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Oil India :: “Natural gas to fuel growth”
Oil India (OIL) is the second largest national oil and gas company operating in
India. OIL operates 65 blocks within the country and 19 blocks abroad and is also
present in downstream refining and transportation sectors. It possesses an
enviable record of posting Reserve Replacement Ratio (RRR) in excess of 1.5 for
each of the last 5 years. Hike in APM gas price, deregulation of gasoline and hike
in prices of diesel, kerosene and LPG indicate a favorable pricing regime which
would limit under recoveries for OIL India going forward.
Investment Argument
A combination of improved economic outlook for the developed world, harsh winter
in OECD countries and risk of political unrest in the Middle East has resulted in
crude prices breaching the $ 100/bbl mark. In addition, domestic fuel price hikes
implemented in FY11 have reduced the intensity of under recoveries and
subsequently improved realizations for OIL yoy. OIL plans to enhance gas
production from 6 mmscmd currently to nearly 10 mmscmd in the next 2-3 yrs in
the north-east mainly from non-associated gas sources by additional drilling and
work over operations. It also aims to double its gas sales within the next 5 yrs.
Going forward, we expect OIL to deliver CAGR of 2.8% and 6.3% in crude oil &
natural gas production during FY10-18E. We forecast combined sales of crude &
natural gas to grow at CAGR of 10.5% during FY10-13, powered by 35.9% CAGR
in natural gas sales. EBITDA margin is set to improve by 760 bps, which translates
into CAGR of 12.5% over FY10-FY13.
Valuation
We value OIL using DCF valuation, to arrive at our price target of `1,520 per share
and initiate coverage with a BUY rating. The price target translates into EV/boe of
$ 6.9/bbl on 2P reserves, which represents a discount of ~ 15% to the E&P universe.
We also expect a dividend of `36 per share in FY12. Upside triggers for the stock
are price hikes / deregulation of natural gas, auto & cooking fuels and discoveries
in its NELP / overseas exploration blocks.
Risks and Concerns
Recurrence of recession in the global or the domestic economy would depress
crude oil prices and would have an adverse effect on the company.
Inability to add new reserves and thereby maintain a healthy reserve replacement
ratio would be negative for the company.
About the company
Oil India (OIL) is the second largest national oil and gas company operating in India. It
operates in 65 domestic oil & gas blocks, out of which it is the operator in 44 blocks. It
also has developmental rights in 19 blocks spread across Africa, Middle East, South
East Asia and Venezuela. The advent of NELP in 1999 and the company’s thrust on
overseas assets has resulted in exponential growth of almost 10 times in its acreage
since 2005. Currently, the company has exploration acreage of 169,535 sq km, with
41,656 sq km in overseas blocks.
Investment Argument
Robust economic outlook supporting high crude oil prices
The primary driver of this industry is the crude oil price, which in turn depends upon
global economic growth prospects, value of the US dollar against other currencies and
OPEC interventions which are aimed at keeping the crude price at “acceptable levels”.
The crude price is a major determinant of the economics of pursuing exploration in a
particular field. For example, OIL incurs raising cost of $ 5.2/bbl whereas the oil sands
of Canada require crude prices of around $ 65-75/bbl to break even. Low cost operations
enable OIL to pursue oil exploration profitably even with low crude oil prices.
Brent crude has crossed the $ 100/bbl mark recently, and the average crude oil price so
far for FY11 is $ 86.3/bbl, which is ~18% higher than the FY10 average of $ 71.2/bbl.
Demand for crude has risen on the back of an improved economic outlook for OECD
countries, record low interest rates in the US and growing fuel needs of the industrializing
economies of China & India. The International Energy Agency (IEA) has raised its CY10
forecast for oil demand by 2.7 mn barrels per day (mbpd) to 87.7 mbpd. It expects CY11
demand to be higher by 1.4 mbpd at 89.1 mbpd. The IMF expects global GDP to expand
by 4.4% in CY11 and 4.5% in CY12, which is a reflection of strong growth prospects.
The US has reported Q4CY10 GDP growth of 2.8% yoy (3.2% qoq), which was
significantly above expectations. The Eurozone is also growing steadily, with Germany
reporting Q4CY10 GDP growth of 3.9% yoy and France reporting Q3CY10 GDP growth
of 1.7% yoy (0.3% qoq). Japan has surprised positively with Q3CY10 GDP growth of
5.3% yoy (1.1% qoq). The Asian powerhouses of China and India are expected to grow
at 9.6% and 8.4% respectively for 2011, as per the IMF. The central banks in the Euro
region, UK and the US Federal Reserve are persisting with their pro-growth stance by
keeping interest rates at low levels. The continuation of the stimulus measures is
expected to result in strong GDP growth which will also be helpful for crude demand
and consequently prices. Further, good retail sales data (2.3% growth yoy) and drop in
the seasonally adjusted US unemployment rate from 9.4% to 9% (mom) indicate higher
consumption demand. However, the fiscal problems in some of the Eurozone countries
have not been resolved and there are possibilities of Greece and Ireland-type scenarios
in the coming years
In its latest monthly report, OPEC has desisted from raising its formal output quotas in
spite of the swift rise in crude prices. OPEC has stated that “The recent surge in prices
cannot be fully explained by a change in oil market fundamentals, as global [oil
inventories] point to a continued well-supplied market”, and has blamed market
speculation for the jump in crude prices. Hawkish statements made recently by Iran
and Venezuela favor continuance of higher crude prices. The Energy Information
Administration’s (EIA) latest weekly inventory report shows that crude inventories have
risen by 2.59 mmbbls for the week ended 28 Jan, 2011. Gasoline inventories have
risen by 6.15 mmbbls during the same week whereas distillate inventories reported a
decline of 1.58 mmbbls. Taking into consideration the state of the economy, trend of the
inventory levels and OPEC spare capacity of ~ 5 mbpd, we feel that crude won’t breach
the $ 120/bbl mark soon. However, crude prices will continue to stay at high levels and
we expect FY12E and FY13E crude prices at $ 86/bbl and $ 87/bbl respectively.
Higher propensity for price hikes to control under recoveries
FY11 has been a landmark year for fuel pricing reforms as it witnessed the hike in APM
gas price to $ 4.2/mmBtu and the deregulation of petrol. Prices of diesel, kerosene and
LPG were also increased to keep a lid on the under recoveries. Consequent to the above
actions, retail price of petrol increased by `3.5/lit, diesel by `2/lit, kerosene by `3/lit and
LPG by `35/cylinder. These actions, taken on 25th Jul 2010, had collectively resulted in
reduction of total under recoveries by ~ `200,000 mn.
However, crude prices rose subsequently from ~ $ 75/bbl in Jul 2010 to ~ $ 100/bbl in Jan
2011, which has resulted in a massive upward revision of FY11E under recovery estimate
to ~ `730,000 mn from the previous estimate of ~ `530,000 mn. This has manifested
itself via increased per unit under recoveries for diesel, kerosene and LPG. For the
fortnight ended Jan 31, under recoveries on diesel, kerosene and LPG were `9.2/lit, `22/
lit and `341.6/cylinder respectively. We estimate FY11 gross under recovery at `742,139.9
mn, with OIL India’s share being `26,939.7 mn. OIL’s share of subsidy burden for 9MFY11
is `16,877 mn.
With domestic headline inflation still in double digit levels, GOI has refrained from
raising fuel prices further in this fiscal year. Going forward, we estimate crude prices to
settle at lower levels as the combined effect of harsh winter in the developed economies
and political unrest in Egypt wears off. Owing to the high base effect, inflation can slide
to single digit which would make it easier for the Govt. to raise fuel prices. Hence, we
build in small price hikes into our estimates, which are explained in detail below.
We estimate modest hikes in retail diesel price of `1.1/lit in FY12, `1.15/lit in FY13,
`0.6/lit in FY14 and none thereafter. This would result in per unit diesel under recovery
reducing from `3.7/lit in FY11E to `2.2/lit, `1.8/lit and `1.6/lit in FY12E, FY13E and
FY14E respectively. For kerosene, we expect no price hike in FY12 in view of the rather
large `3/lit hike in FY11. Going forward, we expect retail kerosene price to be hiked by
a meager `0.5/lit each in FY13 and FY14, with no hikes thereafter. Hence, we expect per
unit kerosene under recovery to marginally reduce from `17/lit in FY11 to `16.1/lit,
`16.2/lit and `15.9/lit in FY12, FY13 and FY14 respectively. Similarly, we expect no price
hike for LPG in FY12, and subsequent price hikes of `10/cylinder each in FY13 and
FY14. This would have the effect of marginally reducing per unit LPG under recovery
from `293.5/cyl in FY11 to `282/cyl, `289.8/cyl and `288.7/cyl for FY12, FY13 and FY14
respectively. We note that any decision to reduce taxes / duties would reduce the gross
under recoveries further.
We expect consumption of diesel to grow at CAGR of ~ 8.4% during FY11-14 which is
in line with the prevalent trend. While we expect consumption of LPG to grow at CAGR
of ~ 6.9% during FY11-14, we expect consumption of kerosene to fall at CAGR of ~ 1.7%
during the same time period. The sequential fall in kerosene consumption yoy has
been observed during the past and is expected to continue going forward. As a result,
gross kerosene under recovery is projected to reduce slightly in absolute terms, while
LPG is forecasted to account for ~ 50% of under recoveries by FY14. Regular price
hikes will keep diesel under recovery in check going forward.
Production jump + price hike = Jump in natural gas revenues
The more than doubling of APM gas price to $ 4.2/mmBtu during Jun 2010 is a big
positive for ONGC and OIL India as it has resulted in a quantum jump in natural gas
revenues and consequently, overall profitability. Further, it also incentivizes exploration
in marginal fields which were previously neglected due to un-remunerative gas prices.
On top of this, OIL intends to double its gas sales within the next 5 yrs to ~ 10 mmscmd.
Historically, OIL has not focused on monetizing its gas resources because of low
demand in the NE market. However, it has found potential customers in NRL, BCPL
and IOCL’s Guwahati refinery. OIL will enhance its production potential to ~ 10 mmscmd
in the next 2-3 yrs mainly from non-associated gas sources by additional drilling and
work over in the north-east. This new production will come from contingent reserves,
i.e., these reserves weren’t being included in official reserves figures as sales contracts
for the same hadn’t been entered into. OIL has entered into sales contracts for the new
gas and will supply 1 mmscmd to NRL via the DNPL pipeline and 3.2 mmscmd to
BCPL. DNPL is expected to be commissioned soon while BCPL is expected to be
commissioned by end-FY13. We expect sales via DNPL to start in FY12 and ramped up
to 1 mmscmd by FY13. The contract with BCPL is expected to commence in FY14 and
would be ramped up to 3.2 mmscmd in the next 2 yrs. A new gas supply agreement has
been entered into with a Rajasthan State Govt. company at a higher price; for supply of
0.9 mmscmd over 3 yrs against the current level of ~ 0.65 mmscmd. OIL is also proactively
working to improve the gas transportation infrastructure in the North East. It has entered
into MOUs with BPCL, IOCL and ONGC for developing city gas distribution (CGD)
infrastructure in the North East and has completed preliminary activities.
OIL has entered into partnership with Arrow Energy of Australia and GAIL (India) for
shale gas exploration. The company feels that there is an abundance of shale structure
in the Assam - Arakan basin, in OIL’s nomination blocks. Currently, the work is in the
exploration stages. Recent reports in the media about ONGC making a shale gas
discovery in Durgapur (West Bengal) have kindled prospects of abundant shale gas
reserves in the country. This is a very significant event since India is the first Asian
country, outside Canada and US, where shale gas reserves have been established.
The shale gas discovery demonstrates that India possesses both reserves and
technology needed to extract these reserves. Given OIL’s extensive knowledge of the
geological characteristics of gas blocks in Assam & Arunachal Pradesh, we believe
that this can prove to be the trump card for OIL.
OIL’s gas sales have seen a quantum jump as APM gas price has been hiked to $ 4.2/
mmBtu (inclusive of royalty @ 10%) from $ 1.79/mmBtu previously for the power and
fertilizer sectors. The price of $ 4.2/mmBtu is currently the lowest gas price in the
country, with LNG being the most expensive at ~ $ 10/mmBtu. More importantly, the
tolerance of the Govt. and customers to higher gas prices has increased markedly. The
govt. has increased prices of natural gas for non-priority sectors by 10% to $ 5.25/
mmBtu wef Dec 1, a hike of $ 0.5/mmBtu. Further, the govt. has allowed new gas
production from nomination fields to be priced higher than the APM price. For example,
ONGC will get $ 5.25/mmBtu for the gas it produces from new fields in nominated
blocks in the western offshore (C-series) and $ 5/mmBtu for fields in Cauvery basin. It
will get $ 4.75/mmBtu for fields in KG basin off the Andhra coast. Further, the planning
commission will come up with a mechanism for uniform natural gas pricing (gas pool
pricing) in the country by Apr 2011. The government wants to put in place a mechanism
for pooled pricing of gas to ensure that consumers pay similar prices irrespective of the
source.
Hence, OIL is expected to realize higher prices for the gas it would supply to NRL and
BCPL, which will be further beneficial for gas revenues. Also, the APM price of $ 4.2/
mmBtu is applicable till Mar 2014, after which it may be hiked further. Realizations in
the North-east are at 40% of APM price with the balance being claimed from the Govt. in
other income. Realizations from Rajasthan fields are also 40% of APM price to account
for lower calorific value of the gas. We assume gas price of $ 4.5/mmBtu for the contracts
with NRL and BCPL till FY14. From FY14 onwards, we expect APM price of $ 4.5/mmBtu
and pricing for the NRL & BCPL contracts to be $ 4.75/mmBtu.
Improving crude realizations, Carabobo field to start production in FY14E
The combination of higher crude prices and lesser intensity of under recoveries has
resulted in higher crude realization yoy for OIL India. Given the improved growth prospects
in developed economies and easy global liquidity conditions, we expect crude price of
$ 86/bbl and $ 87/bbl for FY12 and FY13 respectively. Going forward, we expect subsidy
/ bbl to fall from $ 23.4/bbl in FY11 to $ 19.8/bbl and $ 18.2/bbl in FY12 and FY13
respectively. This will enable realizations to rise in tandem with rising crude prices,
thus, enabling OIL to take benefit of higher crude prices.
The key event to watch out for is start of production from the Carabobo field in Venezuela,
in which OIL has participating interest of 3.5%. A Mixed Company Contract was signed
on 12th May 2010. Commercial production is expected to start by FY14. Recoverable
reserves in 25 yrs of operations are 3 bn barrels, with peak production of around
400,000 bpd of heavy oil in FY16E. At the peak production level, OIL’s share of 3.5%
translates to ~ 20% of its current production. Approximately 200,000 bpd is intended to
be upgraded into light crude oil and mixed with the remaining 200,000 bpd as final
product, thus, improving realizations. The license term will be for 25 years with potential
for a further 15 year extension. The project cost is estimated at $ 15-20 bn, capex &
opex are estimated at $ 6.37/bbl & $ 6.47/bbl for 25 yrs. OIL will invest ~ $ 140 mn of its
own resources over 5 yrs for this project and will receive dividend from FY14E onwards.
OIL had embarked on IOR/EOR 6 yrs ago which will result in a steady rise in production
going forward. It is focusing on bringing discoveries into production and will apply
horizontal drilling to maintain consistent growth. OIL’s exemplary record of posting
RRR in excess of 1.5 for each of the last 5 years make us optimistic about production
& sales growth going forward. We expect crude oil production CAGR of 2.9% from
FY10-18.
OIL compares favorably against ONGC
Although OIL is predominantly based in the North East compared to ONGC which has
presence throughout India and even abroad, OIL has better operational parameters
compared to ONGC. As a result of its extensive experience in Assam, OIL’s production
cost / bbl is almost half of the cost incurred by ONGC in its Assam fields. ONGC
produced 1.19 MMT and 1.22 MMT of crude from its fields in Assam in FY10 & FY09
respectively, incurring production cost of $ 52.5/bbl & $ 50.6/bbl respectively. In contrast,
OIL produced 3.54 MMT & 3.43 MMT of crude at a cost of $ 27.16/bbl & $ 27/bbl only in
FY10 & FY09 respectively. In fact, the petroleum ministry had started an exercise in
FY10 to examine whether transferring ONGC’s fields in the northeast to OIL would help
in pumping up volumes from these fields. The move was spurred by the contrast in the
operational results of the two companies in the region.
Further, OIL has posted RRR in excess of 1.5 for each of the last 5 years, whereas the
highest RRR posted by ONGC in the last 5 years is 1.42 (Avg. RRR from FY06-10:
1.03). OIL also has a higher reserve / production ratio than ONGC, which leaves room
for production to grow organically. OIL’s 2P reserves / production for crude oil & gas are
22.5 years (45% higher than ONGC) and 21.9 years (37% higher than ONGC) respectively.
Moreover, crude accounts for 60.6% of OIL’s 2P reserves, compared to 53% for ONGC.
In FY10, crude oil sales formed 66% of total volumes for OIL as against 50.8% for
ONGC. In spite of a higher benchmark price for ONGC, OIL has a higher realization
post subsidy as subsidy/bbl is lower for OIL. This combination of drastically lesser
operating costs, higher RRR, higher reserves / production, higher proportion of crude
oil in OIL’s reserves & sales and lesser subsidy burden / bbl prove that OIL’s operating
metrics are superior to ONGC.
Update on exploration efforts
MN-OSN-2002/2: ONGC is the operator with participating interest of 40%, OIL has participating
interest of 20%. Discovery was made and Declaration of Commerciality (DOC) was submitted
on 22nd Dec, 2009. Subsequently, the appraisal plan has been approved. 4 wells have been
drilled including the first appraisal well. In place reserves are estimated at 56.91 bcm.
AAP-ON-94/1: This is a pre-NELP block with HOEC as the operator. OIL has a participating
interest of 16.129% with further carried interest of 30%. The block has Dirak Discovery (Area: 14
sq km & pay: about 100 m). 3D seismic campaign has been completed during FY10 and three
additional prospects have been identified. Appraisal plan has been approved & appraisal wells
are planned to be drilled. Initial testing results indicate gas flow potential of around 6.2 msmcfd,
1.91 mmscfd & 23.5 mmscfd in 3 zones. In place reserves are estimated at 98.51 bcm (701
mmbboe).
Libya: OIL is the operator with participating interest of 50% (IOCL: 50%). The seismic campaign
has been completed and 3 exploratory wells have been drilled. There were hydrocarbon
indications in the wells drilled but commerciality of hydrocarbon could not be established. The
company has written off the expenses incurred in drilling wells in the Q3FY11 results.
Gabon: OIL is the operator with participating interest of 45%. 2D seismic campaign has been
completed. The initial results pointed towards prospects of hydrocarbon presence. Subsequently,
100 sq. km of 3D seismic acquisition was started on 22nd Oct, 2010 and will be completed by
Jan 2011. Once the data is interpreted, exploratory drilling would be started during Q3FY12.
Timor Leste: Reliance Energy Ltd is the operator with participating interest of 75% with OIL
having participating interest of 12.5%. As part of Minimum Work Programme, the operator has
completed the acquisition of 1300 sq km of 3D seismic data. 1 exploratory well has been drilled
which was unsuccessful. The company will write off the expenses in Q4FY11.
Iran (Farsi Block): OVL (40%) is the operator of this offshore block, with OIL having a stake of
20%. Gas Commerciality for Farzad-B area has been approved by National Iranian Oil Company
(NIOC). OVL has submitted a draft Master Development Plan (MDP) and the second round of
negotiation on the draft plan and Development Service Contract was held in Dec 09. Acceptance
of Master Development Plan by NIOC is still awaited. OIL has indicated that it may write off
expenses related to this field in Q4FY11.
Rajasthan Heavy Oil Project: OIL has discovered heavy oil in Baghewala, Rajasthan. The
company has a technological tie up with PDVSA (Venezuela) for exploitation of this prospect. On
completion of its Integrated Reservoir Study (Phase 1), PDVSA indicated 53 mmt oil-in-place in
upper carbonate and 78 mmt (25 mmt proved category) oil-in-place in lower Bilara & Jodhpur
sand stone. In phase 2, production efforts through steam injection had to be suspended due to
problems encountered in surface facilities. A pilot programme is planned in the future on
whose success the development plan will be implemented. Completion is targeted by FY13,
and depending upon the results, 60 wells will be drilled, which will take upto 5 yrs.
In addition to the above, the company also has participating interests in overseas blocks in
Nigeria, Yemen and Egypt. It is also present in several NELP & pre-NELP blocks other than
those mentioned above. Exploratory work in the other blocks (overseas & domestic) is in its
initial stages and positive news flow on the same can prove to be a trigger for the stock.
Exploration work on NELP VI blocks will end mostly by FY13. Depending upon the results,
development work will commence, which can result in upside to reserves & production. Similarly,
exploratory work on NELP VIII blocks will conclude by 2018.
Capex to stay high going forward
OIL India will be incurring a total capex of ~ $ 1.65 bn in FY11 and FY12. The company aims to
spend the major portion of this amount towards exploratory & appraisal activities (`30 bn) in its
various blocks. OIL will conduct 1,767 sq km of 3D seismic surveys, drilling of 34 exploratory
wells and 34 development wells in FY12. The company is focusing on ramping up natural gas
production from its Assam fields, maintaining a steady increase in its crude production and
adding to its reserves from NELP & overseas blocks.
It has also earmarked ~ `19 bn towards M&A during this period. The company’s target w.r.t M&A
is to ensure doubling of production levels, i.e., production from acquired blocks should account
for ~ 50% of consolidated production of OIL India. The Carabobo field, at peak production, will
account for 20% of OIL India’s current production. The company’s strategic intent is to scout for
producing areas / areas where discoveries have been made so that development efforts can
be made quickly and the block can be brought into production. The company is looking at
targets in Australia and Latin America and in areas where it is conducting exploratory work. The
company is also open to acquiring companies which have the right type of fields and production
equipment.
Given OIL’s capex commitment in its producing, NELP & overseas blocks, we foresee consistently
high capex over the medium term. We estimate capex of `30-35 bn during FY11-14.
Revenue to grow steadily, OPM to improve
Going forward, revenue will grow on the back of increasing crude production, sequentially
better realizations, jump in natural gas production and higher prices for new gas output.
We forecast revenue CAGR of 8% during FY10-13, with EBITDA CAGR of 12.5% and net
profit CAGR of 5.7% (cash profit CAGR of 9%) over the same period. The surge in
EBITDA margin is largely due to the hike in APM gas price hike to $ 4.2/mmBtu. DD&A
expenses are expected to leap from 9.2% of sales in FY10 to 19.6% of sales in FY13 as
a result of the huge exploration campaign to be undergone by the company. This surge
in DD&A is responsible for a drop in net profit margin from 33% in FY10 to 30.9% in
FY13. However, we note that such a huge thrust towards exploratory & development
activities is required to enhance reserves & ensure production growth going forward.
We expect revenue of `81,556.1 mn, `91,892.6 mn and `99,593.5 mn in FY11, FY12
and FY13 respectively. We expect PAT of `27,645.7 mn, `29,163.4 mn and `30,822.9
mn and EPS of `115, `121.3 and `128.2 in FY11, FY12 and FY13 respectively.
Key Risks
Recurrence of recession in the global or the domestic economy would depress
commodity prices and general equity valuations.
Any adverse change in the subsidy sharing mechanism will reduce profitability and
prove to be detrimental to valuations.
Spike in crude prices would increase the under recovery burden if fuel prices are not
increased in tandem.
The North Eastern area of the country is prone to heavy rains and insurgency, which
might result in stoppage / delay in operations.
Inability to establish new reserves will adversely affect the reserve replacement
ratio.
Outlook and Valuation
We forecast revenue CAGR at 8% and EBITDA CAGR at 12.5% during FY10-FY13, on
the back of crude oil & gas production CAGR of 2.8% and 6.3% respectively over FY10-
13. We estimate post-subsidy realization for crude oil at $ 61.4/bbl, $ 65.7/bbl and $
68.3/bbl for FY11, FY12 and FY13 respectively. The hike in APM gas price, along with
improving realization for crude, is reflected in improving EBITDA margin, which is
forecasted to rise from 58.6% in FY10 to 66.2% in FY13. Free cash flows are estimated
to be (`2,043.6 mn) in FY11 due to heavy capex of ~ `35 bn incurred on exploration &
development activities etc. Subsequently, free cash flow would turn positive to `8,271.9
mn in FY12E. It would increase further to `12,058.9 mn in FY13E primarily due to higher
operating cash flows.
We have valued OIL using DCF valuation and initiate coverage with a FY12E target
price of `1,520 per share. The price target translates into EV/boe of $ 6.9/bbl on 2P
reserves, which represents a discount of ~ 15% to the E&P universe. We have used
WACC of 12% and terminal growth rate of 2% for our DCF valuation. Triggers for the
stock are increased clarity regarding the subsidy sharing mechanism, commencement
of sales via DNPL and positive news flow from its exploration activities.
The intrinsic value of `1,520 represents potential upside of 18.5% to the current market
price. We assume dividend per share of `36, which translates to a dividend yield of
2.8%. Hence, the total return from the stock comes to 21.3%.
Scenario Analysis
We consider the following scenarios and estimate the target price under each of these.
WACC 12%
Terminal Growth 2%
PV of FCF to FY18E (`mn) 99,807.6
Terminal Value (`mn) 393,169.3
PV of terminal value (`mn) 199,191.8
EV of OIL India (`mn) 298,999.4
Net debt (`mn) (66,492.8)
Value of Equity (`mn) 365,492.2
Intrinsic Value (`/share) 1,520
DCF Valuation
Case Scenario Target price (`/share)
A No fuel price hikes 1,242.4
B Upstream sharing 40% subsidy 1,373.2
C Base case 1,520
D Diesel deregulation 1,666.5
E Zero under recoveries 2,212.2
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Oil India :: “Natural gas to fuel growth”
Oil India (OIL) is the second largest national oil and gas company operating in
India. OIL operates 65 blocks within the country and 19 blocks abroad and is also
present in downstream refining and transportation sectors. It possesses an
enviable record of posting Reserve Replacement Ratio (RRR) in excess of 1.5 for
each of the last 5 years. Hike in APM gas price, deregulation of gasoline and hike
in prices of diesel, kerosene and LPG indicate a favorable pricing regime which
would limit under recoveries for OIL India going forward.
Investment Argument
A combination of improved economic outlook for the developed world, harsh winter
in OECD countries and risk of political unrest in the Middle East has resulted in
crude prices breaching the $ 100/bbl mark. In addition, domestic fuel price hikes
implemented in FY11 have reduced the intensity of under recoveries and
subsequently improved realizations for OIL yoy. OIL plans to enhance gas
production from 6 mmscmd currently to nearly 10 mmscmd in the next 2-3 yrs in
the north-east mainly from non-associated gas sources by additional drilling and
work over operations. It also aims to double its gas sales within the next 5 yrs.
Going forward, we expect OIL to deliver CAGR of 2.8% and 6.3% in crude oil &
natural gas production during FY10-18E. We forecast combined sales of crude &
natural gas to grow at CAGR of 10.5% during FY10-13, powered by 35.9% CAGR
in natural gas sales. EBITDA margin is set to improve by 760 bps, which translates
into CAGR of 12.5% over FY10-FY13.
Valuation
We value OIL using DCF valuation, to arrive at our price target of `1,520 per share
and initiate coverage with a BUY rating. The price target translates into EV/boe of
$ 6.9/bbl on 2P reserves, which represents a discount of ~ 15% to the E&P universe.
We also expect a dividend of `36 per share in FY12. Upside triggers for the stock
are price hikes / deregulation of natural gas, auto & cooking fuels and discoveries
in its NELP / overseas exploration blocks.
Risks and Concerns
Recurrence of recession in the global or the domestic economy would depress
crude oil prices and would have an adverse effect on the company.
Inability to add new reserves and thereby maintain a healthy reserve replacement
ratio would be negative for the company.
About the company
Oil India (OIL) is the second largest national oil and gas company operating in India. It
operates in 65 domestic oil & gas blocks, out of which it is the operator in 44 blocks. It
also has developmental rights in 19 blocks spread across Africa, Middle East, South
East Asia and Venezuela. The advent of NELP in 1999 and the company’s thrust on
overseas assets has resulted in exponential growth of almost 10 times in its acreage
since 2005. Currently, the company has exploration acreage of 169,535 sq km, with
41,656 sq km in overseas blocks.
Investment Argument
Robust economic outlook supporting high crude oil prices
The primary driver of this industry is the crude oil price, which in turn depends upon
global economic growth prospects, value of the US dollar against other currencies and
OPEC interventions which are aimed at keeping the crude price at “acceptable levels”.
The crude price is a major determinant of the economics of pursuing exploration in a
particular field. For example, OIL incurs raising cost of $ 5.2/bbl whereas the oil sands
of Canada require crude prices of around $ 65-75/bbl to break even. Low cost operations
enable OIL to pursue oil exploration profitably even with low crude oil prices.
Brent crude has crossed the $ 100/bbl mark recently, and the average crude oil price so
far for FY11 is $ 86.3/bbl, which is ~18% higher than the FY10 average of $ 71.2/bbl.
Demand for crude has risen on the back of an improved economic outlook for OECD
countries, record low interest rates in the US and growing fuel needs of the industrializing
economies of China & India. The International Energy Agency (IEA) has raised its CY10
forecast for oil demand by 2.7 mn barrels per day (mbpd) to 87.7 mbpd. It expects CY11
demand to be higher by 1.4 mbpd at 89.1 mbpd. The IMF expects global GDP to expand
by 4.4% in CY11 and 4.5% in CY12, which is a reflection of strong growth prospects.
The US has reported Q4CY10 GDP growth of 2.8% yoy (3.2% qoq), which was
significantly above expectations. The Eurozone is also growing steadily, with Germany
reporting Q4CY10 GDP growth of 3.9% yoy and France reporting Q3CY10 GDP growth
of 1.7% yoy (0.3% qoq). Japan has surprised positively with Q3CY10 GDP growth of
5.3% yoy (1.1% qoq). The Asian powerhouses of China and India are expected to grow
at 9.6% and 8.4% respectively for 2011, as per the IMF. The central banks in the Euro
region, UK and the US Federal Reserve are persisting with their pro-growth stance by
keeping interest rates at low levels. The continuation of the stimulus measures is
expected to result in strong GDP growth which will also be helpful for crude demand
and consequently prices. Further, good retail sales data (2.3% growth yoy) and drop in
the seasonally adjusted US unemployment rate from 9.4% to 9% (mom) indicate higher
consumption demand. However, the fiscal problems in some of the Eurozone countries
have not been resolved and there are possibilities of Greece and Ireland-type scenarios
in the coming years
In its latest monthly report, OPEC has desisted from raising its formal output quotas in
spite of the swift rise in crude prices. OPEC has stated that “The recent surge in prices
cannot be fully explained by a change in oil market fundamentals, as global [oil
inventories] point to a continued well-supplied market”, and has blamed market
speculation for the jump in crude prices. Hawkish statements made recently by Iran
and Venezuela favor continuance of higher crude prices. The Energy Information
Administration’s (EIA) latest weekly inventory report shows that crude inventories have
risen by 2.59 mmbbls for the week ended 28 Jan, 2011. Gasoline inventories have
risen by 6.15 mmbbls during the same week whereas distillate inventories reported a
decline of 1.58 mmbbls. Taking into consideration the state of the economy, trend of the
inventory levels and OPEC spare capacity of ~ 5 mbpd, we feel that crude won’t breach
the $ 120/bbl mark soon. However, crude prices will continue to stay at high levels and
we expect FY12E and FY13E crude prices at $ 86/bbl and $ 87/bbl respectively.
Higher propensity for price hikes to control under recoveries
FY11 has been a landmark year for fuel pricing reforms as it witnessed the hike in APM
gas price to $ 4.2/mmBtu and the deregulation of petrol. Prices of diesel, kerosene and
LPG were also increased to keep a lid on the under recoveries. Consequent to the above
actions, retail price of petrol increased by `3.5/lit, diesel by `2/lit, kerosene by `3/lit and
LPG by `35/cylinder. These actions, taken on 25th Jul 2010, had collectively resulted in
reduction of total under recoveries by ~ `200,000 mn.
However, crude prices rose subsequently from ~ $ 75/bbl in Jul 2010 to ~ $ 100/bbl in Jan
2011, which has resulted in a massive upward revision of FY11E under recovery estimate
to ~ `730,000 mn from the previous estimate of ~ `530,000 mn. This has manifested
itself via increased per unit under recoveries for diesel, kerosene and LPG. For the
fortnight ended Jan 31, under recoveries on diesel, kerosene and LPG were `9.2/lit, `22/
lit and `341.6/cylinder respectively. We estimate FY11 gross under recovery at `742,139.9
mn, with OIL India’s share being `26,939.7 mn. OIL’s share of subsidy burden for 9MFY11
is `16,877 mn.
With domestic headline inflation still in double digit levels, GOI has refrained from
raising fuel prices further in this fiscal year. Going forward, we estimate crude prices to
settle at lower levels as the combined effect of harsh winter in the developed economies
and political unrest in Egypt wears off. Owing to the high base effect, inflation can slide
to single digit which would make it easier for the Govt. to raise fuel prices. Hence, we
build in small price hikes into our estimates, which are explained in detail below.
We estimate modest hikes in retail diesel price of `1.1/lit in FY12, `1.15/lit in FY13,
`0.6/lit in FY14 and none thereafter. This would result in per unit diesel under recovery
reducing from `3.7/lit in FY11E to `2.2/lit, `1.8/lit and `1.6/lit in FY12E, FY13E and
FY14E respectively. For kerosene, we expect no price hike in FY12 in view of the rather
large `3/lit hike in FY11. Going forward, we expect retail kerosene price to be hiked by
a meager `0.5/lit each in FY13 and FY14, with no hikes thereafter. Hence, we expect per
unit kerosene under recovery to marginally reduce from `17/lit in FY11 to `16.1/lit,
`16.2/lit and `15.9/lit in FY12, FY13 and FY14 respectively. Similarly, we expect no price
hike for LPG in FY12, and subsequent price hikes of `10/cylinder each in FY13 and
FY14. This would have the effect of marginally reducing per unit LPG under recovery
from `293.5/cyl in FY11 to `282/cyl, `289.8/cyl and `288.7/cyl for FY12, FY13 and FY14
respectively. We note that any decision to reduce taxes / duties would reduce the gross
under recoveries further.
We expect consumption of diesel to grow at CAGR of ~ 8.4% during FY11-14 which is
in line with the prevalent trend. While we expect consumption of LPG to grow at CAGR
of ~ 6.9% during FY11-14, we expect consumption of kerosene to fall at CAGR of ~ 1.7%
during the same time period. The sequential fall in kerosene consumption yoy has
been observed during the past and is expected to continue going forward. As a result,
gross kerosene under recovery is projected to reduce slightly in absolute terms, while
LPG is forecasted to account for ~ 50% of under recoveries by FY14. Regular price
hikes will keep diesel under recovery in check going forward.
Production jump + price hike = Jump in natural gas revenues
The more than doubling of APM gas price to $ 4.2/mmBtu during Jun 2010 is a big
positive for ONGC and OIL India as it has resulted in a quantum jump in natural gas
revenues and consequently, overall profitability. Further, it also incentivizes exploration
in marginal fields which were previously neglected due to un-remunerative gas prices.
On top of this, OIL intends to double its gas sales within the next 5 yrs to ~ 10 mmscmd.
Historically, OIL has not focused on monetizing its gas resources because of low
demand in the NE market. However, it has found potential customers in NRL, BCPL
and IOCL’s Guwahati refinery. OIL will enhance its production potential to ~ 10 mmscmd
in the next 2-3 yrs mainly from non-associated gas sources by additional drilling and
work over in the north-east. This new production will come from contingent reserves,
i.e., these reserves weren’t being included in official reserves figures as sales contracts
for the same hadn’t been entered into. OIL has entered into sales contracts for the new
gas and will supply 1 mmscmd to NRL via the DNPL pipeline and 3.2 mmscmd to
BCPL. DNPL is expected to be commissioned soon while BCPL is expected to be
commissioned by end-FY13. We expect sales via DNPL to start in FY12 and ramped up
to 1 mmscmd by FY13. The contract with BCPL is expected to commence in FY14 and
would be ramped up to 3.2 mmscmd in the next 2 yrs. A new gas supply agreement has
been entered into with a Rajasthan State Govt. company at a higher price; for supply of
0.9 mmscmd over 3 yrs against the current level of ~ 0.65 mmscmd. OIL is also proactively
working to improve the gas transportation infrastructure in the North East. It has entered
into MOUs with BPCL, IOCL and ONGC for developing city gas distribution (CGD)
infrastructure in the North East and has completed preliminary activities.
OIL has entered into partnership with Arrow Energy of Australia and GAIL (India) for
shale gas exploration. The company feels that there is an abundance of shale structure
in the Assam - Arakan basin, in OIL’s nomination blocks. Currently, the work is in the
exploration stages. Recent reports in the media about ONGC making a shale gas
discovery in Durgapur (West Bengal) have kindled prospects of abundant shale gas
reserves in the country. This is a very significant event since India is the first Asian
country, outside Canada and US, where shale gas reserves have been established.
The shale gas discovery demonstrates that India possesses both reserves and
technology needed to extract these reserves. Given OIL’s extensive knowledge of the
geological characteristics of gas blocks in Assam & Arunachal Pradesh, we believe
that this can prove to be the trump card for OIL.
OIL’s gas sales have seen a quantum jump as APM gas price has been hiked to $ 4.2/
mmBtu (inclusive of royalty @ 10%) from $ 1.79/mmBtu previously for the power and
fertilizer sectors. The price of $ 4.2/mmBtu is currently the lowest gas price in the
country, with LNG being the most expensive at ~ $ 10/mmBtu. More importantly, the
tolerance of the Govt. and customers to higher gas prices has increased markedly. The
govt. has increased prices of natural gas for non-priority sectors by 10% to $ 5.25/
mmBtu wef Dec 1, a hike of $ 0.5/mmBtu. Further, the govt. has allowed new gas
production from nomination fields to be priced higher than the APM price. For example,
ONGC will get $ 5.25/mmBtu for the gas it produces from new fields in nominated
blocks in the western offshore (C-series) and $ 5/mmBtu for fields in Cauvery basin. It
will get $ 4.75/mmBtu for fields in KG basin off the Andhra coast. Further, the planning
commission will come up with a mechanism for uniform natural gas pricing (gas pool
pricing) in the country by Apr 2011. The government wants to put in place a mechanism
for pooled pricing of gas to ensure that consumers pay similar prices irrespective of the
source.
Hence, OIL is expected to realize higher prices for the gas it would supply to NRL and
BCPL, which will be further beneficial for gas revenues. Also, the APM price of $ 4.2/
mmBtu is applicable till Mar 2014, after which it may be hiked further. Realizations in
the North-east are at 40% of APM price with the balance being claimed from the Govt. in
other income. Realizations from Rajasthan fields are also 40% of APM price to account
for lower calorific value of the gas. We assume gas price of $ 4.5/mmBtu for the contracts
with NRL and BCPL till FY14. From FY14 onwards, we expect APM price of $ 4.5/mmBtu
and pricing for the NRL & BCPL contracts to be $ 4.75/mmBtu.
Improving crude realizations, Carabobo field to start production in FY14E
The combination of higher crude prices and lesser intensity of under recoveries has
resulted in higher crude realization yoy for OIL India. Given the improved growth prospects
in developed economies and easy global liquidity conditions, we expect crude price of
$ 86/bbl and $ 87/bbl for FY12 and FY13 respectively. Going forward, we expect subsidy
/ bbl to fall from $ 23.4/bbl in FY11 to $ 19.8/bbl and $ 18.2/bbl in FY12 and FY13
respectively. This will enable realizations to rise in tandem with rising crude prices,
thus, enabling OIL to take benefit of higher crude prices.
The key event to watch out for is start of production from the Carabobo field in Venezuela,
in which OIL has participating interest of 3.5%. A Mixed Company Contract was signed
on 12th May 2010. Commercial production is expected to start by FY14. Recoverable
reserves in 25 yrs of operations are 3 bn barrels, with peak production of around
400,000 bpd of heavy oil in FY16E. At the peak production level, OIL’s share of 3.5%
translates to ~ 20% of its current production. Approximately 200,000 bpd is intended to
be upgraded into light crude oil and mixed with the remaining 200,000 bpd as final
product, thus, improving realizations. The license term will be for 25 years with potential
for a further 15 year extension. The project cost is estimated at $ 15-20 bn, capex &
opex are estimated at $ 6.37/bbl & $ 6.47/bbl for 25 yrs. OIL will invest ~ $ 140 mn of its
own resources over 5 yrs for this project and will receive dividend from FY14E onwards.
OIL had embarked on IOR/EOR 6 yrs ago which will result in a steady rise in production
going forward. It is focusing on bringing discoveries into production and will apply
horizontal drilling to maintain consistent growth. OIL’s exemplary record of posting
RRR in excess of 1.5 for each of the last 5 years make us optimistic about production
& sales growth going forward. We expect crude oil production CAGR of 2.9% from
FY10-18.
OIL compares favorably against ONGC
Although OIL is predominantly based in the North East compared to ONGC which has
presence throughout India and even abroad, OIL has better operational parameters
compared to ONGC. As a result of its extensive experience in Assam, OIL’s production
cost / bbl is almost half of the cost incurred by ONGC in its Assam fields. ONGC
produced 1.19 MMT and 1.22 MMT of crude from its fields in Assam in FY10 & FY09
respectively, incurring production cost of $ 52.5/bbl & $ 50.6/bbl respectively. In contrast,
OIL produced 3.54 MMT & 3.43 MMT of crude at a cost of $ 27.16/bbl & $ 27/bbl only in
FY10 & FY09 respectively. In fact, the petroleum ministry had started an exercise in
FY10 to examine whether transferring ONGC’s fields in the northeast to OIL would help
in pumping up volumes from these fields. The move was spurred by the contrast in the
operational results of the two companies in the region.
Further, OIL has posted RRR in excess of 1.5 for each of the last 5 years, whereas the
highest RRR posted by ONGC in the last 5 years is 1.42 (Avg. RRR from FY06-10:
1.03). OIL also has a higher reserve / production ratio than ONGC, which leaves room
for production to grow organically. OIL’s 2P reserves / production for crude oil & gas are
22.5 years (45% higher than ONGC) and 21.9 years (37% higher than ONGC) respectively.
Moreover, crude accounts for 60.6% of OIL’s 2P reserves, compared to 53% for ONGC.
In FY10, crude oil sales formed 66% of total volumes for OIL as against 50.8% for
ONGC. In spite of a higher benchmark price for ONGC, OIL has a higher realization
post subsidy as subsidy/bbl is lower for OIL. This combination of drastically lesser
operating costs, higher RRR, higher reserves / production, higher proportion of crude
oil in OIL’s reserves & sales and lesser subsidy burden / bbl prove that OIL’s operating
metrics are superior to ONGC.
Update on exploration efforts
MN-OSN-2002/2: ONGC is the operator with participating interest of 40%, OIL has participating
interest of 20%. Discovery was made and Declaration of Commerciality (DOC) was submitted
on 22nd Dec, 2009. Subsequently, the appraisal plan has been approved. 4 wells have been
drilled including the first appraisal well. In place reserves are estimated at 56.91 bcm.
AAP-ON-94/1: This is a pre-NELP block with HOEC as the operator. OIL has a participating
interest of 16.129% with further carried interest of 30%. The block has Dirak Discovery (Area: 14
sq km & pay: about 100 m). 3D seismic campaign has been completed during FY10 and three
additional prospects have been identified. Appraisal plan has been approved & appraisal wells
are planned to be drilled. Initial testing results indicate gas flow potential of around 6.2 msmcfd,
1.91 mmscfd & 23.5 mmscfd in 3 zones. In place reserves are estimated at 98.51 bcm (701
mmbboe).
Libya: OIL is the operator with participating interest of 50% (IOCL: 50%). The seismic campaign
has been completed and 3 exploratory wells have been drilled. There were hydrocarbon
indications in the wells drilled but commerciality of hydrocarbon could not be established. The
company has written off the expenses incurred in drilling wells in the Q3FY11 results.
Gabon: OIL is the operator with participating interest of 45%. 2D seismic campaign has been
completed. The initial results pointed towards prospects of hydrocarbon presence. Subsequently,
100 sq. km of 3D seismic acquisition was started on 22nd Oct, 2010 and will be completed by
Jan 2011. Once the data is interpreted, exploratory drilling would be started during Q3FY12.
Timor Leste: Reliance Energy Ltd is the operator with participating interest of 75% with OIL
having participating interest of 12.5%. As part of Minimum Work Programme, the operator has
completed the acquisition of 1300 sq km of 3D seismic data. 1 exploratory well has been drilled
which was unsuccessful. The company will write off the expenses in Q4FY11.
Iran (Farsi Block): OVL (40%) is the operator of this offshore block, with OIL having a stake of
20%. Gas Commerciality for Farzad-B area has been approved by National Iranian Oil Company
(NIOC). OVL has submitted a draft Master Development Plan (MDP) and the second round of
negotiation on the draft plan and Development Service Contract was held in Dec 09. Acceptance
of Master Development Plan by NIOC is still awaited. OIL has indicated that it may write off
expenses related to this field in Q4FY11.
Rajasthan Heavy Oil Project: OIL has discovered heavy oil in Baghewala, Rajasthan. The
company has a technological tie up with PDVSA (Venezuela) for exploitation of this prospect. On
completion of its Integrated Reservoir Study (Phase 1), PDVSA indicated 53 mmt oil-in-place in
upper carbonate and 78 mmt (25 mmt proved category) oil-in-place in lower Bilara & Jodhpur
sand stone. In phase 2, production efforts through steam injection had to be suspended due to
problems encountered in surface facilities. A pilot programme is planned in the future on
whose success the development plan will be implemented. Completion is targeted by FY13,
and depending upon the results, 60 wells will be drilled, which will take upto 5 yrs.
In addition to the above, the company also has participating interests in overseas blocks in
Nigeria, Yemen and Egypt. It is also present in several NELP & pre-NELP blocks other than
those mentioned above. Exploratory work in the other blocks (overseas & domestic) is in its
initial stages and positive news flow on the same can prove to be a trigger for the stock.
Exploration work on NELP VI blocks will end mostly by FY13. Depending upon the results,
development work will commence, which can result in upside to reserves & production. Similarly,
exploratory work on NELP VIII blocks will conclude by 2018.
Capex to stay high going forward
OIL India will be incurring a total capex of ~ $ 1.65 bn in FY11 and FY12. The company aims to
spend the major portion of this amount towards exploratory & appraisal activities (`30 bn) in its
various blocks. OIL will conduct 1,767 sq km of 3D seismic surveys, drilling of 34 exploratory
wells and 34 development wells in FY12. The company is focusing on ramping up natural gas
production from its Assam fields, maintaining a steady increase in its crude production and
adding to its reserves from NELP & overseas blocks.
It has also earmarked ~ `19 bn towards M&A during this period. The company’s target w.r.t M&A
is to ensure doubling of production levels, i.e., production from acquired blocks should account
for ~ 50% of consolidated production of OIL India. The Carabobo field, at peak production, will
account for 20% of OIL India’s current production. The company’s strategic intent is to scout for
producing areas / areas where discoveries have been made so that development efforts can
be made quickly and the block can be brought into production. The company is looking at
targets in Australia and Latin America and in areas where it is conducting exploratory work. The
company is also open to acquiring companies which have the right type of fields and production
equipment.
Given OIL’s capex commitment in its producing, NELP & overseas blocks, we foresee consistently
high capex over the medium term. We estimate capex of `30-35 bn during FY11-14.
Revenue to grow steadily, OPM to improve
Going forward, revenue will grow on the back of increasing crude production, sequentially
better realizations, jump in natural gas production and higher prices for new gas output.
We forecast revenue CAGR of 8% during FY10-13, with EBITDA CAGR of 12.5% and net
profit CAGR of 5.7% (cash profit CAGR of 9%) over the same period. The surge in
EBITDA margin is largely due to the hike in APM gas price hike to $ 4.2/mmBtu. DD&A
expenses are expected to leap from 9.2% of sales in FY10 to 19.6% of sales in FY13 as
a result of the huge exploration campaign to be undergone by the company. This surge
in DD&A is responsible for a drop in net profit margin from 33% in FY10 to 30.9% in
FY13. However, we note that such a huge thrust towards exploratory & development
activities is required to enhance reserves & ensure production growth going forward.
We expect revenue of `81,556.1 mn, `91,892.6 mn and `99,593.5 mn in FY11, FY12
and FY13 respectively. We expect PAT of `27,645.7 mn, `29,163.4 mn and `30,822.9
mn and EPS of `115, `121.3 and `128.2 in FY11, FY12 and FY13 respectively.
Key Risks
Recurrence of recession in the global or the domestic economy would depress
commodity prices and general equity valuations.
Any adverse change in the subsidy sharing mechanism will reduce profitability and
prove to be detrimental to valuations.
Spike in crude prices would increase the under recovery burden if fuel prices are not
increased in tandem.
The North Eastern area of the country is prone to heavy rains and insurgency, which
might result in stoppage / delay in operations.
Inability to establish new reserves will adversely affect the reserve replacement
ratio.
Outlook and Valuation
We forecast revenue CAGR at 8% and EBITDA CAGR at 12.5% during FY10-FY13, on
the back of crude oil & gas production CAGR of 2.8% and 6.3% respectively over FY10-
13. We estimate post-subsidy realization for crude oil at $ 61.4/bbl, $ 65.7/bbl and $
68.3/bbl for FY11, FY12 and FY13 respectively. The hike in APM gas price, along with
improving realization for crude, is reflected in improving EBITDA margin, which is
forecasted to rise from 58.6% in FY10 to 66.2% in FY13. Free cash flows are estimated
to be (`2,043.6 mn) in FY11 due to heavy capex of ~ `35 bn incurred on exploration &
development activities etc. Subsequently, free cash flow would turn positive to `8,271.9
mn in FY12E. It would increase further to `12,058.9 mn in FY13E primarily due to higher
operating cash flows.
We have valued OIL using DCF valuation and initiate coverage with a FY12E target
price of `1,520 per share. The price target translates into EV/boe of $ 6.9/bbl on 2P
reserves, which represents a discount of ~ 15% to the E&P universe. We have used
WACC of 12% and terminal growth rate of 2% for our DCF valuation. Triggers for the
stock are increased clarity regarding the subsidy sharing mechanism, commencement
of sales via DNPL and positive news flow from its exploration activities.
The intrinsic value of `1,520 represents potential upside of 18.5% to the current market
price. We assume dividend per share of `36, which translates to a dividend yield of
2.8%. Hence, the total return from the stock comes to 21.3%.
Scenario Analysis
We consider the following scenarios and estimate the target price under each of these.
WACC 12%
Terminal Growth 2%
PV of FCF to FY18E (`mn) 99,807.6
Terminal Value (`mn) 393,169.3
PV of terminal value (`mn) 199,191.8
EV of OIL India (`mn) 298,999.4
Net debt (`mn) (66,492.8)
Value of Equity (`mn) 365,492.2
Intrinsic Value (`/share) 1,520
DCF Valuation
Case Scenario Target price (`/share)
A No fuel price hikes 1,242.4
B Upstream sharing 40% subsidy 1,373.2
C Base case 1,520
D Diesel deregulation 1,666.5
E Zero under recoveries 2,212.2
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