Initial Coverage Russian Oil & Gasir.gazprom-neft.com/fileadmin/user_upload/... · Lukoil – 15% pa div growth outpaces peers’, 28% valuation discount Gazprom neft – 8% dividend

Research Department + 7 (495) 785-53-36 www.bcs.ru

Timur Salikhov, CFA +7 (495) 785 5336 (4631)

[email protected]

Initial Coverage

Thursday, August 1, 2013

Russian Oil & Gas Greenfields – key to profitability and stability

We are initiating coverage of the Russian Oil & Gas sector, which we characterize as both facing notable challenges and offering select investment plays. Greenfield exposure, shareholder returns (dividends, growth and valuation), catalysts and risks are best balanced in Lukoil, Novatek and Gazprom neft.

Greenfields – vital to growth, beneficiaries of sector tax reform; c20% IRR on avg

o Brownfields face diminishing returns on declining production and rising CapEx

o Higher taxes to undermine profitability of refinery upgrades & brownfield gas

Lukoil – 15% pa div growth outpaces peers’, 28% valuation discount

Gazprom neft – 8% dividend yield highest among peers, 31% valuation discount

Novatek – highest EPS growth (18% CAGR 2012-15e), most S-T catalysts

Greenfield exposure – new sources of returns and long-term stability. Oil & Gas producers with larger exposure to greenfields should enjoy robust investment returns in the long term and benefit from the ongoing sector transformation and tax changes, contrary to those adhering to traditional production regions – i.e., brownfields. Under the proposed new tax rules, greenfields, especially NGL-rich fields, will generate >20% IRR on average, we estimate. Our standalone field analysis calculates the top 25 greenfields are worth $75bn in NPV terms, or a quarter of the companies’ market cap.

Refining, brownfield gas – profitability at risk on tax hikes. Indeed, as tax-exempt greenfield barrels substitute in for brownfield production, and light oil products replace heavier-taxed fuel oil following refinery upgrades, the risks to oil & gas budget tax revenues are skewed to the upside. In light of this, the expected higher profitability of refinery upgrades, and already high gas margins are likely to be undermined

Lukoil and Gazprom neft – robust shareholder returns, attractive valuation. Lukoil and Gazprom neft are our preferred exposures among the large-cap and mid-tier oils, respectively. The two companies will generate the highest shareholder returns over the next three years, we estimate – Lukoil’s FCF will allow it to deliver the highest dividend growth (15% pa), while Gazprom neft’s dividend yield is among the highest in the sector (8% vs 4%) – and are trading at attractive valuations relative to their peers (3.9x and 3.6x P/E ’14, respectively, vs sector’s average of 5.1x).

Novatek – strong growth and short-term catalysts. Novatek remains the fastest-growing company among Russian oil & gas majors (2012-15e EPS CAGR of 18%), justifying its valuation premium. Positive news flow in the autumn – liberalization of LNG exports, new LNG delivery contracts, FID on Yamal LNG and the potential entry of another partner – should de-risk Novatek’s flagship Yamal LNG project (19% of fair value), thus adding significant value to the company.

Both Lukoil and Gazprom neft are trading at a substantial discount Novatek has been de-rating over past 3 years

Source: FactSet

Top picks – Lukoil, Gazprom neft and Novatek Company Rating Current Target Upside Dividend MCap, EV, P/E EV/EBITDA price price

yield ‘13 $mn $mn ‘14e ‘15e ‘14e ‘15e

Lukoil BUY $59.80 $75.00 25% 5.4% 45,141 49,757 3.9x 4.5x 2.4x 2.5x

Gazprom neft BUY $18.05 $25.00 39% 7.7% 17,032 23,100 3.6x 4.2x 2.6x 2.8x

Novatek BUY $116.00 $145.00 25% 2.4% 35,185 38,737 11.2x 9.5x 8.9x 7.6x

Rosneft HOLD $7.16 $8.30 16% 3.4% 75,882 136,140 6.2x 6.8x 4.9x 4.8x

Gazprom HOLD $7.85 $8.50 8% 5.1% 90,069 135,165 2.9x 2.9x 2.6x 2.6x

Bashneft HOLD Rb1,990.00 Rb2,100.00 6% 5.3% 11,402 15,196 7.1x 7.4x 5.1x 5.2x

Surgutneftegas (pref) HOLD Rb21.44 Rb23.50 10% 5.7%

5.0x 5.1x 0.4x 0.5x

Surgutneftegas (ord) SELL $8.07 $8.30 3% 1.2% 28,813 3,675 5.0x 5.1x 0.4x 0.5x

Tatneft SELL $37.02 $39.00 5% 4.3% 13,079 15,432 6.1x 6.0x 4.4x 4.4x

Alliance Oil SELL SEK 43.75 SEK 41.00 -6% - 1,145 3,203 2.6x 2.3x 3.4x 3.2x

Transneft (pref) SELL Rb81,878.00 Rb75,000.00 -8% 0.8%

3.1x 2.9x 3.1x 2.9x

As of 30 July 2013 Source: FactSet, BCS

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mailto:[email protected]

Initiation of Coverage – Russian Oil & Gas

2

Contents Investment Case 3

Recommendation Summary 5

Catalysts 8

Valuation 10

Sector Outlook 12

Lukoil 25

Novatek 30

Rosneft 35

Gazprom 39

Gazprom neft 46

Bashneft 48

Alliance Oil 50

Surgutneftegas 52

Tatneft 54

Transneft 56

Risks to BCS theses 58

Valuation methodology 60


3

Investment case We are initiating coverage of the Russian Oil & Gas sector. Our top picks are Lukoil (TP $75/GDR, 25% upside) and Novatek (TP $145/GDR, 25% upside) among large-caps, and Gazprom neft (TP $25/GDR, 39% upside) among mid-tier oils. The companies score the highest among peers on a combination of shareholder returns (dividends, growth and valuation), upcoming catalysts and risk.

Lukoil is a rare example of a Russian energy company willing to translate its strong FCF generation into higher shareholders returns through dividends.

Novatek’s robust growth, strong execution, a portfolio of value-enhancing expansion projects and up-coming catalysts justify the premium valuation.

Gazprom neft is a generous dividend paying, decently growing company with large exposure to high-return greenfields, which the market is not pricing in.

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Source: BCS

2.6 2.9 3.2 3.6 3.95.0

6.1 6.27.1

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Rosn

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P/E '14

8.1%

6.9%6.5%6.4%6.1%

4.2%3.6%

3.1%2.6%

1.4%

0%1%2%3%4%5%6%7%8%9%

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Dividend yield, 2013-15 average

4% 4%

3%

1%1%

0%

-2%-2% -2%

-4%-5%-4%-3%-2%-1%0%1%2%3%4%5%

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EBITDA CAGR 2013-16

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Gazprom Gas export sales growth Gas agreement with China

Novatek liberalization of LNG exports FID on Yamal LNG entry of new partner(s) in Yamal

LNG new domestic gas supply

contracts

Lukoil interim dividend exploration drilling in West

Africa

Gazprom neft interim dividend introduction transfer of additional licenses

from Gazprom greenfield tax breaks

Rosneft decision on Sakhalin LNG

Bashneft interim dividend introduction Trebs and Titov launch

TatneftSurgutneftegas Hydrocracker launch

Alliance Oil refinery launch delay

Transneft Slower than expected

convergence to 25% IFRS profit payout

Lukoil

Novatek

Gazprom neft

Catalysts

Returns

Valuation


4

Greenfield exposure – new sources of profitability

Greenfield exposure for Russian oil and gas companies is necessary to remain profitable and competitive, to sustain returns and long-term growth, and to benefit from the on-going tax changes. We highlight Rosneft, Gazprom neft, Lukoil and Novatek as long-term beneficiaries.

Greenfield exposure a beneficiary of ongoing tax changes:

Downside risk limited for greenfields’ returns: The proposed greenfield tax reform will guarantee a minimum return (16.3% IRR) on new projects unlike the old system of ad hoc tax breaks. We expect such step to stimulate investments, especially as brownfields’ returns deteriorate and refining is more heavily taxed.

Taxation on brownfields unlikely to ease: Costs are rising to maintain stable production. We highlight that oil & gas’ contribution to budget tax revenue in the late 2010s will be lower as tax exempt oil barrels replace brownfield production and light products substitute higher taxed fuel oil. Given the sector’s lion share in budget revenue, we do not expect the government to ease the tax burden on companies’ legacy operations.

Downstream exposure is profitable, but runs risk of a tax hike: Assuming a stable macro environment, downstream operations could become 40% more profitable and highly FCF generative once refinery modernization is complete (2016-18). However, as light products replace highly-taxed fuel oil, contributions to the budget revenues will decrease, thus increasing the risk of further tax hikes.

Robust gas sector returns could handle further tax increase: Russian gas projects are one of the most profitable in the world because of the relatively low tax burden. Although the formula-based MET approach has finally set more transparent rules for sector taxation, one cannot completely rule out the possibility of upward base rate adjustments (as has already occurred in oil). We see gas sector tax risks increasing for the period beyond 2015.

Greenfield exposure instills stable shareholder returns and value-accretive growth:

Brownfields’ returns are declining: Despite the additional government stimulus (adoption of ‘60-66’ in 2011), crude production in traditional regions (West Siberia) continues to roll over (currently at 1% pa) and becomes more and more expensive to maintain (brownfield CapEx nearly doubled since 2009). Even though some companies improved the brownfields’ production dynamics, the additional barrels were not sufficient to sustain past returns.

Guaranteed investment returns on greenfields: The proposed greenfield tax reform will set a floor to projects’ investment returns (16.3% IRR). We estimate the top 25 greenfields (some of them already operating) are worth $75bn in NPV terms versus $200bn CapEx yet to be invested. Moreover, greenfields will eventually be two-four times cheaper to maintain (e.g., Verkhnechonsk’s and Vankor’s $3.8/boe and $2.1/boe long-term maintenance CapEx, respectively, versus Yuganskneftegas’s $7/boe).

Profitable gas exposure: Despite multiple regulatory risks (slower than expected tariff growth, potential tax hike), gas greenfields could generate robust investment returns, we estimate. Wet gas exposure is a significant contributor to profitability.

Cost-competitive LNG poised to benefit from robust Asian demand growth: Although capital-intensive at a first glance, Russian LNG projects are located at the bottom end of the global cost curve ($8-9/mmbtu). Favorable geographical location of future plants makes them perfectly suited to benefit from robust Asian gas demand, on the one hand, and to increase market share in Europe by tapping previously unattainable markets, on the other hand.


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Recommendation summary1

Buy

Lukoil (TP $75/GDR) – Highest shareholder returns in the sector

Robust dividend growth (15% pa) translates into highest returns among peers Diversified asset growth portfolio (Uzbek gas, Iraqi PSA, tax-exempt Caspian fields)

implying gradual production and earnings increase Consensus has yet to re-assess the FCF outlook taking into account CapEx

optimization and West Qurna-2 immediate cost recovery West Siberian production starting to show positive signs: June statistics show

production decline rate is decelerating Attractive valuation - 3.9x P/E '14 - does not reflect robust shareholder returns

Novatek (TP $145/GDR) – Robust growth & catalysts

Strong execution track-record, value-accretive expansion projects and vast resource base have justified Novatek's valuation premium…

… which we expect to persist going forward, given Novatek's robust growth prospects and investment returns

Anticipated growth is significantly above the sector average, accelerating in the second half of the decade once Gydan fields and Yamal LNG come on-stream

The stock is especially attractive in the short term, given numerous up-coming catalysts de-risking Novatek's flagship Yamal LNG project (19% of our fair value)…

… which offsets a handful of industry regulatory risks, including slower domestic tariff growth and gas and condensate MET hike

Gazprom neft (TP $25/GDR) – Robust growth, highest shareholder returns

Highest shareholder returns over the next two years (6% pa EPS growth and 9% dividend yield)

Robust FCF generation in the long-term (c$16bn during 2017-21, equivalent to current market cap)

Valuation implies a 31% discount to peers vs 12% during 2010-12 Large portfolio of greenfield projects (1.1mmboe/d hydrocarbon production) is not

in the price, while additional tax breaks imply further potential upside Catalysts include additional greenfield tax breaks, transfer of oil licenses from

Gazprom and potential liquidity improvement, however, outcomes are twofold and timing is uncertain

1 For risks to BCS theses and valuation methodology, please refer to pages 58-60


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HOLD

Rosneft (TP $8.30/GDR) – Shareholder returns captive to high CapEx

Solid financial position and immense FCF generation capabilities TNK-BP merger synergies have yet to be monetized, reflected in stock valuation Primary beneficiary of the greenfield tax reform proposals… … due to largest portfolio of greenfield projects, potentially translating into robust

returns in the long term However, large CapEx requirements in coming decade… … restrain near-term shareholder returns to the 4% dividend yield, one of the

lowest among peers

Gazprom (TP $8.50/GDR) – World’s cheapest energy name, for good cause

World's cheapest energy name (2014e P/E of 2.9x) reflects poor ROI Stock value is worth Gazprom's future dividend stream Dividend yield, currently 5%, will be among highest of peers (4%), once

management approves the 25% IFRS dividend payout However, vast number of expansion projects will absorb most FCF… … and earnings growth will contribute little to valuation

Bashneft (TP Rb2,100/share) – Valuation premium justified, but high for entry point

Robust FCF generation despite the refinery upgrade CapEx cycle: we estimate FCF yield to average 11% during 2013-16e (vs sector average of 5%)

The highest dividend yield during 2009-11 thanks to the company's flexible dividend policy (distribute generated FCF)

Interim dividend introduction and the launch of Trebs & Titov greenfield in autumn are supportive for the stock in the short term…

… however, in the long term, we see a high risk of M&A (upstream) due to the company's disadvantageous positioning for ongoing oil sector transformation

Valuation premium reflecting strong execution track record and solid shareholder returns is justified (7.1x P/E '14 vs sector's 5.1x), but not an attractive entry point

Surgutneftegas pref (TP Rb23.50/share) – Falling FCF to underscore prefs’ relative attractiveness

The highest, most stable and defensive dividend among sector peers; Preferreds' dividend favored over commons' on higher (6% vs 1.2%), more stable

payout… … potentially leading to a narrower preferred-common spread (19% today, down

from 49% three years ago)


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Sell

Surgutneftegas (TP $8.30/GDR) – Falling FCF to underscore prefs’ relative attractiveness

Common share dividend payout pressured by negative FCF during 2014-16… … due to limited upside from crude production and rising CapEx Preferreds' dividend favored over commons' on higher (6% vs 1.2%), more stable

payout… … potentially leading to a narrower preferred-common spread (19% today, down

from 49% three years ago) Conservative use of $30bn 'war chest' not value-accretive to shareholders;

M&A/greenfield development could generate 3-fold the return

Tatneft (TP $39/GDR) – Premium unjustified

Robust upstream FCF ($16/bbl vs Rosneft's $14/bbl, Lukoil's $15/bbl)… … is not translating into attractive shareholder returns:

o 30% RAS payout implies one of lowest dividend yields (4%), zero EPS growth; o Uninspiring investment returns on Taneco refinery - Taneco

upgrade/expansion is estimated to cost c30% more than average, and bitumen reserves development, whose scale/ profitability is uncertain;

Valuation premium to peers is unsustainable, in our view, taking into account some other companies' superior shareholder returns

Alliance Oil (TP SEK 41/share) – Near-term risks skewed to the downside

Risk of consensus earnings downgrade - consensus too bullish… … BCS 2013-15e EPS forecast is 17% below consensus; BCS 2012-15e EPS CAGR

estimate of 2% compares to consensus' 9% Potential for delay in commercial start until 1H14 is high, equivalent to c$150mn of

foregone EBITDA Robust FCF once upgraded refinery is operational and connection to ESPO could

fully deleverage the balance sheet by 2018… … but search for further production growth will require significant investment, thus

putting pressure on near-term shareholder returns Current valuation (3.4x EV/EBITDA '14e) appears attractive, but we estimate 20%

downside risk from the potential refinery launch delay and CapEx over-run

Transneft pref (TP Rb75,000/share) – Risk-reward not worth the gamble

Robust FCF - $10bn during 2013-15 - is encouraging hope in higher dividends Preferred share price aggressive, assumes 2013e IFRS payout of 19% (v 3% 2012) Risk-reward unattractive:

o potential downside (85%) (no change in dividend policy) o exceeds upside (24%) (25% IFRS payout) by almost 4-fold

No guarantee holders of preferred shares will benefit from IFRS-based payout, unless the company increases RAS profit


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Catalysts

Catalyst Timing Our view Market view Details Gazprom

Agreement on gas supply to China

+ Sep Unless Gazprom demonstrates flexibility with respect to pricing, the Chinese will unlikely commit to the deal given existence of alternative supply sources

Gazprom is likely to compromise on price; deal necessary to compensate for market share loss in Russia and stagnating demand in Europe

The two sides are discussing 30bcm pipeline gas delivery via Eastern route; the gas price has been a stumbling block; Gazprom is insisting on oil-price linkage

Further gas exports increase

+ 2H13 Falling indigenous production in Europe, lower imports from Norway and Africa and re-direction of LNG to Asia have created extra room for Gazprom’s gas

Consensus financial estimates reflect the market’s belief in rising volumes, but below management’s guidance

Gas exports in 1H13 are up 10% y/y; Gazprom revised the full-year target to >160bcm (vs. 139bcm in 2012)

Gas price discounts to European customers

+/– Open-ended We see limited risk of additional price discounts in the short term given Gazprom’s oil-linked prices are equal to current spot levels; take-or-pay limits revision could still happen

Consensus financial estimates do not reflect further earnings downward revision risk

Average gas price discounts have been c10% in addition to compensation for past periods (retro-active payments)

Loss of domestic customers

– Open-ended We expect Gazprom to continue losing domestic market share; we estimate independents could account for half of the domestic market by 2020 vs 27% last year

Gazprom will continue to retreat

Gazprom’s market share has fallen to 73% as independents sign up the monopolist’s customers, including even its subsidiaries (Mosenergo)

Gas deal with Ukraine

– Open-ended Negative: PV of transit tariff savings is nearly equal to acquisition price and CapEx, while gas price discount makes the deal NPV negative

The Ukrainian deal is cheaper than building South Stream

Ukraine is demanding a gas price discount of up to $200/mcm; Gazprom has agreed to a discount in exchange for a right to purchase a stake in Ukrainian GTS

South Stream – Open-ended The project’s scale depends on negotiations with Ukraine on the sale of the stake in the GTS

Abandoned or sharply downscaled

South Stream’s capacity may be up to 63bcm, but the project is getting resistance from EU Energy Commission

Novatek

Interim dividend +/– Aug-Sep We do not expect Novatek to deviate from its dividend policy (30% RAS profit payout)

Same Management is comfortable with the current dividend policy allowing to pursue growth projects

Terms of agreement with CNPC

+/– Sep We do not expect terms to differ from Total’s except for minor adjustments for costs incurred in the past, as noted by management

Same Total agreed to disproportionate CapEx financing terms and paid $425mn for a 20% stake

Liberalization of LNG exports

+ Sep-Nov The adoption of the LNG export liberalization will raise Yamal LNG’s credibility in the eyes of investors

Supportive for Yamal LNG The government favors the reform, but companies ought to have frame LNG supply agreements with customers

FID on Yamal LNG + 2H13 We expect FID to further de-risk the project; further delay in FID is possible

Supportive for Yamal LNG Novatek has completed all pre-FID project stages

Entry of new partner(s) in Yamal LNG

+ Open-ended We expect Novatek to sell down to 51% and the new partner agree to similar terms as Total’s and CNPC’s

Adds credibility to the project

Novatek owns 60% in the project; other partners include Total and CNPC (20% each)

Customer base expansion

+ Open-ended Various forms possible: acquisition of regional gas marketers and/or infrastructure; acquisition of existing producing assets; taking advantage of Gazprom’s expiring agreements and offering more flexible terms

Ascribes success, adding customers and growing domestic sales as function of personal relationships with government

The share of direct gas supplies has increased from 55% in 2011 to 90% in 1Q13 as Novatek continues to expand its client base at Gazprom’s expense

Rosneft

Sakhalin LNG + 2H13 Additional details on the project (resource base, location, CapEx estimate) are necessary for evaluation

Capital-intensive projects, such as this, put additional pressure on Rosneft’s FCF

Rosneft plans to build the LNG plant together with ExxonMobil; Sakhalin-1 resource could be utilized

Arctic offshore drilling results

+/– 2014 Successful exploration could de-risk Rosneft’s enormous Arctic resources, which the market currently assigns little value

Commercial production is too distant to price it in

Rosneft has established a handful of alliances with international oil majors, which hold a 33% share and will fully finance the exploration stage

Source: BCS


9

Catalyst Timing Our view Market view Details Lukoil

2Q13 US GAAP results

– Aug We expect financial performance deterioration q/q; operational results will also likely disappoint given West Siberian production decline accelerated in 2Q13

Production stabilization efforts will bear fruit

Lukoil arrested the 6% pa production decline last year, but the positive effect was temporary (production is now declining at 2% y/y)

Interim dividend + Oct 1H13 DPS will provide indication for full-year dividend expectations

Lukoil is going through peak CapEx years, capping the dividend growth

Lukoil is guiding for a 15% pa dividend increase

Exploration drilling in West Africa

+/– Open-ended Successful exploration drilling could be significantly value-accretive

Ascribes zero value to investments in the region

Lukoil owns licenses for five oil blocks and has invested to date over $1bn in exploration

Gazprom neft

Interim dividend introduction

+ 3Q13 We do not expect the company to deviate from its current payout (25% IFRS), but adoption of such practice is a positive sign

Widely expected, unlikely to be a catalyst

Gazprom neft’s dividends have been consistently above its official policy, but below the company’s FCF generation capacity

Transfer of Prirazlomnoye

+/– Open-ended We see a risk of the transfer price being above expectations given Gazprom has spent to date over $4bn on the field development


Gazprom has already transferred two oil licenses to its oil subsidiary; we expect more transfers going forward, expanding Gazprom neft’s reserve base

Greenfield tax breaks

+ Open-ended Approve of additional tax breaks (export duty relief) for Novoport, Messoyakha and Kuyumba should de-risk the projects

Positive returns are difficult to achieve with additional tax incentives

The projects are an essential part of Gazprom neft’s growth profile, but require significant capital outlay (c$15bn)

Tatneft

Taneco expansion – Open-ended Such decision would imply significant CapEx outlay, not fully benefiting shareholders

Association with value-destructive CapEx spending

To break even, Taneco’s refining margins need to be more than $20/bbl, i.e. nearly three times higher than current levels

Surgutneftegas

Hydrocracker launch

+/– 2H13 The launch is expected and is not a catalyst; further delay may be taken negatively


The hydrocracker will decrease the fuel oil output and increase the diesel output, improving the refining margin

Bashneft

Interim dividend introduction

+ Sep-Nov We expect generous dividends given the company’s robust FCF generation

Confused given the fourfold decrease in 2012 dividend

Management called to wait until fall for more clarity on the dividend outlook

Trebs and Titov launch

+ 2H13 The launch itself is anticipated, but long-term guidance and project parameters, if above expectations, could be taken positively

The market is expecting 6mtpa peak production by 2017

Trebs and Titov is Bashneft’s first greenfield for a long time, but geology in the region is considered complex

Alliance Oil

Refinery upgrade completion

– 4Q13-1Q14 Completion of construction works and test-runs early next year

The company’s progress raises confidence in timely launch (3Q13)

The upgraded refinery and a further tie to ESPO should significantly boost margins and potentially allow start of deleveraging

Acquisition/ development of new fields

+/– Open-ended To ensure stable/rising production in the long term and offset the impact of the potential taxation increase on refining, the company needs to expand its operations

Consensus is not modeling in additional fields/CapEx

Production from existing fields will peak in 2016-17, while expiration of tax breaks on Kolvinskoye and fuel oil export duty increase in 2015 will put additional pressure on earnings

Transneft

Change in the dividend policy

+/– Open-ended Gradual shift towards the 25% IFRS payout (by 2017, as management indicated)

The government imposes a 25% IFRS payout from 2015

The government is attempting to increase the dividend take from state-owned companies. Rosneft has already adopted the change; Gazprom considers switching from 2015; Transneft does not foresee a policy change until major construction projects are complete

Source: BCS


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Valuation The government’s latest steps, e.g., greenfield reform and the formula-based gas taxation, instill confidence that sector transparency will improve and fosters long-term stability, which over time may narrow the Russian companies’ valuation gap to their Western peers.

Materially discounted to global peers: 2014e P/E of 38-51%; Gazprom, at one extreme, trades close to all-time low (2014e P/E of 2.9x); Novatek, at other extreme, trades at a premium, but still has de-rated.

Apart from the obvious macro variables, there are many factors that investors consider before making an investment decision on a particular stock – some draw attention to corporate governance, investor friendliness and social responsibility; others consider the management track-record and adequacy of the development strategy. While the approaches may differ, each could be right. That said, we believe all investors may agree on the following three factors to start with:

Shareholder returns – Average 2013-15e dividend yield. It is vital that FCF covers the dividend payments, but FCF yield on its own is less important since in most cases shareholders cannot claim the rest of the company’s cash flows (residual cash flow is directed towards either new projects – not necessarily value-accretive – or buyback, which never results in share cancellation).

Growth prospects – 2013-16e EPS/EBITDA CAGR. This parameter should reflect an average institutional investor’s time horizon (one-two years), but also adjust for the scheduled fuel oil export duty increase (2015) offset by the first wave of refinery upgrades (2016 onwards).

Valuation – 2014e P/E and EV/EBITDA. This variable depends on the company’s debt gearing (Rosneft’s and Alliance Oil’s high leverage makes it hard to compare on a P/E basis, while Surgutneftegas’s large net cash makes EV/EBITDA valuation meaningless).

Fundamental approach to TP derivation … Our target prices reflect our fundamental approach to valuation – we apply mainly ten-year DCF models to fully capture the impact of on-going investments and planned tax changes as well as to demonstrate dynamics and ability to stress-test companies under various macro assumptions. We apply the dividend discount model (DDM) to Gazprom and Transneft preferred. Gazprom has demonstrated that investors cannot claim the company’s cash flows except for the dividend stream, with the rest of cash flows used to finance capital-intensive projects, which often did not benefit shareholders. Transneft preferred share dynamics has reflected consensus dividend expectations and probability of a policy change in the future (from RAS to IFRS payout).

… in conjunction with catalyst/risk assessment to assign a recommendation. Our investment recommendations take into account the three above-mentioned factors (shareholder returns, growth prospects and valuation), but we also score the stocks on up-coming catalysts and risks and respective probabilities of success to derive our shorter-term theses.

Valuation gap between Russian & global oil majors at 5-yr high Gazprom & Novatek have been de-rating over past 3 years

Source: FactSet

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Russian oil & gas companies are trading at a substantial discount to global peers

Company name Trading Share MCap, EV, P/E EV/EBITDA

currency price $mn $mn ‘13e ‘14e ‘15e ‘13e ‘14e ‘15e

Russian Oil & Gas

Gazprom USD 7.85 90,069 135,165 2.7 2.9 2.9 2.6 2.6 2.6 Rosneft USD 7.16 75,882 136,911 6.1 6.2 6.8 5.2 4.9 4.8 Lukoil USD 59.80 45,141 49,757 4.2 3.9 4.5 2.7 2.4 2.5 Novatek USD 116.00 35,185 38,737 12.8 11.2 9.5 9.8 8.9 7.6 Surgutneftegas USD 8.07 28,813 3,765 4.4 5.0 5.1 0.4 0.4 0.5 TNK-BP RUB 48.00 21,856 25,116 3.0 3.3 3.8 2.1 2.3 2.4 Gazprom neft USD 18.05 17,032 23,100 3.5 3.6 4.2 2.6 2.6 2.8 Tatneft USD 37.02 13,079 15,432 6.0 6.1 6.0 4.3 4.4 4.4 Bashneft RUB 1,990.00 11,402 15,192 7.3 7.1 7.4 5.2 5.1 5.2 Russian Oil & Gas weighted average

5.2 5.1 5.2 4.2 4.0 3.9 Russian Oil weighted average

5.0 5.1 5.5 4.2 4.0 4.0 Russian E&P

Alliance Oil SEK 43.75 1,145 3,203 4.3 2.6 2.3 4.5 3.4 3.2 Exillon Energy GBp 1.42 350 329 7.8 7.3 4.7 4.5 3.2 2.3 Ruspetro GBp 0.31 155 491 neg. neg. neg. 10.3 7.0 3.7 Russian E&P average 5.1 3.7 2.8 5.2 3.8 3.2 Super Majors

ExxonMobil USD 93.81 417,115 430,013 11.9 11.9 11.7 5.3 5.2 5.0 Chevron USD 125.78 243,825 240,272 10.3 10.4 10.3 4.4 4.3 4.1 Royal Dutch Shell GBp 22.97 224,264 243,873 8.5 8.4 8.2 4.0 3.9 3.8 BP GBp 4.51 130,445 146,862 8.5 7.6 7.2 3.7 3.6 3.5 Total EUR 40.21 120,848 149,780 8.1 7.6 7.4 3.5 3.2 3.2 Super Majors weighted average

10.1 9.9 9.8 4.4 4.3 4.2 Integrateds

Eni EUR 16.66 80,229 105,265 10.3 9.1 8.3 2.9 2.8 2.6 ConocoPhillips USD 64.83 79,265 95,927 11.4 10.6 10.4 4.4 4.2 4.0 Occidental Petroleum USD 88.32 71,154 76,696 12.6 12.2 11.8 5.3 5.0 4.9 Statoil NOK 127.30 68,196 73,254 9.6 7.8 7.9 1.9 1.8 1.7 BG Group GBp 11.75 61,009 72,557 14.5 12.3 9.6 7.0 5.9 4.8 Repsol EUR 17.91 30,427 51,497 10.8 10.1 9.7 5.5 5.3 5.1 Marathon Oil USD 36.28 25,716 31,492 12.5 11.4 12.5 3.1 3.0 3.2 Hess USD 73.19 25,126 32,165 9.8 12.1 13.3 4.3 4.5 4.2 Galp EUR 12.09 13,285 18,125 N/M N/M 19.8 11.7 9.8 7.9 Murphy Oil USD 67.31 12,854 14,029 11.7 10.5 11.8 3.8 3.3 3.4 Integrateds weighted average 11.5 10.5 10.3 4.5 4.2 3.9 EM Oils

PetroChina HKD 9.22 217,582 309,427 10.3 9.4 9.0 5.3 4.8 4.6 CNOOC HKD 14.12 81,285 69,115 8.1 7.7 7.5 3.1 2.9 2.8 Petrobras USD 13.73 51,092 135,688 4.0 3.7 3.1 4.2 3.9 3.4 ONGC INR 280.85 39,806 37,683 8.6 7.1 7.6 3.8 3.3 3.6 Reliance Industries INR 858.85 45,949 51,080 12.4 11.1 9.8 9.0 7.8 6.6 Sasol ZAc 453.21 30,773 30,860 11.5 11.0 11.4 5.9 5.6 5.7 Sinopec USD 73.77 18,821 73,447 1.6 1.5 1.4 2.2 2.1 2.0 Indian Oil Corp INR 195.35 7,858 21,080 6.8 5.7 5.1 7.2 6.4 6.2 EM Oils weighted average 9.1 8.2 7.9 4.8 4.4 4.1 UK E&P

Tullow Oil GBp 10.27 14,226 15,194 N/M N/M N/M 8.3 8.5 8.9 Premier Oil GBp 3.60 2,908 3,995 8.2 7.0 5.9 3.5 3.0 2.5 Afren GBp 1.35 2,246 2,812 9.4 8.2 6.4 2.7 2.8 2.3 Soco GBp 3.67 1,858 1,647 7.3 7.0 7.8 3.1 3.0 3.3 Salamander Energy GBp 1.24 485 675 7.3 7.4 13.8 2.3 2.1 2.1 UK E&P weighted average 8.3 7.4 7.0 6.4 6.4 6.5 As of 30 July 2013 Source: FactSet, BCS


12

Russian Oil & Gas Sector Outlook Overall, we forecast investment returns to deteriorate for the sector. Even so, a handful of companies endowed with profitable greenfield exposure and favorably positioned for upcoming tax changes are worthy of investors’ attention.

Greenfield exposure is necessary to remain profitable and competitive, to sustain returns and long-term growth...

… as investment returns on brownfields, the main cash flow generators, are deteriorating.

Best positioned to play sector trends: Rosneft, Gazprom neft, Novatek and Lukoil.

Risks of harsher taxation of refining and gas, both under-taxed and posting sufficient returns, are high …

… as budget tax revenue from the oil sector declines in the late 2010s – tax-exempt greenfield barrels will substitute brownfield production and light oil products will replace heavier-taxed fuel oil post a series of refinery upgrades.

Risks of higher sector tax are skewed to the upside

We expect the government to compensate for declining upstream tax dollars – making up almost half of federal budget revenue – later this decade by levying a higher tax on refining and gas.

Brownfields: Risk of higher taxation is low, but contribution to budget revenues will decline as production continues to gradually slide

Greenfields: Fresh barrels will guarantee attractive investment returns, but will not generate tax dollars in the beginning

Refining: High risk of tax hike as profitability and cash generation strongly improve following a series of refinery upgrades

Gas: Risk of higher taxation, especially for gas condensate

Oil taxation has undergone major changes in the last two years

Source: Company data, MinFin, MinEnergo, BCS

Key beneficiaries:Surgutneftegas, Tatneft, Rosneft, Lukoil

Impact: c$4/bbl crude netback increase, c$3.6/bbl refining margin decrease

“60-66”

Key losers: Bashneft, Alliance Oil, Gazprom neft

Impact: c$2/bblincrease in opportunity cost of exporting gasoline

90% gasoline emergency export duty

Key beneficiaries:Lukoil, TNK-BP

Impact: c4% of EBITDA increase

Differentiated excise taxes

Crude export duty decrease offset by refining product export duty increase

Gasoline export duty increase to address the fuel shortage by preventing exports

Lower excise tax rates for higher quality fuel benefiting early refinery upgrades

Key beneficiaries:Tatneft, Lukoil

Impact: c$45/bbladditional margin for every barrel produced

“10-10-10”

Export duty breaks for high-viscous oil

Key beneficiaries:Rosneft

Impact: Early to quantify at this stage

Offshore tax reform

Differentiated MET rates depending on field complexity; no export duty

Key beneficiaries:Rosneft, Gazprom neft, Lukoil

Impact: c$30/bblexport duty reduction

Greenfield tax reform

Significant oil export duty reduction to achieve a 16.3% real IRR

Profit-based taxation

Objective: stimulate greenfield development

Impact: lower taxation during early and final development stages, higher taxation during peak production cycle

“55-86”

Objective: stimulate investments in brownfields (in continuation of “60-66”)

Impact: taxation ease on upstream at expense of refining

Key losers: Bashneft, Surgutneftegas, Tatneft, Gazprom neft

Impact: c$2/bblrefining margin decrease

Fuel oil export duty increase

Convergence of crude and fuel oil export duties

Adopted/in consideration

Proposed


13

Major oil tax regime changes: bearing some fruit. Tax revenue from the oil sector makes up c45% of Russia’s federal budget. Companies pay over 70% in taxes from every barrel sold. No wonder the word ‘tax’ comes up so often when it comes to the Russian oil sector. The changes to the regime, although still emerging, are bearing some fruit.

Oil sector taxation has undergone major changes since 2011, as sustaining legacy production is becoming more difficult and costly, while greenfields are too expensive to develop. The government logically started off with brownfield reform (the so-called ‘60-66’) stimulating investments in the upstream at the expense of refining. Greenfields continued to receive ad hoc tax breaks; however, large scale development requires transparency and stability of the tax regime – proposals on greenfields, tight oil and offshore resources were born, processed and adopted.

Government actions have so far proved effective. Selected highlights include:

Higher output: Crude production increased from 10.2mmbbl/d in 2011 to 10.5mmbbl/d in July 2013;

Tax breaks: Many greenfields – such as Rosneft’s Yurubcheno-Tokhomskoye, Gazprom neft’s Novoport, Messoyakha and Kuyumba, TNK-BP’s Russkoye and Tagulskoye – will soon become eligible for export duty breaks, once the government approves the greenfield reform, thus allowing companies to commence development;

Strategic alliances: Rosneft signed numerous strategic alliances with global majors, such as ExxonMobil, Eni, Statoil, to develop offshore resources, and exploration has already begun.

Refinery upgrades started: Lukoil and TNK-BP were the first to comply with Euro-5 fuel standard requirements, Surgutneftegas and Alliance Oil will finalize the installation of hydrocracking facilities already this year.

Still, tax reforms are difficult to measure and quantify. It is premature to quantify the impact of the adopted/proposed tax changes. For example, ‘60-66’ has eased the tax burden on upstream by c$4/bbl; however, total investments in brownfields have risen by only $1/bbl. Companies, in turn, are demanding a further export duty reshuffle between upstream and refining (i.e., transition from the current ‘60-66’ to ‘55-70’ or even ‘55-86’) as oil extraction is becoming more and more expensive, they say. A series of refinery upgrades was launched, but one is not to expect the industry to fully modernize operations before the export duty on fuel oil increases in 2015.

Budget deficit will not allow further tax relief. The Ministry of Finance has recently warned that financing numerous capital-intensive infrastructure projects may increase the budget deficit to 1.5% of GDP (vs current 0.2%) (Vedomosti, 29 May). Russian Prime Minister Dmitry Medvedev forecasts the budget deficit at Rb400bn in 2014 and Rb500bn during 2015-16 (Interfax, 24 June). The reserve fund, which is currently 4% of GDP, may shrink to 3% by 2015, while MinFin originally targeted 6-7% by 2016-17. Given the oil sector’s large contribution to government tax revenue (45%), easing taxation on Russian oils may not be timely.

Risks to oil tax dollars are rising

We highlight that risks to budget revenue from the oil & gas sector in the second half of the decade are skewed to the upside as tax-exempt oil barrels replace brownfield production and light products substitute higher-taxed fuel oil. Given the sector contributes half of budget revenue, we do not expect the government to ease the tax burden on companies’ brownfields.

Oil tax revenue may start falling this decade… On our estimates, over the next ten years, barrels from new fields, if commissioned on time, will substitute over 1mmbbl/d of brownfield production and contribute an additional 1mmbbl/d to Russia’s overall production profile. However, under the current tax regime, we do not expect such production dynamics to translate into higher tax revenue. Most greenfields require extensive tax breaks to generate sufficient returns to justify investments. By the end of decade, we expect over 30mtpa of new crude production to be MET-exempt (some even export duty exempt). In addition, refinery modernization completion will result in a substantially higher share of less-taxed light products and fewer high-taxed heavy products (fuel oil), thus also putting pressure on the tax pool.


14

Greenfields will continue driving Russian crude production until 2018, we estimate…

… but federal budget tax revenues will start falling much earlier due to numerous tax breaks

Source: BCS

… and rate of decline might accelerate once greenfields pass through peak production. More worrisome, tax revenue collection may drop further and harder in the next decade after the announced greenfields reach and pass the targeted peak production levels (2020-22). We estimate that production from the top 25 greenfields will slide at 6% pa during 2020-30, based on Wood Mackenzie production assumptions. Assuming no changes in the tax regime, tax revenues will follow the same path.

New generation resources not a short-term solution. New generation resources will require significant government support and stimulus and, thus, will unlikely contribute to the budget revenue right from the start. To sustain crude production in the long-run, the government is stimulating the development of new oil provinces and resources – tight oil and continental shelf. Despite the large resource base, production potential from those resources is uncertain at this stage due to lack of exploration results, cost and risk assessment. We believe the development of these barrels will be impossible without significant fiscal stimulus, implying that new barrels coming along will be tax exempt, thus having limited impact on the federal budget tax revenue. Under such scenario, we believe the government is unlikely to ease taxation on the sector, as requested by oil companies (i.e., transition from ‘60-66’ to ‘55-86’, ‘55-70’). We do not expect higher taxation either, as this risks undermining Russia’s oil production altogether.

Refining & gas – targets for additional tax take

To compensate for tax revenue decline from crude barrels, the government might raise the tax burden on other sectors. Our project profitability analysis demonstrates that oil refining’s and gas projects’ robust returns could handle additional tax increase.

Expensive refinery modernization … Refining is getting taxed heavier and heavier – first, ‘60-66’, next, a scheduled increase in the fuel oil export duty from 2015. Yet, nearly a third of planned investments during the next four-five years are aimed at plant modernization – Lukoil plans $20bn worth of CapEx; Rosneft CEO mentioned $30bn (Interfax, June 21); Gazprom neft is budgeting $11bn.

… hides refiners’ strong FCF generation potential… Nevertheless, while companies’ FCF may be under significant pressure as they go through the peak of the CapEx cycle, we forecast robust cash flow generation afterwards. On our estimates, refiners’ EBITDA margin averaged $9/bbl over the last 12 months.

We have evaluated the effects of upcoming refinery upgrades under three tax regime scenarios – 1) current ‘60-66-100’, 2) ‘55-86-100’ proposed by oil companies, and 3) hypothetical ‘50-100’ where the crude duty falls further at the expense of harsher refining taxation (full convergence to the crude export duty levels). Our evaluation assumes a stable macro environment, even though we believe it is highly likely that refining margins will experience more pressure in the future due to increased supply of light products, especially diesel, and limited consumption growth.

8

9

10

11

12

2012 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e 2021e 2022e

mmbbl/d

Brownfields Greenfields

180

185

190

195

200

205

2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e 2021e 2022e

$bn


15

Refining becomes highly profitable post the upgrade… … but would turn FCF-negative in case of no upgrade at all

(1) Export duty on crude is reduced to 55%, export duty on light products is increased to 86% from 2016 onwards (2) Export duty on crude gradually falls from 55% in 2016 to 50% in 2021, export duty on light products converges with that of crude by 2021

Source: BCS

Our estimates point out to substantial investment returns from refinery upgrades. Without the upgrades, refineries will turn FCF-negative after the fuel oil duty converges with that of crude. On the contrary, refineries undergoing upgrades, FCF-negative today, will generate positive cash flow from 2017-18, which may eventually exceed $7/bbl under ‘60-66-100’. To put the number into perspective, we estimate Rosneft’s and Lukoil’s refining divisions to generate $4.4bn and $2.3bn pa of FCF, respectively, in the long-term – largely equivalent to the companies’ total FCF last year. In light of such profitability we estimate the average payback period at six-seven years.

… which runs the risk of eventually being taxed away. Refiners’ robust profitability might eventually catch the government’s eye looking for additional tax revenue. As such, we see room for a further tax increase on light oil products. In our base case, we model full convergence to the crude export duty by the end of the decade.

Gas sector taxation is getting harsher … Compared to the oil sector, which contributes c45% to federal tax revenue, the gas sector contributes ‘only’ 6% and yet the government found a way to squeeze the gas companies’ pockets even more. The gas MET saga that commenced in 2011 already cost gas companies c$6bn of additional taxes pa (most of the extra tax burden fell on Gazprom), which is equivalent to 1.5% of total federal budget revenues.

… but companies expected to remain profitable, nevertheless. Despite the substantial tax burden increase, we estimate the sector could handle an additional tax take.

Brownfield gas production is adequately profitable, even though Russian gas prices ($112/mcm) are among the lowest in the world. On our estimates, Novatek and Gazprom generate $45/mcm and $23/mcm of operating income, respectively. In FCF terms, this translates into $34/mcm and $12/mcm, respectively. The difference between the companies’ profitability reflects Gazprom’s higher MET (twice that of independents), lifting costs and maintenance CapEx. At the same time, superior economics of Gazprom’s export sales, the company’s main cash flow source, results in $149/mcm of operating income and $109/mcm of FCF.

NGL: superior profitability could handle additional tax. Gas fields with a high share of natural gas liquids (NGL) are especially profitable, reflecting lower MET relative to crude. For example, the crude production tax in 2Q13 was $156/t vs a condensate tax of $19/t. Adjusted for differences in transportation and other operating costs, such difference translates into $1.5bn extra margin, which Russian oil & gas companies are generating per year.

In our view, such phenomena stems from the fact that Cenomanian reserves developed in the olden days did not contain much condensate and its contribution to a company’s overall profitability was so small that the high margins were simply insufficient to raise much attention. Now though, as the condensate-rich Valangian, Achimov and Neocomian reserves replace the depleted / condensate-poor Cenomanian-based production, wet gas as a percentage of production in overall hydrocarbon output has started to grow.

-8

-6

-4

-2

0

2

4

6

8

2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e 2021e 2022e

FCF, $/bbl

"60-66-100" "55-86-100" "50-100"(1) (2)

-10

-8

-6

-4

-2

0

2

4

6

2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e 2021e 2022e

FCF, $/bbl

"60-66-100" "55-86-100" "50-100"(1) (2)


16

Russian gas companies’ FCF… … is steadily growing

Source: Company data, BCS

Gas condensate’s superior profitability contributes to gas projects’ investment returns

Gas condensate’s profitability goes back a long way


Natural gas: tax hike risks remain, especially concerning NGL. Robust profitability of gas projects, especially those with a high share of NGL, raises the probability that the government could eventually make upward base rate adjustments to the newly established gas tax formula (as has already occurred in oil). We see gas sector tax risks increasing for the period beyond 2015.

MET – Formula-based rates established, but … We applaud the government’s decision to improve the sector’s transparency. The formula-based approach, which will come into effect from 2014, will treat gas market participants fairly, taxing heavier high-margin gas and condensate exports, countering the effects of lower gas prices and determine necessary tax breaks for greenfields. The formula will adjust the base rate (Rb35/mcm for gas, Rb42/mcm for condensate) by macro and operational parameters such as prevailing Urals crude price, exchange rate, crude export duty, transport costs, domestic and export gas price levels, gas and condensate output levels, share of domestic gas shipments, and field complexity.

… higher than previously adopted rates. Nevertheless, the new formula-implied MET rates will be higher than previously adopted rates both for natural gas and condensate. We estimate the negative impact on Novatek’s and Gazprom’s 2014-15 EBITDA at 6-8% and 2-4%, respectively. The new taxation approach more heavily taps condensate’s superior returns. The higher the share of condensate output, the higher are rates for both gas and condensate. Keeping gas MET rates constant, we estimate the new formula will allow the government to tax away c$8/bbl of the $20/bbl condensate-crude MET rate discrepancy.

109

34 120

100

200

300

400

Gazprom export gas sales Novatek domestic gassales

Gazprom domestic gassales

$/mcmFCF

Maintenance capex

Income tax

Transportation

Lifting costs

MET

Export duty

-20

0

20

40

60

80

100

120

140

160

180

2005 2006 2007 2008 2009 2010 2011 2012 2013e

FCF, $/mcm Gazprom export gas salesNovatek domestic gas salesGazprom domestic gas sales

1526

0

20

40

60

80

100

120

Crude oil Gas condensate

$/bbl

EBITDA

Income tax

Transport

Opex

MET

Export duty0

5

10

15

20

25

30

35

2005 2006 2007 2008 2009 2010 2011 2012 2013e

EBITDA, $/bbl Crude oil Gas condensate

New formula-implied MET rates are higher than under previous proposal

Gazprom Novatek ‘14e ‘15e ‘14e ‘15e Gas (Rb/ mcm) Old 700 788 471 552 New 829 840 670 689 Diff. 18% 7% 42% 25% Condensate (Rb/ton) Old 647 679 647 679 New 995 1,008 803 826 Diff. 54% 48% 24% 22%

Source: MinFin, BCS estimates


17

Greenfield exposure trumps traditional brownfields

O&G producers with larger exposure to greenfields should enjoy robust investment returns in the long term, contrary to those adhering to traditional production regions.

Greenfields to generate IRR in excess of 20% on average, we estimate;

Brownfields, with high depletion rates, are delivering diminishing returns as rising CapEx is not rewarded with sufficient additional barrels;

LNG exposure is capital-intensive, but relatively low costs will guarantee Russian projects a ‘sweet spot’ on the global arena;

Winners: Rosneft, Gazprom neft, Lukoil and Novatek.

Greenfields – new sources of profitability Robust investment returns on most greenfields justify investments and risks. We point out to several reasons why the large investments (oil & gas companies are slated to invest $130bn in the top 25 greenfields until the end of the decade) and risks that accompany greenfield development are justified and exposure is more attractive than brownfileds for Russian upstream companies:

Fiscal stimulus: Under the proposed greenfield reform, most new fields will qualify for tax breaks to deliver the minimal rate of return (16.3% IRR). Assuming tax breaks, the top 25 greenfields (including those currently operating) are worth $75bn in NPV terms, on our estimates.

Gas exposure: Greenfields will contribute 200bcm of new gas output. We estimate investment returns on gas projects at well in excess of 20%, taking into account superior profitability of gas condensate. We also highlight company efforts to boost returns by converting and shipping gas as LNG (Gazprom, Novatek and Rosneft) and/or processing gas into petrochemicals (Lukoil).

Cheaper maintenance: We estimate that greenfields will eventually be significantly cheaper (two-four times) to operate than brownfields. For example, Verkhnechonsk and Vankor upon achieving plateau production will cost $3.8/boe and $2.1/boe, respectively, to operate compared to Yuganskneftegas’s current maintenance CapEx of $7/boe.

Russia’s largest greenfields

Field Company Start year

Prod. delta (kboed)

Peak prod. (kbd)

Peak prod. year

CapEx remaining, $bn

Reserves (bn boe)

NPV ($bn)

Bovanenkovo Gazprom 2012 1,632 2,427 2020 26.4 19.1 15.3 Severenergia Gazprom neft, Novatek 2012 591 684 2022 8.5 5.4 6.0 Yamal LNG Novatek 2018 407 407 2024 42.3 4.1 7.0 Novoport Gazprom neft 2014 402 402 2022 5.3 2.7 3.3 Kharampur Rosneft 2015 343 343 2020 6.4 2.7 1.4 Messoyakha Gazprom neft 2016 285 285 2023 6.8 1.8 3.6 Rospan TNK-BP 2007 262 364 2017 6.7 1.9 0.7 Filanovskogo Lukoil 2015 204 204 2019 7.0 1.0 2.9 Yurubcheno-Tokhomskoye Rosneft 2016 167 167 2022 4.9 1.0 0.9 Kynsko-Chasel Rosneft 2015 164 164 2018 1.4 0.8 1.3 Kuyumba Gazprom neft 2017 157 159 2020 1.6 0.7 0.5 Russkoye TNK-BP 2017 148 150 2025 4.7 1.0 0.3 Imilorskoye Lukoil 2017 140 140 2022 7.0 1.2 1.3 Pyakyakhinskoye Lukoil 2016 105 105 2020 2.3 0.3 0.2 Shpilman Surgutneftegas 2016 100 100 2020 4.0 0.7 0.8 Trebs and Titov Bashneft, Lukoil 2013 96 102 2020 6.7 1.0 2.2 Chonsk Gazprom neft 2017 70 70 2021 3.5 0.4 0.5 Tagulskoye TNK-BP 2019 70 70 2023 2.5 0.4 1.2 Vankor Rosneft 2009 63 574 2018 8.7 2.8 11.7 Prirazlomnoye Gazprom 2013 59 68 2019 1.8 0.3 2.6 Suzun TNK-BP 2014 59 60 2018 1.4 0.3 1.0 Orenburg Gazprom neft 2012 43 108 2015 2.5 0.7 1.4 Korchagin Lukoil 2010 13 46 2020 0.9 0.3 2.2

Source: Company data, Wood Mackenzie, BCS


18

Greenfields, if delivered on schedule, could contribute 2mmbbl/d of additional crude…

… and 200bcm of gas production by 2022

Source: Company data, Wood Mackenzie, BCS

Brownfields – diminishing returns

Brownfields, historically, have been perceived as ‘cash cows’ due to robust profitability and small CapEx requirements. However, the return on investment is deteriorating as rising CapEx is not rewarded with sufficient barrels.

Brownfields remain the core source of FCF and government revenue… Over 90% of Russian crude production is coming from the mature fields of Western Siberia, the majority of which have been in operation for almost 30 years. Despite high depletion rates and falling production, fields remain the core FCF generators for Russian oil companies, helping finance new greenfields, costly refinery modernization and, in most cases, pay dividends. Brownfields contribute the most to the federal budget (up to 40%, on our estimates).

… but production is falling and CapEx is rising... Peak production for most brownfields has long passed. While companies have managed to maintain relatively stable production rates until mid-2000s, declining production accelerated in 2007 and rates reached -3% during 2008-09. Nevertheless, the country’s overall production has grown at 1% pa, on average, as new fields in Eastern Siberia (Verkhnechonsk, Talakan and Vankor), Timan Pechora (South Khylchuya) and Far East (Sakhalin-1 and Sakhalin-2 ramp-up) came on-stream.

To arrest the production decline, many companies have eventually turned to the application of production enhancement technologies, such as horizontal drilling with horizontal deviations longer than average for Russia, multi-stage hydrofracturing, multiple completion and other techniques.

Production from mature brownfields has been falling at 1% pa…

… a trend likely to remain going forward

Source: CDU TEK, Company data, BCS

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e 2021e 2022e

mmbbl/d

Rosneft Gazprom neft Lukoil Bashneft Surgutneftegas Other

0

50

100

150

200

250

300

2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e 2021e 2022e

bcm

Rosneft Gazprom neft Lukoil Gazprom Novatek

8

9

10

11

12

2006 2007 2008 2009 2010 2011 2012

mmbbl/d


8

9

10

11

12

2012 2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e 2021e 2022e

mmbbl/d



19

The results speak for themselves – the decline in brownfield production has slowed from -3% in 2009 to -0.5% in 2012. Lukoil, TNK-BP and Gazprom neft – companies with the oldest and most depleted fields – were the pioneers. However, brownfield production enhancement has come at a price – average CapEx almost doubled between 2009 and 2012.

… diminishing the fields’ investment returns. The application of production enhancing technologies has generally proved effective and value-accretive in the West. However, the short track-record in Russia does not yet allow for a definitive conclusion.

Theory is supportive; reality is less forgiving. In theory, the math supports such technologies: flow rates from horizontal wells can be nearly three times higher than from standard vertical wells and help extract more cumulative oil; this fully compensates for higher cost (CapEx is nearly two times higher) and steeper decline rate (over 20% vs 15% for vertical wells). In reality, the application of sophisticated drilling technologies has not gone completely smooth.

Lukoil’s experience is telling. We attempted to estimate the investment returns from the application of unconventional production enhancing technologies and considered Lukoil as an example. The company’s production decline has slowed from 5% to 0% in three years. Initially, Lukoil’s production decline rate dropped from minus 5% in 2009 to 1% in 1Q12, while average CapEx per barrel rose from $5 to $7. In present value terms, we estimate this was equivalent to additional $6bn. However, stable production was short-lived and started to roll over again in 2H12. The decline rate now stands at minus 2%, while CapEx continued to rise. In present value terms, this is equivalent to minus $8bn. According to our sensitivity analysis, to compensate for such CapEx increase, the production growth rate should have accelerated to 2% pa.

Based on the June data, West Siberian production decline rate has started to slow from -2%. The decline rate has decelerated to -1.5%, making a strong case for production enhancement technologies, but still not sufficient to generate historically robust returns.

LNG – regaining lost positions

Russian LNG projects are located at the bottom end of the global cost curve and, therefore, may guarantee attractive investment returns despite large construction budgets. We estimate Russia could increase its presence in Europe tapping previously unattainable markets as well as enter the lucrative Asian-Pacific market, taking advantage of robust demand growth in China in spite of significant amount of new liquefaction capacity entering the global market in the late 2010s.

Diminishing global export market share. Russia has lagged its peers on the global gas market – the country’s share of global gas exports fell from 27% in 1998 to 19% in 2012. Of the three major gas-consuming regions – North America, Europe and Asia – Russia remains a major player in only one: its traditional European market.

The increased supply of LNG has been one of the core reasons Russia’s positions have diminished on the world market. The volume of LNG imports trebled between 1998 and 2012, while their share in total gas imports increased from 25% to 32%. In Europe, LNG imports now make up 20% of the European energy balance, up from 11% only eight years ago.


20

Russia’s share of global gas exports has decreased by 8% in the past 15 years

LNG trading made up 32% of the global gas balance in 2012, up from 25% in 1998

Source: BP Statistical Review of World Energy

Falling market positions in the global gas arena, multiple pressures (from regulators and customers), inflexibility of pipeline gas delivery, premium LNG pricing in Asia have all prompted Russia to start thinking about hopping in the last door of the LNG train. We say “last” because LNG market fundamentals have been extremely tight over the last several years, a situation we do not expect to last for long, given significant liquefaction capacity additions beyond 2015 (Wood Mackenzie estimates global liquefaction capacity to grow by 34% (89mtpa) in the second half of the decade), thus potentially putting pressure on premium LNG pricing in Asia (e.g., LNG fob prices in Asia averaged $16.5/mmbtu over the last two years vs European spot levels of $10.3/mmbtu and US Henry Hub prices of $3.9/mmbtu).

Russia is regaining global gas leader status. Russia currently has one operating LNG plant, Sakhalin-2, which produces 10mtpa. Novatek’s Yamal LNG project is already in the advanced development stage with a launch planned in 2016-18. Gazprom, as part of the Eastern Gas Program, intends to tap hot Asian markets by building an LNG plant in Vladivostok and has recently announced intentions to ship LNG to Europe from the future Baltic LNG plant. The recently emerged gas player, Rosneft, is also considering building two plants – in the Sakhalin and Murmansk regions. Together, the companies plan to build 50mtpa of new LNG capacity by the end of the decade.

Russian liquefaction capacity could hit 75mtpa if all projects implemented Plant Partner Status Launch Capacity (mtpa)

Sakhalin-2 Gazprom, Shell, Mitsui, Mitsubishi

Operating 2009 10

Yamal LNG Novatek, Total, CNPC

Under construction 2016-18 15

Sakhalin LNG Rosneft, ExxonMobil

Proposed 2019 15

Vladivostok LNG Gazprom Proposed n/a 15

Baltic LNG Gazprom Proposed n/a 10

Murmansk LNG Rosneft Proposed n/a 10

Source: Company data

Russian LNG is cost-competitive. Global LNG break-even levels range from $3.5/mmbtu (Nigeria) to $15/mmbtu (Australia), according to Wood Mackenzie. On the bottom-end of the cost curve, Australian LNG projects, which will account for 60% of new LNG capacity, suffer from constantly rising costs – local cost pressures, strict environmental controls, currency fluctuations and logistical challenges have all inflated the projects’ costs by over 40% in the last four years. On the upper-end of the cost curve, Nigerian LNG is benefiting from the lowest cost in the world as costs are offset against oil revenue.

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21

Novatek: Yamal LNG’s place on the global cost curve is towards the bottom end thanks to the 12-year MET relief, government support in infrastructure construction and fields’ close proximity to the export terminal. According to Wood Mackenzie, Yamal LNG’s breakeven costs are $8/mmbtu. Unlike the general myth that building an LNG production plant on permafrost would add to the construction cost, we note that the company’s Yurkhara field is operating in almost similar conditions and yet is one of the lowest-cost producing fields in Russia. In addition, the lowland landscape on Yamal will also facilitate the plant construction. The major difficulties we see are related to shipping the product through thick ice in the Northern waters.

Rosneft: Emerged as a new gas player only last year. Besides domestic gas market share expansion, the company aims to become an international LNG player. At the Economic Forum in St. Petersburg in June, Rosneft signed a series of LNG-related agreements:

o Agreement with ExxonMobil to develop an LNG plant in Russia’s Far East. The two companies are to define further steps for development of the Far East LNG construction project by end-2013.

o Agreement with Vitol on LNG purchases. Under the agreement, Vitol would be a major strategic LNG buyer from Rosneft's new project in Russia's Far East. Deliveries to Vitol should begin in 2019 to supply LNG to customers in the Asian-Pacific region.

o LNG deliveries to Japan may start in 2019. Rosneft signed agreements with Marubeni and SODECO of Japan to begin LNG deliveries in 1Q19, Interfax wrote. Rosneft plans to deliver 1.25mtpa of LNG.

The likely source of gas supply for the future LNG plant is the Sakhalin-1 project, where both Rosneft and ExxonMobil are shareholders. We believe that Rosneft’s offshore licenses in the area covering over 110,000 sq km could also potentially serve as a resource base. With 400bcm of reserves, Sakhalin-1 could supply gas to the potential 10-15mtpa LNG plant for over 20 years. The concept of an LNG facility on Sakhalin Island is already well-established, with over 10mtpa already coming from the Sakhalin-2 LNG plant, in which Gazprom is a 50% shareholder.

Gazprom: Gazprom is already exporting LNG via its 50% ownership of the PSA-based Sakhalin-2. Vladivostok LNG could become the company’s new LNG arm. We expect the development of Vladivostok LNG to be capital-intensive when upstream, midstream and plant costs are included. However, economies of scale could be achieved dependent on the source of supply, and the transportation scheme. There are at least three gas supply sources:

o Chayanda: The giant Chayanda field holds over 1tcm of C1+C2 gas reserves and could supply the 15mtpa LNG plant for almost 50 years. The development involves the implementation of a production hub in the region of Yakutia. Gas from the field will be transported to Vladivostok through a 3,200km pipeline.

o Kovykta: The field is the largest one in East Siberia (over 2tcm of gas resources). We believe the development of Kovykta is likely to be carried out in conjunction with that of Chayanda. Gas from Kovykta could be transported to Chayanda before being shipped to the Far Eastern shore.

o Kirinsky: The Kirinsky block could potentially be a cheaper alternative to both Chayanda and Kovykta. The block is located on the East coast of the Sakhalin Island and comprises four fields with gas reserves of over 0.5tcm. Gazprom has recently estimated Kirinsky’s resource base not less than that of the giant Shtokman (Vedomosti, June 3).


22

Costly pipeline construction spoils Gazprom’s LNG project returns Company Novatek Gazprom Rosneft

Project Yamal

LNG Kirinsky

block Chayanda Kovykta + Chayanda Sakhalin

Resource base (bcm) 1,256 564 1,325 3,303 n/a Pipeline:

Capacity (bcm) - 15 15 60 n/a Distance (km) - 1,837 3,200 4,000 n/a

CapEx ($bn): Field development 7 6 13 31 n/a Pipeline - 8 11 26 n/a LNG plant 20 15 15 15 15 Total 27 29 40 72 n/a

Field breakeven cost ($/mmbtu) 8.0 10.9 12.8 10.6 n/a NPV ($bn) 7.0 -5.1 -6.7 -7.0 n/a

Source: Wood Mackenzie, BCS

Room for additional LNG exports from Russia to both Europe and Asia. Despite significant LNG supply additions by the end of the decade, we see sufficient room for new volumes, including those from Russia. Exports to Europe could allow Russian majors to tap new markets and/or increase their presence in the existing ones, while Asia, namely China, will become the real turbo-boost for cost-competitive LNG producers. Based on the signed and considered LNG import agreements, China has contracted 41-43mtpa of LNG during 2016-25. The country’s gas demand/supply balance reveals room for up to 60bcm of additional gas supply, including potential pipeline exports from Russia (30bcm pa).

Robust gas demand in select European countries offers growth opportunity. Assuming a slow economic recovery, Wood Mackenzie forecasts that Europe will grow its gas demand by 13% by 2020, i.e., slightly more than 1% pa. Nevertheless, a standalone country analysis points to robust demand growth in certain areas. According to Wood Mackenzie, Turkey, Spain, Italy, Poland, France and Belgium together will increase their gas consumption by 38bcm by 2020, thus accounting for almost 60% of the aggregate demand growth in the region. We have analyzed each market in detail and concluded that Russia could potentially increase its presence in most of them.

Sufficient room for Russia to increase its presence on the European gas market Demand delta (bcm) Sweet spot Russia’s current Current gas supply

Additional comments 2013-20 2013-25 for Russia market share Prod’n Piped gas LNG Turkey 10.5 14.0 yes 55% 2% 88% 10% Gazprom plans to increase gas sales to >30bcm this

year vs 27bcm in 2012; In the LT, Russia could increase exports via South

Stream, if implemented. Spain 8.8 9.5 unlikely 0% 0% 42% 58% Existing contracts fully cover the country’s gas needs

Russian future LNG will be more expensive than that of current suppliers (Nigeria, Algeria, Egypt, Qatar)

Italy 6.9 9.1 yes 28% 11% 76% 13% Russia could increase its presence in the region with the launch of South Stream, potentially replacing the falling-out piped gas from Algeria

Poland 7.0 8.9 yes 75% 25% 75% 0% Russia stands well to benefit from its dominant supplier position

Poland’s shale gas production prospects are uncertain

The new LNG terminal could import up to 5bcm of gas (1.5bcm pa already contracted with Qatar)

France 2.9 1.8 possibly 23% 1% 60% 39% Russia could increase piped gas exports via Nord Stream

Piped imports from Norway, Netherlands and UK are set to fall as indigenous production rolls over

LNG could gradually replace piped gas as new re-gas capacity is launched

Belgium 2.3 5.5 possibly 0% 0% 66% 34% Sufficient room for Russian future LNG Only three existing LNG contracts Contract with Netherlands on piped gas imports

expires in 2018, creating room for higher LNG shipments



23

Gradual substitution of pipeline gas with LNG. Roughly 50mtpa of new LNG re-gas capacity is expected to be launched in Europe by the end of the decade, providing the region with higher flexibility over gas source choice. According to Wood Mackenzie, Europe will grow LNG imports by 8bcm by 2020; however, the actual volume additions, which could be significantly higher, will likely depend on suppliers’ price attractiveness.

Turkey and France drive the EU gas consumption growth China is to spearhead Asian gas demand growth

Source: Wood Mackenzie

China’s gas demand/supply balance reveals room for additional LNG volume shipments


Asian gas demand to double by 2020, driven by China. Asian gas demand may almost double by 2020, driven by robust consumption growth in three core regions – China (69% of Asian incremental demand), Japan (9%) and India (6%), according to Wood Mackenzie. Chinese gas demand, according to Wood Mackenzie, will double by 2017-18 (to 340bcm) and treble by 2025 (to 500bcm), driven by industrial and power sectors, especially in the coastal regions. The country’s own production will grow at a similar pace, hence, leaving plenty of room for imports. Wood Mackenzie estimates gas imports to grow from the projected 53bcm in 2013 to 134bcm by 2018 and 191bcm by 2025.

China is building new gas/LNG infrastructure to accommodate increased imports. China’s pipeline import capacity will exceed 50bcm after Myanmar commences this year the 11bcm pipeline. Russia continues to negotiate pipeline gas shipments to China, however, the two sides still cannot agree on the pricing formula. The Altai pipeline is off the table at the moment with the Eastern route being a more likely scenario. Nevertheless even with Russian pipeline gas deliveries there is at least a 60bcm extra space for LNG import increase.

China’s current re-gas capacity stands at 37mtpa. Wood Mackenzie estimates additional 60mtpa of re-gas capacity to be launched by the end of the decade and also sees a potential for several existing and planned terminals to expand. Until 2017, China's LNG market is relatively well met with existing contracts. However, in the long-term, China’s LNG requirements may grow substantially to meet robust gas consumption growth. We estimate China may absorb extra 50mtpa of LNG supply by 2025.

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Domestic production Pipeline imports Contracted LNG "Sweet spot" Demand


24

China’s pipeline gas import capacity PIpeline Status Launch Capacity (bcm) Trans-Asia Pipeline Operational 2009 40

Myanmar Under construction 2013 11

Russia East Proposed 2020 38

Altai Proposed 2026 30


China LNG import terminals Terminal Partner Status Launch Capacity (bcm)

Tianjin CNOOC Under construction 2013 2.2

Zhuhai CNOOC Under construction 2013 3.5

Caofeidian PetroChina Under construction 2014 6.5

Qingdao Sinopec Under construction 2014 3.0

Hainan CNOOC Under construction 2015 2.0

Shenzhen CNOOC Under construction 2015 4.0

Subtotal

21.2

Jieyang CNOOC Proposed 2015 2.0

Guangxi Sinopec Proposed 2016 3.0

Yancheng CNOOC Proposed 2016 2.6

Lianyungang Sinopec Proposed 2017 3.0

Ningde CNOOC Proposed 2018 3.0

Zhanjiang CNOOC Proposed n/a n/a

Shenzhen PetroChina Proposed n/a n/a

Qinhuangdao CNOOC Proposed n/a n/a

Subtotal

13.6

Total

34.8 Source: Wood Mackenzie

Russian gas/LNG’s cost competitiveness guarantees a sweet spot in China. Therefore, despite significant liquefaction capacity additions in the world beyond 2015, we expect Russian companies to successfully market and sell their product. Competitive costs will play in favor of Russian LNG majors, we believe, especially as the price spread between Asian LNG and European spot starts to shrink. Russia, according to Wood Mackenzie, will be able to offer one of the most attractive LNG pricing to China with long-run delivered costs of just $9/mmbtu vs the current global average of $11.5/mmbtu and the current LNG price of $16.5/mmbtu.

Russian gas/LNG is cost-competitive Yamal LNG lies at the bottom-end of the global new LNG capacity cost curve


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25

Share data & recommendation Ticker LKOD LI

Last price, $ 60

Target price, $ 75

Upside, % 25%

Recommendation BUY

Market data MCap, $ mn 45,141

Free float, % 56%

Free float, $ mn 25,279

EV, $ mn 49,757

Equity performance 1W chg., % -4.2%

1M chg., % 4.2%

3M chg., % -5.7%

YTD chg., % -9.4%

Company snapshot Largest independent integrated Russian oil producer with interests overseas; hydrocarbon production 2.1mmboe/d in 2012; 2P reserves are 25bn boe, implying a 33-year reserve life. Operates 1.6mn bbl/d of refining capacity in Russia and Europe and runs the largest filling station network in Russia (c6,000 outlets). Growth outlook Lukoil is targeting a 40% hydrocarbon production increase by 2021, driven mainly by gas projects; key growth projects include Caspian offshore, Uzbek gas and Iraqi PSA West Qurna-2. The company estimates that its future FCF will be sufficient to allow a 15% pa dividend increase, the highest growth among peers. Valuation Lukoil is trading on 3.9x P/E ’14 and 2.4x EV/EBITDA ’14, a respective 28% and 45% discount to Russian peers. We believe the stock valuation does not fully reflect the company’s robust dividend growth and shareholder returns and should re-rate upwards.

Lukoil Highest shareholder returns in the sector

We consider dividends to be the cornerstone of Lukoil’s investment case. The highest dividend growth among peers, solid FCF and attractive valuation – we initiate coverage with a Buy call.

Robust dividend growth (15% pa) translates into highest returns among peers

Diversified asset growth portfolio (Uzbek gas, Iraqi PSA, tax-exempt Caspian fields) implying gradual production and earnings increase

Consensus has yet to re-assess the FCF outlook taking into account CapEx optimization and West Qurna-2 immediate cost recovery

West Siberian production starting to show positive signs: June statistics show production decline rate is decelerating

Attractive valuation – 3.9x P/E ‘14 – does not reflect robust shareholder returns

Highest dividend growth… We estimate Lukoil will generate $16bn of FCF during 2013-17. Assuming management maintains its 15% pa dividend growth target, the cumulative dividend stream over the same period will be $16bn, thus fully covered by cash flow. With the current yield at 5%, we estimate that investors could receive a third of Lukoil’s current market capitalization in dividends during the next five years, one of the highest among Russian peers.

… not reflected in the stock valuation. The market has become more confident in management’s 15% pa dividend growth guidance, as seen from higher consensus growth estimates (13% pa vs 4% last year). Nevertheless, despite the highest shareholder returns on the Street, the stock continues to trade at a discount to the sector average (28% vs 23% three-year average). We believe the gap will narrow once the market becomes more confident in the new project returns and the dividend growth story, and re-assesses the dynamic CapEx program and FCF outlook.

We expect consensus to re-assess Lukoil’s FCF outlook. Consensus is estimating negative FCF in the near term (-$1bn in 2013 and $0.8bn in 2014). On the contrary, we forecast robust FCF driven by i) constant CapEx optimization through a complex system of tendering with suppliers, which has already saved Lukoil billions of dollars, and ii) West Qurna-2 recovering over 80% of historical costs during the first year after launch.

West Siberian production is starting to recover. Production of West Siberian fields has been rolling over at 2% y/y since 4Q12, while Lukoil’s CapEx continued to rise. If such trend were to continue, the company valuation would take a $10/GDR hit, we estimate. According to CDU TEK, production kept rolling over at 2% during April-May, but June statistics showed an uptick in dynamics. Further production growth should encourage the market to de-risk Lukoil shares trading at a c30% discount to peers.

$mn 2012 2013e 2014e 2015e

Revenue, $mn 139,171 127,469 128,927 128,192

EBITDA, $mn 18,902 19,598 24,936 25,257

EPS, $ 14.09 13.59 13.46 12.45

DPS, $ 2.90 3.25 3.61 4.12

P/E, x 4.1 4.3 4.3 4.6

EV/EBITDA, x 2.6 2.5 2.0 2.0

EV/DACF, x 2.9 2.9 2.2 2.2

Dividend yield, % 4.8 5.4 6.0 6.9

FCF yield, % 17.2 5.5 8.3 8.9 Source: Company data, BCS

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LKOD LI , USD RTS (rhs)


26

We consider dividends to be the cornerstone of Lukoil’s investment case. We forecast the company will generate sufficient FCF over the next five years to deliver the targeted 15% pa dividend growth. However, Lukoil’s long-term ambitions require more conviction, in our view, due to various pressures on cash flow generation. Nevertheless, being five years away, the stock’s current investment story remains intact.

Dividends matter. Lukoil is a rare example of a Russian oil & gas company with a flexible dividend policy. DPS growth was twice that of EPS during 2010-12 – 22% vs 11%, thus implying a payout increase from 18% to 22%.

300% dividend growth by 2021, 15% pa. Management has been promoting the dividend thesis as a cornerstone of the company’s investment case since March 2012. Lukoil guidance posits 300% growth in dividends by 2021, or 15% pa. The dividend yield of 5% compares to that of the rest of Russian oil & gas majors and is only marginally below such high-yielding plays as Gazprom neft (8%) and Surgutneftegas pref (6%); however, future growth is significantly above that expected of its peers. In the past two years it has exceeded management’s own guidance (27% growth in 2011 and 20% in 2012).

Lukoil has grown DPS at 22% pa during 2010-12… … and now offers one of the highest dividend yields

Source: Company data, FactSet, BCS

Investors are starting to trust the dividend thesis. Investors have been warming up to Lukoil’s new investment case. As data from FactSet shows, consensus is expecting a 13% dividend CAGR over the next two years vs 4% a year ago. We think the reason consensus is still not fully pricing in management’s 15% guidance is because of the near-term pressures on FCF on the back of the large CapEx program Lukoil is carrying out. We, in turn, think this is not going to undermine the guided DPS growth.

Investors’ have significantly raised expectations over Lukoil’s three-year dividend growth prospects…

… especially after the board of directors proposed a 20% DPS increase in April, exceeding consensus expectations

Source: Company data, FactSet

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Russian O&G Supermajors Integrateds GEM oils

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Board of directors proposes a 20% increase in the 2012 DPS, above expectations


27

Consensus is mistakenly estimating negative FCF in the near term. The market is concerned with Lukoil’s 2013-14 FCF. According to FactSet, consensus expects -$1bn in 2013 and $0.8bn in 2014, and, therefore, questions how the company would afford to pay dividends, especially taking into account management’s guidance of a double-digit growth rate.

We believe the market is not factoring in West Qurna-2 properly... The consensus view is that this large capital-intensive project will not start recovering costs until several years from the launch (expected in 2014). We note that the baseline rate of 120kbd can be surpassed already the first year. Assuming 150kbd total initial production from c50 wells, revenue may exceed $5bn in 2014, i.e., sufficient to recover over 80% of historical costs.

… and do not expect WQ-2 to adversely impact Lukoil’s ability to pay dividends. Moreover, we point out that Lukoil’s CapEx in the past has been 10-20% below the original guidance. Lukoil’s system of tendering with suppliers has allowed the company to optimize CapEx spending, saving billions of dollars over the years. For example, last year, the company invested $12bn vs originally planned $14bn.

The market is conservative in its 2013-15 FCF forecast Near-term dividend is fully met by FCF, but long-term target requires additional cash flow generation

Source: FactSet, Wood Mackenzie, BCS

S-T 15% pa dividend growth no problem… Over the next five years, we estimate Lukoil to generate $16bn of FCF. Assuming management maintains its 15% pa dividend growth target, the cumulative dividend stream over the same period will be $16bn, thus fully covered by FCF.

… but L-T ambitions require more conviction. We are concerned about the period beyond 2017. We forecast average FCF at $4.7bn pa vs dividends of $6.1bn pa, assuming management’s 15% pa growth rate guidance. While the company’s production is likely to continue to grow, we see risks that generated FCF will be insufficient to meet the targeted dividend growth:

West Qurna-2: FCF will normalize at $0.2-0.4bn pa (vs $1.8bn and $1.3bn in 2014 and 2015, respectively) as Lukoil recovers all historical costs (our production assumptions are more conservative than the 1.2mmbbl/d target);

Uzbekistan: We forecast FCF to start declining beyond 2018 as the government increases its profit take (from 50% until IRR is below 18% to 80% once IRR exceeds 22%);

Refining: As we discussed in the Russian Oil & Gas Sector Outlook, we see risks of higher taxation once upgrade programs are completed;

Caspian: Tax breaks for Filanovskogo and Korchagina will expire in 2016-17

While not an issue for medium-term shareholder returns, sustainability of the double-digit dividend growth in the long term does raise red flags.

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2013e 2014e 2015e 2016e 2017e 2018e 2019e 2020e 2021e 2022e

$bnFCF Dividends


28

Proceeds from West Qurna-2 will normalize at c$0.2-0.4bn pa once partners recover all historical costs

The government will increase the share of profit take as the projects’ profitability rises


West Siberian operations, key FCF contributor, are getting expensive to maintain… While growth projects impact the FCF profile from the CapEx side, brownfields determine to a large extent operating cash flow. West Siberian fields, which account for 55% of the group’s crude production, generated over $3bn, or half, of last year’s FCF, we estimate. Lukoil has done an impressive job stabilizing production in 2012 – decline rates decelerated from -6% in 2008 to 0% in 1H12 – by application of various advanced recovery techniques such as horizontal drilling with horizontal deviations longer than average for Russia, multi-stage hydrofracturing, multiple completion and other techniques. However, over the past two quarters, production dynamics have been disappointing (down 2% y/y), while CapEx continued to grow.

Lukoil management acknowledges the problem of falling production, but is nevertheless confident it would achieve stabilization again. Data from CDU TEK demonstrates that production continued to roll over at 2% y/y in April-May, but has started to recover in June (-1.5% y/y). The key to watch is the trend sustainability going forward.

… weighing on valuation. We estimate Lukoil’s production stabilization efforts have cost it c$1.5bn of additional CapEx. If Lukoil’s production continues to roll over at 2% pa, the present value of foregone cash flows is $10/GDR. However, as June data from CDU TEK shows, production decline rate is gradually slowing down, hence, we do not incorporate the negative NPV impact in our model yet.

West Siberian production started to roll over again… … and the decline rate keeps accelerating

* Excluding consolidation of Samara-Nafta from April

Source: Company data, CDU TEK

-0.3

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-6%

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Production change, y/y Group West Siberia

-6%

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Production change, y/y Group* West Siberia


29

Financial and Operational Summary


Key price assumptions 2010 2011 2012 2013e 2014e 2015e Market statistics

Crude oil ($/bbl) Share Price ($) 59.80

Brent 80 111 112 104 99 95 Market Cap ($mn) 45,141

Urals 77 109 110 102 97 94 EV ($mn) 49,757

Domestic (Samara) 36 49 50 47 46 44

Crack spreads ($/bbl) Income Statement ($mn) 2010 2011 2012 2013e 2014e 2015e

Gasoline 16 17 23 22 23 22 Revenue 104,956 133,650 139,171 127,469 128,927 128,192

Diesel 12 17 19 17 18 17 Opex -7,969 -9,055 -9,359 -9,162 -9,157 -9,600

Jet fuel 15 22 23 22 23 23 Purchased oil -43,579 -59,694 -64,148 -55,635 -53,246 -51,250

Fuel oil -21 -30 -26 -28 -21 -20 Taxes other than income tax -8,978 -12,918 -13,666 -12,657 -11,805 -11,267

Gas, domestic Excise and export duties -18,878 -22,217 -22,836 -19,975 -18,879 -19,098

$/mcm 82 98 99 109 114 119 Other operating costs -9,865 -12,138 -10,260 -10,443 -10,903 -11,720

$/mcf 2.3 2.8 2.8 3.1 3.2 3.4 EBITDA 15,687 17,628 18,902 19,598 24,936 25,257

Depreciation 4,154 4,473 4,832 5,790 11,579 12,991

Macro assumptions 2010 2011 2012 2013e 2014e 2015e Operating income 11,533 13,155 14,070 13,808 13,357 12,266

USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 Finance expenses -538 -483 -281 -175 -165 -125

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% Other expense/income 475 447 -66 189 481 509

Pre-tax income 11,470 13,119 13,723 13,822 13,673 12,650

Production 2010 2011 2012 2013e 2014e 2015e Income taxes -2,351 -3,293 -2,798 -3,192 -3,145 -2,909

Crude oil Minority interest/other -113 531 79 -16 -16 -16

annual output (mmt) 96 91 90 91 93 96 Net income 9,006 10,357 11,004 10,614 10,512 9,724

daily output (kbd) 1,920 1,821 1,790 1,814 1,858 1,926 Fully diluted EPS ($) 10.94 12.96 14.09 13.59 13.46 12.45

Refined products

annual output (mmt) 64 63 64 63 64 64 Balance sheet ($mn) 2010 2011 2012 2013e 2014e 2015e

daily output (kbd) 1,272 1,253 1,272 1,267 1,274 1,274 Cash 2,368 2,753 2,914 2,681 2,681 2,681

light product yield 69% 69% 73% 73% 73% 76% Inventories 6,231 7,533 8,098 6,998 8,653 8,359

Gas (bcm) 18.6 18.6 19.9 20.9 22.4 24.6 Accounts receivable 8,219 8,921 8,667 7,991 7,963 7,991

Other current assets 3,799 4,322 4,594 4,205 4,205 4,205

Reserves (SEC) Total current assets 20,617 23,529 24,273 21,875 23,502 23,236

1P 2P 1P+2P 3P 1P+2P+3P Fixed assets 54,629 56,803 66,883 76,618 81,825 87,602

Oil (bn bbl) 13.4 5.9 19.3 3.7 23.0 Other non-current assets 8,771 10,860 7,805 8,159 8,159 8,159

Gas (bcm) 665 304 969 101 1,070 Total non-current assets 63,400 67,663 74,688 84,777 89,984 95,761

Total (bn boe) 17.3 7.7 25.0 4.3 29.3 Total assets 84,017 91,192 98,961 106,652 113,486 118,997

EV/Reserves ($/boe) 2.9 2.0 1.7 Short-term debt 2,125 1,792 658 1,481 189 584

Reserve life (years) 22 32 37 Accounts payable 5,607 5,995 7,263 5,864 5,913 5,712

Other current liabilities 3,043 3,321 4,532 4,725 4,725 4,725

Financial ratios 2010 2011 2012 2013e 2014e 2015e Total current liabilities 10,775 11,108 12,453 12,070 10,827 11,020

Valuation Long-term debt 9,069 7,300 5,963 5,747 5,747 4,049

P/E (x) 5.0 4.4 4.1 4.3 4.3 4.6 Other non-current liabilities 4,976 5,146 7,338 7,478 7,494 7,510

PEG (x) 17.6 29.1 65.7 NM NM NM Total non-current liabilities 14,045 12,446 13,301 13,225 13,241 11,559

P/B (x) 0.8 0.7 0.6 0.6 0.5 0.5 Total shareholders' equity 59,197 67,638 73,207 81,358 89,419 96,417

EV/EBITDA (x) 3.2 2.8 2.6 2.5 2.0 2.0 Total liabilities and equity 84,017 91,192 98,961 106,652 113,486 118,997

EV/DACF (x) 3.3 2.8 2.9 2.9 2.2 2.2

Dividend yield (%) 3.2% 4.3% 4.8% 5.4% 6.0% 6.9% Cash flow statement ($mn) 2010 2011 2012 2013e 2014e 2015e

FCF Yield (%) 15.7% 16.4% 17.2% 5.5% 8.3% 8.9% Net income 9,006 10,357 11,004 10,614 10,512 9,724

Profitability Depreciation 4,154 4,473 4,832 5,790 11,579 12,991

EBITDA Margin (%) 15% 13% 14% 15% 19% 20% Changes in working capital -826 -1,529 2,474 670 -1,578 65

EBIT Margin (%) 11% 10% 10% 11% 10% 10% Other 1,207 2,213 687 68 0 0

Net Margin (%) 9% 8% 8% 8% 8% 8% Operating cash flow 13,541 15,514 18,997 17,142 20,514 22,781

Leverage Capex -6,468 -8,093 -11,235 -14,665 -16,786 -18,768

Gross Debt/Equity (x) 0.2 0.1 0.1 0.1 0.1 0.0 Acquisitions -813 -2,655 -1060 38 0 0

Net Debt/Equity (x) 0.1 0.1 0.0 0.1 0.0 0.0 Other -15 -25 -921 -838 0 0

Gross Debt/EBITDA (x) 0.7 0.5 0.4 0.4 0.2 0.2 Investing cash flow -7,296 -10,773 -13,216 -15,465 -16,786 -18,768

Net Debt/EBITDA (x) 0.6 0.4 0.2 0.2 0.1 0.1 Change in debt 35 -2,004 -1,266 605 -1,292 -1,303

Net Interest Cover (x) 21.4 27.2 50.1 79.0 80.8 98.0 Dividends -1,556 -1,830 -2,913 -2,494 -2,451 -2,726

Returns Other -4,625 -2,189 -1,501 6 16 16

ROE (%) 16% 16% 16% 14% 12% 10% Financing cash flow -6,146 -6,023 -5,680 -1,883 -3,727 -4,013

ROACE (%) 14% 14% 15% 13% 12% 10% Effect of Forex -5 -93 60 -27 0 0

ROA (%) 11% 12% 12% 10% 10% 8% Increase (decrease) in cash flow 94 -1,375 161 -233 0 0


30

Share data & recommendation Ticker NVTK LI

Last price, $ 116

Target price, $ 145

Upside, % 25%

Recommendation BUY


Free float, % 26%


EV, $ mn 38,737


1M chg., % -2.6%

3M chg., % 14.6%

YTD chg., % -3.5%

Company snapshot Largest independent and most efficient gas producer in Russia (9% of country’s output in 2012). Unprecedented project execution track-record; production has grown at 20% CAGR since 2004. Novatek delivers all of its gas directly (by-passing sales to Gazprom) to Russian customers, which include power companies, industrial users, regional gas distributors and wholesale gas traders. Growth outlook Novatek plans to double gas production and treble liquid hydrocarbon production by 2020. Near-term growth is dependent on Severenergia and Nortgas ramp-up, and Ust-Luga and Purovsky plants expansion. Long-term growth projects include Yamal LNG and the potential development of Gydan fields. Valuation Novatek trades at a substantial premium to peers on earnings multiples (11.2x P/E ’14). We expect the premium to persist, reflecting Novatek’s superior growth prospects and robust investment returns.

Novatek Robust growth & catalysts Novatek remains the fastest growing company among Russian oil & gas majors, justifying valuation premium. Positive news flow in fall should de-risk Novatek’s flagship Yamal LNG project – we initiate coverage with a Buy call.

Strong execution track-record, value-accretive expansion projects and vast resource base have justified Novatek’s valuation premium…

… which we expect to persist going forward, given Novatek’s robust growth prospects and investment returns

Anticipated growth is significantly above the sector average, accelerating in the second half of the decade once Gydan fields and Yamal LNG come on-stream

The stock is especially attractive in the short term, given numerous up-coming catalysts de-risking Novatek’s flagship Yamal LNG project (19% of our fair value)…

… which offsets a handful of industry regulatory risks, including slower domestic tariff growth and gas and condensate MET hike

Unprecedented execution track-record… In the last ten years, Novatek demonstrated the highest organic growth (20% production CAGR) and a top-class execution track record (Yurkhara, Severenergia). The company plans to further expand its operations, targeting higher efficiency and profitability. Such projects as the Purovsky plant expansion, the Ust-Luga plant and Yamal LNG will account for 11% of the group’s next year’s earnings, the share rising to 38% by 2022.

… confident growth … Novatek’s portfolio of growth and margin-expansion projects will contribute to the highest earnings increase among peers over the next four years – 4% CAGR 2013-17e vs industry average of 0%. Even though the growth is slower than that witnessed in the past (25% EPS CAGR 2008-12), we expect it to accelerate in the second half of the decade (13% EPS CAGR 2017-22e) once Gydan fields and Yamal LNG come on-stream.

… and numerous up-coming catalysts… We expect liberalization of LNG exports in the Fall, final investment decision on Yamal LNG, more pre-shipment LNG contracts and potential entry of a fourth partner to de-risk further Novatek’s flagship LNG project, which accounts for 19% of the company valuation, we estimate. Continued increase in the domestic customer base – acquisition of regional gas marketers or infrastructure; acquisition of existing producing assets; taking advantage of Gazprom’s expiring agreements – also serves a strong catalyst.

… overshadow industry regulatory risks. The high share of domestic gas sales makes Novatek susceptible to gas industry regulatory risks. Slower domestic gas tariff indexation (5% pa vs current 15%) and further gas and condensate MET hike, if confirmed, could cost Novatek 17% of EBITDA during 2014-15 and 27% of TP. However, we have incorporated the lower domestic gas prices in our numbers, which puts us below consensus estimates.

$mn 2012 2013e 2014e 2015e

Revenue, $mn 6,801 9,896 10,891 11,727

EBITDA, $mn 3,109 4,132 4,223 4,224

EPS, $ 7.37 9.43 10.19 10.17

DPS, $ 0.22 0.28 0.31 0.30

P/E, x 15.7 12.3 11.4 11.4

EV/EBITDA, x 12.5 9.4 9.2 9.2

EV/DACF, x 14.3 11.2 10.5 10.2

Dividend yield, % 1.9 2.4 2.6 2.6


1171

1281

1391

1501

1611

96

105

115

124

134


NVTK LI , USD RTS (rhs)


31

Novatek continues to grow production and improve margins. The company’s execution remains unprecedented and even though half of long-term growth depends on projects not yet commenced, we have little doubt in management’s ability to deliver on time. On the flip side, earnings growth over the next three-four years will be lower than it was in the past, but still the highest among sector peers.

A road from growth to profitability. Novatek, in the last decade, has been the fastest growing Russian Oil & Gas major. The company has substantially expanded its resource base and has doubled gas and liquid hydrocarbon output since 2005, which, coupled with favorable macro, has led to a fivefold increase in earnings. Investors picked up on the growth story and drove the stock sevenfold from the IPO’s $16.75/GDR price.

Today, Novatek is no less ambitious. The company intends to double gas output and treble liquid hydrocarbon output by 2020. In addition, Novatek is also undertaking profitability enhancement projects such as the Purovsky plant expansion, the Ust-Luga plant and Yamal LNG, which, we estimate, together will account for 11% of the group’s earnings next year, the share rising to 38% by 2022.

Novatek may double hydrocarbon output over the next decade ... … and profitability enhancement projects will account for a larger share of the group’s earnings


Rising share of high-margin liquids. We expect liquid hydrocarbon production to rise at a slightly higher pace than gas due to the front-loaded nature. We expect output to double by 2018, driven primarily by Severenergia and potentially by the launch of liquids-rich Gydan fields. On our estimates, condensate is almost $10/bbl more profitable than crude due to the difference in MET ($19/bbl). In addition, Purovsky planned expansion and the launch of the Ust-Luga plant will raise margins even higher:

Increasing vertical integration with Ust-Luga. In June, Novatek officially launched the Ust-Luga port and condensate fractionalization facility. The plant uses condensate feedstock to process into light and heavy oil products to be sold on international markets. The first batch of naphtha has already gone to Brazil. The plant runs one 3mtpa production train and will add another one by the end of 2015.

Ust-Luga will not only expand and differentiate Novatek’s sales, but also will allow 1) take advantage of the export duty differentials: condensate export duty is similar to crude, while export duty on oil products is 66% of it (except for gasoline’s and naphtha’s 90%); 2) save on transport costs: the distance between Purovsky and Ust-Luga is c400km shorter than from Purovsky to Vitino, where Novatek handles gas condensate exports. Together the two factors contribute additional $10/bbl margin.

Handling partners’ share of condensate at expanded Purovsky. Novatek plans to more than double capacity of its Purovsky plant’s next year. While the company may not have enough of its own condensate to fully utilize 11mtpa capacity of the expanded plant, Novatek has agreements in place to process liquid hydrocarbons coming from Severenergia (Novatek owns 25.5%) and Nortgas (50%).

Based on Novatek’s 1Q13 financial accounts, the company purchased condensate from Severenergia at an average price of $369/ton vs the prevailing domestic price of $436/ton, thus realizing a $67/ton margin.

71

174 199 197 212 228264

366 386419 428 434 442 453

542 568615 630 646

0

100

200

300

400

500

600

700

2004

2005

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2007

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2009

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e

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mmboe

Gas Liquids

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$bn

Yamal LNG Purovsky Ust-Luga


32

Ust-Luga provides margin on top of already highly profitable condensate sales

LNG exports are twice more profitable than pipeline gas exports

Source: BCS

The margin has shrunk from $179/ton in 2Q12. If the margin were sustainable going forward, we estimate Novatek could generate additional $400mn pa of EBITDA.

Yamal LNG is Novatek’s flagship project … Yamal LNG, a high-margin alternative to pipeline gas export, will bring the company’s gas to international markets. The project has received tremendous support from the Russian state (attractive fiscal terms, including reduced income tax, MET tax breaks, absence of export duty, commitment to finance the development of regional infrastructure and construction of new-class ice-breakers), attracted two partners, Total and CNPC, taking a 20% ownership stake each, and already contracted half of LNG volumes (Interfax, July 1). In addition, Novatek, unlike its project partners, enjoys the disproportionate CapEx financing terms (we estimate that Novatek will finance a third of Yamal LNG’s CapEx while holding a 51% stake), making the project even more value-accretive to the company.

… and LNG exports to generate higher margins. LNG exports more profitable than domestic gas shipments and pipeline exports, despite execution risks and uncertainty over the long-term LNG price due to significant capacity additions globally, we estimate. At current prices and tariffs, LNG exports are two-fold more profitable than pipeline gas exports ($360/mcm vs $170/mcm) and seven times more profitable than domestic gas delivery ($360/mcm vs $50/mcm). Even if elevated LNG prices in Asia were to come down to current European spot levels, LNG exports would still generate a higher margin due to zero export duty ($220/mcm vs $170/mcm).

Modest earnings growth over the next four years… One of key points of Novatek’s investment case in the past was robust production and earnings growth. While the company’s targets over the next decade are no less ambitious, the growth is back-end loaded (beyond 2017) and largely dependent on two major projects – Yamal LNG and Gydan fields. The former is rapidly moving forward, but the decision on the latter is not finalized yet.

We forecast modest earnings growth over the next four years – 4% CAGR 2013-17e. The number compares to 25% CAGR 2008-12. Our financial projections are more conservative than those of consensus: we model in a downward sloping Brent curve, 5% (vs 15%) pa domestic gas tariff growth and income loss from Yamal LNG as the project raises financing. In the long-term, we expect earnings growth to accelerate, once Gydan fields and Yamal LNG come on-stream, but this is not until 2017-18. Our project analysis demonstrates that Gydan and Yamal will account for almost half of the group’s earnings in the long-term.

… but FCF profile is looking healthy. Despite the modest growth outlook in the near-term, Novatek is likely to remain highly FCF generative. Unlike the Russian oils going through a major CapEx cycle, we forecast Novatek’s FCF yield in excess of 5%, equivalent to $1.5bn of FCF pa.

33

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Oil products (Ust-Luga) Condensate Crude

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Export duty difference

Transport cost difference

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33

However, robust FCF does not imply shareholders would enjoy full benefits of it:

No changes to the dividend policy: Novatek management has no plans to amend the current dividend policy of 30% RAS net profit payout yielding slightly over 2%.

Buyback is supportive for the stock, but no share cancellation expected: Novatek extended until June 2014 the $600mn share buyback program. While the volume is insignificant in context of daily trading, it still provides downside support for shares. To date, Novatek bought back slightly more than $60mn worth of shares.

Growth is slowing down in the near-term… … and is dependent on two mega projects in the long-term


Despite growing CapEx requirements… … we forecast Novatek to remain highly FCF generative

Source: BCS

0.20.5 0.5 0.7 0.9 0.8

1.31.9

2.2

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0

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Core Yamal + Gydan

1.6

2.12.2

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1.9 1.9 1.9

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$bn

Legacy upstream Downstream Gydan

0.9 0.9 0.9 1.0 1.0 1.1 1.2 1.2 1.5 1.9

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$bn

FCF Dividends


34






Urals 77 109 110 102 97 94 EV ($mn) 38,737


Gas, domestic Income Statement ($mn) 2010 2011 2012 2013e 2014e 2015e

$/mcm 82 98 99 109 114 119 Revenue 3,911 5,999 6,801 9,896 10,891 11,727

$/mcf 2.3 2.8 2.8 3.1 3.2 3.4 Transportation -1,225 -1,639 -1,960 -3,297 -3,139 -3,468

Taxes other than income tax -332 -597 -543 -678 -1,201 -1,219

Macro assumptions 2010 2011 2012 2013e 2014e 2015e Other operating costs -482 -771 -1,189 -1,789 -2,328 -2,817

USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 EBITDA 1,872 2,992 3,109 4,132 4,223 4,224

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% Depreciation 218 316 360 427 529 652

Operating income 1,655 2,676 2,749 3,705 3,694 3,572

Production 2010 2011 2012 2013e 2014e 2015e Finance expenses 5 42 -48 -72 -39 -20

Gas (bcm) Other expense/income 23 -266 77 -73 168 243

Yurkharovskoye 24.4 32.0 34.1 35.5 35.8 35.8 Pre-tax income 1,683 2,452 2,778 3,560 3,823 3,795

Other fields 12.8 15.5 16.5 16.4 16.4 16.4 Income taxes -356 -535 -540 -697 -728 -708

Subtotal 37.3 47.5 50.5 51.9 52.2 52.2 Minority interest/other 8 12 1 0 - -

Sibneftegas 5.4 5.3 5.4 5.4 5.4 Net income 1,335 1,929 2,238 2,864 3,095 3,087

Nortgas 2.5 3.0 3.5 Fully diluted EPS ($) 4.40 6.35 7.37 9.43 10.19 10.17

Severenergia 0.6 1.2 1.9 3.5

Total 37.3 52.9 56.5 60.9 62.5 64.6 Balance sheet ($mn) 2010 2011 2012 2013e 2014e 2015e

Cash 333 740 603 544 544 544

Liquids (mmboe) 29.6 33.6 34.6 43.4 46.8 50.5 Inventories 61 52 101 58 68 76

Accounts receivable 282 519 537 859 950 1,040

Reserves (PRMS) Other current assets 286 500 665 385 385 385

1P 2P 1P+2P 3P 1P+2P+3P Total current assets 962 1,811 1,907 1,846 1,947 2,046

Gas (bcm) 2,195 911 3,106 698 3,804 Fixed assets 5,519 4,632 5,306 6,162 7,723 9,306

Liquids (mmbbl) 1,242 801 2,043 1,193 3,236 Other non-current assets 2,801 5,466 7,948 8,435 8,435 8,435

Oil and Gas (bn boe) 15.6 6.8 22.4 5.8 28.1 Total non-current assets 8,320 10,098 13,254 14,598 16,159 17,742

EV/Reserves ($/boe) 2.5 1.7 1.4 Total assets 9,282 11,909 15,161 16,444 18,106 19,787

Reserve life (years) 35 51 64 Short-term debt 819 630 1,135 0 56 60

Accounts payable 927 774 521 529 620 695

Financial ratios 2010 2011 2012 2013e 2014e 2015e Other current liabilities 124 152 148 165 193 217

Valuation Total current liabilities 1,870 1,557 1,805 695 869 972

P/E (x) 26.4 18.2 15.7 12.3 11.4 11.4 Long-term debt 1,532 2,335 3,202 3,299 2,622 2,040

PEG (x) 42.1 41.0 98.3 43.9 141.0 NM Other non-current liabilities 1,092 532 660 679 679 679

P/B (x) 8.2 5.7 4.1 3.3 2.7 2.3 Total non-current liabilities 2,624 2,867 3,861 3,977 3,301 2,719

EV/EBITDA (x) 20.7 12.9 12.5 9.4 9.2 9.2 Total shareholders' equity 4,789 7,486 9,495 11,772 13,936 16,096

EV/DACF (x) 23.3 14.7 14.3 11.2 10.5 10.2 Total liabilities and equity 9,282 11,909 15,161 16,444 18,106 19,787

Dividend yield (%) 1.1% 1.8% 1.9% 2.4% 2.6% 2.6%

FCF Yield (%) 2.0% 4.2% 3.3% 4.9% 4.0% 3.6% Cash flow statement ($mn) 2010 2011 2012 2013e 2014e 2015e

Profitability Net income 1,335 1,929 2,238 2,864 3,095 3,087

EBITDA Margin (%) 48% 50% 46% 42% 39% 36% Depreciation 218 316 360 427 529 652

EBIT Margin (%) 42% 45% 40% 37% 34% 30% Changes in working capital -139 -155 -165 -56 17 1

Net Margin (%) 34% 32% 33% 29% 28% 26% Other 63 356 10 63 - -

Leverage Operating cash flow 1,478 2,446 2,443 3,298 3,641 3,739

Gross Debt/Equity (x) 0.5 0.4 0.5 0.3 0.2 0.1 Capex -772 -981 -1,291 -1,651 -2,090 -2,234

Net Debt/Equity (x) 0.4 0.3 0.4 0.2 0.2 0.1 Other -1,511 -722 -1,475 261 - -


Net Debt/EBITDA (x) 1.1 0.7 1.2 0.7 0.5 0.4 Change in debt 1,100 637 1,312 -1,027 -620 -578

Net Interest Cover (x) NM NM 56.7 51.6 94.2 177.8 Dividends -325 -516 -635 -394 -931 -927

Returns Other -8 -460 500 42 - -

ROE (%) 31% 31% 26% 27% 24% 21% Financing cash flow 766 -339 177 -1,463 -1,551 -1,505

ROACE (%) 21% 25% 19% 21% 19% 17% Effect of Forex -3 2 -63 18 - -

ROA (%) 17% 18% 17% 18% 18% 16% Increase (decrease) in cash flow -42 407 -210 -59 0 0


35

Share data & recommendation Ticker ROSN LI

Last price, $ 7.16

Target price, $ 8.30

Upside, % 16%

Recommendation HOLD


Free float, % 10%


EV, $ mn 136,140


1M chg., % 4.4%

3M chg., % 4.8%

YTD chg., % -20.2%

Company snapshot Largest integrated oil producer accounting for 40% of Russia’s crude output. Has unique access to vast offshore oil resources, which it plans to develop with foreign partners (e.g., ExxonMobil, Eni, Statoil). Rosneft is also the major gas player and plans to enter the LNG market by the end of the decade. Growth outlook Rosneft plans to produce 220mtpa of crude, more than double gas output and launch LNG production by 2020. Long-term growth is dependent on exploration success in the offshore Arctic and Far East. Given its vast scale, Rosneft carries a large responsibility for the Russian oil sector, hence, government support, if necessary, is always at the company’s disposal.

Valuation Rosneft trades at 2014e P/E of 6.2x and 2014e EV/EBITDA of 4.9x, a 38% and 65% premium to Russian peers. We believe the premium reflects the company’s unique access to resources and robust FCF generation potential in long-term.

Rosneft Shareholder returns captive to high CapEx Despite superior cash flow potential and non-monetized synergies, shareholder returns do not match Rosneft’s business’ scale and ambitions. We initiate coverage with a Hold call.

Solid financial position and immense FCF generation capabilities

TNK-BP merger synergies have yet to be monetized, reflected in stock valuation

Primary beneficiary of the greenfield tax reform proposals…

… due to largest portfolio of greenfield projects, potentially translating into robust returns in the long term

However, large CapEx requirements in coming decade…

… restrain near-term shareholder returns to the 4% dividend yield, one of the lowest among peers

Superior cash flow potential … Despite heavy investments over the next three years, we estimate Rosneft will generate sufficient FCF ($2-3bn pa) to cover dividends, before becoming a ‘fat cash cow’ in the second half of the decade – Rosneft could become a superior cash flow play in three-four years and generate over $50bn of FCF during 2017-22, enough to fully deleverage. Our FCF forecast rises to $10bn by 2018 as refining profitability improves and greenfields bring along new barrels.

… and substantial merger synergies have yet to be monetized. Close proximity of Rosneft’s and TNK-BP’s assets and the possibility of asset integration and optimization may allow the merged company to monetize up to $12bn of operational synergies, according to Rosneft estimates. A third of synergies would come from CapEx savings and the rest from operating efficiency. The synergy effect is equivalent to $1.1/GDR, but we conservatively do not model it yet.

However, extensive greenfield development possible, implies demanding CapEx… Rosneft has the largest greenfield portfolio among peers. The launch of its numerous oil and gas fields in East Siberia, continental shelf, tight oil resources, Arctic offshore, LNG facilities and petrochemical complex requires investments of hundreds of billions of dollars. Due to significant responsibility for the Russian oil industry, Rosneft may accelerate the development of these projects and look for ways to expand the resource base to ensure continuous oil production. Thus, the company may find itself in a permanent CapEx cycle.

… thus, capping shareholder returns in the near-term. Assuming a stable macro environment, we forecast flat EPS dynamics over the next three years, hence, a 4% dividend yield at best. Deleveraging is possible beyond 2016, but to ensure the launch of major projects (LNG plants, Arctic and other offshore fields) by the end of decade, Rosneft would start spending already in the coming years, we anticipate. While projects could eventually generate sufficient returns and thus benefit shareholders, the payback is too distant for equity funds’ time horizon.

$mn 2012 2013e 2014e 2015e

Revenue, $mn 99,161 139,233 150,737 144,668

EBITDA, $mn 19,620 26,503 30,994 26,214

EPS, $ 1.17 1.04 1.25 0.83

DPS, $ 0.26 0.24 0.31 0.21

P/E, x 6.9 7.3 5.7 8.7

EV/EBITDA, x 6.9 5.1 4.4 5.2

EV/DACF, x 6.9 5.5 5.0 5.8

Dividend yield, % 3.6 3.4 4.4 2.9


1171

1281

1391

1501

1611

6.07

6.61

7.15

7.69

8.23


ROSN LI , USD RTS (rhs)


36

Rosneft, fundamentally, could become a superior cash flow play in three-four years and generate over $50bn of FCF during 2017-22, enough to fully deleverage. However, we believe the company is more likely to engage in active continental shelf and tight oil development, potentially yielding higher returns than interest on its loans, but claiming most of FCF. We see Rosneft in a permanent CapEx cycle due to its enhanced market leadership position post TNK-BP merger and associated responsibilities for the Russian oil sector, therefore, capping returns to shareholders in the near-term.

Rosneft’s merger with TNK-BP does ‘not a Gazprom make’. Market opinion on Rosneft’s merger with TNK-BP is mixed. Some believe that the much larger Rosneft will deliver growth and efficiency required to become a world class major. Others are concerned that, similar to Gazprom, Rosneft will exercise poor CapEx discipline and deliver modest shareholder returns.

We argue that despite comparable scale and state ownership, Rosneft will unlikely exhibit the Gazprom’s negatively perceived characteristics. We believe Gazprom’s CapEx inefficiency comes from the transportation and storage segments, which account for almost half of total CapEx, while contributing a mere 3% of the group’s earnings. On the contrary, Rosneft does not own or run the pipelines (Transneft does that). Moreover, at the EGM in November last year, Rosneft CEO Igor Sechin said the company was satisfied with Transneft taking care of oil and products transportation.

Fundamental analysis points to robust FCF generation capabilities… Rosneft’s FCF profile resembles that of most Russian oil companies – constrained FCF during the next two-three years and significant improvement beyond 2016 when the bulk of investments in refining is completed and higher-margin light products replace fuel oil.

We expect Rosneft’s FCF to average $2-3bn pa during the next three years, just enough to cover dividends. There is an upside to our numbers from the potential $12bn worth of synergies from the merger with TNK-BP, 60% of which during the next five years. We conservatively do not model synergies. Our FCF forecast rises to $10bn by 2018 as refining profitability improves and greenfields bring along new barrels.

We forecast a considerable FCF improvement… … once the CapEx cycle peak has passed

Source: BCS

… but, in reality, there are multiple risks to shareholder returns. In theory, a period of heavy CapEx cycle is followed by several years of rising output and prosperous cash flows, translating into high shareholder returns. Such pattern has worked for European majors. Most Russian Oil & Gas companies are set to undergo a major investment cycle.

While Rosneft has potential to become a superior cash generator (we estimate cumulative 2017-21 FCF at $46bn), we see significant risks to our FCF projections:

Next generation oil resources development. To ensure continuous oil production in Russia, Rosneft, as the undisputed market leader (40% of Russian crude production), will engage in extensive tight oil and continental shelf development, we expect.

2.63.3

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FCF Dividends

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17.7 17.8 17.9 17.8 17.6

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37

While the company is not financing exploration, its engagement at subsequent capital-intensive stages (late-2010s – next decade) is likely to claim billions of dollars of cash flows.

CapEx over-run. Although Rosneft’s execution track-record has not raised concerns so far, one cannot completely rule out such risks, especially considering that two thirds of Rosneft’s investments are aimed at growth projects (greenfields and refinery upgrade). We estimate that a 10% CapEx over-run is equivalent to over $2bn pa of foregone FCF.

Project launch delay. Refinery upgrades are one of the key and first-to-kick-in FCF drivers for most Russian oil companies. We estimate an improved product slate could add a c$4/bbl margin, while CapEx reduction could amount to $6-7/bbl of extra FCF. In Rosneft’s case, FCF boost may be in excess of $6bn pa. Alternatively, a failure to upgrade on time would imply delayed cash inflow.

Oil price volatility. This could be both a positive and a negative risk. On our estimates, a $10/bbl drop in the oil price would claim $1.5-2bn of FCF. While oil companies’ development strategies are fairly flexible and companies could simply postpone some project development and negotiate discounts with suppliers, we expect the net impact to be negative nevertheless.

Greenfields / upgraded refineries will account for 2/3 of FCF uplift

FCF is sensitive to macro changes and CapEx over-run

Source: BCS

We do not expect Rosneft to rapidly deleverage despite capabilities to do so. While some may argue that Rosneft has a substantial debt burden to repay ($70bn) and therefore will exercise considerable CapEx discipline, we believe such high leverage will not prevent the company from, if necessary, levering up even more. A net debt/EBITDA multiple of 2.2x in an unstable oil price environment carries significant risks, but Rosneft has recently agreed with China on a $65bn advance, which will allow the company to fully refinance its debt. Terms of the agreement were not disclosed, but we believe the terms could be even more favorable than those on the previous $15bn 20-year Chinese loan granted to Rosneft in 2009.

Rosneft could start deleveraging already in five years, following the completion of the refinery modernization program. We estimate the cumulative FCF during 2017-22 at $56bn, sufficient to fully cover the net debt. However, with the long-term Chinese cheap loan (we estimate net interest payments at c$1bn), we believe Rosneft will not rush to deleverage but instead will proceed with further expansion potentially yielding >15% long-term IRR, higher than the c3% interest rate the company currently pays.

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38






Urals 77 109 110 105 101 95 EV ($mn) 136,140




Diesel 12 17 19 16 18 17 Opex -4,743 -6,430 -7,088 -12,216 -14,461 -15,291





$/mcf 2.3 2.8 2.8 3.1 3.2 3.4 EBITDA 19,302 22,521 19,620 26,503 30,994 26,214

Depreciation 6,653 7,246 7,313 10,654 11,707 12,554


USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 Finance expenses -33 34 290 -1,909 -2,530 -2,609

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% Other expense/income -791 -1,531 1,482 -1,303 -213 -87

Pre-tax income 11,825 13,778 14,078 12,638 16,543 10,965

Production 2010 2011 2012 2013e 2014e 2015e Income taxes -1,910 -2,926 -3,061 -2,309 -3,309 -2,193

Crude oil Minority interest/other -264 -102 -32 0 0 0



Refined products


daily output (kbd) 958 962 967 1,432 1,703 1,703 Cash 4,134 5,156 9,788 10,578 10,578 10,578




Reserves (PRMS) Total current assets 22,654 25,314 30,771 40,282 40,204 39,809


Oil (bn bbl) 18.3 9.8 28.2 8.9 37.1 Other non-current assets 8,723 10,281 13,291 25,100 25,100 25,100

Gas (bcm) 992 372 1,363 262 1,625 Total non-current assets 75,481 79,575 99,646 175,136 186,799 196,658

Total (bn boe) 24.2 12.0 36.2 10.4 46.6 Total assets 98,135 104,888 130,418 215,417 227,003 236,467

EV/Reserves ($/boe) 5.6 3.8 2.9 Short-term debt 5,436 4,721 4,681 19,104 20,060 24,085

Reserve life (years) 13 20 26 Accounts payable 3,678 5,622 6,973 12,407 12,385 12,360

Other current liabilities 2,344 2,516 3,241 5,503 5,503 5,503




PEG (x) 16.3 62.0 315.3 NM 20.4 NM Total non-current liabilities 29,424 28,823 40,788 94,011 94,011 94,011

P/B (x) 1.5 1.3 1.1 1.0 0.8 0.8 Total shareholders' equity 57,254 63,206 74,735 84,392 95,045 100,508

EV/EBITDA (x) 7.1 6.0 6.9 5.1 4.4 5.2 Total liabilities and equity 98,135 104,888 130,418 215,417 227,003 236,467

EV/DACF (x) 8.4 6.4 6.9 5.5 5.0 5.8

Dividend yield (%) 1.3% 3.4% 3.6% 3.4% 4.4% 2.9% Cash flow statement ($mn) 2010 2011 2012 2013e 2014e 2015e

FCF Yield (%) 9.9% 10.7% 6.6% 12.0% 5.0% 1.9% Net income 9,914 10,852 11,018 10,328 13,235 8,772

Profitability Depreciation 6,653 7,246 7,313 10,654 11,707 12,554

EBITDA Margin (%) 31% 24% 20% 19% 21% 18% Changes in working capital -494 -2,654 966 6,739 55 370

EBIT Margin (%) 20% 17% 12% 11% 13% 9% Other -329 3,300 1,675 2,322 - -


Leverage Capex -8,696 -13,302 -15,013 -20,970 -23,371 -22,413

Gross Debt/Equity (x) 0.4 0.4 0.4 0.9 0.8 0.8 Acquisitions -3,162 987 -193 -4,041 - -

Net Debt/Equity (x) 0.2 0.2 0.3 0.7 0.6 0.6 Other -626 -1,157 838 3 - -


Net Debt/EBITDA (x) 0.6 0.6 1.0 2.3 2.0 2.5 Change in debt 296 306 7,893 38,683 956 4,026

Net Interest Cover (x) 384.0 NM NM 8.3 7.6 5.2 Dividends -725 -919 -2,287 -2,403 -2,582 -3,309

Returns Other -696 -3,707 -7,288 -40,943 - -

ROE (%) 19% 18% 16% 13% 15% 9% Financing cash flow -1,124 -4,319 -1,682 -4,663 -1,626 717

ROACE (%) 15% 16% 10% 9% 10% 7% Effect of Forex 0 68 -290 418 - -

ROA (%) 11% 11% 9% 6% 6% 4% Increase (decrease) in cash flow 2,137 1,022 4,632 790 0 0


39

Share data & recommendation Ticker OGZD LI

Last price, $ 7.85


Upside, % 8%

Recommendation HOLD


Free float, % 47%


EV, $ mn 135,165


1M chg., % 19.3%

3M chg., % -1.1%

YTD chg., % -16.7%

Company snapshot Largest gas producer in the world (15% of global gas output); largest gas supplier to Europe (30% of the region’s consumption). The company holds 18% of global gas resources (35tcm). Through its Gazprom neft subsidiary, Gazprom has a significant presence on the oil market too. The company is the sole operator of domestic and export gas pipelines.

Growth outlook Gazprom’s primary growth region is East Siberia and Far East (the so called Eastern Gas Program). To offset stagnating gas demand in Europe and market share loss at home, Gazprom plans to increase the share of export sales targeting pipeline gas supply to China and construction of several LNG facilities.

Valuation Cheapest energy name in the world, trading on 2.9x P/E ’14. Valuation multiples have significantly de-rated since the 2008-09 Financial Crisis, which we attribute to uninspiring investment returns. Our analysis demonstrates that Gazprom will unlikely impress with shareholder returns in the long-term either.

Gazprom World’s cheapest energy name, for good cause Gazprom’s core store of value is found in dividends. The investment case based on future dividends, which assumes approval of the State’s higher payout of 25% of IFRS beginning 2015, is muted – markets have largely priced in the variable; we estimate stock upside of 8%. Positive ROI would create further upside, but this is remote and until then upside is capped by the DDM value. We initiate coverage with a Hold call.

World’s cheapest energy name (2014e P/E of 2.9x) reflects poor ROI

Stock value is worth Gazprom’s future dividend stream

Dividend yield, currently 5%, will be among highest of peers (4%), once management approves the 25% IFRS dividend payout

However, vast number of expansion projects will absorb most FCF…

… and earnings growth will contribute little to valuation

Dividends define Gazprom valuation. Despite robust profitability, shareholders have hardly benefited from the company’s large cash outflows in the past, we estimate. With Gazprom’s vast pipeline of expansion projects absorbing over 80% of operating cash flow and generating low investment returns, we expect shareholders to place greater weight on the guaranteed investment returns (dividends), which, under the government’s 25% IFRS payout proposal, would generate one of the highest yields among Russian energy companies.

New dividend policy = greater share price stability. In the last two years, the market has been warming up to the idea of higher profit distribution, and is currently pricing in a 20% long-term payout. The correlation of share price with consensus earnings estimates has reached 70% and may rise even higher once Gazprom approves in 2015 the State-proposed 25% dividend payout. We expect this to translate into lower share price volatility, with the stock aiming at the upper-end of the DDM-implied valuation range defined by RAS and IFRS dividend policies. We estimate the range at $6-8.50/GDR.

Future ROI… We do not expect Gazprom shareholders to enjoy robust returns on the major growth projects. While South Stream, the Eastern Gas Program and the potential gas deal with Ukraine all seem reasonable and necessary to adapt to changes in the domestic and global energy markets, we estimate their present value to be negative, nevertheless.

… and earnings deliver meager DDM-implied impact on FV, a modest 8% upside. In light of the rising importance of dividends, we expect investors to increasingly focus on risks to earnings. The ongoing positive momentum in Europe is a strong driver. Our analysis of the regional demand/supply balance demonstrates that Gazprom could grow export volumes to over 170bcm over the next three years. However, in value terms, this is equivalent to DDM-implied fair value of $0.30/GDR, just 5% upside to target price.

$mn 2012 2013e 2014e 2015e

Revenue, $mn 153,761 149,970 149,655 149,932

EBITDA, $mn 52,358 52,028 49,564 48,637

EPS, $ 3.33 2.67 2.55 2.39

DPS, $ 0.40 0.39 0.62 0.58

P/E, x 2.4 2.9 3.1 3.3

EV/EBITDA, x 2.6 2.6 2.7 2.8

EV/DACF, x 3.0 3.0 3.0 3.0

Dividend yield, % 5.2 5.1 8.1 7.6


1171

1281

1391

1501

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6.16

7.11

8.07

9.02

9.98


OGZD LI , USD RTS (rhs)


40

Gazprom is a dividend play, as shareholders benefit more from the current dividend stream than from future expansion projects. Gazprom’s earnings define share price more than capital-intensive mega projects – returns on most of its major projects in the last five years have not fully benefited shareholders and, thus, have, in part, explained the earnings multiples deterioration from 2008 P/E of c10x to c3x this year. However, we estimate that earnings risks are not sufficient to lift valuations significantly above the currently DDM-implied value.

Muted drivers, even despite robust export sales this year:

Gazprom’s status as a supplier of choice in Europe helped raise market share from last year’s 25% to over 30% in 1H13…

… as Europe’s indigenous production is falling and LNG suppliers are redirecting gas to more lucrative Asian-Pacific markets.

Still, DDM-implied impact of higher export sales on fair value is $0.30/GDR, a modest 5%.

Dividend investment case – a function of earnings, which are uncertain. Gazprom’s dividend is a fixed percentage of the company’s earnings, presently capped at 25% RAS profit, but under the government request potentially rising to 25% IFRS from 2015. This is a major uplift for the dividend, given the profit under IFRS accounting standards is nearly twice that under RAS ($38bn vs $18bn, based on 2012 accounts).

The reason dividends matter so much is simple: minorities hardly benefit from the company’s cash flows, most of which, as we will demonstrate later, are spent on large capital-intensive projects with modest returns, while dividends generate a guaranteed cash flow stream fully covered by FCF. The share price dynamics in the last two years clearly demonstrate that the stock has been bouncing between RAS and IFRS DDM-implied fair value estimates.

The share price has been bouncing between RAS and IFRS DDM-implied fair value estimates

Consensus is gradually pricing in the anticipated change in the dividend policy

Source: FactSet, BCS

Risks to Gazprom’s earnings are balanced – S-T downside risks low. On the one hand, additional discounts to European customers, MET hike and slower domestic gas tariff growth could claim a part of earnings. On the other hand, higher volume shipments to Europe, a trend observed this year, could serve as a source of additional upside.

One cannot rule out completely the negative risks outlined above, but the chances of them materializing in the short term are low, we think. Therefore, instead, we suggest evaluating the upside from the ongoing rise in exports.

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Long-term dividend payout


41

Latest developments give confidence in higher export revenue this year, but… Since the start of 2013, we have observed the following trends:

Europe’s storage levels have fallen below five-year average levels contributing to the gas demand increase;

Gazprom has satisfied most of the additional demand raising its market share to above 30% (from 25% last year); exports are up 8% y/y;

European LNG imports have almost halved YTD y/y as suppliers re-direct gas to lucrative Asian-Pacific markets (prices in Asia exceed $500/mcm vs European spot of $380/mcm);

Pipeline gas supply from Norway and Northern Africa is down 4% and 14% y/y, respectively. Norway has extended the maintenance period for its major fields, while political unrest in Algeria and Libya continues to weigh on the regions’ gas export shipments.

As a result, Gazprom has become the supplier of choice. Narrow spread between Gazprom’s oil-linked prices and spot is also helping (-$10/mcm vs $60/mcm, on average, during 2010-12). The company’s management has raised the FY2013 export volume guidance from 152bcm to 160bcm.

More importantly, Gazprom has a high chance to sustain and even increase further its market share in Europe over the next several years, we believe:

European indigenous gas production will continue to fall;

Premium pricing and rising demand will continue to attract LNG producers to Asian-Pacific basin;

Gazprom’s discount-adjusted oil-linked prices are close to spot, thus limiting risks from price reductions.

Gazprom’s exports up 8% ytd, close to 5-year highs Europe gas inventory utilization still below 5-year lows since April

Gazprom’s oil-linked gas export prices are below current spot levels

Despite lower gas prices, Gazprom is set to achieve higher revenue from export gas sales this year

Source: Bloomberg, Company data, BCS

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… DDM-implied impact on fair value is $0.30/GDR, a modest 5%. Assuming stable gas consumption in Europe, we estimate that Gazprom’s export volumes could rise to as high as 170bcm pa, i.e., 10% upside to consensus anticipated level this year. This is equivalent to $5bn of additional revenues and $1.5bn of additional profits. Under the 25% IFRS profit payout, additional profits from higher export volumes could translate into $0.03/GDR of extra dividend. The DDM-implied impact on fair value is $0.30/GDR, or 5%. While still a source of upside, the final impact on valuation is modest.

Impact of export revenue changes on Gazprom’s fair value Export price ($/mcm) 300 310 320 330 340 350 360 370 380 390 400

Expo

rts

(bcm

) 130 -18% -16% -14% -12% -10% -8% -6% -4% -2% 0% 2% 140 -15% -13% -11% -9% -7% -5% -2% 0% 2% 4% 6% 150 -13% -11% -8% -6% -4% -2% 1% 3% 5% 8% 10% 155 -12% -9% -7% -5% -2% 0% 2% 5% 7% 9% 12% 160 -11% -8% -6% -3% -1% 2% 4% 6% 9% 11% 14% 170 -8% -6% -3% -1% 2% 5% 7% 10% 12% 15% 18%

Source: BCS

Major investment projects cap shareholder returns

Projects, such as Eastern Gas Program and South Stream, and deals with China and Ukraine are all essential for Gazprom to maintain its gas export leader status, but high construction costs may put pressure on investment returns, thus capping rewards to shareholders.

Valuation at 10-year low on poor investment returns… Gazprom’s valuation is currently at the ten-year low (except for the 2008-09 troughs) even though the group’s profit is much higher than it used to be. A simple example will explain the phenomenon: during 2006-12, Gazprom generated $41bn of FCF, distributed $22bn as dividends and increased net debt by $10bn. This implies $29bn of foregone cash flows. We estimate that the company’s investments did not fully benefit shareholders:

Beltransgaz consolidation was $13bn NPV-negative, we estimate. Gazprom paid $5bn for acquisition of 100% of shares. In addition, the Russian gas company reduced the gas price to Belarus to the domestic level, thus implying a discount of c$100/mcm on 21-23bcm volumes.

Bovanenkovo field development on its own appears value-accretive; however, in combination with the $30bn Bovanenkovo-Ukhta pipeline, the project’s estimated present value at the start was -$12bn, on our numbers.

Shtokman, though put on hold, absorbed $1.5bn of investments from partners.

During 2006-12, Gazprom generated $41bn of FCF, increased net debt by $10bn, but paid only $22bn as dividends

We estimate Gazprom’s dividend stream to arrive at fair valuation


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FCF Dividends Net debt change

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… nor do we expect future investments to add significant value. We do not expect Gazprom to generate sufficient returns on future mega-projects. On our estimates, investment returns of South Stream, the Eastern Gas Program and the potential gas deal with Ukraine are negative, or zero at best.

We do not expect Gazprom’s future mega-projects to add significant value Project NPV ($bn) Negatives Rationale / potential benefits

Gas deal with Ukraine (-33;-16) Substantial gas price discount (up to $200/mcm) Acquisition of the ownership stake (33% in case of

the three-side agreement with Europe or 50%) in Ukrainian GTS, valued at $20bn

Transit state risk reduction Savings on gas transit fee via an ownership stake Increase in export volumes to Ukraine South Stream downscaling

South Stream (-10;-7) The project itself could well generate positive returns (as Nord Stream does – 10% IRR), but the pipeline on the territory of Russia spoils the overall picture

Independence from gas transit states (i.e. Ukraine)

Eastern Gas Program (-7;-5) Remote location from production fields requires construction of costly pipelines

Tap “hot” Asian markets Flexibility in gas export destinations Restore foregone positions on the global gas

market


Eastern Gas Program – expensive savior. Gazprom’s Eastern Gas Program is a big unknown. East Siberia and Far East hold over 50tcm of gas resources, enough to maintain Gazprom’s current production levels for at least 100 years. The development requires enormous investments in field development and infrastructure. The Program could be aimed at tapping growing Asian-Pacific markets via pipeline gas deliveries and/or LNG, allowing even more shipment flexibility.

Among Gazprom’s priorities are development of the giant Chayanda and Kovykta fields, and subsequent gas deliveries to China and/or to the future LNG plant in Vladivostok. Management has recently named the Kirinskoye field potential replacement for Shtokman pointing to enormous gas resources and close proximity to Asian-Pacific markets.

Gazprom’s Eastern Gas Pipeline is aimed at tapping new export markets

Source: Company data


44

Eastern Gas Program is essential for Gazprom to maintain gas export leader status… Pending negotiations with China and LNG ambitions are essential for Gazprom to compensate for falling domestic market share as independents are signing up Gazprom’s customers, stagnating demand in Europe (even despite the recent surge in export volumes) and constant price reduction requests, and tap new markets.

Both pipeline gas exports to China and LNG deliveries are attractive alternatives not only to domestic gas deliveries, but even to shipments to Europe. Current prices in Eastern Asia are in excess of $16/mmbtu, which, if agreed on, would guarantee Gazprom $7/mmbtu and $10/mmbtu of EBITDA for pipeline gas and LNG, respectively. Russian government at the moment does not impose taxes on LNG exports. However, even under the conservative scenario of a 30% export duty, the netback prices remain well in excess of $6/mmbtu.

… but will come at a high price. Wood Mackenzie estimates Chayanda’s, Kovykta’s and Kirinsky’s field development costs at $10-12/mmbtu, sufficient to generate positive cash flows. However, the fields are located thousand miles away from delivery destinations (seaports, country borders), thus requiring construction of costly pipelines and related infrastructure.

Wood Mackenzie estimates that a 3,200km pipeline to connect Chayanda with Vladivostok will cost over $11bn, assuming 15bcm pa throughput capacity. Integrating the pipeline with Kovykta and quadrupling the throughput capacity will elevate the construction cost to almost $30bn. Kirinsky block off Sakhalin appears a significantly cheaper alternative ($8bn for the Sakhalin-Khabarovsk-Vladivostok pipeline expansion), and a comparably prospective one – preliminary resource estimate of 564bcm (C1+C2 category). However, we do not expect Gazprom to abandon the development of East Siberian fields.

LNG plant construction CapEx will depend on the number of production trains. We believe Gazprom’s budget could fit into global averages of $5,000-6,000 per ton of capacity, which works out to $15-18bn for a 15mtpa plant. As the company pre-announced, the plant may be developed with partner(s), and project financing may be raised.

We expect Gazprom to pursue both pipeline gas exports and LNG. The gas pipeline from Chayanda/Kovykta to Vladivostok will lie close to the Russia-China border and will require minimal investments to build a connection pipeline to China. At the same time, the combined gas production of Chayanda and Kovykta could be 60bcm or more. The Western route to China (Altai) does not seem to be on the agenda anymore, hence, gas shipments require alternative delivery options, i.e., LNG.

Gazprom says the Vladivostok plant will operate at least three production trains (5mtpa each). Kirinsky and adjacent blocks could supply 15-20bcm pa of gas, we estimate, and, therefore, fully cover minimal gas needs of the future LNG plant. We think Gazprom will consider expanding the plant, taking into account prospective future gas demand/supply balance in Asia and high cost of competitors’ LNG (e.g. Australian projects, which will deliver over 50mtpa of new LNG capacity, are break-even at $15/mmbtu or higher). Chayanda and Kovykta together supply the additional volumes (joint production at peak is estimated at over 60bcm pa).

Challenged investment returns: Wood Mackenzie estimates Eastern Gas Program’s fields to break even at $10-12/mmbtu, which would generate a profit at current gas prices in Asia ($16.5/mmbtu). However, adding the pipeline construction costs on top of that reduces investment returns. We estimate Kirinsky block’s total costs at $13.6/mmbtu. Chayanda’s and Kovykta’s costs, on the other hand, could be as high as $15/mmbtu, assuming 30bcm pa production feeding the pipeline to China and 30bcm pa supplying the LNG plant in Vladivostok.


45




Gas ($/mcm) Share Price ($) 7.85

Domestic 76 90 93 99 105 109 Market Cap ($mn) 90,069

Europe 302 383 385 374 347 338 EV ($mn) 135,165

FSU 232 290 305 310 292 289

Crude oil ($/bbl) Income Statement ($mn) 2010 2011 2012 2013e 2014e 2015e

Brent 80 111 112 104 99 95 Revenue 118,912 157,494 153,761 149,970 149,655 149,932

Urals 77 109 110 102 97 94 Transportation -9,021 -9,539 -10,318 -11,795 -12,379 -13,089

Domestic (Samara) 36 49 50 47 46 44 Taxes other than income tax -9,617 -14,244 -18,672 -19,441 -22,440 -22,293

Other operating costs -55,226 -68,137 -72,413 -66,706 -65,271 -65,914

Macro assumptions 2010 2011 2012 2013e 2014e 2015e EBITDA 45,047 65,574 52,358 52,028 49,564 48,637

USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 Depreciation 8,243 9,365 10,767 13,350 14,756 16,092

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% Operating income 36,804 56,209 41,591 38,678 34,809 32,545

Finance expenses -595 -441 -348 -309 -346 -412

Production 2010 2011 2012 2013e 2014e 2015e Other expense/income 5,960 1,203 7,572 796 2,943 2,966

Natural gas (bcm) 509 510 481 485 492 503 Pre-tax income 42,168 56,971 48,815 39,165 37,406 35,099

Liquids (mmboe) 43 46 48 48 50 50 Income taxes -8,222 -9,473 -8,933 -7,833 -7,481 -7,020

Minority interest/other -1,878 -3,142 -1,702 -728 -696 -653

Gas deliveries 2010 2011 2012 2013e 2014e 2015e Net income 32,068 44,356 38,180 30,603 29,229 27,426

Domestic (bcm) 277 281 265 244 242 244 Fully diluted EPS ($) 2.79 3.87 3.33 2.67 2.55 2.39

FSU (bcm) 70 82 66 63 64 65

Non-FSU (bcm) 148 157 151 156 160 163 Balance sheet ($mn) 2010 2011 2012 2013e 2014e 2015e

Cash 14,347 15,572 13,734 13,734 13,734 13,734

Domestic market share 67% 70% 67% 63% 62% 62% Inventories 10,602 12,658 15,043 13,346 13,788 13,928

European market share 23% 27% 25% 27% 28% 29% Accounts receivable 24,669 24,352 30,775 28,238 29,159 29,118



1P 2P 1P+2P Fixed assets 178,578 208,677 255,938 284,560 311,776 337,657

Gas (bcm) 19,100 4,300 23,400 Other non-current assets 61,312 60,313 60,266 60,266 60,266 60,266

Liquids (mmbbl) 10,599 5,310 15,909 Total non-current assets 239,889 268,989 316,204 344,826 372,042 397,923

Oil and Gas (bn boe) 135.5 33.4 168.9 Total assets 300,623 338,572 395,055 419,443 448,023 474,002

EV/Reserves ($/boe) 1.0 0.8 Short-term debt 6,212 11,395 10,698 12,771 14,897 19,752

Reserve life (years) 44 54 Accounts payable 26,697 29,270 38,072 33,777 34,896 35,249

Other current liabilities 7 - - - - -




PEG (x) 9.6 5.3 NM NM NM NM Total non-current liabilities 54,955 56,853 61,452 61,452 61,452 61,452

P/B (x) 0.5 0.4 0.4 0.3 0.3 0.3 Minority interest 9,329 9,238 10,127 10,855 11,551 12,204



Dividend yield (%) 3.2% 8.0% 5.2% 5.1% 8.1% 7.6%

FCF Yield (%) 13.2% 0.9% 1.3% 2.5% 0.4% 0.5% Cash flow statement ($mn) 2010 2011 2012 2013e 2014e 2015e

Profitability Net income 32,068 44,356 38,180 30,603 29,229 27,426

EBITDA Margin (%) 38% 42% 34% 35% 33% 32% Depreciation 8,243 9,365 10,767 13,350 14,756 16,092

EBIT Margin (%) 31% 36% 27% 26% 23% 22% Changes in working capital 8,356 -1,099 1,054 -61 -244 254

Net Margin (%) 27% 28% 25% 20% 20% 18% Other -375 2,634 -3,411 728 696 653

Leverage Operating cash flow 48,293 55,256 46,590 44,621 44,437 44,425

Gross Debt/Equity (x) 0.2 0.2 0.2 0.2 0.2 0.2 Capex -36,393 -54,404 -45,418 -41,972 -41,972 -41,972

Net Debt/Equity (x) 0.1 0.1 0.1 0.1 0.1 0.1 Other 1,784 208 4,473 - - -


Net Debt/EBITDA (x) 0.6 0.5 0.7 0.7 0.8 0.9 Change in debt -7,013 10,435 -1,935 2,073 2,126 4,855

Net Interest Cover (x) 61.8 127.5 119.7 125.1 100.6 79.0 Dividends -1,808 -3,211 -6,158 -4,722 -4,591 -7,307

Returns Other 1,844 -6,382 49 - - -

ROE (%) 17% 20% 15% 11% 9% 8% Financing cash flow -6,977 841 -8,044 -2,649 -2,465 -2,453

ROACE (%) 13% 19% 12% 10% 8% 7% Effect of Forex -619 -677 561 - - -

ROA (%) 11% 14% 10% 8% 7% 6% Increase (decrease) in cash flow 6,088 1,224 -1,838 0 (0) 0


46

Share data & recommendation Ticker GAZ LI

Last price, $ 18.05


Upside, % 39%

Recommendation BUY


Free float, % 4%

Free float, $ mn 681

EV, $ mn 23,100


1M chg., % 1.1%

3M chg., % -11.5%

YTD chg., % -22.5%

Company snapshot Fourth largest oil producer in Russia (1mmbbl/d) and an oil arm of Gazprom. Operates along the whole production chain, fully covering the requirements of its large refining complex (0.9mmbbl/d) and extensive filling station network (>1,600).

Growth outlook Gazprom neft has one of the largest greenfield project portfolios targeting to double hydrocarbon production in the long-term. The company plans to grow organically, executing on its greenfields once additional tax breaks are granted, and via transfer of oil licenses from Gazprom.

Valuation Gazprom neft is among the cheapest oil companies, trading on 3.6x P/E ’14 (31% implied discount to peers). The stock has de-rated from 4.8x P/E last year. We consider Gazprom neft undervalued, especially taking into account large greenfield exposure, robust growth potential and the highest dividend yield (8%).

Gazprom neft Robust growth, highest shareholder returns Among the cheapest oil companies, Gazprom neft is a clear EPS growth and dividend leader; we initiate coverage with a Buy call.

Highest shareholder returns over the next two years (6% pa EPS growth and 8% dividend yield)

Robust FCF generation in the long-term (c$16bn during 2017-21, equivalent to current market cap)

Valuation implies a 31% discount to peers vs 12% during 2010-12

Large portfolio of greenfield projects (1.1mmboe/d hydrocarbon production) is not in the price, while additional tax breaks imply further potential upside

Catalysts include additional greenfield tax breaks, transfer of oil licenses from Gazprom and potential liquidity improvement, however, outcomes are twofold and timing is uncertain

One of the highest shareholder returns… Gazprom neft has the highest dividend yield among peers (9%) and one of the highest earnings growth rates over the next two years (6% pa). Planned introduction of the interim dividend practice underscores management’s commitment to deliver robust shareholder returns. Moreover, completion of refinery upgrade and launch of a series of greenfields in the second half of the decade may generate over $16bn of FCF (equivalent to the current market cap) translating into impressive long-term returns.

… backed by attractive valuation. Gazprom neft is among the cheapest energy names in Russia (3.6x P/E ‘14). The stock has de-rated significantly versus peers in the last three months despite the absence of company-specific negatives. For reference, Gazprom neft’s closest peer, Rosneft, is equally backed by the government, has a similar production growth profile, offers a lower dividend yield and its risks to FCF are skewed to the downside, and yet is trading at twice the multiple.

Greenfield optionality is not in the price… Gazprom neft has large greenfield exposure. Novoport, Orenburg, Messoyakha, Severenergia and Kuyumba together may contribute over 1.1mmboe/d of hydrocarbons at peak (equivalent to the company’s total current production). We include the projects in our base case, but do not include the additional tax breaks, which Gazprom neft is lobbying for (tax breaks imply an additional $3/GDR upside to our TP). International projects (Badrah and Junin-6) are also a potential source of further upside.

… but lack of immediate catalysts may hold back the immediate stock re-rating. The stock lacks immediate triggers. The timing and impact from additional tax breaks for greenfields, oil license transfers from Gazprom, potential liquidity improvement event are uncertain and the outcomes are twofold.

$mn 2012 2013e 2014e 2015e

Revenue, $mn 48,818 44,748 44,586 44,195

EBITDA, $mn 8,230 8,585 9,578 8,220

EPS, $ 5.96 5.52 6.45 5.28

DPS, $ 1.50 1.39 1.62 1.33

P/E, x 3.0 3.3 2.8 3.4

EV/EBITDA, x 2.8 2.7 2.4 2.8

EV/DACF, x 2.9 3.1 2.7 2.7

Dividend yield, % 8.3% 7.7% 9.0% 7.4%

FCF yield, % 10.3% 10.0% 8.8% 9.9% Source: Company data, BCS

1171

1281

1391

1501

1611

16.1

18.1

20.1

22.1

24.1


GAZ LI , USD RTS (rhs)


47






Urals 77 109 110 102 97 94 EV ($mn) 23,100




Diesel 12 17 19 17 18 17 Opex -2,111 -2,464 -3,974 -4,635 -4,922 -5,133





$/mcf 2.3 2.8 2.8 3.1 3.2 3.4 EBITDA 6,277 8,942 8,230 8,585 9,578 8,220

Depreciation 1,619 1,963 1,883 2,249 2,282 2,280


USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 Finance expenses -288 -263 -257 -234 -262 -277

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% Other expense/income -93 115 942 549 764 722

Pre-tax income 4,277 6,831 7,031 6,651 7,798 6,384

Production 2010 2011 2012 2013e 2014e 2015e Income taxes -844 -1,244 -1,155 -1,311 -1,561 -1,278

Crude oil Minority interest/other -285 -235 -253 -128 -150 -123



Refined products


daily output (kbd) 754 824 884 859 876 875 Cash 1,146 914 2,488 2,282 2,402 2,397






Total (bn boe) 8.3 5.9 14.2 5.3 19.5 Other non-current assets 9,057 8,299 8,744 7,229 8,012 8,753

EV/Reserves ($/bbl) 2.8 1.6 1.2 Total non-current assets 24,971 27,612 30,657 36,021 41,076 44,874

Reserve life (years) 19 32 44 Total assets 32,064 36,683 42,560 46,937 51,864 55,623

Short-term debt 1,694 1,277 2,167 2,359 2,546 2,775

Financial ratios 2010 2011 2012 2013e 2014e 2015e Accounts payable 2,730 3,075 2,942 3,610 3,423 3,386

Valuation Other current liabilities 427 65 1,249 944 944 944

P/E (x) 5.4 3.2 3.0 3.3 2.8 3.4 Total current liabilities 4,851 4,417 6,358 6,913 6,914 7,105

PEG (x) 120.8 4.5 59.7 NM 16.6 NM Long-term debt 4,942 5,420 5,448 5,361 5,361 5,361

P/B (x) 1.0 0.8 0.7 0.6 0.5 0.5 Other non-current liabilities 3,584 3,334 3,423 4,203 4,353 4,476

EV/EBITDA (x) 3.7 2.6 2.8 2.7 2.4 2.8 Total non-current liabilities 8,526 8,754 8,871 9,565 9,714 9,837

EV/DACF (x) 4.2 2.7 2.9 3.1 2.7 2.7 Total shareholders' equity 18,687 23,512 27,330 30,459 35,236 38,686

Dividend yield (%) 4.1% 6.9% 8.3% 7.7% 9.0% 7.4% Total liabilities and equity 32,064 36,683 42,560 46,937 51,864 55,628

FCF Yield (%) 14.0% 7.7% 10.3% 10.0% 8.8% 9.9%

Profitability Cash flow statement ($mn) 2010 2011 2012 2013e 2014e 2015e

EBITDA Margin (%) 19% 20% 17% 19% 21% 19% Net income 3,433 5,587 5,877 5,339 6,238 5,107

EBIT Margin (%) 14% 16% 13% 14% 16% 13% Depreciation 1,619 1,963 1,883 2,249 2,282 2,280

Net Margin (%) 10% 12% 12% 12% 14% 11% Changes in working capital 247 -2,359 -296 740 61 -4

Leverage Other 93 810 -76 -523 -124 880

Gross Debt/Equity (x) 0.4 0.3 0.3 0.3 0.2 0.2 Operating cash flow 5,392 6,001 7,388 7,805 8,456 8,263

Net Debt/Equity (x) 0.3 0.2 0.2 0.2 0.1 0.1 Capex -3,292 -4,029 -5,019 -6,349 -7,332 -6,959

Gross Debt/EBITDA (x) 1.1 0.7 0.9 0.9 0.8 1.0 Acquisitions -1,536 -1,156 -146 -21 0 0

Net Debt/EBITDA (x) 0.9 0.6 0.6 0.6 0.5 0.6 Other -24 -289 -203 23 0 0

Net Interest Cover (x) 16.2 26.5 24.7 27.1 27.9 21.4 Investing cash flow -4,852 -5,474 -5,368 -6,347 -7,332 -6,959

Returns Change in debt 419 273 819 -211 187 229

ROE (%) 18% 25% 22% 18% 19% 13% Dividends -728 -1,025 0 -1,421 -1,316 -1,538

ROACE (%) 16% 21% 17% 15% 15% 11% Other 0 0 -1,206 58 0 0

ROA (%) 10% 16% 14% 12% 12% 9% Financing cash flow -309 -752 -387 -1,573 -1,129 -1,309

Effect of Forex 47 -7 -60 29 0 0

Increase (decrease) in cash flow 278 -232 1,574 -86 -5 -5


48

Share data & recommendation Ticker BANE RX

Last price, Rb 1 990

Target price, Rb 2 100

Upside, % 6%

Recommendation HOLD


Free float, % 27%


EV, $ mn 15,175

Equity performance 1W chg., % 1.5%

1M chg., % 8.6%

3M chg., % 0.7%

YTD chg., % 13.2%

Company snapshot Mid-tier oil producer (308kbd) operating in the Volga-Urals and Timan-Pechora regions of Russia. The company operates one of the most advanced refining complexes with total capacity of 480kbd. Such high share of refining makes Bashneft extremely vulnerable to on-going changes in the oil tax legislation (easing taxation on upstream at the expense of refining).

Growth outlook Bashneft plans to maintain stable crude production at its legacy fields over the next five years and expects to launch its first greenfield, Trebs and Titov, already the coming fall. Same as other oil companies, Bashneft is working on the refinery upgrade and plans to expand its filling station network.

Valuation Bashneft is the most expensive oil stock in Russia trading on 7.1x P/E ’14 (43% premium to peers), in line with pre-crisis levels. We consider such valuation justified, but see risks to the premium as the market re-rates other oil companies with attractive returns profiles.

Bashneft Valuation premium justified, but high for entry point

Robust FCF and solid shareholder returns justify a premium, in our opinion, but the current valuation looks too high for an entry point. We initiate coverage with a Hold.

Robust FCF generation despite the refinery upgrade CapEx cycle: we estimate FCF yield to average 11% during 2013-16e (vs sector average of 5%)

The highest dividend yield during 2009-11 thanks to the company’s flexible dividend policy (distribute generated FCF)

Interim dividend introduction and the launch of Trebs & Titov greenfield in autumn are supportive for the stock in the short term…

… however, in the long term, we see a high risk of M&A (upstream) due to the company’s disadvantageous positioning for ongoing oil sector transformation

Valuation premium reflecting strong execution track record and solid shareholder returns is justified (7.1x P/E ’14 vs sector’s 5.1x), but not an attractive entry point

Dividends are integral to Bashneft’s investment case… Bashneft’s official dividend policy assumes distribution of at least 10% of net income. In fact, the company has been paying out most of its FCF, pleasing shareholders with the highest dividend yield during 2009-11. As a result, the share price has had a c80% correlation with consensus dividend expectations.

… and the potential interim dividend introduction in fall would only strengthen it. A fourfold cut in the 2012 DPS was unexpected and was taken negatively by the market. The board of directors plans to discuss in fall the introduction of the interim dividend. While there is no guidance on the size of future dividends, we believe risks are skewed to the upside given the company’s robust FCF expected in 2013 and in subsequent years (8% in 2013e, 12% during 2014-16e, on average).

However, in the long term, M&A risks remain… We forecast Bashneft to generate one of the highest FCF yields among peers in coming years. Management does not rule out the potential M&A, although it has not provided much detail. We believe the company would seek further upstream exposure given its disadvantageous positioning for the on-going oil sector transformation (tax burden shift from upstream onto downstream). While upstream projects might eventually prove value-accretive, shareholder returns in the short term could be capped because of development CapEx requirements. Thus, in the short term, investors would prefer dividends.

… and current valuation is too high for an attractive entry point. Bashneft stock is among the few that has gone back to pre-crisis valuation levels (7.1x P/E ‘14) and is currently trading at a 43% premium to peers. We consider see this valuation as justified, but think the premium could narrow as the market gives full credit to other oil companies’ attractive return profiles (e.g. that of Lukoil and Gazprom neft).

$mn 2012 2013e 2014e 2015e

Revenue, $mn 17,155 16,297 16,159 15,659

EBITDA, $mn 3,179 3,103 3,271 2,942

EPS, $ 7.77 7.89 8.60 7.74

DPS, $ 0.77 3.18 4.29 4.21

P/E, x 6.8 6.4 5.8 6.5

EV/EBITDA, x 4.4 4.5 4.3 4.7

EV/DACF, x 6.8 7.1 6.5 6.5

Dividend yield, % 1.3% 5.3% 7.1% 7.0%


1218

1306

1394

1482

1570

1 748

1 887

2 027

2 166


BANE RX , RUB MICEX (rhs)


49




Crude oil ($/bbl) Share Price (ords) ($/share) 60.42

Brent 80 111 112 104 99 95 Share Price (prefs) ($/share) 33.09

Urals 77 109 110 102 97 94 Market Cap ($mn) 11,402

Domestic (Samara) 36 49 50 47 46 44 EV ($mn) 15,196

Crack spreads ($/bbl)

Gasoline 16 17 23 22 23 22 Income Statement ($mn) 2010 2011 2012 2013e 2014e 2015e

Diesel 12 17 19 17 18 17 Revenue 13,341 16,549 17,155 16,297 16,159 15,659

Jet fuel 15 22 23 22 23 23 Opex -2,665 -1,684 -1,728 -1,585 -1,611 -1,653

Fuel oil -21 -30 -26 -28 -21 -20 Purchased oil -2,882 -3,994 -4,022 -3,536 -3,543 -3,418

Taxes other than income tax -1,421 -2,052 -2,149 -1,990 -1,795 -1,650

Macro assumptions 2010 2011 2012 2013e 2014e 2015e Excise and export duties -2,753 -4,231 -4,649 -4,723 -4,532 -4,568

USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 Other operating costs -1,116 -1,396 -1,427 -1,359 -1,407 -1,429

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% EBITDA 2,504 3,192 3,179 3,103 3,271 2,942

Depreciation 711 616 592 582 619 655

Production 2010 2011 2012 2013e 2014e 2015e Operating income 1,793 2,576 2,587 2,521 2,651 2,286

Crude oil Finance expenses -290 -434 -228 -237 -227 -205

annual output (mmt) 14.1 15.1 15.4 15.4 15.4 15.4 Other expense/income 34 62 -8 -30 26 123

daily output (kbd) 283 302 309 307 308 308 Pre-tax income 1,537 2,204 2,351 2,254 2,450 2,204

Refined products Income taxes -468 -513 -529 -455 -490 -441

annual output (mmt) 19.4 19.2 18.9 18.7 19.0 19.0 Minority interest/dividends -116 5 -144 -4 -5 -4

daily output (kbd) 389 384 378 373 380 380 Net income 953 1,696 1,678 1,794 1,955 1,759

light product yield 64% 64% 64% 65% 65% 67% Fully diluted EPS ($) 4.65 8.28 7.77 7.89 8.60 7.74

Reserves (PRMS) Balance sheet ($mn) 2010 2011 2012 2013e 2014e 2015e

1P 2P 1P+2P 3P 1P+2P+3P Cash 1,067 881 658 1,304 1,785 1,740

Oil (bn bbl) 2.0 0.5 2.5 0.7 3.2 Inventories 625 748 780 845 720 715

EV/Reserves ($/bbl) 7.6 6.0 4.8 Accounts receivable 1,208 1,395 1,666 1,714 1,560 1,521

Reserve life (years) 18 23 28 Other current assets 852 1,245 876 944 944 944

Total current assets 3,752 4,269 3,981 4,807 5,009 4,920

Financial ratios 2010 2011 2012 2013e 2014e 2015e Fixed assets 9,552 7,882 9,073 9,472 10,040 10,590

Valuation Other non-current assets 1,687 1,422 2,120 2,486 2,930 3,249

P/E (x) 12.0 6.7 6.8 6.4 5.8 6.5 Total non-current assets 11,239 9,304 11,192 11,958 12,970 13,839

PEG (x) 9.4 8.6 NM 92.3 64.8 NM Total assets 14,991 13,573 15,173 16,765 17,979 18,759

P/B (x) 2.2 2.1 1.7 1.3 1.1 1.0 Short-term debt 795 420 1,048 1,066 1,066 1,066

EV/EBITDA (x) 6.1 4.8 4.8 4.9 4.6 5.2 Accounts payable 1,071 1,242 1,308 1,229 1,206 1,198

EV/DACF (x) 7.0 5.5 6.8 7.1 6.5 6.5 Other current liabilities 650 632 487 280 280 280

Dividend yield (ords) (%) 12.9% 5.6% 1.3% 5.3% 7.1% 7.0% Total current liabilities 2,516 2,294 2,842 2,575 2,553 2,544

Dividend yield (prefs) (%) 23.5% 10.2% 2.5% 9.6% 13.0% 12.7% Long-term debt 3,118 2,965 2,560 2,961 2,961 2,961

FCF Yield (%) 12.6% 14.4% 12.4% 11.1% 12.0% 9.6% Other non-current liabilities 4,082 2,704 1,817 1,797 1,802 1,806

Profitability Total non-current liabilities 7,200 5,669 4,377 4,758 4,763 4,768

EBITDA Margin (%) 19% 19% 19% 19% 20% 19% Total shareholders' equity 5,275 5,610 7,954 9,432 10,663 11,447

EBIT Margin (%) 13% 16% 15% 15% 16% 15% Total liabilities and equity 14,991 13,573 15,173 16,765 17,979 18,759

Net Margin (%) 7% 10% 10% 11% 12% 11%

Leverage Cash flow statement ($mn) 2010 2011 2012 2013e 2014e 2015e

Gross Debt/Equity (x) 0.7 0.6 0.5 0.4 0.4 0.4 Net income 953 1,696 1,678 1,794 1,955 1,759

Net Debt/Equity (x) 0.4 0.3 0.3 0.2 0.1 0.1 Depreciation 711 655 592 582 619 655

Gross Debt/EBITDA (x) 1.6 1.1 1.1 1.3 1.2 1.4 Changes in working capital -531 -264 -101 -417 257 35

Net Debt/EBITDA (x) 0.9 0.4 0.7 0.7 0.5 0.5 Other 267 141 135 65 -19 -117

Returns Operating cash flow 1,400 2,228 2,304 2,024 2,813 2,333

ROE (%) 18% 31% 25% 21% 19% 16% Capex -492 -851 -992 -1,173 -1,187 -1,205

ROACE (%) 19% 27% 23% 18% 18% 14% Acquisitions -939 - -282 -104 - -

ROA (%) 7% 12% 12% 11% 11% 10% Other -564 -157 12 44 - -

Investing cash flow -1,995 -1,008 -1,262 -1,232 -1,187 -1,205

Change in debt 2,145 -401 52 487 - -

Dividends -1,314 -950 -591 -174 -724 -975

Other -343 -32 -731 -465 -420 -197

Financing cash flow 488 -1,383 -1,270 -153 -1,144 -1,173

Effect of Forex 8 -23 5 6 - -

Increase (decrease) in cash flow -99 -186 -223 646 482 -46


50

Share data & recommendation Ticker AOIL SS

Last price, SEK 44

Target price, SEK 41

Upside, % -6%

Recommendation SELL


Free float, % 52%

Free float, $ mn 596

EV, $ mn 3,204


1M chg., % 19.1%

3M chg., % -15.2%

YTD chg., % -17.5%

Company snapshot Small-cap vertically integrated oil & gas producer operating in Russia and Kazakhstan. Hydrocarbon reserves are 733mmboe, implying a 35-year reserve life. The company is among the first to complete the refinery complex upgrade and thus enjoy above-average refining margins.

Growth outlook Management is targeting a double-digit production growth. Long-term growth is to come from the launch of Timan-Pechora oil fields and numerous gas projects. The company also considers potential M&A. The refinery upgrade completion is scheduled for 3Q13, after which the company will start rapidly deleveraging

Valuation At 3.4x EV/EBITDA ’14 Alliance Oil is 14% cheaper than other Russian oils. The valuation discount reflects the market’s concerns about management’s execution (sharp production decline at Kolvinskoye is still fresh in everyone’s minds), we believe. Timely launch of the upgraded refinery in 3Q13 could partially address the valuation issue.

Alliance Oil Near-term risks skewed to the downside

The stock has traded ahead of itself on the unconfirmed takeover by Rosneft. While this may continue to support the stock in the short term, the fundamental value is below the current level, we estimate. We initiate coverage with a Sell call.

Risk of consensus earnings downgrade – consensus too bullish…

… BCS 2013-15e EPS forecast is 17% below consensus; BCS 2012-15e EPS CAGR estimate of 2% compares to consensus’ 9%

Potential for delay in commercial start until 1H14 is high, equivalent to c$150mn of foregone EBITDA

Robust FCF once upgraded refinery is operational and connection to ESPO could fully deleverage the balance sheet by 2018…

… but search for further production growth will require significant investment, thus putting pressure on near-term shareholder returns

Current valuation (3.4x EV/EBITDA ‘14e) appears attractive, but we estimate 20% downside risk from the potential refinery launch delay and CapEx over-run

Risk of consensus earnings downgrade… Our financial estimates and growth assumptions are below those of consensus. We forecast EPS to average $2.04/share during 2013-15, 17% below consensus, while our EPS CAGR 2012-15e of 2% compares to consensus’ 9%. The difference likely stems from our more conservative production assumptions (e.g., we assume no production growth at Kolvinskoye and gas output of 15kboed by 2015), while we also note a c$160mn negative impact on EBITDA ‘15e from Kolvinskoye tax break expiration and the scheduled fuel oil export duty increase.

… and upgraded refinery launch delay exist. The upgraded refinery (expected 3Q13) and connection to ESPO (2014-15) could potentially double Alliance Oil’s refining margins, translating into additional EBITDA of c$300mn pa. The company targets completion in 3Q13; however, taking into account 2-4 months of test runs, commercial start is unlikely earlier than 1H14, we think. Consensus reflects the refinery in its numbers from 4Q13.

CapEx cycle is not over. We forecast positive FCF next year, for the first time since 2009. On our estimates, Alliance Oil could fully deleverage by 2018. However, with production approaching plateau, we believe the company will seek new sources of growth. This will require investments, whether for development of acquired fields, or acquisition of new ones, thus putting pressure on FCF and delaying deleveraging.

Room for further downside. At 3.4x EV/EBITDA ’14 Alliance Oil is 14% cheaper than other Russian oils; however, our bear-case analysis points to further potential downside. Unlike the consensus, we factor in a three-month delay for the refinery upgrade, and do not rule out the possibility of a further delay until 2Q14 (SEK 4/sh). As Alliance Oil proceeds with new field development and potentially engages in M&A, potential CapEx over-run risk increases (SEK 8/sh). These considerations add up to a potential downside risk to SEK 30/sh.

$mn 2012 2013e 2014e 2015e

Revenue, $mn 3,445 3,424 3,797 3,615

EBITDA, $mn 787 588 998 922

EPS, $ 2.35 0.85 2.77 2.50

P/E, x 2.8 7.8 2.4 2.7

EV/EBITDA, x 4.1 5.5 3.2 3.5

EV/DACF, x 3.6 6.2 3.8 4.1

Dividend yield, % NA NA NA NA

FCF yield, % NM NM 35.8 42.3 Source: Company data, BCS

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AOIL SS , USD RTS (rhs)


51




Crude oil ($/bbl) Share Price (SEK/share) 43.75


Urals 77 109 110 102 97 94 EV ($mn) 3,203




Diesel 12 17 19 17 18 17 Opex -135 -193 -197 -264 -281 -304

Jet fuel 15 22 23 22 23 23 Purchased oil -656 -929 -1,141 -1,057 -1,141 -1,037

Fuel oil -21 -30 -26 -28 -21 -20 Taxes other than income tax -251 -360 -385 -375 -325 -302

Gas, domestic Other operating costs -714 -913 -935 -1,141 -1,052 -1,050

$/mcm 82 98 99 109 114 119 EBITDA 440 687 787 588 998 922

$/mcf 2.3 2.8 2.8 3.1 3.2 3.4 Depreciation 132 174 192 241 256 262

Operating income 307 513 595 346 743 660

Macro assumptions 2010 2011 2012 2013e 2014e 2015e Finance expenses -22 -47 -80 -112 -122 -103

USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 Other expense/income 4 -34 29 -15 0 0

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% Pre-tax income 290 433 544 219 620 557

Income taxes -63 -104 -124 -51 -124 -111

Production 2010 2011 2012 2013e 2014e 2015e Minority interest/dividends -4 - -18 -22 -21 -17

Crude oil Net income 222 328 403 146 475 428

annual output (mn tonnes) 2.2 2.4 2.7 2.7 2.7 2.9 Fully diluted EPS ($) 1.30 1.91 2.35 0.85 2.77 2.50

daily output (kbd) 44 49 54 54 54 58

Gas Balance sheet ($mn) 2010 2011 2012 2013e 2014e 2015e

annual output (mmcm) 611 837 837 Cash 178 188 412 676 676 676

daily output (kboed) 11 15 15 Inventories 141 145 228 249 229 219

Refined products Accounts receivable 215 240 278 340 353 338

annual output (mn tonnes) 3.1 3.5 3.7 4.1 4.5 4.5 Other current assets 195 330 360 305 305 305

daily output (kbd) 62 70 75 83 91 91 Total current assets 730 902 1,277 1,570 1,564 1,539

light product yield 60% 58% 53% 52% 63% 63% Fixed assets 2,528 3,224 4,475 4,899 5,056 5,106

Other non-current assets 89 99 240 239 239 239

Reserves (PRMS) Total non-current assets 2,618 3,323 4,715 5,137 5,294 5,345

1P 2P 1P+2P 3P 1P+2P+3P Total assets 3,347 4,225 5,992 6,708 6,858 6,884

Oil (bn bbl) 0.3 0.4 0.7 0.5 1.2 Short-term debt 127 107 402 780 468 66

EV/Reserves ($/bbl) 9.7 4.4 2.7 Accounts payable 309 393 509 438 403 385

Reserve life (years) 14 31 51 Other current liabilities - - 6 6 6 6

Total current liabilities 436 500 917 1,223 878 458

Financial ratios 2010 2011 2012 2013e 2014e 2015e Long-term debt 912 1,514 1,669 1,995 1,995 1,995

Valuation Other non-current liabilities 194 217 373 362 362 362

P/E (x) 5.2 3.5 2.8 7.8 2.4 2.7 Total non-current liabilities 1,106 1,731 2,042 2,357 2,357 2,357

PEG (x) NM 7.3 12.5 NM 1.1 NM Total shareholders' equity 1,805 1,993 3,033 3,128 3,624 4,069

P/B (x) 0.7 0.6 0.5 0.4 0.3 0.3 Total liabilities and equity 3,347 4,225 5,992 6,708 6,858 6,884

EV/EBITDA (x) 7.3 4.7 4.1 5.5 3.2 3.5

EV/DACF (x) 8.1 5.2 3.6 6.2 3.8 4.1 Cash flow statement ($mn) 2010 2011 2012 2013e 2014e 2015e

FCF Yield (%) NM NM NM NM 35.8% 42.3% Profit before tax 307 433 544 219 620 557

Profitability Depreciation 132 174 192 241 256 262

EBITDA Margin (%) 20% 22% 23% 17% 26% 26% Changes in working capital -176 -118 -245 -148 -28 7

EBIT Margin (%) 14% 17% 17% 10% 20% 18% Other -60 -26 78 -31 -124 -111

Net Margin (%) 10% 11% 12% 4% 12% 12% Operating cash flow 204 463 570 281 724 714

Leverage Capex -605 -1,020 -729 -723 -413 -313

Gross Debt/Equity (x) 0.6 0.8 0.7 0.9 0.7 0.5 Acquisitions - -1 - - - -

Net Debt/Equity (x) 0.5 0.7 0.5 0.7 0.5 0.3 Other -105 -50 -234 -26 - -

Gross Debt/EBITDA (x) 2.4 2.4 2.6 4.7 2.5 2.2 Investing cash flow -709 -1,071 -963 -749 -413 -313

Net Debt/EBITDA (x) 2.0 2.1 2.1 3.6 1.8 1.5 Change in debt 306 632 291 740 -311 -402

Returns Dividends 0 - - -6 - -

ROE (%) 12% 17% 16% 5% 14% 11% Other - -2 317 4 - -

ROACE (%) 11% 13% 12% 6% 11% 10% Financing cash flow 306 631 608 738 -311 -402

ROA (%) 7% 9% 8% 2% 7% 6% FX effects -15 -13 9 -6 - -

Increase (decrease) in cash flow -214 10 224 264 0 0


52

Share data & recommendation Ticker SGGD LI

Last price, $ 8.07


Upside, % 3%

Recommendation SELL

Share data & recommendation Ticker SNGSP RX

Last price, RUB 21.44


Upside, % 10%

Recommendation HOLD


Free float, % 35%


EV, $ mn 3,669

Company snapshot Third largest oil producer in Russia (1.2mmbbl/d) operating in West Siberia (89% of 2012 output) and East Siberia. The company also operates a 420kbd refinery, a network of filling stations and runs the largest in-house drilling division (24% of Russian drilling market).

Growth outlook Surgutneftegas is targeting 60-62mtpa crude production (vs 61mt in 2012) and is working on the Kirishi refinery upgrade (hydrocracker launch is expected later in 2013). The company conservatively holds most of its $30bn cash in deposits.

Valuation At 5.0x P/E ’14 Surgutneftegas is trading in line with Russian peers and 30% below its five-year average. We do not think the stock deserves valuation premium given modest growth prospects and constrained FCF expected in 2013-16.

Surgutneftegas Falling FCF to underscore prefs’ relative attractiveness Rising CapEx will put pressure on FCF, and without a strict dividend policy for common shares, we believe payouts will continue to fall. We initiate coverage with a Sell on commons, a Hold on preferred shares on a high yielding and stable dividend.

Common share dividend payout pressured by negative FCF during 2014-16…

… due to limited upside from crude production and rising CapEx

Preferreds’ dividend favored over commons’ on higher (6% vs 1.2%), more stable payout…

… potentially leading to a narrower preferred-common spread (19% today, down from 49% three years ago)

Conservative use of $30bn ‘war chest’ not value-accretive to shareholders; M&A/greenfield development could generate 3-fold the return

In the long run, we expect falling FCF… To date, Surgutneftegas has delivered one of the most robust cash flows in the industry ($7.4bn during 2011-12, 14% yield); however, limited upside from crude production levels and rising CapEx will put significant pressure on future FCF, we estimate. While other Russian oil companies are undergoing a similarly heavy investment cycle, we expect the depressed FCF period to last longer for Surgutneftegas – at least until 2016-17, when the newly acquired Shpilman field and catalytic cracker at the Kirishi refinery are launched.

… to put additional pressure on common share dividends… Payout on common shares has steadily fallen in 2006-11, which, we believe, is the consequence of rising CapEx requirements. In light of further pressure on FCF and in the absence of a strict dividend policy for commons, we expect Surgutneftegas to reduce the payout even more.

… further narrowing the preferred stock’s discount to common’s. Surgutneftegas’ preferred share dividend is more stable and defensive than the common dividend. Moreover, the yield is nearly four times higher. We forecast flattish EPS during 2013-15 ($1.45/GDR, on average) and, therefore, a stable preferred share dividend despite rising pressure on FCF. The preferred share discount to common has gradually fallen from 49% in 2010 and currently stands at 19%. In light of the dividend discrepancy between the two types of stock, we believe the discount could narrow further.

$30bn ‘war chest – an unused powerful catalyst. Surgutneftegas’s approach to its cash balance is conservative – the company does not spend it and generates a modest 5% interest rate ($1.5bn annual interest income). Under the proposed greenfield tax regime, the investment return on new fields would be over 16%. Therefore, we believe the market would welcome more active engagement in greenfield development and/or M&A. Surgutneftegas’s only major greenfield at the moment is Shpilman (100kbd potential production peak).

$mn 2012 2013e 2014e 2015e

Revenue, $mn 42,118 39,183 38,179 36,221

EBITDA, $mn 8,953 8,090 8,690 7,429

EPS, $ 1.62 1.26 1.73 1.37

DPS (common), $ 0.02 0.01 0.01 0.01

DPS (pref), $ 0.05 0.04 0.05 0.04

P/E, x 5.0 6.4 4.7 5.9

EV/EBITDA, x 0.4 0.5 0.4 0.5

EV/DACF, x 0.5 0.7 0.5 0.6

Dividend yield (common), % 2.0 1.2 1.7 1.4

Dividend yield (pref), % 7.3 5.7 7.8 6.2

FCF yield, % 12.1 0.6 -0.5 -3.4 Source: Company data, BCS

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SGGD LI , USD RTS (rhs)


53




Crude oil ($/bbl) Share Price (ordinary) ($) 8.07

Brent 80 111 112 104 99 95 Share Price (preferred) ($) 0.65




Gasoline 16 17 23 22 23 22 Income Statement ($mn) 2011 2012 2013e 2014e 2015e

Diesel 12 17 19 17 18 17 Revenue 41,148 42,118 39,183 38,179 36,221

Jet fuel 15 22 23 22 23 23 Opex -8,532 -9,381 -9,010 -9,209 -9,459

Fuel oil -21 -30 -26 -28 -21 -20 Taxes other than income tax -8,458 -8,959 -8,422 -7,807 -7,053

Gas, domestic Excise and export duties -14,096 -14,748 -13,582 -12,394 -12,198

$/mcm 82 98 99 109 114 119 Other operating costs -32 -78 -78 -79 -83

$/mcf 2.3 2.8 2.8 3.1 3.2 3.4 EBITDA 10,030 8,953 8,090 8,690 7,429

Depreciation -1,372 -1,525 -1,921 -2,229 -2,542

Macro assumptions 2010 2011 2012 2013e 2014e 2015e Operating income 8,658 7,428 6,168 6,461 4,886

USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 Finance expenses 985 1,420 1,541 1,518 1,510

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% Other expense/income 2,051 -1,641 -2,104 -265 -265

Pre-tax income 11,695 7,206 5,605 7,713 6,131

Production 2010 2011 2012 2013e 2014e 2015e Income taxes -2,340 -1,403 -1,121 -1,543 -1,226

Crude oil Net income 9,355 5,803 4,484 6,171 4,905

annual output (mmt) 59 61 61 61 61 60 Fully diluted EPS ($) 2.62 1.62 1.26 1.73 1.37

daily output (kbd) 1,187 1,216 1,225 1,225 1,227 1,208

Refined products Balance sheet ($mn) 2011 2012 2013e 2014e 2015e

annual output (mmt) 20 20 20 19 19 19 Cash and investments 12,416 12,085 10,871 11,092 10,213

daily output (kbd) 406 406 395 378 378 378 Inventories 1,388 1,720 1,593 1,592 1,578

light product yield 41% 40% 41% 45% 56% 56% Accounts receivable 2,557 2,610 2,423 2,374 2,260

Gas (bcm) 13.9 13.2 12.4 12.3 12.3 12.1 Other current assets 1,384 1,556 1,556 1,556 1,556

Total current assets 17,744 17,971 16,443 16,615 15,607

Reserves (PRMS) Fixed assets 25,162 30,132 35,113 40,469 45,487

1P Other non-current assets 15,984 19,690 19,690 19,690 19,690

Oil (bn bbl) 6.7 Total non-current assets 41,146 49,823 54,803 60,160 65,178

Gas (bcm) 334 Total assets 58,891 67,794 71,246 76,774 80,785

Total (bn boe) 8.8 Short-term debt - - - - -

EV/Reserves ($/bbl) 0.4 Accounts payable 1,061 1,201 1,112 1,112 1,102

Reserve life (years) 17 Other current liabilities 2,124 2,011 2,011 2,011 2,011

Total current liabilities 3,185 3,212 3,123 3,123 3,113

Financial ratios 2010 2011 2012 2013e 2014e 2015e Long-term debt - - - - -

Valuation Other non-current liabilities 3,805 5,227 5,227 5,227 5,227

P/E (x) 3.1 5.0 6.4 4.7 5.9 Total non-current liabilities 3,805 5,227 5,227 5,227 5,227

PEG (x) NM NM 12.4 NM Total shareholders' equity 51,901 59,355 62,897 68,425 72,446

P/B (x) 0.6 0.5 0.5 0.4 0.4 Total liabilities and equity 58,891 67,794 71,246 76,774 80,785

EV/EBITDA (x) 0.4 0.4 0.5 0.4 0.5

EV/DACF (x) 0.5 0.5 0.7 0.5 0.6 Cash flow statement ($mn) 2011 2012 2013e 2014e 2015e

Dividend yield (ordinary) (%) 2.0% 2.5% 2.0% 1.2% 1.7% 1.4% Net income 9,355 5,803 4,484 6,171 4,905

Dividend yield (preferred) (%) 6.0% 11.2% 7.3% 5.7% 7.8% 6.2% Depreciation 1,372 1,525 1,921 2,229 2,542

FCF Yield (%) 11.1% 12.1% 0.6% -0.5% -3.4% Changes in working capital -692 -38 225 49 119

Profitability Other -1,873 729 - - -

EBITDA Margin (%) 24% 21% 21% 23% 21% Operating cash flow 8,161 8,019 6,631 8,449 7,566

EBIT Margin (%) 21% 18% 16% 17% 13% Capex -4,285 -4,501 -6,902 -7,585 -7,560

Net Margin (%) 23% 14% 11% 16% 14% Other -2,997 -1,734 - - -

Returns Investing cash flow -7,282 -6,234 -6,902 -7,585 -7,560

ROE (%) 18% 10% 7% 9% 7% Change in debt - - - - -

ROACE (%) 27% 22% 16% 14% 9% Dividends -924 -1,217 -943 -643 -884

ROA (%) 16% 9% 6% 8% 6% Other -173 235 - - -

Financing cash flow -1,096 -981 -943 -643 -884

Effect of Forex 13 -53 - - -

Increase (decrease) in cash flow -204 751 -1,214 221 -878


54

Share data & recommendation Ticker ATAD LI

Last price, $ 37.0


Upside, % 5%

Recommendation SELL


Free float, % 31%



1M chg., % 1.9%

3M chg., % -2.0%

YTD chg., % -14.5%

Company snapshot Mid-tier oil producer (525kbd) operating in the Volga-Urals region of Russia. Oil reserves of 6.2bn bbl imply a reserve life of 31 years. The company operates one of the largest filling station networks in the region. In 2012, Tatneft launched the long-awaited Taneco refinery and has already achieved full capacity utilization (140kbd).

Growth outlook Tatneft is targeting flat oil output from its legacy fields in the long-term. Growth projects include the Taneco refinery upgrade and potential capacity expansion, and wider development of bitumen reserves (management plans to treble production in three years).

Valuation Tatneft is trading on 6.1x P/E ’14, implying a 22% premium to Russian oil peers and a 1% premium to its five-year average. We estimate the company generates one of the lowest shareholder returns and, therefore, do not consider the current valuation premium justified.

Tatneft

Premium unjustified Low dividend yields and modest EPS growth are no justification for a premium valuation. We initiate coverage with a Sell recommendation.

Robust upstream FCF ($16/bbl vs Rosneft’s $14/bbl, Lukoil’s $15/bbl)…

… is not translating into attractive shareholder returns:

o 30% RAS payout implies one of lowest dividend yields (4%), zero EPS growth;

o Uninspiring investment returns on Taneco refinery – Taneco upgrade/expansion is estimated to cost c30% more than average, and bitumen reserves development, whose scale/ profitability is uncertain;

Valuation premium to peers is unsustainable, in our view, taking into account some other companies’ superior shareholder returns

Strongest upstream FCF … Tatneft generates one of the highest FCF/bbl among Russian O&G peers – c$16/bbl vs Rosneft’s $14/bbl and Lukoil’s $15/bbl. The company has kept production stable for almost a decade and plans to maintain the current production rate for at least another five years without increasing maintenance CapEx significantly.

… does not translate into robust shareholder returns. Tatneft’s dividend policy is capped at 30% RAS payout churning a modest 4% dividend yield; management has not indicated the policy may change. Due to high upstream exposure, we do not expect Tatneft to impress with EPS growth either, assuming a downward sloping Brent forward curve and Taneco hydrocracker launch not before 2015. Moreover, with $7bn already spent on Taneco development and c$4bn left yet to invest, the refinery must generate FCF of at least $22/bbl to break even, we estimate; for reference, Russian refiners’ EBITDA at the moment is below $9/bbl and will unlikely exceed $14/bbl after the upgrade. These add up to one of the lowest shareholder returns in the sector.

Modest growth project portfolio: Among Tatneft’s expansion projects are Taneco upgrade/expansion and development of bitumen reserves. The former is estimated to cost c30% more than peers’ refinery modernization programs, and its returns are among the lowest. The latter retains an element of positive surprise, but so far has not instilled confidence in scale and/or profitability large enough to impact shareholder returns.

A defensive play, but unattractive at current levels. We consider Tatneft a defensive stock in the weak oil price environment: it generates robust upstream FCF and is fairly flexible with regards to its downstream CapEx. While we are not so optimistic about the oil price as to prefer other names to Tatneft, we consider the stock unattractive to own at current levels (6.1x vs sector’s 5.1x P/E ‘14).

$mn 2012 2013e 2014e 2015e

Revenue, $mn 14,299 13,724 13,642 12,813

EBITDA, $mn 3,850 3,666 3,715 3,182

EPS, $ 6.73 6.24 6.64 5.46

DPS, $ 0.28 0.26 0.27 0.22

P/E, x 5.5 5.9 5.6 6.8

EV/EBITDA, x 4.0 4.2 4.2 4.8

EV/DACF, x 4.6 5.1 4.9 5.7

Dividend yield, % 4.6% 4.3% 4.5% 3.7%


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ATAD LI , USD RTS (rhs)


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Crude oil ($/bbl) Share Price (ords) ($/GDR) 37.02

Brent 80 111 112 104 99 95 Share Price (prefs) ($/share) 3.05




Gasoline 16 17 23 22 23 22 Income Statement ($mn) 2010 2011 2012 2013e 2014e 2015e

Diesel 12 17 19 17 18 17 Revenue 10,697 14,196 14,299 13,724 13,642 12,813

Jet fuel 15 22 23 22 23 23 Opex -2,211 -2,683 -2,786 -2,714 -2,898 -2,905

Fuel oil -21 -30 -26 -28 -21 -20 Purchased oil -1,831 -2,513 -1,735 -1,555 -1,494 -1,437

Gas, domestic Taxes other than income tax -2,398 -3,424 -3,424 -3,393 -3,179 -2,966


EBITDA 2,528 3,491 3,850 3,666 3,715 3,182

Macro assumptions 2010 2011 2012 2013e 2014e 2015e Depreciation 411 406 572 672 683 735

USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 Operating income 2,117 3,084 3,279 2,994 3,033 2,448

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% Finance expenses 108 58 -100 -34 46 104

Other expense/income -90 -213 107 -19 -6 -3

Production 2010 2011 2012 2013e 2014e 2015e Pre-tax income 2,135 2,930 3,286 2,941 3,072 2,549

Crude oil Income taxes -458 -749 -754 -620 -614 -510

annual output (mmt) 26 26 26 26 26 26 Minority interest/dividends -132 -87 -160 -121 -118 -114

daily output (kbd) 522 524 525 526 526 516 Net income 1,545 2,094 2,372 2,200 2,340 1,925

Refined products Fully diluted EPS ($) 4.38 5.94 6.73 6.24 6.64 5.46

annual output (mmt) 0.5 2.3 7.2 7.1 6.9 6.9

daily output (kbd) 10 45 143 142 138 138 Balance sheet ($mn) 2010 2011 2012 2013e 2014e 2015e

light product yield 35% 38% 40% 42% 46% 46% Cash 263 529 428 1,172 2,142 2,936

Gas (bcm) 0.8 0.9 0.9 0.9 0.9 0.9 Inventories 493 784 936 902 911 894

Accounts receivable 2,272 2,350 1,753 1,678 1,658 1,562

Reserves (PRMS) Other current assets 1,287 1,169 1,477 1,468 1,458 1,406

1P 2P 1P+2P 3P 1P+2P+3P Total current assets 4,315 4,833 4,594 5,220 6,169 6,798

Oil (bn bbl) 6.2 2.2 8.4 0.2 8.6 Fixed assets 12,817 13,380 14,695 15,511 16,737 17,926

Gas (bcm) 35 13 47 0 48 Other non-current assets 1,329 1,287 1,354 1,292 1,292 1,292

Total (bn boe) 6.4 2.3 8.7 0.2 8.9 Total non-current assets 14,147 14,667 16,049 16,803 18,030 19,218

EV/Reserves ($/boe) 2.4 1.8 1.7 Total assets 18,461 19,500 20,643 22,023 24,199 26,016

Reserve life (years) 32 44 45 Short-term debt 1,118 1,265 1,051 846 846 846

Accounts payable 1,513 1,750 1,455 1,398 1,392 1,348

Financial ratios 2010 2011 2012 2013e 2014e 2015e Other current liabilities 1 - - - - -

Valuation Total current liabilities 2,631 3,015 2,506 2,244 2,239 2,194

P/E (x) 8.5 6.2 5.5 5.9 5.6 6.8 Long-term debt 2,442 1,919 1,244 1,449 1,808 2,154

PEG (x) NM 17.6 41.6 NM 87.4 NM Other non-current liabilities 2,367 2,479 2,819 2,905 3,023 3,137

P/B (x) 1.2 1.1 1.0 0.9 0.8 0.7 Total non-current liabilities 4,809 4,398 4,063 4,354 4,831 5,290



Dividend yield (ords) (%) 2.7% 4.0% 4.6% 4.3% 4.5% 3.7%

Dividend yield (prefs) (%) 5.4% 7.9% 9.1% 8.6% 9.2% 7.6% Cash flow statement ($mn) 2010 2011 2012 2013e 2014e 2015e

FCF Yield (%) NM 6.9% 12.8% 9.0% 9.4% 6.5% Net income 1,545 2,094 2,372 2,200 2,340 1,925

Profitability Depreciation 411 406 572 672 683 735

EBITDA Margin (%) 24% 25% 27% 27% 27% 25% Changes in working capital -153 173 -330 188 15 121

EBIT Margin (%) 20% 22% 23% 22% 22% 19% Other 38 70 306 77 118 114


Leverage Capex -2,543 -1,674 -1,578 -1,767 -1,910 -1,923

Gross Debt/Equity (x) 0.3 0.3 0.2 0.1 0.2 0.2 Acquisitions -3 24 -12 -2 - -

Net Debt/Equity (x) 0.3 0.2 0.1 0.1 0.0 0.0 Other 400 38 28 -12 - -


Net Debt/EBITDA (x) 1.3 0.8 0.5 0.3 0.1 0.0 Change in debt 654 -428 -940 -1 360 345

Returns Dividends -492 -388 -518 -600 -636 -523

ROE (%) 15% 18% 18% 15% 14% 11% Other -18 -50 0 -10 - -

ROACE (%) 12% 16% 16% 15% 14% 11% Financing cash flow 143 -865 -1,458 -612 -276 -178

ROA (%) 9% 11% 12% 10% 10% 8% Increase (decrease) in cash flow -162 266 -101 744 970 794


56

Share data & recommendation Ticker TRNFP RX

Last price, Rb 81 813

Target price, Rb 75 000

Upside, % -8%

Recommendation SELL

Market data MCap, $ mn n/a

Free float, % 100%



1M chg., % 13.3%

3M chg., % 31.2%

YTD chg., % 19.4%

Company snapshot Russian oil transportation monopoly, shipping c90% of the country’s crude via its network of 53,000km of pipelines. Last year, Transneft transported 480mt of Russian and Central Asian crude and 27mt of oil products.

Growth outlook The top line is driven by crude transportation volumes and tariffs. With the finalization of ESPO, we expect the tariff growth rate to slow down considerably. Russian crude volumes are unlikely to increase significantly either; hence, we forecast a stable 4% pa EBITDA growth rate. However, with substantial reduction in CapEx, we estimate the company could fully deleverage by 2017.

Valuation Transneft is trading at a five-year high P/E of 3.1x (’14e). This compares to five-year average of 1.9x. The stock price is reflecting the market’s expectations of a transition to a c20% IFRS profit payout vs the company’s current policy of 25% RAS.

Transneft (pref)

Risk-reward not worth the gamble

Market is pricing in a much too optimistic dividend scenario, suggesting the name is at risk of de-rating, in our opinion. We initiate coverage with a Sell call.

Robust FCF – $10bn during 2013-15 – is encouraging hope in higher dividends

Preferred share price aggressive, assumes 2013e IFRS payout of 19% (v 3% 2012)

Risk-reward unattractive: o potential downside (85%) (no change in dividend policy) o exceeds upside (24%) (25% IFRS payout) by almost 4-fold

No guarantee holders of preferred shares will benefit from IFRS-based payout, unless the company increases RAS profit

Robust FCF allows high dividend… As Transneft finalizes the construction of its most capital-intensive pipeline, ESPO, the company is becoming highly FCF-generative. We forecast up to $10bn of FCF during 2013-15 vs modest $0.6bn last year, and negative FCF in prior periods. Such robust FCF generation could allow the company to fully deleverage (1.4x net debt/EBITDA ‘13e) by 2017, engage in new large-scale projects, and/or distribute funds among shareholders via higher dividends.

… which the market is already pricing in. Transneft prefs are trading at an all-time high of Rb82,000/share, driven by talks on imposing a 25% IFRS payout threshold among state-owned companies. Rosneft has already adopted such a policy, and Gazprom is considering a shift from 2015. This gives Transneft pref shareholders confidence to expect a similar move from the oil pipeline monopolist, even though management said there were no plans to change the dividend policy until major projects are completed, i.e., 2017. Based on a DDM model, the current share price reflects a 19% IFRS payout.

Preferred share price downside outstrips upside… Assuming a 25% IFRS payout and an equal dividend for two classes of shares, Transneft pref’s share price ceiling is Rb102,000/sh, based on our DDM model. A bear-case scenario of no change in dividend policy would imply a Rb12,500/sh floor. The potential upside from the current share price level is 24%, while the downside is 85%, implying a fairly unattractive risk-reward skew.

… and risks are skewed to the upside. The government’s search for additional budget revenues is understandable, and there is no guarantee that Transneft will not change its dividend policy only for common shares (100% held by the state). Management’s decision to increase the common share payout last year (from 15% to 36%) is an indirect indication of such possibility, in our view. Holders of preferred shares can count with certainty on higher dividends only if the RAS profit base itself is higher (e.g., via collecting dividends from subsidiaries). However, to justify the current share price, Transneft’s RAS profit would have to be nearly 7fold its current level. Taking into account such risks and the unattractive risk-reward skew, we believe the gamble is not worth holding the shares.

$mn 2012 2013e 2014e 2015e

Revenue, $mn 23,594 23,644 24,046 24,675

EBITDA, $mn 10,438 10,965 11,256 11,754

EPS, $ 819 725 796 855

DPS, $ 22 20 80 128

P/E, x 3.1 3.5 3.2 3.0

EV/EBITDA, x 3.3 3.2 3.1 3.0

Dividend yield, % 0.8 0.8 3.2 5.2


1218

1306

1394

1482

1570

60 000

65 000

70 000

75 000

80 000

85 000

90 000


TRNFP RX , RUB MICEX (rhs)


57



Market statistics Income Statement ($mn) 2010 2011 2012 2013e 2014e 2015e

Share Price (Rb/share) 81,878 Revenue 14,741 22,802 23,594 23,644 24,046 24,675

Opex -5,651 -6,536 -6,428 -6,202 -6,538 -6,836

Macro assumptions 2010 2011 2012 2013e 2014e 2015e Cost of oil sold -252 -2,843 -2,905 -2,781 -2,741 -2,685

USD/RUB 30.36 29.39 31.04 31.87 32.96 33.26 Export custom duties -2,276 -2,433 -2,251 -2,078 -1,979

CPI 8.2% 6.0% 6.0% 5.5% 5.0% 5.0% Other operating costs -969 -1,242 -1,391 -1,444 -1,433 -1,422

Tariff growth 11.8% 22.5% 1.5% 7.0% 5.0% 5.0% EBITDA 7,869 9,906 10,438 10,965 11,256 11,754

Depreciation 2,371 2,680 2,712 3,380 3,555 3,718

Production (mt) 2010 2011 2012 2013e 2014e 2015e Operating income 5,498 7,227 7,725 7,586 7,701 8,036

Crude oil Finance expenses -465 -414 -633 -731 -586 -407

Domestic 226 233 242 242 242 242 Other expense/income 155 1,200 467 -375 -51 -40

Exports/transit 240 238 239 240 241 241 Pre-tax income 5,188 8,013 7,559 6,480 7,063 7,588

Total 466 472 480 482 482 482 Income taxes -1,074 -1,507 -1,619 -1,285 -1,413 -1,518

% of Russian output 92% 92% 93% 92% 92% 92% Minority interest/dividends -207 -106 -125 -44 0 0

Pipeline length ('000 km) 50 51 54 54 54 54 Net income 3,907 6,399 5,815 5,152 5,651 6,071

Refined products Fully diluted EPS ($) 550 901 819 725 796 855

Domestic 9 9 9 10 10 10

Exports/transit 22 21 19 21 21 21 Balance sheet ($mn) 2010 2011 2012 2013e 2014e 2015e

Total 30 29 27 31 31 31 Cash 9,239 4,521 2,767 3,188 3,188 3,188

% of Russian output 16% 16% 14% 16% 16% 16% Inventories 562 699 839 909 871 887

Accounts receivable 863 1,127 1,303 1,192 1,329 1,364

Financial ratios 2010 2011 2012 2013e 2014e 2015e Other current assets 2,848 7,409 10,204 10,671 10,671 10,671

Valuation Total current assets 13,513 13,756 15,113 15,960 16,059 16,110

P/E (x) 4.6 2.8 3.1 3.5 3.2 3.0 Fixed assets 39,526 41,729 47,602 49,805 52,386 54,302

PEG (x) NM 4.4 NM NM 32.8 39.8 Other non-current assets 720 2,230 2,658 2,793 2,793 2,793

P/B (x) 0.8 0.7 0.5 0.5 0.4 0.4 Total non-current assets 40,246 43,959 50,260 52,598 55,179 57,095

EV/EBITDA (x) 4.4 3.5 3.3 3.2 3.1 3.0 Total assets 53,759 57,715 65,372 68,559 71,238 73,205

Dividend yield (prefs) (%) 0.4% 0.9% 0.8% 0.8% 3.2% 5.2% Short-term debt 347 1,658 836 1,023 0 0

FCF Yield (%) NM NM 3.5% 14.5% 17.1% 23.3% Accounts payable 3,189 3,864 4,139 4,199 4,300 4,378

Profitability Other current liabilities 83 84 5 17 17 17

EBITDA Margin (%) 53% 43% 44% 46% 47% 48% Total current liabilities 3,618 5,606 4,980 5,240 4,317 4,395

EBIT Margin (%) 37% 32% 33% 32% 32% 33% Long-term debt 18,655 17,143 17,811 16,487 14,577 10,961

Net Margin (%) 27% 28% 25% 22% 23% 25% Other non-current liabilities 6,336 5,166 5,398 5,317 5,317 5,317

Leverage Total non-current liabilities 24,992 22,309 23,210 21,804 19,894 16,278

Gross Debt/Equity (x) 0.8 0.6 0.5 0.4 0.3 0.2 Total shareholders' equity 25,149 29,801 37,183 41,515 47,027 52,532

Net Debt/Equity (x) 0.4 0.5 0.4 0.3 0.2 0.1 Total liabilities and equity 53,759 57,715 65,372 68,559 71,238 73,205

Gross Debt/EBITDA (x) 2.4 1.9 1.8 1.6 1.3 0.9

Net Debt/EBITDA (x) 1.2 1.4 1.5 1.3 1.0 0.6 Cash flow statement ($mn) 2010 2011 2012 2013e 2014e 2015e

Returns Net income 3,907 6,399 5,815 5,152 5,651 6,071

ROE (%) 17% 23% 17% 13% 13% 12% Depreciation 2,371 2,680 2,712 3,380 3,555 3,718

ROACE (%) 13% 15% 13% 11% 11% 11% Changes in working capital 658 274 -41 101 2 26

ROA (%) 8% 11% 9% 8% 8% 8% Other -523 -3,515 -1,510 576 - -

Operating cash flow 6,412 5,838 6,978 9,208 9,208 9,815

Capex -7,415 -7,128 -6,346 -6,602 -6,136 -5,634

Other 144 -3,498 -1,897 -809 - -

Investing cash flow -7,271 -10,626 -8,243 -7,410 -6,136 -5,634

Change in debt 1,038 -7 -393 -1,190 -2,933 -3,616

Dividends -47 -40 -89 -157 -139 -565

Other -172 -10 99 -58 - -

Financing cash flow 819 -57 -383 -1,405 -3,072 -4,181

Effect of Forex -101 126 -105 29 - -

Increase (decrease) in cash flow -141 -4,719 -1,754 421 - 0


58

Risks to BCS theses

Buy

Lukoil (TP $75/GDR) Production decline in West Siberia accelerates;

CapEx to stabilize production rises above expectations, thus putting pressure on investment returns;

Lower than guided dividend growth due to insufficient FCF and refusal to borrow;

Execution problems (further ramp-up of Uzbek gas production and Korchagina oil output) and/or project launch delay (Iraqi West Qurna-2, Caspian Filanovskogo) implying lower than expected production, earnings and FCF growth.

Gazprom neft (TP $25/GDR) Overpayment for oil license transfers from Gazprom (Prirazlomnoye license

transfer is pending; Gazprom spent over $4bn on the development and may require compensation for historical costs);

CapEx over-run (refinery upgrade, greenfield development, brownfield production decline, Lakhta Center in St. Petersburg);

Continued production decline in West Siberia despite application of production enhancement technologies and rising CapEx.

Novatek (TP $145/GDR) Approval of lower than expected domestic gas tariff growth (5% vs 15%);

Upward adjustments to the gas and condensate MET formula base rates;

Yamal LNG: execution risk / CapEx over-run / withdrawal of government support.

Hold

Rosneft (TP $8.30/GDR)

Positive risks Monetization of $12bn worth of operational synergies from the merger with

TNK-BP;

Friendly resolution of TNK-BP Holding minorities issue;

Successful offshore field exploration results;

Value-accretive asset / license / company acquisitions.

Negative risks Lack of CapEx discipline;

Greenfield project CapEx over-run / launch delay.

Bashneft (TP Rb2,100/share)

Positive risks Potential SPO increasing stock liquidity and bringing in new investors;

Solid execution on Trebs & Titov and delivery above announced targets;

Value-accretive acquisitions.

Negative risks Lower than expected dividends;

Refinery upgrade CapEx over-run;

Unsustainable production flow rates at legacy fields.


59

Gazprom (TP $8.50/GDR)

Positive risks Agreeing to a 25% IFRS dividend payout earlier than currently expected (2014),

a step that the market may take as a signal of improving corporate governance;

Provision of clearer medium-term CapEx guidance and adherence to the new investment program;

Clear targets for investment returns on numerous capital-intensive projects, signaling the importance of efficiency and shareholder value creation.

Negative risks Adherence to the current dividend policy (25% RAS payout) due to significant

CapEx requirements;

Provision of a price discount to Ukraine and acquisition of an ownership stake in Ukrainian GTS;

Additional gas price discounts to European customers.

Sell

Alliance Oil (TP SEK 41/share) Timely launch of upgraded refinery and connection to ESPO;

Successful exploration in Timan Pechora (West-Osoveisky block);

Guidance for earlier start of additional gas blocks (South Khadyryakhinsky, Kargasoksky);

Value-accretive M&A.

Surgutneftegas (TP $8.30/GDR) Value-accretive M&A;

West Siberian production rate stabilization;

Cash pile ensuring stability in a deteriorating market environment.

Tatneft (TP $39/GDR) Better control and efficiency over the investment program;

Bitumen project achieves a significantly larger scale and profitability;

Dividend payout rises above 25% RAS.

Transneft pref (TP Rb75,000/share) Adoption of IFRS-based payout and introduction of a provision that dividends

on preferred shares cannot be less than that on common shares;

RAS profit increase (e.g., through the requirement that subsidiaries pay a certain dividend to their parent company, Kommersant, 25 April);

Management adopting a significant increase in dividends.


60

Valuation methodology

Buy

Lukoil (TP $75/GDR): Base case price target is derived from a ten-year DCF model, assuming a WACC of 10.2% and a zero real terminal growth rate.

Gazprom neft (TP $25/GDR): Base case price target is derived from a ten-year DCF model, assuming a WACC of 10.1% and a real terminal growth rate of -1%.

Novatek (TP $145/GDR): Base case price target is derived from a ten-year DCF model, assuming a WACC of 10.2% and a real terminal growth rate of 0%.

Hold

Rosneft (TP $8.30/GDR): Base case price target is derived from a ten-year DCF model, assuming a WACC of 9.2% and a real terminal growth rate of 1%.

Surgutneftegas pref (TP Rb23.50/share): Base case price target is calculated as a 15% discount to common share price target, a ratio reflecting a higher and more stable dividend.

Gazprom (TP $8.50/GDR): Base case price target is derived from a ten-year DDM model, assuming a cost of equity of 12.6% and a zero real terminal growth rate.

Bashneft (TP Rb2,100/share): Base case price target is derived from a ten-year DCF model, assuming a WACC of 10.7% and a real terminal growth rate of -1%.

Sell

Alliance Oil (TP SEK 41/share): Base case price target is derived from a ten-year DCF model, assuming a WACC of 10.5% and a real terminal growth rate of -2%.

Surgutneftegas (TP $8.30/GDR): Base case price target is derived from a ten-year DCF model, assuming a WACC of 12.6% and a real terminal growth rate of -2%.

Tatneft (TP $39/GDR): Base case price target is derived from a ten-year DCF model, assuming a WACC of 10.4% and a real terminal growth rate of -2%.

Transneft pref (TP Rb75,000/share): target price is set on blended bear-case, base-case and bull-case valuations (25%, 50% and 25% weightings, respectively), all derived from ten-year DDM models, assuming a cost of equity of 12.6% and a zero real terminal growth rate. Bear case assumes no change in dividend policy. Bull case assumes transition to 25% IFRS payout from 2014 and an equal DPS for preferred and common shares. Base case assumes a gradual transition to 25% IFRS payout by 2017.

Research Department +7 (495) 785 5336

Head of Equity Research

Head of Fixed Income Research Head of Private Client Research Head of Production

Kirill Chuyko (ext. 4733) [email protected]

Leonid Ignatyev (ext. 4679) [email protected]

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Equity Research

Fixed Income Research

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Initial Coverage Russian Oil & Gasir.gazprom-neft.com/fileadmin/user_upload/... · Lukoil – 15% pa div growth outpaces peers’, 28% valuation discount Gazprom neft – 8% dividend