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Oil & Natural Gas Corporation (ONGC)
Energy
Murphy’s law strikes again. ONGC reported 4QFY11 standalone net income at `27.9
bn (-61% qoq, -26% yoy) versus our estimate of `39.6 bn. The weak results reflect (1)
higher subsidy burden in line with government’s decision to increase the share of gross
under-recoveries of upstream companies to 38.7% for FY2011, (2) higher DD&A
charges at `47.9 bn (+31.5% qoq +7.6% yoy) and (3) higher other expenditure at
`41.6 bn (+43.2% qoq and +30% yoy). We maintain our BUY rating on the stock
noting (1) 22% potential upside to our revised target price of `340 (`360 previously)
and (2) attractive valuations with the stock trading at 4.7X FY2012E DACF (on net
crude oil price realization of US$45.1/bbl).
4QFY11 EBITDA at `79.7 bn (-15.4% yoy, -31.5% qoq)
ONGC reported 4QFY11 net income (standalone) at `27.9 bn (-61% qoq, -26% yoy) versus our
estimate of `39.6 bn. The lower-than-expected net income reflects (1) higher-than-expected
DD&A expenses at `47.9 bn (+31.5% qoq +7.6% yoy) versus our estimate of `42.4 bn and (2)
higher-than-expected other expenditure at `41.6 bn(+43.2% qoq and +30% yoy) versus our
expected `26.4 bn. ONGC’s 4QFY11 EBITDA was `79.7 bn (-15.4% qoq, -31.5% yoy) versus our
estimate of `88.3 bn. The qoq decline in EBITDA reflects higher subsidy burden imposed on
upstream companies resulting in lower net crude price realization for ONGC at US$38.7/bbl versus
US$51.4/bbl in 4QFY10 and US$64.8/bbl in 3QFY11.
Ad hoc subsidy sharing and conservative accounting versus cheap valuations
We acknowledge that the government’s decision to increase the share of upstream companies to
38.7% of gross under-recoveries for FY2011 has resulted in earnings uncertainty for upstream
companies. FY2012E earnings face higher risks given gross under-recoveries will likely be higher at
`1.3 tn versus `814 bn in FY2011. Investors may also have to contend with ONGC’s conservative
accounting policies with respect to DD&A charges. However, current valuations for ONGC reflect
an extremely bleak scenario with the stock price discounting 44% share of under-recoveries for
upstream companies in perpetuity. We find ONGC’s valuations attractive with the stock trading at
8.9X FY2012E EPS and 8.8X FY2013E EPS. On cash parameters, the stock looks even more
attractive at 4.7X FY2012E DACF and 4.2X FY2013E DACF.
Fine-tuned FY2012-14E EPS estimates; maintain BUY with a target price of `340
We have revised our FY2012-14E EPS to `31 (-4%), `31 (-5.6%) and `40 (-5.9%) to reflect (1)
4QFY11 results and (2) other minor changes. We model net crude price realization for ONGC at
US$45.1/bbl for FY2012E and US$55.2/bbl for FY2013E versus US$53.8/bbl in FY2011. We
maintain our BUY rating on the stock and target price of `340 based on 10X FY2013E EPS plus
value of investments.
Higher crude oil sales volume; lower gas sales volume. 4QFY11 crude sales volume
improved 2.8% yoy to 5.8 mn tons; our expectation was 5.98 mn tons. 4QFY11 gas sales
volume declined 1.2% yoy and 2.2% qoq to 4.98 bcm; our expectation was 5.02 bcm.
FY2011 crude sales volumes increased 2.6% yoy to 22.9 mn tons while gas volumes
declined 1.6% yoy to 20.3 bcm.
Net realized price for crude oil declined sharply qoq and yoy. 4QFY11 net realized
crude price was US$38.7/bbl versus US$64.8/bbl in 3QFY11 and US$51.4/bbl in 4QFY10.
ONGC’s subsidy burden in 4QFY11 was `121.3 bn or US$70.1/bbl in crude price
equivalent terms versus crude price equivalent of US$24.3/bbl in 3QFY11 and
US$27.7/bbl in 4QFY10. We note ONGC’s share among upstream companies was 82.9%
in 4QFY11 versus 81.2% in 3QFY11. FY2011 net realized crude oil price was US$53.8/bbl
against US$55.9/bbl in FY2010.
DD&A expenses continue to climb. ONGC’s DD&A expenses were at `47.9 bn (+7.6%
yoy) versus our estimate of `42.4 bn. The yoy increase in DD&A expenses reflects higher
depletion charge on account of (1) higher production from JV fields and (2) higher
capitalization at its Rajasthan asset.
Higher other expenditure. ONGC’s 4QFY11 other expenditure increased sharply to
`41.6 bn (+43.2% qoq and +30% yoy). The management attributed the sharp increase
to the following—(1) higher workover operations, (2) cost associated with the oil spill in
the quarter, (3) `2 bn associated with the shale gas pilot project and (4) higher rig costs
due to deployment of advanced rigs to drill some high-technology wells.
Higher employee cost. ONGC’s 4QFY11 employee cost increased to `4.3 bn (+46.6%
qoq and +60.5% yoy) which reflects (1) pay revision for non-executive employees and (2)
gratuity provision.
Final dividend disappointing. The company has declared final dividend of `0.75/share,
in addition to special interim dividend of `8/share.
Good reserves accretion in FY2011. We are encouraged by the addition of 83.6 mn
tons or 610 mboe of proved reserves in ONGC alone (without overseas and domestic joint
ventures), which result in reserves replacement ratio (RRR) of 1.76X (see Exhibits 2 and 3).
We note that ONGC has maintained a reserve replacement ratio of more than 1X for the
past six years. The performance in FY2011 will likely allay concerns about ONGC’s ability
to find hydrocarbons. ONGC (standalone) made 24 discoveries in FY2011 out of which 15
are new prospects and 9 are new pools of hydrocarbons within extant discovered areas.
Key assumptions behind our earnings model
We discuss our key assumptions behind our earnings model below. Exhibit 4 gives the major
assumptions behind our earnings model and Exhibit 5 gives sensitivity of ONGC’s EPS to key
variables (rupee-dollar rate, crude oil price, natural gas price).
Subsidy amount. We model subsidy amount for FY2012E, FY2013E and FY2014E at
`424 bn, `282 bn and `144 bn. We assume diesel deregulation to be implemented from
FY2014E. We assume that upstream companies will bear 39% of the overall underrecoveries
and ONGC will bear 83.7% of the share of upstream companies in FY2012E.
This is in line with the subsidy sharing of upstream companies in FY2011. We assume that
subsidy burden on upstream companies will reduce to one-third of gross under-recoveries
in FY2013E given our expected yoy decline in crude prices.
Crude oil price assumption. We model FY2012E, FY2013E and FY2014E crude oil
(Dated Brent) price at US$105/bbl, US$95/bbl and US$90/bbl. However, we would focus
more on ONGC’s net realized crude price and our long-term crude price assumption.
Exhibit 6 gives ONGC’s historical net realized price and our expectations for FY2012E
(US$45.1/bbl), FY2013E (US$55.2/bbl) and FY2014E (US$71.5/bbl). FY2011 net crude
realized price was US$53.8/bbl.
Natural gas price assumption. We assume FY2012-14E natural gas price at `7.5/cu m.
Exchange rate assumption. We model exchange rate for FY2012E, FY2013E and
FY2014E at `45.5/US$, `44/US$ and `44/US$.
MRPL 4QFY11 results—strong refining performance boosted by adventitious
gains
MRPL, ONGC’s 71.6% refining subsidiary, reported 4QFY11 net income of `5.5 bn
compared to `3.1 bn in 3QFY11 and `2.5 bn in 4QFY10. The steep increase in net income
qoq and yoy reflects higher refining margins at US$9.1/bbl (+US$3.1/bbl qoq and
+US$3.8/bbl yoy). The sharp qoq improvement in refining margins reflects (1) improvement
in global benchmark refining margins and (2) adventitious gain of US$6.3/bbl in 4QFY11
versus US$4.1/bbl in 3QFY11 and US$0.3bbl in 4QFY10. MRPL’s crude throughput for
4QFY11 was at 3.4 mn tons versus 3.5 mn tons in 3QFY11 and 3.1 mn tons in 4QFY10.
We model FY2012E and FY2013E EPS at `5.5 (`9.7 bn net income) and `4.4 (`7.7 bn net
income). We model FY2012E and FY2013E refining margin at US$5.1/bbl and US$5.4/bbl
versus US$5.9/bbl in FY2011 (including adventitious gains of US$2.3/bbl); all figures include
adventitious gains/losses.
We model crude throughput at 13.5 mn tons for FY2012E and 15 mn tons for FY2013E. We
note that MRPL is undertaking a refinery expansion project to increase capacity to15 mtpa
(versus 12.69 mtpa currently), which is scheduled to be completed by October 2011
India Equity Research Reports, IPO and Stock News
Visit http://indiaer.blogspot.com/ for complete details �� ��
Oil & Natural Gas Corporation (ONGC)
Energy
Murphy’s law strikes again. ONGC reported 4QFY11 standalone net income at `27.9
bn (-61% qoq, -26% yoy) versus our estimate of `39.6 bn. The weak results reflect (1)
higher subsidy burden in line with government’s decision to increase the share of gross
under-recoveries of upstream companies to 38.7% for FY2011, (2) higher DD&A
charges at `47.9 bn (+31.5% qoq +7.6% yoy) and (3) higher other expenditure at
`41.6 bn (+43.2% qoq and +30% yoy). We maintain our BUY rating on the stock
noting (1) 22% potential upside to our revised target price of `340 (`360 previously)
and (2) attractive valuations with the stock trading at 4.7X FY2012E DACF (on net
crude oil price realization of US$45.1/bbl).
4QFY11 EBITDA at `79.7 bn (-15.4% yoy, -31.5% qoq)
ONGC reported 4QFY11 net income (standalone) at `27.9 bn (-61% qoq, -26% yoy) versus our
estimate of `39.6 bn. The lower-than-expected net income reflects (1) higher-than-expected
DD&A expenses at `47.9 bn (+31.5% qoq +7.6% yoy) versus our estimate of `42.4 bn and (2)
higher-than-expected other expenditure at `41.6 bn(+43.2% qoq and +30% yoy) versus our
expected `26.4 bn. ONGC’s 4QFY11 EBITDA was `79.7 bn (-15.4% qoq, -31.5% yoy) versus our
estimate of `88.3 bn. The qoq decline in EBITDA reflects higher subsidy burden imposed on
upstream companies resulting in lower net crude price realization for ONGC at US$38.7/bbl versus
US$51.4/bbl in 4QFY10 and US$64.8/bbl in 3QFY11.
Ad hoc subsidy sharing and conservative accounting versus cheap valuations
We acknowledge that the government’s decision to increase the share of upstream companies to
38.7% of gross under-recoveries for FY2011 has resulted in earnings uncertainty for upstream
companies. FY2012E earnings face higher risks given gross under-recoveries will likely be higher at
`1.3 tn versus `814 bn in FY2011. Investors may also have to contend with ONGC’s conservative
accounting policies with respect to DD&A charges. However, current valuations for ONGC reflect
an extremely bleak scenario with the stock price discounting 44% share of under-recoveries for
upstream companies in perpetuity. We find ONGC’s valuations attractive with the stock trading at
8.9X FY2012E EPS and 8.8X FY2013E EPS. On cash parameters, the stock looks even more
attractive at 4.7X FY2012E DACF and 4.2X FY2013E DACF.
Fine-tuned FY2012-14E EPS estimates; maintain BUY with a target price of `340
We have revised our FY2012-14E EPS to `31 (-4%), `31 (-5.6%) and `40 (-5.9%) to reflect (1)
4QFY11 results and (2) other minor changes. We model net crude price realization for ONGC at
US$45.1/bbl for FY2012E and US$55.2/bbl for FY2013E versus US$53.8/bbl in FY2011. We
maintain our BUY rating on the stock and target price of `340 based on 10X FY2013E EPS plus
value of investments.
Higher crude oil sales volume; lower gas sales volume. 4QFY11 crude sales volume
improved 2.8% yoy to 5.8 mn tons; our expectation was 5.98 mn tons. 4QFY11 gas sales
volume declined 1.2% yoy and 2.2% qoq to 4.98 bcm; our expectation was 5.02 bcm.
FY2011 crude sales volumes increased 2.6% yoy to 22.9 mn tons while gas volumes
declined 1.6% yoy to 20.3 bcm.
Net realized price for crude oil declined sharply qoq and yoy. 4QFY11 net realized
crude price was US$38.7/bbl versus US$64.8/bbl in 3QFY11 and US$51.4/bbl in 4QFY10.
ONGC’s subsidy burden in 4QFY11 was `121.3 bn or US$70.1/bbl in crude price
equivalent terms versus crude price equivalent of US$24.3/bbl in 3QFY11 and
US$27.7/bbl in 4QFY10. We note ONGC’s share among upstream companies was 82.9%
in 4QFY11 versus 81.2% in 3QFY11. FY2011 net realized crude oil price was US$53.8/bbl
against US$55.9/bbl in FY2010.
DD&A expenses continue to climb. ONGC’s DD&A expenses were at `47.9 bn (+7.6%
yoy) versus our estimate of `42.4 bn. The yoy increase in DD&A expenses reflects higher
depletion charge on account of (1) higher production from JV fields and (2) higher
capitalization at its Rajasthan asset.
Higher other expenditure. ONGC’s 4QFY11 other expenditure increased sharply to
`41.6 bn (+43.2% qoq and +30% yoy). The management attributed the sharp increase
to the following—(1) higher workover operations, (2) cost associated with the oil spill in
the quarter, (3) `2 bn associated with the shale gas pilot project and (4) higher rig costs
due to deployment of advanced rigs to drill some high-technology wells.
Higher employee cost. ONGC’s 4QFY11 employee cost increased to `4.3 bn (+46.6%
qoq and +60.5% yoy) which reflects (1) pay revision for non-executive employees and (2)
gratuity provision.
Final dividend disappointing. The company has declared final dividend of `0.75/share,
in addition to special interim dividend of `8/share.
Good reserves accretion in FY2011. We are encouraged by the addition of 83.6 mn
tons or 610 mboe of proved reserves in ONGC alone (without overseas and domestic joint
ventures), which result in reserves replacement ratio (RRR) of 1.76X (see Exhibits 2 and 3).
We note that ONGC has maintained a reserve replacement ratio of more than 1X for the
past six years. The performance in FY2011 will likely allay concerns about ONGC’s ability
to find hydrocarbons. ONGC (standalone) made 24 discoveries in FY2011 out of which 15
are new prospects and 9 are new pools of hydrocarbons within extant discovered areas.
Key assumptions behind our earnings model
We discuss our key assumptions behind our earnings model below. Exhibit 4 gives the major
assumptions behind our earnings model and Exhibit 5 gives sensitivity of ONGC’s EPS to key
variables (rupee-dollar rate, crude oil price, natural gas price).
Subsidy amount. We model subsidy amount for FY2012E, FY2013E and FY2014E at
`424 bn, `282 bn and `144 bn. We assume diesel deregulation to be implemented from
FY2014E. We assume that upstream companies will bear 39% of the overall underrecoveries
and ONGC will bear 83.7% of the share of upstream companies in FY2012E.
This is in line with the subsidy sharing of upstream companies in FY2011. We assume that
subsidy burden on upstream companies will reduce to one-third of gross under-recoveries
in FY2013E given our expected yoy decline in crude prices.
Crude oil price assumption. We model FY2012E, FY2013E and FY2014E crude oil
(Dated Brent) price at US$105/bbl, US$95/bbl and US$90/bbl. However, we would focus
more on ONGC’s net realized crude price and our long-term crude price assumption.
Exhibit 6 gives ONGC’s historical net realized price and our expectations for FY2012E
(US$45.1/bbl), FY2013E (US$55.2/bbl) and FY2014E (US$71.5/bbl). FY2011 net crude
realized price was US$53.8/bbl.
Natural gas price assumption. We assume FY2012-14E natural gas price at `7.5/cu m.
Exchange rate assumption. We model exchange rate for FY2012E, FY2013E and
FY2014E at `45.5/US$, `44/US$ and `44/US$.
MRPL 4QFY11 results—strong refining performance boosted by adventitious
gains
MRPL, ONGC’s 71.6% refining subsidiary, reported 4QFY11 net income of `5.5 bn
compared to `3.1 bn in 3QFY11 and `2.5 bn in 4QFY10. The steep increase in net income
qoq and yoy reflects higher refining margins at US$9.1/bbl (+US$3.1/bbl qoq and
+US$3.8/bbl yoy). The sharp qoq improvement in refining margins reflects (1) improvement
in global benchmark refining margins and (2) adventitious gain of US$6.3/bbl in 4QFY11
versus US$4.1/bbl in 3QFY11 and US$0.3bbl in 4QFY10. MRPL’s crude throughput for
4QFY11 was at 3.4 mn tons versus 3.5 mn tons in 3QFY11 and 3.1 mn tons in 4QFY10.
We model FY2012E and FY2013E EPS at `5.5 (`9.7 bn net income) and `4.4 (`7.7 bn net
income). We model FY2012E and FY2013E refining margin at US$5.1/bbl and US$5.4/bbl
versus US$5.9/bbl in FY2011 (including adventitious gains of US$2.3/bbl); all figures include
adventitious gains/losses.
We model crude throughput at 13.5 mn tons for FY2012E and 15 mn tons for FY2013E. We
note that MRPL is undertaking a refinery expansion project to increase capacity to15 mtpa
(versus 12.69 mtpa currently), which is scheduled to be completed by October 2011
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