or loss and shareholders' equity, where applicable. Financial instruments affected by market risk include, accounts receivables, accounts payable and accrued liabilities.

The sensitivity has been prepared for periods ending December 31, 2017 and 2016 using the amounts of debt and other financial assets and liabilities held as at those reporting dates.

Interest rate risk

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

The following table demonstrates the sensitivity 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 cash and cash equivalents.

USD 000	2017		2016
	+100bps	-100bps	+100bps	-100bps
Cash	46	(46)	26	(26)
Net effect	46	(46)	26	(26)

Foreign currency risk

The Company operates internationally and is exposed to risk arising from various currency exposures, primarily with respect to the Norwegian Kroner (NOK), the Pound Sterling (GBP) and the Brazilian Real (BRL). From a financial statements perspective, the subsidiary in Brazil has a BRL functional currency and is exposed to fluctuations for presentation purposes in these financial statements. The volatility in BRL has resulted in a translation loss of USD 3 thousand as of December 31, 2017 (2016: USD 10 thousand loss).

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 2017 or 2016.

A 20% strengthening or weakening of the USD against the following currencies at December 31, 2017 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	2017		2016
USD vs NOK	+ 20%	-20%	+ 20%	-20%
Cash	(27)	27	(20)	20
Receivables	-	-	(53)	53
Payables	19	(19)	138	(138)
Net effect	(8)	8	64	(64)
USD vs GBP	+ 20%	-20%	+ 20%	-20%
Cash	(63)	63	(23)	23
Receivables	(5)	5	(5)	5
Payables	46	(46)	54	(54)
Net effect	(22)	22	26	(26)
USD vs BRL	+ 20%	-20%	+ 20%	-20%
Cash	(25)	25	(1)	1
Receivables	(1)	1	(24)	24
Payables	61	(61)	70	(70)
Net effect	35	(35)	46	(46)

Liquidity risk

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

The table below summarises the maturity profile of the Group's financial liabilities at December 31, 2017 based on contractual undiscounted payments.

2017

USD 000	On demand	Less than 1 year	1 to 2 years	2 to 5 years	>5 years	Total
Accounts payable and accrued liabilities	-	6,810	9,089	-	-	15,899
Total	-	6,810	9,089	-	-	15,899

2016

USD 000	On demand	Less than 1 year	1 to 2 years	2 to 5 years	>5 years	Total
Accounts payable and accrued liabilities	-	2,381	88	-	-	2,469
Total	-	2,381	88	-	-	2,469

The Company had USD 6.3 million in cash and bank balances as of December 31, 2017 not including USD 1.5 million cash was set aside as security of costs in relation to the dispute at Aje. Following the completion of legal formalities, funds were released back to the Company with interest post-period-end. The Company expects it is fully funded through the development of Phase 1 at Dussafu, from cash balances, cash flow from operations, and the non-recourse loan from BWEG. Should additional funding be required in the future for additional capital expenditure for new development phases or working capital requirements, the Company has various alternatives available which it can explore to fulfil such additional requirements. The options include, amongst others, debt financing, offtake prepayment structures, and the issuance of shares. As a result, the financial statement has been prepared under the assumption of going concern and realization of assets and settlement of debt in normal operations.

Credit risk

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

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

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.

Capital Management

The primary objective of the Group's capital management is to continuously evaluate measures to strengthen its financial basis and to ensure that the Group are fully funded for its committed 2018 activities. The Group manages its capital structure and makes adjustments to it in light of changes in economic conditions. In order to maintain or change the capital structure, the Group may adjust the amount of dividend payments to shareholders, return capital to shareholders or issue new shares. The Company has no debt arrangements in place and has the flexibility to source conventional debt capital from the markets.

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

NOTE 19. GUARANTEES AND PLEDGES

Brazil

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.

UK

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, 2017 in such Companies. The Company can make an annual election to support such guarantee for each financial year.

Gabon

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

NOTE 20. OTHER COMMITMENTS AND CONTINGENT LIABILITIES

Leasing arrangements

Operating leases relate to leases of office space with lease terms between 1 to 10 years.

Non-cancellable operating lease commitments

USD 000	2017	2016
Not later than 1 year	267	243
Later than 1 year and not later than 5 years	401	608
Later than 5 years	-	-
At December 31	668	851

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, 2017. 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, 2018 is USD 1.7 million and USD 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 initial charter period is for an initial period of five years with annual subsequent renewals up to year 10. The applicable estimated rentals are subject to oil price thresholds in accordance with the Bare Boat charter agreement whereby the rentals may be higher for any given period from year to year should the oil price exceed certain pre-defined thresholds in any average monthly billing cycle. The estimated rentals disclosed on this note are based on Group's net paying interest of 16.255% in Aje Cenomanian oil development.

Uncertainties surrounding abandonment liabilities

OML 113 – Aje, Nigeria

The highlights of the Agreement included:

All OML 113 joint-venture partners have agreed to halt and withdraw all litigation and arbitration proceedings among the partners;
PPAL would not pay for any Aje-6 costs that have been incurred by the JV, until such time as the equipment and parts are to be used in any potential future well operations;
Substantial court costs already awarded to PPAL to be retained and any remaining balances credited in favour of PPAL; and
PPAL's USD 1.5 million cash security deposit held with UK Courts Funds Office would be released and returned to it. PPAL completed the formalities post-period end and funds have been returned.

Panoro remains committed to explore all options to maximise value at Aje, including, but not limited to, a partial or full divestment of its participation in OML 113.

NOTE 21. RELATED PARTIES TRANSACTIONS

The only related party transactions during the year relate to directors' remuneration which is disclosed in note 4d.

NOTE 22. SUBSIDIARIES

Details of the Group's subsidiaries as of December 31, 2017, are as follows:

Subsidiary Place of incorporation

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%
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%

NOTE 23. EVENTS SUBSEQUENT TO REPORTING DATE

The highlights of the Agreement included:

All OML 113 joint-venture partners have agreed to halt and withdraw all litigation and arbitration proceedings among the partners;
PPAL would not pay for any Aje-6 costs that have been incurred by the JV, until such time as the equipment and parts are to be used in any potential future well operations;
Substantial court costs already awarded to PPAL to be retained and any remaining balances credited in favour of PPAL; and
PPAL's USD 1.5 million cash security deposit held with UK Courts Funds Office would be released and returned to it. PPAL completed the formalities post-period end and funds have been returned.

NOTE 24. RESERVES (UNAUDITED)

The Group has adopted a policy of regional reserve reporting using external third party companies to audit its work and certify reserves and resources according to the guidelines established by the Oslo Stock Exchange ("OSE"). Reserve and contingent resource estimates comply with the definitions set by the Petroleum Resources Management System ("PRMS") issued by the Society of Petroleum Engineers ("SPE"), the American Association of Petroleum Geologists ("AAPG"), the World Petroleum Council ("WPC") and the Society of Petroleum Evaluation Engineers ("SPEE") in March 2007. Panoro uses the services of Gaffney, Cline & Associates ("GCA") 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)	12.1	20.0	30.9
Tortue (Dussafu)	1.1	1.6	1.8
Panoro Total	13.2	21.6	32.7

During 2017, the Group had the following reserve development:

	2P reserves (MMBOE)
Balance (previous ASR) as of December 31, 2016	3.1
Production 2017	(0.1)
Revision of previous estimates, as per new ASR *	(2.6)
New developments since previous ASR *	21.2
Balance (current ASR) as of December 31, 2017	21.6

* New ASR data received in April 2018.

Definitions:

1P) Proved Reserves

Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.

2P) Proved plus Probable Reserves

Probable Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.

3P) Proved plus Probable plus Possible Reserves

Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Probable Reserves.

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For the year ended December 31, 2017

USD 000	Note	2017	2016
Operating income
Operating revenues
Total operating income
Operating expenses
General and administrative expense		(1,751)	(1,249)
Intercompany recharges	8	-	-
Impairment of investments in subsidiary	2, 6	(335)	(38,873)
Loss on disposal of tangible assets		-	-
Impairment of loan to subsidiaries	7, 8	(32,885)	(28,311)
Depreciation		-	-
Total operating expenses		(34,971)	(68,433)
Operating result	2	(34,971)	(68,433)
Financial income	3	9,356	10,122
Interest and other finance expense	3	(79)	(95)
Currency gain / (loss)		16	21
Result before income taxes		(25,678)	(58,385)
Income tax	5	-	-
Result for the year		(25,678)	(58,385)
Earnings per share (basic and diluted) – USD	4	(0.60)	(1.50)

As at December 31, 2017

USD 000	Note	2017	2016
ASSETS
Non-current assets
Investment in subsidiaries	6	-	-
Intercompany receivables	7	-	-
Total non-current assets		-	-
Current assets
Loans to subsidiaries	8	29,076	57,148
Other current assets		-	277
Cash and cash equivalent		4,705	3,926
Restricted cash		1,500	520
Total current assets		35,281	61,871
TOTAL ASSETS		35,281	61,871

EQUITY AND LIABILITIES
EQUITY
Paid-in capital
Share capital	9	299	305
Share premium reserve	9	297,490	297,503
Treasury Shares		(503)	-
Additional paid-in capital	9	122,055	122,054
Total paid-in capital		419,341	419,863
Other equity
Other reserves	9	(390,079)	(364,402)
Total other equity		(390,079)	(364,402)
TOTAL EQUITY		29,262	55,461

LIABILITIES
Current liabilities
Accounts payable		13	18
Intercompany payables	8	5,744	5,722
Other current liabilities	10	262	670
Total current liabilities		6,019	6,410
TOTAL LIABILITIES		6,019	6,410
TOTAL EQUITY AND LIABILITIES		35,281	61,871

For the year ended December 31, 2017

USD 000	Note	2017	2016
CASH FLOW FROM OPERATING ACTIVITIES
Net income / (loss) for the year		(25,678)	(58,385)
Adjusted for:
Impairment of investment in subsidiary	6	335	38,528
Provision for Doubtful Receivables	7, 8	32,885	28,311
Financial Income	3	(9,356)	(10,122)
Financial Expenses	3	79	95
Foreign exchange gains / losses		(16)	(21)
(Increase) / decrease in trade and other receivables		277	(268)
Increase / (decrease) in trade and other payables		(413)	523
(Increase) / decrease in intercompany receivables		-	-
Increase / (decrease) in intercompany payables		22	5,673
Net cash flows from operating activities		(1,865)	4,334

CASH FLOWS FROM INVESTING ACTIVITIES
Net proceeds from loans to subsidiaries		12,737	-
Loans to subsidiaries		(8,573)	(14,527)
Net cash flows from investing activities		4,164	(14,527)

CASH FLOWS FROM FINANCING ACTIVITIES
Own shares buyback		(509)	-
Net proceeds from Equity Private Placement		-	8,755
Interests paid		(79)	(95)
Interests received		32	52
Movement in restricted cash		(980)	(520)
Net cash flows from financing activities		(1,536)	8,192

Effect of foreign currency translation adjustment on cash balances		16	21
Net increase in cash and cash equivalents		779	(1,980)
Cash and cash equivalents at the beginning of the year		3,926	5,906
Cash and cash equivalents at the end of financial year		4,705	3,926

NOTE 1. ACCOUNTING PRINCIPLES

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

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

NOTE 2. GENERAL AND ADMINISTRATIVE EXPENSES

Operating result

Operating result is stated after charging / (crediting):

USD 000	2017	2016
Employee benefits expense (note 2.1)	14	4
Impairment of investment in subsidiary (note 7)	335	38,873
Impairment of Intercompany Loans	32,885	28,311
Operating lease payments	-	-

2.1 Employee benefits expense

a) Salaries

The Company had zero employees at December 31, 2017 and at December 31, 2016. As such, there are no wages and salaries included in general and administrative expenses.

Employee related expenses:

USD 000	2017	2016
Salaries	-	-
Employer's contribution	14	4
Pension costs	-	-
Other compensation including severance provision	-	-
Total	14	4

For details relating to remuneration of CEO and CFO, refer to note 4c in the consolidated financial statements.

b) Directors' remuneration

Please refer to note 4d 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	2017	2016
Julien Balkany	68	66
Alexandra Herger	39	38
Garrett Soden	39	38
Torstein Sanness	39	38
Hilde Adland (i)	39	28
Total	224	208

(i) Pursuant to an Extraordinary General Meeting held on March 2, 2016, Hilde Ådland was elected to the Board of Directors with an effective date of April 1, 2016.

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 2017 and 2016.

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

c) Pensions

d) Auditor

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

USD 000	2017	2016
Ernst & Young
Statutory audit	43	45
Tax services	-	-
Total	43	45

e) Share based payment and new Restricted Share Units scheme

New Restricted Stock Unit scheme ("RSUs")

At the annual general meeting held on May 27, 2015, a new employee incentive scheme was approved where-under the Company may issue restricted stock units ("RSUs") to executive employees. Awards under the new 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 2015 annual general meeting and up to the annual general meeting in 2018 shall not exceed 5% of the number of shares outstanding as per the date of the 2015 annual general meeting (at which point in time the total number of shares was 234,545,786). 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. Vesting of the RSUs is time based. The standard vesting period is three years, where 1/3 of the RSUs vest after one year, 1/3 vest after two years, and the final 1/3 vest after three years after grant, unless the Board decides otherwise for specific grants. RSUs vest automatically at the respective vesting dates and the holder will be issued the applicable number of shares as soon as possible thereafter.

NOTE 3. FINANCIAL ITEMS

The financial expense breakdown is below:

USD 000	2017	2016
Interest income from subsidiaries	9,324	10,070
Other interest income	32	52
Total	9,356	10,122

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	2017	2016
Interest expense on bond loans	-	-
Amortisation of debt issue costs	-	-
Early redemption penalty on bond loans	-	-
Bank and other financial charges	79	95
Total	79	95

NOTE 4. EARNINGS PER SHARE

Basic earnings per share

USD 000 unless otherwise stated	2017	2016
Net result for the period	(25,678)	(58,385)
Weighted average number of shares outstanding - in thousands	42,502	38,814
Basic and diluted earnings per share – (USD)	(0.60)	(1.50)

Diluted earnings per share

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

NOTE 5. INCOME TAX

USD 000	2017	2016
Tax payable	-	-
Change in deferred tax	-	-
Income tax expense	-	-

Specification of the basis for tax payable:

USD 000	2017	2016
Result before income tax	(25,678)	(58,385)

Effect of permanent differences	33,168	67,472
Tax losses not utilised / (utilised)	(7,490)	(9,087)
Basis for tax payable	-	-

Specification of deferred tax:
USD 000	2017	2016
Losses carried forward	46,191	88,748
Taxable temporary differences	-	-
Basis for tax payable	46,191	88,748

Calculated deferred tax asset (24%)	11,086	22,187
Unrecognised deferred tax asset	(11,086)	(22,187)
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, 2016 was NOK 471.0 million (USD 57.4 million at 2017 closing exchange rate). The 2017 income for tax purposes has been provisionally calculated at NOK 62.3 million (approximately USD 7.6 million). 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.

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

NOTE 6. INVESTMENT IN SUBSIDIARIES

Investments in subsidiaries are carried at the lower of cost and fair market value. As of December 31, 2017 USD 3 (2016: USD 1) the holdings in subsidiaries consist of the following:

USD 000	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%

	PEdB	PPHCL	PPGHBV	PPNHBV	PPSHBV	Total
Investment at cost
At January 1, 2017	94,967	129,106	-	-	-	224,073
Investments during the year	335	-	-	-	-	335
At December 31, 2017	95,302	129,106	-	-	-	224,408
Provision for impairment
At January 1, 2017	(94,967)	(129,106)	-	-	-	(224,073)
Charge for the year (note 6.1)	(335)	-	-	-	-	(335)
At December 31, 2017	(95,302)	(129,106)	-	-	-	(224,408)
Total investment in subsidiaries at December 31, 2017	-	-	-	-	-	-
Total investment in subsidiaries at December 31, 2016	-	-	-	-	-	-

Note 6.1 Impairment represents loss in value of Company's investment in shares of Panoro Energy do Brasil Ltda of USD 335 thousand (2016: USD 345 thousand). The impairment has been determined by comparing estimated recoverable value of the underlying investment with the carrying amount.

Note 6.2 During 2017, and as part of the Group's overall reorganisation, the Company acquired all outstanding shares in Pan-Petroleum Nigeria Holding B.V. (PPNHBV) and Pan-Petroleum Services Holding B.V. (PPSHBV) from their indirectly wholly owned subsidiary, Pan-Petroleum Holding B.V. PPNHBV and PPSHBV are only holding companies with no significant assets or liabilities and the only item of value in these companies is their investment in shares in Pan-Petroleum Aje Limited which holds 6.502% equity interest in the Oil Mining Licence, OML 113, offshore Nigeria which contains the Aje Cenomanian oil producing field. Since the Company has a significant investment in the form of a loan which is not likely to be fully recoverable, and considering the net liability position of PPNHBV and PPSHBV, a consideration of EUR 1 was paid for their entire share capital.

NOTE 7. PROVISION FOR DOUBTFUL RECEIVABLES

Provision for doubtful receivables is USD 32.9 million (2016: USD 28.3 million). The provision is represented by the following:

Uncollectible loan principal in part of USD 32.2 million (2016: USD nil) reflecting the further impairment of the Aje Asset during 2017. Subsequently, the Company's loan to its subsidiary, Pan-Petroleum Aje Limited is now reflective of the underlying book value of the Aje Asset.
Uncollectible loan principal in part of USD 0.7 million (2016: USD 28.3 million) reflective of the underlying book value of the Dussafu Asset.

NOTE 8. RELATED PARTY TRANSACTIONS AND BALANCES

The Company's loan to the Dutch subsidiary Pan-Petroleum Gabon B.V was classified as current and amounted to USD 9.9 million as at December 31, 2017 (2016: USD 15.2 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 15.3 million as at December 31, 2017 (2016: USD 38.4 million). This loan carries an interest rate of 10% and is repayable on demand.

Payable balances on account of intercompany recharges was USD 4.4 million (2016: USD 4.1 million) to Company's indirect subsidiary Panoro Energy Limited, which provides technical services and Pan-Petroleum (Holding) Cyprus Limited was USD 1.4 million (2016: USD 1.6 million). These balances do not carry an interest rate and have no maturity date.

NOTE 9. SHAREHOLDERS' EQUITY AND SHAREHOLDER INFORMATION

Nominal share capital in the Company at December 31, 2017 and as at December 31, 2016 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 table below shows the changes in equity in the Company during 2017 and 2016:

USD 000	Share capital	Share premium reserve	Treasury shares	Additional paid-in capital	Other equity	Total
At January 1, 2016	193	288,858	-	122,055	(306,015)	105,091
Loss for the year	-	-	-	-	(58,385)	(58,385)
Share Issue for Cash	112	9,295	-	-	-	9,407
Transaction Costs on Share Issue	-	(650)	-	-	-	(650)
At December 31, 2016	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

Ownership structure

The Company had 3,729 shareholders per December 31, 2017 (2016: 4,371). The twenty largest shareholders were:

No.	Shareholder	Number of shares	Holding in %
1	STOREBRAND VEKST VERDIPAPIRFOND	2,670,082	6.28%
2	J.P. MORGAN SECURITIES LLC	2,325,444	5.47%
3	KLP AKSJENORGE	2,049,269	4.82%
4	F2 FUNDS AS	1,940,412	4.56%
5	KOMMUNAL LANDSPENSJONSKASSE	1,847,585	4.35%
6	DANSKE INVEST NORGE VEKST	1,446,479	3.40%
7	PANORO ENERGY ASA	1,000,000	2.35%
8	NORDNET BANK AB	860,060	2.02%
9	NORDNET LIVSFORSIKRING AS	760,537	1.79%
10	STORHAUGEN INVEST AS	600,000	1.41%
11	RAVI INVESTERING AS	500,000	1.18%
12	TIGERSTADEN AS	469,854	1.11%
13	HAUGESUND PSYKIATRISKE SENTER AS	450,184	1.06%
14	PREDATOR CAPITAL MANAGEMENT AS	445,000	1.05%
15	KAMPEN INVEST AS	420,550	0.99%
16	MEGARON AS	400,000	0.94%
17	LARSEN OIL & GAS AS	394,189	0.93%
18	BALLISTA AS	393,438	0.93%
19	VESLIK AS	340,448	0.80%
20	STEINAR SVOREN	326,600	0.77%
	Top 20 shareholders	19,640,131	46.21%
	Other shareholders	22,862,065	53.79%
	Total shares	42,502,196	100.00%

Shares owned by the CEO, board members and key management, directly and indirectly, at December 31, 2017:

Shareholder	Position	Number of shares	% of total
Julien Balkany (i)	Chairman of the Board of Directors	2,356,253	5.54%
Torstein Sanness	Director	35,000	0.08%
Garrett Soden (ii)	Director	10,008	0.02%
Alexandra Herger	Director	5,950	0.01%
John Hamilton	Chief Executive Officer	104,901	0.25%
Qazi Qadeer	Chief Financial Officer	41,850	0.10%
Richard Morton	Technical Director	91,214	0.21%

(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 1,725,338 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.

Shareholder distribution per December 31, 2017:

Amount of shares	# of shareholders	% of total	# of shares	Holding in %
1 - 1,000	2,605	69.86%	473,553	1.11%
1,001 - 5,000	515	13.81%	1,321,360	3.11%
5,001 - 10,000	197	5.28%	1,487,500	3.50%
10,001 - 100,000	336	9.01%	10,046,581	23.64%
100,001 - 1,000,000	70	1.88%	16,893,931	39.75%
1,000,001 +	6	0.16%	12,279,271	28.89%
Total	3,729	100.00%	42,502,196	100.00%

NOTE 10. OTHER CURRENT LIABILITIES

The breakdown of other current liabilities is below:

USD 000	2017	2016
Accruals including severance costs	239	644
Employee related costs payable (including taxes)	23	26
At December 31	262	670

NOTE 11. COMMITMENTS AND CONTINGENCIES

a) Commitments

Non-cancellable operating lease commitments

There were no non-cancellable operating lease commitments in 2017 or 2016 following the office closure in 2015.

NOTE 12. FINANCIAL MARKET RISK AND BUSINESS RISK

See details in Note 18 in the consolidated financial statements.

NOTE 13. GUARANTEES AND PLEDGES

NOTE 14. EVENTS SUBSEQUENT TO REPORTING DATE

Subsequent events can be referred to in Note 23 to the Group financial statements.

PART 1: SALARIES, BONUSES AND OTHER REMUNERATION PRINCIPLES

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 maintain 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 in 2017:

Remuneration for executive management for 2017 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 2015.

For 2017, the following was paid/incurred to the executives:

2017	Short term benefits			Long 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

Any bonuses that were incurred and paid in 2017 were approved by the Board of Directors during 2017. The bonus paid in 2017 related to the achievement of performance standards set by the Board of Directors for the financial year 2016.

Evaluation, award and payment of cash bonuses is generally performed in the year subsequent to financial year end, unless stated otherwise. Any bonuses for 2017 performance will be awarded in the year 2018 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.

Remuneration principles for 2018:

For 2018, 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 2015. Since the restricted share unit plan of 2015 will expire at the 2018 AGM, the Board of Directors has proposed that the shareholders approve a new restricted share unit plan.

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 2018. The annual bonus for 2018 performance will be awarded in the year 2019 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.

Severance payments etc:

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.

Pensions:

The Company is required to have an occupational pension scheme in accordance with the Norwegian law on required occupational pension ("Lov om obligatorisk tjenestepensjon"). The Company contributes to an external defined contribution scheme and therefore no pension liability is recognized in the statement of financial position. Since the Company no longer employs any staff in Norway, this scheme is effectively redundant.

2017 – Compliance:

In 2017, the executives received base salaries and cash incentive bonuses in line with the executive remuneration policies as presented to the 2017 Annual General Meeting.

PART 2: SHARE BASED INCENTIVES

In June 2017, 420,000 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. 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 2018 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 2017 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.

April 30, 2018 The Board of Directors Panoro Energy ASA

Julien Balkany Chairman of the Board

Garrett Soden Non-Executive Director

Torstein Sanness Non-Executive Director

Alexandra Herger Non-Executive Director

Hilde Ådland Non-Executive Director

John Hamilton Chief Executive Officer

AUDITOR'S REPORT

Panoro Energy ASA ("Panoro" 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 30, 2014 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.

1. IMPLEMENTATION AND REPORTING ON CORPORATE GOVERNANCE

The main objective for Panoro's Corporate Governance is to develop a strong, sustainable and competitive company in the best interest of the shareholders, employees and society at large, within the laws and regulations of the respective country. The Board of Directors (the Board) and management aim for a controlled and profitable development and long-term creation of growth through well-founded governance principles and risk management.

The Board will give high priority to finding the most appropriate working procedures to achieve, inter alia, the aims covered by these Corporate Governance guidelines and principles.

The Norwegian Code of Practice for Corporate Governance as of October 30, 2014 comprises 15 points. The Corporate Governance report is available on the Company's website www.panoroenergy.com.

2. BUSINESS

Panoro Energy ASA is an independent E&P company based in London and listed on the Oslo Stock Exchange. The Company holds production, exploration and development assets in West Africa, namely the Dussafu License offshore southern Gabon, and OML 113 offshore western Nigeria. In

addition to discovered hydrocarbon resources and reserves, both assets also hold significant exploration potential. Panoro Energy was formed through the merger of Norse Energy's former Brazilian business and Pan-Petroleum on June 29, 2010. The Company is listed on the Oslo Stock Exchange with ticker PEN.

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 only one reportable segment with exploration and production of oil and gas, by geographic West Africa. In West Africa, the Company participates in a number of licenses in Nigeria and Gabon.

Vision statement

Our vision is to use our experience and competence in enhancing value in projects in West Africa to the benefit of the countries we operate in and the shareholders of the Company.

3. EQUITY AND DIVIDENDS

Panoro Energy's Board of Directors will ensure that the Company at all times has an equity capital at a level appropriate to its objectives, strategy and risk profile. The oil and gas E&P business is highly capital dependent, requiring Panoro Energy to be sufficiently 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 will normally be restricted to defined purposes. 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. Mandates granted to the Board to issue new shares are normally limited in time to the following year's Annual General Meeting. Any decision to deviate from the principle of equal treatment by waiving the preemption 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.

4. EQUAL TREATMENT OF SHAREHOLDERS AND TRANSACTIONS WITH CLOSE ASSOCIATES

Panoro Energy has one class of shares representing one vote at the Annual General Meeting. The Articles of Association contains no restriction regarding the right to vote.

All Board members, employees of the Company and close associates must internally clear potential transactions in the Company's shares or other financial instruments related to the Company prior to any transaction. All transactions between the Company and shareholders, shareholder's parent company, members of the Board of Directors, executive personnel or close associates of any such parties, are governed by the Code 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.

5. FREELY NEGOTIABLE SHARES

The Panoro Energy ASA shares are listed on the Oslo Stock Exchange. There are no restrictions on negotiability in Panoro Energy's Articles of Association.

6. GENERAL MEETINGS

Panoro Energy's Annual General Meeting will 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.

7. NOMINATION COMMITTEE

The Company shall have a Nomination Committee consisting of 2 to 3 members to be elected by the Annual General Meeting for a two year period. The Annual General Meeting elects the members and the Chairperson of the Nomination Committee and determines the committee's remuneration. The Company will provide information on the member of the Nomination Committee on its website. The Company will further give notice on its website, in good time, of any deadlines for submitting proposals for candidates for election to the Board of Directors and the Nomination Committee.

The Company aims at selecting the members of the Nomination Committee taking into account the interests of shareholders in general. The majority of the Nomination Committee shall as a rule be independent of the Board and the executive management. The Nomination Committee currently consists of three members, 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 Annual General Meeting may stipulate guidelines for the duties of the Nomination Committee.

8. CORPORATE ASSEMBLY AND BOARD OF DIRECTORS – COMPOSITION AND INDEPENDENCE

The composition of the Board ensures that the Board represents the common interests of all shareholders and meets the Company's need for expertise, capacity and diversity. The members of the Board represent a wide range of experience including shipping, offshore, energy, banking and investment. The composition of the Board ensures that it can operate independently of any special interests. Members of the Board are elected for a period of two years. Recruitment of members of the Board may be phased so that the entire Board is not replaced at the same time. The 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.

9. THE WORK OF THE BOARD OF DIRECTORS

The Board has the overall responsibility for the management and supervision of the activities in general. The Board decides the strategy of the Company and has the final say in new projects and/or investments. The Board's instructions for its own work as well as for the executive management have particular emphasis on clear internal allocation of responsibilities and duties. The Chairman of the Board ensures that the Board's duties are undertaken in efficient and correct manner. The Board shall stay informed of the Company's financial position and ensure adequate control of activities, accounts and asset management. The Board member's experience and skills are crucial to the Company both from a financial as well as an operational perspective. The Board 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.

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.

10. RISK MANAGEMENT AND INTERNAL CONTROL

Financial and internal control, as well as short- and long term strategic planning and business development, all according to Panoro Energy's business idea and vision and applicable laws and regulations, are the Board's responsibilities and the essence of its work. This 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.

11. REMUNERATION OF THE BOARD OF DIRECTORS

The remuneration to the Board will be decided by the Annual General Meeting each year.

Panoro Energy is a diversified company, and the remuneration will reflect the Board's responsibility, expertise, the complexity and scope of work as well as time commitment.

The remuneration to the Board is not linked to the Company's performance, and share options will normally not be granted to Board members. 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.

12. REMUNERATION OF THE EXECUTIVE PERSONNEL

The Board has established guidelines for the remuneration of the executive personnel. The guidelines set out the main principles applied in determining the salary and other remuneration of the executive personnel. The guidelines ensure convergence of the financial interests of the executive personnel and the shareholders.

Panoro Energy has appointed a Remuneration Committee (RC) which meets regularly. The objective of the committee is to determine the compensation structure and remuneration level of the Company's CEO. Remuneration to the CEO shall be at market terms and decided by the Board and made official at the AGM every year. Remuneration to other key executives shall be proposed by the CEO to the RC.

The remuneration shall, both with respect to the chosen kind of remuneration and the amount, encourage addition of values to the Company and contribute to the Company's common interests – both for management as well as the owners.

Detailed information about options and remuneration for executive personnel and Board members is provided in the Annual Report pursuant to and in accordance with section 6-16a of the Norwegian Public Limited Companies Act. The guidelines are normally presented to the Annual General Meeting also as a separate attachment to the Annual General Meeting notice.

13. INFORMATION AND COMMUNICATION

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.

14. TAKEOVERS

Panoro Energy has established the following guiding principles for how the Board of Directors will act in the event of a take-over 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.

15. AUDITOR

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.

REPORTING OF PAYMENTS TO GOVERNMENTS

This report is prepared in accordance with the Norwegian Accounting Act § 3-3d. 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 with regard to definitions, publication and group reporting.

This report contains information for the activity in the whole fiscal year 2017 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.

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 2017 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. Aje oil production continued through 2017 and the Group continues to receive revenues for its interest in OML 113. There are customary royalty and taxes due on oil production in Nigeria and as of December 31, 2017 the Group had no tax liability and USD 112 thousand of net production royalty was paid indirectly to the government authorities in Nigeria. The royalty payments were withheld at source from the cargo proceeds by the Operator. As a result, the Company or its subsidiaries have not made any direct payments in relation to the nonoperated assets to the respective governments of Gabon and Nigeria.

1. ABOUT PANORO

Panoro Energy ASA is an international independent E&P company listed on Oslo Stock Exchange with ticker PEN with a primary office in London. The company is focused on its high quality production and development assets in West Africa, namely the Dussafu License offshore southern Gabon, and OML113 offshore western Nigeria. In addition to discovered hydrocarbon resources and reserves, both assets also hold significant exploration potential.

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.

2. MESSAGE FROM THE CEO

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").

3. FRAMEWORK AND SCOPE OF THE ETHICAL CODE OF CONDUCT OF PANORO

3.1 Panoro as a company, as well as its individual employees, will commit to follow this ECOC.
3.2 Equally, we will work through our stakeholders and partners to ensure that we adhere to the values expressed in the ECOC.
3.3 Finally, the ECOC is based on the ten principles expressed in the UN Global Compact.

4. THE UN GLOBAL COMPACT PRINCIPLES

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 Universal Declaration of Human Rights
The International Labour Organization's Declaration on Fundamental Principles and Rights at Work
The Rio Declaration on Environment and Development
The United Nations Convention Against Corruption

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:

Human Rights

Principle 1: Businesses should support and respect the protection of internationally proclaimed human rights; and
Principle 2: make sure that they are not complicit in human rights abuses

Labour

Principle 3: Businesses should uphold the freedom of association and the effective recognition of the right to collective bargaining;
Principle 4: the elimination of all forms of forced and compulsory labour;
Principle 5: the effective abolition of child labour; and
Principle 6: the elimination of discrimination in respect of employment and occupation

Environment

Principle 7: Businesses should support a precautionary approach to environmental challenges;
Principle 8: undertake initiatives to promote greater environmental responsibility; and
Principle 9: encourage the development and diffusion of environmentally friendly technologies

Anti-Corruption

Principle 10: Businesses should work against corruption in all its forms, including extortion and bribery

5. HOST COUNTRIES AND LOCAL COMMUNITIES

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:

observe local laws and rules
respect the sovereignty of the state
observe and, through our example and that of our stakeholders, promote the rule of law
encourage the employment of local staff
engage in capacity building, through the transfer of skills and technologies
work with local communities by contributing to improve their health, education and welfare
respect indigenous people and their traditions
minimize disturbances that may be caused by our operations
be mindful of the impact of our security arrangements on local communities
refrain from any involvement in tribal or internal armed conflicts or acts of violence

6. STAKEHOLDERS

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.

Stakeholder	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 sections 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 practice.
Local community	The communities in which the 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 set up within its operational structure. Panoro will seek to use these to address issues of interest based on the ECOC, including corruption, HS&Q and any other issues listed above.

GLOSSARY AND DEFINITIONS

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

CONVERSION FACTORS

Natural gas and LNG	To billion cubic metres NG	Billion cubic feet NG	Million tonnes oil equivalent	Million tonnes LNG	Trillion British thermal units	Million barrels oil equivalent
From			Multiply by
1 billion cubic metres NG	1.00	35.30	0.90	0.73	36.00	6.29
1 billion cubic feet NG	0.028	1.00	0.026	0.021	1.03	0.18
1 million tonnes oil equivalent	1.111	39.20	1.00	0.805	40.40	7.33
1 million tonnes LNG	1.38	48.70	1.23	1.00	52.00	8.68
1 trillion British thermal units	0.028	0.98	0.025	0.02	1.00	0.17
1 million barrels oil equivalent	0.16	5.61	0.14	0.12	5.80	1.00

COMPANY ADDRESSES

Panoro Energy ASA c/o Michelet & Co Advokatfirma AS Grundingen 3, 0250 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

AI Terminal

Panoro Energy ASA

3706_10-k_2018-04-30_7003e849-1ab6-4551-9e69-27f87d91f8dc.pdf

Panoro Energy

COMPANY OVERVIEW

CONTENTS

FINANCIAL CALENDAR

COMPANY OVERVIEW

2017 HIGHLIGHTS AND SUBSEQUENT EVENTS

SHARE PRICE DEVELOPMENT

ASSETS

GABON

NIGERIA

PANORO OFFICES

PANORO OFFICES

John Hamilton

COMPANY OPERATIONS

GABON

Dussafu Marin Permit (8.333% interest).

NIGERIA

OML 113 Aje field (6.502% participating interest, 12.1913% revenue interest and 16.255% paying interest).

BRAZIL

Operations in Brazil

INTRODUCTION

DISCLAIMER

PANORO ASSETS PORTFOLIO

Dussafu: offshore Gabon, operator BW Energy, Panoro 8.333%.

OML 113 Aje: offshore Nigeria, operator Yinka Folawiyo Petroleum (YFP), Panoro 12.1913%.

MANAGEMENT DISCUSSION AND ANALYSIS

ASSUMPTIONS

2017 – 2P DEVELOPMENT (MMBOE)

OPERATIONS

Operations in Gabon

Operations in Nigeria

Operations in Brazil

THE ACCOUNTS

FINANCIAL PERFORMANCE AND ACTIVITIES

Condensed Consolidated Income Statement

Income statement

Statement of financial position

Cash flows

ALLOCATION OF PROFITS AND LOSSES

Parent company financial information

FUNDING

RISK FACTORS

Operational risk factors

Financial risk factors

ORGANISATION AND HEALTH, SAFETY AND ENVIRONMENT (HSE)

CORPORATE GOVERNANCE

DISCRIMINATION AND EQUAL EMPLOYMENT OPPORTUNITIES

DIRECTORS AND SHAREHOLDERS

REPORTING OF PAYMENT TO GOVERNMENTS

OUTLOOK

BOARD OF DIRECTORS

JULIEN BALKANY

ALEXANDRA HERGER

GARRETT SODEN

HILDE ÅDLAND

Non-Executive Director

TORSTEIN SANNESS

SENIOR MANAGEMENT

JOHN HAMILTON

QAZI QADEER

RICHARD MORTON

For the year ended December 31, 2017

NOTE 1. CORPORATE INFORMATION

NOTE 2. BASIS OF PREPARATION

NOTE 2.1 BASIS OF CONSOLIDATION

NOTE 2.2 SIGNIFICANT ACCOUNTING JUDGMENTS, ESTIMATES AND ASSUMPTIONS

a. Estimates and assumptions

Hydrocarbon reserve and resource estimates

Exploration and evaluation expenditures

Income taxes

b. Judgments

Dispute and litigation

The highlights of the Agreement included:

Impairment indicators

Technical risk in development of oil and gas fields

Asset retirement obligations

Contingencies