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Oil & Natural Gas Corp
In the value zone
Earnings valuation metrics are close to historical lows even after assuming a
worst case on Rajasthan royalties and a price cap of US$60/bbl on own domestic
crude. We retain our Rs325 TP (bonus/split adjusted) and upgrade from Hold to
Buy. Full royalty reimbursement would raise our valuation by Rs14.
Lowering our best-case assumption on royalties
We had earlier assumed that the Indian government (GOI) would fully reimburse ONGC the
excess royalties that it currently pays on the Rajasthan block (ONGC pays a 100% share
compared to its 30% stake). For our FY11-13F earnings estimates, given the delay in getting
this decision, we now assume status quo (ie, zero reimbursement). However, that
assumption leads to losses in subsequent years and hence, for the purposes of our DCF
valuation, we have assumed that GOI ensures that ONGC earns a reasonable project IRR
(we assume 15%, with a resultant valuation of US$1bn for Rajasthan).
Modelling price cap to factor in subsidy risk
To reflect market scepticism on upstream subsidy sharing, we cap oil realisations from
ONGCís own domestic crude at US$60/bbl for our EPS estimates (which we have been
doing in our DCF analysis in any case). Our FY11 EPS forecast increases 11% due to
receipt of gas pool arrears of Rs18.98bn in 3QFY11. With no further arrears assumed and
what we feel is a conservative assumption on price cap and Rajasthan royalties, our FY12F
and FY13F EPS falls 8-16%.
Upgrade to Hold, Rs325 TP
The lower assumption on royalty reimbursement has limited negative impact on our TP as
the reserves attributed by ONGC to the Rajasthan block implied a gross reserve base of just
340mm bbls compared to Cairn Indiaís estimate of gross recoverable reserves of 1154mm
bbls. We now value the Rajasthan block using Cairnís reserve estimate and our assumption
of a 15% project IRR. This results in a valuation of US$1bn (Rs5/share). This rises to
Rs19/share if full reimbursement is provided and falls to negative Rs4/share if the status quo
is maintained. On an earnings basis, the stock trades close to its historical low despite our
conservative assumptions on crude realisation, royalties and ONGCís conservative policy on
exploration write-offs
In the value zone
Absence of clarity on Rajasthan royalties and upstream subsidy sharing mechanism has
had a negative impact on ONGCís stock price performance. We believe the stock now
offers value even after discounting worst case scenarios on both issues.
Lowering our best-case assumption on royalty
Though ONGC owns a 30% stake in the Rajasthan block, which is a joint venture with Cairn India
(CIL), it is currently obliged to bear 100% of the royalty costs (non-cost recoverable). These costs
equate to 20% of the well-head oil price before royalties (16.67% of well-head oil price). The well
head oil price is the oil realisation of the operator after deductions for transportation expenses.
This deduction is as high as US$12/bbl in FY11 (as it is based on FY10 actual costs when the
pipeline was not operational) but would drop to US$3-5/bbl in subsequent years. Based on our
prevailing oil price assumption, we estimate that over the life of the field, ONGCís royalty
payments will aggregate to US$3.8bn if it has to pay only its share of 30%, or US$12.7bn if the
entire 100% share has to be paid.
As ONGC has taken a stake in the block as a representative of GOI, we had earlier believed that
the latter would reimburse ONGC for the royalties it pays on behalf of CIL. We estimate that over
the life of the field GOIís share of profit petroleum will be US$27bn and, hence, it will be in a
position to reimburse ONGC from its own share of profit petroleum. Full reimbursement would
result in ONGC earning a 46% IRR on the Rajasthan project, on our numbers.
However, the decision on royalty reimbursement is getting delayed. Our fear is that an immediate
decision from GOI may not materialise as we estimate that ONGC will continue to earn positive
EBITDA from the Rajasthan block over FY11-13F despite getting zero reimbursement. The
EBITDA contribution turns negative only post FY13, once the GOI profit petroleum rises to 40-
50%. So our earnings estimates over FY11-13F now assume the status quo, ie, ONGC continues
to pay 100% royalty on Rajasthan. If ,however, GOI provides full reimbursement, our EPS
estimates would rise by Rs0.9-2.4/share (3-7%).
ONGC is claiming that royalties are cost recoverable
In recent months, ONGC has stated that it believes that the royalty payments it makes are cost
recoverable as per the terms of the PSC. Oil production from the Rajasthan block started in
August 2009 and since then ONGC has been paying 100% of royalty payable and, initially at
least, not claiming cost recoverability. CIL is disputing ONGCís claim and this is likely to be a
highly legal matter, given that both parties have different interpretations of the same PSC.
If royalties are not cost recoverable (our current assumption), then the cost petroleum for the field
works out to US$20.4bn, resulting in profit petroleum of US$59.5bn. Cost petroleum is effectively
the revenues which are claimed by the JV partners to cover their cash spending.
We estimate GOIís share at US$26.8bn, leaving the rest for CIL/ONGC. Their respective shares
of cost petroleum and profit petroleum lead to their revenue entitlement at US$37.3bn for CIL and
US$15.7bn for ONGC. Comparing this revenue with their cash spending gives the cash inflow or
outflow over life of the field.
If royalties become cost recoverable, then the cost petroleum figure rises to that extent
(US$12.7bn), reducing the share of profit petroleum for all three parties concerned ñ GOI by
US$5.5bn, CIL by US$5bn and ONGC by US$2.2bn. However, since the entire rise in cost
petroleum goes to ONGC, its share of the revenues rises by US$10.6bn.
With higher revenue entitlement, the NPV of the Rajasthan block for ONGC would increase to
US$6.2bn over the life of the project, on our forecasts, or Rs33.3/share from US$1bn
(US$5/share). In the near term, it would positively impact our forecast earnings by 3-14% over
FY11-13F.
Modelling price cap to factor in subsidy risk
The higher the oil price, the higher the upstream subsidy risk
Historically, subsidy sharing by upstream companies has been 30-35% (average 33%), but this
policy is still ad hoc. The petroleum ministry indicated that in FY11 the upstream share would be
pegged at one-third of total under-recoveries, a formula implemented for the first three quarters of
FY11. Assuming an upstream subsidy of one third, ONGC benefits from rising global oil prices
(especially as domestic prices of regulated products rise). But, the one-third formula implicitly
assumes that GOI maintains 50-60% subsidy support, to which the finance ministry has been
unwilling to commit, increasing the risk of a higher upstream subsidy share. Historically, subsidy
sharing adjustments are done at year-end depending on likely profitability of the oil marketing
companies, and, hence, policy followed in first three quarters need not be continued in the fourth.
Global oil prices have started rising again and we have raised our Brent oil price forecasts by
US$1-5/bbl over FY11-13F. The higher the oil price, the higher the absolute level of GOI subsidy
As stated earlier, for the first three quarters, the upstream subsidy has been pegged at one-third
of total under-recoveries of the oil marketing companies. This has resulted in net realisation for
ONGC rising to US$62.8/bbl in 2QFY11 and US$64.8/bbl in 3QFY11, clearly indicating the upside
to oil realisations and earnings if the one-third mechanism is scrupulously followed. The higher
realisations in 2Q and 3Q have also been driven by price hikes in regulated retail products (diesel,
kerosene, LPG and kerosene) in June 2010, which increased the break-even level of oil price for
each of these products.
Assuming a continuation of the one-third subsidy mechanism, we expect ONGCís net realisations
to rise above US$60/bbl in FY12/13, based on our assumptions on gross realisations
(US$88.8/89.1/bbl) which are quite close to the actual gross realisation for 3QFY11.
However, to reflect the risk of higher subsidies, we now cap the oil realisation from ONGCís own
domestic crude at US$60/bbl in our FY12/13 EPS forecasts. Every US$1/bbl rise in net oil
realisation increases our EPS forecasts by 1.7% for FY12 and 1.8% for FY13.
EPS estimates now assume worst case on subsidy and royalties
Our EPS estimates have risen 11% for FY11F and have fallen 8-16% for FY12-13F. The negative
impact of assuming a zero royalty reimbursement has been partially offset by gas pool arrears
received in 3QFY11 (Rs18.98bn). GAIL continues to operate the gas pool and has been directed
by GOI to pay the excess generated in the pool at the end of the financial year to upstream gas
producers like ONGC. In the absence of any clarity on this issue, we have not assumed any gas
pool inflows in FY12 and FY13.
Production performance from ONGCís own fields has been disappointing historically with the
company missing its own guidance.
For FY12, our production forecasts from own fields are 24.77mt for oil and 23.54bcm for gas, in
line with company guidance and flat yoy. However for FY13, we have assumed oil production of
26mt and gas production of 23.54bcm, which is below company guidance, given the historical
disappointments.
As explained above, our EPS estimates for FY11-13F assume that ONGC bears 100% royalty on
Rajasthan block and that its own crude realisations are capped at US$60/bbl.
E&P accounting policy just too stringent
ONGC follows the successful efforts method of accounting whereby it expenses the cost of
surveys and dry wells in the year in which they are incurred. Hence, the higher the exploration
spend, the higher the negative P&L impact, which would not capture any positive impact from
successful wells. The negative impact of dry wells has been significant in recent years due to the
commencement of deep-water and ultra-deep-water drilling, where costs per well are quite high.
Relative to international standards, ONGCís accounting policy appears particularly stringent. As
per ONGC, even if the well is successful (ie, hydrocarbon bearing) it will have to be capped if it
was not intended to be a development well; and even in this instance it is fully written off.
Unfortunately, ONGC cannot provide exact figures on successful wells which are being written off,
but this stringent policy does focus on the need to look at EBITDAX (earnings before interest,
DD&A, tax and exploration expenses). As shown in table below, we expect ONGCís EBITDAX to
rise over FY11-13F, despite the conservative assumptions on royalty and crude realisations. The
lower earnings in FY12/13 are on account of absence of gas pool arrears and higher exploration
expenses.
Upgrade to Buy, Rs325 TP
Separate valuation for Rajasthan block
Our earlier DCF valuation of ONGCís domestic reserves assumed full reimbursement from GOI
on Rajasthan royalties. But the reserves attributed by ONGC to the Rajasthan block look very
conservative (14mmt for its 30% stake). This implies a gross reserve base of just 340mm bbls for
the block compared to CILís estimate of gross recoverable reserves of 1,154mm bbls (which we
use to value CIL).
We have now valued the Rajasthan block separately using CILís estimate of reserves. Based on
our oil price view, the valuation of the block for ONGC works out to US$3.6bn (Rs19/share)
assuming full royalty reimbursement and a negative US$0.8bn (minus Rs4/share) for zero
reimbursement. Both these scenarios are extreme and unlikely in our view. For the purposes of
valuation, we have assumed that GOI reimbursement aims at ONGC achieving a reasonable
return on its investment, which we have defined at 15% post tax. On that basis, the valuation for
the block works out to US$1bn or Rs5/share. To achieve this level of return, ONGC would need to
effectively pay 71.4% of the royalty burden on our numbers (ie GOI would need to reimburse
28.6%).
For the purpose of our DCF valuation of ONGCís balance domestic reserves, we have maintained
a cap ONGCís net realisations on crude sold from its nomination blocks at US$60/bbl. Every
US$1/bbl increase in this net oil realisation increases our DCF valuation and hence would
increase our target price by Rs2/share.
Our cautious view on subsidies/net realisation for the purpose of valuation is also guided by the
fact that the subsidy payments are a form of tax that ONGC has to pay, as it does not pay any
profit petroleum on the main oil fields. In the event that the subsidy payments drop to zero (say,
due to auto fuel pricing deregulation), we would expect GOI to raise taxes to curb super
profitability. It might be too optimistic to assume that any positive move to lower upstream subsidy
would immediately lead to higher profitability for ONGC.
The net result is that our target price is unchanged at Rs325/share, despite a more negative view
on royalty reimbursement. Note that our target price has been adjusted for a stock split (two
shares at Rs5 each in place of 1 share of Rs10) and a 1:1 bonus issue. It was Rs1,300 before the
adjustment
Near-historic low on PER basis
ONGCís stock price movement has been related more to views on GOIís regulatory changes
rather than the global oil prices. Valuations tend to rise during periods of optimism on GOI
regulation and vice versa. The historical PER band chart indicates that 9x 12-month rolling
forward PE is close to the bottom of ONGCís trading band in the last five to six years. On that
basis, the stock is already close to the bottom despite our conservative assumptions on royalty
and price cap on crude used to calculate our EPS.
India Equity Research Reports, IPO and Stock News
Visit http://indiaer.blogspot.com/ for complete details �� ��
Oil & Natural Gas Corp
In the value zone
Earnings valuation metrics are close to historical lows even after assuming a
worst case on Rajasthan royalties and a price cap of US$60/bbl on own domestic
crude. We retain our Rs325 TP (bonus/split adjusted) and upgrade from Hold to
Buy. Full royalty reimbursement would raise our valuation by Rs14.
Lowering our best-case assumption on royalties
We had earlier assumed that the Indian government (GOI) would fully reimburse ONGC the
excess royalties that it currently pays on the Rajasthan block (ONGC pays a 100% share
compared to its 30% stake). For our FY11-13F earnings estimates, given the delay in getting
this decision, we now assume status quo (ie, zero reimbursement). However, that
assumption leads to losses in subsequent years and hence, for the purposes of our DCF
valuation, we have assumed that GOI ensures that ONGC earns a reasonable project IRR
(we assume 15%, with a resultant valuation of US$1bn for Rajasthan).
Modelling price cap to factor in subsidy risk
To reflect market scepticism on upstream subsidy sharing, we cap oil realisations from
ONGCís own domestic crude at US$60/bbl for our EPS estimates (which we have been
doing in our DCF analysis in any case). Our FY11 EPS forecast increases 11% due to
receipt of gas pool arrears of Rs18.98bn in 3QFY11. With no further arrears assumed and
what we feel is a conservative assumption on price cap and Rajasthan royalties, our FY12F
and FY13F EPS falls 8-16%.
Upgrade to Hold, Rs325 TP
The lower assumption on royalty reimbursement has limited negative impact on our TP as
the reserves attributed by ONGC to the Rajasthan block implied a gross reserve base of just
340mm bbls compared to Cairn Indiaís estimate of gross recoverable reserves of 1154mm
bbls. We now value the Rajasthan block using Cairnís reserve estimate and our assumption
of a 15% project IRR. This results in a valuation of US$1bn (Rs5/share). This rises to
Rs19/share if full reimbursement is provided and falls to negative Rs4/share if the status quo
is maintained. On an earnings basis, the stock trades close to its historical low despite our
conservative assumptions on crude realisation, royalties and ONGCís conservative policy on
exploration write-offs
In the value zone
Absence of clarity on Rajasthan royalties and upstream subsidy sharing mechanism has
had a negative impact on ONGCís stock price performance. We believe the stock now
offers value even after discounting worst case scenarios on both issues.
Lowering our best-case assumption on royalty
Though ONGC owns a 30% stake in the Rajasthan block, which is a joint venture with Cairn India
(CIL), it is currently obliged to bear 100% of the royalty costs (non-cost recoverable). These costs
equate to 20% of the well-head oil price before royalties (16.67% of well-head oil price). The well
head oil price is the oil realisation of the operator after deductions for transportation expenses.
This deduction is as high as US$12/bbl in FY11 (as it is based on FY10 actual costs when the
pipeline was not operational) but would drop to US$3-5/bbl in subsequent years. Based on our
prevailing oil price assumption, we estimate that over the life of the field, ONGCís royalty
payments will aggregate to US$3.8bn if it has to pay only its share of 30%, or US$12.7bn if the
entire 100% share has to be paid.
As ONGC has taken a stake in the block as a representative of GOI, we had earlier believed that
the latter would reimburse ONGC for the royalties it pays on behalf of CIL. We estimate that over
the life of the field GOIís share of profit petroleum will be US$27bn and, hence, it will be in a
position to reimburse ONGC from its own share of profit petroleum. Full reimbursement would
result in ONGC earning a 46% IRR on the Rajasthan project, on our numbers.
However, the decision on royalty reimbursement is getting delayed. Our fear is that an immediate
decision from GOI may not materialise as we estimate that ONGC will continue to earn positive
EBITDA from the Rajasthan block over FY11-13F despite getting zero reimbursement. The
EBITDA contribution turns negative only post FY13, once the GOI profit petroleum rises to 40-
50%. So our earnings estimates over FY11-13F now assume the status quo, ie, ONGC continues
to pay 100% royalty on Rajasthan. If ,however, GOI provides full reimbursement, our EPS
estimates would rise by Rs0.9-2.4/share (3-7%).
ONGC is claiming that royalties are cost recoverable
In recent months, ONGC has stated that it believes that the royalty payments it makes are cost
recoverable as per the terms of the PSC. Oil production from the Rajasthan block started in
August 2009 and since then ONGC has been paying 100% of royalty payable and, initially at
least, not claiming cost recoverability. CIL is disputing ONGCís claim and this is likely to be a
highly legal matter, given that both parties have different interpretations of the same PSC.
If royalties are not cost recoverable (our current assumption), then the cost petroleum for the field
works out to US$20.4bn, resulting in profit petroleum of US$59.5bn. Cost petroleum is effectively
the revenues which are claimed by the JV partners to cover their cash spending.
We estimate GOIís share at US$26.8bn, leaving the rest for CIL/ONGC. Their respective shares
of cost petroleum and profit petroleum lead to their revenue entitlement at US$37.3bn for CIL and
US$15.7bn for ONGC. Comparing this revenue with their cash spending gives the cash inflow or
outflow over life of the field.
If royalties become cost recoverable, then the cost petroleum figure rises to that extent
(US$12.7bn), reducing the share of profit petroleum for all three parties concerned ñ GOI by
US$5.5bn, CIL by US$5bn and ONGC by US$2.2bn. However, since the entire rise in cost
petroleum goes to ONGC, its share of the revenues rises by US$10.6bn.
With higher revenue entitlement, the NPV of the Rajasthan block for ONGC would increase to
US$6.2bn over the life of the project, on our forecasts, or Rs33.3/share from US$1bn
(US$5/share). In the near term, it would positively impact our forecast earnings by 3-14% over
FY11-13F.
Modelling price cap to factor in subsidy risk
The higher the oil price, the higher the upstream subsidy risk
Historically, subsidy sharing by upstream companies has been 30-35% (average 33%), but this
policy is still ad hoc. The petroleum ministry indicated that in FY11 the upstream share would be
pegged at one-third of total under-recoveries, a formula implemented for the first three quarters of
FY11. Assuming an upstream subsidy of one third, ONGC benefits from rising global oil prices
(especially as domestic prices of regulated products rise). But, the one-third formula implicitly
assumes that GOI maintains 50-60% subsidy support, to which the finance ministry has been
unwilling to commit, increasing the risk of a higher upstream subsidy share. Historically, subsidy
sharing adjustments are done at year-end depending on likely profitability of the oil marketing
companies, and, hence, policy followed in first three quarters need not be continued in the fourth.
Global oil prices have started rising again and we have raised our Brent oil price forecasts by
US$1-5/bbl over FY11-13F. The higher the oil price, the higher the absolute level of GOI subsidy
As stated earlier, for the first three quarters, the upstream subsidy has been pegged at one-third
of total under-recoveries of the oil marketing companies. This has resulted in net realisation for
ONGC rising to US$62.8/bbl in 2QFY11 and US$64.8/bbl in 3QFY11, clearly indicating the upside
to oil realisations and earnings if the one-third mechanism is scrupulously followed. The higher
realisations in 2Q and 3Q have also been driven by price hikes in regulated retail products (diesel,
kerosene, LPG and kerosene) in June 2010, which increased the break-even level of oil price for
each of these products.
Assuming a continuation of the one-third subsidy mechanism, we expect ONGCís net realisations
to rise above US$60/bbl in FY12/13, based on our assumptions on gross realisations
(US$88.8/89.1/bbl) which are quite close to the actual gross realisation for 3QFY11.
However, to reflect the risk of higher subsidies, we now cap the oil realisation from ONGCís own
domestic crude at US$60/bbl in our FY12/13 EPS forecasts. Every US$1/bbl rise in net oil
realisation increases our EPS forecasts by 1.7% for FY12 and 1.8% for FY13.
EPS estimates now assume worst case on subsidy and royalties
Our EPS estimates have risen 11% for FY11F and have fallen 8-16% for FY12-13F. The negative
impact of assuming a zero royalty reimbursement has been partially offset by gas pool arrears
received in 3QFY11 (Rs18.98bn). GAIL continues to operate the gas pool and has been directed
by GOI to pay the excess generated in the pool at the end of the financial year to upstream gas
producers like ONGC. In the absence of any clarity on this issue, we have not assumed any gas
pool inflows in FY12 and FY13.
Production performance from ONGCís own fields has been disappointing historically with the
company missing its own guidance.
For FY12, our production forecasts from own fields are 24.77mt for oil and 23.54bcm for gas, in
line with company guidance and flat yoy. However for FY13, we have assumed oil production of
26mt and gas production of 23.54bcm, which is below company guidance, given the historical
disappointments.
As explained above, our EPS estimates for FY11-13F assume that ONGC bears 100% royalty on
Rajasthan block and that its own crude realisations are capped at US$60/bbl.
E&P accounting policy just too stringent
ONGC follows the successful efforts method of accounting whereby it expenses the cost of
surveys and dry wells in the year in which they are incurred. Hence, the higher the exploration
spend, the higher the negative P&L impact, which would not capture any positive impact from
successful wells. The negative impact of dry wells has been significant in recent years due to the
commencement of deep-water and ultra-deep-water drilling, where costs per well are quite high.
Relative to international standards, ONGCís accounting policy appears particularly stringent. As
per ONGC, even if the well is successful (ie, hydrocarbon bearing) it will have to be capped if it
was not intended to be a development well; and even in this instance it is fully written off.
Unfortunately, ONGC cannot provide exact figures on successful wells which are being written off,
but this stringent policy does focus on the need to look at EBITDAX (earnings before interest,
DD&A, tax and exploration expenses). As shown in table below, we expect ONGCís EBITDAX to
rise over FY11-13F, despite the conservative assumptions on royalty and crude realisations. The
lower earnings in FY12/13 are on account of absence of gas pool arrears and higher exploration
expenses.
Upgrade to Buy, Rs325 TP
Separate valuation for Rajasthan block
Our earlier DCF valuation of ONGCís domestic reserves assumed full reimbursement from GOI
on Rajasthan royalties. But the reserves attributed by ONGC to the Rajasthan block look very
conservative (14mmt for its 30% stake). This implies a gross reserve base of just 340mm bbls for
the block compared to CILís estimate of gross recoverable reserves of 1,154mm bbls (which we
use to value CIL).
We have now valued the Rajasthan block separately using CILís estimate of reserves. Based on
our oil price view, the valuation of the block for ONGC works out to US$3.6bn (Rs19/share)
assuming full royalty reimbursement and a negative US$0.8bn (minus Rs4/share) for zero
reimbursement. Both these scenarios are extreme and unlikely in our view. For the purposes of
valuation, we have assumed that GOI reimbursement aims at ONGC achieving a reasonable
return on its investment, which we have defined at 15% post tax. On that basis, the valuation for
the block works out to US$1bn or Rs5/share. To achieve this level of return, ONGC would need to
effectively pay 71.4% of the royalty burden on our numbers (ie GOI would need to reimburse
28.6%).
For the purpose of our DCF valuation of ONGCís balance domestic reserves, we have maintained
a cap ONGCís net realisations on crude sold from its nomination blocks at US$60/bbl. Every
US$1/bbl increase in this net oil realisation increases our DCF valuation and hence would
increase our target price by Rs2/share.
Our cautious view on subsidies/net realisation for the purpose of valuation is also guided by the
fact that the subsidy payments are a form of tax that ONGC has to pay, as it does not pay any
profit petroleum on the main oil fields. In the event that the subsidy payments drop to zero (say,
due to auto fuel pricing deregulation), we would expect GOI to raise taxes to curb super
profitability. It might be too optimistic to assume that any positive move to lower upstream subsidy
would immediately lead to higher profitability for ONGC.
The net result is that our target price is unchanged at Rs325/share, despite a more negative view
on royalty reimbursement. Note that our target price has been adjusted for a stock split (two
shares at Rs5 each in place of 1 share of Rs10) and a 1:1 bonus issue. It was Rs1,300 before the
adjustment
Near-historic low on PER basis
ONGCís stock price movement has been related more to views on GOIís regulatory changes
rather than the global oil prices. Valuations tend to rise during periods of optimism on GOI
regulation and vice versa. The historical PER band chart indicates that 9x 12-month rolling
forward PE is close to the bottom of ONGCís trading band in the last five to six years. On that
basis, the stock is already close to the bottom despite our conservative assumptions on royalty
and price cap on crude used to calculate our EPS.
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