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04 December 2013

Europe/United Kingdom

Equity Research

Oil & Gas Exploration & Production (Integrated Oil & Gas/E&P/European

Refiners (Europe))

Genel Energy plc (GENL.L) INCREASE TARGET PRICE

2014 - a defining year

Increase TP to 1430p (from 1296p) / Reiterate O/P: We now view the Iraqi Kurdish oil play as lower risk. Progress has been very impressive since 2011 and we treat recent events – the signing of the energy agreement with Turkey last week – as 'irreversible progress'. Consistent with this, we partly de-risk the value upside and raise our TP to 1430p/share and re-iterate our O/P. We believe Genel could be the bright-spot again in the UK E&P space in 2014.

Progress report: Having finalised the energy agreements, the next step is to meet with the Government of Iraq (GOI) to reach a revenue-sharing agreement. Exports, however, can flow before and contractors amongst others will have the first call on revenue (ie, under this format, they should get paid as exports begin). The KRG, meanwhile, agreed not to draw on its share of revenue from these exports after contractor entitlements, tariffs and payments to the UN Compensation fund widely reported to be held in an escrow account in Turkey, under the control of the KRG, until it reaches an agreement with the GOI. As revenue is accumulated, there will be an incentive to reach an agreement.

KRI oil to the benefit of Iraq as a whole: A series of obstacles, both above and below ground, make it seem unlikely that Iraqi production will ever achieve its full potential. Low-cost KRI oil would help, and as production capacity increases (as we see happening), it should find its way to the market, and with the energy agreements now formalised, this looks imminent, in our view.

2014 – a year of consolidation? Smooth operation (and with that reduced uncertainty) in the KRI may open up the scene for greater consolidation. Differentiation is key. Big Oil can still drive harder bargains with those that are (a) capital constrained and (b) technically not capable to drive developments. The best positioned company or one that has the most sustainable business model with exposure to the KRI is Genel, in our view. Genel is also attractive as it has (a) portfolio quality, (b) portfolio depth with high equity stakes, (c) capital light assets / assets with features of long-duration, (d) intangibles (relationships / technical know-how), and (e) an attractive exploration portfolio outside of the KRI, especially Morocco, where we see growing industry interest.

Valuation: Our TP of 1430p is set at around our risked NAV of 1432p.

Share price performance

592

792

992

Dec-11 Apr-12 Aug-12 Dec-12 Apr-13 Aug-13

Price Price relative

The price relative chart measures performance against the

FTSE 100 IDX which closed at 6532.43 on 03/12/13

On 03/12/13 the spot exchange rate was £.83/Eu 1. -

Eu .74/US$1

Performance Over 1M 3M 12M Absolute (%) 11.5 13.7 31.3 Relative (%) 14.5 12.8 20.0

Financial and valuation metrics

Year 12/12A 12/13E 12/14E 12/15E Revenue (US$ m) 333 351 680 890 EBIDAX (US$ m) 259.5 283.3 540.6 682.0 Pre-tax Profit Adjusted (US$ m) 75.9 180.6 280.2 403.2 CS adj. EPS (US$) 0.27 0.65 1.00 1.44 Prev. EPS (US$) — — 0.87 1.34 ROGIC (%) 2.4 5.5 7.9 10.8 P/E (adj., x) 63.80 26.81 17.28 12.01 P/E rel. (%) 483.2 193.8 138.0 104.6 EV/EBIDAX (x) 14.8 14.4 7.3 5.6

Dividend (12/13E, c) — Dividend yield (%) — Net debt (12/13E, US$ m) -772.9 GIC (12/13E, US$) 3,327.7 BV/share (12/13E, US$) 14.6 Current WACC 12.0 EV/GIC (x) 1.3 Number of shares (m) 280.25 Free float (%) 100.0

Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates.

Rating OUTPERFORM* Price (03 Dec 13, p) 1,057.00 Target price (p) (from 1,296.00) 1,430.00¹ Market cap. (£ m) 2,962.22 Enterprise value (US$ m) 4,075.11

*Stock ratings are relative to the coverage universe in each

analyst's or each team's respective sector.

¹Target price is for 12 months.

Research Analysts

Thomas Adolff

44 20 7888 9114

[email protected]

Charlotte Elliott

44 20 7888 9484

[email protected]

Specialist Sales: Jason Turner

44 20 7888 1395

[email protected]

04 December 2013

Genel Energy plc (GENL.L) 2

Genel Energy plc GENL.L Price (03 Dec 13): 1,057.00p, Rating: OUTPERFORM, Target Price: (from 1,296.00) 1,430.00p

Income statement (US$ m) 12/12A 12/13E 12/14E 12/15E

EBITDAX 260 283 541 682 Depr & amort (excl. goodwill) (170) (105) (180) (202) EBITDA 230 278 451 595 Exploration expense 30 5 90 88 Goodwill impairment — — — — Other adjustments to EBIT — — — — EBIT 60 173 271 392 E&P 60 173 271 392 R&M — — — — Chemicals — — — — Gas & Power — — — — Others — — — — Net interest income (exp) 16 7 10 11 Net non operating inc (exp) — — — — Share of associates/JVs' equity — — — — Exceptionals — — — — Profit before tax 76 181 280 403 Taxes — — — — Profit after tax 76 181 280 403 Extraordinary gain/(loss) — — — — Non-controlling interest (minority) — — — — Preferred dividends — — — — Other analyst adjustments — — — — Adjusted net income 76 181 280 403 Reported net income 76 181 280 403

Cash flow (US$ m) 12/12A 12/13E 12/14E 12/15E

EBIT (CS) 60 173 271 392 Non Cash Items 170 105 180 202 Change in working capital 31 42 — — Other operating cash flow 46 18 100 99 Cash flow from operations 307 339 550 693 CAPEX (234) (522) (440) (561) Disposals of PPE — — — — Free cash flow to the firm 73 (183) 110 132 Acquisitions — — — — Divestments — — — — Exploration investment — — — — Other investment/(outflows) (985) (45) — — Cash flow from investment (1,219) (567) (440) (561) Net share issue/(repurchase) (1) (2) — — Dividends paid — — — — Change in debt — — — — Other financing cash in/(outflows) — — — — Cash flow from financing activities (1) (2) — — Effect of exchange rates — — — — Movements in cash/equivalents (913) (231) 110 132 Net change in cash (913) (231) 110 132

Balance sheet (US$ m) 12/12A 12/13E 12/14E 12/15E

Assets Goodwill & similar 1,173 1,448 1,448 1,448 PPE&E & intangibles 1,933 2,139 2,400 2,758 Associates & JV — — — — Inventory 0.10 0.10 0.10 0.10 Receivable 49 14 14 14 Other current assets 1,001 773 883 1,015 Other non-current assets — — — — Total assets 4,156 4,375 4,745 5,236 Liabilities & equity Payables 5 — — — Net cash/(debt) (1,001) (773) (883) (1,015) Other current liabilities 75 73 73 73 Total current liabilities 80 73 73 73 Provisions (incl Pensions) — — — — Other non-current liabilities 1,157 974 1,174 1,394 Total liabilities 236 274 364 452 Ordinary equity 3,920 4,101 4,381 4,784 Minority interest — — — — Total equity 3,920 4,101 4,381 4,784

Key earnings drivers 12/12A 12/13E 12/14E 12/15E

Brent (USD/bbl) 111.9 107.7 110.0 100.0 Realised crude prices (USD/bbl)

74.5 72.8 87.7 87.5 WI production (kboepd) 44.5 47.4 98.5 138.6 Entitlement production kboepd

12.3 13.2 21.2 27.9 — — — —

Per share data 12/12A 12/13E 12/14E 12/15E

No. of shares (EOP) 279.94 279.94 279.94 279.94 CS adj. EPS (US$) 0.27 0.65 1.00 1.44 Prev. EPS (US$) — — 0.87 1.34 DPS (12/13E, US$) — — — — Book value per share (US$)

14.0 14.6 15.6 17.1 Operating cash flow per share (US$)

1.10 1.21 1.97 2.48

Key ratios and valuation

12/12A 12/13E 12/14E 12/15E

Margins (%) EBITDAX margin 77.8 80.6 79.5 76.7 EBIT margin 18.1 49.3 39.8 44.1 Net margin 22.8 51.4 41.2 45.3 Valuation metrics (%) Div yield — — — — FCF yield (%) 1.5 (3.8) 2.3 2.7 EV/EBIDAX (x) 14.8 14.4 7.3 5.6 P/E 63.8 26.8 17.3 12.0 P/B 1.2 1.2 1.1 1.0 ROE analysis (%) ROE 1.9 4.5 6.6 8.8 ROGIC 2.4 5.5 7.9 10.8 Asset turnover 8.0 8.0 14.3 17.0 Interest burden 1.3 1.0 1.0 1.0 Tax burden — — — — Financial leverage — — — — Credit ratios Net debt/equity (25.5) (18.8) (20.2) (21.2) Interest coverage ratio (3.9) (23.5) (28.5) (35.1) Dividend payout ratio — — — —

Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities

(EUROPE) LTD. Estimates.

592

792

992

Dec-11 Apr-12 Aug-12 Dec-12 Apr-13 Aug-13

Price Price relative

The price relative chart measures performance against the FTSE 100 IDX which

closed at 6774.73 on 29/10/13

On 29/10/13 the spot exchange rate was £.86/Eu 1. - Eu .73/US$1

04 December 2013


Key charts Figure 1: Iraqi production performance (kbd) Figure 2: Iraq: under-delivery in export growth (kbd)

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Oil production Exports

-50

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YTD

y/y export…

Source: Iraq Oil Ministry, Credit Suisse Research Source: Iraq Oil Ministry, Credit Suisse Research

Figure 3: Iraqi Kurdish oil capacity potential – the region

can help the entire country

Figure 4: Generic light oil field IRR at CBP of 30% - the

returns are attractive

0

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2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

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$20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120

IRR

Source: Company data, Credit Suisse estimates Source: Credit Suisse estimates

Figure 5: Progress since 2012– we have come far

May '12 -Turkey/KRG

announce bilateral energy plans

June '12 -disappointing 4th

Iraqi licensing round

July '12 - Trucks start rolling to

Turkey (condensates)

July '12 -Chevron and

Total enter Iraqi Kurdistan

Aug '12 - KRG agrees to restart

exports as a 'goodwill initiative'

Dec '12 - Contractors receive first trance. But

renewed dispute: exports cut

January '13 -Trucks start rolling to Turkey (crude

oil)

Aug '12 - Gazpromneft enters Iraqi Kurdistan

October '13 -independent KRI pipeline tied-in to

the ITP line

2014: - Payment mechanism- Oil exports from new pipeline- GSA (Genel with the KRG)- Consolidation

NEXT CATALYSTS

Sept '12 -agreement in

principle reached between KRG/GOI

November '13 - KRG and Turkey sign

energy agreements

Source: Credit Suisse research

04 December 2013


Executive summary Bottom line – we view the Iraqi Kurdish oil play today as lower risk. Progress has been

very impressive since 2011, particularly in the context of the political complexity in the

region; this includes (a) a growing presence of Big Oil, (b) a bilateral energy agreement

with Turkey, including for upstream blocks and a gas sales agreement (GSA) and (c)

KRG's independent pipeline. All of these will help pave the way for this 'Iraqi oil and gas' to

find its way to the market to the benefit of the country as a whole, and its neighbour

Turkey, especially on gas matters. We treat recent events as 'irreversible progress' and

consistent with this, we partly de-risk the value upside and raise our TP to 1430p/share.

Progress report – Turkey and the KRG have finalised energy agreements last week. The

next step is to meet with the GOI with an update hopefully forthcoming in the near-term.

This, however, does not mean that exports can't begin before and contractors paid as they

(and pipeline tariffs and the UN compensation fund) are widely reported to have the first

call on revenue. Meanwhile, the KRG agreed not to draw on its share of revenue after

contractor entitlements etc widely reported (eg Iraq Oil Report) to be held in an escrow

account in Turkey from exports from the KRI until it reaches an agreement with the GOI.

Payment mechanism – Turkey is preparing to set up an escrow account at a state-owned

Turkish bank, which would fall under the control of the KRG, with contractors having one

of the first calls on revenue. Exports would flow through its own pipeline and metering

point, where SOMO is invited to monitor flows. This is a better version to before, where

SOMO controlled the exports and Iraq's Ministry of Finance controlled the payment flows,

which had been a stumbling block for the KRG and its oil companies. As exports begin

and revenue is accumulated, there is a growing incentive between the parties to reach an

agreement. We are also encouraged by what we read in the press from US policy-makers.

KRI oil to the benefit of Iraq as a whole – Incremental Iraqi oil supply will play an

important role in determining how tight the future global supply/demand balance will be.

Unfortunately, a series of obstacles, both above and below ground, make it unlikely that

Iraqi production will ever achieve its full potential, in our view. Low-cost KRI oil would help,

and as production capacity increases (as we see happening), it should find its way to the

market, and with the energy agreements now formalised, this looks imminent.

Turkey and KRI gas – Turkey relies on gas imports from Russia, Iran, contracted LNG

from Nigeria and Algeria, and Azerbaijan. KRI gas would allow Turkey to diversify its gas

supply, whilst also being able to reduce the gas input cost. Importantly, the agreement for

10bcma (and possibly growing to 20bcma by the middle of the next decade) will make the

KRG one of Turkey's most important long-term strategic partners. This agreement may

also help Turkey to drive harder negotiations over price with its other suppliers.

2014 – a year of consolidation? Smooth operation (and with that reduced uncertainty) in

the KRI may open up the scene for greater consolidation, in our view, and for anyone

looking to gain a greater foothold in the KRI, as much as Big Oils currently have a bias

towards organic growth, a strategic asset like KRI oil and gas should find a place in the

portfolio and with that its fair share of competition, in our view.

Differentiation is key. Big Oil can still drive harder bargains with those that are (a) capital

constrained and (b) technically not capable to drive developments. We see plenty of

companies with exposure to the KRI in this camp, where the Majors can exercise this

leverage. The best positioned or one that has the most sustainable business model (cash

flow & balance sheet strength), in our view, with exposure to the KRI is Genel.

What makes Genel so attractive? In our view, this can also be explained by (a) portfolio

quality with little on the fringe (ie not a 'one trick pony'), (b) portfolio depth with high equity

stakes across its asset base, (c) capital light assets / assets with features of long-duration,

(d) intangibles (relationships / technical know-how) and (e) an attractive exploration

portfolio outside of the KRI, especially Morocco, where we see growing industry interest.

04 December 2013


2014 – a defining year A defining year – One way or another, 2014 is a defining year, in our view. Turkey and

the KRG have finalised energy agreements, including a GSA. Turkey is committed to it as

is also evident by the signatures for 13 upstream blocks in the KRI, around half of which in

partnership with Exxon. The next step is to meet with the GOI to hammer out a revenue

sharing agreement. Exports, however, can flow before an agreement there is reached with

the revenue share to the KRG and GOI accumulated in the escrow account in Turkey in

the interim. In other words, contractors (plus pipeline tariffs and the UN Compensation

fund) will be paid as they are widely reported to have the first call on revenue from the

export that can begin soon from the KRI, while the KRG agreed not to draw on its share of

revenue after contractor entitlements etc until an agreement is reached with the GOI.

The KRG can work towards its 17% entitlement, not the 10.5% it has been paid in the past

after deductions, for exports revenues from the country. Importantly, it will have greater

control/leverage over the revenue as the KRI work towards 500kbd in exports over the

next 18 months using its own pipeline and metering point to the benefit of the entire

country. We would generally ignore rhetoric against this agreement from Iraqi policy-

makers, should there be any, in the run-up to the Iraqi elections in April 2014. Just as in

2010, if not more so now, the KRG may be politically better positioned given

factions/oppositions within the Shia parties – the support from the KRG may go some way

in securing political aspirations of those looking to retain or gain new political seats. The

reality is that even the US appears to be sending positive signals this time around with the

US ambassador to Turkey stating 'we want to see the Iraqi government be happy about

the deal with the Kurdish Regional Government and with Turkey', according to Hurriyet.

Bottom line – we view the Iraqi Kurdish oil play today as lower risk. Progress has been

very impressive since 2011, particularly in the context of the political complexity of the

region; this includes (a) the growing presence of Big Oil, (b) a bilateral energy agreement

with Turkey including for upstream blocks and (c) KRG's independent pipeline. All of these

will help pave the way for this 'Iraqi oil and gas' to find its way to the market to the benefit

of the country as a whole, and its neighbour Turkey, especially on gas matters.

Investors still seem, however, somewhat reluctant to believe at face value that a smooth

operation is possible (and no doubt there may be initial bumps on the road), and appear to

be adopting a wait and see approach. We treat recent events as 'irreversible progress' and

consistent with that, we partly de-risk the value and raise our TP to 1430p/share. Smooth

operation in the KRI may open up for greater consolidation, in our view, and for anyone

looking to gain a greater foothold in the KRI, as much as Big Oils currently have a bias

towards organic growth, a strategic asset like the KRI oil and gas should find its place in

the portfolio and its fair share of competition, in our view, but differentiation is key.

We have come a long way – a recap of history

Figure 6: Timeline of events: 2005-2011

Oct '05 - Iraqi constitution

adopted

Feb '07 - Draft Federal

Petroleum Law

Jun '07 -Agreement on

revenue sharing

Aug 2007 - KRG Petroleum Law

approved

Mar 2010 - 1st Democratic

election

May/Jun 2011 -Release of 1st

export payment to contractors

August 2011 -New PSCs signed

by the KRG

Dec 2010 -President, PM and Cabinet appointed

Sept 2011 -Release of 2nd

export payment to contractors

Oct/Nov 2011 -Exxon signs 6 PSC contracts with the KRG

Oct/Nov 2011 - Iraqi PM and KRG PM

agree to resume talks on Oil/Gas law

Feb 2011 -Kurdistan exports

resumes

Sept 2011 -Genel/Vallares

merger announced

Dec 2011 -Iraqi cabinet approves

2012 (including 175kbd KRG exports)


04 December 2013


2007 – The Iraqi cabinet approved a draft oil and gas (for centralism) legislation in 2007,

but the parliament supported another (federalism) and thus failed to pass a new oil and

gas law. With this, the KRG passed its own legislation (Kurdish Oil Law in August 2007)

and proceeded to award licences to oil companies within its boundaries. The implication of

this impasse was significant—the KRG was largely unable to export production as the GOI

prevented it from using federal infrastructure for export. The KRI is landlocked and export

infrastructure is controlled by the federal government. This meant once Iraqi Kurdish oil is

supplied into the export pipeline, it comes under the control of the federal government via

SOMO (responsible for export sales).

2010 elections – The two Kurdish parties expressed their willingness to work with

whoever was ready to address a list of 19 demands, which includes the implementation of

the 2006 constitution (including the incorporation of Kirkuk) and hydrocarbon laws. The

twin issues – Kirkuk and Oil – are key to the unresolved conflict between Baghdad and the

semi-autonomous KRI.

After nine months of political stalemate following very close March 2010 parliamentary

elections, it became clear that no government could be formed without the two principal

Kurdish parties (KDP and PUK) and at the end of 2010, a new government was formed.

The creation of a unified government at the end of 2010 has gone some way to resolving

the longstanding stalemate in Iraqi politics and this created a situation, which pushed the

KRG and GOI closer:

■ (a) As a pre-condition to supporting Maliki (Shiite) as Prime Minister in the new

government, the KRG extracted assurances that disagreements over oil and gas

matters would be resolved in 2011 (it did not quite happen the way it had hoped);

■ (b) The KRG had often called for former Oil Minister Sharistani’s removal as a

condition of Maliki retaining the PM position and to an oil deal with the GOI, as it

was Sharistani who had pursued the centralisation of Iraq’s oil sector. The export

agreement was signed just a few days after the government came into power and

Luaibi assumed his new role as Oil Minister. Sharistani was eventually appointed

as one of the three Deputy PMs with responsibility for energy matters, which

created some confusion over who is in charge of decision making.

■ (c) The interests of the GOI and the KRG are more aligned with the GOI needing

more export to fund its budget, in particular as export increases in the south are

likely to see infrastructure bottlenecks.

2011 – Export through federally owned infrastructure from the KRI resumed in Feb 2011,

and two payments were made to the KRG, despite Deputy PM Sharistani’s continued anti-

PSC position. The tougher issue is still unresolved however; namely the GOI validating the

PSCs in the KRI. In 2011, Exxon made an entry into the KRI, which appeared to have

angered the GOI, also as the oil giant has a presence in the south.

Figure 7: Progress since 2012 – we have come far

May '12 -Turkey/KRG

announce bilateral energy plans

June '12 -disappointing 4th

Iraqi licensing round

July '12 - Trucks start rolling to

Turkey (condensates)

July '12 -Chevron and

Total enter Iraqi Kurdistan

Aug '12 - KRG agrees to restart

exports as a 'goodwill initiative'

Dec '12 - Contractors receive first trance. But

renewed dispute: exports cut

January '13 -Trucks start rolling to Turkey (crude

oil)

Aug '12 - Gazpromneft enters Iraqi Kurdistan

October '13 -independent KRI pipeline tied-in to

the ITP line

2014: - Payment mechanism- Oil exports from new pipeline- GSA (Genel with the KRG)- Consolidation

NEXT CATALYSTS

Sept '12 -agreement in

principle reached between KRG/GOI

November '13 - KRG and Turkey sign

energy agreements


04 December 2013


Very impressive progress since 2012 – Over the past two years, a growing number of

IOCs have entered the KRI, including Chevron, Total and Gazpromneft. This in turn reduced

the leverage the GOI has over IOCs and helped de-risk the path towards sustainable exports

from the KRI; in fact, the KRI now has major operator investments from all five permanent

members of the UN Security Council. In some ways, this could be seen as undermining the

historical position in the first two licensing rounds in southern Iraq—i.e., that IOCs would

accept unattractive TSCs for the right to bid in the future and more attractive contracts in the

south—and put into question the investment case in the south.

We believe IOCs have learned from the past three years; while production has been on the

rise in Southern Iraq, it was hard going and less than expected, with lagging infrastructure

developments, growing security concerns, challenging bureaucracy and slow cost

repayment. The fiscal terms in the KRI (PSCs) are more commensurate to geological risk.

With the support of Turkey (the announcement of the bilateral energy plans between the

KRG and Turkey in May 2012) and the construction of an independent pipeline (with another

pipeline in the planning stages) with a separate tie-in point (with SOMO invited to monitor the

flows) to the second line of the ITP pipeline (the pipeline now completed), the position of the

KRG had been further strengthened. With this, there is the potential for the oil to start flowing

in 1H14 initially at 150kbd, then quickly reaching 300-350kbd (mostly initially from Tawke,

Taq Taq and Khurmala Dome) and growing to ~500kbd by the middle of 2015, in our view.

Figure 8: Kurdish region of Iraq – infrastructure (a second pipeline is in the planning stages)

Source: Genel

Turkish commitment – an important piece to the Iraqi Kurdish puzzle

Decree – A decree (by the Council of Ministers) was published in the Official Gazetta in

Turkey in November 2011 that allows Turkish companies to pay for hydrocarbons (crude

and oil products) directly from companies in Iraqi Kurdistan; i.e. it would bypass SOMO.

Bilateral agreement – In March 2013, the KRG and Turkey announced bilateral energy

plans, involving oil, gas and downstream plans that rely on Turkey, not Baghdad. This

agreement includes:

■ (a) oil imports/transit fees, which we expect in the form of:

o Transit: $1-2/bbl (cost recoverable) within the KRI

o Transit: $5-10/bbl (not cost recoverable) in Turkey

04 December 2013


■ (b) infrastructure (oil and gas pipelines),

■ (c) gas sales agreement (for 10bcma and possibly growing to 20bcma by the middle of

the next decade) and gas prices, where we expect a border price of $6-7/mmbtu), and

■ (d) upstream acreage acquisition (via a new Turkish state entity, TEC), which is widely

reported to have taken stakes in 13 upstream blocks, half of which are in partnership

with Exxon.

This also included the possibility to barter crude for products. The KRG was, however,

clear in stating that it would be ‘Iraqi oil’ and that the GOI would be entitled to its share as

per the constitution. The wording, however, pointed to a change in the path of payment.

Encouragingly, the Turkish Energy Minister was quoted in Rudaw that 'I would say frankly

that Turkey will not sit idly by its nearby sources of energy'.

Issue of payment mechanism in the past – The central issue is that SOMO is

responsible for the sale of exports to Turkey, before the revenues are channelled to the

Iraqi Ministry of Finance. Below shows an example of how it was meant to work in the

past, and payments for the exports have been largely missing, which explains why oil

companies have opted to rely on the (a) domestic market and (b) trucks to Turkey, for

which they have been paid according to the PSC mechanism.

Figure 9: Previous export payment mechanism


Proposed payment mechanism – Turkey is preparing to set up an escrow account at a

state-owned Turkish bank, according to Dow Jones. The bank will collect the proceeds of

exports of Iraqi hydrocarbons from the KRI with contractor entitlement the first call on

export revenues. However, there is no final agreement yet with the GOI, but importantly

the KRG said that it will not touch its share (as defined by the constitution – 83%/17%

split) of revenue until it hammered out a deal, which means that exports can still resume

and contractors paid their shares under this format. As exports begin and revenue is

accumulated in the escrow account, there is a growing incentive between the parties to

reach an agreement.

We think this mechanism is a much better version of its former self in the eyes of the oil

companies, and according to the Iraq Oil Report falls under the control of the KRG, not the

Iraqi Ministry of Finance. This includes TEC (the Turkish stated entity with 13 upstream

blocks in Iraqi Kurdistan), which would not be committed unless it is confident that its

potential oil and gas volumes finds its way to the international markets and gets paid. The

US Energy Secretary, Ernest Moniz, stated in the WSJ that 'we support the discussions,

and companies being engaged, within the constitutional structure'. The US ambassador

was quoted in Hurriyet that 'we want to see the Iraqi government be happy about the deal

with the Kurdish Regional Government and with Turkey'.

04 December 2013


Rationale for investing in the KRI

Iraq is widely estimated to have the fourth largest proven oil reserves in the world. Given the

under-explored nature of the country, reserve estimates are likely to rise. Iraq is estimated to

hold ~143 billion barrels of oil. While it is not clear whether this figure includes the Iraqi

Kurdish Region, the KRG itself estimates that its territory holds ~45 billion barrels of oil

resources (and upside to this if one includes EOR upside) and ~100-200 tcf of gas.

Since the discovery of the giant Kirkuk field in 1927, Iraq has only enjoyed around 15 years

of intensive exploration efforts. Post-1952 after the signing of agreements with IOCs,

significant exploration efforts led to discoveries such as the large Rumaila field. But the

promulgation of Law 80 in 1961 stopped further exploration efforts. The second leg of

exploration efforts began following the nationalisation of Iraqi oil in 1972.

The Iraqi National Oil Company (INOC) with the help of IOCs embarked on an exploration

campaign, which resulted in multiple discoveries, including Majnoon and West Qurna. But

the 1980 Iran-Iraq war, followed by the Iraqi invasion of Kuwait and resulting UN sanctions,

put a halt to any exploratory efforts in the region. This under-explored nature (and resources

on the lower end of the cost curve) is attracting many western IOCs, particularly in the

Kurdish region, where contract terms are more favourable. The large Taq Taq, Tawke and

Shaikan discoveries are examples of what can be found in the ‘under-explored’ Kurdish

region of Iraq. Gas is also interesting (eg Miran, Bina Bawi) given the proximity to a

growing gas market in Turkey, which is keen to secure gas supply from the region.

Flexible federalism – a benefit to all Iraqis

The Iraqi Constitution, which came into effect in 2006, provides that the ‘management of

oil and gas extracted from present fields’ is to be undertaken jointly between the Iraqi

Government and the producing governorates/regional governments. The KRG interpreted

this as the GOI having the primary authority over ‘Existing fields’, while ‘New fields’ fall into

the purview of the regions. This is the interpretation of Turkey as well, and importantly,

aside from some verbal attacks from the central government (or more specifically from the

Deputy PM Sharistani), the PSCs in the KRI have not been legally contested.

Importantly, the centralised approach is ineffective as evidenced by the slow pace in

developing the projects in the South. In fact, many provinces prefer a more de-centralised

approach over the inefficient centralised approach, whilst staying true to a federal state. It

is a better recipe towards production growth to the benefit of the country as a whole. It is

visible in the Wasit province, where we now have both TSCs and PSCs (in JV between an

oil company and the provincial government). It is likely that other provinces are looking to

sign contracts for ‘New’ fields (ie exploration) independent from the GOI using the same

interpretation of the constitution as the KRG. In fact, acceptance of the KRG-Turkey deal

by the GOI in essence would appear to be a validation of the PSCs in the KRI.

Figure 10: Iraqi production performance (kbd) Figure 11: Under-delivery in export growth (kbd)

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04 December 2013


Figure 12: Southern distribution system (kbd) Figure 13: Northern distribution system (kbd)

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The issues in the Southern controlled fields – Incremental Iraqi oil supply will play an

important role in determining how tight the future global supply/demand balance will be.

Unfortunately, a series of obstacles, both above and below ground, make it unlikely that

Iraqi production will ever achieve its full potential, in our view. The IEA’s base-case

forecast has Iraq producing 6.1mbd by 2020 (which includes limited volumes from the KRI)

and 8.3mbd by 2035. The IEA’s base-case is too bullish in our view and all evidence

points to Iraq (we refer to the south) struggling to significantly increase production and with

the level likely to fall somewhere in between the IEA’s base-case and their more bearish

scenario of 4.0mbd by 2020 and 5.3mbd by 2035. A swing factor could be KRI oil. We

briefly share our concerns on the developments in the South.

In a nutshell, we find medium-term risk is increasingly skewed to the downside:

■ To achieve the consensus (IEA) central oil production scenario, Iraq would need to

have ~100 drilling rigs drilling some 400 wells per year by 2015.

■ Particularly in southern Iraq, operators are struggling with issues that could broadly be

defined as subsurface/technical and above ground.

Figure 14: Southern distribution system plans

Zubair 1 Pump Station

Pump Station 1

Rumaila, West Qurna, Zubair &

Iraqi NOC production

Fao Terminal

c3.2mbbls pipelines

c4.3mbbls pipelines

Tuba

c1.2mbbls pipeline

c0.9mbbls pipeline

SPMs Nassiriya (proposed capacity

Zubair 2 Pump Station

c3.2mbbls pipelines

Bin Umar (proposed

capacity c6.6mb)

c1.6mbbls pipeline

Majnoon, Halfaya, Bin Umar, Missan

& Iraqi NOC production

Ahdab, Gharraf, Badrah & Iraqi

NOC production


04 December 2013


o Three links could hamper exports from the south, namely (a) the network

of pipelines, (b) the storage facilities and (c) the pumping station that

provides a connection between the fields and the main export depot at

Fao. Furthermore, the available pumping and storage capacity at Fao

itself, an important link between the fields and the offshore loading

facilities, could be an additional blockage.

o Export capacity will eventually be enough, currently the goal is to build

out ~6.5mbd of capacity by 2017, but Iraq does not have the ability to

handle the logistics of building the pipes, loading stations, storage

facilities and pumps, simultaneously, just sequentially. As a result, putting

in place the necessary infrastructure will take much longer than expected.

■ Iraq faces a water injection shortage of ~4mbd by 2016, which jeopardises ~1mbd of

production capacity. Other Infrastructure issues abound.

o Water injection capacity stands at ~1.6mbd. By 2016 as much as 5Mb/d

of injection will be needed to sustain production. Increasing water

injection is technically easy, but will be logistically difficult.

o In Saudi Arabia a similar project (Qurayyah Seawater Plant Expansion) to

increase injection capacity at an existing plant by 2mbd took almost four

years to complete. We think it is safe to assume, that the Iraqi ministry

and State Oil Company for Projects will take at least as long to increase

Iraqi injection by 4mbd.

o Any significant delays or failure to meet water injection needs means that

reservoir pressure in unsupported fields will fall, reducing well flow rates,

making it difficult to increase oil output.

■ Unattractive contract terms, coupled with a patchy institutional frame-work has

impacted project return profiles. Not coincidentally, several operators have opted to

invest in the North, likely much to the chagrin of Baghdad;

o Beyond the lack of a basic oil law, of particular struggle are the current

contract terms for individual players.

o Perfect contract implementation, which appears far from forthcoming, is

key to getting a reasonable return on investment, in our view.

o Operators have been frustrated with the contracts despite the fact that

they were amended before signing, in order to (a) strengthen security

provisions, (b) reduce the scope of government procurement oversight,

(c) transfer infrastructure associated risks to the SOC, and (d) provide

compensation for any, hypothetical, Opec-imposed production

restrictions.

o Current feedback from IOCs suggests that government oversight,

bureaucracy, and security have been greater issues than expected.

■ There is a serious shortage of skilled labour, compounded by the myriad obstacles in

the way of deploying foreign expertise, of any origin.

o Another significant constraint on commercial activity is the shortage of

skilled labour – steelworkers, welders and the like. Decades of rule under

the Saddam Hussein regime and three significant wars have hollowed

out Iraq’s, once sizeable, skilled labour force.

o This is relevant to the development of these mega fields. For example, at

Rumaila over 90% of the 5,000 person workforce is Iraqi nationals, many

of whom need significant training.

04 December 2013


o Yet, companies are finding it very difficult to get visas to import the

necessary labour, especially for the Russian and Chinese workers who

typically fill the gap when there is a need for technically skilled labour.

Even more worrying, it appears to be difficult even to get visas for people

to come and train Iraqis to fill the labour shortage.

o As of 2010 Iraq’s labour force was approximately 8 million people, mostly

young unskilled workers. By 2020 that number is estimated to increase

by 25% to roughly 10 million, again, mostly young unskilled workers – all

of whom need to have jobs and a salary to support themselves.

o If Iraq does not find a way to significantly increase production quickly,

demographic trends point towards the rapidly increasing possibility that

significant political instability could prevent them from ever producing

close to their geological potential.

Contribution from Iraqi Kurdistan can help both Iraq and Turkey

Underlying global decline is ~4.5mbd pa. If you add 1mbd of demand, 5.5mbd is the

annual supply need. US/Canada is adding ~1.5mbd through shale. Unless access to

easier reserves in southern Iraq / MENA / Venezuela improves (and some of them are

going backwards), it is the service intensive deep-water, secondary recovery mechanisms

(eg EORs) or yet to be found/developed international shale looking to fill the void. Low-

cost KRI oil would help, and as production capacity increases (as we see happening), it

should find its way to the market, and with the energy agreements now formalised, this

looks likely, in our view.

The KRG has indicated it believes that it can export 1mbd by the end of 2015 rising to

2mbd by 2019, which in our view is unrealistic. Below, we show the potential production

capacity (not exports) in the region, but admit there could be upside to the productive

capacity with further de-risking of the resource base and discoveries in the region. For

example, Chevron is scheduled to declare commerciality at two of its blocks in 2014.

Figure 15: Iraqi Kurdish oil capacity potential (kbd) Figure 16: NOC’s Kirkuk production profile (kbd)

0

200

400

600

800

1000

1200

2012 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

0

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03

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Source: Company data, Credit Suisse estimates Source: Wood Mackenzie

Turkey is energy deficient in both oil and gas resources and must import over 90% of its

energy needs. At the moment, its key suppliers are Iran and Russia. Prior to the recent

sanctions, Turkey imported ~200 kb/d of crude from Iran. Gas resources are strategic to

Turkey, and a GSA between Turkey and the KRG has reportedly been signed paving the

way for Genel to sign its own GSA for Miran and Bina Bawi.

Why KRI Gas? Turkey mostly relies on gas imports from Russia (~58%), Iran (~18%),

contracted LNG from Nigeria and Algeria (~17%), and Azerbaijan (~7%) based on 2012

04 December 2013


data (~46bcm). Turkey also procures expensive spot LNG. The KRG estimates gas

resources in excess of 100tcf in the KRI and it needs an export market. KRI Gas would

allow Turkey to diversify its gas supply, whilst also being able to reduce the gas input cost.

The latter is also the case as, unlike Russian exports, KRI gas will not incur much transfer

fees along its transport route (ie it will not pass through third party countries) and also

because of the short distance between the KRI and Turkey. This will help with the current

account deficit of Turkey. The KRI potential would also help Turkey in the longer term with

its ambitions of becoming a regional energy hub.

Figure 17: KRI Gas – Genel gross resources Figure 18: KRI Gas – cost competitiveness

Source: Genel Energy Source: Genel Energy

Importantly, the agreement for 20bcm, which is higher than the HoA for 10bcm, according

to the Iraq Oil Report, will make the KRI one of Turkey's most important long-term strategic

partners and may help Turkey to drive harder negotiations over the price of gas imports

with its other suppliers.

Figure 19: Turkey’s gas infrastructure and imports in 2012

West gas pipeline

ITG

Iran-Turkey pipeline

South Caucasus pipeline

Aliaga LNG

Marmara Ereglisi LNG

Russia58%

Iran18%

Azerbaijan7%

LNG17%

12.1 14.4

3.4

8.2

2.5

5.4

Turkey

45.9 bcm

Source: IEA, Credit Suisse Research

04 December 2013


Win-win situation. Turkey is amongst the largest consumers of gas in Europe with gas

demand growing at >8% pa over the past 10 years. As consumption per capita remains

relatively low, the growth trajectory is set to remain steep. Thus, when thinking of Turkey

and gas, gas only becomes important once it can be exported and the KRI will play an

important role. Contrary to this, gas reserves in federal Iraq lie mainly in the Basrah

province and Iraq via the Basrah Gas company is prioritising gas for domestic power and

industry unlike KRG’s commitment to Turkey.

Turkey and Gas – As one of the most dynamic economies in the world (5% average real

GDP growth over 2002-2012), Turkey has steadily increased its demand for energy and is

now the sixth largest energy consumer in Europe. The share of natural gas in Turkey’s

energy mix has been growing and currently represents c.32% total primary energy supply.

With little indigenous production (c.0.63bcm in 2012 or less than 2% of the demand) the

country is overwhelmingly dependent on pipeline and LNG imports.

Figure 20: Turkey long-term pipeline and LNG contracts

Seller Route Type

Capacity

(bcm)

Contracted

(bcm) Start date Expiry 2012 inflows (bcm)

Russia West gas pipeline Pipeline 5.7 1987 2031

West gas pipeline Pipeline 7.5 1988 2021

Blue Stream Pipeline 16 15.1 2001 2028 14.4

Azerbaijan South Caucasus pipeline Pipeline 8 5.7 2007 2022 3.4

TANAP* Pipeline 16 5.8 2018 2031 n.m.

Iran Iran-Turkey Pipeline 13 10.5 2002 2025 8.2

Algeria Marmara Eriglisi LNG 3.9 1994 2014

Nigeria Marmara Eriglisi LNG 1.3 1995 2021

Various Aliaga LNG 6 - - - 2.5

Total 79.4 55.5 45.9

*the proposed Trans-Anatolian pipeline will link Shah Deniz Ph II gas to the TAP pipeline

out of 16bcm of capacity c.6bcm is earmarked for Turkey

14

6.4

12.1

5.4

Source: Wood Mackenzie, IEA

With Turkey’s demand for natural gas forecast to grow at a steady rate (to >59bcm

according to Turkey’s Ministry of Energy forecasts), Turkey is eager to diversify its sources

of supply. Azeri import is scheduled to increase by 6bcma once the proposed TANAP

pipeline, which is designed to link Shah Deniz Ph II with European consumers, comes

onstream. Securing further sources of future supply has proved to be more challenging.

In 1999 Turkey and Turkmenistan signed an MOU for delivery of 16bcm of gas, but the

agreement failed to take concrete form. With Azerbaijan keen on developing its own

resource base and Iran and Russia’s opposition to the proposed Trans-Caspian pipeline

we consider this a distant option. Exports of up to 6bcm of gas to Turkey has been

mentioned as an option by the companies developing the Leviathan gas discovery

offshore Israel, but the project is still at an early stage and may prove politically sensitive.

Potential long-term agreement with Qatar may bring 2.5-3bcm a year, but according to

industry press these volumes are likely to replace LNG cargoes Turkey receives from

Algeria under the contract that is due to expire in 2014.

Potential gas from KRG is therefore an increasingly attractive option for gas-hungry

Turkey and will place highly in the supplier order of merit. In our view, aside from

rationales of diversification, Turkey will be especially keen to replace Iranian volumes:

■ The price of Iranian gas supplied under long-term contracts is higher than its Russian

and Azeri alternatives (>$500/mcm compared to ~$330/mcm for Azeri and

>$400/mcm for Russia). In 2012 Turkey took Iran to international arbitration claiming

that the prices it was paying were above international prices.

■ Security of supply has been a concern. Iranian supplies were interrupted several times

in recent years due to sabotage and explosions on the pipeline and tended to depend

on weather conditions and Turkmenistan’s gas exports to Iran.

04 December 2013


■ The US has been tightening financial sanctions against Iran over its nuclear

programme, and is putting political pressure on countries that trade with Iran.

Turkey may also consider reducing the amount of gas it imports from Russia. The reason

is twofold:

(1) due to lower cost and physical proximity Kurdistan may offer more attractive

pricing, and

(2) with 58% of gas currently being imported from Russia, Turkey is

uncomfortably dependent on one trading partner that is well-known for driving a

hard bargain (as Ukraine and Belarus may testify).

Having a more diversified supplier base should strengthen Turkey’s bargaining position.

Consolidation in 2014 in Kurdish Region of Iraq?

At the end of 2012, we said that we did not expect consolidation or M&A to be the theme

in 2013, which has proven to be the case. 2014 could be different, in our view. Admittedly,

we can ask ourselves why would Big Oil/NOCs grow inorganically in the KRI after the

event (exports etc) when valuations could be richer? Why not do it before, when it is

cheaper, but at a risk of spending billions without certainty of the situation in the KRI? We

think it is the latter (ie Majors do not like uncertainty, in our view) that stopped them from

fully committing, but this may change in 2014.

Differentiation is key. Big Oil can still drive harder bargains with those companies that are

(a) capital constrained and (b) technically not capable to drive developments. We see

plenty of companies with exposure to the KRI in this camp, where Oil Majors can exercise

this leverage. The best positioned or one that has the most sustainable business model

(cash flow and balance sheet strength), in our view, with exposure to the KRI is Genel.

Figure 21: Map of Iraqi Kurdistan

Source: WesternZagros (October 2013 Presentation)

04 December 2013


Figure 22: M&A aspects: general considerations for oil companies

Asset-specific considerations Comments

- Geography Is the asset in the geological hot post-code?

- Scale Size of the discovery (too small to be of interest or too big to acquire)

- Commerciality Access to markets/infrastructure

- Life-cycle Early stage/close to FID/approaching production/mature fields

- Control Operating stake versus minority interest

- Partners How credible are the partners, especially if the stake is non-operating

- Regulatory and political considerations Does the government have a stake in the asset; are there unresolved issues with taxation, export

rights, environmental concerns, local content requirements etc

Acquirer-specific considerations Comments

- Acquirer goals Geographic/Geological diversification; Security of supply for NOCs; hedging needs

- Acquirer competencies Knowledge of the particular geology/EOR methods; experience as an operator; political

connections; access to markets; financial strengths etc

- Acquirer-specific synergies Economies of scale, access to infrastructure etc

Transaction-specific considerations Comments

- Level of competition How strategic is the asset base (for an NOC)? How underexposed is an IOC to the theme/region?

- Motivation of the seller How motivated is the seller (distressed or selling purely as part of strategy of portfolio mgmt)?

- Availability of financing Is access to finance easy and cheap?

- Government reaction What is the expected government reaction? The government may prefer experienced players; it

may demand tax (eg CGT); it may demand NOC participation

Corporate transaction considerations Comments

- Shareholder structure

Who are the main shareholders; how is the ownership structured; what are the goals; at what price

did they invest; will they be willing to sell; do you want them as partners if it is not a 100%

acquisition; board composition etc

- Management team

The value can be in the unique team and not in the asset per se; they may have good relationships;

they may have knowledge of a particular geology etc

- Regulatory and political considerations Authorities may not approve the transaction for political reasons Source: Credit Suisse research

What makes Genel so attractive?

Portfolio quality – Genel has an attractive asset base with most of its blocks in the KRI

defined as high quality, in our view, with a ratio of assets on the fringe being low. In other

words, it is not a company that is a 'one trick pony' with a large share of peripheral assets,

and we think that is also an important consideration. After all, if a company is a 'one trick

pony', a Major/NOC may be better off buying the asset, not the company. Genel stands

out in terms of portfolio quality, in our view.

Figure 23: Reserves and Resource base Figure 24: Genel Energy – Key assets in the KRI

Source: Genel Energy (April 2013 Presentation) Source: Genel Energy(April 2013 Presentation)

04 December 2013


Portfolio depth with high equity stakes – Genel has potentially five big projects – Taq

Taq development upside, Tawke development upside, Miran gas development, Bina Bawi

gas development and Chia Surkh. This is second to none in the region, and for anyone

looking to gain a strong and dominant footprint in the region, Genel could offer that. The

potential would represent a decent contribution to a Majors' portfolio, in our view.

Figure 25: Upstream cycle – value cycle

First Production - Plateau 1.5-2 years ramp-up to plateau

Plateau Normal plateau production

plateau (1-3 years)

Can be extended with infill

drilling and EOR

Commercialisation• NPV moves with discount rate

• Increased capex

requirements/funding needs

• Risk of (a) cost inflation (b) delays

- delay to value identification

• Ideally farm-out/reduce exposure

(bring fwd value)

3D Seismic

1st Discovery

Appraisal FID

4-7 years from discovery to first oil

Valu

e

First Production

Monetisation

opportunities

Monetisation

opportunities

Start Up• First production and

project de-risked

Exploration and Appraisal• High risk/reward: value creation

through E&A

CoS 10-15%

De-risked to 50-75%

Firming up volumes & E&A

fully de-risked

Late stage/Mature• Decline or

• Infill drilling and IOR/EOR

upside

20 years plus production license

Value upside


Capital light / features of long-duration – Genel's portfolio can be described as (a) long-

life gas value chain with high IRRs (>20%) and (b) conventional capital light (development

capex/boe of $4-5/boe), low capital intensive oil projects (with IRRs of >40%) with features

of long duration (upside to recovery factors). We calculate break-evens in the $20-30/bbl

range; in other words, on the right side of the cost curve globally. Recovery factors

currently stand in the mid-30%, and this could rise to 50% plus over time through the

application of simple techniques, such as horizontal drilling.

Figure 26: Generic light oil field IRR at capacity building payment of 30%

0%

10%

20%

30%

40%

50%

60%

70%

$20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120

IRR

Source: Credit Suisse estimates

04 December 2013


Intangibles (ie relationship / technical know-how) – Genel has the best relationships

(KRG and Turkey) in the region, in our view. This includes with the KRG and Turkey, and

this is driven by a team led by Mehmet Sepil. This is an important consideration, and we

have seen on many occasions companies (in particular NOCs) partner with companies

that have strong relationships with the host governments. Any company looking to acquire

Genel would likely want to ensure that this strong team remains in place.

Technically, the same could be said for those without exposure to the region or know-how

of the region. Drilling in the KRI is not particularly easy. Although the structures

themselves are fairly simple (Taza for example is a four-way dip closure), the drilling

involves pockets of extreme high pressure and extreme low pressure related to active

deformation in the region. This gives rise to well control issues and it is a great advantage

to have an experienced rig and crew.

Attractive exploration portfolio outside the KRI – The company is first and foremost

about the KRI, but it also has a growing African exploration portfolio – Morocco, Malta and

Somaliland. It is particularly encouraging to see growing industry interest in Morocco

(particularly recently BP (a good explorer) farming-into Kosmos' Morocco acreage), and

the play is well understood by Genel, which with the acquisition of Barrus Petroleum

brought a team that looked at the play extensively over the past 4-5 years.

When extending the EMV beyond the usual 12-month forward looking basis (ie beyond the

normal timeframe for setting TPs) to include more risked exploration upside from Genel’s

Africa portfolio, we estimate the risked value potential is >1,000p/share with substantially

more upside in the case of success. This is simply to highlight the depth of the portfolio or

the potential incremental risked value addition over the medium term. In other words, this

is not reflected in our valuation (consistent with our valuation approach), which currently is

mostly derived from its asset base in the KRI.

Figure 27: Potential risked value from African portfolio (at company CoS as an illustration, where applicable) Pre-drill (gross) Pre-drill (net) COS Net risked WI Well cost (net) Risked Dry well Risked NPV Unrisked NPV

Block Prospect Spud mboe mboe % mboe NPV/boe $mn $mn p/share p/shareJuby Maritime (Morocco) Cap Juby - Juby Maritime 1Q14 250 94 33% 31 13.5 23 15 90 282Juby Maritime (Morocco) Carbonate prospect - Juby Maritime 2H14 200 75 20% 15 13.5 23 18 41 225Juby Maritime (Morocco) Carbonate prospect - Juby Maritime 2014+ 200 75 20% 15 13.5 23 18 41 225Juby Maritime (Morocco) Carbonate prospect - Juby Maritime 2014+ 150 56 20% 11 13.5 23 18 30 169Sidi Moussa (Morocco) Main prospect - Sidi Moussa 2Q14 200 120 20% 24 13.5 50 40 63 361Sidi Moussa (Morocco) Upside in the block - Sidi Moussa 2014+ 650 390 20% 78 13.5 144 115 209 1172Mir Left (Morocco) Main prospect - Mir Left 2H14 200 150 20% 30 13.5 60 48 79 451Mir Left (Morocco) Upside in the block - Mir Left 2014+ 550 413 20% 83 13.5 180 144 216 1240Area 4 (Malta) Hagar Qim 4Q13 250 188 20% 38 5.1 30 24 37 214Area 4 (Malta) Second prospect 2H14 300 225 15% 34 5.1 30 26 33 257Area 4 (Malta) Upside in Area 4 (Blocks 4-7) 2014+ 250 188 15% 28 5.1 23 19 28 21410B & 13 (Somaliland) Prospective upside in the blocks 2015+ 1000 600 15% 90 5.8 100 85 98 7776, 7 & 10A (Somaliland) Prospective upside in the blocks 2015+ 1000 500 15% 75 5.8 100 85 78 648Block 508 (Cote d'Ivoire) Submarine fans - Block 508 2015+ 100 22 15% 3 6.6 12 10 2 32Block 508 (Cote d'Ivoire) Albian tilted fault blocks - Block 508 2015+ 100 22 15% 3 6.6 12 10 2 32Block 508 (Cote d'Ivoire) Diapirs - Block 508 2015+ 100 22 15% 3 6.6 12 10 2 32Adigala block (Ethiopia) Prospective upside in the block 2015+ 250 85 15% 13 3.9 53 45 1 74Total 5750 3222 574 895 730 1051 6404 Source: Company data, Credit Suisse estimates: Note: assumes government back-in rights, where applicable; COS: using company guidance as

an illustration; CABLE at 1.60; well costs assumes a full carry for a number of wells, where applicable

04 December 2013


Figure 28: Economic index (NPV10 on WI) – 350mboe offshore oil field with first oil in 2021 based on CS assumptions

$0

$2

$4

$6

$8

$10

$12

$14

$16M

oro

cco

Sou

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a

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and

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Mo

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Can

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ire

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ibia

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rita

nia

Bra

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nam

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on

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(B

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)

Ken

ya

Ala

skan

Arc

tic

Source: Credit Suisse estimates; Note: we assume initial flow rate per well of 10kbd for all countries in this instance

04 December 2013


Genel Energy – risked NAV summary

Figure 29: Genel Energy – risked NAV summary Country/ Net URR, Oil+Gas Risked Reserves Unrisked Disc EV Risked Unrisked Risked Theoritical

Region mn boe mn boe US$mn US$/boe US$mn GBp/sh GBp/sh GBp/sh

Kurdistan 326 326 1,615 5.0 1,615 361 361

Producing NAV 326 326 1,615 5.0 1,615 361 361

Country/ Net URR, Oil+Gas Risked Reserves Unrisked Disc EV Risked Unrisked Risked Theoritical


Kurdistan 387 334 1,661 4.3 1,420 371 317 54

Development NAV 387 334 1,661 4.3 1,420 371 317 54

Producing + Developing NAV 713 660 3,276 4.6 3,035 731 678 54



Kurdistan 1,372 1,041 2,359 1.7 1,938 527 433 94

Contingent NAV 1,372 1,041 2,359 1.7 1,938 527 433 94



Morocco 364 44 4,896 13.5 596 1,093 133 960

Kurdistan 658 215 893 1.4 336 199 75 124

Malta 250 38 959 6.5 192 214 43 171

Somaliland (onshore) - drill ready in 2015 5.8

Cote d'Ivoire (offshore) - drilling in 1H15 6.6

Exploration NAV 1,271 297 6,748 5.3 1,123 1,507 251 1,256

Enterprise Value 3,356 1,997 12,382 3.7 6,097 2,765 1,361 1,403

Dry well costs -141 -141 -31 -31

Corporates (5x multiple) -86 -86 -19 -19

Financing NAV (end 2013) 883 883 197 197

NAV 3,356 1,997 13,039 3.9 6,753 2,911 1,508 1,403Dilution of Founder Securities at NAV -76NAV post C-shares 1,432Diluted nr of shares used (in mn) 280 Source: Company data, Credit Suisse estimates

Figure 30: Genel Energy – risked NAV in details Field Net URR, Oil+Gas Risked Reserves Unrisked Disc EV Risked Unrisked Risked Theoritical

mn boe mn boe US$mn US$/boe US$mn GBp/sh GBp/sh GBp/shTaq Taq 2P 259 259 1312 5.1 1312 293 293Tawke - current capacity 67 67 303 4.5 303 68 68Producing NAV 326 326 1,615 5.0 1,615 361 361

Field Net URR, Oil+Gas Risked Reserves Unrisked Disc EV Risked Unrisked Risked Theoriticalmn boe mn boe US$mn US$/boe US$mn GBp/sh GBp/sh GBp/sh

Taq Taq 3P upside (expect new CPR in 2014) 156 133 792 5.1 673 177 150 27Tawke P50 development upside 111 94 498 4.5 424 111 95 17Tawke 3P upside 36 30 160 4.5 136 36 30 5Tawke Deep 53 45 152 2.9 129 34 29 5Summail (Dohuk) 31 31 58 1.8 58 13 13Development NAV 387 334 1,661 4.3 1,420 371 317 54

Producing + Developing NAV 713 660 3,276 4.6 3,035 731 678 54


Miran West 509 432 1222 2.4 1038 273 232 41Bina Bawi (P50) 345 293 412 1.2 351 92 78 14Bina Bawi (upside) 242 81 129 0.5 43 29 10 19Peshkabir 21 18 61 2.9 52 14 12 2Ber Bahr (heavy oil) 30 26 55 1.8 46 12 10 2Chia Surkh 10-11 225 191 481 2.1 409 107 91 16Contingent NAV 1,372 1,041 2,359 1.7 1,938 527 433 94


Barda Sur prospect (Chia Surkh) 80 40 170 2.1 85 38 19 19Qalami prospect (Chia Surkh) 58 29 124 2.1 62 28 14 14Taq Taq Deep 109 43 262 2.4 104 58 23 35Miran Deep 411 103 337 0.8 84 75 19 56Cap Juby - Juby Maritime 94 19 1262 13.5 252 282 56 225Main prospect - Sidi Moussa 120 18 1615 13.5 242 361 54 307Main prospect - Mir Left 150 8 2019 13.5 101 451 23 428Hagar Qim 188 38 959 5.1 192 214 43 171Exploration NAV 1209 297 6,748 5.6 1123 1507 251 1256

Enterprise Value 3,294 1,997 12,382 3.8 6,097 2,765 1,361 1403

Dry well costs -141 -141 -31 -31Corporates (5x multiple) -86 -86 -19 -19Financing NAV (end 2013) 883 883 197 197

NAV 13,039 6,753 2,911 1,508 1,403Dilution of Founder Securities at NAV -76NAV post C-shares 1,432 Source: Company data, Credit Suisse estimates

04 December 2013


Companies Mentioned (Price as of 03-Dec-2013)

BP (BP.L, 473.6p) Chevron Corp. (CVX.N, $122.34) ExxonMobil Corporation (XOM.N, $93.52) Genel Energy plc (GENL.L, 1057.0p, OUTPERFORM, TP 1430.0p) Kosmos Energy Ltd (KOS.N, $11.25) Total (TOTF.PA, €43.725)

Disclosure Appendix

Important Global Disclosures

Thomas Adolff and Charlotte Elliott, each certify, with respect to the companies or securities that the individual analyzes, that (1) the views expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his or her compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report.

3-Year Price and Rating History for Genel Energy plc (GENL.L)

GENL.L Closing Price Target Price

Date (p) (p) Rating

08-Dec-11 760.00 1093.00 O *

24-Feb-12 828.00 1111.00

26-Mar-12 740.00 1142.00

17-Apr-12 700.00 1180.00

24-Aug-12 700.00 1138.00

15-Mar-13 801.50 1222.00

10-Apr-13 850.00 1236.00

30-May-13 937.50 1246.00

31-Jul-13 959.00 1296.00

* Asterisk signifies initiation or assumption of coverage.

O U T PERFO RM

The analyst(s) responsible for preparing this research report received Compensation that is based upon various factors including Credit Suisse's total revenues, a portion of which are generated by Credit Suisse's investment banking activities

As of December 10, 2012 Analysts’ stock rating are defined as follows:

Outperform (O) : The stock’s total return is expected to outperform the relevant benchmark*over the next 12 months.

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*Relevant benchmark by region: As of 10th December 2012, Japanese ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractiv e, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. As o f 2nd October 2012, U.S. and Canadian as well as European ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. For Latin Ame rican and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return of the relevant country or regional benchmark; Australia, New Zealand are, and prior to 2nd October 2012 U.S. and Canadian ratings were based on (1) a stock’s absolute total return potential to its current share price and (2) the relative attractiveness of a stock’s total return potential within an analyst’s coverage universe. For Australian and New Zealand stocks, 12 -month rolling yield is incorporated in the absolute total return calculation and a 15% and a 7.5% threshold replace the 10-15% level in the Outperform and Underperform stock rating definitions, respectively. The 15% and 7.5% thresholds replace the +10-15% and -10-15% levels in the Neutral stock rating definition, respectively. Prior to 10th December 2012, Japanese ratings were based on a stock’s total return relative to the average total return of the relevant country or regional benchmark.

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04 December 2013


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Global Ratings Distribution

Rating Versus universe (%) Of which banking clients (%)

Outperform/Buy* 42% (54% banking clients)

Neutral/Hold* 41% (49% banking clients)

Underperform/Sell* 15% (40% banking clients)

Restricted 3%

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Price Target: (12 months) for Genel Energy plc (GENL.L)

Method: We value Genel Energy at 1,430p/sh using a risked NAV framework, and our TP is set in line with our risked NAV based on $90/bbl oil long-term. We use a 12% WACC to reflect country risk in deriving our valuation. We value the producing and development assets using field by field DCFs. We value the contingent (discovered but not developed) and exploration assets by multiplying the resource potential, provided by the third-party reserves auditor McDaniel & Associates, by an analogue NPV per barrel. The resource base is risked according to McDaniel & Associates' geological chance of success.

Risk: Risks to PSC terms - bidders in the first two licensing rounds in southern Iraq in 2009 were awarded technical service contracts (TSCs), which are less attractive than PSCs, but potential reward is commensurate with risk (developing assets). It is important to highlight two facts - (a) the position of the KRG within the political power structure in Iraq, and (b) Taq Taq, Tawke and Dohuk are pre-constitutional and therefore should not be subject to amendments. Payment mechanism - Even assuming that the current PSCs are ultimately ratified by the Iraqi central government, a worst case scenario is one which involves no near-term payment, resulting in a persistent discount to valuations of E&Ps operating in the Kurdish region of Iraq. Political differences - the issue around federalism and centralism is deeply rooted. Security risks - The security situation following the US troop withdrawals is uncertain and the Kurdish region of Iraq, which is enjoying relative stability, may not be immune to potential disruption, especially around the Kirkuk governorate.

Please refer to the firm's disclosure website at https://rave.credit-suisse.com/disclosures for the definitions of abbreviations typically used in the target price method and risk sections.

See the Companies Mentioned section for full company names

As of the end of the preceding month, Credit Suisse beneficially own 1% or more of a class of common equity securities of (GENL.L).

Credit Suisse has a material conflict of interest with the subject company (GENL.L) . Credit Suisse Securities (Europe) Limited acts as broker to GENL.L

Important Regional Disclosures

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The analyst(s) involved in the preparation of this report have not visited the material operations of the subject company (GENL.L) within the past 12 months

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04 December 2013


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Credit Suisse Securities (Europe) Limited............................................................................................................. Thomas Adolff ; Charlotte Elliott

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