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 0 2 4 6 8 10 12 Jul-08 May-09 Mar-10 Jan-11 Nov-11 Sep-12 Jul-13 P/E Lukoil Gazprom neft Russian oils Global majors 0 5 10 15 20 25 Jul-08 May-09 Mar-10 Jan-11 Nov-11 Sep-12 Jul-13 P/E Gazprom Novatek
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Research Department + 7 (495) 785-53-36 www.bcs.ru
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
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
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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asse
ssm
ent
Cata
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k as
sess
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t
Top
pick
s
Source: BCS
2.6 2.9 3.2 3.6 3.95.0
6.1 6.27.1
11.2
0
2
4
6
8
10
12
Alli
ance
Oil
Gaz
prom
Tran
snef
t
Gaz
prom
nef
t
Luko
il
Surg
utN
G
Tatn
eft
Rosn
eft
Bash
neft
Nov
atek
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%
Gaz
prom
nef
t
Gaz
prom
Surg
utN
G (p
ref)
Bash
neft
Luko
il
Tatn
eft
Rosn
eft
Tran
snef
t
Nov
atek
Surg
utN
G (o
rd)
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%
Alli
ance
Oil
Tran
snef
t
Nov
atek
Rosn
eft
Gaz
prom
nef
t
Luko
il
Gaz
prom
Surg
utN
G
Tatn
eft
Bash
neft
EBITDA CAGR 2013-16
Probability
Outcome
Skew
ed to
ups
ide
Skew
ed to
dow
nsid
e
25% 50% 75% 100%
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
Initiation of Coverage – Russian Oil & Gas
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.
Initiation of Coverage – Russian Oil & Gas
5
Recommendation summary1
Buy
Lukoil (TP $75/GDR) – Highest shareholder returns in the sector
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
Initiation of Coverage – Russian Oil & Gas
6
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
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
+ 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
– 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
Widely expected, unlikely to be a catalyst
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
Widely expected, unlikely to be a catalyst
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
Initiation of Coverage – Russian Oil & Gas
10
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
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
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
Initiation of Coverage – Russian Oil & Gas
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.
Initiation of Coverage – Russian Oil & Gas
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.
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.
Gas condensate’s superior profitability contributes to gas projects’ investment returns
Gas condensate’s profitability goes back a long way
Source: Company data, BCS
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
Initiation of Coverage – Russian Oil & Gas
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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.
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…
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.
Initiation of Coverage – Russian Oil & Gas
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.
LNG imports (l.s.) LNG imports share in total gas imports (r.s.)
Initiation of Coverage – Russian Oil & Gas
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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).
Initiation of Coverage – Russian Oil & Gas
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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:
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
Source: Wood Mackenzie, BCS
Initiation of Coverage – Russian Oil & Gas
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
Source: Wood Mackenzie, BCS
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.
Domestic production Pipeline imports Contracted LNG "Sweet spot" Demand
Initiation of Coverage – Russian Oil & Gas
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
Source: Wood Mackenzie
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
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.
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
Board of directors proposes a 20% increase in the 2012 DPS, above expectations
Initiation of Coverage – Russian Oil & Gas
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.
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
Source: Wood Mackenzie, BCS
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
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.
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
Source: Company data, BCS
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.
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
26
15
0
5
10
15
20
25
30
35
Oil products (Ust-Luga) Condensate Crude
$/bbl
Export duty difference
Transport cost difference
359
170
49
0
100
200
300
400
500
LNG exports Pipeline gas exports Domestic gas sales
$/mcm
Operating profit Opex Transport Liquefaction Export duty
Initiation of Coverage – Russian Oil & Gas
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
Source: Company data, BCS
Despite growing CapEx requirements… … we forecast Novatek to remain highly FCF generative
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.
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.
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.
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.
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.
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
… 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
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
Source: Company data, BCS
-20
-15
-10
-5
0
5
10
15
20
2006 2007 2008 2009 2010 2011 2012
$bn
FCF Dividends Net debt change
0.610.40 0.39
0.62 0.58 0.57 0.62 0.69 0.71 0.73
0
1
2
3
4
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
$/GDR
EPS DPS
Initiation of Coverage – Russian Oil & Gas
43
… nor do we expect future investments to add significant value. We do not expect Gazprom to generate sufficient returns on future mega-projects. On our estimates, investment returns of South Stream, the Eastern Gas Program and the potential gas deal with Ukraine are negative, or zero at best.
We do not expect Gazprom’s future mega-projects to add significant value Project NPV ($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
Source: Company data, BCS
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
Initiation of Coverage – Russian Oil & Gas
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.
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.
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).
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.
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).
Increase (decrease) in cash flow -204 751 -1,214 221 -878
Initiation of Coverage – Russian Oil & Gas
54
Share data & recommendation Ticker ATAD LI
Last price, $ 37.0
Target price, $ 39.0
Upside, % 5%
Recommendation SELL
Market data MCap, $ mn 13,079
Free float, % 31%
Free float, $ mn 4,015
Equity performance 1W chg., % -5.7%
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).
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.
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.
Initiation of Coverage – Russian Oil & Gas
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);
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.
Initiation of Coverage – Russian Oil & Gas
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.
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