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Reliance Industries Ltd
Higher refining and gas prices to offset lower gas production
Upgrading RIL’s GRMs to US$10.0/10.5 in FY12/13E.
Nature of issues surfacing in D-6 to potentially lead to a
“reworked” development plan (with help from BP).
On the flip side, cost push (higher devt. capex) and
demand pull (LNG as proxy) to result in higher gas px.
We assume US$6.5/mmbtu (US$4.2 earlier) FY15E on,
partly offsetting NAV impact from lower volume.
Marginal (c2%) upgrade in FY12-13E earnings as higher
GRMs & other income is offset by lower D6 contribution.
Maintain IN-LINE. Price target revised slightly to
Rs1,118 (Rs1,100 earlier).
Well set to gain from the improved refining outlook –
Our refining view is of an up cycle over 2011-13 as Asia’s
independent refiners’ utilization rate is likely to reach 88% in
2013. In addition, limitations on Chinese exports and Libyan
light sweet crude will buoy complex Asian refiners. We
upgrade RIL’s GRMs to US$10/10.5 (US$8.4/9.1) over
FY12/13E.
E&P: Higher gas prices will be the silver lining –
Concerns on interconnectivity and reservoir complexity
would likely require “reworking” of D6 development plan,
with help from BP. While rising LNG proportion in the supply
mix has already created an upward pull on gas prices, we
believe that cost-based push will further aid that process,
making it almost inevitable by FY14, i.e., the next review
cycle. So while investors have been obsessed with nearterm production targets, we believe (1) higher capex esp. if
spread out over years and (2) higher gas prices (US$6.5
from FY15E) could provide downside support to NAV.
Earnings impact of refining and E&P offsets each other
– FY12/13E earnings move up only slightly as impact of (1)
higher GRM, (2) other income from BP’s cash inflow and (3)
likely lower DD&A/boe is offset by lower D6 contribution (on
account of lower production and reduced RIL interest). We
assume gas production of 51/60mmscmd in FY12/13E and
the BP deal to be consummated in mid-FY12.
Valuation: Maintain IN-LINE with PT of Rs1,118 – Based
on Mar-12E SOTP comprising (1) Refining/petrochem
valued at 7.0x (discount to peers to factor re-investment
risks) and (2) E&P at Rs259 based on 20% premium to NAV
of known reserves, implying a 5% discount to that implied in
the BP deal (incl. exploration).
Structural factors to drive refining margins higher
Asian refiners with right product slate and higher operating leverage are well placed to
capitalise on capacity reduction given shutdowns by Japanese and European refiners in the
long run.
In the short term, rising crude price will limit Chinese refinery exports while concerns in Libya,
which limit sweet crude supply to European refiners, will buoy complex Asian refiners.
Reliance, with Nelson complexity of over 12.0 and a product slate tilted towards middle
distillates, is poised to capitalise on this opportunity.
We forecast refining margins of US$8.7/10.0/10.5/bbl for FY11/12/13E (US$7.9/8.4/9.1/bbl)
and factor in a differential of US$4.0/bbl over Singapore GRM (9M FY11 at US$3.6).
Refining cycle on a secular uptrend
Our regional analyst, Duke Suttikulpanich in his report ‘Charging ahead - Asia independent
refiners entering bull cycle over 2011-13’ dated 30 March 2011, highlights Asia’s independent
refiners’ utilization rate over 2011-13E to be 86%, 87% and 88%, respectively, up from 84% in
2010. We believe a utilization rate above 85% implies a healthy demand/supply balance, which
should enable refiners to pass through the cost of crude to end users.
Historically, there has been strong correlation between utilization rates and Singapore GRM at
c.80% (refer Fig 2). We therefore set our Singapore GRM assumptions at US$6.0/bbl for 2011,
US$6.5 for 2012E and US$7.0/bbl for 2013E.
Asian refiners with the right product slate and higher operating leverage are well-placed to
capitalise on capacity reduction given shutdowns by Japanese and European refiners in the long
run. In the short term, rising crude price will limit Chinese refinery exports while concerns in Libya,
which limit sweet crude supply to European refiners, will buoy complex Asian refiners.
Short-term uptrend supported by Chinese constraints and Libyan supply concerns…
1) Chinese refinery exports to come off: We see limitations to China refining product exports,
under high oil price assumption. As the government tries to curb inflation through fuel pricing
control, suppressed domestic margin as a result of high crude price is likely to force privatelyowned Chinese refiners to reduce run rates. Sinopec’s and PetroChina’s priority will be to fill the
supply gap left by the private refiners, estimated to account for 25% of China’s domestic supplies.
2) Libyan sweet crude supply disruption adds to European woes: Disruption from Libya’s
light sweet crude production is likely to limit middle distillate and to a certain extent gasoline
supply in Europe, in the short to medium term. Saudi Arabia’s spare capacity is mainly sour crude
and is unlikely to compensate for Libya’s crude. This is likely to provide arbitrage opportunities for
exporters of refining products in Asia.
…in the long term, products specifications changed to drive margins
In the long term, plagued by rising production costs and product specification supply/demand
mismatch, up to 27% and 10% of refining capacities in Japan and Europe are expected to be
shut by 2013/14E. Based on our thesis, exports of refined products from Japan are expected to
decline by 9% p.a., while demand from Europe is set to rise by 20% p.a.
1) Technical specification change to limit Japanese exports: Japan’s Ministry of Economy,
Trade and Industry (“METI”) has imposed new rules on refiners, requiring operators to increase
the ratio of residue cracking units to crude distillation units by the end of March 2014 to c13%.
The requirement is irrespective of the refiners’ current complexity. Japan’s current overall ratio in
question is c10%, compared to Asia’s average of c15%. In our view, based on the new regulation
and the current set up of the refineries up to 1.2m b/d of refining capacity in Japan is likely to be
permanently shut by 2013/14. We estimate this will reduce Japan’s export volume into Asia by
9% p.a. In our estimation, Japan’s supply reduction exceeds decline in demand. As such we do
not rule out Japan potentially turning from net exporter of refining products, namely middle
distillate, to net importer by 2014.
2) Shift to diesel to accelerate shutdown in Europe: Since 1995, the region has incentivised
the consumption of diesel, while average refineries were built to produce gasoline. As a result,
Europe is now short of diesel, while refineries are becoming idle, on the back of gasoline
oversupply. Additionally, regulations on carbon emission have added to the already high
operating costs in the region. Ultimately, European refiners will shut or convert their sites into
importing facilities. We estimate that 4-10% of European refining capacity will be shut by 2013.
Diesel imports will likely rise as a result.
Asian refiners (ex-Japan), with the right product slate and lower operating costs, are expected to
increase their global market share.
RIL, with Nelson complexity index of over 12x and product slate heavily tilted towards higher
spread middle distillates, is poised to capitalise on the rising void left by Japanese and European
refiners. RIL’s refining margins have consistently outperformed the benchmark Singapore index
with differential rising to 3.6 for 9M FY11 vs. 3.0 for FY10. We expect this differential to be
maintained and forecast refining margins of US$8.7/10.0/10.5/bbl for FY11/12/13E up from
US$7.9/8.4/9.1/bbl we had built in earlier.
E&P: Sea of Gloom, but there’s a silver lining
Investors have focused their attention on the near-term production targets and hence the
impact on EPS in FY12/13E.
However, we believe the medium- to long-term impact of this on development capex, ultimate
recovery, gas prices and hence NAV is much more critical for investment thesis than the nearterm EPS impact.
We believe the adverse impact of (i) lower production and (ii) higher development capex will
be partly offset by (a) likely higher gas prices and (b) deferment of capex recovery based
thresholds for higher profit sharing. The discussion below enumerates the issues facing DG,
the likely outcome in terms of recovery and development capex, its impact on gas prices and
hence the impact on NAV.
Reservoir related challenges manifesting in near-term production headwinds
RIL’s KG-D6 oil and gas volumes have come off from 1Q FY11 peaks (~25kbpd and
~60mmscmd respectively) to ~17kbpd and ~51mmscmd in 4Q FY11. We now factor in D6 gas
production at 51/60mmscmd for FY12/13E. Despite Field Development Plan (FDP) projection to
increase production levels to ~80mmscmd by FY13E, recent press reports (Infraline) have
indicated some evidence of the issues confronting RIL – lower level of interconnectivity and
increased water ingression – which have constrained production rates from the block.
As reported on various websites (Infraline, Indiapetro), the key problem at the reservoir can
broadly be classified into the following:
1) Lower-than-expected connectivity – The D1 and D3 field was put on production with 18
wells and capacity of 80mmscmd and all the wells were drilled in the main channel area. The
earlier expectation (at the FDP stage) that the reservoir volume in the levee and splay areas
would be produced through the wells in the main channel itself has not been met given the low
level of connectivity between the main channel and neighbouring areas. It should be noted that
the main channel typically has good porosity and permeability making it an excellent reservoir
target. Other elements such as levees and splays may contribute reservoir volume and may have
good reservoir properties, but are almost always subordinate to the channel fills in terms of
reservoir quality. See Annexure for the key architectural elements in deepwater systems.
According to media reports (Infraline) regarding RIL’s submission to the DGH, there are 42 sand
units consisting of channels, splays and near channel levees and while 15 have high connectivity
(viz. co-relatable in the range of 4 to 18 km in the wells), 27 of them are essentially isolated (viz.
traceable only in one well). In a nutshell, therefore, the D1-D3 fields have turned out to be a more
complex combination of gas-bearing bodies with different levels of interconnectivity between
them.
2) Increase in water ingress and pressure decline – Infraline reports that a few wells in the
D1and D3 are experiencing increased water production with increasing trend. The sharp increase
in Water Gas Ratio (WGR) in wells A1, A2A, A6, A10, A16, B1, B2, B6 & B13 is mainly due to
increase in choke size resulting in sharp increase in water production, however, gas production
has not increased commensurate with choke size increase. The WGR has not come down on
decreasing choke size. At the MA oil field, Wells MA-6H & MA-7H have high water cut & Gas Oil
Ratio (GOR) while Wells MA-3H, MA-4H & MA-5H have high GOR. The high GOR is due to
breakthrough from gas cap. Water cut does not respond to reduction in choke size. Reservoir
pressure in the block has also declined by 500-700 psi.
Development plan likely to be reworked/expanded
We believe that in light of these concerns, the development plan needs to be reworked, with
possible help from BP. Simplistically speaking, there is a likelihood the development plan (which
so far was focused on drilling 22 wells in the main channel area only) could be extended to cover
drilling in the levee/splay areas, which are thin and widely distributed. Given the production yield
on the wells in adjoining areas are unlikely to be as good, the cost of development is likely to go
up with a potential risk on the ultimate recovery factor also. We have made the following changes
to our assumptions for the D6 NAV model to account for these evolving risks.
1. We have reduced the recoverable reserves to 15tcf (21tcf earlier)
2. Despite lower recovery, we assume the total development capex for D6 including D1/D3, MA
and satellite fields to go up to US$17.5bn, from US$15.5bn earlier.
Cost-push + Demand pull = Higher gas prices
While the above changes (i.e. lower production, recovery at higher capex) will be NAV dilutive on
a standalone basis, there is a silver lining. We believe a higher capex/boe (justified by an
expanded development plan) will strengthen, and in fact justify, the push for higher gas prices.
The tight D-S mismatch in the domestic market has resulted in a situation where imported LNG’s
share in domestic supplies is expected to reach 28% in FY15E vs. 22% in FY10. While rising
LNG in the supply mix had created an upward pull on gas prices, we believe that the cost-based
push could act as a more important factor leading to higher gas prices in the next review cycle i.e.
FY14. We assume gas price of US$6.5/mmbtu from FY15E onwards, vs. US$4.2 earlier.
E&P value at Rs259/share, at 5% discount to implied BP deal valuations
1. We estimate D6 NAV at Rs178/share (for RIL’s reduced 60% stake) on Mar-12E. The
downside in NAV from lower production volumes (plateau of 80mmscmd assumed by FY16
vs. 120mmscmd assumed earlier) is offset by (1) prolonged period of higher capex which
defers the capex recovery thresholds and (2) higher gas prices.
2. The total NAV of known reserves is Rs216/share valuing NEC/CBM resources at
US$4.5/boe as against the implied US$7.0/boe for D6. We believe that a steep discount is
justified given the prolonged gestation period for FDP finalisation and first production.
3. We factor in a 20% exploration premium (vs. 40% earlier) to arrive at E&P value of
Rs259/share in our SOTP. This imputes a 5% discount to the deal valuations in BP’s recent
acquisition of 30% stake in 23 blocks for US$9.0bn (incl. exploration premium).
Financial analysis
We estimate RIL’s earnings to post a 16% CAGR through FY11-13E. This is likely to be driven by
strong refining margins and higher interest income post the BP transfer of interest even as gas
volumes come off given reservoir issues. Likely lower depletion rates will also provide support to
earnings.
Key assumptions:
1. We expect RIL’s refining margin differential to benchmark to remain strong given widening
middle distillate spreads. Accordingly, our FY11/12/13 merged refining margins are
US$8.7/10/10.5/bbl, respectively.
2. Our estimates build in KG-D6 gas volume to ramp up to 60mmscmd in FY13E against
56mmscmd for FY11 and 51mmscmd in FY12E. Oil production during the period is assumed
at 21/19/25kbpd for FY11/12/13E vs 30/35/40kbpd assumed earlier
3. We have modelled based on gas realisation of US$4.2/mmbtu and an exchange rate of
USD/INR of 45.5/45/44 respectively for FY11/12/13E.
4. We have assumed polyester spreads would remain firm given tightness in cotton prices.
5. Our model builds in 30% stake transfer to BP effective October 2011 (i.e. from 2H FY12
onwards).
RIL’s earnings are sensitive to refining margin improvement and changes 7% for every dollar
improvement in GRMs. Refinery export earnings exposes RIL to currency fluctuations. In addition,
crude oil and KG gas realisations are denominated in dollars.
Petchem earnings are also indirectly a function of landed price, which is determined by dollardenominated CIF and the INR/USD rate.
Earnings support from lower depletion post BP deal
Our estimates factor in only 60% DD&A contribution (in line with RIL’s reduced interest) post the
completion of the deal. In addition, it is likely that DD&A per boe will decline as the proceeds from
sale (US$7.2bn) might be set off from the estimated total capex (incl. forecasted) of approx.
US$17bn, which is being currently used to calculate the depletion on KG-D6. It should be noted,
however, that this change only impact reported earnings and has no impact on the NAV of D-6,
which is the basis of our SOTP based target.
1. Under Full cost method, RIL capitalises all costs related to exploration and development (at
the cost centre level) including historical and forecast capex for calculating the DD&A
expenses (charged to P&L). We estimate this RIL’s capitalisation to be approx. US$17bn
including the capex on discovered but non-producing blocks viz. NEC-25, CBM.
2. The sale proceeds from BP might be set off against this estimated block of capex for future
calculation of DD&A. As a result, we estimate the DD&A/boe to decline from ~US$12/boe in
FY11E to US$8/boe in FY13E. This could also provide cushion to RIL earnings and offsets
some of the impact of proportionate reduction in D6 contribution post the stake sale.
Valuation – Lower debt, higher refining offset
lower E&P value
The price target of Rs1,118 is based on Mar-12E SOTP. We believe any further re-rating will be
contingent on RIL’s re-investment plans, beyond the projects that are already in the pipeline.
Given the lack of commensurate re-investment options vis-à-vis its increased cash generation,
we believe that visibility on it will take time to emerge and could involve long gestation projects.
SOTP valuation at Rs1,118
It comprises:
1. Refining and petrochemical segments valued at 7x FY13E (mid-cycle) vs. 6.5x FY12x earlier.
Its important to note that 7x EBITDA is lower than the current valuations of RIL’s regional
peers though we think it’s justified given the (1) significant petrochemical contribution to
EBITDA and (2) low dividend payout coupled with lack of commensurate reinvestment
options.
2. E&P valued at Rs259/share. We have ascribed 20% “exploration” premium to known
reserves adjusted for transfer of 30% stake to BP.
3. Shale gas: We value the NPV of the Marcellus shale asset at Rs24/share and use that to
benchmark the Eagle Ford asset to arrive at the total shale gas value of Rs48/share.
4. We have valued RIL’s Infotel at book value of Rs48bn, RIL’s equity value contribution so far
for the acquisition of BWA/4G license.
5. We have adjusted Mar-12E net debt to factor in US$7.2bn cash receipt from BP, which we
assuming to come in before 2H FY12.
Principal architectural elements of deepwater systems
The interpretation of deepwater systems involving elements often mixes a top-down and bottom
up approach to the hierarchies of the classification. Different depositional sites will have similar
facies characteristics, including sediment type, geometry and biostratigraphy. These can
themselves be grouped into grosser sediment bodies and geometries that are broadly similar,
and form the basis for the bottom-up approach to development of the classification. This high
level hierarchy is made up of:
Channels
Sheets
Levees involving canyon fill
Leveed channel sands
Overbank areas
Amalgamated channel sands
Amalgamated and layered sheet sands
Slumps
Debris flows
Marine shales
Channels
Channels tend to have sharp erosional bases and updip their fill tends to be confined within the
depression they erode into the sea floor. Channels confined by erosion often occur in the mid fan
to distal areas of the base of shelf margin slope. Channel widths range from greater than 3 km to
less than 200 m. Fluvial channel sediments commonly have moderate to good, and locally very
good porosity and permeability making them excellent reservoir targets.
Levees
Levee-overbank deposits accumulate lateral to the main channels of deepwater fans, especially
on the outer channel bends. Channel-margin levee thickness decreases systematically downsystem. They often show a lateral continuity in the facies of the proximal portions of levee facies.
Levees are formed by aggradation, with the growth of the levee systems restricting lateral
migration of the channel. Most natural fluvial levees are dominated by fine-grained sediments and
are predominantly non-reservoir in character. Although the reservoir quality of alluvial levee
facies is typically poor, they can contain a significant proportion of sand and provide additional
reservoir volume.
Splays
The distal portions of deepwater turbidite fans are often the sites of the deposition of sheet sands.
The frontal splays or low-sinuosity, distributary-channel complexes are usually fed by highsinuosity channels. While of moderate reservoir quality, crevasse splays are thin, so contribute
little to reservoir volum
India Equity Research Reports, IPO and Stock News
Visit http://indiaer.blogspot.com/ for complete details �� ��
Reliance Industries Ltd
Higher refining and gas prices to offset lower gas production
Upgrading RIL’s GRMs to US$10.0/10.5 in FY12/13E.
Nature of issues surfacing in D-6 to potentially lead to a
“reworked” development plan (with help from BP).
On the flip side, cost push (higher devt. capex) and
demand pull (LNG as proxy) to result in higher gas px.
We assume US$6.5/mmbtu (US$4.2 earlier) FY15E on,
partly offsetting NAV impact from lower volume.
Marginal (c2%) upgrade in FY12-13E earnings as higher
GRMs & other income is offset by lower D6 contribution.
Maintain IN-LINE. Price target revised slightly to
Rs1,118 (Rs1,100 earlier).
Well set to gain from the improved refining outlook –
Our refining view is of an up cycle over 2011-13 as Asia’s
independent refiners’ utilization rate is likely to reach 88% in
2013. In addition, limitations on Chinese exports and Libyan
light sweet crude will buoy complex Asian refiners. We
upgrade RIL’s GRMs to US$10/10.5 (US$8.4/9.1) over
FY12/13E.
E&P: Higher gas prices will be the silver lining –
Concerns on interconnectivity and reservoir complexity
would likely require “reworking” of D6 development plan,
with help from BP. While rising LNG proportion in the supply
mix has already created an upward pull on gas prices, we
believe that cost-based push will further aid that process,
making it almost inevitable by FY14, i.e., the next review
cycle. So while investors have been obsessed with nearterm production targets, we believe (1) higher capex esp. if
spread out over years and (2) higher gas prices (US$6.5
from FY15E) could provide downside support to NAV.
Earnings impact of refining and E&P offsets each other
– FY12/13E earnings move up only slightly as impact of (1)
higher GRM, (2) other income from BP’s cash inflow and (3)
likely lower DD&A/boe is offset by lower D6 contribution (on
account of lower production and reduced RIL interest). We
assume gas production of 51/60mmscmd in FY12/13E and
the BP deal to be consummated in mid-FY12.
Valuation: Maintain IN-LINE with PT of Rs1,118 – Based
on Mar-12E SOTP comprising (1) Refining/petrochem
valued at 7.0x (discount to peers to factor re-investment
risks) and (2) E&P at Rs259 based on 20% premium to NAV
of known reserves, implying a 5% discount to that implied in
the BP deal (incl. exploration).
Structural factors to drive refining margins higher
Asian refiners with right product slate and higher operating leverage are well placed to
capitalise on capacity reduction given shutdowns by Japanese and European refiners in the
long run.
In the short term, rising crude price will limit Chinese refinery exports while concerns in Libya,
which limit sweet crude supply to European refiners, will buoy complex Asian refiners.
Reliance, with Nelson complexity of over 12.0 and a product slate tilted towards middle
distillates, is poised to capitalise on this opportunity.
We forecast refining margins of US$8.7/10.0/10.5/bbl for FY11/12/13E (US$7.9/8.4/9.1/bbl)
and factor in a differential of US$4.0/bbl over Singapore GRM (9M FY11 at US$3.6).
Refining cycle on a secular uptrend
Our regional analyst, Duke Suttikulpanich in his report ‘Charging ahead - Asia independent
refiners entering bull cycle over 2011-13’ dated 30 March 2011, highlights Asia’s independent
refiners’ utilization rate over 2011-13E to be 86%, 87% and 88%, respectively, up from 84% in
2010. We believe a utilization rate above 85% implies a healthy demand/supply balance, which
should enable refiners to pass through the cost of crude to end users.
Historically, there has been strong correlation between utilization rates and Singapore GRM at
c.80% (refer Fig 2). We therefore set our Singapore GRM assumptions at US$6.0/bbl for 2011,
US$6.5 for 2012E and US$7.0/bbl for 2013E.
Asian refiners with the right product slate and higher operating leverage are well-placed to
capitalise on capacity reduction given shutdowns by Japanese and European refiners in the long
run. In the short term, rising crude price will limit Chinese refinery exports while concerns in Libya,
which limit sweet crude supply to European refiners, will buoy complex Asian refiners.
Short-term uptrend supported by Chinese constraints and Libyan supply concerns…
1) Chinese refinery exports to come off: We see limitations to China refining product exports,
under high oil price assumption. As the government tries to curb inflation through fuel pricing
control, suppressed domestic margin as a result of high crude price is likely to force privatelyowned Chinese refiners to reduce run rates. Sinopec’s and PetroChina’s priority will be to fill the
supply gap left by the private refiners, estimated to account for 25% of China’s domestic supplies.
2) Libyan sweet crude supply disruption adds to European woes: Disruption from Libya’s
light sweet crude production is likely to limit middle distillate and to a certain extent gasoline
supply in Europe, in the short to medium term. Saudi Arabia’s spare capacity is mainly sour crude
and is unlikely to compensate for Libya’s crude. This is likely to provide arbitrage opportunities for
exporters of refining products in Asia.
…in the long term, products specifications changed to drive margins
In the long term, plagued by rising production costs and product specification supply/demand
mismatch, up to 27% and 10% of refining capacities in Japan and Europe are expected to be
shut by 2013/14E. Based on our thesis, exports of refined products from Japan are expected to
decline by 9% p.a., while demand from Europe is set to rise by 20% p.a.
1) Technical specification change to limit Japanese exports: Japan’s Ministry of Economy,
Trade and Industry (“METI”) has imposed new rules on refiners, requiring operators to increase
the ratio of residue cracking units to crude distillation units by the end of March 2014 to c13%.
The requirement is irrespective of the refiners’ current complexity. Japan’s current overall ratio in
question is c10%, compared to Asia’s average of c15%. In our view, based on the new regulation
and the current set up of the refineries up to 1.2m b/d of refining capacity in Japan is likely to be
permanently shut by 2013/14. We estimate this will reduce Japan’s export volume into Asia by
9% p.a. In our estimation, Japan’s supply reduction exceeds decline in demand. As such we do
not rule out Japan potentially turning from net exporter of refining products, namely middle
distillate, to net importer by 2014.
2) Shift to diesel to accelerate shutdown in Europe: Since 1995, the region has incentivised
the consumption of diesel, while average refineries were built to produce gasoline. As a result,
Europe is now short of diesel, while refineries are becoming idle, on the back of gasoline
oversupply. Additionally, regulations on carbon emission have added to the already high
operating costs in the region. Ultimately, European refiners will shut or convert their sites into
importing facilities. We estimate that 4-10% of European refining capacity will be shut by 2013.
Diesel imports will likely rise as a result.
Asian refiners (ex-Japan), with the right product slate and lower operating costs, are expected to
increase their global market share.
RIL, with Nelson complexity index of over 12x and product slate heavily tilted towards higher
spread middle distillates, is poised to capitalise on the rising void left by Japanese and European
refiners. RIL’s refining margins have consistently outperformed the benchmark Singapore index
with differential rising to 3.6 for 9M FY11 vs. 3.0 for FY10. We expect this differential to be
maintained and forecast refining margins of US$8.7/10.0/10.5/bbl for FY11/12/13E up from
US$7.9/8.4/9.1/bbl we had built in earlier.
E&P: Sea of Gloom, but there’s a silver lining
Investors have focused their attention on the near-term production targets and hence the
impact on EPS in FY12/13E.
However, we believe the medium- to long-term impact of this on development capex, ultimate
recovery, gas prices and hence NAV is much more critical for investment thesis than the nearterm EPS impact.
We believe the adverse impact of (i) lower production and (ii) higher development capex will
be partly offset by (a) likely higher gas prices and (b) deferment of capex recovery based
thresholds for higher profit sharing. The discussion below enumerates the issues facing DG,
the likely outcome in terms of recovery and development capex, its impact on gas prices and
hence the impact on NAV.
Reservoir related challenges manifesting in near-term production headwinds
RIL’s KG-D6 oil and gas volumes have come off from 1Q FY11 peaks (~25kbpd and
~60mmscmd respectively) to ~17kbpd and ~51mmscmd in 4Q FY11. We now factor in D6 gas
production at 51/60mmscmd for FY12/13E. Despite Field Development Plan (FDP) projection to
increase production levels to ~80mmscmd by FY13E, recent press reports (Infraline) have
indicated some evidence of the issues confronting RIL – lower level of interconnectivity and
increased water ingression – which have constrained production rates from the block.
As reported on various websites (Infraline, Indiapetro), the key problem at the reservoir can
broadly be classified into the following:
1) Lower-than-expected connectivity – The D1 and D3 field was put on production with 18
wells and capacity of 80mmscmd and all the wells were drilled in the main channel area. The
earlier expectation (at the FDP stage) that the reservoir volume in the levee and splay areas
would be produced through the wells in the main channel itself has not been met given the low
level of connectivity between the main channel and neighbouring areas. It should be noted that
the main channel typically has good porosity and permeability making it an excellent reservoir
target. Other elements such as levees and splays may contribute reservoir volume and may have
good reservoir properties, but are almost always subordinate to the channel fills in terms of
reservoir quality. See Annexure for the key architectural elements in deepwater systems.
According to media reports (Infraline) regarding RIL’s submission to the DGH, there are 42 sand
units consisting of channels, splays and near channel levees and while 15 have high connectivity
(viz. co-relatable in the range of 4 to 18 km in the wells), 27 of them are essentially isolated (viz.
traceable only in one well). In a nutshell, therefore, the D1-D3 fields have turned out to be a more
complex combination of gas-bearing bodies with different levels of interconnectivity between
them.
2) Increase in water ingress and pressure decline – Infraline reports that a few wells in the
D1and D3 are experiencing increased water production with increasing trend. The sharp increase
in Water Gas Ratio (WGR) in wells A1, A2A, A6, A10, A16, B1, B2, B6 & B13 is mainly due to
increase in choke size resulting in sharp increase in water production, however, gas production
has not increased commensurate with choke size increase. The WGR has not come down on
decreasing choke size. At the MA oil field, Wells MA-6H & MA-7H have high water cut & Gas Oil
Ratio (GOR) while Wells MA-3H, MA-4H & MA-5H have high GOR. The high GOR is due to
breakthrough from gas cap. Water cut does not respond to reduction in choke size. Reservoir
pressure in the block has also declined by 500-700 psi.
Development plan likely to be reworked/expanded
We believe that in light of these concerns, the development plan needs to be reworked, with
possible help from BP. Simplistically speaking, there is a likelihood the development plan (which
so far was focused on drilling 22 wells in the main channel area only) could be extended to cover
drilling in the levee/splay areas, which are thin and widely distributed. Given the production yield
on the wells in adjoining areas are unlikely to be as good, the cost of development is likely to go
up with a potential risk on the ultimate recovery factor also. We have made the following changes
to our assumptions for the D6 NAV model to account for these evolving risks.
1. We have reduced the recoverable reserves to 15tcf (21tcf earlier)
2. Despite lower recovery, we assume the total development capex for D6 including D1/D3, MA
and satellite fields to go up to US$17.5bn, from US$15.5bn earlier.
Cost-push + Demand pull = Higher gas prices
While the above changes (i.e. lower production, recovery at higher capex) will be NAV dilutive on
a standalone basis, there is a silver lining. We believe a higher capex/boe (justified by an
expanded development plan) will strengthen, and in fact justify, the push for higher gas prices.
The tight D-S mismatch in the domestic market has resulted in a situation where imported LNG’s
share in domestic supplies is expected to reach 28% in FY15E vs. 22% in FY10. While rising
LNG in the supply mix had created an upward pull on gas prices, we believe that the cost-based
push could act as a more important factor leading to higher gas prices in the next review cycle i.e.
FY14. We assume gas price of US$6.5/mmbtu from FY15E onwards, vs. US$4.2 earlier.
E&P value at Rs259/share, at 5% discount to implied BP deal valuations
1. We estimate D6 NAV at Rs178/share (for RIL’s reduced 60% stake) on Mar-12E. The
downside in NAV from lower production volumes (plateau of 80mmscmd assumed by FY16
vs. 120mmscmd assumed earlier) is offset by (1) prolonged period of higher capex which
defers the capex recovery thresholds and (2) higher gas prices.
2. The total NAV of known reserves is Rs216/share valuing NEC/CBM resources at
US$4.5/boe as against the implied US$7.0/boe for D6. We believe that a steep discount is
justified given the prolonged gestation period for FDP finalisation and first production.
3. We factor in a 20% exploration premium (vs. 40% earlier) to arrive at E&P value of
Rs259/share in our SOTP. This imputes a 5% discount to the deal valuations in BP’s recent
acquisition of 30% stake in 23 blocks for US$9.0bn (incl. exploration premium).
Financial analysis
We estimate RIL’s earnings to post a 16% CAGR through FY11-13E. This is likely to be driven by
strong refining margins and higher interest income post the BP transfer of interest even as gas
volumes come off given reservoir issues. Likely lower depletion rates will also provide support to
earnings.
Key assumptions:
1. We expect RIL’s refining margin differential to benchmark to remain strong given widening
middle distillate spreads. Accordingly, our FY11/12/13 merged refining margins are
US$8.7/10/10.5/bbl, respectively.
2. Our estimates build in KG-D6 gas volume to ramp up to 60mmscmd in FY13E against
56mmscmd for FY11 and 51mmscmd in FY12E. Oil production during the period is assumed
at 21/19/25kbpd for FY11/12/13E vs 30/35/40kbpd assumed earlier
3. We have modelled based on gas realisation of US$4.2/mmbtu and an exchange rate of
USD/INR of 45.5/45/44 respectively for FY11/12/13E.
4. We have assumed polyester spreads would remain firm given tightness in cotton prices.
5. Our model builds in 30% stake transfer to BP effective October 2011 (i.e. from 2H FY12
onwards).
RIL’s earnings are sensitive to refining margin improvement and changes 7% for every dollar
improvement in GRMs. Refinery export earnings exposes RIL to currency fluctuations. In addition,
crude oil and KG gas realisations are denominated in dollars.
Petchem earnings are also indirectly a function of landed price, which is determined by dollardenominated CIF and the INR/USD rate.
Earnings support from lower depletion post BP deal
Our estimates factor in only 60% DD&A contribution (in line with RIL’s reduced interest) post the
completion of the deal. In addition, it is likely that DD&A per boe will decline as the proceeds from
sale (US$7.2bn) might be set off from the estimated total capex (incl. forecasted) of approx.
US$17bn, which is being currently used to calculate the depletion on KG-D6. It should be noted,
however, that this change only impact reported earnings and has no impact on the NAV of D-6,
which is the basis of our SOTP based target.
1. Under Full cost method, RIL capitalises all costs related to exploration and development (at
the cost centre level) including historical and forecast capex for calculating the DD&A
expenses (charged to P&L). We estimate this RIL’s capitalisation to be approx. US$17bn
including the capex on discovered but non-producing blocks viz. NEC-25, CBM.
2. The sale proceeds from BP might be set off against this estimated block of capex for future
calculation of DD&A. As a result, we estimate the DD&A/boe to decline from ~US$12/boe in
FY11E to US$8/boe in FY13E. This could also provide cushion to RIL earnings and offsets
some of the impact of proportionate reduction in D6 contribution post the stake sale.
Valuation – Lower debt, higher refining offset
lower E&P value
The price target of Rs1,118 is based on Mar-12E SOTP. We believe any further re-rating will be
contingent on RIL’s re-investment plans, beyond the projects that are already in the pipeline.
Given the lack of commensurate re-investment options vis-à-vis its increased cash generation,
we believe that visibility on it will take time to emerge and could involve long gestation projects.
SOTP valuation at Rs1,118
It comprises:
1. Refining and petrochemical segments valued at 7x FY13E (mid-cycle) vs. 6.5x FY12x earlier.
Its important to note that 7x EBITDA is lower than the current valuations of RIL’s regional
peers though we think it’s justified given the (1) significant petrochemical contribution to
EBITDA and (2) low dividend payout coupled with lack of commensurate reinvestment
options.
2. E&P valued at Rs259/share. We have ascribed 20% “exploration” premium to known
reserves adjusted for transfer of 30% stake to BP.
3. Shale gas: We value the NPV of the Marcellus shale asset at Rs24/share and use that to
benchmark the Eagle Ford asset to arrive at the total shale gas value of Rs48/share.
4. We have valued RIL’s Infotel at book value of Rs48bn, RIL’s equity value contribution so far
for the acquisition of BWA/4G license.
5. We have adjusted Mar-12E net debt to factor in US$7.2bn cash receipt from BP, which we
assuming to come in before 2H FY12.
Principal architectural elements of deepwater systems
The interpretation of deepwater systems involving elements often mixes a top-down and bottom
up approach to the hierarchies of the classification. Different depositional sites will have similar
facies characteristics, including sediment type, geometry and biostratigraphy. These can
themselves be grouped into grosser sediment bodies and geometries that are broadly similar,
and form the basis for the bottom-up approach to development of the classification. This high
level hierarchy is made up of:
Channels
Sheets
Levees involving canyon fill
Leveed channel sands
Overbank areas
Amalgamated channel sands
Amalgamated and layered sheet sands
Slumps
Debris flows
Marine shales
Channels tend to have sharp erosional bases and updip their fill tends to be confined within the
depression they erode into the sea floor. Channels confined by erosion often occur in the mid fan
to distal areas of the base of shelf margin slope. Channel widths range from greater than 3 km to
less than 200 m. Fluvial channel sediments commonly have moderate to good, and locally very
good porosity and permeability making them excellent reservoir targets.
Levees
Levee-overbank deposits accumulate lateral to the main channels of deepwater fans, especially
on the outer channel bends. Channel-margin levee thickness decreases systematically downsystem. They often show a lateral continuity in the facies of the proximal portions of levee facies.
Levees are formed by aggradation, with the growth of the levee systems restricting lateral
migration of the channel. Most natural fluvial levees are dominated by fine-grained sediments and
are predominantly non-reservoir in character. Although the reservoir quality of alluvial levee
facies is typically poor, they can contain a significant proportion of sand and provide additional
reservoir volume.
Splays
The distal portions of deepwater turbidite fans are often the sites of the deposition of sheet sands.
The frontal splays or low-sinuosity, distributary-channel complexes are usually fed by highsinuosity channels. While of moderate reservoir quality, crevasse splays are thin, so contribute
little to reservoir volum
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