PetroNor E&P ASA

Pre-Annual General Meeting Information • Apr 8, 2021

PetroNor E&P Limited ("PetroNor" or the "Company")

Notice of General Meeting

Notice is given that a General Meeting of Shareholders will be held at 2.00pm (AWST) on 4 May 2021 at the offices of Steinepreis Paganin, Level 4, 16 Milligan Street, Perth 6000, Western Australia.

The Explanatory Statement provides additional information on matters to be considered at the General Meeting. The Explanatory Statement and the Proxy Form are part of this Notice of Meeting.

The Directors have determined pursuant to Regulation 7.11.37 of the Corporations Regulations 2001 (Cth) that the persons eligible to vote at the Meeting are those who are registered Shareholders at 2.00pm (AWST) on 2 May 2021. Shareholders registered in the VPS must be registered shareholders at close of business on 27 April 2021.

Shareholders registered with the VPS must follow the instructions set out in the separate Proxy Vote Instruction form attached to this notice and return their completed and signed proxy, to be received by DNB Bank ASA on or prior to 27 April 2021 at 17:00 hours Oslo, preferably by way of e-mail to the email address: vote@dnb.no or by ordinary mail to DNB Bank ASA, Registrars Dept., P.O. Box 1600 Sentrum, 0021 Oslo, Norway, or if delivery by hand to: DNB Bank ASA, Registrars Dept., attn.: K. G. Berg, Dronning Eufemias gate 30, 0191 Oslo, Norway.

*****

For further information, please contact:

Knut Søvold, Chief Executive Officer Chris Butler, Group Financial Controller info@petronorep.com

Angeline Hicks, Company Secretary Tel: +61 401 489 883

Media Contacts: Buchanan Ben Romney Tel: +44 207 466 5000

About PetroNor E&P

PetroNor E&P Limited is a sub-Saharan focused independent oil and gas exploration and production company listed on Oslo Euronext Expand (previously Oslo Axess) with the ticker PNOR. PetroNor holds exploration and production assets offshore West Africa, specifically the PNGF Sud licenses in Congo Brazzaville, A4 license in The Gambia, the Rufisque Offshore Profond and Senegal Offshore Sud Profond in Senegal, OML 113 in Nigeria (subject to completion) and the Sinapa (Block 2A) and Esperança (Blocks 4A and 5A) licenses in Guinea Bissau (subject to regulatory approval).

PETRONOR E&P LIMITED

ACN 125 419 730

NOTICE OF GENERAL MEETING

Notice is given that the Meeting will be held at:

TIME: 2:00 pm

DATE: 4 May 2021

PLACE: Level 4, The Read Buildings, 16 Milligan Street, Perth 6000

The business of the Meeting affects your shareholding and your vote is important.

This Notice of Meeting should be read in its entirety. If Shareholders are in doubt as to how they should vote, they should seek advice from their professional advisers prior to voting.

The Directors have determined pursuant to Regulation 7.11.37 of the Corporations Regulations 2001 (Cth) that the persons eligible to vote at the Meeting are those who are registered Shareholders at 2.00pm on 2 May 2021.

Independent Expert's Report: Shareholders should carefully consider the Independent Expert's Report prepared for the purposes of Chapter 2E of the Corporations Act. The Independent Expert's Report comments on the fairness and reasonableness of the transaction the subject of Resolution 1 to the non-associated Shareholders. The Independent Expert has determined the transaction subject to Resolution 1 is FAIR AND REASONABLE to the non-associated Shareholders of the Company.

Voting Prohibition Statements

Resolution 1 – Approval of HAH Acquisition and issue of Symero Consideration Shares		In accordance with section 224 of the Corporations Act, a vote on this Resolution must not be cast (in any capacity) by or on behalf of a related party of the Company to whom the Resolution would permit a financial benefit to be given, or an associate of such a related party (Resolution 1 Excluded Party). However, the above prohibition does not apply if the vote is cast by a person as proxy appointed by writing that specifies how the proxy is to vote on the Resolution and it is not cast on behalf of a Resolution 1 Excluded Party.
		In accordance with section 250BD of the Corporations Act, a person appointed as a proxy must not vote, on the basis of that appointment, on this Resolution if:
	(a)	the proxy is either:
		(i)	a member of the Key Management Personnel; or
		(ii)	a Closely Related Party of such a member; and
	(b)		the appointment does not specify the way the proxy is to vote on this Resolution.
		prohibition does not apply if:	Provided the Chair is not a Resolution 1 Excluded Party, the above
	(a)		the proxy is the Chair; and
	(b)		the appointment expressly authorises the Chair to exercise the proxy even though this Resolution is connected directly or indirectly with remuneration of a member of the Key Management Personnel.

Voting in person

To vote in person, attend the Meeting at the time, date and place set out above. Shareholders holding shares in the Company which are registered in the Norwegian Central Securities Depository (VPS) will need to exercise their voting rights through the VPS Registrar.

Voting by proxy

To vote by proxy, please complete and sign the enclosed Proxy Form and return by the time and in accordance with the instructions set out on the Proxy Form.

In accordance with section 249L of the Corporations Act, Shareholders are advised that:

• each Shareholder has a right to appoint a proxy;
• the proxy need not be a Shareholder of the Company; and
• a Shareholder who is entitled to cast 2 or more votes may appoint 2 proxies and may specify the proportion or number of votes each proxy is appointed to exercise. If the member appoints 2 proxies and the appointment does not specify the proportion or number of the member's votes, then in accordance with section 249X(3) of the Corporations Act, each proxy may exercise one-half of the votes.

Shareholders and their proxies should be aware that changes to the Corporations Act made in 2011 mean that:

• if proxy holders vote, they must cast all directed proxies as directed; and
• any directed proxies which are not voted will automatically default to the Chair, who must vote the proxies as directed.

Should you wish to discuss the matters in this Notice of Meeting please do not hesitate to contact the Company Secretary on +61 401 489 883

Shareholders registered in the VPS

Each Shareholder has the right to vote for the number of Shares owned by the Shareholder and registered on an account with the Norwegian Central Securities Depository (VPS) belonging to the Shareholder at close of business on 27 April 2021. Shareholders registered with the VPS must follow the instructions set out in the separate Proxy Vote Instruction form attached to this Notice.

EXPLANATORY STATEMENT

This Explanatory Statement has been prepared to provide information which the Directors believe to be material to Shareholders in deciding whether or not to pass the Resolution.

1. BACKGROUND TO THE PROPOSED TRANSACTION

1.1 Background

The Company is an independent, Sub-Saharan focused oil and gas exploration and production company based in Australia and listed on the Oslo Euronext Expand (formerly Oslo Axess) with ticker PNOR. In 2019, the Company (previously called African Petroleum Corporation Limited) completed a reverse take-over with the Cypriot company, PetroNor E&P Ltd. Subsequently, the Company changed its name to PetroNor E&P Limited and continued to trade on Oslo Euronext Expand.

The Company holds exploration and production assets in Africa, namely the offshore PNGF Sud licenses in the Republic of Congo, through its subsidiary Hemla E&P Congo S.A., the Rufisque Offshore Profond and Senegal Offshore Sud Profond licenses offshore Senegal through its subsidiary African Petroleum Senegal Ltd, the A4 license offshore The Gambia through its wholly owned subsidiary PetroNor E&P Gambia Ltd., OML 113 (Aje) offshore Nigeria through its subsidiary Aje Production AS (transaction pending governmental approval) and the Sinapa (Block 2) and Esperança (Blocks 4A and 5A) licenses offshore Guinea Bissau through its subsidiary SPE Guinea Bissau AB (transaction pending governmental approval).

1.2 Proposed Acquisition

In the Republic of Congo, the Company holds a 11.9% indirect interest in PNGF Sud (comprised of three liquid and gaseous hydrocarbons production licenses: Tchendo II, Tchibouela II, and Tchibeli-Litanzi II) (Project) through its local subsidiary Hemla E&P Congo S.A (HEPCO).

These three production licenses were formally awarded in 2017 to the Congolese National Oil Company (SNPC), and a separate production sharing contract (PSC) is in place in connection with each of them. Other than SNPC, the current members of the contractor groups under these PSCs are Perenco Congo (operator), HEPCO, Kontinent Congo, Africa Oil & Gas Corporation, and Petro Congo.

The Company currently holds an indirect interest in HEPCO by virtue of holding 70.707% of the issued shares in Hemla Africa Holding AS (HAH). The remaining 29.293% interest in HAH (Ownership Interest) is held by Symero Limited (Symero).

Symero is a wholly owned subsidiary of NOR Energy AS, an entity controlled by Knut Søvold, Chief Executive Officer of the Company, and Gerhard Ludvigsen, a former Director of the Company. NOR Energy AS is also the second largest shareholder in the Company (holding approximately 13.59% of the issued Share capital).

The Company has entered an agreement with Symero under which Symero has conditionally agreed to sell the Ownership Interest to the Company, such that upon completion of the transaction, the Company will hold 100% of the issued capital in HAH (the Proposed Transaction).

A summary of the Proposed Transaction is set out below:

The Proposed Transaction will result in a material increase in the Company's interest in the Project as well as streamlining governance procedures to ensure that the interests of all shareholders will be aligned toward the development of the Project. Additionally, the Proposed Transaction is intended to facilitate the introduction of additional institutional investors in the Company and development partners to the Project.

The Proposed Transaction is conditional on the Company obtaining all necessary regulatory and Shareholder approvals to affect the Proposed Transaction. Accordingly, if Resolution 1 is not approved at the Meeting, the Proposed Transaction will not proceed.

1.3 Capital Raising

In conjunction with the Proposed Transaction, the Company is also undertaking a capital raising by way of an issue of 309,090,909 Shares (Capital Raising Shares) at an issue price of NOK 1.10 to raise NOK 247.2 million (~US\$40.1 million) (Capital Raising).

The Capital Raising comprises the following issues of Shares:

• (a) an initial tranche of 84,363,636 Shares at an issue price of NOK 1.10, issued to existing and new investors, including 31,975,454 Shares to Petromal (Tranche 1). The issue of the Tranche 1 Shares was completed on 15 March 2021;
• (b) a second tranche of 138,763,636 Shares at a deemed issue price of NOK 1.10 issued to Symero (Symero Consideration Shares) in consideration for the Proposed Transaction (Tranche 2a). The issue of the Tranche 2a Shares is subject to and conditional on Shareholder approval for Resolution 1; and

(c) a final tranche of 85,963,636 Shares at an issue price of NOK 1.10 issued to Petromal Sole Proprietorship LLC and related group companies (Petromal) (Tranche 2b). The issue of the Tranche 2b Shares is subject to and conditional on the Tranche 2a Shares being approved under Resolution 1.

The purpose of the Capital Raising is to finance drilling of infill wells and other increased oil recovery initiatives on the Project and general corporate purposes, as well as facilitating the Company's acquisition of the Ownership Interest.

Following the Capital Raising, the Company is also proposing to undertake a subsequent offering of Shares (the Repair Offer) to existing Shareholders of the Company pursuant to a prospectus to be issued by the Company in May 2021 (Prospectus). In addition to seeking quotation on Euronext Expand for the Capital Raising Shares, the Prospectus will also invite applications for up to a further 60,000,000 Shares, at an issue price of NOK 1.10 to raise up to a further NOK 66 million under the Repair Offer.

1.4 Summary of Resolution relating to the Proposed Transaction

The Proposed Transaction, if successfully completed, will result in the issue of the Symero Consideration Shares to Symero, a related party of the Company, under Tranche 2a, in consideration for the acquisition of the Ownership Interest. As Symero is a related party, the Company is required to seek Shareholder approval for this issue pursuant to Chapter 2E of the Corporations Act.

In the event Shareholder approval for Resolution 1 is not obtained, the Proposed Transaction will not proceed.

Shareholders should carefully consider the report prepared by the Independent Expert for the purposes of the Shareholder approval required under Chapter 2E of the Corporations Act. The Independent Expert's Report (annexed at Schedule 2 to this Notice) comments on the fairness and reasonableness of the transaction the subject of Resolution 1 to the non-associated Shareholders in the Company.

1.5 Background on Symero

Symero is a wholly owned subsidiary of NOR Energy AS, an entity controlled by Knut Søvold, Chief Executive Officer, and Gerhard Ludvigsen, former Director. NOR Energy AS is also the second largest shareholder in the Company (holding approximately 13.59%). Symero is registered in Cyprus and was incorporated in 2018. Symero's interest in the Project through HEPCO represents the only operations of its business.

1.6 Share Purchase Agreement

As referred to above, the Company has entered share purchase agreement (SPA) to implement the Proposed Transaction.

The material terms of the SPA are as follows:

• (a) Acquisition: Symero agrees to sell, and the Company agrees to purchase, the HAH Ownership Interest, free of any pre-emptive rights, charges, pledges or encumbrances;
• (b) Consideration: the Company agrees to issue Symero with that number of Shares in the Company which, when multiplied by the same issue price of Shares issued under the Capital Raising, is equal to USD18,000,000 (equivalent to 138,382,727 Shares) (Symero Consideration Shares); and

(c) Conditions Precedent: the Proposed Transaction is conditional on the Capital Raising having been completed and the Company convening this General Meeting and obtaining the shareholder approvals required to implement to the Proposed Transaction.

The SPA otherwise contains terms which are considered standard for an agreement of its nature, including terms relating to representations and warranties, confidentiality and assignment.

1.7 Board Changes

There will be no Board changes upon completion of the Proposed Transaction.

1.8 Pro forma capital structure

The anticipated effect of the Proposed Transaction on the capital structure of the Company will be as follows:

	Shares	Options
Current issued capital	1,056,028,9241	1,389,4702
Capital Raising (Tranche 2a – Symero Consideration Shares)	138,763,636	Nil
Capital Raising (Tranche 2b)	85,963,636	Nil
Repair Offer3	60,000,000	Nil
TOTAL	1,340,756,196	1,389,470

Notes

• 1. This figure includes 84,363,636 Shares issued under Tranche 1 of the Capital Raising.
• 1. The capital structure of the Company includes its ordinary Shares as well as 213,400 unlisted share options with exercise price of 2.5 NOK/share to expire on 11 January 2022 and 1,176,070 unlisted share options with exercise price of 7.75 NOK/share expiring 31 May 2022.
• 1. Refer to Section 1.3 above for the details of the Capital Raising and Repair Offer.

1.9 Existing and pro forma interests of NOR Group

The current and anticipated shareholdings of NOR Group post-Proposed Transaction are set out below:

	Current interest in PNOR		Pro forma interest in PNOR following Capital Raising and Proposed Transaction
	Shares	%	Shares	%
NOR Group (including Symero) 1	338,555,857	32.06	477,319,493	37.27
Other PNOR shareholders	717,473,067	67.94	803,436,703	62.73
TOTAL2	1,056,028,924	100	1,280,756,1963	100

Notes:

1. The breakdown of the individual interests of each NOR Group member is set out in Section 1.10 below.

2. 1. As noted in Section 1.2 above, the Proposed Transaction is conditional on the Company's shareholders approving the Proposed Transaction under Resolution in terms of Chapter 2E of the Corporations Act.
3. 1. This figure does not include the 60,000,000 Shares to be issued under the Repair Offer.

1.10 NOR Group

The members of NOR Group are as follows:

• (a) NOR Energy AS (jointly controlled by Knut Søvold, Chief Executive Officer, and Gerhard Ludvigsen, former Director);
• (b) Symero (minority interest holder in HAH, which is jointly controlled by Messrs Søvold and Ludvigsen);
• (c) Gulshagan III AS (an entity controlled by Mr Søvold through an indirect beneficial interest);
• (d) Gulshagan IV AS (an entity controlled by Mr Søvold through an indirect beneficial interest);
• (e) Pust For Livet AS (an entity that may be influenced by Mr Ludvigsen through immediate family control);
• (f) Ambolt Invest AS (an entity controlled by Mr Ludvigsen through an indirect beneficial interest); and
• (g) Lenger Nedi Hgan AS (an entity controlled by Mr Ludvigsen through an indirect beneficial interest).

Following the issue of the Symero Consideration Shares under Tranche 2a of the Capital Raising, NOR Group's voting power in the Company will increase from 32.06% (as it was at the date of this Notice of Meeting) to 37.27%, for a total maximum increase of 5.21%.

However, immediately prior to the issue of 84,363,636 Shares under Tranche 1 of the Capital Raising on 12 March 2021, NOR Group's voting power in the Company was 34.84% (the lowest it has been in the previous 12 months). Therefore, so long as Tranche 2a of the Capital Raising is completed, and the Symero Consideration Shares are issued, prior to 18 September 2021 (being 6 months from settlement of Tranche 1), NOR Group will not have acquired a relevant interest in securities which would require approval under Chapter 6 of the Corporations Act, by virtue of the "3% creep exception" in item 9 section 611 of the Corporations Act.

NOR Group member	Shares (pre Capital Raising)	%	Shares (post Capital Raising)	%
Symero	Nil	-	138,763,636	10.83
NOR Energy AS	143,555,857	13.59	143,555,857	11.21
Gulshagan III AS	45,000,000	4.26	45,000,000	3.51
Gulshagan IV AS	45,000,000	4.26	45,000,000	3.51
Pust For Livet AS	15,000,000	1.42	15,000,000	1.17
Ambolt Invest AS	45,000,000	4.26	45,000,000	3.51

The current and post-Capital Raising holds of NOR Group are shown below:

NOR Group member	Shares (pre Capital Raising)	%	Shares (post Capital Raising)	%
Lenger Nedi Hagan AS	45,000,000	4.26	45,000,000	3.51
Total	338,555,857	32.06	477,319,493	37.27

Notes:

• 1. Based on the number of Shares on issue as at the date of this Notice.
• 1. Based on all tranches of the Capital Raising having been completed, except the Repair Offer, meaning the number of Shares on issue is expected to be 1,280,756,196.
• 1.11 Pro forma consolidated statement of financial position

The pro-forma consolidated statement of financial position of the Company following completion of the Proposed Transaction and issues of all Shares contemplated by this Notice is set out in Schedule 1. The historical and pro-forma information is presented in an abbreviated form, insofar as it does not include all of the disclosure required by the Australian Accounting Standards applicable to annual financial statements.

1.12 Board intentions upon completion of the Proposed Transaction

Following completion of the Proposed Transaction, the Company's business model will be to further explore and accelerate the development of its exploration and production assets. Specifically, the Company's main objectives on completion of the Proposed Transaction include:

• (a) completing the proposed re-domicile of the group's holding company from Australia to Norway, as previously announced to shareholders;
• (b) completing an infill drilling program at PNGF Sud;
• (c) negotiating the license terms to enter into a production sharing agreement for PNGF Bis and commencing drilling;
• (d) rejuvenating the OML 113 partnership and Aje development plan;
• (e) pursuing other acquisition and/or joint venture opportunities that have a strategic fit for the Company; and
• (f) growing the Company into a leading exploration and production company with an aspirational target of 30,000 boepd net production by 2023.
• 1.13 Plans for the Company if completion of the Proposed Transaction does not occur

If Resolution 1 is not passed and the Proposed Transaction is not completed, the Company will continue to progress the Project under the current ownership structure and otherwise pursue the strategic objectives noted in Section 1.12 above.

1.14 Directors' interests in the Proposed Transaction

None of the Directors has any interest in Resolution 1.

1.15 Forward looking statements

The forward-looking statements in this Explanatory Statement are based on the Company's current expectations about future events. However, they are subject to known and unknown risks, uncertainties and assumptions, many of which are outside the control of the Company and the Directors, which could cause actual results, performance or achievements to differ materially from future results, performance or achievements expressed or implied by the forward-looking statements in this Explanatory Statement. Forward looking statements include those containing words such as 'anticipate', 'estimates', 'should', 'will', 'expects', 'plans' or similar expressions.

1.16 Indicative timetable

The Company anticipates the Proposed Transaction will be implemented in accordance with the following timetable:

Event	Date
Launch of Capital Raising	11 March 2021
Settlement of Tranche 1 Capital Raising	18 March 2021
General Meeting to approve the Proposed Transaction	30 April 2021
Settlement of Tranche 2a and 2b Capital Raising	3 May 2021
Completion of the Proposed Transaction1	3 May 2021

Notes

• 1. Completion of the Proposed Transaction is subject to the satisfaction of the conditions precedent set out in Section 1.6.
• 2. RESOLUTION 1 – APPROVAL OF PROPOSED TRANSACTION AND ISSUE OF SYMERO CONSIDERATION SHARES
• 2.1 General

As set out in Section 1.1, the Company has agreed, subject to obtaining Shareholder approval, to issue 138,763,636 Symero Consideration Shares to Symero (or its nominee) in consideration for the Proposed Transaction.

2.2 Chapter 2E of the Corporations Act

Chapter 2E of the Corporations Act requires that for a public company, or an entity that the public company controls, to give a financial benefit to a related party of the public company, the public company or entity must:

• (a) obtain the approval of the public company's members in the manner set out in sections 217 to 227 of the Corporations Act; and
• (b) give the benefit within 15 months following such approval,

unless the giving of the financial benefit falls within an exception set out in sections 210 to 216 of the Corporations Act.

The issue of the Symero Consideration Shares to Symero constitutes giving a financial benefit.

The Proposed Transaction is considered by the Board to be a related party transaction requiring Shareholder approval in terms of Chapter 2E of the Corporations Act because Symero is the subsidiary of Nor Energy AS, the second largest shareholder in the Company (13.59%) and an entity controlled by Knut Søvold and Gerhard Ludvigsen. Messrs Søvold and Ludvigen are related parties of the Company by virtue of being the Chief Executive Officer and a former Director of the Company, respectively (Related Parties).

Due to the structural complexity and interrelated elements to the Proposed Transaction, the Directors resolved to seek Shareholder approval for the issue of the Symero Consideration Shares in accordance with Chapter 2E of the Corporations Act.

In addition, the Directors have commissioned Stantons International Securities to prepare an independent expert's report for the purpose of assessing the fairness and reasonableness of the transaction the subject of Resolution 1. A copy of this report is annexed to this Notice at Schedule 2.

2.3 Technical information required by section 219 of the Corporations Act

Pursuant to and in accordance with the requirements of section 219 of the Corporations Act, the following information is provided in relation to Resolution 1:

• (a) the Symero Consideration Shares will be issued to Symero (or its nominee), which is a related party of the Company for the reasons set out in Section 2.2;
• (b) the number of Symero Consideration Shares to be issued to Symero (being the nature of the financial benefit proposed to be given) is 138,763,636;
• (c) the Symero Consideration Shares issued will be fully paid ordinary shares in the capital of the Company issued on the same terms and conditions as the Company's existing Shares;
• (d) it is not considered that there are any significant opportunity costs to the Company or benefits foregone by the Company in issuing the Symero Consideration Shares on the terms proposed;
• (e) the Symero Consideration Shares are being issued at a deemed issue price of NOK 1.10 per Share;
• (f) the Company does not consider that there are any significant opportunity costs to the Company or benefits foregone by the Company in issuing the Symero Consideration Shares upon the terms proposed;
• (g) the total remuneration packages for each of the Related Parties for the previous financial year and the proposed total remuneration package for the current financial year are as follows:

• (i) Knut Søvold:

  • (A) 2020 Financial Year (Actual): Company subsidiary salary of NOK 2,170,000 plus non-executive director fees for Company subsidiary of USD\$60,000; and
  • (B) 2021 Financial Year (Proposed): Company subsidiary salary of NOK 1,860,000 plus non-executive directors fees for Company subsidiary of USD\$60,000,

• (ii) Gerhard Ludvigsen:

• (A) 2020 Financial Year (Actual): Company subsdiary salary of NOK 2,170,000 plus non-executive director fees for Company subsidiary of USD\$60,000; and
• (B) 2021 Financial Year (Proposed): Company subsidiary salary of NOK 155,000 plus non-executive directors fees for Company subsidiary of USD\$5,000 for January, being the period in which he remained a Director, and now receives NOK 200,000 per month for 6 months for consultancy services provided to the Company.
• (h) the Symero Consideration Shares will be issued for nil cash consideration, as such no funds will be raised from the issue of the Symero Consideration Shares;
• (i) no loans are being made to the Related Parties in connection with the acquisition of the Symero Consideration Shares;
• (j) the relevant interests of the Related Parties in securities of the Company as at the date of this Notice are set out below:

Related Party	Shares1	Options	Performance Rights
Knut Søvold control through:
Gulshagan III AS	45,000,000	Nli	Nil
Gulshagan IV AS	45,000,000	Nil	Nil
Gerhard Ludvigsen control / influence through:
Pust For Livet AS	15,000,000	Nil	Nil
Ambolt Invest AS	45,000,000	Nil	Nil
Lenger Nedi Hagan AS	45,000,000	Nil	Nil
Knut Søvold and Gerhard Luvigsen joint control through:
NOR Energy AS	143,555,857	Nil	Nil

Notes:

1. Fully paid ordinary shares in the capital of the Company.

(k) Upon issue, the Symero Consideration Shares will dilute the shareholding of existing Shareholders would be diluted by approximately 11.6%;

(l) the trading history of the Shares on Euronext Expand in the 12 months before the date of this Notice is set out below:

	Price	Date
Highest	1.638	20 October 2020
Lowest	0.53	30 March 2020
Last	1.144	25 March 2021

(m) None of the current Board members have a material personal interest in the outcome of Resolution 1;

All of the Directors are of the opinion that the Proposed Transaction is in the best interests of Shareholders for the reasons set out in Sections 10.3 to 10.6 of the Independent Expert's Report and, accordingly, the Directors unanimously recommend that Shareholders vote in favour of Resolution 1; and

(n) Shareholders should carefully consider the report prepared by the Independent Expert for the purposes of the Shareholder approval required under Chapter 2E of the Corporations Act. The Independent Expert's Report (annexed at Schedule 2 to this Notice) comments on the fairness and reasonableness of the transaction the subject of Resolution 1 to the nonassociated Shareholders in the Company. The Board is not aware of any other information that is reasonably required by Shareholders to allow them to decide whether it is in the best interests of the Company to pass Resolution 1.

3. RESOLUTION 2 – ELECTION OF DIRECTOR – MS GRO KIELLAND

3.1 General

The Constitution allows the Directors to appoint at any time a person to be a Director either to fill a casual vacancy or as an addition to the existing Directors, but only where the total number of Directors does not at any time exceed the maximum number specified by the Constitution.

Pursuant to the Constitution, any Director so appointed holds office only until the next following general meeting and is then eligible for election by Shareholders.

Mrs Gro Kielland, having been appointed by other Directors on 1 February 2021 in accordance with clause 13.4 of the Constitution, will retire in accordance with clause 13.4 of the Constitution and being eligible, seeks election from Shareholders.

3.2 Biography

Ms Kielland has over 30 years of experience having held a number of leading positions in the oil and gas industry both in Norway and abroad, among others as CEO of BP Norway. Her professional experience includes work related to both operations and field development, as well as HSE. Mrs. Kielland holds an MSc in Mechanical Engineering from the Norwegian University of Science and Technology (NTNU).

3.3 Board recommendation

The Board supports the re-election of Ms Kielland and recommends that Shareholders vote in favour of Resolution 2.

GLOSSARY

\$ means Australian dollars.

ASIC means the Australian Securities & Investments Commission.

ASX means ASX Limited (ACN 008 624 691) or the financial market operated by ASX Limited, as the context requires.

Board means the current board of directors of the Company.

Business Day means Monday to Friday inclusive, except New Year's Day, Good Friday, Easter Monday, Christmas Day, Boxing Day, and any other day that ASX declares is not a business day.

Chair means the chair of the Meeting.

Closely Related Party of a member of the Key Management Personnel means:

• (a) a spouse or child of the member;
• (b) a child of the member's spouse;
• (c) a dependent of the member or the member's spouse;
• (d) anyone else who is one of the member's family and may be expected to influence the member, or be influenced by the member, in the member's dealing with the entity;
• (e) a company the member controls; or
• (f) a person prescribed by the Corporations Regulations 2001 (Cth) for the purposes of the definition of 'closely related party' in the Corporations Act.

Company means PetroNor E&P Limited (ACN 125 419 730).

Constitution means the Company's constitution.

Corporations Act means the Corporations Act 2001 (Cth).

Directors means the current directors of the Company.

Explanatory Statement means the explanatory statement accompanying the Notice.

General Meeting or Meeting means the meeting convened by the Notice.

HAH means Hemla Africa Holding AS.

Key Management Personnel has the same meaning as in the accounting standards issued by the Australian Accounting Standards Board and means those persons having authority and responsibility for planning, directing and controlling the activities of the Company, or if the Company is part of a consolidated entity, of the consolidated entity, directly or indirectly, including any director (whether executive or otherwise) of the Company, or if the Company is part of a consolidated entity, of an entity within the consolidated group.

NOR Group means the following parties:

• (a) NOR Energy AS;
• (b) Symero;
• (c) Gulshagan III AS;
• (d) Gulshagan IV AS;
• (e) Pust For Livet AS;
• (f) Ambolt Invest AS; and
• (g) Lenger Nedi Hagan AS.

NOR Group member means a member of the NOR Group.

Notice or Notice of Meeting means this notice of meeting including the Explanatory Statement and the Proxy Form.

Proxy Form means the proxy form accompanying the Notice.

Related Parties means Messrs Gerhard Ludvigsen and Knut Søvold.

Resolution means a resolution set out in the Notice, or any one of them, as the context requires.

Section means a section of the Explanatory Statement.

Share means a fully paid ordinary share in the capital of the Company.

Shareholder means a registered holder of a Share.

Symero means Symero Limited.

WST means Western Standard Time as observed in Perth, Western Australia.

PROXY VOTE INSTRUCTION

PetroNor E&P Limited (the "Company")

Proxy Solicited for General Meeting 4 May 2021

As you are not recorded in the Company Register of Members maintained by Computershare in Australia in which the Company is incorporated, any voting at the Company's General Meeting, or alternatively issue of a proxy will have to be executed via DNB Bank ASA ("DNB").

The undersigned hereby authorize DNB to constitute and appoint the Chair of the meeting, or failing the Chair of the meeting, any individual appointed by the Chair of the meeting, as his or her true and lawful agent and proxy, to represent the undersigned at the General Meeting of Shareholders of the Company to be held at the offices of Steinepreis Paganin, Level 4, 16 Milligan Street, Perth, Western Australia, on 4 May 2021 at 2.00pm (local time), for the purposes set forth below and in the Notice of General Meeting issued by the Company.

X	Please mark your votes as in this example.
Resolutions	FOR	AGAINST	ABSTAIN
1. Approval of Proposed Transaction and issue of Symero Consideration Shares
2. Election of Director – Ms Gro Kielland

Signature(s) Date:

Note: Please sign exactly as name appears below, joint owners should each sign. When signing as attorney, executor, administrator or guardian, please give full title as such.

Name of shareholder in block letters:

Please return your completed and signed proxy, to be received by DNB Bank ASA on or prior to 27 April 2021, 17:00 hours Oslo, preferably by way of e-mail to email address: vote@dnb.no or by ordinary mail to DNB Bank ASA, Registrars Dept., P.O. Box 1600 Sentrum, 0021 Oslo, Norway, or if delivery by hand to: DNB Bank ASA, Registrars Dept., attn.: K. G. Berg, Dronning Eufemias gate 30, 0191 Oslo, Norway.

SCHEDULE 1 – PRO - FORMA CONSOLIDATED STATEMENT OF FINANCIAL POSITION

USD'000	As at 31 December 2020	Pro forma adjustments	Pro forma As at 31 December 2020	As at 31 December 2019
	(Unaudited)	(Unaudited)	(Unaudited)	(Audited)
Assets
Current assets
Inventories	3,578		3,578	3,233
Trade and other receivables	30,976		30,976	24,772
Cash and cash equivalents	14,121 48,675	28,894 28,894	43,015 77,569	27,891 55,896
Non-current assets
Property, plant and equipment	23,647	-	23,647	22,587
Intangible assets	6,935	-	6,935	4,691
	30,582	-	-	27,278
Total assets	79,257	28,894	108,151	83,174
Liabilities Current liabilities Trade and other payables	22,922	-	22,922	34,602
Loans and borrowings	4,000	-	4,000	12,941
Non-current liabilities Loans and borrowings Provisions	26,922 14,912 15,307	- - -	26,922 14,912 15,307	47,543 - 14,373
	30,219	-	30,219	14,373
Total liabilities	57,141	-	57,141	61,916
NET ASSETS	22,116	28,894	51,010	21,258
Issued capital and reserves attributable to owners of the parent Share capital	17,735	47,254	64,629	17,735
Foreign currency translation reserve	(995)	-	(995)	-
Retained earnings	(8,880)	(13,542)	(22,422)	(11,226)
	7,860	33,712	41,572	6,509
Non-controlling interests	14,256	(4,818)	9,438	14,749
TOTAL EQUITY	22,116	28,894	51,010	21,258

The pro forma consolidated statement of financial position (the "Pro forma") has been prepared using the most recently available interim financial statements for the Company for the period ended 31 December 2020.

The Pro-forma assumes that the Proposed Transaction, and issues of all Shares contemplated by this Notice (Capital Raising and Repair Offer) successfully completed on 31 December 2020.

The historical and pro-forma information is presented in an abbreviated form, insofar as it does not include all of the disclosure required by the Australian Accounting Standards applicable to annual financial statements.

Pro forma adjustments

USD'000		Debit	Credit
Cash and cash equivalents		28,894
Retained earnings Symero consideration Less: HAH NCI Capital raising costs (2a)	18,000 (4,818) 13,182 360 13,542	13,542
Non-controlling interests		4,818
Share capital Tranche 1 Tranch 2a Tranche 2b Repair Offer Capital raising costs (1&2b)	10,943 18,000 11,151 7,783 (623) 47,254		(47,254)

The Capital Raising and Repair Offer will generate USD 28.9 million after deduction of capital raising costs. These costs will be considered part of equity and capitalised with the shares issued.

The USD 18.0 million consideration for the Proposed Transaction exceeds the book value of the net assets for the non-controlling interest ("NCI") of HAH acquired. As the Company already controls HAH, AASB 10 requires the fair value adjustments for the acqusition to be recognised within equity, and the NCI for HAH needs to be removed from the consolidated figures for the Company. The costs associated with the Proposed Transaction cannot be capitalised and have been expensed within retained earnings.

PO Box 1908 West Perth WA 6872 Australia

Level 2, 1 Walker Avenue West Perth WA 6005 Australia

Tel: +61 8 9481 3188 Fax: +61 8 9321 1204

ABN: 42 128 908 289 AFS Licence No: 448697 www.stantons.com.au

31 March 2021

The Independent Directors Petronor E&P Limited 48 Dover Street London W1S 4FF UNITED KINGDOM

Dear Directors,

Independent Expert's Report for Petronor E&P Limited Relating to Proposed Related Party Transaction

1 Executive Summary

Opinion

1.1 In our opinion, the proposed transaction outlined in Resolution 1 of the Notice of Meeting ("NoM") involving the issue of 138,763,636 ordinary shares in Petronor E&P Limited ("Petronor" or the "Company") to Symero Limited ("Symero"), which provides a financial benefit to related parties, is considered FAIR and REASONABLE to the non-associated shareholders of Petronor as at the date of this report.

Introduction

• 1.2 Stantons International Securities Pty Ltd ("SIS") were engaged by the independent directors of Petronor to prepare an Independent Expert's Report ("IER") to determine the fairness and reasonableness of the proposal outlined in Resolution 1 of the attached NoM and Explanatory Statement ("ES"). The NoM will be released ahead of a general meeting of Petronor shareholders to be held in or around April 2021 (the "Meeting").
• 1.3 Petronor is an Australian public company that is headquartered in London, United Kingdom and listed on Oslo Euronext Expand (formerly Oslo Axess), a market controlled by the Oslo Stock Exchange for the purpose of listing small companies ("Oslo Expand"). The Company's primary operations are offshore oil and gas exploration and production across five West African countries. The Company was known as African Petroleum Corporation Limited ("African Petroleum") prior to 30 August 2019.
• 1.4 Petronor owns a 70.707% interest in its subsidiary Hemla Africa Holdings AS ("HAH"), which holds an interest in several petroleum production licenses in the Republic of Congo ("Congo"). The remaining 29.293% of HAH is owned by Symero, which is controlled by NOR Energy AS, an entity owned by Mr Knut Søvold ("Søvold") and Mr Gerhard Ludvigsen ("Ludvigsen"). Søvold is the Chief Executive Officer of Petronor and Ludvigsen is a former Executive Director of Petronor.
• 1.5 Petronor is proposing, subject to shareholder approval for Resolution 1, to acquire Symero's interest in HAH via the issue of ordinary shares in Petronor.

• 1.6 The proposed acquisition comprises the following (the "Acquisition"):

• i) Petronor will acquire 29,293 ordinary shares in HAH from Symero, increasing its interest in HAH to 100%; and

• ii) Petronor will issue 138,763,636 ordinary shares to Symero at a deemed issue price of NOK1.10 (the equivalent price of a concurrent equity raising) or approximately US\$0.1297. The number of shares issued was determined based on fixed consideration of US\$18 million and an exchange rate of NOK/US\$8.48.
• 1.7 A condition precedent to the Acquisition is for the Company to complete an equity raising up to US\$65,000,000, before costs ("Equity Raising Condition").
• 1.8 To satisfy the Equity Raising Condition, Petronor proposed raising approximately US\$40.1 million, including a private placement of approximately US\$22.1 million. We note that the US\$18 million of shares issued to Symero is considered part of the equity raising by the Company. The first tranche of the private placement was completed on 15 March 2021 and raised approximately US\$10.94 million ("Tranche 1 Placement"). A second tranche to raise approximately US\$11.16 million conditional on the Acquisition, is already subscribed for by Petronor's major shareholder, Petromal Sole Proprietorship LLC ("Petromal") (the "Tranche 2b Placement").
• 1.9 Collectively, the proposed Acquisition and Tranche 2b Placement are referred to as the "Transaction" throughout this IER.

Purpose

• 1.10 Chapter 2E ("Chapter 2E") of the Corporations Act 2001 Cth ("Corporations Act") requires a public company to obtain the approval of members when giving a financial benefit to related parties unless an exception applies.
• 1.11 As Søvold is a senior executive of Petronor and Ludvigsen a former director (together the "Related Parties"), they are considered related parties of the Company for the purpose of Chapter 2E of the Corporations Act.
• 1.12 The issue of securities pursuant to the Transaction would constitute giving a financial benefit to the Related Parties.
• 1.13 Accordingly, Petronor intends to seek approval at the Meeting from the shareholders who are not restricted from voting on the proposal (the "Non-Associated Shareholders") for Resolution 1 pursuant to Chapter 2E of the Corporations Act.
• 1.14 The proposed Transaction will be referred to in the NoM and ES to be forwarded to shareholders ahead of the Meeting. This IER provides an opinion on the fairness and reasonableness of the Transaction to Non-Associated Shareholders and will be attached to the NoM.

Basis of Evaluation

• 1.15 With regard to the Australian Securities and Investments Commission ("ASIC") Regulatory Guide 111: Content of Expert Reports ("RG111"), we have assessed the Transaction (pursuant to Resolution 1) as:
• fair if the value of the financial benefit to be provided by Petronor to the related parties is equal to or less than the value of the consideration received by Petronor; and
• reasonable if it is fair, or if despite not being fair there are sufficient reasons for Non-Associated Shareholders to accept the offer.

Assessment

Petronor Share Value Prior to the Transaction

1.16 We assessed the fair market value of a Petronor ordinary share prior to the Transaction using a net assets-based methodology. Quoted market prices were considered as a secondary methodology, though did not alter our assessed valuation due to the low liquidity of Petronor ordinary shares traded on Oslo Expand (refer to Paragraph 7.40).

• 1.17 SIS engaged ResourceInvest Pty Ltd ("ResourceInvest") as a technical specialist to provide fair market valuations for the oil and gas interests of Petronor and HAH to support our assessment. We have relied on the valuations provided by ResourceInvest in their report contained in Appendix E (the "ResourceInvest Report") in forming our opinion.
• 1.18 Our Net Assets methodology assessed the fair market value of a Petronor ordinary share as at 26 March 2021, as follows:

Table 1. Net Asset Valuation of Petronor Shares Prior to Transaction

	Ref	Low	Preferred	High
Petronor hydrocarbon interests (US\$)	Table 23	173,000,000	196,600,000	233,300,000
Add: other net assets (US\$)	Table 20	(5,897,010)	(5,897,010)	(5,897,010)
Total net assets (US\$)		167,102,990	190,702,990	227,402,990
Less: outstanding option value (US\$)	Table 32	(1,025)	(1,025)	(1,025)
Value to ordinary shareholders (US\$)		167,101,964	190,701,964	227,401,964
Number of shares outstanding	Table 15	1,056,028,924	1,056,028,924	1,056,028,924
Petronor value per share (US\$) (control)		0.1582	0.1806	0.2153
Discount for minority interest (%)	7.33	23.1%	23.1%	23.1%
Petronor value per share (US\$) (minority interest)		0.1217	0.1389	0.1656

Source: SIS analysis

1.19 Accordingly, we assessed the fair value of a Petronor ordinary share prior to the Transaction, on a minority interest basis, to be between US\$0.1217 and US\$0.1656, with a preferred value of US\$0.1389.

HAH Valuation

1.20 We assessed the value of an HAH share using a net assets-based methodology. Since HAH owns an indirect interest in the Congo assets through its ownership of HEPCO shares, we assessed the value of a HEPCO share using the values ascribed in the ResourceInvest Report. Our assessed value of a HEPCO share is as follows.

Table 2. HEPCO Net Assets Valuation

	Ref	Low	Preferred	High
20% interest in PNGF Sud (US\$)	Table 36	197,815,324	212,269,120	226,722,916
28% interest in PNGF Bis (US\$)	Table 36	23,193,301	25,210,109	27,394,985
Add: other net assets (US\$)	Table 37	(1,505,695)	(1,505,695)	(1,505,695)
Total net assets (US\$)		219,502,929	235,973,534	252,612,206
Number of shares outstanding	5.6	100,000	100,000	100,000
HAH value per share (US\$) (control)		2,195.03	2,359.74	2,526.12

Source: SIS analysis

1.21 Accordingly, the Net Assets valuation of a HAH share is as follows.

Table 3. HAH Net Assets Valuation

	Ref	Low	Preferred	High
Value of a HEPCO share (US\$)	Table 38	2,195	2,360	2,526
Number of HEPCO shares	5.6	84,150	84,150	84,150
Value of investment in HEPCO (US\$)		184,711,715	198,571,729	212,573,171
Add: other net assets (US\$)	Table 39	11,515,478	11,515,478	11,515,478
Total net assets (US\$)		196,313,538	210,173,717	224,175,326
Number of shares outstanding	Table 17	100,000	100,000	100,000
HAH value per share (US\$) (control)		1,963.14	2,101.74	2,241.75
Discount for minority interest (%)	9.7	23.1%	23.1%	23.1%
HAH value per share (US\$) (minority interest)		1510.10	1616.72	1724.43

Source: SIS analysis

Fairness Assessment

1.22 Our fairness assessment of the Transaction (incorporating Resolution 1) is as set out below. Further details on the methodology and material assumptions are available in Section 9.

Table 4. Fairness Evaluation

	Ref	Low	Preferred	High
Value received by Petronor (US\$)	Table 43	54,424,047	57,547,172	60,702,165
Consideration paid by Petronor (US\$)	Table 43	27,353,832	31,217,044	37,224,667
Premium/(discount) (US\$)		27,070,215	26,330,127	23,477,498
Fairness		Fair	Fair	Fair

Source: SIS analysis

Figure 1. Transaction Fairness Evaluation

Source: SIS analysis

1.23 As the value received by Petronor is greater than the value of the consideration paid under each of the low, preferred and high cases, we consider Resolution 1 of the NoM, to be FAIR to the Non-Associated Shareholders for the purpose of Chapter 2E of the Corporations Act.

Reasonableness Assessment

1.24 As the Transaction (including Resolution 1) is considered fair, under RG111.12 it is also considered reasonable. For informative purposes, we also considered the following likely advantages and disadvantages of the proposed Transaction to Non-Associated Shareholders.

Table 5. Reasonableness Assessment of Transaction

Advantages	Disadvantages
▪ The Transaction is fair	▪ Dilution of existing shareholders
▪ The Company will increase its interest in its Congo based assets
▪ Simplifies ownership structure
▪ Facilitates completion of Placement Tranche 2b which will raise approximately US\$11.16 million (before costs)

Source: SIS analysis

Conclusion

• 1.25 In our opinion, the Transaction proposal subject to Resolution 1 is FAIR and REASONABLE to the Non-Associated Shareholders of Petronor.
• 1.26 This opinion must be read in conjunction with the more detailed analysis included in this report, together with the disclosures, Financial Services Guide, and appendices to this report.

Financial Services Guide

Dated 31 March 2021

Stantons International Securities Pty Ltd (Trading as Stantons International Securities)

Stantons International Securities Pty Ltd (ABN 42 128 908 289 and AFSL Licence No 448697) ("SIS" or "we" or "us" or "ours" as appropriate) has been engaged to issue general financial product advice in the form of a report to be provided to you.

Financial Services Guide

In the above circumstances, we are required to issue to you, as a retail client, a Financial Services Guide ("FSG"). This FSG is designed to help retail clients make a decision as to their use of the general financial product advice and to ensure that we comply with our obligations as financial services licensees.

This FSG includes information about:

• a) who we are and how we can be contacted;
• b) the services we are authorized to provide under our Australian Financial Services Licence, Licence No: 448697;
• c) remuneration that we and/or our staff and any associates receive in connection with the general financial product advice;
• d) any relevant associations or relationships we have; and
• e) our complaints handling procedures and how you may access them.

Financial services we are licensed to provide

We hold an Australian Financial Services Licence which authorises us to provide financial product advice in relation to:

▪ Securities (such as shares, options and debt instruments)

We provide financial product advice by virtue of an engagement to issue a report in connection with a financial product of another person. Our report will include a description of the circumstances of our engagement and identify the person who has engaged us. You will not have engaged us directly but will be provided with a copy of the report as a retail client because of your connection to the matters in respect of which we have been engaged to report.

Any report we provide is provided on our own behalf as a financial services licensee authorised to provide the financial product advice contained in the report.

General Financial Product Advice

In our report, we provide general financial product advice, not personal financial product advice, because it has been prepared without considering your personal objectives, financial situation or needs. You should consider the appropriateness of this general advice having regard to your own objectives, financial situation and needs before you act on the advice. Where the advice relates to the acquisition or possible acquisition of a financial product, you should also obtain a product disclosure statement relating to the product and consider that statement before making any decision about whether to acquire the product. Where you do not understand the matters contained in the Independent Expert's Report, you should seek advice from a registered financial adviser.

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SIS is ultimately a wholly owned subsidiary of Stantons International Audit and Consulting Pty Ltd a professional advisory and accounting practice. From time to time, SIS and Stantons International Audit and Consulting Pty Ltd (that trades as Stantons International) and/or their related entities may provide professional services, including audit, accounting and financial advisory services, to financial product issuers in the ordinary course of its business.

Complaints resolution

Internal complaints resolution process

As the holder of an Australian Financial Services Licence, we are required to have a system for handling complaints from persons to whom we provide financial product advice. All complaints must be in writing, addressed to:

The Complaints Officer Stantons International Securities Pty Ltd Level 2 1 Walker Avenue WEST PERTH WA 6005

When we receive a written complaint, we will record the complaint, acknowledge receipt of the complaints within 10 days and investigate the issues raised. As soon as practical, and not more than 45 days after receiving the written complaint, we will advise the complainant in writing of our determination.

Referral to External Dispute Resolution Scheme

A complainant not satisfied with the outcome of the above process, or our determination, has the right to refer the matter to the Australian Financial Complaints Authority ("AFCA"). AFCA has been established to provide free advice and assistance to consumers to help in resolving complaints relating to the financial services industry.

Further details about AFCA are available at the AFCA website www.afca.org.au or by contacting them directly via the details set out below.

Australian Financial Complaints Authority Limited GPO Box 3 MELBOURNE VIC 3001

Telephone: 1800 931 678

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Contact details

You may contact us using the details set out at above or by phoning (08) 9481 3188 or faxing (08) 9321 1204.

1	Executive Summary1
2	Summary of Transaction10
3	Scope13
4	Profile of Petronor15
5	Profile of HAH 23
6	Valuation Methodology 26
7	Valuation of Petronor Shares 27
8	Valuation of HAH Shares 38
9	Fairness Evaluation41
10	Reasonableness Evaluation 44
11	Opinions 45
12	Other Considerations45
13	Shareholders Decision45
14	Source Information45

2 Summary of Transaction

Background

2.1 Petronor currently holds a 70.707% interest in HAH, a holding company for Petronor's Congo based assets. On 18 February 2021, Petronor announced its intention to acquire the remaining 29.293% interest in HAH from Symero under a Share Purchase Agreement ("Share Purchase Agreement") entered into on 17 February 2021.

Proposed Transaction

• 2.2 Pursuant to the Share Purchase Agreement, Petronor is seeking approval for the issue of ordinary shares resulting from the Acquisition. The key terms of the proposed Acquisition are:
• Petronor to increase its interest in HAH to 100% via the acquisition of the remaining 29,293 ordinary shares from Symero.
• Symero will be issued 138,763,636¹ ordinary shares in Petronor, based on total consideration of NOK152.6 million (US\$18 million) and a deemed issue price of NOK1.10 (US\$0.1297 at the fixed exchange rate in the Share Purchase Agreement).
• 2.3 The Share Purchase Agreement also contains conditions precedent as follows:
• The Equity Raising Condition, requiring completion of an equity raising of up to US\$65 million.
• All required approvals being obtained for completion of the Transaction, including for Resolution 1 of the NoM.
• 2.4 In satisfaction of the Equity Raising Condition, the Company proposes to undertake an equity raising of approximately US\$40.1 million including US\$22.1 million via a private placement (the "Placement"), and the US\$18 million of shares proposed to be issued under the Acquisition. Arctic Securities AS, Pareto Securities AS and SpareBank1 Markets AS have been appointed joint managers and bookrunners. Petronor's largest shareholder, Petromal and related group companies, representing a shareholding of 38.28% of Petronor, has subscribed for its pro rata share of the Placement.
• 2.5 On 15 March 2020, the Company completed the Tranche 1 Placement involving the issue of 84,363,636 ordinary shares at an offer price of NOK1.10 to existing and new investors. Tranche 1 Placement raised gross proceeds of NOK92.8 million (approximately US\$10.94 million² ). Petromal and its related group companies received 31,975,454 ordinary shares for NOK35.2 million, being their approximate pro rata share³ of the amount raised under Tranche 1 Placement. As Tranche 1 Placement has already occurred and was not dependent on completion of the Transaction, we included it in the pre-Transaction position of Petronor for the valuation purpose.
• 2.6 As the issue of ordinary shares to Symero pursuant to the Transaction would dilute the interest of Petromal, Placement Tranche 2b is proposed concurrent to Transaction in order to maintain Petromal's 38.28% interest in Petronor. Placement Tranche 2b will comprise the issue of 85,963,636 ordinary shares to Petromal at an issue price of NOK1.10. Placement Tranche 2b will raise NOK94.6 million, or approximately US\$11.16 million in cash (before costs).
• 2.7 We note that the Company is considering a further offer subsequent to the Transaction of 60,000,000 new shares at a subscription price of NOK1.10, to raise NOK66 million ("Subsequent Offering"). The Subsequent Offering will be directed to existing shareholders of the Company who were not invited to subscribe for shares in the Placement, were not allocated shares in the Placement, and are not resident in a jurisdiction that would require the issue of a prospectus (including Australia). Symero, NOR Energy AS, and any other entities controlled by Søvold and Ludvigsen (or related parties) directly or indirectly, will not be eligible to participate in the

¹ The number of shares was determined based on fixed consideration of US\$18 million and an exchange rate of NOK/US\$8.48 ² Based on the NOK/US\$ exchange rate at the time of completion

³ We note that Petromal was allocated 37.90% under the Tranche 1 Placement due to an error in foreign exchange calculation. This will be corrected (to 38.28%) under the Tranche 2b Placement.

Subsequent Offering. As the Subsequent Offering is not interdependent with the Acquisition, for the purpose of the IER we do not consider it to be included as a component of the Transaction on which we are providing an opinion.

2.8 The potential impact on the capital structure of Petronor should the proposed Transaction complete is presented below.

Table 6. Capital Structure Impact of Transaction

Transaction	Number	Post Transaction Interest (%)
Ordinary shares on issue before private placement	971,665,288	75.87
Tranche 1 Placement	84,363,636	6.59
Total pre-Transaction ordinary shares	1,056,028,924	82.45
Transaction
Shares issued to Symero	138,763,636	10.83
Tranche 2b Placement	85,963,636	6.71
Total Transaction shares issued	224,727,272	17.55
Total post-Transaction ordinary shares	1,280,756,196	100.00

Source: SIS analysis

• 2.9 In addition, we note that there are currently 1,389,470 unlisted options on issue. All options are currently out of the money.
• 2.10 As a result of the Company's acquisition of the outstanding shares in its subsidiary, HAH, from minority shareholder Symero, Petronor will increase its indirect economic interest in the Congo based oil and gas assets held by HAH, comprising the Tchibouela II, Tchendo II and Tchibeli-Litanzi II licences (collectively "PNGF Sud") and an adjacent licence ("PNGF Bis").
• 2.11 We note that separate to the Transaction, the Tribunal de Commerce de Pointe Noire in Congo awarded HAH 9,900 shares (a 9.9% increase in interest) in its subsidiary Hemla E&P Congo SA ("HEPCO") in a recent court ruling ("MGI Ruling"). The MGI Ruling is related to the breach of a debt covenant by MGI International SA ("MGI"), the minority partner in HEPCO. The Company considers the shares have been transferred from MGI to HAH as they were registered at the Business Register in Congo on 25 January 2021, though we note MGI retains the right to appeal to a higher court. For the purpose of this IER, we assumed that HAH are entitled to these shares.
• 2.12 The change in Petronor's interest in the Congo assets resulting from the Transaction is as set out below.

Table 7. Petronor Congo Assets Ownership Structure

	Original Petronor	Petronor Interest After	Post Transaction
Structure	Interest (%)	MGI Ruling (%)	(%)
Petronor	100.000	100.000	100.000
HAH	70.707	70.707	100.000
Petronor net interest in HAH	70.707	70.707	100.000
HAH interest in Hemla E&P Congo SA ("HEPCO")	74.250	84.150	84.150
Petronor net interest in HEPCO	52.500	59.500	84.150
HEPCO interest in PNGF Sud (20% HEPCO interest)	20.000	20.000	20.000
HEPCO interest in PNGF Bis (28%)	28.000	28.000	28.000
Petronor net interest in PNGF Sud	10.500	11.900	16.830
Petronor net interest in PNGF Bis	14.700	16.660	23.562

Source: SIS analysis

2.13 The ownership structure of the Congo assets is as set out below.

Figure 2. Congo Asset Ownership Structure

Source: SIS analysis, Petronor Announcements

3 Scope

Purpose of the Report

Chapter 2E

• 3.1 As Søvold is a senior executive and Ludvigsen a former Director of Petronor, they are considered related parties of the Company for the purpose of Chapter 2E of the Corporations Act.
• 3.2 The issue of securities resulting from the Transaction would constitute giving a financial benefit to the Related Parties.
• 3.3 Chapter 2E of the Corporations Act requires a public company to obtain the approval of members when giving a financial benefit to related parties unless an exception applies.
• 3.4 ASIC's Regulatory Guide 76: Related Parties Transactions ("RG76") requires meeting materials seeking approval for related party transactions to provide sufficient information to enable them to decide whether or not the financial benefit to be given to a related party is in the interests of the entity.
• 3.5 To ensure that members are provided with sufficient information to assess a proposed related party transaction and decide how to vote, it may be necessary for entities to include a valuation from an independent expert with a notice of meeting for member approval under Chapter 2E where:
• a financial benefit is difficult to value;
• the transaction is significant from the point of view of the entity; or
• the non-interested directors do not have the expertise or resources to provide independent advice to members of the financial benefit.
• 3.6 As per RG 76.109, companies are encouraged to obtain an independent expert report to send to members accompanying the explanatory material in the above cases. Given the size of the Transaction, it is reasonable to consider it significant from the point of view of the entity.

Purpose

• 3.7 Accordingly, Petronor intends to seek approval from the Non-Associated Shareholders at a general meeting expected to be held in or around April 2021, for Resolution 1 of the NoM, pursuant to Chapter 2E of the Corporations Act.
• 3.8 The proposed Transaction will be referred to in the NoM and ES to be forwarded to shareholders ahead of the Meeting. The directors of Petronor have engaged SIS to prepare an IER, to be appended to the NoM, to assess the fairness and reasonableness of the proposal contained in Resolution 1.

Basis of Evaluation

• 3.9 In determining the fairness and reasonableness of the Transaction, we have had regard to the guidelines set out by ASIC's RG111.
• 3.10 RG111 requires a separate assessment of whether a transaction is "fair" and whether it is "reasonable".
• 3.11 We therefore considered the concepts of "fairness" and "reasonableness" separately. The basis of assessment selected and the reasons for that basis are discussed below.
• 3.12 We note that under RG111 the Transaction is not considered to be a control transaction.

Fairness

• 3.13 Under RG111.57, a proposed related party transaction is fair if the value of the financial benefit provided by the entity to the related party is equal to or less than the value of the consideration received by the entity. This comparison should be made assuming a knowledgeable and willing, but not anxious, buyer and a knowledgeable and willing, but not anxious, seller acting at arm's length.
• 3.14 Per RG111.58, where the financial benefit given by the entity is securities in the entity and the consideration is securities in another entity held by the related party, the value of the entity's securities should be compared to the value of the securities it is acquiring.
• 3.15 In valuing the financial benefit given and the consideration received by the entity, an expert should consider all material terms of the proposed transactions.
• 3.16 With regard to the above, we have assessed the Transaction as fair if:
• the value of the financial benefit given by Petronor is less than or equal to;
• the value of the consideration received by Petronor.
• 3.17 The value of a Petronor ordinary share is assessed at fair market value, which is defined by the International Glossary of Business Valuation Terms as:

"The price, expressed in terms of cash equivalents, at which property would change hands between a hypothetical willing and able buyer and a hypothetical willing and able seller, acting at arm's length in an open and unrestricted market, when neither is under compulsion to buy or sell and when both have reasonable knowledge of the relevant facts."

3.18 While RG111 contains no explicit definition of value, we believe the above definition of fair market value is consistent with RG111.11 and common market practice.

Reasonableness

• 3.19 In accordance with RG111.12, we have defined the proposed Transaction as being reasonable if it is fair, or if despite not being fair we believe that there are sufficient reasons for the Non-Associated Shareholders to accept the proposal.
• 3.20 We therefore considered whether the advantages to Non-Associated Shareholders of approving the proposed Transaction outweigh the disadvantages.

Individual Circumstances

3.21 We have evaluated the proposed Transaction for Non-Associated Shareholders generically. We have not considered the effect on the circumstances of individual investors. Due to their personal circumstances, individual investors may place different emphasis on various aspects of the proposed Transaction from those adopted in this report. Accordingly, individuals may reach a different conclusion to ours on whether the proposed Transaction is fair and reasonable. If in doubt, investors should consult an independent financial adviser about the impact of the proposed Transaction on their specific financial circumstances.

4 Profile of Petronor

History and Principal Activities

• 4.1 Petronor is an Australian public company headquarter in London, United Kingdom. The Company is listed on Oslo Expand. Petronor was previously called African Petroleum Corporation Limited and changed its name to Petronor on 30 August 2019 following a reverse acquisition of Petronor E&P (Cyprus) Ltd. The Company has operations in oil and gas exploration and production across five West African countries, including Congo, Senegal, The Gambia, Nigeria and Guinea-Bissau.
• 4.2 As at 31 December 2019 the corporate structure of Petronor included the following entities.

Table 8. Petronor Entities

Company	Country of incorporation	Main country of operations
Petronor E&P Ltd	Australia	UK
Petronor E&P Ltd	Cyprus	Cyprus
Petronor E&P AS	Norway	Norway
Petronor E&P Services Ltd	UK	UK
Petronor E&P Nigeria Ltd	Nigeria	Nigeria
HAH	Norway	Norway
HEPCO	Congo	Congo
African Petroleum Corporation Ltd	UK	UK
Africa Petroleum Corporation Ltd	Cayman Islands	UK
African Petroleum Gambia Ltd	Cayman Islands	The Gambia
African Petroleum Senegal Ltd	Cayman Islands	Senegal
African Petroleum Senegal SAU	Senegal	Senegal
African Petroleum Sierra Leone Ltd	Cayman Islands	Sierra Leone
African Petroleum (SL) Ltd	Sierra Leone	Sierra Leone
APCL Gambia B.V.	Netherlands	The Gambia
European Hydrocarbons Ltd	Cayman Islands	UK

Source: Petronor 2019 Annual Report

Congo

• 4.3 Petronor holds an interest in the PNGF Sud operating licences located in offshore Congo, approximately 25 kilometres off the coast of Pointe-Noire, namely Tchibouela II, Tchendo II, and Tchibeli-Litanzi II. PNGF Sud commenced production in 1987 and produces from 61 wells in five oil fields. Petronor obtained its interest in PNGF Sud indirectly through HEPCO through a tender process with the Congo Ministry of Hydrocarbon. HEPCO was awarded a 20% working interest as of 1 January 2017. HEPCO is a majority owned subsidiary of HAH. Under the agreement, Petronor currently holds a net 11.9% interest in PNGF Sud.
• 4.4 The ownership of the PNGF Sud licences is as follows.

Table 9. PNGF Sud Ownership

Company	Interest (%)
HEPCO (net 10.5% to Petronor)	20
Perenco (operator)	40
SNPC	15
Continent Congo S.A.	10
Africa Oil & Gas Corporation	10
Petro Congo	5

Source: Petronor website

• 4.5 The average production of PNGF Sud during the year 2020 was 22,713 barrels of oil per day ("bopd").
• 4.6 Through an umbrella agreement, the partners in PNGF Sud have the right to negotiate, in good faith, the license terms to enter a Production Sharing Contract ("PSC") for an adjacent license located to the north-west of PNGF Sud, PNGF Bis. Subject to successful completion of the negotiations, Petronor is expected to hold an indirect interest in PNGF Bis of approximately 16.66%. A Competent Person's Report prepared in October 2019 by AGR Petroleum estimated that PNGF Bis contained gross 2C resources of 28.9 MMbbl.
• 4.7 Simultaneous to the announcement of the Transaction, the Company announced that the commercial court Tribunal de Commerce de Pointe Noire of Congo ruled in its favour in relation to an ongoing dispute with MGI. The case related to a breach of covenants by MGI under the loan agreement with HAH. The outcome of the MGI Ruling is that HAH have been awarded 9,900 ordinary shares in HEPCO. As noted at paragraph 2.11, the Company considers the share transfer took place on 25 January 2021 when they were registered in HAH's name at the Business Registrar in Congo. However, it remains possible under Congolese law that the ruling may be challenged in a higher court, and if so the timing and outcome of a further appeal is uncertain. We note that Petronor had a net interest of 10.5% in PNGF Sud and 14.7% in PNGF Bis prior to the MGI Ruling.

Senegal

• 4.8 Petronor holds an 81% interest, through a 90% interest in its subsidiary African Petroleum Senegal Limited, which in turn holds a 90% interest in the Rufisque Offshore Profond ("ROP") and Senegal Offshore Sud Profond ("SOSP") licences. The ROP and SOSP licences cover approximately 14,216 square kilometres in offshore Senegal. The remaining 10% interest is held by Petrosen, the national oil company of Senegal. An assessment in 2015 by independent petroleum consultants, ERC Equipoise, estimated unrisked mean prospective oil resources of approximately 1,779 million stock tank barrels.
• 4.9 Following a dispute with the Government of Senegal over its PSCs for the two licences, the Company registered a request for arbitration proceedings with the International Centre for Settlement of Investment Disputes ("ICSID") on 11 July 2018. An extension of two months to halt arbitration proceedings was agreed on 2 February 2021, and negotiations to reach a solution satisfactory to both parties remain ongoing.

Nigeria

4.10 In 2019, Petronor acquired a 13.1% economic interest in Oil Mining Licence 113 ("OML 113") in the Aje Field, located 24 km offshore the coast near Lagos, Nigeria, through transactions with Panoro Energy ASA ("Panoro") and Yinka Folawiyo Petroleum ("YFP"). Both transactions remain subject to regulatory approval from the Nigerian Department of Petroleum Resources and the consent of the Nigerian Minister of Petroleum Resources. On 31 December 2020, an agreement was made with Panoro to extend the long-stop date on that transaction to 30 June 2021, following delays in the approval process due to the COVID-19 pandemic.

• 4.11 Petronor and YFP have agreed to combine their interests in OML 113 through an incorporated joint venture, Aje Production AS. Petronor will take a 45% interest (with YFP holding the other 55%) in Aje Production AS, a Norwegian based special purpose vehicle ("SPV"). Through the SPV, Petronor will hold its net 13.1% economic interest in OML 113.
• 4.12 Petronor's interest in OML 113 through the SPV is as follows.

Table 10. Aje Production AS SPV Ownership Structure

Company	Interest (%)
Aje Production AS	54.07
Less YFP repayment obligation	25.00
Adjusted Aje Production AS	29.07
YFP (55%)	15.99
Petronor (45%)	13.08

Source: ResourceInvest Report

4.13 Production on OML 113 commenced in 2016 and is generated from 2 wells. As a result of the acquisitions Petronor's interest was approximately 320 bopd in net production for the year 2020. The licence is estimated to contain 138.2 mmboe gross 2P reserves. The SPV will work towards the redevelopment of OML 113 (further details of the planned redevelopment are contained in the ResourceInvest Report). Petronor has engaged with several financial and industrial partners with a target to mature the project towards a final investment decision.

The Gambia

• 4.14 In September 2020, a settlement agreement was reached with the Government of The Gambia following arbitration related to two licences, A1 and A4. The terms of the agreement awarded a new A4 licence under 30-year lease terms, providing a 90% interest and operatorship of the A4 licence to the Company, while all rights to the A1 licence have been relinquished. The remaining 10% interest of the new A4 licence is held by the Government of The Gambia.
• 4.15 The A4 licence comprises approximately 1,376 square kilometres located offshore The Gambia in water depths of 1,500m to 3,000m. An assessment prepared by ERC Equipoise in 2015, in conjunction with a 2017 management update, estimates the net unrisked mean prospective oil resources of A4 to be more than 1.5 billion barrels of oil.
• 4.16 Petronor aim to participate in any future well development at an equity level of 30-50% and are seeking partners to help test the portfolio of potential drilling opportunities.

Guinea Bissau

4.17 Petronor agreed to purchase SPE Guinea Bissau AB from Svenska Petroleum Exploration AB on 18 November 2020. Subject to government approval, the Company will hold a 78.57% interest in the Sinapa (Block 2) ("Sinapa") and Esperanҫa" (Blocks 4a and 5a) ("Esperanҫa") licences. The remaining equity is held by FAR Limited. The licences cover almost 6,000 square kilometres and are valid until 2 October 2023.

Board of Directors

4.18 The current board of directors of Petronor, as at 31 March 2021, are:

Table 11. Petronor Board of Directors

Director	Position	Date Appointed	Details
Eyas Alhomouz	Chairman	30 Aug 2019	Mr Alhomouz has experience in the oil and gas sector in the United States, North Africa, and the Middle East. He was previously the Chief Operating Officer and Finance Director of Prism Seismic, a US based consulting and oil and gas software firm, and Director of Business Development, Middle East following the acquisition of Prism Seismic by Sigma Cubed. He was later the General Manager of Jaidah Energy, a company servicing the oil and gas sector in Qatar.
Jens Pace	Non-Executive Director	29 Feb 2020	Mr Pace is a geoscientist with over 30 years' experience. He was the CEO and Executive Director of Petronor from 2015 to 2020. From 1 October 2012 to September 2015, he was the Chief Operating Officer of African Petroleum. Mr Pace previously held a variety of senior positions at BP across North Africa, and also has experience in Europe, Russia and Trinidad.
Joseph Iskander	Non-Executive Director	30 Aug 2019	Mr Iskander has over 20 years' experience in the financial services industry. He has served as a non-executive director for EFG Hermes in Egypt, Oasis Capital Bank in Bahrain, Sun Hung Kai & Co in Hong Kong, Qalaa Holdings in Egypt, Emirates Retakaful in UAE, Marfin Laiki Bank in Cyprus and Marfin Investments in Greece. He is currently a director at Al Baraka Bank Sudan and has been the Director of Private Equity at Emirates International Investments Company since 2017.
Roger Steinepreis	Non-Executive Director	6 Apr 2020	Mr Steinepreis is a corporate and resources lawyer with over 30 years' experience. He is Executive Chairman of Steinepreis Paganin, one of the largest specialist corporate law firms in Perth, Australia.
Alexander Neuling	Non-Executive Director	6 Apr 2020	Mr Neuling is a chartered accountant and has been advising within extractive industries for more than 15 years. He has held numerous senior management positions at listed companies, and previously worked for Deloitte in London and Perth.
Ingvil Tybring Gjedde	Non-Executive Director	29 May 2020	Ms Tybring-Giedde is the former Minister of Public Security and State Secretary/Vice Minister of the Ministry of Petroleum and Energy in Norway. She has a demonstrated history of working with the oil and gas, energy and renewable industry.
Gro Kielland	Non-Executive Director	Feb 2021	Mrs Kielland is the Chairman and CEO of Agility Group AS in Norway. She has over 27 years' experience in the oil and gas industry, including 20 years with BP in a variety of technical and management positions in Norway and the UK.

Source: S&P Capital IQ, Company website

Financial Performance

4.19 Petronor's audited Statements of Profit or Loss and Other Comprehensive Income for the years ended 31 December 2018, 31 December 2019, and unaudited for the year ended 31 December 2020 as per the Company's Interim Financial Report for the fourth quarter announced on 26 February 2021, are set out below.

Table 12. Petronor Statement of Profit or Loss and Other Comprehensive Income

	Audited 12 months to 31 December 2018 (US\$'000)	Audited 12 months to 31 December 2019 (US\$'000)	Unaudited 12 months to 31 December 2020 (US\$'000)
Revenue	101,069	102,760	67,543
Cost of sales	(41,577)	(37,207)	(25,885)
Gross profit	59,492	65,553	41,658
Other operating income	491	9	269
Administrative expenses	(10,090)	(19,793)	(12,644)
Profit from operations	49,893	45,769	29,283
Finance expense	(1,623)	(1,822)	(2,734)
Finance income	-	-	-
Foreign exchange (loss)/gain	(88)	(440)	1,497
Share based payments	-	(19,374)	-
Profit before tax	48,182	24,133	28,046
Tax expense	(31,124)	(29,894)	(17,078)
(Loss)/profit for the year	17,058	(5,761)	10,968
Other comprehensive income Exchange gains arising on translation of foreign operations	-	-	(1,048)
Total comprehensive (loss)/income	17,058	(5,761)	9,920
Profit / (loss) for the period attributable to:
Owners of the parent	7,838	(13,364)	2,306
Non-controlling interest	9,220	7,603	8,662
Total profit/loss	17,058	(5,761)	10,968
Total comprehensive (loss)/income attributable to:
Owners of the parent	7,838	(13,364)	1,352
Non-controlling interest	9,220	7,603	8,568
Total comprehensive income	17,058	(5,761)	9,920

Source: Petronor Annual Report 31 Dec 2019, Interim Report 31 Dec 2020

Financial Position

• 4.20 Set out below is the audited Statement of Financial Position of Petronor as at 30 June 2020, and the unaudited Statement of Financial Position as at 31 December 2020 prepared on a consolidation basis. We have made adjustments to estimate Petronor's financial position as at 26 March 2021, based on management accounts as at 28 February 2021 and details of other material movements subsequent to 28 February 2021 provided to us by Petronor management. Key items include:
• Tranche 1 Placement, involving the issue of 84,363,636 at an issue price of NOK1.10, to raise a net US\$10,943,396 in cash. An equivalent entry has been made to issued capital.
• Estimated costs of Tranche 1 Placement of US\$446,587 (comprising US\$346,587 of manager fees and US\$100,000 of legal fees) have been added to accounts payable and a balancing entry to retained earnings.
• Payment of US\$6,143,632 by HEPCO to settle a dividend liability to MGI, which was paid during the first week of March 2021.
• The acquisition of 9.9% equity in HEPCO relating to the MGI Ruling, resulting in the following adjustments:

Table 13. MGI Ruling adjustments

	Ref	Value (US\$'000)
Trade and other receivables		(3,639)
Intangible assets (goodwill)		719
Retained earnings		143
Non-controlling interest		(3,063)

Source: Petronor management accounts

Table 14. Petronor Statement of Financial Position

	Audited as at 31 December 2019 (US\$'000)	Unaudited as at 31 December 2020 (US\$'000)	Adjustments to 26 March 2021 (US\$'000)	Adjusted as at 26 March 2021 (US\$'000)
Current assets
Cash and cash equivalents	27,891	14,121	9,148	23,269
Trade and other receivables	24,772	30,976	(8,616)	22,360
Inventories	3,233	3,578	1,034	4,612
Total current assets	55,896	48,675	1,566	50,241
Non-current assets
Property plant and equipment	22,587	23,647	116	23,763
Intangible assets	4,691	6,935	612	7,547
Total non-current assets	27,278	30,582	728	31,310
Total assets	83,174	79,257	2,294	81,551
Current liabilities
Trade and other payables	(34,602)	(22,922)	6,851	(16,071)
Loans and borrowings	(12,941)	(4,000)	(1,333)	(5,333)
Total current liabilities	(47,543)	(26,922)	5,518	(21,404)
Non-current liabilities
Loans and borrowings	-	(14,912)	1,226	(13,686)
Provisions	(14,373)	(15,307)	(166)	(15,473)
Total non-current liabilities	(14,373)	(30,219)	1,060	(29,159)
Total liabilities	(61,916)	(57,141)	6,578	(50,563)
Total net assets/(liabilities)	21,258	22,116	8,872	30,988
Equity
Share capital	17,735	17,735	10,943	28,678
Foreign currency translation reserve	-	(955)	280	(675)
Retained earnings	(11,226)	(8,920)	(289)	(9,209)
Equity to members	6,509	7,860	10,934	18,794
Non-controlling interests	14,749	14,256	(2,062)	12,194
Total equity	21,258	22,116	8,872	30,988

Source: Petronor Annual Report 31 Dec 2019, Interim Report 31 Dec 2020 and management accounts

Current Issued Capital Position

4.21 As at 26 March 2021, the equity capital structure of Petronor was as follows.

Table 15. Petronor Current Equity Structure

Security	Number	Exercise price	Expiry date
Ordinary shares	1,056,028,924	n/a	n/a
Ordinary shares on issue	1,056,028,924	n/a	n/a
Unlisted options	213,400	NOK 2.50	11 Jan 2022
Unlisted options	1,176,070	NOK 7.75	31 May 2022
Total options on issue	1,389,470	n/a	n/a
Fully diluted ordinary shares	1,057,418,394	n/a	n/a

Source: Petronor 2019 Annual Report, Company announcements

4.22 The top 20 ordinary shareholders as at 17 March 2021 were as follows.

Table 16. Top 20 Shareholders

Shareholder	Number of shares	Percentage of total shares (%)
Petromal L.L.C	403,936,700	38.25
Nor Energy AS4	143,555,857	13.59
Gulshagan III AS4	45,000,000	4.26
Gulshagan IV AS4	45,000,000	4.26
Lenger Nedi Hagan AS4	45,000,000	4.26
Ambolt Invest AS4	45,000,000	4.26
Eng Group Soparfi S.A.	40,681,739	3.85
Gulshagan II AS	38,901,247	3.68
Enga Invest AA	19,692,746	1.86
Pust For Livet AS4	15,000,000	1.42
Nordnet Bank AB	11,981,906	1.13
Telinet Energi AS	10,818,377	1.02
Nordnet Livsforsikring AS	9,351,607	0.89
Al-Qattan	7,645,454	0.72
Al-Qattan	7,645,454	0.72
UBS Switzerland AG	6,458,073	0.61
Singh	5,051,424	0.48
Sandberg JH AS	4,573,951	0.43
Avanza Bank AB	4,417,904	0.42
Danske Bank A/S	3,770,671	0.36
Total top 20 shareholders	913,483,110	86.50
Total securities (as at 17 March 2021)	1,056,028,924	100.00

Source: Petronor Share Register

⁴ Entities controlled by the Related Parties

5 Profile of HAH

History and Principal Activities

• 5.1 HAH is a Norwegian based subsidiary of Petronor that maintains an indirect holding in the Company's Congo based oil and gas assets through a subsidiary, HEPCO.
• 5.2 As discussed in paragraph 4.7, HAH has been awarded 9,900 ordinary shares in HEPCO under the MGI Ruling. We have assumed⁵ HAH has an increased stake in HEPCO of 84.15%, and therefore its indirect economic interest in PNGF Sud has increased from 14.85% to 16.83%, and in PNGF Bis from 16.66% to 23.562%.

Ownership

• 5.3 As at 31 March 2021, there are 100,000 ordinary shares outstanding in HAH.
• 5.4 The current shareholders of HAH are as follows.

Table 17. HAH Shareholders

Shareholder	Shares	Percentage (%)
Petronor	70,707	70.707
Symero	29,293	29.293
Total	100,000	100.000

Source: Share Purchase Agreement

Financial Position

5.5 The financial position of HAH as at 28 February 2021 based on unaudited management accounts is as follows. An adjustment was made to reflect the position as at 26 March 2020 for US\$3,638,790 being reclassified from due to related parties to investment in subsidiary to reflect the shares transferred from MGI to HAH under the MGI Ruling.

⁵ Based on information from the Company that the shares were registered in the name of HAH at the Business Registrar in Congo on 25 January 2021

Table 18. HAH Statement of Financial Position

	Unaudited as at 26 March 2021 (US\$)
Current assets
Cash and cash equivalents	1,131,362
Due from related parties	25,402,130
Total current assets	26,533,492
Non-current assets
Investment in subsidiary	4,826,790
Total non-current assets	4,826,790
Total assets	31,360,282
Current liabilities
Accounts payable	(12,390)
Accruals and other payables	(5,624)
Current portion of long-term loan	(5,660,000)
Total current liabilities	(5,678,014)
Non-current liabilities
Long term loan	(9,340,000)
Total non-current liabilities	(9,340,000)
Total liabilities	(15,018,014)
Total net assets/(liabilities)	16,342,268
Equity
Issued capital	11,500
Accumulated losses	16,793,981
Current period losses	(1,412,188)
Foreign currency revaluation reserve	948,975
Total equity	16,342,268

Source: HAH management accounts

Profile of HEPCO

• 5.6 As outlined above, HEPCO is a subsidiary of HAH, in which HAH holds 84,150 out of a total 100,000 ordinary shares (84.15%) following the MGI Ruling.
• 5.7 HEPCO is a Congo based company which holds a direct interest of 20% in PNGF Sud and a 28% interest in PNGF Bis.
• 5.8 The unaudited statement of financial position of HEPCO as at 26 March 2021, based on management accounts as at 28 February 2021 and adjusted for the payment of a dividend liability of US\$6,144,000 to MGI in early March, is as follows.

Table 19. HEPCO Statement of Financial Position as at 26 March 2021

	Unaudited as at 26 March 2021 (US\$)
Current assets
Cash and cash equivalents	10,644,305
Inventory	4,612,306
Trade and other receivables	21,853,699
Total current assets	37,110,310
Non-current assets
Licences	7,388,649
Production assets & equipment	21,199,988
Total non-current assets	28,588,637
Total assets	65,698,947
Current liabilities
Due to related parties	(12,150,000)
Accounts payable and other accruals	(6,778,360)
Total current liabilities	(18,928,360)
Non-current liabilities
Provision for decommissioning cost	(15,229,496)
Total non-current liabilities	(15,229,496)
Total liabilities	(34,157,856)
Total net assets/(liabilities)	31,541,091
Equity
Issued capital	1,600,000
Retained earnings	27,893,587
Current period profit	2,047,504
Total equity	31,541,091

Source: HEPCO management accounts

6 Valuation Methodology

Available Methodologies

• 6.1 In assessing the value of Petronor, we have considered a range of common market practice valuation methodologies in accordance with RG111, including those listed below.
• Capitalisation of future maintainable earnings ("FME")
• Discounted future cash flows ("DCF")
• Asset based methods ("Net Assets")
• Quoted market prices or analysis of traded share prices
• Common industry rule-based methodologies
• 6.2 Each of these methods is appropriate in certain circumstances and often more than one approach is applied. The choice of methods depends on several factors such as the nature of the business being valued, the return on the assets employed in the business, the valuation methodologies usually applied to value such businesses and the availability of required information. A detailed description of these methods and when they are appropriate is provided in Appendix B.

Selected Methodology – Petronor Shares

• 6.3 Our primary valuation methodology to value Petronor's shares is a Net Assets based approach on a going concern basis, using the oil and gas interest values ascribed in the ResourceInvest Report.
• 6.4 In selecting an appropriate valuation methodology to value the shares of Petronor, we considered the following factors:
• Petronor's recent earnings have been variable and it is difficult to forecast reliable future earnings. As such the FME methodology is not considered appropriate.
• Reliable cash flow forecasts are not available for the Company and therefore DCF methodology is not appropriate. We note that cash flow forecasts are available at the project level for PNGF Sud, PNGF Bis and OML 113, and were used to derive project values in the ResourceInvest Report.
• Petronor is predominantly a resource project based company that derives its value from a portfolio of oil and gas exploration and production projects. Accordingly, a sum of the parts approach using project values to derive a Net Asset value is appropriate.
• Trading of Petronor's ordinary shares on Oslo Expand demonstrates relatively low liquidity and therefore may not provide a reliable valuation.

Secondary Methodology – Petronor Shares

6.5 Petronor shares have exhibited a relatively low level of liquidity in trading on Oslo Expand, and accordingly the traded share prices were deemed appropriate as a secondary cross-check methodology only.

Selected Methodology – HAH and HEPCO Shares

• 6.6 In selecting an appropriate valuation methodology to value the shares of HAH and HEPCO, we considered the following factors:
• Neither HAH nor HEPCO are publicly traded and therefore no quoted market prices exist
• There are no reliable cash flow or income forecasts available.
• HAH and HEPCO are subsidiaries of Petronor and acts as a holding companies for its Congo based oil and gas assets. Accordingly, a Net Assets based approach using project

values is considered appropriate.

7 Valuation of Petronor Shares

Petronor Pre-Transaction Net Asset Valuation

• 7.1 To assess the value of a Petronor ordinary share prior to the proposed Transaction, we took a Net Assets approach, which sums the assessed values of Petronor's assets and liabilities to arrive at a net value of the Company.
• 7.2 In relation to our approach, we note the following:
• The valuation is conducted as at 26 March 2021.
• The value of Petronor's oil and gas project assets were adopted as assessed by ResourceInvest and summarised in paragraphs 7.5 to 7.31.
• We assessed the values of Petronor's non-project related assets and liabilities as at 26 March 2021 as below. Values are based on the 31 December 2020 quarterly Interim Financial Report and adjusted for material movements between 31 December 2020 and 26 March 2021 (refer paragraph 4.20). We note that Petronor's non-project assets are predominantly liquid assets for which realisation costs are likely negligible.

Table 20. Other Net Assets Calculation

	Ref	Value (US\$)
Cash and cash equivalents	Table 14	23,268,764
Trade and other receivables	Table 14	22,360,210
Inventories	Table 14	4,612,000
Trade and other payables	Table 14	(16,070,955)
Loans and borrowings	Table 14	(5,333,000)
Loans and borrowings	Table 14	(13,686,000)
Provisions	Table 14	(15,473,000)
Non-controlling interests (adjusted)	Table 21	(5,575,029)
Other net assets		(5,897,010)

Source: SIS analysis

▪ The non-controlling interests in Table 20 were adjusted as follows to exclude the portion of the non-controlling interest recorded in the balance sheet that relate to project-based assets and liabilities, since these are replaced by the ResourceInvest project valuations.

Table 21. Non-Controlling Interest Adjustments

	Value (US\$)
Non-controlling interests as adjusted (see Table 14)	12,193,810
Less: NCI in project related net assets - HAH	1,413,912
Less: NCI in project related net assets - HEPCO	5,204,869
Adjusted NCI for non-project net assets only	5,575,029

Source: SIS analysis

• The majority of intangible assets recorded in the balance sheet in Table 14 relate to exploration licences that are represented in the ResourceInvest Report valuations, and accordingly did not include any additional intangible asset value.
• In accordance with RG111.15, we are required to consider the funding requirements where capital is required to develop a project, such as the PNGF Sud and PNGF Bis

projects held by Petronor. The project values assigned by ResourceInvest are based primarily on DCF models, which incorporate required capital expenditure to develop the projects.

• We have been advised that Petronor has not been involved in any material transactions subsequent to 31 December 2020 other than those already referred to in this report (see paragraph 4.20)
• The Transaction is not considered to be a control transaction. Accordingly, a discount for minority interest has been applied to the Petronor share price.
• 7.3 Our pre-Transaction Net Assets based valuation of Petronor, as at the valuation date of 26 March 2021, is set out below.

	Ref	Low	Preferred	High
PNGF Sud (US\$)	Table 23	117,700,000	126,300,000	134,900,000
PNGF Bis (US\$)	Table 23	13,800,000	15,000,000	16,300,000
OML 113 (US\$)	Table 23	20,000,000	25,300,000	35,600,000
Sinapa licence (US\$)	Table 23	11,100,000	11,100,000	13,000,000
Esperanҫa licence (US\$)	Table 23	-	6,200,000	8,100,000
Block A4 (US\$)	Table 23	10,400,000	10,400,000	13,500,000
Senegal (US\$)	Table 23	-	2,300,000	11,900,000
Add: other net assets (US\$)	Table 20	(5,897,010)	(5,897,010)	(5,897,010)
Total net assets (US\$)		167,102,990	190,702,990	227,402,990
Less: outstanding option value (US\$)	Table 32	(1,025)	(1,025)	(1,025)
Value to ordinary shareholders (US\$)		167,101,964	190,701,964	227,401,964
Number of shares outstanding	Table 15	1,056,028,924	1,056,028,924	1,056,028,924
Petronor pre-Transaction value per share (US\$) (control basis)		0.1582	0.1806	0.2153
Discount for minority interest (%)	7.33	23.1%	23.1%	23.1%
Petronor value per share (US\$) (minority interest)		0.1217	0.1389	0.1656

Table 22. Valuation of Petronor Shares Prior to Transaction

Source: SIS analysis

7.4 Accordingly, under Net Assets on a going concern methodology and relying on the values attributed to Petronor's oil and gas interests by ResourceInvest, the value of a Petronor share prior to the Transaction on a minority interest basis has been assessed to be between US\$0.1217 and US\$0.1656, with a preferred value of US\$0.1389.

ResourceInvest Report

Engagement of ResourceInvest

7.5 SIS engaged ResourceInvest as a technical specialist to undertake a market valuation of the oil and gas interests of Petronor. We have used and relied on the ResourceInvest Report and note that ResourceInvest has declared that:

• ResourceInvest is a suitably qualified consulting firm and has relevant experience in assessing the merits and preparing asset valuations of oil and gas projects. The principal author of the ResourceInvest Report, Mr Peter Cameron, is also suitably qualified and experienced.
• ResourceInvest is independent of all parties involved in the Transaction.

ResourceInvest Report Valuation Summary

• 7.6 We note that the ResourceInvest valuation was prepared in accordance with the Australasian Code for Public Reporting of Technical Assessments and Valuation of Mineral Asserts 2015 ("VALMIN Code").
• 7.7 Valuations in the ResourceInvest Report were completed under the following definition of market value:

"the amount of money (or cash equivalent) determined by the specialist in accordance with the VALMIN Code for which the mineral or petroleum asset or security should change hands on the valuation date in an open and unrestricted market between a willing buyer and a willing seller in an arm's length transaction, after appropriate marketing, with each party acting knowledgeably, prudently and without compulsion."

• 7.8 The Congolese and Nigerian assets were valued using an income based DCF approach. The exploration assets were valued using a market-based approach.
• 7.9 We note that the valuation date in the ResourceInvest Report is 1 January 2021, which is different from the dates used to derive the oil price. In the view of ResourceInvest, there have been no changes in conditions which would result in a material change in the valuations between these dates.
• 7.10 The values assigned to the hydrocarbon interests held by Petronor in the ResourceInvest Report are summarised below.

Licence	Country	Petronor interest (%)	Low (US\$)	Preferred (US\$)	High (US\$)
PNGF Sud	Congo	11.90	117,700,000	126,300,000	134,900,000
PNGF Bis	Congo	16.66	13,800,000	15,000,000	16,300,000
OML 113	Nigeria	13.10	20,000,000	25,300,000	35,600,000
Sinapa licence	Guinea Bissau	78.57	11,100,000	11,100,000	13,000,000
Esperanҫa licence	Guinea Bissau	78.57	-	6,200,000	8,100,000
Block A4	The Gambia	90.00	10,400,000	10,400,000	13,500,000
ROP	Senegal	81.00	-	-	-
SOSP	Senegal	81.00	-	2,300,000	11,900,000
Total Value			173,000,000	196,700,000	233,300,000

Table 23. ResourceInvest Valuation of Petronor's Hydrocarbon Interests

Source: ResourceInvest Report

Congo Assets

7.11 The primary methodology used to value the PNGF Sud and PNGF Bis licences (collectively, the "Congo Assets") was an income-based approach, based on a cash flow model provided by Petronor. ResourceInvest reviewed the model with respect to input price assumptions, production profiles, and capital and operating costs. The model for each of PNGF Sud and PNGF Bis contains four cases to allow for different reserve/resource assumptions.

• 7.12 A significant discount was applied to the PNGF Bis value to account for uncertainty in production volumes.
• 7.13 Oil price assumptions are based on an average of Brent oil price forecasts by the US Energy Administration, World Bank, and a compilation of leading oil and gas companies by Stellar Energy Advisors. For each, ResourceInvest assumed escalation of 1% per annum after the final forecast. Brent Futures were also considered, and the base oil price values used in the ResourceInvest Report were based on an average of the market prices and Brent Futures price, with low and high figures at ± 5% of the base price.
• 7.14 A pre-finance, post tax discount factor of 12% was used for the PNGF Sud and PNGF Bis NPV calculations.
• 7.15 The economic model of the Congo Assets allows for four different cases to be evaluated, as follows.

	PNGF Sud	PNGF Bis
Case A	Assumes the decline of 2P reserves without further capital	Assumes 2 mmbbl from production testing of the LOSUM-2 well is exported to Tchibouela
Case B	Assumes the inclusion of 2P reserves after workover	Assumes an additional 3.2 mmbbl from production testing of the LOSUM-2 well is exported to Tchibouela
Case C	Assumes the inclusion of 2C resources with infill drilling	Assumes the development of 2C resources
Case D	Assumes the inclusion of 3C resources with further infill drilling	Assumes the development of 3C resources

Table 24. Congo Asset Economic Model Cases

Source: ResourceInvest Report

7.16 Risk factors were applied to determine a market valuation, based on ResourceInvest's level of confidence in the reserves or contingent resources estimates and the probability of their development.

Table 25. Congo Asset Risk Factors

	Case A + B (%)	Case C (%)	Case D (%)
PNGF Sud	95	80	30
PNGF Bis	50	25	15

Source: ResourceInvest Report

7.17 Unrisked NPV's were calculated using the discount rate of 12% for PNGF Sud and PNGF Bis for each of the low, preferred and high assumption scenarios. The above project risk factors were then applied to obtain the risked NPVs for each project, as follows.

	Case A + B (US\$m)	Case C (US\$m, incremental value)	Case D (US\$m, incremental value)	Total (US\$)
Low oil price
PNGF Sud	87.5	20.9	9.3	117.7
PNGF Bis	2.7	8.1	3.0	13.8
Total	90.1	29.0	12.4	131.5
Base oil price
PNGF Sud	93.6	22.7	10.0	126.3
PNGF Bis	3.1	8.8	3.2	15.0
Total	96.6	31.5	13.2	141.3
High oil price
PNGF Sud	99.7	24.5	10.7	134.9
PNGF Bis	3.5	9.5	3.3	16.3
Total	103.1	34.0	14.0	151.2

Table 26. Congo Asset Risked NPVs

Source: ResourceInvest Report

7.18 Accordingly, the market values for PNGF Sud and PNGF Bis were calculated as below.

Table 27. Congo Asset Market Values

	Low (US\$m)	Preferred (US\$m)	High (US\$m)
PNGF Sud	117.7	126.3	134.9
PNGF Bis	13.8	15.0	16.3
Total	131.5	141.3	151.2

Source: ResourceInvest Report

7.19 A market-based methodology was used as a cross-check, based on the implied US\$/2P reserve ratio for 15 comparable West African oil acquisitions which have occurred since 2014.

Nigerian Assets

• 7.20 The primary methodology used by ResourceInvest to value Petronor's Nigerian asset, the OML 113 licence, was an income-based approach based on a cash flow model provided by Petronor. The model was developed based on an analysis of a proposed redevelopment plan for the project. ResourceInvest reviewed the model with respect to prices, costs, scenarios and timing. Oil price assumptions for the Nigerian assets the same as for the Congo Assets, described at paragraph 7.13.
• 7.21 Under the development plan, the gas development will be divided between an upstream company, which will own a 100% economic interest in OML 113 and be responsible for drilling, operation and maintenance, and a midstream company that will be responsible for the development of a gas processing facility, power barge and an LPG plant. The upstream company will sell wet gas to the midstream company at a transfer price of US\$2.75/mmbtu.
• 7.22 Key assumptions contained in the model relate to the structure of the cost and revenue sharing arrangements in the joint venture terms and the proposals in the development plan (refer to the ResourceInvest Report for further detail).

• 7.23 The discount factor used in the NPV model for OML 113 is 18% due to ResourceInvest's view on the likelihood of the project being developed.

• 7.24 The economic model allows for three cases, which form the low, preferred and high cases in the valuation.

• i) Case 1: After initial development, production increases to 70 mmcfd, which is sold to the midstream gas and power company.
• ii) Case 2: Two further wells drilled to increase gas production to 110 mmcfd, which is sold to the midstream gas and power company.
• iii) Case 3: The midstream gas and power company builds an LPG extraction plant and expands power generation capacity.
• 7.25 The valuation of Petronor's economic interest in the OML 113 licence was assessed as follows.

Table 28. OML 113 Valuation Summary

	Low (Case 1) (US\$)	Preferred (Case 2) (US\$)	High (Case 3) (US\$)
100% interest	198.9	229.4	288.5
Petronor interest	20.0	25.3	35.6

Source: ResourceInvest Report

7.26 As with the Congo Assets, a comparable transactions approach was used as a secondary crosscheck.

Senegal, The Gambia and Guinea Bissau Assets

• 7.27 As Petronor's oil and gas assets in Senegal, The Gambia and Guinea Bissau are all exploration assets with no reliable cash flow estimates available, the ResourceInvest Report used a marketbased approach.
• 7.28 For the purpose of the valuation, ResourceInvest assumed that one of the Senegal licences on one block will be lost due to the arbitration proceedings over the Senegal assets.
• 7.29 Petronor has indicated that it will seek to farmout each of the exploration projects. Accordingly, a farmout methodology was used, with adjustments made for ResourceInvest's risk of tenure and the chance of being drilled. The valuations have assumed that the farminee will contribute their share of back costs.

	Unrisked Value (US\$m)	Farmout Risk (%)	Tenure Risk (%)	Risked Value (US\$m)
Minimum Terms
Senegal	7.3	90	25	1.6
The Gambia	8.2	90	100	7.4
Sinapa	10.1	90	100	9.1
Esperanҫa	7.3	60	100	4.4
Sought Terms
Senegal	13.2	90	25	3.0
The Gambia	15.0	90	100	13.5
Sinapa	14.4	90	100	13.0
Esperanҫa	13.4	60	100	8.1
Average of Minimum and Sought Terms
Senegal	10.3			2.3
The Gambia	11.6			10.4
Sinapa	12.3			11.1
Esperanҫa	10.4			6.2

Table 29. The Gambia, Senegal and Guinea Bissau Valuation

Source: ResourceInvest Report

7.30 The preferred values are derived from the average of the minimum and sought terms. The low values for Esperanҫa and Senegal SOSP assume that the farmouts do not occur. The high value for Senegal assumes a tenure risk factor of 100%. Accordingly, the assessed values of the exploration assets are as below.

Table 30. The Gambia, Senegal and Guinea Bissau Values

	Low (US\$m)	Preferred (US\$m)	High (US\$m)
Senegal	-	2.3	11.9
The Gambia	10.4	10.4	13.5
Sinapa	11.1	11.1	13.0
Esperanҫa	-	6.2	8.1
Total	21.5	30.0	46.5

Source: ResourceInvest Report

7.31 A secondary cost-based methodology was used as a cross-check. As Petronor intends to seek a farmin partner to cover the drilling costs, it is not considered appropriate to use the full value of the drilling costs. Accordingly, the costs were discounted assuming there is a 25% chance of Petronor funding ("COF") the costs in the case farmin agreements are not reached.

	Drilling Costs (US\$m)	COF (%)	Project Value (US\$m)	Petronor Interest (%)	Petronor Value (US\$m)
The Gambia	38.3	25	9.6	78.57	7.5
Sinapa	38.0	25	9.5	78.57	7.5
Esperanҫa	34.0	25	8.5	90.00	7.7
Senegal	34.0	25	8.5	81.00	6.9
Total	144.3		36.1		29.5

Table 31. The Gambia, Senegal and Guinea Bissau

Source: ResourceInvest Report

Discount for Minority Interest

• 7.32 We note a Net Asset valuation assumes a 100% interest in the company. We consider that the Petronor shares to be issued pursuant to the Transaction are a minority interest, and therefore we applied a minority interest discount.
• 7.33 Generally, historical evidence of control premiums offered on takeovers for small cap companies are in the range of 20% to 40%⁶ (although outcomes outside this are not uncommon) with 30% a commonly accepted benchmark where a 100% interest is being acquired. We have considered the factors in Appendix C and concluded that a control premium of 30% is appropriate to apply in this circumstance. Accordingly, we applied a minority interest discount of 23.1% (being the inverse of a 30% control premium) to the value of a Petronor share.

Existing Options Valuation

• 7.34 Petronor had 1,389,470 unlisted options on issue as at 26 March 2021.
• 7.35 We derived a value for existing options using the Black Scholes option methodology with input assumptions as follows:
• A valuation date of 26 March 2021.
• Exercise prices and expiry dates are as defined in each option's terms.
• An underlying spot price of Petronor shares of NOK1.19 based on the closing price on Oslo Expand as at 26 March 2021.
• The Norwegian government bond rates for the nearest available period commensurate with the remaining term of each option was used as a proxy for the risk-free rate. For both options, the nearest available period is 1 year, and we accordingly used the one-year Norwegian government bond rate as at 26 March 2021, being 0.2804%⁷ .
• Volatility of 60%, based on the historical average annualised volatility of Petronor shares traded on Oslo Expand during the period from 30 August 2019 (being the date of the reverse takeover of African Petroleum) to 26 March 2021.
• No dividends to be paid or announced by Petronor during the term of any outstanding option.
• 7.36 Set out below is a summary of the Black Scholes derived valuations for the existing options over Petronor shares.

⁶ "Control Premium Study 2017", RSM

⁷ Note the quoted bond rate of 0.28% was converted to a continuously compounded rate due to the underlying assumptions of the Black Scholes model

Table 32. Petronor Option Values

Option	Number	Exercise Price (NOK)	Expiry Date	Black Scholes Value (NOK)	Total Value (NOK)	Total Value (\$US)
Tranche 1	213,400	2.50	11 Jan 2022	0.0344	7,335	855
Tranche 2	1,176,070	7.75	31 May 2022	0.0011	1,339	156
Total	1,389,470				8,674	1,025

Source: SIS analysis

Secondary Methodology - Traded Market Price Basis

Analysis of Trading History

7.37 We considered the recent trading history of Petronor shares on Oslo Expand between the reverse takeover of African Petroleum on 30 August 2019 and the announcement of the Transaction on 18 February 2021. We excluded the period after the announcement of the Transaction as these traded prices may incorporate the impact of the Transaction. Petronor's trading history is as set out below. We note that Petronor is traded in Norwegian Kroner and all quoted prices have been converted at the relevant daily US Dollar conversion rate for comparative purposes with our Net Asset derived valuation.

Table 33.	Petronor ASX Trading History to 18 February 2021
-----------	--------------------------------------------------	--	--	--

Trading Days	Low Price (US\$)	High Price (US\$)	Volume Weighted Average Price ("VWAP") (US\$)	Cumulative Volume Traded	Percentage of Issued Shares (%)	Annual Equivalent (%)
1 Day	0.153	0.157	0.1542	1,707,960	0.13	31.90
10 Days	0.133	0.164	0.1518	16,311,620	1.19	30.47
30 Days	0.130	0.164	0.1479	31,512,710	2.31	19.62
60 Days	0.130	0.164	0.1476	50,397,470	3.69	15.69
90 Days	0.130	0.179	0.1484	65,777,620	4.82	13.65
180 Days	0.092	0.194	0.1417	97,776,860	7.16	10.15
1 Year (255 trading days)	0.040	0.194	0.1188	144,720,020	10.60	10.60

Source: S&P Capital IQ, SIS analysis

Figure 3.Petronor Oslo Expand Trading History

Source: S&P Capital IQ

• 7.38 Generally, the market is a fair indicator of what a share is worth, however for a quoted market price to be a reliable indicator of a company's value, the company's share must trade in a "liquid and active" market. We consider that a liquid and active market would typically be characterised by:
• regular trading in the company's securities;
• trading of at least 1% of a company's securities on a weekly basis;
• the spread of a company's shares must not be so great that a single minority trade can significantly affect the market capitalisation of the company; and
• no significant but unexplained movements in the share price.
• 7.39 As per RG111.58/111.32, we also considered the volatility of the market price of Petronor shares. We note that the Company was previously African Petroleum, and prior to the reverse takeover by Petronor had different characteristics to the current business. Accordingly, we only considered the volatility of trading since 30 August 2019. The historic annualised volatility of Petronor shares to 18 February 2021 is shown below.

Table 34. Volatility of Petronor Shares

Period	Volatility (%)
1 year to 18 February 2021	68.05%
1 September 2019 – 18 February 2021	61.81%

Source: SIS analysis

• 7.40 The shares of Petronor have historically demonstrated a level of liquidity well below 1% per week, with only 10.60% of the Company's shares traded in the twelve months preceding the announcement of the Transaction. We note that the volatility of Petronor share prices is relatively low for a small cap oil and gas exploration and production company. Given the lack of depth in the market we do not consider traded prices to represent a reliable valuation indicator, however we note that the recent trading prices are broadly consistent with our Net Assets valuation.
• 7.41 Accordingly, we consider traded prices of Petronor as a secondary cross check only.

Conclusion on the Value of Petronor Shares

7.42 Based on the above analysis, we have considered the fair market value of a Petronor ordinary share prior to the Transaction, on a minority interest basis, to be as follows.

Table 35. Petronor Shares Valuation Summary

	Ref	Low	Preferred	High
Adopted value (US\$)	Table 22	0.1217	0.1389	0.1656

Source: SIS analysis

8 Valuation of HAH Shares

HAH Valuation

8.1 As HAH holds its interest in the Congo Assets through its ownership of shares in HEPCO, we first determined the value of a HEPCO share on a Net Asset basis.

HEPCO Valuation

• 8.2 We assessed the value of a HEPCO share on a Net Assets basis, with the value of its interests in the Congo Assets derived from the values ascribed in the ResourceInvest Report (as described in paragraphs 7.11 to 7.19).
• 8.3 The ResourceInvest Report valued Petronor's interests of 11.90% in PNGF Sud and 16.66% in PNGF Bis (refer Table 27). Based on the ResourceInvest valuation, the corresponding valuation of HEPCO's interests are as follows.

Table 36. HEPCO interest in Congo Assets

	Interest	Low (US\$)	Preferred (US\$)	High (US\$)
ResourceInvest valuation of Petronor's interest
PNGF Sud	11.90%	117,700,000	126,300,000	134,900,000
PNGF Bis	16.66%	13,800,000	15,000,000	16,300,000
HEPCO's interest
PNGF Sud	20.00%	197,815,324	212,269,120	226,722,916
PNGF Bis	28.00%	23,193,301	25,210,109	27,394,985

Source: ResourceInvest Report, SIS analysis

8.4 We reviewed the balance sheet of HEPCO and considered whether the assets and liabilities were project or non-project related. Non-project related net assets have been included in the HEPCO valuation at their book value, whereas all project related net assets are represented in ResourceInvest's valuation. The book value of HEPCO's assets and liabilities as per unaudited and adjusted management accounts as at 26 March 2021 were as follows.

Table 37. HEPCO Net Asset Book Values

	Ref	Unaudited as at 26 March 2021 (US\$)
Project related net assets	Table 19	33,046,786
Cash and cash equivalents	Table 19	10,644,305
Due to related parties	Table 19	(12,150,000)
Non project related net assets		(1,505,695)

Source: SIS analysis

8.5 Accordingly, our valuation of a HEPCO ordinary share is as follows.

Table 38. HEPCO Share Valuation

	Ref	Low	Preferred	High
20% interest in PNGF Sud (US\$)	Table 36	197,815,324	212,269,120	226,722,916
28% interest in PNGF Bis (US\$)	Table 36	23,193,301	25,210,109	27,394,985
Non project related Net Assets (US\$)	Table 37	(1,505,695)	(1,505,695)	(1,505,695)
Total net assets (US\$)		219,502,929	235,973,534	252,612,206
Number of shares outstanding	5.6	100,000	100,000	100,000
HEPCO value per share (US\$) (control)		2,195.03	2,359.74	2,526.12

Source: SIS analysis

8.6 We have not applied a discount for minority interest as HAH has a controlling interest in HEPCO.

Valuation of a HAH share

• 8.7 To assess the value of a HAH ordinary share, we took a Net Assets approach, which sums the assessed values of HAH's assets and liabilities to arrive at a net value of HAH.
• 8.8 In relation to our approach, we note the following:
• The valuation date is 26 March 2021.
• The value of HAH's investment in HEPCO is based on its holding of 84,150 ordinary shares. We have assumed HAH is entitled to the 9,900 ordinary shares that it has a right to as a result of the MGI Ruling, though MGI retains the right to appeal.
• The non-project related net assets of HAH have been included at their book values as per the Statement of Financial Position at Table 18.

Table 39. HAH Other Net Assets

	Unaudited as at 26 March 2021 (US\$)
Cash and cash equivalents	1,131,362
Due from related parties	25,402,130
Accounts payable	(12,390)
Accruals and other payables	(5,624)
Current portion of long term loan	(5,660,000)
Long term loan	(9,340,000)
Total other net assets	11,515,478

Source: HAH management accounts

Table 40. HAH Net Assets Valuation

	Ref	Low	Preferred	High
Value of a HEPCO share (US\$)	Table 38	2,195	2,360	2,526
Number of HEPCO shares	5.6	84,150	84,150	84,150
Value of investment in HEPCO (US\$)		184,711,715	198,571,729	212,573,171
Add: other net assets (US\$)	Table 39	11,515,478	11,515,478	11,515,478
Total net assets (US\$)		196,313,538	210,173,717	224,175,326
Number of shares outstanding	Table 17	100,000	100,000	100,000
HAH value per share (US\$) (control)		1,963.14	2,101.74	2,241.75

Source: SIS analysis

• 8.9 Our assessed value of a share in HAH is between US\$1,963 and US\$2,242 with a preferred value of US\$2,102.
• 8.10 Note the above values are on a control basis. We have considered a discount for minority interest in our fairness assessment in Table 43.

9 Fairness Evaluation

Evaluation Methodology

• 9.1 In determining the fairness and reasonableness of the Transaction including Resolution 1, we have had regard to the guidelines set out by ASIC's RG111.
• 9.2 As per RG111, the Transaction is fair if:
• the value of the financial benefit to be provided by Petronor to the Related Parties is less than or equal to;
• the value of the consideration received by Petronor.

Petronor Valuation

9.3 For the purpose of assessing the Transaction, our assessed value of a Petronor share prior to the Transaction is as follows.

Table 41. Petronor Share Value

	Ref	Low	Preferred	High
Petronor ordinary share value – control basis (US\$)	Table 35	0.1217	0.1389	0.1656

Source: SIS analysis

Fairness Assessment

• 9.4 Our assessed value of the financial consideration to be received and the value of the financial consideration to be provided by Petronor is set out below. We note that our valuation includes the impact of Placement Tranche 2b as this is a condition of the Acquisition.
• 9.5 An amount of NOK94,600,000 will be raised under the Placement Tranche 2b. Based on an NOK/US\$ exchange rate of 8.57643 as at 26 March 2021, Placement Tranche 2b will raise approximately US\$11,025,567 (before costs).

Table 42. Placement Tranche 2b

	Value (US\$)
Placement Tranche 2b funds before costs	11,025,567
Costs
Tranche 2 manager fee	583,000
Other transaction costs	254,000
Total costs	837,000
Placement Tranche 2b net funds raised	10,188,567

Source: Petronor management accounts

Table 43. Transaction Fairness Evaluation

	Ref	Low	Preferred	High
Value Received
Value of a HAH share (control) (US\$)	Table 40	1,963	2,102	2,242
Minority interest discount (%)	9.7	23.1%	23.1%	23.1%
Value of a HAH share (minority interest) (US\$)		1,510	1,617	1,724
Number of shares acquired	Table 17	29,293	29,293	29,293
Value of HAH shares acquired (US\$)		44,235,481	47,358,605	50,513,599
Net Placement Tranche 2b cash received (US\$)	Table 42	10,188,567	10,188,567	10,188,567
Total value received (US\$)		54,424,047	57,547,172	60,702,165
Consideration Paid
Number of Petronor shares issued to Symero	Table 6	138,763,636	138,763,636	138,763,636
Number of Petronor shares issued in Placement
Tranche 2b	Table 6	85,963,636	85,963,636	85,963,636
Total shares issued		224,727,272	224,727,272	224,727,272
Value of a Petronor share (minority interest) (US\$)	Table 22	0.1217	0.1389	0.1656
Total consideration paid (US\$)		27,353,832	31,217,044	37,224,667
Premium/(discount) (US\$)		27,070,215	26,330,127	23,477,498
Fairness		Fair	Fair	Fair

Source: SIS analysis

Discount for Minority Interest

• 9.6 We note a Net Asset valuation assumes a 100% interest in the company. Petronor currently owns a controlling interest of 70.707% in HAH and the Transaction is not considered a control transaction. As such, we consider that the shares held by Symero are a minority interest, and therefore applied a minority interest discount to the value of HAH shares to be acquired by Petronor pursuant to the Transaction.
• 9.7 Generally, historical evidence of control premiums offered on takeovers for small cap companies are in the range of 20% to 40%⁸ (although outcomes outside this are not uncommon) with 30% a commonly accepted benchmark where a 100% interest is being acquired. We have considered the factors in Appendix C and note that no shareholders agreement is in place at the HAH level. We have therefore concluded that a control premium of 30% is appropriate to apply in this circumstance. Accordingly, we applied a minority interest discount of 23.1% (being the inverse of a 30% control premium) to the value of Symero's HAH shares.

⁸ "Control Premium Study 2017", RSM

Summary

9.8 Set out below is the low, preferred and high valuations of the consideration paid and the value received by Petronor.

Figure 4.Fairness Evaluation

Source: SIS analysis

• 9.9 We have assessed that the value received by Petronor is greater than the consideration paid to the Related Parties under all the low, preferred and high valuations.
• 9.10 Accordingly, the proposed Transaction, including the issue of 138,763,636 ordinary shares to Symero per Resolution 1 of the NoM is considered to be FAIR to the Non-Associated Shareholders of Petronor.

10 Reasonableness Evaluation

• 10.1 Under RG111, a transaction is considered "reasonable" if it is "fair". As the transaction outlined in Resolution 1 of the NoM is considered FAIR, it is also considered REASONABLE.
• 10.2 For the information of the Non-Associated Shareholders, we note below some of the advantages, disadvantages, and other factors relating to the Transaction.

Advantages

The Transaction is considered fair

10.3 As per our assessment in Section 9, the Transaction is fair to the Non-Associated Shareholders.

The Company will increase its interest in the Congo Projects

10.4 As a result of the Transaction, Petronor will increase its indirect interest in PNGF Sud from 11.90% to 16.83% and in PNGF Bis from 16.66% to 23.56% (assuming that the MGI Ruling is not overturned on a potential appeal).

Simplifies ownership structure

10.5 Future development of the Congo assets will require further capital raisings. A simplified ownership structure may improve the ability of Petronor to raise the required project finance in the future for this development.

Tranche 2b Placement will improve cash position

10.6 Completion of the Acquisition is interdependent with the Tranche 2b Placement, and accordingly approving the Transaction will facilitate a further capital raising. By completing the Tranche 2b Placement the Company will raise a further NOK94.6 million (approximately US\$11.16 million before costs), further improving the Company's cash position. The Tranche 2b Placement will also maintain the ownership interest of the Company's major shareholder, Petromal, and potentially increase the alignment of their interests with the Non-Associated Shareholders. By maintaining the interests of Petromal in the Company, it may also encourage Petromal to participate in any future capital raisings that the Company will require for the development of its projects.

Disadvantages

Significant dilution of Non-Associated Shareholders

10.7 Pursuant to the Transaction, 224,727,272 ordinary shares may be issued. Accordingly, the Non-Associated Shareholders of Petronor may dilute their interest in the ordinary shares (on a fully diluted basis) of the post-Transaction entity.

11 Opinions

11.1 The proposed Transaction, including the proposal outlined in Resolution 1 of the NoM that allows for the issue of up of 138,763,636 ordinary shares to Symero is considered FAIR and REASONABLE to the Non-Associated Shareholders of Petronor as at the date of this report.

12 Other Considerations

Covid-19

12.1 We note that the COVID-19 pandemic has significantly impacted the global economy and capital markets in recent times. Market volatility has been particularly high as a result, and this may lead to significant uncertainty around asset valuations. However, we do not have any reason to believe that these factors would alter our opinion.

13 Shareholders Decision

• 13.1 SIS has been engaged to prepare an IER setting out whether in its opinion the proposal to allow the Transaction is fair and reasonable and to state reasons for that opinion. SIS has not been engaged to provide a recommendation to shareholders as to whether to approve the Transaction.
• 13.2 The decision whether to approve Resolution 1 pertaining to the issue of shares to Symero and consequently provide a financial benefit to the Related Parties or not is a matter for individual shareholders based on each shareholder's views as to the value, their expectations about future market conditions and their particular circumstances, including risk profile, liquidity preference, investment strategy, portfolio structure, and tax position. If in any doubt as to the action they should take in relation to the proposal under Resolution 1, shareholders should consult their own professional advisor.
• 13.3 Similarly, it is a matter for individual shareholders as the whether to buy, hold or sell shares in Petronor. This is an investment decision upon which SIS does not offer an opinion and is independent on whether to accept the proposal under Resolution 1. Shareholders should consult their own professional advisor in this regard.

14 Source Information

• 14.1 In making our assessment as to whether the proposed Transaction, including the terms under Resolution 1, is fair and reasonable to Non-Associated Shareholders, we have reviewed published available information and other unpublished information of the Company that is relevant to the current circumstances. In addition, we held discussion with the management of Petronor about the present and future operations of the Company. Statements and opinions contained in this report are given in good faith, but in the preparation of this report we have relied in part on information provided by the directors and management of Petronor.
• 14.2 Information we have received includes, but is not limited to:
• Drafts of the NoM and ES to shareholders of Petronor to 31 March 2021
• Details of historical market trading of Petronor shares to 31 March 2021
• Petronor Annual Report for the year ended 31 December 2019
• Petronor Interim Financial Report for the quarter ended 31 December 2020
• Announcements made by the Company on Oslo Expand to 31 March 2021
• The Share Purchase Agreement between Petronor and Symero entered on 17 February 2021

• Register of Petronor shareholders and Norway VPS depositary receipts as at 17 March 2021

• Cash flow models provided by Petronor as reviewed and adjusted by ResourceInvest

• Various Legal documents regarding the acquisitions of the Nigeria and Guinea Bissau projects
• Investor presentation for 11 March 2021
• The ResourceInvest Report on the value of Petronor's oil and gas assets, dated 31 March 2021
• The investment and shareholders agreement for Aje Production AS, dated 3 December 2019
• Various licence agreements for Petronor's projects
• 14.3 Our report includes the appendices, our declarations, and our Financial Services Guide.

Yours Faithfully

STANTONS INTERNATIONAL SECURITIES PTY LTD (Trading as Stantons International Securities)

Samir Tirodkar Director

APPENDIX A

GLOSSARY

	Definition
Acquisition	The acquisition Symero's interest in HAH by Petronor in exchange for the issue of 138,763,636 ordinary shares
AFCA	Australian Financial Complaints Authority
African Petroleum	African Petroleum Corporation Limited
ASIC	Australian Securities and Investments Commission
ASX	Australian Securities Exchange
Chapter 2E	Chapter 2E of the Corporations Act
COF	Chance of Funding
Company	Petronor E&P Limited
Congo	Republic of Congo
Congo Assets	PNGF Sud and PNGF Bis
Corporations Act	Corporations Act 2001 Cth
DCF	Discounted cash flows valuation methodology
ES	Explanatory Statement
Esperanҫa	Esperanҫa Blocks 4a and 5a licences in Guinea Bissau
Equity Raising Condition	The condition precedent to the Acquisition for Petronor to compete an equity raising of up to US\$65 million before costs
FME	Capitalisation of future maintainable earnings valuation methodology
FSG	Financial Services Guide
Ludvigsen	Mr Gerhard Ludvigsen
ICSID	International Centre for Settlement of Investment Disputes
IER	Independent Expert's Report
HAH	Hemla Africa Holdings AS
HEPCO	Hemla E&P Congo SA
Meeting	The meeting at which shareholders will vote on Resolution 1
MGI	MGI International SA
MGI Ruling	Ruling by the Tribunal de Commerce de Pointe Noire in Congo awarding HAH 9,900 shares in HEPCO
Net Assets	Net Asset based valuation methodologies
NOK	Norwegian Kroner
NoM	Notice of Meeting
Non-Associated Shareholders	The Petronor shareholders who are not excluded from voting on the proposal contemplated under Resolution 1
OML 113	Oil Mining Licence 113 in the Aje Field, Nigeria
Oslo Expand	Oslo Euronext Expand
PSC	Production sharing contract
Panoro	Panoro Energy ASA
Petromal	Petromal Sole Proprietorship LLC
Petronor	Petronor E&P Limited
Placement	The proposed private placement of approximately US\$22 million
PNGF Bis	An adjacent licence to the north-west of PNGF Sud
PNGF Sud	The Tchibouela II, Tchendo II and Tchibeli-Litanzi II operating licences in offshore Congo
Related Parties	Mr Knut Søvold and Mr Gerhard Ludvigsen

	Definition
Resolution 1	Resolution 1 of the NoM to approve the issue of 138,763,636 ordinary shares to Symero and consequently to give a financial benefit to the Related Parties
ResourceInvest	ResourceInvest Pty Ltd
ResourceInvest Report	Independent Valuation Report on the Petronor E&P Limited Oil and Gas Assets, prepared by ResourceInvest and dated 31 March 2021
RG111	ASIC Regulatory Guide 111: Content of Expert Reports
RG76	ASIC Regulatory Guide 76: Related Party Transactions
ROP	Rufisque Offshore Profond licence in Senegal
Share Purchase Agreement	Agreement between Petronor and Symero for the sale of all Symero's ordinary shares in HAH entered on 17 February 2021
Sinapa	Sinapa Block 2 licence in Guinea Bissau
SIS	Stantons International Securities Pty Ltd
SOSP	Senegal Offshore Sud Profond
Søvold	Mr Knut Søvold
SPV	Special Purpose Vehicle
Subsequent Offering	Potential offering of 60,000,000 new ordinary shares in Petronor at NOK 1.1 per share to be considered after completing the Transaction
Symero	Symero Limited
Tranche 1 Placement	Private placement of 84,363,636 ordinary shares to new and existing investors completed on 15 March 2021
Tranche 2b Placement	Proposed private placement of 85,963,636 ordinary shares to Petromal
Transaction	The acquisition Symero's interest in HAH by Petronor in exchange for the issue of 138,763,636 ordinary shares, and the completion of the Tranche 2b Placement
US\$	United States Dollars
VWAP	Volume Weighted Average Price
YFP	Yinka Folawiyo Petroleum

APPENDIX B

VALUATION METHODOLOGIES

Introduction

In preparing this report we have considered several valuation approaches and methods. These approaches and methods are consistent with:

• Market practice
• The methods recommended by the Australian Securities and Investments Commission in Regulatory Guide 111
• The International Valuation Standards
• The International Glossary of Business Valuation Terms

A valuation approach is a general way of determining an estimate of value of a business, business ownership interest, security or intangible asset. Within each valuation approach there are a number of specific valuation methods, which are specific ways to determine an estimate of value.

There are three general valuation approaches as follows:

i) Income Approaches

Provides an indication of value by converting future cash flows to a single present value. Examples of an income approach are:

• The discounted cash flow method ("DCF")
• The capitalisation of future maintainable earnings method ("FME")

ii) Asset/Cost Approaches

Provides an indication of value using the economic principle that a buyer will pay no more for an asset than the cost to obtain an asset of equal utility, whether by purchase or construction.

iii) Market Approaches

Provides an indication of value by comparing the subject asset with identical or similar assets for which price information is available. The main examples of the market approach are:

• Analysis of recent trading
• Industry rules of thumb

1. Discounted Cash Flow Method

Of the various methods noted above, the DCF method has the strongest theoretical basis. The DCF method estimates the value of a business by discounting expected future cash flows to a present value using an appropriate discount rate. A DCF valuation requires:

• A forecast of expected future cash flows
• An appropriate discount rate
• An estimate of terminal value

It is necessary to project cash flows over a suitable period of time (generally regarded as being at least five years) to arrive at the net cash flow in each period. For a finite life project or asset this would need to be done for the life of the project. This can be a difficult exercise requiring a significant number of assumptions such as revenue and cost drivers, capital expenditure requirements, working capital movements and taxation.

The discount rate used represents the risk of achieving the projected future cash flows and the time value of money. The projected future cash flows are then valued in current day terms using the discount rate selected.

A terminal value reflects the value of cash flows that will arise beyond the explicit forecast period. This is commonly estimated using either a constant growth assumption or a multiple of earnings (as described under FME below). This terminal value is then discounted to current day terms and added to the net present value of the forecast cash flows to provide an estimate for the overall value of the business.

The DCF method is often sensitive to a number of key assumptions such as revenue growth, future margins, capital investment, terminal growth and the discount rate. All these assumptions can be highly subjective, sometimes leading to a valuation conclusion presented that is too wide to be useful.

A DCF approach is usually preferred when valuing:

• Early-stage companies or projects
• Limited life assets such as a mine or toll concession
• Companies where significant growth is expected in future cash flows
• Projects with volatile earnings

It may also be preferred if other methods are not suitable, for example if there is a lack of reliable evidence to support an FME approach. However, it may not be appropriate if:

• Reliable forecasts of cash flow are not available and cannot be determined
• There is an inadequate return on investment, in which case a higher value may be realised by liquidating the assets than through continuing the business

A DCF approach is not recommended when assets are expected to earn below the cost of capital. Also, when valuing a minority interest in a company, care needs to be taken if a DCF based on earnings for the whole business is prepared, as the holder of a minority interest would not have access to, or control of, those cash flows.

2. Capitalisation of Future Maintainable Earnings Method

The FME method is a commonly used valuation methodology that involves determining a future maintainable earnings figure for a business and multiplying that figure by an appropriate capitalisation multiple. This methodology is generally considered a short form of a DCF, where a single representative earnings figure is capitalised, rather than a stream of individual cash flows being discounted. The FME methodology involves the determination of:

• A level of future maintainable earnings
• An appropriate capitalisation rate or multiple

Any of the following measures of earnings can be used:

Revenue – mostly used for early stage, fast growing companies that do not make a positive EBITDA or as a cross-check of a valuation conclusion derived using another method.

EBITDA – most appropriate where depreciation distorts earnings, for example in a company that has a significant level of depreciating assets but little ongoing capital expenditure requirement.

EBITA – in most cases EBITA will be more reliable than EBITDA as it takes account of the capital intensity of the business

EBIT – whilst commonly used in practice, multiples of EBITA are usually more reliable as they remove the impact of amortisation which is a non-cash accounting entry that does not reflect a need for future capital investment (unlike depreciation)

NPAT – relevant in valuing businesses where interest is a major part of the overall earnings of the group (e.g., financial services businesses such as banks).

Multiples of EBITDA, EBITA and EBIT are commonly used to value whole businesses for acquisition purposes where gearing is in the control of the acquirer. In contrast, NPAT (or P/E) multiples are often used for valuing minority interests in a company as the investor has no control over the level of debt.

A normalised level of maintainable earnings needs to be determined for the selected earnings measure. This excludes the impact of any gains or losses that are not expected to reoccur and allows for the full year impact of any changes (such as acquisitions or disposals) made part way through a given financial year.

The selected multiple to apply to maintainable earnings reflects expectations about future growth, risk and the time value of money captured in a single number. Multiples can be derived from three main sources.

• Using the comparable trading multiples, market multiples are derived from the trading prices of stocks of companies that are engaged in the same or similar lines of business that are actively traded on a free and open market, such as the ASX
• The comparable transactions method is a method whereby multiples are derived from transactions of significant interests in companies engaged in the same or similar lines of business.
• It is also possible to build a multiple from first principles based on an appropriate discount rate and growth expectations.

It is important to use the same earnings periods (historical, current or forecast) for calculating comparable multiples, as the period used for determining FME. For example, a multiple based on historical earnings of comparable companies should be applied to historical earnings of the subject of the valuation and not to forecast earnings.

The capitalisation of earnings method is widely used in practice. It is particularly appropriate for valuing companies with a relatively stable historical earnings pattern which is expected to continue. The method is less appropriate for valuing companies or assets if:

• There are no (or very few) suitable alternative listed companies or transaction benchmarks for comparison
• The asset has a limited life
• Future earnings or cash flows are expected to be volatile
• There are negative earnings, or the earnings of a business are insufficient to justify a value exceeding the underlying net assets
• Working capital requirements are not expected to remain stable

3. Asset or Cost Approaches

The asset approach to value assumes that the current value of all assets (tangible and intangible) less the current value of the liabilities should equate to the current value of the entity. Specifically, an asset approach is defined as a general way of determining a value indication of a business, business ownership interest, or security using one or more methods based on the value of the assets net of liabilities. A cost approach is defined as a general way of determining a value indication of an individual asset by quantifying the amount of money required to replace the future service capability of that asset.

The asset-based valuation methods estimate the value of a company based on the realisable value of its net assets, less its liabilities. There are a number of asset-based methods including:

• Orderly realization
• Forced liquidation
• Net assets on a going concern

The orderly realisation of assets method estimates fair market value by determining the amounts that would be distributed to shareholders, after payments of all liabilities including realisation costs and taxation charges that arise, assuming the company is wound up in an orderly manner. The forced liquidation method is similar to the orderly realisation of assets except the liquidation method assumes the assets are sold in a shorter time frame. Since wind up or liquidation of the company may not be contemplated, these methods in their strictest form may not necessarily be appropriate. The net assets on a going concern basis method estimates the fair market values of the net assets of a company but does not take account of realisation costs.

The asset/cost approach is generally used when the value of the business' assets exceeds the present value of the cash flows expected to be derived from the ongoing business operations, or the nature of the business is to hold or invest in assets. It is important to note that the asset approach may still be the relevant approach even if an asset is making a profit. If an asset is making less than the economic rate of return and there is no realistic prospect of it making an economic return in the foreseeable future, an asset/cost approach will be the most appropriate method.

An asset-based approach is a suitable method of valuation when:

• An enterprise is loss making and not expected to become profitable in the foreseeable future
• Assets are employed profitably but earn less than the cost of capital
• A significant portion of the company's assets are composed of liquid assets or other investments (such as marketable securities and real estate investments)
• It is relatively easy to enter the industry (e.g., small machine shops and retail establishments)

Asset based methods are not appropriate if:

• The ownership interest being valued is not a controlling interest, has no ability to cause the sale of the company's assets and the major holders are not planning to sell the company's assets
• A business has (or is expected to have) an adequate return on capital, such that the value of its future income stream exceeds the value of its assets

An asset-based approach is often considered as a floor value for a business assuming the business has the option to realise all its assets and liabilities.

4. Analysis of Recent Trading

The most recent share trading history provides evidence of the fair market value of the shares in a company where they are publicly traded in an informed and liquid market. There should also be some similarity between the size of the parcel of shares being valued and those being traded. Where a company's shares are publicly traded then an analysis of recent trading prices should be considered, at least as a cross-check to other valuation methods.

5. Industry Specific Rule of Thumb

Industry specific rules of thumb are used in certain industries. These methods typically involve a multiple of an operating figure such as traffic for internet businesses or number of beds for a nursing home. These methods are typically fairly crude and therefore only appropriate as a cross-check to a valuation determined by an alternative method.

Selecting an Appropriate Valuation Approach and Method

The choice of an appropriate valuation approach and methodology is subjective and depends on several factors such as whether a methodology is prescribed, the company's historical and projected financial performance, stage of maturity, the nature of the company's operations and availability of information. The selection of an appropriate valuation method should be guided by the actual practices adopted by potential acquirers of the company involved and the information available.

APPENDIX C

CONTROL PREMIUM

Background

The difference between a control value and a minority value is described as a control premium. The opposite of a control premium is a minority discount (also known as a discount for lack of control). A control premium is said to exist because the holder of a controlling stake has several rights that a minority holder does not enjoy (subject to shareholders agreements and other legal constraints), including to:

• Appoint or change operational management
• Appoint or change members of the board
• Determine management compensation
• Determine owner's remuneration, including remuneration to related party employees
• Determine the size and timing of dividends
• Control the dissemination of information about the company
• Set the strategic focus of the organisation, including acquisitions, divestments, and restructuring
• Set the financial structure of the company (debt / equity mix)
• Block any or all the above actions

The most common approach to quantifying a control premium is to analyse the size of premiums implied from prices paid in corporate takeovers. Another method is the comparison between prices of voting and non-voting shares in the same company. We note that the size of the control premium should generally be an outcome of a valuation and not an input into one, as there is significant judgement involved.

Based on historical takeover premia that have been paid in Australian acquisitions in the period 2005-2015, the majority of takeovers have included a premium in the range of 20-50%, with 30% being the most commonly occurring. This is in line with standard industry practice, which tends to use a 30% premium for control as a standard.

Intermediate Levels of Ownership

There are several intermediate levels of ownership between a portfolio interest and 100% ownership. Different levels of ownership/strategic stakes will confer different degrees of control and rights as shown below.

• 90% can compulsorily purchase remaining shares if certain conditions are satisfied
• 75% power to pass special resolutions
• <50% gives control depending on the structure of other interests (but not absolute control)
• <25% ability to block a special resolution
• <20% power to elect directors, generally gives significant influence, depending on other shareholding blocks
• < 20% generally has only limited influence

Conceptually, the value of each of these interests lies somewhere between the portfolio value (liquid minority value) and the value of a 100% interest (control value). Each of these levels confers different degrees of control and therefore different levels of control premium or minority discount.

APPENDIX D

AUTHOR INDEPENDENCE AND INDEMNITY

This annexure forms part of and should be read in conjunction with the report of Stantons International Securities Pty Ltd trading as Stantons International Securities dated 31 March 2021, relating to the proposed Transaction.

At the date of this report, Stantons International Securities does not have any interest in the outcome of the proposal. There are no relationships with Petronor other than Stantons International Securities acting as an independent expert for the purposes of this report. Stantons International Audit and Consulting Pty Ltd ("SIAC") (the parent entity of Stantons International Securities) and Stantons International Securities undertook an independence assessment and considered that there are no existing relationships between Stantons International Securities and the parties participating in the Transaction detailed in this report which would affect our ability to provide an independent opinion. The fee (excluding disbursements) to be received for the preparation of this report is based on time spent at normal professional rates plus out of pocket expenses. Our fee for preparing this report is expected to be up to A\$30,000 exclusive of GST. The fee is payable regardless of the outcome. With the exception of that fee, neither Stantons International Securities nor Mr Samir Tirodkar have received, nor will or may they receive any pecuniary or other benefits, whether directly or indirectly for or in connection with the preparation of this report. We note that Stantons International Securities has previously prepared an IER for the Company (then named African Petroleum Limited) that was issued in March 2019.

Stantons International Securities does not hold any securities in Petronor. There are no pecuniary or other interests of Stantons International Securities that could be reasonably argued as affecting its ability to give an unbiased and independent opinion in relation to the proposal. Stantons International Securities and Mr Samir Tirodkar have consented to the inclusion of this report in the form and context in which it is included as an annexure to the NoM.

QUALIFICATIONS

We advise Stantons International Securities Pty Ltd is the holder of an Australian Financial Services License (No 448697) under the Corporations Act 2001 relating to advice and reporting on mergers, takeovers and acquisitions involving securities. Stantons International Securities Pty Ltd has extensive experience in providing advice pertaining to mergers, acquisitions and strategic financial planning for both listed and unlisted businesses.

Mr Samir Tirodkar, the person with overall responsibility for this report, has experience in the preparation of valuations for companies, particularly in the context of listed company corporate transactions, including the fairness and reasonableness of such transactions. The professionals employed in the research, analysis and evaluation leading to the formulation of opinions contained in this report, have qualifications and experience appropriate to the tasks they have performed.

DECLARATION

This report has been prepared at the request of Petronor to assist Non-Associated Shareholders of Petronor to assess the merits of the Transaction to which this report relates. This report has been prepared for the benefit of Petronor shareholders and those persons only who are entitled to receive a copy for the purposes under the Corporations Act 2001 and does not provide a general expression of Stantons International Securities' opinion as to the longer-term value of Petronor, its subsidiaries and/or assets. Stantons International Securities does not imply, and it should not be construed, that it has carried out any form of audit on the accounting or other records of Petronor or their subsidiaries, businesses, other assets and liabilities. Neither the whole, nor any part of this report, nor any reference thereto, may be included in or with or attached to any document, circular, resolution, letter or statement, without the prior written consent of Stantons International Securities to the form and context in which it appears.

DISCLAIMER

This report has been prepared by Stantons International Securities with due care and diligence. However, except for those responsibilities which by law cannot be excluded, no responsibility arising in any way whatsoever for errors or omission (including responsibility to any person for negligence) is assumed by

Stantons International Securities (and SIAC, its directors, employees or consultants) for the preparation of this report.

DECLARATION AND INDEMNITY

Recognising that Stantons International Securities may rely on information provided by Petronor and its officers (save whether it would not be reasonable to rely on the information having regard to Stantons International Securities experience and qualifications), Petronor has agreed:

• (a) to make no claim by it or its officers against Stantons International Securities (and SIAC) to recover any loss or damage which Petronor may suffer as a result of reasonable reliance by Stantons International Securities on the information provided by Petronor; and
• (b) to indemnify Stantons International Securities against any claim arising (wholly or in part) from Petronor, or any of its officers, providing Stantons International Securities with any false or misleading information or in the failure of Petronor or its officers in providing material information, except where the claim has arisen as a result of wilful misconduct or negligence by Stantons International Securities.

A final draft of this report was presented to Petronor for a review of factual information contained in the report. Comments received relating to factual matters were considered, however the valuation methodologies and conclusions did not change as a result of any feedback from Petronor.

APPENDIX E

RESOURCEINVEST INDEPENDENT TECHNICAL ASSESSMENT AND VALUATION REPORT DATED 31 MARCH 2021

31 March 2021

Mr Samir Tirodkar Director Stantons International Securities Pty Ltd Level 2, 1 Walker Avenue West Perth WA 6005

Dear Sir,

INDEPENDENT VALUATION REPORT ON THE PETRONOR E&P LIMITED OIL AND GAS ASSETS

BACKGROUND

The directors of Petronor E&P Limited ("Petronor" or the "Company") have engaged Stantons International Securities Pty Ltd ("SIS") to prepare an independent expert's report ("IER") on the fairness and reasonableness of the proposed acquisition of the balance of shares it does not currently hold in subsidiary, Hemla Africa Holdings AS ("HAH").

Petronor is an Australian company listed on the Oslo Stock Exchange and currently holds interests in oil and gas assets in Republic of Congo, Gambia, Guinea Bissau, Senegal and Nigeria.

HAH holds producing licenses in the Republic of Congo. Petronor owns a 70.707% interest in HAH, and the remaining 29.293% is held by Symero Limited ("Symero"), an entity owned by Mr Knut Sovold (CEO of Petronor) and Mr Gerhard Ludvigsen (former director of Petronor).

Petronor is proposing to acquire Symero's 29.293% interest in HAH for consideration of US\$18 million, to be settled through the issue of new ordinary shares in Petronor (the "Transaction").

As part of their assignment, SIS will be required to include a valuation of the oil and gas assets of PetroNor (fair market value) as part of an overall valuation of Petronor. SIS has requested ResourceInvest Pty Ltd ("ResourceInvest") to act as a specialist and prepare an independent fair market valuation report on the oil and gas assets for attachment to their IER.

DECLARATIONS

Codes

This Report has been prepared in accordance with the VALMIN Code, 2015, which is a Code for the Technical Assessment and Valuation of Mineral and Petroleum Assets and Securities for Independent Expert Reports. The VALMIN Code provides guidance on matters that may be subject to the Australian Corporations Act 2001, the associated Corporations Regulations, other provisions of Australian law, the published policies and guidance of ASIC and the Listing Rules of the ASX.

Qualification

This Report is prepared by Mr Peter Cameron, a Director of ResourceInvest who graduated with a BSc (Hons) from the University of Tasmania in 1971. He is a Fellow and Chartered Professional of the Australasian Institute of Mining and Metallurgy, and a member of the Petroleum Exploration Society of Australia, the American Association of Petroleum Geologists, and a member of the Society of Petroleum Engineers. He has held technical (geophysical), managerial and analytical roles in government, the oil & gas, and securities industries over a period of thirty five years and thus has the appropriate qualifications to be considered 'Competent' in the Petroleum Industry under the meaning of the term in the VALMIN Code.

Reserves and Resources

References in this report to Reserves and Resources have been classified in accordance with SPE-PRMS.

Information in this report which relates to Petroleum Reserves, Contingent Resources, and Initially-Inplace Resources is based on, and fairly and accurately reflects in the form and context in which it appears, information and supporting documentation prepared by, or under the supervision of AGR Petroleum Services AS (AGR), and AGR TRACS International Ltd AGR TRACS).

AGR and AGR TRACS, as independent Qualified Petroleum Reserves and Resources Evaluators for Petronor, have confirmed to ResourceInvest that the references to AGR and AGR TRACS and the hydrocarbon reserve and resources information in this report which relate to the Republic of Congo (PNGF Sud and Bis fields) and Nigeria (AJE Field, OML113) is based on, and fairly and accurately reflects in the form and context in which it appears, information and supporting documentation prepared by AGR and AGR TRACS.

AGR has consented to the inclusion of the references to AGR and the inclusion of the hydrocarbon reserves information in this report dated 30 March 2021 which relates to the PNGF Sud and Bis fields, and the AJE field, in the form and context in which it appears.

AGR TRACS has consented to the inclusion of the references to AGR TRACS and the inclusion of the hydrocarbon reserves information in this report dated 31 March 2021 which relates to the AJE field, in the form and context in which it appears.

The authors of the AGR and AGR TRACS reports are Petroleum Engineers and Geoscientists with 25+ years of international and sufficient experience relevant to the evaluation and estimation of Petroleum Reserves, Contingent Resources and Prospective Resources to qualify as a Qualified Reserves and Resources Evaluator according to PRMS-SPE.

The information in this report with respect to Guinea Bissau Block 2 which relates to Prospective Resources is based on, and fairly and accurately reflects in the form and context in which it appears, information and supporting documentation prepared by, or under the supervision of, Mr Michael Barrett who is a member of The European Association of Geoscientists and Engineers. Mr Barrett is an employee of PetroNor E&P Limited and has sufficient experience which is relevant to the evaluation and estimation of Petroleum Reserves, Contingent Resources and Prospective Resources to qualify as a Qualified Reserves and Resources Evaluator. Mr Barrett consents to inclusion in the report of the matters based on his information in the form and context in which it appears.

Independence & Previous Work

Neither ResourceInvest, nor any director or employee has, or has had, any shareholding, or related interest in Petronor, or any of their subsidiary companies. Furthermore, neither ResourceInvest, nor any director or employee has, or has had, any interest or contingent interest in the assets of Petronor.

ResourceInvest has prepared this report at the request of SIS and will be paid a consulting fee of approximately A\$38,500 for this service. Payment of the fee is in no way contingent upon the outcome of the report.

ResourceInvest believes that the report is a true, full and accurate account of the basis for determining the market value of the oil and gas assets under review, and includes all relevant information and assumptions. Except to the extent indicated in the report, all information and explanations requested and required to prepare the report were available and used subject to satisfactory verification to the extent set out in the report.

The information contained in this report was obtained from sources we believe to be reliable but ResourceInvest, its directors, employees and consultants do not represent, warrant or guarantee that this information is complete or accurate and no liability is accepted for any errors or omissions.

ResourceInvest has previously provided an Independent Valuation Report on the PNGF Sud and PNGF Bis assets in the Republic of Congo to African Petroleum Ltd in March 2019. By a reverse takeover in 2019 African Petroleum Ltd became PetroNor E&P Ltd.

VALUATION

SIS has sought a Market Value of the oil and gas assets of PetroNor E&P Ltd. Market Value is the estimated amount for which an asset or liability should exchange, on the valuation date, between a willing buyer and a willing seller in an arm's length transaction, after proper marketing and where the parties had each acted knowledgeably, prudently and without compulsion.

Our valuation is for:

• PNGF Sud (11.90%), Republic of Congo,
• PNGF Bis (16.66%), Republic of Congo,
• OML 113 (13.1%) in the AJE Field, Nigeria,
• Block A4 (90%) in the Gambia
• Sinapa Licence (Block 2, 78.57%) and Esperança Licence (Blocks 4A & 5A, 78.57%) in Guinea Bissau
• SOSP and ROP Blocks (90%, adjusted for a 10% non-controlling interest, effectively 81%), Senegal.

Collectively the PetroNor oil and gas Assets.

We have provided a Low, a High and a Preferred Values in the report and our Preferred Value of the assets at 1 January 2021 is US\$196.7 million.

Signed

Peter Cameron Director ResourceInvest Pty Ltd

	BACKGROUND
	DECLARATIONS		( I )
Codes
	Qualifications
	Independence
	VALUATION		( II )
1		METHODOLOGY 4
2		SUMMARY 7
3		THE CONGO ASSETS 8
3.1		Overview 8
3.2		PNGF Sud 11
	3.2.1	Fields and Reservoirs 13
	3.2.2	Reserves and Resources 13
3.3		PNGF Bis 14
3.4		Valuation 16
	3.4.1	Production forecast compared with Reserves/Resources 16
	3.4.2	Input Brent oil price assumptions 18
	3.4.3	Unrisked NPV Valuation 19
	3.4.4	Market Valuation 20
	3.4.5	Value per unit of production. 21
	3.4.6	Other West African Transactions. 21
4		OML 113, AJE FIELD, NIGERIA 25
4.1		Reserves 26
4.2		Tenure OML113 28
	4.2.1	PetroNor Interest 28
4.3		Development Programme 29
4.4		Valuation 30
	4.4.1	Capital Requirements 31
	4.4.1	Other West African Transactions. 32
5		EXPLORATION ASSETS 33
5.1		SOSP and ROP Blocks Senegal 36
5.2		Block A4, The Gambia 37
5.3		Sinapa Licence and Esperança Licence, Guinea Bissau 39
5.4		Exploration Programme 42
5.5		Farmout Valuation 43
	5.5.1	Senegal 43
	5.5.2	Gambia 43
	5.5.3	Guinea Bissau 44
6		REFERENCES 47
7		APPENDIX 1 TENURE DOCUMENTATION 48
8		APPENDIX 2 TENURE HISTORY OML 113 51
9		APPENDIX 3 DISCOUNT FACTOR 54
10		APPENDIX 4 SPE-PRMS CLASSIFICATION 60
11		APPENDIX 5 - GLOSSARY 62

Table 1. 'Notional' versus 'Actual' Farm-out approach. 4
Table 2. Possible valuation approaches according to development status 5
Table 3. Summary of PetroNor oil and gas assets. 7
Table 4. Valuation of PetroNor oil & gas assets (US\$ million). 7
Table 5. PNGF Sud - Summary of fiscal terms 10
Table 6. PNGF Sud Fields. 13
Table 7. AGR Reserves and Contingent Resources (Oil plus gas) 14
Table 8. PNGF Bis Contingent Resources (Vandji reservoir) 16
Table 9. PNGF Bis production forecast compared to AGR 2C and 3C Resources 17
Table 10. Market oil price forecasts 18
Table 11. Unrisked NPVs for PNGF Sud and PNGF Bis (100%) 19
Table 12. Net PetroNor unrisked NPVs for PNGF Sud (11.90%) and PNGF Bis (16.66%) 20
Table 13. Risk Factors. 20
Table 14. Risked net NPVs 20
Table 15. Market Value of Congo Assets. 21
Table 16. Values per unit of production. 21
Table 17. West African transactions. 22
Table 18. West African transaction metrics. 23
Table 19. Aje Field Reserves, 1 January 2019, AGR TRACS International Ltd 27
Table 20. Operating cost and Revenue interests of Aje Petroleum and JV in OML113 28
Table 21. Liquids and Gas production compared with 2P Reserves 30
Table 22. Capex requirements for Phased gas development. 31
Table 23. Value of Upstream & Midstream Companies for three gas export cases 32
Table 26. Comparison of NPV12 and NPV18 32
Table 27. Value per unit boe 32
Table 26. Prospective resources (mmbbls) Atum / Anchova 41
Table 27. Proposed exploration programme. 42
Table 28. Risked Farmout Values. 45
Table 29. Senegal Value with no Tenure Risk 45
Table 30. Exploration Asset Values 45
Table 31. Cost based value comparison. 46
Table 32. Beta calculation 56
Table 33. S&P CapIQ levered beta PetroNor. 56
Table 34. ResourceInvest levered beta PetroNor 57
Table 35. Discount Factor summary derivation for The Congo. 59
Table 36. Discount Factor summary derivation for OML 113 gas development. 59

List of Tables

List of Figures

Figure 1. Generalised stratigraphic column Congo Basin. 8
Figure 2. Schematic cross-section Offshore Congo Basin. 9
Figure 3. Contractor Netback per barrel. 10
Figure 4. Offshore Congo location of PNGF Sud and PNGF Bis. 11
Figure 5. PNGF Sud and PNGF Bis, field and well locations. 12
Figure 6. Typical section in PNGF Sud 13
Figure 7. Schematic well profile for proposed LUSOM-2. 15
Figure 8. Vandji depth map Loussima SW. 15
Figure 9. PNGF Sud Reserves and Resources compared to forecast Production. 17
Figure 10. Brent oil price assumptions. 19
Figure 11. Implied value of West African transactions (US\$/bbl). 24
Figure 12. OML 113 and Aje Field location map. 25
Figure 13. Top Turonian Depth map showing well entry points. 26
Figure 14. Proposed production profile Aje gas development 29
Figure 15. Implied value of West African transactions (US\$/boe). 32
Figure 16. PetroNor exploration areas 33
Figure 17. The Senegal Province 33
Figure 18. MSGBC basin stratigraphy. 34
Figure 19. Schematic oil plays Senegal, Gambia, Guinea Bissau. 35
Figure 20. The SNE-1 (now Sangomar) and FAN-1 discoveries 35
Figure 21. ROP and SOSP Block, Senegal 36
Figure 22. Seismic line across Boabab prospect, ROP Block 37
Figure 23. Gambia prospects and leads 38
Figure 24. Block A4 - Regional context. 38
Figure 25. Sinapa Licence (Block 2) and Esperança Licence (Block 4A & 5A) 39
Figure 26. Sangomar analogue to Atum / Anchova 40
Figure 27. Proposed Atum 1X location and seismic cross-section 41
Figure 28. Norwegian 10 year Government Bond yield Jan 2010- Jan 2020 55
Figure 29. Australian 10 year Government Bond yield Jan 2010- Jan 2020 55
Figure 30. Nigeria Risk ratings. 58
Figure 31. SPE-PRMS Resource Classification. 61

1 Methodology

The valuation undertaken here is to be attached to the SIS Independent Expert's Report ("IER") to determine the fairness and reasonableness relating to the proposed acquisition of oil and gas assets and an associated issue of shares in PetroNor.

Value under the VALMIN Code (2015) is defined as the Market Value of a Mineral or Petroleum Asset or Security. It is the amount of money (or the cash equivalent of some other consideration) determined by a Specialist in accordance with the provisions of the VALMIN Code (2015) for which the Mineral or Petroleum Asset or Security should change hands on the Valuation Date in an open and unrestricted market between a willing buyer and a willing seller in an arm's length transaction, after appropriate marketing, with each party acting knowledgeably, prudently and without compulsion. It may comprise a Technical Value adjusted for factors such as market or strategic considerations.

The VALMIN Code (2015) outlines three widely accepted Valuation Approaches:

• 1. Market-based
• 1. Income-based
• 1. Cost-based

A Market-based approach is based primarily on the notion of substitution. In this approach the asset being valued is compared with the transaction value of similar assets under similar time and circumstance in an open market. Methods may include comparable sales transactions, joint venture terms or farm-in agreement term analysis.

A simple purchase of an interest is a direct indication of value. A farmout usually requires that a farminee pays a 'premium' to the farmor in order to earn an interest in the permit. Thus, to earn a 50% interest, a farminee may pay 100% of the cost of a particular work programme (a 2:1 promote). In this case the additional 50% of the programme cost paid represents the 'premium' paid by the farminee. It can be considered the value of a 50% interest.

We further recognise that this approach can be applied in both a 'notional' sense – a comparable transaction where no farmout actually occurs – and in an 'actual' sense – where a farmout does, or must, occur. The difference being, in the 'notional' case the premium value as a \$ value/percentage point, is applied to the percentage interest being valued without considering any farmout dilution, but in the 'actual' case the \$ value/percentage point is applied to the post-farmout diluted interest. The difference is illustrated in Table 1.

FarmCo interest	100%
Cost of work	\$20m
Farminee pays	100% of \$20m
Farminee earns	50%
Premium value	50% of \$20m = \$10m
Value per % point	% 0.2 m
Value of Permit	\$20 m
Notional Farmout
FarmCo interest	100%	FarmCo Value \$20m
Actual Farmout
FarmCo interest	50%	FarmCo value \$10m

Table 1. 'Notional' versus 'Actual' Farm-out approach.

An Income-based approach is based on the notion of cashflow generation. In this approach the anticipated benefits of the potential income or cash flow of an asset are analysed. Valuation methods here are primarily based on discounted cashflow (DCF) or earnings multiples, but may include Expected Monetary Value (EMV), Monte Carlo analysis and Option pricing.

A Cost-based approach is based on the notion of cost contribution to value. In this approach the costs incurred on the asset are the basis of analysis, and may include sunk costs or current replacement costs.

The cost of a future work commitment a company or joint venture makes to a Government can be considered as a metric for a cost-based approach. It represents the amount a company would pay to realise the potential value of a permit given their assessment of the risk of exploration.

Care must be exercised, as money spent on a permit during the term of that permit may downgrade or enhance the prospectivity, and hence value, of that permit. Also, commitments can vary depending on market conditions at the time of application, and monetary commitments can quickly become unrealistic. If the permit is in good standing, however, and the work commitment is technically justified, this method can provide a reliable valuation metric.

While each Valuation is time and circumstance specific, a general guide to the applicability of each Valuation Approach is outlined with respect to the stage of exploration or development of the asset in Table 2.

Valuation Approach	Exploration Projects	Pre-development projects	Development projects	Production projects
Market	Yes	Yes	Yes	Yes
Income	No	In some cases	Yes	Yes
Cost	Yes	In some cases	No	No

Source: VALMIN Code (2015)

In this valuation we have used the Income-based approach to value the Congo and Nigerian assets, and provided a market based analysis for comparative purposes. For the exploration assets we have used a market based analysis and a cost based analysis for comparative purposes.

Discounted Cash Flow model

Specifically, we have used a discounted cash flow analysis to value the Congo and Nigerian assets based on an economic models provided by Petronor.

The PNGF Sud assets are in production, and have production forecasts based on a number of development scenarios. While the PNGF Bis asset is not in production, there have been discoveries made and engineering studies undertaken to allow a meaningful conceptual cash flow model to be generated.

The Nigerian asset presently has marginal oil production, and there is a development plan to capture the gas resource.

We have modified the models where we think appropriate to allow us to make our own input price assumptions, adjust timing assumptions and undertake sensitivity analysis. We have judiciously used a risked DCF analysis of these models in arriving at a range of values for the Congo and Nigerian assets.

Discount Factor

We have used a post-tax nominal discount factor of 12.0% for net present value (NPV) calculations for the production assets in The Congo. The derivation of the discount factor using a weighted average cost of capital methodology is described in Appendix 3. It includes a 'country risk' factor.

For our valuation of the OML 113 Aje Field gas development we have also included a 'project risk' factor in addition to the 'country risk' factor in the derivation of the discount factor, and use a discount factor of 18%, also shown in Appendix 3.

We have provided an analysis in Section 4.4 where specific project risk is removed from the discount factor derivation but applied as a post-NPV notional project risk factor, as a cross check.

Currency

All references to Dollars in this report refer to US Dollars, unless otherwise specified.

2 Summary

The PetroNor oil and gas assets are detailed in Table 3.

ResourceInvest has reviewed tenure documentation and correspondence, joint venture documentation and correspondence (as detailed in Appendix 1 and Appendix 2), and is satisfied that the tenure and status of the permits are as stated. ResourceInvest does not, however, represent, warrant or guarantee that this is so.

Permit	Country	Regional Description	Interest
PNGF Sud	Congo	Offshore	11.90%
PNGF Bis	Congo	Offshore	Right to acquire 16.66%
OML 113	Nigeria	Offshore	13.1%
Sinapa Licence Block 2	Guinea Bissau	Offshore	78.57%
Esperança Licence Blocks 4A, 5A	Guinea Bissau	Offshore	78.57%
Block A4	The Gambia	Offshore	90.0%
ROP Block	Senegal	Offshore	90.0%* (under arbitration)
SOSP Block	Senegal	Offshore	90.0%* (under arbitration)

		Table 3. Summary of PetroNor oil and gas assets.
--	--	--------------------------------------------------

* PetroNor's Senegal interests are held by a subsidiary company African Petroleum Senegal Ltd which has a 10% non-controlling interest. This implies an effective 81% interest to PetroNor shareholders.

A summary of our valuation is given in Table 4.

Table 4. Valuation of PetroNor oil & gas assets (US\$ million).

	Interest	Low	Preferred	High
PNGF Sud	11.90%	117.7	126.3	134.9
PNGF Bis	16.66%	13.8	15.0	16.3
OML 113	13.1%	20.0	25.3	35.6
Sinapa Licence	78.57%	11.1	11.1	13.0
Esperança Licence	78.57%	0	6.2	8.1
Block A4	90.0%	10.4	10.4	13.5
ROP Block	90.0% (81%)	0	0	0
SOSP Block	90.0% (81%)	0	2.3	11.9
Total		173.0	196.7	233.3

NB. Sums may not exactly match Total due to rounding.

3 The Congo Assets

3.1 Overview

The Congo Basin is part of the large Aptian salt basin of equatorial west Africa which extends from Cameroon in the north to Namibia in the south. This basin formed during the breakup of North America, Africa, and South America at the culmination of the Late Jurassic to Early Cretaceous rifting of an extensive Palaeozoic basin. The Aptian salt basin has undergone a typical, but complex, history that can be divided into pre-rift; syn-rift and post-rift stages. Figure 1 shows a generalised stratigraphic column of the Congo Basin, showing ages, lithology and potential reservoir and source rocks, and tectonic stages.

Figure 1. Generalised stratigraphic column Congo Basin.

Source: Brownfield and Charpentier, 2006

Figure 2 is a schematic cross-section of the northern Congo Basin showing pre-salt and post-salt rock units and the approximate location of the PNGF Sud and Bis licences. Salt was deposited during the late Aptian throughout the equatorial west Africa basins and offshore Congo is represented by the Loeme Salt, which can be at least 1,000 m thick. The thick salt in the basin is important as it acts as a decollement zone for many of the post-salt growth fault structures in the basin.

Source: Brownfield and Charpentier, 2006

Congo (Brazzaville) is among the top five oil producers in Sub-Saharan Africa, producing between 300 and 400 thousand barrels of oil per day. The first significant discovery was in 1972, and oil production comes almost entirely from offshore. Foreign oil company participation is through a Production Sharing Agreement (PSA) with the State prior to the start of their activities. Typically, PSAs are signed with all petroleum companies composing the Contractor group under the PSA, which group also includes the State-owned national petroleum company (SNPC).

Under a PSA, the portion of Cost Oil which may be allocated to the reimbursement of the petroleum costs incurred by the contracting parties is limited to a percentage of the total annual hydrocarbon production. The actual percentage is called the Cost Stop. Profit Oil, which is allocated to the State and the contractor entities in the proportion provided for in the PSA, corresponds to the total annual hydrocarbons production, decreased by Cost Oil and the Royalty. Exact fiscal terms of such contracts are negotiated for each licence.

The PNGF Sud fiscal regime is summarised in Table 5, and example Netback per barrel at different oil prices is shown in Figure 3

Table 5. PNGF Sud - Summary of fiscal terms.

		Comment
Government Royalty	15%	percentage of oil production after super-profit sharing
Cost Stop (Ceiling)	50% - 55%	production remaining after super-profit sharing and royalty is available for cost recovery, subject to a ceiling that is a negotiated percentage of gross production
Profit Oil to Contractor	50% - 30%	depends on cumulative oil produced from individual fields, balance goes to government
Super profit oil to Contractor	34% / 30%	share of the value of produced hydrocarbons calculated with differential of the actual achieved oil price and the ceiling prices
Ceiling price (US\$/bbl)	90	2017-2023
	40	rd contract period 3

Figure 3. Contractor Netback per barrel.

3.2 PNGF Sud

The PNGF Sud licence is located 25 km off the coast of Pointe Noire and includes the 4 producing fields Tchibouela, Tchendo, Tchibeli, Litanzi and one shut-in field - Tchibouela East (Figure 4 and Figure 5) which were discovered from 1979 to 1990. Production commenced in 1987 and are currently flowing at ~22,700 boepd on a gross basis. The field is a shallow water development comprising seven steel jackets as drilling or processing centres. Oil from Tchibouela/Tchendo/Litazi is exported via the onshore Djeno terminal, and oil from Tchibeli is exported via the NKOSSA FPSO.

The PNGF Sud block was taken over by a new licence group in January 2017, comprising:

•	SNPC	15%
•	Continent Congo SA	10%
•	Africa Oil & Gas Corporation	10%
•	Petro Congo	5%
•	Perenco (Operator)	40%
•	HEMLA E&P Congo SA	20%

PetroNor holds a 70.71% interest in Hemla Africa Holding AH (HAH) which in turn holds an 84.15%¹ interest in HEMLA E&P Congo (HEPCo), giving Petronor a net 11.9% interest in the block. This 11.90% interest is the subject interest in PNGF Sud.

There have been significant operational improvements following the new Perenco operatorship:

• Production has grown from ~15,000 bopd to greater than 22,000 bopd in 2020
• Operating costs have been reduced, and
• Perenco plans to further increase production by workover and infill drilling.

Figure 5. PNGF Sud and PNGF Bis, field and well locations.

¹ This interest recently increased from 74.25% to 84.15% after a court ruling in the Congo awarded HAH an additional 9.9% shareholding from MGI International SA as a result of a covenant breach by MGI International SA.

3.2.1 Fields and Reservoirs

The fields produce from a variety of post-salt reservoirs ranging in age from Albian to Senonian, and varying depositional environments. Depths vary from 350 to 1900 metres as shown in Table 6 and Figure 6. In Tchibouela and Tchendo the major reservoirs are the Cenomanian Sendji Formation, and the Turonian Loango Formation. The younger Senonian Emeraude Siltstone in Tchibouela is a tight reservoir holding a gas accumulation and a thin oil zone. It has not produced oil. In Tchendo the Senonian does produce oil but the reservoir is similarly of low permeability.

	Producing Formation	Reservoir Depth m	STOOIP mmbbls	Porosity %	Permeability mD
Tchibouela &	Senonian	350	1500 MSm3 gas	20	1-50
Tchibouela East (shut-in)	Turonian	500	269	20-23	400-2000
	Cenomanian	600	665	26	>2000
	Senonian	450	842	23	1-50
Tchendo	Turonian	600	155	24	10-1000
	Cenomanian	750	31	26	>2500
Tchibeli	Albian	1900	134	19	150
Litanzi	Albian	1800	70	19	150

Table 6. PNGF Sud Fields.

Figure 6. Typical section in PNGF Sud

3.2.2 Reserves and Resources

An independent study by AGR Petroleum Services in October 2019 commissioned by Petronor, evaluated 1P, 2P, 3P reserves, as well as 1C, 2C and 3C contingent resources. Their reporting was in accordance to the SPE-PRMS with effective date 1 January 2019, and assumes production continues to the end of 2041.

Although the reserves and contingent resources are reported in MMboe, only the Tchibouela Main field actually includes gas. All other fields only have oil reserves and contingent resources. Their results are given in Table 7

Units - mmboe					Infill Drilling
	1P	2P	3P	1C	2C	3C
Tchibouela	44.3	63.8	82.6	6.7	9.7	18.8
Tchendo	12.1	20.5	25.6	8.9	10.7	19.6
Tchibeli	9.1	15.1	19.4	8.0	9.7	15.1
Litanzi	10.7	13.2	17.8
Total	76.2	112.6	145.4	23.6	30.1	53.5

		Table 7. AGR Reserves and Contingent Resources (Oil plus gas).
--	--	----------------------------------------------------------------

In the valuation section below, we compare these estimates to the forecast production volumes form our evaluation model.

3.3 PNGF Bis

The PNGF Bis licence is located to the northwest of PNGF Sud (Figure 5), and has no production, but two wells have flowed oil on test. The right to PNGF Bis block was granted to SNPC and Perenco in February 2017, at the time of the renewal of PNGF Sud. In March 2018 HEPCo agreed to join this joint venture, which has the following percentage interests:

•	SNPC	15%
•	Perenco (Operator)	57%
•	HEMLA E&P Congo SA (right to enter)	28%

PetroNor holds a 70.71% interest in Hemla Africa Holding AH (HAH) which in turn holds an 84.15%² interest in HEPCo, giving Petronor a right to a net 16.66% interest in the block. This 16.66% option interest is the subject interest in PNGF Bis.

Three exploration wells have been drilled in the licence – LUSM-1 (1985), LUSOM-1 (1987), and SUEM-2 (1991). LUSM-1 and SUEM-2 were both drilled on the Loussima SW structure (Figure 5), and flowed 45 degree API oil at 4,692 bopd and 1,145 bopd respectively, from the pre-salt Neocomian Vandji Formation. Hydrocarbon shows have also been detected in the Albian post-salt Senji Formation.

The Operator has proposed an extended production test of a new well (LUSOM-2), with oil exported via an 11 kilometre catenary pipeline to Tchibouela. FID is planned for the first half of 2019. LUSOM-2 will target the secondary Sendji reservoir and then deviate to the primary Vandji reservoir (Figure 7).

² This interest recently increased from 74.25% to 84.15% after a court ruling in the Congo awarded HAH an additional 9.9% shareholding from MGI International SA as a result of a covenant breach by MGI International SA.

Figure 7. Schematic well profile for proposed LUSOM-2.

A Vandji depth map with a single oil water contact at 3,357m is shown in Figure 8 with in-place volume estimate of 90 mmbbl oil in-place (STOOIP), and a cross section indicating seven sub-zones identified in LUSOM-1 and SUEM-2. An upside case, with a lower oil water contact into zone E5 could provide an additional 10 mmbbl STOOIP.

Figure 8. Vandji depth map Loussima SW.

The Operator has also indicated potential in the shallower Sendji reservoir of between 3.2 and 10.6 mmbbl STOOIP, with volume variation depending on oil column thickness and fault sealing.

AGR have reviewed the Operator's STOOIP estimates and have verified Contingent Resources for the Vandji reservoir only. They provide a seven year extended production test, and a full field development scenario (Table 8).

	Oil (mmbbl)
	1C	2C	3C
Test well, 7 years production	0.4	1.9	3.8
Full field development	22	27	32

Table 8. PNGF Bis Contingent Resources (Vandji reservoir).

3.4 Valuation

An economic model constructed by Petronor (PNGF_economics_model_2020_v8.27.xls) was provided to ResourceInvest, and has been reviewed with respect to input price assumptions, production profiles, and capital and operating costs.

The model combines individual profiles and costs from Tchibouela, Tchendo, Tchibeli/Litanzi, PNGF Bis and allows four different reserve/resource cases to be evaluated.

For PNGF Sud the four cases are:

Case A – assumes the decline of 2P reserves without further capital

• Case B assumes the inclusion of 2P reserves after workovers
• Case C assumes the inclusion of 2C resources with infill drilling

Case D – assumes the inclusion of 3C resources with further infill drilling

For PNGF Bis, the four cases are:

Case A – assumes 2 mmbbl from production testing of the LOSUM-2 well is exported to Tchibouela

Case B – assumes an additional 3.2 mmbbl from production testing of the LOSUM-2 well is exported to Tchibouela

Case C – assumes the development of 2C resources

Case D – assume the development of 3C resources

The model is built on quarterly increments from the 1st quarter 2017. We have considered cash flows from the 1st quarter of 2021 and discounted those cash flows to 1 January 2021.

Included in the operating cost of each field is a provision for the eventual abandonment cost of all facilities.

3.4.1 Production forecast compared with Reserves/Resources

We compare stated Reserves and Resources from AGR's 1 January 2019 report, and Reserves and Resources presented by PetroNor in a November 2020 presentation, to the Reserves and Resources produced under the economic model from 1 January 2021. This comparison is shown in Figure 9.

Figure 9. PNGF Sud Reserves and Resources compared to forecast Production.

The production forecast by the economic model shown in Figure 9 is in line with the AGR 2P and PetroNor 2P estimates. The 2C and 3C production forecast from the model is greater than stated by AGR, but less than indicated by PetroNor. Given the two year interval between the AGR Report and the present, and the joint venture proposed drilling programme over the next two years, we are comfortable with the forecasts in the economic model.

For PNGF Bis the production volumes modelled are shown in Table 9, compared with the AGR Resource estimates. While the model production does exceed the AGR 2C and 3C estimates we believe that this is a result of AGR not including any resource from the Sendji reservoir. As indicated below, we apply a significant discount to the PNGF Bis value to account for the uncertainty of these volumes.

		Oil (mmbbl)
	Case A/B	Case A/B + C	Case A/B + C + D
Model production	5	30	41
AGR estimates	1C	2C	3C
Test well, 7 years production	0.4	1.9	3.8
Full field development	22	27	32

3.4.2 Input Brent oil price assumptions

We have considered recent Brent oil price forecasts by the US Energy Administration (EIA, February 2021), the World Bank (October, 2020), and a compilation of leading oil & gas companies made by Stellar Energy Advisors (February, 2021) in Table 10. The shaded portion of Table 10 indicates escalation at 1% per annum beyond the end point of the forecast. We take an average of these forecast to arrive at a Market oil price forecast.

	EIA	World Bank	Stellar	Average
2021	53	44	45	47.33
2022	55	50	52	52.33
2023	57	52	58	55.78
2024	60	54	61	58.30
2025	62	57	63	60.48
2026	64	59	64	62.33
2027	66	62	64	64.18
2028	69	65	65	66.03
2029	71	67	66	67.88
2030	73	70	66	69.74
2031	74	71	67	70.66
2032	76	71	68	71.58
2033	77	72	68	72.51
2034	79	73	69	73.45
2035	80	74	70	74.39
2036	81	74	70	75.33
2037	83	75	71	76.28
2038	84	76	72	77.23
2039	86	77	72	78.19
2040	87	77	73	79.15

Table 10. Market oil price forecasts.

We have also considered the Brent Futures price at 21 February 2021, escalated at 1% per annum from 2029.

We have averaged the Brent Forward price with the Market price to give our Base oil price forecast. Our low and high price forecasts are -5%/+5% of the base price, shown in Figure 10.

Given that our oil price forecast is based on third party forecasts and forward prices made between October and 2020 and February 2021, we believe it is appropriate to use for cash flows discounted to 1 January 2021.

Figure 10. Brent oil price assumptions.

3.4.3 Unrisked NPV Valuation

We calculate the NPV at 1 January 2021 using a discount factor of 12% (ie a quarterly discount factor of 2.41%). We calculate the NPV for Case A + Case B, Case A + Case B + Case C and Case A + Case B + Case C + Case D and calculate the incremental value added by Case C and Case D. Table 11 shows these values at our Low, Base, and High oil price cases for a 100% interest.

Low Oil Price	Case A + Case B	Case C	Case D
	US\$m	US\$m	US\$m
PNGF Sud	774	220	262
PNGF Bis	32	194	120
Total	806	414	382
Base Oil Price
PNGF Sud	828	239	281
PNGF Bis	37	211	126
Total	865	450	407
High Oil Price
PNGF Sud	882	258	301
PNGF Bis	42	228	132
Total	923	486	433

Table 11. Unrisked NPVs for PNGF Sud and PNGF Bis (100%)

Table 12 shows the unrisked values net to PetroNor.

Low Oil Price	Case A + Case B	Case C	Case D
	US\$m	US\$m	US\$m
PNGF Sud	92	26	31
PNGF Bis	5	32	20
Total	97	58	51
Base Oil Price
PNGF Sud	98	28	33
PNGF Bis	6	35	21
Total	105	64	54
High Oil Price
PNGF Sud	105	31	36
PNGF Bis	7	38	22
Total	112	69	58

Table 12. Net PetroNor unrisked NPVs for PNGF Sud (11.90%) and PNGF Bis (16.66%).

3.4.4 Market Valuation

We apply Risk Factors to the calculated NPVs to arrive at a Market Value. We apply different Risk Factors to the different Cases depending on the level of confidence we have in the Reserves or Contingent Resources, and their chance of development. We use these Risk Factors, rather than adjusting the Discount Factor, because we are dealing with different classes of reserves and resources (2P, 2C, 3C) which correspond to separate increasing risks, rather than an overall project risk.

Our Risk Factors (RF) are applied to the calculated NPV to provide a discounted NPV:

RF X NPV = Discounted NPV, that is, the Discount applied = (100% - RF).

Our assessed risk factors are shown in Table 13, and the risked values in Table 14.

Table 13. Risk Factors.

	Case A + Case B	Case C	Case D
PNGF Sud	95%	80%	30%
PNGF Bis	50%	25%	15%

Table 14. Risked net NPVs.

	Case A + Case B	Case C	Case D	Total
	US\$m	US\$m	US\$m	US\$m
Low Oil Price
PNGF Sud	87.5	20.9	9.3	117.7
PNGF Bis	2.7	8.1	3.0	13.8
Total	90.1	29.0	12.4	131.5

	Case A + Case B	Case C	Case D	Total
	US\$m	US\$m	US\$m	US\$m
Base Oil Price
PNGF Sud	93.6	22.7	10.0	126.3
PNGF Bis	3.1	8.8	3.2	15.0
Total	96.6	31.5	13.2	141.3
High Oil Price
PNGF Sud	99.7	24.5	10.7	134.9
PNGF Bis	3.5	9.5	3.3	16.3
Total	103.1	34.0	14.0	151.2

Table 14 (continued) Risked net NPVs

We use the risked NPV values as our Low, Preferred and High Market Value as given in Table 15. Our preferred value is US\$141.3 million.

Table 15. Market Value of Congo Assets.

	Low US\$m	Preferred US\$m	High US\$m
PNGF Sud	117.7	126.3	134.9
PNGF Bis	13.8	15.0	16.3
Total	131.5	141.3	151.2

3.4.5 Value per unit of production.

Using forecast volumes from the economic model for our three production cases, and the respective totals from Table 14, we can calculate per unit value in each case. These are effectively unit value per 2P reserves; 2C and 3C resources. They are given in Table 16.

	Case A + Case B '2P'	Case C '2C'	Case D '3C'	Total
Net Production (mmbbl)	13.3	9.3	9.1	31.0
Low oil price US\$/bbl	6.8	3.1	1.4	4.1
Base oil price US\$/bbl	7.3	3.4	1.4	4.5
High oil price US\$/bbl	7.8	3.7	1.5	4.8

Table 16. Values per unit of production.

These per unit values allow comparison with other West African transactions.

3.4.6 Other West African Transactions.

We consider fifteen other West Africa oil acquisitions which have occurred since 2014, and compared their implied US\$ / 2P reserve ratio with our valuation. Where available we also consider US\$ / 2C resource and US\$ / total resource ratios. These are summarised in Table 17 and Table 18Error! Reference source not found.

The 2P implied values are plotted in Figure 11, together with the WTI oil price from 2014 to 2021, and our derived (US\$/2P-bbl) preferred, high, and low values. On this basis our 2P values conform to transactions over this period. We note that the transactions in 2020 were during a much lower oil price regime. It should be noted that the two most relevant recent transactions, the Woodside purchase of Senegal interests from Cairn and FAR in 2020, were for a development project not expected to be in

production until 2023. The US\$/2P for development assets is likely to be less than for production assets.

#	Date	Buyer	Seller	Asset
1	Dec 2020	Woodside	FAR	RSSD Senegal
2	Nov 2020	Vaalco	Sasol	Etame Marin Permit
3	Oct 2020	IPR	Dana Gas	Onshore Egypt
4	Sep 2020	Shell	Kosmos	Namibia, EG, South Africa
5	Aug 2020	Woodside	Cairn	RSSD Senegal
6	Aug 2020	Chevron	Noble	Company acquisition, numbers pro rated for African assets
7	Jul 2020	Perenco	Total	Gabon various fields
8	Apr 2020	Total	Tullow	Lake Albert, Uganda
9	Oct 2018	Maurel & Prom	Japan Oil Co / Mitsubishi	Blocks 3/05, 3/05A offshore Angola
10	Jul 2018	Assala Energy	Total SA	Gabon Rabi-Kounga oilfield, onshore Gabon
11	Oct 2017	Kosmos / Trident	Hess Corp	Ceiba / Okume oilfields, offshore Equatorial Guinea
12	Dec 2016	BW Energy	Harvest Natural Resources	Dussafu PSC Gabon
13	Jan 2016	Global Energy	MX Oil	OML113 offshore Nigeria ( Aje oilfield)
14	Jan 2016	Midwestern Oil & Gas	Mart Resources	Umusadege, OML18, offshore Nigeria
15	May 2014	Sonangol EP	Statoil ASA	Block 15/06, offshore Nigeria

Table 17. West African transactions.

Source: IHS Markit database, Stellar Energy Advisors, ResourceInvest

#	Reserve/resource mmbbl		Value US\$m	US\$ / 2P bbl	US\$ / 2C bbl	US\$ / total resource	US\$/bopd
1	2P 28 2C 32 + 30	Development	100	3.57		1.11
2	not disclosed	Production	49			5.9	11
3	2P 110	Production	236	2.11		3.02	2 7
4	-	Exploration	75*			-	-
5	2P 84.2 2C 164	Development	400	4.75		1.61
6	1P 132*	Production	300*	2.27		2.3
7	8,000 bopd	Production	350				44
8		Development	575			<2.0
9	2P - 9.5		80	8.42
10	2P - 18.5		100	5.40		5.40
11	2P/2C - 132		650		4.93
12	2C - 22.3 pre development		32		1.44
13	2P - 1.17 2C - 22.7		18	10.54 est.		0.75
14	not fully disclosed		304	10.96 est.
15	2P - 21.5		200	9.30
	Preferred value Congo assets		124.7	7.80	3.70	7.44
	* Estimate and pro-rated for African assets

Table 18. West African transaction metrics.

¹ 2P reserve reported by IPR

²source: Stellar Energy Advisors

Figure 11. Implied value of West African transactions (US\$/bbl).

4 OML 113, Aje Field, Nigeria

The Aje Field was discovered in 1997, and is located on the shelf edge, in the western Nigeria offshore Dahomey basin, some 24km south of the coast and 64km from Lagos (Figure 12). The Operator is Yinka Folawiyo Petroleum (YFP) and the development is managed by their wholly owned subsidiary, Folawiyo Aje Services ltd (FASL), headquartered in Lagos.

Figure 12. OML 113 and Aje Field location map.

Water depth across the field ranges from 99 metres to over 1,500 metres. The field contains hydrocarbon resources in sandstone reservoirs at three main levels: Turonian, Cenomanian and Albian. The field was discovered by Aje 1 in 1996 and was further appraised in 1997 by Aje 2, approximately 1 km to the east of Aje 1. A third well Aje 3, drilled as a step-out from the first two locations, confirmed the structural interpretation and resolved fluid distribution, but penetrated poorer quality reservoir. The 2008 appraisal; well Aje 4 confirmed the Turonian and Cenomanian reservoirs, and encountered a gas-condensate bearing interval in the deeper Albian interval.

As part of the initial phase of the Cenomanian oil development a new well Aje 5 was drilled in 2016, and completed as a Cenomanian producer. The reservoir performance, however, was disappointing, and the well watered out and was shut in. Two side-tracks were drilled (Aje 5-ST1, and Aje 5-ST2) to test the western and northern extent of the Cenomanian reservoir, but both wells came in deep to prognosis with limited oil columns. Aje 5-ST2 was therefore plugged back, and recompleted as a producer in the Turonian oil rim in 2017. Figure 13 shows a depth map to the top Turonian with well locations indicated.

Figure 13. Top Turonian Depth map showing well entry points.

Aje is primarily a gas condensate discovery and previous attempts to develop the gas resource have been postponed, as a result of difficulties in commercialising the gas.

A Field Development Plan (FDP) to develop the Turonian gas reservoir, was submitted to the Nigerian government in July 2017, which gained approval in September 2017.

4.1 Reserves

A Competent Persons Report (CPR), conducted in March 2019 by AGR TRACS International Ltd, reported reserve estimates for the Cenomanian and Turonian oil leg incorporating the Aje-4 and Aje-5ST2 production history from May 2016 to year-end 2018. The effective date for this report was 1 January 2019.

The Cenomanian and Turonian production anticipated from the Aje-4 and Aje-5ST2 wells during 2019- 2021 was classed as "Reserves – Developed Producing (DP)", while any oil production from those wells beyond 1 January 2022 was considered dependent on the Turonian gas development project commencing. The anticipated gas/condensate/oil/ LPG production from the Turonian development as well as any oil development from Aje-4 and Aje-5ST2 are considered as "Reserves – Justified for Development (JD)".

In March 2019, AGR TRACS considered the oil production from Aje-4 and Aje-5ST2 as marginal to sub-economic. This has proved to be the case, and we therefore assign no value to this production.

AGR TRACS note some uncertainty with respect to depth conversion of seismic data (as a result of low velocity in-fill in deeply incised valleys the shelf edge and above the Aje field) which could potentially impact resource size, and long term oil deliverability of the wells.

However, they provide a PRMS SPE classified Statement of 1P (Proved), 2P (Proved and Probable) and 3P (Proved, Probable and Possible) Reserves in their report (Table 19).

	1P	2P	3P
Oil (mmbbls)
DP (Cen. 2019-2021)	0.82	0.89	0.94
DP (Tur. 2019-2021)	1.23	1.36	1.49
Sub-total DP (2019-2021)	2.05	2.25	2.43
JD (Cen. 2022 onwards)	0.32	0.69	1.16
JD (Tur. 2022 onwards)	0.79	1.79	3.01
Sub-total (2022 onwards)	1.11	2.48	4.17
Condensate (mmbbls)
JD (2022 onwards)	10.32	17.41	27.87
LPG (mmbbls)
JD (2022 onwards)	20.11	33.86	54.39
Total Liquids (mmbbls)
DP Oil (2019-2021)	2.05	2.25	2.43
JD (2022 onwards oil, + cond. + LPG)	31.54	53.75	86.43
Sub-total Liquids (mmbbls)	33.6	56.0	88.9
Dry Gas (bcf)
Gas Cap Gas	261.6	442.0	704.9
Solution Gas	31.1	50.9	87.0
Sub-total Gas (bcf)	292.7	492.8	791.9
Total (mmboe)	82.4	138.2	220.8
Total (2022 onwards mmboe)*	80.4	136.0	218.4

* This Total added by ResourceInvest subtracts the AGR TRACS forecast 2019-2021 oil production from the Total mmboe provided by AGR TRACS. It did not appear in the AGR TRACS CPR.

4.2 Tenure OML113

A tenure history from the signing of the 2007 Joint Operating Agreement (JOA) of OML113 is provided in Appendix 2. This agreement established the introduction of farminee parties to OML113 under the operatorship of YFP, the farmor. It determines Participation Interests³ , and varying Capital and Operating cost interests, and Revenue and Cost Recovery interests during the period of meeting farmin obligations, and after meeting those obligations (pre- and post- the YFP payout).

Appendix 1 provides a summary of changing participation interests up to the entry of PetroNor into the joint venture.

4.2.1 PetroNor Interest

In the fourth quarter of 2019, PetroNor acquired an interest in OML 113 through two separate transactions:

• Acquisition of the shares in Pan Petroleum Aje Ltd, a company owned by Panoro Energy ASA, which had 6.5020% Participating interest in OML 113 (a 16.225% cost bearing interest, and a 12.1913% revenue interest). PetroNor paid US\$10 million in the form of PetroNor shares.
• Partnership with the existing operator of OML 113, YFP to revitalize the Aje field through a joint venture company Aje Production AS ("Aje Production"), owned 45% by PetroNor and 55% by YFP.

PetroNor and YFP contributed their direct interests in OML 113 to Aje Production, which thus holds a participating interest of 75.5020% in OML 113 and a Capex interest of 38.7550% in OML113. Net Operating Cost and Revenue Interests vary depending on whether the pre-existing farmin commitments have been met in favour of YFP. Table 20 shows Operating Cost and Revenue interests for the period before YFP payout, after YFP payout and after project payout.

	Pre YFP Payout		Post YFP Payout		Post Project Payout
	Opex Interest %	Revenue Interest %	Opex Interest %	Revenue Interest %	Opex Interest %	Revenue Interest %
Aje Production	38.7550	29.0663	38.7550	38.7550	54.063	54.0663
New Age	32.0700	24.0581	32.0700	32.0700	24.0582	24.0582
EER	22.5000	16.8750	22.5000	22.5000	16.8750	16.8750
ADM Energy	6.6750	5.0006	6.6750	6.6750	5.0006	5.0006
PetroNor share*	17.4398	13.0798	17.4398	17.4398	24.3284	24.3298
* The PetroNor share of Aje Production (45%)

Table 20. Operating cost and Revenue interests of Aje Petroleum and JV in OML113.

Thus, PetroNor's revenue share of OML113 is 13.08% (ie 45% of 29.0663%) until YFP payout. It then increases to 17.44% (ie 45% of 38.7550%), which is expected to occur in around three years.

³ Participation Interest reflects the Licence ownership prior to any farmin obligations to YFP, and cost sharing agreements with YFP, being imposed.

4.3 Development Programme

The revised development plan envisages the gas development divided between an Upstream company and a Midstream company. The initial development comprises the replacement of the existing FPSO, drilling of three new wells (one oil producer, two gas producers) and a gas pipeline tieback to shore with sales of wet gas.

The Upstream company will own a 100% economic interest in OML113 and be responsible for drilling, operations and maintenance of the field and FPSO, subsea, umbilicals, risers, flowlines, and the land connection to the West African Gas Pipeline (WAGP).

Liquids production will increase to ~7,000 bopd and gas production to 70 mmscfd in 2022 and up to 110 mmscfd in 2025 after the drilling of two additional wells.

The Upstream company will sell wet gas to the Midstream company at a transfer price of \$2.75/mmbtu.

The Midstream company will be responsible for the development of a gas processing facility, a power barge, and an LPG plant. Processed gas will be split between industrial use (into the WAGP) and power generation. This development is envisaged in two stages:

• 1a Onshore gas plant receiving facilities, civil works
• 1b Power barge with 4 X SGT-8000 turbines, 45 km of high voltage lines
• 2a Expansion of 2 X SGT-800 turbines
• 2b LPG extraction plant

A production profile based on both Phase 1 and Phase 2 developments is shown in Figure 14.

Figure 14. Proposed production profile Aje gas development.

Under these development scenarios, different volumes of oil, condensate, gas and LPG are produced. We compare liquids (in this case oil plus condensate), gas, and LPG production from our model with

2P Reserves from Table 19 above. The comparison is shown in Table 21, and indicates modelled production is largely well within 2P Reserves. The oil / condensate production in the 110 mmscfd + LPG case is, within error limits, the same as 2P Reserves.

	Oil / Condensate mmbbls	Gas bcf	LPG mmbbls	Total Boe
70 mmsfd	16.8	383.3		80.7
110 mmscfd	16.5	444.8		90.6
110 mmscfd + LPG	20.8	437.4	25.6	119.3
2P Reserves	19.9	492.8	33.86	136.0

Table 21. Liquids and Gas production compared with 2P Reserves.

4.4 Valuation.

Our valuation of the Aje field and gas development project is based on a DCF analysis of the proposed development, discounted to 1 January 2021. PetroNor have supplied ResourceInvest with an economic model (NEcoModel_v9.8 OML113_v21), which we have reviewed with respect to prices, costs, scenarios and timing. We have included our own oil price scenarios as previously described.

Our assumptions are:

• that PetroNor holds its interest through its 45% shareholding in the Special Purpose Vehicle with YFP – Aje Production AS.
• that Aje Production has a 38.755% capital and operating cost interest in the new Upstream company that will undertake the gas development, and a 29.0663% interest in the oil, condensate and gas revenue. This implies a net 13.08% (45% of 29.0663%) revenue interest to PetroNor, and a net 17.44% (45% of 38.755%) interest in capital and operating expenses. The 13.08% revenue interest will increase to 17.44% after YFP payout, expected to be in mid-2024.
• Existing JV partners retain their interest in OML113.
• Aje Production will maintain the same revenue and cost interests in the Midstream company.
• development proceeds with a new FPSO, the drilling of three new wells (two gas, one oil), and export of gas to shore. Gas production will initially be 70 mmscfd, but increase to 110 mmscfd after the drilling of two additional wells in 2025.
• The wet gas is to be sold to the Midstream company at a transfer price of \$2.75/mmbtu.
• The Midstream company will undertake the gas processing, construct a power generation barge, export dry gas, and build an LPG extraction plant.
• Capex as indicated in Table 22.

We have run three cases:

• 1. After initial Phase 1 development, production increases to 70 mmcfd, which is sold to the Midstream gas and power company.
• 1. Two further wells drilled to increase gas production to 110 mmcfd, which is sold to the Midstream gas and power company.
• 1. The Midstream gas and power company builds an LPG extraction plant, and expands power generation capability.

We take Cases 1, 2 and 3 as our Low, Preferred and High Values respectively.

The economic model provides a project NPV based on equity funding only or a combination of equity and debt funding. While we expect that the development will be project financed, we base our valuation on the project cash flows based on pre-financing cashflows.

The model allows a choice between Cases 1, 2, and 3 and gives separate cash flows for a 100% interest in both the Upstream and Midstream companies. We have combined the cash flows from the Upstream and Midstream companies, and calculated the PetroNor share using the capital, operating and revenue interests as described above. That is:

Prior to YFP payout in June 2024:	Capex, Opex 17.44%	Revenue 13.08%
Post YFP payout in June 2024:	Capex, Opex 17.44%	Revenue 17.44%%

Discounting is based on monthly cash flows to December 2038, and discounted to January 2021.

We have used a pre-finance discount factor of 18% which includes an allowance for project development risk, since this project, even though approved by the Nigerian Government, has not reached FID. Nor has final equity participation, equity financing or debt financing been completed.

FID is anticipated by PetroNor in the second quarter of 2021, and first oil and gas in the fourth quarter of 2022.

4.4.1 Capital Requirements

Table 22, shows the capital requirements for the different phases of the gas development. These are not incremental, but indicate total capital for each phase.

CAPEX US\$million		Upstream	Midstream	Total
Phase 1	70 mmscfd	319	124	443
Phase 1 + 2	110 mmscfd	415	172	587
Phase 1 + 2 + LPG	110 mmscfd + LPG	415	345	760

Our valuation is shown Table 23

Table 23. Value of Upstream & Midstream Companies for three gas export cases.

US\$ million	Phase 1	Phase 2	Phase 3
	Low	Preferred	High
100% interest	198.9	229.4	288.5
PetroNor share	20.01	25.31	35.62

We have also run the economics with a discount factor of 12%, and compared with the NPV18 values. Expressed as a percentage, this provide a measure of the implied risk, and is shown in Table 24. We consider that the implied risk factor of between 52% and 55% is appropriate for this project at this time.

Table 24. Comparison of NPV12 and NPV18.

US\$ million	Low	Preferred	High
NPV18	198.9	229.4	288.5
NPV12	374.0	420.5	551.0
NPV18/NPV12	53%	55%	52%

Table 25. Value per unit boe.

	Low	Preferred	High
Volume boe	80.7	90.6	119.3
NPV18	198.9	229.4	288.5
US\$/boe	2.46	2.53	2.42

Table 25 shows these values on a US\$/boe basis, which allows comparison with other West African transactions.

4.4.1 Other West African Transactions.

As described in Section 3.4.6 on Page 21 we have considered other West African transactions (Table 17 and Table 18). In Figure 15 we have plotted our values per unit boe for the OML 113 gas development project, along with these other transactions. We consider these values comparable.

Figure 15. Implied value of West African transactions (US\$/boe).

5 Exploration Assets

PetroNor has a regional exploration portfolio in three play-related offshore West African areas (Figure 16) that together represent parts of the Senegal province (Brownfield and Charpentier, 2003), shown in Figure 17. This province comprises onshore and offshore parts of the Senegal Basin along the northwestern African coast and includes Senegal, The Gambia, Guinea Bissau and Guinea. The Senegal Basin is an Atlantic-type passive margin of Middle Jurassic to Holocene age overlying a Palaeozoic basin. It is the largest of the northwest African Atlantic margin basins, with an offshore area in excess of 100,000 square kilometres.

Figure 17. The Senegal Province

The Senegal Basin formed at the culmination of a Permian to Triassic rift system that developed over an extensive Palaeozoic basin during the breakup of North America, Africa, and South America. The basin is divided into pre-rift (Upper Proterozoic to Palaeozoic), syn-rift (Permian to Triassic), and postrift (Middle Jurassic to Holocene) stages.

The tectono-stratigraphic evolution of the area (also referred to as the MSGBC Basin – Mauritania, Senegal, Gambia, Guinea Bissau, Guinea Conakry) is shown in Figure 18. A thick, basal carbonate shelf of Middle to Late Jurassic to Neocomian age continued during the Aptian and Albian in the northern (Mauritanian) part of the basin but included sandstones in the southern Casamance subbasin offshore Guinea Bissau. The Cenomanian is represented by thick marine shales interbedded with marginal marine sandstones, and minor carbonate-rock banks and reefs. The Turonian marks the time of maximum Cretaceous transgression and is represented by widespread black, and commonly bituminous, shale that is an important hydrocarbon source rock in the basin. The Senonian was a time of major marine regression that culminated with the deposition of widespread and thick sandstone units in the Maastrichtian. Tertiary sediments are unconformable with the Upper Cretaceous and consist primarily of marine shales and carbonates.

Figure 18. MSGBC basin stratigraphy.

The PetroNor Blocks are:

• Senegal SOSP, ROP subject to Arbitration
• Gambia Block A4 90% Operator
• Guinea Bissau: Sinapa (Block 2), Esperança (Blocks 4A, 5A) 78.6%, Operator

A schematic illustration of the offshore oil plays in Figure 19 shows shelf edge Cretaceous sandstones truncated by the sealing post-Albian unconformity, as well as deeper base-slope fan deposits. Both

these plays have been proven in the Sangomar (formerly called SNE-1) and Fan-1 discoveries offshore Senegal (Figure 20).

Figure 19. Schematic oil plays Senegal, Gambia, Guinea Bissau.

The region will likely witness significant activity over the next two to three years, with other joint ventures (FAR/Petronas, BP, CNOOC/Impact Oil & Gas) potentially drilling exploration wells in Gambia Block 2, Gambia Block 1, and the AGC Profond block between Senegal and Guinea Bissau. The Sangomar oil development in Senegal is likely to come onstream in 2023.

Figure 20. The SNE-1 (now Sangomar) and FAN-1 discoveries.

Source: Cairn Energy, 2018

Source: African Petroleum Corporation, 2019

5.1 SOSP and ROP Blocks Senegal

PetroNor reserves its rights to a 90% interest⁴ in the exploration blocks 'Rufisque Offshore Profond (ROP) and Senegal Offshore Sud Profond (SOSP), shown in Figure 21.

Both licences are positioned close to oil discoveries (Sangomar and Fan-1) and successful appraisal wells drilled in the adjacent acreage by Cairn Energy.

PetroNor is currently in dispute with the Senegalese government regarding the status of the ROP and SOSP licences. In May 2020, PetroNor reached an agreement with the Government to suspend the arbitration for a period of six months; made a further agreement to suspend until February 2021, and again on 2 February 2021, for a further 2 month standstill.

⁴ This interest is held by African Petroleum Senegal Ltd, which has a10% non-controlling interest. Therefore PetroNor has an effective indirect 81% interest.

Arbitration has been in process since 2017, and only minimal technical work has been undertaken during that time, to update PetroNor's internal interpretation following the Sangomar (SNE-1) discovery.

We have reviewed a Report prepared by ERC equipoise in 2015 for African Petroleum which contains Prospective resource estimates from mapping completed at that time.

The report assessed prospective resources for a number of fan prospects on trend with Fan-1. These deep-water fan prospects were Baobab (ROP) and Jaloo and Kapok (SOSP). A seismic crosssections through Boabab is shown in Figure 22.

There is no certain outcome to the arbitration process, with regards to timing or result. The arbitration prevents PetroNor making any comment on an expected outcome.

For the purpose of this valuation, we have taken the view that tenure on one Block will be lost (we have arbitrarily selected the ROP block). If tenure is retained on the SOSP block, we assume that there will be a one well drilling commitment to meet. Tenure on this block is not guaranteed, and our treatment of 'tenure risk' is dealt with in the valuation section of the report.

Our view of this outcome is partly informed by the result of arbitration on Blocks A1 and A4 with the Gambian government. After a period of arbitration over both blocks, Block A1 was lost and Block A4 was granted to PetroNor in 2020.

5.2 Block A4, The Gambia

Following a period of arbitration between The Gambia and African Petroleum Gambia Ltd (now called PetroNor E&P Gambia Ltd) and APCL Gambia, a Settlement Agreement was signed in September 2020 whereby the Gambian Government agreed to restore Block A4 to PetroNor E&P Gambia Ltd.

Block A4 has an initial two-year Exploration period, with the option of two further two-year Exploration extensions. Prior to the commencement of the first extension period, 30% of the net area of the licence shall be relinquished; and prior to the commencement of the second extension period, a further 25% relinquishment will be required.

The Initial Exploration period has a minimum commitment of seismic reinterpretation and the drilling of one well. The exploration well will likely be drilled on the Lamia prospect in a water depth of 2,200 metres, with a target depth of 3,900 metres (Figure 23).

Figure 23. Gambia prospects and leads.

The Lamia prospect is in an analogous shelf edge position to the Sangomar discovery in Senegal (Figure 24).

Figure 24. Block A4 - Regional context.

5.3 Sinapa Licence and Esperança Licence, Guinea Bissau

The offshore Sinapa Licence (Block 2) and Esperança Licence (Blocks 4A and 5A), cover almost 6,000 km², in water depths ranging from 50m to 900m, located south west of the Dome Flore and Dome Gea oil accumulations, and to the south of the Fan-1 discovery and the Sangomar field in Senegal.

Licence extensions for The Sinapa & Esperança Exploration Permits, offshore Guinea Bissau, were formally granted to Svenska Petroleum Exploration Guinea Bissau AB (Svenska) and FAR Ltd on 2nd October 2020, extending the current exploration phases until 2nd October 2023. One commitment well is to be drilled within the licence period within each permit.

PetroNor entered into a Share Purchase Agreement with Svenska in November 2020 to purchase Svenska's solely owned subsidiary, SPE Guinea Bissau. This gave PetroNor Operatorship of the Blocks and a 78.57% interest in each Block.

Formal notification of the sale of SPE Guinea Bissau AB and a request for approval of the transfer of ownership to PetroNor AS have been sent to Petroguin for submission to the Government of Guinea Bissau. The transaction has been approved by the Council of Ministers, and is awaiting final Presidential signature.

Prospectivity has been identified at various stratigraphic levels including the Uppermost Albian clastics and Albian sand prograde or clinoforms. The Blocks cover the proven, Atlantic Margin Cretaceous play south of the discoveries in Senegal. Due to these discoveries, focus has shifted to the shelf margin in the western part of the blocks, in an analogous position to Sangomar.

A location map is shown in Figure 25.

Figure 25. Sinapa Licence (Block 2) and Esperança Licence (Block 4A & 5A)

Block 2 contains the Sinapa-1 oil discovery drilled by Premier in 2004. Four drill-ready prospects and several other leads have been identified in the post-salt intervals within the Blocks.

Atum / Anchova

The Atum / Anchova Prospect is an analogue to the Sangomar discovery – a large Albian unconformity trap with reservoir in lower Albian clinoforms receiving hydrocarbon migration from the east. It is mapped at two levels, the Senonian Top Albian S1, and Top Clinoform S2 surfaces. It is sealed by Intra-Albian shales and the Senonian unconformity to the west. Figure 26 shows the Sangomar analogue section and Figure 27 a cross-section of the Atum prospect.

Atum and Anchova are potentially connected, but Atum has been selected to drill first as it is the slightly higher part of the structure. The well design was 80% complete at December 2020, and some \$10.3 million has been spent on long lead time items. Drilling is planned in 2022.

West Sinapa, a fault/salt sealed prospect, is also a drill ready target adjacent to East Sinapa discovery.

Figure 26. Sangomar analogue to Atum / Anchova.

Source: Clayburn, 2018

Figure 27. Proposed Atum 1X location and seismic cross-section.

Source PetroNor 2021 Corporate presentation.

Prospective resources for the two prospects, and a combined case are provided in Table 26

Prospect / Level	P90	P50	P10
Atum S1	20	32	47
Atum S2	55	180	370
Anchova S1	10	24	68
Anchova S2	37	107	245
Combined Case
S1	32	152	552
S2	25	167	625

Table 26. Prospective resources (mmbbls) Atum / Anchova.
----------------------------------------------------------	--	--	--

source: SPE Guinea Bissau AB

It should be noted that the estimated quantities of petroleum that may potentially be recovered by the application of a future development project(s) relate to undiscovered accumulations. These estimates have both an associated risk of discovery and a risk of development. Further exploration appraisal and evaluation is required to determine the existence of a significant quantity of potentially moveable hydrocarbons. This cautionary comment applies to all Prospective Resource estimates in this Report and specifically to those detailed in Table 26

5.4 Exploration Programme

From our review of PetroNor, Joint Venture, and tenure documentation we expect an exploration and drilling programme over the next two years similar to that shown in Table 27. This programme envisages the drilling of four exploration wells, commencing with Atum-1X in the first half of 2022.

Table 27. Proposed exploration programme.
-------------------------------------------

	2021			2022				2023
	Q1	Q2	Q3	Q4	Q1	Q2	Q3	Q4	Q1	Q2
Senegal SOSP			post-arbitration licence extension, remapping				Well \$34m
Senegal ROP		assume no renewal / extension
Gambia A4		Re-mapping of 3D seismic				Lamia-1 \$34m
Guinea Bissau Sinapa	G&G well Prep \$10.3 m		Atum 1X \$28m			possible Atum appraisal
Guinea Bissau Esperança	Prospect maturation			Drill or drop decision				Well \$34

We use this exploration programme as the basis of our valuation as discussed below.

5.5 Farmout Valuation

We value the Exploration Assets on the basis of proposed farmouts. In all blocks PetroNor have indicated their intention to seek third party entry and to be covered for the cost of drilling. A contribution to back costs will also be sought from potential farminees, but not on a promoted basis. Because of PetroNor's stated intention to farmout we use the 'actual' farmout method rather than the 'notional' farmout method, as described in the Methodology section of this report.

We make further risk adjustments to these values based on our assessment of Tenure, and chance of being drilled.

SOSP Block	Minimum Terms	Sought Terms
PetroNor initial interest	90.0%	90.0%
Well	\$34 m	\$34 m
Farminee pays	\$34 m	\$34 m
Farminee earns	60.0%	50%
Promote	1:1.67	1 : 2
Premium value	\$13.6 m	\$17.0m
Value per % point	\$0.23 m	\$0.34m
Value of Permit	\$22.6 m	\$34.0m
PetroNor final interest	30%	40%5
PetroNor pre back cost Value	\$6.1* m	\$12.2*
Back Cost contribution	\$1.2m	\$1.0m
PetroNor Value	\$7.3*m	\$13.2*m
* adjusted for the 10% non-controlling interest
5.5.2 Gambia
Block 4	Minimum Terms	Sought Terms
PetroNor initial interest	90.0%	90.0%
Well	\$35 m	\$35 m
Farminee pays	\$35 m	\$35 m
Farminee earns	60.0%	50%
Promote	1:1.67	1 : 2
Premium value	\$14.0 m	\$17.5m
Value per % point	\$0.23 m	\$0.35
Value of Permit	\$23.30 m	\$35.0m
PetroNor final interest	30%	40%
PetroNor pre back cost Value	\$7.0 m	\$14.0m
Back Cost contribution	\$1.2m	\$1.0m

5.5.1 Senegal

5.5.3 Guinea Bissau

Sinapa Licence	Minimum Terms	Sought Terms
PetroNor initial interest	78.57%	78.57%
Atum 1X	\$27.7m remaining cost	\$27.7m remaining cost
Farminee pays	\$27.7m	\$27.7m
Farminee earns	48.57%%	40%
Promote	1:1.62	1:1.96
Premium value	\$8.3 m	\$10.7
Value per % point	\$0.17 m	\$0.27
Value of Permit	\$17.1 m	\$26.7
PetroNor final interest	30%	38.6%
PetroNor pre back cost Value	\$5.1m	\$10.3m
Back Cost contribution	\$5.0m	\$4.1m
PetroNor Value	\$10.1m	\$14.4m

Esperança Licence (option to drop licence prior to drilling in 2023)

	Minimum Terms	Sought Terms
PetroNor initial interest	78.57%	78.57%
Well	\$34 m	\$34 m
Farminee pays	\$34 m	\$34 m
Farminee earns	48.57%%	40.0%
Promote	1 : 1.62	1 : 1.96
Premium value	\$10.2 m	\$13.1 m
Value per % point	\$0.21 m	\$0.33 m
Value of Permit	\$21.0 m	\$32.8 m
PetroNor final interest	30%	38.6%
PetroNor pre back cost Value	\$6.3 m	\$12.6 m
Back Cost contribution	\$1.0m	\$0.8m
PetroNor Value	\$7.3m	\$13.4m

We summarise these cases in Table 28 and apply risk factors for the chance of drilling (ie will the farmout occur = Farmout Risk) and security of tenure (Tenure Risk). We also assume the farminee will contribute their share of back costs and we add this to the value of the farmout.

Table 28. Risked Farmout Values.

Minimum Terms
	Unrisked Value	Farmout Risk	Tenure Risk	Risked Value
Senegal SOSP	\$7.3m	90%	25%	\$1.6m
Gambia Block 4	\$8.2m	90%	100%	\$7.4m
GB Sinapa	\$10.1m	90%	100%	\$9.1m
GB Esperança	\$7.3m	60%	100%	\$4.4m
Sought Terms
Senegal SOSP	\$13.2m	90%	25%	\$3.0m
Gambia Block 4	\$15.0m	90%	100%	\$13.5m
GB Sinapa	\$14.4m	90%	100%	\$13.0m
GB Esperança	\$13.4m	60%	100%	\$8.1m
Average Minimum & Sought Terms
Senegal SOSP	\$10.3m			\$2.3m
Gambia Block 4	\$11.6m			\$10.4m
GB Sinapa	\$12.3m			\$11.1m
GB Esperança	\$10.4m			\$6.2m

We use the average of the Risked Minimum and Sought Terms to arrive at our preferred value. We have assigned a Low Value by assuming the farmouts in Esperança and Senegal do not occur. We have assigned a High Value by assuming the values based on Sought Terms for the four farmouts, and that the Senegal Tenure Risk Factor is 100% as shown in Table 29. Our final valuation is shown in Table 30.

Table 29. Senegal Value with no Tenure Risk.

Sought terms	Unrisked Value	Farmout Risk	Tenure Risk	Risked Value
Senegal SOSP	\$13.2m	90%	100%	\$11.9m

Table 30. Exploration Asset Values

	Low Value	Preferred Value	High Value
Senegal SOSP	-	\$2.3m	\$11.9m
Gambia Block 4	\$10.4m	\$10.4m	\$13.5m
Sinapa Licence	\$11.1m	\$11.1m	\$13.0m
Esperança Licence	-	\$6.2m	\$8.1m
Total	\$21.5m	\$30.0m	\$46.5m

We use a Cost based approach to compare with our derived Farmout Exploration Values. We previously stated in the Methodology section that the work commitment made to the government can be used as a measure of value, on the premise that what a company is prepared to spend on a permit should reflect the value of the permit. In this case, it is the stated aim of PetroNor to seek farm-in partners to cover the cost of the drilling programmes. Thus, we don't believe the actual drilling costs should be used to value the PetroNor interests. Instead we discount those costs to reflect the chance of PetroNor funding (COF) in the case a farmout is not reached. We assume there is a 25% chance of PetroNor funding in this situation. Table 31 shows the results of this analysis and the inferred value of PetroNor's interests of \$29.5 million. We believe this analysis provides confidence to our farmout based valuation.

		Drilling Costs \$m			Total	COF	Value	PN Interest	PN Value
		2020	2021	2022	2023
Guinea Bissau	Sinapa	10.3	28			38.3	25%	9.6	78.57%	7.5
	Esperança				38	38.0	25%	9.5	78.57%	7.5
Gambia	A4			34		34.0	25%	8.5	90%	7.6
Senegal	SOSP			34		34.0	25%	8.5	81%	6.9
		10.3	28.0	68.0	38.0	144.3		36.1		29.5

Table 31. Cost based value comparison.

6 References

African Petroleum Corporation (APC), April 2019 – Corporate Presentation

AGR Petroleum Services, October, 2019 – PNGF Sud / PNGF Bis (Congo Brazzaville), 109pp.

• AGR TRACS International Limited, 20 March, 2019 March 2019 Update of 2018 AGR TRACS CPR, on the Aje Field, OML 113, Nigeria, for Panoro Energy Limited, 107pp.
• Brownfield, M.E., and Charpentier, R.R., 2003 Assessment of the Undiscovered Oil and Gas of the Senegal Province, Mauritania, Senegal, The Gambia, and Guinea Bissau, Northwest Africa, US Geological Survey Bulletin 2207-A, 29pp.http://www.usgs.gov/bul/2207/A/
• Brownfield, M.E., and Charpentier, R.R., 2006 Geology and total petroleum systems of the West-Central Coastal Province (7203), West Africa, US Geological Survey Bulletin 2207-B, 52p. http://www.usgs.gov/bul/2207/B/
• Cairn Energy, 2018 The SNE Discovery Offshore Senegal Moving a Frontier Basin to Emergent, European Association of Geoscientists and Engineers (EAGE) Annual Conference and Exhibition, 11-14 June 2018.
• Clayburn, J., 2018 Realising the Deep Water Hydrocarbon Potential of Senegal, Search and Discovery Article #70345.
• Energy Information Administration (EIA), February 2021 Annual Energy Outlook, Washington DC, 21pp. https://www.eia.gov/pressroom/presentations/AEO2021\_Release\_Presentation.pdf

Petronor E&P – Annual Report 2019, various Press Releases

Numerous internal reports and presentations

Stellar Energy Advisors, February 2021 – The Landscape for Africa A&D activity, 21pp (unpublished).

World Bank, October 2020 – Commodity Market Outlook, 94pp. https://openknowledge.worldbank.org/bitstream/handle/10986/34621/CMO-October-2020.pdf

7 Appendix 1 Tenure Documentation

ResourceInvest has reviewed tenure and joint venture documentation as detailed below, and is satisfied that the tenure and status of the permits are as stated. ResourceInvest does not, however, represent, warrant or guarantee that this is so.

The Republic of The Congo

Production Sharing Agreements, Tchibelli-Litanzi II, Tchendo II Permits, 9 February 2017

The Parties: The Republic of the Congo, and National Petroleum Company of Congo (SNPC), and Perenco Congo SA Hemla E&P Congo Kontinent Congo Africa Oil & Gas Corporation Petro Congo SA

Joint Operating Agreements, Tchibelli-Litanzi II, Tchibelli II, Tchendo II Permits, 20 June 2017

Parties: National Petroleum Company of Congo (SNPC), and Perenco Congo SA Hemla E&P Congo Kontinent Congo Africa Oil & Gas Corporation Petro Congo SA

Accorde Relativ au Regime Applicable aux Permis D'exploitation Tchendo II, Tchibouela II et Tchibeli I-Litanzi II

Parties: National Petroleum Company of Congo (SNPC), and Perenco Congo SA Hemla E&P Congo Kontinent Congo Africa Oil & Gas Corporation Petro Congo SA

This agreement provides the joint venture the Right to negotiate an interest in PNGF Bis.

Releve des Conclusions du Comite PNGF-Bis Tenu le 16.03.2018

Parties: National Petroleum Company of Congo (SNPC), and Perenco Congo SA Hemla E&P Congo Kontinent Congo Africa Oil & Gas Corporation Petro Congo SA

This agreement agrees the working interest between the parties in PNGF Bis.

Senegal

Licence Agreement Senegal Offshore Sud Profond (SOSP), 22 December 2011

Parties: Petrosen (for the Government), and African Petroleum Senegal Limited

Licence Agreement Rufisque Offshore Profond (ROP), 22 December 2011

• Parties: Petrosen (for the Government), and African Petroleum Senegal Limited
• Joint Operating Agreement Agreement Senegal Offshore Sud Profond (SOSP), 25 November 2011
• Parties: Petrosen (for the Government), and African Petroleum Senegal Limited

Joint Operating Agreement Agreement Rufisque Offshore Profond (ROP), 25 November 2011

Parties: Petrosen (for the Government), and African Petroleum Senegal Limited

Gambia

Settlement Agreement, 19 September 2020

Parties: The Government of The Gambia PetroNor E&P Ltd PetroNor E&P Gambia Limited APCL Gambia B.V. African Petroleum Corporation Ltd

Petroleum, Exploration, Development and Production Licence Block A4

Parties: The Republic of The Gambia PetroNor E&P Gambia Limited (the Licensee)

Guinea Bissau

Agreement for Joint Venture Participation (AJVP), Blocks 4A and 5A, 28 June 2007

Parties: Petroguin (on behalf of the Government), and Petrobank Energy Ltd Premier Oil Iran BV

Agreement for Joint Venture Participation (AJVP), Block 2, 28 June 2007

Parties: Petroguin (on behalf of the Government), and Petrobank Energy Ltd

Eleventh Amendment to the AJVP, 23 March 2017

Parties: Petroguin (on behalf of the Government), and SPE Guinea Bissau AB (SVENSKA) FAR Ltd

Fifteenth Amendment to the AJVP, 23 March 2017

Parties: Petroguin (on behalf of the Government), and SPE Guinea Bissau AB (SVENSKA) FAR Ltd

Sixteenth Amendment to Sinapa AJVP

Parties: Petroguin (on behalf of the Government), and SPE Guinea Bissau AB (SVENSKA) FAR Ltd

Twelfth Amendment to Esperança AJVP

Parties:	Petroguin (on behalf of the Government), and
	SPE Guinea Bissau AB (SVENSKA)
	FAR Ltd
Parties:	Petroguin (on behalf of the Government), and
	SPE Guinea Bissau AB (SVENSKA)
	FAR Ltd

Sales and Purchase Agreement, 18 November 2020

Parties: SVENSKA Petroleum Exploration Aktiebolag, and PetroNor E&P AS Relating to the sale of shares in SPE Guinea Bissau to PetroNor

8 Appendix 2 Tenure History OML 113

JOA and the Addendum to the JOA signed 21 September 2007 by:

YFP (OP)	Yinka Folawiyo Petroleum Company Limited, Operator, and

The farminees:

CNDL	Chevron Nigeria Deepwater H Limited
Vitol	Vitol Exploration Nigeria Limited
EER	Energy Equity Resources Aje Limited
Providence	P.R. Oil and Gas Nigeria Limited

Whereby YFP assigned a participating interest to each of the farminees

Party	Participating Interest
Farminees
CNDL	18.0000%
Vitol	12.8310%
EER	6.5020%
Providence	2.6670%
Sub total	40.0000
Farmor
YFP (OP)	60.0000%
Total	100.0000%

Following this Agreement, we have traced changes in ownership of these interests as follows:

EER	to	Pan Petroleum Aje		to	PetroNor
CNDL	to	EER and YFP Deepwater
Providence	to	P.R. Jacka Oil & Gas	to		MX Oil Plc (now ADM Energy Plc)
Vitol	to	New Age

At the time of submitting the FDP (2017) the Joint Venture consisted:

Party	Participating Interest
YFP	60.000%
New Age Exploration Nigeria Ltd	12.8310%
YFP Deepwater Ltd	9.0000%
EER	9.0000%
Pan Petroleum Aje Ltd (Panoro Energy)	6.5020%
P.R. Jacka Oil & Gas	2.6670%
Total	100.0000%

On 23 May 2019, YFP and PetroNor executed a Term Sheet that detailed a subsequent Shareholder agreement between the companies. This term Sheet became Schedule 1 of the Investment and

Shareholders Agreement relating to Aje Production AS between YFP and PetroNor, dated 3 December 2019.

On 21 October 2019 PetroNor had executed a share purchase agreement with Panoro Energy ASA for the acquisition of Panoro Energy's shares in Pan Petroleum Aje Ltd.

The Joint Venture now consisted:

Party	Participating Interest
YFP (OP)	60.000%
New Age Exploration Nigeria Ltd	12.8310%
YFP Deepwater Ltd	9.0000%
EER	9.0000%
Pan Petroleum Aje Ltd (PetroNor)	6.5020%
MX Oil Plc	2.6670%
Total	100.0000%

Since the original JOA and Addendum of 2007 the participating interests held different Capex, Opex, Cost sharing, and Profit interests which reflected the terms of the Production Sharing Contract, and the Farmout to YFP. The farminees had agreed to repay YFP 25% of the revenue from the YFP(OP) share of any sale of crude oil from the Aje Field until US\$30 million had been repaid. Thus, cost and revenue interests differ for the period prior to the YFP payout, and post the YFP payout. These interests are detailed below.

	Pre YFP Cost recovery
	Participating interest	Capex	Opex	Cost recovery	Profit
YFP	60.00%	0.00%	0.00%	25.00%	25.00%
YFP DW	9.00%	22.50%	22.50%	16.88%	16.88%
EER	9.00%	22.50%	22.50%	16.88%	16.88%
New Age	12.83%	32.07%	32.07%	24.05%	24.05%
PetroNor	6.50%	16.26%	16.26%	12.19%	12.19%
ADM	2.67%	6.68%	6.68%	5.00%	5.00%
	100%	100%	100%	100%	100%

	Post YFP Cost recovery
	Participating interest	Capex	Opex	Cost recovery	Profit
YFP	60.00%	0.00%	0.00%	0.00%	0.00%
YFP DW	9.00%	22.50%	22.50%	22.50%	22.50%
EER	9.00%	22.50%	22.50%	22.50%	22.50%
New Age	12.83%	32.07%	32.07%	32.07%	32.07%
PetroNor	6.50%	16.26%	16.26%	16.26%	16.26%
ADM	2.67%	6.68%	6.68%	6.68%	6.68%
	100%	100%	100%	100%	100%

Under the terms of the YFP – PetroNor Shareholder Agreement, YFP and PetroNor agreed to combine their OML113 interests into a Special Purpose Vehicle, Aje Production AS, owned 55% and 45% respectively between YFP and PetroNor.

	Pre YFP Payout Interests
	Participating	Capex	Opex	Cost recovery	Profit
YFP (OP)	60.00%	0.00%	0.00%	25.00%	25.00%
YFP DW	9.00%	22.50%	22.50%	16.88%	16.88%
PetroNor	6.50%	16.26%	16.26%	12.19%	12.19%
Aje Production	75.5%	38.76%	38.76%	54.07%	54.07%
Less YFP (OP) Repayment Obligation					25.00%
Adjusted Aje Production	75.5%	38.755%	38.755%	29.066%	29.066%
PetroNor Share 45%		17.44%	17.44%	13.08%	13.08%

	Post YFP Payout Interests
	Participating	Capex	Opex	Cost recovery	Profit
YFP (OP)	60.00%	0.00%	0.00%	0.00%	0.00%
YFP DW	9.00%	22.50%	22.50%	22.50%	22.50%
PetroNor	6.50%	16.26%	16.26%	16.26%	16.26%
Aje Production	75.5%	38.76%	38.76%	38.76%	38.76%
PetroNor Share 45%		17.44%	17.44%	17.44%	17.44%

Under the Economic model YFP Payout is expected to occur in mid-2024.

9 Appendix 3 Discount Factor

For our discounted cash flow evaluation of the Congo production asset, and the Nigerian Aje field gas development asset, we have assessed a nominal post-tax discount rate, determined using the Capital Asset Pricing Model (CAPM), which is used in determining the cost of equity, which in turn, is a component of the weighted average cost of capital (WACC). While these models derive a specific discount rate, the selection of an appropriate discount rate is also a matter of professional judgement.

The parameters we choose for our inputs are based on the data presented below.

The CAPM is based on the theory that a prudent investor will price assets so that the expected return is equal to:

• the risk free rate of return, plus
• a premium for risk

The CAPM postulates that there is a positive relationship between risk and return. The assessment of risk requires an analysis of the two risk types inherent in any investment, namely:

• Diversifiable (or unsystematic) risk risk which is random and affects only a specific business,
• Undiversifiable (or systematic) risk risk which affects all equity investments, such as a change in business cycles, or tax rates.

Investors in publicly listed companies can effectively eliminate diversifiable risks by spreading their investments into different companies, and cannot expect to be rewarded for risk they can avoid. On the other hand, investors cannot avoid the undiversifiable risk of investing in the stock market, and therefore expect to be adequately rewarded.

The measure of sensitivity to the return of an investment to general market movements is usually called its beta. Treasury Bills, being the closest approximation to a risk free investment have a beta of zero. The market portfolio has a beta of one. A stock may be more or less risky than the general measure of market risk. Betas of listed shares are generally in the range of zero to two.

The CAPM, calculates the cost of equity as follows:

Re = Rf + βe(Rm - Rf), where

• Re = cost of equity capital, or expected return on the investment
• Rf = risk free rate of return
• βe = expected equity beta of the investment
• Rm Rf = market risk premium

The WACC represents the average of the rates of return required by providers of debt and equity capital to compensate for the time value of money and the perceived risk or uncertainty of the cash flows, weighted in proportion to the market value of the debt and equity capital provided.

Post tax WACC = Rd x D/(D+E) x (1-t) x Re X E/(D+E), where

• Re = the required rate of return on equity capital;
• E = the market value of equity capital;
• D = the market value of debt capital;
• Rd = the required rate of return on debt capital; and
• t = the statutory corporate tax rate.

Risk free rate

The risk free rate is usually based on the long term government bond rate. Given the current, historically low global bond yields, we use a longer term average as our risk free rate. Figure 28 and Figure 29 and show the Norwegian and the Australian 10-year Government Bond yield from February 2011 to February 2021. The ten year average is 2.04% in Norway and 2.76% in Australia. We have considered a range from 2.0% to 3.0%.

Figure 28. Norwegian 10 year Government Bond yield Jan 2010- Jan 2020.

Figure 29. Australian 10 year Government Bond yield Jan 2010- Jan 2020.

Market risk premium

The market risk premium represents the additional return an investor expects to receive to compensate for additional risk associated with investing in equities as opposed to investing in assets with a risk free rate of return. This premium is sensitive to the period of observation chosen. Lonergon (2003) describes various studies showing premiums varying from 3% to 8.1%. Mathews (2019) in a Reserve Bank of Australia study shows a long term premium in Australian of around 4%, but accepts that forward-looking measures of the equity return premium can be between 4% - 6%. We have considered a range for market risk premium from 5% to 6%.

Beta

The beta of a company is a measure of the variance of the return gained from holding a share in that company compared with holding a share in each company in the market.

Table 32 shows levered equity betas of the 12 oil and gas companies listed on the Oslo Stock exchange. This data has been supplied by S&P CapIQ, who have taken the unlevered beta, considered PetroNor's debt / equity ratio and calculated a levered beta for PetroNor of 1.182 (shown in Table 33).

Name	5Yr Avg Tax Rate	Levered Beta	Total Debt	Mkt. Val. Equity	Debt/ Equity	Unlevered Beta
			US\$million	US\$million
Equinor	68.6%	0.800	37,470	65,808	56.9%	0.679
Aker BP	77.5%	1.936	4,590	10,585	43.4%	1.764
DNO	0.0%	2.794	1,041	1,007	103.4%	1.374
Norwegian Energy	0.0%	1.058	1,041	390	266.7%	0.288
RAK Petroleum	0.0%	2.145	1,068	292	365.8%	0.460
Panoro Energy	71.5%	2.882	23	261	8.8%	2.811
OKEA	117.0%	0.000	301	173	174.3%	NA
Questerre Energy	37.8%	0.000	12	89	13.8%	NA
North Energy	12.9%	1.306	0	48	0.5%	1.301
Interoil E & P	0.0%	2.521	23	33	69.8%	1.485
Zenith Energy	0.0%	0.000	6	16	41.3%	NA
J.P. Kenny Petroleum	0.0%	-0.493	1	4	14.9%	-0.429
Average		1.661				1.081

Table 32. Beta calculation.

Table 33. S&P CapIQ levered beta PetroNor.

S&P CapIQ Beta calculation
Average Unlevered Beta for 12 Oslo listed Companies	1.081
PetroNor Debt / Equity	13.3%
Tax Rate	30.0%
PetroNor Levered Beta	1.182

We reviewed the 12 companies in Table 32 and selected a sub-set of six companies (shaded green in Table 32) by eliminating the two largest and two smallest in terms of market capitalisation. We believe these six companies are a better comparison to PetroNor. We recalculated the levered beta to provide a beta of 1.406 (Table 34).

Table 34. ResourceInvest levered beta PetroNor.

ResourceInvest Beta Calculation
Average Unlevered Beta for 6 Oslo listed Companies	1.287
PetroNor Debt / Equity	13.3%
Tax Rate	30.0%
PetroNor Levered Beta	1.406

For the purpose of our valuation we have used a low beta value of 1.2 and a high value of 1.4.

Cost of Debt

The interest rate of project financing of oil & gas projects is likely to be between 8% and 12%.

We use a low rate of 8% and a high rate of 12%.

We have calculated the after tax cost of debt by using a tax rate between 30% and 50%. The corporate tax rate paid by PetroNor over the past two years is approximately 30%. We use 50% for the high side to reflect potential additional tax liabilities under various Production Sharing Contracts.

Specific risk premium

Country risk premium

Specific risk premium represents the additional return an investor expects to receive to compensate for country, size and project related risks that are not reflected in the beta of the comparable companies.

Export Finance Australia publishes risk ratings for a number of countries, including Nigeria⁵ as made by global risk agencies and these are shown in Figure 30. They indicate a risk which is sub investment grade, and in the upper speculative grade.

We have considered estimated country risk factors which are estimated by some market analysts and academics based on risk agency ratings. For example, Professor Aswath Damodaran estimates country risk for The Congo and Nigeria of of 8.7% and 10.5%, and a country risk factor of 4.9% for Africa as a whole ( www.damodaran.com as at January 2021).

We also note that Nigeria and The Congo have a long history of offshore oil & gas exploration, development and production. The country hosts global oil & gas companies, and there has been no major issues resulting from sovereign risk. We have thus applied a lower country risk premium than estimated by Damodaran, and used 4.0%.

⁵ https://www.exportfinance.gov.au/resources-news/country-profiles/africa/nigeria/country-risk/

Figure 30. Nigeria Risk ratings.

Project risk premium

We have considered a project risk premium for the Aje Field gas development project based on the following factors:

• Substantial engineering work is still to be completed for concept design, and provision of capital and operating cost estimates. A Final Investment Decision (FID) has not yet been made.
• After development drilling and construction, first gas and liquid production is assumed in October 2022.
• Phase II (increased) gas production and liquefaction is assumed to commence in January 2025.

We have considered a project risk premium range of 6.0% to 8.0% based on our view of what potential buyers or investors in the project would require. This is a subjective estimate and we cross-check this choice with an analysis comparing this premium effect with the application of direct risk factors to the project NPV (see section 4.4 of this report).

We summarise our WACC calculation for The Congo oil production in Table 35, and for the OML gas development project in Table 36.

Table 35. Discount Factor summary derivation for The Congo.

WACC	Low	High
Cost of equity
Risk free rate	2.00%	3.00%
Beta	1.2	1.4
Market risk premium	5.00%	6.00%
Country risk premium	4.0%	4.0%
Project risk premium	0.0%	0.0%
Cost of equity	12.0%	15.4%
Cost of debt
Cost of debt (pre tax)	8.0%	12.0%
Tax	30.0%	50.0%
Cost of debt (post tax)	5.60%	6.00%
Capital structure
Proportion of debt	15.0%	15.0%
Proportion of equity	85.0%	85.0%
WACC (post tax)	10.8%	13.5%
WACC (average)	12.2%
WACC adopted	12.0%

Table 36. Discount Factor summary derivation for OML 113 gas development.

WACC	Low	High
Cost of equity
Risk free rate	2.00%	3.00%
Beta	1.2	1.4
Market risk premium	5.00%	6.00%
Country risk premium	4.0%	4.0%
Project risk premium	6.0%	8.0%
Cost of equity	18.0%	23.4%
Cost of debt
Cost of debt (pre tax)	8.0%	12.0%
Tax	30.0%	50.0%
Cost of debt (post tax)	5.60%	6.00%
Capital structure
Proportion of debt	15.0%	15.0%
Proportion of equity	85.0%	85.0%
WACC (post tax)	15.9%	20.3%
WACC (average)	18.1%
WACC adopted	18.0%

10 Appendix 4 SPE-PRMS Classification

Under PRMS, identified projects must always be assigned to one of the three classes: Reserves, Contingent Resources, or Prospective Resources. Further subdivision is optional, and three sub classification systems are provided in PRMS that can be used together or separately to identify particular characteristics of the project and its associated recoverable quantities. The sub classification options are project maturity subclasses, reserves status, and economic status.

As illustrated in Figure 31, development projects (and their associated recoverable quantities) may be sub classified according to project maturity levels and the associated actions (business decisions) required to move a project toward commercial production. This approach supports managing portfolios of opportunities at various stages of exploration and development and may be supplemented by associated quantitative estimates of chance of commerciality

RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by development and production status.

CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorised in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.

Development Pending is limited to those projects that are actively subject to project-specific technical activities, such as appraisal drilling or detailed evaluation that is designed to confirm commerciality and/or to determine the optimum development scenario. In addition, it may include projects that have nontechnical contingencies, provided these contingencies are currently being actively pursued by the developers and are expected to be resolved positively within a reasonable time frame. Such projects would be expected to have a high probability of becoming a commercial development (i.e., a high chance of commerciality).

Development Unclarified or On Hold comprises two situations. Projects that are classified as On Hold would generally be where a project is considered to have at least a reasonable chance of commerciality, but where there are major nontechnical contingencies (e.g., environmental issues) that need to be resolved before the project can move toward development. The primary difference between Development Pending and On Hold is that in the former case, the only significant contingencies are ones that can be, and are being, directly influenced by the developers (e.g., through negotiations), whereas in the latter case, the primary contingencies are subject to the decisions of others over which the developers have little or no direct influence and both the outcome and the timing of those decisions is subject to significant uncertainty.

Projects are considered to be Unclarified if they are still under evaluation (e.g., a recent discovery) or require significant further appraisal to clarify the potential for development, and where the contingencies have yet to be fully defined. In such cases, the chance of commerciality may be difficult to assess with any confidence.

PROSPECTIVE RESOURCES - are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub classified based on project maturity.

Figure 31. SPE-PRMS Resource Classification.

11 Appendix 5 - Glossary

BCF	Billion (109 ) cubic feet
bcpd	barrels of condensate per day
boe	barrels of oil equivalent
bopd	barrels of oil per day
Contingent Resources	are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorised in accordance with the level of certainty associated with the estimates and may be sub classified based on project maturity and/or characterized by their economic status.
EMV	Expected monetary value
FEED	Front End Engineering and Design
FVF	Formation volume factor
GIIP	Gas Initially in Place
GJ	Giga (109 ) Joules
GOR	Gas oil ratio
GRV	Gross rock volume
MCF mcf	Thousand cubic feet
MD	Measured Depth
MMscfd, mmscfd	Million standard cubic feet per day
MMstb, mmstb	Million US stock tank barrels
Mscfd, mscfd	Thousand standard cubic feet per day
Mstb, mstb	Thousand US stock tank barrels
NPV	Net Present Value
OGIP	Original Gas in Place
OOIP	Original Oil in Place
P90, P50, P10	90%, 50% & 10% probabilities respectively that the stated quantities will be equalled or exceeded. The P90, P50 and P10 quantities correspond to the Proved (1P), Proved + Probable (2P) and Proved + Probable + Possible (3P) confidence levels respectively. With respect to Prospective

	Resources the P90, P50 and P10 quantities are taken to correspond to Low, Best and High Estimates respectively
PDP	Proved Developed Producing
Pg	Probability of geological success
PJ	Peta (1015) Joules
Prospective Resources	are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.
Reserves	are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.
scf	Standard cubic feet (measured at 60 degrees F and 14.7 psia)
SPE	Society of Petroleum Engineers
SPE-PRMS	Petroleum Resources Management System, approved by the Board of the SPE March 2007 and endorsed by the Boards of Society of Petroleum Engineers, American Association of Petroleum Geologists, World Petroleum Council and Society of Petroleum Evaluation Engineers.
STOOIP	Stock Tank Barrels Initially In Place
Surf	Acronym for Subsea/Umbilicals/Risers/Flowlines
Tcf	Trillion (1012) cubic feet
TOC	Total Organic Carbon, a measure of organic richness in sedimentary rocks
US\$	United States Dollar
wet gas	Natural gas that contains less methane (typically less than 85% methane) and more ethane and higher hydrocarbons.
Working Interest	A company's equity interest in a project before reduction for royalties or production share owed to others under applicable fiscal terms
WTI	West Texas Intermediate Crude Oil