premier oil plc · premier oil plc (incorporated in scotland with registered number sc234781) 4 for...

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THIS DOCUMENT AND ANY ENCLOSURES WITH IT ARE IMPORTANT AND REQUIRE YOUR IMMEDIATE

ATTENTION. If you are in any doubt as to the action you should take, you are recommended to seek your own personal financial

advice immediately from your stockbroker, bank manager, solicitor, accountant, fund manager or other appropriate financial adviser

authorised pursuant to FSMA if you are in the United Kingdom or from another appropriately authorised independent financial

adviser if you are in a territory outside the United Kingdom.

Subject to the restrictions set out below, if you sell or transfer or have sold or transferred all of your Existing Ordinary Shares

(other than ex-rights) before 21 April 2009 (the ‘‘ex-rights date’’), please send this document and any Provisional Allotment

Letter, duly renounced, if and when received, as soon as possible to the purchaser or transferee, or to the stockbroker, bank or

other agent through whom the sale or transfer was effected, for onward delivery to the purchaser or transferee. This document

and/or the Provisional Allotment Letter should not, however, be distributed, forwarded to or transmitted in or into any

jurisdiction where to do so might constitute a violation of local securities law or regulations, including, but not limited to

(subject to certain exceptions), the Excluded Territories. Please refer to paragraphs 7 and 8 of Part VIII of this document if you

propose to send this document and/or the Provisional Allotment Letter outside the United Kingdom. If you sell or transfer part

only of your Existing Ordinary Shares, instructions regarding split applications will be set out in the Provisional Allotment

Letter. If you have sold or transferred Existing Ordinary Shares (other than ex-rights) held in uncertificated form, or have sold

or transferred American Depositary Shares (other than ex-rights), in each case before the ex-rights date, a claim transaction will

automatically be generated by Euroclear UK which, on settlement, will credit the appropriate number of Nil Paid Rights to the

purchaser or transferee.

This document, which comprises a prospectus relating to the Rights Issue and a circular relating to the Acquisition, has been

prepared in accordance with the Prospectus Rules made under section 73A of FSMA and has been approved as such by the

FSA in accordance with section 85 of FSMA. A copy of this document has been filed with the FSA in accordance with

paragraph 3.2.1 of the Prospectus Rules. This document has also been made available to the public in accordance with

paragraph 3.2.1 of the Prospectus Rules. This document can also be obtained on request from the Company’s Registrar, Capita

Registrars.

The Directors, whose names appear on page 19 of this document, the Proposed Director and Premier accept responsibility for

the information contained in this document. To the best of the knowledge of the Directors, the Proposed Director and Premier

(who have taken all reasonable care to ensure that such is the case), the information contained in this document is in

accordance with the facts and contains no omission likely to affect the import of such information.

Applications have been made to the UK Listing Authority and to the London Stock Exchange for the maximum number of

New Ordinary Shares that may be issued to be admitted to the Official List of the UK Listing Authority and to be admitted to

trading on the main market for listed securities of the London Stock Exchange. It is expected that, subject to the conditions to

the Rights Issue being satisfied or, where permitted, waived and subject also to the timing of the satisfaction or waiver of the

conditions, Admission will become effective and that dealings on the London Stock Exchange in the New Ordinary Shares (nil

paid) will commence at 8.00 a.m. (London time) on 21 April 2009.

The distribution of this document and/or the accompanying documents, and/or the transfer of Nil Paid Rights, Fully Paid

Rights and/or New Ordinary Shares, into jurisdictions other than the United Kingdom may be restricted by law and therefore

persons into whose possession this document and/or the accompanying documents come should inform themselves about and

observe any such restrictions. Any failure to comply with any such restrictions may constitute a violation of the securities laws

of such jurisdictions.

Premier Oil plc(Incorporated in Scotland with registered number SC234781)

4 for 9 Rights Issue at 485 pence per share to raise approximately £171 million,Acquisition of the entire issued share capital of ONSL (in administration) (or

of the ONSL Assets) and Notice of Extraordinary General Meeting

Deutsche BankFinancial Adviser, Global Co-ordinator, Joint Sponsor, Joint Bookrunner, Underwriter

and Joint Broker

Oriel Securities LimitedJoint Sponsor, Joint Broker, Co-Lead Manager and Underwriter

Barclays Capital, HSBC, RBC Capital MarketsJoint Bookrunners and Underwriters

For a discussion of certain risk factors which should be taken into account when considering whether to vote in favour of the

Resolutions please refer to the section entitled ‘‘Risk Factors’’ on pages 9 to 17 of this document. Your attention is drawn to the

letter from the chairman of Premier in Part I of this document, recommending you to vote in favour of the Resolutions to be

proposed at the Extraordinary General Meeting. You should read this document in its entirety and consider whether to vote in

favour of the Resolutions in light of the information contained in, or incorporated by reference into, this document.

Notice of an Extraordinary General Meeting, to be held at 10.00 a.m. on 20 April 2009 at the offices of Deutsche Bank,

Winchester House, 1 Great Winchester Street, London EC2N 2DB, is set out at the end of this document. Shareholders will find

enclosed a Form of Proxy for use at the Extraordinary General Meeting. Shareholders are requested to complete and return the

Form of Proxy whether or not they intend to be present at the meeting. To be valid, Forms of Proxy should be completed and

signed in accordance with the instructions printed thereon and returned by post or by hand so as to reach the Registrar as soon as

possible and, in any event, by no later than 10.00 a.m. on 18 April 2009. Return of a Form of Proxy will not preclude a

Shareholder from attending and voting at the Extraordinary General Meeting. All Shareholders on the register of members of

Premier at the close of business on 1 April 2009 have been sent this document.

Certain information in relation to Premier is incorporated by reference into this document. Capitalised terms have the meanings

ascribed to them in Part XVIII of this document. Certain abbreviated terms that are commonly used in the oil and gas industry

and which appear in this document are also defined in Part XVIII of this document.

No person has been authorised to give any information or make any representations other than those contained in this

document and, if given or made, such information or representations must not be relied on as having been so authorised. The

delivery of this document shall not, under any circumstances, create any implication that there has been no change in the

affairs of Premier since the date of this document or that the information in it is correct as of any subsequent time.

Deutsche Bank AG is authorised under German Banking Law (competent authority: BaFin - Federal Financial Supervisory

Authority) and authorised and subject to limited regulation by the FSA. Oriel, Barclays, HSBC and Royal Bank of Canada

Europe Limited (which trades as RBC Capital Markets) are authorised and regulated by the FSA. Each of Deutsche Bank and

Oriel is acting for Premier and no one else in connection with the Acquisition and the Rights Issue and will not regard any

other person (whether or not a recipient of this document) as a client in relation to the Acquisition or the Rights Issue, and

will not be responsible to anyone other than Premier for providing the protections afforded to its client or for providing advice

in relation to the Acquisition or the Rights Issue. Each of Barclays, HSBC and RBC Capital Markets are acting for Premier

and no one else in connection with the Rights Issue and will not regard any other person (whether or not a recipient of this

document) as a client in relation to the Rights Issue or the Acquisition and will not be responsible to anyone other than

Premier for providing the protections afforded to their respective clients or for providing advice in relation to the Acquisition

or the Rights Issue.

Apart from the responsibilities and liabilities, if any, which may be imposed on Deutsche Bank, Oriel, Barclays, HSBC and

RBC Capital Markets by FSMA or the regulatory regime established thereunder or under the regulatory regime of any other

jurisdiction where exclusion of liability under the relevant regulatory regime would be illegal, void or unenforceable, none of

Deutsche Bank, Oriel, Barclays, HSBC and RBC Capital Markets accept any responsibility whatsoever for the contents of this

document, including its accuracy, completeness or verification, or for any statement made or purported to be made by any of

them, or on behalf of them, in connection with the Company, the Nil Paid Rights, the Fully Paid Rights, the New Ordinary

Shares, the Rights Issue or the Acquisition. Each of Deutsche Bank, Oriel, Barclays, HSBC and RBC Capital Markets

accordingly disclaim all and any liability whether arising in tort, contract or otherwise (save as referred to above) which it

might otherwise have in respect of such document or any such statement.

Deutsche Bank, Oriel, Barclays, HSBC and RBC Capital Markets may, in accordance with applicable legal and regulatory

provisions and subject to the Underwriting Agreement, engage in transactions in relation to Nil Paid Rights, Fully Paid Rights,

the Ordinary Shares or related instruments for their own account for the purpose of hedging their underwriting exposure or

otherwise. Except as required by applicable law or regulation, Deutsche Bank, Oriel, Barclays, HSBC and RBC Capital Markets

do not propose to make any public disclosure in relation to such transactions.

Subject to the passing of the Resolutions, it is expected that Qualifying Non-CREST Shareholders (other than, subject to

certain exceptions, Shareholders in the United States and other Excluded Territories) will be sent a Provisional Allotment Letter

on 20 April 2009, and that Qualifying CREST Shareholders (other than, subject to certain exceptions, Shareholders in the

United States and other Excluded Territories) will receive a credit to their appropriate stock accounts in CREST in respect of

the Nil Paid Rights to which they are entitled on 20 April 2009. The Nil Paid Rights so credited are expected to be enabled for

settlement by Euroclear UK as soon as practicable after Admission. For further details, see Part VIII of this document.

This document does not constitute an offer to sell or the solicitation of an offer to acquire New Ordinary Shares or to take up

entitlements to Nil Paid Rights in any jurisdiction in which such an offer or solicitation is unlawful. None of the Nil Paid

Rights, the Fully Paid Rights, the New Ordinary Shares nor the Provisional Allotment Letters has been or will be registered

under the US Securities Act of 1933, as amended, or under the applicable securities laws of any state of the United States, any

province or territory of Canada, Australia, the State of Israel, New Zealand, Dubai International Finance Centre or the

Republic of South Africa. Accordingly, unless a relevant exemption from such requirements is available, neither the New

Ordinary Shares nor the Provisional Allotment Letters may, subject to certain exceptions, be offered, sold, taken up, renounced

or delivered, directly or indirectly, within the United States, Canada, Australia, the State of Israel, New Zealand, Dubai

International Finance Centre or the Republic of South Africa or in any country, territory or possession where to do so may

contravene local securities laws or regulations. Shareholders who believe that they, or persons on whose behalf they hold

Ordinary Shares, are eligible for an exemption from such requirements should refer to Part VIII of this document to determine

whether and how they may participate in the Rights Issue. Overseas Shareholders and any person who is resident in or a

citizen or national of any country outside the United Kingdom and any person (including, without limitation, nominees,

custodians and trustees) who has a contractual or other legal obligation to forward this document or a Provisional Allotment

Letter to a jurisdiction outside the United Kingdom should read paragraphs 7 and 8 of Part VIII of this document. Holdings

of Existing Ordinary Shares in certificated and uncertificated form will be treated as separate holdings for the purpose of

calculating entitlements under the Rights Issue.

The contents of this document are not to be construed as legal, business or tax advice. Each Shareholder should consult his,

her or its own legal adviser, financial adviser or tax adviser for legal, financial or tax advice.

Unless otherwise specified, this document contains certain translations of US Dollars into amounts in Pounds Sterling (and of

Pounds Sterling into amounts in US Dollars) for the convenience of the reader based on the exchange rate of US$1.00 =

£0.6787 or £1 = US$1.4734 (as applicable), being the relevant exchange rates on 24 March 2009 (the latest practicable date

prior to the date of the Announcement). These exchange rates were obtained from Bloomberg.

All information on reserves and production in this document is unaudited information and is sourced as set out in paragraph

17 of Part XVI of this document.

The contents of Premier’s website do not form part of this document.

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TABLE OF CONTENTS

Page

SUMMARY 4

RISK FACTORS 9

EXPECTED TIMETABLE OF PRINCIPAL EVENTS 18

DIRECTORY 19

RIGHTS ISSUE STATISTICS 21

PART I LETTER FROM THE CHAIRMAN OF PREMIER OIL PLC 22

PART II INFORMATION ON PREMIER 34

PART III INFORMATION ON ONSL 51

PART IV KEY INFORMATION 59

PART V SUMMARY OF THE PRINCIPAL TERMS OF THE ACQUISITION 65

PART VI SUMMARY OF THE COMPANY VOLUNTARY ARRANGEMENT

PROCEDURE FOR ONSL 68

PART VII SOME QUESTIONS AND ANSWERS ON THE RIGHTS ISSUE 70

PART VIII TERMS AND CONDITIONS OF THE RIGHTS ISSUE 77

PART IX INFORMATION CONCERNING THE NEW ORDINARY SHARES 95

PART X OPERATING AND FINANCIAL REVIEW 97

PART XI FINANCIAL INFORMATION ON PREMIER 124

PART XII FINANCIAL INFORMATION ON ONSL 125

PART XIII UNAUDITED PRO FORMA FINANCIAL INFORMATION 158

PART XIV COMPETENT PERSON’S REPORT 162

PART XV UNITED KINGDOM TAXATION 223

PART XVI ADDITIONAL INFORMATION 226

PART XVII DOCUMENTATION INCORPORATED BY REFERENCE 249

PART XVIII DEFINITIONS 250

NOTICE OF EXTRAORDINARY GENERAL MEETING 256

3


SUMMARY

The following information should be read as an introduction to and in conjunction with the full text

of this document. Any investment decision relating to Premier, the Rights Issue, the Acquisition or

the Enlarged Group should be based on a consideration of this document as a whole, including the

documents incorporated by reference. Investors should therefore read this entire document and notrely solely on this summary. In particular, investors should not rely on the summarised financial

information in this summary and should read the financial information contained in the remainder of

this document.

Civil liability will attach to those persons responsible for this summary (including any translation of

this summary) in any member state of the European Economic Area, but only if the summary ismisleading, inaccurate or inconsistent when read together with the other parts of this document.

Where a claim relating to the information contained in this document is brought before a court in a

member state of the European Economic Area, the plaintiff might, under the national legislation of

the member state where the claim is brought, be required to bear the costs of translating this

document before the legal proceedings are initiated.

1. Introduction

Premier announced on 25 March 2009 that it had (through its wholly-owned subsidiaries, POGL and

POEL) reached conditional agreement with Oilexco Inc. and ONSL to acquire ONSL or the ONSL

Assets for a maximum consideration of approximately US$505 million (approximately £343 million).

Premier proposes to fund the Acquisition and associated costs by way of:

* a 4 for 9 rights issue of New Ordinary Shares at a price of 485 pence per share to raise gross

proceeds of approximately £171 million (approximately US$252 million);

* New Credit Facilities comprising a US$175 million 18-month acquisition bridge facility, a

US$225 million 3-year revolving credit facility and US$63 million and £60 million 3-year letter

of credit facilities; and

* Premier’s existing cash resources.

2. Information on Premier and ONSL

Premier is an oil and gas exploration and production company. It is the Group’s ultimate parent

company. The Group was founded 75 years ago and has current interests in 11 countries around the

world and significant operations in the North Sea (UK and Norway), Asia and the Middle East. It

has a reserve and resource base of 382 mmboe, which is currently producing around 36,500 boepd (asof the year ended 31 December 2008).

ONSL is an oil and gas exploration and production company active in the UK, with its producing

properties located in the UK Central North Sea. ONSL is a wholly-owned subsidiary of Oilexco Inc.

and began operating in the North Sea in 2003. ONSL was placed into administration by its lending

banks on 7 January 2009. Since that date, ONSL’s Administrators have continued to operate thebusiness, which has continued to generate positive current cash flow from ongoing operations.

ONSL’s total production for the year ending 31 December 2009 is expected by Premier to be

approximately 13,700 boepd. As at 31 December 2008, ONSL had total 2P reserves and contingent

resources of approximately 60 mmboe, of which 40 mmboe is expected to be bookable to 2P reserves

by Premier.

3. Background to and reasons for the Acquisition

The Directors believe that the Acquisition is an opportunity with a compelling strategic, operational

and financial rationale, and will contribute significantly to the achievement of Premier’s strategic

objectives. The Acquisition will provide the Enlarged Group with a greater presence in the North Sea,

strengthening the Group’s existing operations in that area by adding a material package of assets

comprising existing producing fields, development projects of existing discovered reserves and a

portfolio of exploration prospects, together with high-quality UK operatorship capabilities.

The Directors believe that particular benefits of the Acquisition will include:

* Balancing the Enlarged Group by delivering critical mass in a second core area, the North Sea

* Enhancing the Group’s reserves, current production and cash flow

* Offering significant overlap with Premier’s existing North Sea assets and infrastructure

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* Strengthening exploration and appraisal portfolio with acquired North Sea acreage

* Strengthening operational flexibility via significant equity and operatorship positions

* Improving Premier’s portfolio of potential development projects

* Allowing Shareholders to benefit from a compelling acquisition valuation

* Ensuring that the Enlarged Group retains a conservative financing structure that allows for

future investment

The Directors also believe that the cash flows from the acquired producing fields of ONSL

complement, and will assist in, the funding of Premier’s previously announced development capital

expenditure requirements for its three developments in Asia.

4. Summary operating and financial information on Premier

The operating and financial information set out below has been extracted from Premier’s statutory

accounts for the three years ended 31 December 2008, which are incorporated by reference into this

document, as explained in Part XI of this document. The information set out below does not

constitute statutory accounts for any company within the meaning of section 435 of the Companies

Act 2006.

2P Reserves

(mmboe)

Production

(kboepd)

Profit after tax

(US$m)

Operating cash flow

(US$m)

2008 2007 2006 2008 2007 2006 2008 2007 2006 2008 2007 2006

228 212 152 36.5 35.8 33.0 98.3 39.0 67.6 352.3 269.5 244.8

5. Current trading and prospects of Premier

Despite volatile markets and the sharp downturn in economic activity, the Directors consider that theGroup is in a strong position to maintain its growth profile. Already in 2009, the Group has

progressed a number of critical contracts which are now at the centre of its development projects.

Premier is about to embark on an extensive exploration and appraisal campaign, which has the

potential to have a material impact on the Group. The quality of the Group’s producing assets,

underpinned by its financial position, secures its forward cash flows and allows it to progress its

exploration and development programmes that could bring very significant upside.

6. Principal terms of the Acquisition

Under the terms of the Acquisition, Premier (through its wholly-owned subsidiaries, POGL and

POEL) has agreed to acquire either: (i) the Shares; or (ii) the Assets. Premier has proceeded initially

with the Share Acquisition. Completion under the Share Acquisition Agreement is conditional upon,

inter alia, the approval of the Company Voluntary Arrangement (as more fully described in Part VI

of this document). The total consideration payable to Oilexco Inc. (acting through the Receiver)

under the Share Acquisition Agreement is US$1. However, in addition, POGL will also fund the

payment by ONSL of a settlement amount of US$505 million (the ‘‘Settlement Amount’’) tocompromise certain debts and liabilities owed to ONSL’s secured and unsecured creditors.

Appropriate adjustments will be made to the Settlement Amount to account for certain payables,

receivables and other items.

If the CVA is not approved, Premier (through POEL) will continue the Acquisition under the Asset

Acquisition Agreement, which has been entered into conditionally upon termination of the ShareAcquisition Agreement. The consideration payable by POEL under the Asset Acquisition Agreement

is US$415 million. Similar adjustments will be made to the consideration to account for certain

payables, receivables and other items.

Both of the Acquisition Agreements are conditional upon (i) Admission; and (ii) the approval byShareholders of the Acquisition at the EGM.

Both of the Acquisition Agreements contain a break fee in an amount of US$5.05 million in favour

of ONSL. The break fee is payable only if: (i) the Resolutions are not passed by Shareholders at the

EGM; or (ii) Admission does not take place by 14 June 2009.

Certain operating assets owned by ONSL are subject to pre-emption rights in favour of third parties.

If a third party exercises its right of pre-emption in respect of an asset, such asset will not form part

of the Acquisition and the consideration will be reduced accordingly.

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Under the terms of the Acquisition Agreements, if ONSL’s interest in one or more of the Balmoral

field interest, the Brenda field interest, the Nicol field interest or the Huntingdon field interest is

forfeited, revoked or terminated, or notice of forfeiture, revocation or termination is given before

Completion, POGL and/or POEL may terminate the Share Acquisition Agreement or the AssetAcquisition Agreement (as applicable) at its discretion.

7. Principal terms and conditions of the Rights Issue

The New Ordinary Shares will be offered by way of rights at 485 pence per share to Qualifying

Shareholders (other than, subject to certain exemptions, Excluded Overseas Shareholders) on the basis

of:

4 New Ordinary Shares for every 9 Existing Ordinary Shares

The Rights Issue Price represents a discount of approximately 49% to the Closing Price for an

Existing Ordinary Share of 952 pence on 24 March 2009 (the latest practicable date prior to the date

of the Announcement).

The New Ordinary Shares will, when issued and fully paid, rank pari passu in all respects with the

Existing Ordinary Shares. The Rights Issue has been fully underwritten by the Underwriters and isconditional upon:

(a) both the Acquisition Agreements not having been terminated, and the Acquisition not ceasing to

be capable of Completion in accordance with the terms of the Acquisition Agreements prior to

Admission;

(b) the Resolutions being passed at the EGM;

(c) Admission becoming effective by not later than 8.00 a.m. on 21 April 2009 (or such later time

and/or date as Premier and the Underwriters may agree (being not later than 8.00 a.m. on 6

May 2009)); and

(d) the Underwriting Agreement having become unconditional in all respects (save for conditionsrelating to Admission) and not having been terminated in accordance with its terms prior to

Admission.

The Rights Issue will result in dilution of 31% if existing Shareholders do not take up their rights

under the Rights Issue.

Application has been made to the UK Listing Authority and to the London Stock Exchange for theNew Ordinary Shares to be admitted to the Official List of the UK Listing Authority and to be

admitted to trading on the main market for listed securities of the London Stock Exchange. It is

expected that Admission will become effective and that dealings in the New Ordinary Shares will

commence on the London Stock Exchange, nil paid, at 8.00 a.m. on 21 April 2009.

8. Use of proceeds of the Rights Issue

The proceeds of the Rights Issue will be used to fund part of the consideration for the Acquisition,

together with transaction and acquisition costs. The Rights Issue is not conditional on Completion. In

the event that the Rights Issue proceeds but Completion does not take place, the Directors’ currentintention is that the net proceeds of the Rights Issue will be invested on a short-term basis while the

Directors consider how best to return the proceeds of the Rights Issue (after the deduction of

acquisition and transaction costs) to Shareholders. However, if, before Admission, the Acquisition

Agreements have both terminated or the Acquisition ceases to be capable of Completion, the Rights

Issue will not proceed.

9. New Credit Facilities

Premier has entered into the New Credit Facilities comprising a US$175 million 18-month acquisition

bridge facility, a US$225 million 3-year revolving credit facility and US$63 million and £60 million 3-year letter of credit facilities. The New Credit Facilities are conditional on Completion of the

Acquisition and are described in paragraph 12(f) of Part XVI of this document.

10. Risk factors

Shareholders should consider carefully the following risks, which are not the only risks facing

Premier, ONSL and the Enlarged Group:

6


Risk factors relating to Premier, ONSL and the Enlarged Group

* failure to access new oil and gas reserves could slow oil and gas production growth and

replacement of reserves;

* the assumptions on which estimates of hydrocarbon reserves or resources have been based may

prove to be incorrect, particularly where uncertified data is used;

* failure to successfully integrate a strategic business acquisition (such as the Acquisition) may

adversely affect the business of the Enlarged Group;

* intense competition in the oil and gas business environment (including as a result of the scarcity

of vital services and capital equipment) may lead to increased costs and reduced available

growth opportunities;

* production plans may be adversely affected by a wide range of factors which are not within the

control of Premier or, following the Acquisition, the Enlarged Group;

* failure to comply with potentially complex and stringent health and safety laws and regulationsmay give rise to significant liabilities;

* fluctuation of hydrocarbon prices may affect Premier’s or, following the Acquisition, the

Enlarged Group’s financial position;

* Premier or, following the Acquisition, the Enlarged Group may be adversely affected by

political, economic, legal, regulatory or social changes in certain countries, including by the

significant influence of certain governments over the oil and gas industry;

* there can be no assurance that the proceeds of insurance applicable to covered risks will be

adequate to cover uninsured hazards;

* conditions in the credit markets could prevent Premier from refinancing its facilities on

acceptable terms or at all in the longer-term.

Risk factors relating to the Acquisition

* the implementation of the Acquisition is subject to the satisfaction of a number of conditions

and there is no guarantee that these conditions will be satisfied; if the conditions are not

satisfied, the proceeds of the Rights Issue will not be used for the purchase price for the

Acquisition;

* as Premier has received no representations, warranties or other indemnities in connection with

the Acquisition, it does not have any recourse against any person for defects in title or third

party rights, or for any undiscovered liabilities or obligations connected with the acquired Shares

or Assets (as applicable);

* there may have been a significant deterioration in the value of ONSL’s business since it wasplaced into administration;

* certain Assets are subject to pre-emption rights which, if exercised, will preclude Premier from

acquiring such Assets;

* accumulated tax losses within ONSL may be less than anticipated;

* if the Acquisition proceeds by way of a Share Acquisition there may be objections by creditors

to the CVA which, ultimately, could lead to a court unwinding the CVA;

* the invalid appointment of, or conferral of powers to, a receiver or an administrator gives rise

to a risk that the purchase of the ONSL Shares (in the case of the Receiver) or the ONSL

Assets (in the case of the Administrator) could be challenged, and Premier would have no

recourse to the Receiver or the Administrators (as applicable) should any liability arise on acontract entered into by such officer.

Risk factors relating to the terms of the New Credit Facilities

* Premier could be required to refinance the US$175 million 18-month acquisition bridge facility

at a significantly increased cost to the Enlarged Group;

* the covenants and other restrictions applicable to the New Credit Facilities could restrict the

Enlarged Group’s business, flexibility or ability to undertake strategic or significant transactions.

7


Risk factors relating to the Rights Issue and the New Ordinary Shares

* Premier’s share price could be the subject of significant price fluctuations due to a change in

sentiment in the market;

* an active market in Nil Paid Rights may not develop on the London Stock Exchange during the

trading period;

* the market price of the Ordinary Shares may decrease, reducing the discount at which the New

Ordinary Shares are available to Qualifying Shareholders; and

* if Shareholders do not take up the offer under the Rights Issue, their proportionate ownership

and voting interests in Premier will be reduced.

8


RISK FACTORS

You should carefully consider the risks and uncertainties described below, in addition to the other

information in this document. The risks and uncertainties described below represent all of those known to

the Directors as at the date of this document which the Directors consider to be material. However,

these risks and uncertainties are not the only ones facing the Group and/or the Enlarged Group;

additional risks and uncertainties not presently known to the Directors, or that the Directors currently

consider to be immaterial, could also impair the business of the Group and/or the Enlarged Group. If

any or a combination of these risks actually occurs, the business, financial condition and operating

results of the Group and/or the Enlarged Group could be adversely affected. In such case, the market

price of the Ordinary Shares could decline and you may lose all or part of your investment.

No statement contained in the risks and uncertainties described below should be taken as qualifying the

statement as to the sufficiency of working capital set out in paragraph 3 of Part IV of this document.

1. Risk factors relating to Premier, ONSL and the Enlarged Group

Reserves replacement

Future oil and gas production will depend on Premier’s or, following the Acquisition, the Enlarged

Group’s access to new reserves through exploration, negotiations with governments and other owners

of known reserves, and acquisitions. Failures in exploration or in identifying and finalisingtransactions to access potential reserves could slow Premier’s or the Enlarged Group’s oil and gas

production growth and replacement of reserves. This, in turn, could have an adverse affect on the

turnover and profits of Premier or the Enlarged Group.

In addition, the results of appraisal of discoveries are uncertain and may involve unprofitable efforts,not only from dry wells, but also from wells that are productive but uneconomic to develop.

Appraisal and development activities may be subject to delays in obtaining governmental approvals or

consents, shut-ins of connected wells, insufficient storage or transportation capacity or other

geological and mechanical conditions all of which may variously increase Premier’s or, following the

Acquisition, the Enlarged Group’s costs of operations.

Exploration activities are capital intensive and inherently uncertain in their outcome. There is

therefore a risk that Premier or, following the Acquisition, the Enlarged Group will undertake

exploration activities and incur significant costs in so doing with no assurance that such expenditure

will result in the discovery of hydrocarbons, whether or not in commercially viable quantities. If

exploration activities prove unsuccessful over a prolonged period of time, Premier or the Enlarged

Group may not, after 12 months from the date of this document, have sufficient working capital to

continue to meet their obligations and their ability to obtain additional financing necessary to

continue operations may also be adversely affected.

Estimation of reserves, resources and production profiles

The estimation of oil and gas reserves, and their anticipated production profiles involves subjective

judgments and determinations based on available geological, technical, contractual and economic

information. They are not exact determinations. In addition, these judgments may change based on

new information from production or drilling activities or changes in economic factors, as well as from

developments such as acquisitions and dispositions, new discoveries and extensions of existing fieldsand the application of improved recovery techniques. Published reserve estimates are also subject to

correction for errors in the application of published rules and guidance.

The reserves, resources and production profile data contained in this document are estimates only and

should not be construed as representing exact quantities. They are based on production data, prices,costs, ownership, geophysical, geological and engineering data, and other information assembled by

Premier or ONSL (as applicable). The estimates may prove to be incorrect and potential investors

should not place undue reliance on the forward-looking statements contained in this document

concerning Premier’s or ONSL’s reserves and resources or production levels.

If the assumptions upon which the estimates of Premier’s or ONSL’s hydrocarbon reserves, resources

or production profiles have been based prove to be incorrect, Premier or, following the Acquisition,

the Enlarged Group may be unable to recover and produce the estimated levels or quality of

hydrocarbons set out in this document and Premier’s or the Enlarged Group’s business, prospects,

financial condition or results of operations could be materially adversely affected.

9


Business acquisitions – integration and other issues

Part of Premier’s strategy is or, following the Acquisition, part of the Enlarged Group’s strategy will

be to increase oil and gas reserves through strategic business acquisitions. Risks commonly associatedwith acquisitions of companies or businesses include the difficulty of integrating the operations and

personnel of the acquired business, problems with minority shareholders in acquired companies, the

potential disruption of Premier’s or the Enlarged Group’s own business, the possibility that

indemnification agreements with the sellers may be unenforceable or insufficient to cover potential

liabilities and difficulties arising out of integration. Furthermore, the value of any business Premier or

the Enlarged Group acquires or invests in may be less than the amount it pays. (These risks may also

apply to the Acquisition itself).

Currency fluctuations and exchange controls

Premier operates and, following the Acquisition, the Enlarged Group will operate in a number of

different countries and territories throughout the world. Premier is, or the Enlarged Group will be,

subject to risks from changes in currency values and exchange controls. The Enlarged Group’s

exposure to such risks will be increased by the Acquisition, as ONSL has a greater exposure to costs

in Pounds Sterling. Changes in currency values and exchange controls could have an adverse effect on

Premier’s or the Enlarged Group’s results of operations and financial position.

Competition

Premier operates or, following the Acquisition, the Enlarged Group will operate in a very challenging

business environment and competition for access to exploration acreage, gas markets, oil services andrigs, technology and processes, and human resources is intense. Competitors include companies with,

in many cases, greater financial resources, local contacts, staff and facilities than those of Premier or

the Enlarged Group. Competition for exploration and production licences as well as other regional

investment or acquisition opportunities may increase in the future. This may lead to increased costs in

the carrying on of Premier’s or the Enlarged Group’s activities and reduced available growth

opportunities. Any failure by Premier or the Enlarged Group to compete effectively could adversely

affect Premier’s or the Enlarged Group’s operating results and financial condition.

Third party contractors and providers of capital equipment

In particular, Premier has or, following the Acquisition, the Enlarged Group will have an interest in

contracts or leases, services and capital equipment from third-party providers. Such equipment and

services can be scarce and may not be readily available at the times and places required. In addition,

the costs of third-party services and equipment have increased significantly over recent years and may

continue to rise. Scarcity of equipment and services and increased prices may, in particular, result

from any significant increase in regional exploration and development activities which in turn may be

the consequence of increased or continued high prices for oil or gas. The scarcity of such equipment

and services, as well as their potentially high costs, could delay, restrict or lower the profitability andviability of Premier’s or the Enlarged Group’s projects and therefore have a material adverse affect

on Premier’s or the Enlarged Group’s business.

Production

The delivery of Premier’s production plans depends or, following the Acquisition, the delivery of the

Enlarged Group’s production plans will depend on the successful continuation of existing field

production operations and the development of key projects. Both of these involve risks normally

incidental to such activities including blowouts, oil spills, explosions, fires, equipment damage or

failure, natural disasters, geological uncertainties, unusual or unexpected rock formations, abnormalpressures, availability of technology and engineering capacity, availability of skilled resources,

maintaining project schedules and managing costs, as well as technical, fiscal, regulatory, political and

other conditions. Such potential obstacles may impair Premier’s or the Enlarged Group’s continuation

of existing field production and delivery of key projects and, in turn, Premier’s or the Enlarged

Group’s operational performance and financial position (including the financial impact from failure to

fulfil contractual commitments related to project delivery).

Premier or, following the Acquisition, the Enlarged Group may face interruptions or delays in the

availability of infrastructure, including pipelines and storage tanks, on which exploration and

production activities are dependent. The production performance of the reservoirs and wells may also

be different to that forecast due to normal geological or mechanical uncertainties. Such interruptions,

delays or performance differences could result in disruptions or changes to Premier’s or the Enlarged

10


Group’s existing production and projects, lower production and increased costs, and may have an

adverse effect on Premier’s or the Enlarged Group’s profitability.

Health, Safety, Environment and Security (‘‘HSES’’)

The range of Premier’s or, following the Acquisition, the Enlarged Group’s operated and joint

venture production operations globally means that Premier’s HSES risks cover, and the Enlarged

Group’s HSES risks will cover, a wide spectrum. These risks include major process safety incidents;

failure to comply with approved policies; effects of natural disasters and pandemics; social unrest;civil war and terrorism; exposure to general operational hazards; personal health and safety; and

crime. The consequences of such risks materialising can be injuries, loss of life, environmental harm

and disruption to business activities. Depending on cause and severity, the materialisation of such

risks may affect Premier’s or the Enlarged Group’s reputation, operational performance and financial

position.

In addition, failure by Premier or, following the Acquisition, the Enlarged Group to comply with

applicable legal requirements or recognised international standards may give rise to significant

liabilities. HSES laws and regulations may over time become more complex and stringent or the

subject of increasingly strict interpretation or enforcement. The terms of licences may include more

stringent HSES requirements. The obtaining of exploration, development or production licences and

permits may become more difficult or be the subject of delay by reason of governmental, regional or

local environmental consultation, approvals or other considerations or requirements. These factorsmay lead to delayed or reduced exploration, development or production activity as well as to

increased costs.

Reputation

It is important for maintaining Premier’s or, following the Acquisition, the Enlarged Group’s licencesto operate and ability to secure new resources that Premier or the Enlarged Group should maintain

strong and positive relationships with the governments and communities in the countries where its

business is conducted. Premier’s business principles govern or, following the Acquisition, will govern

how Premier and the Enlarged Group conduct their affairs. Failure – real or perceived – to follow

these principles, or any of the risk factors described in this document materialising, could harm

Premier’s or the Enlarged Group’s reputation, which could, in turn, impact Premier’s or the Enlarged

Group’s licence to operate, financing and access to new opportunities.

Human resources

Premier’s key human resources are or, following the Acquisition, the Enlarged Group’s key human

resources will be essential for the successful delivery of projects and continuing operations. Loss of

personnel to competitors or inability to attract quality human resources could affect Premier’s or theEnlarged Group’s operational performance and growth strategy.

Hydrocarbon prices

Historically, hydrocarbon prices have been subject to large fluctuations in response to a variety of

factors beyond Premier’s or ONSL’s control. Factors that influence these fluctuations includeoperational issues, natural disasters, weather, political instability or conflicts, economic conditions or

actions by major oil-exporting countries. Price fluctuations can affect Premier’s business assumptions,

investment decisions and financial position or, following the Acquisition, could affect the Enlarged

Group’s business assumptions, investment decisions and financial position. In particular, lower

hydrocarbon prices may reduce the economic viability of Premier’s or the Enlarged Group’s projects,

result in a reduction in revenues or net income, impair Premier’s or the Enlarged Group’s ability to

make planned expenditures and could materially adversely affect Premier’s or the Enlarged Group’s

business, prospects, financial condition and results of operations.

Current and future financing

Premier and, following the Acquisition, the Enlarged Group will require new financing to refinance

existing facilities (all of which have a term or an unexpired term of more than 12 months from thedate of this document) and may, in the longer-term, require additional financing to fund future

exploration and development plans. This financing may not be available or, if available, may not be

available on favourable terms. The ability of Premier or the Enlarged Group to arrange such

financing in the future will depend in part upon the prevailing capital market conditions, as well as

the business performance of Premier or the Enlarged Group. There can be no assurance that Premier

11


or the Enlarged Group will be successful in its efforts to arrange additional financing on satisfactory

terms. If adequate funds are not available, or are not available on acceptable terms, Premier or the

Enlarged Group may not be able to take advantage of opportunities, or otherwise respond to

competitive pressures and remain in business.

Political, economic, legal, regulatory and social uncertainties

Premier operates or, following the Acquisition, the Enlarged Group will operate in some countries

where political, economic and social transition is taking place. Changes in politics, laws and

regulations can affect Premier’s or could affect the Enlarged Group’s operations and earnings. Such

circumstances include forced divestment of assets; limits on production; import and exportrestrictions; international conflicts, including war; civil unrest and local security concerns that threaten

the safe operation of Premier’s or the Enlarged Group’s facilities; price controls, tax increases and

other retroactive tax claims; expropriation (including ‘‘creeping’’ expropriation) and nationalisation of

property; terrorism; outbreaks of infectious diseases; cancellation of contract rights; and

environmental regulations. It is difficult to predict the timing or severity of these occurrences or their

potential effect. If such risks materialise they could affect the employees, reputation, operational

performance and financial position of Premier or the Enlarged Group.

Premier operates or, following the Acquisition, the Enlarged Group will operate in countries which

have transportation, telecommunications and financial services infrastructures that may present

logistical challenges not associated with doing business in more developed locales.

Either Premier or the Enlarged Group may have difficulty ascertaining its legal obligations and

enforcing any rights which it may have. Certain governments in other countries have in the past

expropriated or nationalised property of hydrocarbon production companies operating within their

jurisdictions. Sovereign or regional governments could require Premier or the Enlarged Group to

grant to them larger shares of hydrocarbons or revenues than previously agreed to. Furthermore, it

may be expensive and logistically burdensome to discontinue hydrocarbon exploration and/or

production operations in a particular country should economic, political, physical or other conditionssubsequently deteriorate. All of these factors could materially adversely affect Premier’s or the

Enlarged Group’s business, results of operations, financial condition or prospects.

Joint ventures and partners

Inherently, oil and gas operations globally are conducted in a joint venture environment. Many of

Premier’s and ONSL’s major projects are operated by a partner in the relevant joint venture. Theability of Premier and ONSL to influence their partners will sometimes be limited due to their

percentage ownership in non-operated development and production operations. Non-alignment on

various strategic decisions in joint ventures may result in operational or production inefficiencies or

delay.

Governmental involvement in the oil and gas industry

The governments of countries in which Premier currently operates or may operate or, following theAcquisition, the Enlarged Group will or may operate have exercised and continue to exercise

significant influence over many aspects of their respective economies, including the oil and gas

industry. Any government action concerning the economy, including the oil and gas industry (such as

a change in oil or gas pricing policy or taxation rules or practice, or renegotiation or nullification of

existing concession contracts), could have a material adverse effect on Premier or the Enlarged

Group. Furthermore, there can be no assurance that these governments will not postpone or review

projects or will not make any changes to laws, rules, regulations or policies, in each case, which could

materially adversely affect Premier’s or the Enlarged Group’s financial position, results of operationsor prospects.

Uninsured hazards

Premier or, following the Acquisition, the Enlarged Group may be subject to substantial liability

claims due to the inherently hazardous nature of their business or for acts and omissions of sub-

contractors, operators or joint venture partners. Any indemnities Premier or the Enlarged Group mayreceive from such parties may be difficult to enforce if such sub-contractors, operators or joint

venture partners lack adequate resources. There can be no assurance that the proceeds of insurance

applicable to covered risks will be adequate to cover expenses relating to losses or liabilities.

Accordingly, Premier or the Enlarged Group may suffer material losses from uninsurable or

uninsured risks or insufficient insurance coverage.

12


Counterparties

Premier has entered into or, following the Acquisition, the Enlarged Group will be subject to

agreements with a number of contractual counterparties in relation to the sale and supply ofhydrocarbon production volumes. Therefore, Premier is, or the Enlarged Group will be, subject to the

risk of delayed payment for delivered production volumes or counterparty default. Such delays or

defaults could materially adversely affect Premier’s or the Enlarged Group’s business, results of

operations and cash flows.

Licensing and other regulatory requirements

Countries in which Premier currently operates or may operate or, following the Acquisition, the

Enlarged Group will or may operate are subject to licences, regulations and approvals ofgovernmental authorities, including those relating to the exploration, development, operation,

production, marketing, pricing, transportation and storage of oil and gas, taxation, environmental,

and health and safety matters.

Premier has or the Enlarged Group will have limited control over whether or not necessary approvals

or licences (or renewals thereof) are granted, the timing of obtaining (or renewing) such licences or

approvals, the terms on which they are granted or the tax regime to which Premier or the EnlargedGroup or the assets in which Premier or the Enlarged Group has interests will be subject. As a result,

Premier or the Enlarged Group may have limited control over the nature and timing of exploration

and development of oil and gas fields in which Premier or the Enlarged Group has or seeks interests.

There can be no assurance that Premier or the Enlarged Group will not in the future incur

decommissioning charges since local or national governments may require decommissioning to be

carried out in circumstances where there is no express obligation to do so, particularly in case of

future licence renewals.

Licence withdrawal and renewal

It is possible that in the future Premier or, following the Acquisition, the Enlarged Group may be

unable or unwilling to comply with the terms or requirements of a licence in circumstances that

entitle the relevant authority to suspend or withdraw the terms of such licence. Moreover, some of

the exploration and production licences which are held by Premier or will be held by the Enlarged

Group expire or may expire before the end of what Premier estimates or the Enlarged Group may

estimate to be the productive life of the licenced fields. There can be no assurance that extensions willbe granted in relation to such licences. Any failure to receive such extensions or any premature

termination, suspension or withdrawal of licences may have a material adverse effect on Premier’s or

the Enlarged Group’s reserves, business, results of operations and prospects.

Credit market conditions and credit ratings

Recent events in the credit markets have significantly restricted the supply of credit, as financial

institutions have applied more stringent lending criteria or exited the market entirely. If current

market conditions continue, it will be more costly and more difficult for Premier or, following theAcquisition, the Enlarged Group to refinance its debt as it falls due in the longer-term.

In addition, it has become and may become more costly to raise new funds to take advantage of

opportunities.

Macroeconomic risks could result in an adverse impact on Premier’s or, following the Acquisition, theEnlarged Group’s financial condition

One of the principal uncertainties for Premier and the Enlarged Group at present is the extent to

which the global economic slowdown currently being experienced may feed through into Premier’s or,

following the Acquisition, the Enlarged Group’s major operations, and the timing of that impact. The

links between economic activities in different markets and sectors are complex and depend not only

on direct drivers such as the balance of trade and investment between countries, but also on domestic

monetary, fiscal and other policy responses to address macroeconomic conditions.

2. Risk factors relating to the Acquisition

General risks relating to the Acquisition

Conditions of the Acquisition

The implementation of the Acquisition is subject to the satisfaction (or waiver, where applicable) of a

number of conditions, including:

13


* for the Share Acquisition Agreement, completion of the agreed CVA process with unsecured

creditors; and

* for the Asset Acquisition Agreement, successful completion of the relevant pre-emption processes

applicable to some of the Assets.

There is no guarantee that these (or other) conditions will be satisfied (or waived, if applicable), in

which case the Acquisition will not be completed. The conditions are more fully described in Part V

of this document. If the Rights Issue has become unconditional but the Acquisition has not, the

Company will raise proceeds in the Rights Issue that may not subsequently be used to pay the

purchase price for the Acquisition if the Acquisition does not complete.

No warranties in connection with the Acquisition

As is customary in the case of purchases from sellers in administration or receivership, Premier has

received no representations, warranties or other indemnities of any kind in connection with the

Acquisition. Premier will therefore acquire the ONSL Shares or Assets (as applicable) pursuant to theAcquisition, together with any potential risks and liabilities associated with them, without having any

recourse against any person for defects in title to those ONSL Shares or Assets or for any

undiscovered liabilities or obligations connected with such ONSL Shares or Assets. If any such issues

arise after Completion, Premier could be left without full ownership of the ONSL Shares or Assets,

or with ownership of the ONSL Shares or Assets but with unexpected additional liabilities or

obligations, and with no ability to reclaim any of the consideration it has paid.

Deterioration in the value of ONSL’s business

ONSL was placed into administration on 7 January 2009. During the course of the administration,

the value of ONSL’s business may have fallen significantly due to the negative market perception ofthe administration process. The effects of such perception may include suppliers withdrawing lines of

credit and insisting that purchases are on cash on delivery terms or prepaid; customers refusing to

pay their invoices on time; customers seeking alternate suppliers; customers insisting on discounts on

outstanding debts and any new orders placed; a lack of new business; a fall in employee morale and

productivity; and the departure of skilled and senior employees essential to the business. This may

have negative consequences for the business of the Enlarged Group and its prospects following

Completion.

Certain of the Assets are subject to pre-emption rights

A number of the Assets held by ONSL are held pursuant to joint operating agreements and willtherefore be subject to pre-emption rights held by joint venture partners of ONSL if Premier acquires

such Assets pursuant to the Asset Acquisition Agreement. Premier would only be able to acquire

these Assets following compliance with the relevant contractual pre-emption process, which may

typically take a period of between 30 and 90 days or more to implement. If the joint venture partners

choose to exercise their rights, Premier will not be able to acquire such Assets at all. If all of the

Assets still subject to pre-emption are pre-empted, this could mean a reduction in the benefits of the

Acquisition for Premier, and will also mean that part of the proceeds of the Rights Issue will not be

required for use in payment of the purchase price.

If the Acquisition proceeds by way of Share Acquisition or Asset Acquisition the Bugle asset

(governed by P815 Licence) is also subject to a right of pre-emption under the relevant joint venture

agreement.

Assets subject to third party rights

While Premier has carried out a due diligence exercise in relation to ONSL, the Assets may be

subject to undisclosed third party rights (including, among others, fixed or floating charges, hire

purchase agreements and retention of title claims). If, at the conclusion of ONSL’s administration,

Premier has not procured the formal release of any such rights (or the purported release is in any

way invalid), beneficiaries may be entitled to exercise their rights over such Assets. Post-Acquisition,there is a risk that Premier will be prevented from dealing freely with the Assets or that its use of the

Assets will be restricted and/or made subject to Premier paying the relevant beneficiary a fee for such

use.

The Enlarged Group’s success will be dependent upon its ability to integrate ONSL

The Enlarged Group may encounter numerous integration challenges in connection with the

Acquisition, including challenges which are not currently foreseeable. In addition, the Enlarged

14


Group’s management and resources may be diverted away from its core business activities due to

personnel being required to assist in the integration process. This integration process may take longer

than expected, or difficulties relating to the integration, of which the Board is not yet aware, may

arise. This could adversely affect the implementation of the Enlarged Group’s plans, and the EnlargedGroup may not be successful in addressing risks or problems encountered in connection with the

integration and failure to do so may adversely affect its business or financial condition. In addition,

there is a risk that synergy benefits may fail to materialise, or they may be materially lower than have

been estimated which may have a material adverse affect on the financial condition of the Enlarged

Group.

Risks relating to the Acquisition proceeding by way of Share Acquisition

Objections to the CVA

While the Share Acquisition Agreement is conditional upon both the CVA being approved at a

creditors’ meeting and a 28 day objection period for creditor complaints having passed, there is still a

risk that the decision of the creditors to approve the CVA could be subsequently challenged after

Completion. A creditor entitled to vote at the creditors’ meeting (but who did not receive notice of

such meeting) may apply to the court and challenge the decision of the meeting. If the court issatisfied that the approval of the CVA unfairly prejudices such a creditor, it has the power to revoke

or suspend any decision of the creditors’ meeting and/or direct that a further meeting of the creditors

takes place. If successful, revocation or reconsideration of the approval of the CVA after the

completion of the Share Acquisition Agreement could, in theory, result in the unwinding of the CVA

and the resurrection of ONSL’s original debt obligations (which would therefore fall to be payable by

Premier); or that the CVA would stand, and ONSL would be required to compensate the affected

creditor in cash to the value of the affected claim.

Ongoing relations with suppliers

Certain of the contracts being terminated pursuant to the CVA, and certain of the liabilities being

compromised under the CVA, relate to suppliers to ONSL that have ongoing relationships with

ONSL or other members of the Group. In such cases, while the historic position may be dealt with

as part of the CVA, the ongoing relationships may be adversely affected in such a manner as could

impact on the business of the Enlarged Group going forward, in particular where the Enlarged

Group has limited choices of suppliers to fulfil the relevant role.

Appointment of receiver

The purchase of all the ordinary shares of ONSL is expected to occur through a Receiver appointed

by Royal Bank of Scotland. If this appointment is in any way invalid, or if the Receiver does not

have the right to deal with the property of Oilexco Inc., or has not obtained any required approval

(including any approval of any Canadian court that may be required) or authorisation of any third

party, there is a risk that the Share Acquisition could be challenged by creditors of Oilexco Inc. and

found to be invalid or not to convey any interest in the ONSL Shares to Premier.

Liability of Receiver

While the Business Corporations Act (Alberta) provides that a receiver must deal with any propertyin its possession or control in a commercially reasonable manner, as is customary in the case of

purchases from sellers who are subject to the Companies Creditors Arrangement Act (Canada), the

Share Acquisition Agreement expressly excludes the personal liability of the Receiver. Premier will

therefore have no recourse to the Receiver should any liability arise on any contract entered into by

the Receiver in the exercise of their rights pursuant to any applicable documents.

Taxation

As a result of its significant historical expenditures on exploration, appraisal and development of its

assets, ONSL has accumulated substantial UK tax losses which are potentially available to shelterfuture profits from UK tax if the Acquisition proceeds by way of the Share Acquisition.

As described in the risk factor entitled ‘‘No warranties in connection with the Acquisition’’ on page14, Premier has received no representations, warranties or other indemnities in connection with the

Acquisition. It is possible that the accumulated tax losses will be less than anticipated if HMRC

successfully challenges losses claimed in past tax returns that are still open (2007) or yet to be filed

(2008), either by reason of the eligibility of the actual expenditure, anti-avoidance provisions or by

challenging other aspects of the relevant tax returns.

15


Risks relating to the Acquisition proceeding by way of Asset Acquisition

Appointment of the Administrators

ONSL’s Administrators were appointed on 7 January 2009. If this appointment is in any way invalid,or if the Administrators have dealt with ONSL’s property without obtaining the necessary approvals

or authorisations, there is a risk that the Asset Acquisition could be challenged by ONSL’s creditors

and members.

Liability of the Administrators

As is customary in the case of purchases from sellers in administration, the Asset Acquisition

Agreement expressly excludes the personal liability of the Administrators. Premier will therefore have

no recourse to the Administrators should any liability arise on any contract entered into by the

Administrators in the exercise of their functions.

3. Risk factors relating to the terms of the New Credit Facilities

The covenants contained in the New Credit Agreements include financial and other covenantsincluding restrictions on the ability of the Enlarged Group to incur additional financial indebtedness,

grant security, make acquisitions or disposals, enter into mergers and repurchase shares as well as

covenants related to the Acquisition. These could restrict the Enlarged Group’s activities or flexibility

or ability to undertake strategic or significant transactions.

The Company has also entered into certain refinancing obligations in connection with the

US$175 million 18-month acquisition bridge facility. These include an obligation on the Company, if

required by the financiers at any time after the period commencing four months after Completion and

where the Company has not been able to demonstrate that the bridge facility will be refinanced byother means, to take steps to issue debt securities to refinance the bridge facility. If the Company is

unable to carry out such a refinancing (having taken all practicable steps within its control) the

bridge facility will not become repayable prior to its scheduled maturity date on 24 September 2010.

However, the costs of the bridge facility (both in terms of applicable margin and fees) will increase

over time so long as it remains outstanding and is not refinanced. In addition, the refinancing

arrangements referred to above could require the Company, in refinancing the bridge facility, to do so

at a significantly increased cost to the Enlarged Group.

4. Risk factors relating to the Rights Issue and the New Ordinary Shares

Premier’s share price will fluctuate

The market price of the New Ordinary Shares (including the Nil Paid Rights and the Fully Paid

Rights) and/or the Ordinary Shares could be subject to significant fluctuations due to a change in

sentiment in the market regarding the New Ordinary Shares (including the Nil Paid Rights and the

Fully Paid Rights) and/or the Ordinary Shares (or securities similar to them). Such risks depend on

the market’s perception of the likelihood of completion of the Rights Issue, and/or may occur in

response to various facts and events, including any variations in the Group’s operating results,

business developments of the Group and/or its competitors. Stock markets have, from time to time,experienced significant price and volume fluctuations that have affected the market prices for

securities and which may be unrelated to the Group’s operating performance or prospects.

Furthermore, the Group’s operating results and prospects from time to time may be below the

expectations of market analysts and investors. Any of these events could result in a decline in the

market price of the New Ordinary Shares (including the Nil Paid Rights and the Fully Paid Rights)

and/or the Ordinary Shares and investors may, therefore, not recover their original investment.

The sale of Ordinary Shares could have an adverse effect on the market price of the Ordinary Shares.Furthermore, it is possible that Premier may decide to offer additional shares in the future. An

additional offering could also have an adverse effect on the market price of the Ordinary Shares.

An active trading market in the Nil Paid Rights may not develop

An active trading market in the Nil Paid Rights may not develop on the London Stock Exchange

during the trading period. In addition, because the trading price of the Nil Paid Rights depends on

the trading price of the Ordinary Shares, the Nil Paid Rights price may be volatile and subject to the

same risks as noted elsewhere in this document.

16


Calculation of the issue price of the New Ordinary Shares

The issue price of the New Ordinary Shares has been calculated by reference, among other things, to

the Closing Price. The market price of the Ordinary Shares may subsequently decrease, reducing thediscount at which the New Ordinary Shares are available to Qualifying Shareholders (other than,

subject to certain exemptions, Excluded Overseas Shareholders).

Dilution of ownership

If Shareholders do not take up the offer of New Ordinary Shares under the Rights Issue their

proportionate ownership and voting interests in Premier will be reduced and the percentage that theirshares will represent of the total share capital of Premier will be reduced accordingly. Even if a

Shareholder elects to sell his unexercised Nil Paid Rights, or such Nil Paid Rights are sold on his

behalf, the consideration he receives may not be sufficient to compensate him fully for the dilution of

his percentage ownership of Premier’s share capital that may be caused as a result of the Rights

Issue.

17


EXPECTED TIMETABLE OF PRINCIPAL EVENTS

Each of the times and dates in the table below is indicative only and may be subject to change.

2009

Date of this document 3 April

Record Date for Rights Issue 6.00 p.m. on 16 April

Latest time and date for receipt of Forms of Proxy for

the Extraordinary General Meeting

10.00 a.m. on 18 April

Extraordinary General Meeting 10.00 a.m. on 20 April

Dispatch of Provisional Allotment Letters 20 April

Dealings expected to commence in New Ordinary Shares, nil paid, on the

London Stock Exchange and Existing Ordinary Shares marked ‘‘ex-rights’’


Nil Paid Rights and Fully Paid Rights enabled in CREST as soon as

practicable after


Recommended latest time and date for requesting withdrawal of Nil Paid

Rights or Fully Paid Rights from CREST

4.30 p.m. on 29 April

Recommended latest time and date for depositing renounced Provisional

Allotment Letters, nil paid or fully paid, into CREST

3.00 p.m. on 30 April

Latest time and date for splitting Provisional Allotment Letters, nil paid and

fully paid

3.00 p.m. on 1 May

Latest time and date for acceptance, delivery of Nil Paid Rights, payment in full

for rights taken up in CREST and registration of renunciation of ProvisionalAllotment Letters

11.00 a.m. on 6 May

Commencement of dealings in New Ordinary Shares fully paid on the London

Stock Exchange

8.00 a.m. on 7 May

New Ordinary Shares in uncertificated form credited to stock accounts in

CREST

8.00 a.m. on 7 May

Expected date of dispatch of definitive share certificates for New Ordinary

Shares in certificated form

8.00 a.m. on 14 May

Expected date of Completion of the Acquisition May

Notes:

(1) Reference to times in this document are to London time unless otherwise stated.

(2) The dates set out in the expected timetable of principal events above and mentioned throughout this document and in theProvisional Allotment Letters may be adjusted by Premier in which event details of the new dates will be notified to the FSA,London Stock Exchange and, where appropriate, the Shareholders.

(3) If you have any queries on the procedure for acceptance and payment, you should contact the Registrar on 0871 664 0321 or fromoutside the United Kingdom on +44 20 8639 3399. Calls to the 0871 664 0321 number cost 10 pence per minute (including VAT)plus your service provider’s network extras. Different charges may apply to calls from mobile telephones and calls may berecorded or randomly monitored for security and training purposes. Please note that the Registrar cannot provide financial adviceon the Rights Issue or as to whether or not you should take up your rights under the Rights Issue.

18


DIRECTORY

Registered Office 4th Floor

Saltire Court20 Castle Terrace

Edinburgh EH1 2EN

Directors Sir David John KCMG, Chairman

Simon Lockett, Chief Executive

Tony Durrant, Finance Director

Robin Allan, Director of Business Development

Neil Hawkings, Operations Director

John Orange, Senior Independent Non-Executive Director

Michel Romieu, Independent Non-Executive Director

David Lindsell, Independent Non-Executive Director

Professor Dr. David Roberts, Independent Non-Executive Director

Joe Darby, Independent Non-Executive Director

Company Secretary Stephen Huddle

Financial Adviser Deutsche Bank AG

Winchester House

1 Great Winchester Street

London EC2N 2DB

Global Co-ordinator, Joint Sponsor,

Joint Bookrunner, Underwriter and

Joint Broker

Deutsche Bank AG

Winchester House


London EC2N 2DB

Joint Sponsor, Joint Broker, Co-

Lead Manager and Underwriter

Oriel Securities Limited

125 Wood Street

London EC2V 7AN

Joint Bookrunners and Underwriters Barclays Bank PLC

5 The North Colonnade

Canary Wharf

London E14 4BB

HSBC Bank plc

8 Canada Square

London E14 5HQ

Royal Bank of Canada Europe Limited

71 Queen Victoria Street

London EC4V 4DE

Solicitors to the Joint Sponsors and

Underwriters

Clifford Chance LLP

10 Upper Bank Street

London E14 5JJ

Registrar and Receiving Agent Capita Registrars Limited

The Registry

34 Beckenham RoadBeckenham

Kent BR3 4TU

Auditors and Reporting Accountants Deloitte LLP

2 New Street Square

London EC4A 3BZ

Solicitors to the Company Slaughter and May

One Bunhill Row

London EC1Y 8YY

19


Forward-looking statements

Certain statements contained in this document constitute ‘‘forward-looking statements’’. In some

cases, these forward-looking statements can be identified by the use of forward-looking terminology,including the terms ‘‘believes’’, ‘‘estimates’’, ‘‘plans’’, ‘‘prepares’’, ‘‘anticipates’’, ‘‘expects’’, ‘‘intends’’,

‘‘may’’, ‘‘will’’ or ‘‘should’’ or, in each case, their negative or other variations or comparable

terminology. Such forward-looking statements involve known and unknown risks, uncertainties and

other factors which may cause the actual results, performance or achievements of Premier and/or of

the Enlarged Group, or industry results, to be materially different from any future results,

performance or achievements expressed or implied by such forward-looking statements. Such forward-

looking statements are based on numerous assumptions regarding Premier’s and/or the Enlarged

Group’s present and future business strategies and the environment in which Premier, and/or theEnlarged Group, will operate in the future. Such risks, uncertainties and other factors are set out

more fully in the section entitled ‘‘Risk Factors’’ on pages 9 to 17 of this document. These forward-

looking statements speak only as at the date of this document. Premier expressly disclaims any

obligation or undertaking to release publicly any updates or revisions to any forward-looking

statements contained in this document to reflect any change in Premier’s expectations with regard

thereto or any change in events, conditions or circumstances on which any such statement is based,

except as required by applicable laws, the Prospectus Rules, the Listing Rules and the Disclosure and

Transparency Rules.

20


RIGHTS ISSUE STATISTICS

Rights Issue Price per New Ordinary Share 485 pence

Basis of Rights Issue 4 New Ordinary Shares for

every 9 Existing Ordinary

Shares

Number of Ordinary Shares in issue at the date of this document 79,372,274

Number of New Ordinary Shares to be provisionally allotted pursuant to

the Rights Issue

35,276,566

Number of Ordinary Shares in issue immediately following the Rights Issue 114,648,840

Estimated gross proceeds of the Rights Issue £171 million

Estimated expenses of the Rights Issue and the Acquisition £25.8 million

Estimated net proceeds of the Rights Issue £145.2 million

Note: The number of Ordinary Shares in issue immediately following the Rights Issue assumes that no options or awards are exercisedunder the Premier Share Option Schemes and no Convertible Bonds are converted between the Announcement and the Record Date.

21


PART I

LETTER FROM THE CHAIRMAN OF PREMIER OIL PLC

(Incorporated in Scotland with registered number SC234781)

Directors

Sir David John KCMG, Chairman

Simon Lockett, Chief Executive

Tony Durrant, Finance Director

Robin Allan, Director of Business Development

Neil Hawkings, Operations Director

John Orange, Senior Independent Non-Executive Director

Michel Romieu, Independent Non-Executive Director

David Lindsell, Independent Non-Executive Director

Professor Dr. David Roberts, Independent Non-Executive Director

Joe Darby, Independent Non-Executive Director

Registered office:

4th Floor

Saltire Court

20 Castle Terrace

Edinburgh EH1 2EN

3 April 2009

To the holders of Ordinary Shares

Dear Shareholder,

Acquisition of ONSL (or of the ONSL Assets)

and a 4 for 9 Rights Issue of New Ordinary Shares at a price of 485 pence per share

1. Introduction to the Acquisition

On 25 March 2009, the Board announced that the Company (through its wholly-owned subsidiaries,

POGL and POEL) had entered into an agreement to acquire ONSL or the ONSL Assets for cash of

up to approximately US$505 million (approximately £343 million). ONSL is the principal operating

subsidiary of Oilexco Inc., an international oil and gas exploration and development company with

interests in the UK North Sea, and will be acquired free of bank debt, historical rig and FPSOcommitments.

The Board believes that the Acquisition represents an attractive opportunity for the Company to

expand its presence in the North Sea in line with its stated strategy. The Acquisition secures an

attractive, high-growth North Sea focussed business and delivers synergies with Premier’s existingNorth Sea assets, at a compelling valuation.

The purpose of this document is, amongst other things: (i) to explain the background to, and reasons

for, the Acquisition, (ii) to explain why the Directors believe that the Acquisition will assist in

promoting the success of the Company and is in the best interests of the Company and theShareholders as a whole, and (iii) to recommend that you vote in favour of the Resolutions to be

proposed at the Extraordinary General Meeting.

The Acquisition and associated fees and expenses will be funded by way of:

* a Rights Issue of New Ordinary Shares at a price of 485 pence per share on the basis of 4 New

Ordinary Shares for every 9 Existing Ordinary Shares. Assuming no options under the Premier

Share Option Schemes and no Convertible Bonds are exercised or converted between the

Announcement and the Record Date, 35,276,566 New Ordinary Shares will be issued, raising

gross proceeds of approximately £171 million (approximately US$252 million);





22


The New Ordinary Shares will represent approximately 31% of the enlarged share capital of the

Company following the Acquisition (assuming no options are exercised under the Premier Share

Option Schemes and no Convertible Bonds are converted into Ordinary Shares between the

Announcement and the Record Date).

In view of its size relative to that of Premier, the Acquisition constitutes a Class 1 transaction underthe Listing Rules and accordingly is conditional on Shareholder approval. The Acquisition is also

conditional upon Admission (which in turn is effectively conditional on the passing of the Resolutions

to implement the Rights Issue). Resolutions to approve the Acquisition and to grant authorities

required to implement the Rights Issue will be proposed at an Extraordinary General Meeting of the

Company to be held on 20 April 2009 at 10.00 a.m. The notice convening the Extraordinary General

Meeting is set out at the end of this document.

The Share Acquisition is also subject to the approval by ONSL’s unsecured creditors and Oilexco Inc.

of the terms of the Company Voluntary Arrangement (as more fully described in Part VI of this

document) in respect of ONSL, and upon the expiry of a 28 day objection period after such approvalhas been granted, and upon the court discharging the administration order over ONSL. If these

conditions are not satisfied, the Company will instead seek to implement the Asset Acquisition (see

paragraph 7 below).

The Rights Issue is conditional, amongst other things, upon the passing of the Resolutions,

Admission, and the Underwriting Agreement having become unconditional in all respects (other than

conditions referring to Admission) and not having been terminated in accordance with its terms prior

to Admission. The Rights Issue is not conditional on Completion of the Acquisition. However if,

before Admission, the Acquisition Agreements have both terminated or the conditions to the

Acquisition cease to be capable of satisfaction, the Rights Issue will not proceed.

In the unlikely event that the Rights Issue proceeds but Completion does not take place, the

Directors’ current intention is that the net proceeds of the Rights Issue will be invested in cash ormoney-market funds on a short-term basis while the Directors consider how best to return the

proceeds of the Rights Issue (after the deduction of acquisition and transaction costs) to

Shareholders. Any such return of capital may have tax implications for Shareholders.

The Rights Issue Shares have been fully underwritten by the Underwriters on the basis summarised in

paragraph 2 of Part VIII of this document.

2. Background to and reasons for the Acquisition

The Directors believe that the Acquisition is an opportunity with a compelling strategic, operational

and financial rationale, and will contribute significantly to the achievement of Premier’s strategic

objectives. The Acquisition will provide the Enlarged Group with a greater presence in the North Sea,strengthening the Group’s existing operations in that area by adding a material package of assets

comprising existing producing fields, development projects of existing discovered reserves and a

portfolio of exploration prospects, together with high-quality UK operatorship capabilities.

The Directors believe that the Acquisition will represent a material step forward in Premier’s

development, in particular by:








* Ensuring that the Enlarged Group retains a conservative financing structure that allows forfuture investment


The Acquisition balances the Enlarged Group, delivering critical mass in a second core area, the

North Sea, in addition to Premier’s South East Asia (Indonesia and Vietnam) business. The

Acquisition also rebalances the Group’s business mix between high-impact Asian exploration and cash

generative North Sea production. The enlarged North Sea business, with operations in Aberdeen and

23


Stavanger, will be of a similar operational scale to Premier’s Asian business operating from Jakarta

and Ho Chi Minh City.


ONSL’s assets will add an additional 60 mmboe of 2P reserves and contingent resources (of which 40

mmboe is expected to be bookable to 2P reserves by Premier) to Premier’s 2P reserve and contingent

resources base of 382.3 mmboe (2008 year end). In addition, ONSL’s existing producing fields are

forecast to add an estimated 13,700 boepd of working interest production in 2009 to Premier’s

existing production of 36,500 boepd (2008 average).

Given the cash generative nature of the assets to be acquired, the higher levels of near-termproduction are accretive to Premier’s near-term operating cash flows. ONSL’s producing cash flow

profile is a good financial fit with Premier’s current significant investment programme for its three

Asian development projects.


Premier has been active in the UK North Sea since 1971. The Acquisition is in line with Premier’s

stated strategy of acquiring additional high-quality assets in existing core areas. ONSL’s attractive,

high growth North Sea focussed E&P assets are complementary to, and bring synergies with,

Premier’s existing Scott and Moth area interests in the Central North Sea area. The Acquisition also

provides the Group with an experienced operating team located in Aberdeen.


Upside potential has been identified by ONSL from exploration and appraisal activity conducted by

ONSL to date, with around 15 exploration prospects identified in the acreage surrounding ONSL’s

existing assets with unrisked reserve potential of up to 385 mmboe, as estimated by Oilexco Inc.


The addition of ONSL’s assets to Premier’s portfolio will bring significant equity stakes and pre-

existing operatorships in UK assets, along with an experienced operating team in Aberdeen with UK-

operated development and production competencies. These operatorship and equity positions will

provide flexibility for Premier to control the pace and timing of operated capital expenditure

programmes in response to varying economic and market conditions. In particular, the Directors

believe the Acquisition will allow Premier to participate more effectively in the ongoing consolidation

of North Sea assets that Premier believes provides a good opportunity to create value forShareholders.


The Acquisition enhances Premier’s development portfolio through the addition of ONSL’s

development base in the Balmoral area with a significant number of future potential developments.The Acquisition also adds Huntington to Premier’s pre-development portfolio, and appraisal upside in

the Moth and Scott area (Bugle, Blackhorse and Kildare). ONSL’s principal developments

(Huntington and Moth) are considered by the Directors to be economic at oil and gas prices of

around US$40/bbl and £0.32/therm. The Enlarged Group will also hold a position in field

infrastructure at Scott which will facilitate the developments in that area and also provide a strong

platform for developing other assets in neighbouring acreage. This will provide a source of future

tariff and cost sharing in the Central North Sea area through combining ONSL’s interests in the

Balmoral complex with Premier’s interest in the Scott field infrastructure.


The Acquisition will secure a significant package of North Sea assets at a compelling valuation of less

than US$8.50/bbl, before (in the case of the Share Acquisition) adjustment for ONSL’s substantial

unutilised brought forward tax losses of approximately US$1 billion. The Directors believe that thereare limited opportunities available of this scale in the North Sea and that the Acquisition allows

Premier to take advantage of asset valuations at this stage in the oil price cycle. The Acquisition has

a highly attractive purchase value of US$505 million, compared to the net asset value of 2P reserves

(as estimated by RISC) of approximately US$876 million. The pre-administration enterprise value of

Oilexco Inc. was US$2.7 billion as at 30 September 2008.

24


* Ensuring that the Enlarged Group retains a conservative financing structure that allows for futureinvestment

The Directors believe that the combination of the Acquisition and the Rights Issue leaves theEnlarged Group conservatively financed, with a robust balance sheet and an estimated US$385

million of liquidity in the form of cash and facilities remaining available to draw down at

Completion. With cash flow from the ONSL Assets arising from current production and the Group’s

New Credit Facilities having been successfully negotiated, the Directors believe that Premier has the

flexibility to execute both its existing forward development and exploration programme and that of

the Enlarged Group. The value within the acquired ONSL portfolio will be underpinned by hedging

in line with Premier’s current policy.

Strategy of the Enlarged Group

Post-Completion, Premier’s strategy will remain unchanged: to grow production and cash flow, with a

medium-term production target of 75,000 boepd; to maintain the Group’s high-impact explorationprogramme within disciplined spending limits; and to focus on selected value adding acquisitions

within core areas.

In the short-term, the Premier management team will concentrate on the integration of ONSL, with

interim arrangements in place between the date of signing of the Acquisition Agreements and

Completion, and intends to maintain ONSL’s operatorship capabilities. Premier intends to continue to

execute the Group’s current Asian portfolio investment programme, where development projects areproceeding. Premier’s forthcoming exploration programme will continue as previously announced.

Premier will continue to operate a conservative financing strategy, maintaining adequate levels of

liquidity in cash and undrawn facilities. The Group also plans to access longer-term debt facilities in

due course and will enter into hedging arrangements for acquired production in line with current

Premier policy, while considering selected asset sales from the combined Premier and ONSL

portfolios.

3. Information on ONSL

ONSL is an oil and gas exploration and production company active in the United Kingdom, with itsproducing properties located in the UK Central North Sea. ONSL is a wholly-owned subsidiary of

Oilexco Inc. and began operating in the North Sea in 2003.

ONSL’s gross assets as at 31 December 2007 (the most recent date for which audited financial

statements for ONSL have been prepared), were US$986.8 million and the loss before tax attributable

to those assets, for the year ended 31 December 2007, was US$(121.2) million. These figures reflect

ONSL’s restated financial statements based on Premier’s accounting policies. An accountants’ reporton ONSL covering the three years ended 31 December 2007 is set out in Part XII of this document.

ONSL has a balanced portfolio of offshore UK Central North Sea assets including producing fields

(the Balmoral area and Nelson), fields able to be brought onstream in the medium-term (Shelley,

Huntington) and potentially commercial discoveries (Bugle, Blackhorse, Kildare and Moth) which

remain subject to further appraisal. ONSL has material stakes in the majority of the 37 offshore

licences which it holds, and is the operator of a large proportion of such licences. The table belowsets out details of the principal assets owned by ONSL, all of which are located within the United

Kingdom:

Licence Block Operator Equity (%) Field

P032 30/17a Maersk 6.45% Janice, James

P077 22/12a Shell 50.00% Nelson(2)

P087(4) 22/7 ONSL 46.50% Nelson(2)

P101(6) 23/21 (Moth earn-in area) BG 50.00%

P1042 15/25b ONSL 100.00% Brenda

P1043 15/25c ONSL 100.00%

P1089 14/28a, 14/29b ONSL 45.00%

P1095 16/21b Maersk 50.00%

P110(6) 22/14a, 22/14aF1 ONSL 25.04%

P1104 21/4b Maersk 45.00%

P1114 22/14b, 22/19b E.ON 40.00%

P1157 15/25e, 15/26e ONSL 100.00%

P1181 23/22b Premier 32.50%

25


Licence Block Operator Equity (%) Field

P119 15/29a ONSL 60.00%

P1220 21/23a Sterling 65.00%

P1260 22/2b ONSL 100.00%

P1295 14/23b ONSL 45.00%

P1298(7) 15/26b Nexen 50.00%(4)

P1420 22/13b ONSL 72.70%

P1430 28/9, 28/10c Encore Petroleum 50.00%

P1431 29/6b ONSL 100.00%

P1457 13/20, 14/16, 14/17a, 14/21b,

14/22b

ONSL 55.00%

P1466 15/24c, 15/25f Premier 75.00%

P1467 15/25d Maersk 50.00%

P1498 13/14, 13/15 ONSL 55.00%

P1555 22/3a ONSL 100.00%

P185(4)(7) 15/22 Nexen 50.00%

P201(4) 16/21a (including 16/21aF1),

16/21aF2, 16/21b

ONSL 85.00% Balmoral(1), Glamis,

Stirling(3)

P213(8) 16/26UPF2 ONSL 100.00%

P233(9) 15/25a ONSL 70.00% Nicol

P295 30/16 Maersk 6.45%

P300 14/26a BG 70.00%

P344(4)(7) 16/21b (including 16/21b F1), ONSL 44.20% Balmoral(1),

16/21b 55.00% Northern

16/21c (including 16/21c F1) 44.00% Stirling(3)

P489 15/23b Nexen 50.00%

P640 15/24b ConocoPhillips 50.00%

P811(4) 13/30b BG 70.00%

P815(5)(7) 15/23d, 15/23e Nexen 41.00%

Notes:

(1) Unitised share of 78.11%



(4) Subject to pre-emption rights in the case of the Asset Acquisition Agreement. For more information please see paragraph 13 ofPart V of this document

(5) Subject to pre-emption in the case of the Asset Acquisition Agreement and the Share Acquisition Agreement. For moreinformation see paragraphs 7 and 13 of Part V of this document

(6) Outstanding earn-in interests

(7) Conditional farm-out obligations

(8) Outstanding earn-in interests under a sale and purchase agreement

(9) Conditional earn-in obligations

ONSL’s total production for the year ending 31 December 2009 is expected by Premier to be

approximately 13,700 boepd.

As at 31 December 2008, ONSL had total 2P reserves and contingent resources of approximately 60

mmboe, of which 40 mmboe is expected to be bookable as 2P by Premier. A Competent Person’sReport on ONSL has been prepared by RISC and is reproduced in full in Part XIV of this

document.

ONSL was placed into administration by its lending banks on 7 January 2009, as a result of the

inability of ONSL’s parent company, Oilexco Inc., to secure a refinancing of ONSL’s business. The

Administrators have continued to operate the business since the date of entry into administration andthe ONSL business has continued to generate positive current cash flow from ongoing operations.

It is Premier’s intention following Completion to integrate ONSL’s employees, all of whom are based

in Aberdeen, with its existing North Sea operations.

4. Structure of the Acquisition

POGL (a wholly-owned subsidiary of Premier) has entered into a conditional agreement with the

Receiver (the ‘‘Share Acquisition Agreement’’) to acquire the entire issued share capital of ONSL in a

transaction which values ONSL at approximately US$505 million (approximately £343 million).

26


The Share Acquisition is subject to the approval by ONSL’s unsecured creditors and Oilexco Inc. of

the Company Voluntary Arrangement (as more fully described in Part VI of this document) in

respect of ONSL, the expiry of a 28 day objection period after such approval and the court

discharging the administration order over ONSL. Completion under the Share Acquisition Agreementis also conditional upon the approval of the Acquisition by Shareholders, and upon Admission.

While the Directors believe that these conditions will be satisfied and the Share Acquisition will

proceed to Completion, POEL (another wholly-owned subsidiary of Premier) has entered into afurther conditional agreement with the Administrators (the ‘‘Asset Acquisition Agreement’’) to acquire

the Assets for cash consideration of approximately US$415 million (approximately £282 million) if the

conditions specific to the Share Acquisition above are not satisfied. The difference of US$90 million

(approximately £61 million) in the amounts payable under the two Acquisition Agreements reflects the

fact that Premier will not have the benefit of the existing tax losses carried forward within ONSL

under the Asset Acquisition.

Certain Assets owned by ONSL are subject to pre-emption rights in favour of third parties. The

Acquisition is not conditional on the waiver of such pre-emption rights, and therefore Premier has no

guarantee that it will obtain ownership of all or any of such Assets.

Under the Asset Acquisition, if a third party exercises its right of pre-emption in respect of an Asset

owned by ONSL, such Asset will not form part of the Asset Acquisition and the consideration

payable by Premier will be reduced by the amount paid by the pre-empting third party. Assets subject

to pre-emption in the case of the Asset Acquisition are ONSL’s interests in the P087 (Nelson), P1298,

P185, P201 (the Balmoral Field), P344 (Balmoral, Northern and Stirling), P811 and P815 (Bugle/Blackhorse) licences.

Stakeholders with pre-emption rights will typically have 30 days to decide whether to exercise their

rights, though in some cases this can be up to 90 days. As a result, if the Asset Acquisition proceeds,there will be an initial closing at which the non pre-emption assets will be acquired together with any

pre-emption assets in respect of which all stakeholders have by that time agreed to waive their pre-

emption rights. Further closings will take place for pre-emption assets once the relevant pre-emption

processes have been successfully completed.

Premier and the Administrators intend to approach stakeholders with pre-emption rights to seek

waivers of those rights before that first closing. One such stakeholder has already agreed to waive its

pre-emption rights in respect of two of the pre-emption assets. This includes a waiver of pre-emption

rights in respect of the Balmoral Field, which Premier considers to be the most significant of the pre-

emption assets. None of the remaining pre-emption assets are considered to be material in the context

of the Acquisition or the Enlarged Group.

In addition, if the Acquisition proceeds by way of Share Acquisition, the Bugle asset is also subject

to a right of pre-emption under the relevant joint venture agreement. However, this asset is

immaterial to the Acquisition, and the pre-emption right would be exercisable against ONSL after

Completion of its acquisition by Premier.

Further details of the Assets that are subject to pre-emption rights are set out in the table in

paragraph 2 of Part III of this document.

The Acquisition has been agreed with an effective date of 28 February 2009, such that certain cash

flows accruing between that date and Completion are for the account of Premier. As with any

purchase from administrators or receivers, the Acquisition will be on a no warranty and indemnity

basis (including as to title).

5. Financing the Acquisition

The Acquisition and associated fees and expenses (which are estimated to be approximately US$38

million) will be funded by way of:

* a Rights Issue of New Ordinary Shares at a price of 485 pence per share on the basis of 4 New

Ordinary Shares for every 9 Existing Ordinary Shares. Assuming no options under the Premier

Share Option Schemes or Convertible Bonds are exercised or converted between the

Announcement and the Record Date, 35,276,566 New Ordinary Shares will be issued, raising

gross proceeds of approximately £171 million (approximately US$252 million);




27



The New Credit Facilities are described in paragraph 12(f) of Part XVI of this document. The Rights

Issue is described in Part VIII of this document.

The Directors believe that the Enlarged Group’s balance sheet remains robust, with an estimated

US$385 million of liquidity in the form of cash and facilities remaining available to draw down at

Completion, and will provide the flexibility to execute both Premier’s existing planned investment

programme and that of the Enlarged Group.

6. Financial impact of the Acquisition and Rights Issue

The Board believes that the Acquisition will be beneficial to the Company on the following keymeasures:

Reserves and production

* Premier will benefit from ONSL’s approximately 60 mmboe of 2P reserves and contingentresources of which 40 mmboe is expected to be bookable to 2P by Premier.

* The Acquisition adds an estimated 13,700 boepd of working interest production for 2009, and

12,900 boepd in 2010, enabling the Enlarged Group to exceed Premier’s publicly stated medium-

term target of 50,000 boepd.

* The Acquisition has been agreed at a value of less than US$8.50/bbl, before (in the case of the

Share Acquisition) adjustment for ONSL’s substantial unutilised brought forward tax losses.

Cash flow and net assets

* The cash flows from the acquired producing fields of ONSL complement, and will assist in, the

funding of Premier’s previously announced development capital expenditure requirements for its

three developments in Asia.

The Board further believes that the Enlarged Group will, following the Rights Issue and as at

Completion, have the appropriate financial resources to exploit the combined asset base.

The Rights Issue will result in dilution of 31% if existing Shareholders do not take up their rights

under the Rights Issue. As a result of the Rights Issue, an adjustment will be made to the price at

which the Convertible Bonds can be converted.

7. Principal terms of the Acquisition

Under the terms of the Acquisition, the Group (through Premier’s wholly-owned subsidiaries, POGL

and POEL) has agreed to acquire either: (i) the Shares; or (ii) the Assets. Premier has proceeded

initially with the Share Acquisition. Completion under the Share Acquisition Agreement is conditional

upon, inter alia, the approval of the Company Voluntary Arrangement (as more fully described in

Part VI of this document). The total consideration payable to Oilexco Inc. (acting through theReceiver) under the Share Acquisition Agreement is US$1. However, in addition, POGL will also

fund the payment by ONSL of a settlement amount of US$505 million (the ‘‘Settlement Amount’’) to

compromise certain debts and liabilities owed to ONSL’s secured and unsecured creditors.

Appropriate adjustments will be made to the Settlement Amount to account for certain payables,

receivables and other items.

If the CVA is not approved, Premier (through POEL) will continue the Acquisition under the Asset

Acquisition Agreement, which has been entered into conditionally upon termination of the Share

Acquisition Agreement. The consideration payable by POEL under the Asset Acquisition Agreement

is US$415 million. Similar adjustments will be made to this consideration to account for certain


The Share Acquisition Agreement and the Asset Acquisition Agreement are both conditional upon: (i)Admission; and (ii) the approval by Shareholders of the Acquisition at the EGM.

The Acquisition Agreements contain a break fee in an amount of US$5.05 million, being 1% of the

Settlement Amount, in favour of ONSL. The break fee is payable by POGL or POEL (as the case

may be) only if (i) the Resolutions are not passed by Shareholders at the EGM; or (ii) Admission

does not take place by 14 June 2009.

Under the terms of the Acquisition Agreements, if ONSL’s interest in one or more of the Balmoral

field interest, the Brenda field interest, the Nicol field interest or the Huntingdon field interest is

forfeited, revoked or terminated, or notice of forfeiture, revocation or termination is given before

28


Completion, POGL and/or POEL may terminate the Share Acquisition Agreement or the Asset

Acquisition Agreement (as applicable) at its discretion.

The Company has agreed to guarantee the obligations of POGL and POEL under the Acquisition.

8. Summary of the Rights Issue

General

Under the terms of the Rights Issue, the New Ordinary Shares are being offered, by way of rights, to

Qualifying Shareholders (other than, subject to certain exemptions, Excluded Overseas Shareholders)

at 485 pence per New Ordinary Share, payable in full on acceptance by not later than 11.00 a.m. on

6 May 2009. Since outstanding options under the Premier Share Option Schemes may be exercised(and Convertible Bonds may be converted) before the Record Date for the Rights Issue, the precise

number of shares to be issued in the Rights Issue cannot be determined until that date. Assuming no

options or Convertible Bonds are exercised or converted between Announcement and the Record

Date, 35,276,566 New Ordinary Shares will be issued, raising approximately £145 million (net of

expenses). However, if all outstanding options and Convertible Bonds are exercised or converted, up

to 8,111,100 additional New Ordinary Shares will be available for issue (although not underwritten).

The Rights Issue Price of 485 pence per New Ordinary Share represents a discount of approximately

49% to the Closing Price.

The Rights Issue is being made on the following basis:

4 New Ordinary Shares for every 9 Existing Ordinary Shares

held by Qualifying Shareholders on the Record Date and so in proportion to any other number of

Existing Ordinary Shares then held, and otherwise on the terms and conditions as set out in this

document and, in the case of Qualifying non-CREST Shareholders (other than, subject to certain

exemptions, Excluded Overseas Shareholders) only, the Provisional Allotment Letter. New Ordinary

Shares representing fractional entitlements will not be allotted to Qualifying Shareholders and, where

necessary, entitlements to New Ordinary Shares will be rounded down to the nearest whole number.

New Ordinary Shares representing fractional entitlements will not be allotted to QualifyingShareholders but will be aggregated and, if possible, sold in the market. The net proceeds of such

sales (after deduction of expenses) will be aggregated and will ultimately accrue for the benefit of the

Company. Holdings of Ordinary Shares in certificated and uncertificated form will be treated as

separate holdings for the purpose of calculating entitlements under the Rights Issue.

The New Ordinary Shares will, when issued and fully paid, rank pari passu in all respects with

Existing Ordinary Shares, including the right to all future dividends or other distributions made, paid

or declared after the date of issue. Details of the rights attaching to Ordinary Shares appear in the

Articles of Association, a description of which appears in paragraph 9 of Part XVI of this document.

The Rights Issue is conditional upon:

(a) both the Acquisition Agreements not having been terminated, and the Acquisition not ceasing to

be capable of Completion in accordance with the terms of the Acquisition Agreements prior to

Admission;

(b) the Resolutions being passed at the Extraordinary General Meeting;


and/or date as Premier and the Underwriters may agree (being not later than 8.00 a.m. on6 May 2009)); and

(d) the Underwriting Agreement having become unconditional in all respects (save for conditions

relating to Admission) and not having been terminated in accordance with its terms prior to

Admission.

Application has been made to the UK Listing Authority for the New Ordinary Shares to be admitted

to the Official List and to the London Stock Exchange for the New Ordinary Shares to be admitted

to trading on its main market for listed securities. It is expected that Admission will become effective

and that dealings in the New Ordinary Shares will commence on the London Stock Exchange, nilpaid, at 8.00 a.m. on 21 April 2009.

The latest time and date for acceptance and payment in full of the New Ordinary Shares will be

11.00 a.m. on 6 May 2009.

Based on the Closing Price of 952 pence per share and the proposed Rights Issue Price of 485 pence

for each New Ordinary Share, the theoretical ex-rights price of an Ordinary Share is 808 pence.

29


The terms and conditions of the Rights Issue, including the procedure for acceptance and payment

and the procedure in respect of rights not taken up, are set out in Part VIII of this document.

9. Use of proceeds of the Rights Issue

The net proceeds of the Rights Issue will be approximately £145 million (assuming no options under

the Premier Share Option Schemes are exercised and no Convertible Bonds are converted between

Announcement and the Record Date) which will be used to fund part of the consideration for theAcquisition. The remainder of the funding of the Acquisition will be met from the Enlarged Group’s

cash resources and the New Credit Facilities.

The Rights Issue, which is deeply discounted, has been fully underwritten by the Underwriters to

address Premier’s desire for certainty of funds. The deeply discounted nature of the Rights Issue

reflects recent equity market volatility and has allowed the Company to increase the certainty of the

fundraising by arranging underwriting in respect of the full amount of the issue. The level of thediscount was determined by the Company in discussion with the Underwriters. The Rights Issue is

not conditional on Completion.

In the unlikely event that the Rights Issue proceeds but Completion does not take place, the

Directors’ current intention is that the net proceeds of the Rights Issue will be invested in cash or

money-market funds on a short-term basis while the Directors consider how best to return theproceeds of the Rights Issue (after the deduction of acquisition and transaction costs) to

Shareholders. Any such return of capital may have tax implications for Shareholders. However if,

before Admission, the Acquisition Agreements have both terminated or the Acquisition ceases to be

capable of Completion, the Rights Issue will not proceed.

Qualifying non-CREST Shareholders

Subject to the passing of the Resolutions, Qualifying non-CREST Shareholders (other than, subject to

certain exemptions, Excluded Overseas Shareholders) will be sent a Provisional Allotment Letter on

20 April 2009 which will indicate the number of New Ordinary Shares provisionally allotted to such

Qualifying non-CREST Shareholders pursuant to the Rights Issue.

Qualifying non-CREST Shareholders should retain this document for reference pending receipt of a

Provisional Allotment Letter. Qualifying non-CREST Shareholders should note that, other than the

Provisional Allotment Letter, they will receive no further written communication from the Company

in respect of the subject matter of this document.

Qualifying CREST Shareholders

Subject to the passing of the Resolutions, Qualifying CREST Shareholders (other than, subject to

certain exemptions, Excluded Overseas Shareholders) (none of whom will receive a Provisional

Allotment Letter) are expected to receive a credit to their appropriate stock accounts in CREST in

respect of the Nil Paid Rights to which they are entitled on 21 April 2009. The Nil Paid Rights so

credited are expected to be enabled for settlement by CREST as soon as practicable after Admission.

Qualifying CREST Shareholders should note that they will receive no further written communication

from the Company in respect of the subject matter of this document. They should accordingly retain

this document for, amongst other things, details of the action they should take in respect of the

Rights Issue. Qualifying CREST Shareholders who are CREST sponsored members should refer to

their CREST sponsors regarding the action to be taken in connection with this document and the

Rights Issue.

Overseas SharehoIders

Shareholders resident in any jurisdiction other than the United Kingdom should refer to paragraphs 7

and 8 of Part VIII of this document for further information.

Settlement

The New Ordinary Shares will be capable of being held in certificated or uncertificated form. Pending

the issue of definitive certificates for the New Ordinary Shares, transfers will be certified against the

register. No temporary documents of title in respect of the New Ordinary Shares will be issued.

Any New Ordinary Shares to be issued in certificated form will be represented by definitive share

certificates, which are expected to be despatched by 14 May 2009 to the persons entitled thereto at

that person’s registered address (provided that such registered address is not in the United States or

any other jurisdiction outside the United Kingdom).

30


The attention of Qualifying Shareholders with Ordinary Shares in uncertificated form or who wish to

receive their New Ordinary Shares in uncertificated form is drawn to paragraph 5 of Part VIII of this

document.

10. Current trading and prospects of Premier and ONSL

(a) Premier

Despite volatile markets and the sharp downturn in economic activity, the Directors consider that the

Group is in a strong position to maintain its growth profile. Already in 2009, the Group has


Premier is about to embark on an extensive exploration and appraisal campaign, which has thepotential to have a material impact on the Group.

The quality of the Group’s producing assets, underpinned by its financial position, secures its forward

cash flows and allows it to progress its exploration and development programmes that could bringvery significant upside.

(b) ONSL

Since being placed into administration on 7 January 2009, ONSL’s Administrators have continued to

operate the business on a going concern basis. Whilst new capital investment has been restricted post

appointment of the Administrators, the fields on producing licence interests have continued to

produce hydrocarbons, and (with the exception of a short planned shutdown on the Balmoral, Brenda

and Nicol fields) production and operations have continued. Working interest production for theperiod from 7 January 2009 (when ONSL was placed into administration) to 23 March 2009 (the

latest practicable date prior to the Announcement), averaged 12,200 boepd. In 2009, the Directors

intend to bring online a second producing well on the Nicol field and add a further producing well to

the Brenda field. The Directors believe that there are strong prospects for ONSL’s assets under

Premier’s ownership.

11. New Director

The Company is also pleased to confirm that Andrew Lodge will join the Board on 20 April 2009 as

Exploration Director. Andrew has 30 years’ professional experience in the oil and gas industry and

was, until 31 March 2009, Vice President, Exploration for Hess, responsible for Europe, North

Africa, Asia and Australia. Before he joined Hess in 2000, he was previously Vice President,

Exploration, Asset Manager and Group Exploration Advisor for BHP Petroleum, based in London

and Australia. Prior to joining BHP Petroleum, Andrew worked for BP as a geophysicist principally

in South East Asia, Europe and North Africa.

Andrew has an honours degree in Mining Geology from the University of Wales and a Masters in

Applied Geophysics from the University of Leeds. He is a fellow of the Geological Society.

12. Extraordinary General Meeting

A notice convening the Extraordinary General Meeting to be held at 10.00 a.m. on 20 April 2009 at

the offices of Deutsche Bank, Winchester House, 1 Great Winchester Street, London EC2N 2DB is

set out at the end of this document. The purpose of the Extraordinary General Meeting is to seek

Shareholder approval of the Resolutions in connection with the Acquisition and the Rights Issue.

Resolution 1 is not conditional upon the other Resolutions, but the Acquisition would not proceed

unless the Rights Issue is completed. Resolutions 2 and 3 are expressly conditional upon the passing

of Resolution 1. A summary of the Resolutions is set out below:

Resolution 1 – to approve the Acquisition and to authorise the Directors to make any non-material

amendment, variation, waiver or extension to the terms or conditions of the Acquisition and to do all

such other things as they may consider necessary, desirable or expedient in connection with theAcquisition.

Resolution 2 – subject to the approval of Resolution 1 above and conditional upon the Underwriting

Agreement having become unconditional in all respects, save for any condition relating to Admissionhaving occurred, to authorise the Directors to allot 73,492,846 Ordinary Shares, representing

approximately 92.6% of Premier’s current issued share capital (excluding treasury shares) as at 1 April

2009, the last practicable date before the publication of this document. This will enable Premier to

allot sufficient Ordinary Shares to satisfy its obligations in connection with the Rights Issue, and also

leave it with headroom equal to up to one third of the expected issued share capital following the

31


Rights Issue. This authority will expire at the conclusion of the next annual general meeting of the

Company or, if earlier, 30 September, 2009.

Resolution 3 – subject to the approval of Resolution 1 and Resolution 2 above, to authorise the

Directors to allot Ordinary Shares for cash pursuant to the authority conferred by Resolution 2

above as if section 89(1) of the Companies Act 1985 (which, to the extent not disapplied, confers on

Shareholders rights of pre-emption in respect of the allotment of Ordinary Shares which are, or are

to be, paid up in cash) did not apply to any such allotment. The disapplication will cover a

maximum of 73,492,846 Ordinary Shares if issued by way of rights issue or similar, and the amountgenerally disapplied will cover 5,732,442 Ordinary Shares and will represent approximately 7.2% of

Premier’s total issued share capital as at 1 April 2009, the last practicable date before the publication

of this document, or 5% of the expected issued share capital after the Rights Issue. This authority

will expire at the conclusion of the next annual general meeting of the Company or, if earlier, 30

September 2009.

The full text of the Resolutions are set out in the notice convening the Extraordinary General Meeting

at the end of this document.

13. Action to be taken

(a) The Extraordinary General Meeting

You will find enclosed with this document the Form of Proxy for use at the Extraordinary GeneralMeeting or at any adjournment thereof. You are requested to complete and sign the Form of Proxy

in accordance with the instructions printed on it and return it as soon as possible to, but in any

event so as to be received no later than 10.00 a.m. on 18 April 2009 by the Registrar, Capita

Registrars, at Capita Registrars (Proxies), PO Box 25, Beckenham, Kent BR3 4BR. You may also

deliver the Form of Proxy by hand to Capita Registrars, The Registry, 34 Beckenham Road,

Beckenham, Kent BR3 4TU during usual business hours. CREST members may also choose to use

the CREST electronic proxy appointment service in accordance with the procedures set out in the

notice convening the Extraordinary General Meeting at the end of this document. The lodging of theForm of Proxy (or the electronic appointment of a proxy) will not preclude you from attending and

voting at the meeting in person if you so wish.

(b) Rights Issue

On the basis that dealings commence on 21 April 2009, the latest time for acceptance by Shareholders

under the Rights Issue will be 11.00 a.m. on 6 May 2009. The procedure for acceptance and payment

is set out in Part VIII of this document. Further details will also appear in the Provisional Allotment

Letter which, if all the Resolutions are passed at the Extraordinary General Meeting, will be sent toall Qualifying Non-CREST Shareholders (other than, subject to certain exemptions, Excluded

Overseas Shareholders).

If you are in any doubt what action you should take, you should immediately seek your own

financial advice from your stockbroker, bank manager, solicitor or other independent professional

adviser duly authorised under FSMA who specialises in advice on the acquisition of shares and othersecurities. The Board’s recommendation for the action you should take is set out in paragraph 16

below.

14. Further information and risk factors

Your attention is drawn to the further information set out in Parts II to XVIII (inclusive) of this

document and, in particular, to the risk factors on pages 9 to 17 of this document.

15. Financial advice

The Board has received financial advice from Deutsche Bank in relation to the Acquisition. In

providing its financial advice to the Board, Deutsche Bank has taken into account the Board’s

assessment of the commercial merits of the Acquisition.

16. Recommendation and voting intentions

The Board considers that the Rights Issue and Acquisition, and each of the Resolutions, are in the best

interests of the Company and its Shareholders as a whole. Accordingly, the Board recommends

Shareholders to vote in favour of each of the Resolutions, as the Directors intend to do in respect of

their own beneficial shareholdings held at the time of the Extraordinary General Meeting, amounting to

32


133,600 Ordinary Shares in aggregate as at the date of this document (representing approximately

0.17% of Premier’s existing issued share capital).

17. Directors’ intentions in relation to the Rights Issue

Each of the Directors intends to take up in full his rights to acquire New Ordinary Shares under the

Rights Issue in respect of his own beneficial shareholdings held at the time of the Extraordinary

General Meeting.

Yours faithfully,

Sir David John KCMG

Chairman

3 April 2009

33


PART II

INFORMATION ON PREMIER

1. Company information

Premier Oil plc was incorporated and registered with the name of Dalglen (No. 836) Limited in

Scotland on 31 July 2002 with registration number SC234781. The name of the company was

changed from Dalglen (No. 836) Limited to Premier Oil Group Limited pursuant to a written

resolution passed on 13 September 2002. The company was re-registered as a public limited companyon 10 March 2003. The name of the company was changed from Premier Oil Group plc to Premier

Oil plc pursuant to a special resolution passed on 3 March 2003 and which became effective on 15

July 2003.

The principal legislation under which Premier operates is the Companies Act 1985, the Companies

Act 2006 and regulations made thereunder.

The registered office of Premier is 4th Floor, Saltire Court, 20 Castle Terrace, Edinburgh EH1 2EN.

Premier’s head office is 23 Lower Belgrave Street, London SW1W 0NR.

Premier Oil plc acquired Premier Oil Group Limited as part of a restructuring in 2003. Premier Oil

Group Limited was originally incorporated and registered in Scotland on 10 April 1934.

2. History and development

The Group was founded 75 years ago in Scotland to pursue oil and gas exploration and production

activities in Trinidad. In 1936, the Group’s holding company was publicly listed in London asPremier (Trinidad) Oilfields Limited, and for the next two decades the Group focussed on oil

production in Trinidad.

The Group acquired its first interest in the North Sea in 1971 and expanded its presence on the

UKCS when it merged with the Ball and Collins North Sea Consortium in 1977 to gain significant

interests in the North Sea as well as properties in Sudan and West Africa.

In 1984, the Group purchased a 12.5% interest in the onshore oilfield at Wytch Farm in Dorset. This

acquisition had a significant impact on the Group’s reserve base and cash flow and continues today

to make an important contribution to the Group’s revenues.

In the late 1980s and early 1990s, the Group enjoyed a series of exploration successes, notably the

discovery of the Qadirpur gas field in Pakistan in 1990, the Angus and Fife fields in the UKCS in

1983 and 1991 respectively and the Yetagun gas field in Myanmar in 1992.

In 1995, the Group acquired Pict Petroleum plc (‘‘Pict’’). Hess, which already had a substantial

interest in Pict, became a 25% shareholder of the Group. As a result, the Group participated in

numerous further North Sea oil and gas fields, including the Fife, Fergus, Galahad and Scott fields.

Supported by production revenue from the UKCS, the Group turned its attention to the Far East

with a view to developing energy resources to serve the region’s rapidly expanding economies. In

1996, the Group acquired Sumatra Gulf Oil which gave it a majority interest in the Natuna Sea

Block A offshore Indonesia, comprising the Anoa oil field and substantial gas reserves, as well as

exploration prospects. The Group also acquired Discovery Petroleum NL of Australia, thereby

obtaining an interest in the Kakap licence, also in the Natuna Sea, which added oil and gas reservesand provided access to further prospective exploration acreage.

The Group was the original licencee of concessions M13 and M14 in Myanmar, when they were

awarded in 1990. Shortly afterwards, the Group farmed out its interests to a subsidiary of Texaco,

which became the operator, and a subsidiary of Nippon Oil Corporation, whilst retaining a 30%

interest. The Yetagun Field was discovered in 1992 and development began in 1996. In late 1997,

Texaco sold its entire interest of 30% and transferred the role of operator to the Group. At the same

time the Group sold a 30% interest to Petronas. Construction of the pipeline and facilities for this

field took place during 1998 and 1999. The field started production in May 2000.

In 1998, the Group and Shell brought together their exploration and production interests in Pakistanto form a joint venture company, Premier & Shell Pakistan B.V. (‘‘PSP’’). In May 2001, the Group

announced an asset swap with Shell which dismantled the partnership and, in September 2001, a new

joint venture company was formed with Kufpec to hold the interests in Pakistan, Premier-Kufpec

Pakistan B.V. (‘‘PKP’’). This joint venture was unwound in 2007 with each of the co-venturers now

owning its share of the assets directly.

34


To consolidate its position as a leading independent production company in the south-east Asian

energy markets, the Group formed a strategic alliance with Petronas and Hess in 1999. As part of the

strategic alliance, each of Petronas and Hess owned a 25% equity interest in the Group. In September

2002, the Group agreed to transfer its entire Myanmar business to Petronas and part of theIndonesian West Natuna asset to subsidiaries of Petronas and Hess. In consideration for these

transfers, Petronas and Hess cancelled their combined 50% shareholding in the Group and

contributed US$376.0 million in cash and debt repayment.

As part of the reorganisation, in 2003, Premier acquired POGL and as a result became the holding

company of the Group.

In 2005, the Group reorganised into four regional units: Asia, Middle East & Pakistan, North Sea

and West Africa. This reorganisation took into account successful entry into a number of new

countries including Vietnam, Norway, Mauritania and the Congo. The Group’s activities in West

Africa now focus on Mauritania and the Congo, and the West Africa regional unit was combined

with the North Sea business unit in 2008. In 2008, the Group also set up a joint venture with EIIC

to build a presence in the Middle East and North Africa regions.

3. Organisational structure

Premier has two principal wholly-owned subsidiaries: POGL – through which it holds all of its

project interests (except the interest in the Kyle field which it holds directly) – and POFJL. POFJL is

a Jersey registered company incorporated for the purpose of issuing Convertible Bonds and to be a

party to various financial arrangements supporting the Convertible Bonds. Further information on the

Convertible Bonds is set out in paragraph 12(a) of Part XVI of this document. POGL is a Scottish

registered company and has three principal wholly-owned subsidiaries – POHL, PPPL and POOBV.

POHL, a company registered in England and Wales, is also the parent company of several specially

formed entities which hold the Group’s interest in PSC A and PSC B in Mauritania, including the

Group’s interest in the Chinguetti field.

PPPL, a Scottish registered company, and its wholly-owned subsidiaries hold all of the Group’s UK

producing assets.

POOBV, a Dutch registered company, holds the Group’s wholly-owned subsidiaries, Premier Oil

Kakap B.V. and Premier Oil Natuna Sea B.V., which hold the Group’s interests in Kakap, Indonesia

and the Natuna Sea Block A, respectively. In addition, POOBV holds the Group’s 49% shareholdingin Premco Energy Projects Company LLC, and 50% shareholding in Premco Energy Projects B.V.

These companies were incorporated pursuant to the joint venture arrangements established in January

2008 between POOBV and EIIC, the aim of which is to make acquisitions in a defined area of

mutual interest.

4. Business overview

4.1 Introduction

The Group has current interests in 11 countries around the world. It has significant operations in the

North Sea (UK and Norway), Asia and the Middle East with a reserve and resource base of 382

mmboe, which is currently producing around 36,500 boepd (as of the year ended 31 December 2008).

Premier is targeting growing production to above 50,000 boepd in the medium-term.

Premier is listed on the London Stock Exchange (Bloomberg ticker: PMO LN). As at 1 April 2009

(the latest practicable date prior to the publication of this document), Premier had a market

capitalisation of approximately £868 million. In the financial year ended 31 December 2008, Premier

achieved revenues of US$655.2 million and operating profit of US$261.7 million.

A breakdown of total revenues by category of activity and geographic market for the years ended

31 December 2006, 31 December 2007 and 31 December 2008 is given in the statutory accounts for

Premier for those years which is incorporated into this document by reference, as explained in

Part XVII of this document.

35


4.2 Strategy

There are three main elements to Premier’s strategy:

(1) Production growth to 50,000 boepd and beyond.

Premier is targeting production growth from existing discovered reserves which are fully

appraised. Three projects (Gajah Baru and North Sumatra Block A in Indonesia, and Chim

Sao/Dua in Vietnam) are expected onstream in 2010/2011, driving production to meet this

target. The fourth project, Frøy (Norway), is still under evaluation, and could add a further

14,000 boepd to Premier’s production profile once onstream.

(2) Exploration within disciplined spend.

Premier is about to embark on an extensive exploration and appraisal campaign, which has the

potential to have a material impact on the Group. Premier has set itself, and has generally

maintained, a disciplined spending target each year on exploration activities.

(3) Acquisitions focussed on core areas.

Premier targets acquisitions in existing core areas. These are areas in which Premier has the

relationships and geological experience to assess and add value to completed acquisitions.

Examples of previous acquisitions include the Scott field in the United Kingdom and North

Sumatra Block A in Indonesia.

4.3 Asset Portfolio and organisation

The Group is organised into three regional units: Asia, Middle East & Pakistan, North Sea/West

Africa. Regional teams are appointed for Asia, Middle East & Pakistan and North Sea/West Africa

(one team).

Key Company locations are as follows:

Location Presence

London Corporate head office

Jakarta (Indonesia) Indonesia operationsHo Chi Minh City (Vietnam) Vietnam operations

Singapore Asia regional/Business development

Islamabad (Pakistan) Pakistan operations

Abu Dhabi (United Arab Emirates) Business development

Stavanger (Norway) North Sea/West Africa operations

4.4 Key strengths and competitve advantages

Long-life production profile

Premier’s current producing portfolio generates between 35 and 40 kboepd (2008: 36.5 kboepd) from

a spread of world class assets. Premier has a strong reserve base with over 228 mmboe (as of the

financial year ended 31 December 2008) of 2P reserves and at current production rates implies a

reserve life of 17 years. As a result of the quality of Premier’s assets, Premier’s fields generate

significant cash flow even at lower oil and gas prices.

Good quality long-term gas contracts

Substantially all of the Group’s gas production is sold under profitable long-term contracts to

Singapore and Pakistan government-backed customers. Revenues are denominated in US Dollars and

funds are remitted directly to London bank accounts.

Substantial reserve backing, conservatively booked

The Group’s production and development portfolio is supported by booked 2P reserves of 228

mmboe and contingent resources (not yet booked) of 154 mmboe (as of the financial year ended

31 December 2008).

Significant growth profile

Premier’s current level of production is expected to increase to over 50,000 boepd over the next three

years as a result of projects currently under development. These projects are robust at low oil and gas

prices.

36


Balance sheet strength

The Group has a strong current balance sheet with cash balances of around US$323.7 million and

undrawn bank facilities of US$275 million as at 31 December 2008. Premier has obtained the NewCredit Facilities comprising a US$175 million 18-month acquisition bridge facility, a US$225 million

3-year revolving credit facility and US$63 million and £60 million 3-year letter of credit facilities. The

New Credit Facilities are described in paragraph 12(f) of Part XVI of this document.

Combined with current cash flows, this effectively pre-finances the Group’s planned investment

programme. The Group is committed to maintaining a disciplined exploration spending target each

year and where necessary will seek farm-in partners for drilling programmes to maintain this

discipline.

Downside protection through hedging

In advance of the current investment programme, the Group put in place a portfolio of financialhedges which protect revenues and cash flow. Volumes from expected world-wide oil production

equivalent to Premier’s ‘‘after-tax’’ barrels have an average floor protection of around US$40/bbl for

2009 and 2012 and of US$50/bbl for 2010 and 2011. 35% of Indonesian gas production is hedged

with a floor equivalent to US$40/bbl from 2009 to June 2013. Pakistani production is largely

insensitive to oil prices and is therefore un-hedged.

Experienced management team with deep oil and gas industry knowledge

Premier’s senior management team has a wide range of experience throughout the industry and acrossthe business. Simon Lockett, Chief Executive, joined Premier in 1994 and worked in a variety of roles

within Premier before becoming Chief Executive in 2005. Tony Durrant, Finance Director, joined

Premier in 2005 having been Head of the European Natural Resources Group of Lehman Brothers

since 1997. Operationally, Neil Hawkings and Robin Allan both have significant experience having

spent more than 20 years each working within the industry (with ConocoPhillips and Premier

respectively).

5. Premier licence interests

Premier’s business is dependent on the holding of licences and approvals from government authorities,

which entitle the Group, inter alia, to extract oil and gas. Details of the Group’s key licences are set

out below.

Licence Block Operator

Equity

% Field

Congo-

Brazzaville

Marine IX Marine IX Premier 31.50

Egypt NW Gemsa Vegas Oil & Gas 10.00

NW Gemsa Vegas Oil & Gas 10.00 Al Amir SE

Indonesia Buton Japex 30.00Kakap Star Energy 18.75 Kakap

Natuna Sea Block A Premier 28.67 Anoa

North Sumatra Block A Medco 41.67

Tuna Premier 65.00

Mauritania PSC A Deep Water 3 and

Shallow Water Blocks

4 & 5

Petronas 4.62

PSC B Block 4 & 5 Petronas 9.23

PSC B Chinguetti Petronas 8.12 Chinguetti

37


Licence Block Operator

Equity

% Field

Norway PL359 16/1 (part), 16/4 Lundin 30.00

PL364 25/2, 25/3, 25/5, 25/6 Det Norske 50.00

PL374s 34/2, 34/5 BG 15.00

PL378 35/12, 36/10 Wintershall 40.00

PL406 17/12, 18/10, 18/11,

8/3 & 9/1

Premier 40.00

PL407 17/8, 9, 11, 12 & 18/7,10

BG 20.00

PL417 31/3, 32/1, 36/10 Wintershall 40.00

PL418 35/8 Nexen 15.00

PL496 7/7, 7/10 Premier 70.00

Pakistan Production Leases Bolan MGCL 3.75 Zarghun

South

Dadu BHP 9.37 Zamzama

Kirthar ENI 6.00 BadhraKirthar ENI 6.00 Bhit

Qadirpur OGDCL 4.75 Qadirpur

Tajjal ENI 15.79 Kadanwari

Philippines Ragay Gulf SC 43 SC43 Pearl Energy 21.00

United

Kingdom

P218 15/21a Nexen 45.83 Scott{

P218 15/21a Nexen 3.75 Telford{{

P257 14/25a Talisman 1.52

P288 31/21a, 31/26a, 31/26f,

31/26g, 31/27a

Hess 15.00 Angus, Fife,

Flora

P354 22/2a Premier 30.00 Non-Chestnut

Field Area

P534 98/6a, 98/7a BP 12.50 Wytch Farm

(Offshore){{{

P748 29/2c CNR 40.00 KyleP758 31/26c Hess 35.00

P802 39/1a Hess 15.00 Fife

P802 39/2a Hess 35.00 Fergus

P1022 98/11 BP 12.38

PL089 L97/10 BP 12.50 Wytch Farm/

Wareham{{{

P1181 23/22b (paleocene) Premier 25.00

P1181 23/22b (sub-paleocene)

Premier 25.00

P1466 15/24c, 15/25f Premier 25.00

Vietnam 12W Premier 37.50

07/03 Premier 45.00

104-109/05 Premier 50.00

Notes:{ Unitised share of 21.83%{{ Unitised share of 0.82%{{{ Unitised share of 12.38%

38


6. Premier operations

6.1 ASIA BUSINESS UNIT

The Asia Business Unit aims to leverage off the Group’s position in the Natuna Sea, where it

operates the Anoa gas field delivering gas into Singapore for power generation. The Group recently

extended its position in the Natuna Sea by drilling its first wells in neighbouring Vietnam, resulting in

the Dua oil and gas field and Chim Sao (formerly known as Blackbird) oil field discoveries which are

now being developed for first production in 2010/11.

In 2007, 2P reserves in Asia reached 124.3 mmboe (92% gas) which represented 59% of Premier’s

total 2P reserves. With 11,700 boepd produced in the region in 2008, Asia accounted for 32% of

Premier’s global production.

Asia Operations

6.1.1 Indonesia

Indonesia represents 57% of Premier’s 2P reserves and 32% of Premier’s 2008 production.

Natuna Sea Block A – producing asset and development project, 28.67% operated interest

The present Natuna Sea Block A licence was obtained by Sumatra Gulf Oil in 1979. Oil production

from the Anoa field began in November 1990 from nine platform wells located in the East Lobe.

Following the Group’s acquisition of Sumatra Gulf Oil in 1996, additional development was

undertaken with the installation of the processing and compression AGX platform and the WestNatuna Transporation System (‘‘WNTS’’) pipeline for gas export to Singapore.

Gas is being produced from the Anoa gas field and from fields in the Kakap PSC in which Premier

also has an interest (see below). The two PSCs are located adjacent to each other some 500

kilometres north east of Singapore in the West Natuna Sea. Gas from the fields is exported bypipeline to Singapore through the 650 kilometres WNTS and supplies one-third of Singapore’s energy

needs.

Deliveries under a US$ gas contract with SembCorp, a government controlled Singaporean utility,commenced in January 2001 and are expected to continue under a life of field contract until 2029.

SembCorp sells the gas to various end users including SUT Co-Gen, Tuas Power and Exxon

Chemicals.

In April 2008 the Group signed three fully termed GSAs with SembCorp for gas sales into theSingapore market, and with PLN and UBE for gas sales to be used in power generation in Batam,

for a total volume of 125 BBtud with options for a further 13 BBtud. Agreements with PLN and

UBE are ‘‘life of field’’ contracts and are expected to start in 2011 when the Gajah Baru field starts

producing.

Gas pricing is directly related to HSFO which moves broadly in line with international crude prices.

In 2006, the West Lobe of Anoa was developed with a wellhead platform to sustain gas deliverability.

The Anoa field comprises several stacked reservoirs and to date it is the only field that has been

developed in Block A. Additional development at the Anoa gas reservoir and development of the

39


Gajah Baru field is now underway. Development of Gajah Puteri, Pelikan, and other fields will

maintain gas deliverability in the future.

Total 2P reserves (gross) for the block are estimated at 303 mmboe, 86.9 mmboe net to Premier. 2008

production was 8,400 boepd. Partners in Natuna Sea Block A are Kufpec (33.33%), Hess (23%) and

Petronas (15%).

Kakap field – producing asset, 18.75% non-operated interest

The Kakap field was discovered by a subsidiary of Marathon Oil in 1978, with well KG-1X, and first

production commenced in March 1986. Kakap consists of 10 separate fields, which are developed

with a combination of platforms and sub-sea tie-backs to the Kakap FPSO, where the oil is stabilised

and exported via tankers. Further incremental developments are proceeding.

Premier acquired its interest in December 1996 through the acquisition of Discovery Petroleum NL.

Gas production started in 2001. In 2003, a subsidiary of Star Energy acquired an interest in the

Kakap licence and now operates the field. Gas production from the Kakap field is sold under the gas

sales contracts to Singapore (SembCorp) as described above.

Total 2P reserves (gross) are estimated at 45 mmboe, 8.4 mmboe net to Premier. Net 2008 production

was 3,300 boepd. Partners in the Kakap field are Star Energy (operator, 31.25%), Medco (16%), SPC

(15%), Pertamina (10%) and Santos (9%).

North Sumatra Block A – development asset, 41.67% non-operated interest

North Sumatra Block A

The Group acquired a 16.7% equity share of North Sumatra PSC Block A, onshore Indonesia in

April 2006 from a subsidiary of ExxonMobil. This equity interest was increased to 41.67% in January

2007 through the purchase of additional equity in the block from a subsidiary of ConocoPhillips. The

block contains three undeveloped discoveries (Alur Siwah, Alur Rambong, and Julu Rayeu). In

December 2007, the operators of North Sumatra Block A, Medco and PIM, signed a GSPA which

governs the sale of gas from the Alur Siwah, Alur Rambong and Julu Rayeu fields in North Sumatra

Block A to the PIM fertilizer plants on the northern Aceh coast (pictured above).

Gas will be delivered at a plateau rate of 110 BBtud starting in the fourth quarter of 2010. Medco

and PIM have agreed a fixed floor price of US$6.50 per MMBtu for gas with an additional upside

profit share element which is related to urea prices. The contract allows for minimum sales of 223TBtu with ultimate sales expected of over 400 TBtu.

Gas will be delivered through a new 20 kilometre pipeline to a delivery point at an existing pipelinewhich will transport the gas to the PIM plant, approximately 70 kilometres away. Development

activities are on-going with a view to delivering first gas in the fourth quarter of 2010 from the Alur

Rambong field and mid-2011 from the Alur Siwah field. Medco and its partners have secured

approval from Indonesian regulator, BPMIGAS, for the Block A Plan of Development and an

extension of the Block A PSC to 2031 is expected to be finalised shortly.

40


Total 2P reserves (gross) are estimated at 87.2 mmboe, 36.3 mmboe net to Premier. Partners in the

field are Medco (operator, 41.67%) and Japex (16.67%).

Premier has recently been informed by the operator of the Kakap PSC that the certificate of

classification for the FPSO vessel has been cancelled, which has adverse implications for the operation

(and insurance) of such vessel. Swift remedial action will be necessary to regain the classification and

Premier, together with the operator, Star Energy and the other joint venture partners, is currentlyconsidering the possible options. However, the Directors do not believe that the consequences for the

business of the Group will be material, under any of the possible courses of action.

Tuna Block – exploration, 65% operated interest

In March 2007, the Group was awarded a 65% operated interest in the Natuna ‘‘Tuna’’ offshore

block. The block is located adjacent and immediately to the south of Block 07/03. The Group is

planning to spud up to two wells on the block during 2010. The partner in Tuna is MOECO with a35% interest.

Buton Block – exploration, 30% non-operated interest

In December 2006, the Group was awarded a 30% non-operated interest of an onshore exploration

licence on Buton Island, Sulawesi, by the Indonesian government.

The block lies on the south-eastern side of Buton island. Oil seeps are prolific on the island and large

volumes of oil have been generated as evidenced by the commercial asphalt mining operations that

have been ongoing for many years.

The committed work programme includes 265 kilometres of 2D seismic designed to confirm at depth

the structures mapped at surface, and one exploration well. Five leads have been identified on the

block so far.

The partners in Buton are Japex (operator, 40%) and Kufpec (30%).

6.1.2 Vietnam

Since commencing operations in Vietnam in 2004, Premier has undertaken a successful exploration

programme leading to the discovery of the Chim Sao and Dua Fields in Block 12W. Premier is

planning the development of these oil discoveries and further exploration investment in Block 12W,

the nearby Block 07/03 and Block 104-109/05 offshore northern Vietnam. Vietnam represents 7% of

Premier’s 2P reserves (based on a 31.875% net interest for Chim Sao).

Block 12W – development asset, 37.5% operated interest (31.875% post back-in)

The Group acquired a 75% interest in Block 12E/12W located in the Nam Con Son Basin fromDelek Energy Systems Ltd in 2004, and subsequently farmed-out its interest leaving the Group with a

37.5% operated interest.

The area has similar geology to the West Natuna Sea area, approximately 300 kilometres to the

southwest (see ‘‘Indonesia – Natuna Sea Block A’’ on page 39 above). The Group announced a

discovery at Dua in June 2006 and at Chim Sao in September 2006. Chim Sao was successfully

appraised in 2008 with a further well in the Northern fault block.

The blocks were merged in 2006, and renamed Block 12W. A field development plan has been

submitted to the Vietnamese government and has been approved. First oil production from Chim Sao

is currently targeted for 2010, with first production from Dua anticipated for 2011.

Block 12W was booked into Premier’s 2P reserves at end 2008 at 16.9 mmboe (based on a 31.875%

net interest).

Several tie-back possibilities of field extensions and adjacent exploration prospects are being evaluated.

Partners in Block 12W are Santos (37.5%) and Delek Energy Ltd. (25%). Petrovietnam has the right

to back-in for a gross 55% interest in the PSC reducing Premier’s interest to 31.875%.

41


Chim Sao/Dua (Block 12W)

Block 07/03 – exploration, 45% operated interest

The Group exercised its option to acquire a 45% equity interest in Block 7 and 8/97 from VAMEX

in December 2006. Block 07/03 is located in the Nam Con Son Basin, immediately to the south east

of Block 12W. The Group has already worked with VAMEX to acquire, process and interpret a

comprehensive grid of two dimensional marine seismic data across for Block 07/03 and the results

suggest the existence of the same elements which have created petroleum prospectivity in Block 12W.

The seismic interpretation has identified numerous large structures which appear to be suitable for

high-impact well locations. The Group is planning to spud up to two wells on Block 07/03 during2009. Partners in Block 07/03 are VAMEX (40%) and Pearl Energy (15%).

Block 104-109/05 – exploration, 50% operated interest

Premier was awarded a 50% operating interest in Block 104-109/05 on the western flank of the Song

Hong Basin offshore of Northern Vietnam in February 2008.

A joint study between Premier and the Vietnamese state owned oil company, Petrovietnam, identifiednumerous leads on Block 104-109/05 in water depths ranging from 20 metres to 60 metres. The PSC

carries a firm work commitment of seismic acquisition plus one exploration well.

MOECO has a 50% interest in the Block 104-109/05 joint venture. Under a farm-in agreement with

Premier, MOECO will carry Premier on the first exploration well drilled on Block 104-109/05.

6.1.3 Philippines

Ragay Gulf SC-43 – exploration, 21% non-operated interest

Premier licenced a block covering the offshore area of the Ragay Gulf in January 2004. Half of

Premier’s interest in the licence was farmed out to Pearl Energy and PNOC in return for a full carryon the Monte Cristo well drilled in early 2008. Premier now holds a 21% interest in the SC-43

licence. Further studies on the prospectivity of the block are underway. Partners in SC-43 are Pearl

Energy (operator, 64%) and PNOC (15%).

6.2 MIDDLE EAST & PAKISTAN BUSINESS UNIT

The Middle East & Pakistan Business Unit is based around a growing position in the Pakistan gas

market. In addition, in 2008, Premier established two joint ventures with EIIC of Abu Dhabi to build

a regional asset base in the Middle East & Pakistan and North Africa.

In 2008, 2P reserves in the Middle East & Pakistan reached 51.7 mmboe which represented 23% of

Premier’s 2P reserves. With 14.550 kboepd produced in the region in 2008, the Middle East &

Pakistan accounted for 40% of Premier’s total production.

42


Middle East & Pakistan Production

Field

Gross 2P

Reserves as of

31 Dec 2008

(mmboe)

Premier Equity

Interest

Net 2P Reserves

as of 31 Dec

2008 (mmboe)

Zamzama 265 9.37% 24.9

Bhit/Badhra 149 6.01% 8.9

Kadanwari 16 15.79% 2.5

Qadirpur 313 4.75% 14.8

Zarghun 15 3.75% 0.5

6.2.1 Pakistan

Premier has been present in Pakistan since 1988. In 1990, Premier discovered the Qadirpur field, Since

then, Premier has acquired interests in five other fields, all located in agricultural lowlands, and

reached production of 14,550 boepd in 2008. All fields are long-life gas projects with licences expiring

in 2015-2023 and have relatively low operating costs (average of US$0.20/mcf). All production is sold

at the wellhead to the government-owned gas utilities, SSGCL and SNGPL. Revenues are

denominated in US Dollars and funds are remitted directly to London bank accounts. No production

has been lost as a result of political disturbances or terrorist incidents.

From September 2001 to July 2007, Premier’s interests in Pakistan were held through PKP, the joint

venture between Premier and Kufpec. In 2007, Premier and Kufpec decided to demerge their

respective interests in Pakistan from the joint venture and run the demerged field portfolios as

businesses separately-owned by Premier and Kupfec.

Pakistan represents 23% of Premier’s 2P reserves and 40% of Premier’s 2008 production.

Pakistan Operations

Qadirpur – producing asset, 4.75% non-operated interest

The Qadirpur gas field was discovered in 1990 following a seismic survey on the Qadirpur block. The

field was declared commercial in 1992 and production commenced in October 1995. The field

operator is the OGDCL, the state-owned oil and gas company.

Phase I of the Qadirpur development was completed with gas supplies initially at the rate of 100

Mmcfd commencing to SNGPL in October 1995 with four wells onstream. Shortly thereafter, gas

sales were increased to 200 Mmcfd and were maintained at that level until late 1999. In addition, in

December 2000, raw gas supply started to the nearby Liberty power plant at 40 Mmcfd.

Phase II of the Qadirpur development was completed in January 2004 expanding the gas plant

capacity to 400 Mmcfd. Phase III of the development was completed in the first quarter of 2004

when total gas sales from Qadirpur gas field were increased from 400 Mmcfd to 500 Mmcfd. The

project to enhance the Liberty power plant capacity from 500 Mmcfd to 600 Mmcfd achieved first

43


gas in the first quarter of 2008. A binding term sheet has been signed with SNGPL to increase the

ACQ from the existing 450 Mmcfd to 550 Mmcfd.

Total 2P reserves (gross) are estimated at 313 mmboe, 14.8 mmboe net to Premier. 2008 production

was 4,060 boepd net to Premier. Partners in the Qadirpur field are OGDCL (operator, 75%), Kufpec

Pakistan B.V. (8.5%), Pakistan Petroleum (7%) and PKP Exploration 2 Limited (Kufpec) (4.75%).

Bhit & Badhra – producing asset, 6% non-operated interest

The Bhit gas field was discovered by a subsidiary of Lasmo in 1997. The Group’s equity in the

concession was obtained from a subsidiary of Shell in January 1999 through the joint venturecompany, PSP. Following the de-merger of PSP in 2001, the current equity interest of 6% was

retained by Premier-Kufpec Pakistan B.V., the joint venture between Kufpec and Premier. In late

1997, Lasmo commenced an aggressive appraisal programme on the concessions combined with

seismic data acquisition.

The Bhit partners signed a GSPA with SSGCL in November 2000 for 270 Mmcfd and initial gas

sales were achieved in late December 2002. A supplemental GSPA to increase the Bhit ACQ from

270 Mmcfd to 300 Mmcfd has since been signed by the gas buyer SSGCL and joint venture partners.

The Bhit plant capacity has been enhanced to 315 Mmcfd to allow accelerated Bhit field production

and production of Badhra reserves commenced in early 2008.

The Badhra field was discovered by the Bhadra-1 well, drilled by a subsidiary of Hunt Oil Company

in 1958/1959 and was plugged and abandoned at a depth of 1,333 metres. Badhra-2, located three

kilometres to the north of Badhra-1, was drilled by Lasmo in late 1998 to a depth of 3,495 metres.

Wireline logs and gas shows indicated the presence of a gas column, and a test of an 11 metres thick

interval produced gas at rates of up to 10.4 Mmcfd. The Mughal Kot sandstone had not beenpreviously encountered in the Kirthar fold belt, and represented a new play in the area. The Badhra

field was appraised in 2003, which appraisal formulated the basis of the field development plan. The

Pakistan government approved the field development plan in January 2004 and the field started

producing in January 2008. Further field development is tied to Bhit Phase-2 development.

Total 2P reserves (gross) are estimated at 149 mmboe, 8.9 mmboe net to Premier, and 2008

production was 3,190 boepd net to Premier. Partners in the Bhit/Badhra field are ENI (operator,

40%), Kirthar Pakistan B.V. (Shell) (28%), OGDCL (20%) and Kufpec (6%).

Kadanwari – producing asset, 15.79% non-operated interest

Lasmo discovered the Kadanwari gas field with the Kadanwari-1 well in 1989. The field was brought

onstream in May 1995 and Premier acquired its initial interest in 1996. The gas is processed in a

central processing facility, originally designed for gas sales capacity of 175 Mmcfd. In 2006, the K-15

well was tied back to the processing plant, which compensated for the natural decline of the field andalso provided some production redundancy. Development drilling is proceeding; K-18 went into

production in February 2008, K-17 went into production in December 2008, and three additional

wells are planned for 2009 of which only one is considered a firm commitment.

Total 2P reserves (gross) are estimated at 16 mmboe, 2.5 mmboe net to Premier, and 2008 production

was 1,225 boepd net to Premier. Partners in the Kadanwari field are ENI (operator, 18.42%),

OGDCL (50%) and Kufpec (15.79%).

Zamzama – producing asset, 9.375% non-operated interest

The Zamzama gas field was discovered by Premier in May 1998. The Group drilled the

Zamzama-1 well as part of its farm-in to the block. Zamzama-2 well was drilled to appraise the field

in March 1999. To define the Zamzama structure better, a drilling campaign was conducted in 2002

to 2003. During this period, five further appraisal and development wells were drilled which all

proved successful with commercial gas flow at surface. In April 2000, the consortium signed a GSAwith SSGCL for the supply of 70 Mmcfd of gas from the Zamzama field.

In April 2001, gas production started from extended well tests of the Zamzama-1 discovery well and

Zamzama-2 appraisal well under a 21-month contract signed with SSGCL for 60 Mmcfd. As perphase-1 development plan, two trains of dehydration plants with a capacity of 140 Mmcfd were

installed and commissioned in July 2003. Gas contracts were signed in the fourth quarter of 2001

with SSGCL and SNGPL covering the supply of up to 320 Mmcfd. Work continued in 2006 on the

Zamzama Phase 2 development which aimed to increase the ACQ by 150 Mmcfd starting in the third

quarter of 2007.

44


Total 2P reserves (gross) are estimated at 265 mmboe, 24.9 mmboe net to Premier, and 2008

production was 6,075 boepd net to Premier. Partners in the Zamzama field are BHP Billiton

(operator, 38.5%), GHPL (25%), ENI (17.75%) and Kufpec (9.375%).

Zarghun South – development asset, 3.75% non-operated interest

The discovery well, Zarghun South-1, was drilled in 1998 and tested gas at rates of up to 18 Mmcfd.

Zarghun South-2 was the first appraisal well drilled on the Zarghun South structure. The primary

objective of the well was to prove up the volume of reserves present in the Dunghan, Moro/Mughal

Kot and Chiltan reservoirs. The field development plan was approved by the Pakistan government

and a development and production lease was issued in January 2004. Negotiations on the GSPA weresuccessfully concluded with the gas buyer, SSGCL, for the sale of 22 Mmcfd gas from the field from

2009. The field development has commenced and gas production is planned for the first quarter of

2009.

Total 2P reserves (gross) are estimated at 14.5 mmboe, 0.5 mmboe net to Premier. Partners in the

Zarghun South field are MGCL (operator, 35%), Spud Energy (40%), GHPL (17.50%) and Kufpec

(3.75%).

6.2.2 Egypt

NW Gemsa Block – Production and exploration asset, 10% non-operated interest

Premier holds a 10% non-operated interest in the NW Gemsa Block which lies about 300 kilometres

southeast of Cairo and about 80 kilometres northwest of the Red Sea resort of Hurghada in an

under-explored part of the prolific Gulf of Suez Basin, in which over 10 billion barrels of reserves

have been discovered. Advances in seismic technology have lead to several significant new discoveries

in deeper plays which were previously hard to define. The Al Amir-1 well discovered oil in April 2005

and flowed at 750 boepd on test. Al-Amir-2 confirmed oil at the same reservoir level but flowed

water and oil at sub-commercial rates so was plugged and abandoned. Premier exercised an option

with the operator to reduce its interest in the block to 10% during 2006. An exploration well on Al-Amir SE was drilled in 2008 which flowed at 3,388 boepd and 4.2 mmscfd on test. In December

2008, the 2005 Al Amir-1 discovery well was re-entered and sidetracked in order to re-appraise the

well as a potential producer. The original discovered zone flowed at 416 boepd on test. The sidetrack

also encountered a second deeper pay zone which will be tested and confirmed when the well is

brought into commercial production. An appraisal well on Al-Amir SE was then drilled, encountering

two Kareem sandstones with 42 feet of net pay. The well has flowed from one zone at an average

rate of 5,785 boepd and 7.8 mmscfd. The Al-Amir SE 1 discovery was brought onstream in February

2009 at a rate of 1,300 boepd gross, 130 boepd net to Premier. Total 2P reserves (gross) areestimated at 8.8 mmboe, 0.9 mmboe net to Premier. Partners in NW Gemsa are Vegas Oil and Gas

(operator, 50%) and Circle Oil (40%).

6.2.3 Middle East

In 2008, Premier executed a shareholder agreement with EIIC to form two new joint venture

companies to pursue the acquisition of upstream oil and gas assets across the Middle East and North

Africa region. The first joint venture, Premco Energy Projects Company LLC, is owned 49% byPremier and 51% by EIIC and will hold all joint venture assets which are acquired in the United

Arab Emirates. The second joint venture, Premco Energy Projects B.V., is owned 50% by Premier,

50% by EIIC, and will hold all joint venture assets which are acquired in the Middle East and North

Africa region (excluding the United Arab Emirates).

This joint venture will enable Premier to access acquisition opportunities across the Middle East and

North Africa region via the relationship with EIIC and build a material oil and gas business across

the Middle East and North Africa. A number of potential projects have already been identified but

no acquisitions have been made to date.

6.3 WEST AFRICA BUSINESS UNIT

The West Africa Business Unit is focussed on delivering offshore exploration opportunities. Current

assets are located in Mauritania, SADR and Congo-Brazzaville. The Group is currently planning to

drill its first operated deep water block in Congo in 2009, whilst the Chinguetti field in Mauritania is

currently producing.

45


In 2008, 2P reserves in West Africa were 2.7 mmboe which represented 1% of Premier’s 2P reserves.

With 0.95 kboepd produced in the region in 2008, West Africa accounted for only 3% of Premier’s

total 2008 production. 100% of current West African reserves and production are in Mauritania.

6.3.1 Mauritania

In May 2003, the Group reached agreement with Fusion to purchase a number of West African

interests, including the Chinguetti and Banda oil discoveries offshore Mauritania. The Group acquired

Fusion’s 6% interest in PSC B (containing the Chinguetti discovery) and 3% interest in PSC A

(containing the Banda discovery) for a cash consideration of US$10 million and an overriding royalty

based on ongoing production levels.

In December 2003, the Group purchased an additional 3.23% interest in PSC B and an additional

1.62% interest in PSC A for a consideration of approximately US$5.152 million from a subsidiary of

ENI.

Total 2P reserves (gross) are estimated at 33 mmboe, 2.7 mmboe net to Premier. 2008 production was

950 boepd from Chinguetti.

Mauritania Operations

Chinguetti – producing asset, 8.123% non-operated interest

The Chinguetti oil field came on production on 24 February 2006 at an initial rate of 70,000 boepd

(of which 5,600 boepd were attributable to the Group). The field is located in 800 metres of water 90

kilometres west of the capital Nouakchott. The initial development of six production wells and three

water injectors did not perform to expectations as a result of greater than expected reservoir

compartmentalisation due to reservoir geometry and complex structure. Remedial action to increaseproduction commenced in late December 2006 with drilling of the Chinguetti-18 well. This well

encountered 35 metres of net oil pay. Additional development drilling has taken place during 2008.

The field is currently producing around 17,100 boepd (gross).

Total 2P reserves (gross) are estimated at 33 mmboe, 2.7 mmboe net to Premier. Partners in the field

are Petronas (operator, 47.384%), Hardman (Tullow Oil plc) (19.008%), Societe Mauritanienne des

Hydrocarbures (12%), BG (10.234%) and ROC (3.25%).

6.3.2 SADR – exploration asset, 50% non-operated interest

In March 2006, Premier was awarded four licences by the government of SADR: Daora, Haouza,Mahbes and Mijek. Each block is equivalent in size to two North Sea quads (68 blocks). Premier

holds a 50% participating interest in each block, and is a non-operator.

SADR is a full member of the African Union and is classed as a non-self governing territory by the

United Nations, reflecting the fact that a referendum on self-determination following decolonisation

has not yet occurred. The licences will become effective when SADR’s sovereignty has been achieved.

46


The acreage lies to the north of Mauritania, where the Chinguetti field came onstream in February

2006, and to the south of the Canary Islands where exploration is ongoing for Repsol and Woodside.

6.3.3 Congo-Brazzaville

Block Marine IX – exploration asset, 31.5% operated interest

Premier initially held a 58.5% operated interest in Block Marine IX. After running a farm-out

process, a 27% participating interest was awarded to Kufpec in May 2008, leaving Premier with

31.5% equity and operatorship. The farm-out will result in a carry of Premier’s costs for two

exploration wells to be drilled on the licence. The Aleutian Key rig has been contracted for October

2009 to drill the Frida prospect, targeting 170 Mmbbl. If Frida is successful, management may

consider drilling an additional uncommitted well on the Ida prospect in 2010, targeting 320 Mmbbl.

Partners in Block Marine IX are Ophir Energy (41.5%) and Kufpec (27%).

6.4 NORTH SEA BUSINESS UNIT

The North Sea Business Unit moved to Stavanger, Norway in 2005 from where it now manages the

Group’s UK and Norway businesses. Premier’s existing UK business aims to maximise the value of

its mature producing interests. The acquisition of ONSL’s assets will replenish the North Sea

portfolio providing existing producing fields, development projects of existing discovered resources and

a portfolio of exploration opportunities. Within the Norwegian sector, the business unit has built up

a portfolio of exploration acreage which is being matured to the drilling phase.

In 2008, 2P reserves in the North Sea reached 27.2 mmboe which represented 12% of Premier’s 2P

reserves. With 9.3 kboepd produced in the region in 2008, the United Kingdom accounted for 25% of

Premier’s total production. In 2008, all reserves and production were in the United Kingdom, as the

exploration and development of assets is still progressing in Norway.

6.4.1 Norway

Premier was awarded interests in five licences in the 2005 APA licensing round, and a further five

licences in the 2006 APA licensing round. Premier is qualified as an operator to work in the

Norwegian North Sea.

Key assets and corresponding interests include PL407 Bream appraisal (20%), PL406 Bream

exploration (40%), PL417 NE Troll (40%), PL374 Blabaer (15%), PL378 Grosbeak (40%), PL359

Greater Luno (30%) and PL364 Frøy (50%).

47


In January 2008, Premier was awarded a 70% interest and operatorship of Block 7/7b in the

Norwegian APA 2008 licence round. Participation in this block is an opportunity to develop the Ula

Jurassic sandstone play proven by the Moth well on Block 23/21 and the Corrie discovery on

Premier-operated Block 23/22b across the United Kingdom/Norwegian median line.

Frøy – development asset, 50% non-operated interest

The Frøy oil field was abandoned in 2001 by a previous operator due to the imminent abandonment

of the nearby Frigg field to which it was tied back. The Group was awarded a 50% non-operated

interest in licence PL364 which contains the Frøy field in the 2005 APA licensing round.

In 2008, Premier and the Frøy field operator, Det Norske Oljeselskap, submitted the Plan for

Development and Operation to the Ministry of Petroleum and Energy. It is still under review by the

Norwegian Ministry. The Frøy field is expected to produce 56 mmboe with an initial production of28,000 boepd. However, the date of initial production is currently uncertain. Frøy will be developed

using a jack-up platform with drilling, production and storage facilities (‘‘JUDPSO’’). The contractor

which is providing the JUDPSO has indicated that there will be delays in obtaining the necessary

financing for this production facility. Accordingly, it is not expected that final project sanction will

occur until later in 2009. In the meantime work will focus on seeking cost reductions and identifying

third party volumes that can be developed over the Frøy facility. Oil will be stored in a tank located

on the seabed prior to offloading to shuttle tankers.

The partner in the field is Det Norske Oljeselskap.

6.4.2 United Kingdom

Premier holds producing interests in four producing fields in the UK: Wytch Farm, Kyle, Scott and

Telford. The UK represents 12% of Premier’s 2P reserves and 25% of Premier’s 2008 production.

Wytch Farm – producing field 12.38%, non-operated interest

In May 1984, the Group, as part of the Dorset Bidding Group, acquired from British Gas

Corporation a 12.5% interest in onshore licence PL089. The Group acquired a 12.5% interest in the

P534 licence covering Blocks 98/6a, 7a in the 9th Round. Under the unit operating agreement the

Group has a 12.38% working interest in the Wytch Farm oil field and a 12.5% interest in theWareham oil field.

The Wytch Farm oil field has been developed from 10 well sites (eight mainland sites and two sites

located on Furzey Island) linked to a central gathering station. Wareham oil field has been developed

from two mainland well sites. Phases I and II involved the development of the onshore part of the

Wytch Farm field. Phase I was the development of the Bridport and Frome reservoirs. The second

phase, which was brought onstream in June 1990, involved upgrading and expanding existing facilities

to tap the Triassic Sherwood reservoir. In addition, the third phase of development involved thedrilling of extended reach wells from two onshore well sites beneath Poole Bay to recover the

offshore reserves of the Sherwood reservoir began in 1993 and was completed in 1999.

The Bridport Sandstone reservoir was discovered by well Wytch Farm X1 in 1974, production

commenced in 1979. Following seven onshore appraisal wells and the key offshore appraisal well

98/7-2 in 1987 development drilling of the Sherwood reservoir began in 1988 and first oil from the

Sherwood reservoir was produced in 1990. In 1993, a programme of extended reach-drilling

commenced, which allowed development of the Sherwood reservoir under the environmentallysensitive Poole Harbour area from nine onshore well sites. An infill drilling campaign of multi-laterals

from existing onshore wells started in 2000 and has been ongoing with a single rig.

An infill drilling programme has been deferred and facilities simplification and life of field opex

reductions are being targeted.

Wytch Farm field is Europe’s largest onshore oil field. Total remaining 2P reserves (gross) are

estimated at 79 Mmbbl, 9.8 Mmbbl net to Premier. 2008 production was 2,965 boepd. Partners in

Wytch Farm are BP (operator, 67.81%), Oranje Nassau (7.43%), Maersk (7.43%), and Talisman(4.95%).

Kyle – producing field, 40% non-operated interest

The Kyle field was discovered in 1993 by well 29/2c-8. The well encountered gas bearing limestone

and anhydrite breccias and produced 26 Mmcfd on test. The well was side-tracked down flank as

29/2c-8z and tested oil from Palaeocene sandstones (2,000 boepd) and the Chalk (2,800 boepd). These

48


reservoirs were successfully appraised in 1994 and in 1998. In 2000 a 160 day extended well test,

resulting in production of 1.5 Mmbbl oil and 1.6 bcf gas, confirmed long-term production

performance of the Chalk reservoir.

The Group acquired a 20% interest in the P748 licence when it purchased Pict in 1995. In 1997 the

Group increased its equity interest from 20% to 35% following Mobil’s disposal of its remaining

equity interest after the transfer of operatorship to a subsidiary of Ranger Oil plc in late 1995. In2002 a further 5% was purchased for £3.44 million following ROC’s decision to dispose of its equity

interest.

Following a successful extended well test with the Petrojarl-1 FPSO in 2000 the Kyle field has been

developed via sub-sea wells connected to two manifolds (North and South) tied back 18 kilometres to

the Maersk-operated Maersk Curlew FPSO. Oil and gas production via the Maersk Curlew FPSO

began on 7 April 2001. A gas lift project was completed in 2007 alongside facility upgrades on the

Petrojarl Banff host processing facility.

Total 2P reserves (gross) are estimated at 14 Mmbbl, 5.7 Mmbbl net to Premier. 2008 production was

2,500 boepd. Partners in Kyle include CNR (operator, 45.71%) and Bow Valley Energy (14.29%).

Scott – producing field, 21.83% interest

The Scott field was discovered in 1983. However, potential for a significant oil field was notestablished until 1987 with the successful 15/21a-15 well. Twelve wells and two sidetracks subsequently

appraised the structure. Development commenced in 1990 with first oil produced in 1993. The Scott

oil and gas field was developed via two adjacent steel platforms. One platform incorporates

production and drilling equipment; the second platform has accommodation, utilities and power

generation facilities. Oil production is transported to the Forties Unity riser platform and from there

via the Forties Pipeline System to Cruden Bay. Gas is exported to shore via the Scottish Area Gas

Evacuation system. Scott has proved to be one of the larger and more productive oil fields to be

found on the UKCS. The Group acquired the 15/21 licence as part of its acquisition of Pict in 1995.

In May 2007, the Group announced the successful completion of a transaction to pre-empt Hess’s

proposed sale of its interest in part of the Scott field. The Group increased its existing 1.798%holding to 21.83% for net consideration of US$52.6 million. Letters of credit for approximately

£53 million have been issued at the request of the Group in favour of Hess in respect of their share

of any decommissioning or clean-up costs.

Total 2P reserves (gross) are estimated at 38 Mmbbl, 8.2 Mmbbl net to Premier. 2008 production for

Scott and Telford was 3,525 boepd. Partners in Scott include Nexen (operator, 41.89%), Petro-Canada

(20.64%), ExxonMobil (10.47%) and Maersk (5.16%).

7. Premier Exploration

Premier is committed to a strategy for growth. Premier’s exploration programme for 2009-2010 is

shown in the timetable below. Description of individual licences and prospects for the major parts ofPremier’s 2009-2010 exploration programme can be found in the foregoing country descriptions.

Premier plans to explore within a disciplined spending target, whilst exposing Shareholders to material

upside in the event of success. To achieve this level of expenditure from the portfolio of

opportunities, Premier plans to farm-down its equity interest in some of its licences to maintain an

optimal balance between spending, risk and potential reward.

49


Premier Exploration Timetable

Exploration Outlook

2009Q1 Q2 Q3 Q4

2010AsiaVietnam: 07/03 Alpha (Huyêt Long)

Beta

104-109/05 Seismic

rumiTtuaL hajaGanuT:aisenodnI

Singa Laut

Natuna Anoa-Deep

N. Sumatra A 1 well

Buton 1 well

West AfricaCongo: Marine IX Frida

Ida

North SeaNorway: PL359 (16/1,4) Greater Luno

PL374S (34/2,5) Blåbaer

PL378 (35/12, 36/10) Grosbeak North

PL406 (8/3) Gardrofa

PL407 (17/8,9,11,12) Bream Appraisal

Middle East/PakistanPakistan: Badhra Bado Jabal (Badhra Deep)

Kadanwari K-19

K-22

Egypt NW Gemsa Geyad-1X

Contingent WellsFirm Wells: Rig Contracted Firm Wells: Rig TBC Seismic Programme All well timings are subject to revision for operational reasons

Q1 Q2 Q3 Q4Hakuryu-V

Aleutian Key

West Delta Deep

Maersk Guardian

Muburrak-1

Hakuryu-V

Transocean Winner (provisional)

Schlumberger Rig 15

Schlumberger Rig 60

50


PART III

INFORMATION ON ONSL

1. Company information

ONSL is an oil and gas exploration and production company active in the United Kingdom, with its

producing properties located in the UK Central North Sea. ONSL is a wholly-owned subsidiary ofOilexco Inc. and began operating in the North Sea in 2003.

ONSL has a balanced portfolio of offshore UK Central North Sea assets, including producing fields

(principally the Balmoral area and Nelson), fields able to be brought onstream in the medium-term

(Shelley, Huntington) and potentially commercial discoveries (including Bugle, Blackhorse, Kildare,

Moth) which remains subject to further appraisal. ONSL has material stakes in the majority of the37 offshore licences which it holds, and is the operator of a large proportion of such licences. The

table below sets out details of the principal assets owned by ONSL all of which are located in the

United Kingdom.

ONSL’s total production for the year ending 31 December 2009 is expected by Premier to beapproximately 13,700 boepd. As at 31 December 2008, ONSL had total 2P reserves and contingent

resources of approximately 60 mmboe, of which 40 mmboe is expected to be bookable to 2P by

Premier.

A Competent Person’s Report on ONSL has been prepared by RISC and is reproduced in full inPart XIV of this document.

ONSL was placed into administration by its lending banks on 7 January 2009, as a result of the

inability of ONSL’s parent company, Oilexco Inc., to secure a refinancing of ONSL’s business. Ernst

& Young LLP, who are acting as administrators to ONSL, have continued to operate the business

since the date of entry into administration and the ONSL business has continued to generate positivecurrent cash flow from ongoing operations.

It is Premier’s intention following completion to integrate ONSL’s employees, all of whom are based

in Aberdeen, with its existing North Sea operations.

2. ONSL licence interests

Licence Block Operator Equity % Field

P032 30/17a Maersk 6.45% Janice, James

P077 22/12a Shell 50.00% Nelson(2)

P087(4) 22/7 ONSL 46.50% Nelson(2)

P101(6) 23/21 (Moth earn-in area) BG 50.00%

P1042 15/25b ONSL 100.00% BrendaP1043 15/25c ONSL 100.00%

P1089 14/28a, 14/29b ONSL 45.00%

P1095 16/21b Maersk 50.00%

P110(6) 22/14a, 22/14aF1 ONSL 25.04%

P1104 21/4b Maersk 45.00%

P1114 22/14b, 22/19b E.ON 40.00%

P1157 15/25e, 15/26e ONSL 100.00%

P1181 23/22b Premier 32.50%P119 15/29a ONSL 60.00%

P1220 21/23a Sterling 65.00%

P1260 22/2b ONSL 100.00%

P1295 14/23b ONSL 45.00%

P1298(7) 15/26b Nexen 50.00%(4)

P1420 22/13b ONSL 72.70%

P1430 28/9, 28/10c Encore

Petroleum

50.00%

P1431 29/6b ONSL 100.00%

P1457 13/20, 14/16, 14/17a,

14/21b, 14/22b

ONSL 55.00%

P1466 15/24c, 15/25f Premier 75.00%

P1467 15/25d Maersk 50.00%

51


Licence Block Operator Equity % Field

P1498 13/14, 13/15 ONSL 55.00%

P1555 22/3a ONSL 100.00%

P185(4)(7) 15/22 Nexen 50.00%

P201(4) 16/21a (including

16/21aF1), 16/21aF2,

16/21b

ONSL 85.00% Balmoral(1),

Glamis,

Stirling(3)

P213(8) 16/26UPF2 ONSL 100.00%

P233(9) 15/25a ONSL 70.00% NicolP295 30/16 Maersk 6.45%

P300 14/26a BG 70.00%

P344(4) (7) 16/21b (including

16/21bF1), 16/21b, 16/21c

(including 16/21cF1)

ONSL 44.20%

55.00%

Balmoral(1),

Northern

Stirling(3)

P489 15/23b Nexen 50.00%

P640 15/24b ConocoPhillips 50.00%

P811(4) 13/30b BG 70.00%P815(5)(7) 15/23d, 15/23e Nexen 41.00%

Notes:




(4) Subject to pre-emption rights in the case of the Asset Acquisition Agreement. For more information please see paragraph 13 ofPart V of this document

(5) Subject to pre-emption in the case of the Asset Acquisition Agreement and the Share Acquisition Agreement. For moreinformation see paragraphs 7 and 13 of Part V of this document

(6) Outstanding earn-in interests

(7) Conditional farm-out obligations

(8) Outstanding earn-in interests under a sale and purchase agreement

(9) Conditional earn-in obligations

52


3. ONSL operations

North Sea Operations

United Kingdom

ONSL holds interests in eight producing fields in the UK: Balmoral, Stirling, Glamis, Brenda, Nicol,Nelson, Janice and James. Development opportunities exist at Shelley, Huntington, Bugle, Sheryl,

Blackhorse, Kildare, Moth and Ptarmigan.

Balmoral, Glamis and Stirling area

The Balmoral, Glamis, Nicol and Stirling fields are located in Blocks 16/21a and 16/21b in the UK

Central North Sea, 200 kilometres northeast of Aberdeen. The Balmoral Area fields produce via a

floating production facility located on the Balmoral field. Oil is transported via the Brae-Forties link

to Cruden Bay and overland to Hound Point.

In September 2004, ONSL completed the acquisition of Pentex Oil’s remaining interest in the

Balmoral Area for a cash consideration of £2.15 million. The deal included the Balmoral and Glamis

oil fields and a 7.91% interest in the Balmoral FPV. The agreement was effective from 1 January

2004.

With the purchase of CNR’s interests in the Balmoral area properties in 2007, ONSL’s workinginterest in the Balmoral Field, and the Balmoral FPV rose to 78.11%. As a result of the same

acquisition, ONSL’s working interest in the Glamis Field rose to 85%, and 68.7% for the Stirling

Field.

Balmoral – producing field, 78.11% operated interest

The Balmoral Field produces oil from Paleocene Balmoral turbiditic sandstones trapped in a low

relief anticline. Production is from subsea wells through a subsea template and from three satellite

locations tied back via subsea flow lines. Produced fluid from the template and satellite wells is

passed to the Balmoral FPV via flexible risers. Balmoral was discovered in 1975 and production

commenced in 1986. Cumulative production at Balmoral is approximately 114,300,000 bbls as of the

end of 2007.

Partners in Balmoral are Talisman (15.14%) and Sumitomo (6.75%).

In the event of an asset sale instead of a share sale, this asset may be subject to pre-emption.

53


Stirling – producing field, 68.68% operated interest

The Stirling field was discovered in 1980 and has been producing oil from a fractured Devonian

formation since 1995. Stirling had produced 2,720,000 bbls to the end of 2007.

Partners in Stirling are Sumitomo (16%) and Talisman (15.32%).


Glamis – producing field (suspended), 85% operated interest

The Glamis field was discovered in 1982 and brought onstream in July 1989. Oil is produced from

the Jurassic Piper sandstones trapped along an east west trending fault block. Since 1989, cumulative

production at Glamis has been approximately 19,100,000 bbls to the end of 2007. The Glamis field is

currently suspended.

The partner in Glamis is Talisman (15%).


Brenda – producing field, 100% operated interest

The Brenda oil field is located in the Central North Sea, eight kilometres southwest of the Balmoral

area fields. Although the accumulation was first discovered in 1990 by ConocoPhillips, the field was

not appraised until ONSL acquired the block. ONSL was awarded a 100% interest in Licences P.1042

and P.1043, on Blocks 15/25b and 15/25c respectively, in the 20th UK Offshore Licensing Round inJuly 2002. 12 appraisal wells were completed by ONSL during 2004, and Brenda received

development approval in November 2005. Brenda was developed as a subsea tie-back to the Balmoral

FPV, and first oil was achieved in June 2007. Crude oil is exported via the Forties Pipeline. Brenda

currently produces from five wells.

The development of Brenda provides important subsea infrastructure which will help to facilitate

development of the area. The subsea manifold has been designed to accommodate eight wells or

flowlines to allow future tie-ins. The latest ONSL Field Development Plan for Brenda was an

integrated reservoir study performed in 2008 which envisaged the addition of a sixth production wellin 2010. It is the intention of Premier to accelerate the drilling of this well into 2009.

Nicol – producing field, 70% operated interest

The Nicol oil field lies in Central North Sea Block 15/25a, 10 kilometres north west of the ONSL-

operated Brenda field development. The field was discovered in 1988 by Shell, but was considered

uncommercial at that time. Oil is trapped by a four-way dip closure that is situated in the same

Paleocene turbidite channel fairway that hosts both the Brenda and MacCulloch oil fields. In 2005,ONSL completed an appraisal drilling programme, and the field subsequently received development

approval in May 2006.

In late 2004, ONSL negotiated a farm-in agreement with the operator of Block 15/25a allowing

ONSL to pay 100% of the drilling costs to earn a 70% interest in Block 15/25a. In May 2006, ONSL

signed a sale and purchase agreement with both partners at Nicol. Under this agreement, ONSL’s

partners will lift a joint total of 1.25 mmbo from their current combined 30% equity interest in the

Nicol field. If this production milestone is reached by 31 December 2009 or any later date agreed by

the field partners, the other partners will relinquish their equity in the property, thereby giving ONSL100% ownership of the Nicol field in Block 15/25a.

In August 2006, ONSL finished the drilling and completion of the Nicol 15/25a-N1w horizontal

production well. During cleanup testing, the 15/25a-N1w well flowed oil at a maximum rate of 10,165

bbls per day through a 70/64 choke at 505 psi flowing tubing pressure. Oil production from the Nicol

field began on 23 June 2007 at rates in excess of 8,000 bbls per day via the Brenda manifold and the

Balmoral FPV. A second well has been drilled but its hook-up has been delayed because of the

administration of ONSL. This well is expected to come onstream in 2009.

Partners in Nicol are ConocoPhillips (18%) and ENI (12%).

Nelson – producing field, 1.65% non-operated interest

The large Nelson oil and gas field is located to the southeast of the Forties field. Nelson was

discovered in December 1987. Following an extensive appraisal drilling programme in the late 1980s,

estimates of recoverable reserves were significantly increased. The field was subsequently developed

54


using a conventional stand-alone fixed steel platform with one subsea template located six kilometres

to the south. First oil was achieved in February 1994.

Oil is exported via a spurline to the Forties Pipeline System and onwards to the BP-operated terminal

facilities at Cruden Bay. Gas export is via the Fulmar pipeline to the Shell-operated terminal facilities

at St Fergus.

Partners in Nelson are Shell (operator 58.11%), ExxonMobil (21.23%), Total (11.54%) and Sumitomo

(7.47%).


Janice and James – producing fields, 6.45% non-operated interest

Janice is a mature field which produces fluids processed on a floating production unit which started

up in 1999. Production peaked at 40,000 bbls per day. James is a smaller field, developed as a single-

well subsea tie-back to Janice, which came onstream in 2004. Oil is exported via Norpipe to Seal

Sands terminal on Teesside. There is a gas pipeline to the Judy platform allowing gas exceeding

offshore fuel gas requirements to be sold offshore and evacuated via the Central Area Transmission

System, but there has been no surplus Janice/James gas available for sale since 2005. The Affleck fieldhas recently been developed as a subsea tie-back to Janice and is due to come onstream this year,

providing third party tariff income.

Partners in Janice and James are Maersk (75.3%, operator) and Oranje Nassau (18.22%).


Shelley – potential development asset, 100% operated interest

The Shelley field is located in the Central North Sea, 20 kilometres south of the Britannia gas field

and around 40 kilometres south of ONSL’s hub area which includes Brenda, Nicol and the Balmoral

fields.

Shelley was discovered in 1984, but was considered uncommercial. ONSL acquired the acreage in the

23rd UK Offshore Licensing Round, and has since completed an appraisal programme. Development

of the field was progressed using two horizontal wells and Sevan’s Voyageur FPSO and was dueonstream in early 2009. Progress was halted when ONSL went into administration. Premier is now

looking at future options for the Shelley field which include re-commencing the planned development,

a tie-back to nearby infrastructure or abandonment.

Huntington – potential development asset, 40% non-operated interest (approximately) subject to a final

unitisation agreement

The Huntington light oil field was initially discovered in a Triassic play by exploration well 22/14b-3

in 1989. It was appraised by ONSL in 2007, testing significant hydrocarbons from both a Palaeocene,

Forties sandstone and an Upper Jurassic, Fulmar horizon. An extensive appraisal programme on theForties reservoir throughout 2007 successfully appraised the edges of the Forties accumulation. This

was followed by appraisal of the Fulmar section in 2008. Conceptual selection studies are now in

progress for the field development plan evaluating both FPSO options and a tie-back to ETAP.

Partners in Huntington are E.ON (operator 25%), Noreco (20%) and Carrizo Oil and Gas (15%).

Bugle – potential development asset, 41% non-operated interest

At the end of 2006, ONSL entered into a farm-in agreement with the operator of the Scott Platform

to earn a 41% working interest in the Bugle field. As a result of this agreement, ONSL paid 65% of are-entry appraisal well that was drilled in the first quarter of 2008.

On behalf of the licence operator, ONSL re-entered the original 15/23d-13 well and drilled an

appraisal sidetrack well down-dip to ascertain if the Bugle Jurassic oil accumulations were of a

commercial size. The original 15/23d-13 discovery well, drilled in 1997, encountered 85 feet of oil-

bearing Jurassic Dirk Sandstone and 123 feet of oil-bearing Jurassic Galley Sandstone. Both of the

intervals were tested together at a rate of 7,400 Bopd (44˚ API oil) and 9.06 Mmcfd of gas.

ONSL re-entered the 15/23d-13 well on 24 December 2007. The 15/23d-13z sidetrack well was

successfully kicked off from the original well bore on 6 January 2008 and drilled to a total depth of

15,898 feet on 28 January 2008.

55


The main objective of this appraisal well was to establish an oil/water contact in the Dirk and Upper

Galley sands by drilling a location on the flank of the Bugle structure. Oil bearing Dirk Sandstone

and oil bearing Upper Galley Sandstone were encountered, establishing at least 282 and 280 feet of

oil column respectively, and significantly increasing the size of the Bugle oil accumulation. Oil sampleswere recovered and reservoir pressures were successfully recorded from both the Dirk and the Upper

Galley Sandstone.

Partners in Bugle are Nexen (operator, 41%) and ENI (18%).

In the event of a share sale or asset sale, this asset may be subject to pre-emption.

Sheryl – potential development asset, 65% non-operated interest

ONSL farmed into Block 21/23a to drill the Sheryl Prospect (initially called the Disraeli oil find) in

2005. ONSL paid 95% of the drilling costs to the Eocene to earn a 65% equity interest and, below

this stratigraphic interval, an 85% equity interest.

The Sheryl Prospect targeted the Eocene Tay Formation southwest of the Saxon Tay Sand oildiscovery (formerly known as Gladstone) in Block 21/23b. The prospect was mapped on the flank of

a four-way closure updip from the Gladstone/Saxon structure that was successfully tested to the

northeast by another operator.

The 21/23a-8z sidetrack well bore intersected 74 feet of net oil pay from a 90 feet oil column in the

Eocene Tay Sandstone, located on the northwest flank of the Sheryl structure. The drilling rig

(Bredford Dolphin) was not outfitted with testing equipment and a drill-stem test could not be

performed. The 21/23a-8z well bore was plugged back to allow an additional ‘‘extended reach’’sidetrack well bore to be drilled to evaluate the oil column at the crest of the structure. Electric logs

on the 21/23a-8y well bore confirmed the presence of a thin gas cap overlying oil in interbedded

sands.

ONSL and its partner agreed that additional appraisal drilling was warranted at Sheryl to evaluate

the south and east flanks of the structure. This phase of appraisal drilling commenced in early August

2006 and consisted of seven well penetrations from a single surface well bore. The last well bore was

drill-stem tested through sand screens under ‘‘open-hole’’ conditions. Oil flow during the test wasrecorded at a maximum rate of 1,915 barrels per day, through a 36/64 choke, at 334 psi flowing

pressure. Oil flow was restricted by sand production throughout the flow period as a result of a

damaged sand screen. The quality of the oil was 23º API. The development options of the appraised

Sheryl pool are currently being reviewed.

The partner in Sheryl is Stirling Resources Limited (operator, 35%).

Blackhorse – potential development asset, 50% non-operated interest

In 2005, ONSL earned a 40% interest in the Blackhorse oil find located in Block 15/22 by paying

60% of the cost of the first Blackhorse appraisal well (15/22-18). As part of a further farm-in

agreement in 2006 which related to both Bugle and Blackhorse, ONSL acquired an additional 10% in

Blackhorse making a total of 50%. A well, to be drilled on the Bugle North Prospect, is required to

complete the farm-in obligations by the end of 2009. When drilled, if successful this well could be

kept as a future producer. ONSL will pay 65% of the costs of this well to retain its additional 10%equity interest in the Blackhorse discovery area and to retain its 41% interest in Bugle.

The partner in Blackhorse is Nexen (operator, 50%).


Kildare – potential development asset, 50% operated interest

ONSL was awarded 50% of Licence P298 covering a portion of Block 15/26b in the 23rd UK

Offshore Oil and Gas licensing round on 6 September 2005. The licence is situated 30 kilometres

southwest of the Blackhorse Project. A firm well commitment was accepted by the the Department of

Trade and Industry on this successful bid targeting an oil prospect in the Upper Jurassic Kildare

(Ettrick) sands. This prospect is well defined with 3D seismic and an encouraging hydrocarbon show

of 2,650 bbls per day of oil and 3.5 Mmcfd of gas tested from the Kildare (Ettrick) sands in the 15/

26b-5 well drilled in 1988 by another operator. Drilling of this prospect with the Sedco 712 drillingrig commenced on 10 January 2007.

The ONSL Kildare 15/26b-9 well penetrated about 20 feet of Kildare (Ettrick) sand and recovered oil

samples and successfully recorded reservoir pressures that tied this sand with the Kildare sand in the

56


original 15/26b-5 well that is situated about two kilometres to the north. This indicates an oil-bearing

sand that covers a large area.

The ONSL Kildare 15/26b-9 well was drilled to a total depth of 14,330 feet. A significant reservoir

sand section was encountered in the Upper Jurassic at a depth of 13,705 feet. A total of 91 feet of

net pay from a gross section of 132 feet from the Upper Jurassic was penetrated by this well. Both

well logs and wireline pressure measurements indicated that the entire Upper Jurassic reservoir sand

was oil-bearing. No oil-water contact was intersected by the well. Oil samples were also successfully

extracted from the wireline downhole sampler.

An interval of 125 feet was perforated and drill-stem tested. The test flowed 4,216 bopd and 3.1

Mmcfd through a 64/64 inch choke with a flowing tubing pressure of 460 psia. There was no water

or sand production reported in this test. This well was suspended for future re-entry.

The partner in Kildare is Nexen (50%).

Moth – potential development asset, 50% operated interest

In June 2007, Moth was discovered on Block 23/21. This was a significant discovery of HPHT gas-condensate in Upper Jurassic Fulmar sands, and oil and gas in Middle Jurassic Pentland sands. A

drill-stem test was conducted in the Upper Jurassic Fulmar zone through perforations from 12,982

feet to 13,026 feet in 115 feet of gas condensate bearing reservoir sands. The test flowed gas at an

average rate of 20.3 Mmcfd with 2,110 bbls per day of condensate through a 36/64 inch choke with a

flowing tubing pressure of 4,478 psi during the main flow period. Flow rates were severely restricted

by the test equipment utilised for the test and for the working temperatures and pressures

encountered. No depletion was measured, nor was there any water or sand produced during the test.

Calculations of surface absolute open flow suggest that the Moth well could be capable of 44 Mmcfdand 4,400 bbls per day of condensate (11,800 boepd) with a properly sized production string. A drill-

stem test of the Pentland sands flowed oil and gas to the surface, but before this flow could be

diverted to the test separator to accurately determine flow rates a failure of the downhole test tools

occurred. While the initial results of the test prior to the tool failure appeared positive, definitive

results were unable to be acquired. Further testing will likely occur during the course of additional

appraisal drilling in the future.

Partners in Moth are BG (31%), Hess (8%) and BP (11%).


Ptarmigan – potential development asset, 60% operated interest

The Ptarmigan oil and gas field was first discovered by well 15/29a-9 in 1994 by the previous

operator ChevronTexaco, and was further appraised in 1995. In June 2007, as part of a farm-in

agreement, ONSL began an appraisal programme on the field, paying the drilling costs in exchangefor an operated interest in the field. ONSL drilled a five legged appraisal well into an un-appraised

Paleocene oil discovery at Ptarmigan. These well bores were drilled to map the limits of the oil

accumulation geologically and to calibrate the seismic data to the interpretation. It is anticipated that

Ptarmigan will be developed by a production well tie-back to the Balmoral FPV at some point in the

future.

Partners in Ptarmigan are Chevron (28%), ConocoPhillips (10%) and GDF Suez (2%).


4. ONSL exploration assets

ONSL’s current exploration portfolio, excluding the 25th Round provisional awards, totals 22

licences.

ONSL has one firm well commitment and one contingent well commitment prior to 2011, and two

drill-or-drop decisions to be made in 2009. There are no material outstanding seismic obligations.

There are outstanding farm-in obligations on Bugle North, Kildare and Alpha.

5. ONSL production and development capex

The charts below show details of ONSL’s forecast production and development capital expenditure

over the period to 2015.

57


Production (kboepd)

2009 2010 2011 2012 2013 2014 2015

ONSL producing assets* 12.8 11.9 9.9 7.0 5.1 3.7 2.7

ONSL small fields 0.9 1.0 0.8 0.7 0.6 0.5 0.4

ONSL developments 0.0 0.0 0.0 6.9 17.8 17.0 11.5

Intended development capex plan (US$ million)

2009 2010 2011 2012 2013 2014 2015

ONSL producing assets 57.3 23.9 0.7 0.3 0.0 0.0 0.0

ONSL developments 35.9 51.6 129.0 191.4 34.9 0.0 0.0

Note:

* Does not include Shelley.

58


PART IV

KEY INFORMATION

The financial information set out in this Part IV does not constitute statutory accounts for any

company within the meaning of section 435 of the Companies Act 2006.

1. Capitalisation and indebtedness

The following table sets out the unaudited consolidated capitalisation and indebtedness of the Group

as at 28 February 2009:

28 February

2009

Unaudited

US$ million

Total non-current debt

Unguaranteed/Unsecured 207.5

207.5

Shareholder’s equity

Share Capital 73.6

Legal Reserve(1) 9.7

83.3

Total 290.8

Note:

(1) Represents the Company’s share premium account.

Net indebtedness of the Group as at 28 February 2009

28 February

2009

Unaudited

US$ million

Cash 13.1

Cash equivalent 284.2

Liquidity 297.3

Convertible bonds issued (207.5)

Total non-current financial indebtedness (207.5)

Net Surplus Liquidity 89.8

2. Liquidity and capital resources

The Group’s liquidity requirements arise from its working capital needs and its programmes of capitalexpenditure. These requirements are met by a combination of cash resources, the re-investment of

cash flows from producing fields and the draw-down of bank facilities.

Premier anticipates managing its balance sheet by balancing long-term debt to equity in the range of

70:30 over the medium-term. Interest rate coverage is anticipated to remain a minimum of six times.

Treasury structure and objectives

Premier operates a centralised treasury section which is responsible for the management of the

investment of surplus funds, for making draw downs under the bank facility, for foreign exchange

management and for commodity hedging. Business units only have funds for working capital

purposes and will cash call Premier’s treasury on a monthly or bi-monthly basis for the funds

required. Cash from sales made by the business units in the UK, Indonesia, Pakistan and Mauritania

59


are received in London bank accounts in US Dollars and Pounds Sterling and are managed as part

of Premier’s total available funds.

The Company’s activities expose it to financial risks of changes, primarily in oil and gas prices but

also foreign currency exchange and interest rates. The Company uses derivative financial instruments

to hedge certain of these risk exposures. The use of financial derivatives is governed by the Group’s

policies and approved by the Board, which provide written principles on the use of financial

derivatives.

As Premier reports in US Dollars, the foreign exchange strategy undertaken by Premier’s treasury is

to fund in US Dollars providing a hedge against the almost exclusively US Dollar denominatedassets. A US Dollar convertible bond has been issued and to the extent necessary funding shortfalls

in US Dollars can be met from the bank facility. Surpluses in both US Dollars and to a lesser extent

Pounds Sterling and Norwegian Krone are maintained as a float to meet short-term cash needs of the

business and, to the extent that there are any shortfalls in Pounds Sterling and Norwegian Krone

income to meet this expenditure, US Dollars will be swapped into these currencies to cover this.

Investments are made on a short-term basis (no more than 3 months) in bank deposits with the bank

group participants, and AAA liquidity funds.

It is Company policy that all transactions involving derivatives must be directly related to the

underlying business of the Company. The Company does not use derivative financial instruments for

speculative exposures. The Company undertakes oil and gas price hedging periodically within Board

limits to protect operating cash flow against weak prices.

Premier’s commodity hedging policy is to lock in oil and gas price floors for a portion of expected

future production at a level which protects the cash flow of the Group and the business plan. Current

policy has been to hedge using zero cost collars covering approximately 50% of the expected exposureto oil up to December 2012. Hence slightly more than 50% of oil production is hedged with a floor

of US$50/bbl in 2010 and 2011 and capped at US$80/bbl, and a floor of US$39.3/bbl in 2009 and

2012. In addition zero cost collars for approximately 35% of the expected exposure to Indonesian gas

up to end of June 2013 were also entered into. Opportunities are taken on the basis of market advice

from commodity dealers.

At the end of 2007 a four and a half year physical off-take agreement for the sale of certain oil

production was entered into with effect from 1st July 2008. This agreement incorporates theparameters of existing oil collars and effectively replaces the equivalent amount of hedging.

Cash flows2008 2007US$

millionUS$

million

Net cash from operating activities 352.3 269.5Investing activities:Capital expenditure (217.3) (261.2)Pre-licence exploration costs (15.8) (8.3)Proceeds from disposal of intangible exploration and evaluation assets 3.1 1.0

Net cash used in investing activities (230.0) (268.5)

Financing activities:Issue of Ordinary Shares 0.4 1.0Purchase of shares for ESOP Trust (17.9) —Purchase of own shares (47.2) —Issue of convertible bonds — 250.0Issue costs for the convertible bonds — (5.9)Loan drawdowns — 53.0Repayment of long-term financing (53.0) —Interest paid (10.9) (9.3)

(i) Net cash (used in)/from financing activities (128.6) 288.8

Currency translation differences relating to cash and cash equivalents (2.0) 1.3

(ii) Net (decrease)/increase in cash and cash equivalents (8.3) 291.1Cash and cash equivalents at the beginning of the year 332.0 40.9

(iii) Cash and cash equivalents at the end of the year 323.7 332.0

60


In 2008, cash flow from operating activities, before movements in working capital, amounted to

US$478.1 million (2007: US$408.1 million). After working capital items and tax payments, cash flow

from operating activities rose 31% to US$352.3 million (2007: US$269.5 million). Capital expenditure

was US$217.3 million (2007: US$261.2 million).

Capital Expenditure (US$ million) 2008 2007

Fields/developments 124.0 65.7

Exploration 90.5 104.7

Acquisitions — 88.6

Other 2.8 2.2

Total 217.3 261.2

The principal development projects were the Qadirpur plant capacity enhancement project, Kadanwari

development wells, Zamzama Phase 2 project, Bhit/Badhra Phase 2 project, Wytch Farm infill

programme, Scott infill programme and upgrade of the power generation units, Chinguetti Phase 2B

development, and long lead equipment and interim work for wellhead platforms, pipelines and FPSO

on the Chim Sao field in Vietnam.

Cash position and debt

Net cash/indebtedness of the Group in the short and medium to long-term as at 31 December 2008and 31 December 2007:

31 December

2008

Unaudited

2007

Audited

US$ million

Cash at bank 11.5 7.6

Deposits with banks and liquidity funds 312.2 324.4

Liquidity 323.7 332.0

Bank loans — 53.0

2.875% Convertible Bonds due 2014* 206.4 200.0

Total non-current financial indebtedness 206.4 253.0

Letters of credit and other guarantees 85.3 116.1

Net cash/(debt) 117.3 79.0

Note:

* Excluding equity portion and net of unamortised issue costs

In addition, Premier had the following credit facilities in place:

Balance

Available

Balance

Outstanding Interest Rate Maturity

Revolving Credit Facility $275m — LIBOR + 0.9% 31st July 2010

Letter of Credit Facility £53m — 0.625% 31st July 2010

The facilities include financial covenants that require Premier to maintain certain financial ratios,

which are calculated in accordance with IFRS:

(A) The ratio of its consolidated net debt (including Letters of Credit considered as drawn down) toEBITDA must not exceed 2.75:1.00 for a measurement period being a twelve month period

ending on the last day of a financial half year of the parent company.

(B) The ratio of its EBITDAX to interest expense must not fall below 5.00:1.00 for any

measurement period.

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(C) The aggregate unconsolidated proven non-current assets and probable reserves of the relevant

guarantor subsidiaries of Premier must not at any time amount to less than 80% of the

consolidated non-current assets and proven and probable reserves of the Group.

EBITDA is defined as earnings before interest, taxes, depreciation and amortisation. EBITDAX is

defined as EBITDA before exploration write-off.

Premier has complied with these covenants since the execution of the facility in July 2005.

In June 2007, the Group issued bonds at a par value of US$250 million which are convertible into

Ordinary Shares of the Company at any time until six days before their maturity date of 27 June

2014. Interest of 2.875% per annum will be paid semi-annually in arrear up to that date.

As at the date of this document, aside from US$250 million of indebtedness outstanding under theConvertible Bonds, and outstanding letters of credit of a total value of £52,076,000, the Group had

no indebtedness outstanding under its existing facilities. The New Credit Agreements were signed on

25 March 2009 and, while not presently drawn down, are available for drawdown at Completion.

3. Working capital statement

The Company is of the opinion that, taking into account the net proceeds of the Rights Issue and

the New Credit Facilities available to the Enlarged Group, the working capital available to the

Enlarged Group is sufficient for its present requirements, that is for at least the 12 months following

the date of this document.

The Company is of the opinion that, taking into account the bank and other facilities available to

the Group, the working capital available to the Group is sufficient for its present requirements, that

is for at least the 12 months following the date of this document.

4. Earnings

As set out in the income statement on page 128 of this document, ONSL incurred significant losses

during the year ended 31 December 2007 primarily due to income statement write-offs of unsuccessful

exploration expense incurred. Despite Premier making statutory profits in the year ended 31December 2008, on a pro forma basis the Acquisition would be dilutive to the Enlarged Group’s

statutory earnings for the year ended 31 December 2008 (as assessed with reference to ONSL’s

earnings for the year ended 31 December 2007, the latest period for which audited accounts are

available). However, the Directors believe that the Acquisition will be accretive to the Enlarged

Group’s cash flow in the short to medium-term.

5. Trading update

Despite volatile markets and the sharp downturn in economic activity, the Directors consider that the

Group is in a strong position to maintain its growth profile. Already in 2009, the Group has


Premier is about to embark on an extensive exploration and appraisal campaign, which has thepotential to have a material impact on the Group.

The quality of the Group’s producing assets, underpinned by its financial position, secures its forward

cash flows and allows it to progress its exploration and development programmes that could bringvery significant upside.

6. Significant changes in the financial or trading position of ONSL since 31 December 2007

The following information on ONSL has been sourced from the public statements of its parent,

Oilexco Inc., made after 31 December 2007.

During the first quarter of 2008, Oilexco Inc. announced the completion of the first stage of the

appraisal of the Paleocene Forties and Upper Jurassic Fulmar sands on its Huntington prospect(Block 22/14b). In February 2008, ONSL also announced that it had drilled a successful appraisal

well on the Bugle discovery within licence P815 (Block 15/23d). For the three months ended 31

March 2008, ONSL averaged production of 20,714 bbls per day of oil and gas, and an average oil

price achieved of US$96.47/bbl.

In the second quarter of 2008, a number of operating issues reduced ONSL’s aggregate production

for the period. Early in the quarter, employees at the Grangemouth refinery in Scotland went on

strike for two days. The Forties Pipeline System, which transports oil from a number of fields in the

UK North Sea (including certain fields operated by ONSL), receives power and steam from the

62


refinery in order to operate. All producers feeding into the Forties Pipeline System, including ONSL,

experienced production interruptions for up to six days during periods of ramp down and ramp up

before and after the strike. Production was also halted several other times during the second quarter

of 2008 as ONSL performed maintenance activities on the Balmoral FPV and the Brenda subseamanifold, and tied-in the fifth horizontal production well in the Brenda field. Such maintenance work

interrupted production for approximately 15 days in the quarter.

In April 2008, ONSL acquired 100% of the voting shares of Svenska Petroleum Exploration UK

Limited (now ONSEL) for cash consideration of US$30.6 million (including working capital

adjustments). The acquisition brought with it the following interests:

* 1.66% unitised equity interest in the Nelson Field and platform;

* 6.45% working interest in the Janice and James fields and floating production vessel; and

* 40% working interest in Block 30/23b, south east of Janice.

Development wells were also drilled during the second quarter of 2008 at Brenda and Shelley.

Appraisal wells were drilled at Balmoral and Blaydon located in Block 16/21, and at Caledonialocated 14 kilometres south of the Balmoral FPV in Block 16/26. Exploration wells were drilled at

Moth (Block 23/21), Delta (Block 16/21) and Danica (Block 29/6).

Exploration drilling at Moth (Block 23/21) in June 2008 resulted in a significant discovery of HPHT

gas-condensate in Upper Jurassic Fulmar sands, and oil and gas in Middle Jurassic Pentland sands. A

drill-stem test was conducted in the Upper Jurassic Fulmar zone through perforations from 12,982

feet to 13,026 feet in 115 feet of gas condensate bearing reservoir sands. The test flowed gas at an

average rate of 20.3 Mmcfd with 2,110 bbls per day of condensate through a 36/64 inch choke with a

flowing tubing pressure of 4,478 psi during the main flow period.

In the three months ended 30 June 2008, sales of oil and gas averaged 20,606 bbls per day and

average daily production was approximately 17,073 bbls per day, reflecting production overlift. ONSL

received an average price of US$121.12 per barrel of oil.

The Shelley Field Development was progressed during the year, with facility construction and drilling

operations entering their final stages. During the third quarter of 2008, operations commenced on the

first of two planned horizontal production wells. Construction of the FPSO vessel, the SevanVoyageur, was completed in July 2008.

In July 2008, Oilexco Inc. announced that it had signed an engagement letter with respect torefinancing Oilexco Inc.’s current debt obligations and increasing Oilexco Inc.’s total debt availability

from US$700 million to US$1 billion. The credit facility was to be underwritten by a syndicate of key

relationship banks, subject to internal credit approvals and due diligence.

In the third quarter of 2008, ONSL acquired a 100% interest in the Caledonia Field located in Block

16/26a, and drilled a cluster of five new appraisal wells in the Field area.

During the third quarter of 2008, the Balmoral FPV also underwent its annual maintenance

turnaround, during which time a number of significant enhancements were made to improve its

operating reliability and production capabilities to more effectively produce the reservoirs to their

optimal levels. The project work associated with Brenda Nicol first oil had created a maintenance

build up and it was necessary to reduce some of the backlog. In addition to this routine maintenance

work, certain key areas on the Balmoral FPV were improved.

Production in the three months ended 30 September 2008 averaged 11,951 bbls/day with average daily

sales of 8,623 bbls per day, reflecting a production underlift, a result of the planned annual

maintenance turnaround on the Balmoral FPV discussed above. The average price of achieved perbarrel of oil in the quarter was US$120.16.

On 3 October 2008. Oilexco Inc. announced that the process to close its financing transaction wastaking longer than anticipated due to what it described as the unprecedented liquidity and volatility

issues facing the credit markets.

In October 2008, ONSL identified an extension to the Huntington Forties Pool on Block 22/14a. The

22/14b-9 well encountered 58 feet (TVT – true vertical thickness) of oil-bearing Forties sandstone.

Wireline pressures confirmed that these oil-bearing Forties sandstones were connected with the

Huntington Forties Pool, suggesting that the oil pool extends from Block 22/14b onto a portion of

the adjacent Block 22/14a.

63


In November 2008, Oilexco Inc. announced that it had been awarded eight new licences in the 25th

UK Offshore Licensing Round by the Department of Energy and Climate Change.

On 12 November 2008, Oilexco Inc. announced that ONSL had obtained an extension for the

repayment of £70 million of its £100 million pre-development facility with Royal Bank of Scotland

plc. Whilst £30 million of the pre-development facility would still be repayable on the original

repayment date of 31 January 2009, the repayment date of the remaining £70 million was extended to30 November 2009.

On 13 November 2008, Oilexco Inc. announced its intention to issue US$150,000,000 of 15%convertible senior unsecured bonds and up to 20,000,000 common shares. On 20 November 2008,

Oilexco Inc. announced that it had decided to cancel the offering. On 17 December 2008, Oilexco Inc.

announced that Royal Bank of Scotland plc and ONSL’s banks had agreed the lending of up to

US$47.5 million to ONSL, repayable on demand, with a maturity date of 31 January 2009. In

addition, Oilexco Inc. announced on 17 December 2008 that it had retained Morgan Stanley & Co.

Limited and Merrill Lynch International in a strategic review process to seek alternative funding or

the sale of ONSL or some of its assets. Oilexco Inc. had encountered substantial financial difficulties

and cash flow problems caused in part by the recent significant falls in the price of oil and itsinability to secure further funding. On 31 December 2008, ONSL announced its intention to petition

for administration following confirmation to Oilexco Inc. by Royal Bank of Scotland plc (on behalf

of the syndicate of lenders) that they were not prepared to advance any further funding to ONSL.

On 7 January 2009, ONSL was placed into administration by its lending banks.

On 4 February 2009, Oilexco Inc. announced that it had received demand letters from Royal Bank of

Scotland plc (on behalf the syndicate of lenders) for immediate payment of all amounts outstanding

under ONSL’s US$547.5 million senior and super senior credit facility and £100 million pre-

development credit facility, such amounts being payable by Oilexco Inc. pursuant to the guarantees

given by it in respect of ONSL’s obligations under such facilities. On 5 February 2009, Oilexco Inc.

announced that it obtained a court order for protection under the Companies’ CreditorsArrangements Act (Canada) pursuant to which Oilexco Inc. is able to remain in possession and

control of its assets, to carry on its business and to restructure its operations.

In February 2009, Oilexco Inc. announced its reserves had been independently evaluated by SprouleInternational Limited at 66.226 mmboe as at 31 December 2008.

64


PART V

SUMMARY OF THE PRINCIPAL TERMS OF THE ACQUISITION

1. Introduction

Premier’s wholly-owned subsidiaries, POGL and POEL have entered into, respectively, the Share

Acquisition Agreement and the Asset Acquisition Agreement. Pursuant to the terms of the

Acquisition, Premier will acquire either: (i) (through POGL) the entire issued share capital of ONSL

from Oilexco Inc. (acting through the Receiver) (the ‘‘Share Acquisition’’); or (ii) (through POEL) theprincipal assets of ONSL (including the entire issued share capital of ONSEL) from ONSL (acting

through the Administrators) (the ‘‘Asset Acquisition’’).

2. Purchasing from a receiver/an administrator

As is customary in the case of purchases from sellers in administration or receivership, Premier has

received no representations, warranties or other indemnities of any kind in connection with the

Acquisition. Premier will therefore acquire the ONSL Shares or Assets (as applicable) pursuant to the

Acquisition, together with any potential risks and liabilities associated with them, without having any

recourse against any person for defects in title to those ONSL Shares or Assets or for any

undiscovered liabilities or obligations connected with such ONSL Shares or Assets. If any such issuesarise after Completion, Premier could be left without full ownership of the ONSL Shares or Assets,

or with ownership of the Shares or Assets but with unexpected additional liabilities or obligations,

and with no ability to reclaim any of the consideration it has paid.

THE SHARE ACQUISITION

3. Introduction to the Share Acquisition

Premier has proceeded initially with the Share Acquisition under the Share Acquisition Agreement.

Completion under the Share Acquisition Agreement is conditional upon, inter alia, the approval of

the CVA (as more fully described in Part VI of this document) in respect of ONSL, the expiry of the

28 day objection period after such approval has been granted and the court discharging the

administration order over ONSL (see further paragraph 8 below).

4. Conditions of the Share Acquisition

Completion under the Share Acquisition Agreement is also conditional upon the approval of the

Acquisition by Shareholders, and upon Admission. In the event that such Shareholder approval or

Admission is not obtained by 14 June 2009, either Oilexco Inc. (acting through the Receiver) or

POGL may terminate the Share Acquisition Agreement by notice in writing to the other.

5. Consideration and adjustments in respect of the Share Acquisition Agreement

The total consideration payable to Oilexco Inc. (acting through the Receiver) under the ShareAcquisition Agreement is US$1. However, in addition, Premier will also fund the payment by ONSL

of a settlement amount (the ‘‘Settlement Amount’’) of US$505 million to compromise certain debts

and liabilities owed to ONSL’s secured and unsecured creditors. Under the Share Acquisition

Agreement, appropriate adjustments will be made to the Settlement Amount to account for certain


6. Operation of ONSL prior to Completion under the Share Acquisition Agreement

Oilexco Inc. (acting through the Receiver) has agreed to customary conduct of business obligations

prior to Completion under the Share Acquisition Agreement. In addition, Oilexco Inc. (acting

through the Receiver) has agreed to provide broad rights of access prior to Completion for eight

representatives of POGL to the operations, employees, premises, and books and records of ONSLand Oilexco Inc.

7. Pre-emption Asset

If the Acquisition proceeds by way of Share Acquisition, the Bugle asset is subject to a right of pre-

emption under the relevant joint venture agreement. However, this asset is immaterial to the

Acquisition, and the pre-emption right would be exercisable against ONSL after Completion of its

acquisition by Premier.

65


8. Termination of the Share Acquisition Agreement

POGL may terminate the Share Acquisition Agreement at its discretion if one or more of the

Balmoral field interest, the Brenda field interest, the Nicol field interest or the Huntington fieldinterest is forfeited, revoked or terminated, or notice of forfeiture, revocation or termination is given

before Completion.

Either POGL or ONSL may terminate the Share Acquisition Agreement if, upon application by theAdministrators pursuant to the terms of the Share Acquisition Agreement, the court does not

discharge the administration order over ONSL dated 7 January 2009.

THE ASSET ACQUISITION

9. Introduction to the Asset Acquisition

If the CVA is not approved, Premier, through POEL, will continue to pursue the Acquisition by way

of the Asset Acquisition, pursuant to the terms of the Asset Acquisition Agreement, which has been

entered into conditionally upon termination of the Share Acquisition Agreement for non-fulfilment of

its conditions.

10. Conditions of the Asset Acquisition

Completion under the Asset Acquisition Agreement is also conditional upon approval of the

Acquisition by Shareholders, and upon Admission. In the event that such Shareholder approval or

Admission is not obtained by 14 June 2009, either ONSL or POEL may terminate the Asset

Acquisition Agreement by notice in writing to the other.

11. Consideration and adjustments in respect of the Asset Acquisition Agreement

The total consideration payable by Premier under the Asset Acquisition Agreement would be US$415

million. The difference of US$90 million in the amounts payable under the Share Acquisition

Agreement and the Asset Acquisition Agreement reflects the fact that Premier will not have the

benefit of the existing tax losses carried forward within ONSL under the Asset Acquisition

Agreement. Under the Asset Acquisition Agreement, appropriate adjustments will also be made to the

consideration to account for certain receivables, payables and other items.

12. Operation of ONSL prior to Completion under the Asset Acquisition Agreement

ONSL (acting through the Administrators) and ONSEL have agreed to customary conduct of

business obligations prior to Completion under the Asset Acquisition Agreement. In addition, ONSL

and ONSEL have agreed to provide broad rights of access prior to Completion for eight

representatives of POEL to the operations, employees, premises, and books and records of ONSL,

ONSEL and Oilexco Inc.

13. Pre-emption Assets

Certain of the Assets owned by ONSL are subject to pre-emption rights in favour of third parties.

The Asset Acquisition is not conditional on the waiver of such pre-emption rights, and therefore

Premier has no guarantee that it will obtain ownership of all or any of such Assets.

Under the Asset Acquisition, if a third party exercises its right of pre-emption in respect of an Asset

owned by ONSL, such Asset will not form part of the Asset Acquisition and the consideration

payable by Premier will be reduced by the amount paid by the pre-empting third party. Assets subject

to pre-emption in the case of the Asset Acquisition are ONSL’s interests in the P087 (Nelson), P1298,

P185, P201 (the Balmoral Field), P344 (Balmoral, Northern and Stirling), P811 and P815 (Bugle/

Blackhorse) licences.

Stakeholders with pre-emption rights will typically have 30 days to decide whether to exercise their

rights, though in some cases this can be up to 90 days. As a result, if the Asset Acquisition proceeds,

there will be an initial closing at which the non pre-emption assets will be acquired together with anypre-emption assets in respect of which all stakeholders have by that time agreed to waive their pre-

emption rights. Further closings will take place for pre-emption assets once the relevant pre-emption

processes have been successfully completed.

Premier and the Administrators intend to approach stakeholders with pre-emption rights to seek

waivers of those rights before that first closing. One such stakeholder has already agreed to waive its

pre-emption rights in respect of two of the pre-emption assets. This includes a waiver of pre-emption

rights in respect of the Balmoral field, which Premier considers to be the most significant of the pre-

66


emption assets. None of the remaining pre-emption assets are considered to be material in the context

of the Acquisition or the Enlarged Group.

14. Employees

The Asset Acquisition is likely to constitute a ‘‘relevant transfer’’ under the Transfer of Undertakings

(Protection of Employment) Regulations 2006. The Asset Acquisition Agreement contains provisions

for the transfer of certain employees working for, or connected to ONSL, and an indemnity in favour

of ONSL for claims made against them or the Administrators, regardless of the period to which such

claim relates.

15. Termination of the Asset Acquisition Agreement

POEL may terminate the Asset Acquisition Agreement at its discretion if one or more of the

Balmoral field interest, the Brenda field interest, the Nicol field interest or the Huntington field

interest is forfeited, revoked or terminated, or notice of forefeiture, revocation or termination is given

before Completion.

GUARANTEE AND ESCROW

16. Guarantee

The Company has entered into a deed of guarantee of the obligations of POGL under the Share

Acquisition Agreement and POEL under the Asset Acquisition Agreement.

17. Escrow Arrangements

The consideration and (as applicable) the Settlement Amount under the Acquisition will be paid into

an escrow account in the name of Royal Bank of Scotland plc prior to Completion.

BREAK FEE AND GOVERNING LAW

18. Break Fee

The Acquisition Agreements contain a break fee in an amount of US$5.05 million in favour of

ONSL. Pursuant to the Acquisition Agreements, the break fee shall be payable by POGL or POEL

(as the case may be) to ONSL only upon failure: (i) to obtain the approval by Shareholders of the

Acquisition at the EGM; or (ii) to secure Admission by 14 June 2009.

19. Governing law

Both the Share Acquisition Agreement and the Asset Acquisition Agreement are governed by the laws

of England and Wales.

67


PART VI

SUMMARY OF THE COMPANY VOLUNTARY ARRANGEMENT PROCEDUREFOR ONSL

1. Introduction and summary of proposal

1.1 It is a condition precedent to the Acquisition that ONSL enters into a CVA with its unsecured

creditors pursuant to Part I of the Insolvency Act 1986 (as amended). The Administrators were

appointed on 7 January 2009. The proposal for the entry by ONSL into the CVA has been

made by the Administrators.

1.2 The Administrators are required to hold separate meetings of the creditors and members of

ONSL at which the creditors and members of ONSL will each vote on the Administrators’

proposal for the CVA.

2. What is a company voluntary arrangement?

2.1 A CVA is a formal procedure under the Insolvency Act 1986 (as amended). A CVA enables a

company to agree with its creditors a composition in satisfaction of its debts or a scheme of

arrangement of its affairs which can determine how its debts should be paid and in whatproportions. A CVA does not affect the rights of secured or preferential creditors except with

their specific consent.

2.2 The CVA procedure is available to both solvent and insolvent companies. There are no

eligibility criteria for a company to satisfy as to whether or not it can pay its debts and the

procedure can be implemented in conjunction with and alongside the administration process.

2.3 A CVA can only be implemented if the proposal for the CVA is approved by specified

majorities of the company’s members and creditors. Such approval is obtained through separate

meetings of the members and the creditors.

2.4 Where a company is in administration, the administrator is obliged to summon every member

and every creditor of the company of whose claim and address he is aware, providing them with

at least 14 days’ notice of their respective meetings. Each notice must contain certain terms and

provisions, including a statement on the nature and amount of the company’s liabilities, together

with an explanation as to how these liabilities will be dealt with under the CVA.

2.5 At the creditors’ meeting, the CVA will only be approved if:

(A) a majority in excess of 75% by value of the creditors present in person or by proxy vote in

favour of the resolution to approve the CVA; and

(B) no more than half in value of creditors vote against the resolution (for these purposes

counting only those creditors (i) to whom notice of the meeting was sent, (ii) whose votes

were not left out of account1 and (iii) who are not, to the best of the chairman’s belief,

connected persons or associates of the company).

2.6 Where the quantum of an unsecured creditor’s debt is unascertained, such creditor may still vote

at the creditors’ meeting, with its debt valued at £1 (or such higher value as the chairman mayascribe to it).

2.7 At the members’ meeting, a CVA will only be approved if a majority of more than 50% in

value of the members present in person or by proxy vote in favour of the resolution to approve

the CVA.

2.8 Subject to the matters set out in paragraphs 2.10 to 2.12 of this Part VI (inclusive), if the CVA

is approved at the creditors’ meeting and the members’ meeting, it binds all the creditors of the

company who were entitled to vote at the creditors’ meeting (whether or not they so voted) and

creditors who would have been so entitled had they received notice of the meeting.

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1 A creditor’s vote will be left out of account where, in respect of any claim: i) no written notice of the claim is given at or before themeeting; ii) the claim or part of it is secured; or ii) the debt is wholly or partly on, or secured by, a current bill or promissory note.

2.9 If the outcome of the members’ meeting differs from the outcome of the creditors’ meeting, the

decision of the creditors will prevail. In this instance, a member has 28 days from the date of

the creditors’ meeting (or, if later, the date of the members’ meeting) to apply to the court. On

such application, the court may order the decision of the members’ meeting to have effect, ormake such other order as it sees fit.

2.10 The approval of the CVA obtained in either the creditors’ meeting or the members’ meetingmay be challenged on the grounds that:

(A) the CVA unfairly prejudices the interests of a creditor or member of the company (asapplicable); and/or

(B) there has been some material irregularity in relation to either meeting.

2.11 Any challenge to the CVA approval must be through application to the court. Such an

application may be made by:

(A) in the case of a challenge relating to the creditors’ meeting, any person entitled to vote at

that meeting (and any person who would have been so entitled had they received notice of

the meeting);

(B) in the case of a challenge relating to the members’ meeting, any person entitled to vote at

that meeting; and

(C) in respect of either meeting where the company is in administration, the administrator.

2.12 The entitlement to challenge the CVA approval is subject to the requirement that any

application must be made within 28 days of the approval being notified to the court (or, in the

instance where a creditor was not given notice of the meeting of creditors, within 28 days of

such creditor becoming aware that the creditors’ meeting has taken place).

2.13 By virtue of the Council Regulator (EC) No 1346/2000 of 29 May or insolvency proceedings

(‘‘EC Regulation’’), the courts of European member states (other than Denmark) are obliged torecognise a CVA for a company which is determined to have its centre of main interests in the

United Kingdom within the meaning of the EC Regulation.

3. Terms of ONSL’s proposed CVA

3.1 The CVA, if implemented, will:

(A) compromise all liabilities of ONSL:

(i) which were incurred prior to 7 January 2009 and which have not been discharged

during the course of the administration;

(ii) which arise under certain contracts which are to be terminated (including from their

termination pursuant to the terms of the CVA); and

(iii) which constitute the unsecured part of certain of ONSL’s secured creditors’ claims

against ONSL; and

(B) waive and release ONSL from any obligations that have arisen as a result of its

administration or the CVA, in relation to any existing breaches of, or defaults under, those

contracts which will continue beyond implementation of the CVA.

3.2 The unsecured part of certain claims (referred to in paragraph 3.1(A)(iii) above) will arise by

virtue of the release by those secured creditors of all their existing security following receipt by

them of an agreed portion of the Settlement Amount upon Completion, in repayment of part of

the outstanding debt owed to them. The remaining debt owed to them will constitute the

unsecured part of their claims against ONSL.

3.3 The balance of the Settlement Amount will be made available under the CVA for ONSL’s

creditors, and claims made by ONSL’s creditors will be limited in right of recovery to

distributions paid from such balance. Such distributions shall be made in full and final

settlement of those claims.

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PART VII

SOME QUESTIONS AND ANSWERS ON THE RIGHTS ISSUE

The questions and answers set out in this Part VII are intended to be generic guidance only and, as

such, you should also read Part VIII of this document for full details of what action you should take. Ifyou are in any doubt about the action to be taken, you are recommended to seek your own personal

financial advice immediately from your stockbroker, solicitor, accountant or other appropriate

independent financial adviser duly authorised under FSMA. The attention of Excluded Overseas

Shareholders is drawn to paragraph 7 of Part VIII of this document.

Ordinary Shares can be held in certificated form (that is, represented by a share certificate) or in

uncertificated form (that is, through CREST). Accordingly, these questions and answers are split into

four sections:

* Section 1 (‘‘General’’).

* Section 2 (‘‘Ordinary Shares in certificated form’’) answers questions you may have in respect ofthe procedures for Qualifying Shareholders who hold their Ordinary Shares in certificated form.

You should note that sections 1 and 4 may still apply to you.

* Section 3 (‘‘Ordinary Shares in CREST’’) answers questions you may have in respect of the

equivalent procedures for Qualifying Shareholders who hold their Ordinary Shares in CREST.

You should note that sections 1 and 4 may still apply to you.

* Section 4 (‘‘Further procedures for Ordinary Shares whether in certificated form or in CREST’’)

answers some detailed questions about your rights and the actions you may need to take and is

applicable to Ordinary Shares whether held in certificated form or in CREST.

1. GENERAL

1.1 What is a rights issue?

A rights issue is one way for companies to raise money. They do this by issuing shares for cash

and giving their existing shareholders a right of first refusal to buy these shares in proportion totheir existing shareholdings. For example, a 1 for 4 rights issue generally means that a

shareholder is entitled to buy one new share for every four currently held. This Rights Issue is 4

for 9, that is, an offer of 4 New Ordinary Shares for every 9 Existing Ordinary Shares held at

6.00 p.m. on 16 April 2009 (the Record Date for the Rights Issue).

New shares are typically offered in a rights issue at a discount to the current share price.

Because of this discount, the right to buy the new shares is potentially valuable. In this Rights

Issue, the Rights Issue Price represents a 49% discount to the Closing Price of 952 pence per

Ordinary Share on 24 March 2009 (the latest practicable date prior to the Announcement).

If you do not want to buy the New Ordinary Shares to which you are entitled, you can insteadsell your rights to those shares and receive the net proceeds in cash. This is referred to as

dealing ‘nil paid’.

1.2 What happens next?

Premier has called an Extraordinary General Meeting to be held at the offices of Deutsche

Bank, Winchester House, 1 Great Winchester Street, London EC2N 2DB on 20 April 2009 at

10.00 a.m. Please see the notice of Extraordinary General Meeting at the back of this document.

As you will see from the contents of the notice, the Directors are seeking shareholder approval

for the Acquisition and the Rights Issue.

You will find enclosed with this document a Form of Proxy for use in relation to theExtraordinary General Meeting. Whether or not you intend to be present in person at the

meeting, you are requested to complete, sign and return the Form of Proxy to Capita Registrars

(Proxies), PO Box 25, Beckenham, Kent BR3 4BR so as to arrive no later than 10.00 a.m. on

18 April 2009. You may also deliver the Form of Proxy by hand to Capita Registrars, The

Registry, 34 Beckenham Road, Beckenham, Kent BR3 4TU during usual business hours.

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2. ORDINARY SHARES IN CERTIFICATED FORM

2.1 What are my options and what should I do with the Provisional Allotment Letter?

The Provisional Allotment Letter shows:

In Box 1: how many Ordinary Shares you held at 6.00 p.m. on the Record Date;

In Box 2: how many New Ordinary Shares you are entitled to buy pursuant to the Rights Issue;

and

In Box 3: how much you need to pay if you want to take up your rights in full.

(A) If you want to take up your rights in full

If you want to take up in full your rights to subscribe for the New Ordinary Shares to

which you are entitled, all you need to do is send the Provisional Allotment Letter,

together with your cheque or banker’s draft for the full amount shown in Box 3, payable

to ‘Capita Registrars Limited re Premier Oil plc Rights Issue’ and crossed ‘A/C payee

only’, to the address shown on the front of the Provisional Allotment Letter so as toarrive before 11.00 a.m. on 6 May 2009. You can use the reply-paid envelope which will

be provided with the Provisional Allotment Letter within the United Kingdom. Paragraph

4 of Part VIII of this document has full instructions on how to accept and pay for your

New Ordinary Shares. These instructions are also set out in the Provisional Allotment

Letter. You will be required to pay in full for all the rights you take up. A definitive share

certificate will be sent to you for the New Ordinary Shares you acquire and it is expected

that such certificate(s) will be despatched to you by 14 May 2009.

You will only need your Provisional Allotment Letter to be returned to you if you want todeal in your Fully Paid Rights.

(B) If you do not want to take up your rights at all

If you do not want to take up any of your rights, you do not need to do anything. If you

do not return your Provisional Allotment Letter by 11.00 a.m. on 6 May 2009, the

Company has made arrangements under which the Underwriters will try to find investors

to take up your rights by 5.00 p.m. on 11 May 2009. If they do find investors and are

able to achieve a premium over the Rights Issue Price and the related expenses of

procuring those investors (including any applicable commission and VAT), you will be sent

a cheque for the amount of that aggregate premium above the Rights Issue Price less

related expenses (including any applicable commission and VAT), so long as the amount inquestion is at least £5.00. Cheques are expected to be despatched by 29 May 2009 and will

be sent to your address as it appears on the Company’s register of members (or to the first

named holder if you hold Ordinary Shares jointly).

(C) If you want to take up some but not all of your rights

If you want to take up some but not all of your rights and wish to sell some or all of

those you do not want to take up, you should first apply for split Provisional Allotment

Letters by completing Form X on page 2 of the Provisional Allotment Letter and then

return it by post or by hand (during normal business hours only) to Capita Registrars,

Corporate Action, The Registry, 34 Beckenham Road, Beckenham, Kent BR3 4TU so as

to be received by 3.00 p.m. on 1 May 2009, the last time and date for splitting Provisional

Allotment Letters, together with a covering letter stating the number of split ProvisionalAllotment Letters required and the number of Nil Paid Rights or Fully Paid Rights to be

comprised in each split Provisional Allotment Letter. You should then deliver the split

Provisional Allotment Letter representing the right to New Ordinary Shares you wish to

accept together with your cheque or banker’s draft to Capita Registrars, Corporate Action,

The Registry, 34 Beckenham Road, Beckenham, Kent BR3 4TU so as to be received by

11.00 a.m. on 6 May 2009, the last time and date for acceptance and payment in full.

Alternatively, if you want only to take up some of your rights (and do not wish to sellsome or all of those you do not want to take up), you should complete Form X on page

2 of the Provisional Allotment Letter and return it by post or by hand (during normal

business hours only) to Capita Registrars, Corporate Action, The Registry, 34 Beckenham

Road, Beckenham, Kent BR3 4TU together with a covering letter confirming the number

of New Ordinary Shares you wish to take up and a cheque or banker’s draft for the

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appropriate amount. In this case the Provisional Allotment Letter and cheque must be

received by Capita Registrars, Corporate Action, The Registry, 34 Beckenham Road,

Beckenham, Kent BR3 4TU by 11.00 a.m. on 6 May 2009, the last time and date for

payment. Further details relating to payment and acceptance are set out in paragraphs 4and 5 of Part VIII of this document.

2.2 How do I transfer my rights into the CREST system?

If you are a Qualifying Non-CREST Shareholder, but are also a CREST member and want

your New Ordinary Shares to be in uncertificated form, you should complete Form X and the

CREST Deposit Form (both on page 2 of the Provisional Allotment Letter), and ensure theyare delivered to the CREST Courier and Sorting Service to be received by 3.00 p.m. on 30 April

2009 at the latest. CREST sponsored members should arrange for their CREST sponsors to do

this.

If you have transferred your rights into CREST, you should refer to paragraph 5 of Part VIII

(Terms and Conditions of the Rights Issue) of this document for details on how to pay for the

new Ordinary Shares.

2.3 How do I know if I am eligible to participate in the Rights Issue?

If you receive a Provisional Allotment Letter then you should be eligible to participate in the

Rights Issue (as long as you have not sold all of your Ordinary Shares before 21 April 2009, in

which case you will need to follow the instructions on the front page of this document).

However, if you receive a Provisional Allotment Letter and you have a registered address in, or

are a resident, citizen or national of, a country other than the United Kingdom you must satisfy

yourself as to the full observance of the applicable laws of such territory including obtainingany requisite governmental or other consents, observing any other requisite formalities and

paying any issue, transfer or other taxes due in such territories. Receipt of this document or a

Provisional Allotment Letter does not constitute an offer in those jurisdictions in which it would

be illegal to make an offer. Excluded Overseas Shareholders are not permitted to participate in

the Rights Issue, subject to certain exceptions.

If you do not receive a Provisional Allotment Letter, and you do not hold your shares in

CREST, this probably means you are not eligible to acquire any New Ordinary Shares.However, see question 2.4 below.

2.4 What if I have not received a Provisional Allotment Letter?

If you do not receive a Provisional Allotment Letter and you do not hold your Ordinary Shares

in CREST, this probably means that you are not eligible to participate in the Rights Issue.

Some Qualifying Shareholders, however, will not receive a Provisional Allotment Letter but may

still be able to participate in the Rights Issue, namely:

(A) Qualifying CREST Shareholders (please see section 3 below); and

(B) Qualifying Non-CREST Shareholders who bought Ordinary Shares before 21 April 2009

but were not registered as the holders of those Ordinary Shares at the close of business on

16 April 2009 (see question 2.5 below).

If you are unsure as to whether you should receive a Provisional Allotment Letter please

contact Capita Registrars on 0871 664 0321 or, if telephoning from outside the UK, on +44 20

8639 3399. Calls to the 0871 664 0321 number are charged at 10 pence per minute (includingVAT) plus any of your service provider’s network extras. Calls to the +44 20 8639 3339 number

from outside the UK are charged at applicable international rates. Different charges may apply

to calls made from mobile telephones and calls may be recorded and monitored randomly for

security and training purposes. Capita Registrars cannot provide advice on the merits of the

Rights Issue nor give any financial, legal or tax advice.

2.5 If I buy Ordinary Shares before 21 April 2009 (the date the New Ordinary Shares start trading ex-rights) will I be eligible to participate in the Rights Issue?

If you buy Ordinary Shares before 21 April 2009 (the date the New Ordinary Shares start

trading ex-rights (that is, without the right to participate in the Rights Issue, referred to as the

‘‘ex-rights’’ date)) but are not registered as the holder of those Ordinary Shares on 16 April

72


2009 (the Record Date) you may still be eligible to participate in the Rights Issue. If you are in

any doubt, please consult your stockbroker, bank or other appropriate financial adviser, or

whoever arranged your share purchase, to ensure you claim your entitlement.

You will not be entitled to Nil Paid Rights in respect of any Ordinary Shares acquired on orafter 21 April 2009 (the ‘‘ex-rights’’ date).

2.6 What should I do if I sell or have sold or transferred all or some of the Ordinary Shares shown in Box 1of the Provisional Allotment Letter before the ‘‘ex-rights’’ date?

If you sell or have sold or transferred all of your Ordinary Shares before the ‘‘ex-rights’’ date,

you should complete Form X on page 2 of the Provisional Allotment Letter and send the entireProvisional Allotment Letter together with this document to the stockbroker, bank or other

appropriate financial adviser through whom you made the sale or transfer.

If you sell or transfer only some of your holding of Ordinary Shares before the ‘‘ex-rights’’ date,

you will need to complete Form X on page 2 of the Provisional Allotment Letter and consult

the stockbroker, bank or other appropriate financial adviser through whom you made the sale

or transfer before taking any action with regard to the balance of rights due to you.

2.7 How many New Ordinary Shares will I be entitled to acquire?

Box 2 on page 1 of the Provisional Allotment Letter shows the number of New Ordinary Shares

you will be entitled to buy if you are a Qualifying Non-CREST Shareholder. You will be

entitled to 4 New Ordinary Shares for every 9 Existing Ordinary Shares held on 16 April 2009,

the Record Date. All Qualifying Non-CREST Shareholders (other than, subject to certain

exceptions, certain Excluded Overseas Shareholders) will be sent a Provisional Allotment Letter

after the EGM has approved the resolutions.

2.8 What should I do if I think my holding of Ordinary Shares (as shown in Box 1 on page 1 of theProvisional Allotment Letter) is incorrect?

If you are concerned about the figure in Box 1, please call Capita Registrars on 0871 664 0321

or, if telephoning from outside the UK, on +44 20 8639 3399. Calls to the 0871 664 0321

number are charged at 10 pence per minute (including VAT) plus any of your service provider’s

network extras. Calls to the +44 20 8639 3399 number from outside the UK are charged atapplicable international rates. Different charges may apply to calls made from mobile telephones

and calls may be recorded and monitored randomly for security and training purposes. Capita

Registrars cannot provide advice on the merits of the Rights Issue nor give any financial, legal

or tax advice.

2.9 If I take up my rights, when will I receive my new share certificate?

If you take up your rights under the Rights Issue, share certificates for the New Ordinary

Shares are expected to be posted by 14 May 2009.

3. ORDINARY SHARES IN CREST

3.1 How do I know if I am eligible to participate in the Rights Issue?

If you are a Qualifying CREST Shareholder (save as mentioned below), and on the assumption

that the Rights Issue proceeds as planned, your CREST stock account will be credited with

your entitlement to Nil Paid Rights on 21 April 2009. The stock account to be credited will bethe account under the participant ID and member account ID that apply to your Ordinary

Shares on the Record Date. The Nil Paid Rights and the Fully Paid Rights are expected to be

enabled after 8.00 a.m. on 21 April 2009. If you are a CREST sponsored member, you should

consult your CREST sponsor if you wish to check that your account has been credited with

your entitlement to Nil Paid Rights. The CREST stock accounts of certain Excluded Overseas

Shareholders will not be credited with Nil Paid Rights. Excluded Overseas Shareholders should

refer to paragraph 7 of Part VIII of this document.

3.2 How do I take up my rights using CREST?

If you are a Qualifying CREST Shareholder, you should refer to paragraph 5 of Part VIII of

this document for details on how to take up and pay for your rights.

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If you are a CREST member you should ensure that a Many-to-Many (‘‘MTM’’) instruction

has been inputted and has settled by 11.00 a.m. on 6 May 2009 in order to make a valid

acceptance. If your Ordinary Shares are held by a nominee or you are a CREST sponsored

member you should speak directly to the agent who looks after your stock or your CRESTsponsor (as appropriate) who will be able to help you. If you have further questions,

particularly of a technical nature regarding acceptance through CREST, you should call the

CREST Service Desk on 08459 645 648 (+44 8459 645 648 if you are calling from outside the

United Kingdom).

3.3 If I buy Ordinary Shares before 21 April 2009 (the date that the Ordinary Shares start trading ex-rights) will I be eligible to participate in the Rights Issue?

If you buy Ordinary Shares before 21 April 2009, but are not registered as the holder of those

Ordinary Shares at the Record Date for the Rights Issue (6.00 p.m. on 16 April 2009), you may

still be eligible to participate in the Rights Issue. Euroclear UK will raise claims in the normal

manner in respect of your purchase and your Nil Paid Rights will be credited to your stock

account(s) on settlement of those claims.

You will not be entitled to Nil Paid Rights in respect of any further Ordinary Shares acquiredon or after 21 April 2009, the ‘‘ex-rights’’ date.

3.4 What should I do if I sell or transfer all or some of my Ordinary Shares before 21 April 2009 (the ‘‘ex-rights’’ date)?

You do not have to take any action except, where you sell or transfer all of your Ordinary

Shares before 21 April 2009 (being the ‘‘ex-rights’’ date), to send this document to the purchaseror transferee or to the stockbroker, bank or other financial adviser through whom you made the

sale or transfer. A claim transaction in respect of that sale or transfer will automatically be

generated by Euroclear UK which, on settlement, will transfer the appropriate number of Nil

Paid Rights to the purchaser or transferee.

3.5 How many New Ordinary Shares am I entitled to acquire?

Your stock account will be credited with Nil Paid Rights in respect of the number of NewOrdinary Shares which you are entitled to acquire. You will be entitled to acquire 4 New

Ordinary Shares for every 9 Ordinary Shares you hold on 16 April 2009, the Record Date. You

can also view the claim transactions in respect of purchases/sales effected after this date, but

before the ex-rights date. If you are a CREST sponsored member, you should consult your

CREST sponsor.

3.6 What should I do if I think my holding of Ordinary Shares is incorrect?

If you buy or sell Ordinary Shares between the date of this document and 16 April 2009, your

transaction may not be entered on the register of members before the Record Date and you

should consult the stockbroker, bank or other appropriate financial adviser through whom you

made the sale, purchase or transfer before taking any other action.

If you are concerned about the number of Nil Paid Rights with which your stock account has

been credited, please call Capita Registrars on 0871 664 0321 or, if telephoning from outside theUK, on +44 20 8639 3399. Calls to the 0871 664 0321 number are charged at 10 pence per

minute (including VAT) plus any of your service provider’s network extras. Calls to the +44 20

8639 3399 number from outside the UK are charged at applicable international rates. Different

charges may apply to calls made from mobile telephones and calls may be recorded and

monitored randomly for security and training purposes. Capital Registrars cannot provide advice

on the merits of the Rights Issue nor give any financial, legal or tax advice.

3.7 If I take up my rights, when will New Ordinary Shares be credited to my CREST stock account(s)?

If you take up your rights under the Rights Issue, it is expected that New Ordinary Shares will

be credited to the CREST stock account in which you hold your Fully Paid Rights on 7 May

2009.

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4. FURTHER PROCEDURES FOR ORDINARY SHARES WHETHER IN CERTIFICATED

FORM OR IN CREST

4.1 What happens if the number of Ordinary Shares I hold is not exactly divisible? Am I entitled to fractionsof the New Ordinary Shares?

Your entitlement is calculated by dividing your holding of Ordinary Shares by 9 and multiplying

by 4. If the result is not a whole number, your entitlement will be rounded down to the nearest

whole number of New Ordinary Shares, meaning that you will not receive a New Ordinary

Share in respect of the fractional entitlement. A Provisional Allotment Letter will not be sent to

a Shareholder holding fewer than three Ordinary Shares on the Record Date. The NewOrdinary Shares representing the aggregated fractional entitlements of all Shareholders will, if

possible, be sold in the market for the benefit of the Company, save that you will receive any

proceeds in respect of a fractional entitlement with a value of £5 or more.

4.2 Will I be taxed if I take up or sell my rights or if my rights are sold on my behalf?

If you are resident in the United Kingdom for tax purposes, you will not have to pay UK tax

when you take up your right to receive New Ordinary Shares, although the Rights Issue will

affect the amount of UK tax you may pay when you sell your Ordinary Shares. However, you

may be subject to capital gains tax on any proceeds you receive from the sale of your rights.

Further information for Qualifying Shareholders who are resident in the United Kingdom for

tax purposes is contained in Part XV of this document. Qualifying Shareholders who are in any

doubt as to their tax position, or who are subject to tax in any jurisdiction other than the United

Kingdom, should consult their professional advisers as soon as possible.

4.3 I understand that there is a period when there is trading in the Nil Paid Rights. What does this mean?

If you do not want to buy the New Ordinary Shares being offered to you under the Rights

Issue, you can instead sell or transfer your rights (called ‘‘Nil Paid Rights’’) to those NewOrdinary Shares and receive the net proceeds of the sale or transfer in cash. This is referred to

as dealing ‘‘nil paid’’.

If you wish to sell or transfer all or some of your Nil Paid Rights, and you hold your Ordinary

Shares in certificated form, you will need to complete Form X, the form of renunciation, on

page 2 of the Provisional Allotment Letter and send it to the stockbroker, bank or other agent

through or by whom the sale or transfer was effected, to be forwarded to the purchaser ortransferee.

If you buy Nil Paid Rights, you are buying an entitlement to take up the New Ordinary Shares,

subject to your paying for them in accordance with the terms of the Rights Issue. Any seller of

Nil Paid Rights who holds his Ordinary Shares in certificated form will need to forward to you

his Provisional Allotment Letter (with Form X completed) for you to complete and return, with

your cheque, by 11.00 a.m. on 6 May 2009, in accordance with the instructions on the

Provisional Allotment Letter.

If you are a CREST member or CREST sponsored member and have received a Provisional

Allotment Letter and you wish to hold your Nil Paid Rights in uncertificated form in CREST

then you should send the Provisional Allotment Letter with Form X and the CREST Deposit

Form on page 2 of the Provisional Allotment Letter completed (in the case of a CREST

member) to the CREST Courier and Sorting Service or (in the case of a CREST sponsored

member) to your CREST sponsor by 3.00 p.m. on 30 April 2009 at the latest.

Qualifying CREST Shareholders and, subject to dematerialisation of their Nil Paid Rights as set

out in the Provisional Allotment Letter, Qualifying Non-CREST Shareholders who are CREST

members or CREST sponsored members can transfer Nil Paid Rights, in whole or in part, by

means of CREST in the same manner as any other security that is admitted to CREST. Please

consult your CREST sponsor or stockbroker, bank or other appropriate financial adviser, or

whoever arranged your share purchase, for details.

4.4 What if I want to sell the New Ordinary Shares I have paid for?

If you are a Qualifying Non-CREST Shareholder, provided the New Ordinary Shares have been

paid for and you have requested the return of the receipted Provisional Allotment Letter, you

can transfer the Fully Paid Rights by completing Form X, the form of renunciation, on page 2

of the receipted Provisional Allotment Letter in accordance with the instructions set out on

pages 3 and 4 of the Provisional Allotment Letter until 11.00 a.m. on 6 May 2009.

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After that date, you will be able to sell your New Ordinary Shares in the normal way. However,

the share certificate relating to your New Ordinary Shares is expected to be despatched to you

only by 14 May 2009. Pending despatch of such share certificate, valid instruments of transfer

will be certified by Capita Registrars against the register.

If you hold your New Ordinary Shares and/or rights in CREST, you may transfer them in the

same manner as any other security that is admitted to CREST. Please consult your stockbroker,bank or other appropriate financial adviser, or whoever arranged your share purchase, for

details.

4.5 Do I need to comply with the Money Laundering Regulations (as set out in paragraph 4.4 of Part VIII ofthis document)?

If you are a Qualifying Non-CREST Shareholder, you do not need to follow these procedures if

the value of the New Ordinary Shares you are subscribing for is less than c15,000

(approximately £13,900) or if you pay for them by a cheque drawn on an account in your own

name and that account is one which is held with an EU or UK regulated bank or building

society. If you are a Qualifying CREST Shareholder, you will not generally need to comply withthe Money Laundering Regulations unless you apply to take up all or some of your entitlement

to Nil Paid Rights as agent for one or more persons and you are not an EU or UK regulated

financial institution.

Qualifying Non-CREST Shareholders and Qualifying CREST Shareholders should refer to

paragraphs 4.4 and 5.3 respectively of Part VIII of this document for a fuller description of the

requirements of the Money Laundering Regulations.

4.6 What if I am entitled to Ordinary Shares under a Premier Share Option Scheme?

Participants in Premier Share Option Schemes will be advised separately of adjustments (if any)

to their rights or as to any entitlement to participate in the Rights Issue.

4.7 What should I do if I live outside the United Kingdom?

Your ability to take up rights to New Ordinary Shares may be affected by the laws of thecountry in which you live and you should take professional advice about any formalities you

need to observe. Shareholders resident outside the United Kingdom should refer to paragraphs 7

and 8 of Part VIII of this document.

4.8 What do I do if I have any further queries about the Rights Issue or the action I should take?

If you have any other questions, please telephone Capita Registrars on 0871 664 0321 (calls cost

10 pence per minute) (+44 20 8639 3399) if you are calling from outside the United Kingdom).

This helpline is available from 9.00 a.m. to 5.00 p.m. Monday to Friday. Please note that calls

may be monitored or recorded. For legal reasons, the Shareholder Helpline will only be

available to provide you with information contained in this document (other than informationrelating to the Company’s register of members) and as such, will be unable to give advice on

the merits of the Rights Issue or to provide financial advice. Shareholder Helpline staff can

explain the options available to you, which forms you need to fill in and how to fill them in

correctly.

Your attention is drawn to the further terms and conditions of the Rights Issue in Part VIII of this

document and (in the case of Qualifying Non-CREST Shareholders) in the Provisional Allotment Letter.

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PART VIII

TERMS AND CONDITIONS OF THE RIGHTS ISSUE

1. Details of the Rights Issue

The Company proposes to raise approximately £145 million, net of expenses, by way of a Rights

Issue.

The Rights Issue Price represents a discount of approximately 49% to the Closing Price for an

Existing Ordinary Share of 952 pence on 24 March 2009 (the latest practicable date prior to the

Announcement).

The Rights Issue is not conditional on Completion of the Acquisition. In the event that the Rights

Issue proceeds but Completion does not take place, the Directors’ current intention is that the net

proceeds of the Rights Issue will be invested in cash or money-market funds on a short-term basis

while the Directors consider how best to return the proceeds of the Rights Issue (after the deduction

of certain acquisition and transaction costs) to Shareholders. However if, before Admission, theAcquisition Agreements have both terminated or the Acquisition ceases to be capable of Completion,

the Rights Issue will not proceed.

2. Terms and Conditions

Subject to the fulfilment of the conditions set out below, the New Ordinary Shares will be offered for

subcription by way of rights to Qualifying Shareholders (other than, subject to certain exceptions,

Excluded Overseas Shareholders) on the following basis and otherwise on the terms and conditions

set out in this document (and, in the case of Qualifying Non-CREST Shareholders, the Provisional

Allotment Letter):

4 New Ordinary Shares at 485 pence per New Ordinary Share

for every 9 Existing Ordinary Shares

held and registered in their name at 6.00 p.m. on the Record Date and so in proportion to any other

number of Existing Ordinary Shares then held.

Holdings of Existing Ordinary Shares in certificated and uncertificated form will be treated as

separate holdings for the purpose of calculating entitlements under the Rights Issue. New Ordinary

Shares representing fractional entitlements will not be allotted to Qualifying Shareholders and, where

necessary, entitlements to New Ordinary Shares will be rounded down to the nearest whole number.

New Ordinary Shares representing fractional entitlements will not be allotted to Qualifying

Shareholders but will be aggregated and, if possible, sold in the market. The net proceeds of such

sales (after deduction of expenses) will be aggregated and will ultimately accrue for the benefit of the

Company, save that Qualifying Shareholders will only receive any proceeds in respect of a fractionalentitlement with a value of £5 or more. Accordingly, Qualifying Shareholders with fewer than three

Existing Ordinary Shares will not be entitled to any New Ordinary Shares.

The attention of Qualifying Shareholders and any person (including, without limitation, custodians,

nominees and trustees) who has a contractual or other legal obligation to forward this document intoa jurisdiction other than the UK is drawn to paragraphs 7 and 8 of this Part VIII. In particular,

subject to the provisions of paragraph 7 of this Part VIII, Qualifying Shareholders with registered

addresses in the US or any of the Excluded Territories will not be sent Provisional Allotment Letters

and will not have their CREST stock accounts credited with Nil Paid Rights.

The New Ordinary Shares will, when issued and fully paid, rank pari passu in all respects with the

Existing Ordinary Shares, including the right to all future dividends or other distributions made, paid

or declared after the date of their issue.

Application has been made to the UK Listing Authority for the New Ordinary Shares to be admittedto the Official List and to the London Stock Exchange for the New Ordinary Shares to be admitted

to trading on its main market for listed securities. It is expected that Admission will become effective

and that dealings in the New Ordinary Shares will commence on the London Stock Exchange, nil

paid, at 8.00 a.m. on 21 April 2009 (whereupon an announcement will be made by the Company to a

Regulatory Information Service).

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The Rights Issue has been fully underwritten by the Underwriters up to a number of 35,276,566

Rights Issue Shares and is conditional upon:

(a) both the Acquisition Agreements not having been terminated, and the Acquisition not having

ceased to be capable of Completion in accordance with the terms of the Acquisition Agreements

prior to Admission;

(b) the Resolutions being passed at the Extraordinary General Meeting;


and/or date as the Company and the Underwriters agree, being not later than 8.00 a.m. on 6May 2009); and

(d) the Underwriting Agreement otherwise becoming unconditional in all respects (other thanconditions relating to Admission) and not having been terminated in accordance with its terms

prior to Admission. After Admission, however, the underwriting arrangements will not be

subject to any right of termination (including in respect of any statutory withdrawal rights).

The Underwriters may arrange sub-underwriting for some, all or none of the New Ordinary Shares

which they have underwritten. A summary of the principal terms of the Underwriting Agreement is

set out in paragraph 12(e) of Part XVI of this document.

Subject, inter alia, to the passing of the Resolutions, it is intended that Provisional Allotment Letters

in respect of the New Ordinary Shares will be despatched on 20 April 2009 to Qualifying Non-

CREST Shareholders at their own risk (other than, subject to certain exceptions, such Qualifying

Non-CREST Shareholders with registered addresses in the US or any of the Excluded Territories).

Provisional Allotment Letters will not be sent to Shareholders who hold less than three ExistingOrdinary Shares. Provisional Allotment Letters constitute temporary documents of title.

The Existing Ordinary Shares are already admitted to CREST. No further application for admission

to CREST is required for the New Ordinary Shares and all of the New Ordinary Shares when issued

and fully paid may be held and transferred by means of CREST. Applications have been made for

the Nil Paid Rights and the Fully Paid Rights to be admitted to CREST. Euroclear UK requires the

Company to confirm to it that certain conditions are satisfied before Euroclear UK will admit any

security to CREST. As soon as practicable after Admission, the Company will confirm this to

Euroclear UK. It is expected that these conditions will be satisfied on Admission.

Subject to the conditions above being satisfied and save as provided in this Part VIII, it is expected

that:

(i) the Registrar will instruct Euroclear UK to credit the appropriate stock accounts of Qualifying

CREST Shareholders (other than, subject to certain exceptions, such Qualifying CREST

Shareholders with registered addresses in the US or any of the Excluded Territories) with suchShareholders’ entitlements to Nil Paid Rights, with effect from 8.00 a.m. on 21 April 2009;

(ii) the Nil Paid Rights and the Fully Paid Rights will be enabled for settlement by Euroclear UK

on 21 April 2009, as soon as practicable after the Company has confirmed to Euroclear UK

that all the conditions for admission of such rights to CREST have been satisfied;

(iii) New Ordinary Shares will be credited to the appropriate stock accounts of relevant Qualifying

CREST Shareholders (or their renouncees) who validly take up their rights, by 8.00 a.m. on

7 May 2009; and

(iv) share certificates for the New Ordinary Shares will be despatched to relevant Qualifying Non-

CREST Shareholders (or their renouncees) who validly take up their rights, by 14 May 2009 at

their own risk.

Shareholders taking up their rights by completing a Provisional Allotment Letter or by sending a

MTM instruction to Euroclear UK will be deemed to have given the representations and warranties

set out in paragraph 8 below of this Part VIII, unless such requirement is waived by the Company.

All documents and cheques posted to or by Qualifying Shareholders and/or their transferees or

renouncees (or their agents, as appropriate) will be posted at their own risk.

The attention of Excluded Overseas Shareholders is drawn to paragraph 7 of this Part VIII.

3. Action to be taken

The action to be taken in respect of New Ordinary Shares depends on whether, at the relevant time,

the Nil Paid Rights or Fully Paid Rights in respect of which action is to be taken are in certificated

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form (that is, are represented by Provisional Allotment Letters) or are in uncertificated form (that is,

are in CREST).

If you are a Qualifying Non-CREST Shareholder and do not have a registered address in the US or

any of the Excluded Territories, please refer to paragraphs 4 and 6 to 13 (inclusive) of this Part VIII.

If you hold your Existing Ordinary Shares in CREST and do not have a registered address in the US

or any of the Excluded Territories, please refer to paragraphs 5 to 13 (inclusive) of this Part VIII and

to the CREST Manual for further information on the CREST procedures referred to above.

CREST sponsored members should refer to their CREST sponsors, as only their CREST sponsors

will be able to take the necessary actions specified below to take up the entitlements or otherwise to

deal with the Nil Paid Rights or Fully Paid Rights of CREST sponsored members.

4. Action to be taken in relation to Nil Paid Rights represented by Provisional Allotment Letters

4.1 General

The Company intends that the Provisional Allotment Letters will be despatched to Qualifying Non-

CREST Shareholders (other than Qualifying Non-CREST Shareholders with registered addresses in

the US or any of the Excluded Territories) on 20 April 2009. The Provisional Allotment Letter,which constitutes a temporary document of title, will set out:

(A) the holding of Existing Ordinary Shares on which a Qualifying Non-CREST Shareholder’s

entitlement to New Ordinary Shares has been based;

(B) the aggregate number of New Ordinary Shares provisionally allotted to such Qualifying Non-

CREST Shareholder;

(C) the procedures to be followed if a Qualifying Non-CREST Shareholder wishes to dispose of all

or part of his entitlement or to convert all or part of his entitlement into uncertificated form;

and

(D) instructions regarding acceptance and payment, consolidation, splitting and registration of

renunciation.

On the basis that Provisional Allotment Letters are posted on 20 April 2009 and that dealings

commence on 21 April 2009, the latest time and date for acceptance and payment in full will be

11.00 a.m. on 6 May 2009.

If the Rights Issue is delayed so that Provisional Allotment Letters cannot be despatched on 20 April

2009, the expected timetable at the front of this document will be adjusted accordingly and the

revised dates will be set out in the Provisional Allotment Letters. References to dates and times in

this document should be read as subject to any such adjustment.

4.2 Procedure for acceptance and payment

(A) Qualifying Non-CREST Shareholders who wish to accept in full

Holders of Provisional Allotment Letters who wish to take up all of their Nil Paid Rights must

return the Provisional Allotment Letter in accordance with the instructions thereon, together with acheque or banker’s draft, made payable to ‘Capita Registrars Limited re Premier Oil plc Rights Issue’

and crossed ‘A/C payee only’, for the full amount payable on acceptance, by post or by hand (during

normal business hours only) to Capita Registrars, Corporate Action, The Registry, 34 Beckenham

Road, Beckenham, Kent BR3 4TU, so as to be received as soon as possible and, in any event, not

later than 11.00 a.m. on 6 May 2009. A reply-paid envelope is enclosed for use within the UK only.

If you post your Provisional Allotment Letter, it is recommended that you allow sufficient time for

delivery.

(B) Qualifying Non-CREST Shareholders who wish to accept in part

Holders of Provisional Allotment Letters who wish to take up some but not all of their rights should

refer to paragraph 4.7 of this Part VIII.

(C) Discretion as to validity of acceptances

If payment is not received in full by 11.00 a.m. on 6 May 2009, or if payment is rejected by 7.00 a.m.on 7 May 2009, the provisional allotment will be deemed to have been declined and will lapse.

However, the Company and the Underwriters may, but shall not be obliged to, treat as valid later

acceptances including (a) Provisional Allotment Letters and accompanying remittances that are

received through the post not later than 10.00 a.m. on 7 May 2009 (the cover bearing a legible

postmark not later than 11.00 a.m. on 6 May 2009); and (b) acceptances in respect of which a

79


remittance is received prior to 11.00 a.m. on 6 May 2009 from an authorised person (as defined in

Section 31(2) of FSMA) specifying the number of New Ordinary Shares to be acquired and

undertaking to lodge the relevant Provisional Allotment Letter, duly completed, by 10.00 a.m. on

7 May 2009 and such Provisional Allotment Letter is lodged by that time.

The Company and the Underwriters may also (in their absolute discretion) treat a ProvisionalAllotment Letter as valid and binding on the person(s) by whom or on whose behalf it is lodged even

if it is not completed in accordance with the relevant instructions or is not accompanied by a valid

power of attorney where required.

4.3 Payments

All payments must be made by cheque or banker’s draft in Pounds Sterling payable to ‘CapitaRegistrars Limited re Premier Oil plc Rights Issue’ and crossed ‘A/C payee only’. Third party cheques

will not be accepted. Cheques or banker’s drafts must be drawn on an account at a bank or building

society or a branch of a bank or building society which must be in the UK, the Channel Islands or

the Isle of Man and which is either a settlement member of Cheque & Credit Clearing Limited or the

CHAPS Clearing Company Limited or which has arranged for its cheques or banker’s drafts to be

cleared through the facilities provided by either of those companies. Such cheques and banker’s drafts

must bear the appropriate sorting code number in the top right-hand corner.

Cheques and banker’s drafts will be presented for payment on receipt. No interest will be allowed on

payments made before they are due and any interest on such payments ultimately will accrue for thebenefit of the Company. It is a term of the Rights Issue that cheques shall be honoured on first

presentation and the Company and the Underwriters may elect to treat as invalid any acceptances in

respect of which cheques are not so honoured. Acceptances where cheques have been rejected by

7.00 a.m. on 7 May 2009 will be treated as invalid unless the Company and the Underwriters both

determine otherwise. Return of the Provisional Allotment Letter with a remittance in the form of a

cheque will constitute a warranty that the cheque will be honoured on first presentation.

If New Ordinary Shares have already been allotted to a Qualifying Non-CREST Shareholder prior to

any payment not being so honoured or such acceptances being treated as invalid, the Company and

the Underwriters may (in their absolute discretion as to manner, timing and terms) makearrangements for the sale of such shares on behalf of such Qualifying Non-CREST Shareholder and

hold the proceeds of sale (net of the Company’s reasonable estimate of any loss that it has suffered

as a result of the acceptance being treated as invalid and of the expenses of sale including, without

limitation, any stamp duty or SDRT payable on the transfer of such shares, and of all amounts

payable by such Qualifying Non-CREST Shareholder pursuant to the provisions of this Part VIII in

respect of the acquisition of such shares) on behalf of such Qualifying Non-CREST Shareholder.

Neither the Company nor the Underwriters nor any other person shall be responsible for, or have

any liability for, any loss, expenses or damage suffered by any Qualifying Non-CREST Shareholderas a result.

All enquires in connection with the Provisional Allotment Letter should be addressed to the Receiving

Agent on 0871 664 0321 (or +44 020 8639 3399 if calling from outside the UK). Calls to the 0871

664 0321 number cost 10 pence per minute (including VAT) plus your service provider’s network

extras. Different charges may apply to calls from mobile telephones and calls may be recorded or

randomly monitored for security and training purposes.

4.4 Money Laundering Regulations

To ensure compliance with the Money Laundering Regulations, the Receiving Agent may require, at

its absolute discretion, verification of the identity of the beneficial owner by whom or on whose

behalf the Provisional Allotment Letter is lodged with payment (which requirements are referred to

below as the ‘‘verification of identity requirements’’). If an application is made by a UK regulated

broker or intermediary acting as agent and which is itself subject to the Money Laundering

Regulations, any verification of identity requirements are the responsibility of such broker or

intermediary and not of the Receiving Agent. In such case, the lodging agent’s stamp should be

inserted on the Provisional Allotment Letter.

The person lodging the Provisional Allotment Letter with payment (the ‘‘applicant’’), including anyperson who appears to the Receiving Agent to be acting on behalf of some other person, shall

thereby be deemed to agree to provide the Receiving Agent with such information and other evidence

as the Receiving Agent may require to satisfy the verification of identity requirements. Submission of

a Provisional Allotment Letter shall constitute a warranty that the Money Laundering Regulations

will not be breached by the acceptance of remittance and an undertaking by the applicant to provide

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promptly to the Receiving Agent such information as may be specified by the Receiving Agent as

being required for the purpose of the Money Laundering Regulations.

If the Receiving Agent determines that the verification of identity requirements apply to any applicant

or application, the relevant New Ordinary Shares (notwithstanding any other term of the Rights

Issue) will not be issued to the relevant applicant unless and until the verification of identity

requirements have been satisfied in respect of that applicant or application. The Receiving Agent is

entitled, in its absolute discretion, to determine whether the verification of identity requirements apply

to any applicant or application and whether such requirements have been satisfied, and neither the

Receiving Agent, the Company nor the Underwriters will be liable to any person for any loss or

damage suffered or incurred (or alleged), directly or indirectly, as a result of the exercise of suchdiscretion.

If the verification of identity requirements apply, failure to provide the necessary evidence of identity

within a reasonable time may result in delays and potential rejection of an application. If, within a

reasonable period of time following a request for verification of identity, the Receiving Agent has not

received evidence satisfactory to it as aforesaid, the Company may, in its absolute discretion, treat the

relevant application as invalid, in which event the application moneys will be returned (at theapplicant’s risk) without interest to the account of the bank or building society on which the relevant

cheque or banker’s draft was drawn.

The verification of identity requirements will not usually apply if:

(A) the applicant is a regulated UK broker or intermediary acting as agent and is itself subject to

the Money Laundering Regulations; or

(B) the applicant is an organisation required to comply with the EU Money Laundering Directive

(No. 91/308/EEC) as amended by Directive 2001/97/EC and 2005/60/EC; or

(C) the applicant is a company whose securities are listed on a regulated market subject to specified

disclosure obligations; or

(D) the applicant (not being an applicant who delivers his/her application in person) makes payment

through an account in the name of such applicant with a credit institution which is subject to

the Money Laundering Regulations or with a credit institution situated in a non-EEA state

which imposes requirements equivalent to those laid down in that directive; or

(E) the aggregate subscription price for the relevant New Ordinary Shares is less than c15,000 (orits Pounds Sterling equivalent).

Where the verification of identity requirements apply, please note the following as this will assist in

satisfying the requirements. Satisfaction of these requirements may be facilitated in the following

ways:

(i) if payment is made by cheque or banker’s draft in Pounds Sterling drawn on a branch of abank or building society in the UK and bears a UK bank sort code number in the top right

hand corner, the following applies. Cheques, which must be drawn on the personal account of

the individual investor where they have sole or joint title to the funds, should be made payable

to ‘Capita Registrars Limited re Premier Oil plc Rights Issue’ and crossed ‘A/C payee only’.

Third party cheques will not be accepted except for building society cheques or banker’s drafts

where the building society or bank has confirmed the name of the account holder by stamping

or endorsing the building society cheque/banker’s draft to such effect. The account name should

be the same as that shown on the application; or

(ii) if the Provisional Allotment Letter is lodged with payment by an agent which is an organisation

of the kind referred to in sub-paragraph (B) above or which is subject to anti-money laundering

regulations in a country which is a member of the Financial Action Task Force (the non-EU

members of which are Argentina, Australia, Brazil, Canada, members of the Gulf Co-operation

Council (being Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and the United Arab Emirates),

Hong Kong, Iceland, Japan, Mexico, New Zealand, Norway, the Russian Federation, Singapore,South Africa, Switzerland, Turkey and the US), the agent should provide written confirmation

that it has that status with the Provisional Allotment Letter(s) and written assurances that it has

obtained and recorded evidence of the identity of the person for whom it acts and that it will

on demand make such evidence available to the Receiving Agent and/or any relevant regulatory

or investigatory authority; or

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(iii) if a Provisional Allotment Letter is lodged by hand by the applicant in person, he should ensure

that he has with him evidence of identity bearing his photograph (for example, his passport) and

evidence of his address.

To confirm the acceptability of any written assurance referred to in paragraph (ii) above, or in any other

case, the applicant should contact the Receiving Agent. The telephone number of the Receiving Agent is

0871 664 0321, or, if calling from outside the UK, +44 20 8639 3399. Calls to the 0871 664 0321

number cost 10 pence per minute (including VAT) plus your service provider’s network extras. Differentcharges may apply to calls from mobile telephones and calls may be recorded or randomly monitored for

security and training purposes.

4.5 Dealings in Nil Paid rights

Subject to the fulfilment of the conditions set out in paragraph 2 above and the Resolutions being

passed at the Extraordinary General Meeting, dealings on the London Stock Exchange in the Nil

Paid Rights are expected to commence at 8.00 a.m. on 21 April 2009. A transfer of Nil Paid Rights

can be made by renunciation of the Provisional Allotment Letter in accordance with the instructions

printed on it and delivery of the Provisional Allotment Letter to the transferee, up to the latest time

for acceptance and payment in full stated in the Provisional Allotment Letter, which is 11.00 a.m. on6 May 2009.

4.6 Dealings in Fully Paid Rights

After acceptance of the provisional allotment and payment in full in accordance with the provisions

set out in this document and (in the case of Qualifying Non-CREST Shareholders) in the Provisional

Allotment Letter, the Fully Paid Rights may be transferred by renunciation of the relevant

Provisional Allotment Letter and lodging of the same, by post or by hand (during normal business

hours only), with Capita Registrars so as to be received not later than 11.00 a.m. on 6 May 2009. To

do this, Qualifying Non-CREST Shareholders will need to have their fully paid Provisional Allotment

Letter returned to them after their acceptance has been effected by the Receiving Agent. However,

fully paid Provisional Allotment Letters will not be returned to Qualifying Non-CREST Shareholdersunless their return is requested by ticking the appropriate box on the Provisional Allotment Letter.

From 7 May 2009, the New Ordinary Shares will be registered and transferable in the usual common

form or, if they have been issued in or converted into uncertificated form, in electronic form underthe CREST system.

4.7 Renunciation and splitting of Provisional Allotment Letters

Qualifying Non-CREST Shareholders who wish to transfer all of their Nil Paid Rights or, after

acceptance of the provisional allotment and payment in full, Fully Paid Rights comprised in a

Provisional Allotment Letter may (save as required by the laws of certain overseas jurisdictions)

renounce such allotment by completing and signing Form X on page 2 of the Provisional Allotment

Letter (if it is not already marked ‘‘Original Duly Renounced’’) and passing the entire Provisional

Allotment Letter to their stockbroker or bank or other appropriate financial adviser or to the

transferee. Once a Provisional Allotment Letter has been so renounced, it will become a negotiable

instrument in bearer form and the Nil Paid Rights or Fully Paid Rights (as appropriate) comprised insuch letter may be transferred by delivery of such letter to the transferee. The latest time and date for

registration of renunciation of Provisional Allotment Letters is 11.00 a.m. on 6 May 2009 and after

such date the New Ordinary Shares will be in registered form, transferable by written instrument of

transfer in the usual common form or, if they have been issued in or converted into uncertificated

form, in electronic form under the CREST system.

If a holder of a Provisional Allotment Letter wishes to have only some of the New Ordinary Shares

registered in his name and to transfer the remainder, or wishes to transfer all the Nil Paid Rights, or

(if appropriate) Fully Paid Rights but to different persons, he may have the Provisional Allotment

Letter split, for which purpose he must sign and date Form X on page 2 of the Provisional

Allotment Letter. The Provisional Allotment Letter must then be delivered by post or by hand

(during normal business hours only) to the appropriate address as set out in paragraph 4.2 of thisPart VIII by not later than 3.00 p.m. on 1 May 2009, to be cancelled and exchanged for the split

Provisional Allotment Letters required. The number of split Provisional Allotment Letters required

and the number of Nil Paid Rights or (as appropriate) Fully Paid Rights to be comprised in each

split Provisional Allotment Letter should be stated in an accompanying letter. Form X on page 2 of

split Provisional Allotment Letters will be marked ‘‘Original Duly Renounced’’ before issue.

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Alternatively, Qualifying Non-CREST Shareholders who wish to take up some of their rights, without

transferring the remainder, should complete Form X on page 2 of the original Provisional Allotment

Letter and return it by post or by hand (during normal business hours only) to the appropriate

address as set out in paragraph 4.2 of this Part VIII, together with a covering letter confirming thenumber of New Ordinary Shares to be taken up and a cheque or banker’s draft for the appropriate

amount made payable to ‘Capita Registrars Limited re Premier Oil plc Rights Issue’ and crossed ‘A/C

payee only’ and with the Reference Number (which appears on page 1 of the Provisional Allotment

Letter) written on the reverse of the cheque or banker’s draft to pay for this number of shares. In

this case, the Provisional Allotment Letter and the cheque or banker’s draft must be received by the

Receiving Agent by 11.00 a.m. on 6 May 2009, being the last date and time for payment.

The Company and the Underwriters reserve the right to refuse to register any renunciation in favour

of any person in respect of which the Company and the Underwriters believe such renunciation may

violate applicable legal or regulatory requirements including (without limitation) any renunciation in

the name of any person with an address outside the UK.

4.8 Registration in names of Qualifying Shareholders

A Qualifying Shareholder who wishes to have all his entitlement to New Ordinary Shares registered in

his name must accept and make payment for such allotment prior to the latest time for acceptance and

payment in full which is 11.00 a.m. on 6 May 2009 in accordance with the provisions set out in this

document and, in the case of Qualifying Non-CREST Shareholders, the Provisional Allotment Letter and

this document, but need take no further action.

4.9 Registration in names of persons other than Qualifying Shareholders originally entitled

In order to register Fully Paid Rights in certificated form in the name of someone other than the

Qualifying Shareholder(s) originally entitled, Form X must be signed and the renouncee or his

agent(s) must complete Form Y on page 2 of the Provisional Allotment Letter – see paragraph 4.7 of

this Part VIII – and send the entire Provisional Allotment Letter, when fully paid, by post or (duringnormal business hours only) by hand to Capita Registrars, Corporate Action, The Registry, 34

Beckenham Road, Beckenham, Kent BR3 4TU not later than the latest time for registration of

renunciation which is 11.00 a.m. on 6 May 2009. Registration cannot be effected unless and until the

New Ordinary Shares comprised in a Provisional Allotment Letter are fully paid. If the renouncee is

a CREST member who wishes to hold such New Ordinary Shares in uncertificated form, Form X

and the CREST Deposit Form (both on page 2 of the Provisional Allotment Letter) must be signed

and deposited with the CCSS counter, as explained in paragraph 4.10 below.

The New Ordinary Shares comprised in two or more Provisional Allotment Letters (duly renounced

where applicable) may be registered in the name of one holder (or joint holders) if Form Y on page

2 of one of the Provisional Allotment Letters (the ‘‘Principal Letter’’) and all the Provisional

Allotment Letters are delivered in one batch. Details of each Provisional Allotment Letter (includingthe Principal Letter) should be listed in the Consolidated Listing Form adjacent to Forms X and Y

of the Principal Letter and the allotment number of the Principal Letter should be entered into the

space provided on each of the other Provisional Allotment Letters.

4.10 Deposit of Nil Paid Rights or Fully Paid Rights into CREST

The Nil Paid Rights or Fully Paid Rights represented by a Provisional Allotment Letter may be

converted into uncertificated form, that is, deposited into CREST (whether such conversion arises asa result of a renunciation of those rights or otherwise). Similarly, Nil Paid Rights or Fully Paid

Rights held in CREST may be converted into certificated form, that is, withdrawn from CREST.

Subject as provided in the next paragraph or in the Provisional Allotment Letter, normal CREST

procedures and timings apply in relation to any such conversion. Shareholders are recommended to

refer to the CREST Manual for details of such procedures.

The procedure for depositing the Nil Paid Rights or Fully Paid Rights represented by a Provisional

Allotment Letter into CREST, whether such rights are to be converted into uncertificated form in the

name(s) of the person(s) whose name(s) and address(es) appear on page 1 of the Provisional

Allotment Letter or in the name of a person or persons to whom the Provisional Allotment Letter

has been renounced, is as follows: Form X and the CREST Deposit Form (both set out on page 2 ofthe Provisional Allotment Letter) will need to be completed and the Provisional Allotment Letter

deposited with the CCSS (as such term is defined in the CREST Manual); in addition, the normal

CREST stock deposit procedures will need to be carried out, except that (a) it will not be necessary

to complete and lodge a separate CREST Transfer Form (prescribed under the Stock Transfer Act

1963) with the CCSS; and (b) only the whole of the Nil Paid Rights or Fully Paid Rights represented

83


by the Provisional Allotment Letter may be deposited into CREST. If you wish to deposit only some

of the Nil Paid Rights or Fully Paid Rights represented by the Provisional Allotment Letter into

CREST, you must first apply for split Provisional Allotment Letters. If the rights represented by

more than one Provisional Allotment Letter are to be deposited, the CREST Deposit Form on eachProvisional Allotment Letter must be completed and deposited. A Consolidation Listing Form must

not be used.

A holder of the Nil Paid Rights or Fully Paid Rights represented by a Provisional Allotment Letter

who is proposing to convert those rights into uncertificated form (whether following a renunciation of

such rights or otherwise) is recommended to ensure that the conversion procedures are implemented

in sufficient time to enable the person holding or acquiring the Nil Paid Rights or, if appropriate, the

Fully Paid Rights in CREST following the conversion to take all necessary steps in connection with

taking up the entitlement prior to 11.00 a.m on 6 May 2009. In particular, having regard to processing

times in CREST and on the part of the Receiving Agent, the latest recommended time for depositing a

renounced Provisional Allotment Letter (with Form X and the CREST Deposit Form on page 2 of theProvisional Allotment Letter duly completed), with the CCSS (to enable the person acquiring the Nil

Paid Rights or, if appropriate, the Fully Paid Rights in CREST as a result of the conversion to take all

necessary steps in connection with taking up the entitlement prior to 11.00 a.m. on 6 May 2009) is

3.00 p.m. on 30 April 2009.

When Form X and the CREST Deposit Form (both on page 2 of the Provisional Allotment Letter)

have been completed, the title to the Nil Paid Rights or the Fully Paid Rights represented by the

Provisional Allotment Letter will cease forthwith to be renounceable or transferable by delivery and,

for the avoidance of doubt, any entries in Form Y on page 2 of the Provisional Allotment Letter will

not be recognised or acted upon by the Receiving Agent. All renunciations or transfers of the Nil

Paid Rights or Fully Paid Rights must be effected through the means of the CREST system oncesuch rights have been deposited into CREST.

CREST sponsored members should contact their CREST sponsor as only their CREST sponsors will

be able to take the necessary actions to take up the entitlements or otherwise to deal with Nil PaidRights or Fully Paid Rights of CREST sponsored members.

4.11 Issue of New Ordinary Shares in definitive form

Definitive share certificates in respect of the New Ordinary Shares to be held in certificated form areexpected to be despatched by post by 14 May 2009 at the risk of the person(s) entitled to them, to

accepting Qualifiying Non-CREST Shareholders and renouncees or their agents or, in the case of

joint holdings, to the first-named Shareholder, in each case at their registered address (unless lodging

agent details have been completed on page 2 of the Provisional Allotment Letter). After despatch of

definitive share certificates, Provisional Allotment Letters will cease to be valid for any purpose

whatsoever. Pending despatch of definitive share certificates, instruments of transfer of the New

Ordinary Shares will be certified by the Registrar against the register.

5. Action to be taken in relation to Nil Paid Rights or Fully Paid Rights in CREST

5.1 General

Subject as provided in paragraph 7 of this Part VIII in relation to certain Excluded Overseas

Shareholders, each Qualifying CREST Shareholder is expected to receive a credit to his CREST stock

account of his entitlement to Nil Paid Rights on 21 April 2009. The CREST stock account to be

credited will be an account under the participant ID and member account ID that apply to the

Existing Ordinary Shares held on the Record Date by the Qualifying CREST Shareholder in respect

of which the Nil Paid Rights are provisionally allotted.

The Nil Paid Rights will constitute a separate security for the purposes of CREST and can

accordingly be transferred, in whole or in part, by means of CREST in the same manner as any

other security that is admitted to CREST.

If for any reason it is impracticable to credit the stock accounts of Qualifying CREST Shareholders

or to enable the Nil Paid Rights, Provisional Allotment Letters shall, unless the Company and the

Underwriters agree otherwise, be sent out in substitution for the Nil Paid Rights which have not beenso credited or enabled and the expected timetable as set out in this document may, with the consent

of the Underwriters, be adjusted as appropriate. References to dates and times in this document

should be read as subject to any such adjustment. The Company will make an appropriate

announcement to a Regulatory Information Service giving details of the revised dates but Qualifying

CREST Shareholders may not receive any further written communication.

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CREST members who wish to take up all or part of their entitlements in respect of, or otherwise to

transfer all or part of, their Nil Paid Rights or Fully Paid Rights held by them in CREST should refer

to the CREST Manual for further information on the CREST procedures referred to below. If you are a

CREST sponsored member, you should consult your CREST sponsor if you wish to take up yourentitlement, as only your CREST sponsor will be able to take the necessary action to take up your

entitlements or otherwise to deal with your Nil Paid Rights or Fully Paid Rights.

5.2 Procedure for acceptance and payment

(A) MTM instructions

CREST members who wish to take up all or part of their entitlement in respect of Nil Paid Rights in

CREST must send (or, if they are CREST sponsored members, procure that their CREST sponsor

sends) a MTM instruction to Euroclear UK which, on its settlement, will have the following effect:

(i) the crediting of a stock account of the Receiving Agent under the participant ID and member

account ID specified below, with the number of Nil Paid Rights to be taken up;

(ii) the creation of a settlement bank payment obligation (as this term is defined in the CREST

Manual), in accordance with the CREST RTGS payment mechanism (as this term is defined in

the CREST Manual), in favour of the RTGS settlement bank of the Receiving Agent in Pounds

Sterling, in respect of the full amount payable on acceptance in respect of the Nil Paid Rights

referred to in sub-paragraph (i) above; and

(iii) the crediting of a stock account of the accepting CREST member (being an account under the

same participant ID and member account ID as the account from which the Nil Paid Rights are

to be debited on settlement of the MTM instruction) of the corresponding number of Fully Paid

Rights to which the CREST member is entitled on taking up his Nil Paid Rights referred to in

sub-paragraph (i) above.

(B) Contents of MTM instructions

The MTM instruction must be properly authenticated in accordance with Euroclear UK’s

specifications and must contain, in addition to the other information that is required for settlement in

CREST, the following details:

(i) the number of Nil Paid Rights to which the acceptance relates;

(ii) the participant ID of the accepting CREST member;

(iii) the member account ID of the accepting CREST member from which the Nil Paid Rights areto be debited;

(iv) the participant ID of the Receiving Agent, in its capacity as a CREST receiving agent. This is

7RA33;

(v) the member account ID of the Receiving Agent, in its capacity as a CREST receiving agent.

This is PREMIER;

(vi) the number of Fully Paid Rights that the CREST member is expecting to receive on settlementof the MTM instruction. This must be the same as the number of Nil Paid Rights to which the

acceptance relates;

(vii) the amount payable by means of the CREST payment arrangements on settlement of the MTM

instruction. This must be the full amount payable on acceptance in respect of the number of Nil

Paid Rights to which the acceptance relates;

(viii) the intended settlement date (which must be on or before 11.00 a.m. on 6 May 2009);

(ix) the nil paid ISIN Number. This is GB00B3PZZ165;

(x) the fully paid ISIN Number. This is GB00B3PZZB60;

(xi) the Corporate Action Number to the Rights Issue. This will be available by viewing the relevant

corporate action details in CREST; and

(xii) contact name and telephone numbers in the shared notes field.

(C) Valid acceptance

An MTM instruction complying with each of the requirements as to authentication and contents set

out in sub-paragraph (B) of this paragraph 5.2 will constitute a valid acceptance where either:

(i) the MTM instruction settles by not later than 11.00 a.m. on 6 May 2009; or

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(ii) at the discretion of the Company and the Underwriters (i) the MTM instruction is received by

Euroclear UK by not later than 11.00 a.m. on 6 May 2009; and (ii) the number of Nil Paid

Rights inserted in the MTM instruction is credited to the CREST stock member account of the

accepting CREST member specified in the MTM instruction at 11.00 a.m. on 6 May 2009; and(iii) the relevant MTM instruction settles by 2.00 p.m. on 6 May 2009 (or such later date as the

Company has determined).

An MTM instruction will be treated as having been received by Euroclear UK for these purposes at

the time at which the instruction is processed by the Network Provider’s Communications Host (as

this term is defined in the CREST Manual) at Euroclear UK of the network provider used by theCREST member (or by the CREST sponsored member’s CREST sponsor). This will be conclusively

determined by the input time stamp applied to the MTM instruction by the Network Provider’s

Communications Host.

(D) Representations, warranties and undertakings of CREST members

A CREST member or CREST sponsored member who makes a valid acceptance in accordance with

this paragraph 5.2(D) represents, warrants and undertakes to the Company and the Underwriters that

he/she has taken (or procured to be taken), and will take (or will procure to be taken), whateveraction is required to be taken by him/her or by his/her CREST sponsor (as appropriate) to ensure

that the MTM instruction concerned is capable of settlement at 11.00 a.m. on 6 May 2009 and

remains capable of settlement at all times after that until 2.00 p.m. on 6 May 2009 (or until such

later time and date as the Company and the Underwriters may determine). In particular, the CREST

member or CREST sponsored member represents, warrants and undertakes that at 11.00 a.m. on

6 May 2009 and at all times thereafter until 2.00 p.m. on 6 May 2009 (or until such later time and

date as the Company and the Underwriters may determine) there will be sufficient Headroom within

the Cap (as those terms are defined in the CREST Manual) in respect of the cash memorandumaccount to be debited with the amount payable on acceptance to permit the MTM instruction to

settle. CREST sponsored members should contact their CREST sponsor if they are in any doubt.

If there is insufficient Headroom within the Cap in respect of the cash memorandum account of a

CREST member or CREST sponsored member for such amount to be debited or the CREST

member’s or CREST sponsored member’s acceptance is otherwise treated as invalid and NewOrdinary Shares have already been allotted to such CREST member or CREST sponsored member,

the Company and the Underwriters may (in their absolute discretion as to manner, timing and terms)

make arrangements for the sale of such shares on behalf of that CREST member or CREST

sponsored member and hold the proceeds of sale (net of the Company’s reasonable estimate of any

loss that it has suffered as a result of the acceptance being treated as invalid and of the expenses of

sale including, without limitation, any stamp duty or SDRT payable on the transfer of such shares,

and of all amounts payable by the CREST member or CREST sponsored member pursuant to the

provisions of this Part VIII in respect of the acquisition of such shares) on behalf of such CRESTmember or CREST sponsored member. Neither the Company, the Underwriters nor any other person

shall be responsible for, or have any liability for, any loss, expenses or damage suffered by such

CREST member or CREST sponsored member as a result.

(E) CREST procedures and timings

CREST members and CREST sponsors (on behalf of CREST sponsored members) should note that

Euroclear UK does not make available special procedures in CREST for any particular corporate

action. Normal system timings and limitations will therefore apply in relation to the input of anMTM instruction and its settlement in connection with the Rights Issue. It is the responsibility of the

CREST member concerned to take (or, if the CREST member is a CREST sponsored member, to

procure that his CREST sponsor takes) the action necessary to ensure that a valid acceptance is

received as stated above by 11.00 a.m. on 6 May 2009. In this connection, CREST members and

(where applicable) CREST sponsors are referred in particular to those sections of the CREST Manual

concerning practical limitations of the CREST system and timings.

(F) CREST member’s undertaking to pay

A CREST member or CREST sponsored member, who makes a valid acceptance in accordance with

the procedures set out in this paragraph 5.2(F): (a) undertakes to pay to the Receiving Agent, or

procure the payment to the Receiving Agent of, the amount payable in Pounds Sterling on

acceptance in accordance with the above procedures or in such other manner as the Receiving Agent

may require (it being acknowledged that, where payment is made by means of the RTGS payment

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mechanism (as defined in the CREST Manual), the creation of an RTGS settlement bank payment

obligation in Pounds Sterling in favour of the Receiving Agent’s RTGS settlement bank (as defined in

the CREST Manual), in accordance with the RTGS payment mechanism, shall, to the extent of the

obligation so created, discharge in full the obligation of the CREST member (or CREST sponsoredmember) to pay to the Underwriters the amount payable on acceptance); and (b) requests that the

Fully Paid Rights and/or New Ordinary Shares, to which they will become entitled, be issued to them

on the terms set out in this document and subject to the Memorandum and Articles of Association of

the Company.

If the payment obligations of the relevant CREST member in relation to such New Ordinary Shares

are not discharged in full and such New Ordinary Shares have already been allotted to such CREST

member or CREST sponsored member, the Company and the Underwriters may (in their absolute

discretion as to manner, timing and terms) make arrangements for the sale of such shares on behalf

of that CREST member or CREST sponsored member and hold the proceeds of sale (net of the

Company’s reasonable estimate of any loss that it has suffered as a result of the acceptance being

treated as invalid and of the expenses of sale including, without limitation, any stamp duty or SDRTpayable on the transfer of such shares, and of all amounts payable by the CREST member or

CREST sponsored member pursuant to the provisions of this Part VIII in respect of the acquisition

of such shares) or an amount equal to the original payment of the CREST member or CREST

sponsored member (whichever is the lower) on trust for such CREST member or CREST sponsored

member. Neither the Company, the Underwriters nor any other person shall be responsible for, or

have any liability for, any loss, expenses or damage suffered by such CREST member or CREST

sponsored member as a result.

(G) Discretion as to rejection and validity of acceptances

The Company and the Underwriters may, in their absolute discretion:

(i) reject any acceptance constituted by an MTM instruction, which is otherwise valid, in the event

of breach of any of the representations, warranties and undertakings set out or referred to in

paragraph 5.2(D) of this Part VIII. Where an acceptance is made as described in this paragraph

5.2 which is otherwise valid, and the MTM instruction concerned fails to settle by 2.00 p.m. on6 May 2009 (or by such later time and date as the Company and the Underwriters may

determine), the Company and the Underwriters shall be entitled to assume, for the purposes of

their right to reject an acceptance as described in this paragraph 5.2(G), that there has been a

breach of the representations, warranties and undertakings set out or referred to in paragraph

5.2(D) above unless the Company or Underwriters are aware of any reason outside the control

of the CREST member or CREST sponsor (as appropriate) concerned for the failure of the

MTM instruction to settle;

(ii) treat as valid (and binding on the CREST member or CREST sponsored member concerned) an

acceptance which does not comply in all respects with the requirements as to validity set out or

referred to in this paragraph 5.2(G);

(iii) accept an alternative properly authenticated dematerialised instruction from a CREST member

or (where applicable) a CREST sponsor as constituting a valid acceptance in substitution for, or

in addition to, an MTM instruction and subject to such further terms and conditions as the

Company and the Underwriters may determine;

(iv) treat a properly authenticated dematerialised instruction (in this paragraph 5.2(G), the ‘‘first

instruction’’) as not constituting a valid acceptance if, at the time at which the Receiving Agent

receives a properly authenticated dematerialised instruction giving details of the first instruction,

either the Company or the Receiving Agent has received actual notice from Euroclear UK of

any of the matters specified in CREST Regulation 35(5)(a) in relation to the first instruction.

These matters include notice that any information contained in the first instruction was incorrector notice of lack of authority to send the first instruction; and

(v) accept an alternative instruction or notification from a CREST member or (where applicable) a

CREST sponsor, or extend the time for acceptance and/or settlement of an MTM instruction orany alternative instruction or notification if, for reasons or due to circumstances outside the

control of any CREST member or CREST sponsored member or (where applicable) CREST

sponsor, the CREST member or CREST sponsored member is unable validly to take up all or

part of his/her Nil Paid Rights by means of the above procedures. In normal circumstances, this

discretion is only likely to be exercised in the event of any interruption, failure or breakdown of

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CREST (or of any part of CREST) or on the part of facilities and/or systems operated by the

Receiving Agent in connection with CREST, and (at the latest) only until 10.00 a.m. on 7 May

2009.

5.3 Money Laundering Regulations

If you hold your Nil Paid Rights in CREST and apply to take up all or part of your entitlement as

agent for one or more persons and you are not a UK or EU regulated person or institution (e.g. abank, a broker or another UK financial institution), then, irrespective of the value of the application,

the Receiving Agent is required to take reasonable measures to establish the identity of the person or

persons on whose behalf you are making the application. Such Qualifying CREST Shareholders must

therefore contact the Receiving Agent before sending any MTM instruction or other instruction so

that appropriate measures may be taken.

Submission of an MTM instruction which constitutes, or which may on its settlement constitute, avalid acceptance as described above constitutes a warranty and undertaking by the applicant to

provide promptly to the Receiving Agent any information the Receiving Agent may specify as being

required for the purposes of the Money Laundering Regulations. Pending the provision of evidence

satisfactory to the Receiving Agent as to identity, the Receiving Agent, having consulted with the

Company and the Underwriters, may take, or omit to take, such action as it may determine to

prevent or delay settlement of the MTM instruction. If satisfactory evidence of identity has not been

provided within a reasonable time, the Receiving Agent will not permit the MTM instruction

concerned to proceed to settlement (without prejudice to the right of the Company and/or theUnderwriters to take proceedings to recover any loss suffered by it/them as a result of failure by the

applicant to provide satisfactory evidence).

5.4 Dealings in Nil Paid Rights

Subject to the passing of the Resolutions at the Extraordinary General Meeting and the Rights Issue

otherwise becoming unconditional, dealings in the Nil Paid Rights on the London Stock Exchange

are expected to commence at 8.00 a.m. on 21 April 2009. Dealings in Nil Paid Rights can be made

by means of CREST in the same manner as any other security that is admitted to CREST. The Nil

Paid Rights are expected to be disabled in CREST after the close of CREST business on 6 May

2009.

5.5 Dealings in Fully Paid Rights

After acceptance and payment in full in accordance with the provisions set out in this document and

(where appropriate) the Provisional Allotment Letter, the Fully Paid Rights may be transferred (in

whole or in part) by means of CREST in the same manner as any other security that is admitted toCREST. The last time for settlement of any transfer of Fully Paid Rights in CREST is expected to

be 11.00 a.m. on 6 May 2009. The Fully Paid Rights are expected to be disabled in CREST after the

close of CREST business on 6 May 2009.

After 6 May 2009, the New Ordinary Shares will be registered in the name(s) of the person(s) entitled

to them in the Company’s register of members and will be transferable in the usual way.

5.6 Withdrawal of Nil Paid Rights or Fully Paid Rights from CREST

Nil Paid Rights or Fully Paid Rights held in CREST may be converted into certificated form, that is,

withdrawn from CREST. Normal CREST procedures (including timings) apply in relation to any

such conversion.

The recommended latest time for receipt by Euroclear UK of a properly authenticated dematerialised

instruction requesting withdrawal of Nil Paid Rights from CREST is 4.30 p.m. on 29 April 2009, so

as to enable the person acquiring or (as appropriate) holding the Nil Paid Rights following the

conversion to take all necessary steps in connection with taking up the entitlement prior to 11.00 a.m.

on 6 May 2009. Shareholders are recommended to refer to the CREST Manual for details of such

procedures.

5.7 Issue of New Ordinary Shares in CREST

New Ordinary Shares will be issued in uncertificated form to those persons registered as holding FullyPaid Rights in CREST at the close of business on the date on which the Fully Paid Rights are

disabled. The Receiving Agent will instruct Euroclear UK to credit the appropriate stock accounts of

those persons (under the same participant ID and member account ID that applied to the Fully Paid

Rights held by those persons) with their entitlements to New Ordinary Shares with effect from the

next Business Day (expected to be 7 May 2009).

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5.8 Right to allot/issue in certificated form

Despite any other provision of this document, the Company reserves the right to allot and to issue

any Nil Paid Rights, Fully Paid Rights or New Ordinary Shares in certificated form. In normalcircumstances, this right is only likely to be exercised in the event of an interruption, failure or

breakdown of CREST (or of any part of CREST) or of a part of the facilities and/or systems

operated by the Receiving Agent in connection with CREST, or otherwise if the Company has first

obtained the Underwriters’ written consent.

6. Procedure in respect of rights not taken up

If an entitlement to New Ordinary Shares is not validly taken up in accordance with the procedure

laid down for acceptance and payment, then that provisional allotment will be deemed to have beendeclined and will lapse. The Underwriters will use reasonable endeavours to procure, by not later

than 5.00 p.m. on 11 May 2009, acquirers for all (or as many as possible) of those New Ordinary

Shares not taken up if a premium over the total of the Rights Issue Price and the expenses of

procuring such acquirers (including any related commissions and amounts in respect of VAT which

are not recoverable) can be obtained.

Notwithstanding the above, the Underwriters may cease to endeavour to procure any such acquirers

if, in the opinion of the Underwriters, it is unlikely that any such acquirers can be so procured at

such a price by such time. If and to the extent that acquirers cannot be procured on the basis

outlined above, the relevant New Ordinary Shares will be acquired by the Underwriters as principal

pursuant to the Underwriting Agreement or by sub-underwriters procured by the Underwriters, in

each case, at the Rights Issue Price on the terms and subject to the conditions of the Underwriting

Agreement.

Any premium over the aggregate of the Rights Issue Price and the expenses of procuring acquirers

(including any applicable brokerage and commissions and amounts in respect of VAT which are not

recoverable) shall be paid (subject as provided in this paragraph 6):

(A) where the Nil Paid Rights were, at the time they lapsed, represented by a Provisional AllotmentLetter, to the person whose name and address appeared on page 1 of the Provisional Allotment

Letter;

(B) where the Nil Paid Rights were, at the time they lapsed, in uncertificated form, to the person

registered as the holder of those Nil Paid Rights at the time of their disablement in CREST;

and

(C) where an entitlement to New Ordinary Shares was not taken up by an Excluded Overseas

Shareholder, to that Excluded Overseas Shareholder.

New Ordinary Shares for which acquirers are procured on this basis will be re-allotted to such

acquirers and the aggregate of any premiums (being the amount paid by such acquirers afterdeducting the price at which the New Ordinary Shares are offered pursuant to the Rights Issue and

the expenses of procuring such acquirers including any applicable brokerage and commissions and

amounts in respect of VAT which are not recoverable), if any, will be paid (without interest) to those

persons entitled (as referred to above) pro rata to the relevant lapsed provisional allotments, save that

no payment will be made of amounts of less than £5, which amounts will be aggregated and will

ultimately accrue to the benefit of the Company. Cheques for the amounts due will be sent in Pounds

Sterling, by post, at the risk of the person(s) entitled, to their registered addresses (the registered

address of the first named in the case of joint holders), provided that where any entitlementconcerned was held in CREST, the amount due will, unless the Company (in its absolute discretion)

otherwise determines, be satisfied by the Company procuring the creation of a payment obligation in

favour of the relevant CREST member’s (or CREST sponsored member’s) RTGS settlement bank in

respect of the cash amount concerned in accordance with the RTGS payment mechanism.

Any transactions undertaken pursuant to this paragraph 6 shall be deemed to have been undertakenat the request of the persons entitled to the lapsed provisional allotments and none of the Company,

the Underwriters nor any other person procuring acquirers shall be responsible for any loss or

damage (whether actual or alleged) arising from the terms of or timing of any such acquisition, any

decision not to endeavour to procure acquirers or the failure to procure acquirers on the basis

described above.

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7. Excluded Overseas Shareholders

7.1 General

The offer of Nil Paid Rights, Fully Paid Rights and/or New Ordinary Shares to persons resident in, or

who are citizens of, or who have a registered address in a jurisdiction other than the UK may be

affected by the laws of the relevant jurisdiction. Those persons should consult their professional advisersas to whether they require any governmental or other consents or need to observe any other formalities

to enable them to take up their rights. It is the responsibility of all persons outside the UK receiving this

document and/or a Provisional Allotment Letter and/or a credit of Nil Paid Rights to a stock account in

CREST and wishing to accept the offer of New Ordinary Shares to satisfy themselves as to full

observance of the laws of the relevant territory, including obtaining all necessary governmental or other

consents which may be required, observing all other requisite formalities needing to be observed and

paying any issue, transfer or other taxes due in such territory.

This paragraph 7 sets out the restrictions applicable to Qualifying Shareholders who have registered

addresses outside the UK, who are citizens or residents of countries other than the UK, or who are

persons (including, without limitation, custodians, nominees and trustee) who have a contractual orlegal obligation to forward this document to a jurisdiction outside the UK or who hold Ordinary

Shares for the account or benefit of any such person.

New Ordinary Shares will be provisionally allotted to all Qualifying Shareholders, including all

Excluded Overseas Shareholders. However, Provisional Allotment Letters have not been, and will not

be, sent to, and Nil Paid Rights will not be credited to CREST accounts of, Excluded Overseas

Shareholders with registered addresses in the United States or any Excluded Territory, or to their

agent or intermediary, except where the Company and the Underwriters are satisfied that such action

would not result in the contravention of any registration or other legal requirement in such

jurisdiction.

Receipt of this document and/or a Provisional Allotment Letter or the crediting of Nil Paid Rights toa stock account in CREST will not constitute an offer in those jurisdictions in which it would be

illegal to make an offer and, in those circumstances, this document and/or a Provisional Allotment

Letter must be treated as sent for information only and should not be copied or redistributed. No

person receiving a copy of this document and/or a Provisional Allotment Letter and/or receiving a

credit of Nil Paid Rights to a stock account in CREST in any territory other than the UK may treat

the same as constituting an invitation or offer to him, nor should he in any event use the Provisional

Allotment Letter or deal with Nil Paid Rights or Fully Paid Rights in CREST unless, in the relevant

territory, such an invitation or offer could lawfully be made to him and the Provisional AllotmentLetter or Nil Paid Rights or Fully Paid Rights in CREST could lawfully be used or dealt with

without contravention of any unfulfilled registration or other legal or regulatory requirements.

Accordingly, persons receiving a copy of this document and/or a Provisional Allotment Letter or

whose stock account in CREST is credited with Nil Paid Rights or Fully Paid Rights should not, in

connection with the Rights Issue, distribute or send the same in or into, or transfer Nil Paid Rights

or Fully Paid Rights to any person in or into any jurisdiction where to do so would or might

contravene local securities laws or regulations. If a Provisional Allotment Letter or credit of Nil Paid

Rights or Fully Paid Rights in CREST is received by any person in any such territory, or by their

agent or nominee in any such territory, he must not seek to take up the rights referred to in theProvisional Allotment Letter or in this document or renounce the Provisional Allotment Letter or

transfer the Nil Paid Rights or Fully Paid Rights in CREST unless the Company and the

Underwriters determine that such actions would not violate applicable legal or regulatory

requirements. Any person who does forward this document or a Provisional Allotment Letter into

any such territories (whether under contractual or legal obligation or otherwise) should draw the

recipient’s attention to the contents of this paragraph 7.

Subject to this paragraph 7, any person (including, without limitation, nominees, agents and trustees)

outside the UK wishing to take up his rights under the Rights Issue (or to do so on behalf of

someone else) must satisfy himself as to full observance of the applicable laws of any relevantterritory including obtaining any requisite governmental or other consents, observing any other

requisite formalities and paying any issue, transfer or other taxes due in such territories. The

comments set out in this paragraph 7 are intended as a general guide only and any Qualifying

Shareholder who is in doubt as to his position should consult his own independent professional

adviser without delay.

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The Company and the Underwriters may treat as invalid any acceptance or purported acceptance of

the offer of Nil Paid Rights, Fully Paid Rights or New Ordinary Shares which appears to the

Company or the Underwriters or their respective agents to have been executed, effected or despatched

in a manner which may involve a breach of the laws or regulations of any jurisdiction or if it believesor they believe that the same may violate applicable legal or regulatory requirements or if, in the case

of a Provisional Allotment Letter, it provides for an address for delivery of the definitive share

certificates for New Ordinary Shares, or, in the case of a credit of New Ordinary Shares in CREST,

the CREST member’s or a CREST sponsored member’s registered address is, in the US or any of the

Excluded Territories or any other jurisdiction outside the UK in which it would be unlawful to

deliver such share certificates, or if the Company and the Underwriters believe or their respective

agents believe that the same may violate applicable legal or regulatory requirements. The attention of

Qualifying Shareholders with registered addresses in the US or any of the Excluded Territories orholding shares on behalf of persons with such addresses is drawn to this paragraph 7.

Despite any other provisions of this document or the Provisional Allotment Letter, the Company andthe Underwriters reserve the right to permit any Qualifying Shareholder to take up his rights if the

Company and the Underwriters in their sole and absolute discretion are satisfied that the transaction

in question is exempt from or not subject to the legislation or regulations giving rise to the restriction

in question. If the Company and the Underwriters are so satisfied, the Company will arrange for the

relevant Qualifying Shareholder to be sent a Provisional Allotment Letter if he/she is a Qualifying

Non-CREST Shareholder or, if he/she is a Qualifying CREST Shareholder, arrange for Nil Paid

Rights to be credited to the relevant CREST stock account.

Those Shareholders who wish, and are permitted, to take up their entitlement should note that

payments must be made as described in paragraphs 4 and 5 of this Part VIII.

The provisions of paragraph 6 of this Part VIII will apply generally to Excluded Overseas

Shareholders who do not or are unable to take up New Ordinary Shares provisionally allotted to

them.

7.2 Offering restrictions relating to the United States

The New Ordinary Shares, the Nil Paid Rights, the Fully Paid Rights and the Provisional AllotmentLetters have not been and will not be registered under the US Securities Act or under any relevant

securities laws of any state or other jurisdiction of the United States and may not be offered, sold,

pledged, taken up, exercised, resold, renounced, transferred or delivered, directly or indirectly, within

the United States absent registration or an applicable exemption from the registration requirements of

the US Securities Act and in compliance with state securities laws. The New Ordinary Shares, the Nil

Paid Rights, the Fully Paid Rights and the Provisional Allotment Letter have not been approved or

disapproved by the SEC, any states securities commission in the United States or any other US

regulatory authority, nor have any of the foregoing authorities passed upon or endorsed the merits ofthe offering of the New Ordinary Shares, the Nil Paid Rights, the Fully Paid Rights and the

Provisional Allotment Letters or the accuracy or adequacy of this document. Any representation to

the contrary is a criminal offence in the United States.

Accordingly, the offer by way of rights is not being made in the United States and neither this

document nor the Provisional Allotment Letter constitutes or will constitute an offer, or an invitation

to apply for, or an offer or an invitation to acquire, any New Ordinary Shares, Nil Paid Rights or

Fully Paid Rights by any person in the United States. Provisional Allotment Letters have not been,

and will not be, sent to, and Nil Paid Rights have not been, and will not be, credited to the CREST

account of, any Qualifying Shareholder with a registered address in the United States, subject to

certain exceptions. Accordingly, this document is being sent to such Qualifying Shareholders for

information only, is confidential and should not be copied or redistributed by them.

Subject to certain limited exceptions, envelopes containing Provisional Allotment Letters and

postmarked in the United States or otherwise despatched from the United States will not be accepted,and all persons acquiring New Ordinary Shares and wishing to hold such shares in registered form

must provide an address for registration of the New Ordinary Shares issued upon exercise thereof

outside the United States.

Subject to certain limited exceptions, any person who acquires New Ordinary Shares, Nil Paid Rights

or Fully Paid Rights will be deemed to have declared, warranted and agreed, by accepting delivery of

this document or the Provisional Allotment Letter and delivery of the New Ordinary Shares, Nil Paid

Shares or Fully Paid Rights, that it is not, and that at the time of acquiring the New Ordinary

Shares, Nil Paid Rights or Fully Paid Rights it will not be, in the United States.

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The Company and the Underwriters reserve the right to treat as invalid any Provisional Allotment

Letter: (i) that appears to the Company or the Underwriters or their respective agents to have been

executed in or despatched from the United States; (ii) that does not include the relevant warranty set

out in the Provisional Allotment Letter headed ‘‘Overseas Shareholders’’ to the effect that the personaccepting and/or renouncing the Provisional Allotment Letter does not have a registered address (and

is not otherwise located) in the United States and is not acquiring rights to Nil Paid Rights, Fully

Paid Rights or New Ordinary Shares with a view to the offer, sale, resale, transfer, delivery or

distribution, directly or indirectly, of any such Nil Paid Rights, Fully Paid Rights or New Ordinary

Shares in the United States; or (iii) where the Company and the Underwriters believe acceptance of

such Provisional Allotment Letter may infringe applicable legal or regulatory requirements, and the

Company and the Underwriters shall not be bound to allot (on a non-provisional basis) or issue any

New Ordinary Shares, Nil Paid Rights, Fully Paid Rights in respect of any such ProvisionalAllotment Letter. In addition, the Company and the Underwriters reserve the right to reject any

MTM instruction sent by or on behalf of any CREST member with a registered address in the

United States in respect of Nil Paid Rights.

Until 40 days after the commencement of the Rights Issue, any offer, sale or transfer of the New

Ordinary Shares, Nil Paid Rights or Fully Paid Rights within the United States by a dealer (whether

or not participating in the Rights Issue) may violate the registration requirements of the US Securities

Act.

7.3 Offering restrictions relating to the United Arab Emirates

This document does not constitute a public offering of securities in any part of the United Arab

Emirates (which referred to herein and for the avoidance of doubt shall be deemed to include each of

the seven Emirates, the Dubai International Financial Centre and any other free zone located in the

United Arab Emirates). No interest in the New Ordinary Shares may be offered or sold directly or

indirectly to the public in the United Arab Emirates.

The New Ordinary Shares are not licensed or approved by the UAE Central Bank or any other

regulatory body in the UAE. Neither Deutsche Bank nor Oriel Securities Limited are licensed orapproved by the UAE Central Bank or any other regulatory body in the UAE to market or sell

securities (including the New Ordinary Shares).

This document and any other offering material is strictly private and confidential and is being sent to

and is intended only for Shareholders. It must not be provided to any person or entity other than the

original recipient, and may not be reproduced or used for any other purpose.

7.4 Other overseas territories

Provisional Allotment Letters have been and, where relevant, will be posted to Qualifying Non-CREST Shareholders (other than, subject to certain limited exceptions, those Qualifying Non-CREST

Shareholders who have registered addresses in any of the Excluded Territories) and Nil Paid Rights

have been and, where relevant, will be credited to the CREST stock accounts of Qualifying CREST

Shareholders (other than, subject to certain limited exceptions, those Qualifying CREST Shareholders

who have registered addresses in any of the Excluded Territories). Due to restrictions under the

securities laws of the Excluded Territories, and subject to certain exemptions, no offer of or invitation

to subscribe for New Ordinary Shares is being made by virtue of this document or the Provisional

Allotment Letters into any of the Excluded Territories and no Nil Paid Rights or Fully Paid Rightswill be credited to a stock account in CREST of Qualifying Shareholders with registered addresses in

an Excluded Territory, and their entitlements will be sold if possible in accordance with the

provisions of paragraph 6 of this Part VIII. The Provisional Allotment Letters, the Nil Paid Rights,

the Fully Paid Rights and the New Ordinary Shares may not be transferred or sold to any Excluded

Overseas Shareholder, or renounced or delivered in or into, any Excluded Territory, except in

accordance with certain exemptions. Qualifying Shareholders in jurisdictions other than those specified

above may, subject to the laws of their relevant jurisdiction, accept their rights under the Rights Issue

in accordance with the instructions set out in this document and, in the case of Qualifying Non-CREST Shareholders only, the Provisional Allotment Letter.

No offer of New Ordinary Shares is being made by virtue of this document or the Provisional

Allotment Letter into Canada, Australia, Israel, New Zealand, Dubai International Finance Centre or

the Republic of South Africa.

Qualifying Shareholders who have registered addresses in or who are resident in, or who are citizens

of, countries other than the United Kingdom should consult their appropriate professional advisers as

to whether they require any governmental or other consents or need to observe any other formalities

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to enable them to take up their Nil Paid Rights or to acquire Fully Paid Rights or New Ordinary

Shares.

If you are in any doubt as to your eligibility to accept the offer of New Ordinary Shares or to deal withNil Paid Rights or Fully Paid Rights, you should contact your appropriate professional adviser

immediately.

8. Representations and warranties relating to overseas territories

8.1 Qualifying Non-CREST Shareholders

Any person accepting and/or renouncing a Provisional Allotment Letter or requesting registration of

the New Ordinary Shares comprised therein represents and warrants to the Company and each of the

Underwriters that, except where proof has been provided to the Company’s and the Underwriters’

satisfaction that such person’s use of the Provisional Allotment Letter will not result in the

contravention of any applicable legal requirement in any jurisdiction: (i) such person is not accepting

and/or renouncing the Provisional Allotment Letter from within the US or any of the ExcludedTerritories; (ii) such person is not in any territory in which it is unlawful to make or accept an offer

to subscribe for New Ordinary Shares or to use the Provisional Allotment Letter in any manner in

which such person has used or will use it; (iii) such person is not acting on a non-discretionary basis

for a person located within the US or any Excluded Territory or any territory referred to in (ii)

above at the time the instruction to accept or renounce was given; and (iv) such person is not

acquiring New Ordinary Shares with a view to the offer, sale, resale, transfer, delivery or distribution,

directly or indirectly, of any such New Ordinary Shares into the US or any Excluded Territory or

any territory referred to in (ii) above.

The Company and each of the Underwriters may treat as invalid any acceptance or purported

acceptance of the allotment of New Ordinary Shares comprised in, or renunciation or purported

renunciation of, a Provisional Allotment Letter if it: (a) appears to the Company and the

Underwriters to have been executed in or despatched from the US or any Excluded Territory or

otherwise in a manner which may involve a breach of the laws of any jurisdiction or if the Company

or either of the Underwriters believes the same may violate any applicable legal or regulatory

requirement; (b) provides an address in the US or any Excluded Territory for delivery of definitive

share certificates for New Ordinary Shares (or any jurisdiction outside the UK in which it would beunlawful to deliver such certificates); or (c) purports to exclude the warranty required by this

paragraph 8.1.

8.2 Qualifying CREST Shareholders

A CREST member or CREST sponsored member who makes a valid acceptance in accordance with

the procedure set out in paragraph 5 of this Part VIII represents and warrants to the Company and

the Underwriters that, except where proof has been provided to the Company’s and the Underwriters’

satisfaction that such person’s acceptance will not result in the contravention of any applicable legalrequirement in any jurisdiction: (i) he is not within the US or any of the Excluded Territories; (ii) he

is not in any territory in which it is unlawful to make or accept an offer to acquire or subscribe for

Nil Paid Rights, Fully Paid Rights or New Ordinary Shares; (iii) he is not acting on a non-

discretionary basis for a person located within the US or any Excluded Territory or any territory

referred to in (ii) above at the time the instruction to accept was given; and (iv) he is not acquiring

Nil Paid Rights, Fully Paid Rights or New Ordinary Shares with a view to the offer, sale, resale,

transfer, delivery or distribution, directly or indirectly, of any such Nil Paid Rights, Fully Paid Rights

or New Ordinary Shares into the US or any Excluded Territory or any territory referred to in (ii)above.

The Company and the Underwriters may treat as invalid any MTM instruction which: (a) appears to

the Company and the Underwriters to have been despatched from the US or the Excluded Territories

or otherwise in a manner which may involve a breach of the laws of any jurisdiction or they or their

agents believe may violate any applicable legal or regulatory requirement; or (b) purports to exclude

the warranty required by this paragraph 8.2.

8.3 Waiver

The provisions of this paragraph 8 and paragraph 7 of this Part VIII and of any other terms of the

Rights Issue relating to Excluded Overseas Shareholders may be waived, varied or modified as regards

specific Shareholder(s) or on a general basis by the Company in its absolute discretion. Subject to

this, the provisions of this paragraph 8 and paragraph 7 which refer to Shareholders shall include

references to the person or persons executing a Provisional Allotment Letter and, in the event of

93


more than one person executing a Provisional Allotment Letter, the provisions of this paragraph 8

and paragraph 7 shall apply jointly to each of them.

9. Taxation

Information on taxation in the United Kingdom with regard to the Rights Issue is set out in Part

XV of this document. The information contained in Part XV is intended only as a general guide to

the current tax position in the United Kingdom and Qualifying Shareholders in the United Kingdom

should consult their own tax advisers regarding the tax treatment of the Rights Issue in light of theirown circumstances. Any person taking up, acquiring or otherwise dealing in rights pursuant to the

Rights Issue represents and warrants to the Company that such person is not (and the person

receiving New Ordinary Shares issued pursuant to such rights will not be) a person as mentioned in

section 67, 70, 93 or 96 of the Finance Act 1986. Shareholders who are in any doubt as to their tax

position or who are subject to tax in any other jurisdiction should consult an appropriate professional

adviser immediately.

10. Withdrawal Rights

Qualifying Shareholders wishing to exercise statutory withdrawal rights after the issue by the

Company of a prospectus supplementing this document (if any) must do so by lodging a written

notice of withdrawal, which must include the full name and address of the person wishing to exercise

statutory withdrawal rights and, if such person is a CREST member, the participant ID and the

member account ID of such CREST member with Capita Registrars, Corporate Action, The Registry,34 Beckenham Road, Beckenham, Kent BR3 4TU, so as to be received no later than two Business

Days after the date on which a supplementary prospectus is published. Notice of withdrawal given by

any other means or which is deposited with or received by the Receiving Agent after expiry of such

period will not constitute a valid withdrawal save that the Company shall treat as valid any notice of

withdrawal received through the post by not later than four Business Days after the date on which a

supplementary prospectus is published provided that its envelope bears a legible postmark not later

than the date falling two Business Days after the date on which such supplementary prospectus was

published.

Following the valid exercise of statutory withdrawal rights, application moneys will be returned by

post to relevant Qualifying Shareholders at their own risk and without interest to the address set out

in the Provisional Allotment Letter and/or the Receiving Agent will refund the amount paid by a

Qualifying CREST Shareholder by way of a CREST payment, without interest, as applicable within14 days of such exercise of statutory withdrawal rights. Interest earned on such monies will be

retained for the benefit of the Company. The provisions of this paragraph 10 of this Part VIII are

without prejudice to the statutory rights of Qualifying Shareholders. In such event, Shareholders are

advised to seek independent legal advice.

11. Times and dates

The Company shall in its discretion and after consultation with its financial and legal advisers (and

with the agreement of the Underwriters) be entitled to amend the dates that Provisional Allotment

Letters are despatched or dealings in Nil Paid Rights commence and amend or extend the latest date

for acceptance under the Rights Issue and all related dates set out in this document and in such

circumstances shall announce such amendment, via a Regulatory Information Service, and notify the

UK Listing Authority and, if appropriate, Shareholders.

12. Governing law

The terms and conditions of the Rights Issue as set out in this document and the Provisional

Allotment Letter shall be governed by, and construed in accordance with, the laws of England and

Wales.

13. Jurisdiction

The courts of England and Wales are to have exclusive jurisdiction to settle any dispute which may

arise out of or in connection with the Rights Issue, this document and the Provisional AllotmentLetter. By accepting rights under the Rights Issue in accordance with the instructions set out in this

document and, in the case of Qualifying Non-CREST Shareholders only, the Provisional Allotment

Letter, Qualifying Shareholders irrevocably submit to the jurisdiction of the Courts of England and

Wales and waive any objection to proceedings in any such court on the ground of venue or on the

ground that proceedings have been brought in an inconvenient forum.

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PART IX

INFORMATION CONCERNING THE NEW ORDINARY SHARES

1. Description of the type and class of securities admitted

The New Ordinary Shares will be Ordinary Shares with a nominal value of 50 pence each. The ISIN

of the New Ordinary Shares will be GB0033560011. The New Ordinary Shares will be created under

the Companies Act 1985 and the Memorandum and Articles of Association of Premier. The New

Ordinary Shares will be credited as fully paid and free from all liens, equities, charges, encumbrances

and other interests, and rank in full for all dividends and distributions on the ordinary share capital

of Premier declared, made or paid after the date of allotment and issue of the New Ordinary Shares.

2. Listing

Application has been made to the UK Listing Authority for the New Ordinary Shares (nil and fully

paid) to be admitted to the Official List and to the London Stock Exchange for the New Ordinary

Shares (nil and fully paid) to be admitted to trading on the London Stock Exchange’s main market

for listed securities. It is expected that Admission will become effective and that dealings in the New

Ordinary Shares, nil paid, will commence on the London Stock Exchange at 8.00 a.m. on 21 April

2009. It is expected that Admission will become effective and that dealings in the New Ordinary

Shares, fully paid, will commence at 8.00 a.m. on 7 May 2009.

3. Form and currency of the New Ordinary Shares

The New Ordinary Shares will be issued in registered form and will be capable of being held in

certificated and uncertificated form. Title to the certificated New Ordinary Shares will be evidenced by

entry in the register of members of Premier and title to uncertificated New Ordinary Shares will be

evidenced by entry in the operator register maintained by Euroclear UK (which forms part of the

register of Premier). The registrars of Premier are Capita Registrars. If any New Ordinary Shares are

converted to be held in certificated form, share certificates will be issued in respect of those shares inaccordance with the Articles and applicable legislation. The New Ordinary Shares will be

denominated in Pounds Sterling.

4. Rights attached to the New Ordinary Shares

Each New Share will rank pari passu in all respects with each Existing Ordinary Share and has the

same rights (including voting and dividend rights and rights on a return of capital) and restrictions as

the other Ordinary Shares, as set out in the Articles. These rights are set out in paragraph 9 of Part

XVI of this document.

5. Resolutions, authorisations and approvals relating to the New Ordinary Shares

The New Ordinary Shares will be created, allotted and issued pursuant to the authorities to be

granted under the Resolutions being proposed at the Extraordinary General Meeting.

6. Dates of issue and settlement

It is expected that the Provisional Allotment Letters will be posted on 20 April 2009 and the NewOrdinary Shares will be issued, fully paid, on 7 May 2009. New Ordinary Shares in uncertificated

form are expected to be credited to CREST stock accounts on 7 May 2009 and definitive share

certificates for New Ordinary Shares in certificated form are expected to be despatched on 14 May

2009.

7. Description of restrictions on free transferability

Save as set out below, the New Ordinary Shares are freely transferable.

Premier may, under the Companies Act 2006, send out statutory notices to those it knows or has

reasonable cause to believe have an interest in its shares, asking for details of those who have aninterest and the extent of their interest in a particular holding of shares. When a person receives a

statutory notice and fails to provide any information required by the notice within the time specified

in it, Premier can apply to the court for an order directing, among other things, that any transfer of

the shares which are the subject of the statutory notice is void. The Directors may also, without

giving any reason, refuse to register the transfer of any Ordinary Shares which are not fully paid.

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8. Mandatory takeover bids, squeeze-out and sell-out rules

Other than as provided by the City Code and Chapter 3 of Part 28 of the Companies Act 2006, there

are no rules or provisions relating to mandatory bids and/or squeeze-out and sell-out rules relating tothe Ordinary Shares.

9. Public takeover bids in the last and current financial years

There have been no public takeover bids by third parties in respect of the share capital of Premier in

the last or current financial year.

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PART X

OPERATING AND FINANCIAL REVIEW

Some of the information contained in this review and elsewhere in this document includes forward-

looking statements that involve risks and uncertainties. See ‘‘Forward-looking statements’’ on page 20for a discussion of important factors that could cause actual results to differ materially from the

results described in the forward-looking statements contained in this document.

This review should be read in conjunction with (i) Premier’s audited financial statements and (ii) the

notes explaining the financial statements contained in Premier’s annual report and accounts for the

three years ended 31 December 2008 which are incorporated into this document by reference, as

explained in Part XVII of this document.

Unless otherwise indicated, the selected financial information included in this Part X has been

extracted without material adjustment from Premier’s audited financial statements for the three years

ended 31 December 2008. The financial information set out in this Part X does not constitute

statutory accounts for any company within the meaning of section 435 of the Companies Act 2006.

Shareholders should read the whole of this document and the documents incorporated herein by

reference and should not rely solely on the summary operating and financial information set out in

this Part X.

Introduction

Premier is a leading FTSE 250 independent exploration and production company with gas and oil

interests in Asia, Middle East & Pakistan, the North Sea and West Africa. The Company’s strategy is

to add significant value through exploration and appraisal success, astute commercial deals, and asset

management.

1. OPERATING AND FINANCIAL REVIEW OF 2006

OPERATING REVIEW

Production and reserves

In 2006, working interest production averaged 33,000 boepd (2005: 33,300 boepd). Production

comprised 33% liquids and 67% gas, with Pakistan and Indonesia each accounting for around 37%

and 35% of the total respectively, the UK 21% and West Africa the remainder. On an entitlement

basis, Group production for the year was 28,900 boepd (2005: 28,700 boepd).

Working Interest Entitlement

Production (boepd) 2006 2005 2006 2005

North Sea 6,850 9,750 6,850 9,750

Middle East & Pakistan 12,150 11,500 12,150 11,500

Asia 11,550 12,050 7,800 7,450

West Africa 2,400 — 2,100 —

Total 33,000 33,300 28,900 28,700

As at 31 December 2006 proven and probable reserves, on a working interest basis, based on Premier

and operator estimates, were 152 mmboe. On a pro forma basis, the Scott field acquisition would

have increased reserve estimates to 165 mmboe.Proven and

probable

reserves

(mmboe)

Reserves and

contingent

resources

(mmboe)

Start of 2006 164 232Production (12) (12)

Net additions and revisions — 69

End of 2006 152 289

Scott acquisition* 13 13

Pro forma total 165 302

* Expected to be completed in the first half of 2007.

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At year-end, reserves comprised 18% liquids and 82% gas, and the equivalent volume on an

entitlement basis amounted to 132 mmboe (2005: 146 mmboe).

Booked reserve revisions represented the write-down of five mmboe from the Chinguetti field in

Mauritania, offset by an increase in booked reserves from the Anoa field in Indonesia following

strong offtake volumes by the buyers under the existing GSA. Discoveries made in 2006 in Vietnam

were not recorded in booked reserves at the end of that year, pending completion of ongoing

appraisal and commercialisation work. These volumes, together with others in the process of being

commercialised (including unsold gas in Indonesia and other discoveries which had not yet received

development sanction elsewhere) gave increased total reserves and contingent resources of 289 mmboe

(2005: 232 mmboe).

Exploration and appraisal

Premier’s achievement in growing its exploration portfolio yielded a series of exploration successes in

2006 and the opening up of significant follow-on opportunities. The Company also continued to seek

and sign-up new prospective areas in its North Sea, West Africa and Asia regions.

In 2006, Premier drilled 11 exploration and appraisal wells with a success rate of over 60%. In

Vietnam, the Group drilled three wells resulting in a successful appraisal well and two new

exploration discoveries. In its Indonesian West Natuna Blocks, it made three discoveries. Five ofthese six wells were Premier-operated. The Chim Sao oil discoveries were the first in the vicinity, and

opened up substantial future opportunities across two large tranches of mostly unexplored acreage in

Vietnam (Block 12 and Block 07/03) and another large tranche in Indonesia (the Tuna Block),

awarded in March 2007.

The Company considered that these successes in Asia confirmed the validity of its strategy of

extending the knowledge gained over many years from the Group’s interests in the IndonesianNatuna Sea area into the neighbouring Vietnamese waters. In adding acreage around the world

during 2006 – in Vietnam, in Indonesia, in Congo and in Norway – the Group was mindful of

staying within its areas of competency.

Premier planned to spend no more than US$50 million on seismic and drilling in 2006. In order to

ensure a broad exposure to high reward prospects and, at the same time, keep the cost exposure

down, the Group undertook several farm-outs, reducing its equity in projects in return for fundingcurrent exploration on favourable terms. These projects included farm-outs for the 2006 wells in

Vietnam Block 12E and W, and for the 2007 wells in Guinea Bissau, the UKCS Peveril well and the

Philippines Ragay Gulf SC43 licence.

Asia

Indonesia

Premier’s core asset in Indonesia is its interest in the West Natuna Gas project, which supplies gas

under a long-term gas sales contract to Singapore. This is held through equity interests in the Natuna

Sea Block A and the Kakap PSCs.

In 2006, Premier-operated Natuna Sea Block A sold an overall average of 130 BBtud gross with a

further 66 BBtud gross average sold from the non-operated Kakap fields under the same agreement.Oil production from Anoa averaged 2,581 bopd gross (2005: 3,023 bopd gross) with the reduction

due to natural depletion of the oil reservoirs. Oil production from Kakap averaged 6,998 bopd gross

(2005: 7,263 bopd gross).

Overall, net production from Indonesia amounted to 11,550 boepd (2005: 12,050 boepd) with Anoa

and Kakap contributing 7,890 boepd and 3,660 boepd respectively.

Premier’s commitment to health, safety and environmental performance was demonstrated with the

award of OHSAS 18001 and retention of the ISO 14001 certification and Indonesia’s ‘PROPER Blue’

rating.

The West Lobe wellhead platform was installed in April 2006, with hook-up taking place in May

2006. The Seadrill-5 jack-up drilling rig arrived on location at the platform in August 2006 to drillfour gas production wells into the West Lobe of the Anoa field. All wells achieved their objectives

with first gas flowing from the platform in December 2006. During the drilling campaign an

opportunity was taken to appraise an un drilled potential oil reservoir in the central area of the Anoa

field. The well successfully encountered and evaluated a 67 feet oil column before being sidetracked to

the planned gas development location for the well.

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Negotiations for further gas sales from Natuna Sea Block A continued with prospective buyers in the

region and discussions were also held with PLN, the Indonesian national power company, to sell gas

domestically to Batam.

The 2006 Indonesian exploration drilling campaign resulted in a 100% success rate with a gas

discovery in Macan Tutul-1 and the discovery and testing of oil and condensate rich gas at Lembu

Peteng-1. Technical studies were also carried out across other areas on Block A to identify additional

potential drilling targets for the 2007 drilling campaign. A number of prospects were highlighted for

further assessment, with the final programme dependent on ongoing work and results of the early

wells.

During the year, Premier acquired a 16.67% stake in the North Sumatra Block A PSC. Initially

Premier partnered with Japex and Medco holding equal interests. After year-end Premier increased its

stake in the PSC to 41.67% by jointly purchasing the ConocoPhillips share of the PSC with Medco.

The acquisition cost for the two transactions was US$53 million.

The acreage contains undeveloped discoveries on the Alur Siwah, Alur Rambong, and Julu Rayeufields, with certified reserves of over 650 bcf of gas. There was substantial upside from around 20

identified exploration prospects, with total prognosed unrisked potential reserves of 1.5 tcf gross,

enhanced oil recovery opportunities through redevelopment of old abandoned oil fields, as well as

from the possible development of the giant Kuala Langsa gas field.

In December 2006, Premier was awarded an interest in the Buton PSC in South Eastern Sulawesi,

partnered by Japex and Kufpec with a 30% non-operated interest. The Buton PSC covers 3,396

square kilometres and lies on the south-eastern side of Buton Island, Sulawesi, Indonesia and is anunder-explored block in an onshore frontier area. Oil seeps are prolific over the island and volumes

of expelled oil are sufficient to underpin the commercial asphalt mining operations that have been

ongoing on the island since colonial times. The acreage has potential for multiple targets on

structures that are known to exist from satellite image analysis.

Vietnam

In 2006, Premier drilled three successful exploration wells as operator and acquired over 1,500

kilometres of 2D marine seismic data on Block 12. The first discovery, Dua-4X, drilled in the north

of the Dua field, confirmed the extent of an oil accumulation first discovered in 1974 with the Dua-

1X well. Dua-4X was then sidetracked to delineate the northern half of the Dua field. The rig was

then moved to drill the Dua-5X well which intersected oil in multiple reservoirs in the southern part

of the Dua field. Two reservoir zones were tested and flowed at a combined rate of 6,947 boepd.

Dua-5X was then suspended as a potential producer.

The second exploration structure to be drilled was 20 kilometres to the southwest at Chim Sao, where

well 12E-CS-1X discovered oil in multiple reservoir zones, two of which were tested at a combined

rate of 6,569 boepd. This well was sidetracked to delineate the extent of the hydrocarbon bearing

reservoir. Following this exploration success, Premier commenced appraisal and development studies

for each of the Chim Sao and Dua discoveries.

In December, Premier exercised an option to acquire from VAMEX a 45% working interest in, and

operatorship of, Block 07/03. Block 07/03 is located immediately to the southeast of Block 12 in the

Nam Con Son Basin. Interpretation of 2D marine seismic data from Block 07/03 had demonstrated

the existence of the same play elements which create petroleum prospectivity in Block 12 and the

potential for numerous large structures suitable for high-impact well locations.

India

Drilling commenced on the high-impact Masimpur prospect in Assam on 21 January 2007. Work got

under way to prepare for the drilling of two follow-up wells to Masimpur on the large Hailakandi

and Kanchanpur gas prospects. Road and site construction began at Hailakandi following

environmental approvals. Premier is operator of the Cachar Block and holds a 14.5% working

interest.

All outstanding issues were resolved between the partners regarding the development of the Ratna oil

fields, offshore Mumbai, and documentation leading to the formal signature of the PSC was

progressed. Premier holds a 10% (carried) working interest in the Ratna fields, estimated to contain

around 80 mmbbls.

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Philippines

During 2006, Premier operated the SC43 licence in the Ragay Gulf area of SE Luzon province with a

42.5% working interest. Seismic reprocessing, geological studies and preparatory work for a well onthe Monte Cristo prospect have been carried out. Geological work led to the identification of a new

prospective trend in the Panaon Limestone formation. Subsequent to year-end, Premier has farmed

out 21.5% of its 42.5% interest to Pearl Energy and PNOC in exchange for a carry in the

forthcoming well.

Middle East & Pakistan

Pakistan

The record production level achieved in 2005 was exceeded during 2006. Production net to Premier in

2006 was 12,150 boepd, an increase of 6% over 2005 (11,500 boepd). The increase in production was

mainly due to higher sales from the Zamzama field, from exceptionally high gas demand.

Qadirpur produced an average of 3,866 boepd, for Premier’s net interest of 4.75% (2005: 3,807

boepd). The project to enhance Qadirpur plant capacity from 500 mmscfd to 600 mmscfd was

ongoing through 2006 and first gas from that increased capacity was expected by the end of

December 2007. A Term Sheet was signed with the gas buyer, SNGPL, to increase the ACQ from theexisting 450 mmscfd to 550 mmscfd. The Qadirpur Deep-1 well has been drilled to a depth of 4,681

metres. The well encountered hydrocarbons in several zones and was suspended when higher than

anticipated temperatures were encountered.

On Kadanwari, the K-15 well was tied back to the processing plant. The additional production fromit compensated for the natural decline of the field and also provided some production redundancy.

The field produced an average of 1,200 boepd during 2006 (2005: 1,228 boepd) for Premier’s interest

of 15.79%.

Zamzama produced an average of 4,140 boepd, net to Premier, during 2006 from its 9.375% interest.This was some 13% higher than the previous year (2005: 3,677 boepd). Work continued in 2006 on

the Zamzama Phase 2 development.

The production level in the Bhit field, from Premier’s 6% working interest, was 2,944 boepd in 2006

(2005: 2,788 boepd). A supplemental GSA to increase the Bhit ACQ from 270 mmscfd to 300mmscfd was signed by the gas buyer SSGCL and by joint venture partners. Enhancement of the Bhit

plant capacity to 315 mmscfd commenced, to allow accelerated Bhit field production and production

of Badhra reserves.

In Zarghun South, negotiations on the GSA were successfully concluded with the gas buyer, SSGCL,for the sale of 22 mmscfd gas from the field and the field development commenced. Premier’s interest

of 3.75% was carried by the operator (other than for government commitments) during the

development and production phases of the field.

Egypt

In Egypt, the Al Amir-2 well was drilled to appraise the 2005 Al Amir discovery on the onshoreNorth West Gemsa Concession. The discovery well, Al Amir-1, had flowed oil at over 750 bopd from

the South Gharib Formation. The Al Amir-2 well confirmed oil at the same reservoir level. However,

on test, the well flowed water and oil at sub-commercial rates and was plugged and abandoned. The

Al-Fagr wildcat well was plugged and abandoned after MDT tests were run. Although shows were

recorded while drilling and logs displayed possible hydrocarbon saturations in the target section, no

hydrocarbons were recovered on test. Subsequent to year-end, Premier exercised an option with the

operator, Vegas, to reduce its interest to 10% in the block which entitled Premier to a partial refund

of past costs. Premier continued to participate in exploration licensing rounds and farm-in discussionswith a view to building on its position in Egypt.

New business efforts continued to be focussed on building existing relationships in the region.

North Sea

In the North Sea, Premier continued to pursue the established strategy of seeking out high-impact

exploration opportunities while maximising the value from its existing producing assets.

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UK

Production in the UK in 2006 amounted to 6,850 boepd (2005: 9,750 boepd) representing 21% of the

Group total (29% in 2005). This represented a decrease of some 30% on the 2005 level, due to acombination of natural decline and specific operational problems.

The Wytch Farm oil field contributed 3,205 boepd net production to Premier, down 20% on 2005. In2006, the production performance was severely impacted by a number of serious well failures. In

January, the F05 well, producing 3,000 bopd gross, failed and required a workover. The well was

brought back onstream in March. The M07 well was completed and brought on production in

February but was suspended due to a suspected collapsed hole. The subsequent intervention was

unsuccessful and the well was redrilled and production re-established in June. Year-end production

recovered to 27,000 boepd gross (3,300 boepd net).

Net production from Kyle was 1,962 boepd, down 46% on 2005. Gas production remained below the

annual target for most of the year, however, this was compensated by higher oil production that

enabled Kyle to deliver in line with the annual composite production budget. The re-perforation of

the Kyle-15 well was delayed until October and when completed produced disappointing results. The

K-16 well that was scheduled to be drilled in 2006 was rescheduled to 2008 and the gas lift projectoriginally planned to commence in 2006 slipped to 2007.

In the Fife area, Premier’s net production amounted to 1,156 bopd from the Fife, Fergus, Flora and

Angus fields. The Angus field was suspended in September 2006 after an intervention failed andremained suspended subject to the joint venture determining the forward strategy for this asset. The

Fife FPSO fixed contract term will, unless extended, end in December 2007.

Scott and Telford accounted for the remainder of net UK production. In December 2006, the

Company received notification of Hess’ intention to sell its 20.05% equity interest in the Scott field to

Nexen Petroleum UK, which Premier pre-empted, such that its working interest became 21.83%

effective 1 January 2007, representing an average 2007 entitlement of 5,000 bopd at expected

production rates.

Detailed evaluation of the UK exploration portfolio continued throughout 2006 working on

developing the prospects to drillable candidates for 2007 and 2008, specifically in Blocks 23/22b

(P1181) and 21/7b (P1177) in the Central North Sea. Further geological and geophysical work

integrated with a comprehensive commercial evaluation on the Southern North Sea portfolio of

Blocks 44/21c, 44/26b (P1184), Blocks 42/10, 42/15 (P1229) and Blocks 43/22b, 43/23, 43/27b, 43/28

and 43/29 P1235 resulted in Premier having fulfilled the work obligations for these licences,relinquishing them in December as no commercial viable hydrocarbon prospects were identified.

Integration of the results from the 21/6a-7 well on the Palomino prospect in licence P1048, which was

plugged and abandoned dry in January 2006, were being integrated into the adjacent licence P1177

evaluation to assess the remaining prospectivity.

Premier’s 100% equity in the Fife area Blocks 39/1c and 39/2c was successfully farmed down to a

30% equity level carried through the forecast costs of the Peveril prospect well. Significant follow on

potential was provided by Blocks 39/1b and 39/7 (P1152) where additional prospects were identified

on the reprocessed 3D seismic.

Two licence applications were made by Premier in the UK 24th Licensing Round covering Blocks 15/

23c, 15/24a, 15/25f and 15/29e.

Norway

The five licences awarded to Premier in the APA 2005 Licensing Round were progressed through the

work programmes tendered to reach critical decision points: drill or drop for three of the licences by

the end of 2007; acceleration of a possible well on one licence and development approval for the

Frøy potential redevelopment. These licences offer a spectrum of redevelopment, appraisal and

exploration opportunities which have the potential for both early production and high-impactexploration. The five APA 2005 licences consist of Blocks 35/12 and 36/10 licence PL378; Blocks 16/1

(part) and 16/4 licence PL359, Blocks 34/2 and 34/5 licence PL374(s), Blocks 34/4 (part) and 34/5

licence PL375, and Blocks 25/2, 25/3, 25/5 and 25/6 PL364 Frøy.

The Frøy field was abandoned in 2001 by a previous operator in a much lower oil price environment

and due to the imminent abandonment of the nearby Frigg field to which it was tied back. The Frøy

field was the subject of extensive redevelopment studies with plans to seek early development

approvals.

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Premier was very active in the APA 2006 Licensing Round, submitting applications for five potential

licences. The licence round announcement in January 2007 confirmed that the Company had been

successful in securing five new licences, including two licences in the very competitive Bream discovery

area. The licence interests obtained in the APA 2006 Round were as follows:

Block no. (or part block no.)

Working

interest % Operator

17/8,9,11,12 & 18/7,10 (Bream appraisal) 20 BG

7/12,8/3,9/1,18/10 & 18/11 (Bream exploration) 40 Premier

31/3,32/1,36/10 40 Revus

35/9 (part) 25 Nexen

35/8 15 Nexen

Premier successfully qualified as an operator in Norway in 2006 and the award as operator for theBream exploration acreage reflected Premier’s commitment to develop a business in Norway. The

licence has a five-year first-term duration requiring 3D seismic acquisition and a firm well. Blocks

31/3, 32/1 and 36/10 are adjacent to the PL378 licence and help in the development of a core area

around the Tampen Spur for Premier. The remaining two licence awards are adjacent to the Gjøa

field and offer some interesting stratigraphic potential.

West Africa

Mauritania

The Chinguetti oil field started production in Woodside operated PSC B on 24 February 2006 at an

initial rate of 70,000 bopd (5,600 bopd net to Premier). The field is located in 800m of water some 90

kilometres west of the capital Nouakchott.

The initial development of six production wells and three water injectors did not perform to initial

expectations in 2006. This is the result of greater than expected reservoir compartmentalisation due to

reservoir geometry and complex structure. Production at the end of 2006 was in the region of 22,000

bopd (1,780 bopd net to Premier). Remedial action to increase production commenced in late

December with the drilling of the Chinguetti-18 well. This well encountered 35 metres of net oil pay,close to expectations, and was being completed at the end of the reported period. Additional

development drilling was planned, with up to six wells being considered.

The performance of the initial development wells had an impact on the expected reserves of the field,

with the operator’s proven and probable reserves being reduced from the pre-development expectation

of 123 mmbo to 62 mmbo. However, further upward revisions were expected, and the reserves were

also expected to increase with further phases of development drilling, if commercially viable.

In 2006, the Mauritanian government challenged certain amendments (avenants) to Woodside

operated concessions, including those in which Premier has an interest (PSCs A and B). This resulted

in the joint ventures signing revised PSCs with the Mauritanian government in June 2006, under

which the fiscal provisions in the contracts were altered to reflect the higher oil prices prevailing at

that time at a net cost to Premier of US$9.2 million.

Two exploration wells were drilled in Premier’s Mauritanian acreage, Dore-1 in PSC B and Colin-1 in

PSC A. Both wells failed to encounter hydrocarbons. A third well, Kibaro-1, which had been planned

to test a Cretaceous objective in PSC A, was deferred to 2008 due to rig scheduling necessitated to

drill the Chinguetti-18 well.

In December 2006, following a number of approaches, the Board determined that the Company’s

interests in Mauritania were unlikely to generate high-impact exploration opportunities which are the

Group’s key targets in the region. Accordingly, the Company decided to conduct an auction with a

view to the sale of the asset. The results of the Mauritanian operation were therefore classified

separately in the financial statements for 2006 under ‘assets held for sale’.

Guinea Bissau

During 2006, processing of the 2005 3D seismic data over the Eirozes prospect, and re-processing of

the existing 3D seismic over the Espinafre prospect, were completed. The two data sets were

interpreted to mature the Espinafre and Eirozes prospects for drilling.

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Gabon

In 2006, both existing 2D and 3D seismic data on the Sterling Energy operated Themis Permit were

re-processed. The results of the interpretation of this re-processed data were incorporated into ablock-wide understanding of the prospectivity to mature a prospect for drilling. Premier, as drilling

operator for the joint venture, contracted the Global Santa Fe ‘Adriatic 6’, to drill this exploration

well in 2007.

Data interpretation and studies on the Dussafu Permit were carried out during 2006 leading to

development of a leads and prospects portfolio to be used to find potential targets for drilling in the

fourth quarter of 2007, or the first quarter of 2008.

Congo

During 2006, Premier was awarded a 58.5% operated working interest in Block IX, with its joint

venture partners Ophir Energy and the Congo national oil company, SNPC. The PSC was ratified by

the Congolese Parliament on 5 October 2006. The block contains several prospects with high-impact

exploration potential. Technical evaluation was ongoing with the expectation that the first well on the

block could commence in 2008.

SADR

The Company’s exploration assets in SADR remained under force majeure, awaiting resolution of

sovereignty under a United Nations mandated process.

FINANCIAL REVIEW

Economic environment

2006 saw further strength in oil and gas commodity prices reaching a peak early in the second half of

the year. The Brent oil price, which began the year at US$58.9/bbl, averaged US$65.4/bbl reaching a

peak of US$78.6/bbl during August. Gas prices worldwide were also boosted according to the degree

of linkage with crude pricing.

Strong commodity prices and increased industry activity levels continued to put pressure on both

operating and development costs. Rig rates and other drilling service costs remained at historically

high levels and shortages of key vessels and equipment contributed to project delays. The industryresponded to cost and availability issues by seeking out new engineering and commercial approaches

to optimise use of available resources.

Income statement

Production levels in 2006, on a working interest basis, averaged 33,000 boepd compared to 33,300

boepd in 2005. In 2006, this included an average of 2,400 boepd from the Chinguetti field in

Mauritania. On an entitlement basis, which allows for additional government take under the terms ofthe Company’s PSCs, production was 28,900 boepd (2005: 28,700 boepd). Realised oil prices averaged

US$64.90/bbl compared with US$48.38/bbl in the previous year.

Gas production averaged 127 mmscfd (22,000 boepd) during the year, approximately 67% of total

production. Average gas prices for the Group were US$5.11 per mscf (2005: US$3.82/mscf). Gas

prices in Singapore, which are linked to HSFO, moved broadly in line with crude pricing, averaging

US$9.43/mscf (2005: US$7.90/mscf) during the year.

Total sales revenue from all operations was 12% higher than 2005 at US$402.2 million (2005:US$359.4 million) as a result of the higher average commodity prices. Excluding revenues of US$43.4

million from the Chinguetti field, sales revenue for continuing operations was US$358.8 million.

Cost of sales decreased to US$126.6 million compared to US$176.5 million in 2005. The year-end

inventory position moved from a stock overlift to an underlift position, driven by the timing of

liftings around each year-end, resulting in a credit to cost of sales of US$22.3 million (2005: charge of

US$25.9 million). After excluding this stock effect, underlying unit operating costs were stable at

US$6.0/boe (2005: US$5.9/boe) despite the general rise in the cost environment faced by the industry

in fuel, material and wage costs. Underlying unit amortisation amounted to US$6.3/boe (2005:US$5.5/boe).

The cost of sales and operating cost figures for 2006 exclude those relating to Mauritania, which were

separately reported in the balance sheet and income statement for 2006 as assets held for sale. The

results of the Mauritanian operation include a one-off adjustment for a bonus of US$9.2 million paid

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to the Mauritanian authorities on renegotiation of the PSC documentation and a loss on classification

as assets held for sale of US$8.1 million.

Administrative costs fell by US$3.0 million to US$16.6 million. This included a charge of US$5.7

million in respect of current year and future provisions for long-term incentive plans.

Operating profits were US$178.5 million, a 41% increase from the prior year. Finance charges net of

interest income totalled US$5.7 million (2005: US$1.1 million). Pre-tax profits were 37% higher at

US$172.8 million (2005: US$125.8 million). The taxation charge totalled US$86.7 million (2005:

US$86.3 million) despite higher profits benefiting from the favourable resolution of certainoutstanding prior year provisions. Basic earnings per share from continuing operations amounted to

105.3 cents, an increase of 119% on the previous year.

Cash flow

Cash flow from operating activities, including the assets held for sale, amounted to US$244.8 million,

up from US$121.2 million in 2005. These cash flows included payments of US$31.9 million received

from the joint venture in Pakistan (2005: US$47.1 million).

Capital expenditure and pre-licence exploration expenditure in the year was US$175.7 million (2005:

US$144.4 million). This spend included the US$17.0 million cost of the Group’s first acquisition in

North Sumatra Block A in Indonesia (an equity interest of 16.67%) which was completed in March2006. Exploration spending was US$46.9 million in line with the Company’s stated target.

Net cash inflow, before movements related to financing, amounted to US$69.1 million (2005: US$23.2million outflow).

Net cash position

Net cash at 31 December 2006 amounted to US$40.9 million against a net debt position of US$26.2

million at the previous year-end. This comprised cash balances and short-term investments. As a

result of this strong cash position, the US$275 million credit facility was undrawn at year-end.

Key performance indicators

2006 2005 Change

LTI and RWDC frequency rate* 1.24 1.02 Up 22%

Production (kboepd) 33 33 —

Cash flow from operations (US$) 244.8 121.2 Up 102%

Operating cost per boe (US$) 6.0 5.9 Up 2%

Gearing (%)** 0% 7% Down 7%

Realised oil price per barrel (US$) 64.9 48.4 Up 34%

Realised gas price per mcf (US$) 5.11 3.82 Up 33%

* Lost time injury and restricted workday cases per million man-hours worked.

** Gearing is net debt divided by net assets.

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2. OPERATING AND FINANCIAL REVIEW OF 2007

OPERATING REVIEW


In 2007, working interest production averaged 35,750 boepd (2006: 33,000 boepd). Production

comprised 34% liquids and 66% gas, with Pakistan and Indonesia accounting for 36% and 34% of the

total respectively, the UK 28% and West Africa the remainder. On an entitlement basis, Group

production for the year was 31,450 boepd (2006: 28,900 boepd).

Working interest Entitlement

Production

2007

boepd

2006

boepd

2007

boepd

2006

boepd

Asia 12,000 11,550 7,900 7,800


North Sea 9,850 6,850 9,850 6,850

West Africa 1,200 2.450 1,000 2,100

Total 35,750 33,000 31,450 28,900

As at 31 December 2007 proven and probable reserves, on a working interest basis, based on Premierand operator estimates, were 212 mmboe. This represented a 39% increase in net proven and probable

reserves since 31 December 2006.

Proven and

probable

reserves mmboe

Reserves and

contingent

resources

mmboe

Start of 2007 152 289

Production (13) (13)

Net additions and revisions 73 93

End of 2007 212 369

At year-end, reserves comprised 18% liquids and 82% gas. The equivalent volume on an entitlement

basis amounted to 183 mmboe (2006: 132 mmboe).

Booked reserve additions and revisions included an increase in booked reserves in the Indonesian

West Natuna Sea Block A resulting from an additional GSA, and the North Sumatra Block A gas

development for which a GSA was signed with the PIM Fertilizer Plant. Significant reserve additions

also included the acquisition of the Scott field interest. There were reserves increases on the Kakapfield in Indonesia and the Zamzam field in Pakistan. In the UK, a reduction in Wytch Farm reserves

was offset by increased reserves on the Kyle field. Contingent resource bookings increased to include

the Banda gas discovery in Mauritania, the Kuala Langsa gas discovery in North Sumatra Block A,

the Bream discovery in Norway and the Chim Sao oil field in Vietnam where an Outline

Development Plan was submitted. These volumes, together with others in the process of being

commercialised, gave increased total reserves and contingent resources of 369 mmboe (2006: 289

mmboe).


Premier continued to drill up and expand its exploration portfolio during 2007 and participated in 11

exploration and appraisal wells giving four successes; eight of these wells were drilled by Premier’s

operations team. It acquired new seismic data, reprocessed old data and sought out and signed newlicences in Norway and Vietnam.

Exploration spend on drilling and seismic in 2007 was US$104.7 million pre-tax (post-tax andrecoveries: US$77.5 million). Costs of the exploration programme were reduced from original

estimates by prudent farm-outs in the UK, India and Guinea Bissau.

A focus of the Company’s exploration effort in 2007 was in Vietnam on its Block 12W PSC. The

Company’s Chim Sao sidetrack, drilled early in 2007, confirmed the down-dip extent of the 2006

Chim Sao discovery. Subsequently a large 3D survey (1,600 square kilometres) was acquired over the

block. The Company’s farm-in to the adjacent block, the 07/03 PSC, was ratified by the Vietnamese

105


authorities during the year, allowing the Company to assume operatorship and to accelerate the

exploration of this large, under-explored block. The Company actively built up its Vietnamese

knowledge and was granted another, previously under-explored, licence Block 104-109/05.

Premier also had an active year in Indonesia, with two discoveries, Pancing and Ibu Lembu, thesigning of two new blocks, the Tuna and Buton PSCs, and the purchase of additional equity in its

North Sumatra Block A acreage. These new blocks provided an exciting set of exploration prospects

and, in the case of the North Sumatra acreage, include appraisal of earlier discoveries.

In Pakistan, the Company participated in the successful Qadirpur Deep-1 well, targeting hitherto

undrilled reservoir zones below the Qadirpur field.

Premier also drilled some high-potential but high-risk exploration wells during the year. In advance of

drilling the Company prudently reduced its financial exposure by farming out the well costs on

favourable terms. These wells included Masimpur-3 in India, Peveril in the UKCS, two wells offshore

Guinea Bissau and the Anne-1 well offshore Pakistan.

In the North Sea region the Company evaluated new opportunities and subsequently acquired newexploration licences: five in Norway and one in the UK.

Asia

Indonesia

Premier’s core asset in Indonesia is in the West Natuna Sea, where it operates the Anoa field in

Block A (28.67% interest) and is a partner in the Kakap field (18.75% interest). These fields supply

gas under a long-term sales contract to Singapore. In 2007, Premier sold an average of 137 BBtud

gross from the Anoa field and a further 66 BBtud gross from the non-operated Kakap field, under

this agreement.

Gross oil and condensate production from these two fields averaged 2,498 bopd for Anoa (2006:2,581 bopd) and 7,977 bopd for Kakap (2006: 6,998 bopd). Anoa showed a slow natural oil decline,

but Kakap enjoyed improved performance and a full year’s net production in 2007 of 1,495 bopd

(2006: 1,312 bopd).

Overall net production from Indonesia increased to 12,000 boepd in 2007 (Anoa contributing 8,190

boepd and Kakap 3,810 boepd) (2006: 11,550 boepd). The improvement was attributable to increased

gas demand from Singapore and increased oil production on Kakap.

On the Gajah Baru development, Premier met its 2007 goal to have definitive agreements in place for

further gas sales from Natuna Sea Block A. Heads of Agreement were signed with Sembcorp Gas Pte

Ltd for supply of gas to Singapore and with PLN and UBE for domestic supply of gas to Batam.Engineering work confirmed the development concept for the three fields supplying the gas (Gajah

Baru, Naga and Iguana) and a draft Plan of Development was submitted to the government.

2007 saw three exploration wells drilled in Indonesia. In Natuna Sea Block A, the Ibu Lembu-1 well

was drilled to prove the hydrocarbon potential in the adjacent up-dip structure to the 2006 Lembu

Peteng-1 discovery. The well encountered gas in the primary target but following the running of an

extensive data acquisition programme was plugged and abandoned as sub-economic. The second well,

Gajah Sumatera-1 was drilled to appraise a potential extension to the Gajah Puteri field in Natuna

Sea Block A. While the well encountered some gas shows while drilling, wireline logs indicated thatno significant hydrocarbons were encountered and the well was plugged and abandoned. Further

technical studies continued to be carried out in the area to define the hydrocarbon-bearing sand

distribution proven by adjacent wells. The Pancing-1 well was drilled in the Kakap Block to test a

deep structure close to existing infrastructure. The well flowed oil although at sub-economic rates.

However, the well’s results were significant in encountering hydrocarbons in an under-explored play in

the area, raising the possibility of further exploration potential.

Premier completed the joint acquisition with Medco of ConocoPhillips’ 50% share of North Sumatra

Block A in January 2007, bringing the Company’s interest to 41.67%. Negotiations to sell gas from

the undeveloped Alur Siwah, Alur Rambong and Julu Rayeu fields progressed well through the yearculminating in a December signing of a GSPA with two fertilizer plants owned by PIM, a state-

owned entity, for the delivery of 110 BBtud gross for seven years. A second gas sale to PLN for local

electricity generation was further progressed.

Technical studies including field mapping and sampling took place on the Buton PSC on the south-

eastern side of Buton Island, Sulawesi, with the aim of firming up multiple leads originally identified

106


from satellite imagery. Towards the end of the year a contract was awarded for the acquisition of 265

kilometres of 2D seismic data across the block.

In March, Premier was awarded a 65% operating equity interest in the Tuna PSC in the North East

Natuna Sea. The block covers 4,992 square kilometres and lies south of Premier’s operated Block 07/

03 and Block 12W in Vietnam and to the east of the Natuna Sea Block A and Kakap PSCs in

Indonesia. The Tuna PSC represents an under-explored area in the middle of a region in which

Premier has a strong technical understanding.

Vietnam

Premier acquired and interpreted 3D seismic data on the Chim Sao and Dua oil fields in the first half

of 2007, and in December it submitted reserve reports and development plans for these fields to the

government of Vietnam.

During 2007, Premier and the government of Vietnam agreed the merger of Block 12E into Block

12W and extension of the exploration period of the merged PSC. Detailed interpretation of the 3D

seismic data acquired in 2007 defined several exploration prospects to be drilled with the Wilboss

jack-up rig, including a well in the northern part of the Chim Sao field, the Chim Ung (Falcon) well

and the high-impact Chim Cong (Peacock) prospect. Premier operates a 37.5% exploration working

interest in Block 12W. During 2007, Premier assumed the operatorship of Block 07/03 with a 45%exploration working interest.

India

Discussions continued with the government of India to resolve outstanding issues with respect to the

Ratna field development. The Ratna fields lie in shallow water offshore Mumbai and are estimated to

contain around 80 mmbbls. Premier has a 10% carried interest and is the operator.

The Masimpur-3 well in Cachar was successfully drilled with costs being carried in part. The well did

not flow commercial gas or oil volumes during testing and was plugged and abandoned. The PSC

was terminated since no commercial discovery was made during the exploration period.

Philippines

Premier entered 2007 holding a 42.5% operated participating interest in Philippines Licence SC43

located in the Ragay Gulf area of SE Luzon. During the course of the year Premier farmed-out the

operatorship of SC43 and a 21.5% participating interest, leaving Premier with a 21% participating

interest. In exchange for this consideration all of Premier’s costs relating to the Monte Cristo-1

exploration well will be carried. In the fourth quarter of 2007 a 371 kilometre 2D marine seismic

survey was carried out on the same licence over a prospective trend in the Panaon Limestone

formation.


Pakistan

Production in 2007 surpassed the previous record levels achieved in 2006. Production net to Premier

in 2007 was 12,700 boepd, an increase of 5% on 2006 (2006: 12,150 boepd). This additional volume

was due to increased gas demand and was primarily met through additional supply from theZamzama field.

Qadirpur produced an average of 3,980 boepd from Premier’s net interest of 4.75% (2006: 3,866

boepd). The project to enhance Qadirpur plant capacity from 500 mmscfd to 600 mmscfd continuedduring 2007. In addition, negotiations continued with the existing gas buyer for an additional supply

of 75 mmscfd permeate gas (equivalent to 40 mmscfd processed gas) for subsequent use in power

generation. The Qadirpur Deep-1 well was drilled to a depth of 4,681 metres in 2007 encountering

hydrocarbons in several zones. The well was suspended following higher than anticipated temperatures

and pressures.

On Kadanwari, the K-18 well was drilled and tested successfully during 2007. The field produced an

average of 1,260 boepd (2006: 1,200 boepd) from Premier’s 15.79% net interest. An additional well

was planned to be drilled in the second half of 2008.

Zamzama produced an average of 4,620 boepd in 2007 (2006: 4,140 boepd) from Premier’s 9.37%

interest. Work continued in 2007 on the Zamzama Phase 2 development project to produce gross 150

mmscfd HCV gas for sale, but plant problems meant that only MCV gas was able to be supplied.

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Bhit production was 2,840 boepd in 2007 (2006: 2,944 boepd) from Premier’s 6% working interest.

The slight fall in production in 2007 was due to an extended shut down for Phase 2 tie-in work.

Work on the Phase 2 project to enhance Bhit plant capacity to 315 mmscfd completed allowing

accelerated Bhit field production and delivery of first gas from Badhra reserves.

On Zarghun South, negotiations on the Pipeline Tariff Agreement concluded with the gas buyer (a

condition precedent for the already agreed GSA). Premier’s interest of 3.75% in this asset is carried

by the operator during the development and production phases of the field.

Egypt

In September 2007 Premier reduced its equity in the North West Gemsa Concession from 37.5% to

10.0% resulting in a reimbursement of some previous costs from the operator. During the latter part

of the year, the operator conducted geological studies to define the SE Al Amir prospect.

Abu Dhabi

Shareholder agreements were executed in December with EIIC, forming two new joint venture

companies. These companies will pursue the acquisition of upstream oil and gas assets across the

Middle East and North Africa, and will be headquartered in Abu Dhabi.

The first joint venture, to be known as Premco Energy Projects Company LLC, is owned 49% by

Premier and 51% by EIIC and will hold all joint venture assets which are acquired in the United

Arab Emirates. In the event of a change of control of Premier, EIIC will have a pre-emptive right topurchase Premier’s 49% of this joint venture at fair market value.

The second joint venture, to be known as Premco Energy Projects BV, is owned 50% by Premier,

50% by EIIC, and will hold all joint venture assets which are acquired in the Middle East and North

Africa (excluding the United Arab Emirates).

At the formation of the joint ventures, there are no assets or profits attributable to these new entities.

Future acquisitions of new assets by each joint venture will be funded by Premier and EIIC in

accordance with their relevant percentage holding. This joint venture partnership will enable Premier

to access acquisition opportunities across the Middle East and North Africa via EIIC’s relationship

networks, whilst EIIC will benefit from Premier’s industry expertise and operating capabilities.

North Sea

During 2007, Premier continued with its stated strategy of building the North Sea exploration

portfolio to seek high-impact exploration drilling opportunities while maximising the value from

existing production and development assets.

UK

Production in the UK amounted to 9,850 boepd (2006: 6,850 boepd) representing 28% of the Group

total (21% in 2006). The increase, compared to 2006, was due to a combination of improved field

performance across most of the producing assets and the impact of the Scott field acquisition

completed on 17 May 2007.

The Wytch Farm oil field contributed 2,960 boepd net production to Premier, down 8% on 2006.

Production was adversely impacted by problems with the M19 well, offset by an A08 sidetrack wellwhich was drilled and completed in September. Drilling continued on the M20 water injection well.

Seawater injection service was reinstated after a prolonged outage. The shortfall in production due to

the drilling problems was partly compensated by better than expected production rates from the

remaining wells and successful workover activities.

Net production from Kyle was 2,470 boepd, an improvement of 26% on 2006 from better wellperformance. The gas lift project was completed for all four production wells resulting in a

substantial boost in production with initial gross rates around 9,000 boepd.

Premier completed the purchase of an additional 20.05% equity in the Scott field in May 2007 adding

an average of 5,240 boepd net over the remainder of the year. As a result of this transaction,

Premier’s working interest became 21.83%. The Scott field gross production for the year was 27,750

boepd; this amounted to a full year average of 3,630 boepd net to Premier at the combined equitylevels.

Telford produced slightly below expectation during 2007 following disappointing results from the

Mamion well; gross field production averaged 9,560 boepd (70 boepd net to Premier). 2007 saw the

108


completion of a substantial infill drilling programme consisting of six wells on Scott and one well on

Telford.

In the Fife Area, Premier’s net production amounted to 720 bopd, below expectation due to major

integrity issues with the flexible risers.

Premier operated the Peveril prospect well, located only 10 kilometres south of the Fife field, which

was completed within budget at no cost to Premier. The Peveril well encountered an unexpectedly

thick interval Kimmeridge Clay and no target Fife reservoir sands.

In the UK 24th Licensing Round, Premier was awarded a split portion of 15/24a. The firm work

programme includes seismic reprocessing and study work.

Norway

On the Frøy field in Norway, development planning was progressed. Following concept selection in

September, lease/purchase bids were sought for the jack-up production drilling storage and offtake

unit. These showed significant increases on previous budgetary estimates submitted by suppliers; the

operator was requested to implement a major cost reduction exercise to bring investment down to anacceptable level. The operator was also asked to investigate third-party business opportunities and

exploration upside to improve the robustness of the project as well as tackling other key issues such

as contract guarantees. The partnership issued a Declaration of Continuation at the beginning of

January.

Premier was awarded a further five licences in the APA Licensing Round in January 2007: the Bream

appraisal licence (PL407); the adjacent Bream exploration licence (PL406); PL418 and PL419, down-

dip from the Gjoa discovery, and PL417 adjacent to the Company’s existing licence PL378.

West Africa

Mauritania

Chinguetti production averaged 14,800 boepd (1,200 boepd net to Premier) in 2007. Drilling of the

Chinguetti-18 well was completed in the first quarter of 2007, in line with expectations, and a work-

over was conducted on Chinguetti-14. Operational planning was progressed for the Phase 2Bdevelopment of Chinguetti in 2008 comprising two new production wells and three work-overs.

High resolution 3D seismic surveys were recorded over the Chinguetti and Tiof areas in 2007. A 4D

seismic survey was also recorded over the Chinguetti field, which greatly assists selection ofproduction well locations for the Phase 2B development programme.

In 2007, Premier terminated discussions with a preferred bidder for its Mauritanian operations. In

late 2007, Petronas acquired Woodside Energy’s assets and operatorship in Mauritania PSC A, PSCB and Chinguetti. Opportunities and development options on PSCs A and B continued to be

evaluated with the new operator.

The Atwood Hunter drilling rig was contracted for the Chinguetti Phase 25 and Banda-NW appraisal

programme.

Guinea Bissau

Premier operated a two-well exploration programme during the first half of 2007, using the Global

Santa Fe jack-up rig ‘Baltic’. The wells were completed within budget and without incident. Premier

reduced its exposure to the drilling costs by farming out some of its interests.

The Espinafre-1 well was plugged and abandoned on 23 March 2007 after encountering hole stability

problems. The Eirozes-1 well was plugged and abandoned on 24 April 2007. This well encountered a

significant reservoir section but no hydrocarbons.

Following post-well analyses and re-assessment of the remaining prospectivity of the Sinapa and

Esperanca Permits, Premier effectively withdrew from both concessions in Guinea Bissau in December

2007.

Gabon

The Themis Permit (non-operated) is located in the Gamba play fairway, offshore southern Gabon.

The Themis PSC joint venture commenced drilling the Themis Admiral Marin-1 (THAM-1) well in

December 2007; the well was plugged and abandoned with hydrocarbon shows on 13 January 2008.

The Dussafu Permit (non-operated) is located south of Themis, adjacent to the Congolese border. The

PSC was extended to a Second Exploration Term effective May 2007, with a 2D seismic commitment.

109


In December 2007, Premier signed a Sale and Purchase Agreement with a qualified party to acquire

Premier’s 25% participating interest in the Dussafu PSC. The transaction was completed on 8 March

2008.

Congo

Significant progress was made in the evaluation of the deep water Marine Block IX exploration

acreage. Premier, as operator, conducted a detailed evaluation of Albian ‘raft’ prospectivity, the

characteristic proven play in the area. This identified the Frida and Ida prospects, both in excess of

250 mmbbls gross potential. The joint venture also mapped the potential of Tertiary channel sands

that have proven productive in the adjacent Haute Mer Concession.

Premier and its joint venture partner actively progressed planning for a discretionary drilling

programme of up to two wells. The Company was also in advanced discussions with a party to farm-

in to Premier’s equity interest in Marine Block IX in return for a carry of its costs.

SADR

The Company’s exploration rights in SADR remained under force majeure, awaiting resolution of


FINANCIAL REVIEW


2007 was a year of record oil and gas commodity prices, approaching US$100/bbl towards the end of

the year. The Brent oil price, which began the year at US$60.1/bbl averaged US$72.7/bbl, reaching a

peak of U5$95.8/bbl during November. Gas prices worldwide were also boosted according to the

degree of linkage with crude oil. The sustained period of stronger commodity prices and increased

industry activity levels put further pressure on both operating and development costs. Rig rates and

other drilling service costs were at historically high levels. Shortages of experienced staff and longer

lead times for development equipment added further cost pressures on the industry. The industryresponded to cost and availability issues by optimising the use of available resources, innovative

resource-sharing and focussing on fast track development solutions.

Income statement


boepd in 2006. On an entitlement basis, which allows for additional government take under the termsof the Company’s PSCs, production was 31,450 boepd (2006: 28,900 boepd). Realised oil prices

averaged US$72.3/bbl compared with US$64.9/bbl in 2006.

Gas production averaged 135 mmscfd (23,500 boepd) during the year, or approximately 66% of total

production. Average gas prices for the Group were US$5.60/mscf (2006: US$5.11/mscf). Gas prices in

Singapore, which are linked to HSFO, moved broadly in line with crude pricing, averaging US$11.30/mscf (2006: US$9.43/mscf) during the year.

Following the Group’s decision to terminate discussions with a preferred bidder, the financial results

for Mauritanian operations were no longer required to be presented separately. During 2007, the

Group also restructured its business in Pakistan by de-merging interests from the Premier-KufpecPakistan joint venture and fully consolidated its share of operations in Pakistan. This restructuring

had no impact on the consolidated financial statements.

Total sales revenue from all operations was 44% higher than 2006 at US$578.2 million (2006:

US$402.2 million) as a result of higher production and commodity prices.

Cost of sales was US$267.5 million (2006: US$179.2 million) after including a cost of US$26.8 million

for inventory acquired with the Scott field acquisition. The year-end inventory position moved from a

stock overlift to an underlift position, driven by the timing of liftings around each year-end, and

resulted in a charge to cost of sales of US$27.3 million (2006: credit of US$22.4 million). After

excluding the effect of inventory movements, underlying unit operating costs were higher atUS$9.0/boe (2006: US$7.1/boe) due to one-off cost increases in Indonesia and increased production

from the Scott field in the North Sea. Unit amortisation amounted to US$8.2/boe (2006: US$7.9/boe).

Exploration expense and pre-licence exploration costs amounted to US$65.3 million (2006: US$21.8

million) and US$8.3 million (2006: US$21.8 million) respectively, after taking into account a US$25.7

million write-down of costs in Guinea Bissau.

110


Administrative costs were stable at US$17.7 million (2006: US$16.8 million). This included a charge

of US$4.7 million (2006: US$5.7 million) in respect of current year and future provisions for long-

term incentive plans.

Operating profits were US$219.4 million, a 35% increase from the prior year. Finance charges net of

interest income totalled US$7.5 million (2006: US$4.0 million). Pre-tax profits were US$147.0 million

(2006: US$156.6 million). This included a significant non-cash item relating to mark to marketrevaluation of the Group’s oil and gas hedges totalling US$64.9 million (pre-tax). Such accounting

losses arose as a result of the increase in oil and gas prices. The tax charge totalled US$108.0 million

(2006: US$89.0 million) due to underlying higher taxable profits. Basic earnings per share amounted

to 47.6 cents (2006: 82.6 cents).

Cash flow

Cash flow from operating activities, before movements in working capital, amounted to US$408.1million (2006: US$310.8 million). After working capital items and tax payments cash flow from

operating activities amounted to US$269.5 million (2006: US$244.8 million). Capital expenditure was

US$261.2 million after inclusion of asset acquisition costs of US$88.6 million.

Capital expenditure

2007

US$

million

2006

US$

million



Acquisitions 88.6 17.0

Other 2.2 1.2

Total 261.2 156.5

The principal development projects were the Kyle gas lift project in the UK, the West Lobe

development in Indonesia and the Zamzama Phase 2 development in Pakistan. Exploration costs of

US$104.7 million took into account savings of US$30.9 million due to farm-outs in Guinea Bissau,

the UK and India.

Net cash position

Net cash at 31 December 2007 amounted to US$79.0 million (2006: net cash of US$40.9 million)

following the successful completion of the US$250 million convertible bonds issue in June. This

funding provided seven-year fixed rate debt at a cash coupon of 2.875% and, together with the

Company’s undrawn bank facilities, contributed substantially towards the financing of Premier’s

significant development programme.

Net cash

2007

US$

million

2006

US$

million

Cash and cash equivalents 332.0 40.9

Convertible bonds* (200.0)

Other long-term debt** (53.0)

Net cash 79.0 40.9

* Excluding unamortised issue costs and allocation to equity.

** Excluding unamortised issue costs.

111



2007 2006 Change

LTI and RWDC frequency rate* 1.86 1.24 Up 50%

Production (kboepd) 35.8 33 Up 8%

Cash flow from operations (US$ million) 269.5 244.8 Up 10%

Operating cost per boe (US$) 9.0 7.1 Up 27%Gearing** 0% 0% —

Realised oil price per barrel (US$) 72.3 64.9 Up 11%

Realised gas price per mcf (US$) 5.6 5.11 Up 10%

* Lost time incidents (LTI) and restricted workday cases (RWDC) per million man-hours worked.

** Gearing is net debt divided by net assets.

3. OPERATING REVIEW FOR 2008

OPERATING REVIEW


Significant progress has been achieved during 2008 in all of the Company’s major developmentprojects. Project approvals at partner and government levels have been secured together with

negotiation of gas and transportation agreements and key supplier contracts. This activity has

positioned the Group for success in the completion of the Company’s three projects in Indonesia and

Vietnam. These, together with an ongoing programme of infill drilling and debottlenecking on the

Company’s existing production portfolio, are expected to increase Premier’s production beyond its

stated target of 50 kboepd.

Average production for the full year 2008 was 36.5 kboepd (2007: 35.8 kboepd), in line with previous

guidance. In the UK, production performance from the Scott field was affected by maintenance work

in the fourth quarter but the Wytch Farm and Kyle fields performed strongly. In addition, bothPakistani and Indonesian fields saw strong demand from gas customers, coupled with good

production performance.

Production (boepd) Working interest Entitlement

2008 2007 2008 2007

Asia 11,700 12,000 7,100 7,900


North Sea 9,300 9,850 9,300 9,850

West Africa 950 1,200 800 1,000

Total 36,500 35,750 31,750 31,450

As at 31 December 2008 proven and probable reserves, on a working interest basis, based on Premier

and operator estimates, were 228 mmboe (2007: 212 mmboe).

Proven and

probable

reserves

(mmboe)

2P Reserves

and 2C

contingent

resources

(mmboe)

Start of 2008 212 369

Production (13) (13)

Net additions and revisions 29 26

End of 2008 228 382

At year-end, reserves comprised 22% liquids and 78% gas. The equivalent volume on an entitlement

basis amounted to 198 mmboe (2007: 188 mmboe), based on a price assumption of US$60/bbl Brent

(2007: US$60/bbl Brent).

Booked reserve additions and revisions include the Vietnamese Chim Sao field where all joint venture

and government approvals were achieved in late 2008 and construction work on the first wellhead

platform has commenced. This has resulted in the booking of reserves for this asset for the first time

this year. In addition, there has been an increase in the Indonesian Natuna Sea Block A reserves

resulting from a comprehensive subsurface re-evaluation of the strong and consistent production

112


performance from the Anoa field. Other reserves additions include an increase to the Company’s

Pakistan portfolio in response to integrated reservoir studies conducted during the year. Contingent

resources at year-end remained steady at 154 mmboe (2007: 157 mmboe), due to the successful

commercialisation of the Chim Sao field being offset mainly by improved definition of undevelopedassets in Indonesia.


Premier participated in 14 exploration and appraisal wells in 2008, of which seven were successful.

Successes included: appraising the reserves base in the Chim Sao discovery (Vietnam); appraising the

gas volumes in the Banda field (Mauritania); step-out drilling adding reserves to the Kadanwari field

(Pakistan), and making a new oil discovery at Al Amir SE (Egypt). The Company’s two new oil

discoveries in Vietnam are currently sub-commercial. The Company acquired over 4,250 kilometres of

new 2D seismic and 600 square kilometres of 3D to advance its exploration interpretations in

preparation for 2009/2010 drilling. The Company has also acquired new licences in Vietnam and

Norway.

The Company’s exploration spend on drilling and seismic activities in 2008 totalled US$90.5 million

on a pre-tax basis (2007: US$104.7 million). Estimated post-tax expenditure was US$63.9 million.

In Vietnam the Company’s Chim Sao North Appraisal well (12W-CS-2X) in the Block 12W PSC

confirmed the northern extension of the Chim Sao field allowing development sanction to proceed.Further south in the block the Company drilled two exploration wells and an exploration sidetrack.

The Chim Ung well and the Chim Cong well were both oil discoveries, confirming the southward

extension of the exploration play but are currently considered sub-commercial. In Premier’s adjacent

operated block, the 07/03 PSC, a 1,525 kilometre 2D survey has been acquired and a rig contracted

for 2009 drilling.

Premier also had an active year in Indonesia, acquiring 2D seismic in the Tuna and Buton PSCs

(2,400 kilometres and 300 kilometres respectively) and reprocessing data in the Company’s North

Sumatra Block A acreage. These data are being interpreted and work is progressing towards drilling

in all licences.

In Pakistan the Company started testing in the successful Qadirpur Deep-1 well, flowing 4.5 mmscfd

of high-quality gas from hitherto undrilled reservoir zones below the Qadirpur field. Production from

this zone is expected onstream during 2009. In the Kadanwari licence the K-17 well made a discoveryin a fault block to the south-west of the main field; the well is being placed on production at an

expected rate of up to 25 mmscfd. A new discovery, Al Amir SE, in the NW Gemsa licence in Egypt

tested 3,000 bopd from Kareem sandstones and an appraisal well, drilled at year-end, tested 5,785

bopd. Both wells were completed and production has already commenced.

Premier farmed out part of its licence equity for a full carry of its drilling costs on a high risk

prospect in the Company’s UK North Sea 23/22b block. The well was dry but fulfilled the licence’s

exploration commitment. This allows the Company to retain the block and evaluate the possibility

that the Moth condensate discovery, made in 2008 in the adjacent 23/21 block, extends into the

Company’s licence. Premier has been granted the contiguous licence, Block 7/7, across the border inNorway.

Looking ahead to 2009, the exploration focus in South East Asia is in Vietnam, where the Companyplans to drill in Block 07/03 commencing in the second quarter. If that programme is successful, it

will high-grade a large number of follow-on prospects on this block and on adjacent acreage held by

Premier. In the Indonesian adjacent Tuna Block the Company is working up interpretations of the

newly acquired 2D, ready for drilling in late 2009 or 2010. The Company is also planning to drill a

deep Lama sandstone reservoir target beneath the Anoa field in the Natuna Sea Block A PSC; this

follows encouragement from Company’s 2007 Pancing discovery in this poorly explored reservoir in

the adjacent Kakap Block. In Pakistan, following the success of the Qadirpur deep well, the

Company is drilling similar deep reservoirs below the Badhra field with the Bado Jabal well. This hasthe potential for several tcf of gas. The Company is also drilling a new fault block in the Kadanwari

licence, where it has drilled similar opportunities that were successful in the recent past.

A potentially high-impact well is being drilled in West Africa where the Company has farmed out

equity in the Congo Marine Block IX permit and is spudding a well on the large Frida prospect in

mid-2009. In Norway the delayed appraisal well on the Bream oil discovery is on course to be drilled

in the third quarter of 2009. The Grosbeak North prospect is also scheduled to be drilled in the

second quarter; the Company has farmed out equity in this licence (PL378) to reduce financial

113


exposure, but retain a 20% equity interest. Later in the year the Greater Luno well will target a

possible extension of Lundin’s Luno field into the Company’s block.

Asia

Indonesia

During 2008, Premier’s operated Natuna Sea Block A sales amounted to 142 BBtud (gross), whilst

the non-operated Kakap field contributed a further 60 BBtud (gross). Liquids production from Anoa

averaged 2,212 bopd (gross) and from Kakap 6,000 bopd (gross). Overall, net production from

Indonesia amounted to 11,700 boepd (2007: 12,000 boepd).

Following the signing of three GSAs with Sembgas in Singapore, and PLN and UBE in Batam,

Indonesia in April, the gas transportation and associated agreements required to enable delivery ofgas to Sembgas were executed in October 2008. Negotiation of the associated transportation

agreements for Batam sales are ongoing and are expected to be signed in the second half of 2009.

The government of Indonesia has approved the Plan of Development for three fields (Gajah Baru,

Naga and Iguana). Long lead item orders for steel, compressors, turbines and other critical equipment

were placed at the year-end. A second tender for the EPCI contract was completed on 16 March. It

resulted in gross cost savings of approximately US$100 million. With reductions in expected drilling

costs, total capex for the whole project is now forecast at around US$920 million (gross). Maximum

routine gas sales will be in the order of 140 mmscfd and recoverable reserves from the three fields areexpected to exceed 500 bscf. First gas is now expected before October 2011 and is still in advance of

the contractual obligation under the GSA with Sembgas.

On North Sumatra Block A, commercialisation of the Alur Siwah, Alur Rambong and Julu Rayeu

fields continued with signature, in April 2008, of a second GSA with PLN, the state electricity

company, for the long-term supply of 15 BBtud of gas. The PSC terms for extension are being

amended in line with the new standard PSC for Indonesia and are awaiting government approval. To

compensate for changes in PSC terms, an amendment to the first GSA with PIM has been signed.

The resulting increased gas sales price will have a floor of US$6.50/MMBtu.

Approval for the Plan of Development for the gas fields was received in January and Front-End

Engineering Design commenced in July and is currently nearing completion. Early gas from Alur

Rambong is targeted for 2010, whilst first gas from the main development of Alur Siwah is expectedin 2011. A Heads of Agreement was signed with ExxonMobil in November for use of their facilities

for transportation and a fully termed agreement is expected to be finalised in the first half of 2009.

Drilling is expected to begin on Alur Rambong by early 2010.

Work on the reactivation of the Tualang and Lee Tabue oil fields started in late 2008 and is

continuing. Up to six wells may be worked over and tested and subsurface studies have indicated that

there is potential to restart production from fields previously abandoned in 2001. Plans for a larger

scale reactivation will be based on the results of this initial programme.

Exploration activities during 2009 will focus on the drilling of the Anoa deep well, expected in the

third quarter, and maturing of other licences for further exploration in 2010.

On the Buton block, the 2D seismic programme began in early 2008 and processing is nearing

completion. During 2009 the operator will finalise studies to determine a location to be drilled in

2010.

On the Tuna block, the acquisition of 2,400 kilometres of 2D seismic was completed in October.Interpretation focussed on maturing and high grading the current prospect inventory in parallel with

the work programme in Premier’s Vietnam Block 07/03 immediately to the north. It is now

anticipated that two wells on the Tuna block will be drilled in early 2010.

In partnership with government authorities, Premier has been awarded joint study participation for

three blocks in North Sumatra (East Asahan), East Kalimantan (East Benjkanai) and offshore NW

Java (North Merak). Studies include reprocessing of seismic data and acquisition of gravity data.

Vietnam

Following the interpretation of the 2007 3D data over Block 12W, Premier drilled a successfulappraisal well in the Chim Sao field in 2008, which tested two zones at a combined rate of 4,330

bopd plus 3.5 mmscfd. All joint venture and government approvals for the project were achieved in

late 2008. As a result of the changing cost environment the development plan is being re-engineered

to a single platform development, with resultant cost reductions. Construction work on the wellhead

platform has commenced in Vietnam. Discussions are ongoing with potential providers of an FPSO

114


for leasing to the field owners, and final execution of both the FPSO lease agreement and the EPCI

contract await conclusion of this process.

During 2008, Premier drilled three further exploration prospects in Block 12W. The Chim Ung-1 well

intersected 15 metres of (net) oil pay in a good quality reservoir. A sidetrack was drilled into the

adjacent Chim Boi fault block, which did not encounter hydrocarbons. Well Chim Cong-1 tested oil

at sub-commercial rates with seven metres of (net) oil pay. Premier continues to evaluate these well

results ahead of the expiry of the PSC exploration period late in 2009.

Premier became operator of Block 07/03 in late 2007 and in 2008 it acquired a 2D seismic

programme to define the location of two exploration wells, the first of which is planned for May

2009. The second well will follow at year-end. The exact schedule is dependent on the duration ofintervening wells drilled by the rig-share consortium which Premier is leading. In February 2008,

Premier was awarded Block 104-109/05 and has since begun geological studies and geophysical

reprocessing of seismic data to better understand the exploration potential of this acreage, offshore

northern Vietnam.

Philippines

The Monte Cristo-1 exploration well on the SC43 licence proved to be dry and the well was plugged

and abandoned. Premier’s costs for the well were carried under a farm-out agreement. Premier and its

partners are currently carrying out exploration activities over a prospective trend in the Panaon

Limestone formation found with new seismic data obtained in early 2008.

India

Premier is maintaining a limited presence in India pending resolution of the signature of the Ratna

licence with the government of India.


Pakistan

Production net to Premier in 2008 was 14,550 boepd, an increase of about 15% as compared to the

12,700 boepd in 2007, surpassing previous records. This additional volume was due to increased gas

demand, which was primarily met through additional supplies from the Zamzama and Bhit/Badhra

gas fields.

The Qadirpur field produced an average of 4,060 boepd from Premier’s working interest of 4.75%

(2007: 3,980 boepd). The Qadirpur plant capacity enhancement project was completed in 2008, with

first gas achieved by the end of January 2009. A GSA was signed with SNGPL, for the supply of 75

mmscfd permeate gas (equivalent to 40 mmscfd processed gas), with first gas expected in 2010. Sixnew production wells were drilled and tied-in to optimise increased processed gas sales. The Qadirpur

Deep-1 well was tested, flowing 4.5 mmscfd of high quality gas from hitherto undrilled reservoir

zones below the Qadirpur field. Production from this zone is expected onstream during 2009.

The Kadanwari field produced an average of 1,225 boepd in 2008 (2007: 1,260 boepd) from Premier’s

15.79% working interest. Despite natural production decline, field production was maintained at 2007

levels largely due to tie-in of the new K-18 well. A new production well K-17 was drilled and tied-in

to the gas plant ahead of schedule on 30 December 2008. To maintain and increase the production

levels of the field, K-14ST is currently being drilled, with further wells planned in 2009.

The Zamzama field produced an average of 6,075 boepd in 2008 (2007: 4,620 boepd), from Premier’s

9.375% working interest. The Zamzama Phase-2 development project was commissioned in 2008 for

production of HCV gas. This resulted in a production increase in 2008 of 32% over 2007 levels.

Bhit/Badhra production was 3,190 boepd in 2008 (2007: 2,840 boepd) from Premier’s 6% working

interest, an increase of 12% over last year. The increase was due to the completion of the Phase 2

development which enhanced plant capacity from 270 mmscfd to 320 mmscfd, facilitating first gas

from the Badhra field and accelerated production from the Bhit field.

In Zarghun South, Front End Engineering Design is currently in progress and first gas is expected in

2010. Premier’s costs pertaining to its 3.75% interest in Zarghun South are substantially carried by

the operator.

Egypt

The Al Amir SE-1 well, drilled in October 2008, encountered oil in the Kareem Formation, opening

up a new play in the area. The well tested over 3,000 bopd and 4.25 mmscfd of associated gas. An

115


appraisal well was then drilled on the discovery at year-end encountering two Kareem sandstones

with 42 feet of net pay. This second well tested 5,785 bopd of 42˚ API with 7.8 mmscfd of gas from

one of the two 20 feet zones – the second zone will be perforated at a later date.

In addition, the 2005 Al Amir discovery was re-evaluated and the original Al Amir-1 well was re-

entered and sidetracked in December in order to re-appraise the well as a potential producer. Thesidetrack confirmed the lateral extension of the original reservoir zone and also encountered a deeper

pay zone. The upper zone was tested with a sustained rate of 416 bopd of 16˚ API; the lower pay

zone will be tested when the well is brought into commercial production.

Development plans to bring the Al Amir and Al Amir SE wells into early production were submitted

to Egyptian General Petroleum Company and production on Al Amir SE commenced in February

2009. Flow rates had risen to over 3,000 bopd by early March. The oil is being produced from the

discovery well Al Amir SE-1X and the first appraisal well Al Amir SE-2X. A seven kilometre pipeline

has been laid between these two wells and the Gazwarina facilities to which the oil is being

transported. The Al Amir-1 well is intended to be brought onto production shortly.

Abu Dhabi

The joint venture continues to pursue the acquisition of upstream oil and gas assets across the

Middle-East and North Africa, with a particular focus on future projects in Abu Dhabi and Iraq. An

office has opened in Abu Dhabi and is staffed by a small team of secondees from Premier and EIIC.

North Sea

Production in the UK amounted to 9,300 boepd (2007: 9,850 boepd) representing 25% of the Group

total (28% in 2007). Operational difficulties on the Scott field, particularly in the fourth quarter were

offset by successful programmes of infill drilling on other fields.

The Wytch Farm oil field contributed 2,965 boepd production net to Premier, similar to 2007. A

strong underlying production performance was maintained by a proactive well-work campaign and

minimal production interruptions. At the start of the year the M20 injection well was brought on line

and, together with other water handling improvements, has helped to restore reservoir pressure. The

B41 rig was then mobilised to Furzey Island to drill the K08 and L13 infill wells and threeworkovers. A subsequent A12 sidetrack well has exceeded expectations and will be brought on line

shortly. The Wareham field is also back in production and the infield pipeline replacement project has

been completed with testing and commissioning completed in early 2009.

Production from the Scott and Telford fields was lower than expected at 3,525 boepd (net) (2007:

3,700 boepd). Work on facility projects designed to improve reliability and extend facility life was

ongoing during the second half of the year. Two power generator units have now been upgraded.

Modifications to the Scottish Area Gas Evaluation export pipeline to import gas have been

rescheduled to 2009. In October a three to four well infill drilling programme commenced.

Net production from Kyle was 2,500 boepd, an increase on 2007 as a consequence of improved

operational performance and a full-year under gas lift. Production performance during the second halfof 2008 was more reliable due to facility modifications to the Banff FPSO compressor system during

September. Work continues to optimise the operation of the three producing wells

The Fife Area, where the planned suspension of production occurred on 2 May 2008, accounted for

the remainder of UK net production. Subsea facilities were made safe and the FPSO unit departed

the field in September. Removal of remaining risers is scheduled for 2009 after which the field will be

suspended pending redevelopment or future abandonment. Discussions have been held with a number

of parties interested in participating in further appraisal and development of the fields.

On the Frøy field in Norway (PL364), a Plan for Development was submitted to the authorities in

September. Recent events in the banking markets, however, have impacted the planned contractor’s

financing of the Jack-up Production Unit so that development planning is now progressing for first

oil in 2013. The PL364 licence owners have agreed to use the delay to implement cost reductionmeasures and to investigate opportunities for third party tie-ins. In addition to existing discoveries in

the area surrounding Frøy, several new wells in the area are planned by operators during 2009.

Having satisfied the initial licence work commitment the Frøy field partners have been granted a 10-

year licence extension by the authorities.

Exploration activities in the North Sea focussed on remaining potential in the UK portfolio and

moving towards drilling up the Norwegian acreage.

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On Block 23/22b in the UK the Sparrow well was farmed out to Oilexco and BG. The well was

drilled, in March, to a depth of 10,598 feet, 50 feet into the Ekofisk formation, fulfilling licence

commitments. Good reservoir sands were penetrated but unfortunately these were water wet. The well

was drilled at zero cost to Premier.

Subsequently, Oilexco and BG announced the discovery of oil in the deeper Moth prospect on the

adjacent Block 23/21. This discovery has encouraging implications for the Block 23/22b licence and

the deeper Jurassic prospectivity. BG has farm-in rights to the deeper prospect on Block 23/22b under

which Premier would receive a partial carry whilst reducing equity.

Premier was also awarded the operatorship of Block 7/7 on the Norwegian side of the median line in

the APA 2008 licence round. This block adjoins the 23/22b licence and provides Premier with

complete coverage of the Jurassic prospectivity identified adjacent to the Moth discovery.

In Norway, on PL407, failure by the operator to obtain approval to bring the contracted rig into

Norwegian waters has resulted in the Bream appraisal well slipping to the third quarter of 2009. Thiswell will now be drilled with an alternative rig. A 12-month extension to the licence deadline has been

granted by the Norwegian Ministry of Petroleum and Energy.

On the Premier-operated licence PL406 the 3D seismic acquisition was completed as planned in April.

Processing of the new data commenced and initial fast track volumes were received ahead of

schedule. Site surveys and leg cores for the well are planned for the second and third quarters of

2009 respectively. A rig has been contracted to drill the Gardrofa prospect, expected to spud in the

third quarter of 2010.

The recent Jordbaer discovery has significantly enhanced the potential of the Company’s adjacent

licence PL374S and the decision has been taken to enter the drilling phase of this licence with anexpected well in 2010. In the PL359 licence, immediately south of the 2007 Luno discovery, a well is

planned for the fourth quarter of 2009.

The PL378 licence has been successfully farmed down with Premier retaining an equity position of

20% in the licence. The carried well is planned on the Grosbeak North prospect and will spud in the

second quarter of 2009.

Premier has exited the PL419 licence disposing of its 25% interest to Nexen, the operator.

West Africa

In Mauritania, Chinguetti production averaged 11,700 bopd (950 bopd net to Premier) in 2008. The

Chinguetti Phase 2B development programme comprising three workovers and two new production

wells was completed in the fourth quarter of 2008, increasing gross production from 10,000 bopd to

17,100 bopd by year-end. Production performance will be carefully monitored during 2009. The

operator continues to review and assess remaining potential within the field for a future drilling

campaign.

Evaluation of opportunities and development options on PSC A and PSC B are progressing. In 2008the joint venture drilled the Banda-NW well and sidetrack and the Banda East well, with the

objective of defining the Banda gas and oil resources and commercial viability. Both wells were

suspended as potential future producers. The operator continues working on the Field Development

Plan, with target completion by mid-2009 for an investment decision.

The operator is re-evaluating the Tiof field and proposing to reprocess the seismic data to assist in

better defining the subsurface and progressing this discovery to a development decision.

The joint ventures are currently in discussions with the Mauritanian government to extend the

existing PSCs.

Congo

In Congo, a farm-out of 27% of the Company’s equity was completed providing significant funding

for a possible two-well programme on the Marine IX licence. Following the farm-down, Premier

retains 31.5% equity and anticipates spudding the first of the Albian raft prospects, Frida, in July2009. The Transocean Aleutian Key semi-submersible rig has been contracted to drill the Frida well

and preparations for the drilling operation are well advanced with the environmental impact study

completed and long lead items acquired. Further progress has also been made in the evaluation of the

Company’s deep water exploration block focussing on the tertiary channel sands that have proven

productive in the adjacent blocks.

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The Frida prospect is a large untested Albian raft with multiple stacked reservoir seal pairs and

potential reserves of 170 mmboe.

SADR

The Company’s exploration assets in SADR remain under force majeure, awaiting resolution of


FINANCIAL REVIEW


2008 was a turbulent year for the world economy and for oil and gas prices in particular. Brent

opened the year at US$97/bbl, reached a peak of US$147/bbl in July 2008, before falling back to endthe year at US$35/bbl. The early part of 2009 has seen continued volatility but prices have recovered

to around US$45/bbl on average.

The deterioration in the oil price environment has led to downward pressure on operating and

development costs, which had increased during the recent period of sustained rising commodity

pricing and increasing activity levels. Premier is capturing the benefits of falling costs environment in

rig and development costs.

Income statement


boepd in 2007. On an entitlement basis, which allows for additional government take under the termsof the Company’s PSCs, production was 31,750 boepd (2007: 31,450 boepd). Realised oil prices

averaged US$94.5/bbl compared with US$72.3/bbl in the previous year.

Gas production averaged 148 mmscfd (25,300 boepd) during the year or approximately 69% of total

production. Average gas prices for the Group were US$6.57/mscf (2007: US$5.60/mscf). Gas prices in

Singapore, which are linked to HSFO pricing, which in turn is closely linked to crude oil, averaged

US$15.2/mscf (2007: US$11.3/mscf) during the year.

Total sales revenue from all operations was 13% higher than 2007 at US$655.2 million (2007:

US$578.2 million) as a result of higher production and commodity prices. This figure includes a

reduction of US$15.9 million arising from the price ceilings in the Company’s hedging contracts.

Cost of sales was US$317.6 million (2007: US$267.5 million). Excluding the effect of inventory

movements, underlying unit operating costs were higher at US$9.5/boe (2007: US$9.0/boe) due to a

full year of increased production from the Scott field in the North Sea. Amortisation includes the

effect of an impairment charge of US$31.9 million in respect of the Chinguetti field in Mauritania.

Underlying unit amortisation (excluding impairment) fell marginally to US$8.0/boe (2007: US$8.2/

boe). Exploration expense and pre-licence exploration costs amounted to US$42.9 million (2007:US$65.3 million) and US$15.8 million (2007: US$8.3 million) respectively, following deferral of the

Bream appraisal well in Norway to 2009. Administrative costs were stable at US$17.2 million (2007:

US$17.7 million).

Operating profits were US$261.7 million, a 19% increase over 2007. Finance charges net of interest

income totalled US$12.4 million (2007: US$7.5 million). Pre-tax profits were US$277.6 million (2007:

US$147.0 million). This included a non-cash gain relating to mark to market revaluation of the

Group’s gas hedges totalling US$21.5 million (2007: non-cash loss of US$24.9 million). The taxation

charge totalled US$179.3 million (2007: US$108.0 million) due to underlying higher taxable profits.

Profit after tax reached a record US$98.3 million (2007: US$39.0 million). Basic earnings per share

were 120.8 cents (2007: 47.6 cents).

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Cash flow

Cash flow from operating activities, before movements in working capital, amounted to US$478.1

million (2007: US$408.1 million). After working capital items and tax payments, cash flow fromoperating activities rose 31% to US$352.3 million (2007: US$269.5 million). Capital expenditure was

US$217.3 million (2007: US$261.2 million).

Capital Expenditure (US$ million) 2008 2007



Acquisitions — 88.6

Other 2.8 2.2

Total 217.3 261.2

The principal development projects were the Qadirpur plant capacity enhancement project, Kadanwari

development wells, Zamzama Phase 2 project, Bhit/Badhra Phase 2 project, Wytch Farm infill

programme, Scott infill programme and upgrade of the power generation units, Chinguetti Phase 2B

development, and long lead equipment and interim work for wellhead platforms, pipelines and FPSO

on the Chim Sao field in Vietnam.

Net cash position

Net cash at 31 December 2008 amounted to US$117.3 million (2007: net cash of US$79.0 million).

Together with Company’s undrawn cash facilities of US$275 million, this will contribute substantially

towards the financing of Premier’s significant development programme over the next three years.

Net cash (US$ million) 2008 2007

Cash and cash equivalents 323.7 332.0

Convertible bonds* (206.4) (200.0)

Other long-term debt** — (53.0)

Net cash 117.3 79.0

* Excluding unamortised issue costs and allocation to equity

** Excluding unamortised issue costs


2008 2007 2006

LTI and RWDC frequency rate* 0.40 1.86 1.24

Production (kboepd) 36.5 35.8 33

Cash flow from operations 352.3 269.5 244.8

Operating cost per boe 9.5 9.0 7.1Gearing (%)** 0% 0% 0%

Realised oil price per barrel (US$) 94.5 72.3 64.9

Realised gas price (per mcf) 6.57 5.6 5.11

* Lost time incidents and restricted workday cases per million man-hours worked

** Gearing is net debt divided by net assets

4. HEDGING AND RISK MANAGEMENT

Hedging and Risk Management

The Group’s activities expose it to financial risks of changes, primarily in oil and gas prices but also

foreign currency exchange and interest rates. The Group uses derivative financial instruments to hedge

certain of these risk exposures. The use of financial derivatives is governed by the Group’s policies

and approved by the Board, which provides written principles on the use of financial derivatives.

The Board’s policy remains to lock in oil and gas price floors for a portion of expected future

production at a level which protects the cash flow of the Group against weak prices and the business

119


plan. Such floors are purchased for cash or by selling calls at a ceiling price when market conditions

are considered favourable. All transactions are matched as closely as possible with expected cash

flows to the Group; no speculative transactions are undertaken.

Since the Group now reports in US Dollars, exchange rate exposures relate only to Pounds Sterling

receipts and expenditures, which are hedged in US Dollar terms on a short-term basis. The Group

recorded a loss of US$2.5 million on such hedging at year-end (2007: US$0.4 million).

Cash balances are invested in short-term bank deposits, AAA managed liquidity funds and A1/P1

commercial paper subject to Board approved limits.

Summary

Oil and gas hedging is undertaken with collar options. Oil is hedged using Dated Brent oil price

options. Indonesian gas is hedged using HSFO Singapore 180 cst which is the variable component of

the gas price.

2008 2007 2006

US$m US$m US$m

Income Statement

MTM Valuation on Commodity Hedges: Gain / (Loss) 28.3 (64.9) (2.0)

MTM Valuation on foreign exchange contracts: Gain / (Loss) (2.5) (0.4) —

31-Dec-08 31-Dec-07 31-Dec-06

US$m US$m US$m

Balance Sheet

Fair Value of Oil Hedges: Asset / (Liability) (11.0) (40.8) (0.8)

Fair Value of Gas Hedges: Asset / (Liability) (2.9) (24.4) 0.5

Net Valuation (13.9) (65.2) (0.3)

31-Dec-08 31-Dec-07 31-Dec-06

US$m US$m US$m

Balance Sheet

Fair Value of Option: Asset / (Liability) 10.7 37.9 N/A

Deferred Revenue: Asset / (Liability) (33.7) (37.9) N/A

Oil Hedges 31-Dec-08 31-Dec-07 31-Dec-06

Period Covered 2009 – 2012 2008 – 2012 2007 to end-2012Volume of Oil Hedged (%) 60.0 54.0 50.0

Average Floor (US$ / bbl) 39.3 & 50.0* 39.3 38.9

Average Cap (US$ / bbl) 100.0 & 80.0* 100.0 100.0

Gas Hedges 31-Dec-08 31-Dec-07 31-Dec-06

Period Covered 2009 to mid-2013 2008 to mid-2013 2007 to mid-2012

Volume of Indonesian Gas Hedged (%) 34.0 34.0 34.0

Average Floor (US$ / mt) 250.0 250.0 245.0

Average Cap (US$ / mt) 500.0 500.0 500.0

Note: For the years 2009 and 2012 production is now hedged with an average floor of US$39.3/bbl and an average cap of US$100/bbl.For the years 2010 and 2011 production is now hedged with an average floor of US$50/bbl and an average cap of US$80/bbl.

5 SOCIAL PERFORMANCE

Social performance review

Premier aspires to be an industry leader in social performance, which covers the areas of socialresponsibility, health and safety and environmental impact. Targets are set for these areas with

reference to the Group’s historical performance, the performance of the Company’s peer group and to

the standards set by external agencies. It is the Company’s stated policy to ensure that the risks and

impacts of its activities are reduced to as low as reasonably practicable at all times.

Social performance reporting

Premier publishes a Social Performance Report every two years, and in the intermediate years

prepares a Communication on Progress. The ‘Social Performance Report’ for 2006/7 was published

early in 2008 and can be found on Premier’s corporate website. For 2008, a Communication on

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Progress will be published in accordance with the requirements of the United Nations Global

Compact (‘‘UNGC’’) principles and this may be seen on the UNGC website.

Social responsibility

Backed by a strong Board-level commitment, the Company has enhanced and implemented a coherent

set of policies that lay down the principles by which human rights, relationships with communities,

employment practices, business ethics, the health and safety of people working in Premier operationsand the Group’s impact on the environment are managed. The Company continues to work closely

with local communities, employee representatives, business partners and regulatory authorities to

deliver the Group’s policies and to make a positive difference within the localities where the Group

operates.

Occupational health and safety

2008 2007 2006

Number of Lost Time Injuries (LTI) 1 3 4

Number of Restricted Work Day Cases (RWDC) 0 4 0

Target LTI/RDWC Frequency

(per million man-hours worked) 1.72 1.90 2.10

Actual LTI/RDWC Frequency

(per million man-hours worked) 0.40 1.86 1.27

The Group regularly undergoes a number of OHSAS 18001 surveillance audits on its drilling and

production operations around the world. OHSAS 18001 is a standard to which a company’s health

and safety management system may be certified. Certification demonstrates that an accredited body

has independently verified that Premier’s management systems fully comply with the standard.

Successful certification and ongoing surveillance audits confirm that Premier continues to meet the

highest standards wherever it drills or operates. Premier has held this prestigious award since 2004 for

drilling and 2006 for production. Both the Company’s drilling and production functions retained theirOHSAS 18001 certification in 2008.

Environmental indicators

Environmental performance is reported in line with the IPIECA Oil and Gas Industry Guidance onVoluntary Sustainability Reporting (2005) in the following four core areas:

2008 2007 2006

Green House Gases

(tonnes per 1000 tones of production) 167 171 232

Oil Spills

(tonnes) 0 13.7 3.9

Oil in Produced water

(parts per million) 23 20 21

Energy Use(Giga Joules per tonne of production) 2.0 1.8 1.9

6. PRINCIPAL RISKS

Premier is an international business which has to face a variety of strategic, operational, financial and

external risks. Premier’s business, financial standing, results and reputation may be impacted by

various risks. Not all of these risks are within the Company’s control and the Company may be

affected by risks other than those listed below, which were applicable to the Company in the years

ended 31 December 2006, 31 December 2007 and 31 December 2008. Such risks are set out morefully in the section entitled ‘‘Risk Factors’’ on pages 9 to 17 of this document.

Clear responsibility

The Board is responsible for overall Group strategy, acquisition and divestment policy, approval ofmajor capital expenditure projects, corporate costs and significant financing matters, and the

management of risks. The Board recognises that risk is inherent across Premier’s operations, and all

activities are subject to an appropriate review to ensure that risks are identified, monitored and, if

possible, managed.

121


Risk management process

Premier has an established business management system which includes an integrated risk

management process for identifying, evaluating and managing risks faced by the Group. This is basedon each business unit and corporate function producing a risk matrix which identifies the key

business risks – strategic, operational, financial and external – the probability of those risks occurring,

their impact if they do occur and the actions being taken to manage those risks to an acceptable

level. Risk acceptance and reduction objectives are defined with particular attention given to reducing

them to as low a risk as reasonably practicable. These risk matrices are updated on a regular basis

and made available to the executive Directors.

Key risks facing Premier, their potential impacts and Premier’s responses are outlined below. Effective

risk management is critical to achieving the Company’s strategic objectives and protecting the

Company’s assets, personnel and reputation. Premier manages its risks by maintaining a balanced

portfolio, through compliance with the terms of its agreements and application of appropriate policies

and procedures and through the recruitment and retention of skilled individuals throughout theorganisation.

Key business risks

Reserves replacement

Future oil and gas production will depend on the Company’s access to new reserves through

exploration, negotiations with governments and other owners of known reserves, and acquisitions.

Failures in exploration or in identifying and finalising transactions to access potential reserves could

slow the Company’s oil and gas production and replacement of reserves. Premier manages these risks

by proactive project planning and milestone driven performance criteria. For exploration, effective

peer reviews and thorough diligence on new areas allow the Company to mitigate risk of failure.

Competition

Premier operates in a very challenging business environment and faces competition on access to

exploration acreage, gas markets, oil services and rigs, technology and processes, and human

resources.

Production

The delivery of Premier’s production depends on the successful development of its key projects. In

developing these projects the Company faces numerous challenges. These include uncertain geology,

availability of technology and engineering capacity, availability of skilled resources, maintaining

project schedules and managing costs, as well as technical, fiscal, regulatory, political and other

conditions. Such potential obstacles may impair the Company’s delivery of these projects and, in turn,

the Company’s operational performance and financial position (including the financial impact from

failure to fulfil contractual commitments related to project delivery).

Health, Safety, Environment and Security (HSES)

Given the range of Premier’s operated and joint venture production operations globally, the

Company’s HSES risks cover a wide spectrum. These risks include major process safety incidents;failure to comply with approved policies; effects of natural disasters and pandemics; social unrest;

civil war and terrorism; exposure to general operational hazards; personal health and safety; and

crime. The consequences of such risks materialising can be injuries, loss of life, environmental harm

and disruption to business activities. Depending on their cause and severity, they can affect Premier’s

reputation, operational performance and financial position. Premier has an effective and

comprehensive HSES management system to mitigate this risk and support safe and secure execution

of all critical operating activities.

Reputation

Premier strives to be a good corporate citizen globally and has strong and positive relationships with

the governments and communities in the countries where it does business. This is important formaintaining the Company’s licence to operate and the Company’s ability to secure new resources.

Premier’s business principles govern how it conducts its affairs. Failure – real or perceived – to follow

these principles, or any of the risk factors set out in this operating and financial review materialising,

could harm the Company’s reputation, which could impact its licence to operate, financing and access

to new opportunities.

122


Human resources

Premier’s key human resources are essential for the successful delivery of its projects and continuing

operations. Loss of personnel to competitors or the Company’s inability to attract quality humanresources could affect the Company’s operational performance and growth strategy. Premier has

created salary, bonus and long-term incentive plan processes designed to incentivise loyalty and good

performance.

Commodity prices

Oil and gas prices are affected by global supply of and demand for these commodities. Factors that

influence these include operational issues, natural disasters, weather, political instability or conflicts,

economic conditions or actions by major oil-exporting countries. Price fluctuations can affect theCompany’s business assumptions and can impact investment decisions and financial position. Premier

manages this risk with a oil and gas hedging programme to underpin its financial strength and

capacity to fund its future development and operations.

Financial discipline

Premier has established financial policies and processes to ensure that it is able to maintain an

appropriate level of liquidity and financial capacity and to manage the level of assessed risk

associated with the financial instruments. A financial control framework and a detailed delegation of

authority manual are also in place to reasonably protect against risk of financial fraud in the Group.

An appropriate financial benchmark is considered in relation to the making of all major investment

decisions to secure against downside risk of such investments. The Group also undertakes aninsurance programme to reduce the potential impact of the physical risks associated with exploration

and production activities. In addition, business interruption cover is purchased for a proportion of the

cash flow from producing fields. Cash balances are invested in short-term deposits, AAA managed

liquidity funds and A1/P1 commercial paper subject to approved limits.

Host government – political and fiscal risks

Premier operates in some countries where political, economic and social transition is taking place.

Developments in politics, laws and regulations can affect the Company’s operations and earnings.

Potential developments include forced divestment of assets; limits on production; import and exportrestrictions; international conflicts, including war; civil unrest and local security concerns that threaten

the safe operation of Premier’s facilities; price controls, tax increases and other retroactive tax claims;

expropriation of property; cancellation of contract rights; and environmental regulations. It is difficult

to predict the timing or severity of these occurrences or their potential effect. If such risks materialise

they could affect the employees, reputation, operational performance and/or financial position of

Premier.

Joint ventures and partners

Inherently, oil and gas operations globally are conducted in a joint venture environment. Many of the

Company’s major projects are operated by its partners. The Company’s ability to influence its

partners is sometimes limited due to the Company’s small share in major non operated development

and production operations. Non alignment on various strategic decisions in joint ventures may result

in operational or production inefficiencies or delay. Premier mitigates this risk by continuous and

regular engagement with its partners in operated and non operated projects.

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PART XI

FINANCIAL INFORMATION ON PREMIER

Financial information relating to the Group as at and for the years ended 31 December 2006,

31 December 2007 and 31 December 2008 is incorporated into this document by reference to thestatutory accounts for Premier for those years, as explained in Part XVII of this document.

124


PART XII

FINANCIAL INFORMATION ON ONSL

A. Introduction

Financial information relating to ONSL and its subsidiary for the years ended 31 December 2005,

31 December 2006 and 31 December 2007 is set out on pages 126 to 157 in this Part XII. Financialinformation relating to ONSL and its subsidiary for the year ended 31 December 2008 has not been

presented since there exists no audited financial information for this period. ONSL entered

administration on 7 January 2009 prior to having prepared audited financials for the year ended

31 December 2008.

125


B. Accountant’s report

Deloitte LLP2 New Street SquareLondonEC4A 3BZ

Tel: +44 (0) 20 7936 3000Fax: +44 (0) 20 7583 1198www.deloitte.co.uk

The Board of Directors

on behalf of Premier Oil plc

23 Lower Belgrave Street

London SW1W 0NR

Deutsche Bank AG, London Branch

Winchester House


London EC2N 2DB


125 Wood Street

London EC2V 7AN

3 April 2009

Dear Sirs

Oilexco North Sea Limited (in administration) (‘‘Target’’)

We report on the financial information set out Part XII of the prospectus and class 1 circular (the

‘‘Prospectus’’) relating to the acquisition of the Target dated 3 April 2009 by Premier Oil plc (the

‘‘Company’’). This financial information has been prepared for inclusion in the Prospectus on the

basis of the accounting policies set out in note 23 of the financial information. This report is

required by Listing Rule 13.5.21R and is given for the purpose of complying with that requirement

and for no other purpose.

Responsibilities

The Directors of the Company are responsible for preparing the financial information on the basis of

preparation set out in note 23 of the financial information.

It is our responsibility to form an opinion as to whether the financial information gives a true and

fair view, for the purposes of the Prospectus, and to report our opinion to you.

Save for any responsibility arising under Prospectus Rule 5.5.3R(2)(f) to any person as and to the

extent there provided, to the fullest extent permitted by law we do not assume any responsibility and

will not accept any liability to any other person for any loss suffered by any such other person as a

result of, arising out of, or in accordance with this report or our statement, required by and given

solely for the purposes of complying with Annex I item 23.1 of the Prospectus Directive Regulation,

consenting to its inclusion in the prospectus.

Basis of opinion

We conducted our work in accordance with the Standards for Investment Reporting issued by the

Auditing Practices Board in the United Kingdom. Our work included an assessment of evidence

relevant to the amounts and disclosures in the financial information. It also included an assessment

of significant estimates and judgments made by those responsible for the preparation of the financial

information and whether the accounting policies are appropriate to the entity’s circumstances,

consistently applied and adequately disclosed.

We planned and performed our work so as to obtain all the information and explanations which we

considered necessary in order to provide us with sufficient evidence to give reasonable assurance that

the financial information is free from material misstatement whether caused by fraud or other

irregularity or error.

126


Our work has not been carried out in accordance with auditing or other standards and practices

generally accepted in jurisdictions outside the United Kingdom, including the United States of

America, and accordingly should not be relied upon as if it had been carried out in accordance with

those standards and practices.

Opinion

In our opinion, the financial information gives, for the purposes of the Prospectus, a true and fair

view of the state of affairs of the Target as at the dates stated and of its profits, cash flows and

changes in equity for the periods then ended in accordance with the basis of preparation set out in

note 23 and has been prepared in a form that is consistent with the accounting policies adopted in

the Company’s latest annual accounts.

Declaration

For the purposes of Prospectus Rule 5.5.3R(2)(f), we are responsible for this report as part of the

Prospectus and declare that we have taken all reasonable care to ensure that the information

contained in this report is, to the best of our knowledge, in accordance with the facts and contains

no omission likely to affect its import. This declaration is included in the Prospectus in compliance

with Annex I item 1.2 and Annex III item 1.2 of the Prospectus Directive Regulation.

Yours faithfully

Deloitte LLP

Chartered Accountants

Deloitte LLP is a limited liability partnership registered in England and Wales with registered number

OC303675 and its registered office at 2 New Street Square, London EC4A 3BZ, United Kingdom.

Deloitte LLP is the United Kingdom member firm of Deloitte Touche Tohmatsu (’DTT’), a Swiss

Verein, whose member firms are legally separate and independent entities. Please see www.deloitte.co.uk/

about for a detailed description of the legal structure of DTT and its member firms.

127


INCOME STATEMENT

For the years ended 31 December 2007, 2006 and 2005

2007 2006 2005

Note $’000 $’000 $’000

Sales revenues 1 341,622 4,394 5,136

Cost of sales 2 (239,613) (5,493) (5,417)

Exploration expense (157,563) (107,489) (9,984)

General and administration costs (20,307) (10,935) (9,289)

Operating loss 2 (75,861) (119,523) (19,554)

Interest revenue, finance and other gains 5 13,688 11,213 697Finance costs and other finance expenses 5 (24,364) (9,550) (1,389)

Mark to market revaluation on commodity hedges 14 (34,709) (5,636) —

Loss before tax (121,246) (123,496) (20,246)

Tax 6 86,517 101,159 —

Loss after tax (34,729) (22,337) (20,246)

The results relate entirely to continuing operations.

Statement of total recognised income and expenses


2007 2006 2005

$’000 $’000 $’000

Currency translation differences on conversion 1,191 (4,598) 463

Net gains/(losses) recognised directly in equity 1,191 (4,598) 463

Loss for the year (34,729) (22,337) (20,246)

Total recognised expense (33,538) (26,935) (19,783)

128


BALANCE SHEET

As at 31 December 2007, 2006, and 2005

2007 2006 2005

Note $’000 $’000 $’000

Non-current assets:

Intangible exploration and evaluation assets 7 82,063 24,205 24,488

Property, plant and equipment 8 556,038 357,262 130,869

Deferred tax asset 15 189,129 101,924 —

827,230 483,391 155,357

Current assets:

Inventories 3,192 — —Trade and other receivables 9 94,414 12,989 15,033

Cash and cash equivalents 11 62,007 63,411 102,194

159,613 76,400 117,227

Total assets 986,843 559,791 272,584

Current liabilities:

Trade and other payables 10 (185,623) (125,193) (42,938)

Current tax payable (47) — —

(185,670) (125,193) (42,938)

Net current (liabilities)/assets (26,057) (48,793) 74,289

Non-current liabilities:Other long-term debt 11 (439,064) (215,575) (16,433)

Long-term provisions 13 (50,161) (6,515) (6,742)

(489,225) (222,090) (23,175)

Total liabilities (674,895) (347,283) (66,113)

Net assets 311,948 212,508 206,471

Equity and reserves:

Share capital 16 — — —

Capital contribution reserve 17 398,266 275,073 242,101

Revenue reserves 17 (87,740) (53,011) (30,674)

Share based payment reserve 17 9,785 — —Translation reserves 17 (8,363) (9,554) (4,956)

311,948 212,508 206,471

129


CASH FLOW STATEMENT


2007 2006 2005

Note $’000 $’000 $’000

Net cash in flow/(outflow) from operating activities 18 239,836 (8,117) (6,983)

Investing activities:

– Capital expenditure (507,008) (265,474) (87,944)

Net cash used in investing activities (507,008) (265,474) (87,944)

Financing activities:– Capital contribution from the parent company 107,912 — 159,019

– Loan (repayments to)/funding from the parent

company (1,151) 5,275 7,703

– Short-term loan drawdowns 178,486 247,120 17,399

– Repayment of loans — (17,399) —

– Interest paid (22,373) (8,132) —

Net cash from financing activities 262,874 226,864 184,121

Currency translation differences relating to cash

and cash equivalents 2,894 7,944 (1,512)

Net (decrease)/increase in cash and cash equivalents (1,404) (38,783) 87,682

Cash and cash equivalents at the beginning of the

year 63,411 102,194 14,512

Cash and cash equivalents at the end of the year 18 62,007 63,411 102,194

130


Notes

1. Geographical segments

The Company’s operations are located in the North Sea only and the Company is only engaged in oil

and gas exploration and production business. The Company has a single business segment and all

associated assets are UK based.

2007 2006 2005

$’000 $’000 $’000

Sales Revenue 341,622 4,394 5,136

Interest income 2,987 3,856 697

Total Revenue 344,609 8,250 5,833

2. Operating loss

2007 2006 2005

Note $’000 $’000 $’000

Operating loss for the year is stated after charging:

Operating costs 59,787 4,071 3,857

Amortisation and depreciation of property, plant

and equipment:

– Oil and gas properties 8 74,520 1,378 1,540

– Other 8 148 44 20Impairment of property, plant and equipment 8 105,158 — —

239,613 5,493 5,417

3. Auditors’ remuneration

2007 2006 2005

$’000 $’000 $’000

Audit fees:

– Fees payable to the Company’s auditors for the Company’s

annual accounts 55 26 25

55 26 25

Non-audit fees:

– Tax compliance services 199 44 44

199 44 44

131


4. Employee costs

2007 2006 2005

$’000 $’000 $’000

Staff costs including executive directors

– Wages and salaries 3,626 1,947 1,003

– Social security costs 511 245 124

4,137 2,192 1,127

A portion of the Company’s staff costs above are recharged to the joint venture partners or

capitalised where they are directly attributable to capital projects. The above costs include share-based

payments to employees as disclosed in note 16 on pages 146 to 147.

2007 2006 2005

Average number of employees during the year*:

– Management and administration 14 9 4

14 9 4

* Staff numbers include executive directors.

5. Interest revenue and finance costs

2007 2006 2005

$’000 $’000 $’000

Interest revenue, finance and other gains:

Short-term deposits 2,582 3,766 697

Other 405 90 —

Exchange differences 10,701 7,357 —

13,688 11,213 697

2007 2006 2005

$’000 $’000 $’000

Finance costs and other finance expenses:Interest on intercompany loan 1,763 1,070 550

Bank loans and overdrafts* 21,756 7,967 —

Unwinding of discount on decommissioning provision 228 348 240

Exchange differences — — 599

Other 316 105 —

Joint venture partners 301 60 —

24,364 9,550 1,389

* In 2007, the Company capitalised interest of approximately US$8.0 million (2006: US$3.8 million; 2005: US$0.3 million) which isnot included in the above analysis.

132


6. Tax

2007 2006 2005

$’000 $’000 $’000

Current tax:

UK corporation tax on profits 688 350 —

Adjustments in respect of previous periods — 415 —

Total current tax 688 765 —

Deferred tax:

UK corporation tax – origination and reversal of temporary

differences (87,205) (101,924) —

Total deferred tax (87,205) (101,924) —

Tax on loss on ordinary activities (86,517) (101,159) —

The credit for the year can be reconciled to the loss per the income statement as follows:

2007 2006 2005

$’000 $’000 $’000

Loss on ordinary activities before tax (121,246) (123,496) (20,246)

Tax on loss on ordinary activities before tax at 50% (for 2005 at40%) (60,623) (61,748) (8,098)

Tax effects of:

– Income/expenses that are not taxable/deductible in

determining taxable profit 2,539 (1,638) 1,178

– Tax effect of deductions not related to profit before tax (26,060) (13,600) (3,620)

– Income subject to tax at different rates (459) (234) —

– Adjustments in respect of previous periods (1,914) (8,610) (1,490)– Tax effect of recognition of tax losses not previously

recognised — (15,329) —

– Unrecognised tax losses — — 12,031

Tax (credit) for the year (86,517) (101,159) 0

Effective tax rate for the year 71% 82% 0%

The effective tax rate for UK ring fence profits is 50% for the years 2007 and 2006 following the

Chancellor’s announcement for supplementary corporation tax which took effect on 1 January 2006.

For the year 2005, the effective tax rate was 40%.

The amount of unused tax losses for which no deferred tax asset is recognised in the balance sheet in

the absence of suitable forecast profits is 2005: $38.9 million for the year 2005. This gives rise to a

potential deferred tax asset of $15.5 million.

133


7. Intangible exploration and evaluation (E&E) assets

Oil and gas

properties

North Sea

$’000

CostAt 1 January 2005 85,288

Additions during the year 83,778

Exchange movements (9,755)

Transfer to property, plant and equipment (124,839)

Exploration expenditure written off (9,984)

At 1 January 2006 24,488

Additions during the year 107,930

Exchange movements (724)Exploration expenditure written off (107,489)

At 1 January 2007 24,205

Exchange movements 247Additions during the year 254,667

Transfer to property, plant and equipment (39,493)

Exploration expenditure written off (157,563)

At 31 December 2007 82,063

The amounts for intangible E&E assets represent costs incurred on active exploration projects. These

amounts are written off to the income statement as exploration expense unless commercial reserves

are established or the determination process is not completed and there are no indications ofimpairment. The outcome of ongoing exploration, and therefore whether the carrying value of E&E

assets will ultimately be recovered, is inherently uncertain.

134


8. Property, plant and equipment

Oil and gas properties

North Sea

Other fixed

assets Total

$’000 $’000 $’000

Cost

At 1 January 2005 4,430 17 4,447

Exchange movements — (10) (10)

Additions during the year 3,206 153 3,359

Transfer from intangible fixed assets 124,839 — 124,839

At 1 January 2006 132,475 160 132,635

Exchange movements 18,486 33 18,519Additions during the year 209,142 160 209,302

At 1 January 2007 360,103 353 360,456

Additions during the year 338,554 555 339,109

Transfer from intangible fixed assets 39,493 — 39,493

At 31 December 2007 738,150 908 739,058

Amortisation and depreciationAt 1 January 2005 (230) (2) (232)

Exchange movements 25 1 26

Charge for the year (1,540) (20) (1,560)

At 1 January 2006 (1,745) (21) (1,766)

Exchange movements — (6) (6)

Charge for the year (1,378) (44) (1,422)

At 1 January 2007 (3,123) (71) (3,194)

Charge for the year (74,520) (148) (74,668)Impairment — loss (105,158) — (105,158)

At 31 December 2007 (182,801) (219) (183,020)

Net book value

At 31 December 2005 130,730 139 130,869

At 31 December 2006 356,980 282 357,262

At 31 December 2007 555,349 689 556,038

Depreciation and amortisation for oil and gas properties is calculated on a unit-of-production basis,

using the ratio of oil and gas production in the period to the estimated quantities of proved and

probable reserves at the end of the period plus production in the period, on a field-by-field basis.

Proved and probable reserve estimates are based on a number of underlying assumptions including oiland gas prices, future costs, oil and gas in place and reservoir performance, which are inherently

uncertain. Management uses established industry techniques to generate its estimates and regularly

references its estimates against those of joint venture partners or external consultants. However, the

amount of reserves that will ultimately be recovered from any field cannot be known with certainty

until the end of the field’s life.

For the year 2007, the impairment charge relates to certain UK fields which were found to be

uneconomic at a price assumption for all future years of $60 per barrel Brent oil and with a 10%

discount rate pre tax.

In 2007, the Company capitalised interest of approximately $8.0 million (2006: $3.8 million and 2005:

$0.3 million).

The cost of oil and gas properties includes approximately $4.7 million (2006: $5.2 million, 2005: nil)

in respect of manifold related subsea equipment held under finance lease. This is being depreciated as

part of the fields which the equipment relate to and hence net book value is not separately identified.

135


9. Trade and other receivables

2007 2006 2005

$’000 $’000 $’000

Trade receivables 83,966 7,182 6,087Other receivables 2,572 1,661 140

Prepayments 7,876 4,146 8,806

94,414 12,989 15,033

The carrying value of the trade and other receivables are equal to their fair value as at the balance

sheet date.

10. Trade and other payables

2007 2006 2005

$’000 $’000 $’000

Trade payables 91,902 33,616 13,377

Accrued expenses 32,161 18,559 9,482

Bank loans 13,070 57,931 17,399

Mark to market valuation on commodity hedges (see note 14) 40,345 5,636 —

Social security in respect of share options 2,945 1,111 —

Finance lease obligation 1,023 829 —

Amount due to parent company 4,177 7,511 2,680

185,623 125,193 42,938

The carrying value of the trade and other payables are equal to their fair value as at the balance

sheet date.

136


11. Borrowings – Long-term

2007 2006 2005

Note $’000 $’000 $’000

Amounts due to parent company 23,390 22,778 16,433Bank loans* 14 412,554 189,189 —

Finance leases 12 3,120 3,608 —

Total borrowings 439,064 215,575 16,433

Cash:

Cash at bank and in hand

Short-term deposits 62,007 63,411 102,194

Total cash 62,007 63,411 102,194

*Bank loans have been offset by unamortised issue costs $8.383 million (2006: $4.166 million, 2005:

nil).

The borrowings are repayable as follows:

2007 2006 2005

$’000 $’000 $’000

Borrowings analysed by maturity:

Between one and two years 223,742 56,589 —

Between two and five years 223,705 163,152 16,433



Senior facility

Under the terms of the Senior Facility agreement the use of initial cash flow from Brenda/Nicol

production was limited to expenses and costs related to Brenda and Nicol fields until project

completion. The agreement provided for the project to be completed after 1.56 million barrels of oil

had been recovered (net to the Company) from Brenda/Nicol. The Company achieved this project

completion status on 6 September 2007, at which time the cash flow derived from Brenda/Nicol

became unrestricted or ‘‘free’’ for the Company use.

On 19 October 2007, an Amendment and Restatement Agreement in respect of the Senior Facilitywas signed with a banking syndicate, headed by Royal Bank of Scotland plc. The agreement extends

both the available amount from $275 million to $500 million and the maturity date from 31

December 2010 to 31 December 2012. The interest rates used are based on LIBOR plus a margin of

1.5%, down from a prior agreement margin of 1.75%. The Senior Facility is secured by a first floating

charge over the assets of Oilexco North Sea Limited, a guarantee from Oilexco Incorporated,

supported by charges over Oilexco Incorporated’s share of Oilexco North Sea Limited, assignment of

insurance proceeds from the Brenda, Nicol and Balmoral fields, and a first charge over Oilexco North

Sea Limited’s bank accounts.

In 2007, the Company was charged an additional financing fee of approximately $2.1 million in

respect of the Senior Facility amendment. In 2006, upon establishment of the Senior Facility a

financing fee of $4.8 million was charged. These charges are being amortised over the life of the

facility. As at 31 December 2007, the remaining deferred financing costs on the senior facility

amounted to approximately $5.2 million.

As at 31 December 2007, the outstanding Senior Facility balance was approximately $331.6 million,

including a current portion of $9.8 million and excluding accrued interest of approximately $1.4

million. The interest charges in respect of the Senior Facility amounted to approximately $19.6

million in 2007 (at an overall average rate of 6.8% per annum) compared to $9.9 million in 2006 and

$ nil in 2005.

137


11. Borrowings – Long-term (continued)

Pre-Development Facility

On 26 February 2007, a Pre-Development Credit Facility (‘‘Pre-Development Facility’’) was signed

with Royal Bank of Scotland for £40 million. The Pre-Development Facility is repayable at any time

subject to certain conditions and matures on 31 January 2008. The interest rates are based on LIBOR

plus a margin of 4% per annum. The interest is payable on interest periods elected by the Company

for each drawing (each such interest period to be one, two, three or six months in duration) and

interest must be paid at the end of the selected interest period. The Pre-Development Facility is

subordinated to the existing Senior Facility. The Pre-Development Facility is secured by a second

ranking charge over the assets of Oilexco North Sea Limited, a guarantee from Oilexco Incorporatedand a second ranking charge over Oilexco Incorporated’s share of Oilexco North Sea Limited.

On 6 July 2007, an Amendment and Restatement Agreement in respect of the Pre-Development

Facility was signed with Royal Bank of Scotland. The agreement extends both the amount of fundsavailable under this facility up to £100 million (approximately $198.5 million at 31 December 2007)

and the maturity date until 31 January 2009. The interest rates are based on LIBOR plus a margin is

applied as follows:

– the first £40 million at 3% per annum

– the next £40 million – £70 million at 4% per annum

– the next £70 million – £100 million at 5.5% per annum

As at 31 December 2007, the outstanding Pre-Development Facility balance was $99.2 million.

Interest payable as at 31 December 2007 was $1.8 million. Interest charged for the year ended

31 December 2007 on the approximately $6.6 million (at an overall average rate of 9.9% per annum)and was capitalised to Shelley and Ptarmigan development projects.

During 2007, the Company was charged approximately $4.4 million in finance fees related toestablishing the Pre-Development Facility and the July Amendment and Restatement Agreement.

These charges are being amortised over the life of the facility and are being capitalised to the related

project developments. As at 31 December 2007, the remaining deferred financing costs totalled $3.2

million.

Facilities Repayment Schedules

As at 31 December 2007, aggregate maturities on total bank loans of $434.0 million including accrued

interest payable of $3.2 million were approximately as follows:

– within current year; 2008 – $13.1 million

– 2009 – $222.6 million

– 2010 – $152.4 million

– 2011 – $45.9 million

Pursuant to the amended Senior Facility agreement, loan repayment obligations are required to

reduce the amount borrowed to an amount no greater than the borrowing base. The amount of the

borrowing base may fluctuate over time, particularly due to changes in oil prices and reserves booked

by the Company. Accordingly, for each balance sheet date, the timing of repayment is estimated

based on the most recent re-determination of the borrowing base and repayment schedules may

change in future periods.

As at 31 December 2007, the Company has letters of credit in place in the total amount of $63

million on the Senior Facility borrowing base related to the Balmoral acquisition. Pursuant to the

amended Royal Bank of Scotland agreement, fees are payable quarterly at a rate of 1.625% per

annum.

Overdraft

The Company has a multi-currency overdraft facility of £1.5 million (approximately $3.0 million) with

Royal Bank of Scotland, repayable on demand. This facility was not utilised as at 31 December 2007.

138


12. Obligations under leases

Operating Leases

2007 2006 2005

$’000 $’000 $’000

Minimum lease payments under operating leases recognised as

an expense in the year 489 221 113

489 221 113

Outstanding commitments for future minimum lease payments

under non-cancellable operating leases, which fall due asfollows:

– Within one year 200 — 38

– In two to five years 342,500 412 —

– Over five years 74,000 108 178

416,700 520 216

Operating lease payments represent the Company’s share of rentals payable by the Company for

FPSOs, and for certain of its office properties, office equipment, and motor vehicles.

Finance Leases

Minimum lease payments

Present value of lease

payments

2007 2006 2007 2006

$’000 $’000 $’000 $’000

Amounts payable under finance leases:

Within one year 1,290 1,124 1,023 829

In the second to fifth years inclusive 3,440 4,120 3,120 3,608

After five years — — — —

4,730 5,244 4,143 4,437

Less: future finance charges (587) (806) n/a n/a

Present value of lease obligations 4,143 4,438

Less: Amount due for settlement within 12 months

(shown under current liabilities) (1,023) (829)

Amount due for settlement after 12 months 3,120 3,608

The Company has no finance leases during the year 2005. The finance lease obligation is denominated

in Norwegian Krone. The fair value of the lease obligation approximates its carrying value. Interest

rates are fixed at the contract date. The lease is on a fixed repayment basis.

139


13. Long-term provisions

2007 2006 2005

$’000 $’000 $’000

Decommissioning costs:

At 1 January 6,514 6,743 6,065

Revision arising from:Additions 40,084 — —

– Change in estimates of future decommissioning costs 3,345 (1,444) 477

– Exchange differences (10) 868 (40)

Unwinding of discount on decommissioning provision 228 348 240

At 31 December 50,161 6,515 6,742

The decommissioning provision represents the present value of decommissioning costs relating to the

UK, oil and gas interests, which are expected to be incurred from 2012 to 2022.

These provisions have been created based on the Company’s internal estimates and, where available,

operator’s estimates. Based on the current economic environment, assumptions have been made whichthe management believe are a reasonable basis upon which to estimate the future liability. These

estimates are reviewed regularly to take into account any material changes to the assumptions.

However, actual decommissioning costs will ultimately depend upon future market prices for the

necessary decommissioning works required, which will reflect market conditions at the relevant time.

Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce

at economically viable rates. This in turn will depend upon future oil and gas prices, which are

inherently uncertain.

140


14. Financial instruments

Hedging instruments

The Company’s activities expose it to financial risks of changes, primarily in oil prices but also

foreign currency exchange and interest rates. The Company uses derivative financial instruments to

hedge certain of these risk exposures. The use of financial derivatives is governed by the Company’s

policies and approved by the Board of Directors, which provide written principles on the use of

financial derivatives.

It is Company policy that all transactions involving derivatives must be directly related to the

underlying business of the Company. The Company does not use derivative financial instruments for

speculative exposures. The Company undertakes oil price hedging periodically within Board limits to

protect operating cash flow against weak prices.

Oil hedging is undertaken with collar options. Oil is hedged using Dated Brent oil price options.

Fair value of hedges

Oil

Asset/(liability) $’000

At 1 January 2006 —

Charge to income statement for 2006 5,636

At 1 January 2007 5,636

Charge to income statement for 2007 34,709

At 31 December 2007 40,345

Fair value of option at 31 December 2007 40,345

The fair values, which have been determined from counterparties with whom the trades have been

concluded, have been recognised in the balance sheet in other payables.

The key variable which affects the fair value of the Company’s hedge instruments is market

expectations about future commodity prices. The following illustrates the sensitivity of net income and

equity to a 10% increase and a 10% decrease in this variable as at 31 December 2007:

Oil

$ million

Ten per cent. increase 24.0

Ten per cent. decrease (24.0)

141


14. Financial instruments (continued)

Interest rate risk profile of financial liabilities

The interest rate profile of the financial liabilities of the Company as at 31 December was:

Fixed rate

Floating

rate Total

Fixed rate

weighted

average

interest

rate

Currency $’000 $’000 $’000 %

2005

Bank loans — 17,399 17,399 —

Due to the parent company — 19,113 19,113 —

Total — 36,512 36,512 —

2006

Bank loans — 247,120 247,120 —

Finance Lease 4,437 — 4,437 7.5%


Total 4,437 277,409 281,846 —

2007

Bank loans — 425,624 425,624 —Finance Lease 4,143 — 4,143 7.5%


Total 4,143 453,191 457,334 —

The carrying values on the 2007, 2006 and 2005 balance sheet of the bank loans which are stated net

of debt arrangement fees and issue costs are as follows:

2007 2006 2005

$’000 $’000 $’000

Bank loans 425,624 247,120 17,399

The floating rate financial liabilities comprise bank borrowings bearing interest at rates set by

reference to US$ LIBOR, exposing the Company to a cash flow interest rate risk.

142



Interest rate risk profile of financial assets

The interest rate profile of the financial assets of the Company as at 31 December was:

Floating

rate

Interest

free Total

$’000 $’000 $’000

2005

Cash and short-term deposits:

Sterling 57,916 — 57,916

US$ 1,230 2 1,232

Canadian $ 43,046 — 43,046

Total 102,192 2 102,194

2006

Cash and short-term deposits:

Sterling 27,118 — 27,118

US$ 20,351 — 20,351

Canadian $ 11,069 — 11,069Norwegian Krone 4,804 69 4,873

Total 63,342 69 63,411

2007Cash and short-term deposits:

Sterling 34,470 — 34,470

US$ 26,623 — 26,623

Canadian $ 352 — 352

Norwegian Krone — 562 562

Total 61,445 562 62,007

The floating rate cash and short-term deposits consist of cash held in interest-bearing current

accounts and deposits placed on the money markets for periods ranging from overnight to three

months.

The impact of an interest rate sensitivity analysis is immaterial to the Company’s results.

Borrowing facilities

The Company has committed borrowing facilities of $500 million and £100 million (2006: $275million, 2005: $18.2 million). The undrawn balance as at 31 December was:

2007 2006 2005

$ million $ million $ million

Expiring in less than one year — — —

Expiring in more than one year, but not more than two years 98.3 — —

Expiring in more than two years, but not more than five years 168.4 23.7 —

143



Fair value of financial assets and financial liabilities

The fair values of the financial assets and financial liabilities are:

2007

Carrying

amount

2007

Estimated

fair value

2006

Carrying

amount

2006

Estimated

fair value

2005

Carrying

amount

2005

Estimated

fair value

$’000 $’000 $’000 $’000 $’000 $’000

Primary financial instruments

held or issued to finance the

Company’s operations:

Cash and short-term deposits 62,007 62,007 63,411 63,411 102,194 102,194

Bank loans 425,624 425,624 247,120 247,120 17,399 17,399

Derivative financial instruments

held or issued to hedge the

Company’s exposure on

expected future sales:

Forward commodity contracts

– net 40,345 40,345 5,636 5,636 — —

Fair value is the amount at which a financial instrument could be exchanged in an arm’s length

transaction, other than in a forced or liquidated sale. Where available, market values have been used

to determine fair values. The estimated fair values have been determined using market information

and appropriate valuation methodologies. Values recorded will not necessarily be realised. Non-interest bearing financial instruments, which include accounts receivable from customers, and accounts

payable are recorded materially at fair value reflecting their short-term maturity and are not shown in

the above table.

144



Credit risk

The Company’s credit risk is attributable to its trade receivables and its bank deposits. The amounts

of receivables presented in the balance sheet are net of allowances for doubtful receivables which were

immaterial in 2007. The Company does not require collateral or other security to support receivables

from customers or related parties. The credit risk on liquid funds and derivative financial instruments

is limited because the counterparties are banks with at least single A credit ratings assigned by

international credit rating agencies as at 31 December 2007.

The Company has significant concentration of credit risk as oil is sold to one trading partner only.

However it is an oil major with a very strong financial position.

The ageing profile of the Company’s trade and other receivables and trade and other payables as at

31 December was:

Within

3 months

3 months to

1 year 1 to 5 years

Over

5 years Total

$ million $ million $ million $ million $ million

2005

Trade and other receivables 6,227 8,806 — — 15,033

Trade and other payables 22,859 20,079 — — 42,938

Borrowings — — 16,433 — 16,433

Total 29,086 28,885 16,433 — 74,404

2006

Trade and other receivables 8,843 4,146 — — 12,989Trade and other payables 57,811 67,382 — — 125,193

Borrowings — — 219,786 — 219,786

Total 66,654 71,528 219,786 — 357,968

2007

Trade and other receivables 86,538 7,876 — — 94,414

Trade and other payables 132,247 53,376 — — 185,623

Borrowings — — 447,447 — 447,447

Total 218,785 61,252 447,447 — 727,484

Currency risk

The Company’s borrowings are mainly denominated in US Dollars being the revenue and functional

currency of the Company. The details of Company borrowings are provided in Note 11.

Liquidity risk

Ultimate responsibility for liquidity risk management rests with the Board of Directors, which has

built an appropriate liquidity risk management framework for the management of the Company’s

short, medium and long-term funding and liquidity management requirements. The Companymanages liquidity risk by maintaining adequate reserves, banking facilities and borrowing facilities by

continuously monitoring forecast and actual cash flows and matching the maturity profiles of financial

assets and liabilities.

145


15. Deferred tax asset

UK

petroleum

revenue tax

UK

corporation

tax Total

$ million $ million $ million

At 1 January 2005Charged to income statement — — —

Other movement — — —

At 31 December 2005 — — —

Credit to income statement — 101,924 101,924


At 31 December 2006 — 101,924 101,924

Charged to income statement — 87,205 87,205


At 31 December 2007 — 189,129 189,129

The majority of the deferred tax asset arose as a result of temporary differences between the carrying

values and tax bases of fixed assets.

16. Share capital

2007 2006 2005

$ $ $

Balance at 1 January 2.0 2.0 2.0

Shares repurchased — — —

Shares issued — — —

Balance at 31 December 2.0 2.0 2.0

Ordinary Shares:

2007, 2006,

2005

2007, 2006,

2005

£1 shares £

Authorised 1,000 1,000

Called up, issued and fully paid 1 1

Equity settled share option plans

A share option scheme is in place for employees. Options are granted over the shares of the parent

company, Oilexco Incorporated, which are listed on the London Stock Exchange. All options vest

immediately upon granting. Exercise prices for stock options granted are determined by the closing

price on the day before the grant date or, if the Company is in a black-out period at the time ofgrant, then the closing market price 48 hours after the dissemination of information which ends the

black-out period.

146


16. Share capital (continued)

Details of share options outstanding during the year are as follows (exercise price are denominated in

Canadian Dollars).

2007 2006

Options

Weighted

average

exercise

price Options

Weighted

average

exercise

price

Outstanding at the beginning of the year 2,940,000 CA$3.82 1,660,000 CA$3.07

Granted during the year 825,000 CA$11.30 1,280,000 CA$4.79

Exercised during the year (865,000) CA$3.41 — —

Outstanding at the end of the year 2,900,000 CA$6.04 2,940,000 CA$3.82

Exercisable at the end of the year 2,900,000 CA$6.04 2,940,000 CA$3.82

2005

Options

Weighted

average

exercise

price

Outstanding at the beginning of the year

Granted during the year 1,660,000 CA$3.07Exercised during the year

Outstanding at the end of the year 1,660,000 CA$3.07

Exercisable at the end of the year 1,660,000 CA$3.07

The weighted average share price at the date of exercise for share options exercised during the year

was CA$3.41. The options outstanding at 31 December 2007 had a weighted average exercise price of

CA$6.04 (2006: CA$3.83; 2005: CA$3.07) and a weighted average remaining contractual life of 3.4years (2006 and 2005: Nil – options vest immediately).

The fair value of the options granted in 2007 was US$4.027 million (2006: US$2.31 million; 2005:US$2.680 million)

The fair value of the options granted during the year was determined using the Black-Scholes

valuation model using following assumptions.

2007 2006 2005

Risk free interest rate 3.75% to 5.45% 4.3% to 5.45% 4.3% to 5.45%

Weighted average years 5 5 5

Expected volatility 42% to 50% 40% to 50% 40% to 50%

Expected dividend yield 0% 0% 0%

147


17. Statement of changes in equity

Sharecapital

Capitalcontribution

reserveRevenuereserves

Translationand hedging

reserves

Share basedpayment

reserve Total$’000 $’000 $’000 $’000 $’000 $’000

At 1 January 2005 — 83,082 (2,074) (5,419) — 75,589

Adjustment to Retained Earnings* — — (8,354) — — (8,354)

Capital contribution — 159,019 — — — 159,019

Translation difference on

conversion — — — 463 — 463

Net loss for the year — — (20,246) — — (20,246)

At 31 December 2005 — 242,101 (30,674) (4,956) — 206,471

Translation differences onconversion — 32,972 — (4,598) — 28,374


At 31 December 2006 — 275,073 (53,011) (9,554) — 212,508

Capital contribution — 107,912 — — — 107,912

Provision for share-based

payments — — — — 9,785 9,785

Translation differences on changein functional currency — 15,281 — 1,191 — 16,472


At 31 December 2007 — 398,266 (87,740) (8,363) 9,785 311,948

* This adjustment relates to write off of exploration expense prior to those reported in these financial statements.

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18. Notes to the cash flow statement

2007 2006 2005

$’000 $’000 $’000

Loss before tax for the year (121,246) (123,496) (20,246)Adjustments for:

– Depreciation, depletion, amortisation and impairment 179,826 1,422 1,560

– Exploration expense 157,563 107,489 9,984

– Share-based payment provision 9,785 — —

– Interest revenue, finance and other gains (13,688) (11,213) (697)

– Interest payable and other finance expenses 24,364 9,550 1,389

– Mark to market commodity hedges 34,709 5,636 —

Operating cash flows before movements in working capital 271,313 (10,612) (8,010)– Increase in inventories (3,192) — —

– (Increase)/decrease in receivables (81,425) 2,044 (11,576)

– Increase/(decrease) in payables 50,801 (2,640) 11,906

Cash generated by operations 237,497 (11,208) (7,680)

– Income taxes paid (648) (765) —

– Interest income received 2,987 3,856 697

NET CASH FROM OPERATING ACTIVITIES 239,836 (8,117) (6,983)

Analysis of changes in net (debt)/cash

2007 2006 2005

Note $’000 $’000 $’000

a) Reconciliation of net cash flow to movement in

net (debt)/cash:

Movement in cash and cash equivalents (1,404) (38,783) 87,682

Proceeds from long-term parent company debt

(including accrued interest) (612) (6,345) (8,251)

Proceeds from short-term bank loan (182,703) (251,286) (17,399)

Finance lease changes 276 (4,437) —Repayment of long-term loans — 17,399 —

Increase in net cash in the period (184,443) (283,452) 62,032

Opening net (debt)/cash (215,090) 68,362 6,330

Closing net (debt)/cash (399,533) (215,090) 68,362

b) Analysis of net (debt)/cash:

Cash and cash equivalents 11 62,007 63,411 102,194

Long-term debt* 11 (447,447) (219,741) (16,433)Short-term portion of external long-term

borrowings (14,093) (58,760) (17,399)

Total net (debt)/cash (399,533) (215,090) 68,362

*Long-term debt has been offset by unamortised issue costs $8.383 million (2006: $4.166 million).

19. Capital commitments and guarantees

At 31 December 2007, the Company had capital commitments on exploration and development

licences totalling $938.8 million (2006: $626.6 million), performance guarantees of $nil million (2006:

$nil million), and customs guarantees of $nil million (2006: $nil million).

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20. Related party transactions

The Company was a wholly-owned subsidiary of Oilexco Incorporated, and received funding and

technical services from the parent company. The details of those arrangements are given below:

2007 2006 2005

$’000 $’000 $’000

Total intercompany balance with the parent company 27,567 30,289 19,113

Loan balance – interest charged during the year 1,763 1,070 550

Provision of technical services 7,472 6,201 3,892

Directors’ remuneration

The remuneration of directors during the year is highlighted below.

2007 2006 2005

$’000 $’000 $’000

Directors’ emoluments 711 429 333

711 429 333

Three of the directors were remunerated by the parent company. Their total remuneration for 2007

was CA$ 2,035,000 (2006: US$ 1.47 million; 2005 $1.45 million).

During 2006, David Marshall and Kevin Burke were each granted 200,000 share options in OilexcoIncorporated, exerciseable at $4.75 per share. In 2005, David Marshall was granted 150,000 share

options exercisable at CA$ 3.35 per share and Kevin Burke was granted 400,000 share options at

CA$3.35 per share. They were not granted options in 2007.

21. Dividends

The Company neither declared nor paid any dividends in the year 2007, 2006 or 2005.

22. Events after the balance sheet date

During the first quarter of 2008, the Company’s parent announced the completion of the first stage of

the appraisal of the Paleocene Forties and Upper Jurassic Fulmar sands on its Huntington prospect

(Block 22/14b). In February 2008, the Company’s parent also announced that it had drilled a

successful appraisal well on the Bugle discovery within license P.815 (Block 15/23d).

In the second quarter of 2008, a number of operating issues reduced the Company’s aggregateproduction for the period. Early in the quarter, employees at the Grangemouth refinery in Scotland

went on strike for two days. The Forties Pipeline System, which transports oil from a number of

fields in the UK North Sea (including certain fields operated by the Company), receives power and

steam from the refinery in order to operate. All producers feeding into the Forties Pipeline System,

including the Company, experienced production interruptions for up to six days during periods of

ramp down and ramp up before and after the strike. Production was also halted several other times

during the second quarter of 2008 as ONSL performed maintenance activities on the Balmoral FPV

and the Brenda subsea manifold, and tied-in the fifth horizontal production well in the Brenda field.Such maintenance work interrupted production for approximately 15 days in the quarter.

In April 2008, the Company acquired 100% of the voting shares of Svenska Petroleum Exploration

UK Limited (now ONSEL) for cash consideration of US$30.6 million (including working capital

adjustments). The acquisition brought with it the following interests.

– 1.66% unitised equity interest in the Nelson Field and platform;

– 6.45% working interest in the Janice and James Fields and floating production vessel; and

– 40% working interest in Block 30/23b, south east of Janice.

Development wells were also drilled during the second quarter of 2008 at Brenda and Shelly.

Appraisal wells were drilled at Balmoral and Blaydon located in Block 16/21, and at Caledonia

located 14 kilometres south of the Balmoral FPV in Block 16/26. Exploration wells were drilled atMoth (Block 23/21), Delta (Block 16/21) and Danica (Block 29/6).

Exploration drilling at Moth (Block 23/21) in June 2008 resulted in a significant discovery of High

Pressure High Temperature (HPHT) gas-condensate in Upper Jurassic Fulmar sands, and oil and gas

150


in Middle Jurassic Pentland sands. A drill-stem test was conducted in the Upper Jurassic Fulmar

zone through perforations from 12,982 feet to 13,026 feet in 115 feet of gas condensate bearing

reservoir sands. The test flowed gas at an average rate of 20.3 Mmcf/d with 2,110 bbls/d of

condensate through a 36/64 inch choke with a flowing tubing pressure of 4,478 psi during the mainflow period.

The Shelley Field Development was progressed during the year, with facility construction and drillingoperations entering their final stages. During the third quarter of 2008, operations commenced on the

first of two planned horizontal production wells. Construction of the floating production storage and

offloading (FPSO) vessel, the Sevan Voyageur, was completed in July 2008.

In July 2008, the Company’s parent announced that it had signed an engagement letter with respect

to refinancing the Company’s current debt obligations and increasing the total debt availability from

US$700 million to US$1 billion. The credit facility was to be underwritten by a syndicate of key

relationship banks, subject to internal credit approvals and due diligence.

In the third quarter of 2008, the Company acquired a 100% interest in the Caledonia Field located in

Block 16/26a, and drilled a cluster of five new appraisal wells in the Caledonia Field area. During the

third quarter of 2008, the Balmoral Floating Production Vessel (Balmoral FPV) also underwent its

annual maintenance turnaround, during which time a number of significant enhancements were made

to improve its operating reliability and production capabilities to more effectively produce thereservoirs to their optimal levels. The project work associated with Brenda Nicol first oil had created

a maintenance build up and it was necessary to reduce some of the backlog. In addition to this

routine maintenance work, certain key areas on the Balmoral FPV were improved.

On 3 October 2008, the Company’s parent announced that the process to close its financing

transaction was taking longer than anticipated due to what it described as the unprecedented liquidity

and volatility issues facing the credit markets. In October 2008, the Company identified an extension

to the Huntington Forties Pool on Block 22/14a. The 22/14b-9 well encountered 58 feet (TVT – true

vertical thickness) of oil-bearing Forties sandstone. Wireline pressures confirmed that these oil-bearing

Forties sandstones were connected with the Huntington Forties Pool, suggesting that the oil pool

extends from Block 22/14b onto a portion of the adjacent Block 22/14a.

In November 2008, the Company’s parent announced that it had been awarded eight new licenses in

the 25th UK Offshore Licensing Round by the Department of Energy and Climate Change. On

17 December 2008, the Company’s parent announced that Royal Bank of Scotland plc and theCompany’s banks had agreed the lending of up to US$47.5 million to the Company, repayable on

demand, with a maturity date of 31 January 2009. In addition, the Company’s parent announced on

17 December 2008 that it had retained Morgan Stanley & Co. Limited and Merrill Lynch

International in a strategic review process to seek alternative funding or the sale of ONSL or some of

its assets. The Company’s parent had encountered substantial financial difficulties and cash flow

problems caused in part by the recent significant falls in the price of oil and its inability to secure

further funding. On 31 December 2008, the Company announced its intention to petition for

administration following confirmation to the Company’s parent by Royal Bank of Scotland plc (onbehalf of the syndicate of lenders) that they were not prepared to advance any further funding to the

Company. On 7 January 2009, the Company was placed into administration by its lending banks.

On 25 March 2009, the Company’s parent and the Company’s Administrators reached a conditional

agreement with Premier Oil plc to dispose of either (i) ONSL’s entire issued share capital; or (ii) the

principal operating assets of ONSL and its subsidiary, ONSEL, for a maximum consideration of

approximately US$505 million.

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23. Accounting policies

General information

Oilexco North Sea Limited is a limited company incorporated in the United Kingdom. The Companywas a wholly-owned subsidiary of Oilexco Incorporated, a company incorporated in Canada. The

principal activities of the Company are oil and gas exploration and production in the North Sea.

The historical financial information is presented in US$ since that is the currency in which the

majority of the Company’s transactions are denominated.

Basis of preparation

The historical financial information of ONSL, for all years, is restated to comply with IFRS using

Premier’s accounting policies as applied in its most recent financial statements. Significant accountingpolicies are set out below.

The historical financial information is prepared on the going concern basis for the years 2007, 2006

and 2005, having taken into consideration funding expected to be available to ONSL as part of the

Enlarged Group, pursuant to the Acquisition.

Adoption of new and revised Standards

In the current year, the Company has adopted IFRS 7 – ‘Financial Instruments: Disclosures’ which is

effective for annual reporting periods beginning on or after 1 January 2007. The impact of theadoption of IFRS 7 has been to expand the disclosures provided in these financial statements

regarding the Company’s financial instruments, their significance and the nature and extent of risks to

which they give rise. There was no effect on the Company’s reported income or net assets as a result

of the adoption of this new Standard.

Basis of accounting

The financial information has been prepared in accordance with International Financial Reporting

Standards (IFRSs) as endorsed by the Council of European Union.

The accounts are prepared under the historical cost convention except for the revaluation of financial

instruments and certain properties at the transition date to IFRS.

The Company has not applied the following IFRSs and International Financial Reporting

Interpretations Committee (IFRIC) interpretations which are in issue but were not yet effective for

the year ended 31 December 2007:

* IFRS 8: Operating segments

* Amendments to IAS 1: Presentation of financial statement – A revised presentation)

* Amendments to IAS 23: Borrowing costs)

* IFRIC 11: IFRS 2: group and treasury share transactions

* IFRIC 12: Service concession arrangements)

* IFRIC 13: Customer loyalty programmes)

* IFRIC 14: IAS 19 The limit on a defined benefit asset, minimum funding requirements and their

interaction)

Interest in joint ventures

A joint venture is a contractual arrangement whereby the Company and other parties undertake an

economic activity that is subject to joint control.

Where a Company undertakes its activities under joint venture arrangements directly, the Company’s

share of jointly controlled assets and any liabilities incurred jointly with other venturers are

recognised in the financial statements of the relevant company and classified according to their nature.

Liabilities and expenses incurred directly in respect of interests in jointly controlled assets are

accounted for on an accrual basis. Income from the sale or use of the Company’s share of the outputof jointly controlled assets, and its share of joint venture expenses, are recognised when it is probable

that the economic benefits associated with the transactions will flow to/from the Company and their

amount can be measured reliably.

Joint venture arrangements which involve the establishment of a separate entity in which each

venturer has an interest are referred to as jointly controlled entities. The Company reports its interests

152


in jointly controlled entities using proportionate consolidation – the Company’s share of the assets,

liabilities, income and expenses of jointly controlled entities are combined with the equivalent items in

the consolidated financial statements on a line-by-line basis.

Where the Company transacts with its jointly controlled entities, unrealised profits and losses are

eliminated to the extent of the Company’s interest in the joint venture.

Sales revenue and other income

Sales of petroleum production are recognised when goods are delivered or the title has passed to the

customer.

Interest income is accrued on a time basis, by reference to the principal outstanding and at the

effective interest rate applicable.

Dividend income from investments is recognised when the shareholders’ rights to receive payment

have been established.

Oil and gas assets

The Company applies the successful efforts method of accounting for Exploration and Evaluation

(E&E) costs, having regard to the requirements of IFRS 6 – ‘Exploration for and Evaluation ofMineral Resources’.

(a) Exploration and evaluation assets

Under the successful efforts method of accounting, all licence acquisition, exploration and appraisal

costs are initially capitalised in well, field or specific exploration cost centres as appropriate, pending

determination. Expenditure incurred during the various exploration and appraisal phases is then

written off unless commercial reserves have been established or the determination process has not

been completed.

Pre-licence costs

Costs incurred prior to having obtained the legal rights to explore an area are expensed directly to

the income statement as they are incurred.

Exploration and evaluation costs

Costs of E&E are initially capitalised as E&E assets. Payments to acquire the legal right to explore,

costs of technical services and studies, seismic acquisition, exploratory drilling and testing are

capitalised as intangible E&E assets.

Tangible assets used in E&E activities (such as the Company’s vehicles, drilling rigs, seismic

equipment and other property, plant and equipment used by the Company’s exploration function) are

classified as property, plant and equipment. However, to the extent that such a tangible asset is

consumed in developing an intangible E&E asset, the amount reflecting that consumption is recorded

as part of the cost of the intangible asset. Such intangible costs include directly attributable overhead,

including the depreciation of property, plant and equipment utilised in E&E activities, together withthe cost of other materials consumed during the exploration and evaluation phases.

E&E costs are not amortised prior to the conclusion of appraisal activities.

Treatment of E&E assets at conclusion of appraisal activities

Intangible E&E assets related to each exploration licence/prospect are carried forward, until the

existence (or otherwise) of commercial reserves has been determined subject to certain limitations

including review for indications of impairment. If commercial reserves have been discovered, the

carrying value, after any impairment loss, of the relevant E&E assets is then reclassified as

development and production assets. If, however, commercial reserves have not been found, thecapitalised costs are charged to expense after conclusion of appraisal activities.

(b) Development and production assets

Development and production assets are accumulated generally on a field-by-field basis and represent

the cost of developing the commercial reserves discovered and bringing them into production,

together with the E&E expenditures incurred in finding commercial reserves transferred from

intangible E&E assets as outlined in accounting policy (a) above.

153


23. Accounting policies (continued)

The cost of development and production assets also includes the cost of acquisitions and purchases of

such assets, directly attributable overheads, finance costs capitalised, and the cost of recognising

provisions for future restoration and decommissioning.

Depreciation of producing assets

The net book values of producing assets are depreciated generally on a field-by-field basis using the

unit-of-production (UOP) method by reference to the ratio of production in the year and the related

commercial reserves of the field, taking into account future development expenditures necessary tobring those reserves into production.

Producing assets are generally grouped with other assets that are dedicated to serving the same

reserves for depreciation purposes, but are depreciated separately from producing assets that serve

other reserves.

Pipelines are depreciated on a unit-of-throughput basis.

(c) Impairment of development and production assets

An impairment test is performed at least annually and whenever events and circumstances arisingduring the development or production phase indicate that the carrying value of a development or

production asset may exceed its recoverable amount.

The carrying value is compared against the expected recoverable amount of the asset, generally by

reference to the present value of the future net cash flows expected to be derived from production of

commercial reserves. The cash generating unit applied for impairment test purposes is generally the

field, except that a number of field interests may be combined as a single cash generating unit wherethe cash flows of each field are interdependent.

(d) Acquisitions, asset purchases and disposals

Acquisitions of oil and gas properties are accounted for under the purchase method where the

transaction meets the definition of a business combination.

Transactions involving the purchase of an individual field interest, or a company of field interests,

that do not qualify as a business combination are treated as asset purchases, irrespective of whether

the specific transactions involved the transfer of the field interests directly or the transfer of an

incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and theconsideration is allocated to the assets and liabilities purchased on an appropriate basis.

Proceeds on disposal are applied to the carrying amount of the specific intangible asset or

development and production assets disposed of and any surplus is recorded as a gain on disposal in

the income statement.

Inventories

Inventories, except for petroleum products, are valued at the lower of cost and net realisable value.

Petroleum products and under and over lifts of crude oil are recorded at net realisable value, under

inventories and other debtors or creditors respectively.

Taxation

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

currently payable is based on taxable profit for the year. Taxable profit differs from net profit asreported in the income statement because it excludes items of income or expense that are taxable or

deductible in other years and it further excludes items that are never taxable or deductible. The

Company’s liability for current tax is calculated using tax rates that have been enacted or

substantively enacted by the balance sheet date.

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying

amounts of assets and liabilities in the financial statements and the corresponding tax bases used inthe computation of taxable profit, and is accounted for using the balance sheet liability method.

Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax

assets are recognised to the extent that it is probable that taxable profits will be available against

which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if

the temporary difference arises from goodwill (or negative goodwill) or from the initial recognition

154



(other than in a business combination) of other assets and liabilities in a transaction that affects

neither the taxable profit nor the accounting profit.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in

subsidiaries and associates, and interests in joint ventures, except where the Company is able to

control the reversal of the temporary difference and it is probable that the temporary difference willnot reverse in the foreseeable future.

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the

extent that it is no longer probable that sufficient taxable profits will be available to allow all or part

of the asset to be recovered.

Deferred tax is calculated at the tax rates that are expected to apply in the year when the liability is

settled or the asset realised. Deferred tax is charged or credited in the income statement, except when

it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt

with in equity. Deferred tax assets and liabilities are offset when there is a legally enforceable right to

set off corporation tax assets against corporation tax liabilities and when they relate to income taxes

levied by the same taxation authority and the Company intends to settle its current tax assets and

liabilities on a net basis.

Translation of foreign currencies

Transactions denominated in foreign currencies, being currencies other than the functional currency,are recorded in the local currency at actual exchange rates as of the dates of the transactions.

Monetary assets and liabilities denominated in foreign currencies at the balance sheet date are

reported at the rates of exchange prevailing at the balance sheet date. Non-monetary assets and

liabilities carried at fair value that are denominated in foreign currencies are translated at the rates

prevailing at the date when the fair value was determined. Non-monetary assets held at historic cost

are translated at the date of purchase and are not retranslated. Any gain or loss arising from a

change in exchange rate subsequent to the dates of the transactions is included as an exchange gain

or loss in the income statement.

Company retirement benefits

Payments to defined contribution retirement benefit plans are charged as an expense as they fall due.

Payments made to state-managed retirement benefit schemes are dealt with as payments to defined

contribution plans where the Company’s obligations under the schemes are equivalent to those arising

in a defined contribution retirement benefit plan.

Royalties

Royalties are charged as production costs to the income statement in the year in which the related

production is recognised as income.

Leasing

Rentals payable for assets under operating leases are charged to the income statement on a straight-

line basis over the lease term.

Financial instruments

Financial assets and financial liabilities are recognised on the Company’s balance sheet when the

Company becomes a party to the contractual provisions of the instrument.

Trade receivables

Trade receivables are stated at their nominal value as reduced by appropriate allowances for

estimated irrecoverable amounts.

Bank borrowings

Interest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue

costs. Finance charges, including premiums payable on settlement or redemption and direct issue

costs, are accounted for on an accrual basis to the income statement using the effective interest

method and are added to the carrying amount of the instrument to the extent that they are not

settled in the year in which they arise.

155



Trade payables

Trade payables are stated at their nominal value.

Derivative financial instruments

The Company may use derivative financial instruments (‘derivatives’) to manage its exposure to

changes in foreign currency exchange rates, interest rates and oil price fluctuations.

All derivative financial instruments are initially recorded at cost, including transaction costs.Derivatives are subsequently carried at fair value. Apart from those derivatives designated as

qualifying cash flow hedging instruments, all changes in fair value are recorded as financial income or

expense in the year in which they arise.

For the purposes of hedge accounting, hedging relationships may be of three types. Fair value hedges

are hedges of particular risks that may change the fair value of a recognised asset or liability. Cash

flow hedges are hedges of particular risks that may change the amount or timing of future cash flows.

Hedges of net investment in a foreign entity are hedges of particular risks that may change the

carrying value of the net assets of a foreign entity.

To qualify for hedge accounting the hedging relationship must meet several strict conditions on

documentation, probability of occurrence, hedge effectiveness and reliability of measurement. If these

conditions are not met, then the relationship does not qualify for hedge accounting. In this case thehedging instrument and the hedged item are reported independently as if there were no hedging

relationship. In particular any derivatives are reported at fair value, with changes in fair value

included in financial income or expense.

For qualifying fair value hedges, the hedging instrument is recorded at fair value and the hedged item

is recorded at its previous carrying value, adjusted for any changes in fair value that are attributable

to the hedged risk. Any changes in the fair values are reported in financial income or expense.

For qualifying cash flow hedges, the hedging instrument is recorded at fair value. The portion of any

change in fair value that is an effective hedge is included in equity, and any remaining ineffective

portion is reported in financial income. If the hedging relationship is the hedge of a firm commitment

or highly probable forecasted transaction, the cumulative changes of fair value of the hedging

instrument that have been recorded in equity are included in the initial carrying value of the asset orliability at the time it is recognised. For all other qualifying cash flow hedges, the cumulative changes

of fair value of the hedging instrument that have been recorded in equity are included in financial

income at the time when the forecasted transaction affects net income.

For qualifying hedges of net investment in a foreign entity, the hedging instrument is recorded at fair

value. The portion of any change in fair value that is an effective hedge is included in equity.

Any remaining ineffective portion is recorded in financial income or expense where the hedging

instrument is a derivative and in equity in other cases. If the entity is disposed of, then the

cumulative changes of fair value of the hedging instrument that have been recorded in equity are

included in financial income at the time of the disposal.

Derivatives embedded in other financial instruments or non-derivative host contracts are treated as

separate derivatives when their risks and characteristics are not closely related to those of host

contracts and the host contracts are not carried at fair value with unrealised gains or losses reportedin the income statement.

Fair value is the amount for which a financial asset, liability or instrument could be exchangedbetween knowledgeable and willing parties in an arm’s length transaction. It is determined by

reference to quoted market prices adjusted for estimated transaction costs that would be incurred in

an actual transaction, or by the use of established estimation techniques such as option pricing

models and estimated discounted values of cash flows.

Cash and cash equivalents

Cash comprises cash in hand and deposits repayable on demand, less overdrafts payable on demand.

Cash equivalents comprise funds held in term deposit accounts with a maturity not exceeding three

months.

156



Share-based payments

The Company has applied the requirements of IFRS 2 – ‘Share-based Payment’. In accordance with

the transitional provisions, IFRS 2 has been applied to all grants of equity instruments after 7November 2002 that were unvested at 1 January 2005.

The Company issues equity-settled share-based payments to certain employees. Equity settled share-based payments are measured at fair value (excluding the effect of non market-based vesting

conditions) at the date of grant. The fair value determined at the grant date of the equity-settled

share-based payments is expensed on a straight-line basis over the vesting period, based on the

Company’s estimate of shares that will eventually vest and adjusted for the effect of non market-

based vesting conditions.

157



PART XIII

UNAUDITED PRO FORMA FINANCIAL INFORMATION

The unaudited pro forma statement of net assets of the Group in this Part XIII has been based on

the financial information of Premier for the year ended 31 December 2008 and prepared inaccordance with Annex II of the Prospectus Rules and on the basis of the notes set out below. The

unaudited pro forma statement of net assets has been prepared to illustrate the effect on the

consolidated net assets of the Group of the Acquisition and the Rights Issue as if they had been

completed on 31 December 2008. As indicated above, the unaudited pro forma statement of net assets

has been prepared for illustrative purposes only and because of its nature the pro forma statement

addresses a hypothetical situation and does not, therefore, represent the Group’s actual financial

position and results. This unaudited pro forma statement does not take into account trading of

Premier subsequent to 31 December 2008 or of ONSL subsequent to 31 December 2007.

Basis of preparation of the pro forma combined assets and liabilities statement at 31 December 2008

The pro forma combined assets and liabilities statement set out below is based on information which

has been extracted without material adjustment from the audited balance sheet of Premier as at

31 December 2008 as incorporated by reference in Part XI of this document and the audited balance

sheet of ONSL restated under IFRS as at 31 December 2007 as set out in Part XII of this document.Further adjustments have been made in accordance with Annex II item 6 of Appendix 3 to the

Prospectus Rules.

1. Unaudited pro forma statement of net assets of the Enlarged Group as at 31 December 2008

Adjustments

Premieraudited

31 December2008

US$ million

ONSLadjustment

US$ million

ONSL loanadjustment

US$ million

Acquisitionaccountingadjustment

US$ million

Loan facilityarrangements

US$ million

Cashconsideration

adjustmentUS$ million

Rights issueproceeds

adjustmentUS$ million Pro forma

Note (2) (3) (4) (5) (6) (7) (8)Non-current assets:Intangible exploration and

evaluation assets 157.9 82.1 — (82.1) — — — 157.9Property, plant and equipment 767.4 556.0 — (269.1) — — — 1,027.3Deferred tax asset 5.8 191.1 — 189.1 — — — 386.0

931.1 829.2 — (189.1) — — — 1,571.2

Current assets:Inventories 14.6 3.2 — — — — — 17.8Trade and other receivables 181.2 94.4 — — — — — 275.6Cash and cash equivalents 323.7 62.0 (62.0) — 35.0 (515.0) 240.0 83.7

519.5 159.6 (62.0) — 35.0 (515.0) 240.0 377.1

Total assets 1,450.6 988.8 (62.0) (189.1) 35.0 (515.0) 240.0 1,948.3

Current liabilities:Trade and other payables (202.8) (185.7) 13.1 — — — — (375.4)Current tax payable (73.8) — — — — — (73.8)

(276.6) (185.7) 13.17 — — — — (449.2)

Net current assets 242.9 (26.1) (48.9) — 35.0 (515.0) 240.0 (72.1)

Non-current liabilities:Convertible bonds (202.7) — — — — — — (202.7)Other long-term debt — (439.1) 439.1 — (35.0) — — (35.0)Deferred tax liabilities (188.8) — — — — — — (188.8)Long-term provisions (143.2) (50.1) — — — — — (193.3)Long-term employee benefit

plan deficits (6.8) — — — — — — (6.8)Deferred revenue (33.6) — — — — — — (33.6)

(575.1) (489.2) 439.1 — (35.0) — — (660.2)

Total liabilities (851.1) (674.9) 452.2 — (35.0) — — (1,109.4)

Net assets 598.9 313.9 390.2 (189.1) — (515.0) 240.0 838.9

Notes:

(1) The pro forma combined assets and liabilities has been prepared in a manner consistent with the accounting policies adopted bythe Company for the year ended 31 December 2008.

158


(2) Financial information in respect of Premier has been extracted without material adjustment from the audited consolidatedfinancial information incorporated by reference in Part XI of this document.

(3) This adjustment reflects the balance sheet of ONSL which has been extracted without material adjustment from the financialinformation as restated to IFRS incorporated in Part XII of this document.

(4) This adjustment reflects the Administration process for ONSL which will result in extinguishment of debt and no cash resourceson the date of acquisition.

(5) The adjustment in respect of excess purchase consideration is as follows:

US$

million

Purchase consideration (505.0)Acquisition costs (10.0)Net assets of ONSL as at 31 December 2007 313.9Loans and cash balances extinguished as part of the Administration process (note 4) 390.2

Provisional net asset excess compared to purchase consideration 189.1

For the purpose of the preparation of the pro forma financial information, the Company has attributed the excess of the net assetsof ONSL over the price paid as an elimination of intangible fixed assets, reduction in Property, Plant and Equipment and acommensurate adjustment to deferred tax asset at the 50% rate applicable in the UK North Sea. A fair value allocation exercise isrequired to be performed as at the date of the ONSL acquisition, which will also likely result in similar allocation of the actualexcess on the acquisition date to Property, Plant and Equipment, Intangible exploration and evaluation assets and related deferredtax, based on the assets and liabilities of ONSL as at that date.

(6) Premier will require draw down from the new finance facility partially to fund the transaction, offset by debt transaction expensesof US$15 million. Expenses relating to raising debt will be capitalised on the date of acquisition and released over the term of thefinance facility to the income statement.

(7) This adjustment reflects the payment of cash consideration of US$505 million for the acquisition of ONSL. In addition it isestimated that transaction expenses of approximately US$10 million will be incurred. Acquisition costs will be capitalised.

(8) This adjustment reflects the net cash proceeds received by the Group on issue of 35,276,566 New Ordinary Shares of 50 pence eachpursuant to the Rights Issue. The estimated costs of US$10 million have been deducted from the cash proceeds and adjustedagainst equity.

(9) The financial information set out above in respect of ONSL has been extracted without modification from the unaudited restatedfinancial information set out in Part XII of this document. As disclosed in paragraph 13 of Part V of this document, if theAcquisition proceeds by way of Asset Acquisition, a number of assets owned by ONSL are capable of pre-emption by existingequity joint venture partners in these assets. In the event that pre-emption occurs in any or all of these assets, the net assetsacquired by Premier may be lower than as disclosed in the pro forma.

159


2. Reporting accountant’s report on pro forma combined statement of net assets of the Enlarged Group

Deloitte LLP2 New Street SquareLondonEC4A 3BZ

Tel: +44 (0) 20 7936 3000Fax: +44 (0) 20 7583 1198www.deloitte.co.uk

The Board of Directors

on behalf of Premier Oil plc


London SW1W 0NR


Winchester House

1 Great Winchester StreetLondon EC2N 2DB


125 Wood Street

London EC2V 7AN

3 April 2009

Dear Sirs

Premier Oil plc (the ‘‘Company’’)

We report on the pro forma financial information (the ‘‘Pro forma financial information’’) set out in

Part XIII of the prospectus and class 1 circular dated 3 April 2009 (the ‘‘Prospectus’’), which has

been prepared on the basis described in the notes thereto, for illustrative purposes only, to provide

information about how the acquisition of ONSL and the related rights issue might have affected the

financial information presented on the basis of the accounting policies adopted by the Company inpreparing the financial statements for the period ended 31 December 2008. This report is required by

Annex I item 20.2 of Commission Regulation (EC) No 809/2004 (the ‘‘Prospectus Directive

Regulation’’) and Listing Rule 13.3.3R and is given for the purpose of complying with those

requirement and for no other purpose.

Responsibilities

It is the responsibility of the directors of the Company (the ‘‘Directors’’) to prepare the Pro formafinancial information in accordance with Annex I item 20.2 and Annex II items 1 to 6 of the

Prospectus Directive Regulation.

It is our responsibility to form an opinion, in accordance with Annex I item 20.2 of the Prospectus

Directive Regulation, as to the proper compilation of the Pro forma financial information and to

report that opinion to you in accordance with Annex II item 7 of the Prospectus Directive

Regulation.

Save for any responsibility arising under Prospectus Rule 5.5.3R(2)(f) to any person as and to the

extent there provided, to the fullest extent permitted by law we do not assume any responsibility andwill not accept any liability to any other person for any loss suffered by any such other person as a

result of, arising out of, or in accordance with this report or our statement, required by and given

solely for the purposes of complying with Annex I item 23.1 of the Prospectus Directive Regulation,

consenting to its inclusion in the Prospectus.

In providing this opinion we are not updating or refreshing any reports or opinions previously made

by us on any financial information used in the compilation of the Pro forma financial information,

nor do we accept responsibility for such reports or opinions beyond that owed to those to whom

those reports or opinions were addressed by us at the dates of their issue.

Basis of Opinion

We conducted our work in accordance with the Standards for Investment Reporting issued by the

Auditing Practices Board in the United Kingdom. The work that we performed for the purpose of

160


making this report, which involved no independent examination of any of the underlying financial

information, consisted primarily of comparing the unadjusted financial information with the source

documents, considering the evidence supporting the adjustments and discussing the Pro forma

financial information with the Directors.

We planned and performed our work so as to obtain the information and explanations we considered

necessary in order to provide us with reasonable assurance that the Pro forma financial informationhas been properly compiled on the basis stated and that such basis is consistent with the accounting

policies of the Company.

Our work has not been carried out in accordance with auditing or other standards and practices

generally accepted in jurisdictions outside the United Kingdom, including the United States of

America, and accordingly should not be relied upon as if it had been carried out in accordance with

those standards or practices.

Opinion

In our opinion:

(a) the Pro forma financial information has been properly compiled on the basis stated; and

(b) such basis is consistent with the accounting policies of the Company.

Declaration

For the purposes of Prospectus Rule 5.5.3R(2)(f) we are responsible for this report as part of theProspectus and declare that we have taken all reasonable care to ensure that the information

contained in this report is, to the best of our knowledge, in accordance with the facts and contains

no omission likely to affect its import. This declaration is included in the Prospectus in compliance

with Annex I item 1.2 of the Prospectus Directive Regulation.

Yours faithfully,

Deloitte LLP

Chartered Accountants

Deloitte LLP is a limited liability partnership registered in England and Wales with registered number

OC303675 and its registered office at 2 New Street Square, London EC4A 3BZ, United Kingdom.

Deloitte LLP is the United Kingdom member firm of Deloitte Touche Tohmatsu (‘‘DTT’’), a Swiss

Verein, whose member firms are legally separate and independent entities. Please see www.deloitte.co.uk/

about for a detailed description of the legal structure of DTT and its member firms.

161


PART XIV

COMPETENT PERSON’S REPORT

In view of its size relative to that of Premier, the Acquisition constitutes a Class 1 transaction under

the Listing Rules. Consequently, the Company is required by Listing Rule 13.4.6(1) to include anindependent mineral expert’s report in this document on the oil and gas assets of ONSL. The

Company commissioned RISC to prepare this independent mineral expert’s report (referred to as the

Competent Person’s Report), which is set out in full below.

RISC (UK) LimitedGolden Cross House

8 Duncannon Street

London

WC2N 4JF

UNITED KINGDOM

23rd March 2009

The DirectorsPremier Oil plc


London SW1W 0NR


Winchester House

Great Winchester Street

London EC2N 2DB


125 Wood Street

London EC2V 7AN

Dear Sirs,

Premier Oil plc (‘‘Premier’’) appointed Resource Investment Strategy Consultants (‘‘RISC’’) to

undertake an independent evaluation of the petroleum assets of Oilexco North Sea Ltd. (‘‘Oilexco’’),

which is currently in administration.

RISC has evaluated reserves and resources in accordance with SPE-PRMS definitions1. RISC’s view

on reserves and resources is based on our review of information provided by Premier including access

to a virtual data room managed by Morgan Stanley & Co Ltd. (‘‘Morgan Stanley’’) as well as

information from the public domain.

Oilexco has a significant portfolio of producing fields, discovered fields under appraisal/development

and exploration acreage containing numerous prospects and leads, all located in the UK sector of the

Central North Sea. Oilexco has interests in 6 producing fields of which Balmoral, Brenda and Nicolare of main interest. Stirling and Glamis are mature fields which provide low volume but low cost oil

as they are produced via Oilexco’s Balmoral Floating Production Vessel (FPV). Oilexco’s working

interest in Nelson is small. Oilexco Incorporated, the parent company of Oilexco North Sea Ltd.

prior to administration, holds small interests in two other North Sea fields, Janice and James,

through a separate entity.

Discovered, undeveloped fields play an important role in Oilexco’s portfolio, which includes both

recent discoveries and a number of discoveries made some years ago by previous license owners and

deemed non-commercial at the time. Depending on the maturity of development plans for these assetsthey have been assessed as either reserves or contingent resources in line with SPE-PRMS definitions.

Oilexco has a large number of exploration interests derived both from farm-in agreements and from

licensing rounds. In several blocks the farm-in well was dry and it is unlikely that there will be any

further substantial activity. Other blocks appear to hold significant exploration potential and may

1 SPE/WPC/AAPG/SPEE Petroleum Resource Management System, March 2007

162


hold accumulations that could be commercially developed given the proximity of existing or planned

infrastructure.

RISC prioritised the assets and concentrated on those assets considered at the outset as most likely to

contribute to value. In particular, RISC focussed on the Balmoral, Brenda, Nicol, Shelley,Huntington, Moth, Caledonia, Bugle and Blackhorse fields. Our results are presented as at 1st January

2009. RISC also overviewed the Oilexco exploration portfolio.

Because no consideration has been given to Oilexco’s other assets or liabilities, the evaluation is not

that of the company. RISC has not advised Premier on the acquisition strategy or price bid for

Oilexco’s interests.

The assessment of petroleum assets is subject to uncertainty because it involves judgments on many

variables that cannot be precisely assessed, including reserves, future oil and gas production rates, the

costs associated with producing these volumes, access to product markets, product prices and the

potential impact of fiscal/regulatory changes.

The statements and opinions attributable to RISC are given in good faith and in the belief that such

statements are neither false nor misleading. In carrying out its tasks, RISC has considered and reliedupon information obtained from Premier, including reports and data provided in the virtual data

room. RISC did not have access to all basic data required to allow verification of technical

information provided to it by means of recalculation. No seismic data was provided with which to

audit subsurface maps and volume calculations presented in the data room, nor was information

provided to support all development assumptions. Consequently, where necessary, RISC has reviewed

and modified the work of other evaluators to take into account issues identified from the dataroom

which are likely to materially impact the value of Oilexco’s assets. A more extensive examination with

access to all basic data might result in different conclusions.

Whilst every effort has been made to verify data and resolve apparent inconsistencies, neither RISCnor its servants accept any liability for, or warrant the accuracy or reliability of our conclusions, nor

do we warrant that our enquiries have revealed all of the matters, which an extensive examination

may disclose. In particular, we have not independently verified property title, encumbrances,

regulations that apply to these assets. RISC has also not audited the opening balances at the

valuation date of past recovered and unrecovered development and exploration costs, undepreciated

past development costs and tax losses.

RISC has no pecuniary interest, other than to the extent of the professional fees receivable for the

preparation of this report, or other interest in the assets evaluated, that could reasonably be regardedas affecting our ability to give an unbiased view of these assets. Our review was carried out only for

the purpose referred to above and may not have relevance in other contexts.

RISC was founded in 1994 to provide independent advice to companies associated with the oil and

gas industry. Today the company has approximately 40 highly experienced professional staff at offices

in London and Perth, Australia. We have completed over 1000 assignments in 55 countries for nearly

400 clients. Our services cover the entire range of the oil and gas business lifecycle and include:

* Oil and gas asset valuations, expert advice to banks for debt or equity finance

* Exploration / portfolio management

* Field development studies and operations planning

* Reserves assessment and certification, peer reviews

* Gas market advice

* Independent Expert / Expert Witness

* Strategy and corporate planning

This assignment was undertaken by:

Nigel Banks, BA Geology (Oxford University 1968), D.Phil Geology (Oxford University 1971),

Member of the American Association of Petroleum Geologists (AAPG), Member of the PetroleumExploration Society of Great Britain (PESGB), Fellow of the Geological Society of London and

Member of the Society of Petroleum Engineers (SPE). Author of 21 papers on regional petroleum

geology, field development and reservoir characterisation and sedimentology. Over 30 years

experience, including prior experience with Shell International, Occidental Petroleum and Cairn

Energy.

163


Alan Atkinson, BSc Physics (University of Hull, 1986), MSc Geophysics (University of Newcastle,

1988), Member European Association of Geoscientists and Engineers (EAGE), Member of the Society

of Exploration Geoscientists (SEG), Member PESGB, Member SPE. 20 years experience, including

prior experience with Phillips Petroleum, Amerada Hess Ltd., Canadian Natural ResourcesInternational (UK) Ltd. and Cairn Energy.

Timothy Chapman, BSc Double Major, Geology and Geophysics (University of Adelaide, 1997), BScPetroleum Geophysics (NCPGG, 1988), MSc Geophysics (University of Houston, 2007). Over 10

years experience, including prior experience with Woodside Energy Ltd., Santos and Edge Petroleum.

Richard Woodhouse, BSc (Honours) Physics with Mathematics (Bristol University, 1964). Member

SPE, Member of the Society of Professional Well Log Analysts (SPWLA). Received Distinguished

Technical Achievement Award of the SPWLA in 2004. An independent consultant with over 40 years

experience, including experience with Schlumberger, Sohio Petroleum and BP.

Ian Roberts, BSc Physics (Hons) (University of Nottingham, 1975), MSc Petroleum Engineering

(Imperial College, 1979). Member SPE. 30 years experience, including early experience with

Schlumberger and 23 years in reservoir engineering and development team leader positions in BP.

John McNeill, BSc (Hons) Chemical Physics (Bristol University, 1980), MSc/DIC Petroleum

Engineering (Imperial College, 1988). Over 25 years experience, including prior experience with

Conoco UK and Cairn Energy.

Will Pulsford, MA (1st class Hons) Engineering Science (Oxford University, 1990), Chartered

Engineer, Member SPE. 19 years experience, including prior experience with Shell International,

Woodside Energy Ltd., and Chevron Australia.

John Wright, B Eng Mining Engineering (Leeds University, 1989), MSc Petroleum Engineering

(Imperial College, 1995). 19 years experience, including prior experience with Kerr McGee (UK) Ltd.,

Ranger Oil (UK) Ltd., Amerada Hess (UK) Ltd, Sterling Energy plc and BG Group.

Geoffrey Salter, M.A. Engineering (Hons), Cambridge University, UK, 1979, MSc. Petroleum

Engineering, Imperial College, London, UK, 1983 (with Distinction), Chartered Engineer, Member

SPE, Member of IOM3. Over 25 years experience including prior experience with Schlumberger,

Santos, Woodside Energy Ltd, and Shell (UK).

Patrick Taylor, BSc (Hons) Applied Mathematics (Queens University of Belfast, 1969), Chartered

Engineer (CEng), Member of the Institute of Materials Minerals and Mining (IOM3), Member SPE,Fellow of the Geological Society of London. Over 35 years experience, including over 30 years in

reservoir engineering and technical management positions in BP.

For and on behalf of

RISC (UK) Limited

P Taylor

Director

164


Independent Evaluation of

the Petroleum Assets of

Oilexco North Sea Ltd.

on behalf of

Premier Oil plc

March 2009

165


Table of Contents

1 EXECUTIVE SUMMARY 170

1.1 Asset Overview 170

1.2 Reserves and Resources 171

1.2.1 Reserves 172

1.2.2 Contingent Resources 173

1.2.3 Prospective Resources 173

1.3 Economic Evaluation 173

1.4 Qualifications 174

1.5 Basis of Opinion 175

1.6 Independence 176

2 PRODUCING FIELDS 177

2.1 Balmoral Field 177

2.1.1 Reservoir Description 177

2.1.2 Development Status and Plans 177

2.1.3 Reservoir Performance and Production Forecasts 177

2.1.4 Schedule and Costs 179

2.1.5 Reserves and Resources 180

2.2 Brenda Field 180

2.2.1 Reservoir Description and In Place Volumetrics 180





2.3 Nicol Field 183






2.4 Other Producing Fields 187

3 FIELDS UNDER DEVELOPMENT 188

3.1 Caledonia Field 188





3.1.5 Reserves 190

3.2 Shelley Field 190



3.2.3 Production Forecasts 192



4 UNDEVELOPED FIELDS 194

4.1 Huntington Field 194

4.1.1 Overview 194





4.1.6 Reserves 198

4.1.7 Opportunities and Risks 198

4.2 Moth Field 199


4.2.2 Development Options 200

166





4.2.6 Opportunities and Risks 2024.3 Bugle Field 203





4.3.5 Reserves 206


4.4 Blackhorse Field 2064.4.1 Reservoir Description and In Place Volumetrics 207




4.4.5 Reserves 209


4.5 Other Discoveries 209

4.5.1 Blocks 22/14a and 22/14b – Triassic and Fulmar Reservoirs 2104.5.2 Block 15/26b – Kildare 210

5 EXPLORATION POTENTIAL 211

5.1 Summary of Exploration Review 2125.2 Prospective Resources valuation 213

6 ECONOMICS 214

6.1 Fiscal Terms and Key Assumptions 214

6.2 Economic Results 2156.3 Sensitivity Analyses (Net Consolidated) 215

6.4 Prospective Resources 217

7 LIST OF TERMS 218

167


List of Figures

FIGURE 1 KEY ASSET LOCATIONS 170

FIGURE 2 PRODUCTION FORECAST SUMMARY FOR BALMORAL FIELD 179

FIGURE 3 PRODUCTION FORECAST SUMMARY FOR BRENDA FIELD 182

FIGURE 4 PRODUCTION FORECAST SUMMARY FOR NICOL FIELD 185

FIGURE 5 PRODUCTION FORECAST SUMMARY FOR CALEDONIA FIELD 189FIGURE 6 PRODUCTION FORECAST SUMMARY FOR SHELLEY FIELD 193

FIGURE 7 PRODUCTION FORECAST SUMMARY FOR HUNTINGTON FIELD 197

FIGURE 8 MOTH CGR PROFILES 201

FIGURE 9 PRODUCTION FORECAST SUMMARY FOR MOTH FIELD 201

FIGURE 10 BUGLE AND BLACKHORSE FIELD LOCATIONS 203

FIGURE 11 PRODUCTION FORECAST SUMMARY FOR BUGLE FIELD 205

FIGURE 12 PRODUCTION FORECAST SUMMARY FOR BLACKHORSE FIELD 208

FIGURE 13 SPE/WPC/AAPG/SPEE PRMS 2007 DEFINITIONS CHART 213FIGURE 14 SENSITIVITY TO DISCOUNT RATE AND OIL PRICE BASED ON

PROVED PLUS PROBABLE RESERVES 216

FIGURE 15 SENSITIVITY TO DISCOUNT RATE AND OIL PRICE BASED ON

PROVED PLUS PROBABLE RESERVES (DEVELOPED PRODUCING

FIELDS) 216

FIGURE 16 SENSITIVITY OF NPV10 BASED ON PROVED PLUS PROBABLE

RESERVES 217

FIGURE 17 SENSITIVITY OF NPV10 BASED ON PROVED PLUS PROBABLERESERVES (DEVELOPED PRODUCING FIELDS) 217

168


List of Tables

TABLE 1 OILEXCO’S PRODUCING FIELD INTERESTS 170

TABLE 2 OILEXCO’S DISCOVERED NON-PRODUCING FIELD INTERESTS 171

TABLE 3 RISC ESTIMATE OF OILEXCO’S RESERVES AT 1ST JAN 2009 172

TABLE 4 RISC ESTIMATE OF OILEXCO’S CONTINGENT RESOURCES AT

1ST JAN 2009 173TABLE 5 SUMMARY OF ECONOMIC EVALUATION OF DISCOVERED ASSETS

AS AT 1ST JANUARY 2009 174

TABLE 6 BALMORAL COST SUMMARY 180

TABLE 7 BALMORAL RESERVES AS AT 1ST JAN 2009 180

TABLE 8 BALMORAL CONTINGENT RESOURCES 180

TABLE 9 BRENDA INITIALLY IN PLACE VOLUMES 181

TABLE 10 BRENDA COST SUMMARY 183

TABLE 11 BRENDA RESERVES AS AT 1ST JAN 2009 183TABLE 12 BRENDA CONTINGENT RESOURCES 183

TABLE 13 NICOL INITIALLY IN PLACE VOLUMES 184

TABLE 14 NICOL COST SUMMARY 186

TABLE 15 NICOL RESERVES AS AT 1ST JAN 2009 186

TABLE 16 NICOL CONTINGENT RESOURCES 186

TABLE 17 CALEDONIA COST SUMMARY 190

TABLE 18 CALEDONIA RESERVES AS AT 1ST JAN 2009 190

TABLE 19 SHELLEY INITIALLY IN PLACE VOLUMES 191TABLE 20 SHELLEY RECOVERY FACTOR COMPARISON 192

TABLE 21 SHELLEY RECOVERABLE VOLUMES SUMMARY 193

TABLE 22 SHELLEY COST SUMMARY 194

TABLE 23 SHELLEY CONTINGENT RESOURCES 194

TABLE 24 HUNTINGTON FORTIES INITIALLY IN PLACE VOLUMES 195

TABLE 25 HUNTINGTON COST SUMMARY 197

TABLE 26 HUNTINGTON RESERVES 198

TABLE 27 MOTH INITIALLY IN PLACE VOLUMES. 200TABLE 28 MOTH LIQUID RECOVERY ASSUMPTIONS 200

TABLE 29 MOTH COST SUMMARY 202

TABLE 30 MOTH CONTINGENT RESOURCES 202

TABLE 31 BUGLE INITIALLY IN PLACE VOLUMES 204

TABLE 32 BUGLE COST SUMMARY 206

TABLE 33 BUGLE RESERVES 206

TABLE 34 BLACKHORSE INITIALLY IN PLACE VOLUMES 207

TABLE 35 BLACKHORSE COST SUMMARY 209TABLE 36 BLACKHORSE RESERVES 209

TABLE 37 SUMMARY OF OILEXCO’S EXPLORATION LICENCES AND THEIR

STATUS AS FAR AS IS KNOWN 212

TABLE 38 SUMMARY OF ECONOMIC EVALUATION OF DISCOVERED ASSETS

AS AT 1ST JANUARY 2009 215

169


1 EXECUTIVE SUMMARY

1.1 ASSET OVERVIEW

Oilexco has a significant portfolio of producing fields, discovered fields under appraisal/development

and exploration acreage containing numerous prospects and leads, all located in the UK sector of the

Central North Sea.

Figure 1 Key Asset Locations

Oilexco has interests in 6 producing fields. Parent company Oilexco Incorporated holds interests in

two others (Janice and James) through a separate entity.

Block License Field Name Operator

Oilexco Working

Interest (%)

16/21a P 201 Balmoral Oilexco 78.115/25b P1042 Brenda Oilexco 100.0

15/25a P 233 Nicol Oilexco 70.0

16/21a P 201 Stirling Oilexco 68.7

16/21a P 201 Glamis Oilexco 85.0

22/11 P 087 Nelson Shell 1.7

30/17a P 032 Janice / James Maersk 6.45

Table 1 Oilexco’s Producing Field Interests

Stirling and Glamis are mature fields which provide low volume but low cost oil as they are

produced via Oilexco’s Balmoral Floating Production Vessel (FPV). Oilexco’s working interests in

Nelson, Janice and James are small, leaving Balmoral, Brenda and Nicol as the producing fields of

main interest.

Discovered, undeveloped fields play an important role in Oilexco’s portfolio, which includes both

recent discoveries and a number of discoveries made some years ago by previous license owners and

deemed non-commercial at the time. The list below is indicative and not exhaustive.

170


Block License Field Name Operator

Oilexco Working

Interest (%)

22/2b P 1260 Shelley Oilexco 100.0

22/14b ( +22/14a) P 1114 Huntington Oilexco2 40.0 (25.04)3

23/21 P 101 Moth BG 50.016/26 P 213 Caledonia4 Oilexco 100.0

15/23d P 815 Bugle Nexen 41.0

15/22 P 185 Blackhorse Nexen 40.0/50.05

15/29a P 119 Ptarmigan Oilexco 60.0/100.06

21/23a P 1220 Sheryl Oilexco7 65.0

15/26b P 1298 Kildare Nexen 50.0

Table 2 Oilexco’s Discovered Non-Producing Field Interests

A fuller summary of RISC’s understanding of Oilexco’s Exploration licence status is provided in

section 5.

For this assessment, RISC has reported net working interest shares of reserves and resources as per

Table 1 and Table 2.

1.2 RESERVES AND RESOURCES

RISC has evaluated reserves and resources in accordance with SPE-PRMS definitions8.

2 It has been reported that operatorship has recently transferred to E.on Ruhrgas UK Exploration and Production Ltd. (materialsighted by RISC referred to Oilexco as operator).

3 Applies to shallow reservoirs in Block 22/14a.

4 Caledonia has produced in the past and is listed here in view of its future redevelopment potential.

5 Rises to 50% after next well.

6 Option to increase to 100%.

7. It has been reported that operatorship has recently transferred to Sterling Resources (material sighted by RISC referred to Oilexcoas operator).

8 SPE/WPC/AAPG/SPEE Petroleum Resource Management System, March 2007.

171


1.2.1 Reserves

RISC’s reserves estimates are summarised below, with fields not reviewed by RISC categorised as

‘‘Other Fields’’.

Gross Working Interest

ProvedProved +

Probable

Proved +

Probable +

Possible

ProvedProved +

Probable

Proved +

Probable +

Possible

Oil (MMstb)

Developed Fields

Brenda 10.9 15.2 19.9 10.9 15.2 19.9

Nicol 4.3 6.2 8.6 3.0 4.3 6.0

Balmoral 1.9 3.0 4.1 1.5 2.3 3.2Other Fields — 40.6 — — 1.6 —

Subtotal 15.4 23.4 29.1

Discovered

Undeveloped Fields

Huntington (Forties

Reservoir)17.3 26.4 36.9 6.4 9.8 13.6

Caledonia(redevelopment)

3.3 4.6 5.6 3.3 4.6 5.6

Bugle 2.8 9.1 19.1 1.1 3.7 7.8

Blackhorse 3.5 8.2 19.6 1.4 4.1 9.8

Subtotal 12.2 22.2 36.8

Total 27.5 45.6 65.9

Gas (Bcf)

Developed FieldsBrenda — — — — — —

Nicol — — — — — —

Balmoral — — — — — —

Other Fields — — — — — —

Subtotal 0.0 0.0 0.0

Discovered

Undeveloped FieldsHuntington (Forties

Reservoir)13.2 20.0 28.0 4.9 7.4 10.4

Caledonia

(redevelopment)— — — — — —

Bugle 3.0 9.7 20.4 1.2 4.0 8.4

Blackhorse 2.6 6.2 14.3 1.0 3.1 7.1

Subtotal 7.1 14.5 25.9

Total 7.1 14.5 25.9

Table 3 RISC Estimate of Oilexco’s Reserves at 1st Jan 2009

Other Fields: Nelson, Stirling and Glamis (Janice and James were not included).

172


1.2.2 Contingent Resources

RISC’s contingent resource estimates are summarised below, with fields not reviewed by RISC

categorised as ‘‘Other Fields’’.

Best Estimate

Gross

Working

Interest

Oil and Condensate (MMstb)

Developed Fields

Brenda 3.8 3.8

Nicol 2.4 1.7

Balmoral 1.4 1.1

Subtotal 6.5

Discovered Undeveloped Fields

Moth 3.4 1.7

Shelley 1.7 1.7

Huntington (Fulmar Reservoir) 4.8 1.9

Other Fields 22.2 14.3

Subtotal 19.6

Total 26.1

Gas (Bcf)

Developed Fields

Brenda — —Nicol — —

Balmoral — —

Subtotal 0.0

Discovered Undeveloped Fields

Moth 40.0 20.0

Shelley — —

Huntington (Fulmar Reservoir) — —Other Fields — —

Subtotal 20.0

Total 20.0

Table 4 RISC Estimate of Oilexco’s Contingent Resources at 1st Jan 2009

Other Fields: Sheryl, Ptarmigan and Kildare

1.2.3 Prospective Resources

Oilexco has a large number of exploration interests derived both from farm-in agreements and from

licensing rounds. In several blocks the farm-in well was dry and it is unlikely that there will be any

further substantial activity. Other blocks, such as 23/21 and 23/22b appear to hold significant

exploration potential and may hold a number of commercial accumulations of the order of 20

MMstb oil or 100 Bcf gas that could be commercially developed given the proximity of existing orplanned infrastructure. We understand well commitments to comprise two firm wells, one contingent

well and two ‘drill or drop’ options.

1.3 ECONOMIC EVALUATION

Economic assessment of Oilexco’s interests in the discovered assets has been based on discounted cash

flow analysis. RISC has audited cash flow models provided in the virtual data room.

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Discovered Assets

RISC has prepared production and cost projections for the studied fields listed above, with the

exception of the Huntington (Fulmar Reservoir) discovery. Also, we have included production andcost projections for additional fields as presented in the virtual data room, without review. These were

presented in the data room as ‘Oilexco estimates and preliminary Sproule estimates’ as at 31st

December 2008. Low and high forecasts for these forecasts were not presented.

The following consolidated Oilexco share NPVs are nominal in US$ million based on the forward oil

price forecast and other base case economic assumptions as described in section 6. Sensitivity results

including US$40/bbl flat nominal and US$80/bbl flat nominal oil price forecasts are also included in

section 6. The major sensitivity is to oil price assumption.

Net NPV10 US$million

Proved Reserves

Proved plus

Probable Reserves

366 876

Table 5 Summary of Economic Evaluation of Discovered Assets as at 1st January 2009

Over 97% of the above value of Proved plus Probable reserves relates to fields reviewed by RISC.

The NPV10 of the Proved reserves above is based on arithmetic summation of the NPV10s of the

Proved reserves of the individual fields. The NPV10 of the Possible reserves has been estimated on

the same basis, i.e. arithmetic summation of the NPV10s of the Possible reserves of the individualfields, at US$416 million.

Unrisked Best Estimate contingent resources have been valued at NPV10 of US$328 million. Fields

reviewed by RISC relate to approximately 35% of this amount.

Exploration Assets

We judge that the additional potential value of prospective resources within exploration acreageoutweighs the outstanding commitments.

1.4 QUALIFICATIONS

RISC was founded in 1994 to provide independent advice to companies associated with the oil andgas industry. Today the company has approximately 40 highly experienced professional staff at offices

in London and Perth, Australia. We have completed over 1000 assignments in 55 countries for nearly

400 clients. Our services cover the entire range of the oil and gas business lifecycle and include:

* Oil and gas asset valuations, expert advice to banks for debt or equity finance

* Exploration / portfolio management

* Field development studies and operations planning

* Reserves assessment and certification, peer reviews

* Gas market advice

* Independent Expert / Expert Witness

* Strategy and corporate planning

This assignment was undertaken by:

Nigel Banks, BA Geology (Oxford University 1968), D.Phil Geology (Oxford University 1971),

Member of the American Association of Petroleum Geologists (AAPG), Member of the Petroleum

Exploration Society of Great Britain (PESGB), Fellow of the Geological Society of London and

Member of the Society of Petroleum Engineers (SPE). Author of 21 papers on regional petroleum

geology, field development and reservoir characterisation and sedimentology. Over 30 years

experience, including prior experience with Shell International, Occidental Petroleum and CairnEnergy.

Alan Atkinson, BSc Physics (University of Hull, 1986), MSc Geophysics (University of Newcastle,

1988), Member European Association of Geoscientists and Engineers (EAGE), Member of the Society

of Exploration Geoscientists (SEG), Member PESGB, Member SPE. 20 years experience, including

prior experience with Phillips Petroleum, Amerada Hess Ltd., Canadian Natural Resources

International (UK) Ltd. and Cairn Energy.

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Timothy Chapman, BSc Double Major, Geology and Geophysics (University of Adelaide, 1997), BSc

Petroleum Geophysics (NCPGG, 1988), MSc Geophysics (University of Houston, 2007). Over 10

years experience, including prior experience with Woodside Energy Ltd., Santos and Edge Petroleum.

Richard Woodhouse, BSc (Honours) Physics with Mathematics (Bristol University, 1964). Member

SPE, Member of the Society of Professional Well Log Analysts (SPWLA). Received Distinguished

Technical Achievement Award of the SPWLA in 2004. An independent consultant with over 40 yearsexperience, including experience with Schlumberger, Sohio Petroleum and BP.

Ian Roberts, BSc Physics (Hons) (University of Nottingham, 1975), MSc Petroleum Engineering(Imperial College, 1979). Member SPE. 30 years experience, including early experience with

Schlumberger and 23 years in reservoir engineering and development team leader positions in BP.

John McNeill, BSc (Hons) Chemical Physics (Bristol University, 1980), MSc/DIC Petroleum

Engineering (Imperial College, 1988). Over 25 years experience, including prior experience with

Conoco UK and Cairn Energy.

Patrick Taylor, BSc (Hons) Applied Mathematics (Queens University of Belfast, 1969), Chartered

Engineer (CEng), Member of the Institute of Materials Minerals and Mining (IOM3), Member SPE,

Fellow of the Geological Society of London. Over 35 years experience, including over 30 years in

reservoir engineering and management positions in BP.

Will Pulsford, MA (1st class Hons) Engineering Science (Oxford University, 1990), Chartered

Engineer, Member SPE. 19 years experience, including prior experience with Shell International,

Woodside Energy Ltd., and Chevron Australia.

John Wright, B Eng Mining Engineering (Leeds University, 1989), MSc Petroleum Engineering

(Imperial College, 1995). 19 years experience, including prior experience with Kerr McGee (UK) Ltd.,

Ranger Oil (UK) Ltd., Amerada Hess (UK) Ltd, Sterling Energy plc and BG Group.

Geoffrey Salter, M.A. Engineering (Hons), Cambridge University, UK, 1979, MSc. Petroleum

Engineering, Imperial College, London, UK, 1983 (with Distinction), Chartered Engineer, Member

SPE, Member of IOM3. Over 25 years experience including prior experience with Schlumberger,

Santos, Woodside Energy Ltd, and Shell (UK).

1.5 BASIS OF OPINION

The assessment of petroleum assets is subject to uncertainty because it involves judgments on many

variables that cannot be precisely assessed, including reserves, future oil and gas production rates, the

costs associated with producing these volumes, access to product markets, product prices and the

potential impact of fiscal/regulatory changes.

RISC’s opinion is based on the review, up to end February 2009, of documents, reports and an

amount of raw data provided in a Virtual Data Room managed by Morgan Stanley, and on

additional information provided by Premier following their collection of data from Oilexco offices in

Canada during February 2009.

RISC focussed on the assets considered at the outset as most likely to contribute to value. Five assets

were addressed with high priority (Brenda, Nicol, Balmoral, Huntington and Moth) and a further

four were addressed with secondary priority (Shelley, Bugle, Blackhorse and Caledonia). RISC hasbased its opinion on review of basic and interpreted data where these were considered sufficient.

RISC did not have access to all basic data required to allow verification of technical information

provided to it by means of recalculation. No seismic data was provided with which to audit

subsurface maps and volume calculations presented in the data room, nor was information provided

to support all development assumptions. Consequently, where basic data has been limited, RISC has

reviewed the available data as a basis to accept or modify the work of other evaluators, including

Sproule International Limited (‘‘Sproule’’), who reported on reserves at end 2008, taking into account

issues identified from the dataroom which are likely to materially impact the value of Oilexco’s assets.A more extensive examination with access to all basic data might result in different conclusions.

RISC also undertook a high level review of the exploration portfolio. Our assessment of prospectiveresources value has been based mainly on the value of work programmes and transactional

information.

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1.6 INDEPENDENCE

RISC makes the following disclosures:

* RISC is independent with respect to Premier and Oilexco and confirms that there is no conflict

of interest with any party involved in the assignment.

* Under the terms of engagement between RISC and Premier for the provision of this report,

RISC will receive a fee, based on time expended and our current standard terms and conditions,

payable by Premier. The payment of this fee is not contingent on the outcome of the proposed

transaction.

* The Directors and staff of RISC may have from time to time owned shares in Premier or

Oilexco. No interests are currently held by RISC directors or by staff involved in thepreparation of this report.

* In the last 2 years, RISC has undertaken separate assignments for Premier. The nature of theseassignments included peer reviews and or technical reports on reserves, production and cost

estimates for various assets. These assignments were not related to or in connection with the

proposed transaction.

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2 PRODUCING FIELDS

2.1 BALMORAL FIELD

The mature Balmoral oil field is located in blocks 16/21a and 16/21b in the UK Central North Sea.

The field produces oil from the Palaeocene Andrew/Balmoral sands. It was discovered in 1975, with

production commencing in 1986. The field lies in about 147m water depth.

2.1.1 Reservoir Description

The Balmoral Field Palaeocene Andrew sandstone reservoir was deposited as part of a large

submarine fan system. Deposition occurred as a result of the Tertiary uplift and eastward erosion of

the Orkney-Shetland Platform. The reservoir and seal formations were deposited as turbidity currents

swept large volumes of sand and mud into the area. The Andrew formation is over 600 ft thick, and

demonstrates differential compaction which results in a broad anticlinal structural depth closure

(Gambaro and Currie, 2003). The sandstones demonstrate variable internal character, from fine tocoarse grained, with a poor to moderate level of sorting. The reservoir is thick and clean, making

petrophysical interpretation straight forward. Net reservoir was calculated as that with greater than

8% porosity and less than 30% clay, with net pay having less than 70% water saturation. Across the

field area the reservoir has an average porosity of 25% and demonstrates fractures which influence

well productivity. The field is imaged by 3D seismic. Seismic attribute analysis has primarily been

used to indicate lithology, however in some local cases it has been successfully used to directly

indicate hydrocarbons. An accurate depth conversion is a key concern as the time structures are low

relief and the overlying sediments exhibit lateral velocity variations. Depending on the depthconversion used, the structure may be filled to spill. Seal is provided by the shales of the overlying

Lista Formation.

The reservoir fluid is 39 degree API oil with an initial GOR of 366 scf/stb at an initial reservoir

pressure of 3,160 psia. The field demonstrates an average oil water contact of 7,050 ft TVDss based

on wireline data.

The Balmoral Field is in an advanced state of depletion and RISC has therefore not audited STOIIP

for this field. Given the field’s maturity, production performance trends have been used to assess itsremaining potential.

2.1.2 Development Status and Plans

The Balmoral field production facilities comprise a subsea gathering system delivering production

fluids through flexible risers to the Balmoral Floating Production Vessel (FPV) secured to a swivelmooring system over the field.

Oil from the Balmoral area is transported from the FPV via a 14-inch diameter pipeline to a T-

junction in the existing Brae-to-Forties link, located 8 miles to the east. It is then exported via the

Forties Pipeline System to Cruden Bay. All gas not utilised for fuel is flared, and likewise water not

re-injected is treated and discharged overboard. Recent area production forecasts confirm that total

oil rates flowing through the FPV are expected to remain below 20 Mstb/d, well within the 60 Mstb/d

facility capacity. Operator studies in January 2008 suggest that produced associated gas volumes willprovide sufficient fuel gas until at least 2014.

Future firm development plans comprise drilling of a single horizontal infill well. There is a

contingent development plan for a second infill well.

2.1.3 Reservoir Performance and Production Forecasts

Balmoral began production in November 1986 and has produced 114.6 MMstb oil from fourteen

producers to end 2008. The field is currently producing around 2000 stb/d from a single re-activated

well, B29, though other wells with mechanical problems have some production potential.

Oil production peaked in 1987, soon after the start of production, at about 40 Mstb/d. Water

injection ceased in 1998 as it was apparent that the very large aquifer was providing sufficient

pressure support and oil displacement through bottom water drive.

Due to the mature state of field development, RISC has reviewed the use of decline curve analysis to

estimate the future performance of the field. Historical production data provided a clear field decline

trend until early 2008 when a number of wells failed due to mechanical problems. Well B23 was re-

activated in mid-December 2008 and initially boosted production to around 2800 stb/d. However by

end December 2008 two wells had failed and at the beginning of February 2009 production had

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declined to around 1800 stb/d from B29 only. As there is now only one remaining producer the field

trend is not a valid basis for estimating future performance.

RISC has reviewed the historic decline trend for B29 prior to shut-in and the evolution of the water

to oil production ratio (WOR) and oil production rate versus cumulative oil production. If B29 had

not been shut-in in 2005, the WOR trend suggests that it would have continued to produce around

1.6 MMstb before reaching a WOR of 20 (water-cut of 95%).

Given that the regional oil-water contact is likely to have risen since 2005 when B26 was shut-in, it is

likely that the future WOR trend will develop more rapidly. RISC estimates that the maximumpossible remaining production from B29 could reach 1.5 MMstb implied by the extrapolation of the

past trend through the WOR of 6.5 observed at the beginning of February.

The operator has budgeted for an infill well whose location was defined by reservoir simulation and

4D seismic, to be drilled in 2H 2009. The 4D seismic (1992 to 2002) showed two locations in the core

area of the field where oil displacement appeared to be less than in the surrounding area. These areas

are mapped as being poorer quality reservoir and are also structurally lower than the surrounding

area. The lower structure may be contributing to the lower 4D signal and therefore there is some

uncertainty to the interpretation.

RISC has generated 1P, 2P and 3P production forecasts assuming risk weighted contributions from

B29 re-activation, A2 re-activation, new infill well ‘‘AH’’ and possible minor contributions from other

currently shut-in wells. A risk-weighted approach has been adopted because future production is

uncertain due to the mechanical state of individual wells, uncertainty of location and quantity of

remaining mobile oil and ambiguity of the 4D seismic results. B29 is in a crestal location (NWextension). Some oil appears to have migrated towards B29 by gravity segregation during the three

years of shut-in. However, gravity segregation in the main structure may not have benefited the flank

well A2, which therefore may not experience flush oil production and may even cut water at a higher

rate.

In view of the uncertainty regarding the future well performance, forecasts were prepared assuming

simple exponential decline trends. These are illustrated as an annual average plot below.

An additional production forecast has been generated for a second infill well, contingent upon the

success of the first infill well. The second well has been identified but not yet proposed by the

operator. It would be located at the second of the two locations identified by 4D seismic. The

incremental volumes have been categorised as Contingent Resources and a production forecast

prepared for the Best Estimate (2C) case.

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RISC’s production forecasts are shown below.

Figure 2 Production Forecast Summary for Balmoral Field

2.1.4 Schedule and Costs

RISC’s schedule and cost estimates are based on Operator data adjusted for the production forecasts

developed by RISC.

Capital Costs

The 2009 WP&B capital programme proposes a single infill well and completion of ongoing umbilical

and riser work scopes. A breakdown of abandonment costs was provided by Oilexco which identified

a total of GBP 31 million for Balmoral wells and the FPV plus an additional GBP 11 million for

Brenda and Nicol wells and subsea systems. These values have been adopted for this analysis.

Operating Costs

RISC has reviewed operating costs budgeted for 2009 to develop forward Opex projections. RISC’sestimates reflect the production forecasts discussed above and include a progressive decline towards

the end of field life. Annual operating costs for the Balmoral FPV are estimated as GBP 23MM

fixed, plus GBP 8MM for opex projects, declining exponentially at 20% per annum plus a variable

component. These costs are distributed across the fields producing into the FPV in proportion to

their annual production. Field overhead and intervention operating costs were estimated to be GBP 2

million per year. A tariff is payable for oil transportation through the Brae-to-Forties link.

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Balmoral Field Costs

Gross 2009 RT (GBP million)

Firm Programme Firm + Contingent

Programme

Scope Single additional infill

well plus close out of

riser and subsea projects

Two additional infill

wells plus close out of

riser and subsea projectsCapital Costs

Drill & Complete 25 50

Subsea 4 4

Total CAPEX 29 54

Annual OPEX

Field (fixed) 2 2

FPV

(Shared with all producing fields)

– Fixed + Projects (2009) 31 31– Variable/Tariff (GBP/bbl) 2.87 2.87

Abandonment

Field 20 20

FPV

(Shared with all producing fields)

10 10

Table 6 Balmoral Cost Summary

2.1.5 Reserves and Resources

Based on the above production and cost data, and the economic analysis described in section 6,

RISC estimates reserves as shown in Table 7 below:

Balmoral Field Gross Working Interest

Reserves at 1st Jan

2009Proved

Proved

+ Probable

Proved

+ Probable

+Possible

ProvedProved

+ Probable

Proved

+ Probable

+Possible

Oil (MMstb) 1.9 3.0 4.1 1.5 2.3 3.2Sales Gas (Bcf) 0 0 0 0 0 0

Table 7 Balmoral Reserves as at 1st Jan 2009

In addition, RISC has estimated contingent resources associated with the potential additional infill

well project.

Balmoral Field Oil (MMstb) Sales Gas (Bcf)

Best Estimate Best Estimate

Gross

Working

Interest Gross

Working

Interest

Contingent Resources 1.4 1.1 0 0

Table 8 Balmoral Contingent Resources

2.2 BRENDA FIELD

The Brenda field is located in blocks 15/25b and 16/21a in the UK Central North Sea. The field has

been on production since June 2006 and yields 40 degree API oil from Palaeocene Forties sands. The

field was discovered in 1989 and lies in about 150m water depth. 15 exploration and appraisal wells

were drilled before the 5 horizontal producers (D1 to D5) were drilled.

At the end of 2008 the field was producing 12 Mstb/d of oil.

2.2.1 Reservoir Description and In Place Volumetrics

The Brenda Field is located in the Outer Moray Firth Basin along the same depositional trend as the

MacCulloch Field, approximately 13 miles to the northwest. The same Palaeocene channel trend runs

from MacCulloch down through Brenda, forming the field’s primary reservoir. These distinct channels

mark the sediment transport fairways deeper into the basin that formed during uplift and over

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steepening of the slope system to the west. The Brenda reservoir is a high porosity, high permeability

Upper Balmoral Sand.

The oil column at Brenda, up to 40ft thick, is stratigraphically trapped by a lateral pinch-out of the

reservoir. The field demonstrates up to five separate oil-water contacts (the shallowest to the west

around well D1 at 6,809ft TVDss and the deepest to the south east around well D3 at 6,865ft

TVDss). These likely result from complicated lateral facies variation resulting in localised

compartmentalisation of the field. These combine to form a series of oil accumulations underlain and

connected by an extensive high permeability aquifer. Cores cut in the upper part of the sandstone

recovered medium to coarse grained massive sandstones interbedded with minor mudstones arranged

in cycles of fining up laminated and rippled sandstones. Top seal is provided by the Sele shale, whilebase seal is provided by the underlying claystones.

Sproule utilised a 3D Petrel model of the field, which was based on 3D seismic interpretation. RISC

reviewed the associated net pay maps by comparison with well log CPI data. Locally seismic attribute

analysis has successfully been used to indicate both lithology and in some cases, hydrocarbons.

The reservoir is thick and clean, so that petrophysical interpretation is unambiguous. The reservoir

averages 100ft tickness with an average porosity of 22%. RISC has adopted the same parameters asused for Balmoral, with net reservoir calculated as that greater than 8% porosity and less than 30%

clay, and with net pay containing less than 70% water saturation. Fluid Contacts are based on

transition zones interpreted from well log CPI data.

After review of the maps prepared by Sproule and Oilexco, RISC estimates STOIIP for the Brenda

Field as shown in the table below.

Brenda Field Oil (MMstb) Gross

Low Best High

Estimate

STOIIP 42.2 47.4 52.7

Table 9 Brenda Initially In Place Volumes


Five horizontal wells, 15/25b-D1 through 15/25b-D5, are on production and a sixth well is proposedfollowing a recent reservoir simulation study.

The production facilities comprise a 5 well subsea cluster tied back to the Balmoral FPV, the 5th well

having come onstream in 2008. A selector on the manifold allows wells to be individually routed to a

multiphase meter. A subsea booster pump is installed downstream of the manifold to enhance

recovery by reducing flowing tubing head pressure as the field declines.

As previously stated, oil is transported from the FPV via a 14-inch diameter pipeline to a T-junctionin the existing Brae-to-Forties link, located 8 miles to the east. It is then exported via the Forties

Pipeline System to Cruden Bay. All gas not utilised for fuel is flared, and likewise water not re-

injected is treated and discharged overboard. Recent area production forecasts confirm that total oil

rates flowing through the FPV are forecast to remain below 20 Mstb/d, well within the 60 Mstb/d

facility capacity. Operator studies in January 2008 suggest that produced associated gas volumes will

provide sufficient fuel gas until at least 2014.

A contingent development plan comprises a possible infill well D6 being brought onstream by mid

2010.


Brenda has produced 8.8 MMstb of oil from June 2006 to end 2008, with the five wells producing a

combined total of approximately 12,000 stb/d at the end of 2008. Water production began

immediately and the water-cut is currently around 68%. This behaviour is typical of the bottom water

aquifer drive of the Balmoral Sand reservoirs where water cones up to the well throughout the well’s

producing life. This is an efficient displacement process but Brenda requires artificial lift andmultiphase pumping to sustain current production.

A reservoir simulation study of the Brenda Field was made by Fekete Associates during 2H 2008.

RISC has reviewed the simulation history match and forecasts and modified these forecasts to reflect

RISC’s view of key reservoir parameters and areas of uncertainty.

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The simulation study uses a single set of Corey type relative permeability curves which have a

residual oil saturation (Sor) of 15%. These were derived from resistivity logs from a Balmoral Field

well in a water swept area of the reservoir directly above the original oil-water contact (OWC). RISC

considers a higher value of around 25% more appropriate to account for the added geologicalcomplexity which can not be fully represented in the simulation model. This higher value of residual

oil saturation for simulation purposes is in line with previous experience from other Forties

Formation fields.

RISC has modified the reservoir simulation derived production profiles to generate forecasts at 1P/2P/

3P levels of confidence.

* The 1P case assumes an 80% factor applied to the simulation model hydrocarbon filled pore

volume (HCPV) and effective residual oil saturation (Sor) of 25%

* The 2P case assumes a 90% factor applied to the simulation model HCPV and an Sor of 25%

* The 3P case assumes a 100% factor applied to the model HCPV and an Sor of 15%

The Sor adjustment in the 1P and 2P cases was modeled by adjusting the time scale of the simulation

model forecast in Excel. The adjustment honours the simulation model controls and water-cut

evolution whilst giving a profile in line with a reduced movable oil volume.

An incremental profile has been generated for the contingent case in which a successful sixth

horizontal development well (D6) is drilled in the south-east of the field and begins production inApril 2010. The simulation model predicts an incremental recovery of 4.2 MMstb for this well. RISC

notes that there is considerable uncertainty in the hydrocarbon pore volume in this area of the

reservoir, where there is no immediate well control.


Figure 3 Production Forecast Summary for Brenda Field



developed by RISC.

Capital Costs

The 2009 WP&B capital programme proposes no field-specific spend for Brenda. For the contingent

2010 infill well RISC has adopted the cost reported by Sproule as being provided by the operator.

Abandonment costs provided by Oilexco were benchmarked against typical industry metrics.

Operating Costs

RISC has reviewed operating costs budgeted for 2009 to develop forward opex projections. RISC’s

estimates reflect the production forecasts discussed above and include a progressive decline towards

182


the end of field life. Annual operating costs for the Balmoral FPV are estimated as GBP23 million

fixed, plus GBP8 million for opex projects, declining exponentially at 20% per annum plus a variable

component of GBP1.67/bbl. These costs are distributed across the fields producing into the FPV in

proportion to their annual production.

A tariff is payable for oil transportation through the Brae-to-Forties link.

A summary of our cost projections is shown in the following table.

Brenda Field Costs

Gross 2009 RT (GBP million) Firm

Programme

Firm + Contingent

Programme

Scope No further

development activity

Infill well in 2010

Capital Costs

Drill & Complete 0 29.5

Total CAPEX 0 29.5

Annual OPEX

Field 1.25 1.50

FPV Fixed/Variable Costs and Export Tariff As Table 6 As Table 6

Field Abandonment 7 8

Table 10 Brenda Cost Summary



RISC estimates reserves and contingent resources as shown in Table 11 and Table 12 below:

Brenda Field Gross Working Interest

Reserves at 1st Jan

2009Proved

Proved

+ Probable

Proved

+ Probable

+Possible

ProvedProved

+ Probable

Proved

+ Probable

+Possible

Oil (MMstb) 10.9 15.2 19.9 10.9 15.2 19.9Sales Gas (Bcf) 0 0 0 0 0 0

Table 11 Brenda Reserves as at 1st Jan 2009

Brenda Field Oil (MMstb) Sales Gas (Bcf)


Gross Working

Interest

Gross Working

Interest


Table 12 Brenda Contingent Resources

2.3 NICOL FIELD

The Nicol field is located in block 15/25a in about 164m water depth. The original discovery, made

by Shell in 1988, intersected 5m of net oil pay on the flank of a four way structural closure. The field

was not appraised until 2005 when Oilexco farmed into the block through funding the drilling of 3

wells. The field currently has 11 exploration and appraisal wells and 2 producers. The field has been

on production since June 2006 and produces oil from Palaeocene Forties sands. At the end of 2008

the field was producing 2 Mstb/d oil.


The Nicol Field is located in the Outer Moray Firth Basin and is on the same depositional trend,

and approximately halfway between, the MacCulloch and Brenda Fields. The Nicol Reservoir is a

massive, high porosity, high permeability Upper Balmoral Sand which consists of a series of stacked

deepwater submarine fan sands. The reservoir is 100-200ft thick with an average porosity of 25%.

Core data indicates that the uppermost reservoir is channel abandonment facies while the main

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reservoir consists of more blocky channel sands. The oil column is up to 55 feet thick and 4-way

structurally trapped. It is underlain by an extensive aquifer which provides strong pressure support

for Nicol and other Upper Balmoral reservoirs in the area. Top seal is provided by the overlying Sele

shales.

The field structure is well defined by 3D seismic data, and the reservoir fluid is 39 degree API oil

with an initial GOR reported as 352 scf/stb. The initial oil-water contact is defined by well data and

is constant at 6,422 ft TVDss. The reservoir is thick and clean, with petrophysical interpretation

consistent with that of previous fields. Sproule utilised a 3D Petrel model of the field, which was

based on 3D seismic interpretation. RISC reviewed the associated net pay maps by comparison with

well log CPI data to develop estimates of STOIIP.

RISC’s estimates of STOIIP for the Nicol Field are shown in the table below.

Nicol Field Oil (MMstb) Gross

Low Best

Estimate

High

STOIIP 19.2 21.6 24

Table 13 Nicol Initially In Place Volumes


The Nicol field production facilities comprise a subsea tie-back to the Brenda field. Two horizontal

producers have been drilled although only one is hooked up and on-line. The second well was drilled

and completed in 2008 and requires installation of production and control line jumpers before

commissioning can commence. Providing a Diving Support Vessel (DSV) can be secured, the

remaining scope could be completed within 6 weeks.

No firm future development plans have been considered in this report. However RISC has identifiedthe potential for a third horizontal production well contingent on field performance which is assumed

to be executed to come onstream in Q1 2011.

As previously stated, oil is transported from the FPV via a 14-inch diameter pipeline to a T-junction

in the existing Brae-to-Forties link, located 8 miles to the east. It is then exported via the Forties

Pipeline System to Cruden Bay. All gas not utilised for fuel is flared, and likewise water not re-

injected is treated and discharged overboard. Recent area production forecasts confirm that total oilrates flowing through the FPV are forecast to remain below 20 Mstb/d, well within the 60 Mstb/d

facility capacity. Operator studies in January 2008 suggest that produced associated gas volumes will

provide sufficient fuel gas until at least 2014.


Two horizontal wells 15/25b-N1w and 15/25b-N2u have been completed for production. 15/25b-N1w

began production in June 2006 and 15/25b-N2u is scheduled to commence production in 1Q 2009.

Well 15/25b-N1w produced 1.2 MMstb of oil from June 2006 to end 2008 and was producing around

2,000 stb/d at the end of 2008. The well cut water immediately and the water-cut is currently around

68%. This behaviour is typical of the bottom water aquifer drive of the Balmoral Sand reservoirs

where water cones up to the well throughout the well’s producing life. This is an efficientdisplacement process but requires artificial lift and possibly multiphase pumping from very early in

the field life. Nicol has both these facilities available.

RISC has reviewed the available Nicol field information and generated production forecasts at 1P, 2P

and 3P levels of confidence.

As the oil production rate from well N1w over the past year and water-cut for the last 6 months

have been relatively stable, no decline trend has developed yet. These fields tend to follow an

exponential decline and this has been assumed to develop the forecasts for Nicol.

Based on comparison with other North Sea Palaeocene fields and ranking according to reservoir and

development parameters, RISC has estimated a range of 1P, 2P and 3P recovery factors of 30%, 35%

and 40% assuming the current development scenario.

Nicol is very low relief with an average structural dip less than 2 degrees. The two development wells

have relatively short horizontal sections compared to overall field dimensions. However, reservoir

porosity and permeability are high.

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RISC considers that the well coverage may be sub-optimal and may benefit from an additional

development well. RISC has therefore estimated a production profile including a third well to the

north-west of the template location which results in an increase in total field recovery factor to 45%.

Since there is no current plan to drill this well, the incremental volume has been assigned to theContingent Resources category.


Figure 4 Production Forecast Summary for Nicol Field



developed by RISC.

Capital Costs

The 2009 WP&B capital programme proposes no field-specific spend for Nicol, however the

outstanding direct costs for hook-up of well N2 are summarised in an investment proposal, to which

RISC has added an operator overhead of 20%. For a contingent 2011 infill well RISC has adopted

the cost reported by Sproule as being provided by the operator.

Abandonment costs provided by Oilexco were benchmarked against typical industry metrics.

Operating Costs

RISC has reviewed operating costs budgeted for 2009 to develop forward opex projections. RISC’s

estimates reflect the production forecasts discussed above and include a progressive decline towards

the end of field life. Operating costs for the Balmoral FPV are estimated as GBP23 million fixed, plusGBP8 million for opex projects, declining exponentially at 20% per annum plus a variable component

of GBP1.67/bbl. These costs are distributed across the fields producing into the FPV in proportion to

their annual production.

A tariff is payable for oil transportation through the Brae-to-Forties link.

185



Nicol Field Costs

Gross 2009 RT (GBP million)

Firm

Programme

Firm + Contingent

Programme

Scope No further

development activity

Infill well in 2010

Capital Costs

Hook-up Well N2 7.1 7.1

Drill & Complete 0 29.5

Total CAPEX 7.1 36.6

Annual OPEX

Field 0.5 0.75

FPV Fixed/Variable Costs and Export Tariff As Table 6 As Table 6


Table 14 Nicol Cost Summary



RISC estimates reserves and contingent resources associated with a potential additional well as shownin the tables below:

Nicol Field Gross Working Interest

Reserves at 1st Jan

2009Proved

Proved

+ Probable

Proved

+ Probable

+Possible

ProvedProved

+ Probable

Proved

+ Probable

+Possible

Oil (MMstb) 4.3 6.2 8.6 3.0 4.3 6.0

Sales Gas (Bcf) 0 0 0 0 0 0

Table 15 Nicol Reserves as at 1st Jan 2009

Nicol Field Oil (MMstb) Sales Gas (Bcf)


Gross

Working

Interest Gross

Working

Interest


Table 16 Nicol Contingent Resources

186


2.4 OTHER PRODUCING FIELDS

As noted in section 1, RISC’s economic evaluation has included unreviewed third party forecasts of

production and costs for Oilexco interests in the following additional producing fields. The plotsbelow (from BERR) illustrate the maturity of these unreviewed fields.

Glamis

Sterling

Nelson (Oilexco WI 1.7%)

James

Janice

187


3 FIELDS UNDER DEVELOPMENT

3.1 CALEDONIA FIELD

Caledonia is included in section 3 because although the field has previously produced, it is not

currently producing and provides a redevelopment opportunity.

The Caledonia field is located in Block 16/26 on the northern edge of the Britannia field. The field is

on trend with other Palaeocene oil fields that include MacCulloch, Nicol, and Brenda. The

accumulation is within a four-way dip closure. The reservoir is the Palaeocene Forties Sandstone.

The field was discovered in 1977 with the drilling of 16/26-1. It was appraised by the 16/26-25 and16/26-27 wells drilled in 1993 and 1996. Both of these wells penetrated hydrocarbon saturated Forties

reservoir. 16/26-25 encountered 43.5 ft of net oil pay and 16/26-27 encountered 25 ft of net oil pay.

The Forties formation was tested by 16/26-25 and flowed 33o API oil through a 40/64-inch choke at a

stabilised rate of 2,941 bopd with a separator GOR of 156 scf/bbl. Prior to the Forties test the 16/26-

25 well tested 219 bopd of 28o API oil from the underlying Lista Formation. The development of the

Lista Formation is considered uneconomic.

A consortium, led by Chevron, followed up with 16/26-30 in 2002, to delineate the reservoir to the

north east of the discovery well. 16/26-30 was wet, and the well was sidetracked near 16/26-25 as the

16/26-30z ‘‘U-shaped’’ pilot hole, which intersected the Forties reservoir pay zone twice. Subsequently,

the 16/26-30y horizontal sidetrack was drilled and completed as a producer. This well produced from

2003 until shut in with high water cut in 2008.


Caledonia lies on a NW-SE trending Palaeocene Forties submarine channel trend and is broadly

similar in its geology to other fields in the area such as Brenda and Nicol. The structure does not

close sufficiently in time to explain the existing oil column, indicating that either the field has a

stratigraphic component to its closure or that there are velocity variations in the overburden.Oilexco’s current depth mapping shows that Caledonia does close structurally and has a maximum of

almost 140 ft of structural closure in the central area. The structure is interpreted to be formed by a

combination of compaction over an underlying structural high and compaction-related drape due to

the presence of sand fairways. Faulting is not apparent at the level of the Forties reservoir. Log

analysis is straightforward and the Forties sandstones typically have porosities >20% and good oil

saturations.

Recent (2008) appraisal wells drilled by Oilexco found the original OWC of 7,440 ft TVDss present in

the northern area but in 16/26-31, close to the horizontal production well, the OWC was interpreted

by both Oilexco and Sproule to have moved up to approximately 74 ft TVDss.

Wireline pressure data were collected in early wells and in three of the 2008 appraisal wells. A 20 psi

pressure decline was observed between the wireline pressure surveys in 16/26-25 (1993) and 16/26-27

(1996). This could be explained by regional aquifer depletion in the Palaeocene during the three yearsbetween wells, or it could be due to gauge error. In the 2008 wells, substantial further depletion was

observed in both the oil column and the aquifer. About 740 psi of depletion was observed at the

OOWC level in the central lobe well 16/26-31, drilled close to 16/26-30y, which had been shut in four

months earlier after producing about 6.0 MMstb oil and 8.8 MMbbls water before being suspended

in February of 2008.

16/26-31z was also drilled into the central lobe, but slightly down structure and into a very differentseismic reservoir character. Pressure data shows that the thin Forties sand was in communication and

partially pressure depleted by production from 16/26-30y, but not to the same level as the higher

quality 16/26-31.

The first recent appraisal well drilled into the northern area was 16/26-31y. Reservoir pressure had

declined by 110 psi, either through depletion from local production or depletion of the entire system

due to regional Palaeocene production.

In summary, the OWC in the northern area appears to be at or near its original location and,

although pressures have declined, the impact from production in the central part of the field has been

limited.

Based on review of Sproule’s mapping, RISC‘s best estimate of STOIIP for the total field is 37.6MMstb of which 8.9 MMstb is assigned to the northern area of the field.

In RISC’s opinion a well into the northern area appears justified but the case for a new central well

is less clear.

188



The field was originally developed as a subsea satellite tieback to the ConocoPhillips/ChevronTexaco-

operated Britannia infrastructure located 3.7 miles to the south. The Caledonia development utilises asingle horizontal well, 16/26-30y, tied-back via a mini manifold installed over the field. As noted

above, 16/26-30y was brought onstream in February 2003 and has produced over 6 MMstb of oil

over five years of production. Currently the well is shut-in due to high water production.

Oilexco purchased a 100 percent interest in Block 16/26, and drilled the five-leg appraisal well cluster,

16/26-31, in 2008. As a condition of the acquisition Oilexco assumed 100% ownership of the field

including future abandonment liabilities.

2009 development activity has been budgeted by Oilexco, including the northern horizontal well, to be

drilled and hooked up to the vacant slot in the existing manifold. Controls from the currently shut in

well will be re-directed to this well. Subsequently the existing well will be re-entered and sidetracked

in an attempt to access central attic oil. RISC has deferred the assumed start-up of the field until

2010 to allow time for procurement of a rig and subsea intervention vessels.


Oil production peaked in 2003 at about 11 Mstbd. The average production for 2008 was 133 Mstbd

(gross). The historic field performance indicates a bottom water aquifer driven displacement where the

oil-water contact has risen to the level of the production well.

RISC has reviewed the Caledonia field reserves and methodology presented in the Field Development

Plan (FDP) and considers it appropriate for a 2P forecast when adjusted for northern area STOIIP

as reported above. The operator defined the forecast by analogy with the 16/26-30y historicperformance and other Palaeocene fields in the area.

RISC’s forecasts are based on a new well in the northern area (assumed to be 16/26-32) and a new

sidetrack of existing producer 16/26-30y. RISC considers that a well to the East of 16/26-30y is

unlikely to be successful as only a slight saddle is mapped as separating this area from updip 16/26-

30y. RISC considers that there is significant uncertainty and has applied appropriate factors to define

the production forecast at 1P, 2P and 3P confidence levels. RISC’s production forecast is shown

below.

Figure 5 Production Forecast Summary for Caledonia Field


Capital Costs

Field re-start is assumed to be early 2010. Capital cost estimates are based on operator provided data

for the proposed new northern well and re-entry of the existing production well. Abandonment costs

were estimated from typical industry metrics.

189


Operating Costs

Operating costs will be a combination of field management and well intervention costs plus oil host

platform processing and export tariffs estimated as a total of GBP7.60/bbl.

Caledonia Field CostsGross 2009 RT (GBP million)

Scope

All Cases

Northern horizontal

well plus sidetrack

of existing producer

Capital CostsNorthern Well 25.7

Side-track 16.1

Subsea 11.8

Project Management / Contingency 7.0

Total CAPEX 60.6

Operating Costs

Fixed 1.50Variable (per bbl) 7.60

Field Abandonment 9

Table 17 Caledonia Cost Summary

3.1.5 Reserves


RISC estimates reserves as shown below.

Caledonia Field Gross Working Interest

Reserves at

1st Jan 2009Proved

Proved

+ Probable

Proved

+ Probable

+Possible

ProvedProved

+ Probable

Proved

+ Probable

+Possible

Oil (MMstb) 3.3 4.6 5.6 3.3 4.6 5.6

Sales Gas (Bcf) 0 0 0 0 0 0

Table 18 Caledonia Reserves as at 1st Jan 2009

3.2 SHELLEY FIELD

The Shelley Field is located in Blocks 22/2b and 22/3a and in approximately 115m of water. It was

discovered by the 22/2-2 well, drilled in 1984 by Burmah Oil. The discovery well tested 310 API oil at

2,416 bopd from the Upper Forties reservoir. Oilexco drilled appraisal well 22/2b-13 in October 2006,

followed by six sidetracks, and 22/2b-14 which was also extensively sidetracked. Of the first fourteen

penetrations of the Forties sandstone from these two wells, eight encountered the oil column and six

were wet. This reflects the difficulty associated with seismic structural control in a low relief structure

where seismic imaging and depth conversion are compromised by the presence of gas in the overlying

strata.

A Field Development Plan was approved in 2008, with production from Shelley due to commence at

the end of Q1 2009 at an initial rate of 10,000-15,000 bopd to a dedicated FPSO. During fielddevelopment an additional nine reservoir penetrations were made prior to completion of two

horizontal production wells. 22/2-P1 was completed as the 22/2-P1z horizontal production well. In the

southern area 22/2-P2 unexpectedly encountered gas in the Forties reservoir and was sidetracked five

times before completion in 22/2-P2s. Despite multiple penetrations, there remains significant

uncertainty in STOIIP and reserves.

As discussed below, hook up of the two development wells to the FPSO has been suspended by the

Oilexco Administrator.

190



The field is a low relief, normally pressured Palaeocene Forties oil reservoir with possible upside in

underlying Piper sands where an over-pressured gas condensate accumulation was penetrated in thediscovery well. A small gas cap is present in the southern part of the field.

The field occupies a position within the large and well defined Palaeocene Forties turbidite fairway.

The main reservoir is the Forties Member of the Sele Formation, comprising stacked high density

turbidite fan lobes. The oil accumulation occupies a subtle four-way dip closed anticline with 70 feet

of relief, and extends over approximately 13 km2. The structure was probably formed by drape over

an underlying Triassic horst block but, although the field is covered by a 3D seismic survey,

insufficient seismic data has been seen by the reviewers to confirm this. The reservoir is sealed by the

overlying Sele shales, and the oil is likely to be sourced from the underlying Kimmeridge Clay

formation.

Four layers have been identified in the Forties sand. The upper is a Forties abandonment facies andis considered non-reservoir. The second has characteristic high resistivity, referred to as the High

Resistivity Zone (HRZ), the third has characteristic low resistivity, referred to as the Low Resistivity

Zone (LRZ), while the lowermost layer is also non-reservoir and provides a bottom seal in the

southern part of the field.

The Oilexco depth structure map in the FDP included a simple adjustment to compensate for push-

down under overlying gas sands. Well results (22/2b-P2x, P2u) demonstrated that this adjustment was

justified.

Both the Operator and Sproule modeled a transition zone, identified as a zone of up to 15 feet above

the OWC (8,200 ft TVDss) separately from the remainder of the reservoir, referred to as the main

zone. Sproule re-analysed well test and petrophysical data, confirming Oilexco’s results, and adoptedOilexco’s Petrel model to calculate net oil pay maps for the transition zone, and the main oil zone.

Gross Rock Volumes were calculated and combined deterministically with constant reservoir

parameters for each of three identified areas of the field to estimate STOIIP. Ranges were calculated

by varying formation volume factor.

RISC reviewed all petrophysical logs, assessing the gross thicknesses of the main oil zone,

predominantly the HRZ, and the underlying zone separately. Maps of these thicknesses were hand-

contoured and GRVs for the main oil zone and for the underlying zone were calculated. Ranges were

established by varying the OWC by 5 feet. Core and wireline logs were available from 22/2-2 and 22/

2b-14m. All other wells were evaluated using LWD. RISC accepted petrophysical analysis performedon all wells by the operator.

As most of the wells are highly deviated, there are some discrepancies in logged contacts. All

evaluators have adopted the practice of using the OWC as a datum depth. Under the gas cap, a

thinned oil column is observed. RISC considers that this area is in a poorer reservoir zone. A

convincing OWC is seen in nearby wells 22/2b-14p and 22/2b-14x.

Well tests were run on 22/2-2, 22/2b-14m and 22/2b-13t. Reservoir fluid properties are based on PVT

analysis of fluids obtained in 22/2b-14m.

Shelley contains 310 API oil with a solution GOR of around 670 scf/stb and the bubble point is in

the range 2,900-3,100 psia. (This appears inconsistent with the presence of a gas cap observed in 22/

2b-14y, which lies in the southern part of the field and separated from the 22/2b-14m by a saddle.

This suggests either the possibility of separate oil properties in the two areas or uncertainty in the

validity of sampling/recombination.) Initial reservoir pressure is 3,550 psia and initial reservoirtemperature is 2280F. The formation volume factor was measured at 1.38 from a bottom-hole sample

taken in 22/2b-14m. RISC has used a formation volume factor range of 1.25 – 1.33 – 1.41 for

estimation of STOIIP.

The calculated GRVs were combined probabilistically with fluid and rock parameter ranges to derive

STOIIP estimates which are presented in the table below.

Shelley Field Oil (MMstb) Gross

Low Best High

Estimate

STOIIP 8.8 14.2 23.1

Table 19 Shelley Initially In Place Volumes

191



A Field Development Plan dated March 2008 has received approval and the initial phase of

development has been largely executed.

The development consists of two horizontal subsea production wells, 22/2-P1z and 22/2-P2s, which are

anticipated to come onstream at 10,000-15,000 bopd. Both wells have been drilled and completedfrom a common drill centre and are to be hooked up to a sub-sea manifold. An 8 inch production

line is planned to connect the manifold to a cylindrical FPSO, the Sevan Voyageur, located 2.2 km

from the drill centre. Oil is to be exported from the FPSO by shuttle tanker.

The Oilexco Administrator has suspended the project prior to completion of the subsea hook-up. The

outstanding workscope comprises:

* Hook-up of the manifold drill centre

* Installation of production riser and umbilical

* FPSO production commissioning

* Documentation and hand-over

Execution of the remaining workscope requires access to subsea installation vessels which are in high

demand over the North Sea summer months. Technip has advised the availability of vessels in either

March/early April or October 2009, with the former vessel slots requiring rapid commitment to

mobilisation. In the meantime significant opex and vessel standby costs will be incurred by the owners

under the existing FPSO contract.

There is no provision for gas export, and all gas not utilised for fuel is to be flared. Likewise it is

planned to discharge the produced water overboard. A waiver for water discharge is pending

approval.

RISC understands that the lease agreement for the Sevan Voyageur is expected to be renegotiated by

the future Operator of the field, without which the field is unlikely to commence production asplanned. This introduces an additional uncertainty in forecasting field economic performance and

brings the commerciality of the field into question. Consequently we have treated the forecast

production as a Contingent Resource.

3.2.3 Production Forecasts

As noted above, the oil column in Shelley is relatively thin, particularly in the southern area. The

development plan reflects this in the application of horizontal wells for production and the provision

for rapid rise in water cut.

The 22/2-P1z and 22/2-P2s horizontal production wells penetrated 1830ft and 707ft of pay

respectively. This is less than the 3000ft per well in the Eclipse simulation model, but initial field oil

rates are still predicted to lie in the range of 10,000-15,000 bopd.

A number of simulation sensitivities are documented in the Field Development Plan reflecting

uncertainties in vertical permeability, relative permeability, oil viscosity and aquifer strength as well as

STOIIP. The range of recovery factors from these sensitivity cases is 13.1% to 26.5% with a mean of21%. Sproule adopted different recovery factors for the high and low resistivity pay reflecting the

lower oil saturation calculated. RISC has also adopted this approach. Recovery factors adopted by

RISC are as follows:

Recovery Factors

Reservoir Zone P90 P50 P10

Forties High Resistivity 20.0% 32.5% 45.0%

Low Resistivity 0.0% 10.0% 20.0%

Table 20 Shelley Recovery Factor Comparison

192


RISC has used these recovery factors to arrive at a range of technically recoverable volumes shown in

the following table:

Technically Recoverable Volume (MMstb)

Reservoir Zone Low Best Estimate High

Forties High Resistivity 0.42 1.17 2.79Low Resistivity 0.0 1.06 3.38

Arithmetic sum 0.42 2.23 6.17

Table 21 Shelley Recoverable Volumes Summary

Some of the low resistivity zone is in the southern area of the field which is not drained by either of

the existing horizontal production wells. This constitutes around 30% of the LRZ STOIIP, and

therefore around 0.32 MMstb of the Best Estimate in the above table would require a third

production well to drain the oil in the southern area. The third well has been included in the High

case, which can support the incremental cost, but not in the Best Estimate or Low cases.

Production profiles have been prepared on a monthly basis using a constant liquid rate and a

constantly declining oil rate as simulation indicates essentially no plateau period (although a three

month plateau is replicated for the High case).

In the Low case a rate of 2500 bopd is reached within three months of the start of production, but

in this case the cost of well hook-up and other commissioning costs could render the project

uneconomic on a look-forward basis. Production declines to 2500 bopd within 9 months in the Best

Estimate case and after 32 months in the High case.

RISC’s monthly production forecast is shown below, based on the previously planned 1st oil date of1st April 2009. A production uptime of 90% was used for calculating cumulative production in the

estimation of contingent resources.

Figure 6 Production Forecast Summary for Shelley Field


Field start-up is assumed to be April 2009, on the assumption that, subject to confirmation ofcommerciality, a new owner will wish to minimise exposure to standby opex.

Capital Costs

Capital cost estimates to complete the remaining workscope are based on data provided by the

Operator. Abandonment costs were estimated from typical industry metrics.

Operating Costs

Operating costs will be a combination of field management and well intervention costs, FPSO lease

and operating costs plus oil export tariffs. FPSO lease costs have been derived from Oilexco

193


documentation. Field overhead and intervention operating costs were estimated in addition to FPSO

lease costs. Operating costs are assumed to be incurred from March onwards.

Opex accrued prior to March and outstanding capital liabilities (reported to be GBP7.5 million and

GBP12.4 million respectively) are assumed to have been cleared in the ownership transaction. RISC

notes that the services contract between Oilexco and Sevan is for a 5 year term and that Oilexco

remains liable for lease charges, or the difference between the contract lease charges and any alternatehire rates earned by the Sevan Voyageur, for that entire period. Production profiles developed by

RISC range from 4 months to 32 months, leaving a significant additional liability beyond the

abandonment of the field. This liability has not been included in the economic modeling of the Shelley

field.


Shelley Field Costs

Gross 2009 RT (GBP million) Low/Best Estimate

Cases

High

Case

Scope 2 producers tied back

to Sevan Voyageur

3 producers tied back

to Sevan Voyageur

Capital Costs

Completion of remaining scope 7.2 7.2Third well and subsea hook-up 29.0

Operating Costs

Field per annum 1.5 2.0FPSO + Support (/month) 5.1 5.1

Oil Export Costs (GBP/bbl) 0.5 0.5


Table 22 Shelley Cost Summary


Shelley development is not economic under the above forecasts and the economic assumptions

discussed in section 6. No value has been assigned in the economic summary. RISC estimates

contingent resources as shown in the table below:

Shelley Field Gross Working Interest

Contingent Resources Low Best High Low Best High

Estimate Estimate

Oil (MMstb) 0.4 1.7 5.4 0.4 1.7 5.4

Gas (Bcf) 0 0 0 0 0 0

Table 23 Shelley Contingent Resources

4 UNDEVELOPED FIELDS

The Oilexco portfolio includes several fields which are at various stages of development planning.

4.1 HUNTINGTON FIELD

4.1.1 Overview

The Huntington Field is situated in the UK Central Graben approximately 25 km northwest of theMontrose and the Arbroath fields. The majority of the field is located in Block 22/14b with

extensions into neighbouring blocks. Through various farm-ins, Oilexco hold a 40% interest in Block

22/14b, a 72.7% interest in Block 22/13b, a 25.04% interest in the shallow section of Block 22/14a and

a 27.24% interest in the pre-Chalk section of Block 22/14a.

The discovery well 22/14b-5 was drilled by Oilexco on a seismically defined high and encountered

hydrocarbon-bearing Palaeocene Forties Sandstone, the Upper Jurassic Fulmar Sandstone and

Triassic sandstones of the Skagerrak Formation.

In this report the Fulmar and Triassic reservoirs are discussed in section 4.1.7 with the main text

describing the Forties reservoir.

194



An extensive appraisal programme of the Forties reservoir involved the drilling of nine sidetrack wells

from the 22/14b-6 well cluster together with three further wells, 22/14b-8, which also targeted theFulmar, 22/14b-9 and 22/14b-9z.

The structure is a low relief anticlinal closure at Forties level draped over a more prominent Jurassic-Triassic high. However, stratigraphic trapping seems to be required at Forties level to separate

Huntington from the larger structure to the northeast tested by the dry hole 22/14-1. Huntington

East, tested by well 22/14b-9z, is considered by Sproule to be a separate closure at Forties level but

in RISC’s opinion it may be part of the same structure.

Reservoir quality is good with average porosity of approximately 21% and a high net to gross ratio.

Many Palaeocene fields in the Central Graben have tilted oil-water contacts reflecting a regional

hydrodynamic aquifer gradient from southeast to northwest: Huntington appears to conform to this

model. However, there is considerable uncertainty about the picking of the oil-water contact (OWC)

in most of the wells. Sproule and Oilexco have subdivided the reservoir into an upper high resistivityzone (HRZ) and a lower, low resistivity zone (LRZ). The LRZ varies in thickness from 0-50 ft and

averages 31 ft.

Other evaluators have picked the OWC at the base of the LRZ where the deep resistivity drops

below 1 ohm.m. Various arguments have been put forward to justify this interpretation, the most

convincing of which is the 1300-1400 bopd and 300-400 bwpd oil tested from the upper part of the

LRZ in 22/14b-6q. However, there are many counter-arguments and also considerable uncertainties

and ambiguities in the data that hamper interpretation. In RISC’s opinion this OWC interpretation is

optimistic and we consider, instead, that there is significant residual oil present in the majority of

wells below the true OWC indicating a former deeper OWC which was also tilted to the northwest.

This phenomenon is observed in many oil fields in the North Sea and elsewhere and the OWCprobably moved up due to leakage of oil from the structure after its initial accumulation. We suggest

that the present-day OWC lies within the so-called LRZ, typically about 15 ft below the base of the

HRZ. We consider this interpretation is more consistent with the core, log and pressure data and is

also entirely consistent with the 22/14b-6q test data.

Reservoir fluid samples have been obtained from DSTs and wireline testing tools in 22/14b-5 and 22/

14-6q. Sproule have referenced the PVT analysis conducted on a sample collected with the MDT tool

from the Forties interval in the 22/14b-5 well, which consisted of a Single Stage Flash Analysis and

Liquid and Gas Chromatography. This analysis indicated an oil gravity of 42 degrees API, a

formation volume factor of 1.435 rb/stb, a saturation pressure of 1,280 psia and a solution gas-oilratio (GOR) of 468 scf/stb. Sproule caveat their use of this data, referencing higher GORs observed

during testing, and in RISC’s opinion the solution GOR of this sample is indeed too low in the light

of the DST data. A bottom-hole sample from 22/14b-5 indicated a GOR of 1089 scf/stb, saturation

pressure of 2045 psia and formation volume factor of 1.83. In RISC’s view the GOR of this sample

is too high.

The test data from 22/14b-5 and 22/14b-6q indicate that the solution GOR is 820 scf/stb (22/14b-5) to

880 scf/stb (22/14b-6q upper test). Using standard industry correlations RISC estimates that the

saturation pressure is in the range 1900 psi to 2400 psi and that the formation volume factor is

around 1.6. A recombined sample from the 22/14-6q test gave a solution GOR of 890 scf/stb,

saturation pressure of 2191 psig and formation volume factor of 1.59. In RISC’s view this is the mostrepresentative PVT data set. However, in the light of this uncertainty RISC has used a range of

formation volume factors for volumetric calculations. These range from 1.4 to 1.7 with a most likely

value of 1.6 and a GOR of 672 scf/stb has been used to estimate sales gas volumes. The sales GOR

estimate was accepted from the draft FDP and may be conservative if there is an efficient separation

process and no fuel requirement. The oil gravity is around 42oAPI.

RISC’s estimates of STOIIP are shown in the table below.

Huntington Field Oil (MMstb) Gross

Low Best High

Estimate

STOIIP 56 63 79

Table 24 Huntington Forties Initially In Place Volumes

195



Oilexco’s draft Field Development Plan envisages a sub-sea development with four horizontal

production wells in the Forties reservoir, one of which is in Huntington East, and an initial plateauof 35,000 bopd. Two deviated water disposal wells are planned in the Forties. The horizontal

producers average 3700ft of reservoir penetration and are located around 10ft from the top of the

reservoir. The wells are to be drilled from a well cluster and tied back to an eight slot sub-sea

manifold.

Subsequent exploitation of the Fulmar reservoir remains contingent on successful appraisal and would

require installation of additional sub-sea facilities.

Two offtake options have been considered. Initially it was planned to install a dedicated FPSO, the

Bluewater Glas Dowr, and an option on the vessel was obtained from Bluewater. This option has

now lapsed and a sub-sea tie-back of Huntington to the BP operated ETAP facility is underconsideration.

The tie-back to ETAP would consist of a 16’’ production line, 12’’ water injection line, 6’’ gas lift

line and control umbilical over a distance of around 32km. A new riser caisson would be installed at

the ETAP Central Processing Facility along with conversion of existing facilities and installation of

some new facilities on a new cantilever deck.

An initial cost estimate covering platform modifications and risers is in the range of GBP67-77

million to be fully reimbursed by the Huntington Joint Venture. A schedule to deliver first oil in 24

months from inception is described as ‘‘challenging’’, and it is unlikely that first oil via ETAP isachievable before Q2 2011. A most likely date of 1st July 2011 is used in this analysis.

In the event that the Huntington owners do not implement export via the ETAP facilities then there

remains the alternative to return to the original concept for development of Huntington using an

FPSO.


RISC has categorised recoverable volumes from Huntington as reserves on the basis that although

there is remaining uncertainty over development planning, a JV commitment and approval of the

Field Development Plan is sufficiently likely within a reasonable period.

Recovery factors for Palaeocene Forties analogues to Huntington approach and in some cases exceed

50%. However, Huntington is relatively small and low relief in comparison to fields such as Montroseand Arbroath. The Palaeocene aquifer underlying these reservoirs is believed to be in communication

and provides pressure support in neighbouring fields, but the extent of this support will be unknown

until Huntington is on production. It is planned to re-inject produced water into the aquifer which

will provide some measure of pressure support if the aquifer response is weak.

Based on analogue field information, RISC has estimated a P90, P50 and P10 range of recovery

factors which are as follows:

30%-45%-50% for the High Resistivity Zone

25%-35%-40% for the Low Resistivity Zone

20%-35%-50% for Huntington East area.

At the upper end these ranges reflect the simulation work done by Oilexco and recoveries obtained

from nearby analogue reservoirs, whilst also recognising key uncertainties in aquifer strength and

relative permeability (in the absence of laboratory data). Implementation of plans for full water

injection, rather than injection of produced water disposal, may increase the low estimate of recovery

factor for the HRZ, otherwise the RF estimates for the HRZ assume substantial aquifer support. The

Low Resistivity Zone is downgraded because of inferior reservoir properties and uncertainty in oil

saturation and mobility. The Huntington East area is downgraded because of the lack of injection

support in the development plan.

Oilexco’s base case simulation run results in an ultimate technical recovery 49.4% of oil in place. This

was obtained with an active aquifer large enough to maintain reservoir pressure above 3200 psig

throughout field life, with produced water re-injected into the aquifer. RISC has used the water cut

behaviour from this run to create production profiles for its 1P, 2P and 3P cases which reflect the

recovery factor ranges given above, with a provision for 95% uptime.

196


Figure 7 Production Forecast Summary for Huntington Field


RISC’s schedule and cost estimates are based on field start-up in Q1 2011 and derived from Operator

data adjusted for RISC production forecasts.

Capital Costs

Capital cost estimates are based upon the subsea system defined for the FPSO development, adjusted

for the absence of FPSO interface and longer tie-back distance to ETAP. The estimate of ETAP tie-

in costs assumes that these would be paid by the Huntington owners. Abandonment costs were

estimated from typical industry metrics.

Operating Costs

Production tariffs are payable for processing services at ETAP. In addition Huntington owners will besubject to transportation tariffs from ETAP to shore, including oil transportation through the Graben

area and Forties link pipeline and gas export via the CATS system.

Huntington Field CostsGross 2009 RT (GBP million)

1P Case 2P/3P CasesScope 4 producers and

1 water injectortied back to

ETAP

4 producers and2 water injectors

tied back toETAP

Capital CostsDrilling 100 118Subsea 46 46Pipelines & Umbilical 93 93Project Management & Contingency 71 76ETAP Hook-up 72 72

Total CAPEX 382 405

Annual OPEXField 3.25 3.50ETAP Compliance, Chemicals 1.20 1.20Oil Tariffs (GBP/bbl) 3.80 3.80Gas Tariffs (GBP/Mcf) 0.90 0.90


Table 25 Huntington Cost Summary

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4.1.6 Reserves

Oilexco has a working interest of 40% in 22/14b, 72.7% in 22/13b and 25.04% in the shallow section

of 22/14a which contains Huntington East. RISC has estimated a provisional equity split between thetwo blocks based on the distribution of oil in place.


RISC estimates reserves as below.

Huntington Field Gross Working Interest

Reserves at 1st Jan

2009Proved

Proved

+ Probable

Proved

+ Probable

+Possible

ProvedProved

+ Probable

Proved

+ Probable

+Possible

Oil (MMstb) 17.3 26.4 36.9 6.4 9.8 13.6

Sales Gas (Bcf) 13.2 20.0 28.0 4.9 7.4 10.4

Table 26 Huntington Reserves

4.1.7 Opportunities and Risks

(i) Offtake Agreement

The Huntington Joint Venture has yet to agree terms for offtake over the ETAP facilities and there

remains the possibility that an agreement may not be forthcoming. However the ETAP optionrepresents an opportunity to reduce OPEX and extend field life.

(ii) Triassic and Fulmar Reservoirs

The pre-Tertiary potential of Blocks 22/14a and 22/14b has been tested by six wells of which four

have proven oil. The first well, 22/14-1 encountered water-bearing Triassic sandstones and shales

overlain by Lower Cretaceous sediments. Well 22/14b-3, drilled by Shell close to the southern margin

of Block 22/14a, encountered Triassic sandstones overlain by Kimmeridge Clay. Approximately 140 ftof gross oil sand was encountered and 33o API oil was tested at 114 bopd. Shell also drilled 22/14b-4

to the northwest of 22/14b-3 and encountered 400+ ft of oil bearing Triassic sandstones but this was

not production tested.

Well 22/14b-5 was drilled by Oilexco to test a potential wedge of Upper Jurassic Fulmar sandsdeveloped on the western flank of the Triassic high encountered by the previous two wells. A 130 ft

gross oil column was found in Fulmar sandstones and no OWC was seen. The Fulmar was tested at

a maximum rate of 4624 bopd (39o API). The PVT analysis conducted on a bottomhole sample

obtained from the Fulmar interval in well 22/14b-5 consisted of a Single Stage Flash Analysis and

Liquid and Gas Chromatography. The analysis indicated an oil gravity of 36 degrees API, a

formation volume factor of 1.479, a saturation pressure of 1,605 psia and a solution GOR of 518 scf/

stb. A gradient of 0.31-0.32 psi/ft was measured on the MDT conducted over the Fulmar zone in the

22/14b-5 well, indicating light oil. This is consistent with the results of the PVT analyses describedabove.

Oilexco subsequently drilled 22/14b-8 downdip to the west of 22/14b-5. This well found a poorer

quality Fulmar reservoir which was inconclusively evaluated but is probably water bearing. Further

north, 22/14a-7 tested the Mallory prospect, a Fulmar stratigraphic trap somewhat similar to thattested by 22/14b-5. This also reportedly found oil although RISC did not have any useful data on

this well to review. Further appraisal of the Fulmar potential of Block 22/14b is planned, possible

downdip of the Triassic oil in 22/14b-4, but seismic reprocessing is required prior to deciding on a

location.

In summary, Oilexco has interests in the deep section of blocks 22/14a and 22/14b and both have

proven light oil in both Triassic and Jurassic reservoirs, albeit that reservoir quality is generally

modest. Estimation of the volumes of oil in place is hampered by the limited quality of the current

seismic data and the lack of an integrated analysis of the various discoveries and the extent to which

they might be connected. Nevertheless, considerable upside potential could be present.

Sproule estimated the volumes closely associated with the 22/14b-5 discovery as being in the range of

11.5-16.0 MMstb gross STOIIP, with associated gross contingent resources of 2.3-6.4 MMstb. They

do not comment on the Triassic discoveries. RISC accepts these estimates as reasonable at this stage

and considers 4.8 MMstb as a current Best Estimate.

Given the limited work done on these deeper reservoirs, RISC considers the additional potential

beyond 22/14b-5 as prospective resources. Oilexco have looked at the upside case in which Fulmar

198


sands are considered to be developed on both the western and eastern flanks of the Triassic high

drilled by 22/14b-3 and 22/14b-4. Speculatively, this play could extend over some 30 km2 and RISC

estimates this could possibly contain up to 250 MMstb STOIIP.

Oilexco have also estimated oil volumes associated with the 22/14b-4 Triassic discovery and they

propose a range of 45-161 MMstb with a mean of 96 MMstb. Given the low flow rate (114 bopd) in

22/14b-3 it remains to be established if the Triassic oil can be produced at commercial flowrates in

this area.

(iii) Unitisation

Operator data indicates that the 22/14b Joint Venture parties wish to complete unitisation of

Huntington between 22/14b, 22/14a and 22/13b. As Oilexco have substantial interests in all three

blocks the company’s overall equity in the field is unlikely to be materially increased or diminished

from the provisional split used in RISC’s evaluation. However the risk remains that, contrary to the

intent of the parties, the unitisation process has a detrimental impact on the schedule to first oil.

4.2 MOTH FIELD

The Moth Field is located in Block 23/21 in the UK Central North Sea, immediately south of theLomond Field. The discovery well 23/21-6z was drilled to a total depth of 14,616 ft and hydrocarbon

bearing reservoir sands with a thickness of 605 feet were intersected in the Middle Jurassic Pentland

Formation and a further 219 feet were intersected in the Upper Jurassic Fulmar sands. A Pentland

formation drill-stem test flowed oil and gas to surface but a packer failure occurred before flow could

be diverted to the test separator to accurately determine the flow rates.

An Upper Jurassic Fulmar test flowed gas at an average rate of 20.3 MMscf/d with 2,110 stb/d of

condensate through a 36/64 inch choke with a flowing tubing pressure of 4,478 psi during the main

flow period. The maximum flow rate achieved during the test was 24.4 MMscf/d and 2,460 stb/d of

condensate. Based on the well results the primary commercial interest is seen to be in the Fulmar

sands with the Pentland sands being interpreted as having low permeability and doubtful

commerciality.

Oilexco have a 50% working interest in Moth areas. The partners are BG Group, Hess and BP.


The Moth field is a north-south trending horst block bounded on the west and east flanks by faults.

To the north, the field is limited by onlap against the Lomond salt diapir and the extent of this

onlap is a key uncertainty. Adjacent fault blocks to the east, west and south are carried as separate

prospects and a Moth South exploration well is planned for drilling this year. To the south, the fieldis limited by the gas-water contact seen in 23/21-6z at 12,863 ft TVDss. The deposition of the Fulmar

and Pentland sands was strongly influenced by syn-depositional salt tectonics and hence it is likely

that reservoir thickness could change rapidly away from the well. Various seismic interpretations have

been made but they are all broadly similar and recognise the difficulty in mapping the northern

extent of the Fulmar sands.

The shallow marine Fulmar sands were well developed in 23/21-6z with a high net to gross ratio, 102

ft of net pay having 17% porosity and 74% gas saturation. A PVT analysis was conducted on the gas

condensate samples obtained during the Fulmar DST from the well 23/21-6z in November 2008 and

this provides fluid data for volumetric estimates.

The Moth Fulmar reservoir fluid is a retrograde gas condensate. The well appears to have flowed

above the dew-point throughout the test and the PVT analysis is considered to be representative of

the reservoir fluid. Key properties are as follows:

Fulmar Gas-Condensate Properties

Separator Gas Gravity* 0.738

Oil Density* 43.2 deg API

H2S 6 ppm

CO2 2%Reservoir Temperature 309 deg F

Initial Reservoir Pressure 9,200 psia

Dew Point Pressure 7,600 psia

Maximum Liquid Dropout 14.5% at 3400 psig

Gas Viscosity at Initial Reservoir Conditions 0.0592 cp

199


Gas Viscosity at Dew Point Pressure 0.0516 cp

Gas-Oil Ratio* 7,993 scf/bbl

*at separator conditions of 407 Psig and 155 deg F

Estimates of hydrocarbons in place were available from the Operator and Sproule. RISC reviewed thedetailed work performed by Sproule, who also undertook an independent seismic interpretation, and

found their estimates reasonable except that RISC considers the potential upside volumes to be larger.

RISC’s estimates are set out in the table below.

Moth Field Condensate (MMstb) Gross Raw Gas (Bcf) Gross

Low Best High Low Best High

Estimate Estimate

CIIP/GIIP 3.2 7.6 16.6 30 71 156

Table 27 Moth Initially In Place Volumes.

4.2.2 Development Options

The Moth field is in the appraisal / concept selection phase of development planning. Development

concepts under consideration range from a single well tie-back to the Lomond platform of the

existing Moth Central discovery, to 3 well tie-backs dependent on exploration success in Moth East

and Moth South. There are also potential development synergies with the Lacewing, Badger and Batprospects which lie outside the Moth earn-in area.

For the purposes of assessing development value, RISC has assumed a tie-back from Moth Central to

the Lomond platform as the notional development concept. We assumed that in the Low and BestEstimate cases one vertical producer would be sufficient and that this well would come onstream at

around 40 MMscf/d. In the High case we assume that early performance data indicate sufficient

connected GIIP and a second production well is drilled.

The well or wells are tied back subsea to the Lomond facilities from where gas would be transported

through the existing pipeline to the Central Area Transmission System (CATS) riser platform then

through the existing CATS pipeline to Teesside. Liquids would be exported by pipeline to the CATS

riser platform. From there, oil would be exported through a pipeline to the Forties Pipeline System

for onward transport to Cruden Bay.


The seismic interpretation of the Fulmar reservoir, combined with the observed overpressure, led

RISC to conclude that the reservoir is unlikely to have a large and active aquifer and that it is likelyto behave as a volumetric depletion gas condensate reservoir.

RISC has generated production forecasts using material balance methods based on the followingliquid recovery efficiencies:

Assumptions for Liquid Recovery

Component C2 C3 iC4 nC4 neo-C5 iC5 nC5 C6 C7+

Molar Liquid Recovery – Low

Case 0% 0% 20% 20% 35% 35% 35% 60% 90%

Molar Liquid Recovery – Base

Case 0% 0% 30% 30% 60% 60% 60% 90% 100%

Molar Liquid Recovery –High Case 10% 30% 60% 60% 80% 80% 80% 100% 100%

Table 28 Moth Liquid Recovery Assumptions

200


The derived high, base and low case CGRs are plotted below as a function of average reservoir

pressure:

Figure 8 Moth CGR Profiles

Well inflow performance has been forecast using the results of the multi-rate test of 23/21-6z. The

Best Estimate case assumed a minimum bottomhole flowing pressure of 1500 psia and a maximum

drawdown of 4000 psi. Some allowance for potential condensate blocking has been made in the Low

case where a lower drawdown limit and higher final flowing bottom hole pressure have been used.

RISC’s production forecast is shown below.

Figure 9 Production Forecast Summary for Moth Field


RISC’s schedule and cost estimates are based on data presented by the Operator adjusted for the

production forecasts developed by RISC. Field start-up is assumed to be Q1 2012.

Capital Costs

Capital cost estimates are based on Operator estimates adjusted for well numbers. Abandonment costs

were estimated from typical industry metrics.

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Operating Costs

Operating costs will be a combination of field management and well intervention costs plus oil and

gas host platform processing and export tariffs estimated by Sproule as GBP4.00/bbl for oiltransportation through the Lomond platform and Everest and Forties pipeline and GBP0.80/Mscf for

gas export through the Lomond platform and CATS system.


Moth Field CostsGross 2009 RT (GBP million) Low/Best Estimate

Cases

High

Case

Scope 1 producer tied back

to Lomond

2 producers tied back

to Lomond

Capital Costs

Appraisal Well 28 28

Development Well (sidetracks) 33 66

Host Modifications 83 83Subsea Tie-back 48 48

Total CAPEX 192 225

Annual OPEXField 1.25 1.50

Oil Host/Export Tariff (GBP/bbl) 4.00 4.00

Gas Host/Export Tariff (GBP/Mcf) 0.80 0.80


Table 29 Moth Cost Summary


Moth development is not economic under the above forecasts and the economic assumptions

described in section 6. No value has been assigned in the economic summary. RISC estimatescontingent resources as shown below:

Moth Field Gross Working Interest

Contingent Resources

Low Best

Estimate

High Low Best

Estimate

High

Condensate (MMstb) 1.0 3.4 7.4 0.5 1.7 3.7

Sales Gas (Bcf) 12.3 40.0 82.3 6.1 20.0 41.2

Table 30 Moth Contingent Resources


Opportunity

There are potential development synergies with the Lacewing, Badger and Bat prospects which lie

outside the Moth earn-in area.

202


4.3 BUGLE FIELD

Bugle is a high pressure, high temperature (HPHT) field in Block 15/23d. The discovery well, 15/23d-

13, was drilled in 1997 and followed by a sidetrack, 5/23d-13Z, in 2008. Bugle fluids are characterisedas light oil (43API), with a gas oil ratio of up to 1800 scf/stb.

Figure 10 Bugle and Blackhorse Field Locations


The Bugle trap has a structural element but is controlled by stratigraphic closure of the upper andlower Volgian Dirk and Galley sandstone reservoirs. These are both high density turbidite mass flows

shed from adjacent Jurassic/Triassic rotated fault blocks which experienced erosion of the shoreface

Piper sands during late Jurassic extension. Oil fill is sourced from the encompassing Kimmeridge Clay

formation.

Oilexco provided Sproule with the operator’s (Nexen’s) Petrel model which was used to provide Gross

Rock Volume estimates for various cases. These were used in a deterministic calculation of STOIIP

using average petrophysical parameters for the Dirk and Galley reservoir sands derived from

Sproule’s own petrophysical analysis of the logs for the discovery/appraisal wells 15/23d-13 and 15/

23d-13z. RISC has made use of this work and additional technical data included in presentations by

the Operator.

RFT and MDT pressure data from the discovery well and appraisal sidetrack indicate that Dirk oil

sands are in pressure communication, but that the Galley oil sands have a 70psi difference inpressure, suggesting that they were in separate accumulations. Aquifer pressure measurements are

inconclusive, but indicate that the Galley sands aquifer is in communication between the two wells,

and that a possible OWC is present in the 15/23d-13z well at 14,761ft TVDss. The deepest observed

oil in the Dirk sands is at 14,618 ft TVDss. Well test analyses by various evaluators have inferred

that the test results in both reservoir intervals in 15/23d-13 were influenced by channel boundaries.

RISC adopted Sproule’s petrophysical interpretation, except that within the Galley sands, RISC has

applied a more conservative Sw cut-off.

Reservoir fluid properties are based on PVT analysis of samples from a DST on 15/23d-13, which

indicated an FVF of 1.73.

RISC has estimated STOIIP by applying a range of petrophysical averages to varying areas of oil pay

distribution. It is difficult to define the limits to the oil accumulation as the structure does not close

203


to the west and east at the maximum oil-down-to observed in the wells, and the mapped faults to the

north do not offset the reservoir. Seismic amplitude analysis suggests a discrete distribution of Dirk

sands, which would provide stratigraphic closure to the east and west. These limits, together with the

fault in the north, have been used to provide areas of oil pay distribution for volumetric calculations.The apparent northward extension of Dirk sands, indicated by the geophysical analysis, is considered

to provide upside exploration potential, but not to contribute to discovered volumes. The proved area

for the Dirk oil sands is considered to be restricted to half the area of closure above ODT, within the

stratigraphic limits indicated above, in recognition that the sands may be laterally discontinuous. The

whole area above ODT was adopted for probable volume calculations. The possible area was taken

to include all sands within the extent of the seismic amplitude anomaly (south of the northern

boundary fault). The Galley sands also do not close at the OWC. In the absence of information to

the contrary, a similar areal distribution to the Dirk sands has been assumed, since they aregenetically related. RISC has combined these measurements probabilistically.

RISC considers the Volgian sands to be sufficiently extensive and consistent in reservoir quality to

contain significantly more hydrocarbons than indicated by the well tests.

Oil (MMstb) Gross

Bugle Field Reservoir Low

Best

Estimate High

Upper Dirk 6.6 14.0 29.6

Lower Dirk 5.4 11.5 24.6

Galley 2.3 5.6 11.7

STOIIP Total 14.3 31.1 65.9

Table 31 Bugle Initially In Place Volumes


Initial development is likely to be based on a single, commingled producer located in the vicinity of

the two existing wells. Subsequent development wells if justified may drain the western and eastern

field extensions. These are also likely to be commingled producers.

The field is located 24 km to the south-east of the Nexen-operated Scott platform. The Bugle Field

owners have held technical discussions with the Scott platform owners with a view to processing and

exporting Bugle crude via the Scott facility.

RISC has noted that work by the Scott operator in 2008 has shown that:

* The Scott platform has sufficient oil and produced water processing capacity to accommodate

Bugle oil rates and the small amount of saturation water without impact on the Scott process

although a dedicated Bugle separator my be required.

* Availability of sufficient gas capacity is dependent on Scott / Telford future production

outcomes. Initial analysis suggested that at the Scott / Telford 3P outcome there may be a

requirement to operate 2/2 gas compression trains and 3/3 power generators leaving no

redundancy in either system and impacting availability. However, this 3P case does not take into

consideration recent production observations and is considered to be unrealistically high.

* The produced water scaling risk and the H2S levels in Bugle fluids can be managed by scale

inhibitor and H2S scavenger chemical injection.

* A high level cost estimate to engineer, fabricate, construct and install the new Bugle facilities on

the Scott platform was estimated to be approximately GBP 23 – 32 million +/- 40%, depending

on the development option selected. These estimates allowed for topsides equipment and

modifications, a new fully rated riser and contingency.


RISC adopted a 18-27-33% range of recovery factor, resulting from the application of separaterecovery factors within each formation which reflected RISC’s assumed well numbers and areal

reservoir extent in the light of the potential for intra reservoir channel limits or restrictions to flow,

and noting the result of simulation modeling of natural depletion had indicated recovery factors in

the range of 16 to 24%. Well numbers for the three confidence level cases were set at 1, 3 and 6, with

initial well rates put at 4000 bopd, 5000 bopd and 6000 bopd respectively. Wells were assumed to

204


come onstream sequentially, to allow evaluation of initial reservoir performance prior to commitment

to subsequent wells.

Sproule developed production forecasts based on early volumetric depletion followed by pressure

support from other drive mechanisms as pressure declines. RISC adopted similar rates of decline,

normalised to RISC’s estimate of technically recoverable volume and adjusted for differences in the

timing at which wells were assumed to come onstream.


Figure 11 Production Forecast Summary for Bugle Field


RISC’s schedule and cost estimates are based on Operator estimates and Sproule’s Year 2008

Reserves report adjusted for the production forecasts developed by RISC. Field start-up is assumed to

be mid 2011.

Capital Costs

Capital cost estimates are based on Operator sources and adjusted for additional production wells as

required by the production forecast cases. Abandonment costs were estimated from typical industrymetrics.

Operating Costs


gas host platform processing and export tariffs estimated as GBP3.00/bbl for oil and GBP0.80/Mscf

for gas through the Scott platform and export pipelines.

205



Bugle Field Costs

Gross 2009 RT (GBP million) 1P

Case

2P

Case

3P

Case

Scope 1 Well

Productionto Scott

3 Wells

Productionto Scott

6 Wells

Productionto Scott

1st Well Spud Date 2011 2011 2011

Project Completion Date 2011 2112 2013

Capital Costs

Drill & Complete 22 66 132

Subsea 50 50 50

Platform Modification 50 50 50

Project Management / Logistics 10 10 10

Total CAPEX 132 176 242

Operating Costs

Fixed 1.25 1.75 2.5

Variable (per bbl) 3.00 3.00 3.00

Variable (per Mscf) 0.80 0.80 0.80

Field Abandonment 8 13 20

Table 32 Bugle Cost Summary

4.3.5 Reserves

As the Joint Venture has demonstrated intent to proceed with the drilling of an appraisal/

development well, and subsequently with FDP submission and development sanction, RISC expects

that development will proceed within a reasonable time period and has classified the economically

recoverable volumes associated with the project as reserves. Bugle commerciality is assisted by the

likely future development of Blackhorse which may share infrastructure costs.

Sales gas has been estimated on the basis of a gas oil ratio of 1070 scf/stb, although some increase

may occur in later years. The wide range of reserve estimates is indicative of the large uncertainty in

the reservoir description and suggestive of a staged approach to appraisal/development.

Bugle Field Gross Working Interest

Reserves at

1st Jan 2009Proved

Proved

+ Probable

Proved

+ Probable

+Possible

ProvedProved

+ Probable

Proved

+ Probable

+Possible

Oil (MMstb) 2.8 9.1 19.1 1.1 3.7 7.8

Sales Gas (Bcf) 3.0 9.7 20.4 1.2 4.0 8.4

Table 33 Bugle Reserves


Opportunities

Additional exploration potential exists to the north of the boundary fault. The key risk on Bugle is

the lack of trap definition and lack of understanding of the distribution of the reservoir sands.

Risks

As the well test suggested flow boundaries close to the borehole, there is a risk of segmentation and

consequent uncertainty in the number of wells required to produce the resources.

4.4 BLACKHORSE FIELD

The Blackhorse Field is located in Block 15/22 in about 500 feet of water. The HPHT field was

discovered in 2002 with the drilling of 15/22-16. Well 15/22-18 was successfully tested in November

2005.

RISC’s analysis assumes that Blackhorse may benefit from Bugle infrastructure.

206



Blackhorse is a structural trap with three-way dip and fault closure, but is likely to have some

element of stratigraphic trapping. Reservoir sands are upper and lower Volgian Dirk and Galleymembers of the Kimmeridge Clay Formation. These are both high density turbidite mass flows shed

from adjacent Jurassic/Triassic rotated fault blocks which experienced erosion of the shore-face Piper

sands during late Jurassic extension. Oil fill is sourced from the encompassing Kimmeridge Clay

formation.

RISC reviewed MDT pressure data from the two field wells, which was consistent with the Dirk and

Galley oil sands being in pressure communication. Aquifer pressure measurements in the 15/22-18

Galley sands indicate an OWC at 13,770 ft TVDss.

Reservoir fluid properties are based on PVT analysis of samples from DSTs on both wells. The

analysis shows clearly different fluids in the two wells, suggesting that, in spite of the alignment of

MDT pressure data, the two wells have accessed separate hydrocarbon accumulations. Well test

analysis has indicated reservoir boundaries in the vicinity of each well.

RISC has estimated STOIIP with reference to Operator’s petrophysical interpretation of the two field

wells, and their depth structure maps for top Dirk and top Galley sandstones. The proved area is

considered to be restricted to separate areas around the two wells, as a result of the fluid differences

observed.

The hydrocarbon pore thickness observed in each well for the Dirk sands has been combined with

the minimum areas to calculate minimum volumes. Most likely volumes were calculated using the

average well parameters for the whole area within closure, above the 13,770 ft TVDss OWC.

Maximum Dirk volumes were calculated by assuming that the 15/22-16 Dirk sand quality improved

compared to that seen in 15/22-18.

The (lower) Galley sands hydrocarbon pore thickness has been applied to the mapped areas with a

shape factor, to account for the distribution of these sands within an interval which is thick

compared to the relief of the field. In the minimum case this has been applied to the area around the

15/22-16 well. In the most likely case the 15/22-16 well parameters have been applied to the whole

area within the 13,770ft TVDss closing contour. An upside case has been calculated which considers a

Galley sand thickness which is the average between the two wells.

In each case the distribution of hydrocarbons has been assumed to stop at the fault bounding the

northern edge of the field. However, the fault throw is not sufficient to offset the reservoirs, and there

may be additional oil trapped to the north of this fault. The structure on that side of the fault spills

at a depth shallower than the observed OWC, so a stratigraphic trapping mechanism is required if

the fault is not sealing. Volumes to the north of the fault are considered to be prospective resources.RISC has combined these measurements in a probabilistic scheme and has reported P90/P50/P10

volumes in Table 34.

RISC considers the Volgian sands are likely to be reasonably extensive and consistent in reservoirquality and that the well test results are likely to indicate reservoir complexity or minor faulting

rather than lack of an extensive reservoir.

RISC estimates of STOIIP are shown in the table below.

Oil (MMstb) Gross

Blackhorse Field Low Best High

Estimate

STOIIP 13.9 27.1 55.0

Table 34 Blackhorse Initially In Place Volumes


The development of Blackhorse assumes that it will be tied into future infrastructure installed between

the Bugle field and Scott Platform. The development costs presented here are therefore contingent on

prior execution of the Bugle development.

Development of the Blackhorse field requires reactivation of wells 16 and 18 plus up to four

additional subsea wells. Production would be gathered in a subsea manifold and co-mingled with

Bugle production in a common flowline to the Scott Platform.

207



RISC has assigned a range of recovery factors of 25-30-35%. Producer well numbers for three

confidence level cases were set at 2, 3 and 6, with initial well rates put at 2250 bopd, 2500 bopd and3000 bopd respectively. It was assumed that initial production would come from two available wells

and that subsequent new wells would come onstream sequentially, to allow evaluation of initial

reservoir performance prior to commitment to subsequent wells. Well decline rates were established by

review of Sproule’s analysis, normalised to RISC’s view on technically recoverable volumes and well

phasing.


Figure 12 Production Forecast Summary for Blackhorse Field


RISC’s schedule and cost estimates are based on Sproule’s Year 2008 Reserves Report adjusted forthe production forecasts developed by RISC. Field start-up is assumed to be early 2012.

Capital Costs

Capital cost estimates are taken from Sproule and adjusted for additional production wells.

Abandonment costs were estimated from typical industry metrics.

Operating Costs


gas host platform processing and export tariffs, estimated as GBP3.00/bbl for oil and GBP0.80/Mscffor gas, through the Scott platform and export pipelines.

208


A summary of cost projections is shown in the following table.

Blackhorse Field Costs

Gross 2009 RT (GBP million) 1P

Case

2P

Case

3P

Case

Scope Reactivation of

wells 16 & 18

Reactivation of

wells 16 & 18 plus1 additional well

Reactivation of

wells 16 & 18 plus4 additional wells

Capital Costs

Reactivate 16 & 18 19.3 19.3 19.3

Additional Wells 0.0 19.6 78.4

Subsea 8.8 8.8 8.8

Project Management / Logistics 2.8 2.8 2.8

Total CAPEX 30.9 50.5 109.3

Operating Costs

Fixed 1.50 1.75 2.5

Variable (per bbl) 3.00 3.00 3.00

Variable (per Mscf) 0.80 0.80 0.80

Field Abandonment 7 10 17

Table 35 Blackhorse Cost Summary

4.4.5 Reserves

RISC has estimated field economics on the basis of the above production and cost data and the

economic analysis described in section 6. As for Bugle, RISC expects that development will proceed

within a reasonable time period and has classified the economically recoverable volumes associated

with the project as reserves.

Sales gas has been estimated on the basis of a gas oil ratio of 750 scf/stb, although some increase

may occur in later years. The wide range of resource estimates is indicative of the large uncertainty inthe reservoir description and suggestive of a staged approach to appraisal/development. RISC’s

estimate of reserves is shown below.

Blackhorse Field Gross Working Interest

Reserves at

1st Jan 2009Proved

Proved

+ Probable

Proved

+ Probable

+Possible

ProvedProved

+ Probable

Proved

+ Probable

+Possible

Oil (MMstb) 3.5 8.2 19.6 1.4 4.1 9.8Sales Gas (Bcf) 2.6 6.2 14.3 1.0 3.1 7.1

Table 36 Blackhorse Reserves


Opportunities

Additional exploration potential exists to the north of the boundary fault.

Risks

The key risk on Blackhorse is the quality and distribution of the reservoir sands. As the well tests

suggested flow boundaries close to the borehole, both the size of the accumulation and number of

wells required to produce it are uncertain.

4.5 OTHER DISCOVERIES

Oilexco’s portfolio contains a number of additional discoveries, some arising from acquisition of

licenses containing discoveries made by a previous operator and deemed non-commercial at the time.

It is difficult to segregate these totally from exploration prospects, and section 5 discusses the

exploration license position. Section 4.5 references two discoveries with significant appraisal potential

that are included in the Contingent Resources summary in Table 4.

209


4.5.1 Blocks 22/14a and 22/14b – Triassic and Fulmar Reservoirs

These reservoirs lie beneath the Forties reservoir in the Huntington Field and are described in section

4.1.7. A Best Estimate of Contingent Resources is included in Table 4, but no value has specificallybeen assigned.

4.5.2 Block 15/26b – Kildare

Oil was discovered in this block by BP with well 15/26b-5 which tested 2675 bopd from an Upper

Jurassic Ettrick sand. The test was curtailed by the presence of 6000 ppm H2S in the oil. The block

was acquired in the 23rd licensing round in 2005 by Nexen and Oilexco who drilled 15/26b-9 in a

fault block downthrown from that tested by BP. This well found oil in an older Jurassic sandstone

formation, the Sgiath, and this was tested at 4216 bopd and 3.1 MMscf/d. Log interpretation suggests

some 90 ft of net pay and no OWC was seen.

This discovery is close to infrastructure and clearly merits appraisal and, although uncertainties exist

as to the extent of the Sgiath sands, the potential resources could be in the range 10-40 MMstb. The

Ettrick sands discovered by 15/26b-5 provide potential upside subject to the H2S content beingmanaged in any development scenario.

The Kildare Field contributes to the unrisked Contingent Resources ‘‘Other Fields’’ elements in Table4 i.e. fields not reviewed by RISC. RISC has not evaluated the development options or the risk which

may be associated with these estimates. As for Sheryl and Ptarmigan Fields, value assigned to this

field was based on production and cost estimates as provided in the data room.

210


5 EXPLORATION POTENTIAL

Oilexco has a large number of exploration licences in the UKCS that have been acquired either by

farm-in or through the 24th and 25th Licensing Rounds. Oilexco estimates unrisked and risked

prospective oil resources amounting to 385 MMstb and 59 MMstb net to Oilexco respectively. There

is no certainty that any of these prospects will be drilled although some are covered by obligationwells either as a result of licensing or farm-in commitments. In several blocks ‘drill or drop’ decisions

are required.

The status of blocks offered to Oilexco in the 25th Round has not been confirmed It seems probable

to us that any successor company will be invited to take on these blocks and the associated work

commitments but there is no certainty in this.

In Table 37 we have listed our understanding of Oilexco’s UK North Sea exploration licences and

their status.

211


Licence Block Name Oilexco Equity OperatorProspect/Discovery/

Field Name Status

P1498 (promote) 13/1413/15

55% Oilexco None known not drilled

P811 13/30b 70% BG Oddjob drilled, unsucessful

13/2014/16

P1457 14/17a 55% Oilexco Athena_w not drilled14/21b14/22b

P1295 14/23b 45% Oilexco Laurel valley area Protection acreage

P300 14/26a 70% BG Oddjob Area Protection acreage

P1089 14/28a &14/29a 45% Oilexco Laurel Valley drilled, unsucessful

25th Round Offer 14/30c 50% Nexen Kildare West not drilled

P185 15/22 (non-palaeocene)

40-50% Nexen RusselBlackhorse

not drilledAppraisal

P489 15/23b 50% Nexen not drilled

P815 15/23d 41% Nexen Bugle & N Bugle Appraisal

25th Round Offer 15/23e 50% Nexen Bugle S. LeadCornet or Corniche

not drillednot drilled

P640 15/24b 50% C-P MacCulloch East drilled, successful

P1466 15/24c15/25f

75% Premier Bluebell not drilled

P233 15/25a 70% Oilexco Nicol Development

P1042 15/25b 100% Oilexco Brenda Producing

P1043 15/25c 100% Oilexco Joy drilled, unsucessful

P1467 15/25d 50% Oilexco

P1157 15/25e 100% Oilexco Brenda NW drilled, oil

25th Round Offer 15/26a 100% Oilexco Del Bonita not drilled

P1298 15/26b 50% Nexen Kildare drilled, discovery

P119 15/29a 60% Oilexco Ptarmigan Discovery. Option toincrease interest to 100%

25th Round Offer 15/30b 100% Oilexco Skunk hollow not drilled

16/21a Brenda ProducingP201 16/21aF1 85% Oilexco Balmoral Producing

16/21aF2 Stirling/Glamis

P344 16/21bF116/21cF1

44.2% Oilexco AlphaDelta

not drilleddrilled, unsucessful

P213 16/26UPF2 100% Oilexco Caledonia Appraisal

P1095 16/21d 50% None Bladon drilled successful oilappraisal

P1104 21/4b 45% Maersk/Oilexco

Muness drilled, unsucessful

P1220 (promote) 21/23a 65% Oilexco1 Sheryl drilled, successful

25th Round Offer 21/24b 100% Oilexco Manyberries not drilled

P1260 22/2b 100% Oilexco Shelley Development

P1555 22/3a 100% Oilexco Pandora(East Shelley)

not drilled

P087 22/7F1 47% Oilexco Nelson (part) Producing

P1420 22/13b 72.7% Oilexco Manhattan Morro and Cornado drilled(unsuccessful). Manhattan

remaining

P1114 22/14b22/19b

40% Oilexco Huntingdon Appraisal

P101 23/21 50% BG Moth Appraisal

P1181 23/22b 32.5% Premier Sparrow Exploration

25th Round Offer 23/26c 100% Oilexco Hillcrest & Fleet not drilled

P1430 28/9 50% Oilexco2 Catcher not drilled28/10c

25th Round Offer 29/1c 50% Oilexco Orchid not drilledViola not drilled

Lily not drilled

P1431 29/6b 100% Oilexco Danica drilled, unsucessful

25th Round Offer 29/7b 100% Oilexco Curlew A (Premier) not drilled

P032&P295 30/17a&30/16t 6.45% Maersk/Oilexco

Janice

P1228 (promote) 30/23b 40% Endeavour Relinquished

(1) It has been reported that operatorship has recently transferred to Sterling Resources (material sighted by RISC referred to Oilexcoas operator).

(2) It has been reported that operatorship has recently transferred to Encore Petroleum (material sighted by RISC referred to Oilexcoas operator).

Table 37 Summary of Oilexco’s exploration licences and their status as far as is known.

212


5.1 SUMMARY OF EXPLORATION REVIEW

Oilexco has a large number of exploration interests in the UK North Sea derived both from farm-in

agreements and from licensing rounds. In several blocks the farm-in well was dry and it is unlikelythat there will be any further substantial activity. Other blocks, such as 15/26b, 22/14a, 22/14b, 23/21

and 23/22b appear to have significant exploration (and/or appraisal) potential and may hold a

number of commercial accumulations of the order of 20 MMstb of oil or 100 Bcf of gas that could

be developed given the proximity of existing infrastructure.

In addition to the Kildare discovery in block 15/26b and the Jurassic and Triassic appraisal/

exploration potential of blocks 22/14a and 22/14b, which are discussed in section 4.5 above, we

highlight the appraisal of the follow-up prospects to the Moth discovery in blocks 23/21 and 23/22b.

Leaving aside the 25th Round blocks whose status is uncertain, the remaining drilling commitments

on farm-in and 24th Round blocks are believed to be two firm wells, one contingent well and two

wells where Oilexco effectively has ‘drill or drop’ options.

5.2 PROSPECTIVE RESOURCES VALUATION

RISC has not carried out a full technical evaluation of Oilexco’s exploration portfolio.

However, based on the data available to us, mainly by reviewing the value of work programmes and

transactional information we judge that the potential value of this acreage outweighs the outstanding

commitments.

Figure 13 SPE/WPC/AAPG/SPEE PRMS 2007 definitions chart

213


6 ECONOMICS

6.1 FISCAL TERMS AND KEY ASSUMPTIONS

RISC has audited discounted cash flow models provided in the virtual data room by Morgan Stanley.

The model and data input have been based on 100% project cash flows. Oilexco’s share of value ofeach asset has then been determined by applying Oilexco’s working interest to the resulting project

NPVs.

A summary description of the relevant terms and assumptions used in the models follows.

UK Terms

* All fields pay no Royalties

* All fields pay Corporation Tax (CT) at 30% and a supplementary charge (SCT) of 20%

* Brought forward losses can be offset against CT and SCT

* Only Nelson pays Petroleum Revenue Tax, other liable fields are covered by allowances (as per

Sproule report)

* All field capex is assumed to qualify for 100% capital allowance in the year it is incurred

Effective Date

The effective date is taken as 1st January 2009.

Opening Position

Tax losses at the valuation date have been assumed at $US1240 million as provided in the VirtualData Room.

RISC has not audited the above past costs.

Oil Price

A base case forecast of Brent oil price was assumed to be the forward curve (see below) in nominal

terms. Sensitivities of US$40/bbl and US$80/bbl flat nominal were also recorded.

Brent 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal US$.bbl 48.6 57.3 61.6 64.0 65.8 67.4 68.9 70.3 71.3

Gas Price

A base case forecast of NBP gas sales price was assumed to be GBP 5.00/Mscf. Gas price was kept

constant at all sensitivities.

Inflation

2.5% pa applied to costs (capex and opex) consistent with the nominal oil price forecast.

Discount Rate

Project NPVs are reported at discount rates of 6%, 10% and 15% nominal, with end year discounting.

Exchange rate

US$ per GBP = 1.75 based on 10 year historic data.

214


6.2 ECONOMIC RESULTS

Economic analyses have been performed on estimates of future production of assessed reserves/

resources, forecasts of future capital and operating costs and the assumptions set out in section 6.1above.

Discounted cash flows, nominal net consolidated in US$ million are as follows:

Net NPV10 US$million

Proved Reserves

Proved plus

Probable Reserves

366 876

Table 38 Summary of Economic Evaluation of Discovered Assets as at 1st January 2009

The NPV10 of the Proved reserves above is based on arithmetic summation of the NPV10s of the

Proved reserves of the individual fields. The NPV10 of the Possible reserves has been estimated onthe same basis, i.e. arithmetic summation of the NPV10s of the Possible reserves of the individual

fields, at US$416 million.

The NPV10 of the Proved plus Probable reserves of Developed Producing Fields has been estimatedat US$611 million.

Unrisked Best Estimate contingent resources have been valued at NPV10 of US$328 million.

The above estimates have not been adjusted for other factors that a buyer or seller may consider in

any transaction concerning these assets.

6.3 SENSITIVITY ANALYSES (NET CONSOLIDATED)

Sensitivity to discount factor and oil price is shown on the figures below for:

1. Proved plus Probable Reserves.

2. Proved plus Probable Reserves (Developed Producing Fields only).

215


Figure 14 Sensitivity to Discount Factor and Oil Price based on Proved plus Probable reserves

Figure 15 Sensitivity to Discount Factor and Oil Price based on Proved plus Probable reserves

(Developed Producing Fields)

Associated sensitivities to Opex, Capex, Reserves (low and high scenarios being P90 and P10 values

from a probabilistic summation of individual field reserves/resources-based distributions of NPV10,

with single value estimates for fields not reviewed by RISC) and Oil Price (US$40/bbl and US$80/bbl

flat nominal) are shown in the following figures:

216


Figure 16 Sensitivity of NPV10 based on Proved plus Probable reserves

Arithmetic summation of the individual field NPVs at the Proved (1P) and Proved + Probable +

Possible (3P) levels for all fields provides a net NPV10 range of US $366 million to US$ 1292 million.

Figure 17 Sensitivity of NPV10 based on Proved plus Probable reserves (Developed Producing Fields)

6.4 PROSPECTIVE RESOURCES

As noted in section 5.2, we judge that the additional potential value of prospective resources withinexploration acreage outweighs the outstanding commitments.

217


7 LIST OF TERMS

The following lists, along with a brief definition, abbreviated terms that are commonly used in the oil

and gas industry and which may be used in this report.

Abbreviation Definition

1P Equivalent to Proved reserves or Proved in-place quantities, depending on the context.

1Q 1st quarter

2P The sum of Proved and Probable reserves or in-place quantities, depending on the

context.

2Q 2nd quarter

2D Two dimensional

3D Three dimensional

4D Four dimensional – time lapsed 3D in relation to seismic

3P The sum of Proved, Probable and Possible Reserves or in-place quantities, depending

on the context.

3Q 3rd quarter

3Q 4th quarter

AEO US Energy Information Administration’s Annual Energy Outlook

AFE Authority for Expenditure

boe US barrels of oil equivalent

bbl US barrel

bbl/d US barrels per day

Bcf Billion (109) cubic feet

Bcm Billion (109) cubic meters

BERR Department for Business, Enterprise & Regulatory Reform

BFPD Barrels of fluid per day

BOPD Barrels of oil per day

BTU British Thermal Units

BWPD Barrels of water per day

C Celsius

Capex Capital expenditure

CAPM Capital asset pricing model

CGR Condensate Gas Ratio – usually expressed as bbl/MMscf

Contingent

Resources

Those quantities of petroleum estimated, as of a given date, to be potentially

recoverable from known accumulations by application of development projects but

which are not currently considered to be commercially recoverable due to one or more

contingencies. Contingent Resources are a class of discovered recoverable resources as

defined in the SPE-PRMS.

CO2 Carbon dioxide

Cp Centipoise (measure of viscosity)

CPI Consumer Price Index

deg Degrees

DHI Direct hydrocarbon indicator

Discount Rate The interest rate used to discount future cash flows into a dollars of a reference date

DST Drill stem test

E&P Exploration and Production

218


Eg Gas expansion factor. Gas volume at standard (surface) conditions / gas volume at

reservoir conditions (pressure & temperature)

EIA US Energy Information Administration

EMV Expected Monetary Value

EOR Enhanced Oil Recovery

ESP Electric submersible pump

EUR Economic ultimate recovery

Expectation The mean of a probability distribution

F Degrees Fahrenheit

FC Forward Curve

FDP Field Development Plan

FEED Front end engineering design

FID Final investment decision

Fm Formation

FPSO Floating offshore production and storage unit

FWL Free water level

ft Feet

FVF Formation volume factor

GIIP Gas Initially In Place

GJ Giga (109) joules

GOC Gas-oil contact

GOR Gas oil ratio

GRV Gross rock volume

GSA Gas sales agreement

GTL Gas To Liquid(s)

GWC Gas water contact

H2S Hydrogen sulphide

HHV Higher heating value

ID Internal diameter

IM Information Memorandum

IRR Internal Rate of Return is the discount rate that results in the NPV being equal to zero.

JV(P) Joint Venture (Partners)

Kh Horizontal permeability

km2 Square kilometers

Krw Relative permeability to water

Kv Vertical permeability

kPa Kilo (thousand) pascal (measurement of pressure)

Mstb/d Thousand US barrels per day

LIBOR London inter-bank offered rate

LNG Liquefied Natural Gas

LTBR Long-Term Bond Rate

m Metres

MDT Modular dynamic formation tester

mD Millidarcies (permeability)

MJ Mega (106) Joules

219


MMbbl Million US barrels

MMscf(d) Million standard cubic feet (per day)

MMstb Million US stock tank barrels

MOD Money of the Day (nominal dollars) as opposed to money in real terms

MOU Memorandum of Understanding

Mscf Thousands standard cubic feet

Mstb Thousand US stock tank barrels

MPa Mega (106) pascal (measurement of pressure)

mss Metres subsea

MSV Mean Success Volume

mTVDss Metres true vertical depth subsea

MW Megawatt

NBP Netback Price

NPV Net Present Value (of a series of cash flows)

NTG Net to Gross (ratio)

OCM Operator Committee Meeting

ODT Oil down to

OGIP Original Gas In Place

OOIP Original Oil in Place

Opex Operating expenditure

OWC Oil-water contact

OOWC Original oil-water contact

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.

PBU Pressure build-up

PHIT Total porosity

PJ Peta (1015) Joules

POS Probability of Success

Possible

Reserves

As defined in the SPE-PRMS, an incremental category of estimated recoverable

volumes associated with a defined degree of uncertainty. Possible Reserves are those

additional reserves which analysis of geoscience and engineering data suggest are less

likely to be recoverable than Probable Reserves. The total quantities ultimately

recovered from the project have a low probability to exceed the sum of Proved plus

Probable plus Possible (3P) which is equivalent to the high estimate scenario. Whenprobabilistic methods are used, there should be at least a 10% probability that the

actual quantities recovered will equal or exceed the 3P estimate.

ProbableReserves

As defined in the SPE-PRMS, an incremental category of estimated recoverablevolumes associated with a defined degree of uncertainty. Probable Reserves are those

additional Reserves that are less likely to be recovered than Proved Reserves but more

certain to be recovered than Possible Reserves. It is equally likely that actual remaining

quantities recovered will be greater than or less than the sum of the estimated Proved

plus Probable Reserves (2P). In this context when probabilistic methods are used, there

should be at least a 50% probability that the actual quantities recovered will equal or

exceed the 2P estimate.

Prospective

Resources

Those quantities of petroleum which are estimated, as of a given date, to be potentially

recoverable from undiscovered accumulations as defined in the SPE-PRMS.

220


Proved Reserves As defined in the SPE-PRMS, an incremental category of estimated recoverable

volumes associated with a defined degree of uncertainty Proved Reserves are those

quantities of petroleum, which by analysis of geoscience and engineering data, can be

estimated with reasonable certainty to be commercially recoverable, from a given dateforward, from known reservoirs and under defined economic conditions, operating

methods, and government regulations. If deterministic methods are used, the term

reasonable certainty is intended to express a high degree of confidence that the

quantities will be recovered. If probabilistic methods are used, there should be at least a

90% probability that the quantities actually recovered will equal or exceed the estimate.

Often referred to as 1P, also as ‘‘Proven’’.

PSC Production Sharing Contract

PSDM Pre-stack depth migration

PSTM Pre-stack time migration

Psia Pounds per square inch pressure absolute

p.u. Porosity unit e.g. porosity of 20% +/- 2 p.u. equals a porosity range of 18% to 22%

PVT Pressure, volume & temperature

QA Quality assurance

QC Quality control

rb/stb Reservoir barrels per stock tank barrel under standard conditions

RFT Repeat Formation Test

Real Terms

(RT)

Real Terms (in the reference date dollars) as opposed to Nominal Terms of Money of

the Day

Reserves 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 categorised in

accordance with the level of certainty associated with the estimates and may be sub-

classified based on project maturity and/or characterised by development and

production status.

RISC Resource Investment Strategy Consultants (t/a RISC Pty Ltd Authors of this report)

RT Measured from Rotary Table or Real Terms, depending on context

SC Service Contract

scf Standard cubic feet (measured at 60 degrees F and 14.7 psia)

Sg Gas saturation

Sgr Residual gas saturation

SPE Society of Petroleum Engineers

SPE-PRMS SPE/WPC/AAPG/SPEE Petroleum Resource Management Systems, March 2007

s.u. Fluid saturation unit. e.g. saturation of 80% +/- 10 s.u. equals a saturation range of

70% to 90%

ss Subsea

stb Stock tank barrels

STEO Short term energy outlook

STOIIP Stock Tank Oil Initially In Place

Sw Water saturation

TCM Technical committee meeting

Tcf Trillion (1012) cubic feet

TJ Tera (1012) Joules

TLP Tension Leg Platform

221


TRSSV Tubing retrievable subsurface safety valve

TVD True vertical depth

US$ United States dollar

US$ million Million United States dollars

WACC Weighted average cost of capital

WHFP Well Head Flowing Pressure

Working

interest

A company’s equity interest in a project before reduction for royalties or production

share owed to others under the applicable fiscal terms.

WPC World Petroleum Congresses

WP&B Work Programme and Budget

WTI West Texas Intermediate Crude Oil

222


PART XV

UNITED KINGDOM TAXATION

The following statements do not constitute tax advice and are intended only as a general guide to

current UK law and HMRC published practice (which are both subject to change at any time). Theyrelate only to certain limited aspects of the UK taxation treatment of holders of the Existing

Ordinary Shares and are intended to apply only, except to the extent stated below, to persons who

are resident and ordinarily resident in the United Kingdom for UK tax purposes and who are

beneficial owners of Existing Ordinary Shares and hold them as investments (and not as securities to

be realised in the course of a trade). They may not apply to certain Shareholders, such as dealers in

securities, insurance companies and collective investment schemes, Shareholders who are exempt from

taxation and Shareholders who have (or are deemed to have) acquired their Existing Ordinary Shares

by virtue of an office or employment. Such persons may be subject to special rules. Any person whois in any doubt as to their tax position, or who is subject to taxation in any jurisdiction other than

the United Kingdom, should consult their own professional adviser without delay.

Taxation of chargeable gains

For the purposes of UK tax on chargeable gains, the issue of the New Ordinary Shares to a

Qualifying Shareholder should be regarded as a reorganisation of the share capital of the Company.

Accordingly, no liability to UK tax on chargeable gains should arise for the Qualifying Shareholder

to the extent that the Qualifying Shareholder takes up his/her entitlement to New Ordinary Shares.

For the purposes of UK tax on chargeable gains, New Ordinary Shares allotted to a Qualifying

Shareholder will be treated as the same asset as, and having been acquired at the same time as, the

Qualifying Shareholder’s Existing Ordinary Shares. The amount of subscription monies paid for the

New Ordinary Shares will be added to the base cost of the Qualifying Shareholder’s existingholding(s).

In the case of a Qualifying Shareholder within the charge to corporation tax, indexation allowancewill apply to the amount paid for the New Ordinary Shares only from, generally, the date on which

the subscription monies for the New Ordinary Shares were payable.

If a Qualifying Shareholder disposes of all or some of his/her rights to subscribe for New OrdinaryShares, or if he/she allows or is deemed to have allowed his/her rights to lapse and receives a cash

payment in respect of them, he/she may, depending on his/her circumstances, incur a liability to tax

on any chargeable gain realised. However, if the proceeds resulting from the disposal or lapse of

those rights are ‘‘small’’ as compared to the value of the Existing Ordinary Shares in respect of which

the rights arose, the proceeds will instead be deducted from the base cost of his/her holding of

Existing Ordinary Shares for the purposes of computing any chargeable gain or allowable loss on a

subsequent disposal of Existing Ordinary Shares to which the rights related. As a result, no liability

to UK tax on chargeable gains will normally arise as a result of the disposal or lapse of rights forsuch proceeds (unless the base cost of the relevant Qualifying Shareholder’s Existing Ordinary Shares

is less than the proceeds, or the Qualifying Shareholder elects to disregard these ‘‘small disposal’’

rules and treat the proceeds as triggering a chargeable gains part disposal of his/her Existing Ordinary

Shares). HMRC will normally treat proceeds as ‘‘small’’ if the amount of the proceeds either does not

exceed 5% of the market value of the Existing Ordinary Shares held (measured immediately before

disposal or lapse) or does not exceed £3,000.

Qualifying Shareholders within the charge to tax on chargeable gains in the UK will, subject to the

availability to the Qualifying Shareholder of any exemptions, reliefs and/or allowable losses, be

required to pay tax on any gain arising on a subsequent disposal of New Ordinary Shares.

Stamp duty and SDRT

No stamp duty or SDRT will generally be payable on the issue of Provisional Allotment Letters orsplit Provisional Allotment Letters (provided they are renounceable within six months of issue).

Accordingly, where New Ordinary Shares represented by such documents are registered in the name

of the original shareholder entitled to such shares or New Ordinary Shares are credited in

uncertificated form to CREST accounts, no liability to stamp duty or SDRT will generally arise.

Persons who purchase (or are treated as purchasing) rights to New Ordinary Shares represented by

Provisional Allotment Letters or split Provisional Allotment Letters (whether nil paid or fully paid),

or Nil Paid Rights or Fully Paid Rights held in CREST, on or before the latest time for registration

223


or renunciation) will not generally be liable to stamp duty, but the purchaser will normally be liable

to pay SDRT at the rate of 0.5% of the consideration paid.

Where such a purchase is effected through a stockbroker or other financial intermediary, that person

(rather than the purchaser) will normally account for the liability of SDRT and should indicate that

this has been done in any contract note issued to a purchaser. In other cases, the purchaser of the

rights to the New Ordinary Shares represented by the Provisional Allotment Letter or the split

Provisional Allotment Letter must himself account to HMRC for the SDRT that is due on the

purchase. In the case of transfers within CREST, any SDRT due will be collected through CREST in

accordance with the CREST rules.

No stamp duty or SDRT will be payable on the registration or renunciation of Provisional Allotment

Letters or split Provisional Allotment Letters, whether by the original holders or their renouncees.

It should be noted that certain categories of person, including market makers, brokers, dealers and

other specified market intermediaries, are entitled to exemption from stamp duty and SDRT in

respect of purchases of securities in specified circumstances. Certain other persons, being mainly those

connected within depositary arrangements and clearance services, are generally liable to account forstamp duty or SDRT at a higher rate of 1.5% on securities issued or transferred to them.

Save as mentioned above, any subsequent dealings in New Ordinary Shares will generally be subject

to stamp duty or SDRT in the normal way. The transfer on sale of Existing or New Ordinary Shares

will be liable to ad valorem stamp duty (unless the consideration is £1,000 or less and the instrument

of transfer is certified at £1,000), generally at the rate of 0.5% thereof (rounded up to the nearest

multiple of £5) of the consideration paid. An unconditional agreement to transfer such shares will beliable to SDRT (unless the stamp duty is chargeable due to the £1,000 threshold), generally at the

rate of 0.5% of the consideration paid, but such liability will be cancelled or a right to a repayment

in respect of the SDRT liability will arise if the agreement is completed by a duly stamped transfer

within six years of the agreement having become unconditional. Stamp duty and SDRT are normally

the liability of the purchaser.

Under the CREST system for paperless share transfers, no stamp duty or SDRT will arise on a

transfer of New Ordinary Shares into the system provided, in the case of SDRT, the transfer is notfor money or money’s worth. Transfers of shares within CREST are liable to SDRT (at a rate of

0.5% of the amount or value of the consideration payable) rather than stamp duty, and SDRT on

relevant transactions settled within the system or reported through it for regulatory purposes will be

collected by CREST.

The comments in this section relating to stamp duty and SDRT apply whether or not a Qualifying

Shareholder is resident or ordinarily resident in the United Kingdom.

The above statements are intended as a general guide to the current UK stamp duty and SDRT position.

Special rules apply to agreements made by, amongst others, intermediaries. Shareholders who are in any

doubt about their taxation position and Shareholders who are not resident for tax purposes in the UK

should consult their own professional tax advisers.

Dividends

The Company will not be required to withhold tax at source when paying a dividend.

A Qualifying Shareholder who is an individual and is resident for tax purposes in the United

Kingdom and who receives a dividend from the Company will be entitled to a tax credit equal to

one-ninth of that dividend. The individual will be taxable on the total of the dividend and the tax

credit (the ‘‘gross dividend’’), which will be regarded as the top slice of the individual’s income. Thetax credit will, however, be treated as discharging the individual’s liability to income tax in respect of

the gross dividend, except to the extent that the gross dividend falls above the threshold for the

higher rate of income tax, in which case the individual will, to that extent, pay tax on the gross

dividend (such tax being equal to 32.5% of the gross dividend, less the related tax credit). So, for

example, a dividend of £80 will carry a tax credit of £8.89 and the income tax payable on the

dividend by an individual liable to income tax at the higher rate would be 32.5% of £88.89, namely

£28.89, less the tax credit of £8.89, leaving a net tax charge of £20.

The UK government has announced proposals to introduce, with effect from 6 April 2011, a new tax

rate of 45% for taxable non-savings and savings income above £150,000. On and after the date on

which the new rate takes effect, if and to the extent that the gross dividend received by a UK

resident individual falls above the threshold for income tax at the new 45% rate, that individual will

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be subject to tax on the gross dividend at the rate of 37.5%. If the new rate of tax is applied in the

same way as the existing rates, that individual would be able to set the tax credit off against part of

this liability and the effect of that set-off of the tax credit would be that such an individual would

have to account for additional tax equal to 27.5% of the gross dividend (which is also equal to 30.6%of the cash dividend received), to the extent that the gross dividend fell above the threshold for the

new 45.0% rate of income tax.

Qualifying Shareholders who are within the charge to corporation tax will generally not be subject to

corporation tax on dividends paid by the Company.

A Qualifying Shareholder who is resident for tax purposes in the United Kingdom will not generally

be entitled to claim payment of the tax credit on any dividends paid by the Company.

The UK government has published draft legislation which would, if passed in its current form,

significantly change the tax treatment of dividends received by Qualifying Shareholders within the

charge to corporation tax. The draft legislation would, amongst other things, remove the current

exclusion from corporation tax for dividends paid by a UK resident company. However, it appears

likely that dividends paid on the New Ordinary Shares to UK resident corporate Qualifying

Shareholders will generally qualify for exemption from corporation tax. It should be noted that the

draft legislation is likely to change before being passed and Qualifying Shareholders within the charge

to corporation tax are advised to consult their independent professional tax advisers in relation to theimplications of the legislation.

The right of a Qualifying Shareholder who is resident for tax purposes in any jurisdiction other than

the United Kingdom to a tax credit in respect of a dividend received from the Company and to claimpayment of any part of that tax credit will depend on the existence and terms of any double taxation

convention between the United Kingdom and the jurisdiction in which the holder is resident.

Qualifying Shareholders who are resident for tax purposes in any jurisdiction other than the United

Kingdom should consult their own tax advisers concerning their tax liabilities on dividends received,

whether they are entitled to claim any part of the tax credit and, if so, the procedure for doing so.

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PART XVI

ADDITIONAL INFORMATION

1. RESPONSIBILITY

The Directors, whose names appear on page 19 of this document, the Proposed Director and Premier

accept responsibility for the information contained in this document. To the best of the knowledge of

the Directors, the Proposed Director and Premier (who have taken all reasonable care to ensure that

such is the case), the information contained in this document is in accordance with the facts and

contains no omission likely to affect the import of such information.

2. SHARE CAPITAL OF PREMIER

(a) Share capital

As at the date of this document, the Company’s authorised share capital is £157,612,282 comprising

315,224,564 Ordinary Shares of 50 pence each in the Company. The Company’s issued share capital

as at the date of this document is 79,372,274 Ordinary Shares of 50 pence each in the Company, each

credited as fully paid. A total of 235,852,290 Ordinary Shares in the authorised Ordinary Share

capital of the Company are unissued.

(b) History of share capital

The Company was incorporated with a share capital of £100 divided into 100 shares of £1 each. The

authorised share capital of the Company was increased to £100,000 pursuant to a written resolution

passed on 13 September 2002, by the creation of £99,900 shares of £1 each. By a special resolutionpassed on 3 February 2003, 49,998 shares of £1 each were redesignated as redeemable preference

shares of £1 each.

By a special resolution passed on 3 February 2003 and which became effective on 15 July 2003: (i)the share capital of the Company was increased to £399,394,555.875, by the creation of a further

15,971,782,235 shares of 2.5 pence each, (ii) each of the 49,998 redeemable preference shares of £1

each were redesignated and subdivided into 40 shares of 2.5 pence each, (iii) each of the 50,002 shares

of £1 each were subdivided into 40 shares of 2.5 pence each, (iv) then every 7 authorised but

unissued shares of 2.5 pence each were consolidated into one share of 17.5 pence each, and (v)

2,282,254,605 shares were redesignated as 2,250,000,000 ordinary shares of 17.5 pence each and

32,254,605 non-voting convertible shares of 17.5 pence each.

By a special resolution passed on 3 February 2003, which was confirmed by the Court of Session and

became effective on 12 September 2003, the share capital of the Company was reduced by (i)

cancelling 12.5 pence of paid up capital on each ordinary share of 17.5 pence each and non-voting

convertible share of 17.5 pence each in issue on 11 September 2003, and then (ii) cancelling eachordinary share of 5 pence each and non-voting convertible share of 5 pence each held by Amerada

Hess Limited and Petronas International Corporation Limited on 11 September 2003. By a special

resolution passed on 3 February 2003 and which became effective on 12 September 2003 (following

the reduction of capital), the ordinary share capital of the Company was consolidated into

311,904,002 ordinary shares of 50 pence each (with the authorised but unissued non voting

convertible shares of 17.5 pence left unchanged).

By a special resolution passed on 6 June 2008 the share capital of the Company was increased by

£0.525 to £157,612,282 by the creation of three non-voting convertible shares of 17.5 pence each. By

a special resolution passed on 6 June 2008 the 9,487,317 existing authorised but unissued non-voting

convertible shares of 17.5 pence each in the capital of the Company and the three further such shares

created on 6 June 2008, were consolidated and redesignated as 3,320,562 Ordinary Shares of 50 penceeach in the capital of the Company.

(c) Shares held by or on behalf of Premier

As at 1 April 2009 (the latest practicable date prior to the publication of this document), the

Company held no shares in treasury.

3. DIRECTORS AND PROPOSED DIRECTOR

(a) Director’ biographies and business address

Biographical details of the Directors are given in the section entitled ‘‘Board of Directors’’ of

Premier’s statutory accounts for the year ended 31 December 2008, which are incorporated into this

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document by reference. The business address of all the Directors is 23 Lower Belgrave Street, London

SWIW 0NR.

Proposed Director

Andrew Lodge will join the Board on 20 April 2009 as Exploration Director. Andrew has 30 years’

professional experience in the oil and gas industry and was, until 31 March 2009, Vice President,

Exploration for Hess, responsible for Europe, North Africa, Asia and Australia. Before he joined

Hess in 2000, he was previously Vice President, Exploration, Asset Manager and Group Exploration

Advisor for BHP Petroleum, based in London and Australia. Prior to joining BHP Petroleum,Andrew worked for BP as a geophysicist principally in South East Asia, Europe and North Africa.

Andrew has an honours degree in Mining Geology from the University of Wales and a Masters in

Applied Geophysics from the University of Leeds. He is a fellow of the Geological Society.

The business address of the Proposed Director will be 23 Lower Belgrave Street, London SW1W0NR.

(b) Directorships and partnerships

The following Directors and the Proposed Director hold or have held in the past five years the

following directorships in companies in addition to their directorships of Premier and past or current

members of the Group and are or have been a member of any of the following partnerships in thepast five years:

Director Position Company Still held

Joe Darby Director British Nuclear Fuels Limited (formerly plc) No

Director Carillion JM Limited No

Director Faroe Petroleum plc No

DirectorMallards Reach (Oakley) Management

Company LimitedYes

Director Sandleigh Limited Yes

Director Sellafield Limited No

Tony Durrant Director Clipper Windpower plc Yes

Director Peabody Turkish Investments plc No

Neil Hawkings Director Britannia Operator Limited No

DirectorThe United Kingdom Offshore Oil and Gas

Industry Association LimitedNo

Sir David John KCMG Director Asia House No

Director Asia House Enterprises Limited No

Director Balfour Beatty plc No

Director British Standards Institution Yes

Director Llandovery College Yes

Director Sixty Three New Cavendish Limited No

David Lindsell Director Abbey Gateway Enterprises Limited Yes

Director Drax Group plc Yes

Director The BM Co Pension Trustee Company Limited Yes

Director The British Museum Company Limited Yes

Director The British Museum Friends No

Director St Albans School Yes

Partner Ernst & Young LLP No

John Orange Director Atlas Copco UK Holdings Limited No

Director Exile Resources, Inc. Yes

Director Finavera Gas Limited No

David Roberts Director Geological Trading Limited No

Director Getech Group plc Yes

Director Roberts Geosciences Consulting Limited No

Director Rockall GeoSciences Limited No

Director Roberts Geosciences Consulting Malta Limited Yes

Michel Romieu Director Sican Petroleum plc Yes

Andrew Lodge Director Hess Egypt Limited No

Director Hess (Indonesia Deepwater) Limited No

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Director Hess (Indonesia-Kasuri) Limited No

Director Hess (Indonesia-Semai IV) Limited No

Director Hess (Indonesia-Semai V) Limited No

Director Hess (Malaysia-Block F) Limited No

Director Hess (Malaysia-SB 302) Limited No

Director Hess (North Africa) Exploration Limited No

Director Hess (Offshore Egypt) Exploration Limited No

Director Hess Australia (Dampier) Pty Limited No

Director Hess Australia (Exmouth) Pty Limited No

Director Hess Australia (North West Shelf) Pty Limited No

Director Hess Australia (Offshore) Pty Limited No

DirectorHess Australia Exploration (New Ventures) Pty

LimitedNo

Director Hess Egypt Exploration Limited No

Director Hess Egypt New Ventures Limited No

Director Hess Egypt West Mediterranean Limited No

Director Hess Exploration (Carnarvon) Pty Limited No

Director Hess Exploration (Thailand) Co. Ltd No

Director Hess Exploration Australia Pty Limited No

Director Hess Exploration Ireland Limited No

Director Hess Libya Exploration Limited No

Director Hess Norge AS No

Director Hess Production (Australia) Pty Limited No

Director Hess (Indonesia Jambi-Merang) Limited No

Director Hess (Indonesia Pangkah) Limited No

Director Hess (Indonesia-Blora) Limited No

Director Hess Indonesia New Ventures Limited No

Director Hess Overseas Limited No

Director Hess (Indonesia-Tanjung Aru) Limited No

Director Hess (Faroes) Limited No

Director Hess (Thailand) Limited No

Director Hess (Malaysia-SK 306) Limited No

Director Hess Limited No

Director Hess Indonesia (North Masela) Limited No

Director Hess (Indonesia-South Sesulu) Limited No

Director Hess Services UK Limited No

Director Hess Holdings UK Limited No

Director Hess (Martaban) Limited No

Director Hess Indonesia Exploration Limited No

Director Petrofac (Malaysia-PM 304) Limited No

Director Hess (Indonesia) Limited No

Director Amerada Hess (Khazar) Limited No

Director Hess (Australia) Limited No

Director Hess (Azerbaijan) Limited No

Director Hess (Yemen) Limited No

Director Hess Indonesia (North Masela) Limited No

Director Amerada Hess (Brasil) Limited No

Director Amerada Hess (Vietnam) Limited No

Director Amerada Hess (Argentina) Limited No

Director Amerada Hess (CAO) Limited No

Director Amerada Hess (China) Limited No

Director Amerada Hess (France) Limited No

Director Amerada Hess (Germany) Limited No

Director Amerada Hess (Indonesia) Limited No

Director Amerada Hess (Ireland) Limited No

Director Amerada Hess (MAN) Limited No

228



Director Amerada Hess (NAOC) Limited No

Director Amerada Hess (Netherlands) Limited No

Director Amerada Hess (Indonesia-Pagatan) Limited No

Director Amerada Hess (Indonesia-Sesulu) Limited No

Director Amerada Hess (IOM) Limited No

(c) Directors’ confirmations

At the date of this document none of the Directors nor the Proposed Director:

(i) has any convictions in relation to fraudulent offences for at least the previous five years;

(ii) has been associated with any bankruptcy, receivership or liquidation while acting in the capacity

of a member of the administrative, management or supervisory body or of senior manager ofany company for at least the previous five years; or

(iii) has been subject to any official public incrimination and/or sanction of him by any statutory or

regulatory authority (including any designated professional bodies) nor has ever been disqualified

by a court from acting as a director of a company or from acting as a member of the

administrative, management or supervisory bodies of an issuer or from acting in the

management or conduct of the affairs of any issuer for at least the previous five years.

(d) Conflicts of interest

The following actual and potential conflicts of interest between the Directors’ duties to the Company

and their private interests and/or other duties have been authorised by the Board for the purposes of

section 175(4)(b) of the Companies Act:

Director

Date

Authorised

Potential or Actual

Conflict Details of Conflict

Joe Darby 28/10/2008 Potential Mr Darby’s daughter works in finance for BG

plc, which is a competitor of the Group and

therefore could possibly give rise to a conflict.28/10/2008 Potential Mr Darby’s son works in finance for Centrica

plc, which is a potential customer and a

competitor of the Group and which therefore

could possibly give rise to a conflict.

Tony Durrant 28/10/2008 Actual Mr Durrant is also a director of Premier

Pension Plan Trustees Limited, the trustee

company for the Premier Oil plc Retirement

and Death Benefits Plan.David Roberts 28/10/2008 Potential Mr Roberts’ daughter works as a trade

control analyst for BP Oil, which is a

competitor of the Group and therefore could

possibly give rise to a conflict.

There are no other potential conflicts of interest relating to any of the Directors or the Proposed

Director.

4. DIRECTORS’ SERVICE CONTRACTS AND EMOLUMENTS

(a) Base salary, fees, bonuses and benefits-in-kind

The amount of remuneration paid and benefits in kind granted to the Directors by the Group for

services to the Group in the financial year ended 31 December 2008 (being the last full financial year

for Premier) is stated in the section headed ‘‘Remuneration Report’’ of Premier’s statutory accounts

for the year ended 31 December 2008, which are incorporated into this document by reference.

(b) Retirement benefits

The retirement benefits of the Directors, including the amount accrued by the Group to provide

pension, retirement or similar benefits for the financial year ended 31 December 2008 (being the last

full financial year for Premier) is stated in the section headed ‘‘Remuneration Report’’ of Premier’s

statutory accounts for the year ended 31 December 2008, which are incorporated into this document

by reference.

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(c) Share ownership and options held by Directors

The beneficial interests of the Directors in the Ordinary Shares of the Company are set out below:

Name As at 31 December 2008 As at 1 April 2009

Sir David John KCMG1, 3 16,700 16,700

Robin Allan2 18,992 19,093

Joe Darby3 4,000 4,000

Tony Durrant2 30,622 30,723

Neil Hawkings2 622 723

David Lindsell3 3,000 3,000

Simon Lockett2 50,760 50,861John Orange3, 4 8,500 8,500

Notes:

1. This includes 1,700 Ordinary Shares held by Sir David John’s wife.

2. The beneficial interests of the executive Directors include personal shareholdings together with Share Incentive Plan partnershipshares and any matching shares held for more than three years

3. The beneficial interests of the non-executive directors comprise personal shareholdings.

4. This includes 1,000 Ordinary Shares held by Mr Orange’s wife.

The Directors’ interests in share options, deferred bonus shares, deferred and matching share awards

under the Asset and Equity Plan and Share Incentive Plan entitlements for the financial year ended

31 December 2008 (being the last full financial year for Premier) are set out in the section headed

‘‘Remuneration Report’’ of Premier’s statutory accounts for the year ended 31 December 2008, which

are incorporated into this document by reference.

The Proposed Director has no interest in the Ordinary Shares of the Company.

5. BOARD PRACTICES

(a) Service contracts and letters of appointment

Save for automatic termination when each executive Director becomes 60 years of age, the executive

directors have rolling service contracts and are subject to re-election by Shareholders under the

Company’s Articles of Association and the provisions of the Combined Code. The service contract of

each executive Director may be terminated on 12 months’ notice in writing by either side, inaccordance with current market practice. In such event, the compensation commitments in respect of

their contracts could amount to 12 months’ remuneration based on base salary, annual bonus and

long-term incentive scheme entitlement, benefits-in-kind and pension rights during the notice period.

There are provisions for earlier termination by the Company in certain circumstances. If such

circumstances were to arise, the executive Director concerned would have no claim against the

Company for damages or any other remedy in respect of the termination. There are no other

provisions, such as liquidated damages clauses, which expressly provide for compensation in the event

of early termination. The Remuneration Committee would apply general principles of mitigation toany payment made to a departing executive Director and would consider each case on an individual

basis. Messrs Lockett and Allan have service contracts dated 9 December 2003. Mr Durrant has a

service contract dated 1 July 2005 and Mr Hawkings’ service contract is dated 23 March 2006. While

the Proposed Director has not yet entered into a service contract with the Company, the terms of his

service contract are not expected to be out of line with the service contracts of the existing executive

Directors.

Non-executive Directors have letters of appointment, which are all effective for a period of three

years (subject to reappointment by the members in general meeting), and all of which have a notice

period of three months. Sir David John KCMG and Mr Orange have letters of appointment issuedon 28 July 2006. Professor Dr. Roberts has a letter of appointment dated 30 June 2006 and Mr

Darby has a letter of appointment dated 1 September 2007. Messrs Lindsell and Romieu have letters

of appointment dated 17 January 2008 following their appointment to the Board on that date.

(b) Board committees

Remuneration Committee

The Remuneration Committee determines the remuneration of the executive Directors and senior

employees. The Remuneration Committee is composed entirely of non-executive directors and

comprises Mr Orange, who chairs the Committee and is the Company’s senior non-executive

independent Director, Messrs Darby and Lindsell, and Professor Dr. Roberts. The Board considers

230


that the membership of the Committee is in compliance with the Combined Code recommendation,

on the basis that it considers Mr Orange to be independent, notwithstanding his length of service. Sir

David John KCMG, the Company’s chairman, is not a member of the Committee, but attends by

invitation. Mr Lockett is not a member of the Committee but usually attends meetings by invitation,except when his own remuneration is being discussed, as the Company considers it important that the

Chief Executive is fully aware of discussions concerning remuneration policy and the remuneration

packages of its most senior employees.

The Committee acts within its agreed written terms of reference and complies with the relevant

provisions of the Combined Code in implementing its remuneration policy.

The role of the Committee includes:

– considering and determining the remuneration policy for executive Directors;

– within this agreed policy, considering and determining the total compensation package of eachexecutive Director;

– considering and advising on the general principles under which remuneration is applied to

employees of the Company;

– determining the awards to be made under the Company’s long-term incentive schemes; and

– determining the policy for pension arrangements, service agreements and termination payments

to Directors.

Audit and Risk Committee

The Audit and Risk Committee, comprising only non-executive directors, reviews the Group’s

accounts and its internal controls. The members of the Audit and Risk Committee are Messrs

Lindsell (Chairman), Darby, Orange and Romieu. The Board considers Mr Lindsell and the other

members of the Committee to have the relevant commercial, financial and accounting experience to

assess effectively the complex financial reporting, risk and internal control issues relevant to the

Company. Messrs Lockett, Durrant and Hawkings normally attend, by invitation, all meetings of theCommittee.

The Committee is authorised to engage the services of external advisers as it deems necessary in the

furtherance of its duties at the Company’s expense. No external advisers materially assisted the

Committee during the year.

Minutes of the meetings of the Committee are distributed to all Board members, all of whom are

invited to attend meetings of the Committee (as observers) since the Board believes that the work of

the Committee, particularly in the areas of risk management and internal control, is increasingly

important for all Board members.

The Audit and Risk Committee is mainly responsible for:

– monitoring the integrity of the financial statements of the Company and formal announcements

relating to the Company’s financial performance and reviewing any significant financial reporting

judgements contained in them;

– reviewing the Company’s internal financial and operational control and risk management

systems;

– reviewing accounting policies, accounting treatments and disclosures in financial reports to

ensure clarity and completeness;

– overseeing the Company’s relationship with its external auditors, including makingrecommendations as to the appointment or reappointment of the external auditors, reviewing

their terms of engagement and monitoring their independence; and

– reviewing the Company’s whistleblowing procedures and ensuring these are adequately published

within the organisation, that the Committee chairman is promptly informed of any issues, and

that there are arrangements in place for the investigation of any alleged improprieties.

Nomination Committee

The Nomination Committee meets as and when required and comprises Sir David John KCMG

(Chairman), Messrs Darby, Lockett and Orange, and Professor Dr. Roberts. The Board considers the

membership of the Nomination Committee to be in compliance with the Combined Code.

231


Formal meetings of the Committee are held to consider standing items of business. There is also a

significant level of ad hoc discussion between members of the Committee, particularly when a

recruitment exercise is taking place.

The role of the Nomination Committee includes:

– reviewing the structure, size and composition of the Board and making recommendations to the

Board with regard to any adjustments that are deemed necessary. This requires an ongoing

assessment of the appropriate skills-mix required at Board level in light of the strategy of the

Company in the medium-term;

– responsibility for identifying and nominating candidates, subject to Board approval, to fill board

vacancies as and when they arise and to prepare a description of the role and capabilitiesrequired for a particular appointment; and

– the assessment of time required to fulfil the role of chairman of the Company, senior

independent Director and non-executive Director, ensuring that current members of the Boardhave devoted sufficient time to their duties and that any candidates have sufficient time to

undertake the roles.

The Nomination Committee, together with the Board, addresses the Company’s succession plans. The

Board also considers succession planning for senior corporate executives, with the Nomination

Committee focusing more specifically on succession planning for members of the Board.

(c) Corporate governance

The Board is firmly committed to high standards of corporate governance. Premier complied with all

the provisions of the Combined Code in the year ended 31 December 2008, except to the extent

stated below.

Mr Orange was appointed to the Board in 1997. Whilst his service exceeds the term referred to in the

Combined Code, the Board considers that his experience and long-term perspective of Premier’s

business continues to provide a most valuable contribution and that it benefits from his input to theBoard’s deliberations. The Board is strongly of the view that the important qualities when considering

the issue of independence of non-executive directors are independence of spirit and objectivity of

mind, and therefore regards Mr Orange as an independent Director.

6. EMPLOYEES AND SHARE OPTION SCHEMES

(a) Employees

The average number of employees of the Group for the last three financial years is stated in note 4to the financial statements in Premier’s statutory accounts for the years ended 31 December 2006, 31

December 2007 and 31 December 2008, which are incorporated into this document by reference.

(b) Share option schemes

A description of the Premier Share Option Schemes is included in the section entitled ‘‘Remuneration

Report’’ in Premier’s statutory accounts for the year ended 31 December 2008, which are

incorporated into this document by reference.

7. INTERESTS OF NATURAL AND LEGAL PERSONS INVOLVED IN THE RIGHTS ISSUE

No person involved in the Rights Issue has an interest which is material to the Rights Issue.

8. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

(a) Control

As at 1 April 2009 (the latest practicable date prior to the publication of this document), Premier was

not aware of any persons who, directly or indirectly, jointly or severally, will exercise or couldexercise control over Premier. As at 1 April 2009 (the latest practicable date prior to the publication

of this document), Premier was not aware of any arrangements, the operation of which may at a

subsequent date result in a change of control of Premier.

232


(b) Major shareholders

As at 1 April 2009 (the latest practicable date prior to the publication of this document), Premier had

been notified by the following entities of their interests in the total voting rights of Premier:

Notified number of

voting rights

Notified percentage

of voting rights

Schroders plc 8,094,087 9.876%

AXA S.A. & group companies 7,498,283 9.13%

Ameriprise Financial, Inc. 4,028,672 5.076%

Aviva plc & subsidiaries 3,014,548 3.80%

Bear Stearns International Trading Limited 2,552,847 3.109%

None of the Company’s major shareholders have any different voting rights.

(c) Related party transactions

A description of the material provisions of agreements and other documents between the Group and

various individuals and entities that may be deemed to be related parties is given in note 26 to each

of Premier’s statutory accounts for the years ended 31 December 2006 and 31 December 2007 and

note 25 to the financial statements in Premier’s statutory accounts for the year ended 31 December2008, which are incorporated into this document by reference. No such transactions have been

entered into by any member of the Group since 31 December 2008.

9. SUMMARY OF MEMORANDUM AND ARTICLES OF ASSOCIATION OF PREMIER

The following is a summary of Premier’s Memorandum and Articles of Association, which are

available for inspection at the address specified in paragraph 19 of this Part XVI.

(a) Memorandum of Association

The principal object of Premier is to carry on the business of a holding company. The objects of the

Company are set out in full in clause 3 of the Memorandum of Association which is available for

inspection at the address specified in paragraph 19 of this Part XVI.

(b) Articles of Association

The Articles of Association, which were adopted on 6 June 2008, contain provisions (among others)

to the following effect:

(i) Share rights

Subject to the Companies Act and other shareholders’ rights, shares may be issued with such rights

and restrictions as the Company may by ordinary resolution decide, or (if there is no such resolution

or so far as it does not make specific provision) as the Board may decide. Redeemable shares may be

issued. Subject to the Articles, the Companies Act and other shareholders’ rights, unissued shares are

at the disposal of the Board.

(ii) Voting rights

Subject to any rights or restrictions attaching to any class of shares, every member present in person

at a general meeting has, upon a show of hands, one vote, and every member present in person or by

proxy has, upon a poll, one vote for every share held by him. Resolutions put to the meeting will

generally be decided on a show of hands. No member shall be entitled to vote at any general meeting

in respect of any share held by him if he has not paid any amount relating to that share which is dueat the time of the meeting or if a member has been served with a restriction notice (as defined in the

Articles) after failure to provide the Company with information concerning interests in those shares

required to be provided under the Companies Act.

(iii) Dividends and other distributions

Subject to the Companies Act, the Company’s shareholders can declare dividends by passing anordinary resolution. No such dividend can exceed the amount recommended by the Board. Subject to

the Companies Act, the Directors may pay interim dividends, and also any fixed rate dividend, if they

consider that the financial position of the Company justifies such payments. If the Board acts in good

faith, it is not liable for any loss that shareholders may suffer because a lawful dividend has been

paid on other shares which rank equally with or behind their shares.

233


The Board may withhold payment of all or any part of any dividends (including scrip dividends) or

other money which would otherwise be payable in respect of the Company’s shares from a person

with a 0.25% interest (as described in the Articles) if such a person has been served with a restriction

notice after failure to provide the Company with information concerning interests in those sharesrequired to be provided under the Companies Act.

Except insofar as the rights attaching to, or the terms of issue of, any share otherwise provide, all

dividends will be divided and paid in proportions based on the amounts which have been paid up on

the shares during any period for which the dividend is paid. Dividends may be declared or paid in

any currency.

The Board may, if authorised by an ordinary resolution of the Company, offer ordinary shareholders

the right to choose to receive extra ordinary shares which are credited as fully paid up, instead of

some or all of their cash dividend.

If a dividend has not been claimed for 12 years after being declared or becoming due for payment, it

will be forfeited and go back to the Company.

The Company may stop sending dividend payments through the post, or cease using any other

method of payment (including payment through CREST), for any dividend if, either (i) at least two

consecutive payments have remained uncashed or are returned undelivered or that means of payment

has failed or (ii) one payment remains uncashed or is returned undelivered or that means of payment

has failed and reasonable enquiries have failed to establish any new address or account of the

registered holder. The Company will resume sending dividend payments if requested in writing by theshareholder.

(iv) Variation of rights

Subject to the Companies Act, rights attached to any class of shares may be varied with the written

consent of the holders of not less than three-quarters in nominal value of the issued shares of that

class, or by an extraordinary resolution passed at a separate general meeting of the holders of thoseshares. At every such separate general meeting (except an adjourned meeting) the quorum shall be

two persons holding or representing by proxy not less than one-third in nominal value of the issued

shares of the class.

(v) Lien, Forfeiture and Untraced Shareholders

The Company has a lien (enforceable by sale) on all partly-paid shares for any money owed to the

Company for the shares. The directors are entitled to exercise their right of sale where the money

owed by the shareholder is payable immediately, the directors have given notice to the shareholder of

the amount owed (stating the amount due, demanding payment and setting out the directors’ right to

enforce the lien through sale), the notice has been served on the shareholder and the directors have

waited 14 days for the shareholder to pay the sum due.

The Board can also call on shareholders to pay any money which has not yet been paid to the

Company for their shares as well as any interest which may accrue from the date of the call until the

date it is satisfied and any expenses incurred as a result of the non-payment of the call. The directorscan send the shareholder a notice requiring payment of the unpaid amount, the notice must demand

payment of the sum due plus interest and expenses, give the date by which the total is due (which

must be at least 14 days after the date of the notice), specify where payment is to be made and state

the Company’s right of forfeiture in respect of outstanding calls. Where this call remains unsatisfied

the shares can be forfeited; the shares become the property of the Company and the directors can

dispose of them in any way they decide.

As regards certificated shares, if during a 12 year period at least 3 cash dividends have gone

unclaimed and at least 3 letters from the Company have not been responded to the Company maypublish a notice in a national and local newspaper stating it’s intention to sell the shares. If, during

the 3 months following the notice, the shareholder still fails to respond the Company may sell the

shares.

(vi) Transfer of shares

Any member may transfer all or any of his certificated shares by an instrument of transfer in any

usual form or in any other form which the Board may approve. The instrument of transfer must be

executed by or on behalf of the transferor and (in the case of a partly-paid share) the transferee and

the transferor will continue to be treated as the holder until the transferee’s name is entered in the

register.

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The Board may, without giving any reason, refuse to register the transfer of any shares which are not

fully paid. The Board may also decline to register a transfer of certificated shares if the instrument of

transfer:

(A) Is not properly stamped to show the payment of any applicable stamp duty and accompanied

by the relevant share certificate and such other evidence of the right to transfer as the Board

may reasonably require;

(B) Is in respect of more than one class of share; and

(C) If to joint transferees, is in favour of more than four such transferees.

Furthermore where a shareholder holds over 0.25% of the existing shares in a particular class and has

been served with a restriction notice the Board can refuse to register a transfer of any shares whichare certificated shares unless they are satisfied that they have been transferred to an independent third

party.

Any shares in the Company may be held in uncertificated form and these shares must be transferredthrough CREST. (Provisions of the Articles do not apply to any uncertificated shares to the extent

that such provisions are inconsistent with the holding of shares in uncertificated form, with the

transfer of shares through CREST or with any provision of the Uncertificated Securities Regulations

2001.) If according to the Articles or any relevant legislation the Company has the right to sell,

transfer or otherwise deal with the CREST shares the directors may require the holder of that share

to change the CREST share to a certificated share.

The Board may decline to register a transfer of CREST shares in the circumstances set out in the

Uncertificated Securities Regulations (as defined in the Articles) and where, in the case of a transfer

to joint holders, the number of joint holders to whom the uncertificated share is to be transferred

exceeds four.

(vii) Alteration of share capital

The Company may pass an ordinary resolution to increase, consolidate, consolidate and then divide,

or sub-divide its shares. The resolution may provide that as between the holders of the newly divided

shares different rights can apply to the shares. The Company may, subject to the Companies Act,pass a special resolution to reduce its share capital, share premium account, capital redemption

reserve or any other undistributable reserve.

(viii) Purchase of own shares

The Company may, subject to the Companies Act and to any special rights previously given to

holders of existing shares, purchase or contract to purchase any of its own shares (including

redeemable shares).

(ix) Meetings

Before a general meeting can start there must be at least two people present who are entitled to vote

(shareholders or proxies or both). Every director is entitled to speak at the general meeting. The

chairman is entitled to adjourn a meeting, whether quorate or not, for any reason so that the

business of the meeting can be carried out properly and can also adjourn a quorate meeting with theagreement of the meeting. Meetings can be adjourned indefinitely and more than once.

(x) Directors

(A) Appointment of Directors

The Company must have a minimum of two directors and a maximum of 20 and the directors

are not required to hold shares in the Company. Directors may be appointed by the Companyby ordinary resolution or by the Board. The only people who can be appointed as directors at a

general meeting are those directors retiring during the meeting, persons recommended by the

directors or persons recommended by the shareholders where the shareholder is entitled to vote

and delivers to the Company notice of his intention to recommend the relevant individual along

with the individual’s consent.

(B) Removal of Directors

In addition to any power to remove directors conferred by legislation, the Company can remove

a director before the end of his term in office by passing a special resolution.

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(C) Retirement of Directors

At every annual general meeting the following must retire from office; any director who has

been appointed by the Board since the last annual general meeting, any director who held officeat the time of the preceding two annual general meetings and who did not retire then and any

director who has been in office as a non-executive director, for more than 9 years at the date of

the meeting. Any retiring director may offer himself up for reappointment and can be

reappointed by an ordinary resolution of the shareholders.

(D) Vacation of Office by Directors

In addition to the legislative provisions on vacation of a directors’ office, any director

automatically vacates his office as director if; he gives the Company written notice of his

resignation, he offers to resign and this offer is accepted, all of the other directors (where there

are at least three) pass a resolution requiring him to vacate, he is suffering from a mental health

illness and the directors pass a resolution removing him from office, he has missed directors’meetings for a continuous 6 month period without permission and the directors pass a

resolution removing him or a bankruptcy order is made against him.

(E) Alternate Directors

Any director can appoint another person to act as a director in his place. Where this person is

not already a director their appointment requires the approval of the directors.

(F) Remuneration of Directors

The total fees paid to all of the directors (excluding any payments made to executive directors

or under any other provision of the Articles) must not exceed £600,000 a year or such higher

sum decided on by ordinary resolution of the Company. Any director who is appointed to any

executive office will be entitled to receive such remuneration (whether as salary, commission,

profit share or any other form of remuneration) as the Board or any committee authorised by

the Board may decide, either in addition to or in place of his fees as a director. In addition,any director who, in the opinion of the Board or any committee authorised by the Board,

performs any special or extra services for the company, may be paid such extra remuneration as

the Board or any committee authorised by the Board may determine. Each director may be paid

his reasonable travelling, hotel and incidental expenses of attending and returning from meetings

of the Board, or committees of the Board or of the Company or any other meeting which as a

director he is entitled to attend, and will be paid all expenses properly and reasonably incurred

by him in connection with the Company’s business or in the performance of his duties as a

director. The Company can also fund a director or a director of its holding Company for anypurpose permitted by the Companies Act and, as far as permitted by the legislation, can

indemnify any director against any liability.

(G) Pensions and gratuities for directors

The Board or any committee authorised by the Board may exercise the powers of the Company

to provide benefits either by the payment of gratuities or pensions or by insurance or in any

other manner for any director or former director or his relations or dependents. However, no

benefits (except those provided for by the Articles) may be granted to a director or former

director who has not been employed by or held an executive office or place of profit under the

Company or any of its subsidiary undertakings or their respective predecessors in business

without the approval of an ordinary resolution of the Company.

(H) Permitted interests of directors

The directors may authorise any matter which would otherwise involve a director breaching hisduty under the Companies Act to avoid conflicts of interest. In order to obtain authorisation

the director must tell the nature and extent of his interest to the Board as soon as possible and

in sufficient detail. Any director (including the conflicted director) may propose this

authorisation. In considering this proposal the conflicted director will not be entitled to vote and

will not count in the quorum and may be excluded from the meeting whilst the decision is

taken.

Where authority is given the Board may specify such terms to be imposed on the director as the

Board thinks fit e.g. the conflicted director may be excluded from the receipt of certain

information. The Board may also provide that the director is not bound to disclose to the

Company any information which he comes into possession of otherwise than in his role as a

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director where disclosure would entail a breach of confidence. The Board may provide that the

terms of the authorisation be recorded in writing and any authority given may be varied or

revoked at any time.

Where a director is indirectly or directly interested in a contract with the Company this must be

disclosed in accordance with the Companies Act. Where this is the case the director may do the

following:

* have any kind of interest in a contract with or involving the Company;

* hold any office (except that of auditor) with the Company;

* do paid professional work for the Company;

* become a director of any holding company or subsidiary of the Company; and/or

* be a director of any other company so long as the appointment cannot reasonably be

regarded as giving rise to a conflict of interest.

(I) Restrictions on voting

A director cannot vote or be counted in the quorum when the Board is considering his

appointment to a position within the Company or a company in which the Company has an

interest. Furthermore, except as mentioned below, no director may vote on, or be counted in a

quorum in relation to, any resolution of the board in respect of any contract in which he hasan interest. A director can only vote where his interest cannot reasonably be regarded as

material or where the only material interest he has in it is included in the following list:

* a resolution about giving him any security or any indemnity for any money which he, or

any other person, has lent at the request, or for the benefit, of the Company or any of its

subsidiary undertakings;

* a resolution about giving any security or any indemnity to any other person for a debt or

obligation which is owed by the Company or any of its subsidiary undertakings, to thatother person, if the director has taken responsibility for some or all of that debt or

obligation. The director can take this responsibility by giving a guarantee, indemnity or

security;

* a resolution giving him any other indemnity where all directors are also being offered

indemnities on substantially similar terms;

* a resolution about the Company funding any expenditure incurred defending proceedings

where all directors are also being offered indemnities on substantially similar terms;

* a resolution about any proposal relating to an offer of any shares or debentures or othersecurities for subscription or purchase by the Company or any of its subsidiary

undertakings, if the director takes part because he is a holder of shares, debentures or

other securities, or if he takes part in the underwriting or sub-underwriting of the offer;

* a resolution about a contract in which he has an interest because of his interest in

securities of the Company;

* a resolution regarding a contract with a company in which the director has an interest

(including where the director is a director or shareholder of that other company) as longas he does not hold an interest in shares representing one percent or more of any class of

equity share capital of that company or of the voting rights in that company;

* a resolution relating to a pension fund, superannuation scheme, retirement, death or

disability fund where these benefits are provided to employees generally;

* any arrangement for the benefit of employees of the Company or any of its subsidiary

undertakings which gives him benefits which are also generally given to the employees to

whom the arrangement relates; or

* a resolution about any proposal relating to any insurance which the Company can buy

and renew for the benefit of directors or of a group of people which includes directors.

Subject to the provisions of the Companies Act, the Company may by ordinary resolution

suspend or relax the above provisions to any extent or ratify any contract which has not been

properly authorised in accordance with the above provisions.

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(J) Borrowing powers

Subject to the Company’s Memorandum of Association, the Articles, the Companies Act and

any directions given by the Company by special resolution, the business of the Company will bemanaged by the Board who may use all the Company’s powers.

In particular, the Board may exercise all the Company’s powers to borrow money and to

mortgage or charge any of its undertaking, property, assets and uncalled capital, to issue

debentures and other securities and to give security for any debt, liability or obligation of the

Company or any third party. The Board will limit the total borrowings of the Company and, so

far as it is able, its subsidiary undertakings so as to ensure that the total amount of the Group’s

borrowings does not exceed four times the Company’s adjusted capital and reserves. However,

the Company may pass an ordinary resolution allowing borrowings to exceed such a limit.

10. SIGNIFICANT CHANGES

(a) The Group

There has been no significant change in the financial or trading position of the Group since31 December 2008, the date to which the last audited consolidated financial statements of the Group

were prepared.

(b) ONSL

Details of the significant changes in the financial or trading position of ONSL since 31 December

2007, the date to which the last audited consolidated financial statements of ONSL were prepared,

are set out in paragraph 6 of Part IV. Apart from each of the items set out in paragraph 6 of PartIV, there has been no significant change in the financial or trading position of ONSL since 31

December 2007, the date to which the last audited consolidated financial statements of ONSL were

prepared.

11. LITIGATION

(a) The Group

No member of the Group is or has been engaged in or, so far as Premier is aware, has any pending

or threatened governmental, legal or arbitration proceedings which may have, or have had in the

recent past (covering the 12 months preceding the date of this document), a significant effect on the

financial position or profitability of Premier and/or the Group.

(b) ONSL

ONSL is not and has not been engaged in and, so far as Premier is aware, does not have any

pending or threatened governmental, legal or arbitration proceedings which may have, or have had in

the recent past (covering the 12 months preceding the date of this document), a significant effect on

the financial position or profitability of ONSL.

12. MATERIAL CONTRACTS OF THE GROUP

In addition to the Acquisition Agreements which have been summarised in Part V of this document,

a summary of the other contracts (not being contracts entered into in the ordinary course of business)

that have been entered into by the Company or any member of the Group within the two years

immediately preceding the date of this document which are or may be material or which have been

entered into by the Company or any member of the Group at any other time and which containprovisions under which the Company or any member of the Group has an obligation or entitlement

that is material to the Group as at the date of this document, is set out below:

(a) Contracts relating to the Convertible Bonds

Pursuant to a subscription agreement dated 30 May 2007 (the ‘‘Subscription Agreement’’) between,

amongst others, POFJL, Premier, and Barclays Bank PLC and Merrill Lynch International (the‘‘Joint Lead Managers’’), Premier is guarantor to a US$250,000,000 2.875% Guaranteed Convertible

Bond (the ‘‘Bonds’’) issued by POFJL, one of Premier’s principal wholly-owned subsidiaries, on 27

June 2007.

Subject to and in accordance with the terms and conditions of the Bonds, the Bonds are convertible

into preference shares in POFJL which, in turn, are exchangeable for ordinary shares in Premier.

The conversion rights and exchange rights are guaranteed by Premier pursuant to a Deed Poll dated

27 June 2007 (see below).

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Unless previously purchased and cancelled, redeemed or converted, the Bonds will be redeemed on 27

June 2014. The Bonds are in registered form and issued in the principal amounts of US$100,000 and

integral multiples of US$1,000 in excess thereof up to and including US$199,000. The Bonds are

represented by a global registered bond (the ‘‘Global Bond’’) held on behalf of Euroclear andClearstream, Luxembourg. The Global Bond is exchangeable in certain limited circumstances in

whole, but not in part, for definitive registered Bonds.

The Bonds bear interest from and including 27 June 2007 (the ‘‘Closing Date’’) at 2.875% per annumpayable semi-annually in equal instalments in arrear on 27 June and 27 December each year,

commencing on 27 December 2007.

The Subscription Agreement contains representations, warranties and indemnities by Premier andPOFJL that are customary for such an agreement including, among others, warranties in relation to

the increase in Premier’s authorised share capital necessary for Premier to have available for issue and

authority to allot, free from pre-emption rights, sufficient but unissued ordinary shares to enable the

conversion and exchange rights attaching to the Bonds.

The Subscription Agreement gives the Joint Lead Managers such rights to terminate the Subscription

Agreement as are customary in such an agreement, including in circumstances where there is a

general moratorium on banking activities or where there is a suspension in trading in any of

Premier’s securities or the Bonds which would, in the Joint Managers’ view, be likely to prejudice

materially the success of the issue and offering of the Bonds or the distribution of the Bonds or

dealings in the Bonds in the secondary market.

The Subscription Agreement is governed by English law.

As envisaged in the Subscription Agreement, Premier entered the following contracts in respect of the

Bond issue:

(i) Trust Deed

The Trust Deed dated 27 June 2007 (the ‘‘Trust Deed’’) between POFJL, Premier and Deutsche

Trustee Company Limited (as Trustee). sets out, inter alia, (i) the form and terms and

conditions of the original definitive registered Bonds, (ii) the guarantee given by Premier and (iii)

the appointment of the Trustee, all in a manner as is customary in such deeds.

The terms and conditions of the Bonds are customary for securities of this nature. In particular:

* POFJL and Premier make a negative pledge that, so long as any Bond remains

outstanding, they will not create or permit to subsist any mortgage, charge or other form

of encumbrance or security interest unless approved by the Trustee, in its absolute

discretion,

* no transfer of a Bond will be valid unless and until entered on a register to be kept by

POFJL, and

* the Trustee at its discretion, and if so requested by holders of not less than 25% in

principal amount of the Bonds then outstanding or if so directed by an extraordinary

resolution of the bondholders, shall give notice in writing to POFJL that the Bonds are

due and payable at the principal amount together with accrued interest if any of the events

of default occur, which include, inter alia: non-payment on maturity for a period of seven

calendar days; non-payment of any interest due for a period of 14 calendar days; breach

by Premier or POFJL of any obligations in the Bonds or the Trust Deed not remediedwithin 30 days; and if insolvency or winding-up occur or are threatened by POFJL,

Premier or any material subsidiary.

In the Trust Deed, Premier unconditionally and irrevocably guarantees the due and punctualpayment of all sums from time to time payable by POFJL in respect of the Bonds and the due

and punctual performance by POFJL of all of POFJL’s other obligations in respect of the

Bonds. The guarantee constitutes an unsubordinated, direct, unconditional and (subject to terms

and conditions) unsecured obligation of Premier and shall, save for such exceptions as may be

provided by applicable law and subject to relevant conditions, at all times rank at least equally

with all its other present and future unsecured and unsubordinated obligations.

Premier’s obligations under the Trust Deed remain in full force until no sum remains payable

under the Trust Deed or the Bonds.

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The Trust Deed appoints the Trustee subject to such terms and conditions as are customary in

such deeds, including, among others, that moneys held by the Trustee may be invested in its

name, or under its control in any investments or other assets and in such currency as the

Trustee, in its absolute discretion, think fit.

The Trust Deed is governed by English law.

(ii) Paying, Transfer and Exchange Agency Agreement

The paying, transfer and exchange agency agreement dated 27 June 2007 (the ‘‘Agency

Agreement’’) between, amongst others, POFJL, Premier, Deutsche Bank (as the Paying, Transfer

and Exchange Agent) and Deutsche Trustee Company Limited (as the Trustee) sets out, inter

alia, the terms of appointment and duties of Deutsche Bank AG, London Branch in its capacity

as Paying, Transfer and Exchange Agent.

The Agency Agreement contains such terms and conditions as are customary in such anagreement.

As regards moneys held by the Paying, Transfer and Exchange Agent following payments in

respect of the Bonds, the Paying, Transfer and Exchange Agent may deal with moneys paid to

it under the Agency Agreement in the same manner as other moneys paid to it as a banker by

its customers except that: (i) it may not exercise any lien, right of set-off or similar claim in

respect of them; and, (ii) it shall not be liable to anyone for interest on any sums held by it

under the Agency Agreement. No money held by the Paying, Transfer and Exchange Agent

need be segregated except as required by law.

The Agency Agreement also sets out such powers of the Trustee as are customary in agreementsof this nature, including its capacity to insist that all moneys, documents and records in respect

of the Bonds are delivered to the Trustee if a potential event of default or an event of default

has occurred.

POFJL and Premier jointly and severally indemnify the Paying, Transfer and Exchange Agent

against any loss, liability, cost, action or expense which it may properly incur or which may be

made against it arising out of or in relation to or in connection with its appointment or the

exercise of its functions, except such as may result from a breach by it of the Agency

Agreement or its fraud, wilful default, negligence or bad faith.

POFJL and Premier may, with the prior written approval of the Trustee, at any time terminatethe appointment of the Paying, Transfer and Exchange Agent by giving it at least 60 days’

notice to that effect.

The Agency Agreement is governed by English law.

(iii) Deed Poll

The deed poll was executed on 27 June 2007 (the ‘‘Deed Poll’’) by Premier in favour of POFJL

and the holders of preference shares in the capital of POFJL.

Premier undertakes to POFJL and to each of the holders of preference shares in the capital of

POFJL, to the extent that the amounts due are not paid by POFJL, to make due and punctual

payment of all redemption monies, dividends and other amounts expressed to be payable inrespect of the preference shares in the capital of POFJL. The Deed Poll is a continuing

guarantee and remains in full force and effect until all redemption monies, dividends and other

amounts expressed to be payable have been paid in full.

The Deed Poll also sets out Premier’s purchase offer whereby Premier offers and undertakes to

each of the holders of preference shares in the capital of POFJL, and to POFJL, to purchase

the preference shares allotted and issued on the conversion of any Bond and, in consideration

for such purchase, to deliver fully paid ordinary shares in Premier to the holders of preference

shares in the capital of POFJL.

Furthermore, Premier also undertakes in the Deed Poll that it will, in the event of failure ofPOFJL to perform the same when due to be performed: (i) procure the performance by POFJL

of all obligations to be performed by POFJL; and, (ii) procure the enforcement by POFJL of all

POFJL’s rights, in either case, with respect to the exchange rights and share exchange rights of

holders of the Bonds.

The Deed Poll is governed by English law.

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(b) Existing Facility Agreement

POHL and PPPL entered into a credit facility agreement dated 13 September 2005 made between,

amongst others, Premier, Barclays Capital and Royal Bank of Scotland plc (as mandated leadarrangers), and Barclays Bank PLC (as the issuing bank and as facility agent), as amended and

restated by an amendment and restatement agreement dated 5 April 2007 and by further amendment

letters dated 22 June 2007 and 5 March 2008 (collectively, the ‘‘Existing Facility Agreement’’).

The Existing Facility Agreement provides a US$275 million revolving credit facility (‘‘Facility A’’)

and a £53 million revolving credit facility (‘‘Facility B’’), each with a final maturity date of 31 July

2010. The Existing Facility Agreement is guaranteed by certain members of the Group.

Facility A is available for general corporate purposes and may be utilised by way of the drawing of

loans or the issue of letters of credit. Facility B may only be utilised by way of the issue of letters of

credit, which may only be issued to Hess Limited (a subsidiary of Hess) in support of certainperformance obligations of PPPL in relation to the abandonment of the Scott Field.

A Facility A credit request must be in a minimum amount of US$5 million (or its equivalent in

Pounds Sterling). A Facility B credit request must be in a minimum amount of £3 million. Drawings

under the Existing Facility Agreement bear interest at the aggregate of (a) an agreed margin per

annum; (b) LIBOR; and (c) additional mandatory costs, if any, to cover regulatory or reserve

accounts. Interest on overdue amounts is charged at a rate of 1% above the rate at which loans are

drawn down or letters of credit are issued under the Existing Facility Agreement.

Premier may, by giving five business days’ prior notice, cancel the unutilised amount of the total

commitments in whole or in part. Partial cancellation of Facility A commitments must be in aminimum amount of US$10 million and an integral multiple of US$1 million. Partial cancellation of

the Facility B commitments must be in a minimum amount of £5 million and an integral multiple of

£1 million. In addition, the Existing Facility Agreement allows voluntary prepayment of Facility A

and Facility B, provided that each voluntary prepayment is a minimum of £5 million for drawings in

Pounds Sterling or US$10 million for drawings in US Dollars.

Mandatory prepayment may be required in certain circumstances, including on a change of control. A

‘change of control’ is defined in the Existing Facility Agreement as occurring if any person or group

of persons acting in concert gains control of Premier. If a change of control occurs, the majoritylenders may insist on prepayment if no agreement can be reached with Premier regarding the

continuation of Facility A and Facility B.

Each loan drawn under the Existing Facility Agreement must be repaid in full on its relevant

maturity date. In most cases, any amounts repaid may be re-borrowed. Each letter of credit issued

must be repaid in full on its maturity date or on 31 July 2010, whichever is earliest.

The Existing Facility Agreement contains customary representations and warranties and affirmative

and negative covenants. In particular, unless the lenders agree in writing, neither Premier nor any

other borrower or guarantor under the Existing Facility Agreement nor any subsidiaries may enter

into a merger or reconstruction otherwise than under an intra-Group re-organisation on a solventbasis. Coupled with this, neither Premier nor any of its subsidiaries may make any acquisition or

investment that is a Class 1 transaction subject to certain exceptions unless it is agreed to by the

lenders. This covenant will not be breached by the implementation of the Acquisition, as the Existing

Facility Agreement will be replaced by the New Credit Agreements.

The Existing Facility Agreement also requires, on a Group level, the maintenance of specified leverage

and interest cover ratios.

The Existing Facility Agreement contains certain customary events of default, including:

* any event or series of events which, in the opinion of the majority lenders (acting reasonably) is

likely to have a material adverse effect on the business or financial condition of the PremierGroup taken as a whole;

* a cross-default provision applicable if a debt, or an aggregate of debts, valued at US$10 million

or more is not paid when due (after the expiry of any grace period); and,

* the initiation of certain insolvency proceedings by Premier and/or any material subsidiary.

The Existing Facility Agreement is governed by English law.

All of Premier’s outstanding credits under the Existing Facility Agreement are to be repaid using the

proceeds of the New Credit Facilities (see below) if the Acquisition proceeds and the New Credit

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Facilities are utilised. However, it will remain in place if the consideration for the Acquisition is not

paid.

(c) Framework agreement

Premier entered into a framework agreement (the ‘‘Framework Agreement’’) dated 16 September 2002

between Premier, POGL, Petronas and Hess.

The parties to the Framework Agreement agreed to a restructuring of Premier and the shareholdingsof Hess and Petronas in Premier. In order to give effect to such restructuring, Premier agreed to

propose a scheme of arrangement and POGL agreed to propose a reduction of capital. The principal

practical effects of these measures provided for in the Framework Agreement were:

* the sale by the Premier Group of its entire interest in the Yetagun gas field, Myanmar to

Petronas, a 15% interest in Natuna Block ‘‘A’’, Indonesia to Petronas;

* the sale by the Premier Group of a 23% interest in the Natuna Block ‘‘A’’, Indonesia to Hess as

part of a restructuring which included the cancellation of Petronas’s and Hess’s shareholdings in

POGL; and

* the Company became the holding company of the Group.

The total implied consideration for the sale of interests was approximately US$670 million.

The Framework Agreement contains representations and warranties from POGL and Premiercustomary for such a share sale agreement which are given on an indemnity basis subject to

disclosures.

Petronas agreed to assume and discharge certain assurances given by members of the Group in

relation to obligations of the companies transferred, whereas POGL and Premier agreed to assume

and discharge certain assurances given by companies transferred in support of members of the Group.

POGL also agreed to indemnify Petronas against liabilities of Premier, Premier Petroleum Myannor

Limited (‘‘PPML’’) and Premier Overseas Holdings (Hong Kong) Limited (‘‘POHHKL’’) to the extent

such liabilities do not relate to the Yetagun gas field, and against any liabilities of PPML which may

arise as a result of its gross negligence as operator of the Yetagun gas field.

In the tax covenant referred to in the Framework Agreement, POGL and Premier also agreed,

amongst other things, to indemnify Petronas against the tax liabilities of PPML and POHHKL for all

periods up to 30 September 2002 and for any tax liabilities which arise as a result of transactions

provided for in the Framework Agreement.

While the period for making general warranty claims has now expired, there is a time limit of 10

years from completion for Hess or Petronas to bring tax warranty claims.

No individual warranty claim can be brought by Hess or Petronas for an amount less than

US$200,000 or until claims equal US$1,000,000. The aggregate cap on liability is equal to all amounts

paid by Hess or Petronas on completion and all amounts represented by the cancelled shares.

However, there is no cap on liability for the indemnities for any liabilities of PPML not relating toYetagun and any liability which may arise relating to PPML’s gross negligence as operator.

The Framework Agreement is governed by English law.

(d) Sale and Purchase Agreement

PPPL entered into a sale and purchase agreement (the ‘‘Sale and Purchase Agreement’’) with Hess

dated 30 March 2007 in relation to the purchase by PPPL of continental shelf petroleum licences,

including an interest in the Scott Field, and connected assets such as oil and drilling equipment.

The licences were sold by Hess with full title guarantee and free from all encumbrances, unless

disclosed.

The total consideration to be paid by PPPL under the Sale and Purchase Agreement was

US$60,130,000, subject to certain adjustments to be made following completion, such as an

adjustment to reflect the actual petroleum supply sales produced pursuant to the licences.

Letters of credit for approximately £52 million have been issued by banks and financial institutions atthe request of the Premier Group in favour of Hess, in respect of the obligations of PPPL under the

Sale and Purchase Agreement relating to such decommissioning costs.

The Sale and Purchase Agreement contains warranties, undertakings and indemnities to be given by

PPPL as purchaser as is customary for a transaction of this nature. In particular, PPPL indemnified

Hess for, and holds Hess and its agents harmless against, all environmental liabilities that may arise

242


or may have arisen in respect of the plant and equipment used for oil and gas drilling included as

part of the consideration. Coupled with this, the Sale and Purchase Agreement also includes an

indemnity from PPPL in respect of decommissioning costs in relation to the future abandonment of

the field.

Similarly, the Sale and Purchase Agreement also contains warranties given by Hess, as seller, as arecustomary for a transaction of this nature. For example, Hess warranted that it has all governmental

licences, permits, consents and permissions necessary to own the interests sold to PPPL, and

moreover, that such licences, permits, consents and permissions are in full force and effect and that

no material violations exist.

As regards ongoing obligations post-completion, PPPL agreed not to oppose any future application

by Hess for a release from its obligations and liabilities under the Petroleum Act 1998 (or other

relevant legislation).

None of the rights or obligations of PPPL or Hess under the Sale and Purchase Agreement may be

assigned without the prior consent of the other party.

The Sale and Purchase Agreement is governed by English law.

(e) Underwriting Agreement

The Company and the Underwriters entered into the Underwriting Agreement, dated 25 March 2009,pursuant to which the Underwriters have agreed severally, subject to certain conditions, to use

reasonable endeavours to procure subscribers for, or failing which, to subscribe in the Due

Underwriting Proportions for, the Underwritten Shares to the extent not taken up by Qualifying

Shareholders under the Rights Issue, in each case at the Rights Issue Price.

In consideration of the services to be provided by the Underwriters under the Underwriting

Agreement, the Company will pay to the Underwriters a commission of 3.5% of the value of the

Underwritten Shares at the Rights Issue Price (such amount being shared in the Due Underwriting

Proportions). Such commission shall be payable whether or not the Underwriters are required to

subscribe (or procure subscribers) for the Underwritten Shares, but shall be paid only in the event

that the Underwriting Agreement is not terminated and does not terminate prior to Admission. (Thecommission would have increased on a daily basis had this document not been dispatched to

Shareholders by 3 April 2009). If the Underwriting Agreement does terminate prior to Admission, the

Company will pay to the Underwriters a commission of 1.75% of the value of the Underwritten

Shares at the Rights Issue Price.

In addition to the commissions set out above (and whether or not the obligations of the Underwriters

become unconditional in all respects or this Agreement terminates or is terminated), the Company

shall pay all costs and expenses of, and in connection with, the Underwriting Agreement, the Rights

Issue, the Extraordinary General Meeting, the allotment, issue, registration and delivery of the Nil

Paid Rights or the New Ordinary Shares, the crediting of Nil Paid Rights to any stock account inCREST or the registration of New Ordinary Shares (including without limitation such part of any

such costs or expenses as relates to the VAT chargeable on any supply or supplies for which such

costs or expenses are all or any part of the consideration).

The obligations of the Underwriters under the Underwriting Agreement are subject to certain

conditions including, amongst others:

(a) the passing of the Resolutions at the Extraordinary General Meeting;

(b) Admission becoming effective on 21 April 2009 or such later time and/or date (being not later

than 8.00 a.m. on 6 May 2009) as the Company and the Underwriters may agree; and

(c) the fulfilment by the Company of certain of its obligations under the Underwriting Agreement,

including the delivery of certain documents to Deutsche Bank, by the times and dates specified

in the Underwriting Agreement.

No Underwriter is entitled to terminate the Underwriting Agreement after Admission. However, prior

to Admission, any Underwriter may terminate the Underwriting Agreement in certain circumstances,

including if (i) any statement contained in this document, or certain related documents andannouncements has become or been discovered to by untrue, inaccurate or misleading in any material

respect; (ii) an event occurs or a circumstance arises such that section 87G(2) applies pursuant to

section 87G(1) of, in each case, the Financial Services and Markets Act 2000 (as amended); (iii) there

has been a breach by the Company of any of the representations, warranties or undertakings in the

Underwriting Agreement or any of the same were untrue or inaccurate or misleading when made

243


which in any such case, Deutsche Bank (on behalf of the Underwriters) considers to be material in

the context (inter alia) of the Rights Issue; (iv) there has occurred any event which has or will result

in a material adverse change in or affecting the operations, condition, or prospects of the Group

taken as a whole, or in the Target which is material in the context of the Enlarged Group; or (v)certain other force majeure events, including any material changes in national or international

financial, political, economic or stock market conditions, or any war or act of terrorism, in each case

in this sub-paragraph (v) which in the opinion of Deutsche Bank (on behalf of the Underwriters)

after consultation with the Company, would cause the Rights Issue to be impracticable, inappropriate

or inadvisable.

The parties to the Underwriting Agreement have agreed that if a supplementary prospectus is issued

by the Company two or fewer Business Days prior to the date specified in this document as being the

last date for acceptance and payment in full under the Rights Issue (or such later date as may be

agreed between the parties), such date shall be extended to the date which is three Business Daysafter the date of issue of the supplementary prospectus.

The Company has given certain warranties and indemnities to the Underwriters. The liabilities of the

Company are unlimited as to time and amount.

(f) New Credit Agreements

The Company has entered into the New Credit Agreements, being:

(a) a US$175 million term bridge facility agreement dated 25 March 2009 (‘‘Bridge Facility

Agreement’’); and

(b) a US$225 million 3-year revolving credit facility and US$63 million and £60 million 3-year letter

of credit facilities agreement dated 25 March 2009 (‘‘Medium Term Credit Facilities

Agreements’’).

The bridge facility made available under the Bridge Facility Agreement (‘‘Bridge Facility’’) has a

maximum term of eighteen months. The Medium Term Credit Facilities Agreements provide three

facilities: a US$225 million revolving credit facility (‘‘Revolving Facility’’) and US$63 million and £60

million letter of credit facilities (‘‘Letter of Credit Facilities’’).

The New Credit Agreements are conditional on the Acquisition proceeding. The New CreditAgreements are arranged by Barclays Capital (the investment banking division of Barclays Bank

PLC), HSBC Bank plc, Lloyds TSB Corporate Markets (the corporate markets division of Lloyds

TSB Bank plc), Royal Bank of Canada and The Bank of Tokyo-Mitsubishi UFJ, Ltd and the

original lenders under the facilities are Barclays Bank PLC, HSBC Bank plc, Lloyds TSB Bank plc,

Royal Bank of Canada and The Bank of Tokyo-Mitsubishi UFJ, Ltd.

The Bridge Facility and the Revolving Facility are available to finance amounts payable in respect of

the Acquisition, the refinancing of the Existing Facility Agreement and (in the case of the Revolving

Facility) for general corporate purposes. The Letter of Credit Facilities are available to issue certain

letters of credit specified in the Medium Term Credit Facilities Agreements or to issue cash collateral.

Drawings under the New Credit Agreements bear interest at the aggregate of (a) an agreed margin

per annum; (b) LIBOR; and (c) additional mandatory costs, if any, to cover regulatory or reserveaccounts. The margin in respect of the Bridge Facility is initially 3.50% per annum and is subject to a

ratchet, increasing by agreed amounts after agreed periods. The initial margin in respect of the

Revolving Facility is 3.50% per annum and going forward it is to be determined by reference to a

leverage-based margin ratchet. The initial margin in respect of cash borrowings under the Letter of

Credit Facilities is 3.50% per annum but it is also subject to a leverage-based margin ratchet. Interest

on overdue amounts is charged at a rate of 1.00% per annum above the rate at which loans are

drawn down or letters of credit are issued under the New Credit Agreements. Certain fees are

payable in connection with the facilities, including a fee determined by reference to the period of timeduring which amounts remain outstanding under the Bridge Facility and letter of credit commission

in respect of letters of credit issued under the Letters of Credit Facilities at a rate of 3.50% per

annum.

The Company and various members of the Group are required to guarantee the payment obligations

of each borrower under the New Credit Agreements and to grant various indemnities.

The New Credit Agreements allow voluntary prepayment. Each loan drawn down under the facilities

must be repaid in full on its relevant maturity date.

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The New Credit Agreements contain certain mandatory prepayment events requiring the facilities to

be immediately prepaid in full. These events include the occurrence of a change of control of the

Company (which will occur if any person or group of persons acting in concert gains control of the

Company). The Bridge Facility Agreement contains additional mandatory prepayment requirements inrespect of the proceeds of refinancings, disposals, insurance claims, and claims in respect of the

Acquisition.

The New Credit Agreements include events of default which will entitle the financiers to terminate thefacilities and demand immediate repayment. The New Credit Agreements also contain customary

representations and warranties, affirmative and negative covenants, and conditions precedent. The

financial covenants include specified leverage and interest cover ratios.

The Company has also entered into certain refinancing arrangements in connection with the NewCredit Agreements. These include an obligation on the Company to, if required by the financiers at

any time after the period commencing four months after Completion and where the Company has

not been able to demonstrate that the Bridge Facility will be refinanced by other means, take steps to

issue and sell certain securities to refinance the Bridge Facility subject to certain parameters agreed

with the financiers.

The New Credit Agreements will only become available if the Acquisition is proceeding.

13. MATERIAL CONTRACTS OF ONSL

In addition to the Asset Acquisition Agreement, which has been summarised in Part V of this

document, the following contracts are the only other contracts (not being contracts entered into in

the ordinary course of business): (i) which ONSL has entered into within the two years immediately

preceding the date of this document which are or may be material; or (ii) which have been entered

into by ONSL at any other time and which contain provisions under which ONSL has an obligationor entitlement that is material to ONSL as at the date of this document:

* a US$500 million senior secured borrowing base facility between ONSL as borrower, Oilexco

Inc. as guarantor and Royal Bank of Scotland plc as arranger;

* a US$47.5 million supplementary senior facility between ONSL as borrower, Oilexco Inc. as

guarantor and Royal Bank of Scotland plc as arranger; and

* a £100 million pre-development facility between ONSL as borrower, Oilexco Inc. as guarantor

and Royal Bank of Scotland plc as arranger restated 26 February 2007.

Each of these agreements will either be terminated prior to Completion (if the Share Acquisition

proceeds) or will not be acquired by Premier under the Asset Acquisition.

14. SIGNIFICANT SUBSIDIARIES

The Company acts as the holding company of the Group. The Company holds (directly or indirectly)

interests in the capital of the following undertakings, being those which are considered by the

Company to be likely to have a significant effect on the assessment of the Company’s assets and

liabilities, financial position or profits and losses. Each of these companies is a wholly-owned

subsidiary of the Group and the issued share capital is fully paid. Unless otherwise stated, theregistered office of all companies registered in Scotland is 4th Floor, Saltire Court, 20 Castle Terrace,

Edinburgh EH1 2EN; the registered address of all companies registered in England and Wales is 23

Lower Belgrave Street, London SW1W 0NR; and the registered address of all companies registered in

The Netherlands is Prinsenhof Building 19th Floor, Prinses Margrietplantsoen 76, The Hague 2595

BR, The Netherlands.

Name

Country of

Incorporation Principal Activity

Interest in Share

Capital

Premier Oil Group Limited Scotland Holding Company 100%

Premier Oil Finance (Jersey) Limited Jersey

(Registered office:

22 Grenville Street

St. Helier, Jersey,

JE4 8PX)

Finance Company 100%

Premier Oil Exploration Limited Scotland Operating Company 100%

Premier Oil Holdings Limited England & Wales Holding Company 100%

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Name

Country of

Incorporation Principal Activity

Interest in Share

Capital

Premier Pict Petroleum Limited Scotland Operating Company 100%

Premier Oil Sumatra (North) B.V. The Netherlands Operating Company 100%

Premier Oil Vietnam Offshore B.V. The Netherlands Operating Company 100%

Premier Oil Kakap B.V. The Netherlands Operating Company 100%

Premier Oil Natuna Sea B.V. The Netherlands Operating Company 100%

PKP Exploration Limited England & Wales Operating Company 100%

PKP Kadanwari 2 Limited Cayman Islands Operating Company 100%

PKP Kirthar 2 B.V. The Netherlands Operating Company 100%

Premier Oil Mauritania B Limited Jersey

(Registered office:

12 Castle Street,

St Helier

Jersey JE2 3RT)

Operating Company 100%

FP Mauritania B B.V. The Netherlands Operating Company 100%

15. PROPERTY, PLANT AND EQUIPMENT

(a) Principal establishments

The Group has the following principal establishment:

Property address Current use Description and tenure Current rent

23 Lower Belgrave Street,London SW1W 0NR

Office Leasehold – expires13/10/2014

£925,000 p.a.

(b) Environmental issues

There are no environmental issues that may affect the Group’s utilisation of its properties.

16. GENERAL

(a) Dividend policy

Premier’s policy is to reward Shareholders principally through share price growth and to utilise cash

flows within the business.

(b) Expenses

The expenses of the Rights Issue and the Acquisition payable by the Company are approximately £26

million.

(c) Expert reports

Deloitte LLP is a member firm of the Institute of Chartered Accountants in England and Wales and

its principal place of business and registered office is at 2 New Street Square, London EC1Y 8YY.

RISC is a mineral expert and its business address is at Golden Cross House, 8 Duncannon Street,

London WC2N 4JF.

(d) Financial Information

The financial information contained in this document which relates to the Company and/or the

Group does not constitute statutory accounts within the meaning of section 435 of the Companies

Act 2006. Statutory accounts for the years ended 31 December 2006, 2007 and 2008 have been

delivered to the Companies Registry, and each included an unqualified audit report.

17. SOURCES OF INFORMATION

In this document, unless otherwise stated or the context otherwise requires, the following sources and

bases of information have been used:

* All figures in this document stating an amount of reserves and production for Premier are

Board estimates, prepared on the same basis as for Premier’s report and accounts. Premier has

internal procedures for preparing such figures, which include field-by-field review, geotechnical

246


analysis, relevant experience in assessing fields of similar geological structures and obtaining an

independent certification of reserves from a third party. In most cases (and, in particular, in

relation to overall numbers), the Board estimates are lower and/or more conservative that the

figures that are independently certified.

* In relation to ONSL, in addition to the figures in the Competent Person’s Report, Premier hasincluded in this document figures representing the Board’s estimates of ONSL’s aggregate

reserves and production. In making these estimates, the Board has followed the same internal

procedures as described above in relation to its own reserves and production (including its own

field-by field reviews, geotechnical analysis and relevant experience in assessing fields of similar

geological structures), and has used the Competent Person’s Report as part of this process of

review. This is in line with the procedures it will follow when producing the first set of accounts

for the Enlarged Group. The aggregate Board estimates for ONSL are lower than the equivalent

figures set out in the Competent Person’s Report.

* Production numbers, throughout this document, are based on full-year production (to beadjusted depending on date of completion); figures do not include Shelley.

* The purchase price equivalent to less than US$8.50/bbl is calculated as acquisition price divided

by 2P reserves and contingent resources of 60 mmboe.

* Net asset value of proved plus probable reserves is based on RISC’s economic analysis of the

net NPV of discounted cash flows at a 10% discount rate using forward curve oil prices, taking

into account future production estimates of assessed reserves/resources and forecasts of future

capital and operating costs.

* The enterprise value for Oilexco Inc. is based on the market value of Oilexco Inc.’s shares as at

30 September 2008 of US$2.2 billion sourced from Thomson Datastream plus net debt of

US$0.5 billion as at the same date sourced from Oilexco Inc.’s interim report for the nine

months ended 30 September 2008.

* The figure of 385 mmboe for unrisked prospective oil resources is an internal Oilexco Inc.estimate and has not been verified by RISC.

* The working interest production figure for ONSL for the period from 7 January 2009 to

23 March 2009 has been provided by the Administrators.

* The cash constituent of the US$385 million of liquidity at Completion has been sourced from

Premier’s internal management accounts as at 28 February 2009

Premier confirms that where information has been sourced from a third party, that information has

been accurately reproduced and, as far as the Directors are aware and are able to ascertain from

information published by that third party, no facts have been omitted which would render the

reproduced information inaccurate or misleading.

18. CONSENTS

(a) Deutsche Bank

Deutsche Bank has given and not withdrawn its written consent to the issue of this document and

the references herein to its name in the form and context in which they appear.

(b) Oriel

Oriel has given and not withdrawn its written consent to the issue of this document and the

references herein to its name in the form and context in which they appear.

(c) Deloitte LLP

Deloitte LLP has given and not withdrawn its written consent to the inclusion in Parts XII and XIII

of this document of its reports and the references to its reports and its name in the form and context

in which they appear, and has authorised the contents of those reports for the purposes of Prospectus

Rule 5.5.3R(2)(F).

(d) RISC

RISC has given and not withdrawn its written consent to the inclusion in Part XIV of this document

of its report, and the references to its report and its name in the form and context in which they

appear, and has authorised the contents of that report for the purposes of Prospectus Rule

5.5.3R(2)(f).

247


19. DOCUMENTS AVAILABLE FOR INSPECTION

Copies of the following documents are available for inspection at the offices of Slaughter and May,

One Bunhill Row, London EC1Y 8YY during normal business hours (i.e. 9.30 a.m. to 5.30 p.m.) onBusiness Days up to and including the date of the Extraordinary General Meeting:

(a) a copy of this document;

(b) the Memorandum and Articles of Association;

(c) the Acquisition Agreements and the related Deed of Guarantee;

(d) the written consents referred to in paragraph 18 above;

(e) the accounts described in Part XI of this document;

(f) the unaudited pro forma statement set out in Part XIII and the reports from Deloitte LLP set

out in Parts XII and XIII of this document; and

(g) the Competent Person’s Report set out in Part XIV of this document.

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PART XVII

DOCUMENTATION INCORPORATED BY REFERENCE

The following information, available free of charge from Premier’s head office at 23 Lower Belgrave

Street, London SW1W 0NR, is incorporated by reference into this document:

Information that is itself incorporated by reference in the above documents is not incorporated by

reference into this document.

Information incorporated by reference Reference document

Section heading/

page number

‘‘Premier’s audited financial statements and the

notes explaining the financial statements’’

Annual Report and Accounts –

Year to 31 December 2006

Financial

Statements





Financial

Statements





Financial

Statements

‘‘Audited balance sheet of Premier’’ Annual Report and Accounts –


Financial

Statements

‘‘Financial information relating to the Group’’ Annual Report and Accounts –


Financial

statements



Financial

statements



Financial

Statements

‘‘Financial information in respect of Premier’’ Annual Report and Accounts –


Financial

Statements

‘‘Remuneration paid and benefits in kind

granted to the Directors’’



Remuneration

Report

‘‘Retirement benefits of the Directors’’ Annual Report and Accounts –


Remuneration

Report

‘‘Directors’ interests in share options, bonus

shares, deferred and matching share awards’’



Remuneration

Report

‘‘Average number of employees of the Group’’ Annual Report and Accounts –Year to 31 December 2006

FinancialStatements (Note 4)





‘‘Share option schemes’’ Annual Report and Accounts –


Remuneration

Report

‘‘Related party transactions’’ Annual Report and Accounts –


Financial

Statements(Note 26)

‘‘Related party transactions’’ Annual Report and Accounts –Year to 31 December 2007

FinancialStatements

(Note 26)

‘‘Related party transactions’’ Annual Report and Accounts –Year to 31 December 2008

FinancialStatements

(Note 25)

249


PART XVIII

DEFINITIONS

The definitions set out below apply throughout this document, unless the context requires otherwise.

‘‘$US/bbl’’ US$ per barrel;

‘‘2D’’ two dimensional;

‘‘3D’’ three dimensional;

‘‘2P’’ proved and probable;

‘‘ACQ’’ Annual Contract Quarterly;

‘‘Acquisition’’ the Share Acquisition and/or the Asset Acquisition details of which

are set out in Part V;

‘‘Acquisition Agreements’’ the Share Acquisition Agreement and the Asset Acquisition

Agreement;

‘‘Administrators’’ Roy Bailey, Alan Robert Bloom, Colin Peter Dempster and

Thomas Merchant Burton, each of Ernst & Young LLP of

1 More London Place, London SE1 2AF;

‘‘Admission’’ admission of the New Ordinary Shares, nil paid, to the Official List

and to trading on the main market for listed securities of theLondon Stock Exchange;

‘‘Announcement’’ means the announcement of the Acquisition and the Rights Issue

made by the Company on 25 March 2009;

‘‘APA’’ awards in pre-defined areas on the Norwegian Continental Shelf;

‘‘API’’ American Petroleum Institute;

‘‘American Depositary Shares’’ Ordinary Shares held through Premier’s American Depositary

Receipt programme;

‘‘Articles’’ or ‘‘Articles of

Association’’

the articles of association of the Company in force from time to

time, details of which are set out in paragraph 9 of Part XVI;

‘‘Asset Acquisition’’ the proposed purchase of ONSL Assets as described in Part V of

this document;

‘‘Asset Acquisition Agreement’’ the conditional asset acquisition agreement dated 25 March 2009between the Company and ONSL and ONSEL relating to the Asset

Acquisition and described in Part V of this document;

‘‘Assets’’ or ‘‘ONSL Assets’’ all of the principal assets of ONSL (including the entire issued share

capital of ONSEL), except for those assets which are subject to pre-

emption rights where these rights are exercised;

‘‘Barclays’’ Barclays Bank PLC;

‘‘Barclays Capital’’ the investment banking division of Barclays;

‘‘bbls’’ barrels;

‘‘BBtud’’ billion British thermal units per day;

‘‘bcf’’ billion cubic feet;

‘‘boe’’ barrels of oil equivalent;

‘‘boepd’’ barrels of oil equivalent per day;

‘‘bopd’’ barrels of oil per day;

‘‘bscf’’ billion standard cubic feet;

‘‘Business Day’’ any day on which banks are generally open in London for the

transaction of business other than a Saturday or Sunday or publicholiday;

‘‘Capita Registrars’’ the trading name of the Registrar;

250


‘‘certificated’’ or ‘‘in certificated

form’’

a share or other security which is not in uncertificated form (that is,

not in CREST);

‘‘City Code’’ the UK City Code on Takeovers and Mergers;

‘‘Closing Price’’ the closing, middle market quotation of an Ordinary Share on24 March 2009 (the latest practicable date prior to the

Announcement), as published in the Daily Official List;

‘‘Combined Code’’ the Combined Code on Corporate Governance of the Financial

Reporting Council 2006;

‘‘Companies Act 1985’’ the Companies Act of England and Wales 1985, as amended;

‘‘Companies Act 2006’’ the Companies Act of England and Wales 2006, as amended;

‘‘Competent Person’s Report’’ the report by RISC contained in Part XIV of this document;

‘‘Completion’’ completion of the Acquisition;

‘‘Consideration’’ the consideration payable under the Share Acquisition Agreement

or the Asset Acquisition Agreement (as applicable);

‘‘Convertible Bonds’’ the US$250,000,000 2.875% guaranteed convertible bonds issued

by POFJL pursuant to a subscription agreement dated 30 May

2007, details of which are set out in paragraph 12(a) of Part XVI;

‘‘CVA’’ or ‘‘Company Voluntary

Agreement’’

the company voluntary arrangement procedure in relation to

ONSL, details of which are set out in Part VI of this document;

‘‘Daily Official List’’ the daily official list of the London Stock Exchange;

‘‘Deed of Guarantee’’ the deed of guarantee entered into by the Company in respect of the

Share Purchase Agreement and the Asset Purchase Agreement;

‘‘Deutsche Bank’’ Deutsche Bank AG;

‘‘Directors’’ or ‘‘Board’’ the directors of the Company whose names are set out on page 19

of this document;

‘‘Disclosure Rules and

Transparency Rules’’

the disclosure rules and transparency rules made under Part VI of

FSMA (as set out in the FSA Handbook), as amended;

‘‘Due Underwriting Proportions’’ the proportions in which the Underwriters have severally agreed tounderwrite;

‘‘E&P’’ Exploration and Production;

‘‘EBITDA’’ earnings before interest, taxation, depreciation and amortisation;

‘‘EBITDAX’’ earnings before interest, taxation, depreciation, depletion,

amortisation and exploration expenses;

‘‘EEA States’’ a state which is a contracting party to the agreement on the

European Economic Area signed at Oporto on 2 May 1992, as it

has effect for the time being;

‘‘Enlarged Group’’ the Company together with its subsidiaries and subsidiary

undertakings, as enlarged by the Acquisition;

‘‘EPCI’’ Engineering, Procurement, Construction and Installation;

‘‘EU’’ the European Union, first established by the treaty made at

Maastricht on 7 February 1992;

‘‘Euroclear UK’’ Euroclear UK & Ireland Limited;

‘‘Exchange Act’’ the US Securities Exchange Act of 1934, as amended;

‘‘Exchange Information’’ certain business and financial information which the Company is

required to publish in accordance with the rules and practices of theUK Listing Authority and the London Stock Exchange;

‘‘Excluded Overseas Shareholders’’ (other than as agreed in writing by the Company and the

Underwriters and as permitted by applicable law) Shareholders

who are listed in or who have a registered address in an Excluded

Territory;

251


‘‘Excluded Territories’’ the United States, Australia, Canada, New Zealand, the State of

Israel, Dubai International Finance Centre, the Republic of South

Africa and any other jurisdiction where the extension or availability

of the Rights Issue (and any other transaction contemplatedthereby) would breach any applicable law;

‘‘Existing Ordinary Share’’ an existing issued Ordinary Share prior to the Rights Issue;

‘‘Extraordinary General Meeting’’

or ‘‘EGM’’

the extraordinary general meeting of the Company to be convened

pursuant to the notice set out at the end of this document (including

any adjournment thereof);

‘‘Form of Proxy’’ the form of proxy for use at the Extraordinary General Meeting

which accompanies this document;

‘‘FPSO’’ Floating Production, Storage and Offloading Vessel;

‘‘FPV’’ Floating Production Vessel;

‘‘FSA’’ the Financial Services Authority of the United Kingdom;

‘‘FSMA’’ the Financial Services and Markets Act 2000;

‘‘Fully Paid Rights’’ rights to acquire New Ordinary Shares, fully paid;

‘‘GSA’’ Gas Sales Agreement;

‘‘GPSA’’ Gas Sales and Purchase Agreement;

‘‘Group’’ the Company together with its subsidiaries and subsdiary

undertakings, prior to the Acquisition;

‘‘HCV’’ High Calorific Value;

‘‘HMRC’’ HM Revenue and Customs;

‘‘HPHT’’ High Pressure High Temperature;

‘‘HSBC’’ HSBC Bank plc;

‘‘HSFO’’ High Sulphur Fuel Oil;

‘‘IFRS’’ International Financial Reporting Standards;

‘‘kboepd’’ thousand barrels of oil equivalent per day;

‘‘Listing Rules’’ the listing rules made under Part VI of FSMA (as set out in the

FSA Handbook), as amended;

‘‘London Stock Exchange’’ London Stock Exchange plc or its successor(s);

‘‘mcf’’ million cubic feet;

‘‘MCV’’ Medium Calorific Value;

‘‘Memorandum and Articles of

Association’’

the memorandum and articles of association of the Company;

‘‘Memorandum of Association’’ the memorandum of association of the Company details of which

are set out in paragraph 9 of Part XVI;

‘‘mmbl’’ million barrels;

‘‘mmbo’’ million barrels of oil;

‘‘mmboe’’ million barrels of oil equivalent;

‘‘MMBtu’’ million British thermal units per day;

‘‘mmcfd’’ million cubic feet per day;

‘‘mmscf’’ million standard cubic feet;

‘‘mmscfd’’ million standard cubic feet per day;

‘‘mscf’’ thousand standard cubic feet;

‘‘New Credit Agreements’’ the agreements relating to the New Credit Facilities;

‘‘New Credit Facilities’’ the US$175 million 18-month acquisition bridge facility, the

US$225 million 3-year revolving credit facility and US$63 million

252


and £60 million 3-year letter of credit facilities to be made available

pursuant to the New Credit Agreements;

‘‘New Ordinary Shares’’ the Ordinary Shares to be issued pursuant to the Rights Issue,

comprising the 35,276,566 Underwritten Shares and up to a further8,111,100 New Ordinary Shares if all options outstanding under the

Premier Share Option Schemes and all Convertible Bonds are

exercised or converted;

‘‘Nil Paid Rights’’ rights to acquire New Ordinary Shares, nil paid;

‘‘Official List’’ the official list of the UK Listing Authority;

‘‘Oilexco’’ Oilexco Inc.;

‘‘ONSEL’’ Oilexco North Sea Exploration Limited;

‘‘ONSL’’ Oilexco North Sea Limited (in administration) and, where thecontext so requires, ONSEL;

‘‘Ordinary Shares’’ ordinary shares with a nominal value of 50 pence each in the capital

of the Company and/or New Ordinary Shares, as the context

requires;

‘‘Oriel’’ means Oriel Securities Limited when used in connection with the

role of Joint Sponsor, Joint Broker and Co-Lead Manager and

Oriel Securities Limited (in association with Scotiabank Europe

plc) when used in connection with the role of Underwriter;

‘‘Overseas Shareholders’’ Shareholders with registered addresses outside the UK or who are

citizens of, incorporated in, registered in or otherwise resident in,

countries outside the UK;

‘‘POEL’’ Premier Oil Exploration Limited;

‘‘POGL’’ Premier Oil Group Limited;

‘‘POFJL’’ Premier Oil Finance (Jersey) Limited;

‘‘POHL’’ Premier Oil Holdings Limited;

‘‘POOBV’’ Premier Oil Overseas B.V.;

‘‘Pounds Sterling’’ or ‘‘£’’ the lawful currency of the United Kingdom;

‘‘PPPL’’ Premier Pict Petroleum Limited;

‘‘Premier’’ or ‘‘the Company’’ Premier Oil plc, a company incorporated in Scotland with

registered number SC234781, whose registered office is at 4th

Floor, Saltire Court, 20 Castle Terrace, Edinburgh EH1 2EN;

‘‘Premier Group’’ or

‘‘the Group’’

the Company together with its subsidiaries and subsidiary

undertakings;

‘‘Premier Share Option Schemes’’ means the option schemes referred to in paragraph 6(b) of Part XVIof this document;

‘‘Proposed Director’’ Andrew Lodge, details of whom are provided in paragraph 3 of

Part XVI of this document;

‘‘Prospectus Rules’’ the prospectus rules made under Part VI of FSMA (as set out in the

FSA Handbook), as amended;

‘‘Provisional Allotment Letter’’ the provisional allotment letter issued to Qualifying Non-CREST

Shareholders;

‘‘PSC’’ Production Sharing Contract;

‘‘psi’’ pounds per square inch;

‘‘psia’’ pounds per square inch pressure absolute;

‘‘Qualified Institutional Buyer’’ or

‘‘QIB’’

has the meaning ascribed to it by Rule 144A;

‘‘Qualifying CREST Shareholder’’ Qualifying Shareholders holding Ordinary Shares in uncertificated

form;

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‘‘Qualifying Non-CREST

Shareholders’’

Qualifying Shareholders holding Ordinary Shares in certificated

form;

‘‘Qualifying Shareholders’’ holders of Ordinary Shares on the register of members of the

Company on the Record Date;

‘‘RBC’’ or ‘‘RBC Capital

Markets’’

Royal Bank of Canada Europe Limited;

‘‘Receiver’’ means Roy Bailey and Alan Robert Bloom, appointed as receivers

pursuant to the terms of the Share Charge;

‘‘Receiving Agent’’ Capita Registrars Limited, The Registry, 34 Beckenham Road,

Beckenham, Kent BR3 4TU;

‘‘Record Date’’ 6.00 p.m. (London time) on 16 April 2009;

‘‘Registrar’’ Capita Registrars Limited, The Registry, 34 Beckenham Road,Beckenham, Kent BR3 4TU;

‘‘Registrar of Companies’’ the Registrar of Companies in England and Wales;

‘‘Regulation S’’ Regulation S under the US Securities Act;

‘‘Regulatory Information Service’’ one of the regulatory information services authorised by the UK

Listing Authority to receive, process and disseminate regulatory

information from listed companies;

‘‘Resolutions’’ the resolutions to be proposed at the Extraordinary General

Meeting;

‘‘Rights Issue’’ the proposed offer by way of rights to Qualifying Shareholders to

acquire New Ordinary Shares, on the terms and conditions set out

in this document and, in the case of Qualifying Non-CREST

Shareholders only, the Provisional Allotment Letter;

‘‘Rights Issue Price’’ the issue price for the New Ordinary Shares pursuant to the Rights

Issue;

‘‘RISC’’ RISC (UK) Limited;

‘‘RTGS’’ Real time gross settlement;

‘‘Rule 144A’’ Rule 144A under the US Securities Act;

‘‘SADR’’ Saharawi Arab Democratic Republic;

‘‘SDRT’’ stamp duty reserve tax;

‘‘SEC’’ United States Securities and Exchange Commission, the

government agency having primary responsibility for enforcing

US federal securities laws and regulating the securities industry/

stock market of the United States;

‘‘Settlement Amount’’ means the settlement amount payable under the Share AcquisitionAgreement, as described in Part V of this document;

‘‘Share Acquisition’’ the proposed purchase of ONSL Shares as described in Part V of

this document;

‘‘Share Acquisition Agreement’’ the conditional share acquisition agreement dated 25 March 2009

between the Company and the Receiver relating to the Share

Acquisition and described in Part V of this document;

‘‘Share Charge’’ means the share charge dated 25 January 2006 between (i) Oilexco

Inc. and (ii) Royal Bank of Scotland plc (as security trustee) andconfirmed by deed dated 19 October 2007;

‘‘Shareholder(s)’’ holder(s) of Ordinary Shares;

‘‘Shares’’ or ‘‘ONSL Shares’’ the entire issue share capital of ONSL;

‘‘stock account’’ an account within a member account in CREST to which a holding

of a particular share or other security in CREST is credited;

‘‘TBtu’’ trillion British thermal units;

254


‘‘tcf’’ trillion cubic feet;

‘‘therm’’ unit of energy defined as 105 British thermal units; equivalent to

1.055 6 108 J;

‘‘UKCS’’ United Kingdom Continental Shelf;

‘‘UK Listing Authority’’ the FSA acting in its capacity as the competent authority for the

purposes of FSMA;

‘‘uncertificated’’ or

‘‘in uncertificated form’’

a share or other security recorded on the relevant register of the

share or security concerned as being held in uncertificated form in

CREST and title to which by virtue of the CREST Regulations,

may be transferred by means of CREST;

‘‘Underwriters’’ Deutsche Bank, Oriel, Barclays, HSBC and RBC;

‘‘Underwriting Agreement’’ the conditional underwriting agreement dated 25 March 2009

between the Company and the Underwriters relating to the Rights

Issue and described in paragraph 12(e) of Part XVI of this

document;

‘‘Underwritten Shares’’ or ‘‘Rights

Issue Shares’’

means the 35,276,566 New Ordinary Shares to be issued in the

Rights Issue and underwritten by the Underwriters;

‘‘United Kingdom’’ or ‘‘UK’’ the United Kingdom of Great Britain and Northern Ireland;

‘‘United States’’ or ‘‘US’’ the United States of America, its territories and possessions, any

state of the United States and the District of Columbia;

‘‘US$’’, ‘‘US Dollars’’, ‘‘$US’’ or

‘‘$’’

the lawful currency of the United States;

‘‘US Securities Act’’ the US Securities Act of 1933, as amended; and

‘‘VAT’’ value added tax.

Dated 3 April 2009

255


NOTICE OF EXTRAORDINARY GENERAL MEETING

PREMIER OIL PLC(Incorporated in Scotland with registered number SC234781)

NOTICE IS HEREBY GIVEN that an Extraordinary General Meeting of Premier Oil plc (the‘‘Company’’) will be held at the offices of Deutsche Bank, Winchester House, 1 Great Winchester

Street, London EC2N 2DB on 20 April 2009 at 10.00 a.m. for the purposes of considering and, if

thought fit, passing the resolutions set out below. Words and expressions defined in the prospectus of

the Company dated 3 April 2009 (a copy of which has been produced to the meeting and initialled

by the chairman of the meeting for the purpose of identification only (the ‘‘Prospectus’’)) shall, unless

otherwise defined herein, have the same meaning in this Notice.

As ordinary resolutions:

1. THAT the Acquisition by the Company of: (i) the entire issued share capital of ONSL pursuant

to the Share Acquisition Agreement, or, in the alternative, (ii) the principal assets (subject to

exercise of pre-emption rights) of ONSL (including the entire issued share capital of ONSEL)

pursuant to the Asset Acquisition Agreement, and all agreements and arrangements made or

entered into, or which may in the future be made or entered into, by the Company or any of its

subsidiaries in connection with, or which are ancillary to, the Acquisition including the Share

Acquisition Agreement and/or the Asset Acquisition Agreement, be and are hereby approvedand that the directors (or any duly constituted committee thereof) of the Company be and are

hereby authorised to make any non-material amendment, variation, waiver or extension to the

terms or conditions of the Acquisition, the Share Acquisition Agreement, the Asset Acquisition

Agreement and/or any ancillary agreement which the directors (or any duly constituted

committee thereof) consider necessary, desirable or expedient and to do all such other things as

they may consider necessary, desirable or expedient in connection with the Acquisition.

2. THAT, subject to the approval of resolution 1 above and conditional upon the Underwriting

Agreement having become unconditional in all respects save for any condition relating to

Admission having occurred, for the purposes of section 80 of the Companies Act 1985 (the

‘‘Act’’), in substitution for all subsisting authorities conferred pursuant to that section, the

directors be and are hereby unconditionally and generally authorised to exercise all powers of

the Company to allot relevant securities (as defined in section 80(2) of the Act) of the Company

up to (i) an aggregate nominal amount of £17,638,283 in connection with the Rights Issue, and

(ii) otherwise an additional aggregate nominal amount of £19,108,140. This authority will expireat the conclusion of the next annual general meeting of the Company or, if earlier, 30 September

2009, unless previously revoked or varied by the Company in general meeting. However, before

this authority expires, the Company may make an offer or agreement which would or might

require relevant securities to be allotted after such expiry and the directors may allot relevant

securities under such an offer or agreement as if the authority conferred hereby had not expired.

As a special resolution:

3. THAT, subject to the approval of resolutions 1 and 2 above, the directors of the Company beand are hereby empowered, pursuant to section 95 of the Act and in substitution for all

subsisting authorities conferred pursuant to that section, to allot equity securities (within the

meaning of section 94 of the Act) for cash pursuant to the authority conferred by resolution 2

above as if sub-section (1) of section 89 of the Act did not apply to any such allotment,

PROVIDED THAT this power shall be limited to:

(a) the allotment of equity securities in connection with (i) the Rights Issue, or (ii) any other

rights issue, open offer or other pre-emptive offer in favour of ordinary shareholders

(excluding any shareholder holding shares as treasury shares) where the equity securities

respectively attributable to the interests of such ordinary shareholders on a fixed record

date are proportionate (as nearly as may be) to the respective numbers of ordinary shares

held by them (subject to such exclusions or other arrangements as the directors may deem

necessary or expedient to deal with fractional entitlements or legal or practical problems

arising in any overseas territory, the requirements of any regulatory body or stockexchange or any other matter whatsoever); and

(b) the allotment (otherwise than pursuant to sub-paragraph (a) above) of equity securities up

to an aggregate nominal value of £2,866,221;

256


and shall expire at the conclusion of the next annual general meeting of the Company or, if

earlier, 30 September 2009, save that the Company may before such expiry make an offer or

agreement which would or might require equity securities to be allotted after such expiry and

the directors may allot equity securities in pursuance of such an offer or agreement as if thepower conferred hereby had not expired.

By order of the Board

Stephen Huddle

Company Secretary

3 April 2009

Registered office

4th Floor, Saltire Court,

20 Castle Terrace,

Edinburgh EH1 2EN

NOTES TO THE NOTICE OF THE MEETING

1. Shareholders are entitled to attend and vote at the above-mentioned meeting and may appoint a proxy to exercise all or any of theirrights to attend and to speak and vote on their behalf at the meeting. A shareholder may appoint more than one proxy in relation tothe Extraordinary General Meeting provided that each proxy is appointed to exercise the rights attached to a different share or sharesheld by that shareholder. A shareholder opportunity more than the proxy should indicate the number of shares for which each proxyis authorised to act on his or her behalf. A proxy need not be a member of the Company. A form of proxy which may be used to makesuch appointment and give proxy instructions accompanies this notice. If you do not have a proxy form and believe that you shouldhave one, or if you require additional forms, please contact Capita Registrars on 0871 664 0321 if calling from within the UK (callscost 10p per minute plus network extras) or +44 (0)20 8639 3399 if calling from outside the UK.

2. To be valid, Forms of Proxy must be lodged in one of the following methods by 10.00 a.m. on 18 April 2009:* In hard copy form by post to Capita Registrars (Proxies), PO Box 25, Beckenham, Kent, BR3 4BR; or* In hard copy form by hand to Capita Registrars, The Registry, 34 Beckenham Road, Beckenham, Kent BR3 4TU (during usual

business hours); or* In the case of CREST members or CREST Personal Members, by utilising the CREST electronic proxy appointment service in

accordance with the procedures set out below; or* You may also submit your proxy electronically via the Internet. Instructions on how to do this can be found on the Form of

Proxy enclosed.

3. The return of a completed proxy form, other such instrument or any CREST Proxy Instruction (as described in paragraph 9 below)will not prevent a shareholder attending the Extraordinary General Meeting and voting in person if he/she wishes to do so.

4. Any person to whom this notice is sent who is a person nominated under section 146 of the Companies Act 2006 to enjoy informationrights (a ‘‘Nominated Person’’) may, under an agreement between him/her and the shareholder by whom he/she was nominated, havea right to be appointed (or to have someone else appointed) as a proxy for the Extraordinary General Meeting. If a Nominated Personhas no such proxy appointment right or does not wish to exercise it, he/she may, under any such agreement, have a right to giveinstructions to the shareholder as to the exercise of voting rights.

5. The statement of the rights of shareholders in relation to the appointment of proxies in paragraphs 1 and 2 above does not apply toNominated Persons. The rights described in those paragraphs can only be exercised by shareholders of the Company.

6. To be entitled to attend and vote at the Extraordinary General Meeting (and for the purpose of the determination by the Company ofthe votes they may cast), shareholders must be registered in the Register of Members of the Company at 5 p.m. on 18 April 2009 (or,in the event of any adjournment, 5 p.m. on the date which is two days before the time of the adjourned meeting). Changes to theRegister of Members after the relevant deadline shall be disregarded in determining the rights of any person to attend and vote at themeeting.

7. As at 1 April 2009 (being the last practicable business date prior to the publication of this Notice) the Company’s issued Ordinaryshare capital consists of 79,372,274 Ordinary Shares, carrying one vote each. Therefore the total voting rights in the Company as at1 April 2009 are 79,372,274.

8. CREST members who wish to appoint a proxy or proxies through the CREST electronic proxy appointment service may do so byutilising the procedures described in the CREST Manual. CREST Personal Members or other CREST sponsored members, and thoseCREST members who have appointed a voting service provider(s), should refer to their CREST sponsor or voting service provider(s),who will be able to take the appropriate action on their behalf.

9. In order for a proxy appointment of instruction made using the CREST service to be valid, the appropriate CREST message (a‘‘CREST Proxy Instruction’’) must be properly authenticated in accordance with Euroclear UK & Ireland Limited’s specifications,and must contain the information required for such instruction, as described in the CREST Manual. The message, regardless ofwhether it constitutes the appointment of a proxy or is an amendment to the instruction given to a previously appointed proxy must,in order to be valid, be transmitted so as to be received by Capita Registrars (ID: RA10) by 10.00 a.m. on 18 April 2009. For thispurpose, the time of receipt will be taken to be the time (as determined by the timestamp applied to the message by the CRESTApplication Host) from which the issuer’s agent is able to retrieve the message by enquiry to CREST in the manner prescribed byCREST. After this time any change of instructions to proxies appointed through CREST should be communicated to the appointeethrough other means.

10. CREST members and, where applicable, their CREST sponsors, or voting service providers should note that Euroclear UK & IrelandLimited does not make available special procedures in CREST for any particular message. Normal system timings and limitationswill, therefore, apply in relation to the input of CREST Proxy Instructions. It is the responsibility of the CREST member concerned totake (or, if the CREST member is a CREST personal member, or sponsored member, or has appointed a voting service provider, toprocure that their CREST sponsor or voting service provider(s) take(s)) such action as shall be necessary to ensure that a message istransmitted by means of the CREST system by any particular time. In this connection, CREST members and, where applicable, theirCREST sponsors or voting system providers are referred, in particular, to those sections of the CREST Manual concerning practicallimitations of the CREST system and timings.

Registered Office

4th Floor, Saltire Court, 20 Castle Terrace, Edinburgh EH1 2EN

The above Company is registered in Scotland

Registered No. SC234781

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