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Oil & Natural Gas Corporation (ONGC)
Energy
Why wait for something good? We take comfort in (1) strong working results of July
2011 estimated by the management on a provisional basis and (2) audited reserves
disclosed in ONGC’s DRHP for the upcoming FPO (5% disinvestment by the
Government). We reiterate our BUY rating on ONGC stock given (1) attractive
valuations at 7.1X FY2012E EPS and (2) 45% potential upside to our 12-month target
price of `380 based on 9X FY2013E estimates.
Results: Strong earnings in July 2011 reflect lower subsidies from policy reforms
As per the DRHP, ONGC has estimated standalone profit of `70 bn for the April-July 2011 period
versus reported profit of `41 bn for April-June 2011 (1QFY12). The sharp jump in earnings for July
2011 versus monthly run-rate of 1QFY12 despite similar levels of crude oil price reflects (1) lower
subsidy burden due to decline in gross under-recoveries from price hikes and tax cuts and (2) lower
DD&A cost due to lower exploration activities during monsoons. Exhibit 1 compares the results for
April-July 2011 with reported results for 1QFY12 and our estimates for FY2012E.
Reserves: Certified 2P reserves of 7.5 bn boe from own fields and 2.9 bn boe from overseas blocks
We expect ONGC’s reserves estimates based on audits by independent consultants to allay any
potential concerns about ONGC’s long-term production. Exhibit 3 compares ONGC’s estimates of
reserves with audited estimates. In fact, the independent auditor’s estimates of 2P and 3P
estimates of oil reserves for Mumbai High are significantly higher versus management estimates.
2P estimates for oil are higher by 95 mn tons, a sizeable figure in the context of 1P reserves of 120
mn tons. We highlight that ONGC’s consolidated (including JVs and OVL) 2P reserves have
increased steadily over the past three years to 1.4 bn tons or 10.4 bn boe (see Exhibit 4).
Risks: Attractive valuations in most scenarios
We estimate FY2012E standalone EPS at `26 even if the government was to cap net realization at
FY2011 level of US$53.8/bbl and consolidated EPS at `33.7 including `7.2 from OVL and `0.6
from MRPL. This implies 45% subsidy sharing by upstream companies for FY2012E versus 38.7%
in FY2011. We compute 12-month fair valuation at `315 and valuation at 7.8X FY2012E EPS in
this scenario.
Returns: FY2012E consolidated EPS of `37 is achievable despite conservative assumptions
We estimate ONGC’s FY2012E consolidated EPS at `37 versus `25 in FY2011. The yoy increase
reflects (1) higher net crude price realization (`3.5), (2) higher gas price for full year (`1), (3) costrecoverability
of royalty in Cairn’s Rajasthan block (`2), (4) higher production from Cairn’s
Rajasthan block (`1.5) and (5) higher net income from OVL (`3.4). We see low risks to our
estimate in light of our conservative assumptions of (1) subsidy share of upstream companies at
39% of gross under-recoveries and (2) lower yoy oil and gas sales from own domestic fields.
Likely strong results in 2QFY12E
ONGC has estimated provisional standalone net profits for April-July 2011 at `70 bn versus
reported profit of `41 bn in 1QFY12. We would clarify that these are “working results”
estimated by the management based on “provisional rates for under-recoveries for the
purpose of settling invoices for crude oil supplies to the oil marketing companies” decided
by the Ministry of Petroleum and Natural Gas (MoPNG) for 2QFY12 and have not been
audited by ONGC’s auditors. The final subsidy amount could be very different from the
provisional rates notified by the MoPNG and more important, the final subsidy-sharing
system for FY2012E would be decided only at the time of 4QFY12E results. We would refer
readers to page 422 of the ONGC DRHP for more details on this issue.
Nonetheless, we would note that the subsidy amount for 2QFY12E would be significantly
lower than 1QFY12 due to (1) price increases on diesel, kerosene and LPG and (2) excise tax
reduction on diesel and customs duty cuts on crude oil, diesel and gasoline implemented by
the government on June 24, 2012. As can be seen in Exhibit 2, overall gross underrecoveries
in July 2011 was `73 bn compared to `435 bn in 1QFY12. Average Dated Brent
crude oil price was US$114/bbl in July 2011 compared to US$117/bbl in 1QFY12
Details of ONGC’s reserves
We provide below details of ONGC’s estimates and compare the same with the reserves
estimates of DeGolyer & MacNaughton (D&M), Gaffney Cline & Associates (GCA) and
Sproule. We also explain the variation between the two estimates as provided by the
management.
Mumbai High. ONGC’s estimates of 1P, 2P and 3P oil and natural gas reserves for
Mumbai High field are 166 mn tons, 190 mn tons and 259 mn tons versus GCA’s audited
estimates of 169 mn tons, 280 mn tons and 346 mn tons. GCA’s estimates for 2P and 3P
reserves are significantly higher as it has considered long-term development plan
including aggressive water injection, which would enhance the life of the field and result
into higher recovery rate. However, ONGC has determined its own estimates based on
existing development plan scheduled to complete by end-FY2012.
Other fields. ONGC’s estimates of 1P, 2P and 3P reserves for 62 other fields are 459 mn
tons, 622 mn tons and 719 mn tons versus D&M’s audited estimates of 431 mn tons,
596 mn tons and 734 mn tons. D&M’s estimates for 1P and 2P reserves are lower than
ONGC’s estimates due to expected delays in implementation of company’s development
plans for ageing fields in Assam. However, ONGC is currently implementing three
IOR/EOR projects in Assam at an investment of `27.8 bn and has justified its higher
estimates on the same ground.
Sakhalin-1. OVL’s estimates of 1P, 2P and 3P reserves for Sakhalin-1 field are 107 mn
tons, 140 mn tons and 140 mn tons versus D&M’s audited estimates of 50 mn tons, 98
mn tons and 141 mn tons. D&M’s estimates for 1P and 2P reserves are lower than OVL’s
estimates as (1) OVL has prepared estimates in accordance with Russian reserves
estimation methods as opposed to the more conservative SPE-PRMS 2007 classification
used by D&M, (2) OVL has assumed contract extensions until 2054 versus D&M’s
production forecasts till 2031 and (3) OVL has assumed additional recoverable volumes
that maybe economically feasible from future contracts and extensions given investments
to be undertaken to develop supporting gas infrastructure.
Imperial Energy assets. OVL’s estimates of 1P, 2P and 3P reserves for Imperial Energy
assets are 22 mn tons, 111 mn tons and 111 mn tons versus D&M’s audited estimates of
19 mn tons, 111 mn tons and 383 mn tons. OVL’s estimates for 3P reserves are lower as
it has not undertaken a full evaluation and approval of certain 3P reserves included in
D&M’s estimates.
Sudan. OVL’s estimates of 1P, 2P and 3P reserves for blocks in Sudan are 23 mn tons, 28
mn tons and 38 mn tons versus Sproule’s audited estimates of 16 mn tons, 21 mn tons
and 25 mn tons. Sproule’s estimates are lower than OVL’s estimates as Sproule has
excluded certain discovered recoverable resources due to economic, political or
technological reasons.
Block A1 and A3, Myanmar. OVL’s estimates of 1P, 2P and 3P reserves for Myanmar
blocks are 10 mn tons, 22 mn tons and 37 mn tons versus D&M’s audited estimates of 10
mn tons, 19 mn tons and 29 mn tons. D&M’s estimates for 2P and 3P reserves are lower
than OVL’s estimates due to a difference in reservoir mapping interpretation and petrophysical
parameters used to estimate initial gas volumes.
OVL’s FY2012E EPS of `7 is plausible
Our FY2012E EPS estimate of `7.2 for OVL (versus `3.8 in FY2011) looks reasonable given
reported EPS of `1.7 in 1QFY12. We are conservative in our assumptions as we model (1)
modest increase of 3.6% in OVL’s oil and gas production to 9.5 mn tons in FY2012E versus
9.2 mn tons in FY2011, (2) US$110/bbl of crude oil price and (3) rupee-dollar exchange rate
of `44.75/US$ in FY2012E.
Several positive triggers in the medium term
We discuss some of the potential triggers below but caution that some of these triggers may
materialize over the next 2-5 years. However, it would be prudent to be aware of these
triggers while determining the multiple to be ascribed in arriving at a fair valuation of the
stock.
Favorable subsidy arrangement. Exhibit 5 gives our scenario analysis of the likely
earnings of ONGC at different levels of subsidy burden. In our base-case numbers for
FY2012E and FY2013E, we assume the share of upstream companies at 39%. We note
that the upstream companies have provisionally borne 33.33% share of gross underrecoveries
in 1HFY12.
Increase in natural gas prices. We assume natural gas price at US$4.2/mn BTU over our
forecast period. However, we assume gas prices for RIL’s KG D-6 gas to increase to
US$5.5/mn BTU from FY2015E. We expect APM gas prices to be increased accordingly.
We compute a positive impact of `3/share on ONGC’s EPS if ONGC’s gas price was to be
increased to US$5.5/mn BTU from US$4.2/mn BTU.
Higher oil and gas volumes versus current assumptions. We highlight that ONGC
management has given operational targets of (1) 28 mn tons of crude oil production by
FY2014E versus 24.4 mn tons in FY2011 and (2) 72 mcm/d of gas production by FY2014E
and 100 mcm/d by FY2016E versus 63.3 mcm/d in FY2011. However, we assume a
modest increase of 0.4 mn tons of oil sales volume and 1.5 mcm/d of gas sales volumes
by FY2014E. Thus, we do not rule out upside to our estimates. We note that ONGC has
undertaken 10 major projects for development of new fields and one project for
additional development of D-1 field, which should bolster gas production from its fields.
Exhibit 6 gives the list of these fields, which are expected to be commissioned by FY2014E.
India Equity Research Reports, IPO and Stock News
Visit http://indiaer.blogspot.com/ for complete details �� ��
Oil & Natural Gas Corporation (ONGC)
Energy
Why wait for something good? We take comfort in (1) strong working results of July
2011 estimated by the management on a provisional basis and (2) audited reserves
disclosed in ONGC’s DRHP for the upcoming FPO (5% disinvestment by the
Government). We reiterate our BUY rating on ONGC stock given (1) attractive
valuations at 7.1X FY2012E EPS and (2) 45% potential upside to our 12-month target
price of `380 based on 9X FY2013E estimates.
Results: Strong earnings in July 2011 reflect lower subsidies from policy reforms
As per the DRHP, ONGC has estimated standalone profit of `70 bn for the April-July 2011 period
versus reported profit of `41 bn for April-June 2011 (1QFY12). The sharp jump in earnings for July
2011 versus monthly run-rate of 1QFY12 despite similar levels of crude oil price reflects (1) lower
subsidy burden due to decline in gross under-recoveries from price hikes and tax cuts and (2) lower
DD&A cost due to lower exploration activities during monsoons. Exhibit 1 compares the results for
April-July 2011 with reported results for 1QFY12 and our estimates for FY2012E.
Reserves: Certified 2P reserves of 7.5 bn boe from own fields and 2.9 bn boe from overseas blocks
We expect ONGC’s reserves estimates based on audits by independent consultants to allay any
potential concerns about ONGC’s long-term production. Exhibit 3 compares ONGC’s estimates of
reserves with audited estimates. In fact, the independent auditor’s estimates of 2P and 3P
estimates of oil reserves for Mumbai High are significantly higher versus management estimates.
2P estimates for oil are higher by 95 mn tons, a sizeable figure in the context of 1P reserves of 120
mn tons. We highlight that ONGC’s consolidated (including JVs and OVL) 2P reserves have
increased steadily over the past three years to 1.4 bn tons or 10.4 bn boe (see Exhibit 4).
Risks: Attractive valuations in most scenarios
We estimate FY2012E standalone EPS at `26 even if the government was to cap net realization at
FY2011 level of US$53.8/bbl and consolidated EPS at `33.7 including `7.2 from OVL and `0.6
from MRPL. This implies 45% subsidy sharing by upstream companies for FY2012E versus 38.7%
in FY2011. We compute 12-month fair valuation at `315 and valuation at 7.8X FY2012E EPS in
this scenario.
Returns: FY2012E consolidated EPS of `37 is achievable despite conservative assumptions
We estimate ONGC’s FY2012E consolidated EPS at `37 versus `25 in FY2011. The yoy increase
reflects (1) higher net crude price realization (`3.5), (2) higher gas price for full year (`1), (3) costrecoverability
of royalty in Cairn’s Rajasthan block (`2), (4) higher production from Cairn’s
Rajasthan block (`1.5) and (5) higher net income from OVL (`3.4). We see low risks to our
estimate in light of our conservative assumptions of (1) subsidy share of upstream companies at
39% of gross under-recoveries and (2) lower yoy oil and gas sales from own domestic fields.
Likely strong results in 2QFY12E
ONGC has estimated provisional standalone net profits for April-July 2011 at `70 bn versus
reported profit of `41 bn in 1QFY12. We would clarify that these are “working results”
estimated by the management based on “provisional rates for under-recoveries for the
purpose of settling invoices for crude oil supplies to the oil marketing companies” decided
by the Ministry of Petroleum and Natural Gas (MoPNG) for 2QFY12 and have not been
audited by ONGC’s auditors. The final subsidy amount could be very different from the
provisional rates notified by the MoPNG and more important, the final subsidy-sharing
system for FY2012E would be decided only at the time of 4QFY12E results. We would refer
readers to page 422 of the ONGC DRHP for more details on this issue.
Nonetheless, we would note that the subsidy amount for 2QFY12E would be significantly
lower than 1QFY12 due to (1) price increases on diesel, kerosene and LPG and (2) excise tax
reduction on diesel and customs duty cuts on crude oil, diesel and gasoline implemented by
the government on June 24, 2012. As can be seen in Exhibit 2, overall gross underrecoveries
in July 2011 was `73 bn compared to `435 bn in 1QFY12. Average Dated Brent
crude oil price was US$114/bbl in July 2011 compared to US$117/bbl in 1QFY12
Details of ONGC’s reserves
We provide below details of ONGC’s estimates and compare the same with the reserves
estimates of DeGolyer & MacNaughton (D&M), Gaffney Cline & Associates (GCA) and
Sproule. We also explain the variation between the two estimates as provided by the
management.
Mumbai High. ONGC’s estimates of 1P, 2P and 3P oil and natural gas reserves for
Mumbai High field are 166 mn tons, 190 mn tons and 259 mn tons versus GCA’s audited
estimates of 169 mn tons, 280 mn tons and 346 mn tons. GCA’s estimates for 2P and 3P
reserves are significantly higher as it has considered long-term development plan
including aggressive water injection, which would enhance the life of the field and result
into higher recovery rate. However, ONGC has determined its own estimates based on
existing development plan scheduled to complete by end-FY2012.
Other fields. ONGC’s estimates of 1P, 2P and 3P reserves for 62 other fields are 459 mn
tons, 622 mn tons and 719 mn tons versus D&M’s audited estimates of 431 mn tons,
596 mn tons and 734 mn tons. D&M’s estimates for 1P and 2P reserves are lower than
ONGC’s estimates due to expected delays in implementation of company’s development
plans for ageing fields in Assam. However, ONGC is currently implementing three
IOR/EOR projects in Assam at an investment of `27.8 bn and has justified its higher
estimates on the same ground.
Sakhalin-1. OVL’s estimates of 1P, 2P and 3P reserves for Sakhalin-1 field are 107 mn
tons, 140 mn tons and 140 mn tons versus D&M’s audited estimates of 50 mn tons, 98
mn tons and 141 mn tons. D&M’s estimates for 1P and 2P reserves are lower than OVL’s
estimates as (1) OVL has prepared estimates in accordance with Russian reserves
estimation methods as opposed to the more conservative SPE-PRMS 2007 classification
used by D&M, (2) OVL has assumed contract extensions until 2054 versus D&M’s
production forecasts till 2031 and (3) OVL has assumed additional recoverable volumes
that maybe economically feasible from future contracts and extensions given investments
to be undertaken to develop supporting gas infrastructure.
Imperial Energy assets. OVL’s estimates of 1P, 2P and 3P reserves for Imperial Energy
assets are 22 mn tons, 111 mn tons and 111 mn tons versus D&M’s audited estimates of
19 mn tons, 111 mn tons and 383 mn tons. OVL’s estimates for 3P reserves are lower as
it has not undertaken a full evaluation and approval of certain 3P reserves included in
D&M’s estimates.
Sudan. OVL’s estimates of 1P, 2P and 3P reserves for blocks in Sudan are 23 mn tons, 28
mn tons and 38 mn tons versus Sproule’s audited estimates of 16 mn tons, 21 mn tons
and 25 mn tons. Sproule’s estimates are lower than OVL’s estimates as Sproule has
excluded certain discovered recoverable resources due to economic, political or
technological reasons.
Block A1 and A3, Myanmar. OVL’s estimates of 1P, 2P and 3P reserves for Myanmar
blocks are 10 mn tons, 22 mn tons and 37 mn tons versus D&M’s audited estimates of 10
mn tons, 19 mn tons and 29 mn tons. D&M’s estimates for 2P and 3P reserves are lower
than OVL’s estimates due to a difference in reservoir mapping interpretation and petrophysical
parameters used to estimate initial gas volumes.
OVL’s FY2012E EPS of `7 is plausible
Our FY2012E EPS estimate of `7.2 for OVL (versus `3.8 in FY2011) looks reasonable given
reported EPS of `1.7 in 1QFY12. We are conservative in our assumptions as we model (1)
modest increase of 3.6% in OVL’s oil and gas production to 9.5 mn tons in FY2012E versus
9.2 mn tons in FY2011, (2) US$110/bbl of crude oil price and (3) rupee-dollar exchange rate
of `44.75/US$ in FY2012E.
Several positive triggers in the medium term
We discuss some of the potential triggers below but caution that some of these triggers may
materialize over the next 2-5 years. However, it would be prudent to be aware of these
triggers while determining the multiple to be ascribed in arriving at a fair valuation of the
stock.
Favorable subsidy arrangement. Exhibit 5 gives our scenario analysis of the likely
earnings of ONGC at different levels of subsidy burden. In our base-case numbers for
FY2012E and FY2013E, we assume the share of upstream companies at 39%. We note
that the upstream companies have provisionally borne 33.33% share of gross underrecoveries
in 1HFY12.
Increase in natural gas prices. We assume natural gas price at US$4.2/mn BTU over our
forecast period. However, we assume gas prices for RIL’s KG D-6 gas to increase to
US$5.5/mn BTU from FY2015E. We expect APM gas prices to be increased accordingly.
We compute a positive impact of `3/share on ONGC’s EPS if ONGC’s gas price was to be
increased to US$5.5/mn BTU from US$4.2/mn BTU.
Higher oil and gas volumes versus current assumptions. We highlight that ONGC
management has given operational targets of (1) 28 mn tons of crude oil production by
FY2014E versus 24.4 mn tons in FY2011 and (2) 72 mcm/d of gas production by FY2014E
and 100 mcm/d by FY2016E versus 63.3 mcm/d in FY2011. However, we assume a
modest increase of 0.4 mn tons of oil sales volume and 1.5 mcm/d of gas sales volumes
by FY2014E. Thus, we do not rule out upside to our estimates. We note that ONGC has
undertaken 10 major projects for development of new fields and one project for
additional development of D-1 field, which should bolster gas production from its fields.
Exhibit 6 gives the list of these fields, which are expected to be commissioned by FY2014E.
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