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Oil and gas
Central Asia
Reinitiation of coverage
Equity Research
6 October 2011
Farid Abasov
+44 (207) 367-7983 x8983
[email protected]
Ildar Davletshin
+7 (495) 725-5244 x5244
[email protected]
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Ivan Kokurin
+7 (495) 725-5247 x5247
[email protected]
We reinitiate coverage of Dragon Oil (DGO) with a BUY rating and GBp693

target price (TP); Zhaikmunai (ZKM) with a BUY rating and $14 TP; and
Kazmunaigaz EP (KMG EP) with a HOLD rating and $21 TP.
Central Asian E&Ps generate much higher cash flows and benefit from greater

oil price leverage than Russian upstream players, and trade at 3-4x discounts to
African peers on reserves multiples (despite high growth potential). The Central Asian
space looks resilient on the downside, with a combined cash balance of $5.3bn.
In an environment where downside protection matters just as
much as upside potential, we currently favour DGO. Its $1.5bn cash balance

and recently initiated share buyback programme make the stock resilient in the
current market environment. In addition, our estimate of a 10-15% production CAGR
over the next three years, solid cash flow generation, upside from gas monetisation
and a compelling M&A angle make an appealing investment case, in our view.
Report date:
6 October 2011
Total sector MktCap, $mn
Target MktCap, $mn
RenCap Index high
RenCap Index low
Average sector P/E
Average sector P/S
Average sector EV/EBITDA
Average sector P/B
12,100
15,022
5,170
3,403
8.90
0.60
3.80
0.40
ZKM implies the greatest upside potential to our valuation: 95%

to our base case and 251% to our bull case; although we believe management’s
execution will be instrumental in unlocking the company’s very large resource base.
We like the story for its near-term production growth potential, favourable fiscal terms,
potential reserves upgrade and further upside potential from gas monetisation.
Our HOLD rating on KMG EP is assigned on a relative valuation basis. We

believe its net cash balance of $4.1bn, combined with the share buyback, offers
downside protection for the stock. However, upside potential is limited, in our view, as
the company still faces operational challenges and progress with M&A is slow. We
believe more aggressive steps on the exploration front, M&A and operational
discipline would help ease disappointment in the market. Furthermore, we believe
completion of the Mangistaumunaigas (MMG) acquisition on favourable terms by the
year-end would re-rate the stock, although timing and terms remain uncertain.
Compelling valuation. DGO, with a high 11% 2012E free cash flow yield,

trades at a 31% discount to our target P/CF multiple of 5.5x. ZKM looks very cheap to
us given its growth momentum, trading at 2012E P/E of 4.3x and 2012E EV/EBITDA
of 2.3x. KMG EP trades in line with LUKOIL on 2012E P/E of 3.6x (Bloomberg
consensus) and close to Tatneft on the EV/2P multiple.
Summary ratings and target prices
Company
Ticker
Cur
Dragon Oil
Zhaikmunai
Kazmunaigaz EP
DGO LN
ZKM LI
KMG LN
GBp
$
$
Current
price
456
7.2
14.0
Target
price
693
14
21
Rating
BUY
BUY
HOLD
MktCap
$mn
3,669
1,330
5,899
EV
$mn
2197
1641
1799
P/E
2011E
6.4
11.5
3.6
2012E
6.0
4.3
3.6
EV/EBITDA
2011E
2012E
2.2
2.3
6.3
2.9
1.5
1.2
P/CF
2011E
2012E
4.1
3.8
5.1
2.3
5.0
4.2
Source: Company data, Renaissance Capital estimates
Figure 2: Sector stock performance – three months
Figure 1: Price performance – 52 weeks
$
Sector
Relative to RENCASIA
RENCASIA
6,000
140
5,000
120
100
4,000
80
3,000
60
2,000
40
1,000
20
0
0
Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug
Source: Bloomberg
Tethys Petroleum
Petro Matad Ltd
Roxi Petroleum
KazMunaiGaz E&P
Zhaikmunai
Max Petroleum
Dragon Oil
BMB Munai
RENCASIA
%
-60
-50
-40
-30
-20
-10
0
Source: Bloomberg
Important disclosures are found at the Disclosures Appendix. Communicated by Renaissance Securities (Cyprus) Limited, regulated by the Cyprus Securities & Exchange
Commission, which together with non-US affiliates operates outside of the USA under the brand name of Renaissance Capital.
Renaissance Capital
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6 October 2011
Contents
Executive summary
Who’s who in Central Asia
Valuation tables
3 4 15 The companies ZKM
KazMunaiGaz E&P
DGO
18 40 65 Disclosures appendix
80 2
Renaissance Capital
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6 October 2011
Executive summary
We reinitiate coverage of DGO (TP GBp693) and ZKM (TP $14) with BUY ratings,
and KMG EP (TP $21) with a HOLD rating.
The combined 2P reserves base of the three companies covered here stands at
3.6bnboe, and their aggregate market cap is $12.8bn, implying just a $3.5/boe
multiple for 2P reserves, excluding the cash pile each company holds: with the cash
piles included, the aggregate reserves multiple screens even lower, at $2/boe, on
our estimates. After the recent sell-off in the equity markets, many companies look
cheap. We see this as a good opportunity to select high-quality assets that are
defensive in the downturn and positioned to outperform in the upturn.
In terms of optimal risk/reward, we currently favour DGO. Its $1.5bn cash pile,
accounting for around 40% of the market cap; coupled with a recently initiated share
buyback programme makes the stock defensive. In addition, we think a 10-15%
production CAGR 2012-2015E, strong cash flow generation, upside potential from
gas monetisation and potential M&A make the investment case for DGO appealing.
We see the greatest upside potential in our universe in ZKM: 95% to our base-case
valuation and 251% to our bull case, although unlocking its vast resource base
remains heavily dependent on management execution. We see the main catalyst for
the stock as the long-awaited commissioning of ZKM’s gas treatment plant (GTP),
which will be instrumental in stepping up production. We like the story for its
potential, imminent and rapid production growth, favourable fiscal terms, potential
reserves upgrade and scope for further upside from gas monetisation.
KMG EP’s $4.1bn cash pile and share buyback programme position it defensively in
the current market environment. We assign a HOLD rating to the stock on a relative
valuation basis, as we believe it offers the least upside potential in our coverage
universe. We are concerned about the operational challenges KMG EP faces as its
mature asset is deteriorating faster than management had expected, while
experiencing very high cost inflation. Slow progression with M&A and exploration
has disappointed investors in the past. Accordingly, we believe progress on the
MMG acquisition (on favourable terms) and a more aggressive exploration
campaign would reward the stock. KMG EP screens well on our estimates, with a
free cash flow yield of 9.4% and a current dividend yield of 5.6%.
Valuation
At current levels, ZKM looks very cheap to us given its growth momentum, trading at
2012E P/E of 4.3x, 2012E P/CF of 2.3x and 2012E EV/EBITDA of 2.9x – suggesting
respective discounts to our target multiples of 43%, 42% and 37%.DGO trades at
2012E P/CF of 3.8x, 2012E P/E of 6.0x and 2012E EV/EBITDA of 2.3x, which
suggests a discount to our target multiple of 31%, 25% and 38%, respectively. KMG
EP is trading at 2012E P/E of 4x, which is in line with its Russian peers, on our
numbers.
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Who’s who in Central Asia
KMG EP is the largest listed Kazakh upstream company producing oil and gas
onshore Kazakhstan, accounting for 17% of production and 5.5% of the country’s
reserves base. Its core strategy has been to develop its core, mature fields, and
manage production declines through active drilling and an intensive workover
programme. For the past few years, KMG EP has been growing largely by
consolidating onshore producing assets, as well as adding exploration assets to its
portfolio. It benefits from special rights for onshore assets, including pre-emption
rights for any oil asset transaction and right-of-first-refusal for new licences. A $4bn
net cash balance, coupled with substantial generation of free cash, supports further
reserves growth through M&A and acquisition of new exploration blocks.
ZKM, the second-largest listed Kazakh upstream player, is focused on the
development and appraisal of its core field, Chinarevskoye, located onshore
Kazakhstan close to the Russian border and major pipeline infrastructure. ZKM is on
the path to delivering exceptional production growth from last reported levels of
20kboepd targeting to reach 48kboepd by end of this year and further step up to
100kboepd-plus in 2015 – contingent on building a third train at its gas treatment
facility. Possible reserves account for half the company’s total reserves base, and
there is significant potential to transfer a proportion of these reserves to probable as
a result of planned appraisal activities, fostering further growth.
DGO is a Turkmenistan-based oil producer developing the Lam and Zhdanov fields
offshore Turkmenistan under a single production-sharing agreement (PSA), the
Cheleken contract. We regard DGO as a growth story, with a 15% oil production
CAGR 2012-2015E to untap its 899mmboe reserves potential. The company is on
track to reach 100kboepd of oil production in the next five years, from the current
level of 60kboepd. We see further upside potential in the monetisation of its gas
reserves and resources base. A cash balance of $1.5bn leaves DGO comfortably
positioned to pursue M&A opportunities outside Turkmenistan. We would also see
DGO itself as a compelling M&A candidate.
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DGO and ZKM are fuelled by production growth; KMG EP manages declining
production with a focus on inorganic growth
ZKM and DGO are both growth E&Ps, which we believe are set to deliver
exceptional organic production growth, with 43% and 15% respective CAGRs (23%
if we include commercialisation of associated gas) over the next three years –
targeting to reach 100kboepd by 2015.
Figure 1: Production CAGR 2012-2015E
50%
40%
30%
20%
43%
10%
8% (gas)
15% (oil)
0%
Zhaikmunai
Dragon Oil
Source: Renaissance Capital estimates
The expected full commissioning of ZKM’s GTF by end-October should allow it to
ramp up production to 48kboepd, from the last reported level of 20kboepd. Under
the second phase of the GTF, the company plans to build a third gas treatment unit
with capacity to treat an additional 2.5bcm pa. Completion of the second phase will
allow ZKM to reach its technical production potential of 100kboepd-plus by 2015, we
estimate.
DGO has been growing its oil production more steadily than ZKM, mainly due to the
lower share of associated gas in its production mix and the fact that flaring is
permitted in Turkmenistan. We expect DGO to continuously drill, on average, 10-12
wells per year to realise its sizeable reserves base. The company is currently in
discussions with the Turkmenistan government on the options for monetisation of
gas that is currently being flared. Initially, the company aims to sell c. 100mmscfd of
unprocessed gas into the Turkmen system. Subsequently, it plans to complete the
GTP by 2014, which will allow it to ramp up gas production to the 200mmscfd level –
a 60% increase on current production levels.
KMG EP has inherited a mature asset base, comprising Uzen and Emba, and has
been focused on managing declining production through active drilling and an
intense workover programme. In 2010, KMG EP’s producing wellstock comprised
5,884 wells and new wells drilled amounted to 215. At the consolidated level, the
company has grown production through inorganic means, by consolidating onshore
assets. On 2010 numbers, the KMG’s share in three associates accounted for 35%
of total production of 270kboepd. This year, production performance has been
unimpressive, due to unexpected industrial action causing a 6% production loss.
The long-awaited completion of its acquisition of 50% of MMG assets (MMG
currently produces around 110kboepd) could potentially add an incremental 20% to
the company’s total consolidated production, on our estimates.
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Figure 2: Reserves and resources at YE10, mmboe
2P
Possible+Contingent
3,000
2,500
436
2,000
436
1,500
1,000
500
559
539
233
1707
2165
899
0
ZKM
DGO
KMG
KMG incl associates
We see no transformational near-term upside potential from exploration activity for
any of the three stocks. Among the three, ZKM has the highest portion of possible
reserves, accounting for almost half its 3P reserves base, and a proportion of these
reserves could be transferred to probable as a result of planned appraisal activities.
In addition, over the past two years, the company has focused on delivering the GTP
in order to unlock production potential. In our view, a further increase in probable
reserves through water injection techniques is the most likely outcome in the nearest
future.
Currently, ZKM is mainly focused on the development drilling of production wells in
areas of proven and probable reserves, therefore we do not expect any possible
reserves to be transferred in the short term; rather, we expect 2H12/2013 to see this
medium-term catalyst for the stock.
We see medium-term upside potential for DGO in the upgrade of contingent gas
resources of 1.4tcf (233mmboe) into reserves, which is contingent on negotiating a
gas sales price with Turkmenistan and the construction of a GTP. Once the GTP is
operational, the company will be able to process raw gas to various export
destinations and strip out condensate, hence improving realisations from the
produced hydrocarbon barrel.
KMG EP’s story has, historically, centred on developing its existing 2P reserves
base. However (and although more slowly), the company is increasingly focusing on
exploration drilling as well as screening for more acquisitions of exploration blocks.
We estimate the risked P50 number for all the exploration blocks at around
200mmboe, which represents less than 10% of the company’s total risked
resources. Although we do not view exploration upside of its current portfolio as
transformational for the company, we appreciate the focus on exploration is
increasing.
The Central Asian oil universe shows attractive barrel economics,
underpinned by a favourable tax regime. DGO produces the most profitable
barrel
In this analysis, we dissect a hydrocarbon barrel to compare the underlying
profitability of the selected E&Ps in the emerging markets space.
6
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To clarify the methodology underpinning Figures 5-8 under Discount to Brent, we
look at the total hydrocarbon barrel produced: we have included realisation
expenses, i.e. transportation costs, the quality differential and the difference
between Brent and the realised gas price. Under Oil taxes, we have included export
taxes and mineral extraction tax. In the case of PSA, which is relevant to ZKM and
DGO, oil taxes is the difference between entitlement barrel and working interest
barrel plus royalties. For the PSA models we have looked at future five-year average
payments to the state given the sliding scale of the regime. For KMG EP, we show
economics for a weighted barrel, assuming 80% of the produced crude is exported
and 20% sold domestically.
Figure 3: Operating cash flow at $80/bbl
Ops cashflow
80
60
1
Income tax
11
20
Opex&GA
23
15
5
4
31
24
Dragon Oil
Ops cashflow
120
100
46
80
54
3
18
18
KMG EP
Discount to Brent
8
5
7
5
18
0
Afren
Oil taxes
18
33
35
40
Figure 4: Operating cash flow at $100/bbl
Zhaikmunai Russian E&P
1
11
20
Opex&GA
45
15
5
6
41
33
0
Afren
Oil taxes
30
Discount to Brent
8
22
43
60
40
6
1
11
Income tax
55
71
18
5
6
7
7
24
24
62
13
Dragon Oil Kazmunaigas Zhaikmunai Russian E&P
EP
DGO generates the highest operating cash flow per barrel, because it has the lowest
lifting costs, G&A and realisation expenses of the three (despite relatively high
transportation costs, the company exports all its crude oil), which are offset by
higher taxes.
ZKM generates almost the same operating cash flows as KMG EP, due to its
attractive fiscal regime and low opex, offset by higher realisation costs (discount to
Brent) – the latter reflecting relatively low gas prices accounting for 40% of the
production mix next year which we assume is sold at $80mcm ($13.3/boe). Taking a
conservative stance, for ZKM’s oil taxation we have included average profit oil for
the next five years, as the taxes are applied on a sliding scale depending on
production levels.
KMG EP has a balanced distribution of realisation expenses, operating costs and oil
taxes relative to its Central Asian peers. We note that it has among the highest perbarrel operating expenditures, reflecting its mature oil assets with high watercuts.
7
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Figure 5: Sensitivity of operating cash flow $/bbl (Y-axis) to Brent $/bbl (X-axis)
Russian upstream
Dragon oil
Zhaikmunai
6 October 2011
KMG EP weighted
40
30
20
10
0
60
70
80
90
100
110
120
All three Central Asian companies differ in terms of product mix, cost structure and
fiscal regime, but all have relatively high transportation costs compared with their
African and Russian peers, due to their landlocked locations; however, they all
operate under favourable tax regimes. KMG EP and ZKM barrels are the most
sensitive to oil price changes. ZKM’s oil taxation is a function of production only
which allows the company to capture the greatest upside from changes in the oil
price.
Figure 6: Sensitivity of operating cash flow to $10/bbl change in oil price
Oil price
$70/bbl
$80/bbl
$90/bbl
$100/bbl
Brent
17%
14%
13%
11%
Russian E&P
12%
11%
10%
9%
DGO
14%
12%
11%
9%
ZKM
56%
24%
19%
16%
KMG EP
37%
28%
23%
15%
$110/bbl
10%
8%
9%
14%
12%
$120/bbl
9%
8%
8%
12%
12%
As Figures 9-10 illustrate, DGO still generates the highest cash flow per
produced barrel among its Central Asian peers and Russian E&Ps.
When it comes to drilling costs, we are unsurprised that DGO spends only 20%
more on per-barrel drilling capex vs than KMG EP, although it drills only 12 wells
compared with KMG’s 215. It costs almost 10x as much to drill a well offshore
Turkmenistan than it does to do so in a mature basin onshore Kazakhstan.
However, we note that DGO’s new wells, on average, deliver flow rates of 2,500
boepd compared with 30 boepd at KMG EP’s producing wellstock mature fields.
Given that both DGO and ZKM will have to invest a sizeable amount (beyond
drilling) in infrastructure, we expect further growth, at the net cash flow level to be
unlocked post-infrastructure spend (see Figures 11-12). DGO is in line with KMG
EP, generating higher free cash flow than ZKM. For ZKM and DGO, we pencil-in
an estimated average infrastructure spend for the next three years (see page 3979). For more detailed investment dynamics please refer to the company pages.
8
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Figure 7: Free cash flow before infrastructure capex @ $80/bbl
Free cashflow
Figure 8: Free cash flow before infrastructure capex @ $100/bbl
Drilling capex
Free cashflow
40
30
12
30
12
20
12
19
12
0
Afren
Dragon Oil
10
9
8
9
12
20
7
4
KMG EP Zhaikmunai
10
29
21
Afren
Russian
E&P
Figure 9: Normalised free cash flow @ $80/bbl
Free cashflow
Drilling Capex
Infrastructure capex
Dragon Oil
Free cashflow
25
30
8
12
Dragon Oil
KMG EP Zhaikmunai
Development capex
12
Russian
E&P
9
5
1
0
Zhaikmunai
8
15
9
10
0
7
6
7
20
5
15
25
7
5
14
Figure 10: Normalised free cash flow @ $100/bbl
35
10
9
30
15
10
0
20
Drilling Capex
50
40
10
6 October 2011
14
7
Dragon Oil
Zhaikmunai
When we take a look at our free cash flow projections taking into consideration
phasing of the planned investment programme, we observe the following:

DGO’s free cash flow per barrel will decline for the next few years, we
believe, mainly due to infrastructure investment in the GTP: once the plant
is operational, we expect the free cash flow/barrel trend to reverse.

KMG EP’s free cash flow is on a declining trend, mainly due to high cost
inflation; nevertheless, its cash-generation ability is still solid: if we take into
account dividends paid by associates, our free cash flow/barrel increases
by an average of $5/bbl.

We expect ZKM’s free cash flow to stay relatively low for the next few
years, to fund the infrastructure capex targeted for increasing capacity at its
GTP. Once the majority of the capex has been completed in 2013, we
expect free cash flow dynamics to increase.
9
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Figure 11: Free cash flow per boe
KMG EP
20
18
16
14
12
10
8
6
4
2
0
KMG EP incl div from assoc
18
19
16
13
9
7
Zhaikmunai
19
17
13
13
Dragon Oil
12
8
8
7
6
13
11
4
3
2011
2012
2013
2014
2015

On our estimates, the margin picture reinforces the view that DGO is the
most profitable company in the Central Asian oil universe.

We expect KMG EP’s earning margins to deteriorate as a result of
inflationary pressures.

We expect ZKM’s high margins to fall over time, once costs are recovered
under its PSA, and the company starts paying a higher share of profit oil as
production ramps up.
Figure 12: EBITDA margins
100%
KMG EP
KMG EP incl associates
90%
90%
87%
80%
60%
40%
Figure 13: Net income margins
72%
53%
46%
36%
67%
Dragon Oil
Zhaikmunai
89%
89%
86%
67%
KMG EP
30%
42%
33%
41%
32%
Zhaikmunai
80%
62%
60%
60%
41%
Dragon Oil
100%
39%
31%
37%
30%
40%
50%
39%
55%
52%
31% 31% 32%
38%
52%
32%
38%
49%
47%
31% 34% 29%
22%
20%
20%
13%
0%
0%
2010
2011
2012
2013
2014
2015
2010
2011
2012
2013
2014
2015
10
Renaissance Capital
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6 October 2011
We see significant potential for dividend growth at DGO. KMG EP has potential for
growth, but cash has been set aside for acquisitions. We do not expect dividends for
ZKM shareholders in the near term.
For KMG EP, and to a lesser degree DGO, free cash flow generation translates into
decent dividend distributions to shareholders. Solid cash flow generation, backed up
with a $1.5bn cash balance, ensures growth potential for dividend payouts by DGO
in the future.
We do not expect ZKM to pay dividends near term, as the company needs to fund
an intensive drilling programme, underpinning its ambitious growth plan; invest
about $360-400mn in further upgrading capacity at its GTP; and pay out principal on
a $450mn bond maturing in 2015.
Figure 14: 2012E FCF and dividend yields
14%
FCF yield
Dividend yield
14.1%
12%
10%
10.9%
9.4%
8%
5.6%
6%
5.6%
4%
2%
2.2%
0%
Dragon
KMG EP
Central Asian E&Ps benefit from robust balance sheets

Under current market conditions, having a robust balance sheet is
paramount. Both KMG EP and DGO benefit from large cash balances,
making the stocks defensive.

Among the three companies, ZKM is the only leveraged company of the
three, and its leverage is comfortable. There is no near-term pressure on its
balance sheet, with a bond maturing in 2015, and we expect ZKM to
generate increasing free cash flow from 2013. Moreover, our estimated net
debt/EBITDA ratio is 1.2x and 0.5x for 2011 and 2012, respectively.
11
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Figure 15: Balance sheet, $mn
Cash
NC KMG Bond
Debt
6,000
5,000
4,000
1500
3,000
2,000
3500
1,000
0
1472
-800
139
-450
-1,000
-2,000
KMG EP
Dragon Oil
Zhaikmunai
Compelling valuation: Fundamentally undervalued on reserves, and cheap on
earnings and cash flow multiples
So, what do the reserves and production multiples tell us?
KMG EP looks optically cheap both on 2P reserves and production multiples. The
reality is that the company confronts declining production, rising cost pressures and,
since end-May, industrial action (constraining production), so a certain discount is
justified, in our view.
On the 2P reserves multiple, THE stock screens low and trades on a par with
Tatneft, a Russian producer with mature oil fields. Generally, a low reserves
valuation is typical for mature oil producers with no growth. The economics of KMG
EP’s core asset base are marginal with NPV of around $2/bbl which explains the
discount to reserves multiples.
If we disregard the cash and look at market cap over 2P and production multiples,
the numbers stand at $3.5/bbl and $35/kboepd, respectively; if we strip out the NC
KMG bond from EV, the numbers become $2.6/bbl of 2P reserves and $25/kboepd
of production. It looks to us like the market is discounting both a proportion of the
company’s cash pile and production.
So, what could trigger a change in the market’s perception?
In our view, successful efforts to stabilise production and restore it to pre-industrialaction levels would reward KMG EP stock. From a cash perspective, the longawaited acquisition of MMG by the year-end, and any other acquisitions, on valueaccretive terms, would be supportive for the stock.
While on production multiples both our growth stocks trade in the same range, on
the 2P reserves multiple ZKM trades at a 25% premium to DGO. We think the
premium over DGO is explained by further growth potential of the 2P reserves base
through the conversion of possible reserves. ZKM is making the final steps towards
monetising its gas reserves, while for DGO gas monetisation is yet to be
accomplished, further explaining the reserves valuation gap. Both DGO and ZKM
12
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trade at sizeable discounts to African peers on reserves multiples – 3-4x lower than
the average African multiple and 7x less than Afren. This is despite average
reserves for the Central Asian universe being calculated over 30 years, vs seven
years for the African peers.
Figure 16: EV/2P, $/bbl
Figure 17: EV/kboepd
60
68.2
0
Exillon Energy
Kazmunaigas EP
2.6
1.6
Tatneft
1.3
Kazmunaigas EP
1.1
0
1
2
3
4
5
6
7
Figure 18: 2P as a % of risked Reserves (Y-axis) vs EV/2P $/bbl
Tullow
Dragon Oil
25
38
10
10
3.0
25
34
Dragon Oil
Zhaikmunai
25
33
KMG EP (Mcap/kboe)
20
2.8
Tatneft
Alliance Oil
21
30
Zhaikmunai
30
3.9
JKX
Petrom
27
Exillon Energy
40
4.2
Afren
21.6
JKX
Alliance Oil
Afren
50
50
Petrom
Tullow
Figure 19: Operating cash flow $/bbl (Y-axis) vs. EV/2P $/bbl (X-axis)
110%
40
Tatneft
100%
Petrom
90%
Kazmunaiga
z EP
80%
Dragon Oil
Alliance Oil
Zhaikmunai
Exillon
Energy
50%
Petrom
Zhaikmunai
KMG EP
70%
60%
Dragon Oil
30
Afren 13%,
$18.7/bbl
Tullow 9%,
JKX $68/bbl
20
Exillon
10
40%
JKX
Alliance Oil
Tatneft
0
1
2
3
4
5
6
1
2
3
4
5
6
13
Renaissance Capital
Show me the munai
6 October 2011
We note that:

Historical multiples confirm DGO’s defensive nature.

ZKM has been the most volatile stock in our universe.
Interestingly, in terms of EV/EBITDA multiples, ZKM and KMG EP have been trading
very closely, despite differences in fiscal regimes, growth profiles and product mix:
we believe this could be explained by similar levels of EBITDA/boe. In our view,
ZKM’s EV/EBITDA deserves a premium to KMG EP, due to its growth.
Figure 20: Historical P/E 12-month forward
KMG
ZKM
Figure 21: Historical EV/EBITDA multiple 12-month forward
DGO
KMG
15
14
13
12
11
10
9
8
7
6
5
4
3
2
DGO
ZKM
8
7
6
5
4
3
2
1
0
Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11
Source: Bloomberg
Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11
Source: Bloomberg
14
Renaissance Capital
Show me the munai
6 October 2011
Valuation tables
Figure 22: Oil and gas valuations
Novatek
Gazprom
Rosneft
LUKOIL
Russian majors average
Gazpromneft
TNK-BP
Surgut
Bashneft
Kazmunaigaz
Zhaikmunai
Dragon
FSU integrated average
MOL
OMV
Petrom
Central European integrated average
BP
Chevron
ConocoPhillips
ENI
ExxonMobil
Repsol YPF
Royal Dutch Shell
Statoil
Total
Global integrated average
CNOOC
ONGC
Petrobras
Petrochina
Sinopec
Emerging integrated average
4-Oct-11
Price, $
102.0
8.7
5.3
46.9
MktCap
$mn
31,122
103,039
56,117
40,376
Net
debt
2,030
28,645
19,431
8,826
35,297
144,003
69,724
47,587
16.1
2.4
0.8
39.7
14.0
7.2
7.1
15,551
35,918
28,224
6,756
5,899
1,330
3,669
5,490
2,448
(483)
2,846
(4,100)
311
(1,472)
22,606
37,815
19,190
11,534
1,799
1,641
2,197
66.7
29.6
0.1
708,336
9,607
4,906
4,319
7,391
2,556
14,246
19,369
7,628
5.8
89.9
61.0
17.3
71.2
25.6
29.8
21.1
43.1
111,981
183,233
85,498
71,358
354,108
32,039
193,368
68,774
103,796
20,583
(2,584)
14,138
35,064
7,189
17,000
30,888
15,015
21,315
139,867
181,974
101,073
115,747
366,839
58,035
219,336
75,944
133,339
1.6
5.3
10.8
1.2
1.0
65,081
45,684
136,701
275,156
92,252
(945)
959
28,509
29,852
57,704
42,914
183,038
317,703
132,690
EV
2011E
11.8
2.4
3.3
2.5
5.0
2.7
2.9
1.8
3.5
1.5
6.3
2.2
2.5
4.8
3.5
3.3
3.9
3.0
3.0
3.3
3.1
4.1
4.9
3.5
1.8
3.1
3.3
3.0
3.7
5.0
5.9
4.7
4.5
EV/EBITDA
2012E
2013E
10.5
8.7
2.3
2.3
3.5
3.8
2.5
2.6
4.7
4.4
2.8
3.6
3.1
3.3
2.0
2.6
3.8
3.8
1.2
0.2
2.9
2.8
2.3
2.1
2.6
2.7
4.4
4.3
3.1
2.9
3.2
3.2
3.6
3.5
3.0
2.9
3.0
3.1
3.3
3.3
2.8
2.6
3.9
3.8
4.3
4.0
3.3
3.2
1.8
1.7
3.0
3.0
3.2
3.1
3.0
2.8
3.6
3.4
4.6
4.3
5.5
5.2
4.4
4.2
4.2
4.0
2011E
14.9
2.5
4.4
3.5
6.3
2.8
4.2
0.5
4.6
3.6
11.5
6.4
3.1
5.8
5.9
4.6
5.4
5.1
6.7
7.6
6.4
8.5
10.5
7.2
7.6
6.2
7.3
6.0
8.5
7.0
9.0
7.0
7.5
P/E
2012E
13.4
2.4
4.7
3.7
6.1
2.6
4.8
0.5
5.3
3.6
4.3
6.0
3.4
5.6
5.2
4.6
5.1
5.1
6.9
7.3
5.9
8.3
8.5
6.6
6.9
6.1
6.9
6.2
8.4
6.7
8.4
6.5
7.3
2013E
10.6
2.4
4.9
3.7
5.4
5.2
7.2
5.3
3.6
4.1
6.1
5.3
5.2
4.8
4.1
4.7
4.9
7.1
7.2
5.4
7.9
7.8
6.4
6.5
5.9
6.6
6.1
7.9
6.6
8.1
6.3
7.0
P/CF
2012
11.9
2.2
3.3
2.6
5.0
2.2
3.8
3.4
3.9
4.2
2.3
3.8
3.5
2.5
2.0
2.3
2.3
3.3
4.6
4.2
2.5
5.8
3.2
4.1
3.5
3.5
3.9
4.1
4.9
4.0
4.2
3.1
4.1
2011E
2.1%
2.4%
2.3%
4.8%
2.9%
7.6%
15.6%
3.3%
14.0%
6.5%
n/a
2.4%
9.4%
4.7%
4.6%
6.9%
5.4%
4.8%
3.4%
4.2%
7.7%
2.6%
5.7%
5.6%
5.2%
7.0%
5%
5.8%
4.4%
5.0%
5.0%
3.6%
4.8%
Dividend yield
2012E
2.6%
2.5%
2.6%
5.2%
3.2%
8.6%
14.1%
2.9%
13.2%
5.6%
n/a
2.2%
8.9%
5.9%
4.9%
6.9%
5.9%
5.1%
3.6%
4.4%
7.9%
2.7%
6.2%
5.8%
5.5%
7.1%
5%
5.6%
4.6%
5.4%
5.3%
3.9%
5.0%
2013E
3.3%
3.0%
3.2%
5.6%
3.8%
13.4%
3.0%
12.5%
5.6%
n/a
2.3%
8.6%
6.9%
5.4%
9.2%
7.2%
5.5%
3.7%
4.7%
8.1%
2.8%
6.5%
6.0%
5.8%
7.4%
6%
6.0%
4.2%
4.0%
5.6%
4.0%
4.8%
Source: Bloomberg, Renaissance Capital estimates
15
Show me the munai
6 October 2011
The companies
Renaissance Capital
16
Renaissance Capital
Show me the munai
6 October 2011
17
Oil and gas
Kazakhstan
Equity Research
6 October 2011
Farid Abasov
+44 (207) 367-7983 x8983
[email protected]
Ildar Davletshin
+7 (495) 725-5244 x5244
[email protected]
Ivan Kokurin
+7 (495) 725-5247 x5247
[email protected]
ZKM
Crouching tiger

We reinitiate coverage of ZKM with a BUY rating and $14/GDR TP.

Short-term catalyst: Imminent production growth. ZKM has
Report date:
among the greatest production growth potential in its peer group, in our view, with
a 2012-2015E production CAGR of 43%. The long-awaited commissioning of its
GTP by early October will be instrumental to the company unlocking its vast
resource base, and more than doubling its hydrocarbon production to 48 kboepd.
Medium-term catalyst: Reserves upgrade. Possible reserves make

up almost half the company’s 1.1bnboe 3P reserves base, and we expect a
proportion of these reserves to be transferred to probable as result of planned
appraisal work. Taking a conservative approach, we estimate the reserves
upgrade could add a further 30% to our base-case valuation ($5/GDR)
Long-term catalyst: Step up to 100kboepd-plus by 2015. Once

the first phase of the GTP is fully operational, the company plans to proceed with
further expansion of the facility, to 4.2bcm pa, unlocking a further production step–
up.
Gas monetisation could offer more upside. The company expects

6 October 2011
Rating common/pref.
BUY
Target price (comm), $
$14
Target price (pref), $
n/a
Current price (comm), $
7.2
Current price (pref), $
n/a
MktCap, $mn
1,330
EV, $mn
1,641
Reuters
ZKMq.L
Bloomberg
ZKM LI Equity
ADRs/GDRs since
n/a
ADRs/GDRs per common share
n/a
Common shares outstanding, mn
185.00
Change from 52-week high:
-44.9%
Date of 52-week high:
18/01/2011
Change from 52-week low:
1.1%
Date of 52-week low:
12/09/2011
Web:
www.zhaikmunai.com
Free float
32.3%
Major shareholder
Claremont
with shareholding
40.7%
Average daily traded volume in $mn
0.7
Share price performance
over the last
1 month
-8.54%
3 months
-24.24%
12 months
-6.25%
gas to account for almost half its production by 2015, and we see gas
commercialisation as an important driver of future earnings dynamics.
A compelling valuation. ZKM’s highly favourable fiscal terms leave it

levered to the oil price. At current levels, the stock looks very cheap to us given its
growth momentum, trading at 2012E P/E of 4.3x, 2012E P/CF of 2.3x and 2012E
EV/EBITDA of 2.9x – suggesting respective discounts to our target multiples of
43%, 42% and 37%.
Summary valuation and financials, $mn
Revenue
EBITDA
2010
178
95
2011
365
264
2012
859
575
2013
890
598
Net income
23
117
310
324
EPS
0.12
0.63
1.66
1.74
EBITDA margin
53%
72%
67%
67%
P/E
-11.5
4.3
4.1
EV/EBITDA
-6.3
2.9
2.8
P/CF
-5.1
2.3
2.2
$
ZKMq.L
RENCASIA
160
140
120
100
80
60
40
20
0
14
12
10
8
6
4
2
0
Sep Oct Nov Dec Jan Feb Mar Apr May Jun
Jul Aug Sep
Source: Bloomberg
Petro Matad Ltd
Tethys Petroleum
Roxi Petroleum
KazMunaiGaz E&P
Zhaikmunai
Dragon Oil
BMB Munai
Max Petroleum
RENCASIA
%
-80
-70
-60
-50
-40
-30
-20
-10
0
10
20
Source: Bloomberg
Renaissance Capital
Zhaikmunai
6 October 2011
Investment summary
Short-term catalyst: Imminent production growth
In the emerging markets E&P space, we believe ZKM offers among the greatest
production growth potential, with a three-year CAGR 2012-2015E of 43%. The longawaited full commissioning of the GTP by early October will be instrumental for the
company to unlock its deep resource potential and step up hydrocarbon production
to 48kboepd from the current level of 15kboepd.
Medium-term catalyst: Reserves upgrade
ZKM has a very high proportion of possible reserves, accounting for almost half its
3P reserves base, and a proportion of these reserves could be transferred to
probable as a result of planned appraisal work. In our view, further upside in
probable reserves is possible through improved recovery rates as a result of water
injection techniques. Taking a conservative stance, we do not incorporate possible
reserves, which are valued at $5/GDR in our base-case valuation, suggesting a
further 30% upside to our NAV.
Long-term catalyst: Step up to 100kboepd of production by 2015E
Once the first phase of the GTP is fully operational, the company plans to proceed
with further expansion of the plant’s capacity, to 2.5bcm pa by 2015, with the
addition of a third treatment unit. The completion of the second phase will allow ZKM
to reach technical production potential of 100kboepd-plus by 2015.
Gas monetisation could offer further upside potential
Gas accounts for 45% of ZKM’s 2P reserves base and will account for c. 50% of
total production by 2015E, so gas commercialization is an important driver of future
earning dynamics. Taking a conservative stance, we assume flat $80/mcm net
realisation so any incremental $10/mcm move would increase EBITDA by 2%, on
our estimates.
Favourable fiscal terms
Among its Central Asian peers, ZKM has the most favourable fiscal terms, making it
the company more highly leveraged than its domestic peers to oil price changes. We
believe an attractive fiscal regime will help its to maintain solid free cash flow
generation, despite relatively low gas realisations ($80/mcm translates into only
$13/boe).
Compelling valuation
The company trades at a 95% discount to our $14/GDR target price. Given its
growth momentum, the stock screens cheaply on our assigned EV/EBITDA and
P/CF multiples, trading at 2012E P/E of 4.3x, 2012E P/CF of 2.3x and 2012E of
EV/EBITDA 2.9 which suggest discounts to our target multiples of 43%, 42% and
37%, respectively.
19
Renaissance Capital
Zhaikmunai
6 October 2011
Risks and sensitivities
The key risks to our investment case are:
Execution risk
The GTP is one of the company’s key assets, allowing ZKM to commence
production of gas and LPG, strip out condensate and increase oil production. The
company is progressing with bringing the GTP into full operation, and has already
started commissioning an amine unit which will enable it to treat acid gas. ZKM has
faced numerous delays in launching the GTP, and we think any further delays could
negatively affect its share price.
Change in fiscal terms
ZKM operates under a PSA. We note that a number of state officials in Kazakhstan
have spoken out against tax stabilisation clauses, proposing that all producers
operate under a national tax regime. In our view, the risk of a taxation change is low,
as the PSA is grandfathered and there are no precedents for abandoning or
cancelling PSAs in Kazakhstan. However, if the PSA were abandoned from 2013,
this would reduce our valuation by 16%; if such a change happened at peak
production rates, the negative impact on our valuation would be 10-12%.
Commodity price
Our long-term oil price assumption is $100/bbl and our gas price assumption is
$80/mcm. If market expectations on the long-term oil price differ from our
assumption, the share price could deviate from our target. (See sensitivities to the oil
price assumption below.) The company has not disclosed the gas price, but we have
taken a conservative stance in our assumption.
FX risk
We generally view FX risk low, as all the company’s revenues are in dollars, as is its
financing and capital investment programme. Only 15-20% of costs are in tenge.
Political risk
ZKM has very strong political connections in Kazakhstan. According to The
Telegraph, one of the shareholders of ZKM, KSS (27%) is owned by Timur Kulibaev,
who is the son-in-law of Kazakhstan’s President Nursultan Nazarbayev, and is
currently chairman of the management board at the Samruk-Kazyna National
Welfare Fund.
20
Renaissance Capital
Zhaikmunai
6 October 2011
Figure 25: DCF-based target-price ($/GDR) sensitivity to oil price ($/bbl) and gas price changes ($/mcm)
80
90
100
110
120
80
12
15
18
21
24
140
14
17
20
23
26
200
17
20
23
26
29
260
19
22
25
28
31
320
22
25
28
31
34
Figure 26: DCF-based target-price ($/GDR) sensitivity to oil price ($/bbl) and WACC changes
80
90
100
110
11%
13
17
20
23
12%
12
16
19
22
13%
12
15
18
21
14%
11
14
17
19
15%
10
13
16
18
120
27
25
24
22
21
21
Renaissance Capital
Zhaikmunai
6 October 2011
Valuation
Our 12-month price target for ZKM shares is $14/GDR, implying 95% upside
potential to the current share price.
For our base-case valuation we use a blend of NAV (50%) with a multiples-based
approach (50%). This methodology helps us to take into account long-term growth
potential as well as sufficiently weighting more visible 2012E earnings dynamics.
Taking a conservative stance, we do not incorporate possible reserves that we value
as $5 per GDR in our base-case valuation, suggesting a further 27% upside
potential to our NAV.
Figure 27: ZKM DCF-based valuation
Target price , USD/GDR
30
25
3
20
5
15
25
10
18
5
0
Base case
Possible reserves
Gas price upside
($140/mcm)
Bull Case
For the multiples-based approach, we apply the lower range of the historical
average multiples for the stock and make certain adjustments for a relative peer
valuation. We regard DGO as ZKM’s closest peer operating in the same Central
Asian region, sharing a similar growth profile and having exposure to gas
monetisation.
We base our NAV valuation on a DCF approach on the following assumptions:

A long-term Brent assumption of $100/bbl from 2012 onwards

For oil sales: a $5/bbl discount to Brent, $11/bbl transportation cost

A gas price assumption of $80/mcm flat 2012 onwards

LPG at a $10/bbl discount to Brent, $30/bbl transportation cost

A WACC of 13%
22
Renaissance Capital
Figure 28: ZKM – NAV valuation
2P reserves, mmboe
Produced reserves, mmboe
NPV per boe of production, $/bbl
Remaining reserves, $/bbl
EV of remaining reserves, $mn
Net debt end 2011, $mn
Equity value, $mn
Equity value per share, $/GDR
Zhaikmunai
6 October 2011
539
437
7.9
102
146
332
3275
18
Figure 29: ZKM – multiples-based valuation
Target P/CF multiple
2012 op. Cash flow, $mn
Implied equity value, $mn
Target P/E multiple
2012E net income, $mn
Target EV/EBITDA multiple
2012 EBITDA, $mn
Implied EV, $mn
Net debt end 2011, $mn
Equity value, $mn
5.5
442
2449
13
7.5
310
2312
13
4.6
575
2643
332
2311
12
23
Renaissance Capital
Zhaikmunai
6 October 2011
Figure 30: ZKM ‘s assets and infrastructure
Source: Company
History
In May 1997, ZKM was granted an exploration and production licence for the
Chinarevskoye field, in the northern part of the oil-rich Pre-Caspian Basin. In
October 1997, ZKM entered into an associated PSA with Kazakhstan. The PSA
implies stabilised taxation, which is not supposed to change when the country’s
taxation regime changes, however it is subject to amendments.
In March 2008, ZKM was listed on the LSE, raising $100mn for 9.1% of the total
shares outstanding. The proceeds were invested in infrastructure and drilling. A test
crude production had started long before the IPO, however. The company began its
first test crude oil production in October 2000, and switched to commercial
production of crude oil on 1 January 2007. For the past several years, production
has been capped at around 7,800 boepd, dependent on completion of the first line of
the GTP. As it stands, in addition to 7,000 boepd of oil production, test volumes
going through the plant are around 13kboepd.
ZKM aims to maximise the conversion of its existing probable reserves into proven
reserves, and its possible reserves into probable reserves, and to increase longterm production potential. The concentration of reserves in a small area on the
Chinarevskoye field makes it cheap to sustain exploration activity (3D seismic,
exploration drilling).
24
Renaissance Capital
Zhaikmunai
6 October 2011
Ownership
As noted, ZKM undertook an IPO in March 2008 and a new share offering in July
2009. The total number of shares outstanding is 185mn, with management share
options for a further 2.5mn shares, with an exercise price equal to that at the IPO
(around $10). The fully diluted number of shares used for our valuation is 187.5mn.
The ultimate majority shareholder, Claremont Holdings Limited, which is controlled
by ZKM chairman Frank Monstrey, owns 40.7%. KazStroyService Global BV owns a
27% stake in the company which it purchased for $4.00/GDR at the end of 2009.
The remaining 32.4% is in free float.
Figure 31: Ownership structure
Free float, 32.30%
Claremont Holdings,
40.70%
Kazstroyservice,
27%
KazStroyService is a leading engineering procurement and construction company in
the Kazakh oil and gas sector, with 5,000 employees. It has completed more than
100 construction projects in Kazakhstan and India, partnered Agip KCO,
Karachaganak Petroleum Operations BV, Kazgermunai, KazTransOil,
KazTransGas, Intergaz Central Asia, Exploration & Production KazMunayGas,
Kazakhstan – China Pipeline, Kazakhoil Aktobe and Almaty Power Consolidated.
25
Renaissance Capital
Zhaikmunai
6 October 2011
Assets review
Introduction
ZKM’s field and licence area is the Chinarevskoye field. The field, which is
approximately 274 km2 in size, is located in the province of Batys Kazakhstan, near
the Kazakh-Russian border, and close to several major pipelines. The field lies in
the northern part of the oil-rich Pre-Caspian basin near the Russian-Kazakh border
and close to the international rail network, as well as main oil and gas pipelines.
As of 1H11, the company’s operational facilities consisted of the following:

Thirty existing wells, of which 12 wells were producing from the Tournaisian
reservoir and two water injection wells.

A GTP with 1.7bcm of annual capacity.

An oil processing facility with 400,000 tpa of capacity.

A 120 km oil and condensate pipeline.

A rail-loading terminal in Rostochi.

A 17 km gas pipeline from the field to the Orenburg-Novopskov pipeline.

A gas-powered electricity generation system.

Warehouse facilities and an employee field camp.
Since the current management took control in 2004, the company has invested $1bn
in drilling and infrastructure. We estimate that over the next five years it plans to
invest around $1.1bn, which includes $400mn on infrastructure and $700mn on
drilling. Over the life of the entire project we expect an investment of $2.1bn
A high-quality asset base
Oil and gas operations in the Chinarevskoye field started during Soviet times with
the drilling of nine wells, proving that the Chinarevskoye field is a multi-formation
structure. The first discovery was made at the Biski-Afoninski reservoir in 1991,
followed by discovery in the Tournasian reservoir in 1992. In 1997, ZKM was
granted a subsoil license and signed a PSA. Between 2000 and 2002, the company
reactivated three of the wells that were drilled during Soviet times with the rest
plugged and abandoned for technical and geological reasons. In 2003, a Givetian
accumulation was discovered and in 2004 the Lower Permian reservoir was
successfully tested. In 2007, ZKM discovered oil in the Bashkirian formation.
Currently, ZKM’s licence area covers the entire Chinarevskoye field and comprises
seven oil and gas horizons. The company has tested hydrocarbons at significant
rates from:

Lower Permian horizons at depths of 2,700 metres to 2,900 metres,
represented by limestone and dolomitic limestone.
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Renaissance Capital
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6 October 2011

The Lower Carboniferous Tournaisian formation represented by
limestone at a depth of approximately 4,200 metres with a gross thickness
of about 200 metres.

The Middle Devonian Givetian (Mullinski and Ardatovsky) horizons at a
depth of approximately 5,000 metres represented by sandstone with
carbonate cement.

The Middle Devonian Biski and Afoninski formations at a depth of
approximately 5,000 metres with a gross thickness of 200 metres and
represented by limestone and dolomitic limestone.
Oil has been found in the Lower Permian, Tournaisian and Givetian Mulinski
reservoirs, while gas condensate has been found in the Tournaisian, Biski and
Afoninski and Givetian Ardatovski reservoirs.
Further exploration upside potential in the mid-term
Despite its relatively small size (just 274 km2), the Chinarevskoye field contains a
number of unexplored accumulations, the presence of which was indicated by the
undertaken exploration activities. Existing comprehensive 3D mapping which covers
the entire Chinarevskoye field allows the company to build on its strong track record
of positioning its wells effectively, thereby increasing the chance of success in
converting possible reserves into probable and probable proved reserves. To date,
there have been no dry wells drilled, and every well the company has drilled since
signing the PSA has proved commercially viable.
A solid track record, a growing reserves base

Figure 35 Illustrates that the company’s track record, having more than
doubled its 2P reserve base in three years from 2004-2008, proves the
quality of its reserves base as well as management’s ability to deliver
organic growth. The first increase in reserves mainly came from the
Tournaisian horizon on the back of increased drilling and improved
geological information. The last major reserves upgrade was in 2008 as a
result of exploration and appraisal efforts. Most recently, as of January
2011, the company slightly increased its 2P reserves (2.2%) compared with
last year’s numbers, as a result of drilling activities.
Figure 32: 2P reserves, mmboe
proved
probable
600
500
400
300
182
200
100
170
0
29
2004
402
389
395
261
135
137
133
140
144
2006
2007
2008
2009
2010
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6 October 2011
Potential transfer of possible reserves into probable
Figure 35 illustrates ZKM’s total reserves base, which comprises 539mn boe of 2P
reserves (of which 44% [235mmboe] is gas, 41% [216mmboe] oil and condensate
and 15% [78mmboe] plant products; and 556mmboe of possible reserves. Possible
reserves account for half the company’s total reserves base and management
believes a proportion of these reserves could be transferred to probable as a result
of planned appraisal activities. Over the past two years, the company has focused
on delivering the GTP, in order to unlock production potential. In 2010, ZKM focused
on drilling activities at production wells in an area of proven and probable reserves;
therefore in the most recent CPR report only 2P reserves were upgraded. Provided
that next year, the company focuses on ramping up and stabilising production and
does not rush into exploration drilling, we expect the potential transfer of possible
reserves at the end of 2012 or early in 2013.
Figure 33: Possible reserves, as of 1 January 2009
Oil/gas condensate,
Horizon
Area
mn bbl
Biski/Afoninski
North
38.1
Biski/Afoninski
West
49.5
Tournaisian
South
14.6
Tournaisian
West
164
Givetian Mullinski
West
9.4
Famennian
South
0.3
Total possible resources
276
LPG,
mn bbl
17.7
23.0
8.6
19
5.7
0.2
74.5
Gas,
bcm
8.13
10.56
3.90
6.15
2.07
0.09
30.89
Total,
mmboe
110
143
49.2
224
28.9
1.1
556.3
Notes: The reserves are estimated under SPE standard.
Source: Ryder Scott reserves and resources report as fo 1 July 2008
Increase of probable reserves through water injection techniques
In our view, a further increase in probable reserves through water injection
techniques is the most likely outcome in the nearest future. ZKM has already started
water injection tests in the Tournaisian reservoir to check the impact on production
levels. At the first stage, improved recovery is expected after all four water injection
wells are operational. So far, the water treatment facilities are completed and three
water injectors have been put into operation. The second phase is envisaged to add
four further wells and is also contingent on receiving additional water use permits,
which the company has yet to apply for.
According to management, there is also significant potential for the company to
upgrade its existing reserves on the back of two factors:

First, a new discovery was made in the Bashkirian horizon and the
Vorobyovski reservoir in 2008 that was not included in Ryder Scott’s
reserve estimation.

Second, management believes the company could improve the expected
by independent reserves auditor recovery factors through application of
water injection techniques that could maintain reservoir pressure. Hence,
ZKM is in position to exceed the conservative recovery factor estimates
stated in the Ryder Scott report of 32.2% of oil in the Tournaisian reservoir
and 16% of oil for the Mulinski reservoir.
Overall, in the medium term, we expect a reserves uplift which should act as a
catalyst for the stock.
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Renaissance Capital
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6 October 2011
Figure 34: ZKM's 3P reserves, mmboe
proved , 144mmboe,
13%
possible,
556mmboe, 51%
probable , 395 mn
boe, 36%
Figure 35: Proven and probable (2P) reserves
Figure 36: Possible reserves, mmboe
Oil and
condensate,
213, 40%
Gas , 206,
37%
Gas, 245,
45%
Crude oil
condensate,
276, 50%
Plant
products, 81
mmboe, 15%
Plant
products, 75,
13%
The GTP is expected to be fully commissioned by early October, boosting
production
ZKM is progressing with bringing the GTP into full operation, and has already started
commissioning the amine unit which will allow it to treat acid gas. The project
envisages two phases. Under the first phase, the company has completed the
construction of two gas treatment units, each with capacity to treat 850 mcm per
annum of associated gas and gas condensate. The plant also contains sweetening
and sulphur recovery units to improve the quality of the gas. A condensate
stabilisation unit with capacity of 800,000 tpa has been built as part of the project. In
addition, ZKM has built an associated gas-fired power plant with output of 15 MW,
feeding the field with electricity. Under the first phase, total peak production is
expected to be 48,000 boepd.
A third train, to treat 2.5 bcm, is planned to be completed in 2014
Under the second phase, the company is considering building a third gas treatment
unit, with capacity to treat 2.5 bcm of gas per year and an additional power plant.
Based on our view, the completion of the second phase will allow ZKM to reach
technical production potential of 100 kboepd-plus in 2015 (see Figure 41).
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Renaissance Capital
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6 October 2011
Commissioning of the first phase of the GTP was an important milestone, as gas
utilisation scheme first of all unlocks production growth and it allows company to
treat the associated gas whereby the current gas flaring permit is effective until the
end of 2011. The company will also take advantage by monetising its gas production
instead of flaring.
ZKM has ambitious production growth targets, and we estimate production
could double, contingent on completion of the third gas treatment unit
According to management guidance, total production will peak at 48,000 boepd by
the year end, compared with average production of 7,752 boepd in 2010. Further
production growth will be conditional on completion of the third gas treatment unit
which will allow ramp-up total hydrocarbon production from 48kboepd to its technical
peak of 120kboepd-plus. We assume these levels could be achieved by the end of
2015 which implies a three-year CAGR (2012-2015E) of 43%.
Figure 37: Renaissance Capital vs CPR production forecast, kboepd
CPR 2P profile (Jan'2011)
Rencap estimates
160
120
80
40
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
In our production estimates, we have used management guidance for the next five
years. To be on a conservative stance for the peak years we have adjusted CPR
production by 10% (please refer to Figure 40). For the crude oil forecast post
plateau we have modelled appropriately for the field’s geology decline rates. For the
gas and LPG production estimates we have used profiles produced by the latest
(January 2011) Ryder Scott CPR adjusting for the delay to the GTP launch and
production ramp-up.
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Renaissance Capital
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Figure 38: 2P Production profile, boepd
Figure 39: 2P production breakdown
Oil&Condensate
140,000
6 October 2011
LPG
Gas
Oil&Condensate
100%
120,000
100,000
80%
80,000
60%
0%
40%
40,000
43% 43% 43% 45%
48% 50%
51% 54% 55%
91%
46% 46% 46% 42% 40%
37% 34% 30%
29%
20%
20,000
LPG
2%
7% 10% 10% 10% 12% 13% 13% 15% 16% 16%
100%
60,000
Gas
0%
2010
2012
2014
2016
2018
2010
2020
2012
2014
2016
2018
2020
ZKM expects the production ramp-up to be achieved by increasing the number of
wells drilled per year, enhancing oil recovery methods, as well as extending the
hydrocarbon production areas of the Chinarevskoye field following the completion of
exploration activities. According to management, the company plans to drill five
more production wells and one appraisal well in 2011 and to drill, on average, 13
wells per year between 2012 and 2014. The average drilling time for the new vertical
wells in the Tournaisian reservoir is approximately three months, and four months
for the Devonian wells.
Figure 40: Drilling schedule
2011E
Tournaisian wells
4
Devonian wells
1
Total
5
2012E
8
8
16
2013E
5
14
19
2014E
7
5
12
2015E
3
5
8
2016E
2017E
8
8
1
1
Source: Company data
ZKM also plans to drill a number of horizontal wells, which are 30% more expensive
than vertical wells due to the application of more advanced technologies. At the
same time, horizontal wells provide a much higher daily flow rate, due to a larger
contact with the oil-bearing layer. Although, horizontal wells are more expensive
than the usual vertical wells, they former typically result in decrease in the total
number of wells, achieving not only higher daily flow rates but also cost efficiency.
ZKM gets advantageous netbacks for the exported oil barrel, despite high
transportation costs
The company transports produced crude oil through its self-built 120 km oil pipeline
from the Chinarevskoye field to its Rostochi terminal near Uralsk and from there
through its own oil loading terminal crude is transported by rail into refineries in
Ukraine.
ZKM’s facilities are located in Western Kazakhstan not far from the Russian border
(60 km) which is close to the Atyrau-Samara Pipeline with a capacity of 15 mn tpa
(100 km). In addition to current exports by rail, the company has the option of a
direct connection to this export pipeline which is crossed by the ZKM pipeline. The
availability of its own oil-loading terminal and the current transportation
arrangements of its crude by rail gives the company a stronger position in
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Renaissance Capital
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6 October 2011
negotiating pipeline transportation tariffs if the company decides to choose the latter
option at some point.
Figure 41: Export netbacks $/bbl @$100/bbl Brent
ZKM oil export
Brent
100
Discount to Brent
5
Transportation
11
Export rent tax
Export duty
Netback (realised price)
84
KMG CPC
100
1
8
19
5
67
KMG UAS
100
5
8
19
5
63
Russian E&P (export)
100
2
5
53
40
Source: Renaissance Capital Estimates
The oil produced at the Chinarevskoye field is a high-quality, sweet crude (API
gravity of 40-41.5) with a low sulphur content of 0.4%. ZKM’s oil is lighter than Brent
and has the same sulphur content.
By exercising the rail option to Ukraine, the company avoids dilution of the quality of
its oil as would have happened if transported by pipeline, where the crude mix is of
inferior quality; and also it benefits from not incurring export duty. Accordingly, we
estimate the current logistics option, by rail, provides cost savings of $3-4/bbl
compared with pipeline transit, despite the latter offering lower transportation tariffs.
Accordingly, its discount to Brent reflects only transportation costs to Europe from
the point of sale (the oil terminal at Rostochi).
Figure 42: Oil properties
Sulphur
API
ZKM
0.4%
41-41.5
Brent
0.4%
38
CPC
0.5-0.6%
42-43
Urals
1.25%
33
We expect the expansion works to existing capacity on the Caspian Pipeline
Consortium (CPC) project, running from the Tengiz field to Novorossiysk, to
commence next year and by 2015/2016 to reach capacity of 67mn tpa from the
current 35mn tpa to accommodate volumes from the expected start up of Kashagan
in 2013. Another route where we expect expansion is that to China – where we
expect capacity to double by 2015 from its current capacity of 10mn tpa. There have
also been discussions on the potential doubling of Atyrau-Samara pipeline if
needed. All these pipeline expansion plans reduce the risk of export bottlenecks to
ZKM in the future.
Full commissioning of the GTP and capacity expansion will be instrumental in
monetising gas reserves
Gas accounts for 45% of 2P reserves and we expect gas to account for c. 50% of
total production by 2015. Early this year, ZKM completed the construction and
commissioning of a 17 km gas pipeline linking to the Orenburg-Novoposkov gas
pipeline. Maximum throughput capacity of the pipeline is 5bcm, which is sufficient to
accommodate the expected in 2017 peak gas production of 4bcm. The completion
of the GTF facility and the gas pipeline is an important milestone for monetising its
gas reserves.
No export constraints on gas sales…
The Orenburg-Western Europe pipeline has capacity of 45 bcm. Most of the Russian
volumes into the pipeline are sourced from the Orengburgskoye field, which now
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Renaissance Capital
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6 October 2011
produces around 17 bcm. Kazrosgaz (a joint venture between Gazprom and
Kazmunaigaz) signed a long-term purchase agreement with Karachaganak
Operating Company and last year the purchase by the JV amounted to 8bcm.
Karachaganak exports to Russia could reach 15-16bcm in the near future. If we
factor in the increased contribution to the pipeline from the Karachaganak field, and
take into account declining production at the Orenburgskoye field, there would still
be available space in the gas pipeline to accommodate ZKM’s peak gas production
of 4bcm by 2017. Moreover, the Kazakh government is interested in procuring gas
for the planned Beyneu-Bozoi gas pipeline, with potential capacity of 10 bcm. The
intent is to source gas from Western Kazakhstan, which includes Karachaganak, to
supply population centres in southern Kazakhstan (with up to 5bcm), with the
remaining 5bcm for to export to China. This means gas pipeline capacity availability
should not be an issue for ZKM.
…However, there is still uncertainty on gas pricing in Kazakhstan
In terms of the gas sales price, there is still uncertainty on how sales terms will
evolve. Adhering to contractual confidentiality, ZKM has not yet disclosed the actual
sales terms on which it agreed to sell its gas to Kazrosgaz, which will export the gas
to Russia through the Orenburg pipeline. We have assumed in our model a 2011
price of $80/mcm, which represents a discount of $10/mcm to our domestic Russian
gas price estimate. Our rationale is that gas prices would reach netback parity with
Russian domestic prices – based on the introduction of the Russia and Kazakhstan
customs union, about a year ago.
In May, Interfax cited Kazakhstan’s Ministry of Oil and Gas as saying the
government is considering the proposal of a draft law on gas marketing. The timeline
and eventual wording of the law are uncertain, but the proposed concepts are as
follows:

Gas supplied to the domestic market is to take priority.

The creation of a national operator that will have pre-emptive rights when
sourcing gas.

Government regulation of wholesale gas prices in the domestic market
through the introduction of a unified pricing methodology tailored to each
region.
The Ministry of Oil and Gas proposed maintaining the regulation of domestic gas
prices, with the gas price likely to reach $60/mcm by 2015. This price is in line with
our estimates of what Novatek would get at its wellhead for 30% of the volumes sold
to Gazprom (which is subject to a 42% discount to what Novatek gets in selling its
gas to end customers).
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Renaissance Capital
Zhaikmunai
Figure 43: Gas prices, $/’000m3
Gazprom domestic (indexation)
400
Gazprom netback parity
Gazrpom exports to non FSU
Novatek to end customers
324
309
6 October 2011
320
320
320
320
300
200
100
167
161
75
73
91
160
87
109
159
100
104
156
96
108
153
100
109
101
0
2010A
2011E
2012E
2013E
2014E
2015E
It is too early to draw any conclusions on the proposed domestic gas pricing
methodology in Kazakhstan, as the gas legislation is IN embryonic form and
the newly proposed pricing contradicts the earlier discussion of netback
parity with Russian domestic prices as part of the customs union.
Hence, we are taking a cautious stance by modelling flat $80/mcm long term (2015
onwards) and our assumption is based on a 20-25% discount to Russian domestic
prices. To be on the conservative side, we do not factor in the potential effect of the
liberalisation of the domestic gas market in Russia, expected in 2013-2015, in our
price forecast. If Kazakhstan gas pricing over time is linked to Russian export
netbacks, we would expect additional upside from gas monetisation.
We do not think ZKM’s volumes represent a strategic interest for the government to
source gas volumes to satisfy domestic demand:

Due to the location of its assets, close to the Russian border, the
government will most likely source gas from Western Kazakhstan fields,
including Karachaganak and Aktobe, to supply population centres in
Southern Kazakhstan of (up to 5bcm).

ZKM’s gas volumes will be much lower than those produced at the major
Tengiz and Karachaganak projects.
Pricing-in the worst-case scenario, we note that even at an $80/mcm assumption for
gas, and gas accounting for 50% of the total hydrocarbon mix once production
increases, it contributes only c.15% of total revenues. $80/mcm translates into
$13/boe; and the difference between our assumption of $80/mcm and our worstcase scenario $60/mcm translates into a $3/boe difference, which has marginal
implications for our valuation.
On the upside sensitivity, if we increase our long-term gas price from $80/mcm to
$140/mcm to factor in Russian export netbacks, our DCF-based valuation will
increase by 15%.
34
Renaissance Capital
Zhaikmunai
6 October 2011
ZKM has favourable fiscal terms at the early stage, but the tax burden
increases as production ramps up
ZKM’s PSA, is grandfathered and is not theoretically subject to any changes to
Kazakh oil and gas legislation. In the documents covering the new tax code, existing
PSAs are exempt from any changes to Kazakh tax legislation. However, despite the
fact that there is tax and export duty stability of PSA contracts, the company had to
pay export duty in 2008, which was removed in January 2009. One of the latest
amendments, in 2010, extended the production permit until 2033.
The PSA dictates the payment of royalties on oil and gas revenue, profit oil and
profit gas share payments. Profit oil and profit gas are determined as revenue net of
cost oil, which includes deductible expenses (operating, capital, exploration).
Expenses can be deducted at up to 90% of revenue, with the unrecovered amount
carried forward indefinitely. Both the royalty rate and the profit oil share rate are
purely a function of production rates. Hence, the company has lower tax rates at the
early stage of production and the tax burden increases with higher production, as
per the rates set out in Figures 44-47. For royalty calculations, LPG is included in
the gas royalty calculation. There is little clarity on how to treat LPG volumes for
profit oil calculation. In our model, we have not included LPG in the profit oil
calculation. Based on our production estimates, the highest weighted royalty rate for
both oil and gas is 6.3%. The highest profit oil rate that we apply to our peak
production estimates is 12% for oil and 19% for gas.
Figure 44: Royalty oil
Annual production, tonnes
< 100,000
100,000 - 300,000
300,000 - 600,000
600,000 - 1,000,000
1,000,000 >
Daily production, bpd
< 2,000
2 000 - 6 000
6,000 - 12,000
12,000 - 20,000
20,000 >
Rate
3.0%
4.0%
5.0%
6.0%
7.0%
Figure 45: Royalty gas
Annual production, mcm
< 1,000,000
1,000,000 – 2,000,000
2,000,000 – 3,000,000
3,000,000 – 4,000,000
4,000,000 – 6,000,000
6,000,000 >
Daily production, mcmpd
< 2,740
2,740 - 5,479
5,479 - 8,219
8,219 - 10,959
10,959 - 16,438
16,438 >
Rate
4.0%
4.5%
5.0%
6.0%
7.0%
9.0%
Figure 46: Government share, profit oil
Annual production, tonnes
< 2,000,000
2,000,000 – 2,500,000
2,500,000 - 3,000,000
3,000,000 >
Daily production, bpd
< 40,000
40,000 - 50,000
50,000 - 60,000
60,000 >
Rate
10%
20%
30%
40%
Figure 47: Government share, profit gas
Annual production, mcm
< 2,000,000
2,000,000 – 2,500,000
2,500,000 - 3,000,000
3,000,000 >
Daily production, mcmpd
< 5,479
5,479 - 6,849
6,849 - 8,219
8,219 >
Rate
10%
20%
30%
40%
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Renaissance Capital
Zhaikmunai
6 October 2011
The state has an option to select whether to take physical delivery of the profit oil, or
its monetary equivalent of the. To date, it has opted to receive the monetary
payment.
The tax burden of the PSA relative to that of the normal tax regime depends on
production volumes and price assumptions. The PSA applies higher taxes rates for
the peak years, amounting to 19% on our gas production profile forecasts, and a
much lighter 10% of profit gas when production is ramping up. For oil tax rates, we
observe more stable dynamics, with the weighted average tax rate advancing from
10% to 12% in the peak production years. Clearly, the PSA regime is much more
favourable than the normal tax regime, with the difference between the two
more pronounced in the early years of production.
Figure 48: Estimated tax payments, $/bbl
Royatly+Profit Oil
18
16
14
12
10
8
6
4
2
0
7
7
Income tax
6
7
8
6
6
6
8
4
3
2012
2013
6
2014
8
8
8
7
7
7
2015
2016
2017
2018
2019
2020
Under the normal taxation regime, the burden is more evenly spread over the
production lifecycle, as only mineral extraction tax is a function of production and the
step changes between various productions brackets are marginal compared with the
PSA. Export rent tax is a function of the oil price only.
36
Renaissance Capital
Zhaikmunai
6 October 2011
Figure 49: Total tax take as a proportion of revenues
PSA
Normal tax regime
60%
40%
30%
less pronounced variance
between 2 tax regimes
PSA preferred
50%
37%
25%
36%
23%
36%
33%
38%
38%
34%
34%37%
37%
33%
2016
2017
2018
32%
35%
27%
32%
35%
20%
10%
0%
-10%
2012
2013
2014
2015
2019
2020
What if the government decides to change the PSA?

We see the risk of this as low, as the PSA is grandfathered and there are
no precedents for PSA cancellation in Kazakhstan.

Earnings will deteriorate to a higher extent if the PSA is abandoned before
or during production ramp up.

Once production steps up to the 100kboepd-plus level, the difference
between the two tax regimes becomes less pronounced.

In a hypothetical scenario, if the PSA were abandoned from 2013, our
valuation would reduce by 16%, whereas if it happened at peak production
rates, the impact would be 10-12%.
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Renaissance Capital
Zhaikmunai
6 October 2011
Financial framework
On the financials side, the key focus falls on the ability of the generated free cash
flows to satisfy interest payments on the bond as well as support investment both in
ongoing development as well as infrastructure expansion capex. Based on
management’s latest guidance we are expecting the full commissioning of the GTP
within a few weeks, which will unlock hydrocarbon production growth to 48kboepd
levels. Based on our $100/bbl forecast, interest cover (EBITDA/interest) is 10x,
which should even leave plenty of room for the oil bears. Once the company fully
commissions the GTF and ramps up production to the promised levels of 48kboepd
we forecast it will generate $400-500mn of operational cash flows over the next
three years, which should comfortably fund both the drilling programme and
investment in GTF expansion.
For the GTF expansion we have pencilled in $400mn (higher than the company’s
projection of $360mn). The company has timing and phasing flexibility on the
infrastructure spend, hence we do not think that it could create funding pressure on
the company. This year, the company has hedged a quarter of its oil production of
2kboepd with a floor price fixed at $85/bbl, and we expect it to continue hedging,
further securing its interest obligations.
Figure 50: Capex projections, $mn
Infrastructure
500
Figure 51: Cash flow dynamics, $mn
Cashflow from Operations
Free cashflow
1,000
Drilling
800
400
600
300
200
Cashflow from Investment
186
200
0
132
-200
100
160
120
877
400
251
120
100
120
2014
2015
2016
395
472
-306
-411
2012
2013
174
-160
437
-100
-252
-400
-600
0
2012
2013
2011
Figure 52: Net debt/EBITDA
EBITDA
1600
1400
1200
1000
800
600
400
200
0
-200
-400
-600
-800
Net Debt
Net Debt/EBITDA
40
1.2
1400
35
1200
30
0.6
1000
25
0.4
800
20
0.2
600
15
400
10
-0.4
200
5
-0.6
0
-0.2
2014
Financial Interest
1600
0.0
2013
EBITDA
1.4
0.8
2012
2015
Figure 53: EBITDA/interest
1.0
2011
2014
2015
0
2011
2012
2013
2014
2015
38
Renaissance Capital
Zhaikmunai
6 October 2011
Figure 54: Income statement, $’000
Revenue
Royalties
Government profit share
Production opex
Depreciation and amortisation
Cost of sales
Gross profit
Administrative expenses
Sales and transportation
EBITDA
EBITDA margin
EBIT
Profit before income tax
Current income tax expense
Net profit
2009
116,033
-5,711
-1,112
-21,036
-16,176
-44,035
71,998
-29,726
-5,692
52,756
45%
36,580
8,840
-7,889
-18,768
2010
178,159
-8,863
-1,676
-28,138
-15,183
-53,860
124,299
-27,265
-17,014
95,203
53%
80,020
60,773
-13,709
22,900
2011E
365,332
-15,451
-4,033
-17,638
-22,048
-59,169
306,163
-35,000
-28,909
264,301
72%
242,253
195,003
-78,001
117,002
2012E
858,941
-41,907
-27,508
-76,671
-85,190
-231,276
627,666
-60,000
-78,186
574,669
67%
489,479
442,229
-132,669
309,560
2013E
890,058
-44,072
-24,463
-82,073
-87,015
-237,623
652,434
-60,000
-81,910
597,540
67%
510,525
463,275
-138,982
324,292
2014E
899,392
-44,726
-69,748
-86,388
-87,563
-288,424
610,969
-60,000
-83,027
555,505
62%
467,942
420,692
-126,208
294,484
2015E
2,326,210
-138,321
-287,272
-244,241
-236,449
-906,283
1,419,927
-65,000
-204,321
1,387,055
60%
1,150,606
1,111,231
-333,369
777,862
Source: renaissance Capital estimates
Figure 55: Cash flow statement, $’000
Net cash flows from operating activities
Net cash used in investing activities
Net cash (used in)/provided by financing activities
Effects of exchange rate changes on cash and cash equivalents
Net increase in cash and cash equivalents
2009
2010
2011E
2012E
2013E
2014E
45,934 98,955 173,914 394,546 471,530 436,671
-200,673 -132,189 -160,000 -305,600 -411,000 -252,400
279,418 39,710 -47,250 -47,250 -47,250 -47,250
809
350
124,679 6,476
-33,336 41,696 13,280 137,021
2015E
876,668
-99,600
-489,375
287,693
Figure 56: Balance sheet, $’000
Non–current assets
Cash and cash equivalents
Current assets
Total assets
Total equity
Long-term borrowings
Non–current liabilities
Current liabilities
Total liabilities
Total equity and liabilities
2009
819,808
137,375
182,992
1,002,800
477,769
356,348
449,768
75,263
525,031
1,002,800
2010
965,133
145,201
172,434
1,137,567
500,669
434,931
556,691
80,207
636,898
1,137,567
2011E
1,100,343
112,208
155,729
1,256,071
617,671
444,381
556,037
82,363
638,400
1,256,071
2012E
1,320,753
153,904
256,226
1,576,979
927,231
444,381
556,037
93,711
649,748
1,576,979
2013E
1,644,738
167,184
273,213
1,917,951
1,251,524
444,381
556,037
110,390
666,427
1,917,951
2014E
1,809,575
304,205
411,347
2,220,922
1,546,008
444,381
556,037
118,876
674,913
2,220,922
2015E
1,672,726
591,898
869,012
2,541,738
2,323,870
111,656
111,831
223,487
2,547,357
39
Oil and gas
Kazakhstan
Equity Research
6 October 2011
Farid Abasov
+44 (207) 367-7983 x8983
[email protected]
Ildar Davletshin
+7 (495) 725-5244 x5244
[email protected]
KMG EP
Bear in hibernation
Ivan Kokurin
+7 (495) 725-5247 x5247
[email protected]
Operational challenges: KMG EP has historically maintained a high cost

base, but over recent years, costs have been growing faster than those of its
peers, further compressing margins, while the core asset base is deteriorating
faster than we had expected.
Report date:
Awaiting acquisitions: One of the key investment themes for KMG EP is

co-investment with NC KMG, which has pre-emptive rights to onshore assets in
Kazakhstan. A cash balance of $4bn, which includes $1.5bn of NC KMG bonds,
should enable it to proceed further with the M&A pipeline and potentially close the
long-awaited MMG transaction.
Cash flow supports sustainable dividends: Despite high cost

inflation, the company is still generating solid free cash due to favourable tax
regime. The current free cash flow yield is around 9%, and 14% if we include
dividends from associates. The current dividend yield is 5.6%, but we do see
potential room for a step-up its dividend rate on a sustainable basis.
Exploration upside small, but focus is increasing: Despite

relatively slow steps on the exploration front, exploration is attracting increasing
attention from the company, which is trying to manage a production decline. If
successful, the potential acquisition of large offshore blocks (and one onshore
block [Urikhtau]) from the parent could be a game-changer, in our view.
Share buyback: We view recent the buyback announcement of $300mn (c.

4% of the outstanding common shares) as a positive effort from the company to
support shareholders by improving liquidity, implying 15-20% of daily volume: we
regard this as a decent size to support a floor for the stock.
6 October 2011
Rating common/pref.
HOLD
Target price (comm), $
21
Target price (pref), $
n/a
Current price (comm), $
14.0
Current price (pref), $
n/a
MktCap, $mn
5,899
EV, $mn
1,799
Reuters
RDGZ.KZ
Bloomberg
KMG LI Equity
ADRs/GDRs since
n/a
n/a
421
-40.0%
08/03/2011
4.3%
29/09/2011
Web:
www.kmgep.kz
Free float
34%
Major shareholder
NC KMG
with shareholding
58%
6.7
over the last
1 month
-11.74%
3 months
-24.82%
12 months
-15.34%
Valuation at a discount: The stock trades at 3.7x P/E; in line with LUKOIL

(Bloomberg consensus). On EV/2P of $1.1/bbl, the stock trades close to Tatneft. In
our view, a certain discount to the valuation is justified given operational
challenges and slow process with M&A and exploration activity. We believe more
aggressive steps on the exploration front, M&A and operational discipline would
help ease disappointment in the market.
Revenue
Adj. EBITDA
2010
4135
1893
2011E
5235
2075
2012E
5111
1954
2013E
5084
1876
Net income
1593
1645
1643
1621
EPS
3.78
3.90
3.90
3.85
Adj. EBITDA margin
46%
40%
38%
37%
P/E
-3.6
3.6
3.6
EV/EBITDA
-1.5
1.2
0.2
P/CF
-5.0
4.2
4.3
$
RDGZ.KZ
RENCASIA
30
140
25
120
100
20
80
15
60
10
40
5
20
0
0
Jul Aug Sep
Source: Bloomberg
Petro Matad Ltd
Tethys Petroleum
Roxi Petroleum
KazMunaiGaz E&P
Zhaikmunai
Dragon Oil
BMB Munai
Max Petroleum
RENCASIA
%
-80
-70
-60
-50
-40
-30
-20
-10
0
10
20
Source: Bloomberg
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Investment summary
We initiate coverage with a HOLD rating and target price of $21/GDR, implying
50% potential upside
Operational challenges
KMG EP’s core asset base is deteriorating faster than we had expected. The
company has historically operated with a high cost base, but costs have been
growing faster than those of its peers, further compressing margins. As a result of
recent industrial action, the company expects to lose almost 10% of production at its
core field. Currently, we still do not have clear visibility on production rates, as the
company has not restored production to pre-strike levels.
Awaiting acquisitions
One of the key investment themes for KMG EP is co-investment with NC KMG,
which has pre-emptive rights to onshore assets in Kazakhstan. Historically, the
company has grown its reserves base inorganically by consolidating onshore assets.
A cash balance of $4bn, which includes $1.5bn of NC KMG bonds, should allow it to
proceed further with the M&A pipeline and potentially close the long-awaited MMG
transaction.
Cash flow supports a sustainable dividend payout
Despite high cost inflation, due to a beneficial fiscal regime, the company is still
generating solid free cash with a current free cash flow yield of 9%; and if we include
dividends from associated entities, the free cash flow yield goes to 14%. KMG EP’s
current dividend yield is 5%, but we see potential room for a sustainable step-up its
dividend rate.
Exploration upside is small, but focus is increasing
Despite relatively slow steps on the exploration front, exploration is increasingly in
focus for the company, which is trying to manage a production decline. If successful,
the potential acquisition of large offshore blocks (and one onshore block) from the
parent could be a game-changer, in our view. Though expected results from pre-salt
wells at Federovsky and Zharkamys would not add material value, a successful
result would encourage positive sentiment, in our view.
Share buyback
We view recent the buyback announcement of $300mn (c. 4% of the outstanding
common shares) as a positive effort from the company to support the shareholders
by improving liquidity, implying 15-20% of daily volume, which is a decent size to
support a floor for the stock. We think in today’s market conditions, the buyback will
serve as a cushion protecting against downside for the stock. From a valuation
perspective, the impact is limited to only 1.2% of the incremental value added. In our
view, positive news on an improvement of operational performance, value adding
acquisitions or a more aggressive exploration programme would add more material
upside potential to the stock.
41
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Valuation at a discount
The stock trades at 3.7x P/E; in line with LUKOIL (Bloomberg consensus). On
EV/2P of $1.1/bbl, the stock trades at close levels with Tatneft. In our view, a certain
discount to the valuation is justified given operational challenges and slow process
with M&A and exploration activity. We believe more aggressive steps on the
exploration front, M&A and operational discipline would help ease disappointment in
the market. In our view, a certain discount to the valuation is justified given
operational challenges and slow process with M&A and exploration activity. We
believe more aggressive steps on the exploration front would help ease the hanging
disappointment in the market.
42
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Valuation
KMG EP has underperformed Russian oils, and de-rated
From a multiples perspective, KMG EP, a pure upstream player, has often been
benchmarked against Russian oil companies, although it differs fundamentally given
the exposure of the Russian oil universe to the downstream segment and fiscal
regime. The downstream segment boosts the total profitability of Russian oil
companies, due to lower export duties on refined products than on crude oil,
offsetting punitive taxation in the upstream segment. Nevertheless, what both
Kazakh and Russian oil companies share is the legacy of mature and well
developed assets.
KMG EP operates its fields under a higher cost base, but has more favourable fiscal
terms in upstream, which translates into higher per-barrel earnings compared with
Russian oils. Among the traditional multiples used for comparison of oil companies,
such as EV/DACF, P/CF and P/E, we favour the earnings multiple, mainly because
Bloomberg EPS consensus estimates tend to be more reliable than other metrics,
particularly reflecting contributions from associates and interest income
Figure 59: Historic P/E 12-month forward
KMG EP
12
Russia average
10
8
6
4
2
Aug-11
Apr-11
Jun-11
Feb-11
Oct-10
Dec-10
Aug-10
Jun-10
Apr-10
Feb-10
Dec-09
Oct-09
Aug-09
Jun-09
Apr-09
Feb-09
Dec-08
Oct-08
Jun-08
Aug-08
0
KMG EP has significantly de-rated since its IPO in 2006. As a high-beta stock,
during the last crisis it dropped from peak P/E of 14-16x, to 2.5x. During 1H09, the
stock bounced back following the oil price, and through to mid-2010 it was trading in
the 6-8x P/E range, representing a premium to Russian oils: we believe this was
justified given higher profitability and a less punitive upstream tax regime for the
Kazakh producer. YtD, it has underperformed Russian oils and significantly derated, trading at 3.7x P/E. In our view, the de-rating mainly reflects growing concern
among investors about deteriorating margins impacted by falling production and
above-industry average cost inflation. Most recently, more pressure on the stock
was added by the production loss during the strike and lingering uncertainty about
future production levels. What complements our explanation above is that on
production multiples, the stock is trading at $10 EV/kboe, a very low multiple, and
half the EM average of $30 EV/kboe. We think the stock is defensive given the
announced buyback programme and cash accounting for c. 75% of the current
market cap. However, provided the lack of certainty on future production levels and
high cost inflation, we expect the stock to trade in the 5-6x P/E range under
normalised market conditions, unless it makes transformational steps (i.e. valueaccretive M&A).
43
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Figure 60: KMG EP NAV valuation, $/GDR
30
Target price , $/GDR
25
2
20
6
3
15
5
25
23
5
10
9
0
Core Assets Associates
(KGM, PKI,
CCEL)
KMG NC
Bond
Net Cash
Base case
NAV
Exploration
Bull case
NAV
For our base-case valuation we use a blend of NAV (50%) with a multiples-based
approach (50%). Our preferred methodology is NAV, which allows us to separately
value KMG EP’s core assets and associates using a DCF methodology. (DCF is the
only valuation framework that accurately captures the underlying cash flow and
earnings-generating ability of the asset base over time.) This approach focuses on
the fundamental value of the business, and takes into account both growth and risk.
We use FCF projections through to 2015 and a terminal value for YE15 (our discrete
period). We calculate terminal value for 25 years after 2015 using a 1% decline rate.
We apply a 1% decline rate to the terminal free cash flows, to reflect a mature
portfolio with declining production.
We have separately modelled KGM and PKI associates using DCF methodology.
We view Karazhanbasmunai (CCEL) as a portfolio investment. KMG EP invested
$150mn in 50% of shares in Karazhanbasmunai and gets a priority return of
$26.9mn/year until 2020, which is annuity of 15%.
For the DCF, we use a $100/bbl Brent assumption for the long term, and a 13%
WACC.
Figure 61: KMG EP NAV valuation
Discounted FCF
Terminal value
Long-term growth
Discounted terminal value
EV
+ Cash at December 2011
+ KMG NC bond
- Value of debt at Dec 2011
- Pension liabilities
Net cash/(net debt)
Equity value core assets
KGM
PKI
CCEL
Equity value of associates
Equity value per GDR
$mn
1,714
3,448
-1%
2,115
3,829
3627
1,268
-681
-242
3,973
7,802
828
964
135
1,927
9,729
$/GDR
4.1
8.2
5.0
9.1
9
3
-2
-1
9
19
2.0
2.3
0.3
4.6
23
The second methodology we use to value KMG EP is a multiples-based approach.
We cross-check our DCF valuation using a combination of multiples based on
historical averages as well as relative value to the Russian peers. We view the 12-
44
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
month average prior to the strike as a fair multiples valuation that reflects the new
paradigm of cost inflation and a slight production decline. Our average implied
valuation using P/CF, P/E and EV/EBITDA multiples points to our target price of
$21/GDR which is similar to our DCF valuation.
Figure 62: Multiples valuation
2012 op. cash flow incl assoc, $mn
Equity value, $/GDR
6.0
1674
10046
24
2012 op. cash flow $mn
Equity value, $/GDR
6.0
1394
8365
20
Target P/E multiple
2012 net income, $mn
Equity value, $/GDR
5.5
1643
9037
21
Target EV/EBITDA multiple
2012 EBITDA , $mn
Implied EV, $mn
Net debt, $mn
Equity value, $mn
Equity value, $/GDR
3.0
1679
5036
3973
9009
21
For KMG EP’s exploration assets we assign a risked reserves value of 186mmboe,
which is less than 10% of the total 2P reserves base. Hence, given its relatively
small weight and insufficient visibility on the company’s exploration programme, we
do not include the value of exploration assets ($2/GDR) in our base-case valuation
yet.
Figure 63: Valuation of exploration assets
Liman
R9
Taisogan
Karaton-Sarkamys
Zharkamys East 1
Fedorovsky block 50%
Total
Unrisked P50
reserves, mmboe
CoS
27
63
13
450
232
102
887
50%
5%
20%
20%
20%
30%
24%
Risked
reserves,
mmboe
14
3
3
90
46
31
186
Risked
Risked asset
NPV/bbl, $ asset value,
value/share, $
$mn
5
67.5
0.16
5
15.75
0.04
5
13
0.03
5
450
1.07
5
232
0.55
5
153
0.36
931
2.2
45
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Risks
Execution risk
KMG EP’s core asset base is deteriorating faster than we had expected. The
company is operating under a high cost base that is targeted to manage the
production decline. However, due to industrial action, which lasted several months,
the company expects to lose almost 10% of production at its core field (6% of the
consolidated production). Last year the company also incurred production losses
due to labour action. We see production underperformance as one of the key risks
to our valuation.
High cost inflation
The company faces above-industry-average cost inflation pressures that compress
margins. On the other hand, production has not been growing, due to external
factors (including industrial action).
Risk of restricted use of cash
A net cash balance of $4.1bn including the KMG NC bond ($1.5bn) represents
almost 60% of the company’s market value. For the past several years, the return on
cash has been diminishing with deposit rates coming down from 7-8% to 2-3%. We
include the entire cash balance in our base-case valuation, but if the cash is not
utilised efficiently for a long period, due to saving for a large acquisition, we would
see very limited value for shareholders. Hence, the discount of company’s cash by
the market could widen further.
Strategic decisions in favour of the state
The state, as the largest shareholder of the company, could take decisions that are
not in the best interests of minority shareholders. The acquisitions of MMG, KTM
and KOA from NC KMG have been approved by KMG EP’s independent directors’
board, and were widely expected to close at the end of last year, however they are
still pending approval from the regulators. We see a risk that the agreed price of the
MMG transaction will be revised.
FX risk
Most of the company’s operating costs are in tenge, while capex is 50/50 split
between dollars and tenge. Hence, the company is exposed to USD/KZT volatility.
The USD/KZT exchange rate is dependent on the oil price is and is highly correlated
with the USD/RUB rate. If the oil price drops, we would expect the tenge to
depreciate, with a net positive effect on the costs in dollar terms.
Commodity price
Our long-term oil price assumption is $100/bbl. If market expectations on the longterm oil price differ from our assumption, the share price could deviate from our
target price.
46
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Asset overview
Introduction

In 2005, the company divested a majority stake in the Atyrau Refinery.

In 2006, KMG EP's shares were listed on the Kazakhstan Stock Exchange
and the GDRs are listed on London Stock Exchange.

KMG EP acquired a 50% stake in JV Kazgermunai LLP in 2007.

In 2007, KMG acquired a 50% stake in CCEL (Karazhanbasmunai).

In December 2009, KMG EP acquired 33% of PetroKazakhstan Inc.

In August 2010, KMG EP and BG Group signed an agreement to farm into
a BG Group operated licence in the UK Central North Sea: production
licence (P1722) which contains the White Bear prospect.

In September 2010, KMG EP entered into agreements with Eastern Gate
Management Ltd to acquire 100% of LLP NBK and with Halyk Komir LLP to
acquire 100% of LLP SapaBarlauService (SBS).

2011: Acquisition of 50% of the Fedorovskiy block.
Core assets: Uzen and Emba
The core production assets of the company consist of two main divisions:
Uzenmunaigas (UMG) and Embamunaigas (UMG). UMG accounted for more than
73% of core reserves and 68% of the 2010 core production level.
KMG EP’s core production operations take place across 41 fields at Uzen and Emba
in Western Kazakhstan excluding acquisitions made from 2007 through 2010. One
of the main tasks for the core assets is to maintain production levels by optimising oil
production and using new technology to maintain production levels and manage the
decline. A major role in the production recovery process is played by well workovers
and the use of hydro-fracturing. The company’s strategy now is to maintain
production from existing assets at the current optimal level for the next few years.
UzenMunaiGas is located in the Mangistau region, 130-150 km to the east of Aktau
port, and covers 275.0 km2. The field has developed infrastructure with intra-field
pipelines of about 4,500 km, and an oil treatment unit (capacity of 10mn tpa). The
Uzen field is a large anticline structure, 39 km x 9 km, with complicated geology. In
the Cretaceous and Jurassic deposits there are more than 100 oil- and gas-bearing
layers grouped into 25 horizons.
EmbaMunaiGas oil fields are located in the Atyrau region up to 400 km away from
Atyrau in different directions. There are oil treatment units and intra-field pipelines of
about 2,000 km. The company’s oil fields are of the small and medium category in
terms of reserves. Oil is located in the Cretaceous, Jurassic and Triassic deposits at
a depth of 50 metres to 3,300 metres. About half its oil reserves have high viscosity.
Oil has been produced since 1911, and the average watercut is about 86%.
Associates: Kazgermunai-50%, Karazhanbasmunai-50%, Petrokazakhstan-33%
47
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Kazgermunai: 50%
Kazgermunai was formed in 1993 with a view to attracting investment into the
Republic of Kazakhstan from Germany. Under Kazgermunai’s foundation
agreement, it was granted exclusive rights and licences for exploration and
production at the fields for a period of 30 years, expiring on 1 March 2024.
Kazgermunai currently operates the Akshabulak, Nuraly and Aksai oil fields. In total,
Kazgermunai’s oil fields cover a territory of 897 km2. As at 31 December 2010,
KGM’s 2P reserves were 180mmboe and production of 65.4kboepd.
Karazhanbasmunai (CCEL): 50%
In 1997, Nations Energy acquired 94.62% of the share capital representing 100% of
voting control of JSC Karazhanbasmunai from the Government of Kazakhstan. JSC
Karazhanbasmunai holds 100% of the mineral rights until June 2020 to develop the
Karazhanbas oil and gas field in the western part of Kazakhstan which, according to
Miller and Lents, has proved and probable reserves 449mmboe as of November of
2010. In 2010 JSC Karazhanbasmunai produced approximately 36kboepd of crude
oil.
PetroKazakhstan Inc. (PKI): 33%
The PetroKazakhstan Inc. group of companies is involved in hydrocarbon
exploration and production as well as in the sale of oil and petroleum products. PKI
has a share in 16 fields, 11 of which are in various stages of development. As of 31
March 2009 PKI's 2P oil reserves accounted for 365mmboe. In 2010 PKI production
stood at 128kboepd.
48
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Ownership
Figure 64: KMG EP ownership structure
Treasury shares,
4.5%
Preferred shares,
3.4%
Free float, 34.1%
NC KMG, 57.9%
Below we take a closer look at the economics and operational metrics of KMG EP.
KMG EP is generating higher EBITDA/bbl than Russian upstream, but cost
inflation is squeezing margins
One of the main indicators of operational efficiency and value creation is RoIC,
which for the sake of simplicity we estimate as the ratio of EBIT to the sum of book
value of equity and total debt. The RoIC of KMG EP (including income from
associates) deteriorated from c. 40% in 2006-2008 to 19% in 2010, which now is in
line with the Russian companies. For KMG EP, the main contributors to a decline in
RoIC were a change in the tax regime in 2008/2009 and a consistent increase in
operating costs over the past several years. If we strip out earnings from associates
the RoIC of 15% for last year is even lower and stands lower than the Russian
average. It’s important to reiterate that Russian RoIC numbers represent integrated
business which includes the downstream segment that boosts the total profitability of
oil companies. On upstream EBITDA/bbl, the Kazakh producer still appears more
profitable than it’s Russian peers as more favourable tax regime for KMG offsets its
relatively higher cost base. On last year’s numbers at $80/bbl crude, KMG EP
generated $23/bbl of EBITDA from its core assets which stood $6/bbl higher than
the average Russian producer. Associates contributed an additional $6/bbl to KMG
EP’s P&L.
We acknowledge that accounting metrics have certain limitations and do not provide
a full picture of profitability at the company. From a free cash flow perspective, the
company looks better, but we expect free cash flow to diminish gradually, due to
increased drilling activity and rising cost pressures.
49
Renaissance Capital
KazMunaiGaz E&P
Figure 65: RoIC
Figure 66: EBITDA, $/bbl (LHS) vs Brent, $/bbl (RHS)
45%
40%
35%
30%
25%
20%
15%
10%
5%
0%
6 October 2011
43%
40%
42% 42%
KMG EP
Russia
42%
36%
28%
Russian average
KMG EP
Oil price
60
120
48
41
50
26%
24%
19% 18%
15%
15%
14%
13%
36 38
40
30
20
28 28
17
15
17
100
38
29
23
19 19 17
14
28
34
26
20
0
2007
2008
2009
0
2006
2010
60
40
10
2006
80
2007
2008
2009
2010
2011
2012
Core asset base deteriorating
Most of the company’s fields are at a mature stage of development, characterised by
high water cuts and declining production. Uzen fields have been producing oil for 46
years, whereby some of the fields at Emba produced first oil 100 years ago.
So the reality with which company has to live with is operations under a much higher
cost environment than its peers (see Figure 70). For comparison KMG EP’s capex
per barrel in 2010 was around $9.2/bbl out of which only $0.5/bbl accounted for
exploration). When we benchmark capex numbers against Tatneft, a mature
Russian oil producer with $5.6/bbl capex, the Kazakh producer comes in 64%
higher.
Figure 67:Production costs, $/bbl
Russian oils
Figure 68: F&D, $/bbl
Tatneft
KMG EP
16
14.5
14
12
10
12.5
9.4
10.7
4.74.7
5.24.8
4.34.8
Tatneft
14
12.5
10
5.6
4.6
Russian oils
12
9.6
8
6
KMG EP
6.5
5.3
8
6
4
4
2
2
0
9.2
8.8
6.8
5.0
4.6
4.9
2.8
6.1
7.1
4.4
2.7
3.2
7.8
3.8
0
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
Watercut for the fields is around 86%, which results in higher operating costs per
barrel of crude oil as operating costs incurred to produce liquid are spread over a
smaller volume of oil. The high viscosities of the crude and high freezing
temperatures are other factors that contribute to the higher lifting cost.
KMG’s high cost base is not a discovery, but what concerns us is that production
costs have been growing at much higher rates than realised prices and the costs of
50
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
peers, compressing margins. In 2010, the average oil price for the year was 9%
higher than the average levels for 2007, whereby production costs doubled to
$9.6/bbl over the past three years. Biggest contributors to the opex escalation have
been increase in employee compensation and repair and maintenance costs which
were up 50% since 2007.
Figures 72-73 explain one side of the inflation story: the company’s mature fields,
developed during the Soviet era, face a decline in flow rates. Falling flow rates
reflect decreasing reservoir pressure and increasing watercut ratios. Older wells,
which have higher watercuts, also have higher lifting costs, since more liquids must
be lifted to produce the same amount of crude. Moreover, older assets have shorter
periods between well workovers, thus lowering the average flow rate per well.
KMG’s well flows oil on average at 30 boepd, which is half the average Russian well
(we exclude Rosneft from the average).
Figure 69: Average flow rates per well, boepd
Figure 70: Historical flow rates per well, boepd
113
120
93
100
80
64
66
Russian ave
100
70
74
60
58
59
55
53
52
50
60
40
20
KMG EP
18
27
40
30
33
33
32
31
30
2006
2007
2008
2009
2010
30
20
10
Rosneft
Slavneft
TNK-BP
LUKOIL
SurgutNG
Russneft
KMG EP
Tatneft
Bashneft
0
0
Last year, the company had 5,884 producing wells and performed 1,234 well
workovers. So, given that KMG’s core operations are relatively labour-intensive, we
see potential for cost control and increasing operational efficiency, provided that
KMG EP has among the highest headcount per well which is almost twice the
Russian average. However, we do acknowledge the fact that the government is the
largest shareholder, and that labour is a politically sensitive issue.
Figure 71: Upstream headcount per producing well
5.4
6
5
4
3
1.2
1.2
1.2
1.3
TNK-BP
Rosneft
1
0.8
Lukoil
2
Tatneft
2.4
Surgutneftegaz
KMG EP
Bashneft
0
51
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
We note that the company is managing the decline through increased drilling
activity, having drilled 215 new wells last year. In 2007, it added 18% (272mmboe)
to its 2P reserves base having adopted an increased density drilling programme
which had a major impact on 2010 capex. As a result of the new drilling programme
in 2010, the company doubled its development capex, reaching $9/bbl. Despite the
step-up in drilling activity, the company could not manage to grow production or
keep it flat. In our view, the production decline is not technical in nature, rather it
reflects execution and operational efficiency. Mature oil producers with similar
geology and high water cuts, like Tatneft in Russia and Petrom in Romania, have set
precedents that with a certain capital commitment production could be sustained
and kept flat.
Production impacted by labour action; looking forward to more visibility on
production rates
Industrial action at the Uzenmunaigaz production facility, which lasted for three
months, has had the biggest effect on production. According to management, as a
result of the strike, the loss for 2011 is estimated at 900kt, which is almost 10% of
the company’s core production, and 6% if we include production from associates.
Currently, production has stabilised and the decline has reversed, however, we do
not have clear visibility on next year’s production targets. In our model, for the next
year’s production estimates, we have pencilled in a 2% decline relative to 2010
levels, and we await further management guidance.
Figure 72: Production at core assets, kboepd vs growth/decline rate
UzenMG
200
150
56
57
EmbaMG
growth/decline rate
8%
6%
57
55
56
57
56
56
4%
2%
0%
100
-2%
136
136
134
50
126
120
105
118
116
-4%
-6%
-8%
0
-10%
2006
2007
2008
2009
2010
2011
2012
2013
KMG EP has an edge in growth through acquisitions
The main driver of the company’s reserves growth has been consolidation of the
Kazakhstan’s onshore assets benefiting from co-investing with the government:

2007: Acquisition of 50% of KGM and CCEL.

2009: Acquisition of 33% of Petrokazakhstan.

2010: 100% of NBK and SBS, 35% in White Bear (Partner with BG in the
North Sea).

2011: Acquisition of 50% of the Fedorovskiy block.
52
Renaissance Capital
KazMunaiGaz E&P
Figure 73: Past acquisitions
Asset
KGM
Acquisition date
April 2007 (50%)
Acquisition multiple, EV/2P
Production impact
2P Reserves impact
5.3
33kboepd (+19%)
90mmbbl (+5%)
CCEL
December 2007
(50%)
4.2
18kboepd (+10%)
224mmbbl (+13%)
PKI
December 2009
(33%)
7.5
42kboepd (+24%)
120mmbbl(+7%)
6 October 2011
Total
-93kboepd (+53%)
435mmbbl (+25%)
To compensate for the declining production on the core assets, the company has
been focusing on building up reserves inorganically. As a result associates account
for almost a quarter of the company’s total 2P reserves base and a third of total
production. The associate assets are mature fields with declining production, but
have much better economics relative to its core assets, due to lower operating and
development costs.
Figure 74: 2P reserves, mmbbl
2,550
2,130
363
120
408
(108)
363
435
272
1767
1,495
1707
As at 31-Dec- Production and KGM and CCEL As at 31-Dec2006
adjustments
2007
2007
PKI 33%
Acquisitions in progress:
-MMG 50%
-KOA 50%
-KTM 51%
Existing assets:
-UMG, EMG 100%
-KGM 50%
-CCEL 50%
-PKI 33%
Production and Proforma 31adjustments
Dec-2010
2008-2010
Source:Company data
Figure 75: Total production including associates, kboepd
Uzen+EMBA
PKI
KGM
CCEL
300
250
18
33
200
42
40
16
30
37
15
28
34
14
26
30
14
24
26
176
162
174
172
171
170
2010
2011
2012
2013
2014
2015
17
32
150
100
50
0
53
Renaissance Capital
KazMunaiGaz E&P
Figure 76: 2012E barrel economics
Uzen & Emba
Brent
100
Discount to Brent
21
Oil taxes
28
Transportation cost
7
Opex+G&A
19
EBITDA
25
6 October 2011
KGM
100
25
28
10
4
34
PKI
100
10
26
12
12
39
MMG
100
24
31
9
14
22
Income taxes
5
11
9
4
Operating cash flow
Capex
Free cash flow
19
13
6
24
5
19
31
11
20
18
5
12
Associates are paying dividends
We expect associates to contribute $300mn in dividends to KMG EP next year, but
we believe the payout will fade over time as production declines.
Kazgermunai, in which KMG EP owns a 50% stake, was acquired at an advanced
stage of production and operating cash flow was much higher than the capital
investment required to support production. In our view, the acquisition was a good
deal for KMG EP, as within five years of acquisition for which KMG paid $971mn
through dividends received it already recovered the acquisition price and generated
18% return on it.
Kazgermunai has two key main producing fields: Ashkabulak and Nuraly. The
assets are of a good quality with reservoirs of high permeability and high porosity.
The watercut is very low which results in low operating costs of $4/bbl vs $14/bbl at
Uzen & Emba. Development costs are twice lower than those at Uzen & Emba,
which results in high free cash flow generation which is mostly returned as dividends
to KMG EP. In our model, we pencilled in declining production which results in
fading dividends over time, but according to the company it is possible to keep
production flat with intensifying drilling. There is a very limited exploration potential
at this asset. At a $100/bbl Brent price, we would expect KMG EP to receive about
$1bn in dividends over the next five years.
Petrokazakhstan: KMG PKI owns 33% of PKI (50% Kazgermunai, 50% Turgai
Petroleum, 100% PKKR, 100% Kolzhan). Attributable reserves are 120 mmbbl and
net to KMG EP production around 40kboepd. Similar to the rest of the assets in the
portfolio, production is declining.
KMG PKI notes were issued for the acquisition of the 33% interest in PKI at the time.
Hence KMG-PKI is leveraged with a $1bn note and at the end of 2010 the
outstanding amount of the note and related accrued interest are $760mn and
$15mn, respectively. The note is payable mid-2013 but could be extended by three
years. The arrangement with KMG EP is that only 20% of available cash will be
distributed to shareholders and the remaining 80% will be deposited with banks to
cover service the principal and accrued interest at maturity. Based on our estimates
with the oil price at $100/bbl, the company will be in position to repay the principal by
early 2014.
The dividend expectation is not as high as from Kazgermunai given the priority to
service debt. Based on our estimates, during the next three years, KMG EP will
receive, on average, $45mn per year in dividends from PKI.
54
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Karazhanbasmunai (CCEL)
KMG EP invested $150mn in a 50% of share in Karazhanbas assuming an
obligation to pay back debt of $782mn debt to CITIC at an interest rate of LIBOR +
1.45%. KMG EP receives a priority return of $26.9mn/year until 2020, which
translates into a 15% annuity.
Figure 77: Net dividends to KMG EP, $mn
KGM
PKI
CCEL
400
350
27
300
75
250
27
53
200
150
100
257
27
48
27
39
222
211
192
2012
2013
2014
50
27
29
160
0
2011
2015
So what acquisitions are in the pipeline?
MMG: Just another brick in the wall
Last year KMG EP reached an agreement with its parent NC KMG to acquire 50% in
MMG, 50% in Kazakhoilaktobe and 51% stake in Kazakhturkmunai for a cash
consideration of $750mn and $1,500mn of net debt. The average implied valuation
for all stakes was $5.5/bbl, where implied valuation of MMG’s 2P reserves was at
$5.97/bbl. Transactions have been approved by KMG EP’s independent directors’
board and were expected to close at the end of last year, however they are still
pending approval from the regulatory bodies.
Among the three M&A targets, MMG is by far the largest asset with 2P reserves of
556mmbbl and last year’s production of 109kboepd. MMG holds interest in 15
producing fields in Mangistau region of South West Kazakhstan with production
coming mainly from two major producing fields Kalamkas and Zhetybai with close
proximity to Uzen fields. The fields are mature with declining production and are very
similar to KMG EP’s core fields. In terms of barrel economics, production costs are
around $11/bbl ($14/bbl including G&A) that similar to the lifting costs at Uzen.
Development costs are around $5/bbl which is comparable with Kazgermunai and
half what KMG EP is spending on the development of its core assets. MMG
generates almost same level of operating cash flow as KMG EP’s core assets, but
due to lower capex generates higher cash flows than the Uzen & Emba fields.
MMG assets hold three exploration licences with two offshore blocks: Bobek and
Makhambet. According to KMG EP there is significant exploration upside here.
KOA and KTM are assets of a smaller size than MMG with 2P reserves of
217mmbbl and 41mmbbl, respectively.
55
Renaissance Capital
KazMunaiGaz E&P
Figure 78: New acquisitions could add 22% to production (kboepd)
Uzen+EMBA
MMG
KOA
6 October 2011
Figure 79: The acquisition of 50% of MMG, KOA, KTM could add 19% to 2P
reserves
KTM
3,000
400
+19%
300
51
47
44
2P reserves, mmbbl
2,500
41
200
256
100
250
242
234
2,000
21
109
278
435
1,500
1,000
1707
500
0
2012
2013
2014
Core+Associates
2015
MMG, KOA, KTM
What price to expect for MMG?
We note that the MMG deal was structured to be financed with $330mn of cash and
$1.33bn of debt. According to KMG EP, the price of the deal is likely to be revised to
reflect the higher oil price environment. We also think the structure of the MMG deal
is likely to change, with KMG EP paying out a higher proportion in cash and less in
debt, which will be transferred from NC KMG. The reason behind our thinking is that
NC KMG has been paying off part of the debt through generated cash flows since it
acquired the stake. One of the possible scenarios suggested by the company is that
the $1.5bn NC KMG bond will be used as an acquisition currency for the assets.
What is the potential value of the acquisition?
In our view, the MMG acquisition could add around 20% to KMG EP’s consolidated
production and 13% to the 2P reserves base, while the contribution of KOA and
KTM would be less material – 2% on consolidated production and 6% on reserves. If
the MMG deal successfully completes by the end of 2011, we expect the acquisition
to add 18% to 2012 earnings.
Figure 80: MMG could add 18% to 2012E EPS
5
+18%
0.7
EPS, $//GDR
4
3
2
3.95
1
0
Now
MMG
56
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
We have evaluated full field economics for MMG using DCF based on 2P
production, assuming $100/bbl oil price and we arrive at value of $8 per barrel of 2P
reserves.
Based on the above mentioned valuation if the company aims to make a 15-20%
return on the acquisition it would imply a purchase price of $6.7-7.0/bbl of 2P
reserves. We have shown sensitivities of MMG valuation to a different oil price
assumption (2013 onward) in Figure 84. In our base-case scenario if the acquisition
price ranges between $6-7/bbl the incremental value added to KMG EP would be
within $2/bbl and $1/bbl of 2P reserves, accordingly. This translates into $1.0 to $2.5
of incremental value add per GDR, depending on the acquisition price.
Figure 81: Valuation of MMG's 2P reserves, $/bbl - WACC 13%
Brent
$80/bbl
$90/bbl
NPV/bbl
5.0
6.6
Implied price @18% return
4.3
5.7
Implied price @20% return
4.2
5.5
$100/bbl
8.0
7.0
6.7
$110/bbl
9.2
8.0
7.7
$120/bbl
10.5
9.1
8.8
Figure 82: MMG acquisition would add value to KMG EP even at $7/bbl for 2P
8
7.5
6 - 7?
PKI
MMG
7
6
5
4
5.3
4.2
3
2
1
0
CCEL
KGM
We judge that if the acquisition of MMG happened on the previous terms today it
could add 15% for shareholders ($2.5/GDR), although we understand the price is
more likely to be revised to the higher end of the price range to reflect the different
oil price environment.
The incremental value added from MMG priced at $7.0 per bbl of 2P would add
around $1/GDR which implies 7% upside potential to the current share price, so in
this case simply put it the transaction does not appear to be transformational for the
company. However, we believe closure of the deal could have more impact from a
sentiment perspective provided the offered price is within a reasonable range. We
also reiterate that exploration assets are a free option for the purchase price.
We exclude the MMG acquisition from our valuation, as currently we have
neither information on the terms nor certainty on timing.
Although the revised structure of the transaction is unclear, we think the outstanding
loan provided by CNPC to KMG NC will likely be transferred from the latter to KMG
EP. Provided that the interest rate on the CNPC loan s quite low (LIBOR + 3.5%),
minority shareholders will benefit from the deal.
57
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Would KMG EP expect dividends from MMG?
Based on our model, we do not expect free cash to pay out dividends KMG EP until
2015/2016, as debt will have to be serviced first.
Exploration embryonic, but developing
As we have noted, KMG EP’s assets are at mature stage, facing a production
decline. The reserves replacement ratio is around 73%. Continuous workovers of
mature fields combined with diverse recovery mechanisms helped to keep the
reserve replacement at stable levels. Exploration is attracting increasing attention
from the company that is trying to combat production decline. Steps towards organic
growth are being taken by the company, which has increased exploration capex
from $33mn last year to around $150mn this year with further increase planned for
the next year. This year, KMG EP already has already drilled eight wells, with two
wells making discoveries at the Liman and Fedorovskiy blocks, two dry holes and
four wells currently undergoing testing. Although the weight of exploration is
increasing, in our view current exploration programme is not material relative to the
company’s reserves base. Hence, as of yet we do not include exploration in our
base case valuation and assign a risked value of around $2.2/GDR for all the
prospects - 15% of the current share price.
Figure 83: Key data on exploration
UOM
Overall exploration expenditure, including
-Total exploration capex
-Exploration
-Supplemental exploration
-Opex
Number of wells, including
-Post-salt
-Pre-salt
-Supplemental exploration
-Offshore
Overall depth
2D seismic
3D seismic research
$mn
Wells
Metres
km
km2
2009
17
14
3
11
3
4
2
0
2
0
9,100
400
300
2010
47
33
7
26
14
8
3
0
5
0
18,600
240
855
2011E
>100
23
13
4
5
1
56,250
2,510
739
58
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Figure 84: Key exploration projects in 2011
Acreage
Reserves estimate
Drilling in 2011 (depth)
Seismic in 2011
Liman
R9
Licence
duration
19 Feb 2011
26 Jun 2011
6,468 km2
5,894 km2
2 post-salt wells (3,050 m)
3D (165 km2)
3D (224 km2)
Taisolgan
09 Jan 2012
9,605 km2
27mmbbl (P50)
63mmbl (P50)
13mmbbl (P50) 9mmbbl
(C1+C2)
3D (150 km2)
Karaton Sarkamys
Uzen-Karamandybas
Temir
Teresken
16 Jun 2016
16 May 2016
16 May 2016
01 Dec2012
3,718 km2
2,100 km2
3,874 km2
4,928 km2
1 post-salt well (2,200 m)
1 pre-salt/ 1 post-salt (6,150
m)
3 pre-salt (13,500 m)
1 well (5,500 m)
2D (900 km)
~ 1,500mmbbl (oil in place)
Zharkamys East 1
15 Nov 2012
1,190 km2
232mmbbl (C1+C2 recoverable)
Fedorovsky 50% (gas and condensate)
White Bear
11 May 2014
2015
3,198 km2
213 km2
102mmbbl (C1+C2 recoverable)
several hundred mmbbl
Total
41,118 km2
18 wells/ 42,550 m
2D (1,000 km)
2D (1,000 km)
3D (200 km2) 2D (160
km)
2D: 2,510 km 3D: 739
km2
Liman project
The company successfully completed the well, reaching a depth of 1,300 metres.
Flow of hydrocarbons to the surface was achieved and the presence of another two
producing reservoirs is forecast in the penetrated well columns. Reprocessing and
re-interpretation of 2D seismic data is under way.
P9 project
The company drilled two wells at total depths of 1,850 metres and 1,600 metres, but
the wells had to be abandoned due to geological problems. 3D field seismic
shooting is under way. Architectural analysis of the Jurassic and Triassic
accumulations of the south-eastern zone of Caspian Sea region is being performed
based on the results of the drilled wells integrated with seismic materials
In the near term we expect to hear on the drilling results of the Zharkamys East 1
and Fedorovskiy block wells, both targeting pre-salt. Though not transformational for
the company, in case of success should be positive for the stock, sentiment-wise.
Access to larger onshore projects like Karachaganak, and setting foot
offshore would materially change the company’s profile
In May this year, KMG EP signed an MoU with its parent KMG NC for screening
both offshore and onshore exploration blocks in the Caspian Sea. KMG EP will gain
access to detailed geophysical, financial and economic data on a list of oil and gas
projects. Among the blocks to be screened by KMG EP are Urikhtau (an onshore
block) and the Zhambyl, Ustyur, Zhenis and Godis offshore blocks.
Recently, the parent company made a large discovery at the Urikhtau field when
testing the K-2 carbonate rock mass. Based on the results of the seismic
prospecting performed and drilling of the first U-1 exploration well, expansion of the
Urikhtau structure area has been observed and the high potential of the KT-2
carbonate deposits has been confirmed. According to the national company, the
prospective in-place hydrocarbon reserves of KT-2 are initially at over 200mnt.
We believe the aforementioned prospects like Urikhtau and Zhambyl would
materially change KMG EP’s growth profile. We believe setting foot offshore,
coupled with the JV with BG in the North Sea, should significantly improve KMG
EP’s expertise, allowing greater flexibility in further expansion outside the mature
onshore assets.
59
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
In our view, what could be transformational for KMG EP is to gain access to one of
Kazakhstan’s strategic projects, either Kashagan or Karachaganak. Karachaganak
looks like a more realistic target to us, given it is an already producing onshore
asset. In fact, Karachaganak with 230kbpod production of oil and condensate is the
third largest producer of liquids in Kazakhstan after Tengizchevroil and KMG EP
(including associates). According to the mass media, the parent company
Kazmunaigas NC is finalising negotiations on gaining access to the project with
securing 5% free of charge and buying 5% at the market price which has not been
disclosed yet. We do acknowledge that this is not a near-term catalyst for KMG EP,
rather it is one of the potential opportunities that could be a game-changer for the
mature producer.
60
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Financial framework
We assume the following in our model:
Production: For 2011E production at core assets we have assumed management’s
guidance of 8mnt pa, which takes into account estimated production loss from the
strike. For 2012E we have assumed 1% production decline relative to pre-strike
levels and we apply 1% decline YoY for 2013 onwards.
Pricing: We use $110/bbl Brent for 2011E and $100/bbl Brent for 2012 onwards.
We assume domestic sales to be at 20% and the oil export yield at 80% as per
the agreement with the state. In the domestic market, we assume that at the core
assets, crude will be sold at production cost + a 3% mark-up ($22-23/bbl).
Costs: Both for production opex and development capex we have escalated unit
costs indexed to Kazakh inflation forecast. Our production opex increases from
$14.8/bbl in 2011E to $16.5/bbl in 2015E, while we increase our development capex
from $10/bbl in 2011E to $12/bbl in 2015E
Cash is king
The net cash balance of $4.1bn including the KMG NC bond ($1.5bn) represents
almost 60% of the company’s market value. Apart from operational performance,
efficient use of cash is a very important driver of stocks performance. For the past
several years, the return on cash has been diminishing with deposit rates coming
down from 7-8% to 2-3%. The KMG NC bond the company bought from the parent
with a 7% yield helps to keep the weighted average return on total cash at 4%.
Despite solid free cash flow generation, our concern is that return on the cash
balance on deposits is not likely to add as much value for the shareholders as most
of the oil assets would. As we have mentioned earlier, acquisitions could have more
material impact sentiment wise. With regard to the safety of the cash balance, it is
well diversified among a number of established banks, none of which has material
liquidity issues. The bond of $1.5bn, which accounts for 30% of the company’s cash
balance was issued on 25 June 2010 carrying an annual coupon of 7% and
maturing in 2013. The deal requires NC KMG to offset future dividends from KMG
EP against the outstanding bond. The bond could also serve as an acquisition
currency for the purchase of assets from the parent above a certain threshold
($800mn).
Figure 85: Cash and financial assets, $5bn
Deutsche Bank, 5%
RBS, 3%
Citi, 8%
HSBC, 13%
Other, 1%
KMG NC Bonds,
30%
ATF Bank, 10%
Halyk Bank, 25%
KKB, 5%
61
Renaissance Capital
KazMunaiGaz E&P
6 October 2011
Despite rising cost pressure, the company is still generating solid cash flows to
support the ongoing intensive drilling programme, and has plenty of room to boost
its exploration investment programme without hurting dividend distribution.
Figure 86: Capex, $mn
Development capex
1,000
900
800
700
600
500
400
300
200
100
0
Figure 87: Cash flows, $mn
Cashflow from operations
Cashflow from financing
Exploration capex
Cashflow from investment
2,000
162
161
160
94
150
600
688
716
744
756
1,500
1,000
1350
500
1187
1394
1378
0
(201)
(350)
(351)
(319)
-500
(589)
(562)
(542)
(488)
(268)
(364)
2012
2013
2014
2015
1362
-1,000
-1,500
2011
2012
2013
2014
2015
2011
Sustainable dividend policy
KMG EP is a dividend-paying stock and has a policy to pay out dividends on its
shares equal to 15% of net profit. Historically, the company has consistently
exceeded its payout policy by paying a special dividend, making a historical average
payout ratio for the past five years of around 24%. In our forecast we have assumed
20% payout ratio which implies a 5.6% dividend yield. If we project last year’s
payout ratio of 24% it would increase the dividend yield to 6.5%. Due to the
company’s solid free cash generation, cash balance and dividends from associates,
we clearly see potential for dividend growth. NC KMG is the largest shareholder with
58% ownership in the company, and the parent clearly needs cash to invest in the
strategic offshore project (Kashagan). Most importantly, KMG NC is offsetting future
dividends from KMG EP against the outstanding $1.5bn bond, which is another
strong supporting argument for a sustainable dividend payout. The only feasible
reason we see for cash accumulation is gearing up for strategic acquisitions in
Kazakhstan, such as Karachaganak and Kashagan.
62
Renaissance Capital
KazMunaiGaz E&P
Figure 88: Dividend per share vs (LHS) vs Dividend payout ratio
(RHS)
1.0
35%
0.9
30%
0.8
26%
0.7
23%
24%
20% 20% 20% 20%
0.6
0.5
16%
0.4
16%
14%
20%
12%
15%
10%
2015
2014
2013
2012
2011
0%
2010
0.1
2009
0.2
2008
Dividend yield (%)
25%
5%
2007
Figure 89: Dividend yield, free cash flow yield
30%
10%
0.3
6 October 2011
8%
14.0%
12.8%
FCF yield (%)
14.1%
9.4%
FCF yield incl associates (%)
13.5%
8.6%
7.2%
5.6%
6%
5.6%
13.2%
12.8%
7.9%
5.5%
8.6%
5.3%
4%
2%
0%
2011
2012
2013
2014
2015
Share buyback
On 16 September, KMG EP announced a share buyback programme under which
the company has an option to purchase its common shares represented both by
GDRs listed on the LSE and KASE up to an aggregate amount of $300mn or c. 4%
of the outstanding common shares at current market prices. The programme is
expected to start in the near future and is estimated to take up to the end of 2012 to
execute. We note the following company comment: ‘’The board of directors believes
that the current market prices of its shares and GDRs do not reflect the true
underlying value of the business and its considerable potential based on the current
resources, opportunities for business development and stable financial position’’. We
view the buyback announcement as a positive effort from the company to support
shareholders by improving liquidity, implying 15-20% of daily volume, which is a
decent size to support a floor for the stock.
We think in today’s market conditions, the buyback will serve as a cushion against
downside for the stock. From a valuation perspective, the impact is limited to only
1.2% of the incremental value added. In our view, positive news on any
improvement of operational performance, value-adding acquisitions or a more
aggressive exploration programme would add more material upside to the stock.
63
Renaissance Capital
KazMunaiGaz E&P
Figure 90: Income statement, $mn
P&L
Total revenue
Export customs duty
Rent tax
MET
Transportation
Production opex
Other
EBITDA
DD&A
EBIT
Finance income
Finance costs
Other income/(loss)
Share of result of associates and JVs
Profit before tax
Corporate income tax
Profit for the year
2009
3291
0
(398)
(373)
(365)
(631)
(263)
1261
(211)
1050
317
(22)
607
(17)
1935
(514)
1421
2010
4135
(44)
(662)
(481)
(392)
(802)
(245)
1509
(241)
1268
258
(51)
123
384
1982
(390)
1591
2011E
5235
(252)
(1079)
(597)
(398)
(875)
(438)
1595
(296)
1300
202
(54)
0
583
2030
(385)
1645
2012E
5111
(270)
(951)
(581)
(434)
(939)
(257)
1679
(349)
1330
213
(29)
0
478
1993
(351)
1643
2013E
5084
(268)
(945)
(577)
(439)
(981)
(260)
1613
(346)
1267
228
(13)
0
462
1944
(322)
1621
2014E
5058
(267)
(938)
(574)
(444)
(1024)
(264)
1548
(406)
1142
288
(4)
0
406
1832
(267)
1564
6 October 2011
2015E
5032
(265)
(932)
(570)
(441)
(1033)
(264)
1527
(466)
1061
304
(1)
0
350
1714
(240)
1474
Figure 91: Cash flow statement, $mn
Net operating cash flow
Capex
Dividends rec. from JVs, associates
Other (incl KMG NC bond)
Net cash flow from investing activity
Dividends paid
Repayment of borrowings
Other
Net cash flow from financing activity
2009
1011
(294)
26
(1445)
(1713)
(313)
(43)
(146)
(502)
2010
785
(588)
641
(268)
(215)
(327)
(99)
(207)
(633)
2011E
1176
(734)
328
202
(204)
(385)
(150)
(54)
(589)
2012E
1396
(844)
280
213
(350)
(329)
(200)
(29)
(558)
2013E
1378
(871)
286
1733
1149
(328)
(200)
(13)
(542)
2014E
1362
(897)
290
288
(320)
(324)
(160)
(4)
(488)
2015E
1350
(844)
271
304
(269)
(313)
(50)
(1)
(364)
Total non-current assets
Total current assets
Total assets
Total equity
LT borrowings
Total non-current liabilities
ST borrowings
Total current liabilities
Total liabilities
Total liability and equity
2009
3726
725
4987
8713
6746
620
858
308
1109
1967
8713
2010
5513
668
4180
9693
7867
423
677
408
1149
1826
9693
2011E
6303
1049
4715
11019
9127
423
677
258
1215
1891
11019
2012E
6994
1537
5177
12172
10441
423
677
58
1054
1731
12172
2013E
6130
3522
7157
13287
11734
223
477
0
1076
1553
13287
2014E
6737
4077
7706
14442
12974
63
317
0
1152
1468
14442
2015E
7193
4795
8418
15611
14135
13
267
0
1209
1476
15611
64
Oil and gas
Turkmenistan
Equity Research
6 October 2011
Farid Abasov
+44 (207) 367-7983 x8983
[email protected]
Ildar Davletshin
+7 (495) 725-5244 x5244
[email protected]
DGO
Hidden dragon
Ivan Kokurin
+7 (495) 725-5247 x5247
[email protected]
Solid production growth: We expect DGO to continue its growth at a 10-

15% CAGR (2012-2015E), supported by a cash balance of $1.5bn and strong
free cash flow generation.
Report date:
Gas monetisation to suggest value uplift: The company is due to

finalise negotiations with the Turkmenistan government on a wet gas sales
agreement, and is in talks on a long-term sales agreement for the dry gas that
will be processed once the planned GTP comes on stream in 2014. In our view,
Turkmenistan’s successful gas diversification strategy, coupled with rising
Chinese appetite, sets a solid foundation for DGO to maximise value from the
monetisation of its gas resource base.
An appealing M&A candidate...and potential buyer. Established

production, growth potential, solid cash flow generation, a strong balance sheet
and stable fiscal terms make DGO an attractive acquisition target, in our view.
Provided DGO has limited opportunities to grow reserves organically, the cash
balance of $1.5bn sets solid grounds to grow reserves through M&A, targeting
acquisitions across various geographies including Central Asia, the Middle East,
North and West Africa.
Robust balance sheet, share buyback: Defensive. Next year we

expect the company to release $400mn of free cash which, supported by the
cash balance of $1.5bn, leaves enough flexibility both to pay out dividends with
the current yield of 2% and support its production growth. On 26 September, the
company initiated a buyback programme through to end-January 2012 of 5mn
shares (c. 1% of the outstanding shares) which we consider a positive step to
support shareholders by improving liquidity, implying 10-15% of daily volume.
6 October 2011
Rating common/pref.
BUY
Target price (comm), GBp
693
Target price (pref), GBp
n/a
Current price (comm), GBp
456
Current price (pref), GBp
n/a
MktCap, $mn
3,669
EV, $mn
2,197
Reuters
DGO.L
Bloomberg
DGO LN Equity
ADRs/GDRs since
n/a
n/a
516
-23.4%
04/04/2011
21.3%
09/08/2011
Free float
49%
Major shareholder
ENOC
with shareholding
51%
4.1
over the last
1 month
-7.29%
3 months
-9.95%
12 months
6.87%
DGO is highly cash-generative with an 11% 2012E free cash flow

yield, and trades at a 34% discount to our price target of GBp 693. We think the
stock is attractive on multiples, trading at 2012E P/E of 6.0x and 2012E
EV/EBITDA of 2.3x.
Revenue
EBITDA
2010
780
676
2011
1210
1091
2012
1145
1025
2013
1244
1112
Net Income
386
664
596
642
EPS
0.75
1.28
1.15
1.24
EBITDA margin
87%
90%
90%
89%
P/E
-6.43
5.97
6.15
EV/EBITDA
-2.2
2.3
2.1
P/CF
-4.1
3.8
3.7
BPN
DGO.L
RENCASIA
160
140
120
100
80
60
40
20
0
700
600
500
400
300
200
100
0
Jul Aug Sep
Source: Bloomberg
Petro Matad Ltd
Tethys Petroleum
Roxi Petroleum
KazMunaiGaz E&P
Zhaikmunai
Dragon Oil
BMB Munai
Max Petroleum
RENCASIA
%
-80
-70
-60
-50
-40
-30
-20
-10
0
10
20
Source: Bloomberg
Renaissance Capital
Dragon Oil
6 October 2011
Investment summary
We initiate coverage with a BUY rating, and target price of GBp693, implying
52% potential upside.
Solid production growth
Over the past four years, DGO has shown a consistent track record of growing
production at a 15% CAGR, having reached current levels of 58kboepd from
32kboepd in 2007. We expect strong growth at a 10-15% CAGR, to reach
100kboepd within the next five years. We also see strong potential to accelerate the
production ramp-up by procuring more rigs and intensifying the drilling programme.
We highlight that the commercialisation of 100mmscfpd of associated gas which is
currently flared will immediately add a further 8% to our three-year production
CAGR. A cash balance of $1.5bn, coupled with strong free cash flow generation,
leaves the company comfortably positioned to fund its ambitious development
programme.
Value uplift from gas monetisation
In our view, DGO’s very large gas resource base build up of 1.6tcf of reserves and
1.4tcf of resources with current production of 100mmscfd that is being flared is not
assigned any value by the market. The company is due to finalise negotiations with
the Turkmenistan government on a wet sales gas agreement, and is in talks on a
long-term sales agreement for the dry gas to be processed once the planned GTP
comes on stream in 2014. Turkmenistan’s successful gas diversification strategy,
coupled with rising Chinese appetite, sets solid grounds for DGO to maximise value
uplift from the monetisation of its gas resource base.
An appealing M&A candidate...and potential buyer
We believe established production, growth potential, solid cash flow generation, a
strong balance sheet and stable fiscal terms make DGO a very attractive acquisition
target for international majors, as well as Chinese companies that are building their
presence in the Caspian region. In 2009, DGO was attempted a takeover by its
majority shareholder ENOC at GBp455/ share, implying a 34% premium to the DGO
share price at the time, but the bid was rejected by minorities. We also note ENI’s
$3.5bn acquisition of Burren Energy in 2007, which implied a multiple of $12/bbl for
2P reserves whereby DGO is modestly trading at $2.7/boe of 2P reserves.
Provided that DGO has limited opportunities to grow reserves organically cash
balance of $1.5bn sets solid grounds to grow reserves through M&A. We understand
the company is considering acquisitions across various geographies including
Central Asia, the Middle East, North and West Africa. Although historically, the
company gave preference to targets with small amount of production and large
exploration upside, management has now expanded the criteria to screen
exploration prospects as well. We believe that in the current markets, the company
is well positioned to bid for undervalued assets.
Healthy balance sheet, strong cash flow generation
Next year we expect company to release $400mn of free cash that supported by the
cash balance of $1.5bn leaves enough flexibility both to pay out dividends with the
current yield of 2%, as well as aggressively hunting value-accretive acquisitions. No
debt and a large cash balance also make the stock defensive under current, weak
equity markets.
66
Renaissance Capital
Dragon Oil
6 October 2011
Attractive valuation
The company trades at a 34% discount to our GBp693/share target price. The stock
screens cheaply on P/E, EV/EBITDA multiples trading within a 31% discount to its
historical five-year average P/CF multiple of 5.5. The stock is highly cash-generative
with an 11% 2012E free cash flow yield.
Risks and sensitivities
Rig availability
In our valuation, we assume DGO will have three or four rigs at its disposal over
2011-2025 to drill the c.164 wells required to deliver production levels consistent
with the company’s 2P reserve base. However, we acknowledge that if the company
fails to secure at least three rigs, this could result in lower than assumed by us
production and hence impact our valuation.
Export routes
The company is currently exporting all its crude via the Baku-Tbilisi-Ceyhan pipeline
and we assume the company will be exporting its crude through BTC until the end of
the PSA. The company could change the export terms, which could impact our
valuation.
Gas monetisation
DGO is currently negotiating sales terms with the Turkmenistan government both for
short-term sales of wet gas as well as long-term sales of dry gas once the GTP is
commissioned. We exclude gas sales from our earnings estimates, but assume
$120/mcm of the long-term gas price in our valuation. Hence, the difference in the
long-term sales price would impact our valuation.
Political risk
DGO has operating assets in one country, Turkmenistan, hence political risk is not
diversified. We highlight the company’s longstanding relations with the Turkmenistan
government and are comfortable with the risk involved. Any further potential M&A
should help to diversify the single-country exposure.
Commodity pricing
Our long-term oil price assumption is $100/bbl. If market expectations on the longterm oil price differ from our assumption, the share price could deviate from our price
target. We have included the sensitivities to the long-term oil price and WACC
below.
67
Renaissance Capital
Dragon Oil
Figure 95: Sensitivity of NAC valuation to oil price and NAV
80
90
11.5%
642
703
12.5%
614
670
WACC
13.5%
588
640
14.5%
565
613
15.5%
544
589
100
764
727
693
662
634
110
826
783
745
711
679
6 October 2011
120
887
840
798
759
724
Source: renaissance Capital estimates
Our 12-month price target for DGO shares is GBp693, implying 52% upside
potential to the current share price.
Our preferred valuation method of E&P stocks is NAV, which is split into core NAV
and risked NAV. Under core NAV we value the economics of the LAM and Zhdanov
fields using a DCF approach, assuming a 2P production profile and adjusting for the
net cash position at 1H11. DCF helps us to capture dynamics of the fiscal regime,
cost structure and expected production profile.
For the risked NAV we value the company’s contingent resources base of 1.4tcf
assigning a 50% probability of success to reflect marketing and pricing uncertainties
around monetisation of these resources. We apply:

A long-term Brent assumption of $100/bbl for 2012 onwards.

A gas price assumption for NAV of $120/mcm flat for 2012 onwards (not
included in earnings estimates).

A WACC of 13.6%.
Figure 96: NAV valuation
Lam & Zhdanov liquids
Gas reserves
Net (debt)/cash 1H11
Core NAV
Gas Resources
Risked NAV
Core plus risked NAV
WI reserves
liquids, mmboe
639
260
Unrisked NPV,
$/boe
6.1
1.2
233
1.2
Unrisked asset
Value, $mn
3897
317
1472
5686
282
Risk factor/
CoS, %
100%
100%
50%
Risked
NPV, $mn
3897
317
1472
5686
141
Risked NPV,
GBp/share
463
38
175
676
17
17
693
Our preferred approach for multiples valuation for E&P companies is EV/DACF and
P/CF. Given the difficulty to obtain historical EV/DACF multiples we used
EV/EBITDA multiple as a proxy for EV/DACF. If we look at historical performance of
P/CF 12-month forward multiple we can see a good correlation between DGO and
the oil price until early 2011 when the relationship between the two disconnected.
The disconnect between the oil price and stock performance is not company-specific
but rather reflects the dynamics of the entire E&P sector, although DGO has been
oversold, in our view. The stock is trading at a 2012E P/CF multiple of 3.8x which is
at 34% discount to the historical average of 5.5x. It is also cheap on EV/EBITDA,
trading at 2012E 2.3x, a 40% discount to the historical average of 3.8x.
68
Renaissance Capital
Dragon Oil
6 October 2011
Valuation
Figure 97: Forward P/CF multiple (LHS) vs Brent (RHS)
Dragon Oil
5-yr average
Brent
160
12
140
10
120
8
100
6
80
60
4
40
2
20
0
Jul-11
Jan-11
Jul-10
Jan-10
Jul-09
Jan-09
Jul-08
Jan-08
Jul-07
Jan-07
Jul-06
Jan-06
0
69
Renaissance Capital
Dragon Oil
6 October 2011
Asset overview
Figure 98: DGO assets
Source: DGO
DGO plc’s principal development and production asset is the Cheleken contract
area, in the eastern section of the Caspian Sea, offshore Turkmenistan and west of
the coastal town of Hazar. The area covers approximately 950 km2 and comprises
two offshore oil and gas fields, Dzheitune (Lam) and Dzhygalybeg (Zhdanov), in
water depths of between 8-42 metres. The wells drilled are within the 3,000-5,000
range. The fields comprise two elongate anticlines situated at the eastern end of the
Apsheron Ridge, a prolific hydrocarbon play extending from the Apsheron Peninsula
in Azerbaijan to the Cheleken Peninsula in Turkmenistan, and dividing the South
Caspian and Middle Caspian Basins. A 3D seismic survey of the field was acquired
in 2004/2005; the interpretation was completed, while continuous additional studies
and refinement are ongoing.
LAM (Dzheitun), which was discovered in 1972 and started producing in 1978; and
Zhdanov (Dzhygalybeg), which was discovered in 1968 and started producing in
1972. They were partially developed in the 1970s and 1980s by over 110 wells, with
production piped to shore for processing and storage. After the break-up of the
Soviet Union, Larmag Energy Assets (LEA) and Chelekenmorneftegaz, currently
part of Turkmenneft, set up a 50:50 JV to develop the fields and explore the
associated acreage in the South Caspian Basin. After taking the entire 50% share in
the joint venture, Dragon signed a PSA with Turkmenneft and commenced a drilling
programme at the Lam field in 2000-2001. At the time, only c.16 of the Soviet era
wells were still in service, producing cumulatively less than 8kbopd, while most of
the existing platforms were either in poor condition or abandoned.
Structurally, the fields are characterised by multiple reservoirs with over 100
hydrocarbon bearing layers. The reservoir is of a decent quality with porosity is
ranges between 15-20%, whereby permeability is between 22-95 milidarcies.
The Group is producing from a significant number of new and old wells and has an
aggressive development programme comprising the drilling of new wells and an
ongoing workover programme. Average daily gross field production increased from
approximately 7kboepd in 2000 to over 57kboepd at the turn of 2010-2011.
The produced crude is high quality with 35-45 API and low sulphur content, but is
waxy, containing high levels of paraffin and asphaltene.
70
Renaissance Capital
Dragon Oil
6 October 2011
Dzheitune (LAM)
The Lam Field is located to the south-west of the Zhdanov field. Since the
commencement of the PSA in 2000, DGO has drilled 53 new wells on the Lam field
as of 29 March 2011, constructed and installed two new platforms with plans to
install one more platform in late 2011, refurbished and upgraded existing platforms
and performed a number of successful workovers. Currently there are nine
producing platforms in the field.
Dzhygalybeg (Zhdanov)
The Zhdanov Field is located to the north-east of the Lam field. The initial
exploration and prospecting of the Zhdanov structure began in 1965. The first well
with commercial oil and gas was drilled in 1966. The field has produced oil and gas
from a series of numerous, stacked early to middle Pliocene Red Series sandstone
reservoirs. DGO has completed a number of successful workovers in the Zhdanov
Field and plans to install its first new platform, Zhdanov A, in early 2012.
Ownership
Figure 99: DGO shareholders
Free float, 29.7%
Enoc, 51.4%
Baillie Gifford , 6.0%
Artio Global
Management, 6.1%
JP Morgan Asset
Man, 6.8%
Asset development
Since signing the PSA, DGO has embarked on an active appraisal and development
programme, and significantly ramped up production. Over the past four years, the
company has increased production at a 15% CAGR, having reached 57kboepd in
the first half of 2011 from 32kboepd in 2007. DGO has managed to significantly
improve oil flow rates which average around 2.5kboepd compared with average flow
rates of 800 boepd during Soviet times. The following factors have underpinned the
company’s success in ramping-up operations:

An improved understanding of subsurface dynamics, and identifying new
drilling targets through comprehensive 3D seismic data.

Installing two new wellhead and production platforms with the 12 currently
operating platforms.
71
Renaissance Capital
Dragon Oil
6 October 2011

Drilling 53 new wells bringing the producing well count to 77 wells.

Improving well productivity through the application of directional drilling,
multi-packer and dual completions.
Moreover, in addition to the development of drilling side of the business, the
company has made investments in infrastructure, allowing it to de-bottleneck
production, specifically:

Building a 30-inch, 40 km-long pipeline from the offshore area to the
processing plant.

Building a plant to process and separate oil and water.

Bringing the capacity of the entire system (trunk line and processing facility)
to around 100kboepd.
Development plan
During the first half of the year, DGO drilled eight of the planned 12 development
wells for 2011. This year, it reached a major milestone by increasing production 20%
– mainly as a result of the new wells and the new 30-inch pipeline, allowing it to debottleneck production growth. Currently, DGO is utilising three rigs: Iran-Khazar, NIS
and its own Rig 40 that will complete drilling of the remaining four wells. Overall, we
note decent flow rates, averaging 2400kboepd. Well performance has varied
between the zones, with the more prolific area (28) flowing, on average, 3boepd vs.
1.6kboepd at zone B.
Figure 100: Development drilling in 2011
Well
Rig
Completion date Depth (metres) Type of completion Test rate, boepd
B/150
Iran Khazar
January
3980
Dual
1,622
28/152
NIS
March
3768
Dual
3,463
B/153
Iran Khazar
March
3668
Dual
2,428
28/154
NIS
May
1830
Single
3061
B/155
Iran Khazar
June
2800
Dual
783
28/156
NIS
July
2000
Single
3,038
B/157
Iran Khazar
July
2900
Single
1,767
28/158
NIS
August
1786
Single
2,876
Average flow rate
2,380
Technically, the company could accelerate production growth by intensifying drilling,
which is constrained by the number of rigs. Rig availability in the Caspian is an
issue, given transportation difficulties. To support its intensive drilling campaign
DGO has ensured rig availability by:

Extending the Khazar Rig contract for a further two years, through to 2013,
bringing the total contract length to eight years.

Rig 40, DGO’s own rig, remaining operational.

Leasing a Super M5 jack-up rig which is expected to be delivered in 1Q12.
The rig will be leased for five years, with the option of a two-year extension.

Building a 3,000 hp land rig (under construction) that will drill from the
Zhdanov A platform
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In our model, we have assumed DGO will be operating, on average, four rigs to
support development drilling. The procurement of additional rigs would have an
immediate effect on the intensity of development drilling, translating into a higherthan-expected production ramp-up, which will increase our base-case valuation.
Looking forward, over 2011-2013, management plans to deliver a 40-well
programme that includes five appraisal wells. The drilling programme is planned to
boost production by about 10-15%, on average, for the next three years. In our
model, we have assumed a total of 164 wells to be drilled over the next 13 years
which will allow DGO to reach a production plateau of 100kbpod by 2017. The
increase of processing facilities to 100kboepd capacity reassures us that this is the
plateau rate management expects to reach.
Figure 101: Number of development wells (LHS) vs gross production kboepd (RHS)
Well count
Production
14
120
12
100
10
80
8
60
6
40
4
20
2
0
0
2011
2014
2017
2020
2023
2026
2029
2032
2035
Figure 102: DGO, kboepd
Working interest
Entitlement
120
100
80
60
40
20
0
2007
2010
2013
2016
2019
2022
2025
2028
2031
2034
At present, 77 wells are producing from 12 platforms. To support planned drilling
intensity and exploit the deep reserves potential of the Cheleken area, DGO is
expanding its platform base. The company has budgeted to spend in excess of
$200mn on an infrastructure upgrade programme, with expectations of a second
platform at Zhdanov B to be installed during 1Q12. Moreover, two additional
platforms on the Lam field (Lam D and Lam E) are expected to come on stream
during the next 18 months.
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Renaissance Capital
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6 October 2011
Export routes

At present, DGO exports 100% of its oil production via the Baku-TbilisiCeyhan pipeline, for which we have assumed the company pays $1113/bbl.

Historically, DGO has used other routes, including swap arrangements at
the Iranian port of Neka with a sale point at Kharg Island for Iranian light.

Other options for transportation include shipment by tanker to
Makhachkala, Russia, and by tanker to Azerbaijan, with product sold either
FOB Baku or transported by rail, through Georgia, to the Black Sea port of
Batumi.
Upside from gas monetisation underestimated
At present, DGO produces around 100mmscfpd of associated gas which is
separated and flared offshore. Some gas is transported by pipeline to the onshore
oil and gas separation facility. DGO has a very large gas resource base, with 1.6tcf
of gas reserves and 1.4tcf of contingent resources. In our view, gas is assigned little
value if any by the market and we see significant upside from monetisation of both
reserves and contingent resources. Management is in negotiations with the
Turkmenistan government on a range of gas monetisation options, and we expect
further newsflow on developments here in the next 12 months.
The first part of the gas monetisation strategy involves finalising a short-term sales
agreement with the Turkmenistan government to deliver unprocessed gas to the
Turkmen system, which is awaiting the commissioning of a compressor station by
the government.
The second part of the monetisation strategy will involve the construction of a GTP,
and the negotiation of a sales price for dry gas with the Turkmenistan government.
GTP construction is a prerequisite for realising value for the gas, by stripping
condensate while delivering dry gas suitable for the Turkmen system.
Construction of the 200mcf/d GTP is estimated to absorb around $150-170mn of
investment and is expected to come on stream by early 2014. DGO still has to
negotiate a sales contract, with the marketing route, delivery point and gas price the
main areas of uncertainty. Under its PSA terms, DGO is allowed to sell the gas at
the export price. There are three main directions in which the Turkmenistan gas
could be exported, with a fourth emerging direction towards Ukraine:

To China, via the Turkmenistan-Uzbekistan-Kazakhstan China pipeline.

To Russia, via a gas pipeline through Kazakhstan.

To Iran, via the new line connecting the Dovletabad field to the Khangiran
gas processing plant.
It is becoming clear that Turkmenistan’s strategy is oriented towards the
diversification of its export routes, as Chinese appetite for Turkmen gas is
increasing. First gas exports to China began last year with the launch of the
Turkmenistan-China pipeline. By August this year, total exports to China had
reached 13bcm YtD, compared with 4bcm last year, and we expect volumes to rise
further. Accordingly, robust demand for Turkmen gas sets solid grounds for DGO to
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Renaissance Capital
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6 October 2011
benefit from attractive pricing dynamics. Gas prices at the Turkmenistan border
range between $200-250/mcm across all three export destinations. According to
recent anecdotal evidence, Petronas which is producing offshore Western
Turkmenistan (close to DGO’s fields) sells its gas for $120-120mcm. We exclude
gas sales from our earnings estimates, but have assigned a conservative value of
GBp67/share in our valuation, assuming $120/mcm for the long-term dry gas. We
take a conservative stance, first to reflect the location of DGO’s assets in Western
Turkmenistan, and the consequent need to build a pipeline in order to gain exposure
to Chinese demand, as well as the first priority of Turkmenistan’s own volumes for
exports. If we increase our long-term gas price to $200/mcm this will add another
GBp70/share to our valuation.
DGO’s very large gas resource base, underpinned by favourable pricing dynamics,
makes gas monetisation an additional source of gas value uplift.
Figure 103: Quarterly gas prices in Turkmenistan
Gazprom price to Ukraine
Turkmen price to Gazprom
Turkmen price to Iran
Turkment price to China
400
350
300
250
200
150
100
50
Q1'08 Q2'08 Q3'08 Q4'08 Q1'09 Q2'09 Q3'09 Q4'09 Q1'10 Q2'10 Q3'10 Q4'10 Q1'11
What is the exploration potential for DGO?
The Cheleken contract area has a long history and is predominantly a
redevelopment of fields first developed in the Soviet era. Provided that it is a
redevelopment, the Cheleken area is well studied with 58 wells drilled by the
Soviets, so there is generally a limited exploration upside. Where company could
add value in terms of the exploration upside is through additional drilling of
delineation wells at Lam 28 and other areas, but that would offer marginal
opportunity to add reserves from the existing fields. DGO is targeting to drill five
appraisal wells over the next three years which will shed more light on whether more
reserves could be added. DGO acquired minor interests in three exploration blocks
n Yemen (R2, Block 35 and 49) in 2007 but these were unsuccessful and interests
in 2 blocks (R2 and 49) have been relinquished. The company is reviewing
participation in the remaining block.
DGO looks like a compelling M&A target…
Turkmenistan with its proven gas reserves of 8tcm is in need of foreign investment
to enable it to unlock its resource potential. This year, Turkmenistan also signed an
agreement under which China Development Bank will provide $4.1bn of financing to
fund the development of the South Yolotan field (reserves estimates range from 515tcm). At the same time, the government has said international companies should
focus on projects offshore Turkmenistan while leaving the development of Eastern
75
Renaissance Capital
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6 October 2011
Turkmenistan gas fields mainly to itself. Very few international companies currently
operate offshore Turkmenistan, among them DGO, Malaysian Petronas and Burren
Energy (Acquired by ENI in 2007). In our view, DGO is an appealing candidate for
both international majors and Chinese companies, given its growth potential and
solid cash flow generation, coupled with a robust balance sheet and stable fiscal
terms. However, we think DGO’s strategic shareholder, ENOC, will be reluctant to
sell its stake, and will keep trying to increase its stake by buying out minority
shareholders. In 2009, a takeover of DGO was attempted by ENOC, but the bid was
rejected by minorities. ENOC offered GBp455/share, implying a 34% premium to the
DGO share price at the time. We also want to bring to your attention $3.5bn ENI’s
acquisition of Burren Energy in 2007, which implied a multiple of $13.5/bbl for 2P
reserves. Just to highlight, DGO screens cheaply on the reserves multiple and is
currently trading at $2.7/boe of 2P reserves.
…as well as a potential acquirer, with its $1.5bn cash balance
Provided DGO has limited opportunities to grow reserves organically, its cash
balance of $1.5bn sets a solid foundation to grow reserves through M&A. The
company is considering acquisitions across various geographies, including Central
Asia, the Middle East, North and West Africa. Although historically it has given
preference to targets with low production volumes and large exploration upside,
management has now expanded the criteria to screen exploration prospects as well.
DGO is most comfortable with targeting 2P reserves around 50-100mmboe, offering
transaction value of between $200-500mn. From the exploration angle, onshore
assets are given preference over deepwater assets. We believe that in the current
market environment, the company is well positioned to bid for undervalued assets.
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6 October 2011
Financial framework
We view the Cheleken PSA terms as favourable by international standards. Under
the PSA:

Initial oil, pre-PSA production, which is about 2kbpd, currently declines
constantly at 7.5% is not subject to royalties and is allocated to
Turkmenneft.

A royalty is levied on the incremental production on a sliding production
ranging from 1 to 15% depending on production rates. Based on our
production forecast, royalty rates range between 5-6%.

DGO is entitled to recover 70% of the post-royalty net revenues deemed as
cost oil (current capex and opex and carry-forward from previous periods).

The remaining net revenue post cost oil is referred to as profit oil, of which
7.5% is set aside for the abandonment fund.

The company is entitled to 40-60% of the remainder, depending on the “R
factor” (the ratio of cumulative revenue to cumulative costs).

The income tax rate is 25%.
In Figure 106, we set out the total taxes DGO pays to the government as a
proportion of total revenues, assuming a $100/bbl oil price. At the production rampup stage for the next few years (2012-2014), the company benefits from a relatively
low tax burden, sharing with the government, on average, 59% of revenues,
compared with 70% at the back end of the production cycle (2023-2025), which
positively impacts the valuation. The PSA regime is not progressive like the Russian
upstream, hence the company benefits from increasing oil prices.
From an economic perspective, we believe that due to the time value of money
effect, if the company beats our expectations by intensifying drilling and thereby
accelerating its production growth it would further increase our valuation. As
mentioned, the availability of rigs in the Caspian is a bottleneck for delivering even
higher production than the expected 10-15% CAGR for production growth.
Figure 104: Government take as a proportion of revenues @ $100/bbl Brent
Royalty
State Profit oil
Income tax
100%
80%
60%
40%
20%
0%
2011
2014
2017
2020
2023
Dragon has low lifting costs of $4/bbl that are comparable with Russian majors and
3x less than KMG EP is spending. Although DGO is expected to invest around
77
Renaissance Capital
Dragon Oil
6 October 2011
$500-600mn of capex on development drilling and infrastructure, the company is still
highly cash-flow-generative, producing $6-8/bbl of free cash flow every year, on our
estimates.
Figure 105: Capex $mn (LHS) vs capex as a % of op. cash flow (RHS)
Development capex
Capex as a % of ops cashflow
700
70%
600
60%
500
400
50%
253
308
308
40%
169
300
114
30%
200
100
20%
250
271
271
271
271
2011
2012
2013
2014
2015
10%
0
0%
Though the dividend yield is relatively low, the stock generates a free cash flow yield
of 10-15%, which leaves room for a further dividend increase.
Figure 106: Dividend and free cash flow yields 2012E
Dividend yield
FCF yield
16%
14%
13%
14%
12%
10%
10%
11%
10%
8%
6%
4%
2%
2%
2%
2%
2%
2%
0%
2011
2012
2013
2014
2015
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Renaissance Capital
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6 October 2011
Figure 107: Income statement, $mn
Revenue
Opex
DDA
Gross profit
G&A
Gain/loss on disposal
Other gains and losses
Operating profit
Interest expense
Interest income
Pre-tax profit
Income tax
Net income
2009
624
-93
-189
341
-27
0
0
314
31
345
-86
260
2010
780
-77
-188
516
-28
0
0
488
0
27
515
-129
386
2011E
1,210
-92
-227
890
-27
2012E
1,145
-93
-256
796
-27
2013E
1,244
-105
-288
851
-27
2014E
1,261
-117
-322
821
-27
2015E
1,343
-161
-355
827
-27
863
769
824
794
800
21
884
-221
664
26
795
-199
596
31
855
-214
642
37
831
-208
624
44
844
-211
633
Figure 108: Cash flows, $mn
Cash flow from operations
Change in working capital
Cash flow from operations
Capex
Dividends paid
Other cash flow from investing
Net cash flows
2009
373
127
500
-317
2010
513
82
595
-460
-413
-182
-298
-127
2011E
891
33
924
-503
-139
282
2012 E 2013 E 2014 E 2015 E
852
930
946
988
144
101
45
-3
997
1030
991
985
-579
-579
-440
-385
-88
-87
-88
-88
330
365
463
513
Current assets
Current liabilities
PPE
Non-current assets
Capital employed
Total equity
2009
1,138
1,238
-355
908
909
1,703
1,703
2010
1,337
1,482
-482
1,176
1,176
2,093
2,093
2011 E
1,618
1,844
-595
1,452
1,452
2,617
2,617
2012 E
1,948
2,161
-727
1,775
1,775
3,126
3,126
2013 E
2,313
2,545
-847
2,066
2,066
3,681
3,681
2014 E
2,776
3,011
-895
2,183
2,183
4,216
4,216
2015 E
3,289
3,539
-907
2,213
2,213
4,762
4,762
79
Renaissance Capital
Show me the munai
6 October 2011
Disclosures appendix
Analysts certification and disclaimer
This research report has been prepared by the research analyst(s), whose name(s) appear(s) on the front page of this document, to provide background information about the
issuer or issuers (collectively, the “Issuer”) and the securities and markets that are the subject matter of this report. Each research analyst hereby certifies that with respect to
the Issuer and such securities and markets, this document has been produced independently of the Issuer and all the views expressed in this document accurately reflect his or
her personal views about the Issuer and any and all of such securities and markets. Each research analyst and/or persons connected with any research analyst may have
interacted with sales and trading personnel, or similar, for the purpose of gathering, synthesizing and interpreting market information. If the date of this report is not current, the
views and contents may not reflect the research analysts’ current thinking.
Each research analyst also certifies that no part of his or her compensation was, or will be, directly or indirectly related to the specific ratings, forecasts, estimates, opinions or
views in this research report. Research analysts’ compensation is determined based upon activities and services intended to benefit the investor clients of Renaissance
Securities (Cyprus) Limited and any of its affiliates (“Renaissance Capital”). Like all of Renaissance Capital’s employees, research analysts receive compensation that is
impacted by overall Renaissance Capital profitability, which includes revenues from other business units within Renaissance Capital.
Important issuer disclosures
Important issuer disclosures outline currently known conflicts of interest that may unknowingly bias or affect the objectivity of the analyst(s) with respect to an issuer that is the
subject matter of this report. Disclosure(s) apply to Renaissance Securities (Cyprus) Limited or any of its direct or indirect subsidiaries or affiliates (which are individually or
collectively referred to as “Renaissance Capital”) with respect to any issuer or the issuer’s securities.
A complete set of disclosure statements associated with the issuers discussed in the Report is available using the ‘Stock Finder’ or ‘Bond Finder’ for individual
issuers on the Renaissance Capital Research Portal at: http://research.rencap.com/eng/default.asp
Zhaikmunai LP
RIC: ZKMq.L
Renaissance Capital is either a market maker or on a continuous basis has sold to/bought from customers on a principal basis the securities or related securities of the issuer at
prices defined by Renaissance Capital.
Dragon Oil Plc
RIC: DGO.I
prices defined by Renaissance Capital.
KazMunayGaz Razvedka Dobycha AO
RIC: RDGZ.KZ
prices defined by Renaissance Capital. Investment ratings
Investment ratings may be determined by the following standard ranges: Buy (expected total return of 15% or more); Hold (expected total return of 0-15%); and Sell (expected
negative total return). Standard ranges do not always apply to emerging markets securities and ratings may be assigned on the basis of the research analyst’s knowledge of
the securities.
Investment ratings are a function of the research analyst’s expectation of total return on equity (forecast price appreciation and dividend yield within the next 12 months, unless
stated otherwise in the report). Investment ratings are determined at the time of initiation of coverage of an issuer of equity securities or a change in target price of any of the
issuer’s equity securities. At other times, the expected total returns may fall outside of the range used at the time of setting a rating because of price movement and/or volatility.
Such interim deviations will be permitted but will be subject to review by Renaissance Capital’s Research Management.
Where the relevant issuer has a significant material event with further information pending or to be announced, it may be necessary to temporarily place the investment rating
Under Review. This does not revise the previously published rating, but indicates that the analyst is actively reviewing the investment rating or waiting for sufficient information
to re-evaluate the analyst’s expectation of total return on equity.
If data upon which the rating is based is no longer valid, but updated data is not anticipated to be available in the near future, the investment rating may be Suspended until
further notice. The analyst may also choose to temporarily suspend maintenance of the investment rating when unable to provide an independent expectation of total return
due to circumstances beyond the analyst’s control such as an actual, apparent or potential conflict of interest or best business practice obligations. The analyst may not be at
liberty to explain the reason for the suspension other than to Renaissance Capital’s Research Management and Compliance Officers. Previously published investment ratings
should not be relied upon as they may no longer reflect the analysts’ current expectations of total return.
If issuing of research is restricted due to legal, regulatory or contractual obligations publishing investment ratings will be Restricted. Previously published investment ratings
should not be relied upon as they may no longer reflect the analysts’ current expectations of total return. While restricted, the analyst may not always be able to keep you
informed of events or provide background information relating to the issuer.
Where Renaissance Capital has not provided coverage of an issuer for a period of 12 months, coverage shall be deemed discontinued.
Where Renaissance Capital has not expressed a commitment to provide continuous coverage and/or an expectation of total return, to keep you informed, analysts may prepare
reports covering significant events or background information without an investment rating (Unrated).
Your decision to buy or sell a security should be based upon your personal investment objectives and should be made only after evaluating the security’s expected performance
and risk.
Renaissance Capital reserves the right to update or amend its investment ratings in any way and at any time it determines.
80
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Renaissance Capital equity research distribution ratings
Investment Rating Distribution
Renaissance Capital Research
Buy
Hold
Sell
Under Review
Suspended
Restricted
Investment Banking
Relationships*
Renaissance Capital Research
Buy
Hold
Sell
Under review
Suspended
Restricted
118
58
11
26
0
0
213
55%
27%
5%
12%
0%
0%
2
1
0
0
0
0
3
67%
33%
0%
0%
0%
0%
Zhaikmunai LP share price, target price and rating history
Restricted
Suspended
Unrated
Under Review
Buy
Hold
Sell
Last Price
Series2
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
May-08
Jun-08
Jul-08
Aug-08
Sep-08
Oct-08
Nov-08
Dec-08
Jan-09
Feb-09
Mar-09
Apr-09
May-09
Jun-09
Jul-09
Aug-09
Sep-09
Oct-09
Nov-09
Dec-09
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Jan-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
Sep-11
18
16
14
12
10
8
6
4
2
0
Source: Renaissance Capital, prices local market close or the mid price if illiquid market
Dragon Oil Plc share price, target price and rating history
Restricted
Suspended
Unrated
Under Review
Buy
Hold
Sell
Last Price
700
Series2
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
600
500
400
300
200
100
May-08
Jun-08
Jul-08
Aug-08
Sep-08
Oct-08
Nov-08
Dec-08
Jan-09
Feb-09
Mar-09
Apr-09
May-09
Jun-09
Jul-09
Aug-09
Sep-09
Oct-09
Nov-09
Dec-09
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Jan-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
0
81
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KazMunayGaz Razvedka Dobycha AO share price, target price and rating history
Restricted
Suspended
Unrated
Under Review
Buy
Hold
Sell
Last Price
45
40
35
30
25
20
15
10
5
0
Series2
May-08
Jun-08
Jul-08
Aug-08
Sep-08
Oct-08
Nov-08
Dec-08
Jan-09
Feb-09
Mar-09
Apr-09
May-09
Jun-09
Jul-09
Aug-09
Sep-09
Oct-09
Nov-09
Dec-09
Jan-10
Feb-10
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Jan-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
82
Renaissance Capital research team
Head of Equity Research
Deputy Head of Equity Research
Research COO
Head of South African Research
Head of Turkish Equity Research
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Name
Equity Strategy
Charles Robertson
Ovanes Oganisian
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258-7748
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641-4189
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258-7770 x4908
258-7789
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750-1462
750-1473
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750-1488
750-1462
Russia/CIS
Russia/CIS
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