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Looking for an answer
■ Uncertainty hurts near-term growth: Volume growth expectations at D6
oil/gas form a large part of RIL’s near-term EPS growth. Recent declines,
and a lack of company commentary/guidance has introduced risks to this
growth. In order to obtain better clarity, we spoke to several E&P experts to
discuss the potential technical issues at field, and likely volume growth path.
■ Should be fixable: Technical scenarios range from minor glitches that are
easily fixed to those with a more permanent impact on reserves and field
deliverability. However, given 1) a large proportion of D1/D3 wells seem
affected by lower flow rates, 2) RIL has had more than 6 months to study the
problem and has not really moved to fix it yet, and 3) that RIL/DGH still
maintains its long-term forecast of 80 mmscmd, we conclude that the trouble
with the D1/D3 gas fields relates to a field characteristic, and is not a
mechanical fault. Lower connectivity within the thin reservoir sands seems to
be the most likely cause. Getting to 80 mmscmd may still be possible, but
would require new field studies, and a higher number of wells. Getting
government approvals for the higher capex could become time consuming.
■ Commodity margins can help: We update our gas production forecasts,
reducing FY12E/13E D1/D3 output to 44/61 mmscmd, effecting (hopefully)
the last major cut to near-term earnings. Recent strength in refining means
RIL current GRM run rates may be higher than our US$9.4/bbl FY12E
forecast. Seasonality can cause some weakness near term, but margins can
surprise late 2011. Stronger commodity margins should help RIL stock;
increases in near-term gas volumes now present an Optionality, we think.
■ Valuations: Valuations for D1/D3 fall from Rs258 to Rs211; we reduce E&P
upsides Rs33/share and add Rs35/share to our SOTP for RIL’s US shale
business. FY12/13E EPS falls 10%/12% to Rs68/82. Our target price of
Rs1132 (from Rs1181) implies a 20% upside. Maintain OUTPERFORM.
Looking for an answer
A lack of clarity on falling D6 oil/gas volumes has created uncertainty on RIL’s EPS growth
expectations. In this note, we look at the potential technical problems at the field, and
using visible symptoms, pick the most likely scenario. While it may still be possible to
increase output to 80 mmscmd, near-term volumes could remain subdued. We effect
(hopefully) the last major cut to near-term earnings. Strength in refining margins,
especially into 2H FY12, can potentially lead to stock performance, in our view.
KG D6 – what now?
RIL has so far refused to comment on the reasons for the decline in oil/gas volumes at KG
D6, and has not provided any guidance. Yet, these are a significant part of near-term
earnings estimates and contribute much to growth expectations. We do the next best thing.
We have spoken to several E&P experts and have discussed potential technical issues
that could have led to declining volumes. Scenarios range from minor glitches that are
easily fixed, to those with a more permanent impact on reserves and field deliverability.
Using visible symptoms, we pick the most likely scenario. The D1/D3 gas fields seem to
have been affected by lower flow rates, potentially due to lower-than-modelled connectivity
of reservoir sands. Production rates of 80 mmscmd may still be achieved, but will likely
require re-design and more wells, implying higher capex. Depending on the extent of the
problem, total reserves estimates (gas that can be economically extracted) may or may
not see material change. The government will have to be brought on board any revised
development plan, which process can consume an undefined period of time by itself.
A knock-on effect on other E&P
Development of discovered reserves at the NEC 25 field is taking longer than expected,
perhaps due to ongoing differences with the government. RIL also has materially reduced
its rig fleet. Given more drilling will likely be needed at D1/D3, the two that it has now will
be unable to meet minimum work commitments on other acreage, in our view. Expected
earnings from new fields and potential upsides from new discoveries may take longer to
materialise. We reduce our exploration option valuation by Rs33/share. The US shale
business can potentially add material EBITDA – in 2015. Concerns on US gas prices,
service costs and output ramp up imply little excitement near term.
Rely on commodity margins near term?
With no support from E&P volumes, any growth in earnings will rely on commodity –
refining and petchem margins. Strength in global oil demand (and potentially faster diesel
demand growth), improving product cracks and widening light heavy crude oil spreads
now make our US$11/bbl FY13 forecast seem achievable (RIL delivered US$5.9/bbl in 3Q
FY10 and US$9.0/bbl in 3Q FY11). RIL is also currently operating at potentially its highest
petchem earnings run rate – driven by a surge in polyester margins and a bounce back in
polymer margins. Polyester chain margins are at risk to falling cotton prices. Polymer
margins could remain range bound as capacity currently shut globally comes back on line,
while new Middle East capacities ramp up. Incremental EPS growth is more dependent on
higher refining margins, in our view.
Update model
We reduce FY12/13 D6 volume estimates to 53/70 mmscmd (including output from the MA
field), and reduce total recoverable estimate from D1/D3 to 13.9 TCF from 17.7 TCF.
FY12-13E EPS fall 10-12%. Given the PSC for the block, our valuation for D6 falls by
Rs47/share. Adding Rs36/share for RIL’s US shale business, our SOTP falls from Rs1,181
to Rs1,132/share. Late-2011 strength in refining margins could lead to stock price upside.
Maintain OUTPERFORM.
KG D6 – what now?
The pendulum has swung 180 degrees. Within the first six months of field start, RIL
surprised estimates materially, rapidly increasing output to 60 mmscmd (even testing 80
mmscmd for a short period). Over the last six months, output at the marquee D1 and D3
gas fields have surprised again, by falling to c.45mmscmd levels, while the market was
extrapolating earlier strength.
Given the E&P business forms a large part of Reliance’s growth story, uncertainty on
volumes has increased the risks involved in investing in RIL stock. Volume declines have
deflated RIL’s near-term earnings growth story, which was perceived to be low risk. To
add to the uncertainty, RIL has neither provided an explanation for the decline, nor has
laid out future volume estimates.
With the objective of limiting the problem to one which can be logically addressed, we
ignore the conjecture that RIL has intentionally limited gas output (in order to obtain better
pricing, volume allocation etc.). Crude oil is freely priced, and we don’t see much that can
be gained by intentionally limiting crude production. That volumes at the MA oil field have
also fallen sharply indicate that there is some technical issue with the oil field at least.
Unfortunately, RIL does not seem likely to provide guidance/clarity on KG D6 volumes any
time soon. We do the next best thing. We have spoken with multiple experts in the E&P
business, and gathered their views on what could potentially be wrong with the field and
how that could be fixed.
Categorising potential technical issues
We are not E&P experts, and have likely not addressed a portion of technical issues with
the field. Yet, our conversations lend us to broadly categorise problems at the gas field
into two groups:
■ Trouble with facilities, and
■ Reservoir issues.
Trouble with facilities
This category represents mechanical issues that constrain the flow of gas within/post the
well bore.
RIL had anticipated issues with hydrate formation (crystallisation of the gas within
pipelines), and has reportedly installed one of the largest MEG systems in the world to
tackle the issue. In case the formation of hydrates within pipelines is reducing the flow, RIL
may need to increase the scale/scope of the MEG system and conduct a one-time clean
up of the pipelines.
RIL could also have issues with sand control – loose rock entering the well bore and
choking production underground. We understand RIL has installed sand control devices in
anticipation. If these have failed, RIL will need to re-enter the wells and replace the
devices with ones more suitable to the magnitude of the problem.
In general, issues with facilities represent difficulties with the design or operations of the
equipment installed at the field. These should be relatively easy to fix, and should involve
defined time and one-time cost. Getting to the earlier forecasted peak production of 80
mmscmd should not be difficult.
Reservoir issues
This category represents issues that reduce the flow of gas from within the reservoir to the
well bore.
We understand the gas within the D6 sands is expected to have material aquifer support,
i.e., the pressure of water below the gas is expected to help push the gas out. This could
have been overestimated, and may be leading to the gas flowing out at a lower rate. This
could be fixed by drilling more wells now, and through the life of the field. This should not
impact total gas recoverable, but would increase capex estimates over the life of the field.
Reservoir compaction: As natural gas trapped within the underground layers of rock is
produced, internal pressures fall. If the rock layer is unconsolidated (relatively loose), the
pressure of the rock (and in this case sea water) above may cause the gas bearing rock
layer to compress, constraining further gas flow. Compaction can turn out to be a major
issue, especially in a gas field. In order to maximise production over field life, the operator
must try to maintain pressure within the rock, while producing the gas. Water will have to
be injected into the rock as the gas is extracted. Doing this in deep water, to extract
relatively low value (EV/Boe) gas may not be economical. Large compaction will reduce
the total gas recoverable from the fields.
Connectivity of reservoir sands: We understand the D1 and D3 gas fields consist of
multiple channel/overbank sand systems, some of which, though gas bearing, are
relatively thin. Any field operator would hope that these individual gas bearing layers are
interconnected, allowing gas to flow between the layers and into a single well bore. This
inter-connectivity, however, is difficult to model, and does not show up well on seismic
data. It is possible that the multiple gas bearing sands within D1 and D3 are interspersed
by more impervious rock (like shale), and that gas does not flow well within these layers.
Fixing this issue will require more wells – to tap into unconnected pools of gas. This might
also imply that total recoverable is lower than estimated, as some of the standalone gas
pools may be too small to economically exploit.
Fixing reservoir issues will most likely need materially higher capex – through the drilling of
more wells. RIL may also choose plateau production rates lower than 80 mmscmd, on
optimisation of costs and reservoir life.
So which is it?
RIL, for one, isn’t telling. We look at field performance and RIL’s actions so far to make our
conclusions.
■ Upon start, gas production increased rapidly at D1/D3. RIL had 16 wells online early
2010, and was producing a stable 60 mmscmd until mid-2010 (with these 16 wells
having tested 80 mmscmd of production on 23 December 2009. In the first phase, the
plan was to sustain 80 mmscmd from 22 wells (averaging 3.6 mmscmd per well).
Initially, then the wells were delivering gas at rates better than expected, at about 3.75
mmscmd per well.
■ RIL has since connected 2 more wells in D1/D3. Gas output though, has fallen to c.45
mmscmd, or about 2.5 mmscmd per well. The loss in production is equivalent to the
output of 4 wells (at initial production rates). Yet, RIL reports all wells are online; none
have gone to zero. This means that a large proportion of the 18 wells have seen a
reduction in flow rates – that the problem is not localised. RIL suggests total field
output will remain flat near term, implying flow rates have stabilised; well performance
is not expected to deteriorate further.
■ More than 6 months have passed since output at D1/D3 started declining. RIL will by
now, have collected sufficient data at its wells and should have a fair idea about the
nature of the technical difficulty. In a conference call in November 2010, the company
continued to guide to 80 mmscmd peak production from D1/D3, and at the 3Q FY11
analyst meet, maintained that total in place volumes at the field have not been
questioned. This indicates RIL thinks any present technical problem at the field can be
fixed.
■ RIL has not yet filed a plan with the DGH (Directorate General of Hydrocarbons, the
upstream regulator in India) for any work / capex needed to fix the technical issues.
RIL is also not looking to increase its rig fleet near term. This might mean 1) RIL is still
in the process of evaluating the problem and designing the remedy. This would imply
material redesign and work is needed, or 2) RIL finds the current regulatory situation
unsuitable for filing a request for increased capex. RIL has reportedly complained
about red tapism at the DGH. The CAG is currently auditing capex already incurred at
KG D6, and is expected to file its report soon; filing a request for higher capex may not
go down too well. In either case, D1/D3 can take some time to get to 80 mmscmd of
production.
■ The DGH has reported in the media asserting that a section of the field, with 7.5 TCF
of gas in place has not yet been exploited, even though 20 of the 22 Phase I wells
have been drilled. We believe RIL is likely to have drilled initial wells in line with the
field development plan. If a large part of the field has not been drilled, then it is likely
that it was not supposed to be drilled initially, but was meant to help support plateau
production. This ‘spare capacity’, however, implies that RIL could still endeavour to
raise total output to 80 mmscmd if it so desired.
The most likely scenario …
a) Declining output at D1/D3 is led by disappointing reservoir performance. If there were
issues related to field facilities, RIL would have started measures to fix them and
would potentially have been clearer in providing guidance.
b) Lower flow rates are due to lower reservoir connectivity. Reservoir compaction should
not have led to such a large reduction in flow so soon.
c) RIL’s model for the field will have to be re-evaluated. To take total output to 80
mmscmd, new well locations will have to be identified and drilled.
d) This will require the filing of an amendment/addendum to the Field Development Plan
and will likely involve higher capex. Approvals for such revisions can consume
significant amounts of time.
… suggests D6 gas volume ramp up may take time
We reduce total KG D6 gas volume estimate to 53 mmscmd (including 9 mmscmd from
the MA oil field) and for FY13 to 70 mmscmd (including MA field), getting to 80 mmscmd
(D1 and D3) by FY14. We also remove expectations of upside, limiting peak production to
80 mmscmd and total production (over field life) to 13.9 TCF (in line with 13.8 TCF 2P
numbers published by Niko). We already model capex higher than estimated in the field
development plan, and leave those numbers unchanged.
While near-term EPS numbers see meaningful cuts as a result, asset valuations for D6
don’t fall as much. Capex recovery terms in the Production Sharing Contract impart some
stability to RIL’s total cash flow; any loss of revenue over field life is also shared between
the contractors (RIL and Niko) and the government of India. Our DCF-based NAV for
D1/D3 falls from Rs258 to Rs211.
Niko Resources, which has a 10% interest in KG D6, has also recently guided to flat gas
production volumes through FY12.
MA oil decline more worrying
Oil production at the MA field has been more volatile. 3Q FY11 output averaged close to
17 kbopd, below the 24 kbopd delivered in 1Q FY11, and the 40 kbopd expected run rate.
We understand the FPSO deployed at the field has a capacity to process 60 kbopd;
implying RIL was looking at upside to 40 kbopd, rather than the decline now occurring.
RIL, had a few quarters back, spoken of additional wells drilled, but not connected at MA.
There has been little update on these wells, especially given RIL now refuses to discuss
E&P details. Given oil production fell QoQ, it seems unlikely the new well(s) have been
connected. Production can therefore still go up as this happens. We keep our FY12E oil
production estimate at 30 kbopd.
Disturbingly, RIL has decided to produce gas from the MA field, rather than re-inject it
(which is typically done to maintain oil pressure). We note that RIL, was re-injecting the
gas initially. Optically, this might mean RIL has given up trying to maintain oil flow rates
and is happy with lower medium-term oil production. Over the life of the field, recovering
the oil will therefore likely involve more wells, and more water injection/other EOR
techniques. Costs can be higher than expected.
The D6 story may not be over yet
Up until a few years ago, the argument that RIL has exploited only a small part of the large
D6 block, and much upside is yet to be had was frequently made. The simile “a coffee cup
on a kitchen table” was used to illustrate the relatively small size of the current
development. Not much has changed since – RIL has made smaller discoveries around
D1/D3 and in deeper waters, and we understand, has additional identified prospects.
Given the long gestation of deep water E&P (especially gas bearing), it may be too early to
quantify and attribute material value, but the likelihoods of D6 having higher hydrocarbon
are still high. With government support, RIL can potentially keep working at the block for
some time to come.
Selling out for technical help?
Over the last few weeks, media reports have suggested RIL is about to sell a portion of its
D6 stake to either BP or Shell, in order to obtain technical assistance needed to fix the
field. We believe this will happen only after RIL’s technical vendors express their inability
A knock-on effect on other E&P
In our note Time for a Counsellor dated 31 January 2011, we highlighted increasing
differences between RIL and the upstream regulator – the Directorate General of
Hydrocarbons (DGH). RIL has reportedly written to the government referring to these
issues and expressing concern that its exploration and development activities do not
progress as a result.
Activities at NEC-25 have slowed down
Development of the NEC-25 field seems to have been affected by a slow pace of
approvals / co-ordination. This is a discovered field, for which RIL had filed the initial field
development plan in 2007. We understand the DGH had then asked RIL to conduct more
drilling / appraisal and to resubmit a modified plan.
However, appraisal drilling at NEC-25 has slowed since early FY11. RIL was supposed to
appraise the AJ area discovery by drilling three more wells – AJ10, AJ11 and AJ12. In a
media release, Niko (10% working interest in NEC-25) stated that the appraisal
programme was halted due to rig unavailability. There have also been differences between
RIL and the government. The cost recovery of two wells has been disallowed, whereas the
declaration of commerciality of the D-32 well has been contested.
RIL needs to – 1) complete the appraisal programme, 2) file a revised Field Development
Plan, 3) interact with the DGH to have the plan approved and 4) start building the facilities,
including coordination with the entity constructing the evacuation pipeline.
Depending on the scope of the project facilities, this can potentially take between 2-3
years. Our estimate of initial production in FY13 seems to be at risk; we move this now to
FY14. A one-year delay does not hurt the asset value much (we have Rs24 in the SOTP),
but FY13 EPS estimates are hurt by about Rs3.
Large blocks and well commitments, but no rigs?
RIL has 31 active blocks in India and 13 overseas, a large number of which are in deep
waters. Excitement around some of these blocks (especially the ones where RIL’s
partners have publicly spoken of large resource estimates) has underpinned an option
value for RIL’s E&P acreage. We view some of this as fair, especially as RIL will incur
large amounts of capex in exploration, which should over time generate return.
Using data from the DGH, we estimate RIL has 138 wells under minimum work
programmes for its blocks that it has not yet drilled; of which 116 are deep water well.
Given the recent rig moratorium and continuous revisions, it is difficult to estimate the
exact phasing of these commitments, but a majority are committed under NELP III. Even if
timelines for some of these have been extended, we think a large portion will need to be
drilled within the next 3-5 years. We estimate two rigs, drilling flat out would take about
seven years to drill 116 deep water wells. It is not necessary that RIL drills each of these
138 wells, though. It can potentially pay damages and relinquish blocks as well.
RIL, however, has significantly reduced its rig fleet, and currently has only two assets. In
addition to exploratory work, these rigs will also be needed to fix problems at KG D6, and
for any drilling in overseas acreage. Unless RIL were to now increase its rig count,
monetisation of the exploration upside can take longer than expected. We reduce our
valuation for RIL’s exploration option by Rs33/share and now value it at Rs53/share,
based on a capex driven model.
On paper, the US shale business adds up to a nice
number
Reliance has made substantial investments in US shale, and over time, would end up
investing large amounts in developing these assets. However, uncertainty over 1) US gas
prices, 2) drilling and service costs, and 3) ability of the JV’s to ramp up drilling and
production as forecasted has led to a muted reaction among investors, we believe.
However, going by well drilling forecasts, EBITDA from RIL’s US shale portfolio can
become a meaningful number in a few years. At US$5.75/mmbtu, we estimate the three
shale JV’s can generate EBITDA of about US$1.5 bn by 2015. Media reports suggests RIL
targets an EBITDA of US$15 bn by 2015. Contribution from shale would be a meaningful
portion of this target.
Given the large capex commitments, and the ramp in wells drilled number, RIL’s shale
business is likely to remain FCF negative for the first few years, returning cash only by
2015, we believe. P&L contribution can become positive earlier.
We include RIL’s US shale JV’s in our SOTP, at total valuation of US$2.5 bn (at a
US$5.75/mmbtu gas price assumption), representing about Rs36/share.
Rely on commodity margins near
term
With no support from E&P volumes, any growth in earnings will rely on commodity –
refining and petchem margins. Strength in global oil demand (and potentially faster diesel
demand growth), improving product cracks and widening light heavy crude oil spreads
now make our US$11/bbl FY13 forecast seem achievable (RIL delivered US$5.9/bbl in 3Q
FY10 and US$9.0/bbl in 3Q FY11). RIL is also currently operating at potentially its highest
petchem earnings run rate – driven by a surge in polyester margins and a bounce back in
polymer margins. Polyester chain margins are at risk to falling cotton prices. Polymer
margins can remain range bound as capacity currently shut in globally comes back on line,
while new Middle East capacities ramp up. Incremental EPS growth is more dependent on
higher refining margins, in our view.
Refining – not so bad after all
The strength in global oil demand, and strong 4Q CY2010 headline margins have
suddenly made our c.US$11/bbl RIL FY13 margin estimate within reach. Benchmark
margins, diesel cracks are up in 1Q CY2011 as well; current RIL refining run rates should
be healthier than the US$9/bbl reported last quarter.
Global oil demand may not grow approximately 2.8 mbd seen in CY2010 again. Even if
this halved in 2011, the headline refining spare capacity should fall. While we count oil
barrels, stronger global demand for diesel would imply refiners operate with lower effective
spare capacity – diesel cracks can increase faster. The consequent widening of the diesel
– fuel oil spread should help complex refiners more. This scenario is essentially a repeat
of the conditions that led to the recent margin spike. Yet, we note, that several refiners
have upgraded – there is more global complex refining capacity, oil demand can still be at
risk; and even on our base case, it will be at least another two-three years before the
headline refining utilisation rates reach previous peak.
Light – heavy crude oil spreads could widen some
more
Widening price differentials between light and heavy crudes benefit complex refiners like
Reliance. The Arab Light – Arab Heavy spreads have already more than doubled since the
bottom late 2009.
Significant amounts are being invested in global oil production capacity. New volumes at
Brazil, Iraq should help grow global oil production. The strength in near-term demand
though, means OPEC crude oil spare capacity can fall before increasing again. We
understand OPEC cut output of heavier crudes during the demand contraction – these
barrels should come back into the market as demand grows. This potential increase in
heavy oil supply can lead to a further widening of light – heavy crude spreads.
The potential for continued strength in 1) diesel cracks and 2) light – heavy crude oil
spreads should help maintain/grow RIL refining margins. As happened in 2010, strength in
winter heating demand can lead to spikes. Should hurricanes in the US Gulf become a
threat again, mid-year margins can also gain, in our view.
Petchem – ahead of itself?
RIL delivered its highest ever petrochemical EBIT in 3Q FY11. While volume growth (the
addition of 900 KTA of PP capacity with the RPL refinery, for e.g.) has helped earnings,
the recent increase in both polyester and polymer margins has improved cash flow as well.
For both businesses, expectations of further improvements in margins are beginning to set
in, which might be at risk near term, in our view.
Polyester margins at well above averages
The sharp increase in global cotton prices has helped improve profitability for the polyester
chain, despite raw material (crude price) pressures. Given low global inventories, cotton
prices may remain high near term. Polyester chain margins however, are more than 30%
above long-term average (see Figure 26); having spiked in 3Q FY11.
Cotton prices are up on supply issues (continuously falling acreage, on competition from
other cash crops), and a post recession demand surprise. The USDA expects a 15%
increase in global cotton production in 2010/11 over 2009/10. As per USDA estimates,
about 80% of the world’s cotton production is harvested by the end of February. If this
serves to ease the inventory situation, cotton prices could see a correction near term. The
current high prices can also attract farmers; harvests for 2011/12 can be higher.
If the strength in polyester lasts longer, new polyester capacity can potentially come up.
End product capacity for polyesters require relatively little capex and time. Polyester
margins should not sustain large increases hereon, we think.
Nameplate versus effective capacity utilisation
Global ethylene capacity is expected to grow 5% in 2011. Growth rates thereafter will slow
to an average of 2.3%, until 2014-15. If global demand growth averages 3-4% (in line with
global GDP growth estimates), ethylene utilisation rates should go up, taking margins with
them.
On nameplate, global ethylene utilisation rates are currently 84%, but margins we think,
are reflective of a tighter market. About 10 MTPA of global capacity has been offline,
higher than historical averages. High margins (and improving European refinery
utilisations) should cause a reasonable proportion of these capacities to come back online.
This, combined with the ramp up of recently commissioned (and a few to be
commissioned) Middle East capacity, will mean effective capacity growth is higher than
headline. Margins may remain range-bound, and depending on the timing of the capacity
ramp up, can be at risk to short-term declines as well.
With near-term concerns, we continue to forecast an 8% decline in RIL petchem EBITDA
in FY12 over FY11. RIL proposes to build 1) 2.3 MTPA of PTA, 2) 540 KTA of PET, 3) 360
KTA of PFY and 4) 1.4 MTPA of PX capacities over the next few years. This is in addition
to a 1.5 MTPA off gas cracker that is currently being deliberated, we understand.
Timelines, and capex numbers for these projects are as yet unavailable; RIL expects to
provide improved guidance soon. Our current model does not incorporate these projects.
Update model
We reduce total KG D6 FY12E gas volume estimates to 53 mmscmd (including 9
mmscmd from the MA oil field) and for FY13 to 70 mmscmd (including the MA field),
getting to 80 mmscmd (D1 and D3) by FY14. This still implies RIL begins fixing any
technical issues soon, and is able to get to 80 mmscmd from D1/D3 by end-2012/early-
2013. We also remove expectations of upside from the field, limiting peak production to 80
mmscmd and total production (over field life) to 13.9 TCF (in line with 13.8 TCF 2P
numbers published by Niko), versus our earlier expectations of about 17.6 TCF of total
production.
Given the Production Sharing Contract assures cost recovery, a loss in field value is
shared between the operators and the government. Our DCF value for D1/D3 falls from
Rs258 to Rs211/share; a large part driven by our reduction in total field recoverable
estimates, rather than the cut in near-term volumes.
We include Rs36/share for RIL’s US shale business, based on our models using
US$5.75/mmbtu gas price forecasts. We also delay commencement of volumes at NEC-
25 from FY13 to FY14, and mark-to-market near-term other income run rates.
Our FY12/13E EPS for RIL fall 10/12%. Our target price falls from Rs1,181 to Rs1,132.
Using global EV/EBITDA comps for RIL’s refining / petchem businesses, and putting in no
upside from new E&P discoveries, our SOTP for RIL would add up to Rs839/817 per
share for KG-D6 peak gas production capped at 60/50 mmscmd (including MA field).
KG D6 valuations affected by multiple variables
While lower gas output has clear implications on near-term earnings estimates, valuations
for the fields depend on multiple parameters, given the cost recovery nature of the
production sharing contract. Total capex, total recoverable reserves, gas prices, peak
production rates and the timing of peak production all matter.
Our earlier assumptions incorporated RIL ramping up relatively quickly, and recovering a
large portion of costs incurred upfront. This meant government profit shares kicked in
early, and increased steadily. Increase in gas prices post FY14 had a relatively modest
impact, as a portion of the gains went to the government as well. Upon lowering ramp up
profiles, government profit shares get pushed out. Leverage to gas price increases in
FY14 would be higher, if RIL is unable to ramp up output quickly. This impact, though is
non linear - much slower ramp up profiles reduce the total revenue stream as well; upside
on gas price increases therefore reduce.
We model total capex at D1/D3 at US$10.7 bn; still higher capex reduces our NAV
estimates.
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Looking for an answer
■ Uncertainty hurts near-term growth: Volume growth expectations at D6
oil/gas form a large part of RIL’s near-term EPS growth. Recent declines,
and a lack of company commentary/guidance has introduced risks to this
growth. In order to obtain better clarity, we spoke to several E&P experts to
discuss the potential technical issues at field, and likely volume growth path.
■ Should be fixable: Technical scenarios range from minor glitches that are
easily fixed to those with a more permanent impact on reserves and field
deliverability. However, given 1) a large proportion of D1/D3 wells seem
affected by lower flow rates, 2) RIL has had more than 6 months to study the
problem and has not really moved to fix it yet, and 3) that RIL/DGH still
maintains its long-term forecast of 80 mmscmd, we conclude that the trouble
with the D1/D3 gas fields relates to a field characteristic, and is not a
mechanical fault. Lower connectivity within the thin reservoir sands seems to
be the most likely cause. Getting to 80 mmscmd may still be possible, but
would require new field studies, and a higher number of wells. Getting
government approvals for the higher capex could become time consuming.
■ Commodity margins can help: We update our gas production forecasts,
reducing FY12E/13E D1/D3 output to 44/61 mmscmd, effecting (hopefully)
the last major cut to near-term earnings. Recent strength in refining means
RIL current GRM run rates may be higher than our US$9.4/bbl FY12E
forecast. Seasonality can cause some weakness near term, but margins can
surprise late 2011. Stronger commodity margins should help RIL stock;
increases in near-term gas volumes now present an Optionality, we think.
■ Valuations: Valuations for D1/D3 fall from Rs258 to Rs211; we reduce E&P
upsides Rs33/share and add Rs35/share to our SOTP for RIL’s US shale
business. FY12/13E EPS falls 10%/12% to Rs68/82. Our target price of
Rs1132 (from Rs1181) implies a 20% upside. Maintain OUTPERFORM.
Looking for an answer
A lack of clarity on falling D6 oil/gas volumes has created uncertainty on RIL’s EPS growth
expectations. In this note, we look at the potential technical problems at the field, and
using visible symptoms, pick the most likely scenario. While it may still be possible to
increase output to 80 mmscmd, near-term volumes could remain subdued. We effect
(hopefully) the last major cut to near-term earnings. Strength in refining margins,
especially into 2H FY12, can potentially lead to stock performance, in our view.
KG D6 – what now?
RIL has so far refused to comment on the reasons for the decline in oil/gas volumes at KG
D6, and has not provided any guidance. Yet, these are a significant part of near-term
earnings estimates and contribute much to growth expectations. We do the next best thing.
We have spoken to several E&P experts and have discussed potential technical issues
that could have led to declining volumes. Scenarios range from minor glitches that are
easily fixed, to those with a more permanent impact on reserves and field deliverability.
Using visible symptoms, we pick the most likely scenario. The D1/D3 gas fields seem to
have been affected by lower flow rates, potentially due to lower-than-modelled connectivity
of reservoir sands. Production rates of 80 mmscmd may still be achieved, but will likely
require re-design and more wells, implying higher capex. Depending on the extent of the
problem, total reserves estimates (gas that can be economically extracted) may or may
not see material change. The government will have to be brought on board any revised
development plan, which process can consume an undefined period of time by itself.
A knock-on effect on other E&P
Development of discovered reserves at the NEC 25 field is taking longer than expected,
perhaps due to ongoing differences with the government. RIL also has materially reduced
its rig fleet. Given more drilling will likely be needed at D1/D3, the two that it has now will
be unable to meet minimum work commitments on other acreage, in our view. Expected
earnings from new fields and potential upsides from new discoveries may take longer to
materialise. We reduce our exploration option valuation by Rs33/share. The US shale
business can potentially add material EBITDA – in 2015. Concerns on US gas prices,
service costs and output ramp up imply little excitement near term.
Rely on commodity margins near term?
With no support from E&P volumes, any growth in earnings will rely on commodity –
refining and petchem margins. Strength in global oil demand (and potentially faster diesel
demand growth), improving product cracks and widening light heavy crude oil spreads
now make our US$11/bbl FY13 forecast seem achievable (RIL delivered US$5.9/bbl in 3Q
FY10 and US$9.0/bbl in 3Q FY11). RIL is also currently operating at potentially its highest
petchem earnings run rate – driven by a surge in polyester margins and a bounce back in
polymer margins. Polyester chain margins are at risk to falling cotton prices. Polymer
margins could remain range bound as capacity currently shut globally comes back on line,
while new Middle East capacities ramp up. Incremental EPS growth is more dependent on
higher refining margins, in our view.
Update model
We reduce FY12/13 D6 volume estimates to 53/70 mmscmd (including output from the MA
field), and reduce total recoverable estimate from D1/D3 to 13.9 TCF from 17.7 TCF.
FY12-13E EPS fall 10-12%. Given the PSC for the block, our valuation for D6 falls by
Rs47/share. Adding Rs36/share for RIL’s US shale business, our SOTP falls from Rs1,181
to Rs1,132/share. Late-2011 strength in refining margins could lead to stock price upside.
Maintain OUTPERFORM.
KG D6 – what now?
The pendulum has swung 180 degrees. Within the first six months of field start, RIL
surprised estimates materially, rapidly increasing output to 60 mmscmd (even testing 80
mmscmd for a short period). Over the last six months, output at the marquee D1 and D3
gas fields have surprised again, by falling to c.45mmscmd levels, while the market was
extrapolating earlier strength.
Given the E&P business forms a large part of Reliance’s growth story, uncertainty on
volumes has increased the risks involved in investing in RIL stock. Volume declines have
deflated RIL’s near-term earnings growth story, which was perceived to be low risk. To
add to the uncertainty, RIL has neither provided an explanation for the decline, nor has
laid out future volume estimates.
With the objective of limiting the problem to one which can be logically addressed, we
ignore the conjecture that RIL has intentionally limited gas output (in order to obtain better
pricing, volume allocation etc.). Crude oil is freely priced, and we don’t see much that can
be gained by intentionally limiting crude production. That volumes at the MA oil field have
also fallen sharply indicate that there is some technical issue with the oil field at least.
Unfortunately, RIL does not seem likely to provide guidance/clarity on KG D6 volumes any
time soon. We do the next best thing. We have spoken with multiple experts in the E&P
business, and gathered their views on what could potentially be wrong with the field and
how that could be fixed.
Categorising potential technical issues
We are not E&P experts, and have likely not addressed a portion of technical issues with
the field. Yet, our conversations lend us to broadly categorise problems at the gas field
into two groups:
■ Trouble with facilities, and
■ Reservoir issues.
Trouble with facilities
This category represents mechanical issues that constrain the flow of gas within/post the
well bore.
RIL had anticipated issues with hydrate formation (crystallisation of the gas within
pipelines), and has reportedly installed one of the largest MEG systems in the world to
tackle the issue. In case the formation of hydrates within pipelines is reducing the flow, RIL
may need to increase the scale/scope of the MEG system and conduct a one-time clean
up of the pipelines.
RIL could also have issues with sand control – loose rock entering the well bore and
choking production underground. We understand RIL has installed sand control devices in
anticipation. If these have failed, RIL will need to re-enter the wells and replace the
devices with ones more suitable to the magnitude of the problem.
In general, issues with facilities represent difficulties with the design or operations of the
equipment installed at the field. These should be relatively easy to fix, and should involve
defined time and one-time cost. Getting to the earlier forecasted peak production of 80
mmscmd should not be difficult.
Reservoir issues
This category represents issues that reduce the flow of gas from within the reservoir to the
well bore.
We understand the gas within the D6 sands is expected to have material aquifer support,
i.e., the pressure of water below the gas is expected to help push the gas out. This could
have been overestimated, and may be leading to the gas flowing out at a lower rate. This
could be fixed by drilling more wells now, and through the life of the field. This should not
impact total gas recoverable, but would increase capex estimates over the life of the field.
Reservoir compaction: As natural gas trapped within the underground layers of rock is
produced, internal pressures fall. If the rock layer is unconsolidated (relatively loose), the
pressure of the rock (and in this case sea water) above may cause the gas bearing rock
layer to compress, constraining further gas flow. Compaction can turn out to be a major
issue, especially in a gas field. In order to maximise production over field life, the operator
must try to maintain pressure within the rock, while producing the gas. Water will have to
be injected into the rock as the gas is extracted. Doing this in deep water, to extract
relatively low value (EV/Boe) gas may not be economical. Large compaction will reduce
the total gas recoverable from the fields.
Connectivity of reservoir sands: We understand the D1 and D3 gas fields consist of
multiple channel/overbank sand systems, some of which, though gas bearing, are
relatively thin. Any field operator would hope that these individual gas bearing layers are
interconnected, allowing gas to flow between the layers and into a single well bore. This
inter-connectivity, however, is difficult to model, and does not show up well on seismic
data. It is possible that the multiple gas bearing sands within D1 and D3 are interspersed
by more impervious rock (like shale), and that gas does not flow well within these layers.
Fixing this issue will require more wells – to tap into unconnected pools of gas. This might
also imply that total recoverable is lower than estimated, as some of the standalone gas
pools may be too small to economically exploit.
Fixing reservoir issues will most likely need materially higher capex – through the drilling of
more wells. RIL may also choose plateau production rates lower than 80 mmscmd, on
optimisation of costs and reservoir life.
So which is it?
RIL, for one, isn’t telling. We look at field performance and RIL’s actions so far to make our
conclusions.
■ Upon start, gas production increased rapidly at D1/D3. RIL had 16 wells online early
2010, and was producing a stable 60 mmscmd until mid-2010 (with these 16 wells
having tested 80 mmscmd of production on 23 December 2009. In the first phase, the
plan was to sustain 80 mmscmd from 22 wells (averaging 3.6 mmscmd per well).
Initially, then the wells were delivering gas at rates better than expected, at about 3.75
mmscmd per well.
■ RIL has since connected 2 more wells in D1/D3. Gas output though, has fallen to c.45
mmscmd, or about 2.5 mmscmd per well. The loss in production is equivalent to the
output of 4 wells (at initial production rates). Yet, RIL reports all wells are online; none
have gone to zero. This means that a large proportion of the 18 wells have seen a
reduction in flow rates – that the problem is not localised. RIL suggests total field
output will remain flat near term, implying flow rates have stabilised; well performance
is not expected to deteriorate further.
■ More than 6 months have passed since output at D1/D3 started declining. RIL will by
now, have collected sufficient data at its wells and should have a fair idea about the
nature of the technical difficulty. In a conference call in November 2010, the company
continued to guide to 80 mmscmd peak production from D1/D3, and at the 3Q FY11
analyst meet, maintained that total in place volumes at the field have not been
questioned. This indicates RIL thinks any present technical problem at the field can be
fixed.
■ RIL has not yet filed a plan with the DGH (Directorate General of Hydrocarbons, the
upstream regulator in India) for any work / capex needed to fix the technical issues.
RIL is also not looking to increase its rig fleet near term. This might mean 1) RIL is still
in the process of evaluating the problem and designing the remedy. This would imply
material redesign and work is needed, or 2) RIL finds the current regulatory situation
unsuitable for filing a request for increased capex. RIL has reportedly complained
about red tapism at the DGH. The CAG is currently auditing capex already incurred at
KG D6, and is expected to file its report soon; filing a request for higher capex may not
go down too well. In either case, D1/D3 can take some time to get to 80 mmscmd of
production.
■ The DGH has reported in the media asserting that a section of the field, with 7.5 TCF
of gas in place has not yet been exploited, even though 20 of the 22 Phase I wells
have been drilled. We believe RIL is likely to have drilled initial wells in line with the
field development plan. If a large part of the field has not been drilled, then it is likely
that it was not supposed to be drilled initially, but was meant to help support plateau
production. This ‘spare capacity’, however, implies that RIL could still endeavour to
raise total output to 80 mmscmd if it so desired.
The most likely scenario …
a) Declining output at D1/D3 is led by disappointing reservoir performance. If there were
issues related to field facilities, RIL would have started measures to fix them and
would potentially have been clearer in providing guidance.
b) Lower flow rates are due to lower reservoir connectivity. Reservoir compaction should
not have led to such a large reduction in flow so soon.
c) RIL’s model for the field will have to be re-evaluated. To take total output to 80
mmscmd, new well locations will have to be identified and drilled.
d) This will require the filing of an amendment/addendum to the Field Development Plan
and will likely involve higher capex. Approvals for such revisions can consume
significant amounts of time.
… suggests D6 gas volume ramp up may take time
We reduce total KG D6 gas volume estimate to 53 mmscmd (including 9 mmscmd from
the MA oil field) and for FY13 to 70 mmscmd (including MA field), getting to 80 mmscmd
(D1 and D3) by FY14. We also remove expectations of upside, limiting peak production to
80 mmscmd and total production (over field life) to 13.9 TCF (in line with 13.8 TCF 2P
numbers published by Niko). We already model capex higher than estimated in the field
development plan, and leave those numbers unchanged.
While near-term EPS numbers see meaningful cuts as a result, asset valuations for D6
don’t fall as much. Capex recovery terms in the Production Sharing Contract impart some
stability to RIL’s total cash flow; any loss of revenue over field life is also shared between
the contractors (RIL and Niko) and the government of India. Our DCF-based NAV for
D1/D3 falls from Rs258 to Rs211.
Niko Resources, which has a 10% interest in KG D6, has also recently guided to flat gas
production volumes through FY12.
MA oil decline more worrying
Oil production at the MA field has been more volatile. 3Q FY11 output averaged close to
17 kbopd, below the 24 kbopd delivered in 1Q FY11, and the 40 kbopd expected run rate.
We understand the FPSO deployed at the field has a capacity to process 60 kbopd;
implying RIL was looking at upside to 40 kbopd, rather than the decline now occurring.
RIL, had a few quarters back, spoken of additional wells drilled, but not connected at MA.
There has been little update on these wells, especially given RIL now refuses to discuss
E&P details. Given oil production fell QoQ, it seems unlikely the new well(s) have been
connected. Production can therefore still go up as this happens. We keep our FY12E oil
production estimate at 30 kbopd.
Disturbingly, RIL has decided to produce gas from the MA field, rather than re-inject it
(which is typically done to maintain oil pressure). We note that RIL, was re-injecting the
gas initially. Optically, this might mean RIL has given up trying to maintain oil flow rates
and is happy with lower medium-term oil production. Over the life of the field, recovering
the oil will therefore likely involve more wells, and more water injection/other EOR
techniques. Costs can be higher than expected.
The D6 story may not be over yet
Up until a few years ago, the argument that RIL has exploited only a small part of the large
D6 block, and much upside is yet to be had was frequently made. The simile “a coffee cup
on a kitchen table” was used to illustrate the relatively small size of the current
development. Not much has changed since – RIL has made smaller discoveries around
D1/D3 and in deeper waters, and we understand, has additional identified prospects.
Given the long gestation of deep water E&P (especially gas bearing), it may be too early to
quantify and attribute material value, but the likelihoods of D6 having higher hydrocarbon
are still high. With government support, RIL can potentially keep working at the block for
some time to come.
Selling out for technical help?
Over the last few weeks, media reports have suggested RIL is about to sell a portion of its
D6 stake to either BP or Shell, in order to obtain technical assistance needed to fix the
field. We believe this will happen only after RIL’s technical vendors express their inability
A knock-on effect on other E&P
In our note Time for a Counsellor dated 31 January 2011, we highlighted increasing
differences between RIL and the upstream regulator – the Directorate General of
Hydrocarbons (DGH). RIL has reportedly written to the government referring to these
issues and expressing concern that its exploration and development activities do not
progress as a result.
Activities at NEC-25 have slowed down
Development of the NEC-25 field seems to have been affected by a slow pace of
approvals / co-ordination. This is a discovered field, for which RIL had filed the initial field
development plan in 2007. We understand the DGH had then asked RIL to conduct more
drilling / appraisal and to resubmit a modified plan.
However, appraisal drilling at NEC-25 has slowed since early FY11. RIL was supposed to
appraise the AJ area discovery by drilling three more wells – AJ10, AJ11 and AJ12. In a
media release, Niko (10% working interest in NEC-25) stated that the appraisal
programme was halted due to rig unavailability. There have also been differences between
RIL and the government. The cost recovery of two wells has been disallowed, whereas the
declaration of commerciality of the D-32 well has been contested.
RIL needs to – 1) complete the appraisal programme, 2) file a revised Field Development
Plan, 3) interact with the DGH to have the plan approved and 4) start building the facilities,
including coordination with the entity constructing the evacuation pipeline.
Depending on the scope of the project facilities, this can potentially take between 2-3
years. Our estimate of initial production in FY13 seems to be at risk; we move this now to
FY14. A one-year delay does not hurt the asset value much (we have Rs24 in the SOTP),
but FY13 EPS estimates are hurt by about Rs3.
Large blocks and well commitments, but no rigs?
RIL has 31 active blocks in India and 13 overseas, a large number of which are in deep
waters. Excitement around some of these blocks (especially the ones where RIL’s
partners have publicly spoken of large resource estimates) has underpinned an option
value for RIL’s E&P acreage. We view some of this as fair, especially as RIL will incur
large amounts of capex in exploration, which should over time generate return.
Using data from the DGH, we estimate RIL has 138 wells under minimum work
programmes for its blocks that it has not yet drilled; of which 116 are deep water well.
Given the recent rig moratorium and continuous revisions, it is difficult to estimate the
exact phasing of these commitments, but a majority are committed under NELP III. Even if
timelines for some of these have been extended, we think a large portion will need to be
drilled within the next 3-5 years. We estimate two rigs, drilling flat out would take about
seven years to drill 116 deep water wells. It is not necessary that RIL drills each of these
138 wells, though. It can potentially pay damages and relinquish blocks as well.
RIL, however, has significantly reduced its rig fleet, and currently has only two assets. In
addition to exploratory work, these rigs will also be needed to fix problems at KG D6, and
for any drilling in overseas acreage. Unless RIL were to now increase its rig count,
monetisation of the exploration upside can take longer than expected. We reduce our
valuation for RIL’s exploration option by Rs33/share and now value it at Rs53/share,
based on a capex driven model.
On paper, the US shale business adds up to a nice
number
Reliance has made substantial investments in US shale, and over time, would end up
investing large amounts in developing these assets. However, uncertainty over 1) US gas
prices, 2) drilling and service costs, and 3) ability of the JV’s to ramp up drilling and
production as forecasted has led to a muted reaction among investors, we believe.
However, going by well drilling forecasts, EBITDA from RIL’s US shale portfolio can
become a meaningful number in a few years. At US$5.75/mmbtu, we estimate the three
shale JV’s can generate EBITDA of about US$1.5 bn by 2015. Media reports suggests RIL
targets an EBITDA of US$15 bn by 2015. Contribution from shale would be a meaningful
portion of this target.
Given the large capex commitments, and the ramp in wells drilled number, RIL’s shale
business is likely to remain FCF negative for the first few years, returning cash only by
2015, we believe. P&L contribution can become positive earlier.
We include RIL’s US shale JV’s in our SOTP, at total valuation of US$2.5 bn (at a
US$5.75/mmbtu gas price assumption), representing about Rs36/share.
Rely on commodity margins near
term
With no support from E&P volumes, any growth in earnings will rely on commodity –
refining and petchem margins. Strength in global oil demand (and potentially faster diesel
demand growth), improving product cracks and widening light heavy crude oil spreads
now make our US$11/bbl FY13 forecast seem achievable (RIL delivered US$5.9/bbl in 3Q
FY10 and US$9.0/bbl in 3Q FY11). RIL is also currently operating at potentially its highest
petchem earnings run rate – driven by a surge in polyester margins and a bounce back in
polymer margins. Polyester chain margins are at risk to falling cotton prices. Polymer
margins can remain range bound as capacity currently shut in globally comes back on line,
while new Middle East capacities ramp up. Incremental EPS growth is more dependent on
higher refining margins, in our view.
Refining – not so bad after all
The strength in global oil demand, and strong 4Q CY2010 headline margins have
suddenly made our c.US$11/bbl RIL FY13 margin estimate within reach. Benchmark
margins, diesel cracks are up in 1Q CY2011 as well; current RIL refining run rates should
be healthier than the US$9/bbl reported last quarter.
Global oil demand may not grow approximately 2.8 mbd seen in CY2010 again. Even if
this halved in 2011, the headline refining spare capacity should fall. While we count oil
barrels, stronger global demand for diesel would imply refiners operate with lower effective
spare capacity – diesel cracks can increase faster. The consequent widening of the diesel
– fuel oil spread should help complex refiners more. This scenario is essentially a repeat
of the conditions that led to the recent margin spike. Yet, we note, that several refiners
have upgraded – there is more global complex refining capacity, oil demand can still be at
risk; and even on our base case, it will be at least another two-three years before the
headline refining utilisation rates reach previous peak.
Light – heavy crude oil spreads could widen some
more
Widening price differentials between light and heavy crudes benefit complex refiners like
Reliance. The Arab Light – Arab Heavy spreads have already more than doubled since the
bottom late 2009.
Significant amounts are being invested in global oil production capacity. New volumes at
Brazil, Iraq should help grow global oil production. The strength in near-term demand
though, means OPEC crude oil spare capacity can fall before increasing again. We
understand OPEC cut output of heavier crudes during the demand contraction – these
barrels should come back into the market as demand grows. This potential increase in
heavy oil supply can lead to a further widening of light – heavy crude spreads.
The potential for continued strength in 1) diesel cracks and 2) light – heavy crude oil
spreads should help maintain/grow RIL refining margins. As happened in 2010, strength in
winter heating demand can lead to spikes. Should hurricanes in the US Gulf become a
threat again, mid-year margins can also gain, in our view.
Petchem – ahead of itself?
RIL delivered its highest ever petrochemical EBIT in 3Q FY11. While volume growth (the
addition of 900 KTA of PP capacity with the RPL refinery, for e.g.) has helped earnings,
the recent increase in both polyester and polymer margins has improved cash flow as well.
For both businesses, expectations of further improvements in margins are beginning to set
in, which might be at risk near term, in our view.
Polyester margins at well above averages
The sharp increase in global cotton prices has helped improve profitability for the polyester
chain, despite raw material (crude price) pressures. Given low global inventories, cotton
prices may remain high near term. Polyester chain margins however, are more than 30%
above long-term average (see Figure 26); having spiked in 3Q FY11.
Cotton prices are up on supply issues (continuously falling acreage, on competition from
other cash crops), and a post recession demand surprise. The USDA expects a 15%
increase in global cotton production in 2010/11 over 2009/10. As per USDA estimates,
about 80% of the world’s cotton production is harvested by the end of February. If this
serves to ease the inventory situation, cotton prices could see a correction near term. The
current high prices can also attract farmers; harvests for 2011/12 can be higher.
If the strength in polyester lasts longer, new polyester capacity can potentially come up.
End product capacity for polyesters require relatively little capex and time. Polyester
margins should not sustain large increases hereon, we think.
Nameplate versus effective capacity utilisation
Global ethylene capacity is expected to grow 5% in 2011. Growth rates thereafter will slow
to an average of 2.3%, until 2014-15. If global demand growth averages 3-4% (in line with
global GDP growth estimates), ethylene utilisation rates should go up, taking margins with
them.
On nameplate, global ethylene utilisation rates are currently 84%, but margins we think,
are reflective of a tighter market. About 10 MTPA of global capacity has been offline,
higher than historical averages. High margins (and improving European refinery
utilisations) should cause a reasonable proportion of these capacities to come back online.
This, combined with the ramp up of recently commissioned (and a few to be
commissioned) Middle East capacity, will mean effective capacity growth is higher than
headline. Margins may remain range-bound, and depending on the timing of the capacity
ramp up, can be at risk to short-term declines as well.
With near-term concerns, we continue to forecast an 8% decline in RIL petchem EBITDA
in FY12 over FY11. RIL proposes to build 1) 2.3 MTPA of PTA, 2) 540 KTA of PET, 3) 360
KTA of PFY and 4) 1.4 MTPA of PX capacities over the next few years. This is in addition
to a 1.5 MTPA off gas cracker that is currently being deliberated, we understand.
Timelines, and capex numbers for these projects are as yet unavailable; RIL expects to
provide improved guidance soon. Our current model does not incorporate these projects.
Update model
We reduce total KG D6 FY12E gas volume estimates to 53 mmscmd (including 9
mmscmd from the MA oil field) and for FY13 to 70 mmscmd (including the MA field),
getting to 80 mmscmd (D1 and D3) by FY14. This still implies RIL begins fixing any
technical issues soon, and is able to get to 80 mmscmd from D1/D3 by end-2012/early-
2013. We also remove expectations of upside from the field, limiting peak production to 80
mmscmd and total production (over field life) to 13.9 TCF (in line with 13.8 TCF 2P
numbers published by Niko), versus our earlier expectations of about 17.6 TCF of total
production.
Given the Production Sharing Contract assures cost recovery, a loss in field value is
shared between the operators and the government. Our DCF value for D1/D3 falls from
Rs258 to Rs211/share; a large part driven by our reduction in total field recoverable
estimates, rather than the cut in near-term volumes.
We include Rs36/share for RIL’s US shale business, based on our models using
US$5.75/mmbtu gas price forecasts. We also delay commencement of volumes at NEC-
25 from FY13 to FY14, and mark-to-market near-term other income run rates.
Our FY12/13E EPS for RIL fall 10/12%. Our target price falls from Rs1,181 to Rs1,132.
upside from new E&P discoveries, our SOTP for RIL would add up to Rs839/817 per
share for KG-D6 peak gas production capped at 60/50 mmscmd (including MA field).
KG D6 valuations affected by multiple variables
While lower gas output has clear implications on near-term earnings estimates, valuations
for the fields depend on multiple parameters, given the cost recovery nature of the
production sharing contract. Total capex, total recoverable reserves, gas prices, peak
production rates and the timing of peak production all matter.
Our earlier assumptions incorporated RIL ramping up relatively quickly, and recovering a
large portion of costs incurred upfront. This meant government profit shares kicked in
early, and increased steadily. Increase in gas prices post FY14 had a relatively modest
impact, as a portion of the gains went to the government as well. Upon lowering ramp up
profiles, government profit shares get pushed out. Leverage to gas price increases in
FY14 would be higher, if RIL is unable to ramp up output quickly. This impact, though is
non linear - much slower ramp up profiles reduce the total revenue stream as well; upside
on gas price increases therefore reduce.
We model total capex at D1/D3 at US$10.7 bn; still higher capex reduces our NAV
estimates.
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