Petroceltic International

Transcription

UNITED KINGDOM
Together we can do so much
Initiate with an Outperform and 9p target price
On 17th August 2012 Petroceltic announced an agreed merger with Melrose
Resources (MRS LN). Our Outperform recommendation is premised on:
 The enlarged Board has a track record of building successful E&P companies
(Afren, Tullow, Centurion Energy)
 Free cash-flow derived from the Melrose Resources asset base can now be
used to fund this expansion. We expect the focus to be on exploration.
 We see a greater level of interest in the company as the combined entity will
have a market cap of ~US$525m and plans to move to the Main Board
PCI LN
Price (at CLOSE#, 10 Sep 2012)
12-month target
12-month TSR
Valuation
Outperform
£0.08
£
%
£
0.09
+20.0
0.14
GICS sector
Market cap
£m
30-day avg turnover
£m
Market cap
US$m
Number shares on issue
m
Energy
178
0.6
285
2,370
- DCF (WACC 10.0%)
Investment fundamentals
Year end 31 Dec
2011A 2012E 2013E 2014E
m
0.4
0.6 213.1 230.6
Revenue
m
-9.4
-7.5 139.4 158.3
EBITDA
m
-9.7
-7.9
63.5
78.3
EBIT
m
-8.2
-5.1
31.7
42.1
Reported profit
US$
0.00
0.00
0.01
0.01
EPS adj
%
46.4
39.7
nmf
18.1
EPS adj growth
Source: FactSet, Macquarie Research, September 2012
(all figures in USD unless noted)
Inside
Merger overview
Valuation, recommendation, risks
Melrose Resources brings production
As it stands, exploration is light
Asset overview
Appendices
3
6
9
12
14
24
Analyst(s)
David Farrell
+44 20 3037 4465
Mark Wilson
+44 20 3037 4466
Giacomo Romeo
+44 20 3037 4445
david.farrell@macquarie.com
mark.wilson@macquarie.com
giacomo.romeo@macquarie.com
12 September 2012
Macquarie Capital (Europe) Limited
 Petroceltic‟s share price is supported at the current levels by a Core NAV of
7.6p/sh. Our target price of 9p/sh represents 20% upside.
Merger terms are “more or less” fair
Looking at the value of producing fields, discovered fields with a clear line to
commercialisation and net cash/(debt) suggests a combined company valuation
of US$629m. As Petroceltic would contribute ~55% of the value and Melrose
Resources ~45%, inline with the planned pro-forma shareholding, we see the
deal terms as therefore fair. However, we believe that the market is pricing in at
least some risk of the terms changing in favour of Petroceltic with the inferred
Melrose Resource price still offering 5% upside to the current share price. Using
the market implied exchange ratio of 16.7 Petroceltic shares per Melrose
Resources share (vs. the agreed17.6 exchange ratio) would lead us to increase
our Petroceltic valuation by 1p to 10p.
Cash-flow the draw, Egypt concerns overplayed
From Petroceltic‟s point of view, one of the attractions of the deal is that Melrose
Resources brings immediate production and cash-flow to the company with
assets in Egypt and Bulgaria in 1H12 delivering 28kboe/d on a WI basis. This
cash-flow may well give Petroceltic greater optionality around the financing of its
existing Ain Tsila development in Algeria and therefore potential to retain a larger
economic interest in the farm-out process. The flip side though is that with 50%
of Melrose Resources‟ operating cash-flow derived from Egypt, it also opens the
stock up to Egyptian political risk and concerns about timely payments of
receivables. We believe that any concerns though, at present, are overdone.
We expect the focus to be on adding further exploration
As stand alone companies, neither Petroceltic nor Melrose Resources had the
most exciting exploration portfolios. Combined, the news-flow should certainly
accelerate, however we still feel the exploration portfolio is light. While
Petroceltic talk of six exploration wells over the course of the next 12 months, the
Mesaha exploration well (fully de-risked 0.8p/sh) to spud in October is the only
exploration well with a contracted rig. The other five planned exploration wells all
have real potential for slippage, given the absence of defined prospects and/or
contracted rigs, while we see only one material well result likely before the end of
1H13 – Carpignano Sesia onshore Italy (0.7p/sh risked; 4.6p/sh unrisked).
Please refer to the important disclosures and analyst certification on page 2 and the inside back cover of this
document, or on our website www.macquarie.com.au/disclosures.
Macquarie Research
Together we can do so much
PCI LN vs FTSE Euro 300
Fig 1 Overview of pro-forma Petroceltic asset base
Romania (MRS)
2 offshore concessions: Muridava (40% op. WI); Est Cobalcescu
(70% op. WI) - Exploration drilling in 2H13
Bulgaria (MRS)
1 offshore licence: Galata Block (100% op. WI)
2 producing assets (Kavarna and Kaliakra - 40mmcf/d), 2 nonproducing fields (Galata and Kavarna East), additional exploration
potential (1H13 drilling)
(all figures in USD unless noted)
Italy (PCI)
9 offshore / onshore permits and 4 permits
applications. Exploration drilling in 1H13
Geographic split of pro-forma
2P+2C
Bulgaria
Kurdistan (PCI)
2 licences : Shakrok (16% WI); Dinarta (16% WI)
Exploration drilling to begin in 2013
(MRS),
9mmboe ,
5%
Algeria
(PCI),
105mmboe
, 56%
Egypt (MRS)
4 licences: El Mansoura (100% op. WI), SE Mansoura (100%
op. WI), Mesaha (40% op. WI), Qantara (100% op. WI)
11 producing fields (45mmcf/d and 1,550b/d) at El Mansoura
and SE Mansoura. Exploration drilling in 2H12 (Mesaha)
Egypt
(MRS),
73mmboe ,
39%
Algeria (PCI)
1 permit: Isarene PSC (56.625% WI)
First gas expected in 2017
Source: Company Data, Macquarie Research, September 2012
Source: Macquarie Research, September 2012
* assuming Ain Tsila (Algeria) farm out to 19.5% economic
interest
PCI / MRS proforma shareholders
Holders
Robert F. M. Adair
Caledonia Investments Plc
Henderson Global Investors Ltd.
FIL Investments International
AXA Investment Managers UK Ltd.
Aberforth Partners LLP
JPMorgan Asset Management (UK) Ltd.
Schroder Investment Management Ltd.
BlackRock Investment Management (UK) Ltd.
Blakeney LLP
Scottish Widows Investment Partnership Ltd.
Aviva Investors Global Services Ltd.
Standard Life Investments Ltd.
Capital Research Global Investors
Other
# of shares
% of total
1,028,401,950
207,421,315
175,004,346
112,313,931
110,679,747
107,046,386
102,072,708
84,143,793
68,801,456
67,225,863
65,290,722
63,726,450
56,673,724
54,574,595
48,134,222
2,036,623,409
4,388,134,618
23.4%
4.7%
4.0%
2.6%
2.5%
2.4%
2.3%
1.9%
1.6%
1.5%
1.5%
1.5%
1.3%
1.2%
1.1%
46.4%
(PCI shareholders in yellow, MRS‟ in grey)
Fig 2 Key drivers according to business segment
Segment of business
Comment
Production
Petroceltic needs to limit the natural decline within the mature
Melrose Resource asset base while the market needs to be
reassured on Egyptian receivables
A farm-out of the Ain Tsila discovery in Algeria is being pursued and
is expected to complete before year end. Our farm-out assumptions
suggest that the Ain Tsila discovery has increased 35% since the
April 2011 Enel farm-out
We forecast the gearing ratio to trend down from its current level of
19%. The US$300m HSBC loan facility needs re-financing prior to
1H14 although we do not see this as a major obstacle
The first major exploration well, Carpignano Sesia in Italy (0.7p
risked; 4.6p unrisked) is likely to have a result in 2Q13. We see the
addition of further exploration upside as a key focus for the company.
Developments
Net debt
Exploration
Fig 3
As it stood, Petroceltic production was unlikely before 2018
MRS production is declining
(2012-16 CAGR -13%)
(kboe/d)
35
30
27.0
26.3
27.0
25
25.0
24.6
19.4
19.2
2019
2020
21.7
20
18.7
17.2
15
10
PCI's Ain Tsila development
will support prod. growth from
2017 (2017-19 CAGR 37%)
13.3
14.6
13.2
13.3
12.8
11.2
5
8.7
6.5
2016
2017
0
2012
2013
2014
Ain Tsila
Bulgaria - Kavarna East
2015
Bulgaria - Kaliakra
Egypt
2018
Bulgaria - Kavarna
Total NE production
12 September 2012
2
Macquarie Research
Merger overview
Bringing together two Mediterranean focused E&Ps
The Merger creates
a full cycle E&P with
a market cap of
US$525m
On 17th August 2012 Petroceltic and Melrose Resources (MRS LN, 130p, Neutral, TP 136p,
Mark Wilson) announced a recommended merger to create a full cycle E&P. The major
highlights of the deal are:
 Each Melrose Resources share is to convert into 17.6 Petroceltic shares with Petroceltic
retaining its AIM listing. Melrose Resources shareholders will also be entitled to receive a
special dividend of 4.7p/share payable within 14 days of the merger becoming effective.
 Based upon the previous night‟s closing prices, the terms, including special dividend,
implied a 9.7% premium to Melrose Resource‟s share price and a 23% premium to
Macquarie‟s previous target price for Melrose Resources of 121p. Overall, Melrose
Resources‟ equity was valued at ~US$268m
 The above valuation, together with debt of US$301m and CPR audited 2P reserves of
84mmboe, implies a transaction EV/2P multiple of US$6.8/boe.
 On a basic share count, the above terms would see Petroceltic shareholders own 54% of
the enlarged group and Melrose Resources shareholders hold the residual 46%. Adjusting
for outstanding options and warrants, we estimate that Petroceltic shareholders would own
55.5% of the enlarged group and Melrose Resources 44.5%.
 The merger will be voted on by both sets of shareholders on 20th September 2012 with a
75% approval level required for the deal to be approved. Closing is currently anticipated on
10th October 2012 with a move to the Main Board of the LSE planned within 12 months
 HSBC is to provide a US$300m 18 month loan to Melrose Resources in order to refinance
its existing US$385m Senior Loan and Subordinated Loan Facility, which presumably is
terminated under a Change of Control clause.
Based upon the current market caps of both companies (MRS has fallen by 4% and PCI by
8% since the merger announcement) the enlarged company would have a market cap of
~US$525m which would put it firmly in “mid-cap” E&P territory and make it the 12th largest
stock in our coverage universe (Fig 4 below).
7.5
Pro-forma market capitalization vs. our E&P Universe
20.3
Fig 4
4.0
Combined, Petroceltic and Melrose
Resources move from being small
cap E&Ps to a more meaningful,
liquid and investible, mid cap E&P
with a market cap of ~US$525m
Market Cap (US$bn)
3.5
3.0
2.5
2.0
1.5
1.0
0.5
PTR
AUL
SQZ
HDY
VOG
SLE
MRS
BLVN
PCI
VPP
GPK
PCI (New)
SMDR
RKH
HOIL
DNO
SIA
COV
AFR
CNE
PMO
LUPE
TLW
0.0
Source: Factset, Macquarie Research, September 2012
We provide an overview of the pro-forma capital structure in the appendix where we show the
post-deal share count on a basic and on a fully diluted basis. Throughout our analysis, unless
otherwise stated, we have used a fully diluted share count (4,692,613,455 share pro-forma)
12 September 2012
3
Macquarie Research
We see the merger terms as “more or less” fair
In our view,
company valuations
are within 2% of our
estimates
In Fig 5 below we show our valuation for the assets in the Petroceltic and Melrose Resources
portfolios which are either on production or have a strong chance of being commercialised
(i.e. Core NAV excluding G&A expense).
Combined we see a pro-forma Petroceltic with a valuation of US$629m pre-G&A expenses.
Our estimates suggest Petroceltic would contribute 54.9% and Melrose Resources 45.1% to
the value of the new company which reflects, “more or less”, the agreed basic share count
ownership split of 56% Petroceltic and 44% Melrose Resources.
However, we also believe investors should look at the deal on a fully diluted share count.
Fully diluted, Petroceltic would hold nearer 55.5% of the new company while contributing
54.9% of the value. Even on this measure though the over/under valuation of Petroceltic and
Melrose Resources respectively is <2%. (Note: For complete equality we would actually see
an upwards adjustment to the exchange ratio with Melrose Resources shareholders receiving
18.0 instead of 17.6 Petroceltic shares per Melrose Resource share)
Fig 5
Break-down of Core NAVs (excluding G&A)
Producing assets (US$m)
Discovered undeveloped assets (US$m)
Net cash/(debt) (US$m)
Total (US$m)
% of Petroceltic pro-forma
Deal terms (full diluted)
Over/(under) valuation
Macquarie implied fair exchange ratio
Petroceltic
Melrose Resources
Petroceltic pro-forma
0
266
80
346
54.9%
512
43
(271)
284
45.1%
512
309
(191)
629
55.5%
44.5%
1.1%
(1.4%)
18.0 Petroceltic shares per Melrose Resources share
388mmboe of 2P+2C
resources within our
Core NAV
In the bullet points below, we explain which assets have been included in the above
valuation. All in, the assets valued above amount to 2P+2C resources of 388mmboe.
 Producing Assets: The producing assets within the combined entity will come entirely
from Melrose Resources‟ existing asset base. On a working interest basis this consists of
~21kboe/d of oil and gas production from the onshore Mansoura and SE Mansoura
concessions (11 producing fields, 100% WI) within the Egyptian Nile Delta and a further
7kboe/d of gas production from the Kavarna (3mmboe net) and Kaliakra (4mmboe net) gas
fields offshore Bulgaria.
 Discovered/Undeveloped Assets: The lion‟s share of value within this section comes
from Petroceltic‟s 56.625% WI interest in the 538mmboe Ain Tsila gas/condensate
discovery onshore Algeria. The field is fully appraised and a Formal Declaration of
Commerciality has recently been submitted to the Algerian state regulator for approval.
Our value for the asset is premised upon the farm-out of a 37% economic interest in return
for a free carry to first production in mid 2018, with Petroceltic retaining a 19.5% economic
interest. From the Melrose Resource asset base, we include the Galata (1mmboe net) and
Kavarna East (1mmboe net) gas fields offshore Bulgaria (100% WI) which are likely to be
brought on-stream over the 2013-15 timeframe. Perhaps most controversially, given
uncertainty regarding its commerciality, we have excluded Petroceltic‟s 55% WI in the Elsa
oil discovery offshore Italy (52mmb net).
 Net debt/(cash): We estimate that pro-forma, Petroceltic will have net debt of US$191m,
made up of US$300m of debt (Melrose Resources) and US$109m of cash (US$29m within
Melrose Resources and US$80m within Petroceltic including US$25m ENEL payment).
Algeria accounts for
79% of these
resources
12 September 2012
In Fig 6 on the following page we show the geographic split of the 2P+2C resources with
Algeria accounting for 79% of the resource base if we assume current WI of 56.625%
(305mmboe). However, in Fig 7, we show the resources split in case of a farm-down to a
19.5% economic interest, with Algeria weight dropping to 56% (105mmboe)
4
Macquarie Research
Fig 6 Geographic split of pro-forma 2P+2C res. of
388mmboe (assuming 56.625% WI in Ain Tsila)
Bulgaria
(MRS),
9mmboe , 2%
Fig 7 Geographic split of pro-forma 2P+2C res. of
188mmboe (19.5% economic interest in Ain Tsila)
Bulgaria
(MRS),
9mmboe , 5%
Egypt (MRS),
73mmboe ,
19%
Egypt (MRS),
73mmboe ,
39%
Algeria (PCI),
105mmboe ,
56%
Algeria (PCI),
305mmboe ,
79%
However the share prices infer this is not yet a done deal
Using the market
implied exchange
ratio increase our
valuation by 1p to
10p
In the charts below, we map the performance of the two share prices (rebased to 100) since
the deal was announced on 17th August 2012, along with the inferred Melrose Resources
share price at the agreed terms. While both stocks have declined since the deal was
announced (Fig 8), Melrose Resource‟s share price has outperformed that of Petroceltic‟s by
~5%.
Interestingly though, the two share prices do not, in our view, reflect the current terms of the
merger. As shown by the red bars, the two share prices imply an exchange ratio (taking into
consideration the 4.7p/sh special dividend) currently of just 16.7 Petroceltic shares per
Melrose Resources share, 6% below the agreed terms. Using this market implied exchange
ratio would lead us increase our valuation for Petroceltic by 1p to 10p
We display this another way in Fig 9 where we show the actual Melrose Resources share
price and also its implied value based upon the Petroceltic share price multiplied by 17.6 plus
the 4.7p special dividend. For all but one day since the merger announcement, the implied
value has been higher than the actual value and we estimate there is currently 5.0% upside
from the current share price. To us, this is evidence that the market believes that there is a
chance that the deal may be revised in favour of Petroceltic (decrease of the exchange ratio)
or that it may not receive the required approval from shareholders.
Mkt implied exchange ratio
MRS-LON
12 September 2012
PCI-LON
2%
0%
120
-0.6%
Premium to actual sp
Implied MRS sp
10-Sep
07-Sep
06-Sep
115
05-Sep
-2%
04-Sep
10-Sep
07-Sep
06-Sep
05-Sep
04-Sep
31-Aug
30-Aug
29-Aug
28-Aug
27-Aug
24-Aug
23-Aug
22-Aug
21-Aug
20-Aug
17-Aug
15.0
16-Aug
84
4%
31-Aug
15.5
6%
30-Aug
86
145
7.0%
6.7%
6.2%
6.1%
6.0%
140
5.8%
5.0%5.0%
5.0%
4.5% 4.3%
135
3.4%
3.0%
130
1.6%
1.1%
125
8%
29-Aug
17.7
18.0
17.417.3
17.5
17.117.0
92
16.8
16.8
16.7 17.0
16.716.7
16.516.6
16.5
16.516.6
16.4
90
16.5
16.0
88
16.0
94
155
150
28-Aug
18.5
96
10%
(p/sh)
27-Aug
19.0
(% premium /
disc.)
9.7%
24-Aug
98
12%
23-Aug
100
19.5
22-Aug
20.0
21-Aug
Exch. ratio (x)
20-Aug
sp (100 base)
MRS implied vs. actual share price
17-Aug
102
Fig 9
16-Aug
Fig 8 MRS / PCI relative share price moves
Actual MRS sp
5
Macquarie Research
Valuation, recommendation, risks
We initiate coverage
of Petroceltic with
an Outperform
recommendation
and 9p target price
which suggests 20%
upside to the
current share price.
The table below shows Petroceltic‟s pro-forma asset base. Pages 14-22 of this document
have more details surrounding the main assets however the key elements to highlight are:
 Melrose Resources’ producing assets. The producing assets section of the EMV is
composed entirely of Melrose Resources‟ assets accounting for 6.8p/sh of our 7.6p/sh
Core NAV. While the market is concerned about the ability of the Egyptian authorities to
meet payment schedules we believe that contracting country CDS spreads and
encouraging comments from operators mean that these assets should remain fully derisked for the time being.
 Ain Tsila development. It is the single largest asset in our EMV, with a risked value of
3.5p/sh. A number of factors including uncertain development costs, time to first gas,
residual economic interest and gas pricing means that it is the hardest asset within the
portfolio to value. We assume a farm out of a further 37% of its current 56.625% economic
interest in return for a free carry through to first production in 2018 with this effect reflected
in our NPV/boe given Algerian restrictions on Working Interest farm-downs (see p. 15).
 Short term incremental production potential from Bulgaria. As highlighted in the
production section, the company expects the Kavarna East development to come onstream in 2013, although this may be deferred in favour of re-development of the Galata
field. These production increases are relevant in terms of production and cash-flow
generation, but they represent a small part of our Core NAV (0.6p/sh combined)
 Limited short term E&A upside. The pro-forma company upside remains limited with the
Carpignano Sesia exploration well in Italy accounting for ~41% of the risked upside
(0.7p/sh of 1.7p/sh) and for 46% of the unrisked upside (4.6p/sh of 9.9p/sh). With no
prospects yet defined or rig contracted we do not include the Romanian acreage in our
visible risked E&A upside presently. We assume a 100mmboe prospect for the upcoming
Mesaha exploration well, in-line with comments from Melrose Resources‟ partners.
Fig 10
Petroceltic’s Asset Breakdown EMV (E&A upside included in TP highlighted)
Country
Project/Prospect
Producing Assets
Egypt
El Mansoura (2P)
Egypt
Qantara
Egypt
Other El Mansoura (2P)
Egypt
SE El Mansoura (2P)
Bulgaria
Kavarna (Galata block)
Bulgaria
Kaliakra (Galata block)
Undeveloped assets
Algeria
Ain Tsila (Isarene PSC)*
Bulgaria
Galata field (Galata block)
Bulgaria
Kavarna East (Galata block)
Risked Upside
Italy
Bulgaria
Egypt
Kurdistan
Kurdistan
Kurdistan
Kurdistan
Kurdistan
Egypt
Egypt
Italy
Italy
Bulgaria
Bulgaria
Romania
Romania
France
Carpignano Sesia (Cariso Permit)*
Kamchia (Galata block)
Mesaha Block
Shakrok (Shakrok PSC)
Pelewan (Shakrok PSC)
Shireen (Dinarta PSC)
Chinara (Dinarta PSC)
Bradost (Dinarta PSC)
El Mansoura, Qawasim play (4 prospects)
SE El Mansoura (4 prospects)
Elsa (B.R268R.G Permit)
Elsa West (B.R268R.G Permit)
Chaika (NW, NE and S)
Prospects A, E, F and H (Galata block)
Muridava
Est Cobalcescu
Rhone Maritime
Total Asset Value
Gross Res.
Potential
(mmboe)
Working
Interest
(%)
56
1
8
8
3
4
80
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
538
1
1
540
56.6%
100.0%
100.0%
162
5
100
650
217
660
567
533
13
34
95
54
8
8
21
21
0
3146
23.8%
100.0%
40.0%
16.0%
16.0%
16.0%
16.0%
16.0%
100.0%
100.0%
55.0%
55.0%
100.0%
100.0%
40.0%
40.0%
27.5%
3767
Discounted
Value
(US$/boe)2
Net Risked
(mmboe)
EMV
(US$m)3
Risked
Value
(p/sh)
Unrisked
Value (p/sh)4
$4.4
$6.6
$4.4
$4.4
$28.7
$24.3
56
1
8
8
3
4
80
250
6
37
33
93
93
512
3.3
0.1
0.5
0.4
1.2
1.2
6.8
3.3
0.1
0.5
0.4
1.2
1.2
6.8
70%
75%
75%
$1.2
$23.8
$26.1
213
1
1
215
266
16
27
309
3.5
0.2
0.4
4.1
5.1
0.3
0.5
5.8
15%
20%
10%
25%
15%
15%
15%
15%
30%
10%
25%
10%
10%
10%
10%
10%
5%
$8.9
$13.2
$1.4
$2.7
$2.3
$2.7
$2.3
$2.3
$2.9
$2.9
$13.6
$11.2
$13.2
$13.2
$13.1
$13.1
6
1
4
26
5
16
14
13
4
3
13
3
1
1
1
1
0
111
52
5
3
66
6
38
25
23
6
3
167
16
3
4
2
2
0
422
0.7
0.1
0.0
0.9
0.1
0.5
0.3
0.3
0.1
0.0
2.2
0.2
0.0
0.0
0.0
0.0
0.0
5.6
4.6
0.8
0.7
3.8
1.0
3.8
2.7
2.6
0.5
1.3
9.5
4.4
1.3
1.4
1.5
1.5
0.0
41.4
406
1,243
16.6
54.1
C.O.S.
(%)1
Notes:
Petroceltic outstanding shares (fd)
1. C.O.S. - Chances of Success - Includes all risk factors such as geological, political, project delivery, commercial, etc.
GBP/USD
2. Value/boe - Includes proximity to established infrastructure, development capex required, oil quality, discount rate (10%), etc.
3. EMV - Expected Monetary Value - a risk weighted value. EMV = (Reward*C.O.S.) - [Capital at Risk*(1-C.O.S.)]
4. Unrisked Value - Refers to the value that could potentially be realized if success was achieved on prospect and commercial production realized.
* Assumes farm-down
4692.6
1.60
12 September 2012
6
Macquarie Research
Our Target Price of 9p/sh is based upon a Core NAV of 7.6p/sh and 1.7p/sh of Visible Risked
E&A upside (Fig 11). In our Core NAV we use a pro forma net debt of US$191m derived from
combined net debt positions reported at the 1H12 Interims of both companies while also
including a US$25m contingent payment due to Petroceltic from Enel pertaining to the 2011
Ain Tsila field farm-out.
Fig 11
Petroceltic’s Core and Total NAV. Components of TP highlighted
Petroceltic
Risked
resources
(mmboe)
Unit Value
(US$/boe)
80
6.4
512
6.8p
na
-191
-2.6p
1.4
309
4.1p
-57
-0.8p
572
7.6p
31
0.4p
EMV
(US$m)
Value
(p/sh)
Assets (NPV10)
Producing Assets
Cash/(Net Debt)
Undeveloped Assets
215
Other assets less G&A
Core NAV
295
1.9
Option Proceeds
Risked E&A upside
111
3.8
422
5.6p
Total NAV
406
2.5
1,026
13.7p
Risked E&A upside included in TP
Unrisked value of above
Target Price (rounded)
1.7p
9.9p
9.0p
Petroceltic looks
materially
undervalued relative
to Egyptian peers…
In the table below we look at a market based approach to valuation whereby we compare
Petroceltic in terms of EV/boe to its peers. Given the weighting of production and cash-flow to
Egypt, we think it best to compare the company to a narrow set of peers which includes just
Circle Oil (COP LN, not rated) TransGlobe Energy (TGL CN, C$11.49, Outperform, TP:
C$16.50, David Popowich)both of which like Petroceltic have a majority of 2P reserves
located in Egypt.
On this approach, Petroceltic appears relatively cheap at the EV/2P level but materially
undervalued when including contingent resources for the companies and on an EV/production
basis.
Fig 12
Petroceltic looks attractively valued compared to other Egyptian focused E&Ps
Company
Ticker
Circle Oil
TransGlobe Energy
Petroceltic
COP LN
TGL CN
PCI LN
Mkt Cap
(US$m)
Net debt
(US$m)
175
867
524
15
59
191
EV Production EV/Production
(US$m)
(kboe/d)*
(US$k/boe)
190
927
716
4.2
17.7
28.3
45.2
52.4
25.3
2P Res.
EV/2P
(mmboe) (US$/boe)
21
44
83
9.2
21.0
8.7
2C Res EV/2P+2C
(mmboe) (US$/boe)
0
49
105
9.2
10.0
3.8
Source: Factset, Macquarie Research, September 2012. *Last reported. **Assumes farm-down to 19.5% economic interest
…and trades at a
small discount to its
Core NAV of 7.6p/sh
12 September 2012
In Figs 13 and 14 on the following page we look at Petroceltic within the context of our entire
coverage universe. Trading at a small 2% discount to its Core NAV of 7.6p/share and a 19%
discount to its Core + Risked NAV (vs the sector discount of 18%) suggests that Petroceltic is
not an expensive stock. However, on both these metrics, we believe it would be hard to argue
it is a compelling “value” stock.
7
Macquarie Research
Fig 13 Trading at a only a small discount to Core NAV
Petroceltic is not a “value” stock
Fig 14 However it does trade at a 19% discount to its
Core + Visible E&A NAV
60%
120%
100%
40%
80%
20%
60%
0%
40%
-20%
20%
5%
0%
Pr. / (Disc.) to Core + Risked E&A ups.
Avg.
-60%
The Board has a
track record of
growing E&Ps
PTR
VOG
SQZ
RKH
MXP
PMO
DNO
SMDR
PCI
FPM
BLVN
AFR
CNE
LUPE
SIA
GPK
VPP
HDY
TLW
PTR
RKH
VOG
MXP
PMO
DNO
BLVN
PCI
CNE
SQZ
FPM
LUPE
SIA
-80%
VPP
GPK
SMDR
AFR
Avg.
HDY
-60%
TLW
Pr. / (Disc.) to Core
COV
-40%
-19%
-40%
-2%
-20%
-18%
Instead, our Outperform recommendation is premised upon 20% upside potential to our 9p/sh
fair value but also a confidence that there will be further corporate activity to bolster the
portfolio. This latter argument rests on a Board which contains individuals which have a track
record of growing small cap E&Ps. For more details of the Board‟s composition please refer
to page 26 however a brief overview of the key personnel within the enlarged group is given
below:
Brian O’Cathain – Chief Executive (PCI)
A geologist and petroleum engineer, Mr O‟Cathain was Managing Director of Tullow Oil‟s
international business and CEO of Afren (2005-07). Before that, he was a senior manager of
Shell International, where he was principally involved with acquisitions, divestments and
corporate strategy.
Tom Hickey – Chief Financial Officer (PCI)
Mr Hickey was an Executive Director and CFO of Tullow Oil, from 2000 to 2008, when Tullow
grew through a number of significant acquisitions including the US$570m acquisition of
Energy Africa in 2004 and the US$1.1bn acquisition of Hardman Resources in 2006.
David Thomas – Chief Operating Officer (MRS)
Mr. Thomas was appointed CEO of Melrose in 2007, before that he was President and COO
of Centurion Energy, an Egyptian, Tunisian and West African E&P which was acquired by
Dana Gas in 2007 for US$1bn.
Robert F. M. Adair – Non-executive Chairman (MRS)
Mr Adair founded the company which originally grew into Melrose Resources. Mr. Adair is a
geologist and was a Chartered Accountant specialising in oil and gas taxation.
12 September 2012
8
Macquarie Research
Melrose Resources brings production
Production comes from mature assets in Egypt and Bulgaria
The asset base of
28kboe/d is in its
natural decline
phase
Melrose Resources brings to the combined entity immediate production, with 1H12 WI
production of 28.2kboe/d coming from Egypt and Bulgaria. The fields though are generally
mature and to FY17 we expect overall group production to have fallen by 51% from our FY12
forecast of 27.0kboe/d to just 13.3kboe/d (Fig 15). Within these estimates, the following fields
are expected to come on stream and help support production:
 In 2013 the West Zaharya, East Dikirnis and West Abu Khadra fields onshore Egypt are
expected to commence production, contributing up to ~1kboe/d. We believe that this
incremental production should be enough to stabilize, if not marginally improve, Egyptian
production.
 In 2014 we expect the Kavarna East field offshore Bulgaria to be tied into the existing
Galata facilities with production ramping up to 1.2kboe/d net by 2015. However, this could
be delayed if the Galata field is reactivated. The field was previously shut-in during 2009 in
order to be converted into a gas storage facility however a recent flow test of the Galata-1
well of 17mmcf/d over a 24 hour period has led to conversations with the Bulgarian
authorities about recommencing production as early as next year.
Looking out to 2018 though Petroceltic should see a marked transformation in its production
profile as the Ain Tsila discovery comes on stream, contributing 15kboe/d net at plateau in
2019 based upon a residual 19.5% economic interest. It is worth noting that our mid 2018
start up compares to Petroceltic‟s current timetable which sees the field on stream in 4Q17.
Based on current oil and gas prices and production assumptions, we forecast operating cashflow generation to be more than sufficient to pay for the planned capex assuming that
Petroceltic is carried on its Ain Tsila development spend.
This should help deleverage the company and we expect the gearing ratio (ND / ND + E) to
fall from its current level of 18% to 12% by 2H15 (Fig 16). The graph shows operating cashflow dropping off in 2015, a direct consequence of falling Egyptian production.
Fig 15 Pro-forma WI production profile (existing
discoveries only)
Fig 16 Positive Free cash-flow generation to trigger
deleveraging
100
(kbo e/d)
30
27.0
26.3
90
27.0
25.0
25
24.6
18.7
17.2
15
13.3
19.2
8.7
50
10%
40
12.8
11.2
5
80
60
19.4
13.3
10
20%
70
20
13.2
Gearing ratio
(%)
15%
21.7
14.6
CFO & Capex
(US$m)
30
5%
6.5
20
0
10
2012
2013
2014
2015
2016
2017
2018
2019
2020
A in Tsila
B ulgaria - Kavarna
B ulgaria - Kaliakra
B ulgaria - Kavarna East
Egypt
To tal NE pro ductio n
Source: Company data, Macquarie Research, September 2012
12 September 2012
0
0%
2H12 PF H1 2013 H2 2013 H1 2014 H2 2014 H1 2015 H2 2015
Cashflow from operations
Capex
Gearing
9
Macquarie Research
Receivables from EGPC likely to keep the market on edge
We are not oblivious
to the Egyptian risk
but in our view it is
overplayed
presently
With ~80% of the enlarged groups production and ~50% of its cash-flow from operations
coming from onshore Egypt (1H12A), the market is likely to have some concern over the
Egyptian General Petroleum Company‟s (EGPC) ability to make full and timely payments for
oil and gas production. Unfortunately there is insufficient disclosure in Melrose Resources‟
accounts to determine the precise level and direction of Egyptian receivables and certainly
management and peers state that payments continue to be received in a timely fashion.
However, we believe that the fact that group trade receivable days have stayed at elevated
levels despite Egypt falling as a proportion of overall group revenue may be indicative of
some strain on the EGPC payment mechanism.
 While Melrose Resources does not explicitly break out “Trade receivables” by country, we
believe that group “Trade receivables” is a sufficient proxy and in Fig 17 below we have
looked back at the evolution of Melrose Resources‟ trade receivable days (on a lagged 6
month basis to compensate for the fact that Egyptian production is paid six month in
arrears) to get an indication of whether or not there has been any marked deterioration in
Egyptian payments. Certainly, the current level of ~200days is nothing new.
 However, one thing we would highlight is that as Egyptian revenues became a larger
proportion of group revenues in the 2007-2009 period trade receivable days also
increased. However, the reverse has not really been true. As Egyptian revenue has
become a diminishing part of group revenue since 1H10, trade receivable days have in fact
remained at elevated levels since the onset of the Egyptian Arab Spring in early 2011 and
it is for this reason we at least flag Egyptian receivables as a potential risk
Fig 17 Despite Egyptian production declining as a proportion of group revenue
trade receivable days have remained at elevated levels
Onset of Egyptian Arab Spring
250
100%
90%
200
80%
70%
150
60%
50%
100
40%
30%
50
20%
10%
0
0%
1H07
2H07
1H08
2H08
1H9
2H9
Trade Receivable days (lagged 6 months)
1H10
2H10
1H11
2H11
1H12
Egypt as % of Group Revenue
Source: Melrose Resources, Macquarie Research, September 2012
 While we flag the above as a concern, we take confidence that Melrose Resources‟
management team say that they continue to receive payments inline with a pre-agreed
payment schedule and peer Circle Oil recently declared that trade receivables from EGPC
had diminished since June 30th despite higher prices and volumes. Recent media articles
stating that BP wants to invest US$10bn in Egypt over the next 5 years are further
reassurance of confidence in the new administration.
 In terms of the overall health of the EGPC this remains difficult to gauge. We do know
however that Egypt‟s Sovereign 5yr CDS spread over US Treasuries has fallen from
723bps at the end of June to 463bps presently. We believe this is on the back of US$3bn
of loans from the Islamic Development Bank and Qatar and ongoing talks with the IMF for
a US$4.8bn loan by year end. Furthermore, a planned US$18bn Qatari investment in
Egypt‟s tourism and industry projects over the next 5 years is, in our view, another vote of
confidence in the new Mursi administration.
12 September 2012
10
Macquarie Research
Liquidity looks adequate but HSBC loan needs to be re-financed
As shown in Fig 18 below, based upon our forecast that Petroceltic farms out sufficient equity
in Ain Tsila to ensure a carry through to first gas, cash-flow from operations is sufficient to
meet the current capex profile of the enlarged group as well as US$100m of debt amortisation
which occurs between now and when the HSBC loan comes due in 1H14.
Combined entity’s financing to FY14
(US$m)
WI Production:
Egypt: 21.9kboe/d
Bulgaria 4.4kboe/d
Total 26.3kboe/d
350
300
250
200
150
100
50
10
$25m Enel
contingent
payment and
$15m capex
56
10
124
WI Production:
Egypt: 21.9kboe/d
Bulgaria 5.2kboe/d
Total 27.0kboe/d
107
132
100
67
33
131
81
55
In 2014 the
remaining $200m of
the HSBC loan will
come due and will
need to be
refinanced
200
200
80
Cash at 31-Dec-14
400
Loan refinance
Fig 18
HSBC loan
We do not see any
near term financing
pressure
0
-50
-100
Debt amm.
2014 Net Capex
2014 Op. C. F.
Cash at 31-Dec-13
Debt amm.
2013 Net Capex
2013 Op. C. F.
Cash at 31-Dec-12
MRS cash
PCI 2H12 Net
Capex
PCI 2H12 Op. C.
F.
PCI cash at 30-Jun
-150
As part of the merger, Melrose‟s US$301m of debt drawn down under its existing US$385m
Senior Loan and Subordinated Loan Facility, presumably terminated under a Change of
Control clause - and is to be refinanced by a new 18-month term loan provided by HSBC. We
understand that the amount of debt available under this HSBC loan will amortise to US$200m
by the time it needs to be refinanced in 1H14 and, assuming this amortises at US$33m per
half year, this too can be met from existing cash balances and forecast cash-flow.
Petroceltic may look
for an increase in
the borrowing base
to finance a larger
retained economic
interest in Ain Tsila
12 September 2012
However at the analyst meeting coinciding with the merger announcement, it emerged that
Melrose Resources‟ existing debt facilities were conservatively based upon Egyptian and
Bulgarian field cash-flow until 2014. Therefore, we expect the HSBC US$300m facility to be
refinanced and expanded well before the 1H14 expiry, especially given the deleveraging
trajectory (highlighted previously in Fig 16) and the free cash-flow generation. Indeed, one
strategy that Petroceltic have indicated that may well pursue, but we do not presently model,
is to use the current cash-flow from operations and falling gearing ratio to leverage debt
against the Ain Tsila development. This would see Petroceltic retain a larger economic
interest in the development by executing a farm-out deal for only a partial carry.
11
Macquarie Research
As it stands, exploration is light
Visible E&A
accounts for just
1.7p of risked value
With drilling in the Mesaha block (Egypt) the only firm exploration well in the campaign (and
even here management has not provided a pre-drill resource estimate) we believe that the
shares will fail to price in much of the exploration upside in the near term. However, securing
drilling rigs should help reverse this and we would expect one of management‟s focuses to be
deploying the free cash-flow outlined previously into expanding the exploration portfolio.
In total, we believe that over the course of the next 12 months, Petroceltic may drill up to 6
exploration wells targeting a net unrisked 204mmboe. Combined these are worth 1.7p on a
risked basis and 12.8p on an unrisked basis (Fig19).
Fig 19
Est spud
date
Oct-12
Jan-13
Feb-13
Jun-13
Aug-13
Sep-13
Total
Exploration drilling is targeting 204mmboe of net unrisked resources
Prospect
Portfolio
Mesaha Blockl, Egypt
Kamchia, Bulgaria
Carpignano Sesia, Italy
Muridava, Romania
Shakrok, Kurdistan
Est Cobalcescu, Romania
Melrose Res.
Melrose Res.
Petroceltic
Melrose Res.
Petroceltic
Melrose Res.
Gross res.
(mmboe)
Working
Interest (%)
100
5
162
21
650
21
958
40%
100%
24%
40%
16%
40%
Net unrisked
Chance of Risked value
Unrisked
res. (mmboe) Success (%)
(p/sh) value (p/sh)
40
5
38
8
104
8
204
10%
20%
15%
10%
25%
10%
0.0
0.1
0.7
0.0
0.9
0.0
1.7
0.7
0.8
4.6
1.5
3.8
1.5
12.8
Source: Melrose Resources, Petroceltic, Macquarie Research, September 2012
 Mesaha, Egypt: The Mesaha prospect is located in the frontier Mesha basin in southern
Egypt on the border with Sudan. 2D seismic and aerogravity studies show Mesaha to be a
rift basin consisting of two depocentres separated by an inta-basinal high. The Mesaha-1
well will be the first to be drilled in the basin, and will target Paleozoic aged sands with a
planned TD of 3,000m and gross well costs of ~US$16m. The nearest offset well is 400km
to the north and was drilled back in 1979 and therefore we believe there is likely to be
some uncertainty regarding hydrocarbon phase.. Melrose Resources have not given any
guidance to prospect size however partner Beach Energy suggest that structures are
consistent with prospect sizes >100mmboe.
Fig 20 Location of exploration drilling within the
Melrose Resources portfolio
Fig 21 While exploration drilling in Petroceltic’s
portfolio includes onshore Italy
12 September 2012
12
Macquarie Research
 Kamchia, Bulgaria: The Kamchia prospect is located within the central area of the
offshore Galata block and has been mapped on 3D data shot in 2011. Melrose Resources‟
CPR, issued alongside the merger, estimate the prospect to hold 27bcf of recoverable gas
which would, in the case of success, be commercialised via a low cost tie back to the
Galata production facilities. Migration of hydrocarbons is the greatest risk while the CPR
also points to the possibility of compartmentalisation however it is the lowest risk of eight
prospects identified on the Galata block. Timing of the exploration well is dependent upon
securing a rig which would also be used to drill the two Romanian exploration wells
(below).
 Carpignano Sesia, Italy: Located in the onshore Po Valley area of Italy, the Carpignano
Sesia prospect is estimated in Petroceltic‟s CPR to hold 162mmb of oil on a gross „best
estimate‟ basis within both Jurassic and Triassic potential. The prospect is believed by
Petroceltic to be a direct analogue to ENI‟s Trecate Villafortuna field (~25km offset).
Petroceltic have previously talked of farming down its interest prior to drilling and in our
EMV we have assumed that the company farms-down its current 47.5% WI to a retained
23.75% WI. The well should take approximately 2-3 months to drill, suggesting a 2Q 13
result, however, with all Italian wells requiring both local and environmental permits, the
planned spud date in 1Q 13 cannot be confirmed.
 Muridava & Est Cobalcescu, Romania: There are no defined prospects on either the
Muridava or Est Cobalcescu concessions located within the Black Sea however 3D
seismic is ongoing over both. The licenses lie in water depth <100m are under-explored
and are considered to have both gas and oil potential across Pliocene to Cretaceous aged
sands (MRS have previously indicated 1-2tcfe of gross prospective resources across the
acreage). In March 2012, a 40% WI on the Muridava concession was farmed out to
Sterling Resources while a farm-out of a similar 40% WI to Beach Energy for the Est
Cobalcescu concession was announced in September 2012. Two exploration wells are
planned for 2013 and a further four in 2014 with well costs between US$16m-US$25m on
a gross basis.
 Shakrok, Kurdistan: Petroceltic plan to drill the Shakrok prospect within the Shakrok PSC
in 3Q12. 2D seismic interpretation is currently ongoing although Petroceltic‟s CPR
estimated the Shakrok prospect could hold ~650mmb of gross recoverable resources, and
would in our view, de-risk the 217mmb Pelewan prospect in the case of success. Given the
location of the PSC, we expect Cretaceous, Jurassic and Triassic formations all to be
targeted with the key risks being the hydrocarbon phase and porosity of reservoir.
12 September 2012
13
Macquarie Research
Asset overview
Algeria – The largest component of our target price
Isarene PSC (56.625% WI, op) – Sonatrach (25% WI), Enel (18.375% WI)
Ain Tsila accounts
for 3.5p of our
valuation, with a
farm-out now the
main focus
The Isarene PSC located in the Illizi basin of south-east Algeria contains Petroceltic‟s
principal asset, the Ain Tsila wet gas discovery. The field has been appraised through a total
of 9 wells drilled by Petroceltic and flow tests with the latest estimate of recoverable
resources of 2.1tcf of saleable gas, 113mmb of LPG and 70mmb of condensate.
Geologically, the field is Ordovician in age, a proven commercial reservoir in the nearby Tin
Fouye-Tabankort (Repsol/Total), Ohanet (BHP) and Tignuentourine (BP/Statoil) fields (Fig
22). With theses fields all on production at rates of 350-1,000mmscf/d we see the Ain Tsila
development concept as well tested, with production likely to use the Tin Fouye-Tabankot
export pipeline.
One of the variables though is that the reservoir is not homogenous, with Fig 23 showing
Petroceltic‟s interpretation of reservoir quality across the field. In the development concept put
forward by Petroceltic it is estimated that 20% of the development wells will contribute 80% of
the production with Region 1 likely to be the most prolific because of the High Permeability
High Fracture nature of the reservoir.
Fig 22 Ain Tsila to leverage nearby existing field
infrastructure
Fig 23 Development wells likely to have variable
productivities
The Ain Tsila partners submitted a Formal Declaration of Commerciality for the field to the
Algerian Competent Authorities in early August having agreed a binding heads of terms with
Sonatrach for the marketing of gas sales. Once approved, the partners will be awarded a 30year exploitation permit for the field. Although the precise pricing details have not been
released, we believe that the heads of terms for the gas sales are in line with historical
Algerian contracts which are, within a range, linked to Brent oil prices. Ultimately we believe
US$7-US$10/mcf is likely to be attainable.
In terms of our development scenario, we are generally more conservative than company
guidance:
 Development capex of US$2.9bn, which equates to US$5.4/boe, ~15% ahead of
management‟s guidance of US$4.7/boe. US$1.6bn of capex is prior to first gas.
 Life of field opex of SU$2.5/boe, again ~20% ahead of management‟s guidance of US$2.1/boe.
 A gas sales price of US$9/mcf, although we think that with the contracts linked to oil prices,
realisations may be nearer US$10/mcf if crude stays above US$100/bbl.
 First production in mid 2018, 9 months later than currently planned with our 355mmscf/d
wet gas production plateau rate of 14 years in line with current management guidance
12 September 2012
14
Macquarie Research
Fig 24 Field production and contractor share of post
royalty revenue
Production
(kboe/d)
80
Contractor share
of revenue (%)
100%
90%
70
80%
60
70%
50
Fig 25
2,500
Ain Tsila cash-flow generation profile (gross)
Opex
Capex
Government take
Revenue
AT Cash flow
(US$m)
2,000
1,500
1,000
500
60%
0
50%
Source: Source: Company data, Macquarie Research, September 2012
2046
2044
2042
2040
2038
2036
2034
2046
2044
2042
2040
2038
2036
2034
2032
2030
2028
Contractor share of Total Hydrocarbon Revenue
2032
-2,500
2030
-2,000
0%
2028
10%
2026
Field production
2026
2024
2022
2020
2018
2016
2014
2012
0
2024
-1,500
2022
20%
2020
10
2018
-1,000
2016
30%
20
2014
40%
30
-500
2012
40
We believe that award of the exploitation permit mentioned above will also be the catalyst for
Petroceltic to formalise a second farm-out. We understand that Petroceltic has applied to
Sonatrach to allow potential farm-in partners access to its data and a farm-in is hoped for by
the end of this year.
We estimate
Petroceltic would
retain a 19.5%
economic interest if
carried to first gas
The Melrose Resources merger may allow Petroceltic to fund a larger residual economic
interest in the project by giving it easier access to debt capital. However, for the time being we
assume that Petroceltic seeks a full carry on development costs through to first gas. In order
to achieve this, and for the farm-in partner to still achieve a 15% IRR on the project, we estimate
that Petroceltic would have to farm-out a 37% economic interest. This would see Petroceltic‟s
economic interest in the license reduce from its current level of 56.625% to just 19.5%.
If our assumptions prove correct, as Fig 26 shows, the implied PSC valuation would have
increased 35% since the April 2011 Enel farm-out1.
Fig 26 Under our assumptions, Ain Tsila’s value has increased by 35% since the
2011 Enel farm-out
Date
Equity interest acquired
Value of carry and cash payments (US$m)
PSC Resources at date of transaction
Implied value of PSC (US$m)
Implied NPV/boe (US$/boe)
Enel farm-out
2nd Farm-out
Increase
April 2011
18%
97
400
529
1.3
TBC
37%
313
538
843
1.6
35%
59%
18%
However there are
farm-down
restrictions
Farming down a further 37% economic interest of the license though is complicated by the
fact that the PSC terms preclude Petroceltic from farming down more than 50% of its original
75% Working Interest (i.e. 37.5% of the overall licence interest) prior to first gas. To date it
has already farmed out an 18.375% WI to Enel, meaning that only a further 18.375% WI can
be farmed down with Sonatrach‟s consent. However, we understand that potential exists for
alternative deal structures to be employed that can mitigate this problem, including a binding
commitment to farm-down the additional equity interest upon first gas. Hence, we refer in this
document to Petroceltic‟s interest in Ain Tsila post farm-out as an Economic, rather than
Working, interest.
1
In April 2011 Petroceltic announced the sale of 18.375% WI in the Isarene PSC to Enel, one of Europe‟s
largest energy utilities and the second largest purchaser of Algerian gas. The terms of the farm-down saw
Petroceltic receive back costs and appraisal carry worth a combined US$54.5m, while Petroceltic expect to
receive ~US$25m of a contingent US$75m payment, with the exact level determined by the level of
recoverable hydrocarbon reserves approved by the Algerian Authorities in the Final Discovery Report.
12 September 2012
15
Macquarie Research
Bulgaria – Extending production through near-field exploration
Galata block (100% WI)
Bulgaria accounts
for ~20% of current
production but 50%
of the cash-flows
Fig 27
The Galata block is located in the shallow waters of the Black Sea and contains both the
Kaliakra (23bcf) and Kavarna (19bcf) gas fields which in 1H12 produced 40mmscf/d
(~7kboe/d). The two fields (Fig 27) were discovered by Melrose Resources in 2007 and 2008
respectively and brought on stream in 2010 through subsea tie backs to the Galata platform,
a field which was developed by Melrose in 2004 and shut in during 2009 in order to convert it
to a gas storage facility.
Galata Block overview
Fig 28
Bulgaria production estimates
(mmcf/d)
(% of total)
45
100%
40
90%
35
80%
70%
30
60%
25
50%
20
40%
15
30%
10
20%
5
10%
0
0%
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Kaliakra
Source: Company, Macquarie Research, September 2012
Kavarna
Kavarna East
% of Tot. WI prod
In addition, the Galata block contains the Kavarna East (8bcf) discovery which was made in
2010 and which Melrose Resources expect to be tied into existing infrastructure in mid-2013,
something that for 2014 should see production stabilise (Fig 28). However, the company has
said it may defer this tie in as the Galata-1 well, following a 3 year shut in period, recently
tested 17mmscf/d. This has prompted discussion between Melrose Resources and the
Bulgarian authorities as to whether or not to abandon the gas storage development and
reactivate the field which has between 5-9bcf of recoverable resources remaining.
The 33bcf Kamchia
prospect is likely to
be drilled in early
2013
Following a new 3D seismic survey in 2011, Melrose Resources has also identified eight
exploration prospects within the acreage (Fig 29), with the largest, Kamchia, likely to be drilled
in early 2013. A further contingent well prior to February 2013 would then be required to meet
the minimum work commitments of the current 1st period extension after which a 2nd extension
to February 2015 may be elected. Sub faults within the structures leading to compartmentalism
are one of the principal risks highlighted in the CPR surrounding these prospects.
Fig 29
8 prospects have been defined on the 2011 3D data set
Prospect
Chaika NW
Chaika NE
Chaika S
Kamchia
Prospect A
Prospect E
Prospect F
Prospect H
Low Case (bcf)
Best Case (bcf)
High Case (bcf)
CPR CoS (%)
12
6
12
20
6
18
3
9
22
10
23
33
10
29
6
15
48
15
46
50
15
44
9
26
21%
20%
27%
40%
11%
16%
27%
7%
Gas price realisation are high, averaging US$8.15/mcf in 1H12 with the full year expected to
be US$8.3/mcf and up from US$7.3/mcf in 2011. Concession terms are also attractive,
operating under a 12% Royalty tax and a 10% Corporation Tax. Opex costs, given the
existing infrastructure are US$0.5/mcf (US$3/boe) while Melrose Resources has previously
guided to development costs of US$7.2-US$10.8/boe.
12 September 2012
16
Macquarie Research
Egypt – Trying to stem the natural decline curve
El Mansoura and SE Mansoura Concessions (100% WI)
Egyptian production
comes from a total
of 11 fields
The El Mansoura and SE Mansoura Concessions are located onshore in the Nile Delta (Fig
31). Gas was first discovered on the concessions in December 2001 and currently there are
11 producing fields with 74mmboe of 2P reserves, of which ~83% is gas and the rest oil and
condensate. The most significant fields within the concession are West Khilala and West
Dikirnis, both within the El Mansoura concession, which combined account for 62% of the
overall 2P reserves (Fig 30).
Fig 30
Best estimates of 2P reserves amount to 74mmboe
Field
Concession
West Khilala
South Khilala
El Tamad
East Dikirnis
West Dikirnis
South Zarqa
NE Abu Zahra
East Abu Khadra
West Zahayra
Damas
South Damas
Total
El Mansoura
El Mansoura
El Mansoura
El Mansoura
El Mansoura
El Mansoura
El Mansoura
El Mansoura
El Mansoura
SE Mansoura
SE Mansoura
Gas (bcf)
Cond/LPG (mmb)
Oil (mmb)
Total( mmboe)
129
35
26
3
75
20
3
21
0
1
43
356
0
0
0
0
5
1
0
0
0
0
0
6
0
0
2
0
7
0
0
0
0
0
0
8
22
6
6
1
24
4
0
4
0
0
7
74
Production peaked
at 40kboe/d in 2010
Production has fallen from its peak level of ~40kboe/d in 2010 (Fig 32) and in 1H12
production averaged 21kboe/d (103mmscf/d of gas and 3.58kb/d of liquids) as production has
been choked back to deal with increasing water and sand production.
Melrose Resources is pursuing various methods to help delay the natural decline of the
concessions. In late 2012/2013 the company plans to install compression units on the West
Khilala field while the potential for gas-reinjection to maintain reservoir pressure is being
considered for the West Dikirnis field. High angle/horizontal development wells for both fields
are also planned for 2013. Furthermore, the West Zaharya, East Dikirnis and West Abu
Khadra fields are also planned to be brought on stream in 2013 however they are expected
by Melrose Resources to deliver only 1kboe/d of incremental production.
All in all then, we see scope for Egyptian production to at least stabilise, if not show very
modest growth, over the next 1-2 years.
Fig 31
El Mansoura and SE Mansoura concessions
Fig 32
Egypt actual and forecast production
(kboe/d)
(% of total)
45
100%
40
90%
35
80%
70%
30
60%
25
50%
20
40%
15
30%
Liquids
12 September 2012
Gas
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
0%
2008
10%
0
2007
20%
5
2006
10
% of Tot. WI prod
17
Macquarie Research
Both concessions operate under PSC terms with the Egyptian General Petroleum
Corporation the governmental representative within the PSC. Melrose Resources is able to
recover 25% of its exploration and development expenditure while 100% of opex is cost
recoverable. Cost oil/profit oil is split 35%/65% (contractor/government) while Melrose
Resources‟ share of profit oil is between 15%-18% dependent upon production level.
In terms of sales pricing, oil is sold at international pricing while gas is sold at fixed prices of
US$2.65-US$2.95/mcf.
Looking at the exploration upside within the concession, the Senergy CPR has identified
41mmboe of prospective resources across 8 prospects with Chances of Success up to 42%
(Fig 33)
Fig 33
Overview of Best Estimate prospective resources in Egypt
Prospect
Concession
Mit Hadid
Mustafa
NW Zahayra
SW Tarif
Al Hajarisah
Kafr Saqr
Sidi Gohar
Sinbelaywan
Total
El Mansoura
El Mansoura
El Mansoura
El Mansoura
SE Mansoura
SE Mansoura
SE Mansoura
SE Mansoura
Oil (mmb)
1
2
1
2
6
2
5
9
26
Gas (bcf) Total Mmboe
7
16
10
11
18
10
5
9
86
2
5
3
3
9
4
5
10
41
CoS
31%
40%
40%
42%
13%-18%*
9%-13%*
12%-15%*
11%-15%*
Source: Senergy CPR, Macquarie Research, September 2012. Prospects have prospective intervals at the
Kharita, Barremian and Neocomian intervals
12 September 2012
18
Macquarie Research
Italy – Firming up drilling schedules is the near term goal
In the two Figures below we show the map of the two main Italian assets in Petroceltic‟s
portfolio. The Elsa field (Fig 34), in the central Adriatic Sea and the Carisio permit (Fig 35)
onshore Po Valley
Fig 34 Elsa-2 may well be drilled in 2014 to fully
determine oil quality
Fig 35 Carpignano Sesia farm-out is a near term
priority
B.R268.RG Permit (55% WI, op) – Orca (15% WI), Vega Oil (30%WI)
Shareholders will
have to wait until at
least 2014 before
Elsa’s
commerciality is
assessed
The B.R268.RG permit is located offshore in the Central Adriatic Sea contains the Elsa field,
discovered by Agip in 1992. According to the CPR issued alongside the Melrose Resources
merger, the Elsa discovery holds 95mmb of oil on a best estimate basis (34mmb P90;
187mmb P10) while the Elsa West prospect in the same permit holds prospective resources
of 54mmb. Elsa is potentially an important part of the Petroceltic asset portfolio, worth 2.2p
risked; 9.5p unrisked. However given questions surrounding its commerciality and time-line to
drilling in order to prove this, both outlined below, its value is excluded from our target price.
The original discovery well (Elsa-1) encountered relatively heavy oil of 12-15°API quality,
however Petroceltic believes that the large extent of the interval tested may have
compromised the test results, especially with the nearby Miglianico field containing 34-37°API
oil (a similar sand fan from the Apulian platform margin).
The company was planning to drill the Elsa-2 appraisal well in 2010 with the objective of
demonstrating commercial flow rates and determining oil quality. However, the
implementation of Legislative Decree 128 in August 2010 in response to the Macondo
disaster froze drilling within 5 nautical miles of the Italian coastline and activity on the license
stopped.
This Decree has recently been overturned for grandfathered contracts signed before its
enactment (although an incremental 3% royalty is to be levied to cover improved monitoring
of marine environmental protection) and we expect Petroceltic will now look to put in place the
environmental permits over the 2012/13 period as well as secure a suitable rig for possible
appraisal drilling in 1H14.
We understand that gross well costs are likely to stand at ~US$35m for which Petroceltic
would be liable for ~US$15m as the 2010 farm-out to Orca Exploration sees Petroceltic
partially carried on the appraisal well.
In Fig 36 and 37 below we highlight the model economics for Elsa assuming a production
profile that achieves first oil in 2018 and peak production rate of 25kb/d (and 13% average
decline rate). Based on these assumptions, our model generates a US$17.3/bbl NPV10.
12 September 2012
19
Macquarie Research
Elsa production profile
(kboe/d)
30
Fig 37
(US$m)
1200
Opex
80
1000
Capex
70
800
Revenue
60
600
AT cash flow
50
400
40
200
30
0
20
-200
10
-400
0
-600
(mmboe)
90
25
20
15
10
5
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
0
Oil production
Gas production
Elsa cash-flow generation profile
Cumulative production
Government take
-800
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
Fig 36
As discussed earlier, until the planned appraisal well provides firmer production rates, it is
difficult to generate definitive economics, however, thanks to the favourable Italian tax terms
(31% corporate tax rate and 7% government royalty for offshore oil discoveries) the project is
likely to be NPV positive even at much lower production rates than our assumptions (ceteris
paribus, our break even NPV10 is at 10kboe/d peak rate and 19% average decline).
Carisio permit (47.5% WI) – ENI (47.5% WI, op), Costruzioni Condotte (5% WI)
The Carisio permit, operated by ENI and within the onshore Po Valley area of Italy, contains
the Carpignano Sesia (formerly Rovasenda) 162mmboe prospect which has stacked
objectives across Jurassic and Triassic objectives. Petroceltic believe the prospect to be a
direct analogue to ENI‟s Trecate Villafortuna field (~25km offset) and is the most advanced of
five Mesazoic and Tertiary mapped leads and prospects on the permit.
Despite an extremely bureaucratic environmental permitting process, Petroceltic is optimistic
that ENI will be able to spud the well in 1H13 which will cost an estimated US$40-US$50m
and take 4-6 months to drill. Petroceltic is conducting a farm-out process prior to drilling in
order to manage its financial exposure to the well. This is the largest exploration prospect
(0.7p/sh / 4.6p/sh unrisked) in our E&A risked upside included in the target price after
assuming a farm down to 23.8% for a one well carry
12 September 2012
20
Macquarie Research
Kurdistan – The largest structures in the portfolio
Shakrok & Dinarta PSCs (16% WI) – Hess (64% WI, op), KRG (20% WI)
Prospective
resources of >2.5bn
bbls mapped across
the two PSCs
Petroceltic entered the Kurdistan region of Iraq in July 2011 bidding alongside Hess for the
Dinarta and Shakrok PSCs after it became evident that the Kurdistan Regional Government
(KRG) was unlikely to grant operatorship of PSCs to companies the size of Petroceltic
The PSCs are located in the more mountainous part of Kurdistan, with the Dinarta block
adjacent to MOL‟s (and Gulf Keystone‟s) Akri-Bijeel block which has found heavy oil in the
Jurassic formation while the Shakrok block is further to the south east and adjacent to
ExxonMobil‟s Betwata block.
Fig 38 The position of the Dinarta and Shakrok PSCs
within Kurdistan
Fig 39 The PSCs are in close proximity to existing
discoveries
The Dinarta block has three obvious surface anticlines: Shireen (660mmb), Chinara
(567mmb) and Bradost (533mmb) which are on trend with oil discoveries at Shaikan, Atrush
and Swar Tika. The Shakrok block has two surface anticlines: Shakrok (650mmb) and
Pelewan (217mmb).
Petroceltic has committed to spend in the region of US$90m in Phase 1 which is its share of
signature and other bonuses, 750km of 2D seismic across the two PSCs and an exploration
well on each. We expect that 2D seismic to be completed in 4Q12 with interpretation likely to
finish in early 2013 which should lead to finalised well locations.
Petroceltic envisage the first exploration well to target the 650mmb Shakrok prospect in 2H13
and we foresee an approximate drill time of ~6 months.
12 September 2012
21
Macquarie Research
Romania – Provides shallow water exploration potential
Muridava (40% WI, op); Est Cobalcescu (40% WI, op)
Following the recent
farm-out to Beach
Energy, we expect
prospect definition
in 4Q to be the next
catalyst
Melrose Resources entered offshore Romania is in 2011 through the country‟s 10th licensing
round when it was awarded an 80% WI in the Muridava and Est Cobalcescu shallow water
blocks (WD <100m), with Petromar Resources taking the remaining 20% WI. Prior 2011,
Melrose tried to enter into Romania by farming into two Sterling Resources‟ blocks (Pelican
XIII and Midia XV blocks, containing the Ana and Doina gas fields). The deal was announced
in December 2008 but on 1st November 2010 the companies announced the farm-out deal
had been terminated with no explanation given as to why.
On 22nd March 2012, Melrose Resources farmed down a 40% WI in the Muridava block to
Sterling Resources and on 10th September 2012 followed this up with a farm down of a 40%
WI in the Est Cobalcescu block to Beach Energy for US$4.8m (past costs and carry on the
recently completed 3D acquisition). In both blocks, Melrose Resources retains a 40% WI and
operatorship.
Based upon 2D seismic over the two blocks Melrose Resources has publically declared it
sees 1-2Tcfe prospective resources. However, no discrete prospect sizes have yet been
disclosed. Further prospect definition is likely to emerge over the coming months though as
Melrose Resources has recently completed a 1,930sqkm 3D seismic shoot over both licenses
which is currently undergoing interpretation.
Fig 40
Romania licences overview
Source: Melrose Resources, September 2012
Romania’s
prospectivity has
increased following
ExxonMobil’s
Domino-1 discovery
Fig 41
Romania licences play types
Source: Melrose Resources, September 2012
As highlighted in Fig 41, hydrocarbon prospectivity is seen from the Pliocene through to
Triassic aged sands with the potential for both oil and gas and the six well exploration
campaign for 2013/14 is likely to target a number of different play types. While the region is
under-explored, the Muridava block already holds the Olimpiskiyi discovery (drilled in 2001
but for which there is limited data) while nearby acreage operated by Petrom OMV contains
the Lebada oil and gas fields while Sterling Resources has discovered both the Ana and
Doina gas fields (345bcf contingent resources). Perhaps more high profile though, was the
exploration success of ExxonMobil earlier in the year with the deepwater Domino-1 well which
encountered 71m of net gas pay and is believed by ExxonMobil to hold between 1.5-3.0tcf of
recoverable resources.
Similar to Bulgaria, Romania has attractive commercial terms with a maximum 13.5% royalty
rate and Corporation Tax of 16%. On a per unit basis, we would expect discoveries to have a
similar development and opex cost as the Romanian fields outlined above. In terms of gas
pricing, we also note that Romania is undergoing a liberalisation of the gas market in-line with
an agreement with the European Commission and the IMF. Social tariff subsidies are being
withdrawn from both Industrial and Residential customers over the 2013-17 timeframe while
producers will also be able to access export pricing.
12 September 2012
22
Macquarie Research
PETROCELTIC INTERNATIONAL (PCI, Outperform, Target price: 9p)
Price Assumption
Oil-Brent
Gas-UK
US$/£ (period average)
$/b
US$/mmbtu
2011A
111.3
9.3
2012E
107.5
8.5
2013E
106.3
8.5
2014E
115.5
8.8
2015E
117.5
8.8
$
1.60
1.58
1.60
1.60
1.60
Half-yearly Forecast
Oil-Brent
Gas-UK
Oil & Liquids
Natural Gas
Total Production
Income Statement
Oil & Liquids
Natural Gas
Total Production
Gas Production Ratio
kb/d
mmcf/d
kboe/d (@ 5.8:1)
%
2011A
0.0
0.0
0.0
na
2012E
0.0
0.0
0.0
na
2013E
3.8
130.4
26.3
85.4
2014E
3.8
134.9
27.0
86.0
2015E
3.4
106.3
21.7
84.3
Production Growth YoY
%
nmf
nmf
nmf
0.1
-0.2
Gross Revenue (pre-royalty)
Royalties
Net Revenue
Operating Costs
G&A Costs
Other operating expenses
EBITDA
DD&A
EBIT
Interest Costs
Other fin. costs
Taxes
Net Income
EPS (basic)
EPS (diluted)
Adjusted EPS (diluted)
m
m
m
m
m
0.4
0.0
0.4
0.0
-4.8
-4.9
-9.4
-0.4
-9.7
1.6
0.0
0.0
-8.2
-0.4
-0.4
-0.4
0.6
0.0
0.6
0.0
-5.1
-3.0
-7.5
-0.4
-7.9
2.8
0.0
0.0
-5.1
-0.2
-0.2
-0.2
213.1
-6.4
206.7
-22.0
-28.3
-17.0
139.4
-75.9
63.5
-10.7
0.0
-21.1
31.7
0.8
0.8
0.8
230.6
-7.4
223.2
-24.5
-29.7
-10.7
158.3
-80.0
78.3
-8.1
0.0
-28.1
42.1
1.0
0.9
0.9
183.6
-5.2
178.5
-20.1
-31.2
-10.7
116.4
-62.4
54.0
-6.7
0.0
-18.9
28.4
0.6
0.6
0.6
m
m
m
m
m
m
m
cts/sh
cts/sh
cts/sh
Revenue
EBITDA
Net Income
Net Cash Flow from Operations
$/b
US$/mmbtu
H1/12
113.5
9.0
H2/12
101.5
8.1
H1/13
104.0
8.3
H2/13
108.5
8.7
H1/14
111.0
8.8
kb/d
mmcf/d
kboe/d (@ 6:1)
0.0
0.0
0.0
0.0
0.0
0.0
3.9
130.2
26.3
3.8
130.7
26.3
3.8
134.9
27.0
m
m
m
cts/sh
m
0.3
-4.0
-3.2
-0.1
-22.5
0.3
-3.5
-1.9
-0.1
10.3
105.4
68.5
14.6
0.4
60.9
107.7
70.9
17.1
0.4
63.1
113.1
77.0
19.9
0.4
64.9
2011A
0.0
26.8
7.6
34.4
2012E
0.0
21.5
6.6
28.1
2013E
0.0
21.9
4.4
26.3
2014E
0.0
21.9
5.2
27.0
2015E
0.0
18.1
3.6
21.7
89%
90%
85%
86%
84%
Production profile
Ain Tsila
Egypt
Bulgaria
Total
% gas
kboe/d
kboe/d
kboe/d
kboe/d
%
45.0
35.0
100%
kboe/d
39.4
40.0
33.9
90%
36.1
34.4
80%
28.1
30.0
26.3
70%
27.0
25.0
21.7
20.0
%
%
13
nmf
33
nmf
nmf
nmf
-3
101
30%
Basic Shares (WA / OS)
Diluted Shares (WA / OS)
m
m
2278.7
2489.4
2369.6
2606.6
3883.5
4188.0
4388.1
4692.6
4388.1
4692.6
Balance Sheet
Cash (including Restricted)
Debt
Net Debt (Cash)
m
m
m
2011A
9.1
23.4
14.3
2012E
74.8
0.0
-74.8
2013E
86.1
233.4
147.3
2014E
80.3
200.1
119.8
2015E
81.3
200.1
118.8
Total Assets
Total Liabilities
Total S/H Equity
m
m
m
371.5
53.8
317.8
361.2
20.2
341.0
1177.7
360.0
817.7
1185.9
329.1
856.7
1218.4
331.5
886.8
Ratios Analysis
ROA
ROCE
ROE
Net Debt/Equity
Net Debt/CF
Price/Book
Book Value
Valuation
P/E
P/CF
Dividend Yield
Enterprise Value
EV/DACF
EV/Reserves4
EV/2P + 2C4
EV/Production4
Reserve/Production (2P)
Core Net Asset Value (PV10AT)
P/CoreNAV
Core NAV + Risked Resource Upside
P/RENAV
5
5
20%
5.0
-20
74
50%
40%
15.0
10.0
Revenue per Share Growth YoY
EBITDA per Share Growth YoY
60%
10%
0.0
0%
2008A
2009A
Ain Tsila
2010A
2011A
Bulgaria
2012E
2013E
Egypt
2014E
2015E
% gas
Cashflow Analysis
Cash Flow from Operations
Chgs in Working Cap
Cash Flow from Investing
Cash Flow from Financing
Increase in Cash
m
m
m
m
m
m
2011A
-3.5
12.9
9.3
-164.6
82.1
-73.2
2012E
-1.7
-10.5
-12.2
102.0
-24.1
65.7
2013E
124.0
0.0
124.0
-107.0
-10.5
6.5
2014E
132.3
0.0
132.3
-100.0
-33.3
-1.0
2015E
101.0
0.0
101.0
-100.0
0.0
1.0
Free Cash Flow1
m
-155.3
89.1
17.0
32.3
1.0
m
-17.3
6.0
177.0
196.5
145.5
0.4
-0.5
3.0
2.8
2.2
2011A
-2.5
-0.4
-2.1
4.5
1.5
1.1
0.1
2012E
-1.4
-0.1
-1.3
-21.9
6.1
0.8
0.1
2013E
4.1
2.0
7.7
18.0
1.2
0.6
0.2
2014E
3.6
2.5
10.3
14.0
0.9
0.6
0.2
2015E
2.4
1.7
6.9
13.4
1.2
0.6
0.2
Debt Adjusted Cash Flow (DACF)
%
%
%
%
x
x
$/sh
x
x
%
m
x
$/boe
$/boe
$k/boe/d
years
2011A
nmf
25.1
0.0
389
-22.5
nmf
1.28
nmf
nmf
2012E
nmf
nmf
0.0
236
39.3
nmf
nmf
nmf
nmf
2013E
15.9
2.5
0.0
653
3.7
nmf
nmf
24.81
0.0
2014E
13.5
2.7
0.0
687
3.5
nmf
nmf
25.40
0.0
2015E
20.0
3.5
0.0
686
4.7
nmf
nmf
31.55
0.0
p/sh
x
p/sh
x
7.6
1.0
13.7
0.6
Per Boe Statistics
Revenue/boe
Royalties/boe
Operating costs/boe
Operating Netback/boe
G&A/boe
Interest/boe
Cash Tax/boe
Cash Netback/boe
Depletion and Depreciation/boe
Stock based compensation/boe
Other Non-cash/boe
Deferred Taxes/boe
Exceptionals/boe
Earnings Netback/boe
CFPS
Capital Expenditures & Acquisitions
m
164.6
-101.4
107.0
100.0
100.0
Capex/Cash Flow
x
-46.6
58.5
0.9
0.8
1.0
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
2011A
nmf
nmf
nmf
0.00
nmf
nmf
nmf
0.00
nmf
nmf
nmf
nmf
nmf
0.00
2012E
nmf
nmf
nmf
0.00
nmf
nmf
nmf
0.00
nmf
nmf
nmf
nmf
nmf
0.00
2013E
43.51
-1.31
-4.50
37.71
-5.78
-2.19
-4.31
25.43
-15.50
-0.46
-2.51
nmf
0.00
6.95
2014E
44.70
-1.44
-4.75
38.51
-5.77
-1.57
-5.44
25.73
-15.50
-0.44
-1.63
0.00
0.00
8.16
2015E
44.70
-1.44
-4.75
38.51
-5.77
-1.57
-5.44
25.73
-15.50
-0.44
-1.63
0.00
0.00
8.16
All figures US$ unless noted and production and reserve figures are gross of royalties
1) Cash flow from Operations (before chg in WC) Less Capex
2) Excludes non-producing assets
3) Risked resource upside based on LT price of US$8.8/mmbtu HH, US$115/b Brent, and GBP/USD 1.6
12 September 2012
23
Macquarie Research
Appendices
Combined capital structure
We highlight in Fig 42 the key features of the combined capital structure. The main items in
the capital structure will include;
 US$300m HSBC loan. Alongside with the merger announcement, PCI and MRS have
announced that they agreed with HSBC an 18-month term loan. This is to refinance the
existing MRS Senior Loan and Subordinated Loan Facility of US$385m of which US$301m
is drawn (paying 3.4% blended interest) and which presumably is terminated under a
Change of Control clause. The new loan facility, arranged by HSBC (one of the nine banks
in current facility syndicate) will reduce to US$200m by the time it expires in 1H14.
 US$108m cash resources. The cash balance consists of US$54.5m PCI cash (as
reported in the 1H12 results), US$37.7m MRS cash (as reported during 1H12 results) net
of the US$8.6m special dividend announced by MRS in the merger document (to be paid
in 2H12) and US$25m contingent payment to PCI from Enel as part of the Ain Tsila farm-in
agreement (if confirmed to be paid in 2H12)
 4,388,134,582 basic shares outstanding. Based on the announced 17.6 exchange ratio
(PCI shares for every MRS) the 114,689,178 MRS‟ basic shares outstanding will convert
into 2,018,529,533 PCI shares, equivalent to 46% of the combined basic shares
outstanding. Pre-merger, PCI basic shares outstanding were 2,369,605,049
 304,478,873 options and warrants outstanding. Of these, 67,878,008 are newly issued
PCI‟s options and warrants from the conversion of 3,856,705 MRS‟ options and warrants
(with an average strike price of 262p/sh, or 14.9p/sh once converted into PCI options and
warrants). The remaining 210,337,357 are PCI‟s options and warrants (with an average
strike price of 8.1p/sh). The combined fully diluted shares outstanding is 4,692,613,455 of
which, original fully diluted PCI‟s shares are 2,606,205,914, equivalent to 56% of the
overall shares outstanding
Fig 42
Combined capital structure
PCI shares outstanding
PCI options and warrants outstanding
Additional PCI warrants issued in 2012
FD PCI shares outstanding
2,369,605,049
210,373,357
26,227,508
2,606,205,914
MRS shares outstanding
MRS options and warrants outstanding
FD MRS shares outstanding
114,689,178
3,856,705
118,545,883
PCI : MRS conversion factor
MRS shares outstanding in PCI shares
MRS options and warrants in PCI shares
FD MRS shares outstanding in PCI shares
Post deal shares outstanding
Post deal options and warrants outstanding
Total FD shares outstanding
as per offer doc. (17-Aug-12)
avg. strike 8.15p/sh (AR11)
avg. strike 7.94p/sh (offer doc)
avg. strike 262p/sh (AR11)
17.6
2,018,529,533
67,878,008
2,086,407,541
avg. strike 14.9p/sh
PCI cash and cash equivalents (US$m)
PCI Enel receivable
MRS cash and cash equivalents (US$m)
MRS special dividend (US$m)
Combined cash resources (US$m)
54.5
25.0
37.7
-8.6
108.5
PCI debt (US$m)
MRS senior loan facility (US$m)
MRS debt repayment (US$m)
HSBC loan
Combined debt financing (US$m)
0
301
-301
300
300
Combined net debt (US$m)
191
reported 1H12
US$25m contingent payment
reported 1H12
3.4% intx rate ($40m due in 2012)
18-month facility to refi MRS debt
4,388,134,582
304,478,873
4,692,613,455
avg. strike 9.6p/sh
12 September 2012
24
Macquarie Research
Combined shareholding and board structure
 We illustrate in Fig 43 and 44 below the combined shareholding and board composition.
We highlight in yellow PCI‟s shareholders / Board members and in grey those of Melrose
Resources
 We also highlight how Mr Robert Adair, currently MRS‟ largest shareholder with 50.9% of
the outstanding shares, will also be the largest shareholder of the combined entity with a
23.4% equity interest. However, based on the merger announcement, he will be subject to
a specific “Relationship Agreement” that includes, among other things, a lock-up period,
the mandatory favourable vote for 24 months on specific topics such as capital raises
Fig 43
Combined shareholding
Holders
Robert F. M. Adair
Caledonia Investments Plc
FIL Investments International
AXA Investment Managers UK Ltd.
Aberforth Partners LLP
JPMorgan Asset Management (UK) Ltd.
Schroder Investment Management Ltd.
BlackRock Investment Management (UK) Ltd.
Blakeney LLP
Scottish Widows Investment Partnership Ltd.
Aviva Investors Global Services Ltd.
Standard Life Investments Ltd.
Capital Research Global Investors
Other
Fig 44
# of shares
% of total
1,028,401,950
207,421,315
175,004,346
112,313,931
110,679,747
107,046,386
102,072,708
84,143,793
68,801,456
67,225,863
65,290,722
63,726,450
56,673,724
54,574,595
48,134,222
2,036,623,409
4,388,134,618
23.4%
4.7%
4.0%
2.6%
2.5%
2.4%
2.3%
1.9%
1.6%
1.5%
1.5%
1.5%
1.3%
1.2%
1.1%
46.4%
Combined board of directors
Name (Board role)
Robert F. M. Adair (Non-Executive Chairman)
Brian O'Cathain (CEO)
Tom Hickey (CFO)
David Thomas (COO)
James Agnew (Sr. Independent Director)
Hugh McCucheon (Non-Exec. Dir. / Dep. Chairman)
Robert Arnott (Non-Executive Director
Con Casey (Non-Executive Director)
Alan Parsley (Non-Executive Director)
* MRS shareholders in grey, Petroceltic shareholders in yellow
* MRS Directors in grey, Petroceltic Directors in yellow
12 September 2012
Company
MRS
PCI
PCI
MRS
MRS
PCI
PCI
PCI
MRS
25
Macquarie Research
Key Management and Board members
Brian O’Cathain – Chief Executive (PCI)
 Mr. O‟Cathain (52 years old) is PCI‟s current CEO and will be CEO of the combined entity.
He is a geologist and petroleum engineer with over 25 years‟ experience in senior
technical and commercial roles in upstream oil and gas exploration and production
companies. Before joining Petroceltic, he was Managing Director of Tullow Oil‟s
international business and CEO of Afren (2005-07). Before that, he was a senior manager
of Shell International, where he was principally involved with acquisitions, divestments and
corporate strategy. He has experience in working in West Africa, North Sea, Gulf of
Mexico, South Asia and Offshore Ireland
Tom Hickey – Chief Financial Officer (PCI)
 Mr. Hickey (43 years old) is PCI‟s current Corporate Development Director and will be CFO
of the combined entity. Before joining Petroceltic, he was an Executive Director and CFO
of Tullow Oil, from 2000 to 2008, when Tullow grew through a number of significant
acquisitions including the US$570m acquisition of Energy Africa in 2004 and the US$1.1bn
acquisition of Hardman Resources in 2006. Before that, he was an Associate Director of
ABN AMRO Corporate Finance (Ireland). He is a Fellow of the Institute of Chartered
Accountants in Ireland, and a non-executive Director of PetroNeft
David Thomas – Chief Operating Officer (MRS)
 Mr. Thomas is MRS‟s current CEO and will be COO of the combined entity. He holds a
BSc in Mining Engineering and an MSc in Petroleum Engineering. He was appointed CEO
of Melrose in 2007, before that he was President and COO of Centurion Energy, an
Egyptian, Tunisian and West African E&P which was acquired by Dana Gas in 2007 for
US$1bn. He was also Regional VP for ENI. He started his career in Conoco in 1978,
before moving to Lasmo
Robert F. M. Adair – Non-executive Chairman (MRS)
 Mr. Adair is MRS‟s current executive Chairman and will be non-executive Chairman of the
combined entity. He is a geologist and a Chartered Accountant specialised in oil and gas
taxation. He founded the predecessor company of Melrose. He is also chairman of Skye
Investment (Melrose‟s principal shareholder) and of Terrace Hill Group, Leed Petroleum
and Plexus Holdings (and a number of other companies)
Hugh McCucheon – Non-executive Director / Deputy Chairman (PCI)
 Mr. Mc Cucheon is one of PCI‟s current Non-Executive Directors and will be a Non-
executive Director and Deputy Chairman of the combined entity. He is a Chartered
Accountant and worked for 21 years at Davy including as Head of Corporate Finance.
James Agnew – Senior Independent Director (MRS)
 Mr. Agnew is currently Independent Non-executive Director on MRS‟s board and will be
Senior Independent Director of the combined entity. He is currently Chairman of UK
Corporate Broking at Deutsche Bank, which he joined in 2002 from Merrill Lynch where he
has Head of Corporate Broking. He is a member of the Panel on Takeover and Mergers,
the UKLA Advisory Committee and the LSE Primary Markets Group. He is a Chartered
Accountant
Other Non-executive Directors
 Robert Arnott – Currently Non-Exec Chairman of Petroceltic. A Research Fellow with the
Oxford Institute of Energy Studies and former adviser to DNO.
 Con Casey – Currently a Non-Exec of Petroceltic, Mr Casey is a Chartered Accountant
 James Agnew – Currently an Independent Non-Exec of Melrose Resources, Mr Agnew is
chairman of UK Corporate Broking at Deutsche Bank
 Alan Parsley – Currently an Independent Non-Exec of Melrose Resources, Mr Parsley has
previously worked as Shell‟s Head of Exploration New Business Ventures
12 September 2012
26
Macquarie Research
Updated valuation for Melrose Resources
We have updated our Melrose Resources model for 1H12 results and made changes to our
NAV as we have reviewed the producing assets following the issuance of the CPR in
conjunction with the merger with Petroceltic. Our Core NAV increased by 5% to 127p/sh from
121p/sh, principally impacted by the following changes:
 Changes to our Egypt asset model to reflect CPR reserves split and production profile. We
update our model for the reported EURs for oil and gas and model the production decline
to include the production contribution from the West Zaharya, East Dikirnis and West Abu
Khadra fields expected to come on stream in 2013 (61p/sh positive impact).
 Changes to our Bulgaria asset model to reflect realized gas prices reported in 1H12 and
production profile provided with the CPR. We have also included the Galata field among
our undeveloped assets following the results from flow test results at Galata-1 well
(17mmcf/d) and potential to re-activate production from the field (9p/sh negative impact).
 Updated Net debt and G&A based on 1H12 report (46p/sh negative impact)
Our RENAV declines 20% to 148p from 184p impacted by updated prospect sizes as per the
CPR, Romania farm downs and changes in Bulgaria and Egypt modelling assumptions.
We have also increased our Target Price 12% to 136p/sh from 121p/sh to align it with
Petroceltic merger deal terms of 17.6 PCI shares per MRS shares and the announced
4.7p/sh special dividend. Based on Petroceltic‟s 10th September 2012 closing share price of
7.5p/sh the derived Melrose share price would be 136p/sh (PCI‟s closing share price
multiplied by 17.6 plus 4.7p).
Fig 45
Melrose Resource’s Core and Total NAV. TP derived from PCI’s offer
Melrose Resources
Risked
resources
(mmboe)
Unit Value
(US$/boe)
80.4
6.4
Previous published
EMV
(US$m)
Value
(p/sh)
Change
Value
(p/sh)
Comments
Assets (NPV10)
Producing Assets
Net Cash/(Net Debt)
Undeveloped Assets
1.7
25.2
Other assets less G&A
Core NAV
511.7
270p
39p
17%
231p
Updated Egypt and Bulgaria models
-271.8
-143p
-47p
-49%
-96p
Upd. to 1H12 reported (net of special div)
42.8
23p
14p
151%
9p
-42.7
-23p
1p
4%
-24p
240.0
127p
6p
5%
121p
82.1
2.9
11.6
6p
0p
-1%
6p
Risked E&A upside
15.5
1.8
28.6
15p
-42p
-74%
57p
RENAV
97.5
2.9
280.2
148p
-36p
-20%
184p
Option Proceeds
Risked E&A upside included in TP
5p
4p
2128%
0p
Unrisked value of above
60p
58p
2378%
2p
136p
15p
12%
121p
Target price
Updated Egypt and Bulgaria models
Upd. to 1H12 reported
Updated to reflect CPR
Inlcuded Kamchia prospect
12 September 2012
27
Macquarie Research
Fig 46
Melrose Resources’ Asset Breakdown EMV
Country
Project/Prospect
Producing Assets
Egypt
El Mansoura (2P)
Egypt
Qantara
Egypt
Other El Mansoura (2P)
Egypt
SE El Mansoura (2P)
Bulgaria
Kavarna (Galata block)
Bulgaria
Kaliakra (Galata block)
Undeveloped Assets
Bulgaria
Galata field (Galata block)
Bulgaria
Kavarna East (Galata block)
Risked Upside
Bulgaria
Egypt
Egypt
Egypt
Bulgaria
Bulgaria
Romania
Romania
France
Kamchia (Galata block)
Mesaha Block
El Mansoura, Qawasim play (4 prospects)
SE El Mansoura (4 prospects)
Chaika (NW, NE and S)
Prospects A, E, F and H (Galata block)
Muridava
Est Cobalcescu
Rhone Maritime
Total Asset Value
Gross Res.
Potential
(mmboe)
Working
Interest
(%)
56
1
8
8
3
4
80
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
1
1
2
100.0%
100.0%
100.0%
100.0%
5
100
13
34
8
8
21
21
0
208
100.0%
40.0%
100.0%
100.0%
100.0%
100.0%
40.0%
40.0%
27.5%
100.0%
40.0%
100.0%
100.0%
100.0%
100.0%
40.0%
40.0%
27.5%
291
Costs
Paid
(%)
Discounted
Value
(US$/boe)2
Net Risked
(mmboe)
EMV
(US$m)3
Risked
Value
(p/sh)
Unrisked
Value (p/sh)4
$4.4
$6.6
$4.4
$4.4
$28.7
$24.3
56.5
0.9
8.4
7.6
3.2
3.8
80.4
250
6
37
33
93
93
512
131.6
3.2
19.5
17.6
49.0
48.9
269.8
131.6
3.2
19.5
17.6
49.0
48.9
269.8
75%
75%
$23.8
$26.1
0.7
1.0
1.7
16
27
43
8.5
14.1
22.6
11.3
18.8
30.1
20%
10%
30%
10%
10%
10%
10%
10%
5%
$13.2
$1.4
$2.9
$2.9
$13.2
$13.2
$13.1
$13.1
$0.0
0.9
4.2
3.8
3.4
0.8
0.8
0.8
0.8
0.0
15.5
5
3
6
3
3
4
2
2
0
29
2.9
1.7
3.3
1.8
1.5
1.8
1.0
1.0
0.0
15.1
31.3
29.2
19.5
51.6
52.7
56.4
57.7
57.7
0.0
356.1
97.5
583
307.4
656.0
C.O.S.
(%)1
Notes:
Melrose outstanding shares (fd)
1. C.O.S. - Chances of Success - Includes all risk factors such as geological, political, project delivery, commercial, etc.
GBP/USD
2. Value/boe - Includes proximity to established infrastructure, development capex required, oil quality, discount rate (10%), etc.
3. EMV - Expected Monetary Value - a risk weighted value. EMV = (Reward*C.O.S.) - [Capital at Risk*(1-C.O.S.)]
4. Unrisked Value - Refers to the value that could potentially be realized if success was achieved on prospect and commercial production
** Assumes
realized.
farm-down of assets with 3-2 promote.
* Assumes farm-down
(Q) = Qawasim
(O) = Oligocene
118.5
1.60
12 September 2012
28
Macquarie Research
MELROSE RESOURCES (MRS LN, Neutral, Target price: 136p)
Price Assumption
Oil-Brent
Gas-UK
Gas-UK
US$/£ (period average)
Income Statement
Oil & Liquids
Natural Gas
Total Production
Gas Production Ratio
Production per Share Growth YoY
Gross Revenue (pre-royalty)
Royalties
Net Revenue
Operating Costs
G&A Costs
Other operating expenses
EBITDA
DD&A
EBIT
Interest Costs
Taxes
Other Non-Cash Costs
Net Income
EPS (basic)
EPS (diluted)
$/b
p/therm
US$/mmbtu
2011A
111.34
58.06
9.28
2012E
107.51
54.01
8.53
2013E
106.25
53.13
8.50
2014E
115.54
57.77
9.24
2015E
117.52
58.76
9.40
$
1.60
1.58
1.60
1.60
1.60
kb/d
mmcf/d
kboe/d (@ 6:1)
%
2011A
4.8
177.1
35.4
86.4
2012E
3.7
141.3
28.1
86.8
2013E
3.8
130.4
26.3
85.4
2014E
3.8
134.9
27.0
86.0
2015E
3.4
106.4
21.8
84.3
%
4.4
-15.0
-15.3
5.3
-21.8
m
m
m
m
m
m
m
m
m
m
m
m
m
US$/sh
US$/sh
US$/sh
297.2
-8.6
288.6
-24.4
-22.0
0.0
242.2
-107.8
134.5
-22.8
-32.7
-16.1
62.8
0.5
0.5
0.5
256.6
-9.4
247.3
-26.1
-21.3
-2.7
197.1
-88.7
108.4
-14.9
-34.7
2.2
61.0
0.5
0.5
0.5
213.1
-6.4
206.7
-22.0
-23.0
-14.9
146.7
-76.1
70.6
-11.0
-21.4
-1.6
36.5
0.3
0.3
0.3
230.6
-7.4
223.2
-24.5
-25.4
-10.4
163.0
-79.6
83.4
-8.2
-28.1
-1.6
45.4
0.4
0.4
0.4
183.9
-5.2
178.7
-20.2
-27.9
-10.3
120.3
-61.4
58.9
-6.0
-19.5
-1.6
31.8
0.3
0.3
0.3
Half-yearly Forecast
Oil-Brent
Gas-UK
Oil & Liquids
Natural Gas
Total Production
$/b
US$/mmbtu
H1/12E
113.52
8.95
H2/12E
101.50
8.12
H1/13E
104.00
8.32
H2/13E
108.50
8.68
H1/14E
111.00
8.88
kb/d
mmcf/d
kboe/d (@ 6:1)
3.6
142.9
28.2
3.8
139.7
27.9
3.9
130.2
26.3
3.8
130.7
26.3
3.8
134.9
27.0
m
m
m
US$/sh
m
133.4
104.7
32.7
0.3
89.7
123.3
95.2
28.3
0.2
81.3
105.4
79.8
17.4
0.2
70.8
107.6
81.8
19.1
0.2
72.5
113.1
84.6
21.1
0.2
72.3
2011A
7.6
21.9
4.8
0.2
0.0
34.6
89%
2012E
6.6
17.8
3.7
0.0
0.0
28.1
90%
2013E
4.4
18.0
3.8
0.0
0.0
26.3
88%
2014E
5.2
18.1
3.8
0.0
0.0
27.0
89%
2015E
3.6
14.7
3.4
0.0
0.0
21.8
87%
Revenue
EBITDA
Net Income
Production profile
Bulgaria
Egypt gas
Egypt oil
USA
Romania
Total
% gas
kboe/d
45
40
35.5
37.4
100%
40.5
90%
34.6
35
80%
28.1
30
26.3
70%
27.0
25
60%
21.8
20
30%
10
Revenue per Share Growth YoY
EBITDA per Share Growth YoY
%
%
20.0
28.6
-14.3
-18.6
-16.4
-25.6
8.0
11.1
-19.9
-26.2
20%
5
10%
0
0%
2008A
Basic WA Shares OS
Fully Diluted Shares Outstanding
m
m
114.7
117.1
114.7
117.1
114.7
117.1
114.7
117.1
114.7
117.1
Balance Sheet
Cash (including Restricted)
Debt
Net Debt (Cash)
m
m
m
2011A
53.4
351.5
183.3
2012E
56.1
300.8
115.8
2013E
107.5
300.8
64.4
2014E
166.9
300.8
5.0
2015E
194.5
300.8
-22.6
Total Assets
Total Liabilities
Total S/H Equity
m
m
m
823.9
461.4
362.5
805.6
396.5
409.1
850.1
411.5
438.6
907.4
421.9
485.5
951.2
432.3
518.9
Ratios Analysis
ROA
ROCE
ROE
Net Debt/Equity
Net Debt/CF
Price/Book
Book Value
Valuation
P/E
P/CF
Dividend Yield
Enterprise Value
EV/DACF
EV/Reserves4
EV/2P + 2C4
EV/Production4
Reserve/Production (2P)
Core Net Asset Value (PV10AT)
P/CoreNAV
Core NAV + Risked Resource Upside
P/RENAV
5
5
50%
40%
15
2009A
USA
2010A
2011A
Romania
Bulgaria
2012E
2013E
Egypt gas
2014E
Egypt oil
% gas
Cashflow Analysis
Cash Flow from Operations
Chgs in Working Cap
Cash Flow from Investing
Cash Flow from Financing
Increase in Cash
m
m
m
m
m
m
2011A
197.5
-3.8
193.6
-68.1
-144.8
-19.3
2012E
171.0
0.0
171.0
-69.1
-99.2
2.7
Free Cash Flow1
m
128.1
101.5
66.2
67.7
33.7
m
220.3
185.9
154.2
155.9
119.7
2012E
7.5
15.5
15.8
28.3
0.7
0.6
3.6
2013E
4.4
9.5
8.6
14.7
0.4
0.5
3.8
2014E
5.2
10.7
9.8
1.0
0.0
0.5
4.2
2015E
3.4
7.1
6.3
-4.4
-0.2
0.5
4.5
Debt Adjusted Cash Flow (DACF)
%
%
%
%
x
x
$/sh
2011A
7.2
15.6
18.5
50.6
0.9
0.7
3.2
x
x
%
m
x
$/boe
$/boe
$k/boe/d
years
2011A
7.2
2.3
0.0
642
2.9
18.04
18.04
18.16
2.8
2012E
3.9
1.4
0.0
360
1.9
10.11
10.11
12.82
3.5
2013E
6.5
1.7
0.0
308
2.0
2014E
5.3
1.6
0.0
249
1.6
2015E
7.5
2.1
0.0
221
1.8
11.71
9.21
10.17
p/sh
x
p/sh
x
127
1.0
148
0.9
Per Boe Statistics
Revenue/boe
Royalties/boe
Operating costs/boe
Operating Netback/boe
G&A/boe
Interest/boe
Capital Tax/boe
Cash Netback/boe
Depletion and Depreciation/boe
Stock based compensation/boe
Other Non-cash/boe
Cash Taxes/boe
Deferred Taxes/boe
Earnings Netback/boe
CFPS
2013E
143.2
0.0
143.2
-72.2
-19.6
51.4
2015E
2014E
147.7
0.0
147.7
-80.0
-8.2
59.4
2015E
113.7
0.0
113.7
-80.0
-6.0
27.6
US$/sh
1.7
1.5
1.2
1.3
1.0
Capital Expenditures
m
65.6
69.5
77.0
80.0
80.0
Capex/Cash Flow
x
0.3
0.4
0.5
0.5
0.7
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
$/boe
2011A
43.64
-1.26
-3.58
38.81
-3.23
-3.35
0.00
32.22
-15.83
0.00
0.18
-4.80
0.00
11.78
2012E
45.62
-1.66
-4.63
39.32
-3.79
-2.66
0.00
32.87
-15.77
-0.14
0.20
-6.17
0.00
10.99
2013E
44.82
-1.33
-4.64
38.85
-4.85
-2.32
0.00
31.69
-16.01
-0.34
-3.16
-4.51
0.00
7.68
2014E
46.06
-1.47
-4.90
39.70
-5.06
-1.65
0.00
32.99
-15.91
-0.32
-2.08
-5.62
0.00
9.07
2015E
46.95
-1.31
-5.15
40.49
-7.12
-1.54
0.00
31.83
-15.68
-0.41
-2.65
-4.97
0.00
8.11
All figures US$ unless noted and production and reserve figures are gross of royalties
1) Cash flow from Operations (before chg in WC) Less Capex
2) Excludes non-producing assets
3) Risked resource upside based on LT price of US$11.04/mmbtu HH, US$115/b Brent, and GBP/USD 1.6
12 September 2012
29
Macquarie Research
Other companies mentioned:
 Afren (AFR LN, £1.38, Outperform, TP: £1.50, Mark Wilson)
 Beach Energy (BPT AU, A$1.30, Outperform, TP: A$1.60, Kirit Hira)
 BP (BP/ LN, £4.38, Outperform, TP: £5.70, Jason Gammel)
 BHP Billiton (BHP AU, A$32.46, Outperform, TP: A$40.00, Adrian Wood)
 Centurion Energy (Not Listed)
 Circle Oil (COP LN, Not covered)
 Codotte (Not Listed)
 ConocoPhillips (COP US, US$56.18, Neutral, TP: US$55.00, Jason Gammel)
 DNO International (DNO NO, kr8.69, Outperform, TP: kr11.60, David Farrell)
 Egyptian General Petroleum Company (Not Listed)
 Encore (Not Listed)
 ENEL (ENEL IM, Not covered)
 Energy Africa (Not Listed)
 Eni (ENI IM, €17.86, Neutral, TP: €19.00, Jason Gammel)
 Exxon Mobil Corp (XOM US, US$89.48, Outperform, TP: US$97.00, Jason Gammel)
 Gulf Keystone (GKP LN, Not covered)
 Hardman Resources (Not Listed)
 Hess (HES US, Not covered)
 Lasmo (Not Listed)
 Leed Resources (LDP LN, Not covered)
 Melrose Resources (MRS LN, £1.30, Neutral, TP: £1.36)
 Nautical Petroleum (Not Listed)
 Orca Exploration (Not Listed)
 Petroneft Resources (PTR LN, £0.08, Outperform, TP: £0.11, Mark Wilson)
 Plexus Holdings (POS LN, Not covered)
 Repsol (REP SM, €15.58, Underperform, TP: €13.50, Marc Kofler)
 Royal Dutch Shell (RDSA LN, £22.32, Outperform, TP: £25.50, Jason Gammel)
 Skye Investment (Not Listed)
 Sonatrach (Not Listed)
 Statoil (STL NO, kr149.50, Neutral, TP: kr160.00, Jason Gammel)
 Terrace Hill Group (THL LN, Not covered)
 TOTAL (FP FP, €40.45, Neutral, TP: €42.00, Jason Gammel)
 TransGlobe Energy (TGL CN, C$11.49, Outperform, TP: C$16.50, David Popowich)
 Tullow Oil (TLW LN, £13.86, Underperform, TP: £10.75, Mark Wilson)
 Vega Oil (Not Listed)
12 September 2012
30
Macquarie Research
Important disclosures:
Recommendation definitions
Volatility index definition*
Financial definitions
Macquarie - Australia/New Zealand
Outperform – return >3% in excess of benchmark return
Neutral – return within 3% of benchmark return
Underperform – return >3% below benchmark return
This is calculated from the volatility of historical
price movements.
All "Adjusted" data items have had the following
adjustments made:
Added back: goodwill amortisation, provision for
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Excluded: non recurring items, asset revals, property
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Benchmark return is determined by long term nominal
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yield
Macquarie – Asia/Europe
Outperform – expected return >+10%
Neutral – expected return from -10% to +10%
Underperform – expected return <-10%
Macquarie First South - South Africa
Outperform – expected return >+10%
Neutral – expected return from -10% to +10%
Underperform – expected return <-10%
Macquarie - Canada
Outperform – return >5% in excess of benchmark return
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Macquarie - USA
Outperform (Buy) – return >5% in excess of Russell
3000 index return
Neutral (Hold) – return within 5% of Russell 3000 index
return
Underperform (Sell)– return >5% below Russell 3000
index return
Very high–highest risk – Stock should be
expected to move up or down 60–100% in a year
– investors should be aware this stock is highly
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High – stock should be expected to move up or
down at least 40–60% in a year – investors should
be aware this stock could be speculative.
Low–medium – stock should be expected to
move up or down at least 25–30% in a year.
EPS = adjusted net profit / efpowa*
ROA = adjusted ebit / average total assets
ROA Banks/Insurance = adjusted net profit /average
total assets
ROE = adjusted net profit / average shareholders funds
Gross cashflow = adjusted net profit + depreciation
*equivalent fully paid ordinary weighted average
number of shares
Low – stock should be expected to move up or
down at least 15–25% in a year.
* Applicable to Australian/NZ/Canada stocks only
All Reported numbers for Australian/NZ listed stocks
are modelled under IFRS (International Financial
Reporting Standards).
Medium – stock should be expected to move up
or down at least 30–40% in a year.
Recommendations – 12 months
Note: Quant recommendations may differ from
Fundamental Analyst recommendations
Recommendation proportions – For quarter ending 30 June 2012
Outperform
Neutral
Underperform
AU/NZ
55.67%
30.50%
13.83%
Asia
61.00%
22.11%
16.89%
RSA
53.43%
36.99%
9.59%
USA
42.58%
52.41%
5.01%
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69.23%
28.02%
2.75%
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46.60% (for US coverage by MCUSA, 9.05% of stocks followed are investment banking clients)
33.69% (for US coverage by MCUSA, 8.14% of stocks followed are investment banking clients)
19.71% (for US coverage by MCUSA, 0.45% of stocks covered are investment banking clients)
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Petroceltic International

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