Panoro Energy

ANNUAL REPORT 2016

COMPANY OVERVIEW

Company overview	03
Assets	04
CEO letter	06
Company Operations	07
Annual Statement of Reserves 09
Directors' Report 2016	13
Board of Directors	19
Senior Management	21
Consolidated Statement of Comprehensive Income	22
Notes to the Consolidated Financial Statements	26
Panoro Energy ASA Parent Company Income Statement	54
Panoro Energy ASA Notes to the Financial Statements	57
Executive Remuneration Policies	64
Auditor's Report	67
Statement on Corporate Governance in Panoro Energy ASA	71
Corporate Social Responsibility 75 Ethical Code of Conduct

FINANCIAL CALENDAR:

MAY 24, 2017 FIRST QUARTER 2017 RESULTS AND ANNUAL GENERAL MEETING

Glossary and Definitions 77

AUGUST 24, 2017 SECOND QUARTER 2017 RESULTS

NOVEMBER 16, 2017 THIRD QUARTER 2017 RESULTS Panoro Energy ASA is an independent E&P company based in London and listed on the Oslo Stock Exchange with ticker PEN. The Company holds production, development, and exploration assets in West Africa, namely OML 113 offshore western Nigeria and the Dussafu License offshore southern Gabon. In addition to discovered hydrocarbon resources and reserves, both assets also hold significant exploration potential.

C O M PA N Y O V E RV I E W

KEY FIGURES	2016

EBITDA (USD million)	(3.8)
EBIT (USD million)	(61.9)
Net profit/(loss) (USD million)	(62.6)
2P Reserves (MMBOE)	3.1
2C Contingent Resources (MMBOE)	35.5
Share price December 31, 2016 (NOK)	6.41

The completion of the BWO transaction will result in a reduction in Panoro's net entitlement 2C contingent resources at Dussafu.

2016 HIGHLIGHTS

First oil production at Aje, offshore Nigeria commenced in May 2016
Completion of first two cargo liftings at Aje
Post year-end, Sale completed with BW Energy Gabon Pte. Ltd for the divestment of 25% working interest in Dussafu and consideration of USD 11 million received in cash
Equity Private Placement and Subsequent Offering in February 2016 and April 2016 respectively, the company successfully raised NOK 80 million (USD 9.3 million)

Reference: OSLEPX - Oslo Bors Energy Exploration & Production Index

GABON

• 33.333% interest in Dussafu Marin permit, offshore*

* Panoro's interest reduced to 8.333% 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.

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Dear Fellow Shareholders:

Events during 2016 have realised two of Panoro's prioritised ambitions. First oil production at Aje in Nigeria was a milestone for Panoro and for other project stakeholders. And, with the December 2016 announcement of a Memorandum of Understanding (subsequently formalised into a completed sale) with a BW Offshore subsidiary, the Dussafu project is now moving tangibly forward following 3 years of reduced activity due to the depressed state of the oil industry. Panoro is now a full cycle E&P company, and can look forward to Dussafu production in 2018.

In Nigeria, at the Aje Cenomanian oil development offshore Lagos on OML 113, operations advanced materially during course of the year, culminating in the Aje 4 and Aje 5 wells being brought on stream in May 2016. The Aje field is the first oil production in Nigeria from the emerging Dahomey Basin at the border with Benin, and the first in the State of Lagos. The importance of OML 113 is further underlined by the significant gas resource in the Turonian which has the potential to become a major gas supplier to the city of Lagos and adjacent markets. While production at Aje was subdued due to mechanical issues on the FPSO and issues on the Aje 5 well, the importance of first oil production remains significant following the discovery of the field some 20 years ago.

Phase 2 of the Aje Cenomanian oil development provides potential for additional production and reserves on the block, although Panoro is currently in disagreement with its partners as to the timing of Phase 2 activity. The resolution of the dispute is expected to take several more months, as the arbitration panel considers the merits of Panoro's case. Concurrently Panoro is seeking commercial resolution of the dispute.

In Gabon, post-period, Panoro announced that its fully-owned subsidiary, Pan-Petroleum Gabon B.V. entered into a definitive Sale and Purchase Agreement with BW Energy Gabon Pte. Ltd., a subsidiary of BW Offshore Limited (OSE ticker: BWO), the leading global provider of floating production services to the oil and gas industry. Under the terms of the agreement, Panoro sold a 25% working interest in the Dussafu Production Sharing Contract in Gabon for a total cash consideration of USD 12.0 million. On completion of the transaction with BW Energy on April 28, 2017, Panoro has received USD 11 million plus some working capital adjustments. The remaining USD 1.0 million will be paid in cash no later than December 30, 2017. Panoro will also receive a nonrecourse loan from BW Energy of up to USD 12.5 million at 7.5% annual interest rate in order to fund all expenditures through to first oil production at Dussafu. Post-completion, Panoro will retain an 8.33% working interest in Dussafu. The total gross capital expenditure to reach first oil in 2018 is estimated to be a maximum of USD 150 million. In the meantime, we are engaging with BW Energy to move the project forward with purchase of long lead equipment for the development. We expect to achieve first oil at Dussafu in 2018.

During the year, Panoro has continued its focus on cost reduction. General and Administrative costs have decreased 16% year on year, in addition to the 10% drop achieved in 2015.

The Brazilian operations and overhead are now largely unwound, with only remedial abandonment and administrative costs being incurred. Panoro has a total current staff of five employees. These necessary measures have been part of Panoro's continued efforts to rigorously reduce overhead costs. Panoro is also satisfied that the court case brought against it by Euro Latin Capital has been resolved, with the Oslo Appeals Court finding in favour of Panoro and awarding costs.

With the cash generated from the sale of 25% interest in Dussafu to BW Energy, Panoro is very well positioned to take advantage of growth opportunities. Panoro will use its best endeavours to pursue acquisitions of reserves and production in order to establish a material core position in West Africa. The aim is to establish a value-creating growth platform with production, development and low cost exploration upside. New opportunities are being identified as good quality producing assets become available due to distress, portfolio rationalization, and consolidation within the market.

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

John Hamilton

CEO, Panoro Energy ASA

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

GABON

Dussafu Marin Permit (33.333% 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 an Exploration, Development and Exploitation license with multiple discoveries and prospects 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 wells of which both encountered hydrocarbons; Ruche (2011) and Tortue (2013). The economic gross 2C resources in Dussafu to date are around 33.4 MMbbls of oil distributed between the Ruche, Tortue, Moubenga and Walt Whitman fields.

A detailed plan for development of the four discovered fields as a cluster has been approved by the Gabonese government and an Exclusive Exploitation Authorisation ("Ruche Area EEA") was awarded in 2014. The area awarded under the Ruche Area EEA covers 850.5 km2 and includes all four fields and numerous undrilled structures that could be economically and expeditiously developed through the Ruche area development infrastructure. The Ruche Area 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.

In early 2017 Panoro announced that its fully-owned subsidiary, Pan-Petroleum Gabon B.V. entered into a definitive Sale and Purchase Agreement (the "SPA") with BW Energy Gabon Pte. Ltd. ("BWEG"), a subsidiary of BW Offshore Limited (OSE ticker: BWO), the leading global provider of floating production services to the oil and gas industry. Under the terms of the SPA, Panoro has sold a 25% working interest in the Dussafu Production Sharing Contract in Gabon to BWEG for a total cash consideration of USD 12.0 million. At closing of the transaction, Panoro received USD 11 million in cash plus some working capital adjustments. The remaining USD 1.0 million will be paid in cash no later than December 30, 2017. Panoro will also receive a nonrecourse loan from BWEG of up to USD 12.5 million at 7.5% annual interest rate in order to fund all expenditures through to first oil production at Dussafu. Post-completion, Panoro will retain an 8.33% working interest in the Dussafu PSC. The total gross capital expenditure to reach first oil in 2018 is estimated to be a maximum of USD 150 million.

In the meantime, Panoro are engaging with BWO to move the project forward with purchase of long lead equipment for the development. We expect to achieve first oil at Dussafu in 2018.

2C Contingent Resources net to Panoro related to the Dussafu license stood at 6.8 MMbbls per year-end 2016.

NIGERIA

OML 113 Aje field (6.502% participating interest, 12.19% 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 Cenomanian oil reservoirs. The OML 113 license has full 3D seismic coverage from surveys acquired in 1997 and 2014.

Production at Aje is underway with first oil achieved at the field in May 2016. Aje currently has 2 wells, Aje-4 and Aje-5, which were completed in 2015. Oil is processed, stored and exported at the Front Puffin FPSO via a subsea production system. This comprises the first phase of the Aje Cenomanian oil field development project. This phase is a two well development targeting the Cenomanian reservoirs as detailed in an approved 2014 Aje Field Development Plan (FDP). An AGR TRACS International ("TRACS") Competent Persons' Report of July 2014 certified 2P reserves of 23.4 million barrels of oil for the Phase 1 development. During 2016 the Aje field produced a total of around 110,000 barrels net to Panoro at an average rate of approximately 500 bopd net.

Phase 2 of the Aje development would consist of two further wells in the Cenomanian, Aje-6 and Aje-7. TRACS CPR has certified a 2P and 2C resource of 39.1 million barrels of oil for phase 1 and 2 combined. Phase 3 of the Aje development will entail the commercialisation of the large Turonian gas and associated liquids resource. This development is being conceptualised, with evacuation from a dedicated offshore or onshore facility with extraction of condensate and LPGs and gas sold into the West Africa Gas Pipeline or the Nigerian domestic market. Phase 3 is likely to involve three or four additional wells, with the objective to produce over 500 bcf of gas, 22 MMbbls of condensate and 40 MMbbls of LPG.

At year-end 2016 2P Reserves net to Panoro's interest related to OML 113 stood at 3.1 MMbbls and 2C Contingent Resources stood at 28.7 MMbbls.

BRAZIL

Operations in Brazil

Abandonment and relinquishment activities continued during 2016 for the BS-3 concessions. Cavalo Marinho reporting is finished and awaits final approval from the regulatory authorities which is expected sometime in 2017. Coral has some minor works on-going (at no cost to Panoro) and final relinquishment is now expected to be approved by the end of 2017. Only limited expenditure is expected for these activities during the course of 2017, since the activities are now only reporting and administrative in essence.

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:

In production
Under development
With development committed

Reserves are also classified according to the associated risks and probability that the reserves will be actually produced.

1P – Proven reserves represent volumes that will be recovered with 90% probability

2P – Proven + Probable represent volumes that will be recovered with 50% probability

3P – Proven + 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 Gaffney Cline and Associates in March 2014 for Dussafu and by AGR TRACS International in July 2014 for Aje. Production, well and seismic data acquired since those dates have not been taken into account in these estimates

PANORO ASSETS PORTFOLIO

As of year-end 2016, Panoro had one asset with reserves, OML 113 and two assets with contingent resources, OML 113 and Dussafu. A summary description of these assets with status as of year-end 2016 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 Harvest Natural Resources, Panoro 33.33%

Dussafu is an exploration, development and exploitation license covering an area containing several small oil fields, the most recent discoveries being the Ruche and Tortue fields.

In March 2014 GCA certified (3rd party) potentially recoverable gross 2C contingent Resources of 33.4 MMbbls, based on a commercial evaluation of a development scenario. This evaluation yields 2C potentially recoverable resources net to Panoro of 6.8 MMbbls of oil. These 2C Contingent Resources of 6.8 MMbbls are Panoro's net entitlement fraction of the Gross Field Resources under the terms of the PSC that governs the asset.

A Declaration of Commerciality of the discovered resources was made with the government of Gabon and an Exclusive Exploitation Authorization (EEA) for an 850.5 km2 area within the Dussafu PSC area was subsequently awarded in July 2014. A Field Development Plan (FDP) for the EEA area was approved by the Gabonese Government in October 2014. The FDP describes the development of all the discovered resources in the EEA area consisting of Ruche A (formerly Ruche), Ruche B (formerly Tortue), Ruche C (formerly Moubenga) and Ruche D (formerly Walt Whitman). The FDP concept is based on a centrally located Floating Production Storage and Offloading vessel (FPSO) with sub-sea wells tied back from each of these discoveries.

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 but also contains a separate Cenomanian age oil leg which has been on production since May 2016.

In July 2014 AGR TRACS certified (3rd party) gross 1P Proven Reserves of 11.7 MMbbls in the Cenomanian age oil reservoir of the Aje field. Gross 2P Proven and Probable reserves in the same reservoir amounted to 23.4 MMbbls. Panoro's net entitlement 1P Proven Reserves was 1.8 MMbbls and net entitlement 2P Proven and Probable Reserves was 3.2 MMbbs.

Production during 2016 from the Aje field amounted to 0.9 MMbbls gross and 0.1 MMbbls net to Panoro.

After accounting for this production Gross 1P reserves at Aje amount to 10.8 MMbbls of which Panoro's net entitlement is 1.7 MMbbls. Gross 2P reserves at Aje amount to 22.5 MMbbls of which Panoro's net entitlement is 3.1 MMbbls.

In addition to these reserves AGR TRACS also certified gross 1C Contingent Resources (in both the Cenomanian and Turonian age reservoirs) of 119.5 MMboe and 2C Contingent Resources of 179 MMboe. Panoro's net entitlement 1C Contingent Resources is 19.4 MMboe and net entitlement 2C Contingent Resources is 28.7 MMboe.

A Field Development Plan (FDP) for Aje was approved by the Nigerian Government in March 2014. The FDP comprised two production wells tied back to an FPSO and these wells produce from the Cenomanian age oil reservoir to access the gross 2P reserves. A final investment decision for the first phase was made by the OML 113 Joint Venture partners in October 2014 and first oil was achieved at Aje in May 2016. The second phase will comprise two additional production wells to access the remaining Cenomanian age gross 2C Contingent Resources of 15.7 MMbbls.

MANAGEMENT DISCUSSION AND ANALYSIS

Panoro uses the services of Gaffney, Cline & Associates (GCA) and AGR TRACS for 3rd party verifications of its reserves and resources.

All evaluations are based on standard industry practice and methodology for production decline analysis and reservoir 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 2016 ASR:

Dussafu: In early 2017 Panoro and Harvest announced transactions with BW Energy under which BW Energy has assumed Harvest's entire stake in Dussafu and is now operator of the license and also purchased a portion of Panoro's stake. The intent of BW Energy is to develop the Contingent Resources in the Ruche EEA Area. During 2017, we expect a Final Investment Decision to be taken in the Dussafu project, and the consequent reclassification of the Dussafu Contingent Resources to Reserves.

Aje: The first phase of the Aje Cenomanian age oil development started in 2016 with production from two wells. Conversion of Cenomanian resources to reserves could be achieved by phase 2 drilling. In the meantime we expect concept work on the large Turonian age resource to progress in 2017.

ASSUMPTIONS:

2015 – 2P DEVELOPMENT (MMBOE)

The commerciality and economic tests for the Aje reserves volumes were based on an oil price of US\$80/Bbl.

2P Reserves Development	(MMBOE)
Balance (previous ASR –December 31, 2015)	3.2
Production 2016	(0.1)
Acquisitions/disposals since previous ASR	0.0
New Developments since previous ASR	0.0
Balance (revised ASR) as of December 31, 2016	3.1

This reflects the July 2014 reserve report for the Aje field, conducted by AGR TRACS and production during 2016.

Panoro's 2P reserves amount to 3.1 MMBOE. Panoro's Contingent Resource base includes discoveries of varying degrees of maturity towards development decisions. By end of 2016, Panoro's assets contain a total 2C volume of 35.5 MMBOE.

John Hamilton

CEO April 28, 2017

RESERVES STATEMENT AS OF DECEMBER 31,2016

ANNUAL STATEMENT OF RESERVES
Developed Assets
As of Dec. 31, 2016	1P/P90			2P/P50
Panoro Energy	Liquids MMbbl	Gas Bcf	Total MMBOE	Interest%	Net MMBOE	Liquids MMbbl	Gas Bcf	Total MMBOE	Interest %	Net MMBOE
Aje Field	10.8	0.0	10.8	12.1913%	1.7	22.5	0.0	22.5	12.1913%	3.1
Total	10.8	0	10.8	-	1.7	22.5	0	22.5	-	3.1

Under Development Assets
As of Dec. 31, 2016	1P/P90 2P/P50
Panoro Energy	Liquids MMbbl	Gas Bcf	Total MMBOE	Interest%	Net MMBOE	Liquids MMbbl	Gas Bcf	Total MMBOE	Interest %	Net MMBOE

Total	0	0	0	-	0	0	0	0	-	0

Non-Development Assets
As of Dec. 31, 2016			1P/P90					2P/P50
Panoro Energy	Liquids MMbbl	Gas Bcf	Total MMBOE	Interest%	Net MMBOE	Liquids MMbbl	Gas Bcf	Total MMBOE	Interest %	Net MMBOE

Total	0	0	0	-	0	0	0	0	-	0

					Totals
			1P/P90					2P/P50
Total Assets	10.8	0	10.8	-	1.7	22.5	0	22.5	-	3.1

RESERVES DEVELOPMENT:

2P Reserves Development	(MMBOE)
Balance (previous ASR – December 31, 2015)	3.2
Production 2016	(0.1)
Acquisitions/disposals since previous ASR	0.0
Extensions and discoveries since previous ASR	0.0
New developments since previous ASR	0.0
Revisions of previous estimates	0.0
Balance (revised ASR) as of December 31, 2016	3.1

The completion of the BW Energy transaction will result in a reduction in Panoro's net entitlement 2C contingent resources at Dussafu.

CONTINGENT RESOURCES SUMMARY:

Asset	2C MMBOE (as of Year 2015)	2C MMBOE* (as of this report)
Aje	28.7	28.7
Dussafu	6.8	6.8
Totals	35.5	35.5

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OPERATIONS

Operations in Gabon

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 an Explortaion, Development and Exploitation license with multiple discoveries and prospects lying within a proven oil and gas play fairway within the Southern Gabon Basin. Dussafu is operated by Harvest Natural Resources and Panoro's current interest in the license is 33.33%. Most of the block lies in less than 200 m of water and has been explored since the 1970s. To the north west of the block is the Etame-Ebouri trend, a collection of fields producing from the pre-salt Gamba and Dentale sandstones, and to the north are the Lucina and M'Bya fields which produce from the syn-rift Lucina sandstones beneath the Gamba.

In early 2017 Panoro announced that its fully-owned subsidiary, Pan-Petroleum Gabon B.V. entered into a definitive Sale and Purchase Agreement (the "SPA") with BW Energy Gabon Pte. Ltd. ("BWEG"), a subsidiary of BW Offshore Limited (OSE ticker: BWO), the leading global provider of floating production services to the oil and gas industry. Under the terms of the SPA, Panoro has sold a 25% working interest in the Dussafu Production Sharing Contract in Gabon to BWEG for a total cash consideration of USD 12.0 million. At closing of the transaction, Panoro has received USD 11 million in cash plus some working capital adjustments. The remaining USD 1.0 million will be paid in cash no later than December 30, 2017. Panoro will also receive a non-recourse loan from BWEG of up to USD 12.5 million at 7.5% annual interest rate in order to fund all expenditures through to first oil production at Dussafu. Post-completion, Panoro will retain an 8.33% working interest in the Dussafu PSC. The total gross capital expenditure to reach first oil in 2018 is estimated to be a maximum of USD 150 million.

In the meantime, Panoro are engaging with BWO to move the project forward with purchase of long lead equipment for the development. We expect to achieve first oil at Dussafu in 2018.

2C Contingent Resources net to Panoro related to the Dussafu license stood at 6.8 MMbbls per year-end 2016.

Operations in Nigeria

Covering an area of 840 km2 OML 113 is operated by Yinka Fo-

lawiyo 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 Cenomanian oil reservoirs. The OML 113 license has full 3D seismic coverage from surveys acquired in 1997 and 2014.

Phase 2 of the Aje development would consist of two further wells in the Cenomanian, Aje-6 and Aje-7, to bring the total production up to over 50 million barrels of oil. TRACS CPR has certified a 2P and 2C resource of 39.1 million barrels of oil for phase 1 and 2 combined. Phase 3 of the Aje development will entail the commercialisation of the large Turonian gas and associated liquids resource. This development is being conceptualised, with evacuation from a dedicated offshore or onshore facility with extraction of condensate and LPGs and gas sold into the West Africa Gas Pipeline or the Nigerian domestic market. Phase 3 is likely to involve three or four additional wells, with the objective to produce over 500 bcf of gas, 22 MMbbls of condensate and 40 MMbbls of LPG.

At year-end 2016 2P Reserves net to Panoro's interest related to OML 113 stood at 3.1 MMbbls and 2C Contingent Resources stood at 28.7 MMbbls.

Operations in Brazil

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. However, there are uncertainties related to this assessment.

The Company had USD 5.3 million in cash and bank balances as of December 31, 2016 of which USD 0.5 million cash was set aside as security of costs in relation to the ongoing dispute on OML 113; this was increased to USD 1.5 million post year-end. Subsequent to year end the Company has received USD 11 million plus some working capital adjustments at the 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 to fund cash requirements up to December 31, 2017 from cash in hand and cash flow from operations. If additional funding is required due to unforeseen circumstances, the Company may need to seek additional debt or equity financing and cannot be certain that such financing will available, when needed, on reasonable terms. 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.

The below analysis compares 2016 with 2015 figures:

FINANCIAL PERFORMANCE AND ACTIVITIES

Condensed Consolidated Income Statement
-----------------------------------------	--

USD 000	2016	2015

Continuing operations
Oil and gas revenue	5,461	-
Total revenues	5,461	-

Expenses

Operating costs	(4,558)	-
Exploration related costs and operator G&A	(660)	(1,877)
Severance and restructuring costs	-	(38)
General and administrative costs	(4,063)	(4,823)
Total operating expenses	(9,281)	(6,738)

EBITDA	(3,820)	(6,738)

Depreciation	(2,231)	(90)
Asset write-off and impairment	(55,795)	(32,445)
Share based payments	(47)	-

EBIT	(61,893)	(39,273)
Net financial items	(94)	34

Loss before taxes	(61,987)	(39,239)
Income tax benefit / (expense)	-	(46)

Net loss from continuing operations	(61,987)	(39,285)

Net income / (loss) from discontinued operations	(649)	(582)

Net income / (loss) for the period	(62,636)	(39,867)

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 3.8 million for the year ended December 31, 2016, compared to negative USD 6.7 million in the same period in 2015.

EBITDA includes the oil and gas revenue from the first two liftings from the Aje field and the associated operating costs. In addition to the inclusion of Aje's liftings, an overall decline in G&A and exploration related costs was also noted.

Oil and gas revenue in the period was USD 5.5 million and is based on the Company's entitlement barrels. The revenue was generated by the sale of the net entitlement volume of 110,539 bbls.

From commencement of commercial production, field operating costs per production barrel were USD 27.30/bbl and USD 30.42/bbl with royalties included. Through a carry arrangement, under the OML 113 Joint Operations Agreement (JOA), the Company's share of capital and operating expenditure is 16.255% (paying interest), whereas the allocation of revenue to the Company is at 12.1913% (revenue interest). Based on the net barrels produced which the Company is entitled to sell, Panoro's operating costs per barrel equated to USD 36.40/bbl and USD 40.55/bbl with royalties included. The revenue allocation of 12.1913% will increase to 16.255% once certain pre-defined financial thresholds are met under the JOA. Operating costs will continue to be reviewed aggressively at the JV level; on a normalised production range, the operating cost per barrel is expected to reduce in line with previous estimates.

Panoro Energy reported a net loss of USD 62.0 million from continuing operations for the year ended December 31, 2016, an increase in loss of USD 22.8 million, compared to a loss of USD 39.2 million in 2015. The increase in loss was significantly affected by the inclusion of impairment charges in 2016.

Exploration related costs and operator G&A decreased to USD 0.7 million in the year ended December 31, 2016, down from USD 1.9 million in 2015. This is consistent with the majority of the Aje operator general and administrative costs since first oil being classified as operating costs during 2016.

General and Administration costs from continuing operations decreased to USD 4.1 million for the year ended December 31, 2016 compared to USD 4.8 million in the comparative period in 2015, culminating in a year-on-year decrease of 15.8%. The reduction is a result of continued cost saving efforts and by currency variations on GBP denominated costs.

Depreciation for the year ended December 31, 2016 was USD 2.2 million increasing from USD 90 thousand in the same period in 2015 as a direct result of the commencement of the depreciation of the Aje Cenomanian oil field in 2016.

During the year ending December 31, 2016, the Company recorded a provision for impairment totalling USD 55.9 million against its investment in Aje asset in Nigeria (USD 38.8 million) and Dussafu asset in Gabon (USD 17.1 million). The Aje impairment is a result of application of accounting principles to determine the recoverable amount of the asset as of the balance sheet date. It has been considered following triggers and factors that include amongst others, the recent Aje well performance, rationalisation of historically high exploration costs and a reflection of risks associated with the asset in the current environment. In order to make such determinations, qualitative and quantitative factors were considered. The Dussafu impairment was the result of the effect of lower oil prices at the time and was considered to be a fair and current reflection on the Company's valuation of the carrying value of the asset. The recognition of such provision was in line with the relevant accounting guidance and does not represent an underlying change in technical view of either of the assets.

EBIT from continuing operations was thus a negative USD 61.9 million for the year ending December 31, 2016, compared to a negative USD 39.3 million in 2015.

Net financial items amounted to an expense of USD 94 thousand in the current period compared to an income of USD 34 thousand in the same period in 2015. This is due to accretion of USD 69 thousand notional interest on the Aje Asset Decommissioning Liability.

Loss before tax from continuing activities was USD 62.0 million for the year ending December 31, 2016 compared to the loss of USD 39.3 million for the same period in 2015. The increase in loss in 2016 is predominantly due to the inclusion of impairment provisions for both Dussafu and Aje.

Net loss for both periods from discontinued operations was USD 0.6 million.

The total net loss for the year ending December 31, 2016 was USD 62.6 million, compared to a net loss of USD 39.9 million for 2015.

Statement of financial position

Non-current assets amounted to USD 51.5 million at December 31, 2016, a decrease of USD 50.9 million from December 31, 2015. This can be analysed as: capital additions during the period were USD 14.3 million, offset by USD 60.3 million impairment charges USD 1.0 million expensing of Aje pre-commencement costs and USD 2.2 million depreciation charges.

Property, furniture, fixtures and equipment was USD 169 thousand decreasing from USD 266 thousand at December 31, 2015. The decrease represents the depreciation of office premises in 2016 information technology upgrades carried out in 2015.

Other non-current assets decreased to USD 0.1 million as at December 31, 2016 as a result of the capitalisation of the Rubicon FPSO guarantee deposit of USD 0.8 million. The remaining USD 0.1 million relates to the tenancy deposit for office premises.

Current assets amounted to USD 7.2 million per December 31, 2016, compared to USD 12.6 million per December 31, 2015.

Trade and other receivables stood at USD 1.7 million for both periods. This reflects the utilisation of the cash calls paid during the year, resulting in a similar receivable balance of prepaid cash calls at the end of both periods. In addition, USD 0.2 million has been accumulated and held on the balance sheet as the cash cost of Aje crude oil inventory. USD 0.6 million and USD 0.2 million, both amounts relating to the first Aje cargo lifting for sales proceeds and tax receivable respectively.

Cash and bank balances stood at USD 5.3 million at December 31, 2016, of which USD 0.5 million cash was set aside as security of costs in relation to the ongoing dispute on OML 113), a decrease from USD 10.9 million at December 31, 2015. The decline is due to investment in assets and corporate expenses in the period, offset by the receipt of revenues for the two Aje liftings in the period.

Equity amounted to USD 54.3 million as per December 31, 2016, compared to USD 108.2 million at the end of December 2015. The change reflects the loss for the period, accentuated by the impairment charges against both Aje and Dussafu, offset by the capital increase in 2016.

Total non-current liabilities of USD 2.0 million as of December 31, 2016 compared to USD 6.2 million at the end of December 2015. The decrease primarily relates to the reversal of the Aje Field deferred tax liability which has been unwound as part of the impairment review of the Aje field. The decommissioning provision for the Aje field has remained at USD 1.9 million for both periods. USD 0.1 million is held in long-term liabilities and is in relation to historical tax liability in Brazil.

Current liabilities amounted to USD 2.4 million at December 31, 2016, compared to USD 0.7 million at the end of December 2015.

Accounts payable, accruals and other liabilities amounted to USD 2.3 million, an increase from USD 0.7 million at the end of December 2015. The increase represents increased operational accruals on Aje, royalty due on Aje's second lifting and higher corporate trade payables and accruals as at December 31, 2016. The tax liability of USD 0.1 million is in relation to historical tax liability in Brazil.

Cash flows

Net cash flow from operating activities amounted to negative USD 2.6 million in 2016, compared to negative USD 6.5 million in 2015. The decline is primarily explained by lower costs throughout 2016 brought about by cost saving initiatives introduced by Management.

Net cash flow from investing activities was an outflow of USD 11.8 million in 2016, compared to an outflow of USD 23.5 million in 2015. The cash outflow in 2016 mainly relates to investment in oil and gas assets.

Net cash flow from financing activities represented a cash inflow of USD 8.3 million in 2016, predominantly comprising USD 8.8 million of net proceeds from the Equity Private Placement, net interest income from investments USD 18 thousand offset by USD 520 thousand of restricted cash. This compares to a cash inflow from financing activities of USD 59 thousand in 2015.

Foreign exchange impact on cash balances was a negative USD 33 thousand in 2016 and a negative USD 25 thousand in 2015.

Cash and cash equivalents thus declined to USD 4.8 million (2015: USD 10.9 million).

ALLOCATION OF PROFITS AND LOSSES

Parent company financial information

(Amounts in USD 000)	2016	2015

Total revenues	-	300

Operating expenses
Depreciation	-	-
General and administrative costs	(1,249)	(1,695)
Impairment of investment in subsid iary	(38,873)	(4,576)
Provision for Doubtful Receivables	(28,311)	(42,236)

Write-down of Intercompany ba lances	-	(150)

Total operating expenses	(68,433)	(48,357)

Earnings before interest and tax (EBIT)	(68,433)	(48,357)
Net interest and financial items	10,048	7,635

Loss before taxes	(58,385)	(40,722)
Income tax benefit / (expense)	-	-

Net loss	(58,385)	(40,722)

FUNDING

In April 2017, Panoro has received USD 11 million plus some working capital adjustments at the 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 to fund cash requirements up to December 31, 2017 from cash in hand and cash flow from operations. If additional funding is required due to unforeseen circumstances, the Company may need to seek additional debt or equity financing and cannot be certain that such financing will available, when needed, on reasonable terms. Based on an overall assessment, the financial statement has been prepared under the assumption of going concern and realization of assets and settlement of debt in normal operations.

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 non-operator, 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.

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 abandonment costs of BS-3 licenses.

Operating in a low oil price environment also poses challenges to project financing/ funding and an inherent counterparty risk exists in terms of the financial capability of the Joint Venture partners. Based on information which has been publicly released by certain of these partners, there is a risk that funding shortfalls may result in Panoro increasing its interest in its Licences.

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 customers 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 Reais (BRL). Most of the cash balance is held in USD with institutions of credible credit standing and the currency risk exposure is very limited.

The Company is debt free and has no interest rate risk exposure 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 11 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 to fund cash requirements up to December 31, 2017 from cash in hand and cash flow from operations. If additional funding is required due to unforeseen circumstances, the Company may need to seek additional debt or equity financing and cannot be sure that such financing will available, when needed, on reasonable terms.

In early December 2016, Panoro announced that it was in disagreement with its joint venture partners in OML 113 in Nigeria and intended to initiate arbitration and legal proceedings to protect its interests. The dispute concerns the purported passing of resolutions by the joint venture partners with respect to a proposed new well to be drilled at Aje in OML 113, and a related cash call. The Company believes the drilling of any new well is premature at this stage and is of the firm view that the decision to incur such additional capital expenditures at Aje unambiguously requires unanimous consent of joint venture partners. Panoro is still proactively trying to resolve the issue in order to preserve shareholder value. As the cash call and default notice remain in dispute, Panoro has commenced arbitration proceedings pursuant to the JOA. In addition, to protect its rights prior to commencement of the arbitration proceedings, the Company applied to the High Court in London, UK for interim relief in order to protect its rights under the JOA. The Court order was received whereby Panoro has been granted an interim injunction, and awarded its interim costs in seeking the injunction. The other joint venture partners are now temporarily restricted from taking any action related to new well cash calls that would prevent Panoro's continued participation in the JOA and OML 113. Under the terms of the Court order, Panoro is also required to provide a customary bank guarantee to the benefit of the respondents.

Panoro is in discussion with a number of potential buyers for the sale of all or a portion of its interest in OML 113. However there can be no assurances that any transaction contemplated under these discussions will be consummated. In the meantime, Panoro is resolved to bring the case to arbitration should no commercial solution be forthcoming.

Although on balance the Group believes that it has reasonable grounds to pursue the dispute and it can achieve a favourable outcome; there can be no assurance or certainty that such dispute will either be settled or the resolution of the dispute and litigation will be in Group's favour. As such, uncertainties that material losses may be incurred by the Group in case of an adverse outcome of the legal proceedings.

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.

ORGANIZATION 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. Most recently, Mr. Hamilton was CEO of UK-AIM listed President Energy PLC; a Latin American focused Exploration Company, which opened up a new onshore basin in Paraguay. He is supported by CFO, Qazi Qadeer and Technical Director, Richard Morton, both are also based in London.

Since the beginning of 2016, Panoro Energy has employed 5 persons (including part-time employees), all of which are based in London. The workforce has been reduced as a result of the ongoing efforts to reduce G&A costs and divestment of assets in Brazil.

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 workplace.

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 minimizing 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 and competitive company in the best interest of the shareholders, employees and society at large, within the laws and regulations of the respective countries. The Board and management aim for a controlled and profitable development and long-term creation of growth through well-founded governance principles and risk management.

Panoro Energy acknowledges that successful value-added business is profoundly dependent upon transparency and internal and external confidence and trust. Panoro Energy believes that this is achieved by building a solid reputation based on our financial performance, our values and by fulfilling our commitments. Thus, good corporate governance practices combined with Panoro Energy's Code of Conduct is an important tool in assisting the Board to ensure that we properly discharge our duty.

The composition of the Board ensures that the Board represents the common interests of all shareholders and meets the Company's need for expertise, experience, capacity and diversity. The members of the Board represent a broad range of experience including oil and gas, energy, banking and investment. The composition of the Board ensures that it can operate independently of any special interests. Members of the Board are elected for a 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 a lengthier version of the policy 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 Ethi-

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 2016 and 2015. 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 2016, 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 2016 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 74 of this annual report and on Company's website www.panoroenergy.com.

OUTLOOK

Panoro looks forward to 2017, where it can build and capitalise on a landmark partnership with BWO and sanction the Dussafu development. Furthermore, Panoro's utmost efforts will be directed towards solving the impasse on Aje with the partners in OML 113. Panoro's balanced, full cycle E&P portfolio provides the platform to consider opportunities to grow the asset base and create shareholder value

The Board wishes to thank the staff and shareholders for their continued commitment to the Company.

April 28, 2017 The Board of Directors Panoro Energy ASA

Julien Balkany Chairman of the Board

Hilde Ådland Non-Executive Director

Alexandra Herger Non-Executive Director

Torstein Sanness Non-Executive Director

Garrett Soden Non-Executive Director

John Hamilton Chief Executive Officer

BOARD OF DIRECTORS

JULIEN BALKANY

Chairman of the Board

Mr. Julien Balkany, Chairman of the Board, French citizen resident in London, has been serving as a managing partner of Nanes Balkany Partners, a group of investment funds which primarily pursues active value investments in publicly traded oil and gas companies since 2008. 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 brokerdealer 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.

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. 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)

ALEXANDRA HERGER

Non-Executive Director

Ms. Alexandra Herger, a US citizen based in Maine, has extensive leadership experience in worldwide exploration for oil and gas companies. Ms. Herger has 35 years of global experience in the upstream oil and gas industry. She most recently served as interim Vice President of Global Exploration for Marathon Oil Corporation from April 2014 until her retirement during the summer of 2014. Prior to this position, Ms. Herger was appointed Director of International Exploration and New Ventures for Marathon Oil Company from November 2008 to April 2014. She led five new country entries and was responsible for adding net discovered resources of over 500 million boe to Marathon's portfolio. Before joining Marathon, she was at Shell E&P Company from 2002-2006. Prior to the merger with Shell, Ms. Herger was Vice President of the Gulf of Mexico for Enterprise Oil from 1998-2002. 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 postgraduate 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.

BOARD OF DIRECTORS

GARRETT SODEN

Non-Executive Director

Mr. Garrett Soden, has worked with the Lundin Group of Companies since 2007 as a senior executive and board member. He is a director of Gulf Keystone Petroleum Ltd., a London-listed oil and gas E&P company focused on Iraqi Kurdistan. He is also a director of Etrion Corporation, a Canadian solar power producer focused on Japan. Mr. Soden is the former Chairman and Chief Executive Officer of RusForest AB, a Swedish forestry company with interests in Russia. He is also the former Chief Financial Officer of both Etrion and PetroFalcon Corporation, a Canadian oil and gas E&P company focused on Venezuela. Mr. Soden previously 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 honors 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, 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 Head of Operations for Engie E&P Norge AS (previously GDF SUEZ E&P Norge AS). She held several senior positions with Engie 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.

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, an oil and gas investment fund. He was also Chief Financial Officer of UK FTSE 250 listed Imperial Energy PLC, until its sale for over 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. Mr. Hamilton is a US and British citizen.

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.

FOR THE YEAR JANUARY 1, 2016 TO DECEMBER 31, 2016

USD 000 Note	2016	2015
CONTINUING OPERATIONS
Revenue
Oil and gas revenue 3	5,461	-
Total revenue	5,461	-

Expenses
Operating Costs	(4,558)	-
Exploration related costs and operator G&A	(660)	(1,877)
General and administrative costs 4	(4,063)	(4,823)
Severance and restructuring costs	-	(38)
Impaiment of assets 9D	(55,795)	(32,445)
Depreciation 9	(2,231)	(90)
Share based payments 16	(47)	-
Total operating expenses	(67,354)	(39,273)

Operating loss 4	(61,893)	(39,273)
Net foreign exchange (loss)/gain	(33)	(25)
Interest costs net of income 5	43	73
Other financial costs	(104)	(14)
Loss before income taxes	(61,987)	(39,239)
Income tax benefit / (expense) 6	-	(46)
Net loss from continuing operations	(61,987)	(39,285)

DISCONTINUED OPERATIONS
Net income / (loss) from discontinued operations 12	(649)	(582)
Net loss for the period	(62,636)	(39,867)
Exchange differences arising from translation of foreign operations	(10)	(19)
Other comprehensive income / (loss) for the period (net of tax)	(10)	(19)
Total comprehensive income / (loss)	(62,646)	(39,886)
Net loss attributable to:
Equity holders of the parent	(62,636)	(39,867)
Total comprehensive income / (loss) attributable to:
Equity holders of the parent	(62,646)	(39,886)
Earnings per share 7
(USD) – Basic and diluted - Income/(loss) for the period attributable to equity holders of the parent - Total	(1.61)	(0.17)
(USD) – Basic and diluted - Income/(loss) for the period attributable to equity holders of the parent – Continuing operations	(1.60)	(0.17)

AS AT DECEMBER 31, 2016

USD 000	Note	2016	2015
ASSETS
Non-current assets
Intangible assets
Licenses and exploration assets	8	25,971	31,033
Total intangible assets		25,971	31,033

Tangible assets
Production assets and equipment	9	25,285	-
Development assets	8	-	70,195
Property, furniture, fixtures and equipment	9	169	266
Other non-current assets	9	122	962
Total tangible assets		25,576	71,423
Total non-current assets		51,547	102,456

Current assets
Crude oil inventory		163	-
Trade and other receivables	10	1,724	1,693
Cash and cash equivalents	11	4,768	10,948
Restricted cash	11	520	-
Total current assets		7,175	12,641

TOTAL ASSETS		58,722	115,096

EQUITY AND LIABILITIES
Equity
Share capital	14	305	193
Share premium		297,503	288,858
Additional paid-in capital		122,101	122,054
Total paid-in equity		419,909	411,105
Other reserves	14	(43,404)	(43,394)
Retained earnings		(322,177)	(259,540)
Total equity attributable to shareholder of the parent		54,328	108,171

Non-current liabilities
Decommissioning liability	13	1,925	1,856
Deferred tax liability	6	-	4,376
Other long-term liabilities		88	-
Total non-current liabilities		2,013	6,232

Current liabilities
Accounts payable and accrued liabilities	15	2,287	692
Corporate tax liability		94	1
Total current liabilities		2,381	693
TOTAL EQUITY AND LIABILITIES		58,722	115,096

AS AT DECEMBER 31, 2016

Attributable to the equity holders of the parent

	Note	Issued capital	Share premium	Additional paid-in	Retained earnings	Other reserves	Currency translation	Total
USD 000				capital			reserve
At January 1, 2015		56,333	288,858	65,914	(219,672)	(37,647)	(5,729)	148,057
Net income/(loss) – Continuing Operations		-	-	-	(39,285)	-	-	(39,285)
Net income/(loss) – Discontinued Operations		-	-	-	(582)	-	-	(582)
Other comprehensive income/(loss)		-	-	-	-	-	(19)	(19)
Total comprehensive income/(loss)		-	-	-	(39,867)	-	(19)	(39,886)
Reduction in registered share capital		(56,140)	-	56,140	-	-	-	-
Employee share options	16	-	-	-	-	-	-	-
At December 31, 2015		193	288,858	122,054	(259,539)	(37,647)	(5,748)	108,171

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)
Reduction in registered share capital		-	-	-	-	-	-	-
Employee share based incentives	16	-	-	47	-	-	-	47
At December 31, 2016		305	297,503	122,101	(322,177)	(37,647)	(5,758)	54,328

FOR THE YEAR ENDED DECEMBER 31, 2016

USD 000	Note	2016	2015
Cash flows from operating activities
Net (loss) / income for the year before tax – Continuing operations		(61,987)	(39,239)
Net (loss) / income for the year before tax – Discontinued operations		(514)	(582)
Net (loss) / income for the year before tax		(62,501)	(39,821)
Adjusted for:
Depreciation	9	2,231	90
Exploration related costs and Operator G&A		660	1,877
Impairment and asset write off	8/9	56,566	32,823
Net finance costs		61	(59)
Share-based payments	16	47	-
Foreign exchange loss / (gain)		33	25
Increase/(decrease) in trade and other payables		1,657	(838)
(Increase)/decrease in trade and other receivables		(1,188)	(583)
(Increase)/decrease in oil inventory		(163)	-
Taxes paid		(41)	(46)
Net cash flows from operating activities		(2,638)	(6,532)

Cash flows from investing activities
Investment in exploration, production and other assets	8/9	(12,617)	(22,549)
Movement in related non-current assets		813	(962)
Net cash flows from investing activities		(11,804)	(23,511)

Cash flows from financing activities
Net proceeds from Equity Private Placement		8,774	-
Net financial income (net of charges paid)		18	59
Movement in restricted cash balance		(520)	-
Net cash flows from financing activities		8,272	59
Effect of foreign currency translation adjustment on cash balances		(10)	(9)

Change in cash and cash equivalents during the period		(6,180)	(29,993)

Cash and cash equivalents at the beginning of the period		10,948	40,941

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

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 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, 2016 were authorised for issue by the Board of Directors on April 28, 2017.

The Company had USD 5.3 million in cash and bank balances as of December 31, 2016, of which USD 0.5 million cash was held as restricted cash collateral against a bank guarantee supporting our legal case at Aje. Subsequent to year-end, the collateral and the underlying guarantee was increased to USD 1.5 million. On April 28, 2017, the Company has received USD 11 million plus some working capital adjustments at closing of the BWO transaction, and a further USD 1.0 million is due to be received by year-end 2017. The Company may require funding for future capital investments in our existing projects or working capital requirements due to timing uncertainties regarding the legal dispute on Aje. Should the Company need to seek additional financing, a combination of debt, equity or asset divestment could be considered. The Company cannot be sure that such financing will be available when needed on reasonable terms. Based on an overall assessment, the financial statements have been prepared under the assumption of going concern and realization of assets and settlement of debt in normal operations.

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

NOTE 2. BASIS OF PREPARATION

The consolidated financial statements of Panoro Energy ASA and its subsidiaries ("Panoro" or 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.

Asset retirement costs and obligations

Asset retirement costs will be incurred by the Group at the end of the operating life of certain Group facilities and properties. 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 and amount of expenditure can also change, for example in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the provisions established which would affect future financial results.

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

Since December 2016, The Company has been in a dispute with its partners in OML 113 Joint Venture, offshore Nigeria that involves disagreements commercial and procedural aspects. The Company has taken these matters to Arbitration to protect its interest. Details of this dispute can be referred to in note 20. Although the Company believes it has reasonable grounds to pursue these issues in Arbitration, there are material uncertainties on a downside case where the conclusion of the dispute and arbitration is not in favour of the Company and may result in loss of participation in the OML 113 license. Such outcome would also have a direct material impact on the judgements and basis of estimates made with respect to impairment assessment of OML 113 and the going concern assumption supporting the Group's funding and liquidity position in these financial statements of December 31, 2016.

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

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
Share of the revenue from the sale of the output by 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.

(ii)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:

		2016	2015
	Average rate	Reporting date rate	Average rate	Reporting date rate
Norwegian Kroner/USD	8.3998	8.6051	8.0714	8.8143
Brazilian Real/USD	3.4830	3.2588	3.3384	3.9045
USD/British Pound	1.3542	1.2303	1.5286	1.4819

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-of-production 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. 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-tomaturity investments, 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, 2015 and December 31, 2016.

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.

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 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 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 interest-bearing financial assets classified as available for sale, interest income or expense is recorded using the effective interest rate (EIR), which is the rate that exactly discounts the estimated future cash payments or receipts through the expected life of the financial instrument or a shorter period, where appropriate, to the net carrying amount of the financial asset or liability. Interest revenue is included in finance income in income statement.

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 equitysettled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The income statement expense or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period and is recognised in sharebased payments expense.

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

When the terms of an equity-settled transaction award are modified, the minimum expense recognised is the expense as if the terms had not been modified, if the original terms of the award are met. An additional expense is recognised for any modification that increases the total fair value of the 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). Non-financial assets that were previously impaired are reviewed for possible reversal of the impairment at each reporting date.

A previously recognised impairment loss is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such a reversal is recognised in the income statement. After such a reversal the depreciation charge is adjusted in future periods to allocate the asset's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.

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, 2016 that the Group applied for the first time in the current year. Several other amendments apply for the first time in 2016, 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.

IFRS 11 Joint Arrangements: Accounting for Acquisitions of Interests in Joint Operations – Amendments to IFRS 11

The amendments to IFRS 11 require that a joint operator accounting for the acquisition of an interest in a joint operation, in which the activity of the joint operation constitutes a business, must apply the relevant IFRS 3 Business Combinations principles for business combination accounting. The amendments also clarify that a previously held interest in a joint operation is not remeasured on the acquisition of an additional interest in the same joint operation if joint control is retained. In addition, a scope exclusion has been added to IFRS 11 to specify that the amendments do not apply when the parties sharing joint control, including the reporting entity, are under common control of the same ultimate controlling party.

The amendments apply to both the acquisition of the initial interest in a joint operation and the acquisition of any additional interests in the same joint operation and are applied prospectively. These amendments do not have any impact on the Group as there has been no interest acquired in a joint operation during the period.

IAS 27: Equity Method in Separate Financial Statements – Amendments to IAS 27

The amendments allow entities to use the equity method to account for investments in subsidiaries, joint ventures and associates in their separate financial statements. Entities already applying IFRS and electing to change to the equity method in their separate financial statements have to apply that change retrospectively. These amendments do not have any impact on the Group's consolidated financial statements.

Annual Improvements 2012-2014 Cycle

These improvements include:

IFRS 5 Non-current Assets Held for Sale and Discontinued Operations

Assets (or disposal groups) are generally disposed of either through sale or distribution to the owners. The amendments clarify that changing from one of these disposal methods to the other would not be considered a new plan of disposal, rather it is a continuation of the original plan. There is, therefore, no interruption of the application of the requirements in IFRS 5. This amendment is applied prospectively.

IFRS 7 Financial Instruments: Disclosures

(i) Servicing contracts

The amendments clarify that a servicing contract that includes a fee can constitute continuing involvement in a financial asset. An entity must assess the nature of the fee and the arrangement against the guidance for continuing involvement in IFRS 7 in order to assess whether the disclosures are required. The assessment of which servicing contracts constitute continuing involvement must be performed retrospectively. However, the required disclosures need not be provided for any period beginning before the annual period in which the entity first applies the amendments.

(ii) Applicability of the amendments to IFRS 7 to condensed interim financial statements

The amendments clarify that the offsetting disclosure requirements do not apply to condensed interim financial statements, unless such disclosures provide a significant update to the information reported in the most recent annual report. This amendment is applied retrospectively.

IAS 19 Employee Benefits

The amendments clarify that market depth of high quality corporate bonds is assessed based on the currency in which the obligation is denominated, rather than the country where the obligation is located. When there is no deep market for high quality corporate bonds in that currency, government bond rates must be used. This amendment is applied prospectively.

IAS 34 Interim Financial Reporting

The amendments clarify that the required interim disclosures must either be in the interim financial statements or incorporated by crossreference between the interim financial statements and wherever they are included within the interim financial report (e.g., in the management commentary or risk report). The other information within the interim financial report must be available to users on the same terms as the interim financial statements and at the same time. This amendment is applied retrospectively.

These amendments do not have any impact on the Group.

IAS 1 Disclosure Initiative – Amendments to IAS 1

The amendments to IAS 1 clarify, rather than significantly change, the existing IAS 1 requirements. The amendments clarify:

• The materiality requirements in IAS 1

• That specific line items in the statement(s) of profit or loss and other comprehensive income and the statement of financial position may be disaggregated

• That entities have flexibility as to the order in which they present the notes to financial statements

• That the share of other comprehensive income of associates and joint ventures accounted for using the equity method must be presented in aggregate as a single line item, and classified between those items that will or will not be subsequently reclassified to profit or loss. Furthermore, the amendments clarify the requirements that apply when additional subtotals are presented in the statement of financial position and the statement(s) of profit or loss and other comprehensive income.

These amendments do not have any impact on the Group.

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 adoption of IFRS 9 may have an effect on the classification and measurement of the group's financial assets, but is not expected to impact the classification and measurement of the group's financial liabilities.

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 is currently assessing the impact of IFRS 15 and 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. 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, however IFRS 16 has not yet been endorsed by the EU. The standard may be applied retrospectively or using a modified retrospective approach. The Company is currently evaluating the impact of adopting these standards on its consolidated financial statements

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

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, 2016 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 33.333% 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.

2016
USD 000	West Africa	Corporate	Total – Continuing operations	Brazil – 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

2015
USD 000	West Africa	Corporate	Total – Continued operations	Brazil – Discontinued operations	Total
Revenue (net) *	-	-	-	-	-
EBITDA	(1,954)	(4,784)	(6,738)	(112)	(6,850)
Depreciation	-	(90)	(90)	-	(90)
Impairment	(32,445)	-	(32,445)	(493)	(32,938)
Profit /(loss) before tax	(36,714)	(2,525)	(39,239)	(582)	(39,821)
Net profit/(loss)	(36,714)	(2,571)	(39,285)	(582)	(39,867)
Segment assets	103,698	11,120	114,818	278	115,096
- Additions to licenses, exploration and evaluation assets, development assets	25,168	-	25,168	-	25,168

* Revenue excludes any intercompany revenue

Revenue from major sources from continuing operations:

USD 000	2016	2015
Oil revenue (net)	5,461	-
Other income	-	-
Total Revenue (net)	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	2016	2015
Employee benefits expense		1,571	2,242
Depreciation	9	2,231	90
Impairment and asset write-off	9, 12	56,027	32,823
Operating lease payments		241	359

NOTE 4a. EMPLOYEE BENEFIT EXPENSES

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

USD 000	2016	2015
Salaries	1,228	1,688
Employers contribution	153	251
Pension costs	114	212
Other compensation	76	91
Total	1,571	2,242

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

	2016	2015
Number of employees	5	5

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

Statement for the current year (2016)

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 64 of this report.

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.

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 workforce.

Remuneration for executive management consists of both fixed and variable elements. The fixed elements consist of salaries and other benefits (free phone, electronic communication, etc.), while the variable elements consist of a performance based bonus arrangement and a Restricted Stock Units program that was approved by the Board of Directors as well as the Annual General Meeting in 2015. In June 2016, 190,000 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.

Evaluation, award and payment of cash bonuses is generally performed in the year subsequent to financial year end, unless stated otherwise. Any bonuses for 2016 performance will be awarded in the year 2017 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.

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:

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

2015	Short term benefits
USD 000 (unless stated otherwise)	Salary	Bonus	Benefits	Pension costs	Total	Number of RSUs awarded in 2015	Fair value of RSUs expensed/(credited)
John Hamilton, CEO (vi)	258	-	9	26	293	-	-
Qazi Qadeer, CFO	246	-	5	26	277	-	-
Nishant Dighe, former CEO/COO (vi)	331	72	9	38	450	-	-
Jan Kielland, former CEO (vi)	291	-	2	50	343	-	-
Total	1,126	72	25	140	1,363	-	-

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 not entitled to such remuneration at change of control.
iii. In June 2016, 200,000 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 190,000 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.
vi. Mr. Jan Kielland stepped down from the role of CEO at the end of 2014, but was entitled to his monthly base salary until June 2015. Mr. Nishant Dighe was appointed as interim CEO until Mr. John Hamilton's permanent appointment in May 2015. Subsequently, Mr. Dighe returned to the role of President and Chief Operating Officer of Panoro until his departure from the Company in November 2015.

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

NOTE 4d. BOARD OF DIRECTORS REMUNERATION

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

USD 000	2016	2015
Julien Balkany	66	55
Alexandra Herger	38	34
Garrett Soden	38	19
Torstein Sanness	38	19
Hilde Ådland (i)	28	-
Silje Christine Augustson (ii)	-	17
Lars Brandeggen (ii)	-	14
Total	208	158

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.

(ii)Mr. Lars Brandeggen stepped down at the Annual General Meeting held May 2015, whereas Ms. Silje Augustson resigned from the board in July 2015.

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 2016, 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.

NOTE 4f. AUDITORS' REMUNERATION

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

USD 000	2016	2015
Ernst & Young
Statutory audit	181	243
Tax services	-	-
Other	-	-
Total	181	243

NOTE 5. FINANCE INCOME, INTEREST EXPENSE AND OTHER CHARGES

Interest costs net of income

USD 000	2016	2015
Interest income from placements and deposits	(43)	(73)
Total – Net (income) / expense	(43)	(73)

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	2016	2015
Income Taxes
Current income tax – continuing and discontinued operations	-	46
Deferred income tax	-	-
Tax charge / (benefit) for the period	-	46

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	2016	2015
(Loss) before taxation – continuing	(61,987)	(39,239)
Profit / (Loss) before taxation – discontinued operations	(649)	(582)
Profit /(Loss) before taxation – Total	(62,636)	(39,821)
Tax calculated at domestic tax rates applicable to profits in the respective countries	(17,902)	(9,909)
Expenses not deductible	1,672	2,721
Differences due to functional currency effects in subsidiaries	-	-
Tax effect of losses not utilised in the period	16,230	7,188
Others	-	46
Tax charge / (benefit)	-	46

Deferred tax

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

USD 000	2016	2015
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	-	4,376
Total deferred tax liabilities	-	4,376
Net deferred tax assets / (liabilities)	-	(4,376)

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

USD 000	2016	2015
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:

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	-	-	-	-

Classified as held for sale	-	-	-	-
As at December 31, 2016	-	-	-	-

Deferred tax liabilities

USD 000	Tangible and production as sets	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)
Classified as held for sale	-	-	-	-
As at December 31, 2016	-	-	-	-

Deferred tax liability was reversed as part of impairment charge recognised in the statement of comprehensive income. (Note 9D).

2015

Deferred tax assets
USD 000	Tax losses	Oil and gas assets	Provisions and oth ers	Total
As at January 1, 2015	-	-	-	-
(Charged) / credited to the statement of comprehensive income	-	-	-	-
Classified as held for sale	-	-	-	-
As at December 31, 2015	-	-	-	-

Deferred tax liabilities

USD 000	Tangible and production as sets	Exploration assets	Provisions and oth ers	Total
As at January 1, 2015	-	4,376	-	4,376
Charged / (credited) to the statement of comprehensive income	-	-	-	-
As at December 31, 2015	-	4,376	-	4,376

There are no recognised deferred tax assets in Group the group financial statements as of December 31, 2016.

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 26 million (2015: USD 29 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	2016	2015
Norway	88,748	97,441
UK	2,444	2,381
Cyprus	10,161	9,924
Brazil	-	-
Netherlands	8,015	6,087
Total	109,368	115,833

The decline in tax losses in Norway is primarily due to unfavourable NOK to USD currency rate compared to prior year.

NOTE 7. BASIC AND DILUTED EARNINGS PER SHARE

Basic earnings per share

USD 000, unless otherwise stated	2016	2015
Net loss attributable to equity holders of the parent – Total	(62,636)	(39,687)
Net loss attributable to equity holders of the parent – Continuing operations	(61,987)	(39,285)
Weighted average number of shares outstanding - in thousands	38,814	234,546
Basic and diluted earnings per share - (USD) – Total	(1.61)	(0.17)
Basic and diluted earnings per share - (USD) – Continuing operations	(1.60)	(0.17)

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

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	-

2015
USD 000	Licences, exploration and evaluation assets	Development assets
Acquisition cost
At January 1, 2015	61,480	45,169
Additions	1,998	23,170
Decommissioning provision	-	1,856
At December 31, 2015	63,478	70,195

Accumulated impairment
At January 1, 2015	-	-
Impairment	32,445	-
At December 31, 2015	32,445	-
Net carrying value at December 31, 2015	31,033	70,195

*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	33.33%	Gabon	Ten years from commence ment 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	2016	2015
Acquisition cost

At January 1	-	-
Additions	1,231	-
Transfer from Development Assets	48,601	-
At December 31	49,832	-

Accumulated impairment
At January 1	-	-
Impairment charge for the year	22,413	-
At December 31	22,413	-

Accumulated depreciation
At January 1	-	-
Depreciation charge for the year	2,134	-
At December 31	2,143	-
Net carrying value at December 31	25,285	-

It is noted that certain cash calls relating to the Aje field, offshore Nigeria that are the subject of the current legal proceedings with Aje joint venture partners have not been recognised in the 2016 financial statements. Reference is made to Note 20 for further information.

NOTE 9b. PROPERTY, FURNITURE, FIXTURES AND EQUIPMENT

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

USD 000	Leasehold	Furniture, Fixture and Fittings	Computer Equipment	Total
Acquisition cost
At January 1, 2015	-	-	388	388
Additions	55	104	103	262
Disposals / write-downs	-	-	-	-
At December 31, 2015	55	104	491	650

Accumulated depreciation
At January 1, 2015	-	-	294	294
Depreciation charge for the year	5	16	69	90
Disposals / write-downs	-	-	-	-
At December 31, 2015	5	16	363	384
Net carrying value at December 31, 2015	50	88	128	466

Depreciation method and rates

2015

Category	Straight-line depreciation	Useful life
Furniture, fixtures and fittings	10-33.33%	10-33.33%

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 is invested in Dussafu Permit, offshore Gabon and holds a 33.333% interest in the block. During the year, a USD 17.1 million impairment charge was recognised in the financial statements reflecting the logical application of accounting standards triggered by a decline in oil prices in early part of 2016. The carrying value as of the balance sheet date is aligned to the implied fair value of the sale transaction with BW Energy Gabon Pte Limited. The carrying value for Dussafu, after taking in to account the impairment is USD 15.2 million as of December 31, 2016.

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 10.8 million as of December 31, 2016 is after taking into account impairment charge of USD 20.8 million and determined through a combination of indicative fair value estimates driven from engagement with third parties and an overall value in use analysis of the OML 113 license which includes Aje Cenomanian Oil field as discussed in the next heading of this note. The OML 113 carrying value included in exploration and evaluation assets represents the underlying estimate of the discovered gas resources on the license.

Production Assets and Equipment

The Group has investments in tangible assets with USD 25.3 million of production assets and equipment in Nigeria after taking into account impairment charge of USD 22.4 million for the year ended December 31, 2016. 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 multiple approaches of valuation fair value less cost of sale and value in use calculation. This combination approach was adopted to reasonably measure the recoverable amount after taking into account the potential divestment structures under consideration.

Recoverable amount analysis

Discount rates are outlined below and represent the real pre-tax rates. These rates are based on management's project appraisal metrics adjusted accordingly at a risk premium of each cash-generating unit, taking into account risk associated with different cash generating units.

Discount rate of 25% has been used for the Aje Cenomanian Oil field in Nigeria reflecting the increased uncertainty as a result of the dispute.

Impairment testing is undertaken in line with Group's policy, whenever there are indications of impairment. The recent test was trigged by operational issues at Aje field in Nigeria and a low oil price environment. The most recent test was undertaken at December 31, 2016. In assessing whether the tangible assets are impaired the carrying amount of the cash-generating unit is compared with its recoverable amount and adjustments have also been taken into account for fair value considerations keeping in view the discussions that were ongoing with a number of parties to achieve a divestment/settlement. For the purpose of the impairment test of tangible assets, the recoverable amount for both assets in Nigeria and Gabon was determined individually based on a value in use model and adjusted for fair value less cost of sale considerations.

Based on the results of the recoverable cost analysis, the carrying value of assets in Nigeria exceeded the recoverable as at December 31, 2016 and impairment charges of 20.8 million and 22.4 million was recognised in the financial statements related to exploration and evaluation assets and producing assets respectively.

Cashflows are projected for a period up to the date all commercial hydrocarbons/resources are expected to be extracted, based on management's expectation at the time of completing the testing and is based on Joint Venture's consensus of P50 reserves/2C resources for both assets. The end of extraction period for hydrocarbons can depend on a number of variables, including recoverable reserves and resources, the forecast selling prices and the associated development and operating costs.

Key assumptions used in the calculations

The key assumptions used in the calculation of asset impairment value in use models are:

JV's interpretation of recoverable reserves and resources;
Production profiles achieved;
Expected USD/bbl forward curve oil price assumptions for three years from Balance Sheet date;
Expected project sanction dates;
Cost of development;
Growth rates assumptions 2.5%;
Cost of extraction and processing; and
Discount rates.

Economically recoverable reserves and resources are based on management's current expectation 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.

Sensitivities to change in assumptions

Given the current volatility in the market, adverse changes in key assumptions could result in recognition of impairment charges.

The Group will continue to test its assets for impairment where indications are identified and may in future recognise impairment charges. If the low oil price scenario continues, there is a risk of further impairment of the oil and gas assets.

Due to a combination of approaches used in estimating a recoverable amount that is more skewed towards a fair value less cost of sale approach, oil price and production sensitivities have a lesser impact and therefore have not been disclosed.

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

USD 000	2016					2015
	Nigeria	Gabon	Corporate	Total	Nigeria	Gabon	Corporate	Total
Capitalised licenses, exploration and evaluation assets	20,770	17,147	-	37,917	-	32,445	-	32,445
Production assets and equipment	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	38,810	17,147	(162)	55,795	-	32,445	-	32,445

NOTE 10. ACCOUNTS AND OTHER RECEIVABLES

USD 000	2016	2015
Accounts receivable	795	-
Other receivables and prepayments	929	1,693
At December 31	1,724	1,693

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

At December 31, 2016 and 2015 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	2016	2015
Cash and bank balances	4,768	10,948
Cash and cash equivalents at December 31	4,768	10,948

As at December 31, 2016, the Company held USD 0.5 million as restricted cash collateral against a bank guarantee supporting our legal case at Aje. 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, 2016 the Company held cash denominated in NOK of approximately USD 23 thousand related to the Norwegian withholding tax liability.

Overdraft facilities

The Group had no bank overdraft facilities as at December 31, 2016.

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 2016.

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	2016	2015
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	(103)	(226)
EBITDA	(103)	(226)
Depreciation	-	-
Impairment	(419)	(378)
Share based payments	-	-
Gain / (loss) on sale of subsidiary	-	-
EBIT - Operating income / (loss)	(522)	(604)
Interest costs net of income	-	-
Other financial costs net of income	13	24
Net foreign exchange gain / (loss)	(5)	(2)
Income / (loss) before tax	(514)	(582)
Income tax benefit / (expense)	(135)	-
Net income / (loss) for the period from discontinued operations	(649)	(582)
Earnings per share (basic and diluted) for the period from discon tinued operations (USD)	(0.02)	0.00

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	2016	2015
Balance for provision at December 31	1,856	-
Recognised during the year on Aje development - accretion of notional interest	69	1,856
At December 31	1,925	1,856

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, 2016	234,545,786	193
Equity Private Placement	166,666,666	97
Subsequent Offering	23,809,500	15
Shares issued for rounding purposes prior to the 10:1 Reverse Share Split	8	-
10:1 Reverse Share Split	(382,519,764)	-
As at December 31, 2016	42,502,196	305

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

In February 2016, Panoro successfully completed a fully subscribed Equity Private Placement with the support of new and existing investors, raising NOK 70 million (USD 8.1 million) in gross proceeds at a subscription price of NOK 0.42 per share. Following the Equity Private Placement, the Company issued NOK 10 million (approximately USD 1.2 million) in gross proceeds through the subscription and allocation of 23,809,500 new shares in a Subsequent Offering to the shareholders that did not participate in the Equity Private Placement. The new shares were also issued at a subscription price of NOK 0.42 per share.

In May 2016, the Company completed a reverse split of the Company's shares at a ratio of 10:1 resulting in an increase in the share capital of NOK 0.04. Following the registration of the reverse split and capital increase, the Company had a registered share capital of NOK 2,125,109.80 divided into 42,502,196 shares, each with a nominal value of NOK 0.05.

Shares owned by the CEO, board members and key management, directly and indirectly, at December 31, 2016:

Shareholder	Position	Number of shares	% of total
Julien Balkany(i)	Chairman of the Board of Direc tors	1,325,444	3.12%
Torstein Sanness	Director	35,000	0.08%
Garrett Soden (ii)	Director	10,009	0.02%
Alexandra Herger	Director	5,950	0.01%
John Hamilton	Chief Executive Officer	53,801	0.13%
Qazi Qadeer	Chief Financial Officer	20,350	0.05%
Richard Morton	Technical Director	15,414	0.04%

(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 725,338 shares in the Company.

(ii) Mr. Soden holds directly or indirectly 10,009 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	2016	2015
Accounts payable	254	190
Accruals and other payables	2,033	502
At December 31	2,287	692

NOTE 16. SHARE-BASED PAYMENT PLANS AND RESTRICTED STOCK 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 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. The annual criteria applied for grants of RSUs to members of the executive team during the previous financial year will, unless they contain confidential and company sensitive targets, be disclosed in the Company's annual remuneration statement pursuant to section 6-16a of the Public Limited Companies Act.

In June 2016, 200,000 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, 2016, 200,000 RSUs had been granted (nil granted as at December 31, 2015). All of the 200,000 RSUs were outstanding as of December 31, 2016 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	2016	2015	2016	2015	Fair value hierarchy
Financial assets
Cash and bank balances	Fair value through the P&L	4,768	10,948	4,768	10,948	Level 3
Accounts receivable	Loans and receivables	795	-	795	-	Level 3
Financial liabilities
Accounts payable and accrued liabilities	Other financial liabilities	2,469	693	2,469	693	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 2016. 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, 2016 and December 31, 2015, 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, 2016 and 2015 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 2016				2015
	+100bps	-100bps	+100bps	-100bps
Cash	26	(26)	26
Net effect	26	(26)	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 10 thousand as of December 31, 2016 (2015: USD 19 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 2016 or 2015.

A 20% strengthening or weakening of the USD against the following currencies at December 31, 2016 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	2016		2015
USD vs NOK	+ 20%	-20%	+ 20%	-20%

Cash	(20)	20	(18)	18
Receivables	(53)	53	(1)	1
Payables	138	(138)	33	(33)
Net effect	64	(64)	14	(14)

USD vs GBP	+ 20%	-20%	+ 20%	-20%
Cash	(23)	23	(113)	113
Receivables	(5)	5	(4)	4
Payables	54	(54)	43	(43)
Net effect	26	(26)	(74)	74

USD vs BRL	+ 20%	-20%	+ 20%	-20%
Cash	(1)	1	(54)	54
Receivables	(24)	24	(1)	1
Payables	70	(70)	30	(30)
Net effect	46	(46)	(25)	25

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, 2016 based on contractual undiscounted payments.

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

2015
USD 000	On demand	Less than 1 year	1 to 2 years	2 to 5 years	>5 years
Accounts payable and accrued liabilities	-	692	-	-	-	692
Total	-	692	-	-	-	692

The Company had USD 4.8 million in cash and bank balances as of December 31, 2016. In addition to this, USD 0.5 million cash was held as restricted cash collateral against a bank guarantee supporting our legal case at Aje. Subsequent to year-end, the collateral and the underlying guarantee was increased to USD 1.5 million. The Company has received USD 11 million plus some working capital adjustments at closing of the BWO transaction, and a further USD 1.0 million to be received by year-end 2017. The Company may require funding for future capital investments in our existing projects or working capital requirements due to timing uncertainties regarding the legal dispute on Aje and closing of the BWO transaction. Should the Company need to seek additional financing, a combination of debt, equity or asset divestment could be considered. The Company cannot be sure that such financing will be available when needed on reasonable terms.

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 2017 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, 2016 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 guarantees 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	2016	2015
Not later than 1 year	243	215
Later than 1 year and not later than 5 years	608	1,003
Later than 5 years	-	-
At December 31	851	1,218

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, 2016. 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, 2017 is USD 3.1 million, USD 3.2 million for the year ended December 31, 2018 and USD 1.7 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 and the minimum payment per year is expected to be USD 3.0 million per annum net to Panoro. 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

The Company has provided performance guarantee to the Brazilian Petroleum Agency in order to fulfil all commitments on its licences in Brazil. A recent review of retirement obligations on abandoned wells in BS-3 licences (Cavalo Marinho and Coral) has highlighted certain work on wells which could be performed as a best practice measure. However, the Operator's and consortia's interpretation on the Brazilian Petroleum Agency's guidelines applicable to dismantled wells fulfil the minimum requirements and at present there is a low probability that a major expenditure will be required. Should the regulator require further work on these wells, the cost of such retirement works could be considerable, although it is expected that a risk of such request from the regulator is low and considered to be contestable.

Unsubstantiated legal claims

Subsequent to December 31, 2016, Panoro announced that a judgment was granted in favour of the Company by the Borgarting Court of Appeal in Oslo (the "Court of Appeal"). Panoro was in a dispute with Euro-Latin Capital SA ("ELC"), an M&A advisory firm, in relation to a baseless claim by ELC for the payment of a success fee of up to USD 2.4 million on the sale of Panoro's assets in Brazil in 2014. The Court of Appeal dismissed all of ELC's claims and ordered ELC to pay Panoro's costs, which together with costs awarded earlier are in excess of NOK 2 million. ELC have stated that they will not appeal the case to the Supreme Court of Norway, and as such this case is now deemed closed. Post year-end, the Company received settlement in full, equivalent to approximately USD 275 thousand.

OML 113 – Aje, Nigeria

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, 2016, are as follows:

Subsidiary	Place of incorporation and ownership	Ownership interest and voting power
Panoro Energy do Brasil Ltda	Brazil	100%
Panoro Energy Limited	UK	100%
African Energy Equity Resources Limited	UK	100%
Pan-Petroleum (Holding) Cyprus Limited	Cyprus	100%
Pan-Petroleum Holding B.V.	Netherlands	100%
Pan-Petroleum Gabon B.V.	Netherlands	100%
Pan-Petroleum Gabon Holding B.V.	Netherlands	100%
Pan-Petroleum Nigeria Holding B.V.	Netherlands	100%
Pan-Petroleum Services Holding B.V.	Netherlands	100%
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%

NOTE 23. EVENTS SUBSEQUENT TO REPORTING DATE

On 21 February 2017 the Company's fully-owned subsidiary, Pan-Petroleum Gabon B.V. ("PPGBV"), has entered into a definitive Sale and Purchase Agreement (the "SPA") with BW Energy Gabon Pte. Ltd. ("BWEG"), a subsidiary of BW Offshore Limited, the leading global provider of floating production services to the oil and gas industry. Under the terms of the SPA, PPGBV has sold a 25% working interest in the Dussafu Production Sharing Contract ("Dussafu PSC") in Gabon to BWEG for a total cash consideration of USD 12 million. At closing of the transaction on April 28, 2017, the Company has received USD 11 million in cash plus some working capital adjustments. The remaining consideration of USD 1 million will be paid in cash by December 30, 2017.

As part of this transaction, PPGBV will also receive a non-recourse loan from BWEG of up to USD 12.5 million at 7.5% annual interest rate in order to fund all expenditures through to first oil production at Dussafu. Post-completion, PPGBV has an 8.33% working interest in the Dussafu PSC. The total gross capital expenditure to reach first oil in 2018 is estimated to be a maximum of USD150 million.

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)
Aje (OML 113 Cenomanian oil development)	1.7	3.1
Panoro Total	1.7	3.1

	2P reserves (MMBOE)
Balance (previous ASR) as of December 31, 2015	3.2
Production 2016	(0.1)
Revision of previous estimates	-
New developments since previous ASR	-
Balance (current ASR) as of December 31, 2016	3.1

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) 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.

FOR THE YEAR ENDED DECEMBER 31, 2016

USD 000	Note	2016	2015
Operating income
Operating revenues		-	300
Total operating income		-	300

Operating expenses
General and administrative expense		(1,249)	(1,695)
Intercompany recharges	8	-	-
Impairment of investments in subsidiary	2,6	(38,873)	(4,576)
Loss on disposal of tangible assets		-	-
Impairment of loan to subsidiaries	7,8	(28,311)	(42,236)
Write-down of Intercompany balances		-	(150)
Depreciation	6	-	-
Total operating expenses		(68,433)	(48,657)

Operating result	2	(68,433)	(48,357)
Financial income	3	10,122	7,738
Interest and other finance expense	3	(95)	(90)
Currency gain / (loss)		21	(13)
Result before income taxes		(58,385)	(40,722)
Income tax	5	-	-
Result for the year		(58,385)	(40,722)
Earnings per share (basic and diluted) - USD	4	(1.50)	(0.17)

PANORO ENERGY ASA PARENT COMPANY BALANCE SHEET

AS AT DECEMBER 31, 2016

USD 000	Note	2016	2015
ASSETS
Non-current assets
Investment in subsidiaries	6	-	38,528
Intercompany receivables	7	-	-
Total non-current assets		-	38,528

Current assets
Loans to subsidiaries	8	57,148	60,862
Other current assets		277	9
Cash and cash equivalent		3,926	5,906
Restricted cash		520	-
Total current assets		61,871	66,777
TOTAL ASSETS		61,871	105,305

EQUITY AND LIABILITIES
EQUITY
Paid-in capital
Share capital	9	305	193
Share premium reserve	9	297,503	288,858
Additional paid-in capital	9	122,054	122,054
Total paid-in capital		419,863	411,106

Other equity
Other reserves	9	(364,402)	(306,015)
Total other equity		(364,402)	(306,015)
TOTAL EQUITY		55,461	105,091

LIABILITIES
Current liabilities
Accounts payable		18	11
Intercompany payables	8	5,722	49
Other current liabilities	10	670	154
Total current liabilities		6,410	214
TOTAL LIABILITIES		6,410	214
TOTAL EQUITY AND LIABILITIES		61,871	105,305

PANORO ENERGY ASA PARENT COMPANY STATEMENT OF CASH FLOW

FOR THE YEAR ENDED DECEMBER 31, 2016

USD 000	Note	2016	2015
CASH FLOW FROM OPERATING ACTIVITIES
Net income / (loss) for the year		(58,385)	(40,722)
Adjusted for:
Depreciation		-	-
Impairment of investment in subsidiary	6	38,528	4,576
Provision for Doubtful Receivables	7,8	28,311	42,236
Share based payments	2	-	-
Financial Income	3	(10,122)	(7,738)
Financial Expenses	3	95	90
Write-down of Intercompany balances		-	150
Foreign exchange gains/losses		(21)	13
(Increase)/decrease in trade and other receivables		(268)	49
Increase/(decrease) in trade and other payables		523	(291)
(Increase)/decrease in intercompany receivables		-	-
Increase/(decrease) in intercompany payables		5,673	(4,456)
Net cash flows from operating activities		4,334	(6,093)

CASH FLOWS FROM INVESTING ACTIVITIES
Net proceeds from loans to subsidiaries		-	3,700
Loans to subsidiaries		(14,527)	(30,227)
Net cash flows from investing activities		(14,527)	(26,527)

CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from Equity Private Placement		8,755	-
Interests paid		(95)	(90)
Interests received		52	162
Movement in restricted cash		(520)	-
Net cash flows from financing activities		8,192	72

Effect of foreign currency translation adjustment on cash balances		21	(13)
Net increase in cash and cash equivalents		(1,980)	(32,561)

Cash and cash equivalents at the beginning of the year		5,906	38,467
Cash and cash equivalents at the end of financial year		3,926	5,906

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	2016	2015
Employee benefits expense (note 2.1)	4	350
Impairment of investment in subsidiary (note 7)	38,873	4,576
Impairment Intercompany Loans	28,311	40,293
Impairment of Intercompany Receivables (Share based payment)	-	1,943
Impairment of Intercompany balances (PEdB)	-	150
Operating lease payments	-	41

2.1 Employee benefits expense

a) Salaries

The Company had zero employees at December 31, 2016 (2015: zero employee), and an average of nil employees during the year (2015: 1 employee). As such, there are no wages and salaries included in general and administrative expenses.

Employee related expenses:

USD 000	2016	2015
Salaries	-	206
Employer's contribution	-	72
Pension costs	-	60
Other compensation including severance provision	4	12
Total	-	350

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	2016	2015
Julien Balkany	66	55
Alexandra Herger	38	34
Garrett Soden (ii)	38	19
Torstein Sanness (ii)	38	19
Hilde Adland	28	-
Lars Brandeggen (i)	-	14
Silje Christine Augustson	-	17
Total	208	158

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) Mr. Lars Brandeggen resigned from the Board in May 2015, whereas Ms. Silje Augustson resigned from the board in July 2015.

(ii) 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 pension benefits were received by the Directors during 2016 and 2015.

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	2016	2015
Ernst & Young
Statutory audit	145	195
Tax services	-	-
Total	145	195

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. The annual criteria applied for grants of RSUs to members of the executive team during the previous financial year will, unless they contain confidential and company sensitive targets, be disclosed in the Company's annual remuneration statement pursuant to section 6-16a of the Public Limited Companies Act. 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	2016	2015
Interest income from subsidiaries	10,070	7,576
Other interest income	52	162
Total	10,122	7,738

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	2016	2015
Interest expense on bond loans	-	-
Amortisation of debt issue costs	-	-
Early redemption penalty on bond loans	-	-
Bank and other financial charges	95	90
Total	95	90

NOTE 4. EARNINGS PER SHARE

Basic earnings per share

USD 000 unless otherwise stated	2016	2015
Net result for the period	(58,385)	(40,722)
Weighted average number of shares outstanding - in thousands	38,814	234,546
Basic and diluted earnings per share – (USD)	(1.50)	(0.17)

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	2016	2015
Tax payable	-	-
Change in deferred tax	-	-
Income tax expense	-	-

Specification of the basis for tax payable:

USD 000	2016	2015
Result before income tax	(58,385)	(40,722)
Effect of permanent differences	67,472	(30,433)
Tax losses not utilised / (utilised)	9,087	10,289
Basis for tax payable	-	-

Specification of deferred tax:

USD 000	2016	2015
Losses carried forward	88,748	97,411
Taxable temporary differences	-	-
Basis for tax payable	88,748	97,411
Calculated deferred tax asset (27%)	22,187	26,309
Unrecognised deferred tax asset	(22,187)	(26,309)
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, 2015 was NOK 832.6 million (USD 96.8 million at 2016 closing exchange rate). The 2016 income for tax purposes has been provisionally calculated at NOK 69.8 million (approximately USD 8 million).

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, 2016 USD 1 (2015: USD 38.5 million) 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%

	PEdB	PPHCL	PPGHBV	Total
Investment at cost
At January 1, 2016	-	129,106	-	129,106
Investments during the year	345	-	-	345
At December 31, 2015	345	129,106	-	129,451

Provision for impairment
At January 1, 2016	-	(90,578)	-	(90,578)
Charge for the year (note 6.1)	(345)	(38,528)	-	(38,873)
At December 31, 2015	(345)	(129,106)	-	(129,451)

Total investment in subsidiaries at December 31, 2016	-	-	-	-
Total investment in subsidiaries at December 31, 2015	-	38,528	-	38,528

Note 6.1 Impairment represents loss in value of Company's investment in shares of Pan-Petroleum (Holding) Cyprus Limited of USD 38.5 million (2015: USD 4.6 million). The impairment has been determined by comparing estimated recoverable value of the underlying investment with the carrying amount.

Note 6.2 During December 2016, and as part of the Group's reorganisation of the Gabon business, the Company acquired all outstanding shares in Pan-Petroleum Gabon Holding B.V. from its indirectly wholly owned subsidiary, Pan-Petroleum Holding B.V. Since the Company has a significant investment in the form of a loan which is not likely to be fully recoverable, and considering the sizeable negative equity of the Pan-Petroleum Gabon Holding B.V. and its subsidiary Pan-Petroleum Gabon B.V, a consideration of USD 1 was paid for the entire share capital of Pan-Petroleum Gabon Holding B.V.

NOTE 7. PROVISION FOR DOUBTFUL RECEIVABLES

Provision for doubtful receivables is USD 28.3 million (2015: USD 42.2 million). The provision is represented by the following:

-Uncollectible loan principal in part of USD 28.3 million (2015: USD 40.3 million) reflecting the further impairment of the Dussafu Asset during 2016. Subsequently, the Company's loan to its subsidiary, Pan-Petroleum Gabon B.V. is now reflective of the underlying book value of the Dussafu Asset.

NOTE 8. RELATED PARTY TRANSACTIONS AND BALANCES

The Company's loan to the Cypriot subsidiary Pan-Petroleum (Holding) Cyprus Limited amounted to USD nil as at December 31, 2016 (2015: USD 4.5 million). This follows the assignment of Pan-Petroleum (Holding) Cyprus Limited's loans with Pan-Petroleum Gabon Holding B.V. and Pan-Petroleum Holding B.V. to Panoro Energy ASA during 2016 for a value of USD 3.5 million.

The Company's loan to the Dutch subsidiary Pan-Petroleum Gabon B.V was classified as current and amounted to USD 15.2 million as at December 31, 2016 (2015: USD 31.0 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 38.4 million as at December 31, 2016 (2015: USD 25.3 million). This loan carries an interest rate of 10% and is repayable on demand.

Payable balances on account of intercompany recharges was USD 4.1 million (2015: USD 0.1 million) to Company's indirect subsidiary Panoro Energy Limited, which provides technical services and Pan-Petroleum (Holding) Cyprus Limited was USD 1.6 million (2015: nil). 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, 2016 amounted to NOK 2,125,110 (USD 304,838) consisting of 42,502,196 shares at a par value of NOK 0.05. (December 31, 2015, nominal share capital amounted to NOK 342,547,500 (USD 56,333,267) consisting of 234,545,786 shares at a par value of NOK 1.4604717698). 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 2016 and 2015:

USD 000	Share capital	Share premium reserve	Additional paid-in capital	Other equity	Total
At January 1, 2015	56,333	288,858	65,915	(265,293)	145,813
Loss for the year	-	-		(40,722)	(40,722)
Reduction in registered share capital	(56,140)	-	56,140	-	-
At December 31, 2015	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

Ownership structure

The Company had 4,371 shareholders per December 31, 2016 (2015: 4,379). The twenty largest shareholders were:

No.	Shareholder	Number of shares	Holding in %
1	STOREBRAND VEKST VERDIPAPIRFOND	4,132,356	9.72 %
2	KOMMUNAL LANDSPENSJONSKASSE	1,847,585	4.35 %
3	KLP AKSJENORGE	1,847,579	4.35 %
4	DANSKE INVEST NORGE VEKST	1,446,479	3.40 %
5	J.P. MORGAN SECURITIES LLC	1,325,444	3.12 %
6	NORDNET LIVSFORSIKRING AS	980,932	2.31 %
7	NORDNET BANK AB	975,798	2.30 %
8	F2 FUNDS AS	650,000	1.53 %
9	EUROCLEAR BANK N.V.	592,164	1.39 %
10	STORHAUGEN INVEST AS	500,000	1.18 %
11	FINANCIAL FUNDS AS	494,843	1.16 %
12	BOYE	424,333	1.00 %
13	SKANDINAVISKA ENSKILDA BANKEN AB	412,558	0.97 %
14	LARSEN OIL & GAS AS	404,189	0.95 %
15	C & B CONSULT AS	400,000	0.94 %
16	RAVI INVESTERING AS	369,040	0.87 %
17	KAMPEN INVEST AS	343,000	0.81 %
18	DANSKE BANK A/S	311,624	0.73 %
19	BALLISTA AS	300,000	0.71 %
20	NORDEA BANK DANMARK A/S	299,119	0.70 %
	Top 20 shareholders	18,057,043	42.48 %
	Other shareholders	24,445,153	57.52 %
	Total shares	42,502,196	100.00 %

Shares owned by the CEO, board members and key management, directly and indirectly, at December 31, 2016:

Shareholder	Position	Number of shares	% of total
Julien Balkany (i)	Chairman of the Board of Directors	1,325,444	3.12%
Torstein Sanness	Director	35,000	0.08%
Garrett Soden (ii)	Director	10,009	0.02%
Alexandra Herger	Director	5,950	0.01%
John Hamilton	Chief Executive Officer	53,801	0.13%
Qazi Qadeer	Chief Financial Officer	20,350	0.05%
Richard Morton	Technical Director	15,414	0.04%

(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 725,338 shares in the Company.

(ii) Mr. Soden holds directly or indirectly 10,009 shares in the Company.

Shareholder distribution per December 31, 2016:

Amount of shares	# of shareholders	% of total	# of shares	Holding in %
1 - 1,000	2,886	66.03%	560,466	1.32%
1,001 - 5,000	723	16.54%	1,854,000	4.36%
5,001 - 10,000	276	6.31%	2,081,037	4.90%
10,001 - 100,000	417	9.54%	11,983,682	28.19%
100,001 - 1,000,000	64	1.47%	15,423,568	36.29%
1,000,001 +	5	0.11%	10,599,443	24.94%
Total	4,371	100.00%	42,502,196	100.00%

NOTE 10. OTHER CURRENT LIABILITIES

The breakdown of other current liabilities is below:

USD 000	2016	2015
Accruals including severance costs	644	135
Employee related costs payable (including taxes)	26	19
At December 31	670	154

NOTE 11. COMMITMENTS AND CONTINGENCIES

a) Commitments

Non-cancellable operating lease commitments

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

B) Contingencies

Unsubstantiated legal claims

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.

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PART 1. SALARIES, BONUSES AND OTHER NON-SHARE BASED REMUNERATION

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
Shorm-term Incentives	To align annual performance with Panoro's busi ness objectives and shareholder interests. Short-term incentive pools increase or decrease based on busi ness performance	Cash	Achievement of specific performance bench marks 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 perfor mance 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; recommending for approval all administrative changes to compensation plans that may be subject to the approval of the shareholders or the Board of Directors; reviewing and reporting to the Board of Directors the levels of share ownership by the senior executives in accordance with the Share Ownership Policy adopted by the Company (see below).

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 Compensation 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.

Remuneration in 2016:

Remuneration for executive management for 2016 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 shareholders in the Annual General Meeting in 2015

For 2016, the following was paid/incurred to the executives:

2016	Short Term Benefits			Long 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 Di rector	239	24	4	24	290	40,000	8
	836	143	15	83	1,076	190,000	39

Any bonuses that were incurred and paid in 2016 were approved by the Board of Directors during 2016. The bonus paid in 2016 related to the achievement of performance standards set by the Board of Directors for the financial year 2015.

Remuneration principles for 2017:

For 2017, 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.

Any cash bonuses to members of the executive management for 2017 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 2017. The annual bonus 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. 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. In general, the criteria applied for cash bonuses to members of the executive team during the previous financial year will, unless they contain confidential and company sensitive targets, be disclosed in the Company's annual remuneration statement for the financial year after grant.

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. Other members of the executive management team, at present, are not entitled to such remuneration at 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.

Share ownership guidelines (SOG):

The Board of Directors, upon the Remuneration Committee's recommendation, has also adopted a SOG Policy for members of the executive management to ensure that they have meaningful economic stake in the Company. 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. A member of the executive team has three years to comply with the ownership requirements starting from the later of either the date of appointment to a position noted above or from the date of adoption of the SOG Policy.

2016 – Compliance:

In 2016, the executives received base salaries and cash incentive bonuses in line with the executive remuneration policies as presented to the 2016 Annual General Meeting.

PART 2. SHARE BASED INCENTIVES

In June 2016, 200,000 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 2017, the Board of Directors will only issue share based incentives in line with any shareholder approved program. Awards 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.

STATEMENT OF DIRECTORS' RESPONSIBILITY

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 2016 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 28, 2017 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

STATEMENT ON CORPORATE GOVERNANCE IN PANORO ENERGY ASA

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 high quality 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 pre-emption rights of existing shareholders to subscribe for shares in the event of an increase in share capital will be justified and disclosed in the stock exchange announcement of the increase in share capital. Such deviation will be made only in the common interest of the shareholders of the Company.

Panoro Energy is in a phase where investments in the Company's operations are required to enable future growth, and is therefore not in a position to distribute dividends. Payment of dividends will be considered in the future, based on the Company's capital structure and dividend capacity as well as the availability of alternative investments.

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.

CORPORATE ASSEMBLY AND BOARD OF DIRECTORS – COMPO-SITION 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.

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.

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 takeover 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 sub-committee of the Board, which will meet with the auditor regularly. The objective of the committee is to focus on internal control, independence of the auditor, risk management and the Company's financial standing.

The auditors will send a complete Management Letter/Report to the Board – which is a summary report 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.

16. 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 2016 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 2016 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. During 2016 the Group has started oil production and received revenues for its interest in OML 113. There are customary royalty and taxes due on oil production in Nigeria and as of December 31, 2016 the Group had no tax liability and USD 97 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 non-operated 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 exploration and development assets in West Africa, namely the Dussafu License offshore southern Gabon, and OML113 offshore western Nigeria. Both assets have existing discoveries and the Aje field's cenomanian oil production facility commenced commercial production in May 2016.

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").

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

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 arrangments 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 undertake training on the ECOC on a regular basis.
Partners	Panoro operates and maximises 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 communications, 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 environment, 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, includ ing corruption, HS&Q and any other issues listed above.

Bbl One barrel of oil, equal to 42 US gallons or 159 liters Bm3 Billion cubic meters BoE Barrel of oil equivalent Btu British Thermal Units, the energy content needed to heat one pint of water by degee Fahrenheit M3 Cubic meters MMbbls Million barrels of oil MMBOE Milllion 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 oils 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 W1K 5EF United Kingdom

Tel: +44 (0) 20 3405 1060 Fax: +44 (0) 20 3004 1130

AI Terminal

Panoro Energy ASA

3706_10-k_2017-04-28_682e7ac9-62d0-4033-8953-069110c49d08.pdf

Panoro Energy

COMPANY OVERVIEW

CONTENTS:

C O M PA N Y O V E RV I E W

2016 HIGHLIGHTS

GABON

NIGERIA

PANORO OFFICES

GABON

Dussafu Marin Permit (33.333% interest)

NIGERIA

OML 113 Aje field (6.502% participating interest, 12.19% revenue interest and 16.255% paying interest)

BRAZIL

Operations in Brazil

INTRODUCTION

PANORO ASSETS PORTFOLIO

Dussafu: offshore Gabon, operator Harvest Natural Resources, Panoro 33.33%

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

MANAGEMENT DISCUSSION AND ANALYSIS

ASSUMPTIONS:

John Hamilton

RESERVES STATEMENT AS OF DECEMBER 31,2016

RESERVES DEVELOPMENT:

OPERATIONS

Operations in Gabon

Operations in Nigeria

Operations in Brazil

Income statement

Statement of financial position

Cash flows

ALLOCATION OF PROFITS AND LOSSES

Parent company financial information

RISK FACTORS

Operational risk factors

Financial risk factors

ORGANIZATION 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

Chairman of the Board

TORSTEIN SANNESS

Non-Executive Director

ALEXANDRA HERGER

Non-Executive Director

BOARD OF DIRECTORS

GARRETT SODEN

Non-Executive Director

HILDE ÅDLAND

Non-Executive Director

SENIOR MANAGEMENT

JOHN HAMILTON

Chief Executive Officer

QAZI QADEER

Chief Financial Officer

RICHARD MORTON

Technical Director

AS AT DECEMBER 31, 2016

AS AT DECEMBER 31, 2016

FOR THE YEAR ENDED DECEMBER 31, 2016

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

Asset retirement costs and obligations

Income taxes

b. Judgments

Dispute and litigation

Impairment indicators

Technical risk in development of oil and gas fields

Asset retirement obligations