158825 Project Kraken - Circular Pt1_158825

THIS DOCUMENT IS IMPORTANT AND REQUIRES YOUR IMMEDIATE ATTENTION. If you
are in any doubt as to the action you should take, you are recommended to seek your own personal
and independent financial advice from your stockbroker, bank manager, solicitor, accountant or other
financial adviser authorised under the Financial Services and Markets Act 2000 (“FSMA”).
13.3.1(4)
If you have sold or otherwise transferred all your Ordinary Shares, please pass this document, together with
the accompanying form of proxy (“Form of Proxy”), as soon as possible to the purchaser or transferee, or to
the person who arranged the sale or transfer so they can pass these documents to the person who now holds
the Ordinary Shares. If you have sold only part of your holding of Ordinary Shares, you should retain these
documents and consult the bank, stockbroker or other agent through whom the sale was effected.
13.3.1(6)
This document should be read as a whole. Your attention is drawn to the letter from your Chairman which is
set out on pages 5 to 9 of this document, and which recommends you vote in favour of the resolution to be
proposed at the Extraordinary General Meeting referred to below. Your attention is further drawn to the risk
factors set out in Part II of this document for a discussion of the risks that affect the value of your
shareholding in EnQuest.
EnQuest PLC
PROPOSED ACQUISITION OF INTERESTS IN UKCS BLOCKS
9/2b, 9/2c, 9/6a AND 9/7b INCLUDING THE KRAKEN FIELD
Circular to Shareholders and Notice of Extraordinary General Meeting
Notice of an Extraordinary General Meeting of EnQuest PLC to be held at 12.00 noon on 16 July 2012
at the offices of CMS Cameron McKenna LLP, Mitre House, 160 Aldersgate Street, London, EC1A
4DD, United Kingdom is set out at the end of this document. A Form of Proxy for use by Shareholders
in connection with this Extraordinary General Meeting is enclosed. Whether or not you propose to
attend the Extraordinary General Meeting, please complete and submit the Form of Proxy in
accordance with the instructions printed on the enclosed form. To be valid, the Form of Proxy should
be completed, signed and returned in accordance with the instructions printed thereon to the
Company’s registrar, at the address shown on the Form of Proxy, as soon as possible but in any event
must arrive not later than 12.00 noon on 12 July 2012, being 48 working day hours before the time
appointed for the holding of the meeting.
If you hold your Ordinary Shares in uncertificated form (i.e. in CREST), you may appoint a proxy by
completing and transmitting the appropriate CREST message (the “CREST Proxy Instruction”), in
accordance with the procedures set out in the CREST Manual, so that it is received by the Registrar (under
CREST participant RA10) by no later than 12.00 noon on 12 July 2012. The time of receipt will be taken to
be the time from which the Registrar is able to retrieve the message by enquiry to CREST in the manner
prescribed by CREST. Shareholders may also register the appointment of a proxy electronically by logging
on to www.capitashareportal.com, so that the appointment is received by the Registrar by no later than 12.00
noon on 12 July 2012. Completion and posting of the Form of Proxy or completing and transmitting a
CREST Proxy Instruction or appointing a proxy electronically will not prevent you from attending and
voting in person at the Extraordinary General Meeting, if you wish to do so.
This document is a circular relating to the Proposed Acquisition, which has been prepared in accordance with
the Listing Rules. This document has been approved by the Financial Services Authority.
Merrill Lynch International, which is authorised and regulated in the United Kingdom by the Financial
Services Authority, is acting for EnQuest and no-one else in connection with the Proposed Acquisition and
will not be responsible to anyone other than EnQuest for providing the protections afforded to clients of
Merrill Lynch International or for providing advice in relation to the Proposed Acquisition or on any other
matters referred to herein.
I 5.1.1
Merrill Lynch International accepts no responsibility or liability whatsoever for the contents of this
document, including its accuracy, completeness or verification or for any other statement made or purported
to be made in connection with the Company or the Proposed Acquisition, and nothing in this document is or
shall be relied upon as a promise or representation in this respect, whether as to the past or future. Merrill
Lynch International accordingly disclaims, to the fullest extent permitted by law, all and any responsibility
or liability whether arising in tort, contract or otherwise (save as referred to above) which it might otherwise
have in respect of this document or any such statement.
FORWARD-LOOKING STATEMENTS
This document contains (or may contain) forward-looking statements with respect to certain of EnQuest’s
plans and its current goals and expectations relating to its future financial condition and performance and
which involve a number of risks and uncertainties. EnQuest cautions readers that no forward-looking
statement is a guarantee of future performance and that actual results could differ materially from those
contained in the forward-looking statements. These forward-looking statements can be identified by the fact
that they do not relate only to historical or current facts. Forward-looking statements sometimes use words
such as ‘aim’, ‘anticipate’, ‘target’, ‘expect’, ‘estimate’, ‘intend’, ‘plan’, ‘goal’, ‘believe’, or other words of
similar meaning. Examples of forward-looking statements include, among others, statements regarding
EnQuest’s future financial position, income growth, impairment charges, business strategy, projected levels
of growth in its markets, projected costs, estimates of capital expenditure, and plans and objectives for future
operations of EnQuest and other statements that are not historical fact.
By their nature, forward-looking statements involve risk and uncertainty because they relate to future events
and circumstances, including, but not limited to, UK domestic and global economic and business conditions,
the effects of continued volatility in credit markets, market-related risks such as changes in interest rates and
exchange rates, the policies and actions of governmental and regulatory authorities, changes in legislation,
the further development of standards and interpretations under International Financial Reporting Standards
(“IFRS”) applicable to past, current and future periods, evolving practices with regard to the interpretation
and application of standards under IFRS, the outcome of pending and future litigation, the success of future
acquisitions and other strategic transactions and the impact of competition — a number of which factors are
beyond EnQuest’s control. As a result, EnQuest’s actual future results may differ materially from the plans,
goals, and expectations set forth in EnQuest’s forward-looking statements. See Part II of this document for
further information in relation to risk factors. Any forward-looking statements made herein by or on behalf
of EnQuest speak only as of the date they are made. Except as required by the FSA, the London Stock
Exchange or applicable law, EnQuest 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 changes
in EnQuest’s expectations with regard thereto or any changes in events, conditions or circumstances on
which any such statement is based. Except to the extent required by applicable law, the Listing Rules or the
Disclosure and Transparency Rules, EnQuest will not necessarily update any of them in light of new
information or future events and undertakes no duty to do so.
NOTE REGARDING PRESENTATION OF CURRENCIES
Unless otherwise indicated, all references in this document to “pounds sterling’’ or “£” are to the lawful
currency of the United Kingdom and all references to “$”, “US$”, “US dollars” or “United States dollars”
are to the lawful currency of the United States.
2
TABLE OF CONTENTS
Page
DIRECTORS, SECRETARY, REGISTERED OFFICE AND ADVISERS
4
PART I
LETTER FROM THE CHAIRMAN OF ENQUEST PLC
5
PART II
RISK FACTORS
10
PART III
SUMMARY OF THE PRINCIPAL TERMS OF THE ACQUISITION AGREEMENT
18
PART IV
ADDITIONAL INFORMATION
21
PART V
COMPETENT PERSON’S REPORT ON THE KRAKEN FIELD, UK NORTH SEA
31
GLOSSARY
65
NOTICE OF EXTRAORDINARY GENERAL MEETING
69
DEFINITIONS
71
EXPECTED TIMETABLE OF KEY EVENTS
Latest time and date for receipt of forms of proxy for the
Extraordinary General Meeting
12.00 noon on 12 July 2012
Extraordinary General Meeting
12.00 noon on 16 July 2012
Expected date of Completion of the Proposed Acquisition
3
17 July 2012
DIRECTORS, SECRETARY, REGISTERED OFFICE AND ADVISERS
Directors
James Buckee (Non-Executive Chairman)
Amjad Bseisu (Chief Executive)
Nigel Hares (Chief Operating Officer)
Jonathan Swinney (Chief Financial Officer)
Helmut Langanger (Non-Executive Director)
Jock Lennox (Non-Executive Director)
Clare Spottiswoode (Non-Executive Director)
Company Secretary
Paul Waters
Registered Office and Head Office
Rex House
4-12 Regent Street
London
SW1Y 4PE
United Kingdom
Sponsor
Merrill Lynch International
2 King Edward Street
London
EC1A 1HQ
United Kingdom
Legal Advisers to the Company
as to English Law
CMS Cameron McKenna LLP
160 Aldersgate Street
London
EC1A 4DD
United Kingdom
Legal Advisers to the Company
as to Swedish Law
Advokatfirman Vinge KB
Smålandsgatan 20
Box 1703
S-111 87 Stockholm
Sweden
Competent Person
Gaffney, Cline & Associates Limited
Bentley Hall
Blacknest, Alton
Hampshire
GU34 4PU
United Kingdom
4
I 5.1.4
PART I
LETTER FROM THE CHAIRMAN OF ENQUEST PLC
ENQUEST PLC
I 5.1.4
(Incorporated and registered in England and Wales under number 7140891)
Directors:
James Buckee (Non-Executive Chairman)
Amjad Bseisu (Chief Executive)
Nigel Hares (Chief Operating Officer)
Jonathan Swinney (Chief Financial Officer)
Helmut Langanger (Non-Executive Director)
Jock Lennox (Non-Executive Director)
Clare Spottiswoode (Non-Executive Director)
Registered Office:
13.3.1(1)
Rex House
4-12 Regent Street
London
SW1Y 4PE
13.3.1(3)
28 June 2012
Proposed Acquisition of interests in UKCS Blocks 9/2b, 9/2c, 9/6a and 9/7b
including the Kraken Field and Notice of Extraordinary General Meeting
Dear Shareholder
1.
Introduction
On 25 April 2012, EnQuest announced that it has agreed to acquire the Kraken Interest from First Oil for a
total consideration of up to US$144 million by way of a development carry.
The Kraken Interest consists of interests in Blocks 9/2b, 9/2c, 9/6a and 9/7b on the United Kingdom
Continental Shelf. The interests include a 15 per cent. interest in the Kraken Field, a large heavy oil
accumulation contained within UKCS Blocks 9/2b and 9/2c.
10.4.1(2)(b)
Following the Canamens Acquisition and the Nautical Acquisition, which took place earlier this year and
further details of which are set out in paragraphs 6.1, 6.2 and 6.5 of Part IV of this document, EnQuest
currently holds a 45 per cent. equity interest in the Kraken Field. Following the Proposed Acquisition,
EnQuest will hold a 60 per cent. equity interest in the Kraken Field.
In accordance with the Listing Rules, due to the size of the Proposed Acquisition, when aggregated with
EnQuest’s other recent acquisitions of interests in the Kraken Field, in relation to the size of the Company,
the Acquisition is subject to, inter alia, the approval of EnQuest’s Shareholders at an Extraordinary General
Meeting expected to take place on 16 July 2012.
The Board believes that the Proposed Acquisition is in the best interests of EnQuest and its Shareholders as
a whole and seeks your approval of the Resolution to be proposed at the Extraordinary General Meeting. A
Notice convening the Extraordinary General Meeting is set out at the end of this document. The action you
should take to vote on the Resolution and the recommendation of the Board are set out in paragraphs 9 and
11 of this letter.
Shareholders should read the whole of this document and not just rely on the summarised information
contained within this letter.
2.
Background to, and reason for, the Proposed Acquisition
EnQuest aims to become one of the UK’s leading independent oil and gas production and development
companies. The Group operates a production biased portfolio with exposure predominantly to the significant
and low-risk hydrocarbon basin of the UKCS. The Group’s management intends to deliver sustainable
growth in shareholder value by focusing on exploiting its existing reserves, commercialising and developing
5
13.3.1(2)
discoveries, converting its significant contingent resources into reserves and pursuing selective acquisitions.
EnQuest intends to achieve its strategy through:
•
pro-actively operating its assets;
•
maximising production, reserves and cash flow generation from the Group’s existing assets;
•
using the Group’s operational, execution, subsurface and integration skills;
•
becoming a development partner of choice; and
•
delivering balanced growth.
EnQuest therefore uses its operating and technical expertise as well as its financial strength to take advantage
of the significant number of undeveloped discoveries and assets with potential for development in the UKCS,
a large hydrocarbon basin which the Directors believe continues to offer significant potential. The Directors
also believe these skills can be applied internationally.
Furthermore, EnQuest’s strategy for growth has been to re-invest cash generated through its operations into
acquisitions by undertaking farm-ins in discoveries and development projects and making selective
acquisitions of both companies and assets.
EnQuest has focused on obtaining operatorship and high equity interests in the fields in which it participates.
This allows the Group to have a significant influence over field development, production and adjacent
appraisal and exploration activities, and ultimately extract material value from its operated assets.
The Proposed Acquisition of the Kraken Interest will complement the Canamens Acquisition and the
Nautical Acquisition that both occurred in early 2012 by adding a further 15 per cent. equity interest to
EnQuest’s existing 45 per cent. equity interest in the Kraken Field, taking its aggregate equity interest in the
Kraken Field to 60 per cent. Furthermore, at completion of the Proposed Acquisition, First Oil (as the seller
of the Kraken Interest) has irrevocably agreed to approve the appointment of EnQuest Dons (a wholly owned
subsidiary of EnQuest) as the operator of Licence P.1077 and, following completion of the Proposed
Acquisition, support the appointment of EnQuest Dons as the operator of Licence P.1575.
Following the Proposed Acquisition, the EnQuest Group’s operatorship and high equity interest in the
Kraken Field will ensure that the EnQuest Group has significant influence over the field development and
subsequent production in the Kraken Field and over appraisal and exploration activities in adjacent areas.
The Directors believe that the Proposed Acquisition will complement EnQuest’s key strengths and further its
stated strategy.
3.
Information on the Kraken Interest
The Kraken Interest consists of interests in Blocks located in the East Shetland basin, in an area to the west
of the North Viking Graben.
The Kraken Field is one of the largest identified undeveloped oil fields in the UK North Sea and is being
progressed to development following successful appraisal and well test results.
The gross 2C contingent resources for the Kraken Field are estimated by GCA to be 172 MMbbl and
therefore the Proposed Acquisition will deliver a further 26 MMbbl of 2C contingent resources net to the
Enlarged Group, increasing EnQuest’s net 2C contingent resources in the Kraken Field, as estimated by
GCA, from 77 MMbbl to 103 MMbbl.
The most recent and first horizontal well 9/02b-5z in the Kraken Field was drilled and tested at a stabilised
rate of 4,000 bopd and a series of flow and build-up periods were conducted up to a maximum flow rate of
4,500 bopd. At the same time the viscosity was measured at 162 centipoise. This, together with the flow
rates, gave the management of EnQuest significant comfort that a viable new development could be
progressed.
6
10.4.1(2)(f)
The Proposed Acquisition will also enable the Enlarged Group to exercise the option, granted in the Nautical
Acquisition, to acquire a further 5 per cent. interest in UKCS Block 9/1a (known as the Ketos discovery).
This option grants the Enlarged Group the right to acquire an interest in Licence P.1759 and a percentage
interest in Block 9/1a equal to the Enlarged Group’s interest in Block 9/2 (up to a maximum of 50 per cent.).
Currently, the Enlarged Group’s interest in Block 9/2 is 45 per cent.; following the Proposed Acquisition, the
Enlarged Group’s interest in Block 9/2 will be 60 per cent. and therefore this option will enable the Enlarged
Group to exercise the option to obtain the maximum 50 per cent. interest in Block 9/1a. Further analysis of
the 3D seismic data in relation to the Ketos discovery is required with the potential to drill further wells.
Please refer to paragraph 6.5 of Part IV of this document for further details of this option and the Nautical
Acquisition.
UKCS Blocks 9/6a and 9/7b are exploration Blocks and no resources have been discovered in these areas to
date, although the Blocks provide potential for exploration drilling in the future.
Please refer to GCA’s Competent Person’s Report, contained at Part V of this document, for further details
of the Kraken Interest.
4.
Principal Terms of the Proposed Acquisition
On 25 April 2012, EnQuest Dons, a wholly owned subsidiary of the Company, entered into a conditional
farm-in agreement with First Oil to acquire a 15 per cent. interest in each of Block 9/2b, Block 9/2c,
Block 9/6a and Block 9/7b of the UKCS (together with interests in the P.1077 and P.1575 Licences and
documents related to the P.1077 and P.1575 Licences).
10.4.1(2)(a)
The interests acquired include a 15 per cent. interest in the Kraken Field which, together with the Group’s
existing 45 per cent. interest, following Completion, will give the Group an aggregate 60 per cent. interest
in the Kraken Field.
In accordance with the Listing Rules, due to the size of the Proposed Acquisition, when aggregated with the
recent acquisition of interests in the Kraken Field as part of the Canamens Acquisition and the Nautical
Acquisition, the Proposed Acquisition is subject to Shareholder approval. It is also conditional, among other
things, on approval by the Secretary of State and other third party consents. Approval is currently expected
to be received from the Secretary of State on or around 13 July 2012.
In consideration of the transfer of the Kraken Interest, EnQuest Dons shall pay certain costs which would
otherwise be borne by First Oil as holder of its remaining 15 per cent. participating interest in Licences
P.1077 and P.1575 up to a maximum of US$144 million. The amount payable by EnQuest Dons is dependent
on a future determination of the gross 2P reserves in the Kraken Field. If the determination is less than or
equal to 100 MMboe, EnQuest will only pay US$90 million, by way of development carry. If the
determination is less than 166 MMboe, but more than 100 MMboe, then the amount of the development
carry will be increased by up to a further US$54 million, calculated on a linear pro-rata basis. EnQuest will
pay the maximum of US$144 million if the future determination of gross 2P reserves is equal to or greater
than 166 MMboe.
The effect of the structure of the consideration payable by EnQuest Dons is such that EnQuest Dons will not
be committed to paying a significant part of the consideration until the Secretary of State’s approval of the
field development plan in respect of the Kraken Field has been obtained and a viable development project
has been formulated. Therefore, considerable flexibility is maintained for EnQuest without having to commit
significant amounts of funding.
At Completion, EnQuest shall be obliged to guarantee to First Oil the obligations and liabilities of EnQuest
Dons under the Acquisition Agreement.
The Acquisition Agreement contains warranties that in terms of scope are customary for a transaction of this
nature.
Further details of the Acquisition Agreement are set out in Part III of this document.
7
10.4.1(2)(c)
5.
Financing the Proposed Acquisition
The Proposed Acquisition is not conditional on EnQuest obtaining funds to finance the Proposed
Acquisition.
10.4.1(2)(c)
The consideration for the Proposed Acquisition will be satisfied through EnQuest’s existing cash balances,
generated cashflow and the Facility Agreement.
On 6 March 2012, EnQuest entered into the Facility Agreement, which is a secured and guaranteed
multicurrency revolving credit facility, the aggregate commitments of which start at US$525 million but may
be increased, with the agreement of the lenders, to US$900 million. The facilities are provided by Lloyds
TSB Bank plc, BNP Paribas, Barclays Corporate, The Royal Bank of Scotland Plc, Banc of America
Securities Limited and Credit Agricole Corporate Investment Bank (as mandated lead arrangers), NIBC
Bank N.V. (as lead arranger) and Lloyds TSB Bank Plc (as facility agent). Further details of the Facility
Agreement are set out in paragraph 6.6 of Part IV of this document.
6.
EnQuest Current Trading and Prospects
The Group’s production from 1 January to 30 April 2012 averaged 20,976 Boepd, in line with expectations.
The Directors anticipate that the average for the full 2012 calendar year will be 20,000 to 24,000 Boepd.
Amjad Bseisu, the chief executive of the Company, stated in EnQuest’s interim management statement
released on 18 May 2012:
“We have had a busy 2012 to date, with three transactions giving us a 60 per cent. working interest in the
exciting Kraken development as well as the purchase of an additional 18.5 per cent. of West Don. Our
production for 2012 is going according to plan and the Alma/Galia development is on schedule. Today, we
are announcing further additions to our growing pipeline of potential developments, with an increase in our
position in the Kildrummy discovery from 40 per cent. to 60 per cent. and in the Cairngorm discovery from
50 per cent. to 100 per cent.”
“Our production continues to drive our earnings and cash flow, putting us in a good position to take
advantage of further business development opportunities as they arise.”
7.
Risk Factors
Shareholders should consider fully and carefully the risk factors associated with the Proposed Acquisition
and the operations of the Enlarged Group. Your attention is drawn to the risk factors set out in Part II of this
document.
8.
Notice of Extraordinary General meeting
In accordance with the Listing Rules, the Proposed Acquisition is conditional on, amongst other things, the
approval of the Shareholders. A Notice convening the Extraordinary General Meeting in relation to the
Proposed Acquisition to be held at 12.00 noon on 16 July 2012 at the offices of CMS Cameron McKenna
LLP, Mitre House, 160 Aldersgate Street, London, EC1A 4DD, United Kingdom is set out at the end of this
document. At this meeting the Resolution will be proposed for the purpose of approving the Proposed
Acquisition.
9.
Action to be taken
You will find enclosed with this document a Form of Proxy for use at the Extraordinary General Meeting.
Whether or not you propose to be present at the Extraordinary General Meeting, you are requested to
complete and sign the Form of Proxy, in accordance with the instructions printed thereon, and return it to the
Company’s registrars, at the address shown on the Form of Proxy, to arrive as soon as possible and, in any
event, not later than 12.00 noon on 12 July 2012.
8
I.12
10.
Additional information
Your attention is drawn to the additional information set out in Part IV of this document and to the Notice
of Extraordinary General Meeting set out at the end of this document.
11.
Recommendation
Your Board considers that the Proposed Acquisition is in the best interests of Shareholders taken as a whole
and unanimously recommends that Shareholders vote in favour of the Resolution to be proposed at the
Extraordinary General Meeting, as the Directors each intend to do in respect of their own beneficial holdings
which, as at 27 June 2012, amounted in total to 75,202,322 Ordinary Shares, representing approximately
9.37 per cent. of the issued share capital of the Company.
Yours sincerely,
James Buckee
Chairman
9
13.3.1(5)
PART II
RISK FACTORS
The following risk factors should be considered carefully when deciding whether or not to vote in favour of
the Resolution to be proposed at the Extraordinary General Meeting. The risk factors should be read in
conjunction with all other information relating to the Proposed Acquisition and the Enlarged Group
contained in this document. The risks and uncertainties set out below are those which the Directors believe
are the material risks relating to the Proposed Acquisition and to the Enlarged Group and their markets. If
any or a combination of these risks actually materialise, the business, operations, financial conditions and
prospects of the Group and, following Completion of the Proposed Acquisition, the Enlarged Group as
appropriate could be materially and adversely affected. The following is not exhaustive and does not purport
to be a complete explanation of all the risks involved. Additional risks and uncertainties not presently known
to the Directors, or which the Directors currently consider to be immaterial, may also have a material
adverse effect on the Proposed Acquisition and on the Enlarged Group if they materialise. If any of the risks
actually materialise, the market price of the EnQuest Shares could decline and you may lose all or part of
your investment.
RISKS RELATING TO THE PROPOSED ACQUISITION
The Proposed Acquisition may fail to realise anticipated benefits
There can be no guarantee that the Enlarged Group will realise any or all of the anticipated benefits of the
Proposed Acquisition, either in a timely manner or at all. The process of estimating resources that may be
developed and produced with respect to the Kraken Interest is based on volumetric calculations and
analogies to similar types of fields. As a result, the estimation of the resources at the Kraken Interest may be
materially inaccurate. If this is the case, and the Enlarged Group has incurred significant costs, this could
have a material adverse impact on the business, results of operation and the financial condition of the
Enlarged Group.
Estimates of resources and forward looking statements
The resources data and forward looking statements contained in this document in respect of the Kraken
Interest are estimates only and should not be construed as representing exact quantities. They are based on
ownership, geophysical, geological and engineering data, and other information assembled by EnQuest, as
well as EnQuest’s assumptions based on its experience in developments of a similar nature. 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 the Kraken Interest’s resources. If the assumptions upon
which the estimates for the Kraken Interest’s hydrocarbon resources prove to be incorrect, the Enlarged
Group may be unable to recover and produce the estimated levels or quality of hydrocarbons and the
Enlarged Group’s business, prospects, financial condition or results of operations could be materially
adversely affected.
The Proposed Acquisition may not complete
The implementation of the Proposed Acquisition is subject to the satisfaction (or waiver, where applicable)
of a number of conditions, including:
•
the receipt of a consent from the Secretary of State for the Department of Energy and Climate Change
to the assignment of the Kraken Interest;
•
the receipt of all necessary third party consents; and
•
the approval, as a class 1 transaction, of the Proposed Acquisition by the Shareholders in accordance
with the rules of the UKLA and the London Stock Exchange.
10
I.4
There is no guarantee that these (or other) conditions will be satisfied (or waived, if applicable), in which
case the Proposed Acquisition will not be completed. The conditions are more fully described in Part III of
this document.
The Kraken Interest will be subject to a right of re-transfer to First Oil for a specified time following
completion of the Proposed Acquisition
The Enlarged Group’s ownership of the Kraken Interest will in certain circumstances be subject to a right of
re-transfer to First Oil in the event, inter alia, where a field development plan has not been submitted by
31 December 2013 or such other date as the parties may agree acting reasonably. Further details of the
Acquisition Agreement are provided in Part III of this document.
Failure to have a field development plan approved
The field development plan relating to the Kraken Interest that must be submitted is required to be approved
by the Secretary of State. There is no certainty at this stage that the Secretary of State will approve this field
development plan.
The Enlarged Group may not be able to develop commercially the Kraken Interest’s contingent
resources
The process of estimating oil and gas resources is complex and involves a high degree of uncertainty. The
resources relating to the Kraken Interest set out in this document represent estimates only. In general,
estimates of the quantity of recoverable oil and gas are based upon a number of variable factors and
assumptions, such as ability to recover resources, interpretation of geological and geophysical data, timing
and amount of capital expenditures, marketability of oil and gas, continuity of current fiscal policies and
regulatory regimes, future oil and gas prices, operating costs, development and production costs, all of which
may vary from actual results. Estimates involve subjective judgments and determinations and are also to
some degree speculative. Classification of resources is an assessment of the chance of commerciality.
The Kraken Interest’s contingent resources have been determined according to the guidelines and definitions
of the SPE PRMS. Under SPE PRMS, contingent resources are those deposits that are estimated, on a given
date, to be potentially recoverable from known accumulations but that are not currently considered
commercially recoverable. The resources may not be considered commercially recoverable by the Enlarged
Group for a variety of reasons, including the costs involved in recovering the contingent resources, the price
of oil at the time, the availability of the Enlarged Group’s resources and other development plans that the
Enlarged Group may have. The Enlarged Group’s estimates of its contingent resources are uncertain and can
change with time and there can be no guarantee that the Enlarged Group will be able to develop the Kraken
Field resources commercially.
The Kraken Field development is dependent on the availability of infrastructure and third party
contractors
The Kraken Field development, as with all production, development and exploration activities, will be,
should the field development plan be approved by the Secretary of State, dependent on the availability of
drilling equipment and offshore services, including third party services in the North Sea. The Group
contracts or leases (and following Completion and the Secretary of State’s approval of the field development
plan the Enlarged Group shall continue to contract and lease) services and equipment from third party
providers and suppliers. Such equipment and services may be scarce and may not be readily available at the
times and places required. Even where the Enlarged Group has secured rigs under a contract, the rigs will
usually only be available for use after the current user has finished its drilling programme. If there are delays
in the completion of the user’s drilling programme, the Enlarged Group could be delayed in procuring
contracted rigs. Under the terms of its licences, the Enlarged Group may have a commitment to drill within
a certain time frame. The Enlarged Group, therefore, risks losing licences if it is delayed in obtaining rigs
and thus meeting its drilling commitments. Shortages or the high cost of drilling rigs, equipment, supplies,
personnel or oilfield services could delay or adversely affect the Enlarged Group’s production, development
11
and exploration operations, which could have a material adverse effect on its business, financial condition or
results of operations.
The scarcity of third party services and equipment as well as any increases in their costs, together with the
failure of a third party provider or supplier to perform its contractual obligations, or an inability to achieve
a commercially viable contract with a third party provider or supplier could delay, restrict or lower the
profitability and viability of the activities related to the Kraken Field. This could have a material adverse
impact on the Enlarged Group’s business, the results of operations or financial condition.
RISKS RELATING TO THE OIL AND GAS INDUSTRY AND THE COUNTRIES IN WHICH THE
ENLARGED GROUP OPERATES
A material decline in oil and gas prices may adversely affect the Enlarged Group’s results of
operations and financial condition
Both oil and gas prices can be volatile and subject to fluctuation due to a variety of factors beyond the
Enlarged Group’s control. Any material decline in oil prices could result in a reduction of the Enlarged
Group’s net production revenue. Historically, oil prices have fluctuated widely for many reasons, including
global and regional supply and demand, and expectations regarding future supply and demand for oil and
petroleum products; geopolitical uncertainty; access to pipelines, tanker ships and other means of
transporting oil, gas and petroleum products; price, availability and government subsidies of alternative
fuels; price and availability of new technologies; the ability of the members of OPEC and other oil-producing
nations to set and maintain specified levels of production and prices; political, economic and military
developments in oil producing regions, particularly the Middle East; domestic and foreign governmental
regulations and actions, including export restrictions, taxes, repatriations and nationalisations; global and
regional economic conditions; and weather conditions and natural disasters.
It is impossible to predict accurately future oil and gas price movements. Accordingly, oil and gas prices may
not remain at their current levels. The economics of producing from some of the Enlarged Group’s wells may
change as a result of lower prices, which could result in a reduction in the volumes of the Enlarged Group’s
reserves if some are no longer economically viable to develop. The Enlarged Group might also elect not to
produce from certain wells at lower prices. All of these factors could result in a material decrease in the
Enlarged Group’s net production revenue adversely affecting its acquisition, development and exploration
activities and financial condition.
Under IFRS, the net capitalised cost of oil and gas properties may not exceed their recoverable amount which
is based, in part, upon estimated future net cash flows from oil and gas reserves. If the net capitalised costs
exceed this limit, the Enlarged Group must charge the amount of the excess against earnings. If oil or gas
prices were to decline, the Enlarged Group’s net capitalised cost of oil and gas properties may approach or
exceed their recoverable amount, resulting in a charge against earnings.
The Enlarged Group’s success depends on its ability to appraise, develop and explore oil and gas
reserves that are economically recoverable
The Enlarged Group’s long-term commercial success depends on its ability to appraise, develop, explore and
commercially produce oil and gas reserves. The Enlarged Group must continually locate and develop or
acquire new reserves to replace its existing reserves that are being depleted by production. Future increases
in the Enlarged Group’s reserves will depend not only on its ability to appraise, develop and explore its
existing assets but also on its ability to select and acquire suitable additional assets either through awards at
licensing rounds or through acquisitions. There are many reasons why the Enlarged Group may not be able
to find or acquire oil and gas reserves or develop them for commercially viable production. For example, the
Enlarged Group may be unable to negotiate commercially reasonable terms for its acquisition, appraisal,
development or production activities. Factors such as adverse weather conditions, natural disasters,
equipment or services shortages, procurement delays or difficulties arising from the political, environmental
and other conditions in the areas where the reserves are located or through which the Enlarged Group’s
products are transported may increase costs and make it uneconomical to develop potential reserves. Without
successful exploration or acquisition activities, the Enlarged Group’s reserves, production and revenues will
12
decline. There is no assurance that the Enlarged Group will discover, acquire or develop further commercial
quantities of oil and gas.
Appraisal and exploration projects do not necessarily result in a profit on the investment or the
recovery of costs
Appraisal and exploration activities are capital intensive and inherently uncertain in their outcome. The
Enlarged Group’s future oil and gas appraisal and exploration projects may involve unprofitable efforts,
either from dry wells or from wells that are productive but do not produce sufficient net revenues to return
a profit after development, operating and other costs. Completion of a well does not guarantee a profit on the
investment or recovery of the costs associated with that well. In addition, drilling hazards or environmental
damage could greatly increase the cost of operations, and various field operating conditions may adversely
affect the production from successful wells. These conditions include delays in obtaining governmental
approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient
storage or transportation capacity, or adverse geological conditions. For additional risks in conducting
appraisal and development activities, please see the risk factor “The Enlarged Group’s offshore operations
are subject to a number of risks and hazards that may result in material losses in excess of insurance
proceeds” below. While diligent well supervision and effective maintenance operations can contribute to
maximising production rates over time, production delays and declines from normal field operating
conditions cannot be eliminated and may adversely affect the Enlarged Group’s revenues and cash flows.
The Enlarged Group’s offshore operations are subject to a number of risks and hazards that may
result in material losses in excess of insurance proceeds
Oil and gas development, production and exploration operations are inherently risky and hazardous. Risks
typically associated with these operations include unexpected formations or pressures and premature decline
of reservoirs. Losses resulting from the occurrence of any of these risks could have a material adverse effect
on the Enlarged Group’s financial position, results of operations and prospects. Hazards typically associated
with offshore oil and gas production, development and exploration operations include fires, explosions,
blowouts, marine perils, including severe storms and other adverse weather conditions, vessel collisions, gas
leaks and oil spills, each of which could result in substantial damage to oil and gas wells, production
facilities, other property and the environment or in personal injury. Oil and gas installations are also known
to be likely objects, and even targets, of military operations and terrorism.
Although the Group obtains insurance prior to drilling in accordance with industry standards to cover certain
of these risks and hazards, insurance is subject to limitations on liability and, as a result, may not be sufficient
to cover all of the Enlarged Group’s losses. In addition, the risks or hazards associated with the Enlarged
Group’s offshore operations may not in all circumstances be insurable or, in certain circumstances, the
Enlarged Group may elect not to obtain insurance to deal with specific events due to the high premiums
associated with such insurance or for other reasons. The Group does not currently have business interruption
insurance in place and, therefore, it will suffer losses as a result of a shut-in or cessation in production. The
occurrence of a significant event against which the Enlarged Group is not fully insured, or the insolvency of
the insurer of such event, could have a material adverse effect on the Enlarged Group’s financial position,
results of operations and prospects.
The Enlarged Group’s business is subject to government regulation with which it may be difficult to
comply and which may change
The Enlarged Group’s oil and gas exploration and production operations are principally subject to the laws
and regulations of the United Kingdom, including those relating to health and safety and the production,
pricing and marketing of oil and gas. In addition, the Enlarged Group will be subject to laws affecting foreign
ownership, government participation, taxation, royalties, duties, rates of exchange and exchange control. In
order to conduct its operations in compliance with these laws and regulations, the Enlarged Group must
obtain licences and permits from various government authorities. The grant, continuity and renewal of the
necessary approvals, permits, licences and contracts, including the timing of obtaining such licences and the
terms on which they are granted, are subject to the discretion of the relevant governmental and local
13
authorities in the United Kingdom and cannot be assured. In addition, the Enlarged Group may incur
substantial costs in order to maintain compliance with these existing laws and regulations and additional
costs if these laws are revised or if new laws affecting the Enlarged Group’s operations are passed.
The Enlarged Group’s operations expose it to significant compliance costs and liabilities in respect of
HSE matters
The Enlarged Group’s operations and assets are affected by numerous international, European Union and
national laws and regulations concerning HSE matters including, but not limited to, those relating to
discharges of hazardous substances into the environment, the handling and disposal of waste and the health
and safety of employees. The technical requirements of these laws and regulations are becoming increasingly
complex, stringently enforced and expensive to comply with and this trend is likely to continue. The failure
to comply with current HSE laws and regulations may result in regulatory action, the imposition of fines or
the payment of compensation to third parties which each could in turn have a material adverse effect on the
Enlarged Group’s business, financial condition and results of operations.
Certain HSE laws provide for strict, joint and several liability without regard to negligence or fault for natural
resource damages, health and safety, remediation and clean-up costs of spills and other releases of hazardous
substances, and such laws may impose liability for personal injury or property damage as a result of exposure
to hazardous substances. Further, such HSE laws and regulations may expose the Enlarged Group to liability
for the conduct of others or for acts that complied with all applicable HSE laws when they were performed.
In addition, the enactment of new HSE laws or regulations or stricter enforcement or new interpretations of
existing HSE laws or regulations could have a significant impact on the Enlarged Group’s operating or
capital costs and require further expenditure to modify operations, upgrade employee and contractor
accommodation as other infrastructure, install pollution control equipment, perform clean-up operations,
curtail or cease certain operations, or pay fines or make other payments for pollution, discharges or other
breaches of HSE requirements. There can be no assurances that the Enlarged Group will be able to comply
with such HSE laws in the future. The failure to comply with such HSE laws or regulations could result in
substantial costs and/or liabilities to third parties or government entities which could have a material adverse
effect on the Enlarged Group’s business, financial condition and results of operations.
The Offshore Combustion Installations (Prevention and Control of Pollution) Regulations 2001 (the “PPC”)
have been implemented in the UK and apply to the Heather and Thistle platforms and the Northern Producer
FPF. Permits under the PPC have been issued to the Group by the DECC in 2009. Applications for these PPC
permits normally contain an energy efficiency survey. Energy efficiency surveys that the Group has
conducted as part of the PPC application process have identified potential energy efficiency measures and
other upgrades to the installations that may be implemented by the Enlarged Group, which have been built
into the assets’ life-of-field opportunity registers maintained by the Enlarged Group, for future investment
opportunities for improved performance. The costs associated with the PPC permit compliance and other
measures to be undertaken are material for the Enlarged Group.
All of these factors may lead to delayed or reduced production, development and exploration activity as well
as to increased costs.
Future legislation may require further reductions of greenhouse gas emissions and discharges of oil in
produced waters
The United Kingdom is a signatory to the United Nations Framework Convention on Climate Change and
has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide
emissions of carbon dioxide, methane, nitrous oxide and other so called “greenhouse gases”.
Due to the requirements of the European Union’s Emissions Trading Scheme (the “EU ETS”), Member
States’ governments have put forward national plans that set carbon dioxide emission reduction requirements
for various industrial activities. For the current phase of the EU ETS (Phase II, running from 2008 to 2012),
these activities include offshore oil and gas exploration and production facilities incorporating combustion
plants (including flaring) with aggregate thermal ratings of greater than 20 megawatts (thermal input).
14
Currently the majority of allowances for emissions under Phase II EU ETS are allocated to individual
installations free of charge based on forecast emissions. If the Enlarged Group’s verified emissions are less
than its prescribed allocation, then it may sell its excess allocations by means of a market auction. However,
if the Enlarged Group’s verified emissions from an installation exceed its allocated allowances, then it will
have to purchase extra allowances to cover those excess emissions from the market.
Phase III of the EU ETS will run from 2013 to 2020. In Phase III an increasing level of an installation’s
allowances will have to be purchased at market auctions, as a result of Directive 2009/29/EC of the European
Parliament and of the Council of 23 April 2009. Furthermore, the number of allowances available to
installations will decrease and allocations will be managed centrally by the EU rather than by Member
States. The costs of these allowances is built into the life-of-field cost forecasts.
Controls on the quantities of oil that can be discharged in process waters in the course of offshore operations
have been implemented in the UK by the Offshore Petroleum Activities (Oil Pollution Prevention and
Control) Regulations 2005 (the “OPPC”). Future compliance by the Heather and Thistle platforms and the
Northern Producer FPF with the OPPC may require material expenditure by the Enlarged Group if the
Enlarged Group is required to modify its operations.
The Enlarged Group operates in a competitive industry
The oil and gas industry is competitive in all its phases. The Enlarged Group’s ability to increase reserves in
the future will depend not only on its ability to exploit and develop its present assets but also on its ability
to select and acquire suitable producing assets or prospects for appraisal or exploratory drilling.
The Enlarged Group competes with numerous other participants in the search for and the acquisition of oil
and gas assets, and in the marketing of oil and gas. The Enlarged Group’s competitors include major
international oil and gas companies that may have substantially greater financial and technical resources,
staff and facilities than those of the Enlarged Group. These companies have strong market power as a result
of several factors, including the diversification and reduction of risk, including geological, price and
currency risks; increased financial strength facilitating major capital expenditures; greater integration and the
exploitation of economies of scale in technology and organisation; strong technical experience; increased
infrastructure and reserves; and strong brand recognition. Due to this competitive environment, the Enlarged
Group may be unable to acquire attractive, suitable assets or prospects on terms that it considers acceptable.
As a result, the Enlarged Group’s revenues may decline over time, thereby materially and adversely affecting
its business, results of operations and financial condition.
The Enlarged Group’s tax liability could increase substantially as a result of changes in, or new
interpretations of, tax laws in the United Kingdom
The Enlarged Group will be subject to taxation in the United Kingdom and is faced with increasingly
complex tax laws. The amount of tax the Enlarged Group pays could increase substantially as a result of
changes in, or new interpretations of, these laws, which could have a material adverse effect on its liquidity
and results of operations. During periods of high profitability in the oil and gas industry, there are often calls
for increased or windfall taxes on oil and gas revenue. Taxes have increased or been imposed in the past and
may increase or be imposed again in the future. In addition, taxing authorities could review and question the
Enlarged Group’s tax returns leading to additional taxes and penalties which could be material.
Macroeconomic risks could result in an adverse impact on the Enlarged Group’s financial condition
One of the principal uncertainties for the Enlarged Group at present is the extent to which the global
economic slowdown currently being experienced may feed through into the Enlarged Group’s 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.
15
RISKS RELATING TO THE GROUP AND, FOLLOWING COMPLETION, THE ENLARGED
GROUP
Risks relating to the Group and, following Completion, the Enlarged Group and its business
The Enlarged Group cannot accurately predict its future decommissioning liabilities
The Group, through its licence interests, has in the past assumed certain obligations in respect of the
decommissioning of its fields and related infrastructure and the Enlarged Group is expected to assume
additional decommissioning liabilities in respect of its future operations. These liabilities are derived from
legislative and regulatory requirements concerning the decommissioning of wells and production facilities
and require the Enlarged Group to make provision for and/or underwrite the liabilities relating to such
decommissioning. The oil and gas industry currently has little experience of decommissioning petroleum
infrastructure on the UKCS as few such structures have been removed in these regions. Although, the
Enlarged Group’s accounts make a provision for such decommissioning costs, there can also be no
assurances that the costs of decommissioning will not exceed the value of the long-term provision set aside
to cover such decommissioning costs. It is, therefore, difficult to forecast accurately the costs that the
Enlarged Group will incur in satisfying its decommissioning obligations and the Enlarged Group may have
to draw on funds from other sources to bear such costs. When its decommissioning liabilities crystallise, the
Enlarged Group will be jointly and severally liable for them with other former or current partners in the field.
In the event that other partners default on their obligations, the Enlarged Group will remain liable and its
decommissioning liabilities could be magnified significantly through such default. Any significant increase
in the actual or estimated decommissioning costs that the Enlarged Group incurs may adversely affect its
financial condition.
Actions of joint venture partners
Oil and gas operations globally are often conducted in a joint venture environment. Non-alignment on
various strategic decisions in joint ventures may result in operational or production inefficiencies or delay.
Where the Enlarged Group is operator, the Enlarged Group depends on its partners to meet their contractual
obligations in respect of “cash calls” and any failure to do so could have a material adverse impact on the
Enlarged Group’s operations.
Business acquisitions – integration and other issues
Part of EnQuest’s strategy is or, following the Proposed Acquisition, part of the Enlarged Group’s strategy
will be to increase oil and gas resources through strategic business acquisitions. Risks commonly associated
with acquisitions of companies or businesses include integrating the operations and personnel of the acquired
business, problems with minority shareholders in acquired companies, the potential disruption of EnQuest’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.
Risks relating to the Enlarged Group’s financial condition
Exchange rate fluctuations and devaluations could have a material adverse effect on the Enlarged
Group’s results of operations
Currency exchange rate fluctuations and currency devaluations could have a material adverse effect on the
Enlarged Group’s results of operations from time to time. As the Enlarged Group’s reporting currency is the
US dollar but it predominantly incurs operating expenses in pounds sterling, a depreciation of the US dollar
against sterling adversely affects the Enlarged Group’s reported results of operations. Although the Enlarged
Group may undertake limited hedging activities on capital expenditure in an attempt to reduce certain
currency fluctuation risks, these activities provide only limited protection against currency-related losses. In
addition, in some circumstances hedging activities may require the Enlarged Group to make cash outlays.
16
Risks relating to the Enlarged Group’s structure
The holding company structure means that the Company’s ability to pay dividends is dependent on
distributions received from its subsidiaries
Since the Company is a holding company, its operating results and financial condition are entirely dependent
on the performance of members of the Enlarged Group. Although there is no current intention to pay
dividends, the Company’s ability to pay dividends in the future will depend on the level of distributions, if
any, received from the Company’s subsidiaries. The ability of the Company’s subsidiaries to make
distributions to the Company may, from time to time, be restricted as a result of several factors, including
restrictive covenants in loan agreements, foreign exchange limitations, the requirements of applicable law
and regulatory, fiscal or other restrictions.
Participation by the Company in a distribution of a subsidiary’s assets will generally be subject to prior
claims of creditors
The Company holds all of its assets in its subsidiaries. The Company’s rights to participate in a distribution
of its subsidiaries’ assets upon their liquidation, re-organisation or insolvency is generally subject to prior
claims of the subsidiaries’ creditors, including any trade creditors and preferred shareholders.
17
PART III
SUMMARY OF THE PRINCIPAL TERMS OF THE
ACQUISITION AGREEMENT
1.
10.4.1(2)(a)
Introduction
On 25 April 2012, EnQuest Dons, a wholly owned subsidiary of the Company, entered into a conditional
farm-in agreement (the “Acquisition Agreement”) with First Oil to acquire the Kraken Interest. The
principal terms of the Acquisition Agreement are set out below.
2.
Structure of the Proposed Acquisition
Pursuant to the Acquisition Agreement, First Oil transfers to EnQuest Dons:
•
an undivided legal interest in Licence P.1077 and Licence P.1575;
•
a 15 per cent. interest in each of Block 9/2b, Block 9/2c, Block 9/6a and Block 9/7b; and
•
a corresponding beneficial interest under the licence interest documentation,
together the “Transferred Interest”.
In consideration of the transfer of the Kraken Interest, EnQuest Dons shall pay certain costs which would
otherwise be borne by First Oil as holder of its remaining 15 per cent. participating interest in Licences
P.1077 and P.1575 (the “Carried Interest”).
In addition, at Completion, First Oil has irrevocably agreed to approve the appointment of EnQuest Dons as
operator of Licence P.1077 and, following Completion, First Oil is obliged to support the appointment of
EnQuest Dons as operator of Licence P.1575.
3.
Conditions and Termination Rights
The closing of the Proposed Acquisition is conditional on the satisfaction of certain conditions, including
approval by the Shareholders at the Extraordinary General Meeting, approval by the Secretary of State and
other third party consents. Approval is currently expected to be received from the Secretary of State on or
around 13 July 2012.
The Acquisition Agreement shall terminate if the conditions are not satisfied or waived by 31 December
2012.
If at any time prior to Completion there is a breach of the warranties (or it becomes apparent there will be a
breach of the warranties) given by First Oil to EnQuest Dons as to title to the Kraken Interest giving rise to
a loss of at least US$15 million, then EnQuest Dons may terminate the Acquisition Agreement.
4.
Consideration
In consideration of the transfer of the Transferred Interest, with effect from 1 January 2012 EnQuest Dons
shall pay and discharge on behalf of First Oil costs up to a maximum amount of US$144 million attributable
to the Carried Interest incurred (i) under or in connection with a Secretary of State approved field
development plan in respect of the Kraken Field; and (ii) under an agreed budget under the joint operating
agreement for Licence P.1077. Although EnQuest Dons is liable to pay these costs with effect from 1 January
2012, since the costs to be incurred largely relate to a Secretary of State approved field development plan,
EnQuest Dons will not be committed to paying a significant part of the consideration until such a field
development plan has been submitted and approved by the Secretary of State.
18
10.4.1(2)(c)
The amount payable by EnQuest Dons as consideration is dependent on a future determination of the gross
2P reserves in the Kraken Field as determined by an independent assessor. If the determination of the 2P
reserves of the Kraken Field is:
•
less than or equal to 100 MMboe, then EnQuest Dons will pay a maximum consideration of
US$90 million;
•
less than 166 MMboe, but more than 100 MMboe, then the amount of consideration will be increased
from US$90 million by an amount of up to a further US$54 million, calculated on a linear pro-rata
basis; or
•
equal to or greater than 166MMboe, then the amount of consideration will be the maximum of
US$144 million.
In the event that a field development plan for the Kraken Field does not provide for the burning of crude oil
as the primary source of supplementary fuel and instead requires a supplementary fuel gas import line then
the consideration shall be reduced. The maximum consideration for 2P reserves of:
•
less than or equal to 100MMboe shall be US$78 million instead of US$90 million;
•
less than 166 MMboe, but more than 100 MMboe, then the amount of consideration by which such
amount is increased on a pro rata linear basis in respect of assessed reserves between 100MMboe and
166 MMboe shall be up to a maximum of US$48 million instead of US$54 million; or
•
equal to or greater than 166 MMboe, then the amount of consideration shall be up to a maximum of
US$126 million instead of US$144 million.
As mentioned above, the effect of the structure of the consideration payable by EnQuest Dons is such that
EnQuest Dons will not be committed to paying a significant part of the consideration until the Secretary of
State’s approval of the field development plan in respect of the Kraken Field has been obtained and a viable
development project has been formulated. Therefore, considerable flexibility is maintained for EnQuest
without having to commit significant amounts of funding.
5.
First Oil’s Right of Re-Transfer
In the event that:
•
EnQuest Dons is in material breach of its obligations to pay any amount of consideration due in
respect of the Carried Interests; or
•
a field development plan has not been submitted to the Secretary of State for the DECC by
31 December 2013 (or such other date as the parties may agree acting reasonably), then First Oil may
require EnQuest Dons to re-assign and re-transfer the Transferred Interest to it.
6.
Warranties and Indemnities
The parties mutually indemnify each other for liabilities in respect of the Transferred Interests before and
after 1 January 2012 with First Oil bearing the risk prior to such date and EnQuest Dons after such date.
Notwithstanding the mutual indemnities noted above, EnQuest Dons indemnifies First Oil against all
decommissioning and environmental liabilities in respect of the Transferred Interests except to the extent
they arise out of the wilful misconduct of First Oil.
First Oil provides customary warranties to EnQuest Dons including in respect of due incorporation,
authorisation, solvency, material litigation, insurance, title to the Transferred Interests, the Licences, the
Licence Interest Documents, defaults under the Licences or the Licence Interest Documents, sole risk notices
and operations, material health and safety issues, abandonment, decommissioning and plugging of wells.
EnQuest Dons provides customary warranties to First Oil in respect of its incorporation, authorisation,
material disputes and solvency.
19
7.
Warranty Claims
The liability of First Oil with respect to its warranties is subject to a number of limitations including: (i)
EnQuest Dons must make a claim within 15 months of Completion; (ii) no claims may be made by EnQuest
Dons until aggregate losses suffered exceed US$100,000; and (iii) First Oil’s maximum liability under the
warranties shall be 100 per cent. of the costs paid by EnQuest Dons in respect of the Carried Interests.
8.
EnQuest right of first offer in respect of the Carried Interest
If First Oil intends to sell the Carried Interest then it must notify EnQuest Dons. EnQuest Dons shall have
the right to make an offer, and if that offer is not accepted by First Oil then, First Oil may, for six months
thereafter, sell the Carried Interest to a third party, but not for consideration with a value less than the cash
equivalent value of that offered by EnQuest Dons.
9.
Governing Law and Dispute Resolution
The Acquisition Agreement is governed by the laws of England and Wales. The courts of England are given
exclusive jurisdiction for the resolution of disputes.
10.
Guarantee
At Completion, EnQuest shall be obliged to guarantee to First Oil the obligations and liabilities of EnQuest
Dons under the Acquisition Agreement.
20
PART IV
ADDITIONAL INFORMATION
1.
RESPONSIBILITY STATEMENTS
1.1
The Directors (whose names appear on page 4 of this document) accept responsibility for the
information contained in this document. To the best of the knowledge and belief of the Directors (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 omissions likely to affect the import of such
information.
1.2
Gaffney, Cline & Associates whose registered address is at Bentley Hall, Blacknest, Alton, Hampshire
GU34 4PU, United Kingdom, accepts responsibility for the CPR set out in Part V of this document.
To the best of the knowledge and belief of Gaffney, Cline & Associates (which has taken all
reasonable care to ensure that such is the case) the information contained therein is in accordance with
the facts and contains no omissions likely to affect the import of such information.
2.
THE COMPANY AND THE DIRECTORS
2.1
The Company was incorporated and registered in England and Wales on 29 January 2010 with
registered number 7140891 under the Companies Act as a public limited company with the name
EnQuest PLC. The principal legislation under which the Company operates and the Ordinary Shares
have been created is the Companies Act.
2.2
The registered office and the principal place of business in the United Kingdom of the Company is at
Rex House, 4-12 Regent Street, London SW1Y 4PE (telephone number (0)20 7925 4900 or, if dialling
from outside the United Kingdom, +44 (0)20 7925 4900).
3.
DIRECTORS’ INTERESTS
3.1
As at 27 June 2012 (being the latest practicable date prior to the date of publication of this document),
the interests of each Director, their immediate families and related trusts and, insofar as is known to
them or could reasonable diligence be ascertained by them, persons connected (within the meaning of
section 252 of the Companies Act) with the Directors (all of which, unless otherwise stated, are
beneficial) in the Ordinary Shares, including interests arising pursuant to any transaction notified to
the Company in accordance with rule 3.1.2 of the Disclosure and Transparency Rules, are as follows:
13.4.1(4)
13.4.1(6)
I.5.1.1
I.5.1.4
I.17.2
As at 27 June 2012
Directors
Dr. James Buckee
Amjad Bseisu(1)
Jonathan Swinney
Nigel Hares
Helmut Langanger
Jock Lennox
Clare Spottiswoode
Number of
Ordinary Shares
% of existing
issued
share capital
868,107
70,797,182
62,033
3,455,000
–
20,000
–
0.11
8.82
–
0.43
–
–
–
I.17.2
Notes:
(1) These Ordinary Shares are held by Double A Limited, a discretionary trust in which the extended family of Amjad Bseisu
has a beneficial interest.
3.2
The Company operates, inter alia, the EnQuest PLC Performance Share Plan 2010 (the “PSP”) and
the EnQuest PLC Restricted Share Plan (the “RSP” and together, the “Share Plans”). The Share
Plans were adopted and approved by Shareholders on 18 March 2010. The key terms of the Share
21
I.17.2
Plans were summarised in paragraphs 6.2 and 6.4 of Part XI (Additional Information) of the
Prospectus, which is incorporated by reference into this document.
3.3
In addition to the Share Plans, the Company operates the EnQuest PLC Sharesave Scheme
(“Sharesave Scheme”), which was adopted and approved by the Directors on 23 February 2012, with
the Shareholders’ approval of the satisfaction of the options granted under the Sharesave Scheme
being satisfied by way of issued shares in the capital of the Company being obtained at the Company’s
annual general meeting held on 30 May 2012. The key terms of the Sharesave Scheme were
summarised in the appendix entitled “Summary of the EnQuest PLC 2012 Sharesave Scheme” to the
Company’s notice of annual general meeting held on 30 May 2012, which is incorporated by
reference into this document.
I.17.2
3.4
The following options over Ordinary Shares have been granted to the Directors under the RSP and are
outstanding as at 27 June 2012 (being the latest practicable date prior to publication of this document):
I.17.2
Name of Director
Amjad Bseisu
Nigel Hares(1)
Jonathan Swinney
Number of Ordinary
Shares under option
1,609,063
591,324
268,177
804,532
536,354
163,387
Vesting Period
Expiry Date
1 April 2012 - 1 April 2014
19 April 2012 - 19 April 2014
1 April 2011
1 April 2012 - 1 April 2014
1 April 2012 - 1 April 2014
19 April 2012 - 19 April 2014
31 March 2020
18 April 2020
31 March 2020
31 March 2020
31 March 2020
18 April 2020
Notes:
(1) An amount of 268,177 nil cost award shares granted to Nigel Hares under the RSP vested in 2011 but were not exercised.
They were rolled over in line with the RSP plan rules.
3.5
The following awards to acquire Ordinary Shares under the PSP have been granted to the Directors:
Name of Director
Granted
First Vesting Date
Expiry Date
Amjad Bseisu
583,090
391,790
443,148
317,164
324,975
254,663
19 April 2014
19 April 2015
19 April 2014
19 April 2015
19 April 2014
19 April 2015
18 April 2021
18 April 2022
18 April 2021
18 April 2022
18 April 2021
18 April 2022
Nigel Hares
Jonathan Swinney
I.17.2
The vesting of awards is subject to achievement of performance conditions.
3.6
On 11 May 2012, Jonathan Swinney was granted the option to acquire 9,000 Ordinary Shares under
the Sharesave Scheme.
I.17.2
3.7
On 1 April 2010, a one-off award of 1,416,880 Ordinary Shares was made to the Chairman, James
Buckee, on substantially the same terms as the RSP, which vests in such proportions as the
Remuneration Committee determines on the third, fourth and fifth anniversaries of the date of the
grant. Following the Remuneration Committee’s determination, the first vesting date was on 2 April
2012 whereby 176,737 Ordinary Shares vested.
I.17.2
3.8
Save as disclosed in paragraphs 3.1, 3.4, 3.5, 3.6 and 3.7 above, the Directors do not have any interests
in the share capital of the Company.
I.17.2
4.
DIRECTORS’ SERVICE AGREEMENTS
10.4.1(2)(g)
4.1
Amjad Bseisu has a service agreement with EnQuest Britain (a subsidiary undertaking of the
Company). He is entitled to an annual salary of £395,000. Jonathan Swinney has a service agreement
with EnQuest Britain. He is entitled to an annual salary of £255,000. Nigel Hares has a service
agreement with EnQuest Britain. He is entitled to an annual salary of £290,000. James Buckee has a
letter of appointment with the Company. He is entitled to an annual fee of £200,000. The other non-
I.16.2
22
executive directors of the Company have each entered into letters of appointment with the Company
and are each entitled to an annual fee of £45,000, with the exception of the non-executive directors,
Helmut Langanger and Jock Lennox, who are entitled to an additional £8,000 each as payment for
chairing the remuneration committee and the audit committee respectively.
4.2
Further details of the service agreements of the executive directors and the terms of appointment of
the non-executive directors (with the exception of Alexandre Schneiter, who retired as a non-executive
director of the Company on 30 May 2012) are included in the Remuneration Report section of the
Company’s 2011 annual report and accounts.
5.
MAJOR INTERESTS IN ENQUEST SHARES
5.1
So far as is known to the Company, as at 27 June 2012 (being the latest practicable date prior to the
date of publication of this document), the names of persons (other than a Director) who are, directly
or indirectly, interested in three per cent. or more of the voting rights in the Company and the capital
of the Company in issue, and the amount of such person’s interest, is as follows:
I.18.1
As at 27 June 2012
% of voting
rights in
respect of
Number of existing issued
Ordinary Shares
share capital
Shareholder
Baillie Gifford & Co
Swedbank Robur Asset Management
Ayman Asfari and family(1)
Investec Asset Management
39,446,123
36,005,418
32,583,982
27,025,081
4.91
4.49
4.06
3.37
Notes:
(1) Includes the interests of Lamia Trust and LAM Trust.
5.2
The Company is not aware of any person who exercises, or could exercise, directly or indirectly,
jointly or severally, control over the Company.
6.
MATERIAL CONTRACTS
Save for the Acquisition Agreement, the principal terms of which are summarised in Part III of this
document, and as disclosed below, no contracts have been entered into (other than contracts entered into in
the ordinary course of business) by any member of the Group either: (i) within the period of two years
immediately preceding the date of this document, which are or may be material to the Group; or (ii) which
contain any provisions under which any member of the Group has any obligation or entitlement which is, or
may be, material to the Group as at the date of this document:
6.1
Acquisition by EnQuest of the entire issued share capital in Canamens Energy North Sea Limited
(“CENSL”)
On 8 January 2012 Canamens Limited (the “Seller”) and EnQuest entered into an agreement relating
to the acquisition, subject to satisfaction of certain conditions precedent, of 100 per cent. of the issued
share capital of CENSL (the “CENSL Shares”) by EnQuest. EnQuest completed the acquisition of
the CENSL Shares on 31 January 2012 (“CENSL Closing”).
The consideration payable for the CENSL Shares comprised initial consideration and contingent
consideration. The initial consideration was payable on CENSL Closing and was US$35,000,000,
subject to certain adjustments, including, inter alia: (a) any amounts paid by the Seller under an
informal capital contribution agreement during the period of 31 October 2011 to CENSL Closing; (b)
any amounts owing to the Seller pursuant to an asset management agreement; and (c) interest
calculated pursuant to the agreement. The contingent consideration is US$45,000,000 and payable,
except as otherwise set out therein, within 30 days of the date of the Secretary of State’s authorisation
23
I.18.1
I.22
of a field development plan by for a development programme for the development of a discovery
relating to Licence P.1077.
Under the terms of the agreement, the Seller provided warranties to EnQuest relating to, among other
things, title to the CENSL Shares, capacity and authority to enter into the agreement, and general
business, operational and tax warranties. The Seller’s liability to EnQuest under the warranties is
limited to, in respect of any taxation warranties, 6 years from the date of CENSL Closing, and
15 months from the date of CENSL Closing in respect of any other claim.
EnQuest has agreed, in the event that the Secretary of State requires CENSL to submit, fund, or carry
out a decommissioning programme or otherwise pay monies in respect of residual liabilities relating
to the P.1077, P.1573, P.1574 and P.1575 Licences (the “Liabilities”), to procure that CENSL
complies and funds all such obligations and, in the event CENSL fails to do so, EnQuest shall
indemnify the Seller for all costs incurred by the Seller, its shareholders or affiliates against such
Liabilities.
6.2
Acquisition by EnQuest of the entire issued share capital in Canamens UK 814 and 815 Limited
(“CUKL”)
On 8 January 2012 Canamens Limited (the “Seller”) and EnQuest entered into an agreement relating
to the acquisition, subject to completion of EnQuest’s acquisition of the CENSL Shares referred to
above, of 100 per cent. of the issued share capital of CUKL (the “CUKL Shares”) by EnQuest.
EnQuest completed the acquisition of the CUKL Shares on 31 January 2012 (“CUKL Closing”).
The consideration payable for the CUKL Shares was US$10,000,000, payable on CUKL Closing.
Under the terms of the agreement, the Seller provided certain warranties to EnQuest relating to,
among other things, title to the CUKL Shares, capacity and authority to enter into the agreement, and
general business, operational and tax warranties. The Seller’s liability to EnQuest under the warranties
is limited to, in respect of any taxation warranties, 6 years from the date of CUKL Closing, and
15 months from the date of CUKL Closing in respect of any other claim.
EnQuest has agreed, in the event that the Secretary of State requires CUKL to submit, fund, or carry
out a decommissioning programme or otherwise pay monies in respect of residual liabilities relating
to the P.1278 Licence (the “Liabilities”), to procure that CUKL complies and funds all such
obligations and, in the event CUKL fails to do so, EnQuest shall indemnify the Seller for all costs
incurred by the Seller, its shareholders or affiliates against such Liabilities.
6.3
Acquisition of an interest in the Crawford and Porter fields
On 9 May 2011 EnQuest Heather and Fairfield Acer Limited (“Fairfield”) entered into an agreement
(the “Crawford Porter Acquisition Agreement”) relating to the transfer of an interest in Licence
P.209, a 32 per cent. participating interest in Block 9/28a Area B and a corresponding interest under
relevant licence interest documents (the “Interests”) by Fairfield to EnQuest Heather. The Interests
were transferred in consideration for the payment by EnQuest Heather of the development and
appraisal costs incurred from 1 January 2011 in respect of a development programme for the Porter
Field and the Crawford Field which would otherwise have been payable by Fairfield in respect of its
remaining 20 per cent. interest in Block 9/28a Area B, up to a maximum of £34.85 million.
If a development programme in respect of the Porter field and the Crawford field has not been
submitted by to the Secretary of State by 30 June 2013, then Fairfield may within six months of such
date require EnQuest Heather to re-transfer the Interests to it for nominal consideration. If EnQuest
Heather defaults in its payment of the development and appraisal costs payable by it under the
Crawford Porter Acquisition Agreement, Fairfield may require EnQuest Heather to transfer to
Fairfield a proportion of the Interests equal to the proportion of £34.85 million represented by the
defaulted payment.
EnQuest Heather has indemnified Fairfield against decommissioning and environmental liabilities
arising in respect of the Interests with effect from 1 January 2011. Fairfield provided EnQuest Heather
24
with customary warranties. The warranties are subject to certain limitations including a cap on
Fairfield’s liability of £34.85 million and a time limit for bringing claims of 30 June 2012.
By a guarantee dated 30 June 2011, EnQuest Britain guaranteed to Fairfield the obligations and
liabilities of EnQuest Heather under the Crawford Porter Acquisition Agreement.
6.4
Arrangement Agreement with Stratic Energy Corporation (“Stratic”)
Stratic and EnQuest entered into an arrangement agreement on 2 August 2010 under which they
agreed to implement a business combination by way of a plan of arrangement (the “Arrangement
Agreement”). The Arrangement Agreement contained representations and warranties from EnQuest
(none of which have survived the implementation of the plan of arrangement) and various conditions
precedent.
The acquisition of Stratic was completed on 5 November 2010, whereby the Group acquired 100 per
cent. of the issued share capital of Stratic for a consideration of US$54,163,000, satisfied by the issue
and allotment of 24,434,983 Ordinary Shares.
6.5
Acquisition of interests, inter alia in the Kraken Field, from Nautical Petroleum PLC and Nautical
Petroleum AG
On 24 January 2012 EnQuest Dons, Nautical Petroleum PLC (“Nautical PLC”) and Nautical
Petroleum AG (“Nautical AG” and together with Nautical PLC, the “Sellers”) entered into an
agreement (the “Nautical Acquisition Agreement”) relating to the transfer of interests in Licence
P.1077, Licence P.1573, Licence P1574 and Licence P.1575, a 25 per cent. participating interest in
Block 9/2b, a 25 per cent. participating interest in Block 9/2c, a 10 per cent. participating interest in
each of Block 9/6a and Block 9/7b, a 15 per cent. participating interest in each of Block 3/22a and
Block 3/26 and a corresponding interest under the relevant licence interest documents (the
“Interests”) by the Sellers to EnQuest Dons. The Interests were transferred in consideration for the
payment by EnQuest Dons of the development costs (other than operator costs) incurred from
1 January 2012 in respect of a development programme for the Kraken Field which would otherwise
have been payable by the Sellers in respect of their aggregate remaining 25 per cent. interest in
Licence P.1077, up to a maximum of US$150 million, plus an amount dependent on a future
determination of the gross 2P reserves in the Kraken Field.
The amount payable by EnQuest Dons as additional consideration may increase dependent on a future
determination of the gross 2P reserves in the Kraken Field as determined by a competent person. If
the determination of the 2P reserves of the Kraken Field is:
(a)
less than or equal to 100 MMboe, then EnQuest Dons will pay no further consideration to the
Sellers;
(b)
equal to or greater than 166MMboe, then EnQuest Dons will pay a further US$90 million of
consideration to the Sellers; and
(c)
greater than 100 MMboe but less than 166 MMboe, then EnQuest Dons will pay a further
amount of consideration to the Sellers equal to a proportion of US$90 million pro rated on a
linear basis to the amount by which the reserves are determined to be in excess of 100 MMboe
but less than 166 MMboe.
In the event that a field development plan approved by the Secretary for State for the Licence P.1077
does not provide for the burning of crude oil as the primary source of supplementary fuel and instead
requires a supplementary fuel gas import line then the maximum initial amount payable by EnQuest
Dons as consideration under the Nautical Acquisition Agreement shall be reduced from
US$150 million to US$130 million and the additional maximum consideration payable shall be
reduced from US$90 million to US$80 million (the actual amount payable otherwise being calculated
in the same manner as stated above).
25
Under the Nautical Acquisition Agreement, Nautical PLC also grants the right to EnQuest Dons to
acquire an interest in Licence P.1759 and a percentage interest in Block 9/1a (including the Ketos
discovery) equal to the Group’s interest in Block 9/2 at the time of the exercise of the option (up to a
maximum of 50 per cent.). The option must be exercised prior to the later of: (i) three calendar months
from the date Nautical PLC makes a new seismic survey of the relevant area available to EnQuest
Dons; and (ii) 30 June 2012.
If EnQuest Dons defaults in its payment of the development costs payable by it under the Nautical
Acquisition Agreement or, if a field development plan in respect of Licence P.1077 has not been
submitted by to the Secretary of State by 31 May 2013 (or such other date agreed by the parties acting
reasonably), then the Sellers may within 30 days of such event require EnQuest Dons to re-transfer to
them the Interests.
EnQuest Dons has indemnified the Sellers against decommissioning and environmental liabilities
arising in respect of the Interests with effect from 1 January 2012. The Sellers provided EnQuest Dons
with customary warranties. The warranties are subject to certain limitations including a cap on the
Sellers’ liability of the amounts payable by EnQuest Dons under the Nautical Acquisition Agreement
and a time limit for bringing claims of 16 June 2013.
By a guarantee dated 15 March 2012, EnQuest guaranteed to the Sellers the obligations and liabilities
of EnQuest Dons under the Nautical Acquisition Agreement.
6.6
The Facility Agreement
Overview
EnQuest and certain of its subsidiaries entered into an English law governed credit agreement on
6 March 2012 with, amongst others, Lloyds TSB Bank Plc, BNP Paribus, Barclays Corporate, The
Royal Bank of Scotland Plc, Banc of America Securities Limited and Credit Agricole Corporate and
Investment Bank (as mandated lead arrangers), NIBC Bank N.V. (as lead arranger) and Lloyds TSB
Bank Plc (as facility agent) (referred to hereafter as the “Facility Agreement”).
The Facility Agreement provides a multicurrency revolving credit facility, the aggregate commitments
of which start at US$525 million but may be increased, with the agreement of the lenders, to US$900
million (the “Aggregate Commitments”). The Facility Agreement allows for nine of the Enlarged
Group’s companies (EnQuest and certain subsidiaries) to borrow funds (“Borrowers”). The
obligations on the Enlarged Group under the Facility Agreement are guaranteed by the Borrowers and
three additional group companies (collectively, the “Guarantors”).
The Borrowers’ obligations under the Facility Agreement are secured by way of (i) charges over the
shares of all the Borrowers (except for EnQuest) and EnQuest Britain Ltd, which is a Guarantor only,
and (ii) floating charges over the assets of all the Borrowers.
Purpose
The Facility Agreement provides funding to the Enlarged Group for general corporate purposes.
The facilities may also be used by the Borrowers to obtain letters of credit (“LOCs”) in connection
with the operation, development and decommissioning of petroleum assets, and infrastructure related
to such assets.
Utilisations and interest
The amount of funds that the Borrowers may draw under the Facility Agreement is limited to the
lower of (i) the Aggregate Commitments, and (ii) the maximum amount that may be drawn without
the Borrowers breaching the financial covenants less US$5,000,000. The amount drawn under the
LOCs is limited to the greater of (a) US$300 million and (b) 50 per cent. of the Aggregate
Commitments. A utilisation request made in US dollars must be in a minimum amount of
US$5 million; a request in sterling, £3 million; and a request in euros, €3 million.
26
Loans made under the Facility Agreement bear interest at the aggregate of (a) an agreed margin
ratchet that varies depending on the group’s leverage ratio; (b) LIBOR or, in the case of any euro loan,
EURIBOR; and (c) additional mandatory costs of the lenders (if any). Interest on overdue amounts is
charged at a rate of 2 per cent. above the rate at which loans are drawn down or LOCs are issued under
the Facility Agreement.
Cancellation and repayment
EnQuest is able to cancel the unutilised amount of the total commitments in whole or in part. Partial
cancellation of Facility Agreement commitments must be in a minimum amount of US$1 million and
an integral multiple of US$1 million. In addition, the Facility Agreement will allow voluntary
prepayment of a loan, on the giving of five business days’ notice, provided that each voluntary
prepayment is a minimum of US$1 million (or the equivalent in other currencies where the loan is in
another currency).
Each lender may request mandatory prepayment of its outstanding loans/LOCs if a change of control
occurs. A ‘change of control’ is defined in the Facility Agreement as occurring if any person or group
of persons acting in concert gains control of EnQuest.
Maturity
Each Borrower which has drawn a loan shall repay that loan in full on the last day of the interest
period chosen by such Borrower for that loan. As is typical with a revolving facility, the amounts that
are repaid may then be re-borrowed. Each LOC issued shall expire one month before the final
maturity date of the facilities unless such LOC is deemed to be an extended LOC where, subject to
certain conditions, it shall expire 5 years after the final maturity date of the facility. The final maturity
date for the facility is three years from the date that the Facility Agreement is entered into, subject to
a provision which allows EnQuest, provided certain conditions are met, to extend the Facility
Agreement for a further year (i.e. four years from the date of the Facility Agreement) and a further
provision that subsequently allows EnQuest, with lender consent and provided certain conditions are
met, to again extend the Facility Agreement for a further year (i.e. five years from the date of the
Facility Agreement).
Controls on the Enlarged Group’s activities
The Facility Agreement contains customary representations and warranties and affirmative and
negative covenants. In particular, unless the lenders agree in writing, neither EnQuest nor any other
Borrower or Guarantor under the Facility Agreement may enter into a merger or reconstruction.
Coupled with this, neither EnQuest nor any of its subsidiaries may enter into any transaction that is a
Class 1 transaction unless it is agreed to by the lenders and certain conditions are met. The Facility
Agreement also contains a negative pledge, restrictions on financial indebtedness and disposals and
requires, at the Enlarged Group level, the maintenance of specified leverage, reserve based value and
interest cover ratios.
The Facility Agreement contains certain customary events of default for this type of facility,
including:
(a)
any event or series of events which has, or is reasonably likely to have, a material adverse effect
on the business or financial condition of any Borrower or Guarantor.
(b)
a cross-default provision applicable if a debt, or an aggregate of debts, valued at US$1 million
or more is not paid when due (after the expiry of any grace period);
(c)
if all or any part of any petroleum asset or petroleum or revenues derived from any petroleum
asset is nationalised, expropriated, compulsory acquired or seized by any government entity or
any such government entity announces that it shall take such action and that action it is likely
to have a material adverse effect on the business or financial condition of any Borrower or
Guarantor; or
27
(d)
6.7
the initiation of certain insolvency proceedings by any Borrower or Guarantor.
Disposal of interests in the Alma Field and the Galia Field to KUFPEC UK Limited
On 29 May 2012, EnQuest Heather and KUFPEC UK Limited (“KUFPEC”) entered into an
agreement (the “KUFPEC Disposal Agreement”) relating to the disposal of interests, by EnQuest
Heather to KUFPEC, in Licence P. 1765 and Licence P. 1825, a 35 per cent. interest in each of
Block 30/24b, Block 30/24c and Block 30/25c, a 35 per cent. interest in asset data (in the possession
of under the control of EnQuest Heather), assets and property derived from Licence P. 1765 and
Licence P. 1825, and a corresponding interest under the relevant licence interest documents (together
the “A&G Interests”). The A&G Interests are to be transferred, following the satisfaction of certain
conditions (described below), in consideration for the payment by KUFPEC:
(a)
of the costs that have been and will be incurred by EnQuest Heather in relation to the A&G
Interests during the period between 1 January 2012 and the date the A&G Interests are
transferred to KUFPEC (the “Transfer Date”);
(b)
of up to 90 per cent. of the costs arising, from and including the Transfer Date, in respect of
the A&G Interests in accordance with the terms of the agreed form joint operating agreement
to be entered into on the Transfer Date by EnQuest Heather and KUFPEC (the “A&G JOA”);
and
(c)
of the development costs (excluding such costs for equipment items) incurred, from and
including the Transfer Date, for the both the A&G Interests and EnQuest Heather’s 65 per cent.
carried interest in the Alma Field and the Galia Field up to a maximum sum of US$182 million
(the “Cap”).
Following the exhaustion of the Cap, the development costs for the A&G Interests shall be satisfied
by EnQuest Heather and KUFPEC in accordance with their respective participating interests in the
Alma Field and the Galia Field in accordance with the A&G JOA.
As security for the payment by KUFPEC of such development costs referred to in (c) above, KUFPEC
has agreed to procure, on the Transfer Date, a letter of guarantee under which KUFPEC’s payment
obligations under the KUFPEC Disposal Agreement are guaranteed by Deutsche Bank in favour of
EnQuest Heather up to the value of the Cap.
The transfer of the A&G Interests is conditional upon the satisfaction of certain conditions, including
the Secretary of State’s approval of the transfer of the A&G Interests, the execution by EnQuest
Heather and KUFPEC of assignment documentation, and the agreement by EnQuest Heather and
KUFPEC of the forms of a construction and tie-in agreement and an operation maintenance and
services agreement. In the event that these conditions are not satisfied or waived by 31 December
2012 (or such other date agreed by EnQuest Heather and KUFPEC), the KUFPEC Disposal
Agreement shall terminate upon notice.
If on 1 January 2017, the development costs KUFPEC has incurred and paid, in respect to the A&G
Interests (including the carried costs paid in accordance with (c) above) (the “KUFPEC Costs”),
exceeds the higher of: (i) the actual revenue (net of operating expenditure) KUFPEC has received
from the sale of petroleum relating to the A&G JOA; or (ii) the deemed revenue (net of operating
expenditure) in accordance with a US dollar multiplier, specified in the KUFPEC Disposal
Agreement, based on the A&G Interests’ share of the number of barrels of petroleum produced by the
Alma Field and the Galia Field, then KUFPEC shall be entitled, from 1 January 2017, to receive from
EnQuest Heather an additional 20 per cent. share of the revenue (net of operating expenditure)
received from the sale of petroleum relating to the A&G JOA (the “Additional Revenue”). EnQuest
Heather shall continue to attribute this Additional Revenue to KUFPEC until the earlier of: (i) the date
the actual revenue (net of operating expenditure) KUFPEC has received from the sale of petroleum
relating to the A&G JOA equals or exceeds the KUFPEC Costs; or (ii) the date the deemed revenue
(calculated in accordance with the formula described above) equals or exceeds the KUFPEC Costs.
28
EnQuest Heather has agreed, with effect from the Transfer Date, to indemnify KUFPEC in respect of
any liabilities in respect to the A&G Interests that accrued in or relate to the period prior to 1 January
2012. Furthermore, EnQuest has agreed, with effect from the Transfer Date, to guarantee the
obligations and liabilities of EnQuest Heather under the KUFPEC Disposal Agreement.
Completion of the transfer of the A&G Interests is currently expected to complete in July 2012.
6.8
Heather Field Arrangements
The Enlarged Group’s decommissioning liabilities in respect of the Heather field are not based on its
equity interest in this field. Instead, the Enlarged Group’s decommissioning liabilities are based on a
contractual obligation of 37.5 per cent. of such decommissioning liability, for which there is: (i) a
letter of credit in place expiring on 6 February 2014 (or as extended), for the sum of US$5 million,
issued by BNP Paribas on behalf of EnQuest Heather and in favour of Unocal International
Corporation (“Unocal”); and (ii) a letter of credit in place expiring on 31 December 2012 (or as
extended), for the sum of £75 million issued by BNP Paribas on behalf of EnQuest Heather and in
favour of BG Great Britain Limited (“BGGL”) (the “Letters of Credit”). Pursuant to the terms of the
Letters of Credit, BNP Paribas, as the issuing bank, is required to pay the respective values of the
Letters of Credit on demand from Unocal or BGGL.
6.9
Thistle and Deveron Field Arrangements
Your attention is drawn to details of the “Thistle and Deveron Field Arrangement” set out in paragraph
16.6 of Part XI (Additional Information) of the Prospectus with the subheadings “Intervening Period
Agreement” and “Retransfer Sale and Purchase Agreement” only, such sections being incorporated
by reference into this document.
7.
LITIGATION
7.1
There are no, and there have not been, any governmental, legal or arbitration proceedings (including
any such proceedings which are pending or threatened of which the Company is aware) during the
12 months prior to the date of this document which may have, or have had in the recent past, a
significant effect on the Company’s and/or the Group’s financial position or profitability of the Group.
7.2
There are no, and there have not been, any governmental, legal or arbitration proceedings (including
any such proceedings which are pending or threatened of which the Company is aware) during the 12
months prior to the date of this document which may have, or have had in the recent past, a significant
effect on the financial position or profitability of the Kraken Interest.
8.
WORKING CAPITAL
The Company is of the opinion that, taking into account the cash and other facilities available to the Enlarged
Group, the Enlarged Group has sufficient working capital for its present requirements, that is, for at least the
next twelve months from the date of publication of this document.
9.
SIGNIFICANT CHANGE
9.1
Save for entering into the Facility Agreement disclosed in paragraph 6.6 of this Part IV of this
document, the Canamens Acquisition disclosed in paragraphs 6.1 and 6.2 of this Part IV of this
document, the Nautical Farm-In Agreement disclosed in paragraph 6.5 of this Part IV of this
document, the Alma/Galia Farm-Out disclosed in paragraph 6.7 of this Part IV of this document, there
has been no significant change in the financial or trading position of the Company since 31 December
2011, being the date on which the audited annual report and accounts 2011 were prepared.
9.2
As a result of the Alma/Galia Farm-Out, while it enhances the economics of the project by farming
out 35 per cent. of the gross production, EnQuest will therefore reduce its anticipated net production
by approximately 7,000 Boepd in 2014 (previous estimate in excess of 40,000 Boepd) and by
29
I.20.8
III.3.1
I.20.9
approximately 1,750 Boepd in 2013 (previous estimate 25,000 to 30,000 Boepd). EnQuest’s overall
company net production outlook will similarly be reduced.
10.
FINANCIAL INFORMATION
Due to the nature of the carry arrangement, there is no initial consideration and therefore the Directors
believe that, as at the date of Completion, the Proposed Acquisition has no material effect on the Group’s
earnings, assets and liabilities.
11.
RELATED PARTY TRANSACTIONS
Save as set out in note 26 to the Notes to the Group Financial Statements section of the Company’s annual
reports and accounts 2011, and note 23 to the Notes to the Group Financial Statements section of the
Company’s annual reports and accounts 2010, there have been no related party transactions during the
financial years ended 31 December 2010 and 2011.
12.
13.4.1(5)
I.19
CONSENTS
12.1 Gaffney, Cline & Associates Limited has given and not withdrawn its written consent to the inclusion
of the CPR in Part V of this document and/or extracts therefrom and the references thereto and to its
name in the form and context in which they appear, in this document.
13.4.1(6)
12.2 Merrill Lynch International, has given and not withdrawn its consent to the inclusion in this document
of the references to its name in the form and context in which they appear in this document.
13.3.1(10)
13.
INFORMATION INCORPORATED BY REFERENCE
Information from the following documents (or parts of documents) has been incorporated in this document
by reference:
(a)
paragraphs 6.2 and 6.4 of Part XI (Additional Information) of the Prospectus;
(b)
paragraph 16.6 of Part XI (Additional Information) of the Prospectus with the subheadings
“Intervening Period Agreement” and “Retransfer Sale and Purchase Agreement” only;
(c)
the sections entitled “Remuneration Report” and “Notes to the Group Financial Statements”
contained in the Company’s 2011 annual report and accounts; and
(d)
the section entitled “Notes to the Group Financial Statements” contained in the Company’s 2010
annual report and accounts.
14.
DOCUMENTS AVAILABLE FOR INSPECTION
Copies of the following documents will be available for inspection during normal business hours on any
weekday (Saturday, Sundays and public holidays excepted) at Rex House, 4-12 Regent Street, London,
SW1Y 4PE, United Kingdom (the Company’s registered office) and the offices of CMS Cameron McKenna
LLP, Mitre House, 160 Aldersgate Street, London, EC1A 4DD, United Kingdom from the date of this
document up to and including 16 July 2012:
(a)
the articles of association of the Company;
(b)
the Acquisition Agreement;
(c)
the Competent Person’s Report set out in Part V of this document;
(d)
the letters of consent referred to in paragraph 12 above; and
(e)
this document and the Form of Proxy.
30
I.24
PART V
COMPETENT PERSON’S REPORT
ON THE KRAKEN FIELD, UK NORTH SEA
Prepared for
ENQUEST Plc
JUNE, 2012
.
www.gaffney-cline.com
EnQuest Plc
Copy No.
31
EL-12-208200
Page No.
INTRODUCTION .....................................................................................................
1
EXECUTIVE SUMMARY .........................................................................................
4
DISCUSSION .........................................................................................................
5
1.
BACKGROUND ...........................................................................................
5
2.
GEOLOGICAL SETTING .............................................................................
7
3.
FIELD GEOLOGY ........................................................................................
9
4.
GEOPHYSICS AND SEISMIC MAPPING ...................................................
11
5.
STATIC MODEL...........................................................................................
13
6.
PETROPHYSICS .........................................................................................
15
7.
RESERVOIR ENGINEERING ......................................................................
15
8.
DYNAMIC MODEL .......................................................................................
17
9.
DRAFT FIELD DEVELOPMENT PLAN .......................................................
19
10.
CONTRACT AND FISCAL TERMS .............................................................
21
11.
CONTINGENT RESOURCE ESTIMATES ...................................................
21
12.
QUALIFICATIONS .......................................................................................
22
13.
BASIS OF OPINION ....................................................................................
23
Summary of Kraken Field Ownership ..........................................................
Licence Summary as at 31st March, 2012 ....................................................
Summary of Gross and Net Unrisked Oil Contingent Resources as at
31st March, 2012 ..........................................................................................
Summary of Gross and Net Unrisked Oil Contingent Resources after
First Oil Acquisition ......................................................................................
Summary of Kraken Field HCM Recoverable Volumes ...............................
Summary of Kraken Field FFM Recoverable Volumes ................................
Summary of Gross and Net Unrisked Oil Contingent Resources as at
31st March, 2012 ..........................................................................................
Summary of Gross and Net Unrisked Oil Contingent Resources after
First Oil Acquisition ......................................................................................
4
4
Tables
0.1
0.2
0.3
0.4
8.1
8.2
11.1
11.2
32
5
5
18
19
22
22
Page No.
Figures
0.1
1.1
2.1
2.2
2.3
3.1
4.1
5.1
5.2
7.1
8.1
8.2
9.1
Kraken Field Location Map ..........................................................................
9/02-1 Reservoir Summary ..........................................................................
East Shetland Platform Paleocene Stratigraphy ..........................................
East Shetland Platform and Slope: Heimdal Sedimentology .......................
Regional Sedimentology Model Integrated with Basin Reconstruction
& Amplitudes ................................................................................................
Heimdal Unit III Geomodel: Top Heimdal Unit III Depth Shading and
Faults ...........................................................................................................
N-S Seismic Line (Inline 3260) Illustrating Core Area and Extended Pick ...
Kraken Geomodel: Top Heimdal Unit III Main Depth ...................................
Net:Gross “Holes” Case ...............................................................................
9/02b-4 DST Flow Periods ...........................................................................
Kraken Development Area Porosity Map from Simulation Model ................
Full Field Model Best Estimate Case ...........................................................
Phase 1 and Phase 2 Development Areas ..................................................
Appendices
I.
II.
Abbreviated Form of SPE-PRMS
Glossary
33
2
6
7
8
9
10
12
13
14
16
17
18
20
Gaffney, Cline & Associates Limited
Bentley Hall, Blacknest
Alton, Hampshire GU34 4PU, UK
Telephone: +44 (0)1420 525366
www.gaffney-cline.com
28th June, 2012
TG/EL-12-208200/sf
The Directors,
EnQuest Plc,
4th Floor,Rex House,
4-12 Regent Street,
London, SW1Y 4PE
Paul Frankfurt Esq,
Merrill Lynch International,
2 King Edward Street,
London, EC1A 1HQ
Dear Sirs,
COMPETENT PERSON’S REPORT ON THE KRAKEN FIELD, UK NORTH SEA
INTRODUCTION
In accordance with the instruction from EnQuest Plc (EnQuest or “the Company”), dated
10th May, 2012, Gaffney, Cline & Associates (GCA) has reviewed the petroleum interests
owned or intended to be owned by EnQuest in the Kraken field located in the UK Northern
North Sea Block 9/02b (Figure 0.1), in order to provide an independent opinion on Resources
for the main Heimdal Unit III/II reservoir in the field. The Effective Date of the evaluation is
31st March, 2012.
In January, 2012 EnQuest acquired the 20% participating interest of Canamens Energy
North Sea Ltd (Canamens) and a 25% interest from Nautical Petroleum Plc (Nautical) in
Licence P1077 (Blocks 9/02b & 9/02c). On 25th April, 2012, EnQuest entered into an
agreement with First Oil to acquire a further 15% interest in Block 9/02b, Block 9/02c,
Block 9/06a and Block 9/07b. Following this acquisition, EnQuest will take over as Operator
of the Kraken discovery during the third quarter of 2012. Both the acquisition and the
transfer of Operatorship will be subject to approval by the Department of Energy and Climate
Change (DECC).
This report has been prepared for EnQuest as part of its obligations regarding the publication
of a Circular issued to its shareholders requesting their consent to the Proposed Acquisition
of the Kraken Interest.
Registered in England, number 1122740, at the above address
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EnQuest Plc
FIGURE 0.1
KRAKEN FIELD LOCATION MAP
BRESSAY
9/2b-2
KRAKEN
BENTLEY
9/2-1
9/2b-5
9/2b-4
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EnQuest has made available to GCA, via the current Kraken field Operator, Nautical, a data
set of technical information including geological, geophysical, and engineering data and
reports together with financial data pertaining to the fiscal terms applicable to the Kraken
field’s Block 9/02b. In carrying out this review GCA has relied on the accuracy and
completeness of this information in addition to the caveats imposed on the pre-existing,
outline Field Development Plan (FDP) by the incoming Operator, EnQuest.
The Resources reported herein are in accordance with the guidelines and definitions of the
Society of Petroleum Engineers/World Petroleum Council/American Association of Petroleum
Geologists/Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) Petroleum
Resources Management System (“SPE PRMS”), approved in March 2007 (see Appendix I
for an abbreviated version).
Reserves are those quantities of petroleum that are anticipated to be commercially
recoverable by application of development projects to known accumulations from a given
date forward under defined conditions. Reserves must further satisfy four criteria: they must
be discovered, recoverable, commercial and remaining (as of the evaluation date) based on
the development project(s) applied. Reserves are further categorized in accordance with the
level of certainty associated with the estimates and may be sub-classified based on project
maturity and/or characterized by development and production status.
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be
potentially recoverable from known accumulations, but the applied project(s) are not yet
considered mature enough for commercial development due to one or more contingencies.
Contingent Resources may include, for example, projects for which there are currently no
evident viable markets, or where commercial recovery is dependent on technology under
development, or where evaluation of the accumulation is insufficient to clearly assess
commerciality. Contingent Resources are categorized as 1C, 2C and 3C in accordance with
the level of certainty associated with the estimates and may be sub-classified based on
project maturity and/or characterized by their economic status. Contingent Resource
volumes are presented as unrisked. The stated 'Chance of Development', a percentage
which pertains to the probability of achieving the status of a Reserve has not been applied to
the volumes presented.
The reported hydrocarbon volumes are estimates, based on professional judgment and are
subject to future revisions, upward or downward, as a result of future operations or as
additional information becomes available.
GCA accepts responsibility for the CPR insofar as it is based on data provided by EnQuest,
which GCA has relied on the accuracy and completeness thereof, and confirms that, to the
best of its knowledge and belief having taken all reasonable care to ensure that such is the
case, the information contained in the CPR is in accordance with the facts and contains no
omission likely to affect its import.
GCA is an independent energy consultancy specialising in petroleum evaluation and
economic analysis. In the preparation of this report, GCA has maintained, and continues to
maintain, a strict consultant-client relationship with EnQuest. The directors of GCA have
been, and continue to be, independent of EnQuest in the services they provide to the
Company including the provision of the opinion expressed in this review. Furthermore, the
directors of GCA have no interest in any assets or share capital of EnQuest or in the
promotion of the Company.
Appendix II is a glossary of oilfield terms, some or all of which may be used in this report.
This report must only be used for the purpose for which it was intended.
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EXECUTIVE SUMMARY
The Kraken field is a heavy oil discovery located in Block 9/02b on the western margin of the
South Viking Graben in the UK Northern North Sea, in water depths of 114 m. The nearest
producing field and export infrastructure is Bruce, located about 10 km to the south-east.
The licence ownership of the Kraken discovery as at 31st March, 2012 and after the First Oil
acquisition is completed, are summarised in Table 0.1. The Company’s Licence interests as
at 31st March, 2012 are summarised in Table 0.2.
TABLE 0.1
SUMMARY OF KRAKEN FIELD OWNERSHIP
Company
EnQuest
Nautical
First Oil
Working Interest as at
31st March, 2012
(%)
45
25
30
Interest Being
Acquired
(%)
15
-
Working Interest
after Acquisition
(%)
60
25
15
TABLE 0.2
LICENCE SUMMARY AS AT 31ST MARCH, 2012
Country
Licence/Block
Operator
United Kingdom
P1077 9/02b, 9/02c
Nautical
Company WI
(%)
45
Expiration Date
2029 (anticipated)
GCA has previously evaluated the field on behalf of Nautical, the current Operator, with an
effective date of 28th February, 2012. Based on data and representations made by Nautical,
and the joint venture’s commitment to submitting a draft FDP to the DECC during 2012, GCA
attributed Reserves to the field. With the intended transfer of operatorship to EnQuest it has
determined to review the FDP and consider other options for development, GCA has now
re-classified the potentially recoverable hydrocarbon volumes as Contingent Resources.
This reclassification does not result from any new data or change in the perception of
recoverable volumes, it is based on the fact that EnQuest’s Board of Directors has yet to
approve its commitment to the development.
EnQuest as the incoming Kraken field Operator has elected to interpret the 3D seismic data
acquired during 2011 and after integrating these data into the dynamic model, confirm the
development concept and obtain project sanction from the EnQuest Board.
GCA
understands that EnQuest anticipates the submission of a revised FDP to DECC comprising
a Phase 1 Development of the High Confidence Area followed by a Phase 2 Development
provided the presence of oil filled sands is confirmed by the drilling of two appraisal wells.
GCA’s estimates of 1C, 2C and 3C Gross and Net EnQuest Working Interest Contingent
Resources are summarised in Table 0.3 as at 31st March, 2012 and in Table 0.4 after the
First Oil acquisition.
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TABLE 0.3
SUMMARY OF GROSS AND NET UNRISKED OIL CONTINGENT RESOURCES
AS AT 31ST MARCH, 2012
Gross Contingent Resources
(MMBbl)
1C
100
2C
172
3C
273
EnQuest Net Working
Interest
(%)
45.0
EnQuest Net Contingent Resources
as at 31st March, 2012
(MMBbl)
1C
3C
2C
45
123
77
Notes:
1.
2.
3.
The meaningful Contingent Resource volume reported here is the 2C, or ‘Best Estimate’ value.
No economic limit cut off is applied for Contingent Resources.
The volumes reported here are “Unrisked” in the sense that “Chance of Development” values have not
been arithmetically applied to the designated volumes within this assessment. “Chance of Development”
represents an indicative estimate of the probability that the Contingent Resource will be developed,
which would warrant the reclassification of that volume as a Reserve
TABLE 0.4
SUMMARY OF GROSS AND NET UNRISKED OIL CONTINGENT RESOURCES
AFTER FIRST OIL ACQUISITION
Gross Contingent Resources
(MMBbl)
1C
100
2C
172
3C
273
EnQuest Net Working
Interest
(%)
60.0
EnQuest Net Contingent Resources
after Acquisition
(MMBbl)
1C
3C
2C
60
164
103
Notes:
1.
2.
3.
The meaningful Contingent Resource volume reported here is the 2C, or ‘Best Estimate’ value.
No economic limit cut off is applied for Contingent Resources.
The volumes reported here are “Unrisked” in the sense that “Chance of Development” values have not
been arithmetically applied to the designated volumes within this assessment. “Chance of Development”
represents an indicative estimate of the probability that the Contingent Resource will be developed,
which would warrant the reclassification of that volume as a Reserve
GCA has considered its opinion on the Chance of Development that the Kraken project will
progress and warrant re-classification as Reserves. At this time GCA considers that the
factors requiring confirmation prior to such re-classification relate to the interpretation and
incorporation of the 3D seismic and confirmation of the development concept through FEED
and ultimately project sanction. EnQuest’s assessment of the Chance of Development is
90% for Phase 1 and 75% for Phase 2, contingent on the two proposed appraisal wells
confirming the presence of oil filled sands. Based on GCA’s review and discussion with
EnQuest, GCA concurs with the EnQuest assessment as fair and reasonable.
DISCUSSION
1.
BACKGROUND
The Kraken field was discovered in 1985 by the Occidental Petroleum well 9/02-1a. This
well was located on the western margin of the South Viking Graben in the UK Northern North
Sea, and was drilled to test an Upper Jurassic fault-block prospect with secondary objectives
in overlying Upper Palaeocene sands. The Upper Jurassic was absent, but heavy oil
(14° API) with an apparent viscosity of 374 cP was tested at an initial rate of 220 bopd from a
16 m interval from 1,179 m to 1,195 m BRT known as the Main Sand Unit of the Heimdal
Unit III Member of the late Palaeocene, Lista Formation (Figure 1.1). The tested oil rate
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declined to 43 bopd; well 9/02-1a was plugged and abandoned and the block relinquished,
later to be awarded to Nautical as a Promote licence (Block 9/02b) in 2003.
FIGURE 1.1
9/02-1 RESERVOIR SUMMARY
SP
(m V )
6
CALS
(in)
0
GR
(GAPI)
100
16
Depth (ft)
0
150
0.2
RD
(ohm m )
2000
0.2
M LL
(ohm m )
2000
0.2
ILD
(ohm m )
2000
0.2
ILM
(ohm m )
2000
VSHGR
PHIDWe
0 0
0.5
60
CNC
(%)
1.7
ZDEN
(g/cc)
ACedit
(us/f)
0 190
AC
(us/f)
2.7 190
40 1
Sw Free
(frac)
40 0.5
PHIS
(frac)
1
PHIDWe
0 1
0
SW*POR
0 1
0
Interbedded Unit L. Bressay Sst
Interbedded
Unit
3850
Main Unit L. Bressay Sst
3900
Main Unit
Base L. Bressay Sst
3950
Inter-bedded Unit
Main sand
N:G ~98%
Main Unit
Complete Unit
Top Interval (m/ft MD)
1162
3814
1180
3871
1162
Base Interval (m/ft MD)
1180
3871
1195
3921
1195
Gross Thickness (m)
3814
3921
17.5
15.5
33
8
15
23
Porosity ~30.4%
Net Pay Thickness (m)
Oil sat ~77%
Pay Arith Avg Sw (%)
30.8
23.1
25.7
Pay Arith Avg Phi (PHIDWe) (%)
23.7
30.4
28.1
After conversion to a conventional licence and following the purchase and reprocessing of
3D seismic data plus specialist studies in rock physics and structural modelling, appraisal
well 9/02b-2 was drilled in 2007 and found the oil-bearing Heimdal Unit III (10 m gross) and
the underlying Unit I (22 m gross) reservoirs. The ODT in the Heimdal Unit III of the 9/02b-2
well was found to be 51 m deeper than that of the discovery well. The Heimdal Unit I sands
comprised three distinct bodies each 3-4 m thick separated by background shales. Seismic
inversion studies were undertaken prior to drilling the down-dip appraisal well 9/02b-3 in
2008, ca. 3 km to the NE of 9/02b-2; however, this well failed to locate the oil water contact
(OWC) as prognosticated and found the Heimdal Unit III and Unit I sands to be absent.
In 2009 the rock physics model was revised and a two dimensional (2D) Controlled Source
Electro-Magnetic (CSEM) survey was acquired mainly in the Central “Core Area”, along with
further three dimensional seismic (3D) studies including coloured inversion. Sedimentological
and back-stripping studies were carried out prior to drilling the 9/02b-4 & -4z appraisal well.
This 2010 appraisal well with its sidetrack proved the extension of the Heimdal Unit III
fairway ca 4-5 km to the SW with a deeper ODT at -1,198 m TVDss and the presence of
oil-bearing sands in underlying Heimdal Unit II or Unit IIIb, but no Unit I sands. The Main
Sand gross and net thicknesses were 26 m in 9/02b-4 and 13 m in 9/02b-4z Unit III. This
westward halving in thickness occurs over a distance of approximately 350 m and may in
part be due to a NE-SW trending fault interpreted between the vertical well and its sidetrack.
The most recent and last planned appraisal well designated 9/02b-5 and its horizontal
sidetrack -5z were drilled and tested in Q3/Q4 2011 at a stabilised rate of 4,000 bopd with
well test analysis indicating effective horizontal permeability of 3,500 to 5,000 mD in the high
confidence Central Core Area of the field between wells 9/02b-4 and 9/02-1. The pilot,
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deviated well 9/02b-5 found the Heimdal Unit III/II reservoir sands as predicted, albeit
subdivided into three distinct geo-bodies separated by shales. The uppermost geo-body is
informally known as Leaf 1, separated by 7.6 m of shale from the lower two geo-bodies,
which are divided by a thinner shale interbeds and labelled Leaf 2. Leaf 1 is 10.4m thick,
100% net to gross with an average porosity of 38% and average water saturation of 20% and
an ODT of -1,173 m TVDss. Leaf 2 is 23.3 m gross, 18.7 m net (net to gross 78%), with an
average porosity of 38% and average water saturation of 23% and an ODT of -1,201 m
TVDss. The uppermost Leaf 2 section was cored and the sands described as very fine to
medium grained, rarely coarse grained, subangular to subrounded, moderately sorted, loose,
friable and unconsolidated.
In summary, the Kraken Main Sand Unit reservoir of Heimdal Unit III/II penetrated fully by the
four wells and one side-track to date, ranges in gross thickness from 10.2 m to 33.7 m,
where present, averaging ca.20 m with a Net to Gross ratio of 78-100% (92% average).
Average porosities range between 28% and 38% and this combined with multi-Darcy
permeability (3.5 D average) results in exceptional sand quality, but leads to sand production
and plugging of completions; thus gravel packs are planned to be used routinely in
production wells.
2.
GEOLOGICAL SETTING
The late Palaeocene Lista Formation comprises predominantly slope mudstones, which pass
laterally into turbiditic sands of the Heimdal Member (Figure 2.1). The Heimdal Member is
subdivided from bottom to top into up to four units, namely I, II, III and IV. Heimdal Unit III/II
is also referred to as the Main Unit within the Kraken field as it forms the principal reservoir
interval. In the Kraken area these reworked shelf sands are thought to have been sourced
from the East Shetland Platform to the west, shed eastwards and trapped on the East
Shetland Slope (Figure 2.2) due to a subtle bathymetric low caused by inversion on an
extensional fault, antithetic to the main Viking Graben boundary fault system, which then
funnelled the submarine channel system southwards (Figure 2.3).
FIGURE 2.1
EAST SHETLAND PLATFORM PALEOCENE STRATIGRAPHY
Top Balder/T50
Top Dornoch/T45
Intra Dornoch
Reservoir
objectives
Top
Lista/T34
Top T33
Top T32
Top T31
Top
Maureen/T20
Base Tertiary
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FIGURE 2.2
EAST SHETLAND PLATFORM AND SLOPE: HEIMDAL SEDIMENTOLOGY
Heimdal
Sedimentology
Extent of
sequence
mapping
From: Ahmadi et al. 2003, Paleocene, Millennium Atlas
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FIGURE 2.3
REGIONAL SEDIMENTOLOGICAL MODEL INTEGRATED WITH BASIN
RECONSTRUCTION & AMPLITUDES
In the well penetrations to date, the basal Heimdal Unit I is identified only in well 9/20b-2 on
the western flank of the field, within an isolated fault-block. Heimdal Unit III comprises a
Main Sand Unit overlain by an Inter-bedded Unit; only the Main Sand Unit is included in
volumetric estimates of recoverable volumes for Unit III.
3.
FIELD GEOLOGY
The Kraken field’s trap mechanism includes fault and dip closure on the western margin (the
Kraken fault), dip closure to the south and stratigraphic pinch-out plus possible dip-closure to
the north and east. The Kraken fault footwall has undergone some inversion and the
subsidiary faults that splay from the main fault in the Central Core Area, appear to be
evidence of footwall collapse and/or wrenching (Figure 3.1). Transpression on the
sub-vertical Kraken fault would provide a mechanism for the rollover evident in the overlying
Tertiary section. Extensional faulting is mapped at Top Main Sand level in the Northern
Area, sub-parallel to the Kraken fault. Additional, sub-seismic faults may be present (i.e. with
throws less than 25 m), which could offset the reservoir and/or act as baffles to fluid flow. It
is possible that a proportion of the faults are syn-sedimentary and that they influenced the
location and orientation of local channel bodies. The 9/02b-2 well is located in a separate
fault block on the basis of both mapping and different pressure and fluid data compared to
wells 9/02-1 and 9/02b-4 & -4z, -5 and -5z.
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FIGURE 3.1
HEIMDAL UNIT III GEOMODEL: TOP HEIMDAL UNIT III DEPTH SHADING AND FAULTS
9/02b- 3
9/02b- 2
9/02- 1A
9/02b- 4(Z)
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4.
GEOPHYSICS AND SEISMIC MAPPING
Following the award of Block 9/02b as a Promote Licence in 2003, Nautical purchased 2D
speculative seismic data acquired by Spectrum (one survey) and Western (two surveys) in
the 80s and 90s, plus a 3D speculative survey acquired by CGG in 1998, which was
reprocessed and reinterpreted in 2004 and 2005. After initial interpretation of this local
seismic data, the regional seismic mapping and well data base was expanded by Nautical
and specialist studies initiated in rock physics and structural modelling.
Following the unsuccessful 9/02b-3 well in 2008, the 3D seismic inversion model was revised
and test high resolution 2D data acquired. In addition, revisions were made to the rock
physics model and a 2D CSEM survey was acquired. A structural filter was applied to the 3D
data and coloured inversion methods tried in an attempt to approximate the presence of pay
within the Kraken “tank”.
The top and base of the Main Sand Unit is frequently problematic to identify and map
seismically throughout the whole field area due to a lack of an impedance contrast between
the largely unconsolidated sands and the surrounding shale. The seismic mapping
confidence generally deteriorates towards the south and appears to follow a quasi-linear, low
sinuosity channel pattern elsewhere in the field. Forward seismic modelling from the well
control has been reasonably thorough, including consideration of the most important
variables likely to influence the Main Sand’s seismic reflection character.
A clear improvement in resolution is evident on the far stack coloured inversion when
compared to the full-stack processing. The zero crossing, far-stack coloured inversion (CI)
seismic volume has been found to be the most reliable for top reservoir mapping and
amplitude extraction. The top Heimdal III main sand is picked on a trough minimum, which
brightens at far offsets, the brighter reflector indicating thicker and higher porosity sands;
however, as the sands thin and porosity reduces the seismic amplitude dims and may
phase-reverse (Figure 4.1).
A simple polynomial function is sufficient to achieve time to depth conversion capable of
top/base reservoir mapping accuracy to within 5 m. Base reservoir mapping is achieved
using the conventional seismic volume. The apparently linear relationship between seismic
amplitude and reservoir porosity-thickness has been used to estimate porosity directly from
the far-stack 3D volume and propagate these porosities into the geo-cellular model.
However, this approach may be an over-simplification and only be applicable over a very
narrow range of reservoir thickness and porosity. The new, high quality 3D data set may
resolve some of these issues.
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FIGURE 4.1
N – S SEISMIC LINE (INLINE 3260) ILLUSTRATING CORE AREA AND EXTENDED PICK
Top Heim III
Base
Tertiary
Base Heim III
Top Heimdal III Main Sand pick on a trough minimum
which brightens at far offsets.
Where the reflector is brighter it indicates the sand is
thicker and of higher porosity.
As the sands become thin and lower porosity the
seismic amplitude dims and may phase reverse.
INLINE
3260
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5.
STATIC MODEL
The 9/02b-2, 9/02-1, 9/02b-4 & -4z and 9/02b-5 & -5z wells are located within a very narrow,
NNE-SSW corridor ca 1.5 km wide near the western margin of the mapped field limit and
coincident with the submarine channel trend and orientation (Figure 5.1). Therefore, the
application of a Net:Gross ratio of 1.0 throughout the geo-cellular model for the Main Sand
Unit (actual values are 0.96, 0.88, 0.98, 1.0, 0.86 & 0.8) is optimistic. The 611 m open-hole
section of the Main Sand Unit in the -5z horizontal well exhibits a Net:Gross ratio of 0.8 and
is probably the most representative data point thus far.
FIGURE 5.1
KRAKEN GEOMODEL: TOP HEIMDAL UNIT III MAIN DEPTH
9/02b-2
9/02b-3
9/02-1
9/02b-5
9/02b-4
The construction of a seismic confidence map (referred by Nautical as the “holes” map) takes
into account the ambiguities of the seismic pick for top and base reservoir and the limitations
of porosity prediction directly from seismic amplitudes (Figure 5.2). Essentially, where
seismic confidence is low, sand presence has been assumed to be zero, hence the apparent
holes in the resultant map, albeit the broadly N-S lineation of excluded sand zones is
suggestive of possible intra-channel areas, which lends geological credibility to the map.
Employing this seismic confidence map as a filter to generate the most likely volumetric case
would be consistent with the reliance on seismic attributes to delineate and characterise the
reservoir. However, in recognition of the probability that moderate amounts of net sand
could be present in the intra-high confidence areas, providing both in-place volume and
connectivity, GCA considers that a Net:Gross ratio of 0.2 is appropriate as the basis for ‘Best
Case’ modelling.
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FIGURE 5.2
NET:GROSS “HOLES” CASE
Red areas retain a
net:gross value of
100% in all cases
Net:Gross set to intermediate
values in areas where amplitude
response dims
Blue areas set to
intermediate values
of net:gross
Prior to drilling the 9/02b-5z well, the seismic character displayed on the arbitrary, coloured
inversion line of the well trajectory suggested considerable rugosity on the top and base of
the Main Sand Unit and the probable presence of lensoid bodies, which suggest individual
channels. The probable presence of channels, visible in an axial orientation, suggests that
although sheet sand geometry has been employed in the geo-cellular model, this is an oversimplification and baffles or barriers to fluid flow may be present in intra-channel areas.
A prototype Schlumberger logging tool (the Deep Directional Resistivity tool) was run in the
9/02b-5z horizontal well and initial results suggest that the base and top of the Main Sand
Unit exhibit rugosity more consistent with channelised sand deposition rather than sheet
sand deposition. According to Nautical’s draft FDP, this well is “the first well to encounter
stacked depositional units with intra-reservoir claystones, indicating that there are some
horizontal baffles within the seismically-defined reservoir envelope.” These observations
support Nautical’s interpretation of deposition from a channel thalweg migrating within a
larger slope channel system.
In addition to the probable channelized nature of the Heimdal Member sands, the main sand
or Unit III, demonstrates evidence for sand mobilisation soon after deposition via injectites
(sedimentary dykes or sills) such as “Leaf 1” penetrated by the 9/02b-5 pilot hole.
An OWC has not been proven in the Kraken field, only ODTs, the deepest of which is at
-1,201 m TVDss in well 9/02b-5. In order to estimate a possible free water level (FWL),
saturation-height curves from Bressay sands in nearby well 3/28a-4 were compared with the
log-derived water saturation gradient from the Heimdal Units I and III in well 9/02b-2,
resulting in a best estimate of -1,224 m TVDss. An upside FWL at -1,230 m TVDss was
proposed by Nautical as a high case for volumetric estimation and this has been accepted as
reasonable by GCA.
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6.
PETROPHYSICS
Petrophysical evaluation within the Heimdal Unit III main reservoir interval is relatively
straightforward in that log data are reliable and supported/calibrated by core and test data.
Clean sand analysis in the main sand allows porosity to be derived from the density log with
a cross-check to the sonic log with matrix density at 2.65 g/cc and fluid density of 1.0 g/cc.
Water saturation is calculated using the Archie equation where exponents ‘a’ is 0.62, ‘m’ or
the cementation exponent is 2.15 and ‘n’ or the saturation exponent is 2.
The only unknown variable is water resistivity (Rw) as no water samples have yet been
obtained in the field and only ODT fluid levels have been observed. Therefore, Rw is
obtained by analogy using water samples from nearby well 3/28a-4. Saturation-height
functions are derived from the saturation gradient seen in well 9/02b-2 as noted in Section 5
above.
Core porosity data from the 9/02b-5 pilot well and revised model porosities from the -5z well
have been used to derive Low, Mid and High Case permeability-porosity transforms by
plotting these data against air permeability either unconstrained (low), linked to a Mariner
field data set (mid) or tied to 9/02b-2 mini drill-stem test data. These power functions have in
turn been used with co-kriged total porosity mapping to produce low, mid and high
permeability maps as input to dynamic simulation modelling.
7.
RESERVOIR ENGINEERING
Reservoir fluids data are available from tests carried out in the discovery well 9/02-1, vertical
appraisal wells 9/02b-2 and -4 and horizontal appraisal well 9/02b-5z. The discovery
well 9/02-1 achieved a successful DST (DST 2) from 1,179 m to 1,195 m (16 m) in the main
sand of Heimdal Unit III, using 12”, 6 shots per foot perforating guns with a diesel cushion.
On a 12/64” choke, the initial rate was 220 bopd at 180 psig Well Head Pressure (WHP).
With the final choke set at 16/64”, the final rate was 43 bopd at 10 psig WHP. Downhole
sampling was close to or above the bubble point (Pb) with a GOR range of 77-130 scf/Bbl.
During the total flow period of 12 hours, 36.8 Bbl of oil was produced, with oil gravity
recorded variously as 13.9o API at 60 degrees Fahrenheit (composite); 16.70 API (test report)
and 15.30 API (PVT report). Dynamic viscosity was measured at 373 cP at 1000 F and
1,670 psig (reservoir pressure). Test-derived permeability was 3,700 mD and the well flowed
naturally throughout the test period without depletion and with limited sand production.
Appraisal well 9/02b-2 was completed without a DST, but obtained valuable PVT data from
Mini Drill Stem Tests (MDTs) in the Heimdal Unit III reservoir section encountered. At the top
of the reservoir section (1,176m), an oil gravity of 15.1 0API was recorded with a GOR of
147 scf/Bbl, a Pb of 1,445 psia and a viscosity of 120 cP at 930 F and 1,690 psia reservoir
pressure (Pres). At the base of the reservoir interval (1,185 m), oil gravity was 14.80 API,
GOR 111 scf/Bbl and Pb 1,240 psia. Unfortunately, too little fluid was recovered for a reliable
viscosity measurement to be made.
The DST results from well 9/2b-4 provided some useful PVT data and valuable information
regarding completion constraints. The interval between 1,198 m and 1,214 m was perforated
overbalanced by 250 psi; a packer and screens were run with an ESP test string. Initial
flow/pump rates were ca. 200 bopd with a PI of 2 bopd/psi; however, fluids were not
produced to surface and after a shut-in period, the well was reopened and rates declined
rapidly. Despite multiple attempts to pump the well, no significant flow was recorded and the
Operator concluded that screens or perforation channels had become blocked by fine sand
(Figure 7.1).
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FIGURE 7.1
9/02b-4 DST FLOW PERIODS
IP PFO
#1 #1
Initial Flow, Flowed 17bbls
Injectivity test to check blockage
II ~ 2bpd/psi. Pressure Fall-off
Well shut-in due to
darkness
FP
#1
PBU
#1
FP
#2
PBU
#2
FP
#3
PBU
#3
Final PBU
Main flow at declining rate.
Final rate ~13bpd
Flowed 30 bbls
Pump started but very little
flow to surface
Both MDT and DST were attempted in well 9/02b-4, with oil gravity recorded at 13.40 to
140 API, GOR from 76 to 86 scf/Bbl and viscosity from 83 to123 cP at 1070 F, although with
5-9% oil-based mud contamination. In summary, fluid and pressure data indicate that wells
9/02-1 and 9/02b-4 are in pressure communication and that 9/02b-2 is a separate
accumulation.
The most recent and first horizontal well 9/02b-5z tested at a stabilised rate of 4,000 bopd for
11.5 hours, the oil gravity was 140 API, GOR was 85 scf/Bbl with a viscosity at initial
conditions of 162 cP and a bubble-point of 882 psia. The horizontal 8½” open hole
(ca. 611 m gross) was completed with a gravel pack inside a pre-perforated liner and tested
using an ESP. A series of flow and build-up periods were conducted up to a maximum flow
rate of 4,500 bopd and well test analysis indicates a range of effective permeability from
3,500 to 5,000 mD. Based on a stabilised flow rate of 3,000 bopd and a final flowing
pressure of 1410 psia the transient productivity index for 9/02b-5z is calculated by the
Operator to be 10.1 bopd/psi.
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8.
DYNAMIC MODEL
In undertaking its work for Nautical GCA was provided with Nautical’s Eclipse dynamic model
of the Heimdal Unit III/II reservoir over the Kraken field, which was based upon the static
model that had been constructed prior to the drilling of the well 9/02b-5 & -5z. The Eclipse
files included a High Confidence Model (HCM) dataset based upon a 19 well development
programme (10 producers and 9 injectors) drilled from the two Drill Centres, 1 & 2
(Figure 8.1). The Full Field Model (FFM) is a separate dataset based upon all three drilling
centres, i.e. with the addition of 6 producers and 5 injectors drilled from Drill Centre 3.
FIGURE 8.1
KRAKEN DEVELOPMENT AREA POROSITY MAP FROM SIMULATION MODEL
High Confidence
Model Area
The STOIIP was the same in Nautical’s Best and High Cases in the FFM and the HCM,
therefore the only difference is the number of wells employed in the Best and High Case
developments. In the Low Case, the STOIIP in Nautical’s FFM and HCM employ a zero net
to gross array where the seismic amplitude response was strongly diminished, i.e. weak or
dim. In the HCM and FFM, Nautical assigned a Net:Gross ratio of 0.3 in the Best Case.
In assigning recoverable volume estimates GCA made the following minor changes to
Nautical’s HCM, which was judged by GCA to be generally robust:
•
•
Low Case: The STOIIP used by GCA matches that of Nautical, drawn from the
simulation model. Since the Free Water Level in the simulation model is based upon
the ODT, the relative permeability files feature zero capillary pressure tables. GCA
made two changes to Nautical’s Low Case model. Firstly, GCA used the Mariner
field’s downside relative permeability tables with zero capillary pressure, leading to a
decrease in forecast recovery. Secondly, GCA moved the completion layers to the
top layers of the model, leading to an increase in recovery.
Best Case: GCA used a Net to Gross array of 0.2 over areas with a weak seismic
amplitude response compared with a value of 0.3 employed by Nautical, resulting in a
reduced STOIIP in GCA’s model.
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•
High Case: No changes were made, thus GCA’s STOIIP volume is identical to that of
Nautical.
Table 8.1 summarises the range of recoverable volumes derived by GCA from the High
Confidence Model.
TABLE 8.1
SUMMARY OF KRAKEN FIELD HCM
RECOVERABLE VOLUMES
GCA HCM Volumes MMBbl
Low
Best
High
77
127
169
In preparing FFM forecasts, GCA made minimal changes to the input decks supplied by
Nautical. In the Best Estimate (Figure 8.2) and Low Estimate cases GCA used Net:Gross
arrays of 0.2 and 0.1 respectively, in the areas of weak seismic amplitude response, leading
to slightly reduced STOIIP estimates in the GCA models. The only other change made by
GCA was to the completion intervals in the Low Case, moving these up from simulation layer
4 to layer 2. GCA made no changes to the High Estimate case.
FIGURE 8.2
FULL FIELD MODEL BEST ESTIMATE CASE
ƒ As base case, except
– Relative permeability downside
– Water injection at reservoir temp
P01
V05 V04
I01
P02
P06
P09
I02
P03
I05
I08
ƒ Gives reserves 169 MMstb (25
yrs)
Drill Centre 1
ƒ Basis for C2 contingent resource
I03
P07
P10
P04
I06
I09
P11
I04
I10
P05 P12
P08
I07
Drill Centre 3
P13
I11
P14 I12
P15
I13
P16
Drill Centre 2
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The FFM forecasts derived from the inclusion of all three drilling centres includes the
volumes to be produced from Drill Centre 3.
Table 8.2 summarises the range of the recoverable volumes derived by GCA from the Full
Field Model:
TABLE 8.2
SUMMARY OF KRAKEN FIELD FFM
RECOVERABLE VOLUMES
GCA FFM Volumes MMBbl
Low
Best
High
100
172
273
This wide range of recoverable volumes reflects the inherent uncertainties in reservoir
presence and performance at this early stage prior to field development following the results
from the first horizontal well 9/02b-5z. When the new 3D seismic data are interpreted and
the results of the Drill Centre 1 & 2 penetrations are available, the range of recoverable
volume estimates may narrow.
EnQuest has estimated base case recoverable oil at 177 MMBbl for both Phase 1 and
Phase 2, which is comparable with the GCA Best Estimate for the FFM. GCA was not
provided with data to review how EnQuest derived these volumes or whether they represent
a like for like comparison with the GCA estimates.
9.
DRAFT FIELD DEVELOPMENT PLAN
The following description and commentary should be read in the context of an “as agreed
FDP” prior to the change of Kraken field Operator. GCA acknowledges that EnQuest may
modify the draft FDP following the interpretation of the 2011 seismic and further appraisal
drilling of the Kraken field.
Nautical’s draft FDP for Kraken, based on the FFM volumes, included three drill centres
with 16 producers and 14 interspersed water injectors with a fan-like spacing of 400 m at the
heel and 600 m at the toe of each horizontal well. The main recovery mechanism was
water-flooding to maximise sweep efficiency with a line drive configuration at an
approximately 1:1 injector to producer ratio. The development was via an FPSO with
pre-drilled subsea tie-backs from three manifolds located in the Central (Drill Centre 1),
Northern (Drill Centre 2) and Southern (Drill Centre 3) areas of the field. The FPSO was
located near Drill Centre 1. The drilling programme outlined in the draft FDP began with the
pre-drilling of 4 wells (2 producers and 2 injectors) at each of the first two Drill Centres using
two rigs in parallel with an expectation of first oil in Q4 (October) 2015.
All producers and injectors were planned as horizontal and these subsea completions were
produced via Hydraulic Submersible Pumps (HSPs). Notably, HSPs have a proven track
record on the analogous Captain field and could underpin flow assurance on Kraken as they
are reported to have a P50 (50% probability) life in excess of 10 years.
Completion of the first 8 wells at Drill Centres 1 & 2 was scheduled for Q4 2016 with
development drilling beginning at Drill Centre 3, in the south of the field, in Q1 2017. The
initial development drilling with first oil planned for October 2015, was intended to enhance
understanding of the field’s production potential and to calibrate well to seismic ties prior to
the commencement of the initial development at Drill Centre 3 and the drilling of the
remaining 6 producers and 5 injectors at Drill Centres 1 & 2.
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Under the Nautical FDP, the wells on the drilling centres would produce back to and be
supported by a purpose-built FPSO. The production wells would be fitted with HSPs, with
the hydraulic fluid being seawater in an open cycle configuration. Both injection and drive
water would be heated to maintain reservoir and produced fluid temperatures. Injection
water and HSP drive fluid would be conveyed in separate lines due to the higher drive fluid
pressure meaning that all flow-lines were insulated. Produced fluids would be commingled
into one production flow-line at each drilling centre, and a separate test flow-line was
provided for each drilling centre, to allow a rotating well test programme via the test
separator on the FPSO.
Nautical had progressed development planning as far as well design, completions design
and preliminary FPSO contractor selection, with an indicative FPSO lease contract. Subsea
systems design has not progressed as far as the other elements, due to the shorter lead
times.
EnQuest currently anticipates a two-phase development of the Kraken field with Phase 1
consisting of the drilling of 8 producers and 6 injectors from Drill Centres 1 and 2, which
focuses on the “Central Core Amplitude Bright-spot” and the “Northern Core Amplitude
Bright-spot” (Figure 9.1). GCA understands that 5 producers and 4 injectors are considered
for Drill Centre 1 and 3 producers plus 2 injectors for Drill Centre 2.
FIGURE 9.1
PHASE 1 AND PHASE 2 DEVELOPMENT AREAS
NOTE: Phase 1 targets the amplitude bright spots – dims are not confirmed by seismic and are undrilled
Phase 2 (if implemented) will consist of drilling infill wells (2 producers and 3 injectors) at Drill
Centre 2 and the previously planned drilling programme at Drill Centre 3 of 6 producers and
5 injectors.
Prior to project sanction for the Phase 1 development, EnQuest intends to interpret the new
2011 3D seismic data and integrate these into a revised static model and dynamic model in
order to confirm the development concept. EnQuest has advised that it will not proceed with
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the development of the Phase 2 area until the presence of oil-filled sands is confirmed by the
drilling of two appraisal wells.
10.
CONTRACT AND FISCAL TERMS
The relevant elements of the UK fiscal regime for petroleum operations as they currently
stand are summarised below and are assumed to remain constant going forward:
•
•
•
•
•
Royalty: not applicable, as Royalty was abolished from 1st January, 2003;
Petroleum Revenue Tax (PRT): is not applicable, as PRT was abolished for fields
given development consent on or after 16th March 1993;
Ring Fence Corporation Tax (RFCT) applies at 30%;
Supplementary Charge (SC) applies at 32%. A "field allowance" which removes from
the charge to supplementary charge a slice of production income applies to this field.
The total field allowance available for a new Ultra heavy oil field is £800 million; and
A Ring Fence Expenditure Supplement (RFES) of 10% applies to this field, the RFES
allows the option to increase the value of losses carried forward from one period to
the next by 10% for a maximum of 6 years, not necessarily consecutively.
Nautical considered the Kraken oil quality was expected to represent a 7% price discount
relative to Brent.
11.
CONTINGENT RESOURCE ESTIMATES
In the absence of an agreed and sanctioned FDP for Kraken the recoverable oil volumes are
classified as Contingent Resources. In order for any proportion of these Contingent
Resources to move into the Reserves category, a revised FDP must be agreed by the
Kraken field owners, sanctioned by the EnQuest Board of Directors and its joint venture
partner’s Boards of Directors and have a reasonable expectation of receiving DECC
approval, in addition to the satisfaction of commerciality criteria including the future
economics of the project and ensuring that development commences within a reasonable
timeframe.
GCA’s estimates of 1C, 2C and 3C Gross and Net EnQuest Working Interest Contingent
Resources are summarised in Table 11.1 as at 31st March, 2012 and in Table 11.2 after the
First Oil acquisition.
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TABLE 11.1
SUMMARY OF GROSS AND NET UNRISKED OIL CONTINGENT RESOURCES
AS AT 31ST MARCH, 2012
Gross Contingent Resources
(MMBbl)
1C
100
2C
172
3C
273
EnQuest Net Working
Interest
(%)
45.0
EnQuest Net Contingent Resources
as at 31st March, 2012
(MMBbl)
1C
2C
3C
45
77
123
Notes:
1.
2.
3.
The meaningful Contingent Resource volume reported here is the 2C, or ‘Best Estimate’ value.
No economic limit cut off is applied for Contingent Resources.
The volumes reported here are “Unrisked” in the sense that “Chance of Development” values have not
been arithmetically applied to the designated volumes within this assessment. “Chance of Development”
represents an indicative estimate of the probability that the Contingent Resource will be developed,
which would warrant the reclassification of that volume as a Reserve.
TABLE 11.2
SUMMARY OF GROSS AND NET UNRISKED OIL CONTINGENT RESOURCES
AFTER FIRST OIL ACQUISITION
Gross Contingent Resources
(MMBbl)
1C
100
2C
172
3C
273
EnQuest Net Working
Interest
(%)
60.0
EnQuest Net Contingent Resources
after Acquisition
(MMBbl)
1C
2C
3C
60
103
164
Notes:
1.
2.
3.
The meaningful Contingent Resource volume reported here is the 2C, or ‘Best Estimate’ value.
No economic limit cut off is applied for Contingent Resources.
The volumes reported here are “Unrisked” in the sense that “Chance of Development” values have not
been arithmetically applied to the designated volumes within this assessment. “Chance of Development”
represents an indicative estimate of the probability that the Contingent Resource will be developed,
which would warrant the reclassification of that volume as a Reserve.
GCA has considered its opinion on the Chance of Development that the Kraken project will
progress and warrant re-classification as Reserves. At this time GCA considers that the
factors requiring confirmation prior to such re-classification relate to the interpretation and
incorporation of the 3D seismic and confirmation of the development concept through FEED
and ultimately project sanction. EnQuest’s assessment of the Chance of Development is
90% for Phase 1 and 75% for Phase 2, contingent on the two proposed appraisal wells
confirming the presence of oil filled sands. Based on GCA’s review and discussion with
EnQuest, GCA concurs with the EnQuest assessment as fair and reasonable.
12.
QUALIFICATIONS
GCA is an independent international energy advisory group of nearly 50 years’ standing,
whose expertise includes petroleum reservoir evaluation and economic analysis.
The report is based on information compiled by professional staff members who are either
full time employees of GCA or senior associates.
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Staff who participate in the compilation of this report include Mr. B. Rhodes, Mr. J Weston,
Mr. I Taylor and Mr. A Goodearl.
Mr. Rhodes holds a B.Sc. (Hons) Geology, is a member of the Energy Institute, the
Petroleum Exploration Society of Great Britain, the Society of Petroleum Engineers and the
European Association of Geoscientists and Engineers, and has more than 37 years industry
experience. Mr. Weston holds a Bsc. (Hons) Geology and an MSc. Micropaleontology
(Palynology), he is a member of the American Association of Petroleum Geologists,
Petroleum Exploration Society of Great Britain, Geological Society, Society of Petroleum
Engineers, and Energy Institute and has over 35 years experience. Mr. Taylor holds a B.Sc.
Chemical Engineering and has over 35 years experience. Mr. Goodearl holds B.Sc. (Hons)
Chemical Engineering and M.Eng. Petroleum Engineering, he is a member of the Society of
Petroleum Engineers and the Energy Institute and has 40 years experience.
13.
BASIS OF OPINION
This assessment has been conducted within the context of GCA’s understanding of the
effects of petroleum legislation, taxation, and other regulations that currently apply to these
properties and GCA’s best professional judgement, subject to the generally recognised
uncertainties associated with the interpretation of geoscience and engineering data.
GCA is not in a position to attest to property title or rights, conditions of these rights including
environmental and abandonment obligations, and any necessary licences and consents
including planning permission, financial interest relationships or encumbrances thereon for
any part of the appraised properties. Further GCA is not in a position to comment on the
likeliness or otherwise of the First Oil acquisition receiving DECC approval or completing.
GCA is also not in a position to comment on the approval or otherwise of the change of
operatorship from Nautical to EnQuest receiving DECC approval.
GCA has no reason to believe that any material facts have been withheld from it, but does
not warrant that its inquiries have revealed all of the matters that a more extensive
examination might otherwise disclose. The opinions and statements contained in this report
are made in good faith and in the belief that such opinions and statements are representative
of prevailing physical and economic circumstances.
It should be understood that any determination of hydrocarbon volumes particularly involving
petroleum may be subject to significant variations over short periods of time as new
information becomes available and perceptions change. GCA does not guarantee the
correctness or accuracy of any interpretation made by it and does not warrant that the
opinions contained herein will be any form of guarantee of the outcome.
Yours faithfully
GAFFNEY, CLINE & ASSOCIATES
Brian Rhodes
Global Director – Corporate Advisory Services
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APPENDIX I
Abbreviated Form of SPE-PRMS
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Society of Petroleum Engineers, World Petroleum Council, American Association of
Petroleum Geologists and Society of Petroleum Evaluation Engineers
Petroleum Resources Management System
Definitions and Guidelines (1)
March 2007
Preamble
Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earth’s
crust. Resource assessments estimate total quantities in known and yet-to-be-discovered accumulations;
resources evaluations are focused on those quantities that can potentially be recovered and marketed by
commercial projects. A petroleum resources management system provides a consistent approach to
estimating petroleum quantities, evaluating development projects, and presenting results within a
comprehensive classification framework.
International efforts to standardize the definition of petroleum resources and how they are estimated began in
the 1930s. Early guidance focused on Proved Reserves. Building on work initiated by the Society of
Petroleum Evaluation Engineers (SPEE), SPE published definitions for all Reserves categories in 1987. In the
same year, the World Petroleum Council (WPC, then known as the World Petroleum Congress), working
independently, published Reserves definitions that were strikingly similar. In 1997, the two organizations
jointly released a single set of definitions for Reserves that could be used worldwide. In 2000, the American
Association of Petroleum Geologists (AAPG), SPE and WPC jointly developed a classification system for all
petroleum resources. This was followed by additional supporting documents: supplemental application
evaluation guidelines (2001) and a glossary of terms utilized in Resources definitions (2005). SPE also
published standards for estimating and auditing reserves information (revised 2007).
These definitions and the related classification system are now in common use internationally within the
petroleum industry. They provide a measure of comparability and reduce the subjective nature of resources
estimation. However, the technologies employed in petroleum exploration, development, production and
processing continue to evolve and improve. The SPE Oil and Gas Reserves Committee works closely with
other organizations to maintain the definitions and issues periodic revisions to keep current with evolving
technologies and changing commercial opportunities.
The SPE PRMS document consolidates, builds on, and replaces guidance previously contained in the 1997
Petroleum Reserves Definitions, the 2000 Petroleum Resources Classification and Definitions publications,
and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and Resources”; the latter document
remains a valuable source of more detailed background information.,
These definitions and guidelines are designed to provide a common reference for the international petroleum
industry, including national reporting and regulatory disclosure agencies, and to support petroleum project
and portfolio management requirements. They are intended to improve clarity in global communications
regarding petroleum resources. It is expected that SPE PRMS will be supplemented with industry education
programs and application guides addressing their implementation in a wide spectrum of technical and/or
commercial settings.
It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor
application for their particular needs; however, any modifications to the guidance contained herein should be
clearly identified. The definitions and guidelines contained in this document must not be construed as
modifying the interpretation or application of any existing regulatory reporting requirements.
The full text of the SPE PRMS Definitions and Guidelines can be viewed at:
www.spe.org/specma/binary/files/6859916Petroleum_Resources_Management_System_2007.pdf
1
These Definitions and Guidelines are extracted from the Society of Petroleum Engineers / World Petroleum Council /
American Association of Petroleum Geologists / Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE)
Petroleum Resources Management System document (“SPE PRMS”), approved in March 2007.
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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 satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the
development project(s) applied. Reserves are further subdivided in accordance with the level of certainty
associated with the estimates and may be sub-classified based on project maturity and/or characterized by their
development and production status. To be included in the Reserves class, a project must be sufficiently defined to
establish its commercial viability. There must be a reasonable expectation that all required internal and external
approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a
reasonable time frame. A reasonable time frame for the initiation of development depends on the specific
circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a
longer time frame could be applied where, for example, development of economic projects are deferred at the
option of the producer for, among other things, market-related reasons, or to meet contractual or strategic
objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be
included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as
supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well
logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to
reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.
On Production
The development project is currently producing and selling petroleum to market.
The key criterion is that the project is receiving income from sales, rather than the approved development
project necessarily being complete. This is the point at which the project “chance of commerciality” can be
said to be 100%. The project “decision gate” is the decision to initiate commercial production from the
project.
Approved for Development
A discovered accumulation where project activities are ongoing to justify commercial development in the
foreseeable future.
At this point, it must be certain that the development project is going ahead. The project must not be subject
to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital
expenditures should be included in the reporting entity’s current or following year’s approved budget. The
project “decision gate” is the decision to start investing capital in the construction of production facilities and/or
drilling development wells.
Justified for Development
Implementation of the development project is justified on the basis of reasonable forecast commercial
conditions at the time of reporting, and there are reasonable expectations that all necessary
approvals/contracts will be obtained.
In order to move to this level of project maturity, and hence have reserves associated with it, the development
project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of
future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm
intention to proceed with development within a reasonable time frame will be sufficient to demonstrate
commerciality. There should be a development plan in sufficient detail to support the assessment of
commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to
project implementation will be forthcoming. Other than such approvals/contracts, there should be no known
contingencies that could preclude the development from proceeding within a reasonable timeframe (see
Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that
the project has reached a level of technical and commercial maturity sufficient to justify proceeding with
development at that point in time.
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Proved Reserves
Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering
data, can be estimated with reasonable certainty to be commercially recoverable, from a given date
forward, from known reservoirs and under defined economic conditions, operating methods, and
government regulations.
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. The area of the
reservoir considered as Proved includes:
(1)
the area delineated by drilling and defined by fluid contacts, if any, and
(2)
adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it
and commercially productive on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known
hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience,
engineering, or performance data. Such definitive information may include pressure gradient analysis and
seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves
(see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified
as Proved provided that the locations are in undrilled areas of the reservoir that can be judged with
reasonable certainty to be commercially productive. Interpretations of available geoscience and
engineering data indicate with reasonable certainty that the objective formation is laterally continuous with
drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should
be defined based on a range of possibilities supported by analogs and sound engineering judgment
considering the characteristics of the Proved area and the applied development program.
Probable Reserves
Probable Reserves are those additional Reserves which analysis of geoscience and engineering data
indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than
Possible Reserves.
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. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data
control or interpretations of available data are less certain. The interpreted reservoir continuity may not
meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated
with project recovery efficiencies beyond that assumed for Proved.
Possible Reserves
Possible Reserves are those additional reserves which analysis of geoscience and engineering data
indicate 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. When
probabilistic methods are used, there should be at least a 10% probability that the actual quantities
recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a
reservoir adjacent to Probable where data control and interpretations of available data are progressively
less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly
define the area and vertical reservoir limits of commercial production from the reservoir by a defined
project. Possible estimates also include incremental quantities associated with project recovery
efficiencies beyond that assumed for Probable.
Probable and Possible Reserves
(See above for separate criteria for Probable Reserves and Possible Reserves.)
The 2P and 3P estimates may be based on reasonable alternative technical and commercial
interpretations within the reservoir and/or subject project that are clearly documented, including
comparisons to results in successful similar projects. In conventional accumulations, Probable and/or
Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent
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portions of a reservoir within the same accumulation that may be separated from Proved areas by minor
faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted
to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be
assigned to areas that are structurally higher than the Proved area. Possible (and in some cases,
Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P
area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major,
potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive.
Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be
assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e.,
absence of reservoir, structurally low reservoir, or negative test results); such areas may contain
Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil
(HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only
be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such
portions are initially above bubble point pressure based on documented engineering analyses. Reservoir
portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on
reservoir fluid properties and pressure gradient interpretations.
Developed Reserves
Developed Reserves are expected quantities to be recovered from existing wells and facilities.
Reserves are considered developed only after the necessary equipment has been installed, or when the
costs to do so are relatively minor compared to the cost of a well. Where required facilities become
unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed
Reserves may be further sub-classified as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open
and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in
operation.
`
Developed Non-Producing Reserves
Developed Non-Producing Reserves include shut-in and behind-pipe Reserves
Shut-in Reserves are expected to be recovered from:
(1)
completion intervals which are open at the time of the estimate but which have not yet started
producing,
(2)
wells which were shut-in for market conditions or pipeline connections, or
(3)
wells not capable of production for mechanical reasons.
Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require
additional completion work or future re-completion prior to start of production. In all cases, production can
be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
Undeveloped Reserves
Undeveloped Reserves are quantities expected to be recovered through future investments:
(1)
from new wells on undrilled acreage in known accumulations,
(2)
from deepening existing wells to a different (but known) reservoir,
(3)
from infill wells that will increase recovery, or
(4)
where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is
required to
(a)
(b)
recomplete an existing well or
install production or transportation facilities for primary or improved recovery projects.
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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 may include, for example, projects for which there are currently no viable markets, or
where commercial recovery is dependent on technology under development, or where evaluation of the
accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in
accordance with the level of certainty associated with the estimates and may be sub-classified based on
project maturity and/or characterized by their economic status.
Development Pending
A discovered accumulation where project activities are ongoing to justify commercial development in the
foreseeable future.
The project is seen to have reasonable potential for eventual commercial development, to the extent that
further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to
confirming that the project is commercially viable and providing the basis for selection of an appropriate
development plan. The critical contingencies have been identified and are reasonably expected to be
resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead
to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the
decision to undertake further data acquisition and/or studies designed to move the project to a level of
technical and commercial maturity at which a decision can be made to proceed with development and
production.
Development Unclarified or on Hold
A discovered accumulation where project activities are on hold and/or where justification as a commercial
development may be subject to significant delay.
The project is seen to have potential for eventual commercial development, but further
appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the
project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual
commercial development. Development may be subject to a significant time delay. Note that a change in
circumstances, such that there is no longer a reasonable expectation that a critical contingency can be
removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not
Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation
designed to clarify the potential for eventual commercial development or to temporarily suspend or delay
further activities pending resolution of external contingencies.
Development Not Viable
A discovered accumulation for which there are no current plans to develop or to acquire additional data at
the time due to limited production potential.
The project is not seen to have potential for eventual commercial development at the time of reporting, but
the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in
the event of a major change in technology or commercial conditions. The project “decision gate” is the
decision not to undertake any further data acquisition or studies on the project for the foreseeable future.
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PROSPECTIVE RESOURCES
Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations.
Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the
estimated quantities that would be recoverable under defined development projects. It is recognized that the
development programs will be of significantly less detail and depend more heavily on analog developments in the
earlier phases of exploration.
Prospect
A project associated with a potential accumulation that is sufficiently well defined to represent a viable
drilling target.
Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of
potential recoverable quantities under a commercial development program.
Lead
A project associated with a potential accumulation that is currently poorly defined and requires more data
acquisition and/or evaluation in order to be classified as a prospect.
Project activities are focused on acquiring additional data and/or undertaking further evaluation designed
to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the
assessment of the chance of discovery and, assuming discovery, the range of potential recovery under
feasible development scenarios.
Play
A project associated with a prospective trend of potential prospects, but which requires more data
acquisition and/or evaluation in order to define specific leads or prospects.
Project activities are focused on acquiring additional data and/or undertaking further evaluation designed
to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming
discovery, the range of potential recovery under hypothetical development scenarios.
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RESOURCES CLASSIFICATION
PROJECT MATURITY
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APPENDIX II
Glossary
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GLOSSARY
List of Standard Oil Industry Terms and Abbreviations
ABEX
ACQ
o
API
AAPG
AVO
A$
B
Bbl
/Bbl
BBbl
BHA
BHC
Bscf or Bcf
Bscfd or Bcfd
Bm3
bcpd
BHP
blpd
bpd
boe
boepd
BOP
bopd
bwpd
BS&W
BTU
bwpd
CBM
CO2
CAPEX
CCGT
cm
CMM
CNG
cP
CSG
CT
DCQ
Deg C
Deg F
DHI
DST
DWT
E&A
E&P
EBIT
EBITDA
EI
EIA
EMV
EOR
EUR
FDP
FEED
FPSO
FSO
ft
Fx
g
g/cc
gal
gal/d
G&A
Abandonment Expenditure
Annual Contract Quantity
Degrees API (American Petroleum Institute)
American Association of Petroleum Geologists
Amplitude versus Offset
Australian Dollars
Billion (109)
Barrels
per barrel
Billion Barrels
Bottom Hole Assembly
Bottom Hole Compensated
Billion standard cubic feet
Billion standard cubic feet per day
Billion cubic metres
Barrels of condensate per day
Bottom Hole Pressure
Barrels of liquid per day
Barrels per day
Barrels of oil equivalent @ xxx mcf/Bbl
Barrels of oil equivalent per day @ xxx mcf/Bbl
Blow Out Preventer
Barrels oil per day
Barrels of water per day
Bottom sediment and water
British Thermal Units
Barrels water per day
Coal Bed Methane
Carbon Dioxide
Capital Expenditure
Combined Cycle Gas Turbine
centimetres
Coal Mine Methane
Compressed Natural Gas
Centipoise (a measure of viscosity)
Coal Seam Gas
Corporation Tax
Daily Contract Quantity
Degrees Celsius
Degrees Fahrenheit
Direct Hydrocarbon Indicator
Drill Stem Test
Dead-weight ton
Exploration & Appraisal
Exploration and Production
Earnings before Interest and Tax
Earnings before interest, tax, depreciation and amortisation
Entitlement Interest
Environmental Impact Assessment
Expected Monetary Value
Enhanced Oil Recovery
Estimated Ultimate Recovery
Field Development Plan
Front End Engineering and Design
Floating Production, Storage and Offloading
Floating Storage and Offloading
Foot/feet
Foreign Exchange Rate
gram
grams per cubic centimetre
gallon
gallons per day
General and Administrative costs
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GBP
GDT
GIIP
GJ
GOR
GTL
GWC
HDT
HSE
HSFO
HUT
H2S
IOR
IPP
IRR
J
k
KB
KJ
kl
km
km2
kPa
KW
KWh
LKG
LKH
LKO
LNG
LoF
LPG
LTI
LWD
m
M
m3
Mcf or Mscf
MCM
MMcf or MMscf
m3d
mD
MD
MDT
Mean
Median
MFT
mg/l
MJ
Mm3
Mm3d
MM
MMBbl
MMBTU
Mode
Mscfd
MMscfd
MW
MWD
MWh
mya
NGL
N2
NPV
OBM
OCM
ODT
OPEX
Pounds Sterling
Gas Down to
Gas initially in place
Gigajoules (one billion Joules)
Gas Oil Ratio
Gas to Liquids
Gas water contact
Hydrocarbons Down to
Health, Safety and Environment
High Sulphur Fuel Oil
Hydrocarbons up to
Hydrogen Sulphide
Improved Oil Recovery
Independent Power Producer
Internal Rate of Return
Joule (Metric measurement of energy) I kilojoule = 0.9478 BTU)
Permeability
Kelly Bushing
Kilojoules (one Thousand Joules)
Kilolitres
Kilometres
Square kilometres
Thousands of Pascals (measurement of pressure)
Kilowatt
Kilowatt hour
Lowest Known Gas
Lowest Known Hydrocarbons
Lowest Known Oil
Liquefied Natural Gas
Life of Field
Liquefied Petroleum Gas
Lost Time Injury
Logging while drilling
Metres
Thousand
Cubic metres
Thousand standard cubic feet
Management Committee Meeting
Million standard cubic feet
Cubic metres per day
Measure of Permeability in millidarcies
Measured Depth
Modular Dynamic Tester
Arithmetic average of a set of numbers
Middle value in a set of values
Multi Formation Tester
milligrams per litre
Megajoules (One Million Joules)
Thousand Cubic metres
Thousand Cubic metres per day
Million
Millions of barrels
Millions of British Thermal Units
Value that exists most frequently in a set of values = most likely
Thousand standard cubic feet per day
Million standard cubic feet per day
Megawatt
Measuring While Drilling
Megawatt hour
Million years ago
Natural Gas Liquids
Nitrogen
Net Present Value
Oil Based Mud
Operating Committee Meeting
Oil down to
Operating Expenditure
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OWC
p.a.
Pa
P&A
PDP
PI
PJ
PSDM
psi
psia
psig
PUD
PVT
P10
P50
P90
Rf
RFT
RT
Rw
SCAL
cf or scf
cfd or scfd
scf/ton
SL
so
SPE
SPEE
ss
stb
STOIIP
sw
T
TD
Te
THP
TJ
Tscf or Tcf
TCM
TOC
TOP
Tpd
TVD
TVDss
USGS
US$
VSP
WC
WI
WPC
WTI
wt%
1H05
2Q06
2D
3D
4D
1P
2P
3P
%
Oil Water Contact
Per annum
Pascals (metric measurement of pressure)
Plugged and Abandoned
Proved Developed Producing
Productivity Index
Petajoules (1015 Joules)
Post Stack Depth Migration
Pounds per square inch
Pounds per square inch absolute
Pounds per square inch gauge
Proved Undeveloped
Pressure volume temperature
10% Probability
50% Probability
90% Probability
Recovery factor
Repeat Formation Tester
Rotary Table
Resistivity of water
Special core analysis
Standard Cubic Feet
Standard Cubic Feet per day
Standard cubic foot per ton
Straight line (for depreciation)
Oil Saturation
Society of Petroleum Engineers
Society of Petroleum Evaluation Engineers
Subsea
Stock tank barrel
Stock tank oil initially in place
Water Saturation
Tonnes
Total Depth
Tonnes equivalent
Tubing Head Pressure
Terajoules (1012 Joules)
Trillion standard cubic feet
Technical Committee Meeting
Total Organic Carbon
Take or Pay
Tonnes per day
True Vertical Depth
True Vertical Depth Subsea
United States Geological Survey
United States Dollar
Vertical Seismic Profiling
Water Cut
Working Interest
World Petroleum Council
West Texas Intermediate
Weight percent
First half (6 months) of 2005 (example of date)
Second quarter (3 months) of 2006 (example of date)
Two dimensional
Three dimensional
Four dimensional
Proved Reserves
Proved plus Probable Reserves
Proved plus Probable plus Possible Reserves
Percentage
68
ENQUEST PLC
(incorporated and registered in England and Wales under number 7140891)
(the “Company”)
NOTICE OF EXTRAORDINARY GENERAL MEETING
NOTICE IS HEREBY GIVEN that an Extraordinary General Meeting of the Company will be held at
12.00 noon on 16 July 2012 at the offices of CMS Cameron McKenna LLP, Mitre House, 160 Aldersgate
Street, London, EC1A 4DD, United Kingdom to consider and, if thought fit, pass the following Resolution
as an ordinary resolution:
ORDINARY RESOLUTION
That the Proposed Acquisition, on the terms and subject to the conditions set out in the Acquisition
Agreement (both as defined in the circular to shareholders dated 28 June 2012 (the “Circular”), a copy of
which was produced to the meeting and initialled by the Chairman for the purposes of identification) be and
is hereby approved for the purposes of Chapter 10 of the Listing Rules of the Financial Services Authority
and the directors of the Company (or a duly authorised committee of the directors of the Company) be and
are hereby authorised to conclude and implement the Proposed Acquisition in accordance with such terms
and conditions and to make such non-material modifications, variations, waivers and extensions of any of
the terms of the Proposed Acquisition and of any documents and arrangements connected with the Proposed
Acquisition as they may consider to be necessary or desirable to complete, implement and give effect to, or
otherwise in connection with, the Proposed Acquisition and any matters incidental to the Proposed
Acquisition.
Registered Office:
Rex House
4-12 Regent Street
London
SW1Y 4PE
By order of the Board
Paul Waters
Company Secretary
28 June 2012
Notes:
(1) Pursuant to Regulation 41 of the Uncertificated Securities Regulations 2001, the Company specifies that in order to have the right
to attend and vote at the Extraordinary General Meeting (and also for the purpose of determining how many votes a person
entitled to attend and vote may cast), a person must be entered on the register of members of the Company at 6.00 p.m. on
Thursday 12 July 2012 or, in the event of any adjournment, at 6.00 p.m. on the date which is two days before the day of the
adjourned meeting. Changes to entries on the register of members after this time shall be disregarded in determining the rights
of any person to attend or vote at the meeting.
(2) A member is entitled to appoint another person as his proxy to exercise all or any of his rights to attend, to speak and to vote at
the Extraordinary General Meeting. A member may appoint more than one proxy in relation to the meeting, provided that each
proxy is appointed to exercise the rights attached to a different share or shares held by him. A proxy need not be a member of
the Company. A form of proxy for the meeting is enclosed.
To be valid any proxy form or other instrument appointing a proxy must be received by post or by hand (during normal business
hours only) in accordance with the instructions printed on the form of proxy to arrive no later than 12.00 noon on 12 July 2012.
If you are a CREST Member, see note 3 below.
Completion of a form of proxy, or other instrument appointing a proxy or any CREST Proxy Instruction will not preclude a
member attending and voting in person at the meeting if he/she wishes to do so.
Shareholders may also submit their proxy electronically via the internet. Details on how to do this can be found on the form of
proxy.
(3) Alternatively, if you are a CREST Member, you may register the appointment of a proxy by using the CREST electronic proxy
appointment service. Further details are contained below.
CREST Members who wish to appoint a proxy or proxies through the CREST electronic proxy appointment service may do so
for the Extraordinary General Meeting and any adjournment(s) thereof by using the procedures, and to the address, described in
the CREST manual (available via www.euroclear.com/CREST) subject to the provisions of the Company’s articles of association.
CREST personal members or other CREST sponsored members, and those CREST Members who have appointed a voting
69
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.
In order for a proxy appointment or 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 and Ireland Limited’s
(“Euroclear”) specifications and must contain the information required for such instructions, as described in the CREST manual.
The message, regardless of whether it constitutes the appointment of a proxy or 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 the issuer’s agent (ID RA10) by
12.00 noon on 12 July 2012. For this purpose, the time of receipt will be taken to be the time (as determined by the time stamp
applied to the message by the CREST applications host) from which the issuer’s agent is able to retrieve the message by enquiry
to CREST in the manner prescribed by CREST. After this time any change of instructions to proxies appointed through CREST
should be communicated to the appointee through other means.
CREST Members and, where applicable, their CREST sponsors or voting service provider(s) should note that Euroclear does not
make available special procedures in CREST for any particular messages. Normal system timings and limitations will therefore
apply in relation to the input of CREST Proxy Instructions. It is the responsibility of the CREST Member concerned to take (or,
if the CREST Member is a CREST personal member or sponsored member or has appointed a voting service provider(s), to
procure that his CREST sponsor or voting service provider(s) take(s)) such action as shall be necessary to ensure that a message
is transmitted by means of the CREST system by any particular time. In this connection, CREST Members and, where applicable,
their CREST sponsors or voting service provider(s) are referred, in particular, to those sections of the CREST manual concerning
practical limitations of the CREST system and timings.
The Company may treat as invalid a CREST Proxy Instruction in the circumstances set out in Regulation 35(5)(a) of the
Uncertificated Securities Regulations 2001.
(4) Any person to whom this notice is sent who is a person nominated under section 146 of the Companies Act 2006 (the “Act”) to
enjoy information rights (a “Nominated Person”) may have a right, under an agreement between him/her and the member by
whom he/she was nominated, to be appointed (or to have someone else appointed) as a proxy for the Extraordinary General
Meeting. If a Nominated Person has no such proxy appointment right or does not wish to exercise it, he/she may have a right,
under such an agreement, to give instructions to the member as to the exercise of voting rights.
The statement of the above rights of the members in relation to the appointment of proxies does not apply to Nominated Persons.
Those rights can only be exercised by members of the Company.
(5) Any corporation which is a member can appoint one or more corporate representatives who may exercise on its behalf all of its
powers as a member provided that they do not do so in relation to the same shares.
(6) Any member attending the Extraordinary General Meeting has the right to ask questions. The Company must cause to be
answered any such question relating to the business being dealt with at the meeting but no such answer need be given if (a) to do
so would interfere unduly with the preparation for the meeting or involve the disclosure of confidential information, (b) the
answer has already been given on a website in the form of an answer to a question, or (c) it is undesirable in the interests of the
Company or the good order of the meeting that the question be answered.
(7) A copy of the Acquisition Agreement is available for inspection at the Company’s registered office during normal business hours
from the date of this notice until the close of the Extraordinary General Meeting (Saturdays, Sundays and public holidays
excepted) and will be available for inspection at the place of the meeting for at least 15 minutes prior to and during the meeting.
A copy of this notice, and other information required by section 311A of the Companies Act 2006, can be found at
www.enquest.com.
(8) As at 27 June 2012 (being the last practicable date prior to the publication of this notice) the Company’s issued share capital
consists of 802,660,757 Ordinary Shares, carrying one vote each. Therefore, the total voting rights in the Company as at that date
are 802,660,757.
(9) You may not use any electronic address (within the meaning of section 333(4) of the Act) provided in this Notice of Meeting (or
in any related documents and proxy form) to communicate with the Company for any purposes other than those expressly stated.
70
DEFINITIONS
The following definitions apply throughout this document and the accompanying Form of Proxy, unless the
context requires otherwise:
Acquisition or Proposed Acquisition the proposed acquisition of the Kraken Interest pursuant to and in
accordance with the Acquisition Agreement
Acquisition Agreement
the conditional agreement relating to the Proposed Acquisition, the
principal terms of which are summarised in Part III of this
document
Alma/Galia Farm-Out
the disposal by EnQuest Heather of interests in the UKCS
petroleum production licences P.1765 and P.1825, and interests in
each of the UKCS Blocks 30/24b, 30/24c and 30/25c, further details
of which are set out in paragraph 6.7 of Part IV of this document
Alma Field
the hydrocarbon accumulation underlying Block 30/24c and
Block 30/25c, known as the “Alma Field” as it may exist from time
to time
Articles
the articles of association of the Company from time to time
Block
a block on the UKCS
Board or Directors
the executive and non-executive directors of the Company, as at the
date of this document whose names are set out on page 4 of this
document
Boepd
barrels of oil equivalent per day
bopd
barrels of oil per day
Brent Blend
a blend of oil that is used as an international benchmark for the
prices of other crude oils
Britoil
Britoil plc or any of its subsidiaries, as the case may be
Canamens Acquisition
the acquisitions by the Company of the entire issued share capital of
Canamens Energy North Sea Limited and Canamens UK 814 and
815 Limited, further details of which are set out in paragraphs 6.1
and 6.2 of Part IV of this document
Capita or Capita Registrars or
Registrars
Capita Registrars Limited
Chairman
the chairman for the time being of EnQuest
Companies Act
the Companies Act 2006, as amended
Company or EnQuest
EnQuest PLC, a public limited company incorporated in England
and Wales with registered number 7140891
Completion or Closing
completion of the Proposed Acquisition in accordance with the
terms and conditions of the Acquisition Agreement
ConocoPhillips or Conoco
ConocoPhillips (U.K.) Limited
CPR or Competent Person’s Report the independent competent person’s report produced by Gaffney,
Cline & Associates, a copy of which is reproduced in Part V of this
document
71
Crawford and Porter Acquisition
the acquisition by the Company of interests in the Crawford and
Porter fields further details of which are set out in paragraph 6.3 of
Part IV of this document
CREST
the relevant system (as defined in the CREST Regulations) for the
paperless settlement of share transfers and the holding of shares in
uncertificated form in respect of which Euroclear is the operator (as
defined in the CREST Regulations) in accordance with which
securities may be held and transferred in uncertificated form
CREST Member
a person who has been admitted by Euroclear as a system-member
(as defined in the CREST Regulations)
CREST Regulations
the Uncertified Securities Regulations 2001 (SI 2001 No. 3755) (as
amended)
DBSP
the EnQuest PLC Deferred Bonus Share Plan, further details of
which are set out in paragraph 6.3 of Part XI of the Prospectus
DECC
the Department of Energy and Climate Change
Disclosure and Transparency Rules
the disclosure and transparency rules relating to the disclosure of
information in respect of financial instruments which have been
admitted to trading on a regulated market or for which a request for
admission to trading on such a market has been made, as published
by the FSA of the United Kingdom
Don fields
the Don Southwest field and the West Don field
EGM or Extraordinary General
Meeting
the extraordinary general meeting of EnQuest at which a resolution
will be proposed to approve the Proposed Acquisition, and which is
set to be held at 12.00 noon on 16 July 2012, Notice of which is set
out at the end of this document
Enlarged Group
the Group following Completion
EnQuest
EnQuest PLC, a public limited company incorporated in England
and Wales with registered number 7140891
EnQuest Dons
EnQuest Dons Limited, a company incorporated and registered
under the laws of England and Wales with registered number
3351775
EnQuest Britain
EnQuest Britain Limited, a company incorporated and registered
under the laws of England and Wales with registered number
3628497
EnQuest Heather
EnQuest Heather Limited, a company incorporated and registered
under the laws of England and Wales with registered number
2748866
EnQuest Thistle
EnQuest Thistle Limited, a company incorporated and registered
under the laws of England and Wales with registered number
4487223
EU
the European Union
EU ETS
the European Union’s Emissions Trading Scheme
Euroclear
the relevant clearing systems run by Euroclear UK & Ireland
Limited
72
Facility Agreement
shall have the meaning given to it in paragraph 6.6 of Part IV of this
document
Financial Services Authority or FSA the Financial Services Authority in its capacity as the competent
authority for the purposes of Part VI of the FSMA and in the
exercise of its functions in respect of admission to the Official List
otherwise than in accordance with Part VI of the FSMA
First Oil
First Oil and Gas Limited
FSMA
the Financial Services and Markets Act 2000, as amended
GAAP
the Generally Accepted Accounting Practices
Gaffney, Cline & Associates or
Competent Person or GCA
Gaffney, Cline & Associates Limited, an independent consultancy
firm specialising in petroleum reservoir evaluation and economic
analysis
Galia Field
the hydrocarbon accumulation underlying Block 30/24b, known as
the “Galia Field” as it may exist from time to time
Group
the Company, its subsidiaries and its subsidiary undertakings
HSE
Health and Safety and Environment
IFRS
the International Financial Reporting Standards
Kraken Field
the hydrocarbon accumulation underlying Block 9/2b and
Block 9/2c known as the “Kraken Field” as it may exist from time
to time as determined by the Secretary of State, but only to the
extent that it lies within the boundaries of Block 9/2b and
Block 9/2c
Kraken Interest
an undivided legal interest in the UKCS petroleum production
licences P.1077 and P.1575, a 15 per cent. interest in each of UKCS
Blocks 9/2b, 9/2c, 9/6a and 9/7b, and beneficial interests in
ancillary documents and licences related thereto
Licence
a UKCS petroleum licence
Listing Rules
the rules and regulations made by the FSA in its capacity as the UK
Listing Authority under FSMA, and contained in the UK Listing
Authority’s publication of the same name
London Stock Exchange
London Stock Exchange plc
Member State
a member state of the EU
Merrill Lynch International
Merrill Lynch International, whose registered address is at 2 King
Edward Street, London EC1A 1HQ and whose registered number is
02312079
MMbbl
million barrels of oil
MMboe
million barrels of oil equivalents
Nautical
Nautical Petroleum PLC and Nautical Petroleum AG
Nautical Acquisition
the acquisition by the Company from Nautical of interests in the
UKCS petroleum production licences P.1077, P.1573, P.1574 and
P.1575, and interests in each of the UKCS Blocks 9/2b, 9/2c, 3/22a,
73
3/26, 9/6a, 9/7b and 9/1a, further details of which are set out in
paragraph 6.5 of Part IV of this document
Northern Producer FPF
converted semi-submersible drilling rig of Aker H-3 design
Notice
the notice of Extraordinary General Meeting, which is set out at the
end of this document
Obligors
shall have the meaning given to them in the section “Risk Factors”
of this document
Official List
the Official List maintained by the FSA pursuant to Part VI of the
FSMA
OPEC
the Organisation of Petroleum Exporting Countries
OPPC
the Offshore Petroleum Activities (Oil Pollution Prevention and
Control) Regulations 2005
Ordinary Shares or EnQuest Shares ordinary shares of £0.05 each in the capital of the Company
p or pence
one hundredth part of one pound Sterling
PPC
the Offshore Combustion Installations (Prevention and Control of
Pollution) Regulations 2001
Proposed Acquisition
the proposed acquisition of the Kraken Interest pursuant to and in
accordance with the Acquisition Agreement
Prospectus
EnQuest’s prospectus dated 18 March 2010 in relation to the offer
of 48,130,326 Ordinary Shares of 5 pence each
PRT
the UK Petroleum Revenue Tax
PSP
the EnQuest PLC Performance Share Plan, further details of which
are set out in paragraph 6.2 of Part XI of the Prospectus
Regulatory Information Service
a Regulatory Information Service that is approved by the FSA and
that is on the list of Regulatory Information Service providers
maintained by the FSA
Remuneration Committee
the remuneration committee of the Board
Resolution
the ordinary resolution relating to the Proposed Acquisition set out
in the Notice of Extraordinary General Meeting, which is set out at
the end of this document
RSP
the EnQuest PLC Restricted Share Plan, further details of which are
set out in paragraph 6.4 of Part XI of the Prospectus
Secretary of State
the Secretary of State for the Department of Energy and Climate
Change
Shareholders
the holders of Ordinary Shares from time to time
Share Plans
the share plans of the Company, namely the EnQuest PLC
Performance Share Plan, the EnQuest PLC Deferred Bonus Share
Plan and the EnQuest PLC Restricted Share Plan, further details of
which are set out in paragraph 6 of Part XI of the Prospectus
SPE
the Society of Petroleum Engineers
74
SPE PRMS
The Petroleum Resources Management System of the Society of
Petroleum Engineers, the World Petroleum Council, the American
Association of Petroleum Geologists and the Society of Petroleum
Evaluation Engineers, dated March 2007
SPL
Sea Production Limited
Sponsor
Merrill Lynch International
Stasco
Shell International Trading and Shipping Company Limited
Sterling or £ or pound sterling
the lawful currency for the time being of the United Kingdom
UK or United Kingdom
the United Kingdom of Great Britain and Northern Ireland
UKCS
the United Kingdom Continental Shelf
UK Listing Authority or UKLA
the FSA in its capacity as the competent authority for the purposes
of Part VI of the FSMA
uncertificated
a share or other security title to which is recorded on the relevant
register of the share or security concerned as being held in
uncertificated form in CREST or Euroclear and title to which may
be transferred by means of CREST or Euroclear
US or United States
the United States of America, its territories and possessions and all
areas subject to its jurisdiction, any state of the United States of
America and the District of Columbia
US dollar or US$ or USD
the lawful currency for the time being of the United States
75
sterling 158825