PDF 9.9mb - San Leon Energy

THIS DOCUMENT IS IMPORTANT AND REQUIRES YOUR IMMEDIATE ATTENTION. If you are in any doubt about the
contents of this document or as to the action you should consult your stockbroker, bank manager, solicitor or accountant or
other independent financial adviser, being (in the case of persons resident in Ireland) an organisation or firm authorised or
exempted pursuant to the Investment Intermediaries Act 1995 of Ireland or the Stock Exchange Act 1995 of Ireland and in the
case of persons resident in the United Kingdom an organisation or firm authorised pursuant to the Financial Services and
Markets Act 2000 (“FSMA”) who specialises in advising on the acquisition of shares and other securities in the United
Kingdom. The whole of the text of this document should be read. You should be aware that an investment in the Company
involves a high degree of risk and prospective investors should also carefully consider the section entitled “Risk Factors” in
Part III of this document before taking any action.
This document comprises an admission document for the purposes of the AIM Rules. This document does not constitute a prospectus
for the purposes of the Prospectus (Directive 2003/71/EC) Regulations 2005 of Ireland or section 85 of FSMA and is not a prospectus
for the purposes of the Prospectus Regulations, nor has it been approved by the UK Listing Authority or the Financial Services
Authority. This document has not been delivered to the Registrar of Companies in Dublin or the Registrar of Companies in England
and Wales or any other authority in any jurisdiction for registration.
The Directors of San Leon Energy Plc, whose names appear on page 4 of this document and the Company accept responsibility for the
information contained in this document including individual and collective responsibility for compliance with the AIM Rules. 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 does not omit anything likely to affect the import of such information.
Application has been made for the Issued Share Capital to be admitted to trading on AIM. It is expected that Admission will
become effective and that dealings will commence on AIM on 29 September 2008. The Ordinary Shares are not dealt in or on
any other recognised investment exchange and no such other applications have been made.
AIM is a market designed primarily for emerging or smaller companies to which a higher investment risk tends to be attached
than to larger or more established companies. AIM securities are not admitted to the Official List of the UK Listing Authority.
A prospective investor should be aware of the risks of investing in such companies and should make the decision to invest only
after careful consideration and, if appropriate, consultation with an independent financial adviser. Each AIM company is
required pursuant to the AIM Rules to have a nominated adviser. The nominated adviser is required to make a declaration to
the London Stock Exchange on admission in the form set out in Schedule Two to the AIM Rules for Nominated Advisers.
The London Stock Exchange has not itself examined or approved the contents of this document. The AIM Rules are less
demanding than those of the Official List of the UK Listing Authority. It is emphasised that no application is being made for
admission of these securities to the Official List of the UK Listing Authority or the Official List of the Irish
Stock Exchange Limited.
San Leon Energy Plc
(Incorporated and registered in the Republic of Ireland with limited liability under the Companies Acts 1963 to 1990 with registered number 237825)
Admission to trading on AIM
Nominated Adviser & Broker
Daniel Stewart & Company plc
Share capital immediately following Admission
Authorised
Amount
Number
€37,500,000
750,000,000
Ordinary Shares of €0.05 each
Issued and fully paid
Amount
Number
€13,566,468.35
271,329,367
Daniel Stewart & Company plc (“Daniel Stewart”), which is authorised and regulated by the Financial Services Authority, is
acting as Nominated Adviser and Broker to the Company and no one else in connection with Admission and will not be
responsible to any person other than the Company for providing the regulatory and legal protections afforded to clients (as
defined by the FSA Rules) of Daniel Stewart nor for providing advice in relation to the contents of this document or any matter,
transaction or arrangement referred to in it. The responsibilities of Daniel Stewart, as Nominated Adviser under the AIM Rules
for Nominated Advisers, are owed solely to London Stock Exchange and are not owed to the Company or any director of the
Company or to any other person in respect of their decision to acquire Ordinary Shares in reliance of any part of this document.
This document does not constitute an offer to buy or to subscribe for, or the solicitation of an offer to buy or subscribe for, Ordinary
Shares in any jurisdiction in which such offer or solicitation is unlawful. The Ordinary Shares have not been, and will not be, registered
in the United States of America under the United States Securities Act of 1933 (as amended) (the “Securities Act”) or qualified for
sale under the laws of any state of the United States or under the applicable laws of any of Canada, Australia, the Republic of
South Africa, or Japan and, may not be offered or sold in the United States of America, Canada, Australia, the Republic of
South Africa, or Japan or to, or for the account or benefit of, US persons (as such term is defined in Regulation S under the Securities
Act) or to any national, resident or citizen of Canada, Australia, the Republic of South Africa, or Japan. Neither this document nor any
copy of it may be sent to or taken into the United States, Canada, Australia, the Republic of South Africa, or Japan, nor may it be
distributed to any US person (within the meaning of Regulation S under the Securities Act). In addition, the securities to which this
document relates must not be marketed into any jurisdiction where to do so would be unlawful.
Copies of this document which is dated 23 September 2008 will be available from the date of this document free of charge to the public
on any weekday (Saturdays, Sundays and public holidays excepted) at the offices of Daniel Stewart, Becket House, 36 Old Jewry,
London EC2R 8DD for one month from the date of Admission.
CONTENTS
Page
SHARE CAPITAL STATISTICS
3
EXPECTED TIMETABLE OF PRINCIPAL EVENTS
3
DIRECTORS, SECRETARY AND ADVISERS
4
DEFINITIONS
6
PART I
SUMMARY
9
PART II
INFORMATION ON THE GROUP
11
1.
Introduction
11
2.
History and Background
11
3.
Summary of the Petroleum Consultant’s Report
11
4.
The Group’s Assets
13
5.
Petroleum Consultant’s Report
16
6.
Strategy
16
7.
Current Trading and Prospects
16
8.
Board of Directors
17
9.
Corporate Governance
17
10.
Reasons for Admission
18
11.
Dividend Policy
19
12.
Options
19
13.
Warrants
19
14.
Regulation
19
15.
Taxation
19
16.
Admission and CREST
19
17.
The Takeover Code
20
18.
Lock-in and Orderly Market Arrangements
20
19.
Additional Information
20
PART III
RISK FACTORS
21
PART IV
PETROLEUM CONSULTANT’S REPORT
27
PART V
FINANCIAL INFORMATION ON THE GROUP
133
A.
Financial information on the Group
133
B.
Unaudited interim financial information on San Leon Energy plc
for the six month period to 30 June 2008
146
PART VI
155
ADDITIONAL INFORMATION
197
GLOSSARY AND ABBREVIATIONS
2
SHARE CAPITAL STATISTICS
Number of Ordinary Shares in issue on the date of this
document and on Admission (undiluted)
Number of share options in issue on Admission
271,329,367
9,500,000
Number of Warrants in issue on Admission
30,697,443
Number of Ordinary Shares in issue on Admission (diluted)
Market capitalisation of the Company on Admission at 37 pence per share
311,526,810*
£100.4 million
* This number of Ordinary Shares does not take into account share options which may be exercised in specified circumstances
pursuant to the Convertible Loan Note.
EXPECTED TIMETABLE OF PRINCIPAL EVENTS
Publication date of this document
23 September 2008
Admission and dealings in the Ordinary Shares to commence on AIM
29 September 2008
Delivery into CREST of the Ordinary Shares to be held in uncertificated form
29 September 2008
3
DIRECTORS, SECRETARY AND ADVISERS
Directors
Oisín Brendan Fanning
William Arthur Philip Thompson
Charles McEvoy
James Mathew Dominic Paul
Sullivan
Jeremy Boak
Raymond Albert King
Chairman
Chief Executive Officer
Operations Director
Commercial Director
Non-Executive Director
Non-Executive Director
all of:
Registered Office
First Floor
Wilton Park House
Wilton Place
Dublin 2
Republic of Ireland
Telephone Number
00 353 1 2916292
Company Website
http://www.sanleonenergy.com
Company Secretary
Raymond King
Nominated Adviser & Broker
to the Company
Daniel Stewart & Company plc
Becket House
36 Old Jewry
London EC2R 8DD
United Kingdom
Petroleum Consultant
Netherland, Sewell & Associates, Inc.
4500 Thanksgiving Tower
1601 Elm Street
Dallas
Texas 75201-4754
United States of America
Solicitors to the Company
WhitneyMoore
Wilton Park House
Wilton Place
Dublin 2
Republic of Ireland
Provider of legal opinion
as to Nebraska Law
Matzke, Mattoon & Miller
907 Jackson Street
P.O. Box 316 Sidney, Nebraska 69162 – 0316
United States of America
Provider of legal opinion
as to Dutch Law
CMS Derks Star Busmann N.V.
Mondriaantoren 8A
Postbus 94700
1096 BC Amsterdam
The Netherlands
Provider of legal opinion
as to Moroccan Law
UGGC & Associés
97 Boulevard Massira-Al Khadra
Casablanca, Morocco
4
Provider of legal opinion
as to the Laws of British
Virgin Islands
Harney Westwood & Riegels LLP
5, New Street Square
London EC4A 3BF
United Kingdom
Solicitors to Daniel Stewart
Fox Williams LLP
Ten Dominion Street
London EC2M 2EE
United Kingdom
Reporting Accountants
LHM Casey McGrath
6 Northbrook Road
Dublin 6
Republic of Ireland
Auditors
Barr Pomeroy
21 Herbert Place
Dublin 2
Republic of Ireland
Financial Public Relations
College Hill
The Registry
Royal Mint Court
London EC3N 4QN
United Kingdom
Paul White & Associates
Beacon Court
Sandyford
Dublin 18
Republic of Ireland
Registrars
Computershare Investor Services (Ireland) Limited
Heron House
Corrig Road
Sandyford Industrial Estate
Dublin 18
Republic of Ireland
ISIN
IE00B3CLK236
EPIC
SLE.L
5
DEFINITIONS
The following definitions apply throughout this document, unless the context otherwise requires:
“1963 Act”
“1983 Act”
“1990 Act”
the Companies Act 1963 of Ireland
the Companies (Amendment) Act 1983 of Ireland
the Companies Act 1990 of Ireland
“2006 Act”
the Companies Act 2006 of Ireland
“Admission”
admission of the Issued Share Capital to trading on AIM and such
admission becoming effective in accordance with the AIM Rules
“Admission Agreement”
the conditional agreement dated 23 September 2008 between the
Company, the Directors and Daniel Stewart relating to Admission,
further details of which are set out in paragraph 12.15 of Part VI of
this document
“AIM”
“AIM Rules” or
“AIM Rules for Companies”
the AIM market operated by the London Stock Exchange
the AIM Rules for companies as published by the London Stock
Exchange entitled “AIM Rules for Companies” as amended from
time to time
“AIM Rules for
Nominated Advisers
the AIM Rules for Nominated Advisers published by the London
Stock Exchange as amended from time to time
“Articles”
the articles of association of the Company
“Board” or “Directors”
the board of directors of the Company for the time being, whose
names appear on page 4 of this document and Director means any
one of them including a duly constituted committee of such directors
“Code”
the City Code on Takeovers and Mergers
“Companies Acts”
the Companies Acts 1963 to 2006 of Ireland
“Company” or “San Leon”
San Leon Energy Plc, a company incorporated and registered in the
Republic of Ireland with registered number 237825
“Convertible Loan Note”
the Convertible Loan Note of €5 million further details of which are
set out in paragraph 3.18 of Part VI of this document
“CREST”
the computer based system and procedures which enable title to
securities to be evidenced and transferred without a written
instrument, administered by Euroclear UK & Ireland Limited
“CREST Regulations”
the Companies Act, 1990 (Uncertificated Securities) Regulations
1996 (SI 68 of 1996) of Ireland
“Daniel Stewart”
Daniel Stewart & Company plc, the Company’s nominated adviser
and broker for the purpose of the AIM Rules, a member of the
London Stock Exchange and regulated in the UK by the FSA
“Denver Basin” or “DJ Basin” Denver Julesburg or DJ Basin covering North East Colorado
(including Denver), South West Nebraska and North East Kansas
“EBN”
Energie Beheer Nederland B.V.
“EU”
the European Union
“EUROCLEAR UK”
Euroclear UK & Ireland limited, the operator of CREST
“Exploration Permits”
the seven exploration permits granted in relation to the Tarfaya
onshore area in Morocco to ONHYM Island International
Exploration Morocco, San Leon (Morocco) and Longreach Oil and
Gas Ventures Limited
“FSA”
the Financial Services Authority of the UK
6
“FSMA”
the Financial Services and Markets Act 2000, as amended
“HMRC”
Her Majesty’s Revenue and Customs
“Irish Takeover Panel”
The Irish Takeover Panel established under the Irish Takeover Panel
Act 1997
“IOG”
Island Oil & Gas Plc an Irish registered Company and/or any of its
subsidiaries as the context permits
“ISIN”
International Securities Identification Number
“Issued Share Capital”
the issued share capital of the Company immediately following
Admission, being 271,329,367 Ordinary Shares
“Leases”
the 70 oil and gas leases entered into by Western Nebraska Land
Services Inc. and landowners covering the Lease Area and assigned to
San Leon (USA) on 8 August 2008.
“Lease Areas”
the entire land area covered by the Leases being approximately 26 km2
“London Stock Exchange”
London Stock Exchange plc
“Lock-In Agreements”
the lock-in agreements between the Company, the Directors, their
respective nominee companies and Daniel Stewart further details of
which are set out in paragraph 12.13 of Part VI of this document
“Netherland Sewell”
Netherland, Sewell & Associates, Inc., the competent person who
prepared the Petroleum Consultant Report
“Netherlands Agreement”
the share purchase agreement made between Philip Thompson and San
Leon dated 11 July 2008 in respect of the sale and purchase of the
entire issued share capital of San Leon (Netherlands) further details of
which are set out in paragraph 12.9 of Part VI of this document
“Official List”
the official list of the United Kingdom Listing Authority
“ONHYM”
Office National des Hydrocarbures et des Mines
“Option”
a right to acquire Ordinary Shares granted to certain of the Directors
pursuant to the Option Agreements
“Option Agreements”
agreements between inter alia the Company and certain Directors
details of which are set out in paragraph 3.16 of Part VI of
this document
“Option Holder”
a holder of an option
“Ordinary Shares”
ordinary shares of €0.05 each in the capital of the Company
“Panel”
the Panel on Takeovers and Mergers
“Petroleum Agreement”
the petroleum agreement between ONHYM, Island International
Exploration Morocco, San Leon (Morocco) and Longreach Oil and
Gas Limited dated 15 November 2007
“Petroleum Consultant’s Report”
the report prepared by Netherland, Sewell & Associates, Inc. and set
out in Part IV of this document
“Production Licence”
the production licence granted pursuant to a decree dated
16 November 2006 by the Minister of Economic Affairs of the
Netherlands in relation to the Netherlands continental shelf block
Q13 to Nido Petroleum Limited and pursuant to the same decree,
the Minister of Economic Affairs granted approval for the transfer
of the production licence from Nido Petroleum Limited to Nido
Petroleum Limited and IOG.
“Prospectus Regulations”
the Prospectus Regulations 2005, implementing the EU Prospectus
Directive 2003/71/EC of the UK and the Prospectus (Directive
2003/71/EC) Regulations 2005 of Ireland
7
“QCA Guidelines”
the corporate governance guidelines for AIM companies, published
by the Quoted Companies Alliance
“Regulatory Information
Scheme”
a channel recognised by the FSA from time to time as a channel for
the dissemination of regulatory information by companies admitted
to AIM
“Republic of Ireland” or
“Ireland”
the island of Ireland excluding Northern Ireland and the word
“Irish” shall be construed accordingly
“Restricted Period”
the 12 month lock in period described in paragraph 18 of Part I and
paragraph 5 of Part VI of this document
“Royalty Agreement”
means the royalty agreement dated 7 December 2007 between
San Leon (Netherlands) and Island Netherlands B.V
“San Leon Group” or
“the Group”
San Leon Energy Plc and its subsidiaries
“San Leon (Italy)”
San Leon Italy s.r.l, a subsidiary of the Company registered in Italy
with company number 04085270751
“San Leon (Morocco)”
San Leon (Morocco) Limited, a subsidiary of the Company registered
in the British Virgin Islands with company number 1038054
“San Leon (Netherlands)”
San Leon (Netherlands) Limited, a subsidiary of the Company
registered in the British Virgin Islands with company
number 1402154
“San Leon Services”
San Leon Services Limited, a subsidiary of the Company registered
in Jersey with company number 101410
“San Leon (USA)”
San Leon (USA) Limited, a subsidiary of the Company registered in
Ireland with company number 366153
“Shareholder(s)”
the person(s) who are registered as holder(s) of Ordinary Shares
from time to time
“subsidiary” or “subsidiaries”
a subsidiary of the Company as defined in the 1963 Act
“Takeover Act”
The Irish Takeover Panel Act 1997 of Ireland (as amended)
“Takeover Rules”
The Irish Takeover Panel Act 1997, Takeover Rules 2001 to 2006
and the Irish Takeover Panel Act, 1997, Substantial Acquisition
Rules 2007, each of Ireland (as amended)
“United Kingdom” or “UK”
United Kingdom of Great Britain and Northern Ireland
“UK Listing Authority” or
“UKLA”
the Financial Services Authority acting in its capacity as the
competent authority for the purposes of Part VI of FSMA
“uncertificated” or
“in uncertificated form”
recorded on the register of holders of Ordinary Shares as being held
in uncertificated form in CREST, entitlement to which by virtue of
the CREST Regulations, may be transferred by means of CREST
“Warrants”
the warrants outstanding over the Ordinary Shares
“p” or “pence”
one hundredth part of one pound sterling
“£” or “sterling”
United Kingdom pounds sterling
“€” or “Euro”
Euro, the basic unit of currency among participating European
Union Countries
In this document, all references to time and dates are in reference to those observed in
London, England.
8
PART I
SUMMARY
The following is determined from, and should be read in conjunction with the full text of this document
and prospective investors should read the whole document and not just rely on the information set out
below. The attention of prospective investors is drawn, in particular, to Part III of this document, which
is entitled “Risk Factors”.
Overview
The San Leon Group is an international group of companies focused on the exploration and production
of oil and gas projects in North America, Morocco and The Netherlands.
In early 2008, the San Leon Group commissioned Netherland Sewell to produce the Petroleum
Consultant’s Report on the assets held by the Group. Under the Royalty Agreement, the Group is
entitled to a royalty from the Production Licence with Contingent Resources in the Dutch North Sea
through its wholly owned subsidiary, San Leon (Netherlands). In addition, through its subsidiary
San Leon (Morocco), the Group operates an onshore reconnaissance license and is also a partner in an
exploration license in Morocco. San Leon (USA) is also conducting a drilling campaign in Nebraska in
the United States.
The Group is in negotiations to acquire additional licences, in particular in Italy, and is actively
investigating other exploration areas.
Assets
The Group’s combined lease and license assets are summarised in the table below:
Area
Operator
Amstel Field, Block
Q/13a Production
License, Offshore
Island Oil &
Gas Plc
IOG
DJ Basin, Cheyenne
County, Nebraska,
United States
Participating
interest
Area
(km2)
Status
Expiration date
0.6 per cent.
royalty
Contingent
Production License is
retained for the duration
of oil production
30
San Leon
(USA)
Limited
100 per cent.
working and
82 per cent.
revenue(1)
Exploration
Leases are valid for
18 months; pending
discovery, leases are
held by production
26
Tarfaya Exploration
Permits, Morocco
IOG
30 per cent.
working(2)(3)
Exploration
Phase I – 07/2010
Phase II – 07/2013
Phase III – 01/2016
13,434
Zag Exclusive
Reconnaissance
License, Morocco
San Leon
(Morocco)
50 per cent.
Exploration
Exclusive Reconnaissance
License extension – 12/2008
21,807
(1) James Mitchell, a consultant to San Leon, has a 4.5 per cent. overriding royalty interest, and San Leon has agreed to provide a
1 per cent. royalty interest to Western Nebraska Land Services Inc., a company that has provided land services to San Leon. This
leaves San Leon (USA) with an 82 per cent. revenue interest.
(2) Pursuant to the Petroleum Agreement, San Leon’s participating interest in the Tarfaya exploration permits is initially 30 per cent.
because of a royalty exemption on the first 300 thousand tons, approximately 1.9 million barrels (MMBBL), of oil. San Leon’s interest
becomes 27 per cent. after production of the exempted oil volume to account for the 10 per cent. royalty on oil production.
(3) Pursuant to the Petroleum Agreement, the Office National des Hydrocarbures et des Mines (ONHYM) has a 25 per cent. interest,
and San Leon has a 22.5 per cent. interest. ONHYM has the right to maintain its interest of up to 25 per cent. If ONHYM
relinquishes all of its 25 per cent. interest, San Leon may be entitled to an interest of up to 30 per cent. as a nonoperating partner.
If ONHYM maintains its interest at the maximum 25 per cent., San Leon will have a 22.5 per cent. equity interest. The participating
interest volumes shown in this report for San Leon in relation to the Tarfaya exploration permits are based on the assumption that
ONHYM will relinquish all of its 25 per cent. interest.
The table and notes above are extracted from the Petroleum Consultant’s Report on page 52 in Part IV of this document.
9
Key highlights & strengths
The Directors believe that the key strengths of the Group are:
•
its portfolio of oil and gas exploration assets in Morocco and the USA;
•
the benefit of the Royalty Agreement in The Netherlands;
•
operational progress in the exploration of its assets;
•
its negotiations for new licences and additional exploration areas; and
•
a strong management team that has technical, exploration and commercial expertise.
Strategy
The strategy of the Group is to acquire a balance of low risk production and high reward exploration
licences. In the short term, the Group intends to concentrate on delivering oil and gas production
through its US assets in the DJ Basin.
Management
The Board has many years of international oil and gas experience and commercial expertise. The
technical team includes Philip Thompson and Jeremy Boak who collectively have over 50 years of
experience in petroleum geophysics and geology.
Expected market capitalisation at Admission
On Admission, the market capitalisation of the Company at 37 pence per Ordinary Share is expected to
be £100.4 million.
Risk Factors
Your attention is drawn to the risk factors which are set out in Part III of this document.
10
PART II
INFORMATION ON THE GROUP
1.
Introduction
The San Leon Group is an international group of companies focused on the exploration and production
of oil and gas projects in North America, Morocco and The Netherlands.
In early 2008, the San Leon Group commissioned Netherland Sewell to produce the Petroleum Consultant’s
Report on the assets held by the Group. The Group is entitled to a royalty from the Production Licence with
Contingent Resources in the Dutch North Sea through its wholly owned subsidiary San Leon (Netherlands).
In addition through its subsidiary, San Leon (Morocco), the Group operates an onshore reconnaissance
license and is also a partner in an exploration license in Morocco. Further, San Leon (USA) is conducting
a drilling campaign in the Denver Basin in Nebraska in the US. In aggregate, the Group’s license interests
represent a combined area covering approximately 35,297 square kilometres (km2).
San Leon is now seeking Admission to AIM.
2.
History and Background
The Company was incorporated in 1995 as an oil and gas exploration company. Between 1995 and
2007, its principle activity was to act as an investment vehicle. In October 2007 the Company acquired
its first exploration assets, situated in Morocco.
With new management, investment and a strategy of balanced acquisition and exploration, the Company
has established the portfolio of assets described in this document. The Company has secured financing
of €5 million through the Convertible Loan Note. Further details of the Convertible Loan Note are set
out in paragraph 3.18 of Part VI of this document.
3.
Summary of the Petroleum Consultant’s Report
The Group’s combined lease and license areas are shown below:
Area
Operator
Amstel Field, Block
Q/13a Production
License, Offshore
the Netherlands
Island Oil
and Gas Plc
IOG
DJ Basin, Cheyenne
County, Nebraska,
United States
San Leon
(USA)
Limited
Tarfaya Exploration
Permits, Morocco
IOG
Zag Exclusive
Reconnaissance
License, Morocco
San Leon
(Morocco)
Participating
interest
Area
(km2)
Status
Expiration date
0.6 per cent.
royalty
Contingent
Production License is
retained for the duration
of oil production
30
100 per cent.
working and
82 per cent.
revenue(1)
30 per cent.
working(2)(3)
Exploration
Leases are valid for 18 months;
pending discovery, leases are
held by production
26
Exploration
Phase I – 07/2010
Phase II – 07/2013
Phase III – 01/2016
13,434
50 per cent.
Exploration
Exclusive Reconnaissance
License extension – 12/2008
21,807
(1) James Mitchell, a consultant to San Leon (USA), has a 4.5 per cent. overriding royalty interest, and San Leon (USA) has agreed
to provide a 1 per cent. royalty interest to Western Nebraska Land Services Inc., a company that has provided land services to
San Leon (USA). This leaves San Leon (USA) with an 82 per cent. revenue interest.
(2) Pursuant to the Petroleum Agreement, San Leon’s participating interest in the Tarfaya exploration permits is initially 30 per cent.
because of a royalty exemption on the first 300 thousand tons, approximately 1.9 million barrels (MMBBL), of oil. San Leon’s interest
becomes 27 per cent. after production of the exempted oil volume to account for the 10 per cent. royalty on oil production.
(3) Pursuant to the Petroleum Agreement, the Office National des Hydrocarbures et des Mines (ONHYM) has a 25 per cent. interest,
and San Leon has a 22.5 per cent. interest. ONHYM has the right to maintain its interest of up to 25 per cent. If ONHYM
relinquishes all of its 25 per cent. interest, San Leon may be entitled to an interest of up to 30 per cent. as a nonoperating partner.
If ONHYM maintains its interest at the maximum 25 per cent., San Leon will have a 22.5 per cent. equity interest. The participating
interest volumes shown in this report for San Leon in relation to the Tarfaya exploration permits are based on the assumption that
ONHYM will relinquish all of its 25 per cent. interest.
The table and notes above are extracted from the Petroleum Consultant’s Report on page 52 in Part IV of this document.
11
A summary of the Group’s Contingent Resources located offshore The Netherlands and Prospective
Resources located in the United States and Morocco, as assessed by Netherland Sewell, is set out in the
Petroleum Consultant’s Report.
The Petroleum Consultant’s Report, as prepared by Netherland Sewell, is set out in its entirety in Part IV
of this document.
Contingent Resources
A summary of the Group’s Contingent Resources and cash flow to the Group’s royalty interest in the
Amstel Field offshore The Netherlands as at 1 September 2008 is as follows using a combination of
deterministic and probabilistic methods:
Contingent Oil Resources
Gross
Net
(MBBL)
(MBBL)
Category
Low Estimate
Best Estimate
High Estimate
4,100.0
8,500.0
16,200.0
Net Contingent Cash Flow (M$)
Discounted
Total
at 10%
24.6
51.0
97.2
1,968.1
4,079.9
7,776.3
1,625.9
3,151.5
5,302.8
Note: The oil resources shown only include crude oil. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent
to 42 United States gallons. Gross resources are 100 per cent. of the resources expected to be produced from the wells. Net resources
are the share of the resources attributable to San Leon (Netherlands)’s 0.6 per cent. net royalty interest (being a 1 per cent. royalty
entitlement under the Royalty Agreement less the State Profit Share). Cash flow estimates are expressed in thousands of United States
dollars (M$).
The table and notes above are extracted from the Petroleum Consultant’s Report on page 28 in Part IV of this document.
Prospective Resources
A summary of the Group’s unrisked and risked Prospective Resources in the DJ Basin
Lease Area, Nebraska and Tarfaya Exploration Permits, Morocco as at 1 September 2008 is as follows:
Lease Area or
License/Category
DJ Basin Lease Area,
Nebraska
Low Estimate
Best Estimate
High Estimate
Tarfaya Exploration
Permits, Morocco
Low Estimate
Best Estimate
High Estimate
Prospective Resources
Gross (100 per cent.)
San Leon Participating Interest
Unrisked
Risked
Unrisked
Risked
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
(MMBBL)
(BCF) (MMBBL)
(BCF) (MMBBL)
(BCF) (MMBBL) (BCF)
1.7
3.3
6.3
4.5
5.4
6.3
0.3
0.5
1.0
1.5
1.8
2.2
1.4
2.7
5.2
3.7
4.4
5.2
0.2
0.4
0.8
1.2
1.5
1.8
133.8
711.3
3,878.6
0.0
0.0
0.0
8.5
40.5
195.9
0.0
0.0
0.0
36.5
192.9
1,048.1
0.0
0.0
0.0
2.3
11.0
52.9
0.0
0.0
0.0
Exploration and production leases, DJ Basin, Cheyenne County, Nebraska, United States:
•
Assessed low, best and high estimate unrisked prospective resources to San Leon (USA)’s 100 per cent. working interest and
82 per cent. revenue interest in 6 identified prospects using a combination of deterministic and probabilistic methods.
•
Conducted geological risk assessment for each identified prospect.
Tarfaya exploration permits, onshore Morocco:
•
Assessed low, best and high estimate unrisked prospective resources to San Leon (Morocco)’s 30 per cent. nonoperating
working interest, assuming ONHYM relinquishes all of its 25 per cent. interest, for 15 identified leads using a combination of
deterministic and probabilistic methods.
•
Prepared a scoping economic analysis for a representative development of a single lead.
•
Conducted geological risk assessment for each identified lead.
Play concept description – Zag exclusive reconnaissance license, onshore Morocco:
•
Prepared a description of basin petroleum system and play types for San Leon (Morocco) operated 50 per cent. participating
interest in the Zag exclusive reconnaissance license.
The table and notes above are extracted from the Petroleum Consultant’s Report on pages 29 to 31 in Part IV of this document.
12
4.
The Group’s Assets
The San Leon Group’s combined lease and licence areas cover approximately 35,297 square kilometres
(km2), as shown in Figures 1, 2 and 3 of the Petroleum Consultant’s Report and reproduced on pages 84
to 86 in Part IV of this document and summarised in the table on page 11 above under “Summary of
the Petroleum Consultant’s Report”.
Further details of these assets are set out below in this paragraph 4 of this Part II of this document.
Amstel Field, Block Q13a Production Licence, offshore the Netherlands
Amstel Field is an appraised but undeveloped discovery that was awarded by the Dutch Ministry of
Economic Affairs of the Netherlands to IOG as a production licence effective from 17 November 2006.
The Production Licence is awarded in respect of that part of Block Q13 which is referred to as “Block
Q13a”. The Amstel Field development area is located in the West Netherlands Basin of the North Sea
approximately 10km offshore, and covers 30 km2 in water depths between 21 and 23 metres.
The location of the Amstel Field assets is shown below:
Source: Petroleum Consultant’s Report
The Block Q13a Production Licence is operated by Island Netherlands B.V with a 40 per cent.
mandatory state participation through EBN. San Leon (Netherlands) entered into the Royalty
Agreement with IOG on 7 December 2007. Under the terms of the Royalty Agreement, San Leon
(Netherlands)’s interest in Block Q13a is a royalty interest of 0.6 per cent. after EBN participation. The
royalty interest entitles San Leon (Netherlands) to 0.6 per cent. of the gross revenue from the production
flowstreams from Block Q13a. Pursuant to the Netherlands Agreement and the satisfaction of certain
conditions, Philip Thompson is entitled, inter alia, to a payment equal to 50 per cent. of the royalties
received by San Leon (Netherlands) in excess of US$1 million. Further details of the Netherlands
Agreement are set out in paragraph 12.9 of Part VI of this document.
13
The hydrocarbon resources at Amstel Field are planned to be developed during 2008 from 2 high-angle
or horizontal wells and 1 vertical well. Production startup is anticipated during 2010 with oil produced
via an unmanned wellhead protector jacket. The oil is anticipated to be exported through a 24 kilometre
(km) pipeline to the Rijn Field platform facilities for processing and onward transmission. Pending
regulatory approval, confirmation by EBN that it will exercise its 40 per cent. equity participation and
demonstration of commerciality, the undeveloped hydrocarbon volumes are classified as Contingent
Resources. Provided these contingencies are met, some portion of the Contingent Resources estimated
in the Petroleum Consultant’s Report may be reclassified as reserves. The field operator, Island
Netherlands B.V. has informed San Leon (Netherlands) that the letters of agreement for field
development are in the final stages of the approval process.
An assessment of Contingent Resource estimates for the Amstel Field, Block Q13a licence is included
at paragraph 4.1.4. of the Petroleum Consultant’s Report in Part IV of this document.
DJ Basin, Cheyenne County, Nebraska, United States
San Leon (USA) owns a 100 per cent. working interest in the Leases in Nebraska that encompass
approximately 6,400 contiguous acres (approximately 26 km2). The Lease Area is located on the eastern
flanks of the DJ Basin where San Leon (USA)’s exploration efforts will be focused on the
Cretaceous-aged D Sandstone oil reservoirs with secondary objectives in the shallower Cretaceous-aged
Niobrara gas reservoirs and a deeper Permian-aged Lyons oil interval.
The location of the DJ Basin assets is shown below:
Source: Petroleum Consultant’s Report
The acreage was leased on behalf of San Leon (USA) from a number of mineral rights owners at an
average cost of US$4.75 per acre per annum. The mineral rights owners retain a 12.5 per cent. royalty
interest for revenue generated from production. James Mitchell, a consultant to San Leon (USA) has a
4.5 per cent. overriding royalty interest, and San Leon (USA) has agreed to provide a 1 per cent. royalty
interest to Western Nebraska Land Services Inc., a company that has provided land services to
San Leon (USA). This leaves San Leon with an 82 per cent. revenue interest. Mineral leases provide the
rights to conduct exploration drilling and, in the event of a discovery, to construct necessary facilities to
produce the discovered hydrocarbons.
14
San Leon (USA) recently acquired a 3-D seismic data set over the Lease Area. 8 exploration prospects
have been identified and assessed. The ongoing drilling campaign is expected to be completed by the
first quarter of 2009. Drilling and completion costs for a successful discovery are estimated by
San Leon (USA) to average US$540,000, which includes at least one Lyons Sand test. Dry hole costs
are estimated to be US$165,000 for a D Sand test and US$375,000 for a Lyons Sand test. San Leon
drilled its first exploration well, Ludeman 1, in July 2008 to test the D Sand C prospect and Lyons Sand
Dune East prospect. This well failed to find commercial quantities of hydrocarbons in the D Sand and
Lyons Sand intervals.
An assessment of Prospective Resource estimates for the DJ Basin exploration and production leases,
is included at paragraph 5.1.4 of the Petroleum Consultant’s Report in Part IV of this document.
Tarfaya Exploration Permits, Morocco
The Tarfaya interest, comprising of 7 Exploration Permits, is located in the Tarfaya-Laayoune Basin of
southern Morocco and encompasses 13,434 km2. The Exploration Permits are located onshore and
border the coastline of the Atlantic Ocean.
The location of the Tarfaya and Zag (discussed below) assets is shown below:
Source: Petroleum Consultant’s Report
The Petroleum Agreement sets out the basis for the award of the Exploration Permits. The Exploration
Permits were awarded by ONHYM effective 14 January 2008, for an initial term of 2 years and
6 months. The parties to the Petroleum Agreement are entitled to apply to have the term of the
exploration permits extended for further periods of 3 and 2.5 years as set out below.
Pursuant to the Petroleum Agreement ONHYM has an interest of 25 per cent. and San Leon (Morocco), a
non operator, has an interest of 22.5 per cent. in the Tarfaya area. None of the costs incurred pursuant to the
Exploration Permits are borne by ONHYM. Any costs incurred pursuant to an exploitation concession, when
one is issued, are borne by all parties to the Petroleum Agreement including ONHYM in proportion to their
interests, which for ONHYM is 25 per cent. and San Leon (Morocco) 22.5 per cent. If ONHYM were to back
out of the Tarfaya area and relinquish all of its interest San Leon (Morocco) may be entitled to participate in
ONHYM’s share and have an interest of up to 30 per cent. in total in the Exploration Permits.
The exploration work programs for the three periods include the following:
15
•
Phase I: 2.5-year period – acquire, process, and interpret 500 km line of 2-D seismic data and conduct
geochemical modeling. A drill or drop decision will be made at the end of the initial period.
•
Phase II (if granted): 3-year period – drill 1 well.
•
Phase III (if granted): 2.5-year period – drill 2 wells.
There are 15 onshore leads that have been identified and assessed which can be subdivided into two
primary types contained in Mesozoic age reservoirs: Jurassic platform carbonates and Triassic clastic
reservoirs. Delineation of the lead areas through exploratory drilling will dictate development plans.
ONHYM has provided San Leon (Morocco) with a preliminary dry hole cost estimate of US$7 million.
An assessment of Prospective Resource estimates for the Tarfaya Exploration Permits is included at
paragraph 5.2.8 of the Petroleum Consultant’s Report in Part IV of this document.
Zag Exclusive reconnaissance license, Morocco
The Zag exclusive reconnaissance license is located in southern Morocco and occupies approximately
21,807 km2. The license was awarded by ONHYM to San Leon (Morocco) and its joint venture partners
IOG and GB Oil and Gas Ventures Limited (which has since changed its name to Longreach Oil and
Gas Ventures Limited) on December 25, 2006, for a 12-month period initially. ONHYM subsequently
granted a 12-month extension valid until 25 December 2008. The joint venture partners in the license
are San Leon (Morocco), as operator, with a 50 per cent. interest; Longreach Oil and Gas Ventures
Limited with a 30 per cent. interest and IOG with a 20 per cent. interest.
Following agreement with the joint venture partners, San Leon (Morocco)’s cost for the first year work
program has been fully carried by the partners. The first year work program includes reviewing existing
studies; conducting geological field studies and a geochemical study; and the interpretation of satellite
image data. The Directors believe that the integration of this data will aid in high-grading areas for future
acquisition of a 2-D seismic survey to delineate leads and prospects. The first year work program has been
completed by San Leon (Morocco). The studies completed by San Leon (Morocco) were compiled into a
comprehensive report entitled “Zag License: First Prospectivity Report”. This report documents the
drilling history and oil and gas shows encountered by previous wells on the basin margins and analog wells
from the Reggane-Tindouf Basin in Algeria, source rock geochemistry obtained from diggings from water
wells in the 50 to 100 metre depth range, and analysis of the petroleum system and play concepts.
San Leon (Morocco) is currently progressing in the 12-month extension period work programme. The
key obligation in this period is the acquisition, processing, and interpretation of an aero-magnetic
survey which it is anticipated will be completed in the fourth quarter of this year.
5.
Petroleum Consultant’s Report
Your attention is drawn to the full text of the report prepared by Netherland Sewell which is set out in
Part IV of this document.
6.
Strategy
The strategy of the Group is to acquire a balance of low risk production and high reward exploration
licenses. In the short term, the Group intends to concentrate on oil and gas production through its US
assets in the D J Basin.
7.
Current Trading and Prospects
The principal focus of the Group’s current activities is drilling and development in the DJ Basin,
Nebraska. Five wells are planned to be drilled within the next 18 months.
In addition, an aero-magnetic survey of the Zag Basin, Morocco is expected to be completed by the end
of 2008. There is no planned exploration activity in the Tarfaya Basin, Morocco in the short term.
16
The Directors believe that the anticipated development schedule of the Amstel Field, The Netherlands
indicates a production start date of January 2010 leading to the commencement of royalty income being
paid to the Group.
The Directors intend to continue to seek additional licences, in particular in Italy where San Leon (Italy)
has applied for five licences, and is actively investigating other exploration areas.
8.
Board of Directors
The Board comprises of 6 directors, brief biographies of whom are set out below.
Oisín Fanning (aged 50), Chairman, has over twenty five years experience in structured finance,
stockbroking and corporate finance, including ten years specialising in the oil & gas industry. From
1999 to 2006 he was chief executive of Smart Telecom plc, from 1993 to 1998 he was chief executive
of MMI Stockbrokers Limited and from 1990 to 1993 he was chief executive of Astley Pearce limited.
Philip Thompson (aged 48), Chief Executive Officer, has over twenty five years experience in the oil &
gas industry throughout Africa, Europe, North America, and South America. Key projects have included
oil & gas discoveries in Chad, offshore Holland, onshore USA and offshore Ireland. He has extensive
experience in project management, international oil and gas exploration new-ventures and geophysics with
Exxon, Anadarko (formerly Oryx Energy and Kerr-McGee) and Vanco Energy. He has an M.Sc. in
Geophysics from Southern Methodist University and a B.Sc. in Geophysics from Texas A&M University.
Charles McEvoy (aged 53), Operations Director, has over 25 year operational, engineering and
business development experience. He has been involved with major blue chip organisations within the
manufacturing and service industries, including Intel, ADT and in business restructuring with Eircom.
Paul Sullivan (aged 51), Commercial Director, has over thirty years experience in corporate treasury
and operations within banking, including with Nordbanken NY, Standard Chartered Bank, Dublin, and
BNP Paribas, Dublin.
Jeremy Boak Ph.D (aged 56), Non-Executive Director, is Project Manager with the Colorado Energy
Research Institute (CERI), the Los Alamos National Laboratory and the U. S. Department of Energy
(DOE). He chaired international symposia on the development of oil shale and he carried out geological
investigations for exploration and development in Alaska, Colorado, Oklahoma, Texas and California.
He is affiliated to the Geological Society of America, American Association of Petroleum Geologists
(AAPG), AAPG Division of Environmental Geology and the American Nuclear Society. Dr Boak is
extensively published and has a Ph.D. and BA in Geology from Harvard University and an
M.S. Geology from the University of Washington.
Raymond King (aged 66), Non-Executive Director, is a qualified Chartered Secretary, Compliance
Officer, Information Technologist, Banker and Accountant. He has considerable experience in Finance
and IT and has been a Chartered Secretary for 40 years. From 1958 to 1986 he worked for the NatWest
Group. He was also associate director of Christiana Bank, general manager of operations of Moscow
Narodny Bank, company secretary of SIM Group and chairman of Smart Telecom plc. He has acted in
various senior executive and non-executive director roles, such as finance director, managing director
and chairman of companies which have been brought to AIM, NASDAQ and OFEX (now PLUS
Markets). In all companies he has also acted as company secretary.
9.
Corporate Governance
The Combined Code
It is the Board’s intention that, in so far as it is practicable and taking into account the size and nature
of the Company, it will comply with the Combined Code on Corporate Governance published in
June 2006 by the Financial Reporting Council (the “Combined Code”). Where full compliance is not
appropriate due to the size of the Company, the Directors will refer to the QCA Guidelines. In addition,
the Company will abide by Rule 21 of the AIM Rules (regarding directors’ dealings) and will take all
reasonable steps to ensure compliance by the Directors and applicable employees.
The Company is committed to high standards of corporate governance. The Board is accountable to
Shareholders for good corporate governance and has adopted procedures it considers appropriate,
having regard to the size and best interests of the Company.
17
The Board
The Board comprises of Oisín Fanning, Philip Thompson, Paul Sullivan, Raymond King, Charles
McEvoy and Jeremy Boak. Oisin Fanning, Philip Thompson, Paul Sullivan and Charles McEvoy have
entered into full time service agreements with San Leon Services, a subsidiary of San Leon, pursuant
to which they have agreed to devote their whole time to the business of the San Leon Group.
In order to ensure that the Directors can properly carry out their roles, the members of the Board are
provided with comprehensive information and financial details prior to all Board meetings. The Board
meets at least six times a year to discuss and decide the Company’s business and strategic decisions. In
addition, there is a high degree of contact between Board meetings to ensure all Directors are aware of
the Company’s business. If necessary, the non-executive Directors may take independent advice at the
expense of the Company.
Remuneration Committee
The Remuneration is composed of Raymond King, Oisin Fanning and Paul Sullivan. Raymond King has
been appointed chairman. The Remuneration Committee monitors the performance of each of the
Company’s executive Directors and senior executives to ensure they are rewarded fairly for their
contribution. The recommendations of the Remuneration Committee are presented to a meeting of the
full Board. The remuneration and terms and conditions of appointment of the non-executive directors
are set by the Board as a whole.
The Audit Committee
The Audit Committee consists of Raymond King and Paul Sullivan. Raymond King has been appointed
chairman. The Audit Committee is responsible for ensuring that the Combined Code is implemented in
respect to matters relating to the Company’s external audit. In addition, the Committee also discusses the
scope of the audit before its commencement and it receives reports from the external auditors. The
Committee also recommends the appointment of, and will review the fees of, the external auditors. The
Audit Committee meets the external auditors and meets internally at least twice per year. It also meets
on an ad hoc basis as required.
Internal Controls
The Board acknowledges its overall responsibility for ensuring that the Company has a system of
internal controls in place that is appropriate. However, Shareholders should be mindful that any system
can only provide reasonable, not absolute assurance against material misstatement or loss and is
designed to manage but not eliminate the risk of failure to achieve business objectives. The key
procedures are:
•
a corporate governance policy with clearly defined rules relating to the delegation of authority;
•
preparation of annual budgets for all of the businesses, reviewed by the executive management
and subject to Board approval; and
•
monthly review of sales, cash and profitability compared with budget.
The Company has adopted a model code for Directors’ share dealings which is appropriate for an AIM
quoted company. The Directors have undertaken to comply with Rule 21 of the AIM Rules relating to
Directors’ dealings and will take all reasonable steps to ensure compliance by the Company’s applicable
employees as well.
10. Reasons for Admission
Application has been made to the London Stock Exchange for the Issued Share Capital to be admitted
to trading on AIM. It is expected that Admission will take place and that dealings on AIM will
commence on 29 September 2008.
The Company is seeking Admission for the following reasons:
•
to provide access to capital in order to develop the Group’s assets;
•
to facilitate the raising of finance, both equity and debt, and to enable it to offer its quoted shares
for any potential acquisitions; and
•
to enhance the Group’s profile.
18
11. Dividend Policy
The Directors intend to commence the payment of dividends only when it becomes commercially
prudent to do so, having regard to the resources needed for the Group’s growth.
12. Options
The Company has entered into Option Agreements with certain of the Directors under which, in aggregate
it has granted options to acquire 7,000,000 Ordinary Shares. The Company, through its subsidiary
San Leon (Italy) has submitted five applications for Italian licence permits. On the successful granting of
an Italian permit, a success fee of £55,000 per licence application (the “Success Fee”) will be paid to BWG
s.r.l. It has been agreed between BWG s.r.l. and the Company that BWG s.r.l. shall apply its Success Fee
by subscribing for 500,000 Ordinary Shares at a subscription price of £0.11 per share. The maximum
number of shares that may be issued as a result of the agreement with BWG s.r.l. if the five applications
are successful is 2,500,000 Ordinary Shares. Further details of the Options and the agreement relating to
the Success Fee are set out in paragraph 3.16 of Part VI of this document.
In addition Mr. David Turner has the right in certain circumstances to subscribe for Ordinary Shares
pursuant to the Convertible Loan Note details of which are set out in paragraph 3.18 of Part VI of
this document.
13. Warrants
The Company has 30,697,443 Warrants in issue. Each Warrant entitles the holder to subscribe for one
Ordinary Share at a price of £0.11 per share. The Warrants expire three years from the date of Admission.
Further details of the Warrants are set out in paragraph 3.17 of Part VI of this document.
14. Regulation
Summaries of oil and gas regulation in Nebraska (USA), Morocco and The Netherlands are set out in
paragraph 14 of Part VI of this document.
15. Taxation
General information relating to taxation is set out in paragraph 16 Part VI of this document. These
details are, however, intended only as a general guide to the current tax position under UK and Irish
taxation law.
This document has been prepared on the basis of current legislation, rules and practice and the advisers’
interpretation thereof. Such interpretation may not be correct and it is always possible that legislation,
rules and practice may change. Any changes in legislation and in particular any changes to bases of
taxation, tax relief and rates of tax may affect the availability of reliefs.
Shareholders and potential shareholders of the Company who are in any doubt as to their tax position
are strongly advised to consult their own financial adviser immediately.
16. Admission and CREST
It is expected that Admission will take place and that dealings on AIM will commence on
29 September 2008.
All of the Ordinary Shares will be in registered form and no temporary documents of title will be issued.
The Company has applied for the Ordinary Shares to be admitted to CREST. CREST is a paperless
settlement system which allows for the transfer of shares electronically in uncertificated form. The
Articles of the Company allow the holding and transfer of Ordinary Shares under the CREST system
and it is expected that the Ordinary Shares will be so admitted, and accordingly enabled for settlement
in CREST, on the date of Admission. However, CREST is a voluntary system and holders of Ordinary
Shares who wish to receive and retain share certificates will be able to do so.
19
17. The Takeover Code
San Leon is incorporated in the Republic of Ireland and the place of central management and control of
the Company is located outside of the UK, the Channel Islands and the Isle of Man. Accordingly, as the
Company is one to which paragraph 3(a)(ii) of the Introduction to the Code applies, the Directors
believe that the Company is not subject to the Code and Shareholders will not be afforded any
protections under the Code.
If circumstances change, including if changes to the Board are made, the Company will consult with
the Takeover Panel to ascertain whether this will affect the central place of management of the
Company. If the Takeover Panel determines that, as a result of such changes, the place of central
management of the Company is located in the UK, the Channel Islands or the Isle of Man such that the
Code then becomes applicable to the Company, an announcement will be made.
San Leon is subject to the Takeover Rules in Ireland and Shareholders are therefore afforded protections
under the Takeover Rules. A summary of these Rules relating to mandatory bids is set out in
paragraph 9 of Part VI of this document.
18. Lock-in and Orderly Market Arrangements
The Directors and their respective nominees have given undertakings:
i)
for the purposes of Rule 7 of the AIM Rules for Companies that they will not dispose of any
interests they have in Ordinary Shares or other securities of the Company for a period of one year
from Admission (the “Hard Lock-in Period), except in the strictly limited circumstances permitted
by Rule 7 of the AIM Rules and then only with the prior written consent of Daniel Stewart; and
ii)
not to dispose of any interests they have in Ordinary Shares or other securities of the Company
for a further period of one year following the expiry of the Hard Lock-in Period without the prior
written consent of Daniel Stewart, which it will not unreasonably withhold. During this period
Daniel Stewart will have the exclusive right to effect any such disposal on their behalf.
Further details of the lock-in arrangements are set out in paragraph 12.13 of Part VI of this document.
19. Additional Information
Your attention is drawn to Part I of this document, which contains summaries of San Leon Group’s
licences, Part III of this document which contains risk factors relating to an investment in the Company,
Part IV of this document which contains the Petroleum Consultant’s Report in respect of San Leon
Group’s oil and gas assets and Part V which contains financial information on the San Leon Group, as
well as further additional information on the San Leon Group contained in Part VI of this document.
20
PART III
RISK FACTORS
Before deciding whether to invest in the Company’s Ordinary Shares, prospective investors should
carefully consider the risks described below together with all other information contained in this
document. If any of the following risks actually occur, the San Leon Group’s business, financial
condition, results of operations and/or the scope of its operations and anticipated expansion could
be materially and adversely affected. In such case, an investor may lose all or part of his or her
investment. Additional risks and uncertainties not currently known to the Directors may also have
an adverse effect on the Group’s business and the information set out below does not purport to
be an exhaustive summary of the risks affecting the San Leon Group.
An investment in the Company is suitable only for financially sophisticated investors who are
capable of evaluating the merits and risks of such an investment and who have sufficient resources
to be able to bear any losses which may arise therefrom and which may be equal to the whole
amount invested.
SECTION A: RISKS RELATING TO THE COMPANY AND THE SAN LEON GROUP
San Leon (USA) Leases
San Leon (USA) is the assignee of interests in base oil and gas leases described more particularly in
paragraph 12.10 of Part VI of this document. The Company has carried out limited title investigations
in relation to the Lease Area but has not incurred the significant expense involved in carrying out
exhaustive title searches in relation to the Lease Area until the Company has completed its review of the
Lease Area and identified the areas within the Lease Area in which it proposes drilling. There can be
no guarantee that the parties will be able to obtain drill-site opinions confirming that they have good
title to the Lease Area and until such time as positive drill-site legal opinions are obtained, there is a risk
that the Company will not be able to obtain good title to the Lease Area.
Exploration risk and permitting regulations
The future value of San Leon is largely dependent on the success or otherwise of the San Leon Group’s
activities, which are directed towards the search, evaluation and development of oil and gas reserves.
Exploration for and development of resources is speculative and involves a significant degree of risk.
While the rewards can be substantial, there is no guarantee that exploration by the San Leon Group will
lead to commercial discovery or, if there is such discovery, that the San Leon Group will be able to
realise such reserves as intended. If at any stage the San Leon Group is precluded from pursuing its
exploration or production programmes, or decides not to continue with any of these, this is likely to have
an adverse effect on the value of investors’ holdings.
Moreover, if the San Leon Group does not meet its work and/or expenditure obligations under its
production sharing agreements or any existing or future permits and/or licences in which it has a
participating interest this may lead to dilution of its interest in, or the loss of, such production sharing
agreements, permits or licences.
Drilling and operating risk
Exploration and development activities may be delayed or adversely affected by factors outside the
control of the San Leon Group. These include adverse climatic conditions, the performance of joint
venture or farm-in partners on whom the San Leon Group may be or may become reliant, compliance
with governmental requirements, shortage or delays in installing and commissioning plant and
equipment or import or customs delays. Problems may also arise due to the quality or failure of locally
obtained equipment or interruptions to services (such as power, water, fuel or transport or processing
capacity) or technical support which result in failure to achieve expected target dates for exploration or
production and/or result in a requirement for greater expenditure. Drilling may involve unprofitable
efforts, not only with respect to dry wells, but also with respect to wells which, though yielding some
21
oil or gas, are not sufficiently productive to justify commercial development or cover operating and
other costs. Completion of a well does not ensure a profit on the investment or recovery of drilling,
completion and operating costs.
Substantial operational risks are involved in seismic exploration and the drilling for, development of and
production from oil and gas fields, including blow-outs, cratering, explosions, pollution, seepage or
leaks, fire, earthquake activity, unusual or unexpected geological conditions and other hazards which
may delay, or ultimately prevent, the exploitation of such fields or may result in cost overruns or
substantial losses to the San Leon Group due to substantial environmental pollution or damage, personal
injury or loss of life, clean up responsibilities, regulatory investigation and penalties or suspension of
operations. Such hazards can also severely damage or destroy equipment, surrounding areas or property
of third parties. Damage or loss occurring as a result of such risks may give rise to claims against the
San Leon Group. Although the San Leon Group proposes to maintain insurance which the Directors
consider to be appropriate in accordance with industry practice, there may be circumstances where the
San Leon Group’s insurance or that of the operator of a field will not cover or be adequate to cover the
consequences of such events or where the San Leon Group may become liable for pollution or other
operational hazards against which it either cannot insure or may have elected not to have insured on
account of high premium costs or otherwise. Moreover, there can be no assurance that the San Leon
Group will be able to maintain adequate insurance in the future at rates the Directors
consider reasonable.
Economic and political risk
The San Leon Group’s current interests are in Morocco, the Netherlands and the United States where
there may be a number of associated risks over which it will have no, or limited, control. These may
include contract renegotiation, contract cancellation, economic, social, or political instability or change,
hyperinflation, currency non-convertibility or instability and changes of laws affecting foreign
ownership, government participation, taxation, working conditions, rates of exchange, exchange
control, exploration licensing and petroleum export licensing and export duties as well as government
control over domestic oil and gas pricing.
While most of the San Leon Group’s financial obligations are denominated in US dollars, a number of
foreign currency effects may arise from exchange rate movements. San Leon does not engage in active
speculative hedging to minimise exchange rate risk.
Western Sahara or Southern Provinces of Morocco
The territory that lies in the west of the Sahara desert is currently claimed by both the Moroccan
government and a pro-independence movement, known as the Polisario Frente. The Polisario presents
itself as the representation of the indigenous peoples of Western Sahara, collectively referred to as the
Sahwari People. The Polisario is also known as the Sahwari Arab Democratic Republic (SADR) and is a
member of the African Union. The Zag exclusive reconnaissance licence granted to San Leon (Morocco)
(“Zag Licence”) overlaps some of the acreage that is disputed. The dispute in this area may impact upon
San Leon Group’s ability to undertake exploration and or other activities relating to the Zag Licence.
Legal systems
Jurisdictions in which the San Leon Group operates or might operate in the future may have less
developed legal systems than more established economies which could result in risks such as
(i) effective legal redress in the courts of such jurisdictions, whether in respect of a breach of law or
regulation, or in an ownership dispute, being more difficult to obtain; (ii) a higher degree of discretion
on the part of governmental authorities; (iii) the lack of judicial or administrative guidance on
interpreting applicable rules and regulations; (iv) inconsistencies or conflicts between and within
various laws, regulations, decrees, orders and resolutions; or (v) relative inexperience of the judiciary
and courts in such matters. In certain jurisdictions, the commitment of local business people,
government officials and agencies and the judicial system to abide by legal requirements and negotiated
agreements may be more uncertain, creating particular concerns with respect to the San Leon Group’s
licences and agreements for business. These may be susceptible to revision or cancellation and legal
22
redress may be uncertain or delayed. There can be no assurance that production sharing agreements,
joint ventures, licences, licence applications or other legal arrangements will not be adversely affected
by the actions of government authorities or others and the effectiveness of and enforcement of such
arrangements in these jurisdictions cannot be assured.
Corporate and regulatory formalities
The jurisdictions in which the San Leon Group may obtain interests, conduct operations and the steps
involved in the San Leon Group acquiring its current interests involve or may involve the need to
comply with numerous procedures and formalities. In some cases, failure to follow such formalities or
obtain relevant evidence may call into question the validity of the entity or the actions taken.
Ability to exploit successful discoveries
It may not always be possible for the San Leon Group to participate in the exploitation of successful
discoveries made in areas in which the San Leon Group has an interest. Such exploitation may involve
the need to obtain licences or clearances from the relevant authorities, which may require conditions to
be satisfied and/or the exercise of discretion by such authorities. It may or may not be possible for such
conditions to be satisfied. Furthermore, the decision to proceed to further exploitation may require the
participation of other companies whose interests and objectives may not be the same as those of the
San Leon Group. Such further work may also require the San Leon Group to meet or commit to
financing obligations, which it may not have anticipated or may not be able to commit to due to lack of
funds or inability to raise funds.
Environmental regulation
Environmental and safety legislation (e.g. in relation to plugging and abandonment of wells, discharge
of materials into the environment and otherwise relating to environmental protection) may change in a
manner that may require stricter or additional standards than those now in effect, a heightened degree
of responsibility for companies and their directors and employees and more stringent enforcement of
existing laws and regulations. There may also be unforeseen environmental liabilities resulting from oil
and gas activities, which may be costly to remedy. In particular, the acceptable level of pollution and the
potential clean up costs and obligations and liability for toxic or hazardous substances for which the San
Leon Group may become liable as a result of its activities may be impossible to assess against the
current legal framework and current enforcement practices of the various jurisdictions.
Market risk
In the event of successful development of oil and gas reserves, the marketing of the San Leon Group’s
prospective production of oil and gas from such reserves will be dependent on market fluctuations and
the availability of processing and refining facilities and transportation infrastructure, including access
to ports, shipping facilities, pipelines and pipeline capacity at economic tariff rates over which the
San Leon Group may have limited or no control. Pipelines may be inadequately maintained and subject
to capacity constraints and economic tariff rates may be increased with little or no notice and without
taking into account producer concerns. The right to export oil and gas may depend on obtaining licences
and quotas, the granting of which may be at the discretion of the relevant regulatory authorities. There
may be delays in obtaining such licences and quotas leading to the income receivable by the San Leon
Group being adversely affected, and it is possible that from time to time export licences may be refused.
Reliance on strategic relationships
In conducting its business, the San Leon Group may rely on forming strategic relationships with other
entities in the oil and gas industry, such as joint venture parties and farm-in partners, and also certain
regulatory and governmental departments. While the Directors have no reason to believe otherwise,
there can be no assurance that these relationships will be successfully formed and maintained.
23
Competition
A number of other oil and gas companies operate, and are allowed to bid for, production sharing
agreements in the countries in which the San Leon Group may operate in the future, thereby providing
competition to the San Leon Group. Larger companies, in particular, may have access to greater
resources than the San Leon Group which may give them a competitive advantage.
Dependence on key personnel
The San Leon Group has a small management team and the loss of a key individual or the San Leon
Group’s inability to attract suitably qualified personnel in the future could affect the San Leon Group’s
business. Difficulties may also be experienced in certain jurisdictions in employing and retaining
qualified personnel who are willing to work in such jurisdictions.
Results to date and additional requirement for capital
San Leon is likely to remain cash flow negative for some time and, although the Directors have
confidence in the future revenue earning potential of the San Leon Group, there can be no certainty that
San Leon will achieve or sustain profitability or positive cash flow from its operating activities. The
Directors are satisfied that the working capital available to the San Leon Group will be sufficient for its
present requirements. However, the San Leon Group may need to raise additional capital in the future.
Actual future production, oil and gas prices, revenues, taxes, transportation costs, capital expenditures
and operating expenses and geological success will all be factors which have an impact on the amount
of additional capital required. Any additional equity financing may be dilutive to Shareholders and debt
financing, if available, may involve restrictions on financing and operating activities. If the San Leon
Group is unable to obtain additional financing as and when needed, it will be required to reduce the
scope of its operations or anticipated expansion and will be unable to fulfil its commitments which
could result in them being terminated.
Risks related to taxation
Investors should refer to paragraph 16 of Part VI of this document for a summary of the possible tax
consequences of owning the Ordinary Shares.
Foreign jurisdiction taxation
The operations and activities of the San Leon Group in jurisdictions outside the US, Morocco and The
Netherlands could expose the San Leon Group to income and/or capital taxes in such jurisdictions
which may have a substantial adverse effect on the San Leon Group’s business, financial condition and
prospects. This will depend, in part, on:
•
the nature of the San Leon Group’s income and operations in these jurisdictions (carried on by
employees of the San Leon Group or service providers on behalf of the San Leon Group)
•
the attitude of the tax authorities in these jurisdictions; and
•
the ability of the San Leon Group to claim treaty benefits under any applicable income tax treaties
between jurisdictions other than those in which it carries on operations and activities
Residence of each member of the San Leon Group
The San Leon Group has taken steps to minimize the risk of being treated as being resident in
jurisdictions (other than each member of the San Leon Group’s respective jurisdiction of incorporation)
for tax purposes where such jurisdictions have a residence test based on the place of effective
management and control. However if these steps are not strictly adhered to then profits could be subject
to tax in those other jurisdictions.
24
SECTION B: OIL & GAS MARKET RISKS
Volatility of prices for oil and gas
The demand for, and price of, oil and gas is highly dependent on a variety of factors, including
international supply and demand, the level of consumer demand, weather conditions, the price and
availability of alternative fuels, actions taken by governments and international cartels, and global
economic and political developments. Geographic location and a lack of adequate infrastructure may
also result in any oil or gas produced being sold at a discount to world market prices for oil and gas.
International oil and gas prices have fluctuated widely in recent years and may continue to fluctuate
significantly in the future.
SECTION C: RISKS RELATING TO THE ORDINARY SHARES
Possible volatility of the price of ordinary shares
The market price of the Ordinary Shares could be subject to significant fluctuations due to a change in
sentiment in the market regarding the Ordinary Shares (or securities similar to them) or in response to
various factors and events, including any regulatory changes affecting the San Leon Group’s operations,
variations in the San Leon Group’s operating results and business developments of the San Leon Group
or its competitors.
Stock markets have from time to time experienced significant price and volume fluctuations which have
affected the market prices for securities which may be unrelated to the San Leon Group’s operating
performance or prospects. Furthermore the San Leon Group’s operating results and prospects from time
to time may be below the expectations of market analysts and investors. Any of these events could result
in a decline in the market price of the Ordinary Shares. The trading prices of the Ordinary Shares may
go down as well as up and Shareholders may, therefore, not recover their original investment costs.
Substantial sales of ordinary shares could cause the price of ordinary shares to decline
There can be no assurance, that the Directors or other shareholders will not elect to sell their Ordinary
Shares when they are legally entitled so to do. The market price of Ordinary Shares could decline as a
result of any sales of such Ordinary Shares or as a result of the perception in the market which may
occur as a result of such a sale. If these or any other sales were to occur, the Company may in the future
have difficulty in offering or selling Ordinary Shares at a time or at a price it deems appropriate.
Dividends
The dividend policy of the San Leon Group is dependent upon its financial condition, cash
requirements, future prospects, profits available for distribution and other factors deemed to be relevant
at the time and on the continued health of the markets in which it operates. There can be no guarantee
that San Leon will pay dividends in the foreseeable future.
Tax considerations
Changes in tax laws or subordinate legislation or the practice of any taxation authority could have a
material adverse effect on the San Leon Group.
An investment in the Company may involve complex tax considerations which may differ for each
investor and each investor is advised to consult its own tax advisers. Any tax legislation and its
interpretation and the legal and regulatory regimes which apply in relation to an investment in the
Company may change at any time.
Securities traded on AIM
The Ordinary Shares will be traded on AIM rather than on the Official List. An investment in shares
traded on AIM may carry a higher risk than an investment in shares listed on the Official List. Investors
should be aware that the value of the Ordinary Shares may be volatile and may go down as well as up
and investors may therefore not recover their original investment especially since the market in the
Ordinary Shares on AIM may have limited liquidity.
25
The price at which investors may dispose of their shares in the Company may be influenced by a number
of factors some of which may pertain to the Company and others of which are extraneous. Investors may
realise less than the original amount invested.
Suitability
Investment in the Ordinary Shares may not be suitable for all readers of this document. Readers are
accordingly advised to consult your stockbroker, bank manager, solicitor or accountant or other
independent financial adviser, being (in the case of persons resident in Ireland) an organisation or firm
authorised or exempted pursuant to the Investment Intermediaries Act 1995 of Ireland or the
Stock Exchange Act 1995 of Ireland and (in the case of persons resident in the United Kingdom) an
organisation or firm authorised pursuant to the FSMA who specialises in investments of this nature
before making any investment decision.
Forward looking statements
This document contains forward looking statements, including, without limitation, statements
containing the words “believes”, “anticipates”, “expects” and similar expressions. Such forward looking
statements involve unknown risks, uncertainties and other factors which may cause the actual results,
financial condition, performance or achievements of the San Leon Group, or industry results, to be
materially different from any future results, performance or achievements expressed or implied by such
forward looking statements. Factors that might cause such a difference include, but are not limited to,
those discussed in “Risk Factors”. Given these uncertainties, prospective investors are cautioned not to
place any undue reliance on such forward looking statements. The San Leon Group disclaims any
obligation to update any such forward looking statements in this document to reflect future events
or developments.
Daniel Stewart, the Company’s Nominated Adviser and Broker, considers the Ordinary Shares to
be a “high risk’’ investment according to its categories of investment. As the Directors have
intimated that the Company is unlikely to pay dividends in the foreseeable future, the Ordinary
Shares are in particular not suitable for investors requiring income. The foregoing factors are not
exhaustive and do not purport to be a complete explanation of all the risks and significant
considerations involved in investing in the Company.
26
PART IV
PETROLEUM CONSULTANT’S REPORT
September 12, 2008
The Directors
San Leon Energy Plc
6 Northbrook Road
Dublin 6
Ireland
The Directors
Daniel Stewart & Company Plc
Becket House
36 Old Jewry
London EC2R 8DD
United Kingdom
Ladies and Gentlemen:
In accordance with your request, we have conducted an assessment of the contingent resources for certain
properties located offshore the Netherlands and prospective resources for certain properties located in the United
States and Morocco, as of September 1, 2008, for San Leon Energy Plc and its subsidiaries (collectively referred
to herein as "San Leon"). The subsidiaries consist of San Leon (Netherlands), San Leon (Morocco), and San
Leon (USA). We have estimated contingent resources and cash flow for Amstel Field located in the Q/13a
Production License, offshore the Netherlands; prospective resources for 6 prospects in San Leon's acreage in the
Denver-Julesburg (DJ) Basin located in Cheyenne County, Nebraska, United States; and prospective resources
for 15 leads in the Tarfaya exploration permits located in the Tarfaya-Laayoune Basin, onshore Morocco.
Scoping economics were prepared for a single representative lead in the Tarfaya exploration permits to confirm
economic viability if a discovery is made. In addition, San Leon has an interest in the Zag exclusive
reconnaissance license located in the Zag-Tindouf Basin, onshore southern Morocco. The Zag license is in the
earliest stages of exploration where drilling prospects are yet to be identified; no resources volumes have been
estimated for the Zag license at this time. In this report, we describe the Zag license in terms of petroleum play
concepts and the work programs planned to elevate play concepts to leads and prospects. The estimates of
resources in this report have been prepared in accordance with the definitions and guidelines set forth in the 2007
Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers; definitions
are presented immediately following this letter. Following the definitions is a list of abbreviations used in this
report.
CONTINGENT RESOURCES __________________________________________________________
Contingent resources are those quantities of petroleum that are estimated, as of a given date, to be potentially
recoverable from known accumulations but for which the applied project or projects are not yet considered mature
enough for commercial development because of one or more contingencies. The contingent resources estimates
shown in this report are for certain reservoirs at Amstel Field located offshore the Netherlands and are contingent
upon (1) regulatory approval, (2) confirmation by Energie Beheer Nederland B.V. that it will exercise its 40 percent
equity participation, (3) demonstration of economic viability, (4) commitment of the license partners to develop the
resources, and (5) a development plan being submitted and approved by the appropriate authorities. If these
issues are resolved, some portion of the contingent resources estimated in this report may be reclassified as
reserves. It is anticipated that Amstel Field will be developed during 2008 with production scheduled to begin in
2010. The estimates of contingent resources and cash flow in this report have been prepared using constant
price and cost parameters specified by San Leon, as discussed in subsequent paragraphs of this letter.
27
We estimate the contingent oil resources and cash flow to the San Leon royalty interest in Amstel Field, as of
September 1, 2008, to be:
Category
Low Estimate (1C)
Best Estimate (2C)
High Estimate (3C)
Contingent Oil Resources
Gross
Net
(MBBL)
(MBBL)
04,100.0
08,500.0
16,200.0
24.6
51.0
97.2
Net Contingent Cash Flow (M$)
Discounted
Total
at 10%
1,968.1
4,079.9
7,776.3
1,625.9
3,151.5
5,302.8
The oil resources shown include crude oil only. Oil volumes are expressed in thousands of barrels (MBBL); a
barrel is equivalent to 42 United States gallons. Gross resources in this report are 100 percent of the resources
expected to be produced from the wells. Net resources are the share of resources attributable to San Leon's 0.6
percent royalty interest. Cash flow estimates are expressed in thousands of United States dollars (M$).
The contingent resources shown in this report have been estimated using a combination of deterministic and
probabilistic methods. The probability that the quantities of oil actually recovered will equal or exceed the
estimated amounts is at least 90 percent for the low estimate (1C), at least 50 percent for the best estimate (2C),
and at least 10 percent for the high estimate (3C). The resources included herein have not been adjusted for risk.
Future gross contingent revenue and net contingent cash flow to the San Leon interest are after deductions for
royalties but before consideration of any income taxes. The future net contingent cash flow has been discounted
at an annual rate of 10 percent to indicate the effect of time on the value of money; the discounted contingent
cash flow should not be construed as being the fair market value of the properties.
As requested, this report has been prepared using an oil price specified by San Leon of $80.00 per barrel. The oil
price is held constant throughout the lives of the properties.
Because San Leon owns no working interest in Amstel Field, lease and well operating costs would not be
incurred. However, estimated lease and well operating costs provided by San Leon have been used in the
determination of the economic limits for the properties. These estimated lease and well operating expenses have
been reviewed and found to be reasonable based on our experience with similar properties. As requested, lease
and well operating costs are held constant throughout the lives of the properties.
Capital costs have been included to determine whether workovers, new development wells, and production
equipment requirements are economic. Capital costs used in this report for Amstel Field are also based on
estimates provided by San Leon. These estimated capital costs have been reviewed and found to be reasonable
based on our experience in the region. As requested, capital costs are held constant to the date of expenditure.
PROSPECTIVE RESOURCES _________________________________________________________
The prospective resources included in this report indicate exploration opportunities and development potential in
the event a petroleum discovery is made and should not be construed as reserves or contingent resources.
Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from undiscovered accumulations by application of future development projects. Prospective
28
resources are dependent upon successful exploration for petroleum and are assessed according to their chance
of discovery. Prospective resources estimates in this report are for 6 identified prospects in San Leon's lease
holdings in the DJ Basin in eastern Nebraska and for 15 identified leads in the Tarfaya exploration permits of
southern Morocco. The 2007 PRMS defines a prospect as a project associated with a potential accumulation that
is sufficiently well defined to represent a viable drilling target and a lead as 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. A geologic risk assessment was performed for these properties, as discussed in
subsequent paragraphs of this letter.
We estimate the unrisked and risked prospective resources volumes in the DJ Basin and Tarfaya exploration
permits, as of September 1, 2008, to be:
(1)
Lease or Permit Area/
Category
Prospective Resources(1)
(2)
Gross (100 Percent)
San Leon Participating Interest(2)
Unrisked
Risked
Unrisked
Risked
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
(MMBBL) (BCF) (MMBBL) (BCF) (MMBBL) (BCF) (MMBBL) (BCF)
DJ Basin Lease Area, Nebraska
Low Estimate
Best Estimate
High Estimate
0,001.7
0,003.3
0,006.3
4.5
5.4
6.3
000.3
000.5
001.0
1.5
1.8
2.2
0,001.4
0,002.7
0,005.2
3.7
4.4
5.2
00.2
00.4
00.8
1.2
1.5
1.8
Tarfaya Exploration Permits, Morocco(3)(4)
Low Estimate
Best Estimate
High Estimate
0,133.8
0,711.3
3,878.6
0.0
0.0
0.0
008.5
040.5
195.9
0.0
0.0
0.0
0,036.5
0,192.9
1,048.1
0.0
0.0
0.0
02.3
11.0
52.9
0.0
0.0
0.0
Note: As recommended in the 2007 PRMS, the low, best, and high estimate prospective resources have been aggregated by
arithmetic summation for each lease or permit area.
(1)
(2)
(3)
(4)
The overall probability of success for the 6 identified prospects in the DJ Basin lease area and 15 identified leads in the
Tarfaya exploration permits is summarized in Section 3.1.1 of the Technical Discussion of this report.
San Leon participating interest resources, rather than net resources, have been included in this report; net resources can
only be determined from a full economic assessment, which was not performed because of the indeterminate nature of the
resources and development plans.
Pursuant to the Petroleum Agreement, San Leon's participating interest in the Tarfaya exploration permits is initially 30
percent because of a royalty exemption on the first 300 thousand tons, approximately 1.9 million barrels (MMBBL), of oil.
San Leon's interest becomes 27 percent after production of the exempted oil volume to account for the 10 percent royalty
on oil production.
Pursuant to the Petroleum Agreement, the Office National des Hydrocarbures et des Mines (ONHYM) has a 25 percent
interest, and San Leon has a 22.5 percent interest. ONHYM has the right to maintain its interest of up to 25 percent. If
ONHYM relinquishes all of its 25 percent interest, San Leon may be entitled to an interest of up to 30 percent as a
nonoperating partner. If ONHYM maintains its interest at the maximum 25 percent, San Leon will have a 22.5 percent
equity interest. The participating interest volumes shown in this report for San Leon in relation to the Tarfaya exploration
permits are based on the assumption that ONHYM will relinquish all of its 25 percent interest.
The oil resources shown include crude oil only. Oil volumes are expressed in MMBBL; a barrel is equivalent to 42
United States gallons. Gas volumes are expressed in billions of cubic feet (BCF) at standard temperature and
pressure bases.
29
The prospective resources shown in this report have been estimated using probabilistic methods and are
dependent on a petroleum discovery being made. If a discovery is made, the probability that the quantities of oil
and gas actually recovered will equal or exceed the estimated amounts is at least 90 percent for the low estimate,
at least 50 percent for the best estimate, and at least 10 percent for the high estimate.
We conducted a probabilistic assessment for each lead or prospect to derive the range of unrisked gross (100
percent) in-place and recoverable hydrocarbon volumes. In addition, a geologic risk assessment was conducted
for each lead or prospect. Geologic risking of prospective resources addresses the probability or chance of
success for the discovery of petroleum that can be produced at a measurable rate to the surface; such risk
analysis is conducted independently of probabilistic estimations of petroleum volumes and without regard to the
chance of development. Principal risk elements of the petroleum system include (1) trap and seal characteristics;
(2) reservoir presence and architecture; (3) source rock capacity, quality, and maturity; and (4) timing, migration,
and preservation of petroleum in relation to trap and seal formation. Lead or prospect risk assessment is a highly
subjective process dependent upon the experience and judgment of the evaluators and is subject to revisions with
further data acquisition or interpretation. Included in this report is a discussion of the primary risk elements for
each lead or prospect. Unrisked prospective resources are estimated ranges of potential in-place and
recoverable oil and gas volumes assuming a petroleum discovery is made.
Each lead or prospect was evaluated to determine probabilistic ranges of in-place and recoverable petroleum and
was risked as an independent entity without dependency between potential prospect drilling outcomes. If
petroleum discoveries are made, smaller-volume leads or prospects may not be commercial to independently
develop, although they may become candidates for satellite developments and tie-backs to existing infrastructure
at some future date. The development infrastructure and data obtained from early discoveries will alter both lead
or prospect risk and future economics of subsequent discoveries and developments.
It should be understood that the prospective resources discussed and shown herein are those undiscovered
resources estimated beyond reserves or contingent resources where geological and geophysical data suggest the
potential for discovery of petroleum but where the level of proof is insufficient for classification as reserves or
contingent resources. The unrisked prospective resources are those volumes that could reasonably be expected
to be recovered in the event of the successful exploration and development of these leads or prospects.
SUMMARY ________________________________________________________________________
The scope of our assessment is outlined below.
Contingent resources - Amstel Field, offshore the Netherlands
N
Evaluated low, best, and high estimate contingent oil resources and cash flow to San Leon's 0.6
percent royalty interest in Amstel Field using a combination of deterministic and probabilistic
methods.
Prospective resources - exploration and production leases, DJ Basin, Cheyenne County, Nebraska, United States
N
Assessed low, best, and high estimate unrisked prospective resources to San Leon's 100 percent
working interest and 82 percent revenue interest in 6 identified prospects using a combination of
deterministic and probabilistic methods.
N
Conducted geologic risk assessment for each identified prospect.
30
Prospective resources - Tarfaya exploration permits, onshore Morocco
N
Assessed low, best, and high estimate unrisked prospective resources to San Leon's 30 percent
nonoperating working interest, assuming ONHYM relinquishes all of its 25 percent interest, for 15
identified leads using a combination of deterministic and probabilistic methods.
N
Prepared a scoping economic analysis for a representative development of a single lead.
N
Conducted geologic risk assessment for each identified lead.
Play concept description - Zag exclusive reconnaissance license, onshore Morocco
N
Prepared a description of basin petroleum system and play types for the San Leon-operated 50
percent participating interest Zag exclusive reconnaissance license.
As shown in the Table of Contents, the Technical Discussion section of this report includes an overview of the
lease, permit, and license areas, a summary of the lease, permit, and license terms, a review of the data available
for this assessment, and a discussion of the technical approach used in our assessments. Included in the Figures
section are pertinent maps, seismic lines, tables, and exhibits.
For the purposes of this report, we did not perform any field inspection of the properties. We have not
investigated possible environmental liability related to the properties; therefore, our estimates do not include any
costs due to such possible liability. Our estimates of cash flow do not include any salvage value for the lease and
well equipment but do include San Leon's estimates of the costs to abandon the wells and production facilities for
Amstel Field. Abandonment costs are included as capital costs.
The resources shown in this report are estimates only and should not be construed as exact quantities. The
resources may or may not be recovered; if contingent resources are recovered, the cash flows therefrom and the
costs related thereto could be more or less than the estimated amounts. The resources are for undeveloped
locations. Therefore, these resources are based on estimates of reservoir volumes and recovery efficiencies
along with analogy to properties with similar geologic and reservoir characteristics; it may be necessary to revise
these estimates as performance data become available. Because of governmental policies and uncertainties of
supply and demand, the sales rates, prices received for the resources, and costs incurred in recovering such
resources may vary from assumptions made while preparing this report. Also, estimates of resources may
increase or decrease as a result of future operations.
In evaluating the information at our disposal concerning this report, we have excluded from our consideration all
matters as to which the controlling interpretation may be political, socioeconomic, legal, or accounting, rather than
engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the
interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed
professional judgment. We hereby assert that there has been no material change in any of the data used in this
evaluation that would cause us to materially alter the estimates set forth herein.
Netherland, Sewell & Associates, Inc. was established in 1961 and has offices in Dallas and Houston, Texas.
Our company has conducted technical reserves, resources, and deliverability studies for financial institutions,
private and government companies, and government agencies throughout the world. Our staff and associates
work as a team to provide the integrated expertise required for complex field studies and reserves and resources
evaluations.
31
32
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS
Excerpted from the Petroleum Resources Management System Approved by
the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
This document contains information excerpted from definitions and guidelines prepared by the Oil and Gas Reserves
Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council
(WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers
(SPEE).
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.
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 this document 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.
1.0 Basic Principles and Definitions
The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent
degree of uncertainty. These quantities are associated with development projects at various stages of design and
implementation. Use of a consistent classification system enhances comparisons between projects, groups of projects, and
total company portfolios according to forecast production profiles and recoveries. Such a system must consider both technical
and commercial factors that impact the project's economic feasibility, its productive life, and its related cash flows.
1.1 Petroleum Resources Classification Framework
COMMERCIAL
DISCOVERED PIIP
1P
SUB-COMMERCIAL
2P
Probable
3P
Possible
CONTINGENT
RESOURCES
1C
2C
3C
UNRECOVERABLE
PROSPECTIVE
RESOURCES
Low
Estimate
Best
Estimate
Increasing Chance of Commerciality
Figure 1-1 is a graphical representation of the SPE/WPC/
AAPG/SPEE resources classification system. The system
defines the major recoverable resources classes: Production,
Reserves, Contingent Resources, and Prospective
Resources, as well as Unrecoverable petroleum.
RESERVES
Proved
UNDISCOVERED PIIP
The term "resources" as used herein is intended to
encompass all quantities of petroleum naturally occurring on
or within the Earth's crust, discovered and undiscovered
(recoverable and unrecoverable), plus those quantities
already produced. Further, it includes all types of petroleum
whether
currently
considered
"conventional"
or
"unconventional."
PRODUCTION
TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP)
Petroleum is defined as a naturally occurring mixture
consisting of hydrocarbons in the gaseous, liquid, or solid
phase. Petroleum may also contain non-hydrocarbons,
common examples of which are carbon dioxide, nitrogen,
hydrogen sulfide and sulfur. In rare cases, non-hydrocarbon
content could be greater than 50%.
High
Estimate
UNRECOVERABLE
Range of Uncertainty
The "Range of Uncertainty" reflects a range of estimated
quantities potentially recoverable from an accumulation by a
project, while the vertical axis represents the "Chance of
Not to scale
Figure 1-1: Resources Classification Framework.
Definitions - Page 1 of 10
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Excerpted from the Petroleum Resources Management System Approved by
the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
Commerciality", that is, the chance that the project that will be developed and reach commercial producing status. The
following definitions apply to the major subdivisions within the resources classification:
TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally
occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in
known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered
(equivalent to "total resources").
DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to
be contained in known accumulations prior to production.
PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all
recoverable resources are estimated and production is measured in terms of the sales product specifications, raw
production (sales plus non-sales) quantities are also measured and required to support engineering analyses based
on reservoir voidage (see Production Measurement, section 3.2).
Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion
of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated
recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below.
RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of
development projects to known accumulations from a given date forward under defined conditions. Reserves must
further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation
date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of
certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by
development and production status.
CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for
commercial development due to one or more contingencies. Contingent Resources may include, for example,
projects for which there are currently no viable markets, or where commercial recovery is dependent on technology
under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality.
Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates
and may be subclassified based on project maturity and/or characterized by their economic status.
UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be
contained within accumulations yet to be discovered.
PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from undiscovered accumulations by application of future development projects. Prospective Resources
have both an associated chance of discovery and a chance of development. Prospective Resources are further
subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery
and development and may be sub-classified based on project maturity.
UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is
estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may
become recoverable in the future as commercial circumstances change or technological developments occur; the
remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of
fluids and reservoir rocks.
Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group
of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be
potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of
recoverable resources).
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PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS
Excerpted from the Petroleum Resources Management System Approved by
the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
1.2 Project-Based Resources Evaluations
The resources evaluation process consists of identifying a recovery project, or projects, associated with a petroleum
accumulation(s), estimating the quantities of Petroleum Initially-in-Place, estimating that portion of those in-place quantities
that can be recovered by each project, and classifying the project(s) based on its maturity status or chance of commerciality.
This concept of a project-based classification system is further clarified by examining the primary data sources contributing to
an evaluation of net recoverable resources (see Figure 1-2) that may be described as follows:
RESERVOIR
(in-place volumes)
Net
Recoverable
Resources
PROJECT
(production/cash flow)
Entitlement
PROPERTY
(ownership/contract terms)
Figure 1-2: Resources Evaluation Data Sources.
N
The Reservoir (accumulation): Key attributes include the types and quantities of Petroleum Initially-in-Place and the fluid
and rock properties that affect petroleum recovery.
N
The Project: Each project applied to a specific reservoir development generates a unique production and cash flow
schedule. The time integration of these schedules taken to the project's technical, economic, or contractual limit defines
the estimated recoverable resources and associated future net cash flow projections for each project. The ratio of EUR to
Total Initially-in-Place quantities defines the ultimate recovery efficiency for the development project(s). A project may be
defined at various levels and stages of maturity; it may include one or many wells and associated production and
processing facilities. One project may develop many reservoirs, or many projects may be applied to one reservoir.
N
The Property (lease or license area): Each property may have unique associated contractual rights and obligations
including the fiscal terms. Such information allows definition of each participant's share of produced quantities
(entitlement) and share of investments, expenses, and revenues for each recovery project and the reservoir to which it is
applied. One property may encompass many reservoirs, or one reservoir may span several different properties. A
property may contain both discovered and undiscovered accumulations.
In context of this data relationship, "project" is the primary element considered in this resources classification, and net
recoverable resources are the incremental quantities derived from each project. Project represents the link between the
petroleum accumulation and the decision-making process. A project may, for example, constitute the development of a single
reservoir or field, or an incremental development for a producing field, or the integrated development of several fields and
associated facilities with a common ownership. In general, an individual project will represent the level at which a decision is
made whether or not to proceed (i.e., spend more money) and there should be an associated range of estimated recoverable
quantities for that project.
An accumulation or potential accumulation of petroleum may be subject to several separate and distinct projects that are at
different stages of exploration or development. Thus, an accumulation may have recoverable quantities in several resource
classes simultaneously.
In order to assign recoverable resources of any class, a development plan needs to be defined consisting of one or more
projects. Even for Prospective Resources, the estimates of recoverable quantities must be stated in terms of the sales
products derived from a development program assuming successful discovery and commercial development. Given the major
uncertainties involved at this early stage, the development program will not be of the detail expected in later stages of maturity.
In most cases, recovery efficiency may be largely based on analogous projects. In-place quantities for which a feasible project
cannot be defined using current, or reasonably forecast improvements in, technology are classified as Unrecoverable.
Not all technically feasible development plans will be commercial. The commercial viability of a development project is
dependent on a forecast of the conditions that will exist during the time period encompassed by the project's activities (see
Definitions - Page 3 of 10
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PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS
Excerpted from the Petroleum Resources Management System Approved by
the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
Commercial Evaluations, section 3.1). "Conditions" include technological, economic, legal, environmental, social, and
governmental factors. While economic factors can be summarized as forecast costs and product prices, the underlying
influences include, but are not limited to, market conditions, transportation and processing infrastructure, fiscal terms, and
taxes.
The resource quantities being estimated are those volumes producible from a project as measured according to delivery
specifications at the point of sale or custody transfer (see Reference Point, section 3.2.1). The cumulative production from the
evaluation date forward to cessation of production is the remaining recoverable quantity. The sum of the associated annual
net cash flows yields the estimated future net revenue. When the cash flows are discounted according to a defined discount
rate and time period, the summation of the discounted cash flows is termed net present value (NPV) of the project (see
Evaluation and Reporting Guidelines, section 3.0).
The supporting data, analytical processes, and assumptions used in an evaluation should be documented in sufficient detail to
allow an independent evaluator or auditor to clearly understand the basis for estimation and categorization of recoverable
quantities and their classification.
2.0 Classification and Categorization Guidelines
2.1 Resources Classification
The basic classification requires establishment of criteria for a petroleum discovery and thereafter the distinction between
commercial and sub-commercial projects in known accumulations (and hence between Reserves and Contingent Resources).
2.1.1 Determination of Discovery Status
A discovery is one petroleum accumulation, or several petroleum accumulations collectively, for which one or several
exploratory wells have established through testing, sampling, and/or logging the existence of a significant quantity of
potentially moveable hydrocarbons.
In this context, "significant" implies that there is evidence of a sufficient quantity of petroleum to justify estimating the in-place
volume demonstrated by the well(s) and for evaluating the potential for economic recovery. Estimated recoverable quantities
within such a discovered (known) accumulation(s) shall initially be classified as Contingent Resources pending definition of
projects with sufficient chance of commercial development to reclassify all, or a portion, as Reserves. Where in-place
hydrocarbons are identified but are not considered currently recoverable, such quantities may be classified as Discovered
Unrecoverable, if considered appropriate for resource management purposes; a portion of these quantities may become
recoverable resources in the future as commercial circumstances change or technological developments occur.
2.1.2 Determination of Commerciality
Discovered recoverable volumes (Contingent Resources) may be considered commercially producible, and thus Reserves, if
the entity claiming commerciality has demonstrated firm intention to proceed with development and such intention is based
upon all of the following criteria:
N
N
N
N
N
Evidence to support a reasonable timetable for development.
A reasonable assessment of the future economics of such development projects meeting defined investment and operating
criteria.
A reasonable expectation that there will be a market for all or at least the expected sales quantities of production required
to justify development.
Evidence that the necessary production and transportation facilities are available or can be made available.
Evidence that legal, contractual, environmental and other social and economic concerns will allow for the actual
implementation of the recovery project being evaluated.
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.
Definitions - Page 4 of 10
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PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS
Excerpted from the Petroleum Resources Management System Approved by
the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
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.
2.2 Resources Categorization
The horizontal axis in the Resources Classification (Figure 1.1) defines the range of uncertainty in estimates of the quantities
of recoverable, or potentially recoverable, petroleum associated with a project. These estimates include both technical and
commercial uncertainty components as follows:
N
N
N
The total petroleum remaining within the accumulation (in-place resources).
That portion of the in-place petroleum that can be recovered by applying a defined development project or projects.
Variations in the commercial conditions that may impact the quantities recovered and sold (e.g., market availability,
contractual changes).
Where commercial uncertainties are such that there is significant risk that the complete project (as initially defined) will not
proceed, it is advised to create a separate project classified as Contingent Resources with an appropriate chance of
commerciality.
2.2.1 Range of Uncertainty
The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by either deterministic
scenarios or by a probability distribution (see Deterministic and Probabilistic Methods, section 4.2).
When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided
such that:
N
N
N
There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low
estimate.
There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best
estimate.
There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high
estimate.
When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such
estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the
deterministic incremental (risk-based) approach, quantities at each level of uncertainty are estimated discretely and separately
(see Category Definitions and Guidelines, section 2.2.2).
These same approaches to describing uncertainty may be applied to Reserves, Contingent Resources, and Prospective
Resources. While there may be significant risk that sub-commercial and undiscovered accumulations will not achieve
commercial production, it is useful to consider the range of potentially recoverable quantities independently of such a risk or
consideration of the resource class to which the quantities will be assigned.
2.2.2 Category Definitions and Guidelines
Evaluators may assess recoverable quantities and categorize results by uncertainty using the deterministic incremental (riskbased) approach, the deterministic scenario (cumulative) approach, or probabilistic methods (see "2001 Supplemental
Guidelines," Chapter 2.5). In many cases, a combination of approaches is used.
Use of consistent terminology (Figure 1.1) promotes clarity in communication of evaluation results. For Reserves, the general
cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associated incremental quantities are
termed Proved, Probable and Possible. Reserves are a subset of, and must be viewed within context of, the complete
resources classification system. While the categorization criteria are proposed specifically for Reserves, in most cases, they
can be equally applied to Contingent and Prospective Resources conditional upon their satisfying the criteria for discovery
and/or development.
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PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS
Excerpted from the Petroleum Resources Management System Approved by
the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3C respectively. For
Prospective Resources, the general cumulative terms low/best/high estimates still apply. No specific terms are defined for
incremental quantities within Contingent and Prospective Resources.
Without new technical information, there should be no change in the distribution of technically recoverable volumes and their
categorization boundaries when conditions are satisfied sufficiently to reclassify a project from Contingent Resources to
Reserves. All evaluations require application of a consistent set of forecast conditions, including assumed future costs and
prices, for both classification of projects and categorization of estimated quantities recovered by each project (see Commercial
Evaluations, section 3.1).
Based on additional data and updated interpretations that indicate increased certainty, portions of Possible and Probable
Reserves may be re-categorized as Probable and Proved Reserves.
Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it is required to
report a single representative result, the "best estimate" is considered the most realistic assessment of recoverable quantities.
It is generally considered to represent the sum of Proved and Probable estimates (2P) when using the deterministic scenario
or the probabilistic assessment methods. It should be noted that under the deterministic incremental (risk-based) approach,
discrete estimates are made for each category, and they should not be aggregated without due consideration of their
associated risk (see "2001 Supplemental Guidelines," Chapter 2.5).
Table 1: Recoverable Resources Classes and Sub-Classes
Class/Sub-Class
Reserves
Definition
Guidelines
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, marketrelated 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.
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PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS
Excerpted from the Petroleum Resources Management System Approved by
the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
Class/Sub-Class
Approved for
Development
Definition
All necessary approvals have been
obtained, capital funds have been
committed, and implementation of
the development project is under
way.
Guidelines
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.
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.
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PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS
Excerpted from the Petroleum Resources Management System Approved by
the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
Class/Sub-Class
Development Not
Viable
Definition
Guidelines
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.
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.
Table 2: Reserves Status Definitions and Guidelines
Status
Definition
Guidelines
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 NonProducing 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 recompletion 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.
Definitions - Page 8 of 10
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PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS
Excerpted from the Petroleum Resources Management System Approved by
the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
Status
Undeveloped
Reserves
Definition
Undeveloped Reserves are
quantities expected to be
recovered through future
investments:
Guidelines
(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)
recomplete an existing well or (b) install production or transportation
facilities for primary or improved recovery projects.
Table 3: Reserves Category Definitions and Guidelines
Category
Definition
Guidelines
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:
N The locations are in undrilled areas of the reservoir that can be judged
with reasonable certainty to be commercially productive.
N 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.
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Category
Possible
Reserves
Definition
Guidelines
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 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.
The 2007 Petroleum Resources Management System can be viewed in its entirety at
http://www.spe.org/spe-app/spe/industry/reserves/prms.htm.
Definitions - Page 10 of 10
42
ABBREVIATIONS
1C
2C
3C
BCF
Bo
BOPD
BP
CIT
DJ
EBN
FDP
FRL
GRV
IOG
km
km2
MBBL
MCF
md
MMBBL
MMBTU
MMCF
MMCFD
NRV
NTG
OGIP
ONHYM
OOIP
OWC
Pg
PRMS
RB/STB
San Leon
Sh
SMT
SPS
TAQA
TCF
TOC
US$
USMM$
low estimate contingent resources
best estimate contingent resources
high estimate contingent resources
billions of cubic feet
oil formation volume factor
barrels of oil per day
British Petroleum
Corporate Income Tax
Denver-Julesburg
Energie Beheer Nederland B.V.
Field Development Plan
Fugro Robertson Limited
gross rock volume
Island Oil & Gas Plc
kilometers
square kilometers
thousands of barrels
thousands of cubic feet
millidarcies
millions of barrels
millions of British thermal units
millions of cubic feet
millions of cubic feet per day
net rock volume
net-to-gross ratio
original gas-in-place
Office National des Hydrocarbures et des Mines
original oil-in-place
oil-water contact
probability of geologic success
Petroleum Resources Management System
reservoir barrels per stock tank barrel
San Leon Energy Plc and its subsidiaries
hydrocarbon saturation
Seismic Micro-Technology, Inc.
State Profit Share
Abu Dhabi National Energy Company
trillions of cubic feet
total organic carbon
United States dollars
millions of United States dollars
43
TABLE OF CONTENTS
Page
Number
TECHNICAL DISCUSSION
1.0 Overview
1
2.0 Overview of Lease, Permit, and License Areas
2
2.1 Amstel Field, Q/13a Production License, Offshore the Netherlands
3
2.2 DJ Basin, Cheyenne County, Nebraska, United States
4
2.3 Tarfaya Exploration Permits, Morocco
4
2.4 Zag Exclusive Reconnaissance License, Morocco
5
3.0 Technical Procedures
6
3.1 Geologic Risk Assessment for Prospective Resources
6
3.1.1 Summary of Prospect and Lead Geologic Risk
7
3.2 Economic Considerations
7
4.0 Contingent Resources Assessment
8
4.1 Amstel Field, Q/13a Production License, Offshore the Netherlands
8
4.1.1 Basic Data
8
4.1.2 Summary
8
4.1.3 Data Sources
8
4.1.3.1 Well Data
8
4.1.3.2 Seismic Data
9
4.1.4 Contingent Oil Resources Estimates
9
4.1.5 Production Rates
10
4.1.6 Operating Expenses and Capital Requirements
10
4.1.7 Development Scheduling
10
4.1.8 Economics
11
5.0 Prospective Resources Assessments
11
5.1 DJ Basin, Cheyenne County, Nebraska, United States
11
5.1.1 Basic Data
11
5.1.2 Summary
11
5.1.2.1 D Sand
11
5.1.2.2 Niobrara Chalk
12
5.1.2.3 Lyons Sand
12
5.1.3 Data Sources
12
44
TABLE OF CONTENTS
Page
Number
TECHNICAL DISCUSSION (Continued)
5.0 Prospective Resources Assessments (Continued)
5.1 DJ Basin, Cheyenne County, Nebraska, United States (Continued)
5.1.4 Prospective Resources Estimates
12
5.1.4.1 Parameters
13
5.1.4.2 Probabilistic Estimates of Unrisked In-Place
and Recoverable Volumes
14
5.1.4.3 Uncertainty/Risk Analysis
14
5.2 Tarfaya Exploration Permits, Tarfaya-Laayoune Basin, Morocco
15
5.2.1 Basic Data
15
5.2.2 Summary
15
5.2.3 Data Sources
16
5.2.3.1 Seismic Data
16
5.2.3.1.1 Depth Conversion
16
5.2.3.2 Well Data
17
5.2.3.3 On-Trend Exploration
17
5.2.3.3.1 Cap Juby Field
17
5.2.4 Tectonic History
18
5.2.5 Hydrocarbon Source Rocks
19
5.2.6 Reservoir and Seal
20
5.2.6.1 Jurassic Reservoir and Seal
20
5.2.6.2 Triassic Reservoir and Seal
21
5.2.7 Leads
22
5.2.7.1 Jurassic Daora, Jurassic Daora North, and
Triassic Daora Leads
23
5.2.7.2 Jurassic J, Triassic J North, and Triassic J South Leads
23
5.2.7.3 Jurassic and Triassic Puerto Cansado Leads
23
5.2.7.4 Jurassic C Lead
23
5.2.7.5 Jurassic F Lead
24
5.2.7.6 Jurassic G Lead
24
5.2.7.7 Triassic K Lead
24
5.2.7.8 Jurassic B Lead
24
45
TABLE OF CONTENTS
Page
Number
TECHNICAL DISCUSSION (Continued)
5.0 Prospective Resources Assessments (Continued)
5.2 Tarfaya Exploration Permits, Tarfaya -Laayoune Basin, Morocco (Continued)
5.2.7 Leads (Continued)
5.2.7.9 Jurassic D Lead
24
5.2.7.10 Jurassic I Lead
24
5.2.8 Prospective Resources Estimates
24
5.2.8.1 Parameters
24
5.2.8.2 Probabilistic Estimates of Unrisked In-Place
and Recoverable Volumes
25
5.2.8.3 Uncertainty/Risk Analysis
26
5.2.9 Representative Scoping Economics for Exploration Success Case
27
5.2.9.1 Well Performance
27
5.2.9.2 Operating Expenses and Capital Requirements
27
5.2.9.3 Development Scheduling
28
5.2.9.4 Economics
28
5.3 Zag Exclusive Reconnaissance License, Zag-Tindouf Basin, Morocco
29
5.3.1 Summary
29
5.3.2 Data Sources
29
5.3.2.1 Well Data
29
5.3.2.2 Algeria - Tindouf Basin Exploration
30
5.3.2.3 Algeria - Reggane Basin Exploration and Recent Activity
30
5.3.3 Zag-Tindouf Basin Petroleum System
31
5.3.4 Tectonic History
31
5.3.5 Hydrocarbon Source Rocks
32
5.3.6 Reservoir and Seal
32
5.3.7 Play Types
33
6.0 Conclusions
33
46
TABLE OF CONTENTS
Figure
Number
FIGURES
Location Maps
Amstel Field
1
DJ Basin Lease Area
2
Tarfaya Exploration Permits and Zag Exclusive Reconnaissance License
3
Depth Structure - Top Amstel (Rijswijk) Sandstone, Amstel Field
4
Stratigraphic Column - West Netherlands Basin Area
5
Type Log - Q/13-8 Well, Amstel Field
6
Depth Structure with Amplitude - Top Amstel (Rijswijk) Sandstone, Amstel Field
7
Time-Domain Seismic Line 1475 - Amstel Field
8
Summary Projections of Resources and Cash Flow - Amstel Field
Low Estimate (1C) Contingent Resources
9
Best Estimate (2C) Contingent Resources
10
High Estimate (3C) Contingent Resources
11
Graphs of Projected Oil Production for a Representative Development Well
1C Type Well
12
2C Type Well
13
3C Type Well
14
Stratigraphic Column - DJ Basin
15
Depth Structure - Top D Sand, DJ Basin Lease Area
16
Time-Domain Seismic Line 190 - DJ Basin
17
DJ Basin Lease Area
Seismic Amplitude Anomaly - Niobrara
18
Lyons Sand Isopach
19
Tarfaya Exploration Permits
2-D Seismic Coverage
20
Depth Structure - Near Top Jurassic
21
Regional Average Velocity to Near Top Jurassic
22
Isochron - Near Top Jurassic to Near Top Triassic
23
Depth Structure - Near Top Triassic
24
Well Locations - Tarfaya-Laayoune Basin, Morocco
25
On-Trend Discoveries - Onshore and Offshore Morocco
26
47
TABLE OF CONTENTS
Figure
Number
FIGURES (Continued)
Cap Juby Field Play Types - Offshore Morocco
27
Composite Stratigraphic and Lithologic Column - Tarfaya-Laayoune
and Zag-Tindouf Basins, Morocco
28
Representative Cross Section - Tarfaya-Laayoune Basin, Morocco
29
Jurassic Depocenter - Tarfaya-Laayoune Basin, Morocco
30
Time-Domain Seismic Lines
Dip Line 88TA13 - Northern Regional Line
31
Dip Line 88LA07 - Southern Regional Line
32
Dip Line 88LA03 - Daora Lead
33
Dip Line 88LA01 - Daora North Lead
34
Strike Line 87LA02 - Daora, Daora North, and I Leads
35
Gravity and Magnetic Data with Daora Triassic Lead
36
Time-Domain Seismic Lines
Dip Line 88TA17-1 - J, J North, and J South Leads
37
Dip Line 87TA03W - Puerto Cansado Lead
38
Dip Line 88LA13 - C Lead
39
Dip Line 88LA05 - F and G Leads
40
Strike Line 88LA10 - G Lead
41
Dip Line 88LA07 - K Lead
42
Strike Line 88LA12 - B Lead
43
Dip Line 87TA05W2 - D Lead
44
J North Lead - Triassic
Graph of Projected Oil Production - Type Well
45
Summary Projection of Resources and Cash Flow
46
Representative Cross Section - Zag-Tindouf Basin
REFERENCES
48
47
TECHNICAL DISCUSSION
49
TECHNICAL DISCUSSION
CONTINGENT RESOURCES LOCATED OFFSHORE THE NETHERLANDS AND
PROSPECTIVE RESOURCES LOCATED IN THE UNITED STATES AND MOROCCO
1.0
OVERVIEW __________________________________________________________________
In accordance with your request, we have conducted an assessment of the contingent resources for
certain properties located offshore the Netherlands and prospective resources for certain properties
located in the United States and Morocco, as of September 1, 2008, for San Leon Energy Plc and its
subsidiaries (collectively referred to herein as "San Leon"). The subsidiaries consist of San Leon
(Netherlands), San Leon (Morocco), and San Leon (USA). We have estimated contingent resources and
cash flow for Amstel Field located in the Q/13a Production License, offshore the Netherlands; prospective
resources for 6 prospects in San Leon's acreage in the Denver-Julesburg (DJ) Basin located in Cheyenne
County, Nebraska, United States; and prospective resources for 15 leads in the Tarfaya exploration
permits located in the Tarfaya-Laayoune Basin, onshore Morocco. In addition, San Leon has an interest
in the Zag exclusive reconnaissance license located in the Zag-Tindouf Basin, onshore southern
Morocco. The Zag license is in the earliest stages of exploration where drilling prospects are yet to be
identified; no resources volumes have been estimated for the Zag license at this time. In this report, we
describe the Zag license in terms of petroleum play concepts and the work programs planned to elevate
play concepts to leads and prospects. Lease, permit, and license terms are further described in Section
2.0 of this report.
The estimates of resources presented in this report have been prepared in accordance with
internationally recognized standards, as stipulated by the London Stock Exchange's "Guidance Note for
Mining, Oil and Gas Companies" dated March 2006. We have prepared our estimates of contingent and
prospective resources in accordance with the definitions and guidelines set forth in the 2007 Petroleum
Resources Management System (PRMS) approved by the Society of Petroleum Engineers. Contingent
and prospective resources shown in this report should not be construed as reserves.
Contingent resources are those quantities of petroleum that are estimated, as of a given date, to be
potentially recoverable from known accumulations but for which the applied project or projects are not yet
considered mature enough for commercial development because of one or more contingencies.
Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from undiscovered accumulations by application of future development projects. Prospective
resources are subdivided in accordance with the level of certainty associated with recoverable estimates
assuming their discovery and development and are subclassified based on project maturity. Of the
entities for which prospective resources have been estimated in this report, those in the DJ Basin have
been subclassified as prospects, and those in the Tarfaya exploration permits have been subclassified as
leads. The 2007 PRMS defines a prospect as a project associated with a potential accumulation that is
sufficiently well defined to represent a viable drilling target and a lead as 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. The Zag exclusive reconnaissance license, for which
no prospective resources volumes have been estimated at this time, is described herein under the
subclassification of play types.
The contingent and prospective resources shown in this report have been estimated using a combination
of deterministic and probabilistic methods. The probability that the quantities of oil and gas actually
recovered will equal or exceed the estimated amounts is at least 90 percent for the low estimate, at least
50 percent for the best estimate, and at least 10 percent for the high estimate. Contingent resources are
Page 1
50
categorized as 1C for the low estimate, 2C for the best estimate, and 3C for the high estimate.
Prospective resources are subclassified as plays, leads, or prospects; such subclassification reflects
increasing project maturity. Prospective resources associated with leads and prospects are categorized
as low, best, and high estimates. As recommended in the 2007 PRMS, the prospective resources have
been aggregated by arithmetic summation for each lease area or permit area.
Prospective resources are dependent upon successful exploration for petroleum and are assessed
according to their chance of discovery and, assuming a discovery, are the estimated quantities, as of a
given date, that would be recoverable under appropriate development projects. Unrisked prospective
resources are estimated ranges of in-place and recoverable oil and gas volumes assuming a petroleum
discovery is made. Geologic risking of prospective resources addresses the probability or chance of
success for the discovery of petroleum that can be produced at a measurable rate to the surface; such
risk analysis is conducted independently of probabilistic estimates of petroleum volumes and without
regard to the chance of development. Principal risk elements of the petroleum system include (1) trap
and seal characteristics; (2) reservoir presence and architecture; (3) source rock capacity, quality, and
maturity; and (4) timing, migration, and preservation of hydrocarbons in relation to trap and seal
formation.
San Leon has not finalized any development plans at this time; therefore, estimates of recoverable
hydrocarbon volumes are based on our current understanding of potential development concepts. Since
the ultimate hydrocarbon recovery is dependent on the development and operational plans, any revision
in the development concept may affect the estimates of recoverable hydrocarbon volumes.
Scoping economics were prepared for a single representative lead in the Tarfaya exploration permits to
confirm economic viability if a discovery is made. The scoping economics are based on the assumption
that, in the event of a successful discovery, the unrisked best estimate prospective resources volumes
are appropriate for preliminary development estimates. Our economic analysis of a typical lead
development included drilling costs, completion and tie-in costs, and operating costs provided by San
Leon. We did not evaluate or estimate costs associated with seismic data acquisition nor were there
environmental or political considerations. Royalties and production taxes were provided by San Leon for
the purposes of our evaluation.
We have reviewed the drilling history, test and production data, regional geology, various reports, and
interpretive data supplied by San Leon for each of the lease, permit, and license areas. We conducted
independent analysis of well logs and seismic data to define field and prospective areas and to assess
variability in the reservoir parameters of net reservoir thickness, effective porosity, and hydrocarbon
saturation (Sh). Original oil-in-place (OOIP), contingent oil resources volumes, and prospective oil and
gas resources volumes were estimated using a spreadsheet-based Monte Carlo simulation model. The
spreadsheet model is based on a range of probability distributions of the reservoir variables combined
with probability distributions of structural or stratigraphic closure areas and recovery factors used as input
parameters to the Monte Carlo simulation.
2.0
OVERVIEW OF LEASE, PERMIT, AND LICENSE AREAS _____________________________
The combined lease, permit, and license areas described herein cover 35,297 square kilometers (km2),
as shown on Figures 1 through 3. The interests described in the following table are based on the
assumption that all events, acquisitions, work programs, etc. envisaged and described in detail in the
Admission Document proceed as planned.
Page 2
51
Area
Area
2
(km )
Amstel Field,
Q/13a Production
License, Offshore
the Netherlands
Island Oil &
Gas Plc (IOG)
0.6 percent
royalty
Contingent
Production license is
retained for duration of
oil production
00,030
DJ Basin, Cheyenne
County, Nebraska,
United States
San Leon
(USA)
100 percent
working and
82 percent
(1)
revenue
Exploration
Leases are valid for 18
months; pending
discovery, leases are
held by production
00,026
Tarfaya Exploration
Permits, Morocco
IOG
30 percent
(2)(3)
working
Exploration
Phase I - 07/2010
Phase II - 07/2013
Phase III - 01/2016
13,434
Zag Exclusive
Reconnaissance
License, Morocco
San Leon
(Morocco)
50 percent
Exploration
Exclusive
reconnaissance license
extension - 12/2008
21,807
(1)
(2)
(3)
2.1
Operator
San Leon Lease and License Holdings
Participating
Interest
Status
Expiration Date
Comments
Production anticipated
to commence during
2010
James Mitchell, a consultant to San Leon, has a 4.5 percent overriding royalty interest, and San Leon has agreed to provide a 1
percent royalty interest to Western Nebraska Land Services Inc., a company that has provided land services to San Leon. This
leaves San Leon with an 82 percent revenue interest.
Pursuant to the Petroleum Agreement, San Leon's participating interest in the Tarfaya exploration permits is initially 30 percent
because of a royalty exemption on the first 300 thousand tons, approximately 1.9 million barrels (MMBBL), of oil. San Leon's
interest becomes 27 percent after production of the exempted oil volume to account for the 10 percent royalty on oil production.
Pursuant to the Petroleum Agreement, the Office National des Hydrocarbures et des Mines (ONHYM) has a 25 percent interest,
and San Leon has a 22.5 percent interest. ONHYM has the right to maintain its interest of up to 25 percent. If ONHYM
relinquishes all of its 25 percent interest, San Leon may be entitled to an interest of up to 30 percent as a nonoperating partner. If
ONHYM maintains its interest at the maximum 25 percent, San Leon will have a 22.5 percent equity interest. The participating
interest volumes shown in this report for San Leon in relation to the Tarfaya exploration permits are based on the assumption that
ONHYM will relinquish all of its 25 percent interest.
AMSTEL FIELD, Q/13A PRODUCTION LICENSE, OFFSHORE THE NETHERLANDS
Amstel Field is an appraised but undeveloped discovery that was awarded by the Dutch Ministry of
Economic Affairs of the Netherlands as a production license to IOG effective November 17, 2006. The
award of the license is understood to take the form of a "ring-fence" around the Amstel development area
and does not cover the whole of the Q/13 permit area. The Amstel development area covers 30 km2 in
water depths between 21 and 23 meters, as shown on the location map on Figure 1. The field is
operated by IOG with a 50 percent interest, after agreement for 40 percent mandatory state participation
through Energie Beheer Nederland B.V. (EBN) has been completed, and Encore Oil plc owns a 10
percent interest. San Leon entered into a royalty agreement with IOG in November 2007. Under the
terms of the agreement, San Leon's interest in Amstel Field is a royalty interest of 0.6 percent after EBN
back-in. The royalty interest entitles San Leon to 0.6 percent of the gross revenue from the production
flowstreams.
The Dutch fiscal regime applicable to Amstel Field comprises Corporate Income Tax (CIT) and State
Profit Share (SPS). CIT is a general income tax applicable to all companies in the Netherlands and is
therefore not petroleum-industry specific. SPS and CIT are interdependent in that SPS is an allowable
deduction for CIT. As of January 1, 2007, the CIT rate is 35 percent on all taxable profits over 60,000
Euros. The SPS rate is 50 percent of the profit remaining after CIT has been deducted. Our economic
analysis does not consider any income taxes and therefore does not include the effects of CIT and SPS.
The hydrocarbon resources at Amstel Field are planned to be developed during 2008 from 2 high-angle
or horizontal wells and 1 vertical well. Production startup is anticipated during 2010 with oil produced via
Page 3
52
an unmanned wellhead protector jacket. The oil is anticipated to be exported through a 24-kilometer (km)
pipeline to the Rijn Field platform facilities for processing and onward transmission. Pending regulatory
approval, confirmation by EBN that it will exercise its 40 percent equity participation, and demonstration of
commerciality, the undeveloped hydrocarbon volumes are classified as contingent resources. Provided
these contingencies are met, some portion of the contingent resources estimated in this report may be
reclassified as reserves. The field operator, IOG, has informed San Leon that the letters of agreement for
field development are in the final stages of the approval process and are likely to be completed during the
second or third quarter of 2008.
2.2
DJ BASIN, CHEYENNE COUNTY, NEBRASKA, UNITED STATES
San Leon owns a 100 percent working interest in leases in Nebraska that encompass approximately
6,400 contiguous acres (approximately 26 km2), as shown on Figure 2. San Leon leased the acreage
from a number of mineral rights owners at an average cost of US$4.75 per acre per annum. The mineral
rights owners retain a 12.5 percent royalty interest for revenue generated from production. James
Mitchell, a consultant to San Leon, has a 4.5 percent overriding royalty interest, and San Leon has
agreed to provide a 1 percent royalty interest to Western Nebraska Land Services Inc., a company that
has provided land services to San Leon. This leaves San Leon with an 82 percent revenue interest.
Mineral leases provide the rights to conduct exploration drilling and, in the event of a discovery, to
construct necessary facilities to produce the discovered hydrocarbons.
San Leon acquired a 3-D seismic survey over the lease areas and identified 8 prospect targets. San
Leon drilled its first exploration well, Ludeman 1, in July 2008 to test the D Sand C Prospect and Lyons
Sand Dune East Prospect. This well failed to find commercial quantities of hydrocarbons in the D Sand
and Lyons Sand intervals. For this report, we have assessed the 6 remaining exploration prospect
targets.
2.3
TARFAYA EXPLORATION PERMITS, MOROCCO
The Tarfaya exploration permits are located in southern Morocco and encompass 13,434 km2 (Figure 3).
The permits are located onshore and border the coastline of the Atlantic Ocean. The exploration permits
were awarded by ONHYM in November 2007 and are effective January 14, 2008, for an 8-year term
divided into three work phases. Pursuant to the Petroleum Agreement, ONHYM has a 25 percent
interest, and San Leon has a 22.5 percent interest. ONHYM has the right to maintain its interest of up to
25 percent. If ONHYM relinquishes all of its 25 percent interest, San Leon may be entitled to an interest
of up to 30 percent as a nonoperating partner. If ONHYM maintains its interest at the maximum 25
percent, San Leon will have a 22.5 percent equity interest, and the other joint venture partners, IOG (as
operator) and Longreach Oil and Gas Ventures Limited, will have a 30 percent interest and a 22.5 percent
interest, respectively. State participation is carried through the exploration phases with no reimbursement
for exploration costs. The exploration work programs for the three periods include the following:
Phase I: 2.5-year period - acquire, process, and interpret 500 line km of 2-D seismic data and
conduct geochemical modeling. A drill or drop decision will be made at the end of the initial
period.
Phase II: 3-year period - drill 1 well.
Phase III: 2.5-year period - drill 2 wells.
The fiscal regime for commercial discoveries and award of an exploitation license onshore and offshore in
water depths of less than 200 meters includes royalty payments of 10 percent for oil and 5 percent for
gas. The first 300 thousand tons, approximately 1.9 MMBBL, of oil and 300 million cubic meters,
Page 4
53
approximately 11 billion cubic feet (BCF), of gas are exempted. Our economic analysis assumes
ONHYM will relinquish its 25 percent interest and includes the royalty exemption on production. As such,
our typical development case assumes a 30 percent working interest and a 30 percent revenue interest
initially, which converts to a 27 percent revenue interest after production of the exempted oil volume. This
lower revenue interest accounts for the 10 percent royalty on oil.
At application and approval for an exploitation license, a lease payment of 1,000 Moroccan dirhams per
km2 (approximately US$100.00 per km2) is made to the state and is tax deductible. Taxable income is
determined after deduction of royalties, lease rentals, bonuses, training expenses, and production
expenses. Negotiable elements of the Petroleum Agreement include work programs, bonuses, training
budgets, and amortization. Bonuses upon each commercial discovery at agreed production levels are
negotiable and are tax deductible.
Taxation of profit oil includes a 10-year tax holiday from the start of commercial production and
consolidation of exploration costs. The tax rate is 35 percent of taxable income, and dry hole costs are to
be deducted against revenues of any exploitation license held by the taxpayer. Other taxes include
withholding tax on profits, value added tax, business activity tax, urban tax, and tax on nonimproved land.
Our scoping economic analysis does not consider any taxes and therefore does not include the effects of
these taxes.
There are 15 onshore leads that have been identified and assessed. Delineation of the lead areas
through exploratory drilling will dictate development plans. ONHYM has provided San Leon with a
preliminary dry hole cost estimate of US$7 million.
2.4
ZAG EXCLUSIVE RECONNAISSANCE LICENSE, MOROCCO
The Zag exclusive reconnaissance license is located in southern Morocco and occupies approximately
21,807 km2 (Figure 3). The license was awarded by ONHYM to San Leon and its joint venture partners
on December 12, 2006, for a 12-month period initially. ONHYM subsequently granted a 12-month
extension valid until December 2008. The joint venture partners in the license are San Leon, as operator,
with a 50 percent interest; Longreach Oil and Gas Ventures Limited with a 30 percent interest; and IOG
with a 20 percent interest. Under agreements with the joint venture partners, San Leon's cost for the
Phase I work program is fully carried by the partners.
The Phase I work program includes reviewing existing studies; conducting geological field studies and a
geochemical study; acquisition, processing, and interpretation of aeromagnetic data; and the
interpretation of satellite image data. The integration of these data will aid in high-grading areas for future
acquisition of a 2-D seismic survey to delineate leads and prospects. Much of the Phase I work program
has been completed by San Leon with the acquisition of gravity and magnetic data set to be completed
during the fourth quarter of 2008. The studies completed by San Leon were compiled into a
comprehensive report entitled "Zag License: First Prospectivity Report". This report documents the
drilling history and oil and gas shows encountered by previous wells on the basin margins and analog
wells from the Reggane-Tindouf Basin in Algeria, source rock geochemistry obtained from diggings from
water wells in the 50- to 100-meter depth range, and analysis of the petroleum system and play concepts.
Subsequent to the 1-year Phase I reconnaissance period, San Leon has the right to enter into an 8-year
Phase II exploration program. The Phase II work program is anticipated to require acquisition,
processing, and interpretation of a grid of 2-D seismic data at an estimated cost of US$12.0 million.
There is no drilling commitment for the Phase II work program.
Page 5
54
3.0
TECHNICAL PROCEDURES ____________________________________________________
The resources assessments presented herein are based on the data provided by San Leon. Our
assessments focused on (1) geologic and reservoir data and interpretations made available by San Leon,
supplemented with the nonconfidential files of Netherland, Sewell & Associates, Inc., along with publicdomain data; (2) preparation of probabilistic volumetric assessments; (3) prospect and lead risk
assessments to estimate the probability of success for hydrocarbon discoveries; (4) estimates of
flowstreams and net cash flows for the contingent resources in Amstel Field; and (5) scoping economics
and estimates of product flowstreams for a representative development of a potential successful
discovery in the Tarfaya exploration permits.
A combination of deterministic and probabilistic methods was used for estimating the contingent
resources in Amstel Field and the prospective resources in the DJ Basin lease area and Tarfaya permits.
Volumetric interpretations were constructed on the basis of available well logs, production tests, and 2-D
or 3-D seismic data. Available seismic data were integrated with on-trend production and reservoir data,
where available, to derive our estimates of in-place and recoverable hydrocarbon resources. Seismic
travel time was converted to depth to estimate probability ranges of closure areas and gross rock volume
(GRV).
Volumetric estimates of original hydrocarbons-in-place and contingent and prospective resources were
calculated probabilistically using a Monte Carlo simulation of input variables. We have generally
estimated for each objective reservoir a range of values for (1) area of closure; (2) net reservoir thickness;
(3) hydrocarbon yield based on porosity, Sh, oil formation volume factor (Bo), and gas formation volume
factor; and (4) recovery factors. We have based these parameters on our knowledge of other on-trend
fields and reservoir and production data available in the public domain. Recovery factors have been
estimated based on reservoir drive mechanisms seen and expected for the various depositional and
structural environments and on analogy to known fields with similar geologic characteristics and potential
development scenarios.
3.1
GEOLOGIC RISK ASSESSMENT FOR PROSPECTIVE RESOURCES
A primary consideration in petroleum exploratory ventures is determining the presence of an active
petroleum system. An active petroleum system requires (1) the presence of organically rich, thermally
mature source beds capable of generating hydrocarbons and (2) the presence of adequate migration
pathways for mature hydrocarbons to migrate out of source beds into porous and permeable reservoir
beds. The hydrocarbon resources potential of a basin is dependent on (1) the proximity of prospects
(traps) to potential source beds; (2) the timing of source maturation and hydrocarbon migration relative to
trap development; (3) the area, thickness, porosity, and permeability characteristics of the reservoir beds;
and (4) trap and seal capacity. The San Leon lease, permit, and license areas described in this report
indicate the presence of active petroleum systems by direct evidence from production in the same or
similar basins, hydrocarbon shows from drilled wells, regionally known surface hydrocarbon seeps, and/or
source rock studies.
Each prospect or lead discussed herein was evaluated for the probability of discovering hydrocarbons in
sufficient quantity for them to be produced at a measurable rate to the surface without regard to the
chance of development. We evaluated this probability of geologic success (Pg) or risk factor using a fourcomponent methodology, based on Otis and Schneidermann (1997). We recognize the primary risk or
uncertainty elements as (1) source, including capacity of charge and maturity of source rock; (2) reservoir
presence and quality; (3) trap integrity, including seal and trap definition; and (4) timing of migration
relative to trap presence, migration pathways, etc. The product of values assessed for these four
components is the Pg.
Page 6
55
Each prospect or lead was evaluated and risked as an independent entity without dependency between
potential prospect or lead drilling outcomes. The subjective nature of geologic risk assessment is highly
dependent on the experience of the evaluators, the data available to define a lead or prospect, the
available regional data describing reservoir and production characteristics, and the historical local and
regional hydrocarbon discovery success rates. The Pg values estimated for the prospects and leads are
subject to significant change with the acquisition and interpretation of additional well and seismic data.
Otis and Schneidermann (1997) define a Pg greater than 0.50 as very low risk, a Pg between 0.50 and
0.25 as low risk, a Pg between 0.25 and 0.125 as moderate risk, a Pg between 0.125 and 0.0625 as high
risk, and a Pg below 0.0625 as very high risk. We characterize the main uncertainties or risks associated
with each prospect or lead in the prospect and lead discussion sections herein.
3.1.1
Summary of Prospect and Lead Geologic Risk
As discussed in Section 5.1.4.3, the overall probability of success for the 6 identified prospects in the DJ
Basin lease area ranges from 15 to 34 percent, or 66 to 85 percent probability of failure, and therefore
represents low to moderate risk exploration. As discussed in Section 5.2.8.3, the overall probability of
success for the 15 identified leads in the Tarfaya exploration permits ranges from 3 to 9 percent, or 91 to
97 percent probability of failure, and therefore represents high to very high risk exploration.
3.2
ECONOMIC CONSIDERATIONS
Considerations for development, if a discovery has been made, include (1) field development plans
(FDPs), including capital and operating expenses; (2) drilling and well completion techniques;
(3) reservoir deliverability rates; (4) surface facility considerations; (5) transportation; and (6) product
pricing, tariffs, and taxation. We recognize that ongoing technical evaluations, additional data acquisition,
and revised or improved drilling and well completion techniques may significantly alter development
plans.
We prepared estimates of development economics for Amstel Field, as discussed in Section 4.0 below.
For the Tarfaya exploration permits, we conducted a scoping economic analysis to test the economic
viability of a hypothetical petroleum discovery case using a single representative development. The
scoping economic analysis includes estimated production forecasts based on reservoir depth,
temperature, pressure gradients, and expected mean reservoir properties. The unrisked best estimate
prospective resources were used to estimate the number of required production wells to achieve the
production forecasts. We reviewed the drilling, completion, facilities, and operating costs supplied by San
Leon and supplemented these data with our experience of similar development costs of analogous fields.
Future gross revenue and net cash flow to the San Leon interest are after deductions for government
royalty payments and are composed of San Leon's share of cost and profit oil or gas, as set forth in the
license agreement. In preparing our estimates, we relied upon San Leon's interpretation of the terms of
the license agreement without independent verification. The future net cash flow has been discounted at
an annual rate of 10 percent to indicate the effect of time on the value of money; the discounted cash flow
should not be construed as being the fair market value of the properties.
As requested, this report has been prepared using an oil price specified by San Leon of $80.00 per barrel.
The oil price is held constant throughout the lives of the properties.
Page 7
56
4.0
CONTINGENT RESOURCES ASSESSMENT _______________________________________
4.1
AMSTEL FIELD, Q/13A PRODUCTION LICENSE, OFFSHORE THE NETHERLANDS
4.1.1
Basic Data
Discovered Field:
License, Basin:
Water Depth:
Reservoir:
Reservoir Depth:
Area:
San Leon Interest:
4.1.2
Amstel Field
Q/13a Production License, West Netherlands Basin
21 to 23 meters
Rijswijk Member sandstones of the Delfland Subgroup (Lower Cretaceous)
1,820 meters
30 km2
0.6 percent royalty
Summary
Amstel Field is located in the West Netherlands Basin of the North Sea approximately 10 km offshore in
water depths of 21 to 23 meters. The field is delineated by 1 exploration well, 4 appraisal wells, and
1992-vintage 3-D seismic data; the field is a faulted anticline with multiple culminations (Figure 4). Of the
5 wells drilled near the field, 3 wells were drilled into the hydrocarbon column of the Lower Cretaceous
age Delfland reservoirs (Figure 5). The discovery well, Q/13-1, was drilled in 1962 by NAM (Shell/Esso),
and the Q/13-8 and Q/13-9 appraisal wells were drilled in 1992 by PanCanadian Petroleum Limited. The
Q/13-8 well was production-tested at estimated total rates of 3,500 barrels of oil per day (BOPD) and 1.12
MCF per day of associated gas. The other wells were not flow-tested but are interpreted to be in
reservoir communication on the basis of fluid pressure gradient data. Amstel Field was previously
considered uneconomic for development because of low oil prices and economics.
4.1.3
Data Sources
To complete our assessment, San Leon provided all its available technical data as well as open
interaction with its technical staff and the field's operator, IOG. Technical data and information available
over Amstel Field included 3-D seismic data, digital wireline well log data, check shot surveys, and well
deviation surveys, as well as copies of internal reports and evaluations. We were also provided the
Competent Persons Report prepared by Fugro Robertson Limited (FRL) on behalf of IOG. We conducted
independent analysis as deemed necessary to confirm the estimated in-place and recoverable
hydrocarbon resources volumes reported therein.
The raw and interpreted data provided us an extensive database with which to conduct our assessment
of the in-place and recoverable resources volumes. After reviewing the provided data, reports, and
interpretations, seismic and well data were loaded onto our workstations and interpreted using a suite of
Landmark software.
4.1.3.1
Well Data
Well data were available in digital format for 7 Amstel Field area wells. We reviewed these well data to
confirm top and base reservoir intervals, net-to-gross ratio (NTG) of the reservoir, average net porosity,
and average net Sh. Figure 6 is a type log showing the Amstel Field reservoir in the Q/13-8 well. The
Rijswijk Member sandstones were deposited in a transgressive, shallow marine setting and exhibit
porosity in the range of 11 to 19 percent and water saturation ranging from 17 to 46 percent.
Page 8
57
4.1.3.2
Seismic Data
The 3-D seismic data are 1992 vintage and cover the majority of the Q/13 Production License and all of
the Amstel Field ring-fence development area. The seismic data are generally fair to good quality, and
we consider the data adequate to define the structural configuration of the field. The Rijswijk Member
sandstones are relatively thin and directly overlie an angular unconformity, making estimation of reservoir
properties from seismic amplitudes difficult, though some qualitative information about reservoir presence
can be obtained (Figure 7). Major bounding faults and folds are clearly evident on the 3-D seismic data
as is the structure and stratigraphy of the overburden above the field, which is important from the
standpoint of time-to-depth conversion (Figure 8).
Conversion from seismic time to depth is complicated at Amstel Field because the compressional
tectonics that created the field structure also uplifted the overlying Ommelanden Chalk, which was later
eroded directly over the field. Velocity data from wells in the field cannot be used to estimate velocity
outside the field area because the chalk is missing, and hence, the area outside the field sees faster
velocities due to the presence of the faster chalk interval. For our independent depth conversion, we
therefore used a layered model in Landmark's DepthTeamExpress software to account for higher
velocities outside the chalk erosion area. Final depth conversion of our independent time interpretation of
the field resulted in a GRV that closely matched the estimates prepared by FRL. Therefore, we have
accepted the range of GRV presented by FRL and used it in making in our probabilistic estimates of inplace hydrocarbons and contingent resources.
4.1.4
Contingent Oil Resources Estimates
The Rijswijk Member sandstone reservoirs are penetrated by each of the drilled wells, and an oil-water
contact (OWC) has been established at 1,861 meters true vertical depth subsea. The reservoir is
considered a single zone in our volumetric assessments. OOIP and contingent oil resources volumes for
Amstel Field were estimated using a probabilistic spreadsheet combining distributions for net rock volume
(NRV), porosity, Sh, Bo, and recovery factor.
Volumetric parameters for Amstel Field are listed in the following table:
Objective Interval
Low
NRV
(Acre-Feet)
Best
Amstel (Rijswijk) Sandstone
24,457
34,994
High
57,206
Reservoir parameters for Amstel Field are listed in the following table:
Objective Interval
Amstel (Rijswijk) Sandstone
Average Porosity
(Decimal)
Low Best High
Average Sh
(Decimal)
Low Best High
Bo
(RB/STB)
Low Best High
Recovery Factor
(Decimal)
Low Best High
0.13
0.56
1.23
0.25
0.18
0.21
0.74
0.85
1.24
1.25
0.33
0.41
Probabilistic estimates of gross (100 percent) OOIP and contingent oil resources for Amstel Field are
shown in the following table:
Page 9
58
Objective Interval
Low
Amstel (Rijswijk) Sandstone
16.5
4.1.5
Gross (100 Percent)
Contingent Oil Resources
OOIP
(MMBBL)
(MMBBL)
Low
Best
High
Best
High
(1C)
(2C)
(3C)
25.9
39.7
4.1
8.5
16.2
Production Rates
The Q/13-8 well tested at a rate of 3,500 BOPD and 1.12 MCF per day of associated gas. No gas sales
are included in this report, which is consistent with the economic templates provided by San Leon.
4.1.6
Operating Expenses and Capital Requirements
Because San Leon owns no working interest in Amstel Field, lease and well operating costs would not be
incurred. However, estimated lease and well operating costs provided by San Leon have been used in
the determination of the economic limits for the properties. These estimated lease and well operating
expenses have been reviewed and found to be reasonable based on our experience with similar
properties. As requested, lease and well operating costs are held constant throughout the lives of the
properties.
Operating expenses are based on the FDP provided by San Leon. The gross fixed operating cost is
estimated to be US$164,000 per month and comprises headquarters general and administrative
overhead expenses, rentals, and workover costs. Gross variable operating costs are estimated to be
US$3.75 per gross barrel of oil produced and comprise line, processing, and other tariffs. An additional
gross variable operating cost is also estimated to be US$120,000 per month per well and comprises
direct costs.
Capital costs have been included to determine whether workovers, new development wells, and
production equipment requirements are economic. Capital costs used in this report for Amstel Field are
also based on estimates provided by San Leon. These estimated capital costs have been reviewed and
found to be reasonable based on our experience in the region. As requested, capital costs are held
constant to the date of expenditure.
Capital cost requirements are also based on the FDP provided by San Leon. The drilling and completion
of 3 development wells are estimated to have a total gross cost of US$21.7 million. The installation of a
wellhead protector platform, tie-back to the Abu Dhabi National Energy Company (TAQA) Rijn P/15-C
production platform, and installation of facilities on the TAQA platform are estimated to have a total gross
cost of US$42.3 million. The total gross cost for abandonment of the wellhead protector platform,
facilities, and wells is estimated to have a total gross cost of US$7.2 million. These abandonment costs
are scheduled at the end of the commercial life of the project.
4.1.7
Development Scheduling
We have assumed that development will commence with drilling during 2008 and installation of the
wellhead protector platform, facilities, and flowline in 2008 and 2009, with production start-up in January
2010.
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59
4.1.8
Economics
We have prepared unrisked economics for the 1C, 2C, and 3C development cases wherein the 3
development wells are expected to recover a combined 4.1, 8.5, and 16.2 MMBBL of gross oil resources,
respectively. Summary projections of resources and cash flow for the 1C, 2C, and 3C contingent
resources are shown on Figures 9 through 11, respectively. Graphs of projected oil production for a
representative development well for the 1C, 2C, and 3C contingent resources are shown on Figures 12
through 14, respectively. The net resources and net cash flows reflect San Leon's 0.6 percent royalty
interest. We have not included the effect of CIT or SPS in our estimates.
5.0
PROSPECTIVE RESOURCES ASSESSMENTS _____________________________________
5.1
DJ BASIN, CHEYENNE COUNTY, NEBRASKA, UNITED STATES
5.1.1
Basic Data
Leases, Basin:
Exploration Methods:
Prospective Reservoirs:
Reservoir Depth:
Area:
Trap Style:
Source:
Main Uncertainties:
San Leon Interest:
5.1.2
Multiple leases in Cheyenne County, Nebraska; DJ Basin
3-D seismic data and offset well and production data
Cretaceous D Sand, Cretaceous Niobrara Sand, and Permian Lyons Sand
3,300 to 4,200 feet
Approximately 6,400 acres
Structural dip
Permian Wolfcamp mature oil shales for the D Sand and Lyons Sand; Niobrara
is self-sourcing biogenic gas
Structural trap and migration pathway
100 percent working, 82 percent revenue
Summary
The Nebraska lease area is located on the eastern flanks of the DJ Basin where San Leon's exploration
efforts are focused on the Cretaceous-aged D Sandstone oil reservoirs with secondary objectives in the
shallower Cretaceous-aged Niobrara gas reservoirs and a deeper Permian-aged Lyons oil interval. A
location map of the Nebraska lease area is shown on Figure 2, and a stratigraphic column of the DJ
Basin is shown on Figure 15.
5.1.2.1
D Sand
The D reservoir interval is at relatively shallow burial depths of approximately 4,200 feet below surface.
The reservoir is a regionally continuous stratigraphic interval deposited in a complex shallow marine-tomarginal marine-to-nonmarine environment with pinchout updip to the east on the flanks of the basin.
Structural traps are subtle dip closures formed by the dissolution of salt in the underlying Permian Lyons
Formation. The D Sand appears to be connected to a regional aquifer that provides a water drive
mechanism to discovered oil volumes. The primary uncertainties associated with the D Sand play are
delineation on 3-D seismic data of the following: (1) sufficient structural elevation in dip-closed structures
above the regional aquifer; (2) location of hydrocarbon migration pathways relative to known structures
southwest of the San Leon acreage; and (3) known non-oil-bearing structures within the San Leon
acreage. The recovery of discovered oil with sufficient elevation above the aquifer is generally
accompanied by water production that increases over time but generally results in a high recovery of the
in-place oil volumes. Most of the known oil-bearing structures are drained by 1 to 2 well penetrations.
Dry holes that penetrate the D reservoir are attributed to inadequate closure or to having been bypassed
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60
by migrating hydrocarbons. A depth structure map of the Top D Sand and a representative seismic line
are shown on Figures 16 and 17, respectively.
5.1.2.2
Niobrara Chalk
The Niobrara Formation is above the D Sand reservoir interval at approximately 3,300 feet below surface.
The reservoir is regionally continuous and comprises interbedded limestones (chalks) and calcareous
shales deposited in an open marine environment. Porosity is reasonable in the Niobrara Chalk, but
permeability is very low and natural fracturing is required to produce self-sourced, biogenic gas such as at
Miller and McCourt Fields located approximately 5 miles northwest of the San Leon acreage. Fracturing
at Miller and McCourt Fields is likely due to differential compaction and faulting from dissolution of
underlying salts in the Permian Lyons Sand. The Niobrara Prospect on the San Leon acreage overlies a
large D Sand structure and a remnant, structurally positive Lyons Sand dune feature, suggesting the
mechanisms for fracture formation are in place. The Niobrara Prospect is further delineated by a seismic
amplitude anomaly observed on 3-D seismic data and shown on Figure 18.
5.1.2.3
Lyons Sand
The potential Lyons Sand reservoirs over the San Leon acreage are believed to be eolian dune
sandstones deposited in southwest-to-northeast trending features, as shown on the Lyons Sand isopach
on Figure 19. The Lyons Sand is Permian aged and thought to be composed primarily of sandstones,
halites, and anhydrites deposited in a nonmarine-to-shallow marine environment.
Dune-like
geomorphologic features have been interpreted on the good-quality 3-D seismic data across the San
Leon acreage, and the dunes themselves resting on the generally flat-lying Wolfcamp below form the
potential traps for oil. The oil source will be from the underlying Wolfcamp Formation with migration
through faults or other discontinuities in the Satanka Shale layered between the Wolfcamp and Lyons
Formations. Lyons dune sandstones are only rarely penetrated in the region surrounding the San Leon
acreage, but a few wells have indicated the presence of thick, high-NTG, high-quality sandstones. The
Lyons dune play is a new play concept that has not been actively pursued in the northeast DJ Basin.
5.1.3
Data Sources
San Leon acquired a 3-D seismic survey during the first quarter of 2008 that was processed and
interpreted during April 2008. Data provided to us included a Seismic Micro-Technology, Inc. (SMT)
Kingdom database containing 3-D seismic data, digital well log data, check shot surveys, and well
deviation surveys, as well as copies of internal reports and evaluations. After reviewing the provided
data, reports, and interpretation we assessed probability ranges for prospect size and reservoir
parameters. Offset well and production data were obtained from public domain data sources and
incorporated into our assessment of reservoir drive mechanisms, recovery factors, and estimation of
product flowstreams.
5.1.4
Prospective Resources Estimates
The 2007 PRMS defines a prospect as a project associated with a potential accumulation that is
sufficiently well defined to represent a viable drilling target. For the Nebraska lease area, the play type
and demonstrated active petroleum system are well established, and closure areas are defined by the
3-D seismic data. As such, the closure areas identified are classified as prospects. As appropriate, we
have conducted a geologic risk assessment of the chance for discovery of recoverable hydrocarbons
based on historic success rates and interpretation of the available data.
The DJ Basin is a mature petroleum province, and our exploration assessment of the block focused
primarily on seismic time-to-depth conversion to estimate closure areas for potential trap sizes and net
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61
reservoir thickness above estimated OWCs. Net thickness and reservoir parameter values were derived
from offset well data from both oil- and water-wet intervals.
5.1.4.1
Parameters
For this report, 6 prospects have been assessed: 4 in the D Sand, 1 in the Niobrara interval, and 1 in the
Lyons interval. Volumetric parameters for the DJ Basin oil prospects are listed in the following table:
Low
NRV
(Acre-Feet)
Best
High
D Sand
A
B
Near Franzen 1
Near Franzen 2
00,508
00,322
00,156
00,000
00,822
00,735
00,454
00,353
00,904
00,809
00,499
00,388
Lyons Sand
Dune West
07,266
08,548
25,956
Objective Interval/
Prospect
Volumetric parameters for the DJ Basin gas prospect are listed in the following table:
Objective Interval
Niobrara
Low
Area
(Acres)
Best
High
1,800
2,000
2,200
Reservoir parameters for the DJ Basin oil prospects are listed in the following table:
Porosity
(Decimal)
Low Best High
Sh
(Decimal)
Low Best High
Bo
(RB/STB)
Low
Best High
Recovery Factor
(Decimal)
Low Best High
D Sand
A
B
Near Franzen 1
Near Franzen 2
0.20
0.20
0.20
0.20
0.22
0.22
0.22
0.22
0.24
0.24
0.24
0.24
0.60
0.60
0.60
0.60
0.70
0.70
0.70
0.70
0.80
0.80
0.80
0.80
1.50
1.50
1.50
1.50
1.60
1.60
1.60
1.60
1.70
1.70
1.70
1.70
0.18
0.18
0.18
0.18
0.25
0.25
0.25
0.25
0.33
0.33
0.33
0.33
Lyons Sand
Dune West
0.25
0.27
0.29
0.65
0.75
0.80
1.50
1.60
1.70
0.18
0.25
0.33
Objective Interval/
Prospect
Reservoir parameters for the DJ Basin gas prospect are listed in the following table:
Gas Yield per 80-Acre Well
(MMCF)
Low
Best
High
Objective Interval
Niobrara
190
220
250
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62
5.1.4.2
Probabilistic Estimates of Unrisked In-Place and Recoverable Volumes
Probabilistic estimates of unrisked gross (100 percent) OOIP and prospective oil resources, in thousands
of barrels (MBBL), for the DJ Basin prospects are shown in the following table:
Objective Interval/
Prospect
D Sand
A
B
Near Franzen 1
Near Franzen 2
Total - D Sand
Lyons Sand
Dune West
Total
Low
Unrisked Gross (100 Percent)
OOIP
Prospective Oil Resources
(MBBL)
(MBBL)
Best
High
Low
Best
High
0,348
0,231
0,114
0,044
00,520
00,413
00,241
00,156
00,734
00,643
00,394
00,306
0,077
0,053
0,026
0,010
0,129
0,102
0,060
0,038
0,203
0,174
0,105
0,082
0,737
01,330
02,077
0,166
0,329
0,564
6,727
11,967
21,187
1,529
2,990
5,747
7,464
13,297
23,264
1,695
3,319
6,311
Totals may not add because of rounding.
Probabilistic estimates of unrisked gross (100 percent) prospective gas resources, in millions of cubic feet
(MMCF), for the DJ Basin prospects are shown in the following table:
Unrisked Gross (100 Percent)
Prospective Gas Resources
(MMCF)
Low
Best
High
Objective Interval
Niobrara
5.1.4.3
4,468
5,360
6,345
Uncertainty/Risk Analysis
Our estimation of the Pg for the DJ Basin prospects ranges from 0.15 to 0.34 and is shown in the table
below. The main uncertainties for these prospects are structural trap and location of migration pathways.
Based on the risking technique of Otis and Schneidermann (1997), these prospects would be categorized
as low to moderate risk.
Objective Interval/
Prospect
Trap
Reservoir
Source
Timing/
Migration
Pg
D Sand
A
B
Near Franzen 1
Near Franzen 2
0.80
0.85
0.75
0.65
0.90
0.90
0.90
0.90
0.85
0.85
0.85
0.85
0.50
0.50
0.45
0.35
0.31
0.33
0.26
0.17
Lyons Sand
Dune West
0.70
0.80
0.90
0.30
0.15
Niobrara
0.75
0.85
0.90
0.60
0.34
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63
5.2
TARFAYA EXPLORATION PERMITS, TARFAYA-LAAYOUNE BASIN, MOROCCO
5.2.1
Basic Data
License, Basin:
Exploration Methods:
Prospective Reservoirs:
Water depth:
Reservoir Depth:
Area:
Trap Style:
Source:
Main Uncertainties:
San Leon Interest:
5.2.2
Tarfaya exploration permits, Tarfaya-Laayoune Basin
2-D seismic and gravity magnetic data
Jurassic carbonates and Triassic clastics
Onshore to 100 meters
Jurassic: 2,500 to 4,000 meters drill depth
Triassic: 4,000 to 5,200 meters drill depth
13,434 km2
Faulted horsts, tilted fault blocks, and structural noses
Jurassic marine shales
Reservoir, seal, and source migration
30 percent working, 27 percent revenue
Summary
We have evaluated 15 leads identified by San Leon and from our independent interpretations within the
Tarfaya exploration permits. The identified leads are subdivided into two primary play types contained in
Mesozoic age reservoirs: Jurassic platform carbonates and Triassic clastic reservoirs. The structural
traps evaluated are contained in fault- and dip-closed structures, anticlinal folds with four-way dip closure,
or structural noses with three-way dip closure. The Tarfaya joint venture partners intend to evaluate the
prospective potential of the concession by acquisition and interpretation of 2-D seismic data to mature the
leads to prospect drilling locations during the Phase II exploration work program.
The Tarfaya exploration permits lie within the Tarfaya-Laayoune Basin of southern Morocco (Figure 3).
The basin formed as part of an extensional rift system that extended throughout much of west and northcentral Africa during the Late Triassic to Lower Jurassic, followed by basin subsidence and renewed
rifting during the Cretaceous period. The rift episodes formed a basement system of faulted horsts and
grabens. From the Lower Tertiary to present time, the basin has been undergoing compression related to
the convergence of North Africa and Europe. Basin compression has been accompanied by inversion of
earlier extensional structures, strike-slip faulting, crustal folding, and uplift of the Atlas Mountains. The
primary petroleum system at Tarfaya was formed following the earlier rift episode when Jurassic age
ramp and platform carbonates were deposited as the basin subsided. Mature source rocks of Type II
marine kerogen were deposited along the Jurassic platform in elongated depositional troughs trending
north-northeast to south-southwest. Cretaceous clastics followed by organic-rich marine shales overlie
the Jurassic to form top seals to the platform carbonates. A second and deeper petroleum system
comprises Triassic age clastics along the top of faulted horst and graben blocks and is possibly sourced
by Triassic lacustrine shales or from juxtaposition across faults with the Jurassic source rocks.
In addition to the 15 leads, a portion of the Tarfaya exploration permits contains one of the largest oil
shale deposits in the world (Dyni, 2006). This unconventional hydrocarbon deposit is a Cretaceous age
hydrocarbon source rock comprising fine-grained marine shales rich in organic matter with high hydrogen
content (kerogen). Kerogen can be converted into a substance similar to petroleum but, in this case, has
not gone through the oil-generation window composed of temperatures and pressures necessary to
convert the kerogen into a liquid or gas phase (Youngquist, 2005). A deposit of oil shale having
economic potential is generally one that is at or near enough to the surface to be developed by open pit,
conventional underground mining, or drilling methods. The shale requires surface processing by heating
to temperatures of about 450 degrees Celsius to extract liquid hydrocarbons. The Tarfaya oil shale is up
to 150 meters thick and averages 22 meters in thickness with an estimated total oil shale resources
2
volume of 86 billion tons (632 MMBBL of oil equivalent) within a 2,000-km area (Dyni, 2006). In the
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1980s, companies from North America and Europe conducted exploratory drilling and experimental
mining and processing of Moroccan oil shale, but no commercial oil was produced. We have not
conducted an assessment of the unconventional hydrocarbon potential of this oil shale deposit for this
report.
5.2.3
Data Sources
Our independent lead assessments for the Tarfaya exploration permits are based on a review of previous
industry reports and subsurface interpretations conducted by San Leon or its consultants. The technical
data set for this study consisted of technical reports and presentations containing interpreted 2-D seismic
lines, images and interpretations of well logs, geochemical analysis, and other technical data. We were
supplied with 2,293 line km of 2-D seismic data in digital format with San Leon's two-way time
interpretation of the Near Top Jurassic, Near Top Triassic, and Base Triassic horizons. Digital well data
for exploration wells were not available, but selected scanned images and hardcopy well logs that could
be accessed were provided along with stratigraphic columns and interpreted formation tops. Analysis of
these exploration data results has been thoroughly documented by San Leon, and presentations and
interpretations of the data were provided for our prospective resources assessment. Technical papers
related to regional geology, source rocks, and reservoir studies were accessed from various publicdomain sources to supplement the provided database. We reviewed and interpreted the database
provided and supplemented it with nonconfidential data to derive our estimates of in-place and
prospective resources volumes.
5.2.3.1
Seismic Data
The 2-D seismic data form a grid of approximately 5- to 23-km spacing with an average line spacing of
approximately 14 km, as shown on Figure 20. The seismic grid is located entirely onshore and does not
extend into the offshore area. The data were acquired by ONHYM and Société Chérifienne des Pétroles
from 1986 through 1988. The digital 2-D seismic data were supplied in SMT Kingdom format. The
seismic data were exported from Kingdom and imported into Landmark OpenWorks and SeisWorks for
use on our internal workstations. Integration of the well and seismic data is generally good for depicting
the general structure of the basin and to identify leads. We have independently evaluated the seismic
data and interpreted seismic time reflectors for the Base Triassic, Near Top Triassic, Middle Jurassic,
Near Top Jurassic, Near Top Cretaceous, and shallow Tertiary age canyons. These interpreted data
were used for making preliminary estimates of potential closure areas for the identified leads. As
described below, many of the leads are identified by one to three seismic lines, and additional data are
needed to mature the leads to prospect status.
5.2.3.1.1
Depth Conversion
We depth-converted the Near Top Jurassic (Figure 21) using average velocity data derived from the
available well log data to construct a regional average velocity map, as shown on Figure 22. There is
only 1 well in the Tarfaya permit area that definitively penetrated the Triassic (Chebika-1). This well is
located over a basement high and does not have representative velocity information for regional Triassic
depth conversion. To estimate depths to the Near Top Triassic, an isochron of the Jurassic was
generated by subtracting the interpreted seismic time horizons (Near Top Triassic minus Near Top
Jurassic), as shown on Figure 23. A constant interval velocity model was then applied to depth-convert
the Jurassic isochron. The resultant thickness interval was then added to the Near Top Jurassic to
estimate the depth of the Near Top Triassic (Figure 24).
The Jurassic interval velocity function assumes a relatively low value for limestone velocity of 6,400
meters per second seismic one-way travel time and assumes a predominance of limestone sediments
with contribution from lower-velocity marine shales. If these lower-velocity lithologies were replaced with
faster-velocity, dense limestones, dolomites, or anhydrites, the average interval velocity would be much
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faster, perhaps up to 7,500 meters per second. For this reason, our depth structure map of the Near Top
Triassic is considered a minimum estimate of depth. The relative size and depth of the identified Triassic
leads, shown on Figure 24, are uncertain because of the sparse depth and velocity data to constrain the
depth conversion.
5.2.3.2
Well Data
A total of 10 exploration wells have been drilled on the Tarfaya permits, with 8 wells drilled in 1961 and
1962 and 2 wells drilled in 1972 and 1973 (Figure 25). The data provided contained well information for 4
wells that penetrated the Upper to Middle Jurassic and 2 wells that penetrated the Triassic to
Precambrian. The well data assembled by San Leon include the following:
Well
Operator
Drill
Date
Total
Depth
(Meters)
Formation
Daora-1
Union Oil Company of Spain
1961
4,241
Puerto Cansado-1
Azienda Generale Italiana
Petroli
1961
4,091
Hagunia-1-2
Union Oil Company of Spain
1961
2,401
Chebika-1
Azienda Generale Italiana
Petroli
Azienda Generale Italiana
Petroli
Union Oil Company of Spain
1962
4,201
Malm
(Upper Jurassic)
Precambrian
1962
2,574
Precambrian
1962
4,117
1962
3,470
1962
4,199
1972
2,003
1973
2,029
Dogger
Gas shows (Tertiary)
(Middle Jurassic)
Lias
(Lower Jurassic)
Malm
(Upper Jurassic)
Neocomian
(Lower Cretaceous)
Albian
Gas shows (Miocene and Upper
(Lower Cretaceous) Cretaceous)
El Amra-1
Amseiquir-1-8
Corc-23-1
Corc-15-1
Laayoune-8-2
Laayoune-8-3
5.2.3.3
Champlin Petroleum
Company
Champlin Petroleum
Company
Empresa Nacional Petróleos
de Aragon, S.A.
Empresa Nacional Petróleos
de Aragon, S.A.
Malm
(Upper Jurassic)
Lias
(Lower Jurassic)
Comments
Oil show (Upper Jurassic)
Trace gas at 3,400 meters (Upper
Jurassic); bitumen odor at 206 to
208 meters (Cretaceous)
Weak traces of gas in Triassic; all
reservoirs water-filled
Trace gas (Cretaceous)
On-Trend Exploration
On-trend discoveries include the offshore Cap Juby Field and fields in the Essaouira Basin, as shown on
Figure 26. Cap Juby Field is the nearest field on-trend with Tarfaya and is discussed separately below.
A total of seven discoveries in the Triassic and Jurassic intervals were made in the onshore Essaouira
Basin, including one oil field and two gas and gas-condensate fields.
5.2.3.3.1
Cap Juby Field
Cap Juby Field is a heavy oil discovery located 40 km offshore and north of the Tarfaya permits in 100
meters water depth. The field was discovered in 1969 by Esso Morocco with the drilling of the MO-2 well.
This well tested 2,377 barrels per day of 10- to 12-degree API gravity, heavily biodegraded oil and
formation water that increased in volume to 40 percent during the test period. The test interval was from
karsted and fractured limestones in the Upper Jurassic below 2,076 meters subsea. The MO-8 appraisal
well was drilled on the flanks of the structure below the main reservoir OWC but is reported to have
recovered 0.28 barrels of 38-degree API gravity oil and 57.60 barrels of formation water from fractured
carbonates below the karst porosity zone (Figure 27).
The heavy oil is trapped in karsted and fractured Upper Jurassic platform carbonate reservoirs and
sealed by a thin cover of Cretaceous shales. The karst (cave) porosity is interpreted to have been
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derived from subaerial erosion that predated timing of hydrocarbon migration during the Middle to Late
Cretaceous. The heavy oil deposits are interpreted to be the result of biodegradation from Tertiary age
deep erosion of the overlying Cretaceous cover, biogenic processes, and migration loss of the light
components of the hydrocarbons.
Depending on the various reported estimates, the OOIP ranges from 40 to 70 MMBBL of oil with
recoverable resources of 4 to 14 MMBBL of oil (ONHYM internal report). The field has not been
monetized because of the nature of the heavy oil deposits and reservoir complexities. The trap geometry
forms an elongated dome approximately 25 km long and 15 km wide. There are reported to be four
reservoir intervals containing heavy oil within a 109- to 125-meter hydrocarbon column.
Average reservoir porosity varies considerably between and within the limestone layers. The karsted
reservoir comprises primarily vugular and fracture porosity and is generally restricted to intervals 1 to 4
meters thick and often less than 0.25 meters thick. The average porosity range in karsted intervals is 10
to 15 percent. The fracture-only porosity forms the bulk of the effective porosity and is less than 1
percent. Matrix porosity for nonkarsted limestone layers is thought to be ineffective for hydrocarbon
production and is less than 5 percent. The total net oil pay thickness at Cap Juby is estimated to range
from 4 to 32 meters.
5.2.4
Tectonic History
An understanding of the tectonic history of the Tarfaya-Laayoune Basin is important to our overall
assessment of prospective resources and geologic risk. A stratigraphic column depicting the sedimentary
fill, reservoir and source pairs, and source rock maturity is shown on Figure 28. A representative cross
section from northwest to southeast across the basin illustrating basin depth and sedimentary fill is shown
on Figure 29.
The Tarfaya-Laayoune Basin petroleum system is Mesozoic in age with economic basement considered
to be the top of the Paleozoic. The basin covers an area of about 170,000 km2 where Mesozoic thickness
may locally exceed 12 km. The Paleozoic history of the basin may play some role in the reactivation of
basement faults during Mesozoic deformation but is not thought to contribute to the Tarfaya petroleum
system of source, reservoir, and seal. The primary Mesozoic structures are fault and dip closures. The
primary Mesozoic tectonic events are identified from erosional unconformities occurring in five tectonic
cycles summarized as follows:
1. Paleozoic: The main Hercynian collision occurred in the Permian, forming a metasedimentary
Paleozoic basement with subsequent continental red bed sedimentation in the Late Permian
to Late Triassic from the arid continental margin. The Triassic sedimentary rocks are
estimated to be 4,000 to 4,500 meters thick comprising mostly fluvial deposits.
2. Late Triassic to Early Jurassic: Continental rifting began along a northeast-southwest trend
as the region underwent extension associated with the ultimate opening of the Atlantic
Ocean, which resulted in down-to-the-basin faulting along the margins of the African craton.
Continental sedimentation and transitional marine sediments of up to 6,000 meters thickness
were deposited in the onshore and shelf portions of the rift basin. The Tarfaya permit area
was the site of continental fluviodeltaic red bed deposits, which grade upward to evaporites.
Basaltic lavas and lacustrine clastics were deposited in the deeper offshore rift valleys
followed by evaporites, initially only within topographic lows, but as the region became a
more restricted marine environment, halite deposition became more widespread.
3. Jurassic to Early Cretaceous: Marine conditions prevailed in the Early to Middle Jurassic as
seafloor spreading began and a carbonate shelf formed along the continental margin.
Carbonates up to 4,000 meters thick were deposited as north-northwest prograding wedges,
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67
initially as ramp deposits grading upward to shelf margin sediments in the Middle to Upper
Jurassic. Pelagic sedimentation in deeper-water areas deposited marine marls and shales
(potential source rocks) as the drift phase progressed to the thermal subsidence phase.
Transgressive and regressive cycles, resulting from sea level fluctuations, alternately eroded
then built the shelf basinward, potentially sending pulses of clastic turbidite deposits into the
deepwater areas. Anoxic conditions during the Oxfordian resulted in the deposition of black
organic shales in the nearshore regions of the basin, providing local source rocks. Overlying
carbonates and anhydrites were deposited during latest Jurassic and Early Cretaceous time
as sea level fluctuated, potentially comprising layered carbonate reservoirs and
interformational anhydrite seals.
4. Upper Cretaceous: Transtensional rifting (wrenching) with fault reactivation along previous
structures in combination with a lowering of sea level resulted in widespread and deep
erosion of portions of the onshore and former shelf margin. Clastics were shed from the shelf
and deposited into the basin followed by Albian and Cenomanian-Turonian transgressive
series of marls and shales rich in organic matter. Progradational sediment influx and loading
initiated significant halokinesis throughout the basin, mainly in the form of salt diapirs and salt
pillows.
5. Tertiary: At the start of the Tertiary, hotspot volcanism created uplift of the Canary Island
volcanic trend, depositing basalts to the west of the permit area. Compressive tectonics in
the Eocene to Oligocene initially resulted in uplift and variable amounts of inversion of the
Atlas Trough and eventually to the collision of Africa and Europe to form the High and Middle
Atlas Mountains. Compression continued during the Neogene to form the Rif Mountains,
which are a segment of the Western Mediterranean fold belt. This inversion, along with
increased crustal heat flow, is thought to have uplifted existing structures bounded by crustal
faults. The rising slope was accompanied by deep erosional channels that are predominantly
shale-filled and possibly interbedded with clastic turbidites.
5.2.5
Hydrocarbon Source Rocks
There is abundant evidence for the presence and thermal maturity of one or more source rocks. Direct
evidence includes the penetration of organic-rich, high total organic carbon (TOC) intervals in exploration
wells; penetrations of potential reservoir zones with shows of oil and gas; the accumulation of
hydrocarbons at Cap Juby Field; and on-trend gas and oil fields to the north in the Essaouira Basin
(Figure 26).
The primary source rock is interpreted to be derived from early post-rift Jurassic depocenters (Figure 30)
and composed of marine Type II oil-prone kerogen and lesser amounts of Type III kerogen. The
Tan Tan-1 well offshore to the northwest penetrated a 60-meter interval of good to very good quality
source rock in Early Jurassic argillaceous limestone with TOC of 1.45 to 2.50 percent. San Leon has
modeled the burial history and maturity of the Jurassic source interval and estimates the oil-generative
phase began during the Upper Jurassic to Early Cretaceous period at burial depths below 3,100 meters
and the late mature oil- to early gas-generation phase from Early Cretaceous to Early Paleocene at burial
depths below 4,500 meters. The Lower Jurassic burial depths on the Tarfaya permits are not likely to
have entered into the dry gas generation phase. Tertiary age basin inversion reversed the basin burial
trend such that the source interval at present time is in the oil-generation phase. Based on the basin
modeling conducted by San Leon and our estimated depth to the base of the Jurassic syn-rift sequence,
we estimate that the primary hydrocarbon product at Tarfaya is oil. We recognize that a component of
associated gas or gas caps above oil is possible, but we have conducted our lead assessments based on
oil volumes only.
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Cretaceous black shales in the deepest portions of the offshore area are potential source rocks but will
require long-distance migration paths since they are at shallow burial depths and are immature for
hydrocarbon generation local to the Tarfaya leads. The Upper Cretaceous shales and marls have locally
demonstrated high TOC above 7 to 18 percent of Type II and minor amounts of Type III kerogen (Kolonic
et al., 2005) and constitute the outcropping shale oil deposits in the southern portions of the permit area.
In the offshore region beyond the shelf edge, the TOC of these rocks averages between 1 and 3 percent.
Additional but less well-documented source intervals may be provided by lacustrine shales from the early
and syn-rift Triassic to lowermost Jurassic.
5.2.6
5.2.6.1
Reservoir and Seal
Jurassic Reservoir and Seal
The Jurassic carbonates range in thickness from zero meters on the basement high fault block margins
(Chebika-1 and El Amra-1 wells) to approximately 4,000 meters toward the north and west. Although the
formation is a transgressive megasequence, relative fluctuations in sea level are identified from the well
and seismic data. The sequence consists primarily of marine limestones, calcareous shales, dolomites,
and interbedded anhydritic shales. Sediments with the potential to have developed a network of matrix
porosity would be localized patch reefs, shoal-reef complexes, or lagoonal dolomites. Interbedded or
overlying shales or anhydrites provide reservoir seals.
Primary matrix porosity in the Jurassic limestones at Tarfaya penetrated by wells to date is generally
poor. Low effective porosity is attributed to normal processes of chemical and physical alteration of
carbonate sediments at shallow burial depths. Preservation and connectivity of matrix porosity in
carbonate sediments mostly relies on secondary porosity formed by fracture networks and vugular
porosity along open fracture walls and by chemical and mineralogical alteration. In some cases, matrix
porosity may be preserved by early hydrocarbon charge soon after deposition and burial. Hydrocarbon
presence can impede pore-plugging mineralization. In the absence of early hydrocarbon migration, open
fracture networks are necessary to provide adequate reservoir storage and connectivity for commercial
hydrocarbon accumulations. Enhancement of secondary fracture porosity can also be improved by
chemical dissolution from migrating acidic fluids to form vugular porosity along the walls of open fractures.
Secondary karst (cave) porosity development is also possible where structural uplift is sufficient to expose
carbonates to meteoric waters such as occurred at Cap Juby Field. However, there is no direct evidence
from the available seismic data across the Tarfaya permits to indicate the Jurassic was uplifted and
eroded to the extent observed at Cap Juby.
Fracture development is related to the burial and tectonic history of the basin and to the timing of
hydrocarbon migration and trapping within the fracture networks. Petroleum traps within the Jurassic
carbonates are dependent on fracture systems open to migration from mature source rocks vertically
sealed by overlying ductile shales or anhydrites. Two stages of fracture development in relation to source
maturity are possible, including (1) Upper Cretaceous age extension correlative with oil generation from
mature Jurassic source rocks and (2) Tertiary compression and uplift of the Atlas Mountains
corresponding with hydrocarbon generation from the Jurassic source rocks. The ductile Cretaceous
marls and shales overlying the Jurassic and intraformational Lower and Middle Jurassic anhydrites and
shales would be less prone to fracturing and are potential reservoir seals.
Considerable variation in the amount of preserved open fracture systems is common within known
worldwide carbonate reservoirs. Fracture density increases where structural deformation is greater, such
as the crest of anticlines or in close proximity to large faults. Fracture porosity may range from no open
fractures or vugs to a maximum of 1 percent of the total GRV (Weber and Baker, 1981). Carbonate
reservoirs with the best preserved porosity are contained in strongly folded anticlines where fracture
porosity is enhanced by leaching, while porosity of less than one-tenth of a percent is contained in low-dip
anticlines and monoclinal structures. Karst porosity is generally preserved only over a limited vertical
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69
interval of less than 100 meters with an average porosity generally on the order of 3 percent. A summary
of fracture parameters for various structures and rock types (Weber and Baker, 1981) is shown in the
following table:
Rock Type
Porosity Range
(Percent)
Low-Dip Monoclines
Strongly Folded Anticlines
Fractures Enhanced by Leaching
Karst Aquifer to Surface Shallow
Deep Karst, Collapse Breccia
Fractured Chert
Fractured Tuffs and Igneous
0.01 - 0.10
0.10 - 0.30
0.20 - 1.00
0.20 - 3.00
0.50 - 2.00
5.00 - 8.00
2.00 - 8.00
The probability range of effective porosity used in our Monte Carlo models includes a low estimate that
includes fracture-only porosity, a best estimate that includes fracture plus minor contribution from matrix,
and a high estimate that includes preservation of high-energy reef-shoal carbonates. The low estimate
fracture porosity values were derived from the type of structure observed in the seismic data and
assigned values from the table above. The best and high estimate porosities ranged from 2 to 20
percent. The high end of the porosity range credits the potential for high-energy carbonates such as reefshoal complexes or carbonate grainstones and porosity preservation from early oil migration. The ranges
of porosities were input as triangular probability distributions in our Monte Carlo assessments.
5.2.6.2
Triassic Reservoir and Seal
Well data for the Triassic interval are sparse in the Tarfaya-Laayoune Basin, and we have therefore relied
on the tectonic history of the basin and data from other continental rift systems to estimate possible
porosity and net thickness. Deposition of the Triassic is interpreted to consist of an overall upward
transition from continental red beds to marine- or lacustrine-dominated deposits at the earliest onset of
rifting. The sequence mostly comprises cyclic continental sediments deposited on a stable platform
margin where fluvial and lacustrine deposition was cyclic relative to the timing of sediment input and
fluctuations in water depths. Alternating cycles of relative high and low sea level along a subsiding shelf
margin form sequences of repetitive, stacked sand-dominated fluvial channels, associated channel
overbank deposits, shallow marine deltaic clastics, and floodplain lacustrine or marine shales.
The basin architecture influenced sedimentation trends with thickening on the downthrown side of relic
and active faults and thinning sediment wedges over basement high fault blocks. The channel or shallow
marine sequences that could provide hydrocarbon storage have been estimated by comparison with the
available well data and continental rift basin analogy to have a thickness range of 3 to 60 meters
separated by localized floodplain shales. Fluvial-dominated reservoirs generally have 18 to 26 percent
porosity between 300 and 2,000 meters depth, while burial depths below 3,500 meters are considered to
have low rock quality of 2 to 16 percent porosity.
Depending on trap geometry, the vertical stacking of multiple fluvial channel or marine sandstone
sequences could provide significant hydrocarbon storage. Vertical and lateral seal rocks above and
adjacent to reservoir-quality sediments might be provided by both localized and regional floodplain and
marine shales and Late Triassic to Early Jurassic anhydrites. Comparison with known hydrocarbonproducing continental rift basins indicates localized shale layers generally range in thickness from 1 to 30
meters with most shale layers less than 3 meters. Only some of these shale beds have sufficient lateral
continuity to form semiregional and localized seals to hydrocarbon migration. Thick regional shales of
more than 100 meters are generally the primary seal rocks for moderate to large hydrocarbon
accumulations. Intraformational seals can support vertical hydrocarbon columns ranging from 10 to 50
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70
meters. Relatively continuous regional shales of more than 100 meters thickness might support vertical
hydrocarbon columns of 30 to 500 meters, depending on the trap geometry and the juxtaposition of
sediment layers offset by faulting.
For our Monte Carlo assessments, we have incorporated the range of porosities with depth observed
from well data and analogous continental African basins. The following table summarizes the estimated
ranges of reservoir porosities and possible ranges of net thickness of stacked fluvial and shallow marine
to lacustrine sediments. The ranges shown were input to our Monte Carlo assessments on a lognormal
distribution using 90 and 10 percent probabilities of occurrence.
5.2.7
Depth Range
(Meters Below Surface)
Porosity Range
(Percent)
Net Reservoir
Thickness Range
(Meters)
1,000 - 2,000
2,000 - 3,500
3,500 - 6,000
18 - 26
05 - 26
02 - 16
20 - 85
20 - 85
20 - 85
Leads
We have focused on 13 leads identified by San Leon and 2 leads identified from our independent seismic
interpretations. We assessed and estimated prospective resources for 10 Jurassic leads and 5 Triassic
leads. Three of the leads have dual objectives in the Jurassic and Triassic intervals. Lead closure areas
and GRVs were estimated by depth conversion of the interpreted seismic lines and from our estimates of
minimum to maximum closure areas. Figures 21 and 24 show the location of the lead areas: the Daora
Lead area is the largest and straddles the Moroccan coastline with the Atlantic Ocean. Figures 31 and 32
are regional dip lines showing the northern and southern portions of the Tarfaya permit area, respectively.
We have not attempted to make any inference on reservoir quality or thickness based on seismic data.
Seismic reflectivity of multiple parallel to subparallel events is not necessarily indicative of alternating
sequences of porous clastics and carbonates with nonporous intervening shales and marls. Lateral and
vertical contrasts in sediment densities provide both positive and negative acoustic impedance contrasts
and can easily be mistaken as boundaries between depositional sequences. Determining the number of
potential stacked reservoirs is not recommended in areas where seismic response has not been
calibrated to well data. Our estimates of reservoir thickness and porosity therefore relied on local well
data and analogy to reservoirs with similar burial depths.
The principal structural play types identified within the Tarfaya permits are summarized as follows:
Jurassic fractured carbonates within folded and/or faulted anticlines sealed by overlying
Cretaceous marls and shales.
Jurassic fractured carbonates located within footwall closures and horst blocks sealed by
overlying Cretaceous marls and shales.
Triassic sandstones in footwall closures with preserved matrix porosity sealed by Lower Jurassic
impermeable shales.
Triassic sandstones in horst-block closures sealed by Lower Jurassic impermeable shales.
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71
5.2.7.1
Jurassic Daora, Jurassic Daora North, and Triassic Daora Leads
The Daora Lead area is located on the northwest portion of the permit area along the Atlantic coast and
has 2 identified Jurassic anticlinal structures and 1 lead at the Triassic interval. The Jurassic structures
are on-trend with the Cap Juby heavy oil discovery in a similar structural setting but at greater depth and
with thicker Cretaceous cover. Therefore, the Jurassic leads are not considered to be at risk of
containing biodegraded oil. The Jurassic leads are dip-closed anticlines and include the Daora and
Daora North Lead areas (Figures 21 and 33 through 36). The primary risk is considered to be reservoir
quality with additional risks of source migration and definition of structural closure.
The Triassic is a footwall rotated fault block dipping toward the south-southeast (Figures 24, 33, and 35).
The structural culmination at the Triassic lies in the offshore area and is beyond the 2-D seismic
coverage. Integration of the onshore seismic data with gravity and magnetic data is necessary to
complete the interpretation of the structural closure in the offshore region. The trap is delineated onshore
by 9 2-D seismic lines of variable but generally good quality, indicating a monoclinal structure with
increasing elevation to the north-northwest. The gravity magnetic data indicate the crest of the lead forms
a prominent basement high that is likely bounded by a northwest-dipping normal fault (Figure 36). The
on-permit portion of the structure from the Atlantic coast to spill point ranges in area from 20.2 to 735.9
2
km . The Triassic section is at deep burial depth at a minimum of 5,000 meters below surface and is at
high risk for reservoir presence and preservation of porosity. For the on-permit portion of the lead to have
trapped hydrocarbons, the overlying seal rock would require a capacity to hold approximately a 1,000meter column of oil between the offshore structural crest and spill point. The primary risks are reservoir,
seal, source migration, and trap definition.
5.2.7.2
Jurassic J, Triassic J North, and Triassic J South Leads
The J Lead is a dual-objective lead that includes a dip closure at the Jurassic (Figures 21 and 37) and a
north horst block and south hanging-wall trap at the Triassic level (Figures 24 and 37). The fault complex
is downthrown from the basement high fault block penetrated by the El Amra-1 and Chebika-1 wells that
drilled thin Mesozoic sediments above the Precambrian basement. The Jurassic closure is imaged by 2
seismic lines and the Triassic by 3 lines. The primary risk for the Jurassic lead is reservoir. The primary
risks for the Triassic lead are source migration and reservoir presence.
5.2.7.3
Jurassic and Triassic Puerto Cansado Leads
The Puerto Cansado Lead is a dual-objective Jurassic and Triassic lead (Figures 21 and 24) located west
and northwest of the Puerto Cansado-1 well. This well was drilled to 4,091 meters and penetrated the
Lower Jurassic section but was located off the crest of the structure (Figure 38). The Triassic lead is a
structural inversion fold (Figure 38) mapped as a structural nose trending outside the Tarfaya permit area
to the north-northwest (Figure 24). The minimum depth to the Triassic is estimated to be below 4,600
meters where the primary risks are reservoir, trap definition, and source migration.
5.2.7.4
Jurassic C Lead
The C Lead is a Jurassic lead comprising a three-way dip-closed structural nose (Figure 21). This lead is
a low-relief structure with less than 50 meters of structural elevation above the regional dip and is
estimated to have a range of closure area from 8.2 to 83.1 km2 (Figure 21). The structure is imaged by 1
seismic line (Figure 39). The primary risks for the C Lead are reservoir, source migration, and structural
definition.
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5.2.7.5
Jurassic F Lead
The F Lead is a Jurassic lead that is a small dip closure imaged by 1 seismic line (Figure 40) that
indicates a flattening of regional dip, possibly indicating a structural nose or anticline. The primary risks
are trap definition, reservoir, source migration, and structural definition.
5.2.7.6
Jurassic G Lead
The G Lead is a Jurassic lead comprising an inversion fold structure with three-way dip closure on a
structural nose. The structure is imaged by 1 dip-oriented line but is barely visible on 1 strike line (Figures
40 and 41). Estimated closure is 3.3 to 20.5 km2. The primary risks are trap definition, reservoir, source
migration, and structural definition.
5.2.7.7
Triassic K Lead
The K Lead is a Triassic objective at an estimated minimum depth of 4,725 meters with an interpreted
range of dip closure between 18.9 and 251.6 km2. The structure is imaged by 3 seismic lines; the diporiented line is shown on Figure 42. The primary risks are reservoir quality and source migration.
5.2.7.8
Jurassic B Lead
The B Lead is a Jurassic lead that appears on 1 strike-oriented seismic line (Figure 43). This lead may
be the result of a velocity pull-up created by seismic processing. The seismic data were acquired over a
surface topographic depression where shot points and receivers are widely spaced. The primary risks
are trap definition, reservoir, and source.
5.2.7.9
Jurassic D Lead
The D Lead is a Jurassic lead defined as a structural nose by 5 seismic lines and crossed by 2 dip lines
(Figures 21 and 44). The primary risks are reservoir quality and source migration.
5.2.7.10 Jurassic I Lead
The I Lead is a Middle to Lower Jurassic lead on-trend with the Daora-1 well that recorded shows in the
Upper Jurassic (Figure 21). It is crossed by 1 strike-oriented line (Figure 35) and lies between 2 dip lines.
The primary risks are reservoir quality, source migration, and trap definition.
5.2.8
Prospective Resources Estimates
The 2007 PRMS defines a lead as 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. Because of the sparse 2-D seismic data coverage, all prospective resources at Tarfaya are
categorized as leads. The Phase II work program includes acquisition of up to 200 line km of 2-D seismic
data that will further delineate the leads prior to drilling. Our assessments of the leads were limited only
to the portion of the leads that lie within the Tarfaya permits.
5.2.8.1
Parameters
Volumetric parameters for the Tarfaya leads are listed in the following table:
Page 24
73
Low
Area
(km2)
Best
High
Jurassic
Daora
Daora North
J
Puerto Cansado
C
F
G
B
D
I
03.8
11.4
22.5
40.9
08.2
07.4
03.3
09.9
22.7
12.6
006.2
016.7
041.0
074.6
026.2
013.7
008.3
019.3
046.3
021.5
009.9
024.6
074.9
136.2
083.1
025.4
020.5
037.7
094.7
036.6
20
05
05
05
05
05
05
05
05
05
40
10
10
10
10
10
10
10
10
10
85
35
35
35
35
35
35
35
35
35
Triassic
Daora
J North
J South
Puerto Cansado
K
20.2
57.7
37.2
34.1
18.9
122.0
105.3
067.9
045.3
068.9
735.9
192.3
124.0
060.2
251.6
20
20
20
20
20
41
41
41
41
41
85
85
85
85
85
Objective Interval/
Lead
Net Thickness
(Meters)
Low
Best
High
Reservoir parameters for the Tarfaya leads are listed in the following table:
Objective Interval/
Lead
Porosity
(Decimal)
Low
Best High
Sh
(Decimal)
Low
Best High
Bo
(RB/STB)
Low
Best
High
Recovery Factor
(Decimal)
Low
Best High
Jurassic
Daora
Daora North
J
Puerto Cansado
C
F
G
B
D
I
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.60
0.60
0.60
0.60
0.60
0.60
0.60
0.60
0.60
0.60
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
0.75
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.397
1.386
1.349
1.360
1.389
1.387
1.370
1.372
1.373
1.393
1.401
1.389
1.352
1.367
1.391
1.390
1.374
1.376
1.376
1.396
1.408
1.394
1.358
1.375
1.396
1.395
1.380
1.381
1.382
1.400
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.20
0.40
0.40
0.40
0.40
0.40
0.40
0.40
0.40
0.40
0.40
Triassic
Daora
J North
J South
Puerto Cansado
K
<0.02
<0.02
<0.02
<0.02
<0.02
0.06
0.06
0.06
0.06
0.06
0.16
0.16
0.16
0.16
0.16
0.40
0.40
0.40
0.40
0.40
0.55
0.55
0.55
0.55
0.55
0.75
0.75
0.75
0.75
0.75
1.410
1.384
1.406
1.410
1.420
1.433
1.390
1.412
1.414
1.423
1.457
1.400
1.421
1.419
1.429
0.18
0.18
0.18
0.18
0.18
0.30
0.30
0.30
0.30
0.30
0.40
0.40
0.40
0.40
0.40
5.2.8.2
Probabilistic Estimates of Unrisked In-Place and Recoverable Volumes
Probabilistic estimates of unrisked gross (100 percent) OOIP and prospective oil resources for the
Tarfaya leads are shown in the following table:
Page 25
74
Objective Interval/
Lead
Jurassic
Daora
Daora North
J
Puerto Cansado
C
F
G
B
D
I
Unrisked Gross (100 Percent)
OOIP
Prospective Oil Resources
(MMBBL)
(MMBBL)
Best
High
Low
Best
High
Low
001.0
001.0
002.3
003.8
001.2
000.8
000.4
001.0
002.3
001.2
0,015.0
0,013.9
0,034.1
0,059.6
0,021.3
0,011.4
0,006.2
0,015.3
0,037.2
0,017.7
00,089.6
00,084.2
00,219.5
00,418.5
00,194.2
00,075.7
00,047.8
00,105.8
00,257.6
00,111.4
000.3
000.3
000.7
001.1
000.3
000.2
000.1
000.2
000.7
000.3
004.3
004.0
009.7
016.9
006.0
003.2
001.8
003.3
010.5
005.0
0,025.4
0,023.8
0,062.2
0,118.6
0,055.0
0,021.4
0,013.5
0,023.7
0,073.0
0,031.6
015.0
0,231.7
01,604.2
004.2
064.7
0,448.2
Triassic
Daora
J North
J South
Puerto Cansado
K
099.8
141.5
089.1
064.1
063.1
0,804.5
0,548.2
0,349.4
0,228.7
0,348.9
06,076.5
02,083.9
01,295.2
00,766.3
01,885.4
028.3
040.1
025.3
018.2
017.9
227.9
156.0
099.0
064.8
098.9
1,721.7
0,590.4
0,367.0
0,217.1
0,534.2
Total - Triassic
457.6
2,279.7
12,107.4
129.7
646.6
3,430.4
472.6
2,511.5
13,711.6
133.8
711.3
3,878.6
Total - Jurassic
Total
Totals may not add because of rounding.
5.2.8.3
Uncertainty/Risk Analysis
Our estimates of Pg for the leads in the Tarfaya exploration permits range from 0.03 to 0.09 and are
shown in the table below. The main uncertainties for the leads are presence of a porous reservoir, size
and integrity of the structural trap, and effectiveness of vertical seals in the Cretaceous intervals above
the carbonate reservoirs. Based on the risking technique of Otis and Schneidermann (1997), these leads
would be categorized as high to very high risk.
Objective Interval/
Lead
Jurassic
Daora
Daora North
J
Puerto Cansado
C
F
G
B
D
I
Trap
Reservoir
Source
Timing/
Migration
Pg
0.25
0.30
0.20
0.55
0.35
0.40
0.30
0.20
0.30
0.20
0.35
0.35
0.45
0.30
0.35
0.35
0.35
0.35
0.35
0.35
0.60
0.70
0.70
0.70
0.70
0.70
0.70
0.70
0.70
0.70
0.60
0.60
0.60
0.55
0.45
0.40
0.50
0.55
0.50
0.60
0.03
0.04
0.04
0.06
0.04
0.04
0.04
0.03
0.04
0.03
Page 26
75
Objective Interval/
Lead
Triassic
Daora
J North
J South
Puerto Cansado
K
5.2.9
Trap
Reservoir
Source
Timing/
Migration
Pg
0.25
0.60
0.60
0.20
0.40
0.35
0.40
0.40
0.35
0.35
0.60
0.70
0.70
0.70
0.70
0.60
0.55
0.55
0.55
0.65
0.03
0.09
0.09
0.03
0.06
Representative Scoping Economics for Exploration Success Case
The J North Lead was assessed for economic viability in the Triassic interval. We estimated production
forecasts based on reservoir depth, temperature, pressure gradients, and expected mean reservoir
properties. The estimated mean area and unrisked best estimate prospective resources were used to
estimate the number of required production and injection wells to achieve the production forecasts. We
reviewed the drilling, facilities, and operating costs provided by San Leon and found these costs to be
consistent with similar development costs onshore North Africa. The costs to develop and operate the
properties and the prices received for production may vary from assumptions made while preparing this
report.
5.2.9.1
Well Performance
For our evaluation, we used a type well profile to project the well-by-well and development total projected
production. We have no direct or nearby analogy information regarding the potential performance of
these formations. Therefore, we have relied on our experience with relatively deep, relatively low-porosity
oil formations to construct an acceptable type well for this analysis. We have used performance from
wells in western Venezuela because they are fairly analogous. Figure 45 shows the type curve used for
the Triassic J North Lead economic evaluation.
The best estimate case has an area of 105.3 km2 (26,028 acres). We have assumed a spacing
development of 80 acres per well to be consistent with the 30 percent recovery factor used in this case,
which indicates a requirement of 325 development wells recovering an average of 480 MBBL of gross oil
resources per well for a total of 156 MMBBL of oil. No gas sales are included in this report, which is
consistent with the economic templates provided by San Leon. Any produced gas is assumed to be
flared or consumed in field operations.
5.2.9.2
Operating Expenses and Capital Requirements
The estimated gross capital costs for this development have been based on the San Leon FDP dated
March 2008. We have modified this plan for the Triassic J North Lead best estimate case. Estimated
drilling and completion costs for the 2 long-term testing wells are US$7.0 million per well, while the
estimated development well cost is US$5.2 million per well. Development will be undertaken in three
phases as follows:
Phase
Phase I
Phase II
Phase III
Wells
Drilled
Capacity
(BOPD)
Transport
Method
002
323
000
05,000
50,000
50,000
Trucking
Trucking
Pipeline/Shipping
Page 27
76
It should be noted that Phase III commences prior to completion of Phase II, thereby permitting
suspension of trucking at rates less than 5,000 BOPD. Development costs by phase, in millions of United
States dollars (USMM$), are shown in the following table:
Phase
Phase I
Phase II
Phase III
Subtotal
Abandonment
Total
Facilities
Development Costs (USMM$)
Export
Wells
Company
Total
012.5
120.0
050.0
01.5
05.0
20.0
0,014.0
1,679.6
-
02.0
20.0
05.0
0,030.0
1,824.6
0,075.0
182.5
26.5
1,693.6
27.0
1,929.6
010.0
-
0,048.9
-
0,058.9
192.5
26.5
1,742.5
27.0
1,988.5
Gross abandonment costs are estimated to be US$58.9 million, which includes US$10.0 million for the
facilities and infrastructure, along with US$48.9 million for wells. The well abandonment costs are
estimated using US$150,000 per well and 325 wells. These abandonment costs are scheduled at the
end of the commercial life of the project. Gross operating expenses have been estimated to be
US$500,000 per month and are fixed for the life of the project. Variable costs are estimated to be
US$5,000 per month per well.
5.2.9.3
Development Scheduling
San Leon's FDP dated March 2008 envisions a three-phase development plan. We have modified this
plan for the Triassic J North Lead unrisked best estimate case. Phase I utilizes an early production
system, 2 long-term test wells, and trucking transport of crude oil. Phase II utilizes permanent production
facilities for full-field development drilling. Phase III involves the installation of permanent export facilities.
These facilities would comprise either installation of an oil export pipeline to established regional oil
storage and sales points or installation of onshore oil storage and export terminal facilities for tanker
loading.
We have assumed that Phase I investments will be made during 2009, with oil production from the first 2
wells commencing in July 2009 via truck transport. We have assumed that Phase II drilling will be
undertaken starting in 2011 and will proceed for 6 years until the end of 2016. A total of 6 rigs are
employed with each rig drilling and completing 1 well per month. The first 2 rigs will start operations in
mid-2011, 2 more rigs will start operations mid-2012, and 2 more rigs will start operations in mid-2013.
Each well is assumed to come on line one month after being drilled and completed. Phase II
infrastructure installation is assumed to occur during 2010 and 2011. Phase III infrastructure installation
is assumed to occur during 2012 and 2013.
5.2.9.4
Economics
We have prepared unrisked economics for the unrisked best estimate development case of the Triassic J
North Lead wherein 325 wells are expected to develop a combined 156 MMBBL of gross oil resources. A
summary projection of resources and cash flow is shown on Figure 46. Fiscal terms incorporated in our
scoping economics include a 30 percent working interest, an exempted volume with regard to the royalty
on oil production, and a 27 percent revenue interest on postexemption production. We have not included
provisions for production taxes, production sharing provisions, or income taxes for the Tarfaya exploration
permits.
Page 28
77
5.3
ZAG EXCLUSIVE RECONNAISSANCE LICENSE, ZAG-TINDOUF BASIN, MOROCCO
5.3.1
Summary
The Zag exclusive reconnaissance license is located in the Zag-Tindouf Basin of southern Morocco and
western Algeria and is the westernmost of the prolific hydrocarbon-producing Paleozoic basins of North
Africa, as shown on Figure 3. The Paleozoic and Triassic successions contain some 43 percent of the
known oil and 84 percent of the known gas reserves of the entire North African region, with more than
460 billion barrels of oil equivalent of recoverable hydrocarbons discovered in 350 separate
accumulations across this vast area (Casati et al., 2003). The Zag-Tindouf Basin is predominantly a gasprone hydrocarbon system. As such, the basin is poorly explored because historically it was considered
remote and lacking production and transportation infrastructure. Large gas discoveries in Algeria and
planned export gas pipelines to the European market have renewed interest in the Zag-Tindouf Basin.
The Zag-Tindouf Basin is interpreted to contain in excess of 8,000 meters of sediments. The central
portions of the basin are therefore expected to contain mature source rocks. A schematic southwestnortheast cross section through the axis of the basin illustrating basin depth and sedimentary fill is
illustrated on Figure 47. The cross section utilizes well data, 1960 coarse-grid gravity and magnetic data,
surface outcrop data, and satellite image interpretations to estimate basin and reservoir interval
thicknesses. There are no known seismic data to have been acquired over the Zag license area.
5.3.2
Data Sources
The Phase I reconnaissance studies completed by San Leon were compiled into a comprehensive report
entitled "Zag License: First Prospectivity Report". This report documents the drilling history, oil and gas
shows encountered by previous wells drilled along the basin margins, source rock geochemistry obtained
from diggings from water wells in the 50- to 100-meter depth range, and views on the petroleum system
and play concepts. Additional data included available well logs, well drilling summaries, and previous
industry reports.
5.3.2.1
Well Data
A total of 8 exploration wells have been drilled in the Zag license area, and an additional 4 wells were
drilled in the remainder of the Zag-Tindouf Basin of Morocco from 1961 to 1963. The well database
assembled by San Leon is summarized in the following table with the first 8 wells representing the historic
drilling on the Zag license; the Morcba-1, 2, and 3 wells were drilled to the north of the license area, and
the 7-1 well was drilled immediately to the east of the license area in Algeria.
Well
Operator
Drill
Date
Total Depth
(Meters)
Smara 17-1
Smara 17-2
Smara 17-3
El Mach 1-1
12-1
12-2
6-1
F1-3
Morcba-1
General American Oil of Spain
General American Oil of Spain
General American Oil of Spain
Phillips
Atlantic Exploration Company
Atlantic Exploration Company
Pan American
Gulf Oil
Empresa Minera del Sahara
1961
1961
1963
1962
1962
1962
1963
1961
1965
0,259
1,551
0,572
2,385
1,503
2,100
3,001
1,704
0,671
Morcba-2
Morcba-3
7-1
Empresa Minera del Sahara
Empresa Minera del Sahara
Tidewater
1965
1965
1962
0,841
0,706
3,333
Comments
Two additional core holes to 130 and 504 meters
Gas discovery, tested 0.3 million cubic feet per day
(MMCFD) of gas from 650 meters in the Silurian
Gas shows
Dry hole
Just east in Algeria
Page 29
78
5.3.2.2
Algeria - Tindouf Basin Exploration
The Zag-Tindouf Basin extends into Algeria where 13 wells were drilled between 1956 and 1971. Five
wells were drilled by British Petroleum (BP) from 1956 to 1964, and the most recent wells were drilled by
Sonatrach from 1968 to 1971. No log data or post-well summaries were available for these wells.
5.3.2.3
Algeria - Reggane Basin Exploration and Recent Activity
The Zag-Tindouf Basin of Morocco and western Algeria share a common tectonic and sedimentary
history with the Reggane Basin of south-central Algeria. Hercynian age basement high blocks allow for
separate basin designations, but in essence, the Tindouf and Reggane Basins are subbasins of the same
Paleozoic petroleum system that stretches from the Sirte and Murzuq Basins in Libya across the
Ghadames and Illizi Basins of east-central Algeria and the Ahnet, Reggane, and Tindouf Basins of
western Algeria (Figure 3).
Significant wells, discoveries, and resources estimates for which San Leon was able to obtain data and
that are in the Reggane Basin are summarized in the following table. We have not independently
conducted a reserves or resources assessment for the gas volumes or test rates reported below.
Therefore, we cannot confirm or endorse any estimates of field reserves or resources or the reservoir
data reported herein and provided by San Leon or to any press releases in the public domain, because
we have not had access to the data or performed an independent analysis of the on-trend discoveries or
field developments. The reported values summarized below were provided by San Leon and obtained
from various sources and should be considered only in terms of the possibility of an active petroleum
system for the Zag license that may or may not have similar structures, resources volumes, and
associated risks.
Operator
Drill
Date
Total Depth
(Meters)
CEP (now Total)
CEP (now Total)
CEP (now Total)
1957
1958
1964
3,272
2,584
3,158
Gas shows
Estimated original gas-in-place (OGIP) 133 BCF
Sonatrach
1980
3,000
Discovery well
Sonatrach
1980
3,510
Feidj El Had
FHD-1
Sonatrach
1995
1,628
Hassi M'Dakane
HDK-1
Sonatrach
1997
1,774
Azrafil
SE-1
Sonatrach
2000
4,042
Djebel Hirane/Kahal Tabelbala
DHKT-1
Sonatrach
2000
2,572
Kahal Tabelbala Nord
KTN-1
Reggane 5
Sonatrach
2003
2,938
Repsol YPF
2005
4,509
Kahlouche-2
Repsol YPF
2005
Below 3,983
Sali-1
Repsol YPF
2005
3,500
Tested 4.84 MMCFD of gas from Siegenian
above 3,300 meters
Tested 1.77 MMCFD of gas from Ordovician;
estimated OGIP 133 BCF; additional appraisal
well in 2004 resulted in lower estimated OGIP of
23 BCF
Tested 1.67 and 3.88 MMCFD of gas from Lower
Devonian Emsian and Gedinnian; estimated
OGIP 23 BCF
3.53 MMCFD of gas from Siegenian; 14.48 and
1.17 MMCFD of gas from 2 intervals in the
Gedinnian; estimated OGIP 150 BCF
Tested 15.2 MMCFD of gas from 21-meter gross
interval Siegenian sandstones; estimated OGIP
180 BCF
Tested 8.38 and 6.91 MMCFD of gas from Lower
Devonian Siegenian and Gedinnian sandstones
Tested gas from 2 reservoirs at rates up to 33
MMCFD; Repsol YPF confirmed Lower Devonian
tested 22.46 MMCFD of gas
Tested gas from Siegenian at 3,983 meters at a
rate of 26.9 MMCFD and for first time in basin
from Carboniferous below 2,360 meters at 17.2
MMCFD
Tested 3.5 MMCFD of gas from Lower Devonian
Field/Well
Kahlouche-1
Kahlouche-101
Reggane
R-102
Djebel Hirane
N-2
Tioulinine-1
Comments
Page 30
79
Both historic and recent exploration activity in the Reggane Basin have resulted in several gas
discoveries. BP made 2 gas discoveries in 1980 and Sonatrach drilled 10 wildcats from 1995 to 2005
with 6 reported gas discoveries. Estimates of discovered gas-in-place reported by Petroconsultants
through 2003 are 1.4 trillion cubic feet (TCF) of gas. Sonatrach's estimates through 2005 are 4.3 TCF of
gas-in-place.
During the 2003 Third International Licensing Round, Sonatrach licensed 2 blocks, 351c and 352c, to
Repsol YPF. Repsol YPF is reported to have drilled 13 wildcats with 5 gas discoveries. Sonatrach's
estimation of proved and probable reserves on the blocks is 2.8 TCF of gas. During the 2005 Sixth
International Licensing Round, the Djebel Reggane 328b, 352d, and 362d blocks were awarded to Shell.
5.3.3
Zag-Tindouf Basin Petroleum System
Throughout most of the Paleozoic era, North Africa was a single depositional basin on the northern shelf
of the African craton. The basin generally deepens to the north where deposition and marine influence
were greater. The regional stratigraphy is relatively continuous across North Africa, but petroleum
generation, migration, and entrapment within each subbasin is locally controlled by the tectonic and
sedimentary history of individual basins.
The age, lithostratigraphic subdivisions, bounding
unconformities, and major tectonic events controlling the Paleozoic sedimentary infill of the Zag-Tindouf
Basin are shown in the stratigraphic column on Figure 28 and are summarized below. A schematic cross
section of the main basin architecture is shown on Figure 47.
5.3.4
Tectonic History
The Paleozoic geology of the Zag-Tindouf Basin can be characterized by multiple episodes of tectonic
deformation resulting in basement high uplifts and crustal deformation followed by thermal subsidence
and basin infilling by terrestrial and marine clastics and marine carbonate deposition. The primary
tectonic events are identified from erosional unconformities occurring in six distinct tectonic cycles
summarized below:
1. Precambrian to Early Silurian: Pan-African orogeny resulting from compression and collision
between the West and East African cratons, leading to folding and faulting followed by an
erosional phase. Basin extension by transpressional faulting followed the early compression
stage.
The Late Ordovician period corresponded with widespread glacial events
accompanied by lowering sea level, followed by rising sea level during glacial retreat. The
sequence of deposition comprises an upward transition to coarse clastic sediments in
continental fluvial and shallow marine environments.
2. Silurian to Early Carboniferous: Mostly a basin sag phase with subsidence rates and sea
level changes controlling the depositional framework, including a widespread marine
transgression and deposition of the Silurian shale source rocks with an overall upward
transition to continental sediments in the Devonian that are the primary reservoir rocks. In
the Middle to Late Devonian, a sea-level rise corresponds to deposition of the Frasnian shale
source rocks and carbonate deposition. A mild compression stage in Late Devonian may
have resulted in deformation with associated uplift and erosion by the distal effects of the
Caledonian orogeny in Europe.
3. Middle to Late Carboniferous: The Hercynian orogeny marks a major tectonic event that
resulted in regional uplift, folding, faulting, and erosion of basement highs. Many of the
petroleum structural traps in North Africa were formed during this time and were charged with
hydrocarbons, primarily from Early Silurian age source rocks that were matured prior to the
Hercynian uplift. The structural highs that separate the North African Paleozoic basins were
also formed during this time.
Page 31
80
4. Permian to Triassic: A period of crustal extension and the opening of the ancestral Tethys
Ocean to the north and Atlantic Ocean to the west, which resulted in down-to-the-basin
faulting along the margins of the African craton, possibly causing minor reactivation of
previous faults within the Zag-Tindouf Basin. There is only very minor and localized
thickness of Mesozoic age sedimentary cover within the Zag-Tindouf Basin. The Zag-Tindouf
Basin and much of North Africa became essentially a passive, subaerially exposed
continental plate following the Hercynian orogeny.
5. Upper Cretaceous: Transtensional rifting (wrenching) with reactivation of older structures
causing localized uplift and erosion.
6. Eocene to Oligocene: Marked by crustal compression that initially resulted in uplift and
variable amounts of inversion of the Paleozoic basins and eventually to the collision of Africa
and Europe to form the High and Middle Atlas Mountains to the north. The Zag-Tindouf
Basin shows little or no effects from this orogenic event.
5.3.5
Hydrocarbon Source Rocks
Two major marine transgressions or flooding events are responsible for most of the known Paleozoic
hydrocarbon source rocks across North Africa: the first is the radioactive and organic-rich black shales of
the Lower Silurian, and the second is the calcareous shales of the Middle Devonian Frasnian. Minor and
more local source rocks are also possible within the Ordovician and Upper Devonian as well as Lower
Carboniferous. The Silurian hot shales are the primary source rock and are thought to have sourced
most of the discovered hydrocarbons in the Paleozoic basins of North Africa, with approximately 10
percent of the Paleozoic-derived hydrocarbons thought to be derived from the Devonian Frasnian
sources.
Basin assessments conducted by Occidental International Exploration & Production Company in 1990
used a database of approximately 40 wells in the Moroccan and Algerian portions of the Zag-Tindouf
Basin to evaluate the source rock maturity and hydrocarbon potential. The conclusions of this report
indicated the Silurian source interval is post-mature for oil and gas generation throughout the northern
half of the Zag-Tindouf Basin but appears to be mature with respect to gas across the remainder of the
basin.
5.3.6
Reservoir and Seal
Reservoir rocks in the Zag-Tindouf Basin may include Cambrian-Ordovician and Silurian-Devonian clastic
sediments deposited in a variety of continental, deltaic, and shallow marine environments. By analogy to
the Reggane Basin, the Siegenian and Gedinnian of the Lower Devonian comprise the primary reservoir
rocks with net pay thicknesses up to 50 meters contained within four layers of sandstone with a mean
porosity of 11 percent and permeability of 50 millidarcies (md). The Siegenian Formation from gas-tested
wells demonstrates porosity ranges from 4 to 19 percent and permeability from 0.1 to 100 md. The
Gedinnian Formation from gas-tested wells in the southeast part of the Reggane Basin has a mean
porosity of 8 percent and mean permeability of 10 md. Cambrian-Ordovician reservoirs are relatively tight
with porosity less than 5 percent. Reservoir quality is a primary exploration risk in the Zag-Tindouf and
Reggane Basins.
Tournaisian and Visean sandstone members of the Carboniferous period have also had reported oil
shows in the Reggane Basin with porosities of 10 to 20 percent and permeabilities of 10 to 100 md.
Transgressive anoxic shales and nonorganic shales deposited during relative high stands in sea level
may provide both a source of hydrocarbons and act as regionally extensive seals. Local seals may be
provided by evaporites and lacustrine to shallow marine shales deposited during relative low sea level
periods.
Page 32
81
5.3.7
Play Types
Structural traps in fault blocks and folded anticlines formed primarily during the Hercynian orogeny are the
primary play type. Analogous petroleum structural traps formed during this compressive event are
charged primarily from Early Silurian age source rocks that were matured prior to the Hercynian uplift.
Reservoirs are predominantly Devonian clastics with secondary objectives within clastic reservoirs of the
Cambrian, Ordovician, Carboniferous, and Silurian periods. Intraformational Paleozoic mudstones are
the primary seal rocks.
6.0
CONCLUSIONS_______________________________________________________________
We have conducted an assessment of the contingent resources for certain properties located offshore the
Netherlands and prospective resources for certain properties located in the United States and Morocco as
of September 1, 2008. Our assessments included the following: (1) estimation of contingent resources
and cash flow for Amstel Field located in the Q/13a Production License, offshore the Netherlands;
(2) estimation of unrisked prospective resources for 6 prospects in San Leon's acreage in the DJ Basin
located in Cheyenne County, Nebraska, United States; (3) estimation of unrisked prospective resources
for 15 leads in the Tarfaya exploration permits located in the Tarfaya-Laayoune Basin, onshore Morocco;
and (4) description of the petroleum system and potential play types in the Zag exclusive reconnaissance
license.
We conducted a review of the leads and prospects identified by San Leon and its technical consultants
and independently verified or interpreted the probability ranges associated with prospect area, reservoir
thickness, reservoir rock and fluid parameters, and recovery factors. The available 2-D or 3-D seismic
data were integrated, where available, with available on-trend production and reservoir data or by analogy
to reservoirs with similar depositional environments. We estimated original hydrocarbons-in-place and
recoverable hydrocarbon volumes for the contingent and prospective resources using a spreadsheetbased Monte Carlo simulation model. The spreadsheet-derived estimates are based on probability
distributions of reservoir variables input into the Monte Carlo simulation. Scoping economic analysis for a
single representative lead in the Tarfaya exploration permits was conducted as an indication of cost
recovery for development in the event of a hydrocarbon discovery.
The petroleum system of the Zag license is based on reconnaissance surface and subsurface
interpretations conducted by San Leon or its consultants and available industry reports. We have not
estimated prospective resources for the Zag license because of its immature stage of evaluation and the
general absence of subsurface well and seismic data from which to delineate prospects or leads. Also,
we have not conducted an assessment of the oil shale reservoirs located within the Tarfaya permit area.
The data provided for Amstel Field, the DJ Basin prospects, and Tarfaya leads were independently
interpreted to derive our estimates of in-place volumes and contingent and prospective resources.
The contingent and prospective resources shown in this report have been estimated using a combination
of deterministic and probabilistic methods. The probability that the quantities of oil and gas actually
recovered will equal or exceed the estimated amounts is at least 90 percent for the low estimate, at least
50 percent for the best estimate, and at least 10 percent for the high estimate. Contingent resources are
categorized as 1C for the low estimate, 2C for the best estimate, and 3C for the high estimate.
Prospective resources are subclassified as plays, leads, or prospects; such subclassification reflects
increasing project maturity. Prospective resources associated with leads and prospects are categorized
as low, best, and high estimates. As recommended in the 2007 PRMS, the prospective resources have
been aggregated by arithmetic summation for each lease or permit area. It should be noted that the
prospective resources volumes herein are dependent upon successful exploration for hydrocarbons.
Page 33
82
FIGURES
83
Figure 1
84
1,250 2,500
5,000
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Modified after a figure provided by San Leon Energy Plc.
0
SCALE IN METERS
Location Map
Amstel Field
Q/13 Production License, Offshore the Netherlands
Figure 2
FRANZEN
13
1
1 REXROTH
1
SCHMALE
18
SCHMALE
1
1
17
ST OF NEBR
0
STATE
SCALE IN FEET
36
1
1,250 2,500
STATE
5,000
1 BLOCK
1
BLOCKTREMAIN
1
31
32
29
A
SCHMALE
16
1
33
28
LEE
B
Niobrara
Prospect
1
21
T15 N
1
43-33
34
27
22
San Leon
Lease Area
1
R47 W
1
14
1
35
26
23
100
113
1
36
1
A
TAY
TAYLOR
STATE
1-A
25
1WURTELE,
CARL
MARKEL,
EUGE
MA
3-D Seismic
Survey Area
WURTELE
1
RUS
MILLER,
FLOYD
1
24
DYKMAN
WURTELE
1
FLORKE
MILLER, FLOYD
BORGES, MILLER
CG 1 1
MILLER, FLOYD
MILLER, 1G
FLESSNER, D
BORGES
1
LUDEMAN 1
1
HAXBY
FLESSNER
15
HAXBY, W C
HOAGLAND
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
1 WITTROCK 44-32
FRANZEN
1
FRANZEN
4
JOHNSON, A M 1
FRANZEN
2
JOHNSON, LEMOYNE
FRANZEN
3
MAN
1
FRANZEN
1
FRANZEN
1
TREMAIN 30-1
ANZEN
2 25 2
FRANZEN
30
MON
2
FRANZEN
4
1
Near
ANZEN
3
TREMAIN 1
SON
1 NEBR "B" 2
ST OF
Franzen 2
1
BLOCK 1
ON 2
RANZEN
1
FRANZEN
1
COOK, M
3
FLESSNER
1 Near
COOK 24
4
OOK, M 2
Franzen 1 19
SCHMALE 2023-20
23-1
SNER
4
PEARSON 1
100
ER
1
COOK 1
SCHMALE HOAGLUND
20-1
2
NCK
1FRANZEN 25-1
1
GEUJOHNSON
1
1
REXROTH
1-A
Modified after http://quickfacts.census.gov/qfd/maps/nebraska_map.html.
Plugged Oil Well
Location
Dry Hole with Oil Show
Dry Hole
Abandoned Oil Well
Legend
NS
Location Map
DJ Basin Lease Area
Cheyenne County, Nebraska, United States
100
100
300
300
200
200
85
Figure 3
86
Reggane Basin
REPSOL ~ 3 discoveries
Kahlouche-2 well (tested 44 MMCFD)
May 2006
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Modified after a figure provided by San Leon Energy Plc.
Tindouf-Reggane Basin
SONATRACH ~ Total Joint Basin
Zag Exclusive
Reconnaissance License
(21,807 km2)
Daora Prospect
Cap Juby Field
Tarfaya Exploration
Permits
(13,434 km2)
Location Map
Tarfaya Exploration Permits and Zag Exclusive Reconnaissance License
Within the Northwest African Petroleum System
Figure 4
87
Q/13-2
Q/13-8
Q/13-1
Q/13-9
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Modified after a figure provided by San Leon Energy Plc.
Q/13-7
Amstel Field
0
250
500
1,000
SCALE IN METERS
Contour Interval: 20 meters
Depth Structure
Top Amstel (Rijswijk)
Sandstone
Q/13a Production License, Offshore the Netherlands
Stratigraphic Column
West Netherlands Basin Area
Figure provided by San Leon Energy Plc.
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
88
Figure 5
Type Log – Q/13-8 Well
Amstel Field
Q/13a Production License, Offshore the Netherlands
Amstel
(Rijswijk)
Sandstone
(From R. Kuijper, 1994)
Modified after a figure provided by San Leon Energy Plc.
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
89
Figure 6
Figure 7
90
Q/13-2
Q/13-8
Q/13-1
Q/13-9
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Modified after a figure provided by San Leon Energy Plc.
Q/13-7
0
250
500
1,000
SCALE IN METERS
Contour Interval: 20 meters
Depth Structure with Amplitude
Top Amstel (Rijswijk)
Sandstone
Q/13a Production License, Offshore the Netherlands
Amstel Field
41.014
-3746.855
-3595.341
-3443.826
-3292.311
-3159.736
-3008.221
-2856.706
-2724.131
-2572.616
-2421.101
-2288.526
-2137.011
-1985.496
-1833.981
-1701.406
-1549.891
-1398.376
-1265.801
-1114.286
-962.771
-830.186
-678.681
-527.167
-394.591
-243.076
Figure 8
91
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Amstel (Rijswijk)
Sandstone
Lower Vlieland
Shale
Intermediate
Marker
Top Amstel
(Rijswijk)
Sandstone
Base Ommelanden
Chalk
Time-Domain Seismic Line 1475
Amstel Field
Q/13a Production License, Offshore the Netherlands
Base North Sea
Group
92
93
94
Figure 12
95
6
10
5
10
2005
2006
2007
2008
2009
RESOURCES
START: 1/2010
2012
2013
2014
2015
2016
2017
2022
NO: 000001
AC:
2011
2018
2019
2020
2021
2023
2024
2
9
8
7
6
5
4
3
2
2
104 9
8
7
6
5
4
3
2
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
103
3
3
6
6
4
7
7
5
8
8
4
9
9
2010
2
4
5
2
0- 0- 0
3
RIJSWIJK
6
3
4
5
6
7
8
7
9
1C TYPE WELL
AMSTEL
,
8
LEASE:
FIELD:
CNTY, ST:
OPERATOR:
ZONE:
ID:
9
5
OIL - BBLS/MO.
Figure 13
96
6
10
5
10
2005
2006
2007
2008
2009
RESOURCES
START: 1/2010
2012
2013
2014
2015
2016
2017
2022
NO: 000001
AC:
2011
2018
2019
2020
2021
2023
2024
2
9
8
7
6
5
4
3
2
2
104 9
8
7
6
5
4
3
2
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
103
3
3
6
6
4
7
7
5
8
8
4
9
9
2010
2
4
5
2
0- 0- 0
3
RIJSWIJK
6
3
4
5
6
7
8
7
9
2C TYPE WELL
AMSTEL
,
8
LEASE:
FIELD:
CNTY, ST:
OPERATOR:
ZONE:
ID:
9
5
OIL - BBLS/MO.
Figure 14
97
6
10
5
10
2005
2006
2007
2008
2009
RESOURCES
START: 1/2010
2012
2013
2014
2015
2016
2017
2022
NO: 000001
AC:
2011
2018
2019
2020
2021
2023
2024
2
9
8
7
6
5
4
3
2
2
104 9
8
7
6
5
4
3
2
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
103
3
3
6
6
4
7
7
5
8
8
4
9
9
2010
2
4
5
2
0- 0- 0
3
RIJSWIJK
6
3
4
5
6
7
8
7
9
3C TYPE WELL
AMSTEL
,
8
LEASE:
FIELD:
CNTY, ST:
OPERATOR:
ZONE:
ID:
9
5
OIL - BBLS/MO.
Stratigraphic Column
DJ Basin
Figure taken from http://www.oiltrash.com/trashtools/Strats/Nebraska.htm.
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
98
Figure 15
596,000
99
4
586,000
1
Legend
TREMAIN
1
Location
Dry Hole
Abandoned Oil Well
36
2
1
1
1
BLOCK
1
SCHMALE
-2 5
29
SCHMALE
23-20
20
A Prospect
1,108,750
30
30-1
NTREMAIN
ear Franzen
2 Prospect
JOHNSON, LEMOYNE
JOHNSON, A M
1 JOHNSON
PEARSON
19
1
20-1
SCHMALE
1
HOAGLUND
1
200
28
1,118,750
HOAGLAND
1,118,750
B Prospect
21
T15 N
20
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
ATE
4
GEU
Near Franzen 1 Prospect
2
ST OF NEBR "B"
N
ANZEN
N FRANZEN
1
25 1
3
FRANZEN
2
FRANZEN
1
1
-3 025-1
FLESSNER
24
4
1
FRANZEN
RANZEN
RANZEN
0
2
3
COOK
M
1
RANZEN
1
0
100
FRANZEN
SCHMALE
1,108,750
0
1
FLESSNER
5
1
00
-3
LUDEMAN 1
300
-
26
0
30
23
1
0
Cheyenne County, Nebraska, United States
1,250
2,500
SCALE IN FEET
5,000
Contour Interval: 10 feet
Depth Structure
Top D Sand
10
WURT
1,128,750
FLESSNER, D
1,128,750
DJ Basin Lease Area
-2
Ludeman 1
27
22
R47 W
0
00
596,000
586,000
Figure 16
Time (milliseconds)
S
Wolfcamp
80
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
1,500
1,400
1,300
1,200
60
3
1
TATE
1
30
36
2
3
FRANZEN
25-1
1
4
TREMAIN
1
BLOCK
TREMAIN
1
GEU
30
30-1
1
30 0
1
-2
5
JOHNSON, LEMOYNE
1
-25 0
-
JOHNSON
PEARSON
JOHNSON, A M
1
19
Top D Sand
251
FRANZEN
ST OF NEBR "B"
2
24
FLESSNER
1
FRANZEN
FRANZEN
2
4
RANZEN
1
FRANZEN
4
1
COOK
FRANZEN
0
M
FRANZEN
FRANZEN
Lyons
0
1,100
40
-
0
SCHMALE
1
SCHMALE
29
23-20
SCHMALE
20
20-1
100
1
HOAGLUND
SCHMALE
- 3 00
1
D Sand
- 30 0
28
21
-3 0 0
T15 N
-3
0
0
HOAGLAND
1
FLESSNER
27
22
R47 W
Niobrara
20
1,000
Trace
200
Time-Domain Seismic Line 190
DJ Basin
Cheyenne County, Nebraska, United States
100
00
-2
1
50
300
100
5
-2 0
2 50
- 30 0
-
-3
26
23
-2
FLESSNER, D
50
Figure 17
300
-1 5 0
1
WUR
10
120
N
1,500
1,400
1,300
1,200
1,100
1,000
2
EN
2
251
596,000
101
586,000
36
4
TREMAIN
1
Location
Dry Hole
Abandoned Oil Well
Legend
3
FRANZEN
25-1
1
BLOCK
TREMAIN
1
GEU
30-1
30
JOHNSON, A M
1
1
1
JOHNSON
PEARSON
19
1
1,108,750
JOHNSON, LEMOYNE
1
SCHMALE
29
23-20
SCHMALE
20
Niobrara
Prospect
1
20-1
SCHMALE
1
HOAGLUND
1
200
28
21
T15 N
200
1,118,750
HOAGLAND
1,118,750
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
1
2
FRANZEN
FRANZEN
24
FLESSNER
OF NEBR "B"
N
1
EN
1
FRANZEN
4
OK
ZEN
1
100
FRANZEN
SCHMALE
1,108,750
1
LUDEMAN 1
300
26
23
1
1,128,750
FLESSNER, D
Cheyenne County, Nebraska, United States
DJ Basin Lease Area
1
300
0
1,250
2,500
SCALE IN FEET
5,000
Seismic Amplitude Anomaly
Niobrara
27
22
FLESSNER
R47 W
1,128,750
596,000
586,000
Figure 18
4
596,000
102
2
251
586,000
Legend
4
0
TREMAIN
10
0
1
1
Location
Dry Hole
Abandoned Oil Well
36
3
FRANZEN
25-1
1
BLOCK
TREMAIN
1
GEU
1
150
30
JOHNSON, A M
30-1
5
1
JOHNSON
1
0
1 0
PEARSON
19
1
1,108,750
Dune West
Prospect
JOHNSON, LEMOYNE
1
1 50
150
100
SCHMALE
50
23-20
29
SCHMALE
10 0
20
20-1
1 00
SCHMALE
1
50
100
HOAGLUND
00
1
1
150
28
0
50
21
T15 N
200
10
50
1,118,750
00
50
HOAGLAND
100
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
1
2
FRANZEN
FRANZEN
00
24
FLESSNER
ST OF NEBR "B"
TATE
4
FRANZEN
1
FRANZEN
2
FRANZEN
1
1
COOK
3
FRANZEN
0
M
FRANZEN
1
0
0
10
0
5
200
1
1
5
1
50
10 0
50
1
300
1 00
LUDEMAN 1
50
1 5
0
26
23
FLESSNER, D
WUR
10
1,128,750
1
1,128,750
DJ Basin Lease Area
300
0
1,250
2,500
SCALE IN FEET
5,000
Contour Interval: 10 feet
Lyons Sand Isopach
Cheyenne County, Nebraska, United States
Ludeman 1
27
5
22
50
FLESSNER
R47 W
0
FRANZEN
100
SCHMALE
0
1,118,750
1
1,108,750
1
1 50
1
50 00
0
50
LUDEMAN 1
596,000
586,000
Figure 19
88
TA
12
A 02
87TA 04
87T
87TA 06
88
TA
88
TA
17
-1
15
E
1
A0
87T
87TA 01W
2
87TA 05W
87T
A0
9
TA
87
1
06
88
LA
A 02
88
LA
87L
88
LA
88
LA
04
88
LA
88
LA
17
13
03
05
07
09
11
88
LA
12
88
LA
10
88
LA
08
88
LA
06
88
LA
88
LA
13
01
88
LA
88
LA
15
A 11
88
TA
16
88T
88
TA
87TA 03W
87TA 05W
87TA 07W
Tarfaya Exploration Permits
Tarfaya-Laayoune Basin, Morocco
2-D Seismic Coverage
SCALE IN METERS
0
12,500
25,000
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
103
50,000
Figure 20
J
Puerto
Cansado
D
C
Daora North
Daora
I
F
G
B
Tarfaya Exploration Permits
Tarfaya-Laayoune Basin, Morocco
Depth Structure
Near Top Jurassic
Contour Interval: 100 meters
SCALE IN METERS
0
12,500
25,000
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
104
50,000
Figure 21
Tarfaya Exploration Permits
Tarfaya-Laayoune Basin, Morocco
Regional Average Velocity to
Near Top Jurassic
Contour Interval: 25 meters/second
SCALE IN METERS
0
12,500
25,000
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
105
50,000
Figure 22
Tarfaya Exploration Permits
Tarfaya-Laayoune Basin, Morocco
Isochron
Near Top Jurassic to
Near Top Triassic
Contour Interval: 50 milliseconds
SCALE IN METERS
0
12,500
25,000
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
106
50,000
Figure 23
Puerto Cansado
J South
J North
Daora
K
Tarfaya Exploration Permits
Tarfaya-Laayoune Basin, Morocco
Depth Structure
Near Top Triassic
Contour Interval: 250 meters
SCALE IN METERS
0
12,500
25,000
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
107
50,000
Figure 24
108
Figure 26
109
TARFAYA
N'DARK
TMT-1
RR-1
AF-4
TE-2
OIL PRODUCTION
GAS PRODUCTION
GAS SHOWS
OIL SHOWS
200Km
KAT-1
OUJDA
HARICHA
MEDITERRANEAN
SEA
OLM-9
CASABLANCA
OYF-1
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Modified after a figure provided by San Leon Energy Plc.
DAKHLA
JEER
ZELTEN
LAYOUNE
CAP JUBY
SIDI RHALEM
TOUKIMT
MESKALA
KECHOULA
NRT-5
LOT-1
ONZ-2 ONZ-1
OKT-1
On-Trend Discoveries
Onshore and Offshore Morocco
Cap Juby Field Play Types
Offshore Morocco
1350
1250
1150
1050
MO-2
CJ-1
950
850
750
650
550
450
400
500
Base Tertiary
1,000
Top Tan Tan
(Lower Cretaceous)
1,500
2,000
Top Jurassic
Initial drift
(Jurassic aggradation carbonate bank)
2,500
Main drift
(Early Cretaceous progradation –
distant Atlantic rifting events)
Compression events
(Tertiary progradation proximal Atlas tectonism)
Initial drift
(Jurassic aggradation carbonate bank)
Jurassic
source rocks
Modified after Cameron et al., 2007.
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
110
Figure 27
111
Figure 29
112
Basement
Seismic Line 88LA03
Puerto Cansado-1
(Projected)
Paleozoic
0
El Amra-1
Seismic Line 88TA15
10
SCALE IN KILOMETERS
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Triassic
Middle and Lower Jurassic
Upper Jurassic
Lower Cretaceous
Upper Cretaceous
Modified after a figure provided by San Leon Energy Plc.
Tertiary
Channels
Daora-1
NW
Atlantic
Coast
Representative Cross Section
Tarfaya-Laayoune Basin, Morocco
SE
6
5
4
3
2
1
0
Depth in km
Figure 30
113
Subsurface Depth (m)
7000
6000
4000
2000
0
200
Age (my)
Age (million years)
100
50
Pal
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
150
Main Gas Generation
1.3 to 2.6 (%Ro)
Late Mature (oil)
1 to 1.3 (%Ro)
Mid Mature (oil)
0.7 to 1 (%Ro)
K
Jurassic Depocenter
Tarfaya-Laayoune Basin, Morocco
Early Mature (oil)
0.5 to 0.7 (%Ro)
J
Modified after a figure provided by San Leon Energy Plc.
Depth Subsurface (m)
N
U. Triassic
L. Jurassic
M. Jurassic
U. Jurassic
Tan Tan F
Aguidir F
TERTIARY
0 t=0
Q
H Fm
Figure 31
114
Middle Jurassic
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Base Triassic
Triassic
Jurassic
Cretaceous
Time-Domain Seismic Dip Line 88TA13
Northern Regional Line
Tarfaya-Laayoune Basin, Morocco
Depth Structure
Near Top Jurassic
Syn- and PostRift Sediment
Wedge
Figure 32
115
Base Triassic
Triassic
Middle Jurassic
Jurassic
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Downlapping Ramp
Carbonates
Shelf
Carbonates
Tertiary Canyon
Time-Domain Seismic Dip Line 88LA07
Southern Regional Line
Tarfaya-Laayoune Basin, Morocco
Depth Structure
Near Top Jurassic
Cretaceous
Figure 33
116
Base Triassic
Triassic
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Daora
Tertiary Canyon
Time-Domain Seismic Dip Line 88LA03
Daora Lead, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Middle Jurassic
Jurassic
Cretaceous
Depth Structure
Near Top Jurassic
Figure 34
117
Base Triassic
Triassic
Middle Jurassic
Jurassic
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Daora North
Time-Domain Seismic Dip Line 88LA01
Daora North Lead, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Cretaceous
Depth Structure
Near Top Jurassic
Figure 35
118
Cretaceous
Base Triassic
Triassic
Middle Jurassic
Jurassic
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Daora
I
Daora North
Tertiary Canyon
Time-Domain Seismic Strike Line 87LA02
Daora, Daora North, and I Leads, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Depth Structure
Near Top Jurassic
Figure 36
119
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Modified after a figure provided by San Leon Energy Plc.
N
Daora
Triassic
Lead
Gravity and Magnetic Data with Daora Triassic Lead
Tarfaya-Laayoune Basin, Morocco
0
25
50
SCALE IN KILOMETERS
Figure 37
120
J North
Cretaceous
J South
Jurassic
Middle Jurassic
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Base
Triassic
Triassic
J
Time-Domain Seismic Dip Line 88TA17-1
J, J North, and J South Leads, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Depth Structure
Top Triassic
Figure 38
121
Base Triassic
Triassic
Puerto Cansado
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Depth Structure
Near Top Jurassic
Middle Jurassic
Jurassic
Time-Domain Seismic Dip Line 87TA03W
Puerto Cansado Lead, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Figure 39
122
C
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Triassic
Cretaceous
Time-Domain Seismic Dip Line 88LA13
C Lead, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Middle Jurassic
Jurassic
Depth Structure
Near Top Jurassic
Figure 40
123
F
G
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Depth Structure
Near Top Jurassic
Cretaceous
Time-Domain Seismic Dip Line 88LA05
F and G Leads, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Triassic
Middle Jurassic
Jurassic
Figure 41
124
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Depth Structure
Near Top Jurassic
G
Time-Domain Seismic Strike Line 88LA10
G Lead, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Base Triassic
Triassic
Middle Jurassic
Jurassic
Cretaceous
Figure 42
125
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Depth Structure
Top Triassic
K
Time-Domain Seismic Dip Line 88LA07
K Lead, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Base Triassic
Triassic
Middle Jurassic
Jurassic
Figure 43
126
B
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Triassic
Middle Jurassic
Jurassic
Cretaceous
Time-Domain Seismic Strike Line 88LA12
B Lead, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Depth Structure
Near Top Jurassic
Figure 44
127
Triassic
Middle Jurassic
Jurassic
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Depth Structure
Near Top Jurassic
Cretaceous
D
Time-Domain Seismic Dip Line 87TA05W2
D Lead, Tarfaya License Area
Tarfaya-Laayoune Basin, Morocco
Figure 45
128
4
10
3
10
2006
2007
2008
2009
2010
2013
2014
2015
2016
2017
2018
2023
NO: 000400
AC: 000400
2011
2012
2019
2020
2021
2022
2024
2025
2
9
8
7
6
5
4
3
2
2
102 9
8
7
6
5
4
3
2
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
101
3
3
6
6
4
7
7
5
8
8
4
9
9
2
4
5
2
0- 0- 0
3
TRIASSIC
6
7
3
4
5
6
7
8
TYPE WELL
J NORTH LEAD
,
9
LEASE:
FIELD:
CNTY, ST:
OPERATOR:
ZONE:
ID:
8
RESOURCES
START: 7/2011
9
5
OIL - BBLS/MO.
129
Figure 47
130
All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Modified after a figure provided by San Leon Energy Plc.
SW
Representative Cross Section
Zag-Tindouf Basin, Morocco
NE
REFERENCES
131
REFERENCES
Casati, L. and J. Craig, 2003, Paleozoic and Triassic Petroleum Systems in North Africa, presented at AAPG
Hedberg Conference, February 2003.
Dyni, J.R., 2006, Geology and Resources of Some World Oil-Shale Deposits, U.S. Geological Survey Scientific
Investigations Report 2005-5294, 42 p.
Kolonic, S., T. Wagner, A. Forster, J.S. Sinninghe Damsté, B. Walsworth-Bell, E. Erba, S. Turgeon, H. Brumsack,
E. Chellai, H. Tsikos, W. Kuhnt, and M. Kuypers, 2005, Black shale deposition on the northwest African Shelf
during the Cenomanian/Turonian oceanic anoxic event: Climate coupling and global organic carbon burial,
Paleoceanography, Volume 20, PA1006.
Otis, R.M. and N. Schneidermann, 1997, A Process for Evaluating Exploration Prospects, AAPG Bulletin,
Volume 81, Number 7, pages 1087-1109.
Weber, K.J. and M. Baker, 1981, Fracture and Vuggy Porosity, Paper SPE 10332, presented at SPE Annual Fall
Technical Conference and Exhibition, San Antonio, TX, October 1981.
Youngquist,
W.,
2000,
Survey
http://www.energybulletin.net/5600.html.
of
Energy
132
Resources:
Oil
Shale,
Energy
Bulletin:
PART V
A. FINANCIAL INFORMATION ON THE GROUP
San Leon Energy plc
Wilton Park House
Wilton Place
Dublin 2
Daniel Stewart & Co. Plc
Becket House
36 Old Jewry
London EC2R 8DD
23 September 2008
Dear Sirs,
San Leon Energy plc (‘‘San Leon’’ or the ‘‘Company’’)
We report on the financial information for the period from 1 January 2005 to 31 December 2007 set out
in Part VA of the Admission Document of San Leon Energy plc, dated 23 September 2008
(the ‘Admission Document’).
This report is required by Schedule 2 of the Rules of the AIM Rules for Companies (“AIM Rules”) and
is given for the purpose of complying with those paragraphs and for no other purpose.
Responsibilities
The Directors of the Company are responsible for preparing the financial information on the basis of
the accounting policies set out in paragraph 6 of the financial information and in accordance with
applicable Irish law and International Financial Reporting Standards (“IFRS”). It is our responsibility
to form an opinion on the financial information as to whether the financial information gives a true and
fair view for the purposes of the Admission Document and to report our opinion to you.
Save for any responsibility arising under Schedule Two of the AIM Rules to any person as and to the
extent therein provided, to the fullest extent permitted by the law we do not assume any responsibility
and will not accept any liability to any other person for any loss suffered by any such other person as a
result of, arising out of, or in connection with this report or our statement, required by and given solely
for the purposes of complying with Schedule Two of the AIM Rules consenting to its inclusion in the
Admission Document.
Basis of opinion
We conducted our work in accordance with the Standards for Investment Reporting issued by the
Auditing Practices Board. Our work included an assessment of evidence relevant to the amounts and
disclosures in the financial information. It also included an assessment of the significant estimates and
judgments made by those responsible for the preparation of the financial information and whether the
accounting policies are appropriate to the Company’s circumstances, consistently applied and
adequately disclosed.
We planned and performed our work so as to obtain all the information and explanations which we
considered necessary in order to provide us with sufficient evidence to give reasonable assurance that
the financial information is free from material misstatement whether caused by fraud or other
irregularity or error.
133
Opinion
In our opinion, the financial information gives, for the purposes of the Admission Document dated
23 September 2008, a true and fair view of the state of affairs of San Leon and of its consolidated losses,
cash flows and recognised income and expense for the three year period ended 31 December 2007 in
accordance with the accounting policies set out in paragraph 6 of the financial information and in
accordance with applicable Irish law and International Financial Reporting Standards.
Declaration
For the purposes of Schedule 2 of AIM Rules we are responsible for this report as part of the Admission
Document and declare that we have taken all reasonable care to ensure that the information contained
in this report is, to the best of our knowledge, in accordance with the facts and contains no omission
likely to affect its import. This declaration is included in the Admission Document in compliance with
Schedule 2 of the AIM Rules.
Yours faithfully,
LHM Casey McGrath
Chartered Certified Accountants
6 Northbrook Road,
Dublin 6.
134
1.
Consolidated Income Statement
For the three years ended 31 December 2007
Notes
Turnover
Administrative Expenses
2007
€
2006
€
2005
€
—
(318,225)
—
(8,762)
—
(2,852)
(8,762)
9
464,311
—
(2,852)
9
—
—
(2,843)
—
Operating Loss
Finance Income
(Loss)/Profit on disposal of financial assets
Finance Expenses
5.4
(318,225)
3,196
(28,262)
(732)
(Loss)/Profit on ordinary activities before tax
Income tax expense
5.1
5.5
(344,023)
260
455,558
—
Profit and loss account at beginning of year
(343,763)
(335,704)
455,558
(791,262)
(2,843)
(788,419)
Profit and loss account at end of year
(679,467)
(335,704)
(791,262)
Loss per ordinary share – basic & diluted
5.3
5.6
135
€(0.02)
€309.70
€(0.02)
2.
Consolidated Balance Sheet
As at 31 December
Non Current Assets
Property, plant and equipment
Intangible assets
Notes
2007
€
2006
€
2005
€
5.8
5.7
6,511
26,111,695
—
—
—
—
26,118,206
—
—
—
174,775
11,901
650,839
3,566
1,637
186,529
13,753
586
186,676
656,042
200,868
26,304,882
656,042
200,868
11,250,685
15,160,376
(679,468)
1,868
974,197
(335,704)
1,868
974,197
(791,262)
25,731,593
640,361
184,803
573,288
15,681
16,065
26,304,882
656,042
200,868
Total non current assets
Current assets
Financial assets
Trade and other receivables
Cash and cash equivalents
5.9
5.10
Total assets
Equity and liabilities
Capital and reserves
Issued share capital
Share premium account
Retained earnings
Total equity attributable to equity
Holders of the company
Current liabilities
Trade and other payables
5.13
5.11
Total equity and liabilities
136
3.
Consolidated Statement of Changes in Equity
As at 31 December
Notes
Share
Capital
€
Share
premium
account
€
Retained
earnings
€
Total
€
At 1 January 2005
Loss for the year
5.13
1,868
—
974,197
—
(788,419)
(2,843)
187,646
(2,843)
At 31 December 2005
Loss for the year
5.13
1,868
—
974,197
—
(791,262)
455,558
184,803
455,558
At 31 December 2006
Shares issued
Bonus shares issued
Share issue costs
Profit for financial year
5.13
1,868
227,010
11,021,807
—
—
974,197
25,238,991
(11,021,807)
(31,005)
—
(335,704)
—
—
—
(343,763)
640,361
25,466,001
—
(31,005)
(343,763)
At 31 December 2007
5.13
11,250,685
15,160,376
(679,467)
25,731,594
137
4.
Consolidated Cash Flow Statement
For the three years ended 31 December 2007
Notes
Cash flows from operating activities
Profit/(loss) for the year
Finance costs recognised in profit/loss
Investment revenue recognised in profit/loss
Loss/(profit) on sale of investment
Depreciation of non-current assets
5.2
5.4
5.3
2007
€
2006
€
2005
€
(344,023)
732
(3,196)
28,262
2,171
455,558
—
(9)
(464,311)
—
(2,843)
—
(9)
—
—
(316,054)
(8,762)
(2,852)
(173,801)
557,607
—
(11,225)
1,802
1,050
67,752
(732)
2,851
(19,987)
—
1,042
—
—
—
69,871
(18,945)
—
(216,891)
839,468
3,196
(344,377)
(8,682)
(976,850)
—
—
9
19,987
—
—
—
—
9
—
—
—
(704,136)
19,996
9
Cash flows from financing activities
Proceeds from issues of equity shares
Payment for share issue costs
675,534
(31,005)
—
—
—
—
Net cash generated in financing activities
644,529
—
—
Net increase in cash and cash equivalents
Cash and cash equivalents at start of year
10,264
1,637
1,051
586
9
577
Cash and cash equivalents at end of year
11,901
1,637
586
5.8
Movements in working capital
(Increase) in trade and other receivables
Increase/(decrease) in trade and other payables
Cash generated from operations
Interest paid
Corporation and income tax refunds
5.4
Net cash generated/(used) by operating activities
Cash flows from investing activities
Payments to acquired financial assets
Proceeds on the sale of financial assets
Investment income received
Amounts advanced to related parties
Payments for property, plant and equipment
Payments for intangible assets
5.3
5.8
Net cash (used)/generated by investing activities
138
5.
5.1
Notes to the financial statements
Segmental analysis
The Group is engaged in one business segment only, oil and gas exploration therefore only an
analysis by geographical segment has been presented. Prior to 31 December 2006, all activity was
located at the Group head office in Ireland.
Following the commencement of oil and gas exploration activity in 2007, the Group has
geographic segments in Africa and America in addition to the head office operation n Ireland.
The segment results for the year ended 31 December 2007 are as follows:
Africa
€
America
€
Head Office
€
Group
€
Segment result before tax
Income tax
—
—
—
—
(344,023)
260
(344,023)
260
Loss for the year
—
—
(343,763)
(343,763)
The segment assets and liabilities at 31 December 2007 and capital expenditure for the year then
ended are as follows:
Africa
€
5.2
Group
€
25,769,684
(318,538)
497,580
(31,806)
37,618
(222,944)
26,304,882
(573,288)
Net assets
25,451,146
465,774
(185,326)
25,731,594
Capital exploration
25,614,115
497,580
—
26,111,695
2007
€
2006
€
2005
€
2,171
656
80,000
11,039
6,000
—
—
—
—
4,840
—
—
—
—
2,638
2007
€
2006
€
2005
€
78
3,118
9
—
9
—
3,196
9
9
2007
€
2006
€
2005
€
732
—
—
Profit on ordinary activities before tax
Finance income
Deposit interest income
Dividend income
5.4
Head Office
€
Segment assets
Segment liabilities
The profit on ordinary activities before taxation
is stated after charging:
Depreciation of tangible assets
Loss on foreign currencies
Directors benefits
Directors pension
Auditor’s remuneration
5.3
America
€
Finance expenses
Bank interest and charges
139
5.5
Taxation on ordinary activities
2007
€
5.6
2005
€
The charge based on the profit on ordinary
activities comprises:
Overprovision in prior year
(260)
—
—
Current tax credit for the year
(260)
—
—
Loss per share
The calculation of basic loss per ordinary share is based on the loss per year and the average
number of ordinary shares in issue during the relevant year as set out below. There is no difference
between the diluted loss per share and the basic loss per share.
2007
€
Profit / loss for the year
(343,763)
Weighted average number of shares
18,629,615
2006
€
455,558
1,471
2005
€
(2,843)
1,471
€(0.02)
€309.70
Africa
€
America
€
Total
€
Cost
At 31 December 2005 and 31 December 2006
Additions
Acquisition of San Leon Morocco Ltd
—
479,270
25,134,845
—
497,580
—
—
976,850
25,134,845
At 31 December 2007
25,614,115
497,580
26,111,695
Provision for diminution in value
At 31 December 2005 and 31 December 2006
Charge for year
—
—
—
—
—
—
At 31 December 2007
—
—
—
Net book value
At 31 December 2007
25,614,115
497,580
26,111,695
Basic & Diluted earnings / (loss) per share
5.7
2006
€
€(0.02)
Intangible assets – Exploration costs
Expenditure on exploration activities is deferred on areas of interest until a reasonable assessment
can be determined of the existence or otherwise of economically recoverable reserves. The
directors are satisfied that this deferred expenditure is worth not less than cost and that the
exploration projects described above have the potential to achieve production and positive cash
flows. Whilst there are no current indications of impairment, the directors recognise that the
future realisation of these exploration and evaluation assets is dependent on future successful
exploration and appraisal activities and the subsequent economic production of oil and gas
reserves. They have reviewed current and prospective plans for licence areas and are satisfied that
future exploration and evaluation activities are appropriate.
140
5.8
5.9
Property, plant & equipment
Office
equipment
€
Total
€
Cost or valuation
At 31 December 2005 and 31 December 2006
Additions
—
8,682
—
8,682
At 31 December 2007
8,682
8,682
Accumulated depreciation
At 31 December 2005 and 31 December 2006
Charge for year
—
2,171
—
2,171
At 31 December 2007
2,171
2,171
Net book value
At 31 December 2007
6,511
6,511
2007
€
2006
€
2005
€
—
650,839
186,529
—
650,839
186,529
2007
€
2006
€
2005
€
155,569
—
—
19,193
13
76
—
—
886
2,604
76
9,146
2,286
886
1,359
174,775
3,566
13,753
2007
€
2006
€
2005
€
442,673
27,774
80,000
22,841
—
4,840
—
10,841
5,445
10,620
—
—
573,288
15,681
16,065
Paul
Sullivan
€
Barry
Kenny
€
At 31 December 2005
Advances by director
—
—
—
10,841
At 31 December 2006
Advances by director
—
12,000
10,841
—
At 31 December 2007
12,000
10,841
Financial Assets
Quoted investment
5.10 Trade and other receivables
Prepayments and accrued income
Directors Loan
Income tax receivable
Vat recoverable
Corporation tax
5.11 Trade and other payables (amounts falling due within one year)
Trade payables
Accrued expenses
Payroll taxes
Directors loan account
5.12 Director’s loan
The director’s loan is interest free and has no fixed repayment date.
141
5.13 Share capital
2007
€
2006
€
2005
€
Authorised
750,000,000 ordinary shares of €0.05 each (2006 &
2005: 1,000,000 ordinary shares of €1.269738 each) 37,500,000
1,269,738
1,269,738
1,868
1,868
Allotted called up and fully paid
225,013,692 ordinary shares of €0.05 each (2006 &
2005: 1,471 ordinary shares of €1.269738 each)
11,250,685
Details of the ordinary shares issued during the period are given in the table below:
Date
Description
Price
No. of shares
27 April 2007
15 October 2007
23 November 2007
14 December 2007
Subdivision of shares
Acquisition of San Leon Morocco Ltd
Bonus Issue
Share subscriptions
n/a
€140.43
n/a
Stg£0.11
42,659
176,520
220,429,350
4,363,692
5.14 Related party transactions
During the year ended 31 December 2007, Charles McEvoy charged the company €30,000 for
the provision of consultancy services. This amount was outstanding at 31 December 2007 and is
included under trade creditors in the financial information.
During the year ended 31 December 2007, Oisín Fanning charged the company €7,800 for the
provision of consultancy services.
5.15 Capital Commitments
At 31 December 2007 there were no capital commitments.
5.16 Acquisitions
On 15 October 2007, the Company acquired the entire share capital of San Leon Morocco
Limited, a British Virgin Island company, in consideration for which the Company allotted
176,520 €0.05 Ordinary Shares at a premium of €140.39 per share
Book and fair values of the net assets at date of acquisition, were as follows:
Non current assets
Exploration and appraisal expenditure
Liabilities
Amounts due to related parties
Book Value
Fair value
adjustment
Fair value
to the Group
794,377
24,340,468
25,134,845
(344,377)
Net assets / liabilities
450,000
Discharged by: Fair value of shares issued
—
24,340,468
(344,377)
24,790,468
24,790,468
Goodwill arising on acquisition
—
No identifiable goodwill has arisen in respect of this transaction. The surplus of value of the
consideration over the other separable net assets and liabilities of the acquired group has been
attributed to the oil and gas properties and represents their estimated fair value of €25,134,485
as at the date of acquisition of 15 October 2007.
142
6.
Accounting Policies
Statement of compliance
The Group financial information has been prepared in accordance with International Financial
Reporting Standards adopted by the EU and effective at 31 December 2007 and Irish statute comprising
the Companies Acts, 1963 to 2006.
Basis of preparation
The group financial information is prepared on the historical cost basis, except for available-for-sale
assets, which are carried at fair value. The accounting policies have been applied consistently by group
entities. The financial statements are presented in Euro.
The preparation of financial statements in conformity with EU IFRS requires management to make
judgements, estimates and assumptions that affect the application of policies and reported amounts of
assets and liabilities, income and expenses. The estimates and associated assumptions are based on
historical experience and various other factors that are believed to be reasonable under the
circumstances, the results of which form the basis of making the judgements about carrying values of
assets and liabilities that are not readily apparent from other sources.
In particular, significant areas of estimation uncertainty and critical judgements in applying accounting
policies that have the most significant effect on the amount recognised in the financial statements are
in relation to the measurement of the impairment of intangible assets
Basis of consolidation
The financial information incorporates the financial information of the Company and entities controlled
by the Company (its subsidiaries). The results of subsidiaries acquired or disposed of during the year
period included in the consolidated income statement from the effective date of acquisition or up to the
effective date of disposal, as appropriate. Where necessary, adjustments are made to the financial
information of subsidiaries to bring their accounting policies into line with those used by other members
of the Group. All intra-group transactions, balances, income and expenses are eliminated on consolidation.
Segmental reporting
A segment is a distinguishable component of the Group that is engaged either in providing products or
services (business segment), or in providing products or services within a particular environment
(geographic segment), which is subject to risks and rewards that are different from those of other segments.
Inter-segment pricing is determined on an arm’s length basis. Segment results included items directly
attributable to a segment as well as those that can be allocated on a reasonable basis.
Intangible fixed assets – exploration costs
The Group applies the full-cost method of accounting under which all expenditure relating to the
acquisition, exploration, appraisal and development of oil and gas interests, including an appropriate
share of directly attributable overheads, is capitalised within cost pools. Capitalised costs are amortised
on a unit of production basis. The Board regularly reviews the carrying values of intangible assets and
writes down capitalised expenditure to levels it considers to be prudent. Costs pools are determined on
the basis of geographical principles. The Group currently has two cost pools, being its exploration
interests in Africa and North America. Expenditure incurred prior to obtaining the legal rights to explore
an area is written off to the income statement.
Under the full cost based method of accounting, the Group capitalises exploration costs until it is
capable of determining whether its exploration efforts were successful and, if they were successful,
whether any impairment charges may be required to bring the net book values of assets in line with their
economic values.
Unproven oil and gas properties, including oil and gas licences which are acquired by the Group and
which have finite useful lives, are stated at cost less accumulated amortisation and impairment losses.
143
Intangible assets acquired as part of an acquisition of a business are capitalised separately from
goodwill if the fair value can be measured reliably on initial recognition, subject to the constraint that,
unless the asset has a readily ascertainable market value, the fair value is limited to an amount that does
not create or increase any negative goodwill arising on the acquisition.
Property, plant and equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is provided
at rates calculated to write off the cost less residual value of each asset over its expected useful life, the
residual value is the estimated amount that would currently be obtained from disposal of the asset if the
asset were already of the age and in the condition expected at the end of its useful life. The annual rate
of depreciation for each class of depreciable asset is:
Office equipment
25% Straight line
The carrying value of tangible fixed assets is assessed annually and any impairment is charged to the
income statement.
Financial assets
Financial assets are stated at fair value with gains and losses recognised in the income statement.
Impairment
The carrying amounts of the Group’s assets are reviewed at each balance sheet date and, if there is any
indication that an asset may be impaired, its recoverable amount is estimated. The recoverable amount
is the higher of its net selling price and its value in use.
Estimates on impairment are limited to an assessment by the Directors of any events or changes in
circumstance that would indicate that the carrying value of the asset may not be recoverable.
Any impairment loss arising from the review is charged to the income statement whenever the carrying
amount of the asset exceeds its recoverable amount. An impairment loss is reversed only to the extent
that the asset’s carrying amount does not exceed the carrying amount that would have been determined,
net of depreciation or amortisation, if no impairment loss had been recognised.
Taxation
Income tax expense comprises current and deferred tax. Income tax expense is recognised in profit or
loss except to the extent that it relates to items recognised directly in equity, in which case it is
recognised in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or
substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred tax is recognised using the balance sheet method, providing for temporary differences between
the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for
taxation purposes. Deferred tax is not recognised for the following temporary differences: the initial
recognition of goodwill, the initial recognition of assets or liabilities in a transaction that is not a business
combination and that affects neither accounting nor taxable profit, and differences relating to investments
in subsidiaries to the extent that they probably will not reverse in the foreseeable future. Deferred tax is
measured at the tax rates that are expected to be applied to the temporary differences when they reverse,
based on the laws that have been enacted or substantively enacted by the reporting date.
A deferred tax asset is recognised to the extent that it is probable that future taxable profits will be available
against which temporary difference can be utilised. Deferred tax assets are reviewed at each reporting date
and are reduced to the extent that it is no longer probable that the related tax benefit will be realised.
Foreign currencies
Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rates
ruling at the balance sheet date, and revenues, costs and non-monetary assets at the exchange rates
ruling at the dates of the transactions.
144
Profits and losses arising from foreign currency transactions and on settlement of amounts receivable
and payable in foreign currency are dealt with through the income statement.
Monetary assets are monies held and amounts to be received in money; all other assets are non
monetary assets.
Finance income
Dividend income from investments is recognised when the shareholder’s right to receive payment has
been established.
Interest income is accrued on a time basis by reference to the principal on deposit and the effective
interest rate applicable.
Ordinary shares
Incremental costs directly attributable to the issue of ordinary shares are recognised as a deduction
from equity.
145
B. UNAUDITED FINANCIAL INFORMATION ON SAN LEON ENERGY PLC
FOR THE SIX MONTH PERIOD TO 30 JUNE 2008
The following historical financial information on San Leon Energy Plc represents the Company’s
interim results for the 6 months ended 30 June 2008. The financial information (for which the Directors
have accepted responsibility) is unaudited and has not been reviewed.
1.
Consolidated Income Statement
For the six months ended 30 June 2008
Notes
Turnover
Administrative Expenses
Operating Loss
Finance Expenses
Loss per ordinary share – basic & diluted
—
(870,092)
—
(21,640)
5.1
(870,092)
(1,213)
(21,640)
(94)
(871,305)
—
(21,734)
—
(871,305)
(21,734)
5.3
146
Unaudited
30/06/07
€
5.2
5.2
Loss on ordinary activities before tax
Income tax expense
Unaudited
30/06/08
€
(0.3)c
€(1.34)
2.
Consolidated Balance Sheet
As at 30 June 2008
Notes
Non Current Assets
Property, plant and equipment
Intangible assets
5.4
Total non current assets
Current assets
Financial assets
Trade and other receivables
Cash and cash equivalents
5.5
Total assets
Equity and liabilities
Capital and reserves
Issued share capital
Share premium account
Retained earnings
5.7
Total equity attributable to equity Holders of
the company
Current liabilities
Trade and other payables
Other creditors
5.6
5.6
Total liabilities
Total equity and liabilities
147
Unaudited
30/06/08
€
Unaudited
30/06/07
€
8,908
27,619,417
8,682
26,293
27,628,325
34,975
—
442,293
254,236
330,466
284,116
39,662
696,529
654,244
28,324,854
689,219
11,770,685
15,160,376
(1,550,769)
2,207
973,858
(357,438)
25,380,292
618,627
353,290
2,591,272
70,592
—
2,944,562
70,592
28,324,854
689,219
3.
Consolidated Statement of Changes in Equity
As at 30 June 2008
Share
Capital
€
Share
premium
account
€
At 1 January 2008
Shares issued
Loss for the period
11,250,685
520,000
—
15,160,376
—
—
(679,464)
—
(871,305)
At 30 June 2008
11,770,685
15,160,376
(1,550,769)
148
Retained
earnings
€
Total
€
25,731,597
520,000
(871,305)
25,380,292
4.
Consolidated Cash Flow Statement
For the six months ended 30 June 2008
Unaudited
30/06/08
€
Cash flows from operating activities
(Loss) for the period
Finance costs recognised in profit/loss
Other non cash expenses
Depreciation of non-current assets
Unaudited
30/06/07
€
(871,305)
1,213
520,000
2,670
(21,734)
94
—
—
(347,422)
(21,640)
Movements in working capital
(Increase) in trade and other receivables
Increase/(decrease) in trade and other payables
(267,518)
(219,995)
(280,899)
54,911
Cash generated from operations
Interest paid
Corporation and income tax refunds
(834,935)
(1,213)
—
(247,628)
(94)
350
Net cash generated/(used) by operating activities
(836,148)
(247,372)
Cash flows from investing activities
Proceeds on the sale of financial assets
Investment income received
Amounts advanced to related parties
Payments for property, plant and equipment
Payments for intangible assets
—
—
—
(5,067)
(1,507,721)
320,373
—
—
(8,682)
(26,293)
Net cash (used)/generated by investing activities
(1,512,788)
285,398
Cash flows from financing activities
Increase in other creditors
2,591,272
—
Net cash generated in financing activities
2,591,272
—
Net increase in cash and cash equivalents
Cash and cash equivalents at start of period
242,336
11,900
38,026
1,636
Cash and cash equivalents at 30 June
254,236
39,662
149
5.
5.1
Notes to the interim financial information
Segmental Analysis
The Group is engaged in one business segment only, oil and gas exploration therefore only an
analysis by geographical segment has been presented. The Group has geographic segments in
Africa and America in addition to the head office operation in Ireland.
The segment results for the period ended 30 June 2008 are as follows:
Africa
€
America
€
Head Office
€
Group
€
Segment result before tax
Income tax
—
—
—
—
(871,305)
—
(871,305)
—
Loss for the year
—
—
(871,305)
(871,305)
The segment assets and liabilities at 30 June 2008 and capital expenditure for the six months then
ended are as follows:
Africa
€
America
€
Segment assets
Segment liabilities
26,034,058
—
1,792,519
—
498,277
(2,944,562)
28,324,854
(2,944,562)
Net assets
26,034,058
1,792,519
(2,446,285)
25,380,292
212,782
1,294,940
Capital exploration
5.2
Group
€
—
1,507,722
Unaudited
30/06/08
€
Unaudited
30/06/07
€
1,213
94
Finance expenses
Bank interest and charges
5.3
Head Office
€
Loss per share
The calculation of basic loss per ordinary share is based on the loss per year and the average
number of ordinary shares in issue during the relevant year as set out below. There is no difference
between the diluted loss per share and the basic loss per share.
Unaudited
30/06/08
€
Loss for the year
(871,305)
Weighted average number of shares
235,413,692
Basic & Diluted earnings / (loss) per share
(0.3)c
150
Unaudited
30/06/07
€
(21,734)
16,181
€(1.34)
5.4
Intangible assets – Exploration costs
Africa
€
America
€
Total
€
Cost
At 1 January 2008
Additions
25,614,115
212,782
497,580
1,284,940
26,111,695
1,507,722
At 30 June 2008
25,826,897
1,792,520
27,619,417
Provision for diminution in value
At 1 January 2008
Charge for period
—
—
—
—
—
At 30 June 2008
—
—
—
Net book value
At 30 June 2008
25,826,897
1,792,520
27,619,417
Expenditure on exploration activities is deferred on areas of interest until a reasonable assessment
can be determined of the existence or otherwise of economically recoverable reserves. The
directors are satisfied that this deferred expenditure is worth not less than cost and that the
exploration projects described above have the potential to achieve production and positive cash
flows. Whilst there are no current indications of impairment, the directors recognise that the
future realisation of these exploration and evaluation assets is dependent on future successful
exploration and appraisal activities and the subsequent economic production of oil and gas
reserves. They have reviewed current and prospective plans for licence areas and are satisfied that
future exploration and evaluation activities are appropriate.
5.5
Trade and other receivables
Prepayments and accrued income
Other debtors
Vat recoverable
Corporation tax
5.6
Unaudited
30/06/08
€
Unaudited
30/06/07
€
207,161
185,825
49,294
13
—
265,350
16,511
2,254
442,293
284,115
Unaudited
30/06/08
€
Unaudited
30/06/07
€
240,177
9,992
92,280
2,591,272
10,841
67,551
—
—
—
3,041
2,944,563
70,592
Trade and other payables (amounts due within one year)
Trade payables
Accrued expenses
Payroll taxes
Other creditors
Directors’ loans
Other creditors relates to subscriptions received for ordinary shares in the San Leon Energy Plc.
The shares in respect of these subscriptions were allotted by the Company in August 2008.
151
5.7
Share capital
Authorised
750,000,000 ordinary shares of €0.05 each
Allotted called up and fully paid
235,413,692 ordinary shares of €0.05 each
Unaudited
30/06/08
€
Unaudited
30/06/07
€
37,500,000
37,500,000
11,770,685
—
—
2,207
44,130 ordinary shares of €0.05 each
Details of the ordinary shares issued during the period are given in the table below:
Date
Description
16 January 2008
Issue of shares in lieu of
consultancy services provided
Price
No. of shares
€0.05
10,400,000
6.
Accounting policies
The Group interim financial information has been prepared in accordance with International Financial
Reporting Standards adopted by the EU and Irish statute comprising the Companies Acts, 1963 to 2006.
Basis of preparation
The group financial information is prepared on the historical cost basis, except for available-for-sale
assets, which are carried at fair value. The accounting policies have been applied consistently by group
entities. The financial statements are presented in Euro.
The preparation of financial statements in conformity with EU IFRS requires management to make
judgements, estimates and assumptions that affect the application of policies and reported amounts of
assets and liabilities, income and expenses. The estimates and associated assumptions are based on
historical experience and various other factors that are believed to be reasonable under the
circumstances, the results of which form the basis of making the judgements about carrying values of
assets and liabilities that are not readily apparent from other sources.
In particular, significant areas of estimation uncertainty and critical judgements in applying
accounting policies that have the most significant effect on the amount recognised in the financial
statements are in relation to the measurement of the impairment of intangible assets
Basis of consolidation
The financial information incorporates the financial information of the Company and entities controlled
by the Company (its subsidiaries). The results of subsidiaries acquired or disposed of during the year
period included in the consolidated income statement from the effective date of acquisition or up to the
effective date of disposal, as appropriate. Where necessary, adjustments are made to the financial
information of subsidiaries to bring their accounting policies into line with those used by other members
of the Group. All intra-group transactions, balances, income and expenses are eliminated on consolidation.
Segmental reporting
A segment is a distinguishable component of the Group that is engaged either in providing products or
services (business segment), or in providing products or services within a particular environment
(geographic segment), which is subject to risks and rewards that are different from those of other segments.
Inter-segment pricing is determined on an arm’s length basis. Segment results included items directly
attributable to a segment as well as those that can be allocated on a reasonable basis.
Intangible fixed assets – exploration costs
The Group applies the full-cost method of accounting under which all expenditure relating to the
acquisition, exploration, appraisal and development of oil and gas interests, including an appropriate
share of directly attributable overheads, is capitalised within cost pools. Capitalised costs are amortised
on a unit of production basis. The Board regularly reviews the carrying values of intangible assets and
writes down capitalised expenditure to levels it considers to be prudent. Costs pools are determined on
152
the basis of geographical principles. The Group currently has two cost pools, being its exploration
interests in Africa and North America. Expenditure incurred prior to obtaining the legal rights to explore
an area is written off to the income statement.
Under the full cost based method of accounting, the Group capitalises exploration costs until it is
capable of determining whether its exploration efforts were successful and, if they were successful,
whether any impairment charges may be required to bring the net book values of assets in line with their
economic values.
Unproven oil and gas properties, including oil and gas licences which are acquired by the Group and
which have finite useful lives, are stated at cost less accumulated amortisation and impairment losses.
Intangible assets acquired as part of an acquisition of a business are capitalised separately from
goodwill if the fair value can be measured reliably on initial recognition, subject to the constraint that,
unless the asset has a readily ascertainable market value, the fair value is limited to an amount that does
not create or increase any negative goodwill arising on the acquisition.
Property, plant and equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is provided
at rates calculated to write off the cost less residual value of each asset over its expected useful life, the
residual value is the estimated amount that would currently be obtained from disposal of the asset if the
asset were already of the age and in the condition expected at the end of its useful life. The annual rate
of depreciation for each class of depreciable asset is:
Office equipment
25% Straight line
The carrying value of tangible fixed assets is assessed annually and any impairment is charged to the
income statement.
Financial assets
Financial assets are stated at fair value with gains and losses recognised in the income statement..
Impairment
The carrying amounts of the Group’s assets are reviewed at each balance sheet date and, if there is any
indication that an asset may be impaired, its recoverable amount is estimated. The recoverable amount
is the higher of its net selling price and its value in use.
Estimates on impairment are limited to an assessment by the Directors of any events or changes in
circumstance that would indicate that the carrying value of the asset may not be recoverable.
Any impairment loss arising from the review is charged to the income statement whenever the carrying
amount of the asset exceeds its recoverable amount. An impairment loss is reversed only to the extent
that the asset’s carrying amount does not exceed the carrying amount that would have been determined,
net of depreciation or amortisation, if no impairment loss had been recognised.
Taxation
Income tax expense comprises current and deferred tax. Income tax expense is recognised in profit or
loss except to the extent that it relates to items recognised directly in equity, in which case it is
recognised in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or
substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred tax is recognised using the balance sheet method, providing for temporary differences between
the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for
taxation purposes. Deferred tax is not recognised for the following temporary differences: the initial
recognition of goodwill, the initial recognition of assets or liabilities in a transaction that is not a business
combination and that affects neither accounting nor taxable profit, and differences relating to investments
153
in subsidiaries to the extent that they probably will not reverse in the foreseeable future. Deferred tax is
measured at the tax rates that are expected to be applied to the temporary differences when they reverse,
based on the laws that have been enacted or substantively enacted by the reporting date.
A deferred tax asset is recognised to the extent that it is probable that future taxable profits will be
available against which temporary difference can be utilised. Deferred tax assets are reviewed at each
reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will
be realised.
Foreign currencies
Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rates
ruling at the balance sheet date, and revenues, costs and non-monetary assets at the exchange rates
ruling at the dates of the transactions.
Profits and losses arising from foreign currency transactions and on settlement of amounts receivable
and payable in foreign currency are dealt with through the income statement.
Monetary assets are monies held and amounts to be received in money; all other assets are non
monetary assets.
Finance income
Dividend income from investments is recognised when the shareholder’s right to receive payment has
been established.
Interest income is accrued on a time basis by reference to the principal on deposit and the effective
interest rate applicable.
Ordinary shares
Incremental costs directly attributable to the issue of ordinary shares are recognised as a deduction
from equity.
154
PART VI
ADDITIONAL INFORMATION
1.
1.1
The Company
The Company was incorporated in Ireland on 4 September 1995 under the Companies Acts 1963
to 1990 with registered number 237825 as a private company limited by shares with the name
Fondville Limited. Fondville Limited changed its name to Pioneer Resources Limited on
29 September 1995. On 9 July 2008, the Company was re-registered as a public company with
limited liability under the name San Leon Energy Public Limited Company pursuant to the
Companies Acts 1963 to 2006.
1.2
The liability of the members of the Company is limited.
1.3
The principal legislation under which the Company operates is the Companies Acts and the
regulations made thereunder.
1.4
The Company’s registered office is at First Floor, Wilton Park House, Wilton Place, Dublin 2 and
the head office is at 6 Northbrook Road, Ranelagh, Dublin 6.
1.5
The accounting reference date of the Company is 31 December.
1.6
The International Security Identification Number for the Ordinary Shares is IE00B3CLK236.
1.7
The Company’s telephone number is 00 353 1 2916292 and its website is www.sanleonenergy.com.
2.
The San Leon Group
The Company is the ultimate holding company of the following subsidiaries:
Company
Activity
San Leon
(Morocco)
Limited
Interests in
oil and gas
exploration
projects
Interests in
oil and gas
exploration
projects
Interests in
oil and gas
exploration
projects
Interests in
oil and gas
exploration
projects
Employer
company
San Leon
(Netherlands)
Limited
San Leon
Italy Srl
San Leon
(USA) Limited
San Leon
Services
Limited
Company
Registration
Number
Country of
Incorporation
Issued Share
Capital
Proportion
Ownership
British Virgin
Islands
1038054
Six shares
of $1.00 each
100%
British Virgin
Islands
1402154
Two shares
of $1.00 each
100%
One share
of €10,000
100%
Italy
04085270751
Ireland
366153
Two ordinary
shares of €1.00.
each
100%
Jersey
10410
Two ordinary
shares of £1.00
each
100%
155
3.
3.1
Share Capital
The Company was incorporated with an authorised share capital of IR£1,000,000.00 divided into
one million ordinary shares of IR£1.00 each (“IR£1.00 Shares”). Two IR£1.00 Shares of the
Company were issued on incorporation, one to Equity Trust Company Limited and one to
Fiduciary Trust Company Limited.
3.2
748 IR£1.00 Shares were issued at par on 5 September 1995. 50 IR£1.00 Shares were issued at par
on 6 September 1995. 225 IR£1.00 Shares were issued (for an issue price of IR£500 per share) on
11 September 1995.
3.3
115 IR£1.00 Shares were issued for an issue price of IR£500 per share on 11 December 1995.
110 IR£1.00 Shares were issued for an issue price of IR£500.00 per share on 11 March 1996.
3.4
123 IR£1.00 Shares were issued for an issue price of IR£2,565 per share on 7 August 1998.
20 IR£1.00 Shares were issued for an issue price of IR£2,565 per share on 1 October 1998.
78 IR£1.00 Shares were issued for an issue price of IR£2,565 per share on 18 December 1998.
3.5
On 27 December 1999 the Company had a total of 1,471 IR£1.00 Shares in issue. On
1 January 2002 pursuant to the Economic and Monetary Union Act 1998 each issued IR£1.00
Share of IR£1.00 was redenominated into an ordinary share of €1.26973808.
3.6
As at 31 December 2006, the authorised share capital of the Company was €1,269,738.08
comprising 1,000,000 ordinary shares of €1.26973808 each. 1,471 ordinary shares of
€1.26973808 each were in issue.
3.7
Resolutions passed on 27 April 2007
Set out below is a summary of the resolutions passed by Shareholders on 27 April 2007:
3.7.1 The authorised share capital of the Company (under its former name Pioneer Resources
Limited) of €1,269,738.08 was increased to €1,500,000 by the creation of an additional
1,000,000 “A” ordinary shares of €0.23026192 each;
3.7.2 The members resolved that that the Directors of the Company were, for the purposes of
Section 20 of the 1983 Act authorised to exercise all the powers of the Company to allot
and issue relevant securities (as defined by the said Section 20) up to an amount equal to
the authorised but un-issued share capital of the Company after the passing of the
resolution. It was resolved that the authority would expire five years from the date of the
resolution unless previously renewed, varied or revoked by the Company in general
meeting. Section 23 of the 1983 Act (providing statutory pre-emption rights shareholders
on an allotment of shares) was disapplied to any allotments;
3.7.3 For every ordinary share of €1.26973808 held by a shareholder, one “A” ordinary share of
€0.23026192 each was issued to that shareholder. The ordinary shares of €1.26973808
each and the “A” ordinary shares of €0.23026192 each were then consolidated so that the
authorised share capital of the Company was €1,500,000 divided into 1,000,000 ordinary
shares of €1.50 each. Each of the issued ordinary shares and “A” ordinary shares were
consolidated resulting in 1,471 ordinary shares of €1.50 each being in issue;
3.7.4 The issued and unissued shares of €1.50 each were sub-divided into 30 ordinary shares of
€0.05 each; and
3.7.5 The authorised share capital was increased by €6,000,000 to €7,500,000 by the creation of
an additional 120,000,000 Ordinary Shares divided into 150,000,000 Ordinary Shares.
On 27 April 2007 there were 44,130 Ordinary Shares in issue.
3.8
Share for Share Exchange - 15 October 2007
The Company (under its former name Pioneer Resources Limited) entered into a share for share
exchange agreement on 15 October 2007 (the “Exchange Agreement”) with Philip Thompson,
Oisin Fanning and Paul Sullivan. Under the Exchange Agreement, the entire issued share capital
of San Leon (Morocco) (being six ordinary shares of $1.00 each) was transferred to the Company.
In return, the Company issued 88,260 Ordinary Shares to each of Aramis Securities Limited and
156
Aramis Investments Limited. The new shares issued in the Company to Aramis Securities Limited
and Aramis Investments Limited (totalling 176,520 Ordinary Shares) were beneficially held for
Philip Thompson, Oisin Fanning and Paul Sullivan, each individual being beneficially entitled to
58,840 of such shares.
3.9
Resolutions passed on 23 November 2007
Set out below is a summary of the resolutions passed by Shareholders on 23 November 2007:
3.9.1 The authorised share capital of the Company of €7,500,000 was increased to €37,500,000
by the creation of an additional 600,000,000 Ordinary Shares. Each shareholder received
by way of bonus issue 999 Ordinary Shares for every one share held (the sum of
€11,021,467.50 was appropriated from the share premium account to issue a total of
220,429,350 Ordinary Shares so that each of the holders of the 220,650 Ordinary Shares
received an additional 999 shares for each share held).
3.9.2 The Directors of the Company were authorised to exercise all of the powers of the
Company to allot and issue relevant securities up to an amount equal to the authorised but
un-issued share capital of the Company after the passing of the resolution (for the purposes
of Section 20 of the 1983 Act). It was resolved that the authority would expire five years
from the date of the resolution unless previously renewed, varied or revoked by the
Company in general meeting. Section 23 of the 1983 Act was disapplied and some minor
amendments were made to the Articles of Association.
3.9.3 The members resolved to change the Company’s name to San Leon Energy Limited; and
3.9.4 It was further resolved that San Leon be re-registered as a public limited company and new
Memorandum and Articles of Association of a public company be adopted. The members
also resolved that with effect from the date of registration of the plc, the Directors be
empowered to allot equity securities for cash and Section 23 of the 1983 Act be disapplied
in respect of such allotments up to a maximum of 40 per cent. of the aggregate nominal
value of the issued shares at the close of business on the date of re-registration, such
authority to expire on the 5th anniversary of the date of the meeting.
The Company was re-registered as a public limited company on 9 July 2008.
3.10 Resolutions passed on 4 August 2008
Set out below is a summary of the resolutions passed by Shareholders on 4 August 2008:
3.10.1 The members resolved that, with effect from the day after the date of Admission, the
Directors be empowered pursuant to Section 24 of the 1983 Act, to allot equity securities
(as defined by Section 23 of the 1983 Act) for cash pursuant to the authority conferred by
Article 4(e) of the Articles of Association, as if sub-section (1) of the said Section 23 did
not apply to any such allotment. It was resolved that the powers conferred by the resolution
are limited to:
(i)
the allotment of equity securities (including without limitation, any shares purchased
by the Company pursuant to the provisions of the 1990 Act and held as Treasury
Shares) in connection with any offer of securities, open for a period fixed by the
Directors, by way of rights, open offer or otherwise in favour of ordinary shareholders
and/or any persons having a right to subscribe for or convert securities into ordinary
shares in the capital of the Company (including, without limitation, any person
entitled to options under any of the Company’s shares option schemes for the
time-being) and subject to such exclusions or other arrangements as the Directors may
deem necessary or expedient in relation to legal or practical problems under the laws
of, or the requirements of any recognised body or stock exchange in, any territory; and
157
(ii)
in addition to the authority conferred by paragraph (i) above, the allotment of equity
securities (including without limitation, any shares purchased by the Company
pursuant to the provisions of the 1990 Act and held as Treasury Shares) up to a
maximum of 30 per cent. of the aggregate nominal value of the issued ordinary share
capital of the Company at the close of business on the date of Admission.
It was resolved that the authority conferred by the resolution shall become effective on the
day after Admission and shall expire on the earlier of the close of business on
4th November 2009 and the next annual general meeting, unless previously renewed, varied
or revoked by the Company in general meeting; and
3.10.2 The members resolved that the Articles be adopted with effect from the date of Admission.
A summary of the Articles is contained in paragraph 4 of this Part VI.
3.11 4,363,692 Ordinary Shares were issued for an issue price of £0.11 on 14 December 2007. 10,400,000
Ordinary Shares were issued on 10 January 2008 in consideration for services provided to the
Company. 29,819,740 Ordinary Shares were issued for an issue price of £0.11 on 22 August 2008.
1,294,890 Ordinary Shares were issued for an issue price of £0.11 on 1 September 2008. 4,801,045
Ordinary Shares were issued for an issue price of £0.11 on 10 September 2008.
3.12 The Company’s authorised and issued fully paid share capital, at the date of this document is, and
on Admission will be, as follows:
At the date of this document
Number of
Amount €
Ordinary Shares
Authorised
Issued and
fully paid
On Admission
Amount €
Number of
Ordinary Shares
37,500,000
750,000,000
37,500,000
750,000,000
13,566,468.35
271,329,367
13,566,468.35
271,329,367
3.13 The provisions of section 23 of the 1983 Act (which confer on shareholders rights of pre-emption
in respect of the allotment of equity securities which are, or are to be, paid up in cash with certain
limited exceptions) will apply to the authorised but unissued share capital of the Company to the
extent not disapplied by the resolution of the Company detailed in paragraph 3.10 above.
3.14 There are no shares in the Company which are held by, or on behalf of, the Company and none
of the Company’s subsidiaries holds any shares in the Company.
3.15 Other than set out in this document, no person has any rights to purchase the authorised but
unissued capital of the Company.
3.16 At a board meeting on 23 November 2007, the Company resolved to grant to the directors listed
below or nominees on their behalf the following Options on the terms as described below to
acquire Ordinary Shares:
Director
Charles McEvoy
Raymond King
Number of Options
5,000,000
1,000,000
On 23 September 2008, the Company entered into an Option Agreement with each of the above
named directors in respect of the Options. The parties to the Option Agreement granting Charles
McEvoy’s Options are (1) the Company, (2) San Leon Services, (3) Charles McEvoy and (4) Blue
Clie Limited, his nominee company. The parties to the Option Agreement granting Raymond
King’s Options are (1) the Company and (2) Raymond King.
The Option Agreement granting Charles McEvoy his Options provides as follows:
3.16.1 In consideration of the payment of €10.00 by Charles McEvoy to the Company, San Leon
Services procured the right for Blue Clie Limited to be granted Options to acquire
5,000,000 Ordinary Shares at an exercise price of €0.05 for the period commencing on
23 September 2008 and expiring 6 years and 364 days thereafter;
158
3.16.2 The Options are not exercisable prior to 1 January 2009 and are conditional on the price
of the Ordinary Shares maintaining an average price of £0.20 on any recognised stock
exchange for a 7 day period and his Service Agreement not having been terminated prior
to 1 January 2009; and
3.16.3 The Options may be transferred, assigned, mortgaged or disposed of by the nominee
company upon providing prior written notice to San Leon Services.
The Option Agreement granting Options to Raymond King provides as follows:
3.16.4 In consideration of the payment of €10.00 by Raymond King to the Company, the
Company grants Raymond King Options to acquire 1,000,000 Ordinary Shares at an
exercise price of €0.05 during the period commencing on 23 September 2008 and
expiring 6 years and 364 days thereafter;
3.16.5 The Options are not in any circumstances exercisable before 1 January 2009 and are
conditional on the price of the Ordinary Shares maintaining an average price of £0.20 on
any recognised stock exchange for a 7 day period; and
3.16.6 The Options may be transferred, assigned, mortgaged or disposed of by Raymond King
upon providing prior written notice to the Company.
At a board meeting on 8 July 2008, the Company agreed to grant 1,000,000 options (the “Further
Options”) to Jeremy Boak and entered into an option agreement (the “Further Option Agreement”)
with Mr. Boak. The Further Option Agreement provides that in consideration of the payment of
€1.00 by Mr. Boak to the Company, the Company granted Mr. Boak the Further Options to acquire
1,000,000 Ordinary Shares at an exercise price of £0.11 for a period of 7 years commencing on
7 July 2008. The exercise of the Further Options is conditional on the price of the Ordinary Shares
maintaining an average price of £0.20 on any recognised stock exchange for a 7 day period.
The Company, through its subsidiary San Leon (Italy) has submitted five applications for Italian
licence permits. On the successful granting of an Italian permit, a success fee of £55,000 per licence
application (the “Success Fee”) will be paid to BWG s.r.l. It has been agreed between BWG s.r.l.
and the Company that BWG s.r.l. shall apply its Success Fee by subscribing for 500,000 Ordinary
Shares in the Company at a subscription price of £0.11 per share. The maximum number of shares
that may be issued as a result of the agreement with BWG s.r.l. if the five applications are successful
is 2,500,000 Ordinary Shares.
As at 23 September 2008, and save in respect of the right to convert the loan into Ordinary Shares
under the Convertible Loan Note described in paragraph 3.18 of this Part VI of this document,
and the Warrants described in paragraph 3.17 of this Part VI of this document, there are no other
options existing or agreed conditionally or unconditionally over the capital of the Company or of
its subsidiaries.
3.17 As at 23 September 2008, there were outstanding 30,697,443 Warrants over the Ordinary Shares.
The exercise price of the Warrants is £0.11 per Ordinary Share. The Warrants expire 3 years from
the date of Admission.
3.18 Pursuant to a resolution of the Company, the Company created the Convertible Loan Note which
was constituted by a loan note instrument dated 12 September 2008 (the “Loan Note Instrument”).
The Convertible Loan Note was alloted and issued to Mr Turner fully paid. The Loan Note
Instrument provides that the Convertible Loan Note is subject to interest at 12 per cent. per annum
for a two year term. The Company may at any time, upon giving not less than 30 days prior notice
in writing to Mr. Turner, and subject to a minimum repayment amount of €5,000, repay any portion
of the Convertible Loan Note. The Convertible Loan Note shall become immediately repayable on,
inter alia, the Company ceasing or threatening to cease to carry on business or on any member of
the Group being unable to pay its debts or entering into any arrangement with its creditors or on a
resolution being passed for the winding up of any member of the Group. Mr. Turner is entitled at
any time prior to the repayment of the Convertible Loan Note, on giving 10 days written notice to
the Company, to serve a conversion notice on the Company to convert some or all of the
159
outstanding balance of the Convertible Loan Note into Ordinary Shares at a price per share of
£0.40. If the Company chooses to accelerate the repayment of the outstanding Convertible Loan
Note, Mr. Turner shall be entitled to subscribe for Ordinary Shares in the Company at a price of
£0.40 per Ordinary Share up to the amount of the accelerated repayment that the Company has paid
to Mr. Turner.
3.19 Save as set out in this document:
3.19.1.1 there are no shares in the Company not representing capital;
3.19.1.2 there are currently no outstanding convertible or exchangeable securities or securities
with warrants issued by the Company;
3.19.1.3 no share or loan capital of the Company has been issued or is proposed to be issued; and
3.19.1.4 no person has any preferential or subscription rights for any share capital of the Company.
4.
4.1
Memorandum and Articles of Association
Memorandum of Association
The principal object of the Company set out in clause 2 of Memorandum of Association enables
the Company to carry on the business of exploiting natural resources of every nature including
oil exploration and the development and production of oil, gas and other energy substances and
to inter alia purchase, lease or otherwise acquire rights as may be considered necessary for the
purposes of carrying on this business. The Company is also authorised to carry on the business
of an investment holding company and to acquire and hold stocks and shares of any class or
description. The Company has other ancillary powers necessary to carry on its business including
the power to borrow and raise money and to develop and turn to account all or any part of the
property and rights of the Company.
Articles of Association
The Articles contain provisions, inter alia, to the following effect;
4.2
Authorised Capital
The authorised share capital of the Company is €37,500,000 divided into 750,000,000 Ordinary
Shares of €0.05 each.
4.3. Voting rights
4.3.1. Subject to any special rights or restrictions as to voting attached by or in accordance with
the Articles to any shares or class of shares, on a show of hands every member who is
present in person shall have one vote and on a poll every member who is present in person
or by proxy shall have one vote for every share of which he is the holder.
4.3.2 No member shall, unless the Board otherwise determines, be entitled to vote:
4.3.2.1 if any call or other sum presently payable by him to the Company in respect of the
shares remains unpaid; or
4.3.2.2 if he has been served with a notice requiring disclosure of information regarding
shares held by him and has failed to provide the Company with information
concerning the interest in those shares.
4.4. Transfer of shares
4.4.1 Form of transfers
Transfers of shares may be effected by an instrument of transfer in any usual form or in any
other form approved by the Board. The instrument of transfer shall be signed by or on
behalf of the transferor and (except in the case of fully paid shares) by or on behalf of the
transferee. Title to any shares may also be evidenced and transferred by electronic means
without a written instrument in accordance with the Articles.
160
4.4.2 Right to refuse to register a transfer
The Board may in its absolute discretion and without assigning any reason for its actions
refuse to register any transfer of any share which is not a fully paid share. The Board may
decline to recognise any instrument of transfer unless the duly stamped instrument of
transfer:
4.4.2.1 is in respect of only one class of share;
4.4.2.2 is lodged at the registered office or such other place as the Board may determine;
4.4.2.3 is accompanied by the relevant share certificate(s) and such other evidence as the
Board may reasonably require to show the right of the transferor to make the
transfer;
4.4.2.4 in the case of a transfer to joint holders, the number of joint holders does not
exceed four; and
4.4.2.5 the instrument of transfer is duly stamped (if so required).
4.5. Class of shares admitted to trading on AIM
Notwithstanding the right of the Board to refuse to register a transfer, the Board shall not refuse
to register a transfer if the refusal would prevent dealings in those shares from taking place on an
open and proper basis.
4.6. Dividends and Distributions
The Company may by ordinary resolution declare dividends but no such dividends shall exceed
the sum recommended by the Board.
4.6.1. Interim and fixed dividends
The Board may pay such interim dividends (including any dividend payable at a fixed rate)
as appear to the Board to be justified by the financial position of the Company. The Board
may pay such interim dividends on shares which rank after shares conferring preferential
rights (if any), unless at the time of payment any preferential dividend is in arrears.
4.6.2 Retention of dividends
The Board may retain any dividend or other moneys payable on or in respect of a share on
which the Company has a call or otherwise, and may apply the same in or towards
satisfaction of all sums of money in respect of which the call exists.
4.6.3 Unclaimed dividends
Any dividend unclaimed after a period of twelve years from the date the dividend became
due for payment shall be forfeited and shall revert to the Company.
4.6.4. Issue of Ordinary Shares in lieu of cash dividend
The Directors may, subject to the approval of the Company at general meeting in respect of
any dividend declared or proposed to be declared at that general meeting offer holders of
ordinary shares the right, prior to or contemporaneously with their announcement of the
dividend in question, to elect to receive in lieu of such dividend an allotment of additional
ordinary shares credited as fully paid.
4.6.5. Dividend in Specie
A general meeting declaring a dividend may, upon the recommendation of the Directors,
direct that it shall be satisfied wholly or partly by the distribution of assets.
4.6.6 Distribution of Assets on Liquidation
If the Company shall be wound up and the assets available for distribution among the
members as such shall be insufficient to repay the whole of the paid up or credited as paid
up share capital, such assets shall be distributed so that, as nearly as may be, the losses shall
be borne by the members in proportion to the capital paid up or credited as paid up at the
161
commencement of the winding up on the shares held by them respectively. If on a winding
up the assets available for distribution among the members shall be more than sufficient to
repay the whole of the share capital paid up or credited as paid up at the commencement of
the winding up, the excess shall be distributed among the members in proportion to the
capital at the commencement of the winding up paid up or credited as paid up on the said
shares held by them respectively.
4.7. Capitalisation of profits and reserves
The Company in general meeting may, upon the recommendation of the Directors, resolve that
any sum standing to the credit of any of the Company’s reserve accounts or any other sum
standing to the credit of the profit and loss account be capitalised and applied on behalf of the
members in issuing shares to members in proportion to their holdings of ordinary shares and
applying such sum on their behalf in paying up in full unissued shares or debentures of the
Company or applying such sums towards paying up any amounts unpaid on any shares.
4.8. Share capital
4.8.1. Variation of rights
The special rights attached to any class of shares may, subject to the provisions of the
Companies Acts, be varied either with the consent in writing of the holders of not less than
three-quarters in nominal value of the issued shares of the class or with the sanction of an
extraordinary resolution passed at a separate general meeting of the holders of the shares
of the class.
4.8.2. Purchase of own shares
Subject to the provisions of the Companies Acts, the Company may purchase any of its own
shares.
4.8.3 Variation of Share Capital
The Company from time to time by ordinary resolution, may increase its authorised share
capital by such sum to be divided into shares of such amount as the resolution shall prescribe.
The Company, by ordinary resolution may:
(a)
consolidate and divide all or any of its share capital into shares of larger amounts; or
(b)
subject to the provisions of the Companies Acts, subdivide its shares, or any of them,
into shares of smaller amounts; or
(c)
cancel any shares which, at the date of the passing of the resolution have not been
taken or agreed to be taken by any person and reduce the amount of its authorised
share capital by the amount of the shares to be cancelled.
Subject to the Companies Acts, the Company may by special resolution reduce its share
capital, any capital redemption reserve fund or any share premium account.
4.9. Forfeiture and lien
4.9.1 Notice on failure to pay a call
If a member fails to pay in full any call or instalment of a call on the due date for payment
the Board may at any time after the failure serve a notice on him requiring payment and
shall state that in the event of non-payment in accordance with such notice the shares on
which the call was made will be liable to be forfeited.
4.9.2 Disposal of shares
Where the Company is entitled under the Companies Acts or the Articles to dispose of,
forfeit, enforce a lien over or otherwise procure the sale of any shares, the Directors shall
have the power to take such steps as may be required to effect such disposal, forfeiture,
enforcement or sale.
162
4.10 Directors
4.10.1 Number of Directors and quorum
Unless otherwise determined by ordinary resolution the Directors shall not be less than
three, nor more than fifteen.
4.10.2 Ordinary Remuneration
The ordinary remuneration of the Directors shall be determined from time to time by the
Company in general meeting and shall be divided among the Directors in such proportion
and manner as the Directors may agree or if no such agreement, equally.
4.10.3 Directors’ expenses
The Board may pay to any Director all such reasonable expenses as he may properly incur
in attending meetings of the Board or of any committee of the Board or shareholders’
meetings or otherwise in connection with the business of the Company.
4.10.4 Retirement by rotation
At each annual general meeting one-third of the Directors for the time being (or, if their
number is not a multiple of three, the number nearest to and exceeding one-third) shall
retire from office by rotation.
4.10.5 Restrictions on voting
4.10.5.1 A Director shall not vote (save as provided in the Articles) in respect of any
contract or arrangement or any other proposal whatsoever in which he has,
directly or indirectly, a material interest or a duty which conflicts or may conflict
with the interests of the Company. A Director shall not be counted in the quorum
at a meeting in relation to any resolution on which he is not entitled to vote.
4.10.5.2 A Director shall (in the absence of material interest other than is indicated below)
be entitled to vote (and be counted in the quorum) in respect of any resolution
relating to:
(a)
the giving of any security, guarantee or indemnity to him in respect of
money lent by him or obligations undertaken by him for the benefit of the
Company or any subsidiary;
(b)
the giving of any security, guarantee or indemnity to a third party in respect
of a debt or obligation of the Company or any subsidiary which the Director
has himself guaranteed or indemnified or secured in whole or in part;
(c)
any issue or offer of shares, debentures or other securities of the Company
or any subsidiary in respect of which the Director is or may be entitled to
participate as a holder of securities, or in the underwriting or
sub-underwriting of which the Director is to participate;
(d)
any contract or arrangement concerning any other company in which he is
interested provided the Director does not own one per cent. or more of any
class of the equity share capital or voting rights;
(e)
any arrangement for the benefit of the employees which does not provide
in respect of any Director any privilege or benefit not generally accorded to
the employees to whom such arrangement relates;
(f)
the purchase or maintenance of insurance for the benefit of Directors or for
the benefit of persons including Directors; and
(g)
any proposal concerning the adoption or operation of a pension or similar
retirement scheme which relates both to Directors and employees and does
not award the Director any privilege or benefit not generally accorded to
the employees to whom such arrangement relates.
163
4.11 Borrowing powers
The Directors may exercise all the powers of the Company to borrow money and to mortgage or
charge its undertaking, property and assets both present and future and uncalled capital, or any
part thereof, and to issue debentures and other securities, whether outright or as collateral security
for any debt, liability or obligation of the Company or of any third party.
4.12 General Meetings
4.12.1 Calling of general meeting
The Company shall in each year hold an annual general meeting. All general meetings,
other than annual general meetings, shall be called general meetings. The Directors may
convene general meetings. If there are not within Ireland sufficient members of the Board
to convene a general meeting, any Director or any two members may call a general meeting.
4.12.2 Notice period
Subject to the provisions of the Companies Acts, an annual general meeting and a general
meeting convened for the passing of a special resolution shall be convened by not less than
21 clear days’ notice in writing. All other general meetings shall be convened by not less
than 14 clear days’ notice in writing. The accidental omission to give notice of a meeting
to, or the non-receipt of notice of a meeting by any person entitled to receive notice shall
not invalidate proceedings at the meeting.
4.12.3 Content of notice
The notice shall specify the time and place of the meeting and the general nature of
business to be transacted. It shall also give particulars of any Directors who are to retire
by rotation or otherwise at the meeting, and of any person who are recommended by the
Directors for appointment or re-appointment.
4.12.4 Quorum
Except as provided in the Articles in relation to an adjourned meeting, three persons
entitled to vote upon the business to be transacted, each being a member or a proxy for a
member or a duly authorised representative of a corporate member shall be a quorum.
4.13 Redemption of Shares
Subject to the provisions of the Companies Acts relating to authority, pre-emption or otherwise in
regard to the issue of new shares and to any resolution of the Company in general meeting passed
pursuant thereto, all unissued shares (including Treasury Shares) shall be at the disposal of the
Directors, and they may (subject to the provisions of the Companies Acts) allot, grant options over
or otherwise dispose of them to such persons on such terms and conditions and at such times as
they may consider to be in the best interests of the Company and its shareholders.
4.14 Conversion of Shares
The Company may by ordinary resolution convert any paid up shares into stock, and reconvert
any stock into paid up shares of any denomination.
5.
5.1
Directors’ and Director’s interests and lock-in arrangements
On Admission, the Directors will have interests in 178,520,000 Ordinary Shares in aggregate,
representing approximately 65.79 per cent. of the Issued Share Capital. Details of the Directors’
holdings of Ordinary Shares are set out in paragraphs 5.2 and 5.3 below.
5.2
Each of Paul Sullivan, Philip Thompson, Charles McEvoy and Oisin Fanning and their respective
nominee companies disclosed below undertook to Daniel Stewart for the purposes of rule 7 of the
AIM Rules for Companies that they will not dispose of any interests they have in Ordinary Shares
or other securities of the Company for a period of one year from Admission (the “Hard Lock-in
Period), except in the strictly limited circumstances permitted by Rule 7 of the AIM Rules. They
each further undertook not to dispose of any interests they have in Ordinary Shares or other
securities of the Company for a further period of 1 year following the expiry of the Hard Lock-in
164
Period without the prior written consent of Daniel Stewart, such consent not to be unreasonably
withheld. During such period Daniel Stewart will have the exclusive right to effect any such
disposal on their behalf. The interests of the Directors subject to the undertakings are as follows:
Date of
Undertaking
Number of
Ordinary
Shares
Options
23 September 2008
23 September 2008
23 September 2008
23 September 2008
23 September 2008
23 September 2008
58,840,000
58,840,0002
58,840,000
2,000,0003
None
None
None
None
None
5,000,0004
1,000,000
1,000,000
Director
Oisin Fanning
Philip Thompson
Paul Sullivan
Charles McEvoy
Raymond King
Jeremy Boak
1
Notes
5.3
1.
These Ordinary Shares are held by Red Cedar Limited in trust for Oisin Fanning
2.
These Ordinary Shares are held by Gold Spark Limited in trust for Philip Thompson
3.
These Ordinary Shares are held by Blue Clie Limited in trust for Charles McEvoy
4.
These Options are held by Blue Clie Limited a company the entire share capital of which is beneficially owned by
Charles McEvoy
The interests of the Directors and their respective families (as defined in the AIM Rules) all of
which are beneficial unless otherwise stated and of connected persons within the meaning of
section 26 of the 1990 Act, in the Issued Share Capital as at the date of this document and on
Admission, the existence of which is known to, or could, with reasonable diligence, be ascertained
by the Directors, together with the percentages which such interests represent of the Ordinary
Shares in issue are or will be as follows:
Director
Oisin Fanning
Philip Thompson
Paul Sullivan
Charles McEvoy
As at the date of this document
Percentage of
Number of
Issued Share
Ordinary Shares
Capital
58,840,000
58,840,000
58,840,000
2,000,000
21.69
21.69
21.69
0.74
On Admission
Number of
Ordinary Shares
Percentage
Issued Share
Capital
58,840,0001
58,840,0002
58,840,000
2,000,0003
21.69
21.69
21.69
0.74
Notes
1.
These Ordinary Shares are held by Red Cedar Limited in trust for Oisin Fanning
2.
These Ordinary Shares are held by Gold Spark Limited in trust for Philip Thompson
3.
These Ordinary Shares are held by Blue Clie Limited in trust for Charles McEvoy
5.4
None of the Directors or any member of a Director’s family (as defined in the AIM Rules) is
interested in any related financial product (as defined in the AIM Rules) whose value in whole or
in part is determined directly or indirectly by reference to the price of Ordinary Shares including
a contract for difference or a fixed odds bet.
6.
6.1
Additional Information on the Directors
The Directors have held the following directorships or have been partners in the following
partnerships within the previous five years prior to the date of this document:
(i)
Oisin Fanning
Current Directorships/Partnerships
•
San Leon
•
San Leon (Morocco)
•
San Leon (Netherlands)
•
San Leon (USA)
•
Outpost Properties Limited
Past Directorships/Partnerships
•
Smart Telecom plc.
165
(ii)
Philip Thompson
Current Directorships/Partnerships
•
San Leon
•
San Leon (Morocco)
•
San Leon (Netherlands)
•
San Leon (USA)
Past Directorships/Partnerships
•
None
(iii)
Paul Sullivan
Current Directorships/Partnerships
•
San Leon
•
San Leon (Morocco)
•
San Leon (Netherlands)
•
San Leon (USA)
•
Outpost Properties Limited
•
Avi Kiran Sons Limited
•
Forwarding Software Limited
Past Directorships/Partnerships
•
Smart Telecom plc
(iv)
Charles McEvoy
Current Directorships/Partnerships
•
San Leon
•
San Leon (USA)
•
Ireland for Khao Lak Direct Limited
Past Directorships/Partnerships
•
None
(v)
Raymond King
Current Directorships/Partnerships
•
San Leon
•
Surplan Limited
•
Eagleflag Limited
•
Cice Blossac Golf and Leisure sarl.
•
Global e-Network Holdings plc.
•
Global e-Network Limited
•
Global e-React Limited
•
Global e-Impact Limited
•
Bjoni Trading Limited
•
Pinfolds Leisure Group plc
•
Leggymore Homes Limited
•
Real Estate Relocations Limited
Past Directorships/Partnerships
•
Smart Telecom plc
(vi)
Jeremy Boak
Current Directorships/Partnerships
•
San Leon
Past Directorships/Partnerships
•
None
166
6.2
Oisin Fanning was a director of MMI Stockbrokers Limited, and resigned as a director on
2 December 1998. MMI Stockbrokers Limited was placed into compulsory liquidation on
15 March 1999.
6.3
As at the date of this document, save as set out in this document, none of the Directors has:
6.3.1 any unspent convictions in relation to indictable offences;
6.3.2 had any bankruptcy order made against him or entered into any voluntary arrangements;
6.3.3 been a director of a company which has been placed in receivership, compulsory liquidation,
administration, been subject to a voluntary arrangement or any composition or arrangement
with its creditors generally or any class of its creditors, whilst he was a director of that
company or within the 12 months after he had ceased to be a director of that company;
6.3.4 been a partner in any partnership with has been placed in compulsory liquidation,
administration or been the subject of a partnership voluntary arrangement, whilst he was a
partner in that partnership or within the 12 months after he ceased to be a partner in
that partnership;
6.3.5 been the owner of any asset which has been placed in receivership or a partner in any
partnership which has been placed in receivership whilst he was a partner in that
partnership or within the 12 months after he ceased to be a partner in that partnership;
6.3.6 been publicly criticised by any statutory or regulatory authority (including recognised
professional bodies); or
6.3.7 been disqualified by a court from acting as a director of any company or from acting in the
management or conduct of the affairs of a company.
6.4
Save as set out in this document, or by virtue of his shareholdings in the Company, no Director
has or has had any interest in any transaction which is or was significant in relation to the business
of the Group and which was effected during the current or immediately preceding financial period
or which was effected during an earlier financial period and remains outstanding or unperformed.
7.
7.1
Directors’ Letters of Appointment and Service Contracts
Letters of Appointment
Each of the Directors entered into a letter of appointment with the Company on 16 September 2008.
The principal terms of the letters of appointment are as follows:7.1.1 Each of Philip Thompson, Oisin Fanning, Paul Sullivan and Charles McEvoy will receive
a fee of €50,000 per annum (plus VAT if applicable) payable monthly in arrears. Ray King
will receive a fee of £30,000 per annum and Jeremy Boak will receive a fee of US$50,000
(each plus VAT if applicable and payable monthly in arrears).
7.1.2 Save in respect of Raymond King and Jeremy Boak the appointments shall be terminable
at any time by either party upon 12 months notice in writing. The notice period for each of
Raymond King and Jeremy Boak is 3 months. The Company may terminate the
appointment summarily without notice or prior warning if the Director commits any act of
gross misconduct or gross incompetence, becomes in the reasonable opinion of the Board
incapable of performing his duties in accordance with the agreement or commits any
serious offence or commits any conduct which in the opinion of the Board brings the
Company into disrepute.
7.1.3 The Directors agree to abide by any relevant Company policy which may be promulgated
from time to time and agrees not to, without the Company’s prior consent, hold any interest
in any person which competes with any business carried on by the Company or impairs or
might reasonably be thought by the Company to impair the ability to act at all times in the
best interest of the Company.
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7.2
Service Agreements
San Leon Services entered into an executive service agreement with each of Paul Sullivan, Oisin
Fanning, Charles McEvoy and Philip Thompson on 18 September 2008 on the following terms:7.2.1 Each of the service agreements commence on 18 September 2008 and may be terminated
by either party on 12 months written notice. San Leon Services is entitled to terminate each
of the service agreements forthwith at any time by giving to the executive a payment
equivalent to an amount of his contractual notice entitlement and in lieu of requiring him
to continue work under the terms of the agreement.
7.2.2 San Leon Services agrees to pay each of Oisin Fanning, Phil Thompson and Paul Sullivan
a salary of £350,000 per annum to be paid monthly in arrears, and to be reviewed annually
on the anniversary of the agreement. Charles McEvoy’s salary is £185,000. The service
agreements further provide that the executive may be included in any bonus, profit share
and/or option arrangements which San Leon Services or an associated company may in its
sole discretion from time to time adopt. The executive is entitled to 25 working days
holidays in each year.
7.2.3 The service agreements may be terminated forthwith by San Leon Services without prior
notice if at any time the executive shall be guilty of any serious breach or repeated breaches
of any of the provisions in the agreement or of any serious misconduct, or shall be
adjudicated bankrupt or make any arrangement or composition with his creditors or if an
executive commits any serious act of dishonesty or repeated acts of dishonesty or engaging
in any action to bring himself or the Group into disrepute.
8.
Employees
There are no employees of the San Leon Group other than Paul Sullivan, Oisin Fanning, Charles McEvoy
and Philip Thompson. Details of their service agreements are set out in paragraph 7.2 of this Part VI of
this document.
9.
9.1
Mandatory Bids Squeeze Out and Buy-Out Rules
Mandatory bid
Upon Admission, the Takeover Rules will apply to the Company. Under the Irish Takeover Rules,
if an acquisition of Ordinary Shares were to increase the aggregate holding of the acquirer and its
concert parties to Ordinary Shares carrying 30 per cent. or more of the voting rights in the
Company, the acquirer and depending on the circumstances, its concert parties, would be required
(except with the consent of the Irish Takeover Panel) to make an offer for the outstanding shares
at a price not less than the highest price paid for the Company's Ordinary Shares by the acquirer
or its concert parties during the previous 12 months. This requirement would also be triggered by
any acquisition of shares by a person holding (together with its concert parties) shares carrying
between 30 per cent. and 50 per cent. of the voting rights in the Company if the effect of such
acquisition were to increase that person's percentage of the voting rights by 0.05 per cent.
9.2
Squeeze-out
Under the Companies Acts, if an offeror were to acquire 80 per cent. of the Ordinary Shares
within four months of making its offer, it could then compulsorily acquire the remaining
20 per cent. It would do so by sending a notice to the Shareholders telling them that it would
compulsorily acquire their shares and then, unless the High Court of Ireland determined
otherwise, one month later, it would execute a transfer of the outstanding shares in its favour and
pay the consideration to the Company, which would hold the consideration on trust for
outstanding shareholders. Where the offeror already owns more than 20 per cent. of the Company
at the time that the offeror makes an offer for the balance of the shares, then the compulsory
acquisition rights only apply if the offeror acquires at least 80 per cent. of the remaining shares
which also represent at least 75 per cent. in number of the holders of the accepting shareholders.
168
9.3
Buy-out rules
The Companies Acts also give minority shareholders a right to be bought out in certain
circumstances by the offeror who has made a takeover offer. If a takeover offer related to all the
Ordinary Shares, and at any time before the end of the period within which the offer could be
accepted, the offeror held or had agreed to acquire not less than 80 per cent. of the Ordinary Shares,
any holder of shares to which the offer related who had not accepted the offer could, by a written
communication to the offeror, require it to acquire those shares. The offeror would be required to
give any shareholders notice of their right to be bought out within one month of that right arising.
10. Substantial Shareholders and Concert Party
As at 22 September 2008 (being the latest practicable date prior to publication of this document), in so
far as is known to the Directors, the only holders of Ordinary Shares, other than the Directors disclosed
under paragraph 5 above, who are interested directly or indirectly in 3 per cent. or more of the Issued
Share Capital as at 22 September 2008, or immediately following Admission will be so interested, are the
following persons:
Registered Shareholder
Barry Kenny
Dermot Sheerin
David Turner
As at
22 September 2008
Immediately following
Admission
11,250,000
12,300,000
10,538,942
11,250,000
12,300,000
10,538,942
There are no differences between the voting rights of the Ordinary Shares held by the Shareholders
disclosed above and the voting rights of any other holder of Ordinary Shares.
11. Disclosure Requirements and Notification of Interests in Shares
Under Irish company law, where any person acquires an interest in 5 per cent. or more of the issued
voting share capital of any class of an Irish public limited company, such person must notify the
company in the prescribed manner and normally within five business days, of his interest and of certain
information relating to that interest. Notification must also be made of any change in the percentage
level of a person’s interest above 5 per cent. and of any reduction to his or her interest to less than
5 per cent. Any interest, whether direct or through a spouse, minor child or company which the person
in question is deemed to control, or in certain circumstances, other persons with whom he is acting in
concert, would be regarded as an interest in shares for this purpose. Failure to notify punctually and
properly is an offence under Irish company law. Additionally, Irish law provides that no right or interest
whatsoever in respect of any of the relevant shares will be enforceable, whether directly or indirectly, by
action or legal proceeding by the person having such an interest should they fail to notify the company
of such interest. Application may be made to the High Court of Ireland to remove this restriction, and
if the court is satisfied that the failure to notify was accidental or due to inadvertence or that it is just
and equitable to grant relief then the court may grant such relief as it sees fit. The Company is obliged
to keep a register showing all notifications received and to keep it open for inspection by the public.
The notification to the relevant company must be in writing and must specify the share capital to which
it relates, the number of shares comprised in that share capital in which the person making the
notification knows he was interested immediately after the time when the obligation arose and give
details of the registered holder of the shares and the number of shares held by them. In a case where the
person no longer has a notifiable interest in shares comprised in the share capital, the notifier must state
that he no longer has an interest; identify the notifier and give his address.
The AIM Rules require a company that is admitted to AIM to issue a notification without delay of any
relevant changes to the legal or beneficial interest, whether direct or indirect, to the holding of a
significant shareholder, such a shareholder being a shareholder holding 3 per cent. or more of any class
of security, which increases or decreases such holding through any single percentage.
Under the Articles persons are also obliged to make a notification to the Company where the person is
interested in 3 per cent. or more of the issued share capital of the Company.
169
12. Material Contracts
The following contracts being either (i) contracts which relate to the San Leon Group’s assets and are, or
may be, material; and/or (ii) contracts not entered into in the ordinary course of business which have been
entered into by a member of the Group in the two years prior to the date of this document or prior thereto
where a member of the Group has any outstanding obligations thereunder and are, or may be material.
12.1 Share Exchange Agreement
The Company (under its former name Pioneer Resources Limited) entered into an Exchange
Agreement (as defined in paragraph 3.8 and a summary of which is set out in paragraph 3.8 of
this Part VI of this document).
The Exchange Agreement also contains warranties from each of Oisin Fanning, Philip Thompson
and Paul Sullivan in relation to the assets and business of San Leon (Morocco).
Tarfaya Morocco
12.2 Petroleum Agreement
The Petroleum Agreement (in respect of the Tarfaya onshore area in Morocco) was entered into
between ONHYM, Island International Exploration Morocco (“Island”), San Leon (Morocco) and
Longreach Oil and Gas Ventures Limited (“Longreach”) and dated 15 November 2007. The
Petroleum Agreement which is governed by Moroccan law records that the parties have filed with
the Ministry in charge of Energy in Morocco applications in respect of seven Exploration Permits
in the Tarfaya area. Island, a company incorporated in Morocco is appointed the operator under
article 19 of the Petroleum Agreement.
San Leon (Morocco) has a 22.5 per cent. interest in the Exploration Permits granted to the parties
by the Minister in charge of Energy, Island, Longreach and ONHYM hold the remaining
30 per cent., 22.5 per cent. and 25 per cent. respectively. Each of the Exploration Permits granted
may not have an aggregate duration exceeding eight years divided into periods as follows (i) an
initial period of two and a half years, (ii) a first extension period of three years and (iii) a second
extension period of two and a half years. In the event that hydrocarbons are discovered in the last
year of the second extension period of an Exploration Permit the parties will have the right to apply
jointly for an extension of this latter in accordance with Moroccan Law. Pursuant to the terms of the
Petroleum Agreement the parties are permitted to carry out exploration and appraisal studies and
operations in order to establish the existence of hydrocarbons in commercially exploitable quantities
subject to the terms of an Exploration Permit or an exploitation concession (details of which are set
out below).
During the initial period of 2.5 years, Island, San Leon (Morocco) and Longreach (hereinafter
“ISALO”) have committed to carry out pursuant to article 4.2 of the Petroleum Agreement a
minimum exploration work program the estimated cost of which is US$2 million. If ISALO
decides to enter into the first extension period of three years from the end of the initial period
ISALO would have to carry out a minimum exploration work program to include drilling one well
and acquiring 250KM2 of 3D seismic, the estimated cost of which is US$5 million. If ISALO
decides to enter into the second extension period of two and a half years from the end of the first
extension period, ISALO would have to carry out a minimum exploration work program including
drilling 2 wells, the estimated cost of which is US$8 million.
ISALO is required to provide irrevocable bank guarantees to ONHYM in order to secure the
completion of the minimum exploration work programs; ISALO is required to grant prior to
entering into the Petroleum Agreement a bank guarantee for US$1 million in respect of the
minimum exploration work program for the initital period of 2.5 years. Each time ISALO decides
to enter into an extension period as provided for in the Petroleum Agreement, at the time of such
an application, ISALO would have to provide a bank guarantee to ONHYM in respect of an
amount equal to 50 per cent. of the estimated cost of the minimum work program for such
extension period.
170
Under article 5.1 of the Petroleum Agreement the discovery of a commercially exploitable
hydrocarbon deposit gives ISALO the right to obtain an exploitation concession for a maximum
duration of up to 25 years. This 25 year period may be extended once only for a period of 10 years
on application by all the parties. The interests of the parties in any such exploitation concession
would be identical to that of the parties in an Exploration Permit. Under article 11 each of the
parties must pay the Moroccan state an annual royalty equal to its interest in the hydrocarbons
produced from each exploitation concession as follows: (i) 10 per cent. of any production of crude
oil in excess of 300,000 tons from an exploitation concession and (ii) 5 per cent. of the production
of natural gas in excess of 300 million cubic meters from an exploitation concession. Under
article 15, ISALO agrees to pay the Moroccan state in the event that a deposit of hydrocarbons is
declared to contain commercially exploitable quantities a discovery bonus of US$500,000 within
30 days of the grant of the exploitation concession. In the event that the total production of crude
oil from all exploitation concessions granted in accordance with the Petroleum Agreement are
maintained for a minimum period of 30 consecutive days ISALO shall pay the Moroccan state an
additional bonus payment which commences at US$1 million in the case of 75,000 BOPD/BOE
and increases progressively to US$3 million in the case of 300,000 BOPD/BOE.
Pursuant to article 17 no transfer of ISALO’s interests in the Exploration Permits can occur
without the prior written authorisation of the Minister in charge of Energy. Article 18 requires
ISALO to enter into an association agreement with ONHYM simultaneously with the entry into
the Petroleum Agreement.
12.3 Association Contract
The association contract is made between ONHYM, Island, San Leon (Morocco) and Longreach
which also relates to the Tarfaya interest in Morocco and is dated 15 November 2007 (the
“Association Contract”). The Association Contract regulates the conduct of exploration and
exploitation operations and the relationship between the parties. Under article 2.1 ISALO
commits to execute the minimum work programs in relation to the 7 Exploration Permits in
accordance with the Petroleum Agreement.
Under article 3.2.6 of the Association Contract a jointly-owned non-profit operating company shall
be formed two years after any commencement of commercial production from the first exploitation
concession to replace the operator which is currently Island under the Petroleum Agreement. The
joint operating company would be owned by the parties in the same proportions as their respective
interests in the exploration concession. The operations and works of the parties would be carried out
by the operator under the supervision of a management committee. Under article 5.2 the management
committee is to be comprised of 3 representatives of ONHYM and 3 representatives of ISALO. In
general all costs and expenses incurred pursuant to the Petroleum Agreement and the Association
Contract by the operator in conducting joint operations in an exploitation concession shall be borne
by the parties in proportion to their interests in this exploitation concession.
Article 7 of the Association Contract requires ISALO to provide ONHYM with an irrevocable
bank guarantee issued by a Moroccan bank or a foreign correspondent of a Moroccan bank in a
form acceptable to ONHYM. The Association Contract states that “IOG” shall provide this bank
guarantee instead of “ISALO” which appears to be an error as the term “IOG” is not defined. The
amount of the guarantee is to be equal to 50 per cent. of the estimated costs of the minimum
exploration work program. A copy of the guarantee dated 3 January 2008 granted by Citygroup
in favour of ONHYM is attached in Appendix IV of the Association Contract.
Article 10 of the Association Contract provides that if a party wishes to abandon all or part of its
interest in an Exploration Permit or exploitation concession it is obliged to notify the other parties.
If a party opposes the abandonment, the abandoning party is obliged to assign their interest to be
abandoned to the non-consenting party without compensation. Article 11 of the Association
Contract provides that if any party receives an offer for any portion of its interest in the
agreement, the Exploration Permits or the exploitation concession, that party will notify the other
parties. Such notification will confirm the identity of the offering third party and the terms and
conditions of the offer and provide the other parties with an option to purchase the entire interest
proposed to be sold on the same terms and conditions proposed by the offeror in the same
171
percentage proportions as the percentage interests of all the parties exercising their rights. This
does not apply to a transfer to a parent company or its affiliates. The Association Contract is
subject to Moroccan law pursuant to article 16. The Association Contract becomes effective and
terminates simultaneously with the Petroleum Agreement.
Appendix V of the Association Contract deals with the joint operating company and provides that
it will be formed between ISALO and ONHYM and governed by the laws of Morocco.
12.4 Exploration Permits
Pursuant to ministerial orders n°639-08 to 645-08 published in the Moroccan Bulletin Officiel
dated 19 June 2008 seven Exploration Permits were granted in relation to the Tarfaya onshore area
to ONHYM and Island, San Leon (Morocco) and Longreach for a period of 2 years and 6 months
from 14 January 2008.
Zag Area Morocco
12.5 Reconnaissance Contract
The reconnaissance contract is dated 5 December 2006 (the “Reconnaissance Contract”) and is
between ONHYM, San Leon (Morocco), Island Oil and Gas Plc and GB Oil and Gas Ventures
Limited in relation to the Zag basin in Morocco. The parties filed a joint request for the granting
of an exclusive reconnaissance license (the “Exclusive Reconnaissance License”) which would be
valid for an initial period of 12 months commencing on the effective date which is assumed to be
25 December 2006.
This is in accordance with the:
(i)
the geographical co-ordinates of the license area which are set out in Annexe A and Annexe
B respectively to the Reconnaissance Contract; and
(ii)
Addendum No. 1 to the Reconnaissance Contract between ONHYM, San Leon (Morocco),
Island Oil and Gas plc and Longreach which states that Decision No. 09/06 dated
25 December 2006 signed by the Minister in charge of Energy granted the Exclusive
Reconnaissance License.
Pursuant to article I the initial period of 12 months (the “Initial Validity Period”) can be extended
in accordance with Moroccan law. Article III addresses the minimum reconnaissance work
program whereby San Leon (Morocco), Island Oil and Gas Plc and GB Oil and Gas Ventures
Limited (hereinafter “SIG”) commit to undertake in relation to the interest, geological field
studies, geochemical study, purchase and interpretation of satellite data and processing and
interpretation of available gravity and magnetic data, the cost of which is estimated to be
US$180,000. It is stated however that the cost of the minimum reconnaissance work program may
exceed the estimate.
Article IV provides that SIG are obliged to contribute to the training of ONHYM personnel during
the Initial Validity Period and any extension period (together the “Validity Period”) of the Exclusive
Reconnaissance License and provides for amounts allocated by SIG in the Initial Validity Period
of US$50,000. Article V provides that no later than the date of signing the Reconnaissance
Contract which is 5 December 2006 GB Oil and Gas Ventures Limited would issue an irrevocable
bank guarantee in the amount of US$100,000 to cover the risk of non fulfilment by SIG of the
minimum reconnaissance work program. SIG are obliged to deliver to ONHYM during or at the
end of the Validity Period complete reports on the research and evaluation studies and all
operations conducted in the area of the interest together with geophysical data and records and
established maps and all field data obtained.
SIG are obliged to communicate to ONHYM all technical results obtained and to hold periodic
technical presentations at any location decided by mutual agreement at least every 6 months during
the Validity Period. No later than 30 days before the end of the Initial Validity Period or any
extension period, SIG have to notify ONHYM of a decision to (i) abandon the rights in the area of
interest, (ii) specifically designate the area to retain for the continuation of the minimum
172
reconnaissance work program during the extension of the Validity Period or (ii) enter with
ONHYM into a petroleum agreement relating to the area of interest. The Reconnaissance Contract
is governed by the laws of Morocco.
12.6 Addendum No. 1
Addendum No.1 to the Reconnaissance Contract regarding the reconnaissance and evaluation of
the petroleum potential of the “Zag Basin” area between ONHYM, San Leon (Morocco), Island
Oil and Gas plc and Longreach is dated 23 November 2007 (the “Addendum”). The purpose of
the Addendum is to extend the Exclusive Reconnaissance Licence regarding the “Zag Basin” area
for 12 months as from 25 December 2007.
San Leon (Morocco), Island Oil and Gas plc and Longreach (“SIL”) undertake, for an estimated
cost of US$577 000, to carry out in the Zag area (i) the acquisition, processing and interpretation
of 15,000 km aeromagnetic data, and (ii) geological and geophysical studies. SIL will contribute
to the training of ONHYM personnel during this first extension period in accordance with the
provisions of the Reconnaissance Contract.
Upon or prior to the signing of the Addendum SIL is obliged to provide an irrevocable bank
guarantee in the amount of US$100,000 in favour of ONHYM to cover the non-fulfilment of the
minimum reconnaissance work program for the first extension period. The provisions of articles
II, IV, VI, VII, VIII, IX, X, XI and XII and Appendixes A and B to the Reconnaissance Contract
are applicable to the Addendum. These Appendixes A and B consist of a map of the Zag area
reconnaissance licence and the geographical coordinates (Datum Merchich) of the area of
21,807 km2.
12.7 Joint Operating Agreement
San Leon (Morocco) entered into a joint operating agreement on 26 July 2007 (the “Joint
Operating Agreement”) between Island Oil and Gas Plc and GB Oil and Gas Ventures Limited.
Under Article 4 of the Joint Operating Agreement the interest of the parties in the Reconnaissance
Contract and all costs and obligations in relation to the joint operations under the Joint Operating
Agreement are borne by the parties as follows:
San Leon (Morocco)
GB Oil and Gas Ventures Limited
Island Oil and Gas Plc
Fifty (50%)
Thirty (30%)
Twenty (20%)
San Leon (Morocco) is designated as the operator of the Joint Operating Agreement.
Netherlands
12.8 Royalty Agreement
Pursuant to a decree dated 16 November 2006 the Minister of Economic Affairs of the
Netherlands (“MEA”) granted the Production Licence in relation to The Netherlands Continental
Shelf Block Q13 to Nido Petroleum Limited (“Nido”). Pursuant to the same decree the MEA
granted approval for the transfer of the Production Licence from Nido to Nido and IOG and the
Production Licence came into effect from 17 November 2006 for a period of 15 years. The
Production Licence is awarded in respect of that part of Block Q13 the coordinates for which are
set out in article 2 of the Production Licence (which is referred to as “Block Q13a”). The current
operator appointed pursuant to the Production Licence is Island Netherlands B.V. (“INBV”). The
MEA consented by a decree dated 4 May 2007 to the transfer of the Production Licence from
Nido and IOG to Island Netherlands B.V. (“INBV”) and Aceiro Energy B.V. (“Aceiro”). By a
decree dated 30 November 2007 the MEA granted approval to the transfer of the Production
Licence from INBV and Aceiro to INBV, Aceiro and EnCore Oil Nederland B.V. (“Encore”).
San Leon (Netherlands) entered into a Royalty Agreement with INBV. Pursuant to the Royalty
Agreement San Leon (Netherlands) has a royalty interest of 1 per cent. in petroleum substances
from Block Q13a subject to an adjustment by reducing INBV’s share of production in proportion
to the reduction in the percentage of interest in the Royalty Area (as defined in the Royalty
Agreement) following any transfer, disposal or assignment to EBN. Pursuant to clause 3 of the
Production Licence EBN has been designated in accordance with article 90 sub 1 of the Dutch
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Mining Act. In view of the State participation through EBN, the 100 per cent. interest in the
Production Licence is de facto a 60 per cent. interest for INLBV, Encore and Aceiro jointly, and
a 40 per cent. interest for EBN. Pursuant to clause 2(b) of the Royalty Agreement, the overriding
royalty shall be adjusted by reducing INBV’s share of production from time to time in proportion
to the reduction in percentage of the interest of INBV in the Royalty Area following any transfer,
disposal or assignment to EBN. This means that the 1 per cent. royalty set out in clause 2 of the
Royalty Agreement is de facto a 0.6 per cent. royalty. However pursuant to clause 4 of the Royalty
Agreement if San Leon (Netherlands) does not take possession of and separately dispose of its share
of petroleum substances from Block 13a, the royalty is paid from the gross proceeds of the sale of
such petroleum substances with a deduction equal to a proportionate share of the transportation
costs. Transportation costs are the costs of transportation of the petroleum substances to their
respective sales delivery point(s), including the cost of transportation from (i) Block Q13a to a host
facility and (ii) from a host facility to the nearest mainland shore, and charged by a host facility for
gathering and onward transportation as included in any tariffing arrangements. Transportation costs
exclude any costs associated with the construction of the transportation system and any items of
capital expenditure not forming part of such tariffing arrangements.
12.9 San Leon Netherlands Acquisition
San Leon entered into a share purchase agreement on 11 July 2008 with Philip Thompson to
acquire the entire issued share capital in San Leon (Netherlands) from Philip Thompson, the
beneficial owner of the shares in San Leon (Netherlands) and a director of San Leon (the
“Netherlands Agreement”).
The acquisition of the shares in San Leon (Netherlands) pursuant to the Netherlands Agreement
was conditional on the approval of the Shareholders of San Leon and a number of related items.
As Philip Thompson was a director of San Leon and a director of San Leon (Netherlands) the
transaction had been entered into between related parties which required the approval of
Shareholders in accordance with Section 29 of the Companies Act 1990. The acquisition of the
entire issued share capital of San Leon (Netherlands) completed on 7th August 2008. The
consideration to be paid by San Leon to Philip Thompson for the shares in San Leon (Netherlands)
pursuant to clause 3.1 of the Netherlands Agreement is:(i)
a payment of US$1 million in cash on the day following the date the Company is admitted
to AIM; and
(ii)
following completion and on condition that San Leon (Netherlands) receives US$1 million
in royalties, a payment equal to 50 per cent. of the royalties received by San Leon
(Netherlands) in excess of US$1 million (the “Additional Payment”).
On 23 September 2008 San Leon entered into an agreement with Philip Thompson pursuant to which
the payment of the US$1 million pursuant to clause 3.1 of the Netherlands Agreement and the
Additional Payment is to be deferred until the expiry of one month from the earlier of the
commencement of production from the Block Q13a interest and a significant fundraising.
A significant fundraising is defined as the raising by San Leon following Admission of at least
€30 million by way of debt or pursuant to an allotment of shares or by a combination of debt
and shares.
San Leon is entitled following receipt of the first payment of the royalties by San Leon
(Netherlands) to make a payment equal to US$1.7 million to Philip Thompson in satisfaction of
and to discharge in full the Additional Payment. Philip Thompson provided warranties to the
Company in relation to the title to the shares in San Leon (Netherlands), the activities of San Leon
(Netherlands) and the Royalty Agreement.
The Netherlands Agreement also provides that should San Leon (Netherlands) become entitled to
any royalty in relation to Block Q13b in the Netherlands North Sea (which is composed of Block
Q13 other than Block Q13a) San Leon would procure that San Leon (Netherlands) would pay
50 per cent. of such payment to Philip Thompson. In the event that Philip Thompson or any legal
entity in which he has an interest becomes entitled to any royalty in relation to Block Q13b Philip
Thompson will pay 50 per cent. or an appropriate percentage of such payment to San Leon.
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U.S. Assets
12.10 Leasehold Interests
San Leon (USA) holds interests in the Leases covering an area of approximately 26 kilometres2
in Cheyenne County, Nebraska. The Leases were entered into by Western Nebraska Land Services
Inc (“WNLS”) as agent for the Company. The Leases were entered into between the landowners
and WNLS between September 2007 and July 2008 and assigned to San Leon (USA) Limited on
8 August 2008.
The Leases last for a period of between 18 months and 4 years (the “Term”). The Leases for a
Term of 18 months contain an option to extend the Term for 3 additional years exercisable at any
time prior to the expiration of the Term by paying to the lessor the sum of $10.00 per mineral acre
so extended. Each of the Leases continue after its Term for as long thereafter “as oil or gas of
whatsoever nature or kind is produced” from the land or drilling operations are continued as
provided for in the Leases and provide that if at the end of the Term oil or gas is not being
produced, but the lessee is engaged in drilling or re-working operations on the land, the Lease will
continue as long as operations are being carried on continuously on the land.
The lessee covenants under each of the Leases:
•
to deliver to the credit of the lessor an equal 1/8th part of all oil produced from the land;
•
to pay the lessor 1/8th of the gross proceeds each year for the gas from each well where
only gas in found if it is being used off the premises, and if the gas is used in the
manufacture of gasoline, a royalty of 1/8th at the prevailing market rate for gas; and
•
to pay the lessor for gas produced from any oil well and used off the premises or in the
manufacture of gasoline or any other product a royalty of 1/8th of the proceeds at the mouth
of the well at the prevailing market rate.
The Leases provide that the rights of the lessor and the lessee can be assigned.
12.11 Agreement with Western Nebraska Land Services Inc.
The Company entered into an agreement with WNLS on 2 July 2007 whereby WNLS agreed to
conduct land services on behalf of the Company and the Company agreed to pay for the land
services at a rate of US$500 per eight-hour day including travel time, plus expenses. The
agreement also provided that as additional compensation, WNLS shall retain or San Leon shall
assign, an undivided 1.0 per cent. of 8/8ths overriding royalty interest, in and to (i) all leases &
leasehold interests acquired by WNLS during the term of this agreement, and (ii) in all leasehold
interests acquired by or for the account of San Leon during the term of the agreement and during
the 6 month period immediately following termination of the agreement, in those lands in which
WNLS has conducted lease negotiations and in lands in which WNLS has provided services
pursuant to this agreement. The agreement provided that the royalty interest shall also be
applicable to any extensions, renewals, substitute leases, or new leases taken in lieu thereof, by
San Leon.
12.12 Agreement with James Mitchell
The Company entered into an agreement with Mr. James Mitchell on 1 April 2008 in relation to the
Cheyenne County 3D project. The agreement provides that James Mitchell will provide proprietary
professional knowledge and experience of a specified area in Cheyenne County, Nebraska, and
provide advice for the leasing, 3D seismic acquisition and interpretation, and exploration for oil and
gas. Under the agreement San Leon agrees to assign an undivided 5 per cent. of 8/8ths overriding
royalty interest (reduced to 4.5 per cent. if WNLS receive a 1 per cent. royalty for landman services)
in the following leases and leasehold interests:(a)
All leases and leasehold interest acquired within the identified area of Cheyenne County,
Nebraska, by or for the account of the Company, its affiliates, successors or assigns; and
(b)
Any extensions, renewals, substitute leases or new leases taken in lieu thereof by or for the
account of the Company, its affiliates, successor or assigns.
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The agreement provides that James Mitchell will advise the Company on leasing, and on seismic
design, shooting and processing and will also interpret 3D surveys on behalf of the Company. For
these and other services related to oil exploration in the identified area, the Company will pay
James Mitchell $1,000 per day.
12.13 Lock-in Agreements
Each of Paul Sullivan, Philip Thompson, Charles McEvoy and Oisin Fanning entered into Lock-In
Agreements with Daniel Stewart and the Company on 23 September 2008 undertaking not to
dispose of any interests they have in Ordinary Shares or other securities of the Company for a
period of one year from Admission (the “Hard Lock-in Period), except in the strictly limited
circumstances provided by Rule 7 of the AIM Rules. They each further undertook not to dispose
of any interests they have in Ordinary Shares or other securities of the Company for a further
period of 1 year following the expiry of the Hard Lock-in Period without the prior written consent
of Daniel Stewart, such consent not to be unreasonably withheld, during which period Daniel
Stewart will have the exclusive right to effect any such disposal on their behalf. The interests
subject to the undertakings are as described in paragraph 5.2 of this Part VI of the document.
12.14 Nominated Adviser & Broker Agreement
The Company and the Directors entered into a nominated adviser and broker agreement with Daniel
Stewart dated 23 September 2008 pursuant to which Daniel Stewart agreed to act as the Company’s
nominated adviser and broker. The Company has agreed to pay to Daniel Stewart a fee for its services
under the Agreement plus all reasonable expenses it occurs. The Agreement contains certain
undertakings given by the Company in respect of inter alia compliance with all applicable laws,
regulations and the AIM Rules. The Agreement continues for an initial period of 12 months from
Admission (unless terminated for any reason prior to such date in accordance with the terms of the
Agreement) and thereafter unless terminated on 3 months notice.
12.15 Admission Agreement
The Company and the Directors entered into the Admission Agreement pursuant to which Daniel
Stewart conditionally agreed to provide its reasonable assistance to the Company in connection with
obtaining Admission. The Company and the Directors have given certain warranties as to the accuracy
of the information contained in this document and other matters in relation to the Company and its
business. The Company has agreed to pay Daniel Stewart a corporate finance fee. The Company is also
responsible for all outlay and legal expenses of Daniel Stewart. The Company and the Directors have
also indemnified Daniel Stewart in respect of any loss arising out of inter alia Admission or claims
made against Daniel Stewart in connection with Admission.
13. Related Party Transactions
13.1 Philip Thompson, Oisin Fanning and Paul Sullivan Directors of the Company were the ultimate
beneficial owner of the shares in San Leon (Morocco) at the time of the share for share exchange
as detailed in paragraphs 3.8 and 12.1 of this Part VI of this document. The transaction was
approved by the Shareholders in accordance with Section 29 of the 1990 Act.
13.2 Philip Thompson, a Director of the Company was the ultimate beneficial owner of the shares in
San Leon (Netherlands) at the time of the purchase of such shares by the Company as detailed in
paragraph 12.9 of this Part VI of this document. The transaction was approved by the
Shareholders in accordance with Section 29 of the 1990 Act.
14. Summary Oil & Gas Regulation
14.1 Oil & Gas Regulation in Nebraska, United States of America.
NEBRASKA REGULATORY REGIME
The power and authority for the development of oil and gas in the State of Nebraska is set forth
in the statutory provisions of Neb. Rev. Stat. Section 57-901 through 57-923, inclusive, commonly
referred to as Nebraska Oil and Gas Conservation Act. Section 57-901 provides that it is declared
to be in the public interest to foster, to encourage and to promote the development, production and
utilization of oil and gas in the State in such manner as will prevent waste; and to authorize and
to provide for the operation and development of oil and gas properties in such manner that the
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greatest ultimate recovery of oil and gas be had and that the correlative rights of all owners be
protected. Said Statute further provides that it is the intent and purpose to permit each and every
oil and gas pool in Nebraska to be produced up to its maximum efficient rate of production,
subject to the prohibition of waste and subject further to the enforcement and protection of
correlative rights. Waste is defined as inefficient, excessive or improper use or dissipation of
reservoir energy and also the abuse of the correlative rights of any owner in a pool due to
non-uniform, disproportionate, unratable or excessive withdrawal of oil or gas therefrom causing
reasonably avoidable drainage between the tracts of land or resulting in one or more owners in
such pool producing more than his or her just and equitable share of the oil or gas from said pool.
The power and authority to enforce the provisions of the Nebraska Oil and Gas Conservation Act
is vested in the Nebraska Oil and Gas Conservation Commission (the “Commission”), which is
located in Sidney, Cheyenne County, Nebraska. The Commission consists of three members
appointed by the Governor. Neb. Rev. Stat. Section 57-905 provides that the Commission shall
have jurisdiction and authority over all persons and property, public and private, necessary to
enforce effectively the provisions of the Nebraska Oil and Gas Conservation Act, including the
authority to make such investigations as it deems proper to determine whether waste exists or is
imminent or whether other facts exist which justify action by the Commission. This also includes
authority over the drilling and plugging of wells, the operation of wells, the metering or other
measuring of oil, gas or other products and pipelines or gathering systems and maintaining all
records with regard to drilling, production and plugging of wells. The Commission has specific
authority in Neb. Rev. Stat. Section 57-905 (7), to promulgate and to enforce rules, regulations
and orders to effectuate the purposes and intent of the Nebraska Oil and Gas Conservation Act.
Spacing units shall be established that are uniform in shape for the entire pool, which may be
effectively and economically drained by one well. Unleased owners and non-participating
working interest owners of separately owned tracts within a spacing unit may be involuntarily
pooled with statutory penalties for non-consenting working interest owners pursuant to Neb. Rev.
Stat. Section 57-909. Unless otherwise determined by special Order of the Commission, the
general spacing unit in the State of Nebraska is 40 acres, with the set back requirement being
500 feet if the well is in excess of 2,500 feet and 300 feet if the well is 2,500 feet or less.
Pools, or parts thereof, may be unitized, usually for secondary recovery, if said unitization is in the
public interest, protective of correlative rights and reasonably necessary to increase ultimate recovery
or to prevent waste of oil or gas. This is accomplished by the execution of an Operating Agreement
which must be signed by 65 per cent. of those owners bearing the cost of Unit operation and by
execution of a Unit Agreement signed by at least 75 per cent. of those total owners having an interest
in the total Unit production or proceeds thereof. This is based upon Neb. Rev. Stat. Section 57-910,
et. seq. Unitization requires a public hearing and approval by Order of the Commission.
In order to proceed with drilling operations, it is necessary that an operator file a bond with the
Commission in the amount of either $5,000.00 per well or a blanket bond in the amount of
$25,000.00. It is then necessary that the operator file a request for a drilling permit, which permit
is issued by the Commission. Subsequent to completion, a Well Completion Report is filed with
the Commission, together with the Well Logs. The operator may request that the well completion
report and remaining documents and information remain confidential and not disclosed to the
public for a period of 12 months from the time the logs were run.
Currently, there is a 3 per cent. severance tax to the State of Nebraska, together with a
conservation tax based upon the sales of oil or gas. In addition, there are ad valorem taxes due to
the county in which the producing well is located. These include a tax at the county's mill levy of
the fair market value of the real estate involved and an additional personal property tax upon
tangible equipment located at the well and tank battery.
The two main sources of leases are from the State Board of Educational Lands and Funds of the
State of Nebraska for State owned land and from private individuals, corporations, partnerships,
L.L.C. and entities with regard to privately owned lands. Typically, the leases will vary from three
to five years, with the customary landowner royalty being 1/8th. With regard to leases obtained
from the State of Nebraska, said leases are subject to the provisions of Neb. Rev. Stat.
177
Section 72-901, et. seq. The maximum amount of acres to be leased is 640 acres, which is a
section of land. Leases are sold at public auction in Lincoln, Nebraska. If the land is located in a
county where there is no oil or gas production, the minimum required bonus is $1.00; together
with a 1/8th royalty. If the land is located in a county where there is production of oil or gas, the
minimum required bonus is $2.00 and a 1/6th royalty. The Board of Educational Lands of the
State of Nebraska holds sales twice a year.
Drilling operations have increased dramatically in the past few years, from a low of approximately
18 wells drilled in 1999, to approximately 120 wells drilled in 2007. As of August 1, 2008, 198
Drilling Permits had been issued by the Commission and approximately 112 wells have been drilled.
There is neither a standard nor required oil and gas lease for privately owned land in the State of
Nebraska. However, oil and gas leases in the State of Nebraska usually contain the following basic
provisions and terms:
1.
The primary term of the oil and gas Lease, together with language that the oil and gas lease
continues in the event there is production of oil or gas at the end of the primary term.
2.
Provisions allowing for continuation of the oil and gas lease if there are production
operations commenced and still in effect at the end of the primary term, together with
provisions that if production ceases after the end of the primary term, the operator is
granted a certain period of time in which to commence additional operations, usually
between 60 and 180 days.
3.
Royalty upon oil or gas; the customary amount of which is 1/8th.
4.
Delay rentals and a depository for payment of delay rentals upon a yearly base unless the
oil and gas lease is a paid-up lease, whereby all bonuses and delay rentals are paid at the
beginning of the lease.
5.
A shut-in gas provision whereby if a well capable of producing gas is shut-in the lease
continues after the primary term by payment of a per acre royalty per year; typically
US$1.00 to US$3.00.
6.
Provisions allowing assignment of the oil and gas lease by the lessor and lessee with an
additional provision that the lessee is not bound by the change of ownership and assignment
until notified by the lessor.
7.
Provisions for damages caused by lessee’s operations on the land.
8.
Pooling provisions which vary substantially as to the size of the area to be pooled.
9.
Provision that the oil and gas leases are subject to federal and state rules and regulations.
10.
A warranty of title provision which often times the landowner will strike. However, striking
the warranty clause does not invalidate the lease but merely provides that the lessor is not
liable for damages in the event of failure of title.
Many oil and gas leases will also have additional provisions attached by the landowner
concerning location, restoration of the surface, access, non-interference with irrigation and
livestock operations, damages, etc.
14.2 Oil & Gas Regulation in Morocco.
14.2.1. Purpose and scope of analysis
This paragraph summarises the law and decree governing oil and gas licenses in
Morocco, namely (i) the Dahir 1-91-118 dated April 1, 19921 enacting law 21-90
relating to the exploration for and the exploitation of hydrocarbons deposits (hereafter
the “Law”), and (ii) the Decree 2-93-786 dated November 3, 1993 implementing the
Law2 (hereafter the “Decree”).
1
As subsequently modified by Dahir 1-99-340 of February 15, 2000
2
As subsequently modified by Decree 2-99-210 of March 16, 2000
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The Law regulates the reconnaissance, exploration for and exploitation of natural
hydrocarbons (including crude oil and natural gas) in the land3 and offshore4 sectors,
together with activities ancillary thereto (Article 1 of the Law).
14.2.2 General provisions
Natural hydrocarbon deposits are public property of the State (Article 1 of the Law).
All geological, geochemical or geophysical reconnaissance, the exploration for hydrocarbon
deposits and their exploitation are subject respectively to the obtaining of a reconnaissance
license, an exploration permit or an exploitation concession (Article 4 of the Law).
Temporary occupation – The holder of a reconnaissance license, an exploration permit
or an exploitation concession may, in the absence of an amicable agreement with the
landowners, be permitted by the administration to occupy temporarily the areas situated
within the reconnaissance license, the exploration permit, or the exploitation concession
which are needed for the exploration, the exploitation and transport of hydrocarbons or for
the establishment of railways, workshops and ancillary industries.
Evidence – Only written evidence is accepted in matters covered by the laws and
regulations relating to hydrocarbons.
14.2.3 Reconnaissance license
The reconnaissance license confers on its beneficiary the right to carry out all activities
necessary for the satisfactory conclusion of the reconnaissance works.
All the results of the reconnaissance works are communicated to the Minister of Energy
free of charge according to the terms determined in the license (Article 21 of the Law and
Article 5 of the Decree).
Several reconnaissance licenses may be granted concurrently over the same area except
where the first license confers exclusive rights on its holder (Article 20 of the Law).
Application (Article 2 of the Decree) – An application for a reconnaissance license must
be filed with the Ministry of Energy that comes with documents showing the applicants’
technical and financial capabilities.
It must contain information such as:
•
the company name of the applicant as well as its articles of association and its
registered address,
•
the name of the legal representatives of the applicant legal entity,
•
details of reconnaissance licenses or exploration permits, whether expired or not,
which have already been granted,
•
the exact coordinates of the area covered by the requested reconnaissance license or
exploration permit, together with an extract from a topographic map,
•
the overall program and timetable for the works as well as the minimum financial
investment which the applicant undertakes to allocate to the carrying out of such works.
Licence – The reconnaissance license is issued by a decision of the Minister of Energy
(Article 4 of the Decree). It may only be granted for areas which are not covered by
hydrocarbon exploration permits or exploitation concessions (Article 20 of the Law).
3
i.e. the territory delineated to the west by the Atlantic Ocean, to the north by the Mediterranean Sea, to the east and to the South
by the frontiers of the Moroccan State.
4
i.e. the sea-bed and the subsoil of the regions adjacent to the Moroccan coastline extending to the point where the depth of the
water permits the exploitation of the hydrocarbon deposits of such regions but without prejudice to international conventions
duly ratified by the Moroccan State, and particular geographical or geomorphological circumstances in which the delineation
of territorial waters is determined by agreement between States.
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The license contains the period of validity, the conditions applicable to the giving and
repayment of guarantees and deposits, the holder’s obligations and the limits within which
the license is valid.
The reconnaissance license is granted for a maximum initial period of one year from the
date of its notification and may be extended for one or several periods of maximum
duration of one year each and either for part of or for the same area, on condition that
liabilities undertaken during the first period have been fulfilled (Article 20 of the Law).
An application for renewal of the reconnaissance license must be filed at least one month
prior to the expiry of the preceding period (Article 4 of the Decree).
Transfer – Reconnaissance licenses are non-transferable (Article 20 of the Law).
14.2.4 Exploration permit and exploitation concession
General provisions – Exploration permit and exploitation concession create titles of a
limited duration which do not confer on their holder any proprietary right over either the
ground itself or the sub-soil (Article 6 of the Law).
The holders of exploration permits or exploitation concessions must send a report on the
setting up of operations to the Minister of Energy no later than fifteen days prior to the
commencement of drilling operations for the exploration or exploitation of hydrocarbons
(Article 40 of the Decree).
Surrender (Article 7 of the Law and Articles 12 and 26 of the Decree) – The holder of an
exploration permit or an exploitation concession, who has carried out its obligations
within the stipulated time limit and that the concession’s dependencies are free of any
encumbrance or charge, has the right to withdraw either in part or in total.
When the permit or the concession are assigned jointly to several holders, the
withdrawal of one or several of them does not entail the partial or total cancellation of
the permit or the concession if one or the other holders take responsibility for all
liabilities previously assumed by the one or those withdrawing.
However, as regards the concession, the State benefits from a pre-emptive right of three
(3) months from the date of notification of the withdrawal to the administration over the
use of part or all of the part relinquished.
The State may delegate to a governmental agency to perform on its behalf the exercise of
the pre-emptive right (Article 71 of the Law).
If the State does not exercise the aforementioned pre-emptive right and the holder or the
other holders of the concession do not take responsibility for the relinquished part, then
the withdrawing concession holder must clean the site, at his own expense, in such a way
as is generally accepted in the oil industry.
Transfer (Article 8 of the Law and Articles 19 and 27 of the Decree) – Any partial or total
transfer of interest in an exploration permit or an exploitation concession must relate to
the whole of the area covered by this permit or concession and will be notified to the
Minister of Energy for prior authorization of the latter.
The transferee takes responsibility for all liabilities assumed by the transferor.
An order from the Minister of Energy declares the part or whole permit which is
transferred in favour of the transferee.
Where the transfer of the exploitation concession is made in favour of a third party other
than the parent company or an affiliate of the transferor, the State may exercise a right of
pre-emption of 120 days from the notification of the transfer’s project.
The transfer is authorized, if need be, by decree upon the proposal of the Minister of Energy.
180
The State may delegate to a governmental agency to perform on its behalf the exercise of
the rights of pre-emption (Article 71 of the Law).
Leasing – The leasing, partial or total, of an exploration permit is subject to the prior
consent of the Minister of Energy (Article 9 of the Law and Article 20 of the Decree).
For exploitation concession, the leasing must receive prior authorization under the prescribed
procedure for transfers of concessions (Article 28 of the Decree).
The leasee of an exploration permit or an exploitation concession is subject to the
obligations deriving from such permit or concession (Article 9 of the Law).
Contracts relating to any rentals of sites used for the purposes of an exploitation
concession must include a clause reserving to the State the right to substitute itself for the
concession holder either in the event of the latter’s withdrawal or in the event of the
concession being taken away, or if the normal expiry date of the concession should occur
during the term of the contract (Article 10 of the Law).
The State may delegate to a governmental agency to substitute itself for the concessionholder (Article 71 of the Law).
Limitation – No exploration or exploitation activity may be undertaken at ground level
within a zone of fifty (50) metres around properties enclosed by walls or by other means,
villages, dwelling places, wells, religious edifices, burial places, transportation routes,
water pipes and, in general, all constructions of public utility or public works, except with
the consent of the owner as regards private property or of the administration or of the
relevant local district authorities as regards the public sector, constructions of public utility
or public works of art (Article 11 of the Law).
Ancillary activities of holders of exploration permits and exploitation concessions for
hydrocarbons – Holders are responsible for setting up all installations necessary for their
exploration and exploitation works which are of no interest to the general public (Article
51 of the Decree).
Holders benefit from a special treatment from the State when installations necessary for
their exploration and exploitation works which are of interest to the general public (Article
53 of the Decree).
Miscellaneous – The exploration and exploitation of hydrocarbons are considered as
commercial acts (Article 18 of the Law).
14.2.4.1
Exploration permit
The exploration permit confers on its holder the exclusive right to prospect
for deposits of hydrocarbons in the territory to which it relates (Article 23 of
the Law).
The exploration permit may only be granted to a legal entity or, on a joint basis,
to several legal entities. It is assigned by an administrative order given by the
Minister of Energy which is notified to the applicant and published in the
Bulletin Officiel (Article 22 of the Law).
Application – An application for an exploration permit must be filed with the
Minister of Energy and contains the same information than the application for
a reconnaissance licence.
The applicant must demonstrate that it has both the technical skills and
financial support necessary to complete the exploration activities in question.
The applicant must also commit to carry out a minimum program of works that
goes with a corresponding financial commitment and a provisional schedule
for its fulfillment.
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The exploration permit may include an obligation for its holder to provide a
deposit in order to guarantee its contractual obligations (Article 22 of the Law).
To be receivable, each application for an exploration permit and for an
extension period is accompanied by a receipt of payment to the treasury
(“Trésorerie Générale”) of the institution fee which amount is fixed at 1000
dirhams (Article 43 of the Law and Article 6 of the Decree).
Exploration permits will be attributed within sixty (60) days of the date on
which applications are filed (Article 7 of the Decree).
The granting of the exploration permit is subject to the conclusion of a
petroleum agreement with the State (Article 4 of the Law).
Duration – The total period of validity for an exploration permit cannot
exceed eight (8) consecutive years which shall consist of an initial period
which may be followed by one or two additional successive periods if the
holder of the permit has fulfilled its undertakings (Article 24 of the Law and
Article 9 of the Decree). However, when hydrocarbons are discovered during
the last year of validity of the permit, its duration may be extended by the
Minister of Energy for an exceptional period which may not exceed two
(2) years in order to evaluate such discovery (Article 24 of the Law and
Article 11 of the Decree).
Any application for an additional period during the period of validity of the
exploration permit must be filed with the Ministry of Energy no later than two
months prior to the expiry of the current period. An administrative order given
by the Minister will determine the duration of the additional period requested
and will define the area of the exploration permits retained by the holder
(Articles 15 and 18 of the Decree).
Each extension is accompanied by a reduction in the area of the permit (Article
24 of the Law). Indeed, the initial surface area will be scaled down n times 10
per cent. upon the first of the permit’s additional periods (n being the number
of years constituting the initial period of the said permit). For the second
additional period, the permit’s surface area will be scaled down such that it is
reduced to a maximum of 50 per cent. of its initial surface area (Article 10 of
the Decree).
Surface (Article 25 of the Law) – The surface area of an exploration permit may
not be less than 200 square kilometers nor greater than 2,000 square kilometres.
A legal entity may not, directly or indirectly hold exploration rights relating to a
surface area greater than 10,000 square kilometres in the land sector and 20,000
square kilometres in the maritime sector, except as a derogation granted by the
administration with regard to permits located in sectors not greatly explored.
Obligations of holders of exploration permit (Article 39 of the Law and
Article 21 of the Decree) – On risk of forfeiture of the exploration permit
declared by an order of the Minister of Energy setting out the reasons for such
a decision if no action is taken to make good the default within thirty days of
formal notice having been served, the holder of such permit is notably required:
•
to commence implementation of the works program within a time limit
fixed by the ministerial order and not to interrupt such work without
valid reason;
•
to carry out, according to the rule book, the agreed exploration
work program;
182
•
to observe any particular undertakings given at the time of the granting
of the permit;
•
to notify the administration in writing of all discoveries of hydrocarbons
or other mining resources within a time limit of three days;
•
to store in Morocco the cores as well as all samples concerning
hydrocarbons and mining products;
•
to effect without delay appraisal drillings to permit an evaluation of all
potentially commercial discoveries.
The holder of an exploration permit must inform the Minister of Energy in
writing, within a period of not more than three (3) days from the time when the
discovery is made, of any discovery of hydrocarbons or other mining resources
(Article 36 of the Decree).
14.2.4.2
Exploitation concession
The holder of an exploration permit who has fulfilled its legal and contractual
obligations, has the right, in the event of a discovery of a commercially
exploitable hydrocarbon deposit, to obtain an exploitation concession over this
deposit (Article 27 of the Law).
Applications for concessions must be filed with the Ministry of Energy no later
than three months prior to the expiry of the period of validity of the exploration
permit. The application must give approximately the same information than for
a reconnaissance license, and, in addition, the following: a map in triplicate on
a scale of 1/10000, a technical report, the program of the development works,
an economic and commercial study relating to the exploitation of the deposit
discovered (Article 23 of the Decree).
Granting – This concession is granted by decree upon the Minister of Energy
proposal notified to the applicant and published in the Bulletin Officiel
(Article 27 of the Law and Article 24 of the Decree).
This act cancels that part of the area of the exploration permit covered by the
concession and definitively rules on the assignment, the limits and the scope of
the exploitation concession (Article 27 of the Law).
Duration – The period of validity of an exploitation concession may not
exceed twenty-five (25) years. However, a single exceptional extension may be
granted by an administrative act if the reasonable and economical exploitation
of the deposit justifies it (Article 29 of the Law).
Applications for exceptional extension must be filed with the Ministry of
Energy at least two (2) years before the expiry of the period of validity of the
concession. The extension is granted by decree upon the proposal of the
Minister of Energy that states the length of the extension of the concession
which may not exceed ten (10) years (Article 25 of the Decree).
Fees – The holder or, if need be, each of the co-holders of an exploitation
concession must pay to the Treasury (“Trésorerie Générale”) proportionally to
its share of interest an annual rental fee of 1000 dirhams per square kilometre
(Article 43 of the Law and Article 34 of the Decree).
It must also pay to the Treasury an annual royalty on its production share
according to rates varying whether it is crude oil or natural gas, and the weight
of the production. For the calculation of the royalty, quantities of hydrocarbons
used within the limits of the concession for the needs of direct or assisted
exploitation of the deposit are not taken into consideration (Article 44 of the
Law and Article 34 bis of the Decree).
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The holder or, if need be, each of the co-holders will submit to the Treasury,
within the 90 days following the end of each calendar year, a final annual
statement of the annual royalty calculated as being the product of its share
of the volume of the annual royalty and the weighted average sales price
realized during the calendar year terminating December 31, and pay the
difference between the calculated actual amount due and the sum of
semestrial payments made.
Taxes – The holder, or as the case may be, each of the co-holders of an
exploitation concession benefits of a total exemption from corporate income
tax for a ten consecutive year-period for each exploitation concession starting
at the date of commencement of regular production from each such
exploitation concession (Article 42 of the Law).
The holder or, if need be, each of the co-holders of an exploitation concession
may, if he wishes, make an allowance for the “reconstitution” of hydrocarbon
deposits that shall be exempted from corporate income tax. This allowance
must be used to undertake hydrocarbon reconnaissance exploration and
development works (Article 45 of the Law).
Exemptions (Article 62 of the Law) – Holders of an exploration permit or an
exploitation concession benefit from the exemption from:
•
professional tax (“taxe professionnelle”);
•
the urban tax introduced by the Law no. 37-89 other than the municipal
tax (“taxe des services communaux”);
•
the tax on non-developed urban areas introduced by the Law n°30-89
relating to the tax regime for local communities and their groupings).
Obligations of holders of exploitation concession (Article 40 of the Law and
Article 30 of the Decree) – On risk of forfeiture of the concession declared by
a decree upon the Minister of Energy’s proposal giving reasons for the decision
if no action is taken to make good the default within ninety days of formal
notice having been served, the holder of such concession is notably bound:
•
to conduct the development and the putting in production of the deposit
without delay;
•
to carry out the agreed development program;
•
to exploit the deposit in a reasonable manner and in accordance with
good oil field practices;
•
to abide by any particular undertakings given at the time of allocation of
the concession;
•
to notify to the administration in writing within the time limits
determined by regulations all useful information relating to the progress
of the works, the results obtained and any additional exploration.
The concessionaire must provide the Minister of Energy with all relevant
information in writing as regards the progress of work, the results obtained and
any further exploration which may need to carried out (Article 37 of the Decree).
In the event of forfeiture of the concession for one of the aforementioned
reasons, the administration will issue an invitation to tender in which the
forfeiting concession-holder may not take part. The State may during the
month following the auction, exercise a pre-emptive right that it may delegate
to a governmental agency to perform on its behalf the exercise of the preemptive right (Articles 31 and 71 of the Law).
184
When this invitation to tender does not produce any results, a decree, setting
out reasons for the decision, upon the proposal of the Minister of Energy will
cancel the concession or pronounce its return to the State, free of charge and
restriction including its dependencies (Article 31 of the Decree).
Supply to the domestic market – The holder of an exploitation concession must,
before contemplating export of its share of production, contribute to the needs of
the local market according to the conditions defined in the petroleum agreement
(Article 41 of the Law).
Demarcation – of an exploitation concession may be required by the
administration. This may be carried out or supervised, at the expense of the
concession holder, by the administration.
On its expiry, the concession, together with its dependencies5, will revert, free
of all charges, to the State. This reversion will take place by an administrative act.
14.2.5 Petroleum agreement
As indicated above, the granting of an exploration permit is subject to the conclusion of a
petroleum agreement with the State that must be approved by the administration (Article 4
and 34 of the Law).
However, the State may delegate to a governmental agency to perform on its behalf the
conclusion of petroleum agreement with oil companies and the holding of the
participation in the exploration permits or exploitation concessions reserved for the State
(Article 71 of the Law).
This petroleum agreement which mentions that it is subject to Moroccan law, defines the
conditions relating to the exercise of the exploration and, if need be, the exploitation
activity within the areas covered by the exploration permit or the exploitation concession.
It also determines the terms and conditions of the State’s participation in such activities
that may not exceed 25 per cent. (Article 4, 32 and 34 of the Law).
It includes provisions relating notably to matters such as the boundary of the exploration
permit, works undertakings and the corresponding financial undertakings, the commercial
discovery, the percentages interests of the parties, the determination of hydrocarbon
prices, the allocation of production, the supply to the domestic market, the professional
training programs, the settlement of disputes, etc.
14.2.6 Obligations of holders of reconnaissance license, exploration permit or exploitation
concession
Holders must conduct their operations in compliance with hygiene and health and safety
standards in respect of both its employees and neighbouring populations, as well as in
respect of the environment (Article 32 of the Decree).
Medicine and safety equipment necessary for workers must be kept on the premises in
sufficient quantities (Article 33 of the Decree).
Holders are bound to repair the damage that its works cause to landowners as well as to
neighbouring exploration and exploitation works (Article 35 of the Law).
In the event of termination, for any reason whatsoever, of the rights of a holder of a
reconnaissance license, an exploration permit or an exploitation concession over all or part
of its area, the holder is bound to restore such area (Article 36 of the Law).
The holder of a reconnaissance license, an exploration permit or an exploitation
concession must contribute to the professional training of national executives and
technicians of the oil industry by involving them in the reconnaissance, exploration and
exploitation operations and to make them benefit from suitable training programs
(Article 37 of the Law).
5
The sites, buildings, construction works, machinery, equipment and engines of any sort used in the exploitation of the
concession constitute the dependencies of the concession.
185
The results of the geophysical survey must be sent to the Minister of Energy in the form
of a report upon the completion of the operations, or at six (6) monthly intervals if the
operations extend beyond a period of six months (Article 39 of the Decree).
The holder must keep a register of all drilling sites recording the conditions in which the
work is carried out, and ensure that all drillings are followed by a geological team, the
members and responsibilities of which must be communicated to the Minister of Energy
upon the latter’s request (Article 41 of the Decree).
The concessionaire must carry out a minimum amount of works, and notify the Minister
of the production forecasts (Article 47 of the Decree).
14.2.7 Provisions relating to tax, customs, international trade and foreign exchange
The hydrocarbons prices – used for the calculation of the corporation income tax shall
be the actual prices obtained in direct sales of hydrocarbons to national or foreign third
parties who are independent from the concession holders or, in absence of such prices, the
prices shall be based on the published prices of crude oil on the international market,
adjusted in particular to account for differences in quality and transport.
For the calculation of the royalty paid in cash for concessions, the price to be used is the
average value of the sales prices weighted by volumes sold during the period taken into
consideration as defined by regulations. Such prices are those defined above less all
expenses relating to sales commissions, transportation and/or delivery costs incurred
between the point of production and the point of sales (Article 46 of the Law).
Importation (Article 50 of the Law) – Holders of reconnaissance licenses, exploration
permits and exploitation concessions, their contractors and sub-contractors benefit from
an exemption from all duties and taxes on the importation of equipment, materials and
consumable products intended for use in the reconnaissance, the exploration and the
exploitation of hydrocarbons and in activities ancillary thereto.
However, the above exemption will not be granted if such equipment, materials and
consumable products can be supplied by the local market at a price within a maximum excess
of 10 per cent. of the CIF price and on equivalent conditions of quality and terms of delivery.
The personal property, effects and other personal objects in use belonging to the personnel
of the company that is the State’s partner, its contractors or sub-contractors, in the
reconnaissance, exploration and exploitation of hydrocarbons recruited from abroad, are
imported free of all duties and taxes in accordance with the legislation in force.
New objects may be imported under the regime of temporary importation.
The list of such equipment, materials, consumable products, personal property, effects and
objects is cleared by the administration.
Vehicles subject to the registration procedure which are the property of such personnel
benefit from the regime of temporary importation provided by section 145 et seq. of the
Customs and Indirect Taxes Code.
Customs (Article 52 of the Law) – Holders of reconnaissance license, exploration permit
and exploitation concession, their contractors and subcontractors have the benefit of
temporary importation, by way of exemption from the fee payable under Section 148 of
the Customs Code and from all duties and taxes for all pieces of equipment, materials and
consumable products intended for use in reconnaissance, exploration and exploitation of
hydrocarbons and works related thereto.
The duty of actual capital contributions – is fixed at 0.50 per cent. as regards
contributions made at the time of incorporation or increases in capital of companies
whatever the nature of the assets contributed.
The application of the above-mentioned capital duty leads to an exemption from the
transfer duty relating to the taking over of liabilities, as the case may be.
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Individual foreign holders of a reconnaissance license and companies which are holders
of a reconnaissance license or an exploration permit which are not incorporated as
Moroccan companies must provide for all their requirements in foreign currency
(Article 53 of the Law).
Sales – Foreign holders of an exploitation concession may retain outside Morocco the
proceeds of their sales of hydrocarbons made outside Morocco.
Foreign holders of exploitation concessions must periodically provide, in the form
required by exchange regulations, a statement of their assets held outside Morocco derived
from export sales of hydrocarbons, together with the payments made with these assets for
the operations relating to their activities as holders of a hydrocarbon exploitation
concession (Article 53 of the Law).
Exchange control – Notwithstanding the above, foreign concession holders are required
to return to Morocco such funds in foreign currency as are necessary to cover their local
expenses and their financial and fiscal obligations, in addition to the proceeds of their
sales in the local market (Article 56 of the Law).
Unless otherwise authorized by the administration which authorization may be granted in
order to meet requirements for foreign currency outside Morocco for the purpose of their
activities of exploration for and exploitation of hydrocarbons, Moroccan legal entities
which are holders of an exploitation concession are required to repatriate to Morocco the
proceeds of their sales of hydrocarbons made outside Morocco (Article 57 of the Law).
The transfer of the net proceeds of assets sale is guaranteed if the investment is made by
a foreigner. This guarantee relates to the capital contribution made by way of transfer to
Bank Al Maghrib if convertible foreign currencies and the net capital gain on the assets
sale (Article 58 of the Law).
The profits and dividends of the holders of an exploitation concession and those of the
shareholders of concessionary companies are exempt from the tax on income from shares,
capital rights and similar revenues, introduced by the Law no.18-88 promulgated by the
Dahir n°1-89-145 of the 23rd October, 1989 (Article 59 of the Law).
VAT – Holders of a reconnaissance license, an exploration permit or an exploitation
concession, their contractors and subcontractors are exempted, as regard to the goods and
services that they acquire in the local or foreign market required for their activities, from the
value added tax subject to provisions of the 2nd alinea of Article 506 (Article 61 of the Law).
The Tax Department (“Direction des Impôts”) will provide the holder of a reconnaissance
license, an exploration permit or an exploitation concession with a certificate enabling the
holder to purchase goods and services on the local market exempt from valued added tax
(Article 35 of the Decree).
14.2.8 Sanctions
Breaches of the Law and of its implementing texts will be the subject of legal proceedings
and penalties provided for by law, without prejudice, as regards the holders of exploration
permits or exploitation concessions, to the other sanctions provided for in this Law such as,
as the case may be, the forfeiture of the exploration permit or the exploitation concession.
The administration may decide that a person who has been the subject of a sanction in
accordance with the first paragraph above may not obtain a reconnaissance license or an
exploration permit or an exploitation concession throughout a period up to a maximum of
five years from the date of the sanction, if it is administrative, or from the date upon which
the sentence becomes irrevocable if it is a judicial sanction.
6
However, the exemption from all duties and taxes on the importation of equipment, materials and consumable products
intended for use in the reconnaissance, the exploration and the exploitation of hydrocarbons and in activities ancillary thereto
will not be granted if such equipment, materials and consumable products can be supplied by the local market at a price within
a maximum excess of 10 per cent. of the CIF price and on equivalent conditions of quality and terms of delivery.
187
To this effect, an extract of all convictions judgments is addressed to the administration
(Article 68 of the Law).
All work undertaken contrary to the provisions of this Law and the texts concerning its
application may be suspended by administrative measures without prejudice to the
application of the provisions of Article 68 of the Law above.
14.3 Oil & Gas Regulation in The Netherlands.
14.3.1 Mining laws of The Netherlands
As from 1 January 2003 the new mining legislation (Mijnbouwwetgeving) consisting of
the Mining Act, the Mining Decree and the Mining Regulation entered into force. The new
Mining legislation replaced the old Mining Act from 1810.
State Participation
The Dutch Mining Act stipulates that the Minister of Economic Affairs (“MEA”) may
designate a company through which the State will participate in the exploration and
production of hydrocarbons.
Energie Beheer Nederland B.V. (“EBN”), a company in which the State holds all the
shares, is designated in individual licenses for this purpose.
If a company wants to explore mineral resources (hydrocarbons) in the Netherlands, an
exploration license is required pursuant to the Mining Act. Articles 81 to 88 of the Mining
Act stipulate that at the request of the license holder, EBN may participate in offshore
exploration activities. If EBN participates, EBN and the license holder will carry out
exploration activities at their joint expense. The rights and obligations of the parties are set
out in a cooperation agreement between the license holder and EBN (overeenkomst van
samenwerking). This agreement of cooperation is to be approved by the MEA. The license
holder(s) ha(s)(ve) an interest of 60 per cent. and EBN an interest of 40 per cent.. These
percentages have been set out in the Mining Act.
If an exploration license leads to hydrocarbons being found, and it has been demonstrated that
production will be economically feasible, the holder of the exploration license may apply for
a production license. The State again may designate a company (EBN) to participate in the
mining activities under this production license. The interest of the license holder is set in the
Mining Act at 60 per cent., and that of EBN at 40 per cent.. The rights and obligations are set
out in a cooperation agreement between EBN and the license holder (overeenkomst van
samenwerking). This agreement also requires the approval of the MEA.
The principal rule is that there is a requirement for State participation in the production. Only
if production is expected to be financially disadvantageous to the State, or if the risks
involved are estimated to be too high, will the MEA waive state participation with the
granting of the license.
In view of the State participation through EBN, the 100 per cent. interest in a license
is de facto a 60 per cent. interest for the license holder(s) (jointly) and a 40 per cent.
interest for EBN.
If EBN has not been involved in the exploration activities under the exploration license
which precedes the production license, the agreement of cooperation will state that EBN
will pay the license holder a sum of 40 per cent. of the costs incurred for the discovery of
hydrocarbons, the further exploration and the subsequent investments for mining activity.
This compensation is referred to as the initial contribution.
Recent legislation (Staatsblad 2008, 248) allows for the possibility for EBN to undertake a
wider range of commercial activities. Such activities require the prior approval of the MEA.
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Transfer of interest
Article 20 sub 1 of the Dutch Mining Act stipulates that a license holder may only transfer
his interests in a license after having obtained the prior written approval of the MEA.
Article 20 also applies in the event the license holder no longer exists as a legal entity as
a result of a legal merger (juridische fusie).
The MEA may refuse approval for a request pursuant to article 20 sub 1 on the grounds
set out in article 9 sub 1 of the Mining Act, being:
(a) in view of the technical and financial capabilities of the transferee (if it is not
sufficiently certain that the transferee can meet the obligations under the Mining Act
regarding the granting of security for liability for earth movement, decommissioning
or payment of taxes);
(b) the manner in which the transferee proposes to perform the activities for which the
license has been granted;
(c) lack of efficiency and social responsibility of the transferee.
The approval of the MEA is published in the National Gazette (Staatscourant).
In the event of a change of control with regard to the license holder article 21 sub 1 of the
Dutch Mining Act does not apply. A change of control does not have any legal
consequences. Please note however that in the event of a change of control of the licensee,
a license may be revoked by the MEA pursuant to either article 21 sub 1under c in the event
that the new shareholder of the licensee does not have sufficient financial or technical
capability, and the license was granted on the basis of such shareholder/group technical and
financial capability and such information is no longer correct after the change of control.
Upon MEA approval having been obtained, the transfer of the interests in the license takes
place through the valid execution of a deed of transfer and assignment between the
transferor(s) and the transferee(s). The MEA is to be notified of the actual date of transfer.
Liability for decommissioning liabilities
Pursuant to article 44 of the Mining Act unused mining installations are to be removed.
Pursuant to article 45 unused cables and pipelines are to be removed. These obligations
rest pursuant to article 44 jo 41 sub 4 on the license holder or if there are more license
holder on the operator (the entity designated pursuant to article 22 Mining Act) of the
mining installation or the manager of the pipeline (or the last known operator or manager).
Pursuant to article 47 and 48 of the Mining Act the MEA may demand security for the
removal costs.
Liability for environmental liabilities
At the time of the entry into force of the Dutch Mining Act (January 1, 2003), a new
paragraph 6:177 was added to the Dutch Civil Code.
This provision sets out a strict liability (risico-aansprakelijkheid) for the holder of the
license (or if more on the operator) of mining installations as defined under the Mining Act.
For the exploration and production of gas and oil other licenses and permits may be
required, such as an Environmental Permit.
Termination/revocation of licenses
Under the Article 21 sub 1 of the Mining Act, the MEA can revoke a license if:
a)
the data or documents accompanying the application are found to be inaccurate or
incomplete to the extent that a different decision would have been taken, had during
the evaluation the true circumstances been known, or
b)
the license is no longer necessary for the proper execution of the activities to which
it applies,
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c)
revocation is justified because of a change in the technical or financial capability of
the holder,
d)
the activities are not carried out in conformity with the license, or
e)
the rules applying to the holder of the license or the persons designated to carry out
the actual operations in relation to the field are not being observed.
The MEA shall not proceed with revocation on the ground of (d) or (e) above until he has
warned the license holder(s) in writing, and the holders or the designated person referred
to in Article 22 (operator) continues or repeats the infringement after having been notified.
Please note that the powers of the MEA to grant or revoke a license under the Mining Act
will have to be used taking into account the so called Dutch general principles of sound
administration (algemene beginselen van behoorlijk bestuur). These general principles
dictate for instance that the MEA cannot revoke without giving proper notice and that the
Minster cannot discriminate or act arbitrarily when using this power.
The MEA may also revoke a license at the request of the license holder. Such a request can
only be refused if for the systematic management of mineral deposits it is necessary that
the holder complies with a condition attached to the license or observes applicable rules.
The license holder of an exploration license may surrender the license. The license shall
lapse with effect from the day after the day on which the MEA has received a written
statement from the holder stating that he is surrendering the license. This rule does not
apply to production licenses.
The license may also lapse by operation of the law:
1)
if the holder is a natural person, on the day after the day of his decease;
2)
if the holder is a legal person, on the day after the day that that person has ceased to exist.
A decision to withdraw a license or the lapse of a license is published in the Staatscourant.
Please note that legislation is pending which purports to grant the MEA more rights to
revoke so called fallow licenses.
Extension of Term
A license can be extended upon request of the holder pursuant to Article 18 sub 3 of the
Mining Act. Such request will be honoured, if it is apparent that the activities for which
the license has been granted cannot be completed with the term of the license. The MEA
may extend the license for a restricted area within the original licensed area.
15. Working Capital
In the opinion of the Directors, having made due and careful enquiry, the working capital available to
the Company is sufficient for the Company’s and the San Leon Group’s present requirements, that is for
at least 12 months from the date of Admission.
16. Taxation
16.1 Irish Taxation
The following paragraphs are intended as a general guide only for Shareholders who are resident
and ordinarily resident in Ireland for tax purposes, holding Ordinary Shares as investments and
not as securities to be realised in the course of a trade, or by reason of their or another person’s
employment, collective investment schemes, and insurance companies, and are based on current
legislation and Irish Revenue Commissioners practice. Any prospective purchaser of Ordinary
Shares who is in any doubt about his tax position or who is subject to taxation in a jurisdiction
other than Ireland should consult his own professional adviser immediately.
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Withholding Tax
Withholding tax at the standard rate of income tax (currently 20 per cent.) applies to dividend
payments and other profit distributions by an Irish resident company. Certain categories of Irish
resident Shareholders are exempt from withholding tax if they make an appropriate declaration of
entitlement to exemption to the Company in advance of payment of any relevant distribution,
including (but not limited to):
•
An Irish resident company;
•
An Irish pension fund or an exempt Irish charity approved by the Irish Revenue
Commissioners;
•
A qualifying fund manager in an approved retirement fund or an approved minimum
retirement fund or qualifying savings manager in accordance with section 172C(ba) of the
Irish Taxes Consolidation Act 1997 (“TCA”), who is receiving the relevant distribution as
income arising in respect of assets held;
•
A Personal Retirement Savings Account (“PRSA”) administrator who is receiving the
relevant distribution as income arising in respect of PRSA assets;
•
A qualifying employee share ownership trust;
•
A collective investment undertaking;
•
A designated broker receiving the distribution for a special portfolio account;
•
A person who is entitled to exemption from income tax under Schedule F on dividends in
respect of an investment in whole or in part of payments received in respect of a civil action
or from the Personal Injuries Assessment Board for damages in respect of mental or
physical infirmity;
•
Certain qualifying trusts established for the benefit of an incapacitated individual and/or
persons in receipt of income from such a qualifying trust;
•
A person entitled to exemption to income tax under Schedule F by virtue of section 192 (2)
of the TCA; and
•
A unit trust to which section 731(5)(a) of the TCA applies.
Certain categories of non resident Shareholders are exempt from withholding tax if they make an
appropriate declaration of entitlement to exemption to the Company in advance of payment of any
dividend, including (but not limited to):
•
Persons (other than a company) who (i) are neither resident or ordinarily resident in Ireland
and (ii) are resident for tax purposes in (a) a country which has in force a tax treaty with
Ireland (a “tax treaty country”) or (b) an EU Member State other than Ireland;
•
Companies not resident in Ireland which are resident in an EU Member State or a tax treaty
country, by virtue of the law of a tax treaty partner country or an EU Member State, and
are not controlled, directly or indirectly, by Irish residents;
•
Companies not resident in Ireland which are directly or indirectly controlled by a person or
persons who are, by virtue of the law of a tax treaty partner country or an EU Member
State, resident for tax purposes in a tax treaty country or an EU Member State other than
Ireland and who are not controlled, directly or indirectly, by persons who are not residents
for tax purposes in a tax treaty partner country or an EU Member State;
•
Companies not resident in Ireland the principal class of shares of which is substantially and
regularly traded on a stock exchange in Ireland, on one or more than one recognised stock
exchange in a tax treaty country or in another EU Member State or such other stock
exchange as may be approved of by the Minister of Finance; or
191
•
Companies not resident in Ireland that are 75 per cent. subsidiaries of a single company, or
are wholly-owned by two or more companies, in either case the principal class(es) of shares
of which is/are substantially and regularly traded on a stock exchange in Ireland, on one or
more than one recognised stock exchange in a tax treaty country or in another EU Member
State or such other stock exchange as may be approved of by the Minister of Finance.
In the case of a non-resident Shareholder resident in an EU Member State or tax treaty country,
the declaration must be accompanied by a current certificate of residence from the revenue
authorities in the Shareholder’s country of residence. In addition, in the case of non-resident
companies controlled by residents of an EU Member State other than Ireland or of a tax treaty
country or whose shares are substantially and regularly traded on a stock exchange in Ireland, an
EU Member State or a tax treaty country, certain certification by their auditors is required. The
declaration also must contain an undertaking by the non-resident person that he or she will advise
the relevant person accordingly if he or she ceases to be non-resident. No declaration is required
where the stockholder is a 25 per cent. parent company in another EU Member State pursuant to
the Parent/Subsidiary directive. Neither is a declaration required on the payment by a company
resident in Ireland to another company so resident where the company making the dividend is a
51 per cent. subsidiary of that other company.
This summary does not address the position for all types of Shareholder.
Taxation of Dividends
Irish resident Shareholders who are individuals will be subject to income tax and levies on the
aggregate of the net dividend received and the withholding tax deducted. The withholding tax
deducted will be available for offset as a credit against the individual’s income tax liability. A
Shareholder may claim to have the withholding tax refunded to him to the extent it exceeds his
income tax liability.
An Irish resident Shareholder which is a company will not be subject to Irish corporation tax on
dividends received from the Company and tax will not be withheld at source by the Company
provided the appropriate declaration is made. A company, which is a close company as defined
under Irish legislation, may be subject to a corporation tax surcharge on dividend income to the
extent that it is not distributed.
Capital Gains Tax
The Company’s Ordinary Shares constitute chargeable assets for Irish capital gains tax purposes
and accordingly Shareholders who are resident or ordinarily resident in Ireland, depending on
their circumstances, may be liable to Irish tax on capital gains on a disposal of Ordinary Shares.
The Irish capital gains tax rate is currently 20 per cent. As it is not expected that the shares will
derive the greater part of their value directly or indirectly from land or buildings within Ireland,
the Shareholders of the Company who are neither resident or ordinarily resident in Ireland and
who do not hold the Ordinary Shares for the purposes of a trade carried on in Ireland should not
be subject to Irish tax on capital gains arising on the disposal of the Ordinary Shares. An Irish
resident individual, who is a shareholder who ceases to be an Irish resident for a period of less
than five years and who disposes of Ordinary Shares during that period, may be liable, on a return
to Ireland, to capital gains tax on any gain realised.
Stamp Duty
Irish stamp duty will be charged at the rate of 1 per cent. on the amount or value of the
consideration on any conveyance or transfer on sale or voluntary disposition of Ordinary Shares.
In relation to a conveyance or transfer on sale or voluntary disposition of Ordinary Shares under
the CREST System, Irish stamp duty at the rate of 1 per cent. will be payable on the amount or
value of the consideration.
The person accountable for the payment of stamp duty is generally the transferee. Stamp duty is
normally payable within 30 days following the date of execution of the transfer. Late or
inadequate payments of stamp duty will result in a liability for interest, penalties and surcharges.
192
Under an arrangement between Ireland and the Untied Kingdom, credit is given in Ireland for
stamp duty payable on the transfer of Ordinary Shares where the instrument of transfer is
stampable in both jurisdictions (see paragraph 16.2 of this Part VI as regards UK Stamp Duty).
16.2 United Kingdom Taxation for UK Investors
The following paragraphs are intended as a general guide only for Shareholders who are resident
and ordinarily resident in the UK for tax purposes, holding Ordinary Shares as portfolio
investments and not as securities to be realised in the course of a trade. They do not purport to be
comprehensive nor to describe all potential relevant considerations. They are based on current
legislation and HM Revenue & Custom’s practice relating to the taxation of foreign source
dividends at the date of this Document.
Any Shareholder who is any doubt about his tax position or who is subject to taxation in a
jurisdiction other than the UK, should consult his or her own professional adviser immediately.
UK tax on capital gains
If an individual Shareholder disposes of all or some of his Ordinary Shares, a liability to tax on
chargeable gains may arise, depending on the Shareholder’s circumstances and available
exemptions and reliefs. In the absence of any exemptions and reliefs the current rate of tax on
gains made by individuals resident in the UK is 18 per cent.
In general gains of companies as reduced by indexation relief (which increases the cost of the
asset by reference to the movement in the RPI index over the period of ownership) are subject to
corporation tax at the company’s relevant rate.
UK Stamp duty and stamp duty reserve tax
No stamp duty or stamp duty reserve tax (“SDRT”) will generally be payable on the issue of new
Ordinary Shares by the Company.
Other than for share sales whose consideration does not exceed £1,000 and are evidenced by a
certified instrument (which are exempt to the charge to stamp duty), any subsequent transfer of
Ordinary Shares will generally be subject to UK stamp duty on the instrument of transfer,
normally at the rate of 0.5 per cent, of the amount or value of the consideration given. Where an
unconditional agreement to transfer Ordinary Shares is not completed by a duly stamped
instrument of transfer, a charge to SDRT (generally at the same rate) will normally arise.
Transfers on sale and agreements to transfer shares to charities will not give rise to stamp duty or
stamp duty reserve tax.
Dividend withholding taxes in Ireland
Dividends paid to investors resident for tax purposes in the UK may be subject to a reduced
withholding tax of 15 per cent. of the gross dividend in Ireland in accordance with the provisions
of the UK:Ireland Double Taxation Treaty. For most UK investors this withholding tax will be
credited against and thereby reduce, their UK tax liability. For both individuals and companies
having insufficient taxable income to give rise to a UK tax charge, the investor can elect to treat
Irish withholding tax as an expense to be deducted from the gross dividend so that the taxable
receipt is reduced to the amount of the dividend net of withholding tax.
It is possible for certain non-Irish resident persons to claim exemption from Irish Dividend
Withholding Tax on making an appropriate declaration to the Company (see paragraph 16.1).
Non UK Domiciled Individuals
Where the individual is resident but not domiciled in the UK it is recommended that such
individuals should consult his or her own professional adviser in respect to the UK taxation of
dividends received from the Company.
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UK Taxation of Foreign Dividend Income
Dividends paid by a Company resident for tax purposes in Ireland will constitute “equivalent
foreign income” for UK income tax purposes when received by individuals or trustees of a
discretionary trust who are tax resident in the UK. Such dividends received by a UK tax resident
corporate investor will form part of that Company’s profits chargeable to corporation tax.
Individual shareholders who are resident in the UK for tax purposes will be taxed on the
aggregate of the net dividend received together with any withholding tax deducted in Ireland. This
dividend income will be treated as the top slice of an individual’s income and will be subject to
tax at a rate of 32.5 per cent. where the individual is liable at the higher rate or 10 per cent. where
liable at other rates (the lower or basic rate). Any withholding tax deducted on payment of the
dividend will be credited against the resulting UK income tax liability. Accordingly a higher rate
taxpayer will pay an additional 17.5 per cent. of the gross dividend (net dividend plus withholding
tax) received. Individuals liable at other rates will have no further UK income tax liability as a
result of the offset of the withholding tax credit. Unutilised withholding tax is not repayable.
Accordingly, those individuals liable at other than the higher rate will incur an effective tax charge
of 15 per cent. referable to the withholding tax deducted in Ireland.
UK resident individual shareholders who control less than 10 per cent. of the voting power of the
Company are treated as receiving income of an amount equal to the sum of the gross dividend
(net dividend plus withholding tax) and its associated tax credit. Such tax credit is 10 per cent. of
the combined amount of the gross dividend and the tax credit (i.e. the tax credit will be one-ninth
of the gross dividend). The tax credit will discharge in full the income tax liability of any taxpayer
other than a higher rate taxpayer, who will have an additional liability. The special rate of tax for
higher rate taxpayers who receive dividends is 32.5 per cent, this rate being applied to the
combined amount of the gross dividend and the tax credit. After taking into account the
10 per cent. tax credit and Irish withholding tax deducted at 15 per cent. of the gross dividend,
such a taxpayer would have to account for an additional 10 per cent. of the combined amount of
the gross dividend and tax credit.
Corporate shareholders resident in the UK for tax purposes which either directly or indirectly
control less than 10 per cent. of the voting power of the Company, will be subject to corporation
tax in the UK on the gross dividend received at its relevant rate of corporation tax. Credit will be
given against this corporation tax liability for any withholding tax deducted on payment of the
dividend. Any unutilised withholding tax credit is not recoverable by repayment.
Corporate shareholders either directly or indirectly controlling 10 per cent. or more of the voting
power of the Company will be liable to UK corporation tax on the aggregate of the dividend (plus
any withholding tax suffered) and the underlying Irish corporation tax. The underlying Irish
corporation tax and any Irish withholding tax suffered will be available for set off against the
UK corporation tax liability on the aggregate amount. Any unutilised withholding tax or
underlying tax credit is not recoverable by repayment.
UK resident trustees of discretionary or accumulation trusts are liable to income tax on
UK company dividends at 32.5 per cent. of the gross dividend. Any withholding tax deducted will
be credited against this liability resulting in a net income tax liability equivalent to 17.5 per cent.
of the gross dividend.
17. Legal and arbitration proceedings
There are no governmental, legal or arbitration proceedings in which any company in the San Leon
Group is involved or of which any company in the San Leon Group is aware, is pending or threatened
by or against any company in the San Leon Group which may have or have had in the 12 months
preceding the date of this document a significant effect on the San Leon Group’s financial position.
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18. General
18.1 Save as otherwise described in this document, there has been no significant change in the trading
or financial position of any company in the San Leon Group since 31 December 2007, the date
to which the financial information set out in Part VA of this document in respect of the Company
has been prepared.
18.2 Daniel Stewart & Company plc of Becket House, 36 Old Jewry, London, EC2R 8DD, which is
regulated by the Financial Services Authority, has given and not withdrawn its written consent to
the inclusion in this document of its name in the form and context in which it appears.
18.3 LHM Casey McGrath of 6 Northbrook Road, Ranelagh, Dublin 6 has given and not withdrawn its
written consent to the inclusion in this document of its name and reports in the form and context
in which they appear.
18.4 Netherland, Sewell & Associates, Inc. of 4500 Thanksgiving Tower, 1601 Elm Street, Dallas, Texas
75207 4754, USA has given and not withdrawn its written consent to the inclusion in this document
of its name and reports in the form and context in which they appear. Netherland Sewell accepts
responsibility for the Petroleum Consultant’s Report for the purposes of a competent person’s report
under the AIM Rules. Netherland Sewell has confirmed that, to the best of its knowledge, the
information contained in the Petroleum Consultant’s Report is in accordance with the facts and
contains no omission likely to affect its import.
18.5 The financial information set out in this document relating to the San Leon Group does not
constitute statutory accounts within the meaning of the Companies Acts.
18.6
No dividends have been paid by the Company to date. There is no fixed date on which any
Shareholders’ entitlements to dividends arises and there are no arrangements in place under
which future dividends are waived or agreed to be waived.
18.7 Save as set out in this document, as far as the Directors are aware, there are no environmental
issues that may affect the Company’s utilisation of its tangible fixed assets.
18.8 Save as disclosed in this document no person (excluding professional advisers otherwise
disclosed in this document and trade suppliers) has received, directly or indirectly from the
San Leon Group within the 12 months preceding the date of this document or entered into
contractual arrangements (not otherwise disclosed in this document) to receive, directly or
indirectly, from the San Leon Group on or after Admission any of the following:
18.8.1 fees totalling £10,000 or more;
18.8.2 securities of the Company where these have a value of £10,000 or more calculated by
reference to the price of £0.37; or
18.8.3 any other benefit with the value of £10,000 or more at the date of this document.
No payment aggregating over £10,000 has been made to any government or regulatory authority
or similar body by or on behalf of the Company with regard to the acquisition or maintenance of
its assets.
18.9 Save as disclosed in this document:
18.9.1 the Company has no principal investments for each financial year covered by the historical
financial information and no principal investments in progress; and
18.9.2 there are no principal future investments on which the Board has made a
firm commitment.
18.10 So far as the Directors are aware, and save as set out in this document, there are no known trends,
uncertainties, demands, commitments or events that are reasonably likely to have a material effect
on the San Leon Group’s prospects for at least the current financial year.
195
18.11 The Company is not aware of the existence of any takeover bid pursuant to the Irish Takeover
Rules or any circumstances which may give rise to any takeover bid, and the Company is not
aware of any public takeover bid by third parties for the Ordinary Shares.
18.12 Where in this document, information has been sourced from a third party, it has been accurately
reproduced and as far as the Company and the Directors are aware and are able to ascertain from
information published by the relevant third party, no facts have been omitted which would render
the reproduced information inaccurate or misleading.
18.13 Barr Pomeroy who are members of the Institute of Chartered Accountants in Ireland have audited
the statutory accounts of the Company and have given unqualified audit reports on the statutory
accounts of the Company for the 3 financial years ended 31 December 2007. The statutory
accounts of the Company for the 2 financial years ended 31 December 2006 have been delivered
to the Registrar of Companies in Ireland. There has been no removal, resignation or
non-reappointment of any auditor of any member of the Group during the period covered by the
historical financial information set out in Part V of this document.
18.14 The total costs and expenses relating to Admission are payable by the Company and are
estimated to amount to approximately £925,000.
18.15 More than 10 per cent. of the share capital of the Company has been paid for with assets other
than cash the details of which are set out in the contracts with certain of the Directors set out in
paragraph 13 of Part VI of this document.
18.16 Save as disclosed in this document, there are no patents or intellectual property rights, licences,
industrial, commercial or financial contracts or new manufacturing processes which are material
to the Group’s business or profitability.
19. Availability of Admission Document
Copies of this document will be available free of charge during normal business hours on any week day
(Saturdays, Sundays and public holidays excepted) until the date following one month after the date of
Admission at the registered office of the Company and at the offices of Daniel Stewart, Becket House,
36 Old Jewry, London, EC2R 8DD.
Dated 23 September 2008
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GLOSSARY AND ABBREVIATIONS
The following terms apply throughout this document, unless the context otherwise requires:
1C
low estimate contingent resources
2C
best estimate contingent resources
3C
high estimate contingent resources
3D
three dimensions
Basin
an area which in a past geological era has been depressed, acquiring
deposits of sedimentary rocks such as sands, silts or limestones
bbl(s)
barrel(s)
bcf
billions of cubic feet
Bo
oil formation volume factor
BOE
barrels of oil equivalent
BOPD
barrels of oil per day
BP
British Petroleum
Bscf
billion standard cubic feet
CIT
Corporate Income Tax
Contingent Resources
has the meaning ascribed to it in the Petroleum Consultant’s Report
in Part IV of this document
DJ
Denver-Julesburg
FDP
Field Development Plan
FRL
Fugro Robertson Limited
Formation
a rock deposit or structure of homogeneous origin and appearance
GOC
gas/oil contact
GRV
gross rock volume
km2 or sq km
square kilometer
lead
a conceptual exploration idea usually based on minimal data but with
sufficient support from geological analogues and the like to encourage
further data acquisition and/or study on the basis that hydrocarbon
accumulations of unknown size may be found in the future
Mbbl(s)
thousand barrels of oil
MCF
thousands of cubic feet
MD
Millidarcy
MMBBL
millions of barrels
MMBTU
millions of British thermal units
Migration
the movement of hydrocarbons from their source rock into reservoirs
Mmboe
million barrels of oil equivalent
MMcf
million cubic feet
197
MMcfd
million cubic feet per day
MMscf
millions of standard cubic feet
MMstb
millions of stock tank barrels of oil
NRV
net rock volume
NTG
net-to-gross ratio
OGIP
original gas-in-place
OOIP
original oil-in-place
OWC
oil/water contact
Pg
probability of geologic success
Permeability
the degree to which a body of rock will permit a fluid to flow
through it
Porosity
the percentage of pore volume or void space, or that volume within
rock that can contain fluids
Possible reserves
has the definition ascribed to it in the Petroleum Consultant’s Report
in Part IV of this document
Prospect
geological formations (whether stratigraphic or structural) that, on
the basis of geoscientific evidence and/or modeling, are believed to
have the potential to contain commercially viable quantities of
hydrocarbon
Prospective Resources
has the definition ascribed to it in the Petroleum Consultant’s Report
in Part IV of this document
Proved or Proven reserves
has the definition ascribed to it in the Petroleum Consultant’s Report
in Part IV of this document
Probable reserves
has the definition ascribed to it in the Petroleum Consultant’s Report
in Part IV of this document
PRMS
Petroleum Resources Management System
RB/STB
reservoir barrels per stock tank barrel
Reserves
potential volume of hydrocarbon that could be commercially
produced from a field. Formal reserves cannot be attributed to the
prospects at this stage of exploration since the existence of
commercially developable hydrocarbon accumulations is
conceptual. In all of the prospects there is uncertainty about
reservoir presence and quality, hydrocarbon presence and, on the
assumption that hydrocarbons are found, their type and the potential
well deliverability
Reservoir
a subsurface body of rock having sufficient porosity and
permeability to store and transmit fluids
Resources
those volumes of hydrocarbons either yet to be found (prospective)
or if found the development of which depends upon a number of
factors being resolved (contingent)
Seismic Survey
a survey conducted to map the depths and contours of various
prospective rock strata by timing the reflections from strata-tops of
sound waves released on the surface or down a borehole
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Sh
hydrocarbon saturation
SMT
Seismic Micro-Technology, Inc.
SPS
State Profit Share
Stimulation
methods such as acidising or fracturing or explosions designed to
break up low permeability reservoir rock in the vicinity of a well so
that oil can flow freely into the bore
TAQA
Abu Dhabi National Energy Company
tcf
trillion cubic feet (1000 billion)
TOC
total organic carbon
USMM$
Millions of United States dollars
Workover
a maintenance operation on a well usually to replace equipment or
to stimulate production
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Millnet Financial
(8140-01)