indonesia industry focus oil & gas - dbs bank price can be varied from our view and forecast....

ed-TH / sa- MA

No longer an easy play

The era of easy oil & gas is over

Low crude oil price is the key factor

Insufficient support from government

Initiate MEDC with HOLD and ELSA with Fully Valued

Challenging industry outlook. Indonesia's oil & gas sector will face multiple headwinds as low crude oil price outlook will halt existing and potential projects' economic feasibility. Indonesia's average lifting cash cost is at US$20-40 per barrel and at this crude oil price level, we believe current existing drilling are operating at a thin profit if not loss, and as their exploration projects are mainly offshore, deepwater ones, they are subject to delays and write-offs. The low crude oil price environment is also negative for oil & gas service companies, given downward fee re-negotiation from its struggling clients.

Slow progress on oil & gas reform. We see only marginal reform in Indonesia's oil & gas industry and so far, we do not see any relevant incentives/support for upstream investors and contractors amid the currently challenging situation. With existing regulations and policies, plus current low crude oil prices, Indonesia's oil & gas industry appears to be unattractive to investors.

Initiate MEDC with HOLD, TP Rp820 and ELSA with Fully Valued, TP Rp205. We initiate MEDC with HOLD and ELSA with Fully Valued. We see MEDC's low-cost structure helping it to cope with the current situation, while its valuation is undemanding but future outlook is uncertain as its key reserves unlock in overseas assets. We have a Fully Valued call on ELSA as we see the contract fee renegotiation and dry new contract renewal.

JCI : 4,374.19

Analyst William Simadiputra +62 2130034939 [email protected]

STOCKS

Source: DBS Vickers Medco Energi : Integrated energy company, explores and produces oil and gas both in Indonesia and internationally

Elnusa : Integrated oil services company, offers services that include geophysical data, drilling and oil field services

DBS Group Research . Equity 15 Dec 2015

Indonesia Industry Focus

Oil & Gas

Refer to important disclosures at the end of this report

Price Mkt Cap Target Price Performance (%)

Rp US$m Rp 3 mth 12 mth Rating

Medco Energi 760 179 820 (68.0) (78.7) HOLD Elnusa 245 127 205 (42.4) (62.9) FULLY VALUED

Industry Focus

Oil & Gas

Investment thesis: No longer an easy play Indonesia's oil & gas industry will face challenges ahead on low crude oil prices and insignificant industry reform, which will negatively impact both oil & gas contractors and service companies' businesses. Current deregulation and reform progress is very slow and a little bit too late, in our view, while crude oil price has plunged to a low level. We do not see any relevant incentives from government to upstream oil & gas contractors to support oil & gas upstream drillers amid to support their operation and business going concern at our US$60 per barrel and US$65 per barrel in FY16 and FY17 respectively, and our long-term crude oil price of US$70 per barrel (2017 and beyond). National oil & gas activity, covering from exploration to lifting activity, are facing headwinds which will lead oil & gas production volume downtrend, which will cause Indonesia to continue relying on imported energy (mainly oil) in the future. The number of new potential investments and project feasibility have reduced in the last five years and are subject to impairments at the current level of crude oil price. Meanwhile, existing wells are entering their period of decline. We initiate coverage on Medco Energy (MEDC) with a HOLD rating and Elnusa with a Fully Valued rating with target prices of Rp820 and Rp205 respectively. Amid the bleak oil & gas price outlook, Indonesian oil & gas companies are focusing on maintaining positive earnings, capital allocation and cash reserves while putting production volume growth as a lower priority. This is means there will be no earnings growth and potential stock price upside, in our view. Low crude oil price. We are basing our oil & gas industry

analysis on our regional in-house crude oil price assumption of US$60 per barrel. There are negative implications to Indonesia's oil & gas industry as the country's oil & gas cash cost projects average at US$35 per barrel. We believe at current price range of crude oil price, 90% of new investments and projects in the pipeline are not feasible and subject to be written-off. Existing oil wells are entering their period of decline. The industry trend, according to our channel check, is focusing on managing costs.

Slow reform in upstream oil & gas industry. Indonesia's oil & gas industry reformation as per government's plans, such as streamlining the paperwork bureaucracy and incentives for deep water drilling progress is very slow as per a survey on the oil & gas stakeholders in Indonesia by PricewaterhouseCoopers (PWC). We do not see any

structural changes in Indonesia's oil & gas industry regulations, which is positive or would at least help contractors to survive amid the crude oil price downtrend. The government's focus on initiating the fuel storage expansion in Indonesia amid the slow upstream oil & gas reform signals that Indonesia will continue to rely on oil imports in order to extend Pertamina's operational fuel reserve from 22 days to 30 days. We also believe the initiatives is not a long-term solution to fix the national oil & gas production bottleneck.

Uncertainties on PSC expiration extension. The government's plan to take over the expiring PSC (averaging eight years) via Pertamina raises uncertainties for investors. In this case, Mahakam Block has been under process of take over by Pertamina recently under presidential decision.

Downtrend in exploration investments; threat for Indonesia's long-term oil & gas reserves and production. Exploration investments have also halted at current crude oil price level as contactors seek to strengthen their balance sheets and cash flows. Oil & gas contractors will focus on short- to medium-term plans such as maintaining efficiencies on existing operations. Low crude oil price create another challenge besides the internal issues such as the challenging bureaucracy which used to be the only single bottleneck of Indonesia's oil & gas industry expansion.

Execution risk on existing reserve monetisation . 75% of

the current remaining oil and gas reserves are located in the Eastern part of Indonesia, offshore and dominate by gas. Offshore drilling cash cost per barrel is 200% higher than onshore in general. Moreover, the Eastern part of Indonesia lacks infrastructure and gas captive buyers which also means the natural gas produced in Eastern part of Indonesia is not price competitive with the domestic market.

Negatives for oil & gas services. We are negative on oil & gas services as current low crude oil prices squeeze contractors' profitability and project feasibility. This means oil & gas service companies' earnings outlook will be more uncertain given rising competition, tough contract renegotiation and slow new contract roll-outs.

Undemanding valuation, but we see further de-rating potential for ELSA. Indonesia's oil & gas companies' stocks have dropped by 70% YTD (including OSV) and we believe the current valuation is undemanding. MEDC's low-cost

Industry Focus

Oil & Gas

structure will support its survivability in the currently challenging industry conditions. On the other hand, We believe market expectations on its turnaround story is overdone amid current slowing industry dynamics which hurt its upstream-related oil & gas business.

Risks We aware that we could be wrong on our analysis, which could lead to inaccurate earnings forecast, target price derivation and stock rating. We list the key assumptions that we understand could deviate from our base assumption in our analysis, as follows: Our long-term crude oil price assumption. We base our

analysis on our in-house long-term crude oil price assumption. Hence, if the actual crude oil price range miss from our forecast, our view regarding national oil & gas industry outlook, per company earnings forecast and target price can be varied from our view and forecast.

Faster-than-expected oil and gas reform. If the government's oil & gas industry plan transformation is faster than expected, Indonesia's oil & gas investments will ramp up better than expected and oil & gas service companies will benefit from the rising upstream oil & gas investments.

Better-than-expected drilling technology. We assume only conventional drilling technology application in Indonesia as we believe the unconventional technology is too expensive

at our long-term crude oil price assumption. We can be wrong if a new breakthrough technology is available in the market at a reasonable price.

We under estimate the feasibility of oil and gas reserves in Eastern part of Indonesia. We assume the development and monetisation of Eastern Indonesia's oil & gas reserves will be very slow on infrastructure bottleneck. We can be wrong also if the government provides incentives for offshore deepwater drilling and hence, the price competitiveness could be maintained.

Execution risks. Our forecast on MEDC depends on its capability to monetise, whether its domestic or overseas oil & gas reserves. We use reserve life index multiple in our terminal value, implying that MEDC's execution capability will impact our target price. For ELSA, our earnings growth forecast depends on its capability to find, and renew existing contracts with competitive rates.

Energy mix substitution threat; gas and coal. Amid the struggling domestic oil & gas production expansion, again, coal is the strongest candidate to fill the energy supply gap. Indonesia has 80bn ton of coal reserves which it is ready to monetise in the case of seaborne market structural slowdown. Moreover, LNG is also more economically feasible to import after the oil price slump as oil & gas players such as Pertagas and Medco are continuously expanding their LNG facility and infrastructure.

Industry Focus

Oil & Gas

Initiate coverage on MEDC and ELSA with HOLD and Fully

Valued ratings, TP of Rp820 and Rp205 respectively

We initiate MEDC and ELSA with a HOLD and Fully Valued rating with DCF-based target price of Rp820 and Rp205 respectively. Our calls for both stocks reflect our bearish views on Indonesia's oil & gas sector as the current low crude oil price has raised another challenge besides current bureaucracy bottle neck, fading periods on existing old wells and offshore new reserves monetization challenges. We also believe Indonesia's oil & gas companies' valuations are undemanding and further de-rating potential is minimum, given the steep correction in stock prices in the last one year. Exception for oil & gas service companies particularly ELSA, which is exposed to the risks of existing contracts' working fee renegotiations and slow new contract roll-outs. Current valuation also still reflects consensus expectations on its continuous business turnaround efforts. Meanwhile, we expect the turnaround to take a longer time and will not be as good as consensus expects amid current challenging upstream oil and gas industry. 1) We have a Hold rating and TP of Rp820 for MEDC We initiate coverage on Medco Energy with a Hold rating with target price of Rp820 (FY16 EV/EBITDA of 6.9x and P/BV 0.2x), implying no upside potential from the current stock price. We believe MEDC's valuation is undemanding. However, we do not see any positive catalyst within the next twelve months amid low crude oil price which pressurise earnings and halt MEDC's expansion. MEDC will focus on survival, maintaining positive cash margin and profitability as well as its balance sheet and cash flows in the short to medium term. MEDC will rely on its existing profitable oil & gas blocks' operations given their highest profitability. However, they have limited potential in production volume upside. Moreover, in order to maintain a sustainable production volume momentum, we believe MEDC needs to incur extra costs in technology and methodology which is more expensive than conventional drilling. On the other hand, we believe MEDC will struggle to monetise its overseas assets as current low crude oil price erase the projects' economic feasibility. Execution risk is another issue as the regulation structure is also uncertain in countries like Libya on government transition. Note that Medco's 45% oil reserves is trapped in its overseas assets. Hence, MEDC will focus on monetising its remaining domestic oil & gas reserves.

However, we also believe that monetising gas reserves woule be challenging on MEDC's unfavourable geographical conditions. MEDC's gas reserves are located in the Eastern part of Indonesia, which means that the company's natural gas should compete with imported gas and another onshore field natural gas producers. Key earnings forecast We forecast MEDC's EBITDA to grow by only 2% FY15-17 CAGR, driven by modest production volume expansion, stabilised ASP on stabilised crude oil price volatility and contribution from jointly controlled investments, mainly on DSLNG upstream-downstream projects. Revenue, EBITDA and net profit

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

0

100

200

300

400

500

600

700

800

900

1,000

2011 2012 2013 2014 2015F 2016F 2017F

Revenue EBITDA Net profit EBITDA margin

Source: DBS Vickers, Company We believe EBITDA margin will be stable at the 32-33% level. We believe management, given its proven execution track record in the past two decades, will maintain MEDC's low-cost structure and higher ASPs in FY16 and FY17, in line with our crude oil price benchmark assumption. MEDC's current cash cost per barrel of US$15 per barrel will gradually expand as it will implement a strategy to enhance its existing profitable oil reserves in Rimau. Oil & gas lifting cash cost per barrel (US$ per barrel)

12 13

14

16 16 17

18

‐

2

4

6

8

10

12

14

16

18

20

2011 2012 2013 2014 2015F 2016F 2017F

Lifting cost per barrel

Source: DBS Vickers, Company

Industry Focus

Oil & Gas

We believe MEDC will rely on existing productive and profitable oil & gas blocks such as Rimau block, South Sumatra, and potentially its newly commenced Senoro-toili block, in order to maintain positive cash margins and strong cash flows. Oil & gas reserves by location

Source: DBS Vickers, Company On the other hand, we believe MEDC will postpone the majority of its green- and brown-field project expansions given their unattractive economic feasibility at low crude oil price. This implies MEDC will spend only 60% of its budgeted capex in the next three years. We see this as a sign of prudent capital allocation as MEDC will carefully time its cash flows and debt maturity. Our MEDC's capex trend vs. company guidance

176

324

230

335

230

275

201 224

456 470

417

‐

50

100

150

200

250

300

350

400

450

500

2011 2012 2013 2014 2015F 2016F 2017F

Capex Guidance

Source: DBS Vickers, Company 2) Meanwhile, we have a Fully Valued rating on ELSA

with Rp205 TP We believe oil & gas service companies will secure a low number of new contracts on contractors' exploration investment downtrend in the next several years, given the low crude oil price, which will translate into fewer projects entering the exploitation stage. Moreover, existing ongoing contracts

also are facing fee renegotiation risks as many contractors are struggling financially. We initiate coverage on Elnusa with a Fully Valued rating and target price of Rp205 (FY16F PE of 8.0x), implying a 15% downside potential from its current stock price. We believe oil & gas service companies will be the most negatively impact by the low crude oil price on existing contract renegotiation and difficulties in obtaining new contracts. ELSA has begun to face renegotiations from contractors as seen in its 2Q15 financial performance despite stable profitability. ELSA is looking to maintain growth momentum via overseas working scope expansion to India and Myanmar. This not only signals limited incoming new contracts from domestic industry, but it also raises our concerns on ELSA's unproven track record in executing overseas projects. However, the company believes that the working contract term is more flexible vs. domestic, and hence it could maintain healthy profitability with competitive contract fee. Key earnings forecast EBITDA and earnings will reach Rp586bn (-12% y-o-y) and Rp497bn (-15% y-o-y), while net profit also has a similar trend and reach Rp308bn (-40% y-o-y) and Rp189bn (-16% y-o-y) in FY15 and FY16 respectively. Our earnings forecasts are around 15% below consensus' forecasts as we believe the consensus has not fully accounted for the likelihood of existing contract renegotiations which will hurt ELSA's revenue and earnings growth, despite the company's capability in maintaining stable profitability ahead. Gross profit, EBITDA and net profit forecast (Rpbn)

285

551

647

760

652

506 453

202

605 599

665

586

497 468

(43)

128

238

412

308

189 163

(100)

‐

100

200

300

400

500

600

700

800

2011 2012 2013 2014 2015F 2016F 2017F

Gross profit EBITDA Net profit

Source: DBS Vickers, Company We believe ELSA faces negative top-line growth from all its upstream-related businesses, given the slowing upstream oil & gas contractors' activity of its clients. MEDC and Pertamina are ELSA's largest clients and both have scaled back their capital

Industry Focus

Oil & Gas

spending mainly on new oil & gas reserve survey and exploration activity, which are ELSA's significant revenue and earnings contributor. Meanwhile, we believe other segments such as drilling services activity performance will be relatively stable, as contractors will continuously monetise their profitable reserves even at the current low crude oil price, in order to generate cash flows. We believe ELSA could maintain stable profitability as its major costs are salaries and overheads. ELSA's careful cost control in maintaining its expenses was seen in its 1H15 performance. Amid the contractors' contract renegotiation which reflects in

slower top-line growth, ELSA could maintain stable profitability mainly on its overhead spending. We also estimate that ELSA will scale back its capex spending amid challenging new contracts winning. Our capex forecast is lower than the management's guidance on its company latest Our capex assumption is lower than management guidance. This is in line with our forecast assumption that ELSA will rely only on existing project renewals instead of new contracts. Hence, ELSA can minimise its capex by slashing unnecessary spending on new equipment and engineer hiring.

ELSA's profitability trend (%) Capex trend (Rpbn)

6.0

11.5

15.7

18.017.3

16.515.8

4.3

12.7

14.615.8 15.5

16.2 16.3

‐0.9

2.7

5.8

9.8

8.2

6.2 5.7

‐5.0

0.0

5.0

10.0

15.0

20.0

2011 2012 2013 2014 2015F 2016F 2017F

Gross margin EBITDA margin Net profit margin

262

130 110

366

264

215 201

‐

50

100

150

200

250

300

350

400

2011 2012 2013 2014 2015F 2016F 2017F

Capex


Industry Focus

Oil & Gas

Valuation looks undemanding but we remain cautious Indonesia's oil & gas stock performance, mainly SMC (Shipping) like Wintermar Offshore and Logindo Samudra Makmur dropped by 87% y-o-y and 84% y-o-y respectively per June 2015. MEDC and ELSA's stock price performance dropped by 61% and 38% y-o-y respectively in the same period since the crude oil price collapse in June 2014. Stock price performance since Mid-June 2014

‐87%‐84%

‐61%

‐38%

‐12.70%

‐54%

‐100%

‐90%

‐80%

‐70%

‐60%

‐50%

‐40%

‐30%

‐20%

‐10%

0%

WINS LEAD MEDC ELSA APEX BIPI

Stock price performance

Source: DBS Vickers, Bloomberg Finance L.P. The valuation has fallen to the financial crisis level in terms of book value, as the panic selling in recent months is a reflection of the deferred recovery of oil prices, as US shale has yet to show any meaningful production cuts and the world's largest oil importer- China- is seeing slower economic growth, further fuelled by a strengthened USD and fears of financial crisis. MEDC looks attractive at price-to-book below 0.5x, its lowest P/BV multiple in the last five years. Meanwhile, ELSA is still trading at 1.2x P/BV, in line with its average five-year average P/BV multiple. We are excluding the smaller, not rated oil & gas companies (both contractors and services) as we see smaller players struggling more than companies under our coverage, thereby distorting our analysis. We believe ELSA's valuation is still being backed by its better results following its management turnaround in 2012-2014.

MEDC five years' price-to-book value band

Average

+1 stdev

+2 stdev

-1 stdev

-2 stdev

0.2

0.4

0.6

0.8

1.0

Jan-12 Jan-13 Jan-14 Jan-15

(x)

Source: DBS Vickers, Bloomberg Finance L.P.

ELSA five years price to book value band

Average

+1 stdev

+2 stdev

-1 stdev

-2 stdev0.0

0.7

1.4

2.1


(x)

Source: DBS Vickers, Bloomberg Finance L.P. Indonesia's oil & gas industry is trading at FY16 EV/EBITDA of 5.0x. Both ELSA and MEDC are trading at their five-year average EV/EBITDA of 5.0x and 3.5x respectively. Meanwhile, SMC is trading at a discount given its capital-intensive business characteristics, mainly on vessel purchases. MEDC is trading at a slight premium to the industry average given its low-cost and strong capital structure, which increase its survivability amid the currently challenging situation, we believe. .

Industry Focus

Oil & Gas

MEDC five-year EV/EBITDA band

Average

+1 stdev

+2 stdev

-1 stdev

-2 stdev

1.0

2.0

3.0

4.0

5.0

6.0

7.0

Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15

(x)


ELSA five-year price EV/EBITDA band

Average

+1 stdev

+2 stdev

-1 stdev

1.0

3.0

5.0

7.0


(x)

Source: DBS Vickers, Bloomberg Finance L.P. Our sanity check with price-to-earnings ratio multiple also confirms that Indonesia's oil & gas companies' valuation is undemanding as it is currently trading at -2SD of its five-year multiple standard deviation (see chart) ex. ELSA, which still at five years average mean. We prefer to measure our upstream oil & gas companies on EBITDA basis as it is more comparable and excludes any one-off write-offs, which is possible at the current low crude oil price level and financing cost. EBITDA also tells us more about the firm's survivability and solvency instead of net earnings, in our view. Despite ELSA's valuation looks undemanding on EV/EBITDA multiple, ELSA is still trading at double digit P/E multiple of 12.0x despite we believe our earnings forecast for next year is fairly conservative as we include only the existing contracts. We also prefer to use P/E multiple as valuation metrics beside DCF, as ELSA contract-based business model only require external financing for capital expenditure only after ELSA locked a project or contract, with certain economic feasibility guarantee

MEDC five-year PE band

Average

+1 stdev

+2 stdev

-1 stdev

-2 stdev0.0

10.0

20.0

30.0

40.0

50.0


(x)


ELSA five-year PE band

Average

+1 stdev

+2 stdev

-1 stdev

-2 stdev0.0

7.0

14.0

21.0


(x)

Source: DBS Vickers, Bloomberg Finance L.P. Relative to our regional coverage, Indonesia's oil & gas stocks' valuation is relatively undemanding relative to our ASEAN coverage after considering its profitability performance and overall top-line bottom-line growth outlook (see table on the next page). However, we do not see this is as an argument to accumulate Indonesia's oil & gas stocks as we believe they are relatively reasonable priced. Meanwhile, regional oil & gas stock valuations, mainly those in Singapore, are demanding, this is reflected by their stock price drop, which is the steepest in our ASEAN coverage.

Industry Focus

Oil & Gas

Regional Comparison

Stock Stock

price* Market

cap

PE (x) EV/EBITDA PBV ROAE EBITDA growth (%yoy) Net profit growth (%yoy)

2014 2015 2016 2014 2015 2016 2014 2015 2016 2014 2015 2016 2014 2015 2016 2014 2015 2016

Indonesia

Logindo Samudramakmur 178 31 0.4 10.8 5.8 3.2 6.1 4.2 0.1 0.2 0.2 16 2 4 20.2 (30.2) 26.3 21.4 (85.5) 87.7

Wintermar Offshore Marine 160 44 2.0 255.1 9.6 3.2 6.6 5.6 0.2 0.2 0.2 11 0 2 7.1 (51.0) 24.4 (19.8) (99.2) 2559.5

Elnusa 343 141 4.8 6.4 10.4 2.1 1.7 1.9 0.8 0.8 0.7 17 9 7 24.3 (17.9) (8.8) 73.2 (39.6) (16.1)

Medco Energy 1,150 260 27.1 7.0 7.9 3.5 4.2 4.7 0.3 0.3 0.2 1 4 3 28.0 (9.0) 1.0 (72.5) 290.3 (12.1)

Malaysia

Bumi Armada 0.91 274 21.3 18.3 12.5 9.3 8.2 7.0 0.8 0.8 0.7 5 4 6 (11.0) 29.6 23.4 (41.7) 16.4 47.2

Coastal Contracts 1.89 1,004 5.4 5.4 7.0 3.1 5.9 6.0 0.7 0.6 0.6 16 13 9 27.7 10.1 (14.1) 26.2 0.1 (21.9)

Dayang Enterprise Holdings 1.7 1,491 8.3 10.2 8.7 5.8 6.6 5.4 1.8 1.7 1.5 24 17 18 55.8 (15.2) 13.9 20.7 (19.0) 16.8

Dialog Group 1.59 8,085 37.8 29.6 29.5 26.9 21.3 20.1 5.2 4.7 4.3 15 17 15 15.8 23.9 8.4 11.7 27.5 0.4

Malaysia Marine & Heavy En. 1.07 1,712 15.9 19.0 20.2 7.8 9.1 8.8 0.7 0.6 0.6 4 3 3 (31.7) (8.8) 0.6 (54.4) (16.4) (6.2)

UMW Holdings 7.68 8,972 8.3 13.0 12.3 7.1 9.0 9.1 1.4 1.3 1.2 17 10 10 11.7 (21.2) 2.8 103.2 (36.5) 5.6

Singapore

Cosco Corporation 0.375 840 40.2 505.4 87.4 20.2 17.8 16.3 0.6 0.6 0.6 2 0 1 (18.7) 13.3 18.5 (31.8) (92.0) 478.1

Ezion Holdings 0.66 731 3.4 5.3 3.0 6.7 7.3 4.8 0.7 0.6 0.5 24 12 18 58.3 1.0 48.2 40.8 (36.1) 78.5

Keppel Corporation 6.76 12,262 6.5 8.4 8.8 5.7 7.3 7.3 1.2 1.1 1.1 19 14 12 4.6 (34.1) (2.8) 2.1 (22.0) (5.2)

Mermaid Maritime 0.158 157 3.2 14.0 9.9 1.8 3.6 7.8 0.3 0.3 0.3 9 2 3 77.5 (45.9) 27.3 214.2 (77.4) 41.8

Sembcorp Marine 2.25 4,701 8.4 10.0 10.3 6.7 7.9 7.6 1.6 1.5 1.4 20 15 14 11.4 (6.8) 4.2 0.8 (15.8) (3.3)

Vard Holdings 0.445 3,119 8.9 31.0 42.8 23.6 54.8 41.8 0.8 0.7 0.7 9 2 2 (37.5) (55.1) 4.9 (2.2) (71.2) (27.6)

Yangzijiang Shipbuilding 1.12 19,197 5.5 5.4 5.0 3.6 2.9 2.2 0.9 0.8 0.7 18 16 16 (13.3) 11.0 4.8 12.4 3.1 7.3

Thailand

IRPC PCL 3.8 77,651 nm 7.6 11.0 nm 9.7 9.2 1.1 1.0 1.0 (7) 14 9 (225) (357) 4.4 (733.5) (295.7) (31.1)

PTT 245 699,794 12.5 9.7 9.0 5.4 6.0 5.4 1.0 1.0 0.9 8 10 10 1.6 (11.6) 13.9 (40.1) 28.8 8.5

PTT Exploration & Production 71.5 283,854 13.2 15.0 11.8 1.7 3.2 3.0 0.7 0.7 0.6 5 5 6 8.7 (36.3) 18.7 (61.8) (11.9) 26.8

* Price as of 30 November 2015 Source : DBS Vickers, Bloomberg Finance L.P.

Industry Focus

Oil & Gas

Long term crude oil price assumption of US$70 per barrel;

oversupply is still the key issue We have imputed DBS’s regional oil and gas price assumption to our analysis and forecast for Indonesia oil and gas industry and the stocks that we cover. We have assumed Brent crude oil price of US$45/bbl - US$55/bbl in FY15 and US$55-US$65/bbl in FY16. Our FY15-16 crude oil price assumption in our ELSA and MEDC financial forecast is US$5/bbl lower than our regional current oil price forecast. Our long term Brent crude oil price assumption is US$70/bbl and our regional supply and demand view is summarized in this section. Our full report 'Drilling Deeper for the Gems' released 18 September 2015. Widening supply and demand gap - worse than consensus

expectation

We believe crude oil prices will remain under pressure based on the widening supply gap in 2015, as well as geopolitical factors like the removal of sanctions on Iran. Higher productivity in the US shale oil sector has largely fended off the challenges from low oil prices but the question is for how long. Expiring oil selling price hedges will help to lower supply in 2016-17 and this point underpins our thesis on higher oil prices compared to the current level. The gap between global crude oil and gas supply and demand has widened to 2mmbpd this year, though this is expected to contract to around 1mmbpd in 2016. However, the gap is unlikely to be bridged before 2017 at the earliest. Global oil production and consumption trend forecast

Source: DBS Vickers, EIA There has also been no let up regards production from OPEC countries, led by Saudi Arabia. Production has consistently remained above the 30mmbpd cap set by member nations so far in 2015. Iraq and Saudi Arabia are key countries behind the production increase in recent months. Iran is still producing 2.8mmbpd and expectations are that can ramp up to 3.8mmbpd - a level before sanctions were imposed - over the

next two years. Expectations for OPEC to cut production has been low so far given OPEC's reluctance to cede market share. OPEC production trends

Source: DBS Vickers, Bloomberg Finance L.P. At the beginning of the year, consensus believed that Saudi Arabia's policy of maintaining oil production would push US shale oil players out of business. However, US shale oil production has increased 18% (as June 2015) y-o-y since oil prices started to free fall in June 2014. Productivity is the key reason of higher oil production despite the fact that working rigs from 7 regions comprising the bulk of tight oil production actually experienced a dramatic decline to 579 units as of July 2015. Another factor that has allowed US shale oil players to cope with Saudi Arabia’s high production levels: break-even oil prices are lower than expected. This is has been due to the knock-on effect from productivity gains since break-even levels are moving targets. The break-even level of US$ shale players is as low as US$42/bbl with an average of around US$58/bbl. WTI breakeven levels for US shale plays

42 4350 52 53 54 55 56 58 61 62 65

73 7480

0102030405060708090

Eagle Ford Oil

Niobara‐Wattenber

Eagle Ford Condensate

PRB Tight Oil

Bakken (N

D)

Wolfcamp (Delaware)

Bone Spring/ Avalon

Woodford Cana

Missisipian Lime

Wolfcamp (Midland)

Utica

Bakken(M

T)

Anadarko

Tight Oil

Wolfberry

Wolfbone

WTI breakeven for US$ shale plays

Source: DBS Vickers, EIA

Industry Focus

Oil & Gas

Low crude oil price has not led to any significant pickup in

demand either China will still be adding 0.3mmbpd incremental oil demand in 2015/16 but it will no longer be the demand driver like in the past. China’s economic data has been weak in recent weeks. The stock market turbulence and Yuan's devaluation also stoked fears of hard landing and collapse in demand for commodities. Overall OECD inventory levels continue to rise from 58 days at the end 2014 to about 63 days of supply currently.

OECD oil inventories and forecasts

Source: DBS Vickers, EIA

Structural issues likely to impact oil-prices ahead


Industry Focus

Oil & Gas

Indonesia: the era of easy oil & gas drilling is over We see more challenges from economic and technical aspects for our long-term crude oil price assumption of US$70 per barrel. At the current crude oil price range, which is hovering around US$50-60 per barrel, many new projects commenced in the last three years should be postponed, if not halted, given the diminishing drilling economic feasibility. Technically, even excluding the estimated time periods for dealing with administrative work, Indonesia's time to production will naturally expand given the shift to more complex offshore reserves which require more financing and technology, a risk taking without proven risk-and-reward profile. In this section, we will only discuss on Indonesia's reserve profile and its monetisation challenges, on top of uncertainties in government reform progress and blue print, which we will discuss in the next section.

New reserves locked offshore, Eastern part of Indonesia In the oil & gas business, crude oil prices also determine the field economic feasibility covering the risk tolerance, financing and technical aspects. This means, at our long-term crude oil price assumption of US$70/bbl, not all existing and potential oil field projects are economically feasible or in the better case, it would take a longer project payback period. Indonesia's current cash cost/bbl has reached US$30/bbl, blended between onshore and offshore cash cost average of US$20/bbl and US$40/bbl respectively, with major onshore projects, old wells. However, current old fields are entering their period of decline. Exploitation stage contract area (%)

Onshore58.8%

Offshore41.3%

Source: DBS Vickers, SKK Migas

Meanwhile, on the other hand, 75% of remaining resources are located offshore, shallow & deepwater, in remote Eastern Indonesia, according to our discussion with Indonesia Petroleum Association (IPA). As offshore drilling is exposed to more challenges due to the remote and harsher environment, offshore, mainly on deep water drilling, is only feasible when the crude oil price is above US$70/bbl. Resources by theme

Source: DBS Vickers, IPA Potential reserves by location

Source: DBS Vickers, IPA Indonesia largest offshore mega project is also potentially delayed. We estimate that the project would only feasible at crude oil price of above US$70/barrel or at least at our long-term crude oil price assumption, given its more comprehensive operational challenges and field locations. Even successful exploration will require additional rig time to appraise discoveries. The government provides a better PSC scheme for deepwater drilling.

Industry Focus

Oil & Gas

Indonesia's large offshore projects

Projects Description

Indonesia deepwater development project (IDD) - Chevron

Integration Gehem-Gendalo-Bangka Project to monetise 3 TCF of gas reserves with an estimated total project capex of US$12bn. Project still awaiting approval revision POD

Abadi Masela Floating LNG project - Inpex

Floating LNG project in the South Maluku - Abadi field for the monetisation of gas reserves of approximately 6 TCF with total capex of US$7bn project. Project awaiting approval PSC contract extension

Tangguh Train III - BP Train 3 expansion project with a capacity of 3.8m MPTA and capital expenditure estimated at US$12. FID is expected in 2015 and go on stream in 2019

East Natuna Project 0 (Pertamina-Exxon-Total-PTTEP)

East Natuna Project (d/h Natuna D-Alpha) has 222 TCF reserves which 46 TCF can be produced due to the high CO2 content of 70%. Total capex estimated at US$24bn and planned decision FID 2016

Source : IPA, DBS Vickers

Gas dominates potential resources; distribution and

infrastructure availability is the key issue

85% of remaining potential resources is dominated by gases which means, future reserves discoveries and production activity will be more on gas. On the other hand, fewer oil discoveries means that long-term oil reserves replacement ratio will remain at the current low level. In this section, we try to assess the impact on Indonesia's oil & gas landscape if gas play a more important role in Indonesia's energy mix. Resources by type

Source: DBS Vickers, IPA In terms of the drilling technique, investment and field infrastructure requirements, they are relatively similar with drilling oil. However, the difference is in the monetizing, transporting and finding buyers in the Eastern part of Indonesia. Major gas distributors like PGAS and Pertagas do not have infrastructure in the Eastern part of Indonesia in the absence of a captive market comprising mainly industry buyers.

Gas distributors are only willing to invest in distribution and transmission pipeline infrastructure if a certain area has a potential captive market. PGAS's distribution infrastructure focuses on Sumatera, East Java and West Java, where industrial and manufacturing activities are the busiest. PGAS working scope (SBU I, II & III)

Source: DBS Vickers, Company Moreover, unlike the Western part of Indonesia, the Eastern part is more scattered and separated by seas. This means that even distribution and transmission infrastructure has less economical feasibility on a shorter and narrower pipeline scope of work. Underwater natural gas transportation will also take time to build and is expensive. Given the absence of potential buyers in the Eastern part of Indonesia, transportation alternatives such as shipping is also less economical vs. onshore pipeline distribution. We estimate

Industry Focus

Oil & Gas

that the transportation cost per MMSCFD is 40% higher than via onshore pipeline. Moreover, there are further infrastructure requirements such as a dedicated LNG port and storage. The only solution is to sell the gas at a higher price, but amid the weakening economy and natural gas demand as we discussed on our Perusahaan Gas Negara coverage, we believe that it will be more difficult to find buyers from third-party distributors or end users for gas produced in the eastern part of Indonesia. In reality, major industry players are suffering from high energy costs amid the weakening IDR. Some industry associations have urged the government to lower the natural gas price, an indication that buyers are being squeezed by competition and weak consumer purchasing power. This implies the eastern part of Indonesia's gas price will not be competitive vs. existing onshore gas produced. A prolonged story on upstream supply bottleneck is also not really valid in the current weak economy as the problem also arises from the weakening demand. This means, with a higher price, more expensive natural gas will not find any buyers right now. Produced & remaining oil and gas profile

Source: DBS Vickers, IPA Another example of the Eastern part of Indonesia is Masela block, which current project status is under review, a move which will potentially delay the country's largest deep water gas project. Coordinating Minister of Affairs Rizal Ramli called on SKK Migas and pointed out that the development of the gas block should be linked to an onshore LNG plant instead of an offshore floating plan proposed by Inpex. This confirms our thesis that the eastern part of Indonesia is hardly marketable given the infrastructure and geographical challenges. Hence, the export market is the best option for this region's oil & gas projects, which at the same time also means that the eastern

part's upstream oil & gas activities will not significantly help Indonesia. Existing onshore reserves need enhancement and

unconventional technology, but it is costly

Existing production oilfields, at an average age of 12 years, is entering their period of decline. Boosting oil & gas production in old wells requires technology which will raise the drilling cost higher than conventional earlier stage wells. This means oil drillers' cash cost will rise in the coming years as they will try to monetise the existing fields further while waiting to exploit their newfound reserves when oil price is at its peak. Oil production will enter its decline phase after 40-50% of the oil field reserves have been monetised. We estimate that the current wells have a remaining life of eight years, and assuming that the reserve replacement ratio remains at the current level of 60%, most of Indonesia's wells are entering their declining phase. Oilfield production profile

0

5

10

15

20

25

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

Oil lifting (MBOPD)

Source: DBS Vickers, Company The oil & gas production volume composition in a certain contract area also indicates the concession working phase. Indonesia's current concession is dominated by gas, and according to oil & gas field production's rule of thumb, gas will dominate the production portion at the end of production phase. We estimate current low cost producers' cash cost per barrel (average US$20 per barrel), 70% of current existing producing field, which are located on-shore, also will not sustain ahead as further technology and effort to maintain the oil production. We estimate the old well reactivation to take another US$5-10/bbl of cash cost which means the production cost will be close to or even beyond the offshore drilling cash cost of US$40/bbl.

Declining phase

Plateau phase Build up period

Industry Focus

Oil & Gas

SKK Migas encourages PSC contractors to carry out Enhanced Oil Activities both in the study and the Field Trial/Pilot Stage. There were four trials/pilots in 2014 as below:

Kaji Surfactant Polymer, Medco E&P, completed in May 2014

Tanjung Surfactant, Pertamina E&P, completed in March 2014

Widury Polymer , CNOOC, expected to be completed in 2018

Old Rimau Electrical EoR, Medco E&P, expected to complete in 2015

The pilot project has completed but we do not see the EOR activities being fully implemented given their high cost and reduced feasibility at the current crude oil price level, according to our talks with contractors. Contractors prefer to maximise their remaining reserves, as long as they provide an acceptable level of profitability to survive amid the currently challenging situation. Unconventional drilling technologies such as shale gas, tight gas and CBM to exploit trapped oil in rocks. Hydraulics fracturing will push bunch of water chemicals and sand into the rocks, breaking them apart and releasing the trapped energy. Combining the fracturing technologies with horizontal drilling will provide better penetration to the energy-bearing rock. Horizontal drilling and fracturing illustration

Source: DBS Vickers, Greenlight Capital Unconventional gas projects require extensive financing and capital expenditure, mainly for technology and infrastructure. Moreover, these projects also require a high crude oil price level in order to be able to secure bank financing and government support, in our view. Otherwise, at our long-term crude oil price, the projects will be risky as operators potentially incur

negative earnings in the first decade of operations, implying that every dollar invested in the project will be initially burning cash. Unconventional contract areas have stagnated in the past three years, reflecting the challenges on the field. Indonesia's unconventional contract areas rose from seven in 2007 to 66 in 2012, but they had stagnated until 2014. The development in this contract is in line with global shale revolution in 2009-2014. However, as the projects require huge financing with unproven outcome in Indonesia, new contract proposals have fizzled out, leaving behind the existing unfinished unconventional contract areas. Unconventional contract areas (contracts)

7

2023

4

54 55 55 55

0

10

20

30

40

50

60

2007 2008 2009 2010 2011 2012 2013 2014

Unconventional CA


Enter Jokowi: Industry reform in progress, but seems to

be taking time 'Contract sanctity and clear tax regulations will be key factors for the continuity of exploration and production activity'. Moreover, 'significant/radical regulatory changes are required to spur investments in exploration such as VAT & import facilities, complete non-compliance with PTK 007 for exploration activities, better fiscal terms (investments credit, DMO and tax holidays), relaxation of expats' working permits requirements' according to PWC 2015 oil & gas survey participants' comments. The survey also showed that major participants expect there to be no changes/reforms in Indonesia's oil & gas sector.

Industry Focus

Oil & Gas

Quality and usefulness of government regulations

Significantly improve7.0%

Improve33.0%

Remain the same44.0%

Deteriorate16.0%

Source: DBS Vickers, PWC Indonesia's oil & gas production volume is the largest in Southeast Asia, and the country has high production potentially as large areas remain under-explored (mainly in the Eastern part of Indonesia) due to technical challenges on high CO2, deep-water and unconventional hydro carbon structure. Foreign and domestic oil & gas contractors are also interested in Indonesia's oil & gas industry, mainly on its attractive geographical area. Despite its challenges, the country also offers an appealing risk-and-reward potential. Indonesia's environmental rules and regulations are also not as complicated as those of the developed countries. Oil production ('000 BOPD)

0

100

200

300

400

500

600

700

800

900

Indonesia Malaysia Thailand Australia Vietnam Brunei

Oil


In the paper, in order to unlock and exploit its oil & gas assets, Indonesia should liberalise its oil & gas assets via partnerships with both domestic and foreign contractors, who have better access to financing, technology and proven execution track record. However, in reality, we see Indonesia's PSC scheme and overall oil & gas regulations as being provide less support and

incentives to domestic and foreign contractors, in our view, unless crude oil price reaches above US$75 per barrel, according to our estimate. We understand this is part of the government's initiatives to protect, and meanwhile maximize the benefit and national revenue from the national oil & gas assets. There are also no relevant short-term incentives for the upstream oil & gas industry, amid the low crude oil price in order to keep the existing projects afloat and new investments attractive. The government appears to be passive, resulting in very slow progress in industry reformation as per the new government's election blueprint. The first stage of the reform, is by plan to dismiss Pertamina's overseas trading arm PT Pertamina Energi Trading Ltd (Petral). However we see that the dismissal plan, which has been heavily exposed by the media as the key reformation of oil & gas industry, will not significantly change the landscape of the national oil & gas industry unless, the reform also radically streamlines the national oil & gas regulations and workflow, which caused the major project bottlenecks in the past two decades. Moreover, Petral's major debtors and business partners are national oil companies such as Pertamina and CNOOC. Hence, the dismissal will also mean disappearing potential income and thus, we also believe the dismissal progress will be challenged by some parties, including the House of Representatives. The government's plan to raise fuel storage capacity amid the upstream sector transformation also signals that the government expects the upstream oil & gas transformation progress to be challenging and slow. We understand the government's plan is positive for Indonesia's energy security to extend Pertamina's fuel reserves to 30 days from 22 days. However, without parallel transformation work from the upstream side, we only see that the fuel storage capacity expansion signals that Indonesia will continue to import fuel in the short to medium term to fulfil its domestic demand.

One-stop services via BPKM to only solve marginal

challenges

The new application is for a one-stop service via Indonesia's Investment Coordinating Board (BKPM). The initiative is to reduce the bureaucracy in applying for working permits and provide a better investment climate mainly for foreign investors. However, we think BKPM's one-stop service will only cover the initial scope of permit and licensing, for new potential investors. This policy does not specifically address the struggling, existing

Industry Focus

Oil & Gas

investors who are in the midst of obtaining approval via the old procedures. Moreover, the one-stop service policy also does not address the new and existing investors' concerns such as the contract renewal process. Investors under this phase face uncertainties on asset valuation over Pertamina's intention to take over the expiring PSC, and local government intervention during the renewal process. We estimate this one-stop policy to only reduce a quarter of the bureaucracy layer but leaves the most challenging bureaucracy barrier such as the local government's coordination with central government. Moreover, we see investments and licensing as being only the tip of the iceberg as shown in the previous chart and table. We believe local government bureaucracy is challenging as the coordination between local and central government remains unclear. The same concerns are also raised on the power plant project licensing. So far, we do not see any strategy to strengthen the coordination between local and central government and hence, we think the streamlining process still has a long way to go.

Current PSC scheme, at current crude oil price range, is

unattractive for new oil & gas investments

Given the lack of expertise and financing on exploration and execution, the government has structured a production sharing contract with oil contractors. Indonesia was the first country to introduce a structured production sharing contract in 1966. The majority of the government's partners are foreign oil & gas contractors given their expertise and technology in various oil fields, both onshore and offshore. Production sharing contract (PSC) is granted by Indonesian government via SKK Migas to one or more contractors to explore, develop and produce oil & gas reserves and resources in designated working areas. The sharing contract work structure is the oil companies act as the government oil and gas third parties partners with pre-agreed allocation of oil remaining after payment of cost oil.

Indonesia's PSC scheme in chart

Source: DBS Vickers, SKK Migas On the sharing portion, government will take 85% and 70% share on an after-tax basis, leaving the rest for the contractors. The production sharing contract is favourable to government, in our view, as the government acts as a passive investor/landlord with oil & gas ownership and let the contractors work with a smaller sharing portion. The cost recovery scheme is also only applicable if a particular oil field is granted commercial status. Given the PSC term above and the <50% contractors' share, we believe the current PSC scheme significantly reduces Indonesia's oil & gas investment's attractiveness and competitiveness amid the current low crude oil price, as contractors are exposed to the downside risk, mainly in the expensive pre-production stage. We understand that the contractor is typically entitled to recover its exploration and production costs. However, the cost is only recoverable if the government ensures that a project is guaranteed a certain desired return on investment and obtains commercial status or otherwise the project should be terminated. Moreover, SKK Migas could also terminate the contract that fails to secure new reserves, or if the newly proposed PSC provides only a marginal return, in a certain timeframe determined by the government. The contract recently terminated was for Total's concession in South West Bird's Head, Papua. The government will terminate 15 PSCs this year after terminating 20 last year.

Industry Focus

Oil & Gas

Contract area status (2014)

Exploitation CA22.2%

Exploration CA64.4%

Approved termination CA

2.2%

Undergoing termination CA

11.2%


Moreover, proposed PSC revision is marginal; we do not

see it enhancing oil & gas investments' attractiveness

Contractors are being offered as much as 35% of production split for oil and 40% for gas, higher than the existing split of 15% and 30% respectively, in an attempt to attract investors. Although there is no final draft on the proposal, we think this it is positive on paper as the current PSC scheme offers unattractive returns to contractors at the current crude oil price, or even at our long-term crude oil price assumption. Three key options for PSC changes :

All costs will be recoverable. However, the government's revenue split will be higher than the current portion

Gross split system. Contractors will not able to recover their costs. However, they gain a larger revenue split until their investments reach breakeven point, following which the government's split will gradually widen.

Sliding scale system. Contractors costs are still recoverable. However, the government's revenue split is progressive; 1% for oilfield with 5bn BBTUD threshold and the government will charge a higher split if production exceeds the threshold.

However, we see the higher revenue split to contractor being only applicable at the early stage of the project before the contractor reaches the breakeven point of their investments, following which the government's revenue split will be widened again. We think this proposal does not change the overall net split between the government and contractors. It only manages the timing of cash flows and help contractors to survive in the current low crude oil price environment, mainly in the early stage of development. Although the final draft on the amendment has not been released yet, we do not think there will be any radical changes on the regulations as the government also has its own oil & gas

revenue target to meet the national revenue and spending budget. Even without the PSC term revision, currently oil & gas revenue is projected to decline by 20% y-o-y to Rp20.2tn in FY16, after dropping by 45% y-o-y to Rp24.5tn in FY15. We believe the government will not sacrifice more revenue streams from the natural resource sector as it recently halted the royalty hike from thermal coal miners as per miners' request for low commodity prices. O&G and mineral & coal mining revenue (Rptn)

35.237.3

47.4

29.3

42.9

24.6

20.2

7.8

14.512.9 11.6

16.4

27.7

32.7

0

5

10

15

20

25

30

35

40

45

50

2010 2011 2012 2013 2014 2015F 2016F

Oil and gas Mineral and coal mining

Source: DBS Vickers, various media Pertamina plans to take over the expiring PSC, raising

uncertainties for existing and potential investors

Recently, the government appears to have taken over the expiring PSC which also put Indonesia's oil & gas industry under scrutiny. The Mahakam block takeover is also the government's opportunity to boost national oil & gas income. This plan raises uncertainties for new and existing investors. This also raises doubts on the government's one-stop services via BKPM as we had discussed previously, as we see this plan as being contrary with sector liberalisation the partnership with contractors to exploit national oil and gas reserves. SKK Migas has also not completed valuing the assets of Mahakam Block given its size, according to the media. Uncertainties on oilfield asset values also put stakeholders involved in contract renewal negotiations under uncertain circumstances as the values of underlying assets they are negotiating for are undetermined. This is means that the negotiations will likely take a longer time. The Mahakam block case also triggers uncertainties for contractors in other oil fields. The existing PSC has eight years of remaining life, which we think is relatively short considering Indonesia's oil & gas operational phase's slow progress. Moreover, according to SKK Migas, the average contract

Industry Focus

Oil & Gas

renegotiation should commence at the latest 10 years before the contract expiration. We expect the takeover plan to disappoint contractors as the government will enjoy and continue the exploitation phase, leaving the previous contractor to incur billion dollars' worth of investments in the preliminary exploration stage. We also see this action triggering foreigners' perspective concerns on asset nationalisation and hinder new investments in the sector, although at the first stage, Pertamina will grant an option for a 30% stake to the existing PSC holder for a smooth transition process. Previously under PSC contract, Total and Inpex had a 50:50 share split and it is scheduled to expire at the end of 2017. But the government has endorsed Pertamina to become the new operator of the Mahakam block, taking over Total's role and scheduled to start operating in January 2018. The President has the final say on the future of the expired PSC as seen in the Mahakam block case among Pertamina, Total and Inpex. The Mahakam block currently produces around 1.6bn standard cubic feet, accounting for 25% of national production. Besides the central government's final decision, the local government will also play a key role in share negotiation as in the Mahakam case, the East Kalimantan governor was also involved in the Pertamina share negotiation. Pertamina is looking for a majority share of 70% and due to the size of the block, Pertamina is asking Inpex to stay in Mahakam as a partner with a proposed share of 30%. Total EP's rejection of its share swap option with Pertamina's overseas oil & gas assets further complicates the PSC contract renegotiation. Total believes the current PSC reassessment itself will take a very long time, while the share swap scheme also poses a challenge mainly on valuation works. Beyond the Mahakam case, media news flows also indicate that Pertamina is also looking to take over another expiring block like Cepu which is currently operated by Exxon Mobil and will expire in 2018. Pertamina's rationale is to secure the gas supply as Arun LNG facility will start to operate soon. Previously, Arun's operations were halted in October 2014 as its LNG export contract expired. Unavailability of financing and technology expertise are

the key execution risks

The high investments required to fulfil Pertamina's aspirations in both upstream and downstream segments raises questions

on Pertamina's financing capability as the company's balance sheet strength and earnings performance are also relatively weak. Based on Pertamina's sluggish financial performance, but high capex plan in the next three years for both upstream and downstream segments, we are doubtful on Petamina's capability to take over the expired PSC from the existing contactors. Lower crude oil price has also hit Pertamina's financial performance as seen recently in 1H15. Pertamina EP's revenue and net profit fell by 64% y-o-y and 38% y-o-y on weaker oil price, while production of both oil & gas at 105.8 mbopd and 1,030 MMSCFD respectively, fell short of expectations. On the other hand, besides the plan to take over the upstream expired PSC, Pertamina via Pertagas is also looking to expand on the middle segment by developing its LNG storage facility and distribution network around Indonesia with imported LNG. Beyond the distribution and storage segments, Pertagas is also considering the gas-fired independent power plant (IPP) project business with key project of gas-fired power plant (PLTG) Jawa 1, Jawa 3 and Riau, partnering with foreigners. Pertagas first attempt in power plant project also raises concerns as the current power plant projects are facing multi-year delays on land acquisition problems. We understand that the government's plan is to increase government presence via expanding Pertamina's role as the largest national oil company after it dwarfed by the Law 22/2001. But on the other hand, we also think Pertamina cannot afford the execution under the current PSC scheme, as contractors will execute all the operations and equipment with their own finances and expertise.

Struggling upstream oil & gas drillers also negatively

impact the whole supply chain Challenging upstream oil & gas environment is also negative for the supply chain, including downstream and distributors. Oil & gas service revenue derives from contractors upstream investment spending both in exploration and exploitation stage. However, low crude oil prices have potentially halted oil & gas investments in Indonesia further, after experiencing a flattish growth trend in the past decade. Indonesia's oil & gas service companies are in a fragmented industry, where each players only has a single-digit market share. This could potentially trigger a price war in contract fee in order to win new contract tenders and maintain current contracts in order to stay alive.

Industry Focus

Oil & Gas

ELSA quarterly revenue trend

(10)

(5)

0

5

10

15

20

25

0

200

400

600

800

1,000

1,200

1,400

1Q11

2Q11

3Q11

4Q11

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

Revenue EBITDA margin

Source: DBS Vickers, SKK Migas The implication to oil & gas distribution business Upstream problems also raises difficulties for oil & gas distributors as it means the domestic oil & gas supplies will not sufficiently catch up with the growing demand. As seen in Perusahaan Gas Negara (PGAS, HOLD, TP Rp2,600), the largest national natural gas distributor, its historical distribution volume growth has stagnated in the past decade. PGAS cannot fully monetise its infrastructure monopoly, premium distribution spreads and captive market in Java and Sumatera. Please refer to our PGAS full reinstatement coverage report Caught between a rock and a hard place, released 13 July 2015. We also believe oil & gas distributors are more likely to be subject to regulations mainly on the gas price, as distributors have enjoyed a wide distribution spread in the past decade. Regulating the gas price in the upstream level could potentially add further complexity as upstream contractors' scope of work has been written based on the PSC with the government.

PGAS historical distribution volume (MMSCFD)

579

792824

800 807 824 852

0

100

200

300

400

500

600

700

800

900

2008 2009 2010 2011 2012 2013 2014

Distribution volume


Indonesia's oil & gas: from net exporter to importer

Amid the raising oil & gas demand, domestic oil & gas production peaked in 1995, and has then continuously trended down. It has been missing its annual production target since 1998, given the lack of new exploration investments and several execution issues on exploitation phase projects. Lack of financing, technology and bureaucracy hurdles are the key issues on domestic oil & gas reserves monetisation. Indonesia's oil & gas industry complication started from the establishment of Law (UU) No. 22/ 2001 on upstream oil & gas. This regulation dwarfed the national largest oil & gas company (NOC), Pertamina's role and add government entities called Special Task Force for Upstream Oil & Gas Business Activities Republic of Indonesia (SKK Migas, formerly known as BP Migas). Changing business relationship from B2B to B2G raises the complication of the industry, mainly on dealing with bureaucracy before facing the fields' technical challenges.

Industry Focus

Oil & Gas

Indonesia's oil & gas production 1966-2016F

0

200

400

600

800

1000

1200

1400

1600

1800

2000

1966

1968

1970

1972

1974

1976

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

2014

2016

F

Oil Gas

Source: DBS Vickers, IPA, SKK Migas The increase of bureaucracy, besides the financing and technology hurdle, has caused domestic national oil & gas lifting volume downtrend. Indonesia's peaked oil production in 1995 also triggered by the longer of time lag between the oil findings and production startup. Indonesia's oil & gas industry's timeline between discovery and production start-up jumped from five years in 1970 to 17 years in 2000 and above. We estimate technically, assuming lean permit and working paper, each field only requires three years on average from discovery to production start-up. Hence, the rest of the 14 years are dedicated to the non-field activity mainly on administrative tasks. However, the time to production jumped significantly after the second generation and newer PSC. We also believe second generation PSCs also contribute to the Indonesian oil & gas production slowdown due to more complicated nature of second generation PSC vs. the first generation as the government changed terms to ensure every field generated sufficient positive cash flow for the government.

Time to production (years)

56

12

17

0

2

4

6

8

10

12

14

16

18

1970s 1980s 1990s 2000s

Source: DBS Vickers, IPA Concurrent with extending production time, despite the downtrend on the oil & gas production volume, Indonesia's oil & gas reserves replacement ratio has continued to drop since 2007. Latest oil & gas replacement ratio only reached 46.6% and 90.2% respectively, which means that every year, Indonesia's oil & gas reserves are depleting and if there are no significant exploration discoveries, the country's oil & gas reserves will evaporate.

Law 22/2001 era Plateau stage

1st generation PSC

Industry Focus

Oil & Gas

Oil & gas replacement ratio (%)

32%

62%

23%

63%82%

52% 47%35%

180%

69%

310%

130% 127%

90%

0%

50%

100%

150%

200%

250%

300%

350%

2007 2008 2009 2010 2011 2012 2013

Oil Gas

Source: DBS Vickers, IPA Indonesia's exploration investment is also trending lower, which means the reserves replacement ratio will stay below 100%, and the country's oil & gas reserves will continue to deplete. Flattish trend in exploration investments in the last five years implies limited new oil & gas findings. Oil & gas investment trend

‐

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2009 2010 2011 2012 2013 2014

Expliration Development Production Administration

Source: DBS Vickers, IPA, SKK Migas

This also implies that Indonesia oil & gas production rate will continue to decline in the incoming years. SKK Migas itself even believe that Indonesia's oil & gas production will continue to trend down. According to SKK Migas 2014 annual report, Indonesia's oil & gas production will decline by 300k BOEPD per year in 2015- 2050.

SKK Migas domestic oil & gas production forecast


Slow reform on oil & gas, negative impact to Indonesia's

macro-economy

Indonesia's oil & gas revenue account lower contribution to national total domestic revenue in year after year. Domestic oil & gas sector government revenue only reach Rp212tn, 13% of the state's total revenue in 2014. Oil & gas sector revenue contribution to domestic revenue has been trending lower in the past decade. Oil & gas revenue contributed 21.4% in 2004 and based on PWC's estimate, oil & gas revenue will only contribute 5.1% in 2015. Oil & gas revenue trend & % to domestic revenue

0%

5%

10%

15%

20%

25%

30%

0

50

100

150

200

250

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

O&G revenue % domestic revenue

Source: DBS Vickers, PWC, SKK Migas

On the other hand, as Indonesia's oil demand grows amid the oil producers' struggle to increase output, Indonesia has started to import oil to fulfil the growing demand (see chart). However, this strategy has proven to create an inferior national trade balance, and burden the central government's spending for economic growth. Hence, we think Indonesia's oil & gas

Industry Focus

Oil & Gas

slow reform will also negatively impact Indonesia's economic situation. Indonesia's oil production and consumption

0

100

200

300

400

500

600

700

800

900

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Production Consumption Import

Source: DBS Vickers, SKK Migas Importing oil and maintaining a stable, reasonable retail fuel price amid the rising domestic oil demand means the government subsidy will continue to burden the government's budget. Energy subsidy to total spending reached 19% of the government's total spending in FY14. Meanwhile, infrastructure accounts for only 8%. This contradicts the government's plan to boost infrastructure expansion in Indonesia by allocating a large percentage of the budget for energy subsidy. Percentage to total spending

10%

13%

20%

21%

19%19%

8% 8%9% 10%

11%

8%

0%

5%

10%

15%

20%

25%

2009 2010 2011 2012 2013 2014

Energy subsidy Infrastucture

Source: DBS Vickers, IPA

Oil and gas Law 22/2001; B2B to B2G, dwarf Pertamina's

role as largest national oil & gas company That is our first impression we gathered from reading points in Law 22/2001. The law is structured to maximise government benefits as the upstream business activities, mainly on exploration of non-renewable natural resources of state assets, and leaves contactors with a minority portion of the revenue.

Shifting the contract scheme from B2B to B2G has proven to be ineffective as its means the cash flow and value contribution from the Indonesian oil & gas activity will be less measurable and accountable, in our view, relative to a B2B scheme via a limited liability, state-owned company. The current B2G scheme means investors/contractors should deal with the government entities, and not state-owned companies. The government has full control on all the oil & gas found in the country. This means investors should first complete the bureaucracy matters before the first exploration study. The law also states that Pertamina, as a limited liability company (Perseroan Terbatas, PT), will only focus on its operations as an independent state-owned oil & gas company and thus, forces Pertamina to compete with other domestic and international companies. The Law dwarfed status of Pertamina as key single executor and supervisor of national oil and gas, and create a government entity called SKK Migas (previously BP Migas) beyond Pertamina and take over its role. The law requires the state-owned oil company to be treated like other privately-owned, independent ones, both foreign and domestic contractors. Since then, the relationship between the oil & gas contractor and government has become a B2G (Business to government) arrangement instead of a common B2B (Business to business) joint venture. In November 2001, Indonesia's parliament passed a new oil and gas law to replace the previous law, Law No.44/1960 and No.8/1971 under criticism against it from a number of groups such as national oil company, local government and environmental groups. The new law aims to scrap the monopoly of Pertamina and liberalise Indonesia's oil & gas sector. The bill promises fundamental changes in the governance of Indonesia's oil & gas industry by establishing two new government entities; implementing and regulatory bodies. The implementing body is assigned to regulate the upstream sector and take over Pertamina's role on supervision and entities, to work with foreign contractors ended and handed over to BP Migas (Executing Agency for Upstream Oil and Gas Business Activities), which in 2012 the Constitutional Court (MK) issued MK Decision 36/2012, annulled articles of the oil & gas law relating to the authority, role and function of BP Migas, therefore BP Migas ceased to exist. In the meantime, MK has ordered all authority and responsibilities of BP Migas to be

Industry Focus

Oil & Gas

transferred to the Indonesian government via Ministry of Mineral Resources until a new oil & gas law is adopted. Indonesia's oil & gas industry is one of the worst in the world, according to Mr. Kurtubi, member of house of representative, who is also an oil & gas industry reformation activist. Industry participants, from survey to exploitation phase, will need to submit more than 600k sheets of documents, complete with customised terms and covering a multi-sectoral scope. Number of permits

Permits

Ministry of energy and mineral resources 52

Ministry of finance 14

Ministry of forestry 40

Ministry of transportation 58

Ministry of industry 3

Ministry of trade 12

Ministry of Nakertrans 14

Ministry of communication and informatic 11

Ministry of defense 3

Ministry of human right 4

Indonesia National Army 2

Indonesia National Police 19

Ministry of agriculture (BPN) 3

Local governor 35

Local mayor 66

Nuclear energy regulatory 4

IUPHHK holder (private entities) 2

Total 341

Source : IPA, DBS Vickers This will negatively impact the monetisation of national oil & gas reserves, as it theoretically needs eight to 10 years from survey to exploitation stages. However, in reality, Tangguh, Senoro, Masela and Banyu Urip Cepu took 16 years, 16 years, 17 years and 10 years respectively before their initial commercialisation. We think the base case of eight to 10 years' time horizon itself is too long to deal with as Indonesia's average governmental tenure is only five years. This means there are risks of rework and delay in the government transition. This is not to mention the potential regulation changes along the way as each

government has its own policy and plan to reform the industry. We think that is why in reality the time horizon is always longer than investors expected. Number of permits per operational stage

26

85

107 109

14

0

20

40

60

80

100

120

Preliminary survey Exploration Development Production Pra‐production

Permits

Source: DBS Vickers, IPA

Indonesia's exploration-to-exploitation ratio, which indicates the numbers of contract areas converted to exploitation stage, dropped from 86% in 2012 to 40% in 2014. This means most of the new exploration projects have not been converted to the production stage. Hence, Indonesia's oil & gas industry growth will continue to rely on existing contract areas. We believe this is reflected by the number of permits as per previous chart, where most are in the development and production stages. Exploration-to-exploitation ratio (%)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Exploitation/exploration CA ratio


Industry Focus

Oil & Gas

Appendix

Indonesia PSC scheme

Revenue100

Equity To Be Split 65

Net Revenue To Be Split85

Total Contractor Share 40.50

Net Contractor Share25.50

Total Government Share59.50

Tax Payment (23.54)

Tax Revenue23.54

Government Share35.96

Contractor Share49.04

First Tranche Petroleum20

Cost Recovery15

20%

42.3077% 57.6923%

48%

Source: DBS Vickers, Company Indonesia PSC payment scheme

Revenue From Buyer100

Paying Agent100

Government Account35.96

Contractor Account 64.04

Tax Payment(23.54)

Received Tax Payment23.54

Ending Balance59.50

Ending Balance40.50


Industry Focus

Oil & Gas

Indonesia's product sharing contract agreement summary: The contractor is responsible for both technical and

financial operations, while the equipment purchased by the contractors become the property of SKK Migas.

Contractors do not pay any royalty but pay corporate and dividend tax instead (total around 48% comprising 35% of corporate tax and 13% of dividend tax, assuming 20% payout ratio).

Contractors obliged for First tranche Petroleum (FTP), deduction of production to guarantee government a minimum share of the petroleum production. The deduction is 20% of gross revenue prior to cost recovery and will be shared between the government and contractor.

Contractors must relinquish a portion of crude oil to fulfil domestic market supply (DMO) 25% of contractors' share before tax times lifting times price.

Key historical development of Indonesia PSC

The revolution of PSC from generation to generation has become increasingly unfavourable to the contactors. The latest oil and gas law 22/2001 requires the product sharing contract granted by the government to be via SKK Migas instead of Pertamina as the national oil company and this is the point where Indonesia's exploration investments and oil production start to gradually decline every year. The first generation PSC (1966-1976) had the final management by approving the Work Program, Budget and

Plan of Development with Pertamina/contractor share of 67.5%/32.5% if the production level exceeded 75,000 barrels of oil per day (BOPD). Second generation PSC's basic principle remained the same but the cost was calculated based on the accepted accounting principles without a 40% ceiling (100% recovery). However, it raised complications as to low crude oil price, high cost but small reserve field might not provide income to the government during its lifetime. To cope with this concern, NOC created a new rule 'Declaration of Commerciality', whereby a field could only be classified as commercial for development if there was at least 49% of the cash flow for the government. This raised concerns from the contractors as NOC held the authority to determine whether an oil field is commercial or otherwise. Operators could not recover their costs for non-commercial oil fields. Under the third generation PSC (1988-1999), the government issued incentives to enhance oil exploration activities. The government's minimum take was reduced to 75% from 85%, while those for smaller fields in conventional and frontier areas were reduced to 80% and 75% respectively. In 1988-1994, the government issued a series of exploration incentive packages to encourage new exploration in high-risk areas, especially in the Eastern Part of Indonesia. The 1992 incentives contained improvements to existing contracts to increase exploration in high-risk frontier areas such as 125% incentive credit for water depths in excess of 1,500 metres.

Industry Focus

Oil & Gas

List of expiring PSCs

Block Operator Stakeholders

Oil 1P Reserve (MTSB)

Gas 1P Reserve (BSCF)

Production (MBOPD)

Contract Expiry

Gebang Energi Mega Persada EMP 50%, Pertamina 50% 11.00 40.83 - 2015 Northwest Java Sea Pertamina PHE ONWJ 58.28%, EMP ONWJ 36.72%, Risco Energi 5% 75,330.00 315.50 41,168.46 2017 Mahakam Total E&P Indonesia Total 50%, Inpex Corp 50% 111,500.00 3,233.30 78,766.84 2017 Lematang Medco E&P Lematang Medco E&P Lematang 51.1176%, Lundin Lematang BV 25.8824%, Lematang E&P Ltd 23% 36.00 123.38 398.81 2017 Tuban JOB Pertamina - Petrochina East Java CNPC 12.5%, Pertamina 75%, Petrochina 12.5% 27.88 20.60 5,257.10 2018 Ogan Komering JOB Pertamina - Talisman (Ogan Komering) Talisman 50%, Pertamina 50% 3,191.00 18.80 2,746.48 2018

Sanga-Sanga Vico BP East Kalimantan 26.25%, Lasmu Sanga-Sanga 26.25%, Virginia Indonesia Co Llc 7.5%, OPICOIL Houston Inc 20%, Universe Gas and Oil Company 4.375%, Virginia International Co Llc 15.625%

13,232.00 448.96 16,733.23 2018

South East Sumatera CNOOC SES Ltd

CNOOC Ltd 65.54%, Pertamina 13.07%, KNOC 8.91%, Risco Energy 5%, Fortuna Resources (Sunda) Ltd 3.77%, Talisman UK (Southeast Sumatera) Ltd 2.08%, Talisman Resources (Bahamas) Ltd 1.64%)

33,799.00 214.14 34,199.67 2018

B Block ExxonMobil Oil Indonesia ExxonMobil 100% 3,343.00 104.00 2,408.81 2018 NSO Extention ExxonMobil Oil Indonesia ExxonMobil 100% 272.00 92.00 - 2018 Tengah Total E&P Indonesie PHE 50%, Total Tengah 22.5%, Inpex 22.5%

1,000.00 38.10 w/ blok

Mahakam 2018

East Kalimantan Chevron Indonesia Company Chevron 92.5%, Inpex Corporation 7.5% 63,580.00 2,317.87 19,180.35 2018 Pendopo dan Raja JOB Pertamna Golden Spike Energy

Indonesia PT Golden Spike 50%, PHE Raja Tempirai 50% 13927

7.19 628.58 - 2019

Bula Kalrez Petroleum (Seram) Ltd Global Select 100% 2,168.00 - 413.44 2019 Seram Non Bula CITIC Seram Energy Limited CITIC Rescurces 51%, KUFPEC 30%, Gulf Petroleum 16.5%, Lion Energy 2.5% 6,170.00 - 2,758.78 2019 Jambi Merang Talisman Talisman 25%, Pertamina 50%, Pacific Oil and Gas Indonesia 25% 18,998.00 590.70 5,362.47 2019 Saith Jambi Blokc B ConaPhilips (Suth Jamti) Ltd ConccoPhlips 45%, Pertamina 25%, Petrochina Int Jambi 30% 38.00 5,782.00 - 2020 Brantas Lapindo Lapindo Brantas 50%, PT Prakasa Brantas 32%, Minarak Labuan Co Llc 18% 230.00 37.05 20.22 2020 Salawati Kepala Burung JOB PertaminaPetrochina Salawati PHE Salawati 50%, Petrochina Int KB 16.78%, RHP Salawati Island BV 14,51%, Petrogas (Island) Ltd

18.7% 3,915.00 21.63 1,393.21 2020

Malacca Strait EMP Malacca Strait S.A Kondur Petrcleum 34.46%, Malacca Petroleum ltd 6.93%, OOGC (Malacca Strait) Ltd 32,58%, PT Imbang Tata Alam 26,03%

12,624.00 37.19 4,498.51 202

Makassar Strait Chevron Makassar ltd Chevron Makassar Strait 72%, PHE 10%, Tiptop Makassar 18% 1,860.00 23.35 3,342.07 2020 Onshore Salawati Basin Petrochina Intemational Bermuda Petrogas Basin 34,06%, RH Petrogas 25,94%, Petrochina 30%, Pertamina 10% 28,112.00 59.96 4,993.19 2020 Bentu Segat Kalla (Bentu) Ltd EMP Bentu Ltd 100% - 119.40 270.48 2021 Rokan PT Chevron Pacific Indonesia Chevron 100% 1,174,262.00 77.13 283,767.19 2021 Selat Panjang Petroselat Ltd PT Petronusa Bumibakti 51%, Petrochina Int Selat Panjang 45%, Intenational Mineral Resources 4% 4,385.00 52.73 474.30 2021 Tarakan East Kalimantan PT Medco E&P Tarakan PT Medco E&P 100% 2,367.33 16.24 1,813.73 2022 Coasta Plains and Pekanbaru Pertamina PHE 50%, PT Bumi Siak Pusako 50% 61,512.00 - 13,098.46 2022 Muturi BP Muturi Holding BV BP Muturi Holding 1%, CNOOC Muturi 64.77%. Indonesian Natural Gas Resources Muturi Inc

34,23% - 3,965.20 - 2022

Bengkal MontD'Or MontD'Or Oil Tungkal Ltd 70%, Fuel X 30% 809.00 6.72 858.03 2022 Sengkang Energy Equity Epic (Sengkang) Pty ltd Energy Equity Epic (Sengkang) PTY Ltd 100% - 387.51 232.89 2022 Corridor ConocPhilips Grissik Ltd ConocPhilp (Grissik) Ltd 54%. PHE Corridor 10%, Talisman Corridor 36%, 35,858.00 4,785.94 13,774.46 2023 Rimau Medco E&P Indonesia Medco E&P Ranau 95%, Perusahaan Dareah Pertambangan Energi 5% 30,540.00 22.71 11,491.36 2023 Wiriagar BP Wiriagar Ltd BP Wiriagar 37,6%, Talisman Wiriagar 42,4%, K.G. Wiriagar Petroleum 20% - 1,035.70 - 2023 Jabung Petrochina Intemational Jabung Ltd Petrochina Jabung 42,86%, Petrogas Carigali 42,86%, Pertamina 14,29% 29,371.00 342.43 15,898.71 2023 Bangko Petrochina International Bangko Ltd Petrochina Intemational Bangko Ltd 100% 9,610.00 26.21 8.62 2025 Source : Media, DBS Vickers

Industry Focus Oil & Gas

Industry Focus

Oil & Gas

Company Profiles

ed: TH / sa: MA

HOLD Rp760 JCI : 4,374.19 (Initiating Coverage) Price Target : 12-Month Rp 820 Reason for Report : Initiating coverage Potential Catalyst: Crude oil price outlook Analyst William Simadiputra +62 2130034939 [email protected]

Price Relative

2 4

4 4

6 4

8 4

1 0 4

1 2 4

1 4 4

1 6 4

1 8 4

2 0 4

6 8 4 . 0

1 , 1 8 4 . 0

1 , 6 8 4 . 0

2 , 1 8 4 . 0

2 , 6 8 4 . 0

3 , 1 8 4 . 0

3 , 6 8 4 . 0

4 , 1 8 4 . 0

D e c - 1 1 J a n - 1 3 J a n - 1 4 J a n - 1 5

R e l a t i v e I n d e xR p

M e d c o E n e r g i In t e r n a s io n a l ( L H S ) R e la t iv e J C I IN D E X ( R H S ) Forecasts and Valuation FY Dec (US$ m) 2014A 2015F 2016F 2017F

Turnover 751 590 578 593 EBITDA 259 183 195 215 Pre-tax Profit 111 6 10 6 Net Profit 10 4 6 4 Net Pft (Pre Ex.) 10 11 6 4 EPS (Rp) 40.4 16.7 25.6 16.6 EPS Pre Ex. (Rp) 40.4 46.2 25.6 16.6 EPS Gth (%) (73) (59) 53 (35) EPS Gth Pre Ex (%) (73) 14 (45) (35) Diluted EPS (Rp) 40.4 16.7 25.6 16.6 Net DPS (Rp) 21.2 0.0 5.1 1.7 BV Per Share (Rp) 3,836.6 3,944.6 4,235.6 4,448.7 PE (X) 18.7 45.2 29.5 45.5 PE Pre Ex. (X) 18.7 16.3 29.5 45.5 P/Cash Flow (X) 1.1 1.9 1.5 1.4 EV/EBITDA (X) 3.2 5.1 5.3 4.9 Net Div Yield (%) 2.8 0.0 0.7 0.2 P/Book Value (X) 0.2 0.2 0.2 0.2 Net Debt/Equity (X) 0.7 0.8 0.8 0.8 ROAE (%) 1.1 0.4 0.6 0.4 Consensus EPS (Rp): 1,403.8 8,422.8 11,230.4 Other Broker Recs: B: 1 S: 2 H: 4 ICB Industry : Oil & Gas ICB Sector: Oil & Gas Producers Principal Business: Integrated energy company, explores and produces oil and gas both in Indonesia and internationally

Source of all data: Company, DBS Vickers, Bloomberg Finance L.P.

At A Glance Issued Capital (m shrs) 3,332 Mkt. Cap (Rpm/US$m) 2,514,927 / 179 Major Shareholders Encore Energy Pte Ltd (%) 47.0 PT Medco Energi International

7.0

UBS AG Singapore PT Medco

5.0 Free Float (%) 41.0 Avg. Daily Vol.(‘000) 1,645


Indonesia Company Focus

Medco Energi Bloomberg: MEDC IJ | Reuters: MEDC.JK Refer to important disclosures at the end of this report

Low cost driller Single digit EBITDA growth outlook

Low cost structure helps profitability

Expansion scale-back positive for cash-flows

Initiate coverage with Hold and TP of Rp820

In defensive mode. We forecast 2% EBITDA CAGR in FY15-17 on relatively flattish trends for oil and gas lifting volumes. We believe cash cost per barrel will be stable as Medco energy (MEDC) will rely on its current existing profitable reserves to maintain stable operational profitability. However, MEDC’s long term earnings outlook depends on its capability to enhance current existing reserves, finding new reserves or monetizing its overseas assets which are definitely worth more than its existing concession. Expansion scale-back, cash-flows and balance sheet are key priorities. We assume that MEDC will only spend half of its capex guidance of Rp1tn in FY15-17 as it focuses on its near term strategy to strengthen its balance sheet and cash flows. MEDC will postpone the development of its unprofitable overseas assets and cut investments in exploration projects. Initiate coverage with Hold and target price of Rp820. We initiate coverage with HOLD rating and target price of Rp820 (6.9x FY16 EV/EBITDA; 0.2x P/BV). MEDC’s valuation is undemanding but prospects for oil and gas lifting and earnings growth is subdued given the low crude oil prices.

Company Focus

Medco Energi

Investment thesis

We initiate coverage with Hold rating and target price of Rp820 per share, implying 6.9x FY16 EV/EBITDA. We see 2% EBITDA CAGR in FY15-17 on modest oil and gas production volume growth. We believe MEDCO will only focus on its existing low cost reserves mainly in Rimau and South Sumatera. Revenue, EBITDA and net profit

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

0

100

200

300

400

500

600

700

800

900

1,000

2011 2012 2013 2014 2015F 2016F 2017F

Revenue EBITDA Net profit EBITDA margin

Source: DBS Vickers, Company MEDC's earnings trend is in-line with our crude oil benchmark price forecast trend as we expect relatively flattish volume expansion ahead. Meanwhile MEDC’s profitability is expected to remain relatively stable thanks to its low cash cost per barrel and conservative management strategy. MEDC will rely only on its profitable fields, and not pursue aggressive volume expansion at current crude oil prices. MEDC's 9M15 financial and operational performance reflected the impact of lower realised price of US$53.51 per barrel (-49.7% q-o-q) and US$106.3 per MMBTU (-2.1% y-o-y) given the lower benchmark crude oil prices. Oil lifting and gas sales volumes are expected to be weaker as MEDC prefers to be conservative, and looks to maintain profitability amid the current challenging environment. Pricing forecast trend is in line with our benchmark price forecast, with discount imputed We assume oil ASP will reach US$55 per barrel in FY15 (-44% y-o-y) and US$60 per barrel in FY16 and thereafter. Our ASP trend is in line with our in-house crude oil price assumption outlook, however, we have conservatively imputed a US$3-5 per barrel discount to our ASP calculation which we believe is fair after considering on the impact from selling price negotiations.

Oil ASP (US$ per barrel)

113.7 115.6108.3

97.8

50 52 55

0

20

40

60

80

100

120

140

2011 2012 2013 2014 2015F 2016F 2017F

Oil ASP

Source: DBS Vickers, Company However, unlike the oil ASP, which is marked to market, we assume MEDC will sell its gas in the domestic market to gas distributors and end users. Gas prices are sealed under a contract between buyers and sellers after considering the volumes to be transacted. Hence, we assume MEDC’s gas ASP is adjusted up by 3% p.a. in our forecast. We also believe this is fair, as seen in PGAS business model, where distributors enter into a contract to lock in upstream natural gas prices, and determine the distribution spreads before selling it to end industrial uses. Gas ASP (US$ per MMBTU)

3.84.0

5.1

5.6 5.7 5.9 6.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

2011 2012 2013 2014 2015 2016 2017

Gas ASP

Source: DBS Vickers, Company Oil and gas lifting activity to focus on existing profitable reserves We align our forecast in line with management’s strategy to focus on its most profitable concession for both oil and gas lifting activity. This is implies MEDC will maximize its current profitable reserves like Rimau (crude oil) and South Sumatra (natural gas), and cut production from its less profitable fields, which are mainly from its overseas assets. We also

Company Focus

Medco Energi

believe MEDC will maintain relatively stable level of profitability through this strategy. Oil and gas reserves per region

Source: DBS Vickers, Company Oil and gas revenue will remain the largest contributor to MEDC’s consolidated revenue followed by other supporting businesses like thermal coal and power plant. Gas will lead the modest growth on MEDC’s top-line driven by both lifting volume and ASP. Oil and gas lifting revenue (US$mn)

800

873 827

701

553 545 560

‐

100

200

300

400

500

600

700

800

900

1,000

2011 2012 2013 2014 2015 2016 2017

Oil and gas revenue

Source: DBS Vickers, Company We believe Rimau and South Sumatra, which are MEDC’s most profitable concessions, will continue to be growth drivers for oil production. The Senoro-Toili block which completed this year also will contribute to gas production volume. It started to supply gas for Donggi-Senoro LNG (DSLNG) plant starting mid-June 2015. Rimau and South Sumatra account 21% and 23% of MEDC's total oil and gas daily production volume (BOED) respectively. Current reserves imply Rimau has five years of reserves life left. However, since not all oilfields are profitable at the current crude oil price, we forecast MEDC’s crude oil production rate trend will be flat this year at 22 MBOPD in FY15, before a slight drop of 6% in FY16 and flat thereafter.

We believe Rimau will be able to maintain stable production momentum given MEDC’s Enhancement Oil Recovery (EOR) program in the Rimau block. Current EOR program is focusing on the Kaji-Semoga block as a pilot project, and it expected to be applicable on whole Rimau block in. MEDC is also implementing unconventional oil and gas in 34 work-over wells including artificial lifting and fracturing. In addition, MEDC will conduct drilling for one horizontal well with multiple fracturing at Telisa field. We believe Rimau’s low cost structure enable MEDC to execute its oil production enhancement program. On the other hand, we assume lower overseas and domestic oil production volume on less then less economical lifting activity. For exploration stage assets, both domestic and overseas development will remain idle as we believe it is not feasible to develop the blocks into the next stage at current level of oil price. This is also in line with management’s strategy to maintain strong cash flows and balance sheet, which should result in lower capex on exploration activities. Oil lifting forecast (BBOPD)

30.4 29.8

26.3

22.2 22.020.9 20.9

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

2011 2012 2013 2014 2015F 2016F 2017F

Oil

Source: DBS Vickers, Company We also assume the same trend for natural gas lifting volumes; natural gas lifting will reach 120 BBTUD in FY15 (-15% y-o-y) before gradually growing by 3% y-o-y thereafter. MEDC’s long term growth driver will be supported by its gas reserves at both South Sumatra and Senoro-Toili, which account for 86% of MEDC’s natural gas reserves.

Company Focus

Medco Energi

Gas production volume (BBTUD)

163154

160

141

120 124 127

0

20

40

60

80

100

120

140

160

180

2011 2012 2013 2014 2015F 2016F 2017F

Gas


Small contribution from non-majority investments We forecast income from jointly controlled entities to be flat at US$7m, which is equity accounted. The largest contributor is Api Metra Graha (oil and gas services), followed by Medco Power Indonesia (utilities) and Kuala Langsa (Blok-A, oilfield). The business outlook for MEDC's non-controlled investments is stable as seen in their historical performances. We assume flat earnings from Donggi Senoro LNG (DSLNG). We also believe the value of MEDC’s downstream investments will remain only marginally visible given the equity method accounting (jointly controlled investment income). Jointly controlled investment income contributors

AMG65.2%

MPI33.8%

KLL1.1%

Source: DBS Vickers, Company We believe MEDC profitability will be stable and EBITDA margins will be steady at 35% in the next three years. This is in line with management’s strategy of focusing on efficiencies, however, volume expansion growth is expected to be low. We believe MEDC’s cash cost per barrel will gradually go up as MEDC needs to enhance its existing profitable reserves (EOR program) as its overseas reserves are not economically feasible at the current crude oil price level. MEDC also employs local professionals on its oil fields which we believe its more economical than expatriate.

EBITDA margin (%)

33%

38%39%

34% 33% 32%35%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

2011 2012 2013 2014 2015F 2016F 2017F

EBITDA margin

Source: DBS Vickers, Company On the other hand, we do not rely our forecast and valuation on net earnings, as we prefer EBITDA metrics which reflect on MEDC core operational performance. MEDC’s bottom-line is sensitive to refinancing options for its existing debt and other one-off charges, and the potential of its reserves given the current crude oil price environment which would affect the economic value of its reserves, such as assets impairment/revaluation, gain/loss on non-core assets discontinuation. MEDC booked loss of US$17.5m in 1H15 due to a one-off charge of US$22m from assets in the East Cameron area under Medco Energi US LLC as the contract had expired on 31 May 2015. Oil and gas lifting cash cost per barrel (US$ per barrel)

12 13

14

16 16 17

18

‐

2

4

6

8

10

12

14

16

18

20

2011 2012 2013 2014 2015F 2016F 2017F

Lifting cost per barrel

Source: DBS Vickers, Company MEDC will focus on most profitable reserves despite the long life of its reserves We assume MEDC oil and gas exploration project will at least maintain its reserves life index at FY14’s level or 17 years (2P reserves), which implies a reserves replacement ratio of 100% until 2018F. The reserves replacement ratio is a combination of slow production volume expansion, reserves enhancement program and exploration activity. However, for the terminal year, we have conservatively applied 13 years of reserve life, which reflects the scaling back of MEDC’s exploration investment.

Company Focus

Medco Energi

We estimate that reserves will expand from MEDCO EOR and horizontal drilling on Rimau Blocks. On the South Sumatra block, we believe Lagan-1A wells will start producing after a series of production testing procedures are carried out. We also believe current 2D and 3D seismic data acquisition will support the development of new reserves. Oil and gas reserves life (years)

8

14

1211

14 14

1716

1718

0

2

4

6

8

10

12

14

16

18

20

2008 2009 2010 2011 2012 2013 2014 2015F 2016F 2017F

Reserves life index

Source: DBS Vickers, Company Muted growth in coal mining business Beside power plant and oil & gas services business, MEDC also owns two coal mining work permits (IUP) acquired in 2009 via PT Duta Tambang Rekayasa and PT Duta Tambang Sumber Alam with probable coal reserves of 4m tons and 1.7 m tons respectively . The negative growth for coal business revenue was mainly due to weak coal ASP based on the downtrend of coal benchmark prices. We assume long term thermal coal ASP of US$57 per ton, in line with our in-house long term benchmark thermal coal price assumption of US$67 per ton, and that production will remain flat at 582 tons. At this level of coal prices, MEDC’s cash margin is around US$8 per ton, which translates into relatively minimal earnings contribution to MEDC’s consolidated earnings. Coal production volume (tons)

9.1

43.0

36.2

19.2

22.8 22.8

0

5

10

15

20

25

30

35

40

45

50

2012 2013 2014 2015F 2016F 2017F

Coal production volume


Strong balance sheet and cash flows on capex cut; but third party financing still forms the backbone of its balance sheet We assume 40% lower capital expenditure for the next three years vs. MEDC’s guidance during its management presentation, implying US$230m average per year. We believe MEDC will scale back its early stage development projects mainly on its overseas assets in Yemen and Tunisia, both are still in the early development stage. The lower capex will help MEDC to maintain a healthy balance sheet. We expect debt to equity ratio will be stable at 1.0x-1.2x. Capex forecast vs. management target (US$mn)

176

318

75

335

230

325

201 224

456 470

417

‐

50

100

150

200

250

300

350

400

450

500

2011 2012 2013 2014 2015F 2016F 2017F

Capex Guidance


MEDC will continue rely on third party financing as its will only generate marginal FCFF relative to its debt maturity profile. Weak crude oil prices will lead to weaker cash flow generation, while some capital has been allocated for certain under-developing projects. This is implies MEDC will continue to rely on its capability to find alternative financing options in order to stay profitable. Maturing debt vs. FCF (US$m)

(45)

(87)

2

102 103 105

283300

262

100

(150)

(100)

(50)

‐

50

100

150

200

250

300

350

2015F 2016F 2017F 2018F 2019F

FCF Maturing debt


Company Focus

Medco Energi

SWOT Analysis

Strengths Weakness Competitive cost structure. MEDC’s low cash cost per barrel helps the company to stay afloat amid the low crude oil price environment. MEDCO cash cost will continue to stay low as it will only focus on utilising its most profitable domestic oil and gas fields. Undeveloped reserves. MEDC has 17 years of oil and gas reserves - 65% domestic and 35% overseas. This means MEDC could minimise its exploration investments if necessary. Proven track record management. MEDC’s senior management has a sound track record in developing MEDC since its listing in 1994. Understands Indonesia’s oil and gas industry.

Remote assets. Long term growth depends on MEDC’s capability to monetise its overseas assets and the eastern part of Indonesia oil and gas assets. Low crude oil prices reduces the operating feasibility at its overseas assets. Leveraged balance sheet. MEDC is continuously looking for cheaper financing alternatives; US$230m debt will mature per year in the next three years as.

Opportunities Threats M &A potential. The challenging oil and gas sector could potentially trigger industry consolidation and provide M&A opportunities to MEDC, backed by its relatively strong balance sheet and low gearing level. Supporting business. MEDC’s power plant subsidiaries can potentially become big contributors as the development is in line with the government 35,000 MW power plant mega project

Crude oil price outlook. If the crude oil price trades at levels lower than our assumption, this could adversely impact MEDC earnings growth and profitability Industry regulation. Slow reform in Indonesia’s oil and gas sector will negatively impact MEDC as it will be harder to find new reserves and business.

Source: DBS Vickers

Company Focus

Medco Energi

Company Background Corporate History. MEDC was established in 1980 as an Indonesia drilling contractor, and became an oil and gas exploration and production company in 1992. After listing on the IDX in 1994, MEDC expanded its exploration and production activities with the acquisition of an interest in the Rimau block in 1995, followed by the subsequent discovery of the Kaji and Semoga oil fields in the same block in 1996. MEDC acquired 100% of Stanvac Indonesia from Exxon/Mobil. Since 2000, MEDC acquired additional blocks within Indonesia and outside Indonesia.

MEDC’s oil and gas activities consist of 33 blocks in various stages of production, development, and exploration in Indonesia, Libya, Oman, Papua New Guinea, United States, Tunisia and Yemen. MEDC 11 Indonesia consists of 6 producing blocks under PSC with SKK Migas. Beyond its upstream business, MEDC also owns power plants under PT. Medco Power Indonesia.

Sales Trend Profitability Trend

-20.0%

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

0

100

200

300

400

500

600

700

800

900

2013A 2014A 2015F 2016F 2017F

US$ m

Total Revenue Revenue Growth (%) (YoY)

3

53

103

153

203

2013A 2014A 2015F 2016F 2017F

US$ m

Operating EBIT Pre tax Profit Net Profit

Source: Company, DBS Vickers Company structure


Company Focus

Medco Energi

Indonesia oil and gas production 1966-2016F


Indonesia oil and gas production 1966-2016F


Company Focus

Medco Energi

Management Composition. MEDC's senior management team has an average 30 years of experience in exploration and production of oil and gas in Indonesia and overseas. It has good local knowledge on Indonesia’s exploration and production operators and its good relations with the government also provides support o MEDC’s Indonesian

based operations. Management has a proven track record to guide the company in its daily operations and also to look at potential acquisitions of new assets.

Key Management Team

Name Current appointment Experiences

Hilmi Panigoro President Director Indonesian citizen. Joined Medco Group in 1997. Took MBA Core Program at Thunderbird University, Arizona, USA in 1984 and received MSc from Colorado School of Mines, USA in 1988. Graduated from Bandung Institute of Technology in Geological Engineering in 1981. Joined Medco Energi as Vice President in 1997 and became a Director of the Company from 1998 - 2001. Appointed as Chief Executive Officer of PT Medco Energi Internasional in 2001 and presently he is also serving as Director and Commisioner in several of Medco´s subsidiaries

Roberto Lorato Director, Chief Executive Officer Over a period of some 30 years, Roberto has gained extensive experience in the international O&G industry through a variety of roles - from project economics to business development to general management - in Italy, West Africa, Russia, Central Asia, the UK and SE Asia. As President of Premier Oil Indonesia (2010-15), Managing Director of Eni Indonesia (2006-09), President & CEO of VICO (2003-06) and Managing Director of Agip, UK (2001-02), he has successfully managed the reorganisation of large and complex activities. Since 2006, Roberto has also been an active member of the IPA Board of Directors and was elected President of the Association for the years 2008 and 2009.

Anthony Mathias Director, Chief Financial Officer Tony has worked in the O&G Industry since 1994 in a variety of positions in Strategy, Portfolio and Risk Management, Business Improvement, post-acquisition company integration, Finance and Planning. He gained this experience while working in a several international locations and fiscal regimes in both the UK and Norwegian North Sea, Houston Texas, Calgary Canada, Ho Chi Min Vietnam and Jakarta Indonesia. Firstly with Mobil Oil, then ConocoPhillips and most recently Premier Oil. Tony has held the position of Vice-President Finance and IT with Premier Oil since 2012. After university Tony began his career as an Engineer with GEC Marconi in 1988 before joining PriceWaterHouse in 1990.

Ronald Gunawan Director, Chief Operating Officer Over a period of 27 years, Ronald has gained extensive experience in the national and international O&G industry through a variety of roles - from field operations, subsurface, project management, and asset management to general management - in Indonesia, Australia and Italy. As VP Operations & Development of Premier Oil Indonesia (2014-15), President & General Manager of Hess Indonesia (2012-14), various management positions in operations and projects with Eni Australia and Eni E&P (2007-2012), and VP Assets of Vico Indonesia (2002-2006), he has well rounded experience in managing both newly developed and mature complex assets in onshore and offshore.

Source: Company

Company Focus

Medco Energi

Competitive Strengths Management team with proven track record. Execution is the key issue in Indonesia’s oil and gas industry. Relationships with government and understanding the local culture are also plus points in running businesses in Indonesia. Management has been able to navigate the company amid domestic regulations, bureaucracy and technical challenges. Low cost structure. MEDC’s average lifting cost is US$15 per barrel thanks to employment of local professionals. A lower cost structure guarantees positive EBITDA from current operating reserves which would help MEDC to maintain its balance sheet and cash flows. Large undeveloped reserves base for future production. MEDC has 1P and 2P oil and gas reserves of 216.66 MMBOE and 290.04 MMBOE respectively, implies a reserve life of 17 years. Growth Strategies Focus on profitable reserves. MEDC will focus on its profitable on-shore oil and gas reserves which has low cash cost per barrel relative to offshore and overseas projects. Strengthening balance sheet and cash flows. MEDC will scale-back its capex for three years and focus on strengthening its balance sheet and cash flows. Management is prepared for the worst case scenario. Management has prepared an operational and financial strategy based on crude oil price of US$40 per barrel. This is to provide a high degree of comfort to shareholders and creditors that it should be able to sustain operations and cash flows. Key catalyst Successful refinancing. MEDC continue to search for more competitive financing options to cope with the low crude oil price environment. Lower financing cost will support

MEDC’s earnings outlook amid modest oil and gas volume growth and ASP. Non-core assets divestment. MEDC may also potentially divest its non-core assets and unprofitable fields as part of its strategy to strengthen its balance sheet and cash flows. As part of this strategy, MEDC has divested its ethanol business. Faster than expected oil and gas industry reform. If the oil and gas reform by the government is faster than expected, it should be positive for Indonesia’s oil and gas industry. This holds re-rating potential for listed Indonesia oil and gas related companies.

Key risks

Crude oil price. If the crude oil price dips below our crude oil price range, the impact on Indonesia’s oil and gas industry could be larger than expected. This would translate into lower ASP for MEDC, and hence lead to weaker than expected earnings growth

Execution risk. Our earnings forecast also depends on MEDC’s execution capability to maintain low cash cost per barrel, enhance its depleted existing reserves and successful exploration investments.

Worse than expected oil and gas lifting performance. We assume natural gas production volume would still be able to offset the oil production volume going forward. If MEDC cuts natural gas production, its operational and financial performance will be below what we expect.

Oil and gas reserve and resource. Oil and gas reserve and resource estimates depend on various assumptions that may be inaccurate, with the main impact from crude oil price assumption. Moreover our target price implies MEDC will be able to fully monetise its remaining 13 years reserve life in the terminal year.

Company Focus

Medco Energi

Key Assumptions

FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Oil production (MMBOPD) 29.8 26.3 22.2 22.0 19.8 18.8

Gas production (BBUPD) 153.9 159.8 141.4 120.0 123.6 127.3

Crude oil ASP (US$/bbl) 115.6 108.3 97.8 50.0 52.0 55.0

Lifting cost (US$/bbl) 13.0 14.0 16.0 16.0 17.0 18.0

Capex (US$mn) (165.5) (308.0) (229.6) (274.6) (201.3) (127.7) Segmental Breakdown FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Revenues (US$ m)

Oil and gas sales 873 827 701 553 545 560

Chemicals and other petroleum products sales 9 43 36 24 20 20

Services 27 17 13 13 13 13

Total 909 887 751 590 578 593

Operating profit (US$ m)

Oil and gas sales 228 268 255 190 210 217

Chemicals and other petroleum products sales

(4) (14) 15 3 9 8

Services (4) (1) (2) (7) 5 5

Total 220 253 268 185 224 230

Operating profit Margins (%)

Oil and gas sales 26.1 32.4 36.4 34.2 38.5 38.7

Chemicals and other petroleum products sales (47.1) (33.4) 42.1 13.8 43.7 39.8

Services (13.3) (3.3) (18.0) (56.6) 37.9 39.8

Total 24.2 28.6 35.7 31.4 38.7 38.8 Source: Company, DBS Vickers

Sensitivity Analysis 2016

O & G prod volume +/- 1%

Net Profit +/- 1.5%

Oil ASP +/- 1% Net Profit +/- 2%

Lower ASP but marginal production volume growth to drive earnings growth

Profitability relatively stable on low lifting cost

Company Focus

Medco Energi

Income Statement (US$ m)

FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Revenue 909 887 751 590 578 593

Cost of Goods Sold (513) (522) (480) (378) (389) (406)

Gross Profit 396 365 271 212 189 187

Other Opng (Exp)/Inc (148) (116) (106) (115) (113) (106)

Operating Profit 248 249 165 97 76 81

Other Non Opg (Exp)/Inc 0 0 0 (22) 0 0

Associates & JV Inc 1 9 7 8 8 8

Net Interest (Exp)/Inc (74) (65) (61) (70) (74) (83)

Exceptional Gain/(Loss) 6 0 0 (7) 0 0

Pre-tax Profit 181 192 111 6 10 6

Tax (156) (154) (98) (2) (3) (2)

Minority Interest (6) (3) (4) 0 0 0

Preference Dividend 0 0 0 0 0 0

Net Profit 18 35 10 4 6 4

Net Profit before Except. 12 35 10 11 6 4

EBITDA 347 358 259 183 195 215

Growth

Revenue Gth (%) 11.2 (2.5) (15.3) (21.4) (2.0) 2.6

EBITDA Gth (%) 28.6 3.1 (27.6) (29.2) 6.3 10.3

Opg Profit Gth (%) 21.8 0.4 (33.7) (41.0) (21.9) 6.6

Net Profit Gth (%) (79.6) 94.4 (72.5) (58.7) 53.3 (35.2)

Margins & Ratio

Gross Margins (%) 43.6 41.1 36.1 36.0 32.6 31.5

Opg Profit Margin (%) 27.3 28.1 22.0 16.5 13.1 13.6

Net Profit Margin (%) 2.0 3.9 1.3 0.7 1.1 0.7

ROAE (%) 2.1 4.1 1.1 0.4 0.6 0.4

ROA (%) 0.7 1.3 0.4 0.1 0.2 0.1

ROCE (%) 1.4 2.1 0.8 2.6 1.9 1.8

Div Payout Ratio (%) 125.7 9.6 52.5 0.0 20.0 10.0

Net Interest Cover (x) 3.3 3.8 2.7 1.4 1.0 1.0 Source: Company, DBS Vickers

Margins Trend

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

2013A 2014A 2015F 2016F 2017F

Operating Margin % Net Income Margin %

Company Focus

Medco Energi

Balance Sheet (US$ m)

FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Net Fixed Assets 1,110 1,175 1,396 1,525 1,689 1,764

Invts in Associates & JVs 0 0 0 0 0 0

Other LT Assets 402 535 556 556 556 556

Cash & ST Invts 837 523 475 411 517 683

Inventory 37 37 39 31 32 33

Debtors 147 144 102 80 78 80

Other Current Assets 124 118 135 135 135 135

Total Assets 2,656 2,532 2,702 2,738 3,006 3,251

ST Debt

163 142 184 184 230 344

Creditor 95 95 92 72 75 78

Other Current Liab 174 174 192 170 172 170

LT Debt 1,187 759 922 973 1,123 1,200

Other LT Liabilities 193 466 392 392 392 392

Shareholder’s Equity 835 885 911 936 1,005 1,056

Minority Interests 8 12 10 10 10 10

Total Cap. & Liab. 2,656 2,532 2,702 2,738 3,006 3,251

Non-Cash Wkg. Capital 39 30 (8) 3 (1) 0

Net Cash/(Debt) (514) (378) (631) (745) (835) (861)

Debtors Turn (avg days) 70.2 59.9 59.6 56.1 49.9 48.8

Creditors Turn (avg days) 91.7 82.2 86.6 108.0 96.4 99.3

Inventory Turn (avg days) 35.3 31.9 35.5 46.2 41.2 42.5

Asset Turnover (x) 0.3 0.3 0.3 0.2 0.2 0.2

Current Ratio (x) 2.6 2.0 1.6 1.5 1.6 1.6

Quick Ratio (x) 2.3 1.6 1.2 1.2 1.3 1.3

Net Debt/Equity (X) 0.6 0.4 0.7 0.8 0.8 0.8

Net Debt/Equity ex MI (X) 0.6 0.4 0.7 0.8 0.8 0.8

Capex to Debt (%) 16.3 18.4 27.8 19.9 20.3 13.0 Source: Company, DBS Vickers

Asset Breakdown

Net Fixed Assets -85.8%

Assocs'/JVs -0.0%

Bank, Cash and Liquid

Assets -8.0%

Inventory -1.7%

Debtors -4.5%

MEDC will rely on third party financing given tight internal cash inflows amid low crude oil price and marginal oil and gas volume expansion

Company Focus

Medco Energi

Cash Flow Statement (US$ m)

FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Pre-Tax Profit 181 192 111 6 10 6

Dep. & Amort. 98 100 87 100 111 126

Tax Paid (156) (154) (98) (2) (3) (2)

Assoc. & JV Inc/(loss) (1) (9) (7) 0 0 0

Chg in Wkg.Cap. (30) 63 29 (11) 4 (1)

Other Operating CF 119 71 41 0 0 0

Net Operating CF 209 264 163 93 122 129

Capital Exp.(net) (220) (166) (308) (230) (275) (201)

Other Invts.(net) (105) (65) (27) 0 0 0

Invts in Assoc. & JV 0 0 0 0 0 0

Div from Assoc & JV 0 0 0 0 0 0

Other Investing CF (68) (59) 21 0 0 0

Net Investing CF (393) (290) (314) (230) (275) (201)

Div Paid (23) (3) (5) 0 (1) 0

Chg in Gross Debt 51 (449) 205 51 196 192

Capital Issues (13) 41 20 22 64 47

Other Financing CF (26) 186 (127) 0 0 0

Net Financing CF (10) (226) 94 72 259 239

Currency Adjustments 13 (8) (1) 0 0 0

Chg in Cash (180) (260) (57) (64) 106 166

Opg CFPS (US cts.) 7.2 6.0 4.0 3.1 3.5 3.9

Free CFPS (US cts.) (0.3) 2.9 (4.3) (4.1) (4.6) (2.2) Source: Company, DBS Vickers

Capital Expenditure

0.0

50.0

100.0

150.0

200.0

250.0

300.0

350.0

2013A 2014A 2015F 2016F 2017F

Capital Expenditure (-)

US$

Lower than management’s

Company Focus

Medco Energi

Quarterly / Interim Income Statement (US$ m)

FY Dec 2Q2014 3Q2014 4Q2014 1Q2015 2Q2015 3Q2015

Revenue 171 192 199 128 146 144


Gross Profit 53 47 72 50 45 64

Other Oper. (Exp)/Inc (15) (22) (27) (32) (16) (44)


Other Non Opg (Exp)/Inc 13 6 (20) 0 0 (19)


Net Interest (Exp)/Inc (18) (10) (19) (16) (19) (15)

Exceptional Gain/(Loss) 0 0 0 0 0 0

Pre-tax Profit 38 23 6 4 12 (12)

Tax (32) (23) (6) (5) (4) (15)

Minority Interest (1) (1) 0 (1) (1) (2)

Net Profit 6 1 1 (1) (16) (27)

Net profit bef Except. 6 1 1 (1) (16) (27)

EBITDA 56 33 26 20 30 3

Growth

Revenue Gth (%) (9.8) 12.1 3.8 (35.8) 14.4 (1.2)

EBITDA Gth (%) (2.6) (40.8) (22.4) (22.8) 53.2 (90.1)

Opg Profit Gth (%) (34.2) (34.4) 81.8 (60.8) 62.9 (30.6)

Net Profit Gth (%) 94.7 (86.9) (20.1) nm (998.9) (68.2)

Margins

Gross Margins (%) 31.2 24.5 36.3 39.0 30.8 44.4

Opg Profit Margins (%) 22.1 12.9 22.6 13.8 19.7 13.8

Net Profit Margins (%) 3.4 0.4 0.3 (1.1) (11.0) (18.7)

Margins Trend

-30%

-20%

-10%

0%

10%

20%

30%

40%

2Q2013

3Q2013

4Q2013

1Q2014

2Q2014

3Q2014

4Q2014

1Q2015

2Q2015

3Q2015


Source: Company, DBS Vickers

One-off item on ethanol assets divestment

Core operating profitability relatively stable quarter on quarter

Company Focus

Medco Energi

Valuation We initiate MEDC with Hold rating and DCF-based target price of Rp820, which implies 6.9x FY16F EV/EBITDA:

Forecast FY15-24 forms the first stage of our DCF

valuation. Our production volume and ASP assumption result in 3% EBITDA growth for FY16-25F. Our long term crude oil benchmark price is US$70 per ton

For the second stage of the DCF analysis, we employ exit multiple approach instead of terminal growth rate on mining company’s finite life. MEDC has remaining 17 reserves life in FY25. We multiply our FCFF at the terminal year by these additional years to generate our terminal value.

Assumptions : WACC 7.6%; cost of equity 14.0%; (risk free rate of 8.0%, risk premium of 7.0% and beta 0.9x) and cost of debt of 5.0% (after-tax)

Our target price implies 6.9x FY16F EV/EBITDA, which is slightly above our domestic peers (including OSV companies) but still below regional listed oil and gas companies . Based on MEDC’s outlook, we think the valuation is fair, given its low cost structure. In addition,

MEDC will generate positive EBITDA for next three years. MEDC also has ample exploration stage oil and gas reserves for future development. MEDC five years EV/EBITDA

Average

+1 stdev

+2 stdev

-1 stdev

-2 stdev

1.0

2.0

3.0

4.0

5.0

6.0

7.0


(x)


DCF Valuation

US$mn FY16F FY17F FY18F FY19F FY20F FY21F FY22F FY23F FY24F FY25F

EBITDA 187 207 236 241 247 254 261 269 277 286

(-) Depreciation (111) (126) (135) (141) (146) (152) (158) (164) (170) (177)

EBIT 76 81 101 101 101 102 103 104 107 110

Tax rate 28% (3) (2) (5) (4) (4) (4) (5) (5) (6) (7)

NOPLAT 73 79 96 97 97 98 98 99 101 102

(+) Depreciation 111 126 135 141 146 152 158 164 170 177

(-) Capex (275) (201) (128) (133) (138) (144) (149) (147) (153) (149)

(+/-) Changes in WC 4 (1) (1) (2) (1) (1) (1) (0) (0) (0)

(+/-) Other adjustment - - - - - - - - - -

Free Cash Flow for Firm (87) 2 102 103 105 105 106 116 118 130

FCFF PV -70 1 61 57 54 51 48 116 118 130

NPV 472

Terminal value 826

Equity 1,299

Net debt (1,104)

Shares out. (mn shares) 3,332

Value per share (Rp/share) 817

Source : DBSVickers

ed: TH / sa: MA

FULLY VALUED Rp245 JCI : 4,374.2 (Initiating Coverage) Price Target : 12-Month Rp 205 Reason for Report : Initiate coverage Potential Catalyst: Crude oil price outlook Analyst William Simadiputra +62 2130034939 [email protected]

Price Relative

Forecasts and Valuation FY Dec (Rp bn) 2014A 2015F 2016F 2017F

Turnover 4,221 3,771 3,067 2,865 EBITDA 665 486 497 468 Pre-tax Profit 560 441 272 233 Net Profit 412 308 189 163 Net Pft (Pre Ex.) 412 308 189 163 EPS (Rp) 56.5 42.2 25.9 22.3 EPS Pre Ex. (Rp) 56.5 42.2 25.9 22.3 EPS Gth (%) 73 (25) (38) (14) EPS Gth Pre Ex (%) 73 (25) (38) (14) Diluted EPS (Rp) 56.5 42.2 25.9 22.3 Net DPS (Rp) 16.3 12.2 7.5 6.4 BV Per Share (Rp) 349.6 379.6 398.0 413.9 PE (X) 4.3 5.8 9.4 11.0 PE Pre Ex. (X) 4.3 5.8 9.4 11.0 P/Cash Flow (X) 4.3 2.8 3.8 8.4 EV/EBITDA (X) 1.8 1.5 1.5 1.7 Net Div Yield (%) 6.7 5.0 3.1 2.6 P/Book Value (X) 0.7 0.6 0.6 0.6 Net Debt/Equity (X) CASH CASH CASH CASH ROAE (%) 17.2 11.6 6.7 5.5 Consensus EPS (Rp): - - - Other Broker Recs: B: 1 S: 1 H: 2 ICB Industry : Oil & Gas ICB Sector: Mining Principal Business: Integrated oil services company, offers services that include geophysical data, drilling and oil field services

Source of all data: Company, DBS Vickers, Bloomberg Finance L.P.

At A Glance Issued Capital (m shrs) 7,299 Mkt. Cap (Rpm/US$m) 1,788,133 / 127 Major Shareholders Pertamina Persero PT (%) 41.1 Dapen Pertamina (%) 17.8 Free Float (%) 41.1 Avg. Daily Vol.(‘000) 31,682


Indonesia Company Focus

Elnusa Bloomberg: ELSA IJ Equity | Reuters: ELSA.JK Refer to important disclosures at the end of this report

Peaked performance

Negatively impacted by low crude oil price

Risks on both existing and potential projects

Further de-rating potential

Fully Valued and TP of Rp205

Growth peaked in FY14, future outlook uncertain on low crude oil price. We think ELSA's revenue and earnings have peaked this year and will drop several years ahead and begin to become flattish in FY18. Low crude oil price halted ELSA's upstream services segment as O&G contactors halted exploration investments and lifting activities, which is negatively impacting ELSA's earnings growth on the risk of existing contract working value re-negotiations and lack of new contract roll-outs. This will potentially hurt ELSA's investments in equipment and technology on lower asset utilization, and unfavorable working fee. Low crude oil price also hindered turnaround effort. ELSA's turnaround efforts since 2010 have resulted in profitability expansion and share price appreciation. However, we expect the turnaround effort to be more challenging at the current crude oil price range. ELSA's turnaround program has not been completed yet as profitability on reach half of its potential, in our view. Initiate with Fully Valued call and TP of Rp205. Our DCF-based TP implies FY16 PE of 8.0x. We believe ELSA should de-rate amid earnings uncertainties, mainly on services contract renewals and slow new contract roll-outs.

58

108

158

208

258

147.6

247.6

347.6

447.6

547.6

647.6

747.6

Dec-11 Jan-13 Jan-14 Jan-15

Relative IndexRp

Elnusa (LHS) Relative JCI INDEX (RHS)

Company Focus

Elnusa

Investment thesis ELSA's business models consist of integrated upstream and downstream oil & gas service companies. In our analysis, we divide the business segments into three as per new management based on the services and product line approach into upstream oil & gas services, downstream oil & gas services and upstream supporting business. ELSA per segment revenue breakdown

Source: DBS Vickers, Company ELSA's turnaround story from 2011-2014 have resulted in better top-line growth and profitability. The key turnaround stories is on ELSA's radical changes to its governance and internal control which have resulted in better expense control. ELSA's EBITDA margin expanded from a single digit in the first semester of 2011 to double digits; 15% on average starting second semester of 2013 (see chart below). q-o-q EBITDA margin trend

Source: DBS Vickers, Company The turnaround story result share price appreciation and valuation re-rating in the last two years and reached its peak in 3Q14 with PE of 21.0x. ELSA stock price appreciation also triggered by the oil & gas sector reform in Indonesia in Jokowi's presidential period, on the hope that it will trigger oil & gas sector's investment which will benefit ELSA moreover, after its profitability turnaround.

ELSA 's three years PE Band

Source: DBS Vickers, Company However, ELSA's current EBITDA margin is still lower than other oil & gas services companies like Apexindo's (APEX IJ, Not rated) 45%. ELSA itself could historically achieve EBITDA margin of 34% in 2010. This means there is scope for turnaround to achieve its historical high EBITDA margin and a sign that the turnaround story is not finished yet. We see slow reform progress and weak crude oil prices giving the industry another set of challenges, resulting in slower exploration investments and upstream contractors' activities. we see this is raise challenges to the oil and services companies, given the slowing incoming new contracts and re-pricing risk from existing contracts in hand. Moreover, our forecast relies on existing project renewals (flat numbers of contracts under progress in our forecast). Our assumption is based on ELSA's long-standing relationships with its primary clients such as Pertamina E & P and Medco Energy, which have a solid cost structure and balance sheet and hence, we believe they will maintain production and exploration expenditure. Upstream oil & gas services We estimate revenue to drop by 60% FY15-17 CAGR, mainly driven by negative growth on Seismic data acquisition and oilfield maintenance services. Both account for 62% of upstream oil & gas services revenue in FY14. We expect drilling services companies to start declining next year on further contractors' production cut. We expect the drilling services segment to drop by 27% FY15-17 CAGR.

Integrated Upstream Oil and Gas Services

52.7%

Upstream oil and gas support services

5.7%

Downstream Oil and Gas Services Revenue

41.6%

(10)

(5)

0

5

10

15

20

25

0

200

400

600

800

1,000

1,200

1,400

1Q11

2Q11

3Q11

4Q11

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3Q12

4Q12

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

3Q15


Average

+1 stdev

+2 stdev

-1 stdev

-2 stdev0.0

7.0

14.0

21.0


(x)

Turnaround period before crude oil price crash

Company Focus

Elnusa

ELSA per segment revenue breakdown (Rpbn)

Source: DBS Vickers, Company We assume 2D & 3D data collection on Seismic data collection and processing services will drop to 1,000sqkm in FY15 before falling further to 800 sqkm and 500sqkm in FY16 and FY17 respectively. Our assumption is reflecting the lower survey, mainly seismic data collection activity which is an early stage of exploration expenditures in the new field.

Seismic and data acquisition (km)


On oil field maintenance services, we expect overall revenue trend to be lower mainly on reduced miscellaneous oilfield maintenance activity. This is in line with ELSA clients' cost-cutting trend and we believe that miscellaneous maintenance activity will be less of a priority.

Oilfield maintenance services (Rpbn)


We assume a steady flow of drilling projects as we believe producing oilfield will maintain its production activity in order to reach the breakeven point. We assume wire-line's total number of logging projects will remain at 20 projects and utilisation rate of 88% in FY15 before drop to 17 projects and 13 projects in FY16 and FY17 respectively with lower equipment utilization rate of 70%. Meanwhile, we assume drilling rig will still utilise its two projects in FY15 before drop to only one project in with utilization rtae of 83% and 65% in FY15 and FY16 respectively.

Drilling service revenue (Rpbn)


Downstream oil & gas services We forecast throughput transportation business to continue to make a dominant contribution to ELSA's downstream business. Meanwhile its retail business will continue to contribute in a minor way to its revenue. ELSA's management also do not have any ambitious targets to expand its retail fuel distribution business in the short term.

867

964 980

604 560

953

867

441

353 314

736 717

630

475 443

0

200

400

600

800

1000

1200

2013 2014 2015F 2016F 2017F

Drilling services Seismic data acquistion and seismic Oilfield maintenance

2,567

2,907

3,741

1,982

1,000 800

500

‐

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2011 2012 2013 2014 2015F 2016F 2017F

Seismic data acquisition

221 208 208

173 173

118 115 109 100 100

177

122 122 109 109

3 3 3 2 2

162

115

70 70

50

‐

50

100

150

200

250

2013 2014 2015F 2016F 2017F

Hydraulic Workover Services Snubbing Services Coiled Tubing Services Pumping Others

451

549 549

372

284

347

289 289

91 91

‐

100

200

300

400

500

600

2013 2014 2015F 2016F 2017F

Wire line logging revenue Drilling rig revenue

Company Focus

Elnusa

Drilling service revenue (%)


We assume flat growth for transportation business throughput, to grow by 2% y-o-y to 12.1mnL in FY15 and flat in FY16 and FY17. We believe the throughput volume will peak in FY15, in line with upstream oil production volume and relatively weak domestic demand on weakening economy. Downstream business has thin profitability, and its operating profit of around 2% is not sufficient to buffer its weakening upstream-related business growth.

Throughput volume (mn litre)

Source: DBS Vickers, Company Upstream oil & gas support We forecast only flat growth on upstream oil & gas support due to weak activity on upstream oil & gas services and overall activities. The supporting business consists of equipment fabrication and construction via its subsidiaries PT Elnusa Fabrikasi & Konstruksi, PT Sigma Cipta Utama and PT Patra Nusa Data.

Upstream oil and gas revenue (Rpbn)

Source: DBS Vickers, Company Earnings and profitability ELSA's cost structure consists of overhead, subcontracting, labour and materials. Overhead and subcontracting cost will enable ELSA to control its expenses and profitability in the case of clients' contract re-pricing pressure. The competitive advantage from ELSA on its local engineering and human resources team which offer an advantage over expatriates without impairing its services to clients. ELSA cost breakdown (%)

Source: DBS Vickers, Company Management also emphasises on efficiencies and focuses on maintaining profitability and this is seen in 2H15 financial performance. Amid contract renegotiation from its major clients, ELSA is capable of maintaining stable profitability amid downtrend in revenue.

Throughput transpotatation

98.6%

Fuel distribution (depo)1.2%

Retail fuel distribution

0.2%

10,116.9

11,877.2 12,114.8 12,357.1 12,604.2

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2013 2014 2015F 2016F 2017F

Volume Throughput Transportasi (mnL)

242

218 215 205

194

‐

50

100

150

200

250

300

2013 2014 2015F 2016F 2017F

Upstream oil and gas support

Direct labor10.8%

Direct material17.3%

Subcontract23.6%

Overhead48.2%

Company Focus

Elnusa

Quarterly EBITDA margin trend (%)

Source: DBS Vickers, Company We forecast that ELSA will maintain stable profitability in FY16-17 amid top-line downtrend as we believe management, whom has so far showed successful efficiency efforts, will continue to support ELSA's EBITDA and earnings. Our earnings forecast implies FY15-17 EBITDA margin of 15-16% ahead, a stable profitability level since ELSA's turnaround in 2013.

ELSA's profitability trend (%)

Source: DBS Vickers, Company We forecast that EBITDA and earnings will reach Rp586bn (-12% y-o-y) and Rp497bn (-15% y-o-y), net profit also has a similar trend and reached Rp307bn (-25% y-o-y) and Rp209bn (-38% y-o-y) in FY15 and FY16 respectively. Our earnings forecast is around 15% below consensus forecast as we believe the consensus has not fully accounted for the possibility of existing contract renegotiations which will hurt ELSA's revenue and earnings growth, despite ELSA's capability to maintain stable profitability ahead.

Revenue, EBITDA and net profit forecast (Rpbn)

Source: DBS Vickers, Company We also estimate that ELSA will scale back its capex spending amid challenging new contracts winning. Our forecast capex is lower than the management's guidance on its company's latest presentation as we only accounted for minor capex spending for new contracts, this is in line with our forecast assumption that ELSA will rely only on existing project renewals instead of new contracts. Hence, ELSA can minimise its capex by slashing unnecessary spending on new equipment. Capex trend (Rpbn)

Source: DBS Vickers, Company We believe capital expenditure spending scale back, despite its sign the slowing business, it also positive for ELSA cash position and gearing level. Currently ELSA is in a net cash position and we believe the trend will continue ahead, given the lack of significant expansion, we believe, as ELSA will only budget its capital spending after it secured contracts in terms of size and fee rate.

(10)

(5)

0

5

10

15

20

25

0

200

400

600

800

1,000

1,200

1,400

1Q11

2Q11

3Q11

4Q11

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

3Q15


6.0

11.5

15.7

18.017.3

16.515.8

4.3

12.7

14.615.8 15.5

16.2 16.3

‐0.9

2.7

5.8

9.8

8.2

6.2 5.7

‐5.0

0.0

5.0

10.0

15.0

20.0

2011 2012 2013 2014 2015F 2016F 2017F

Gross margin EBITDA margin Net profit margin

(100)

0

100

200

300

400

500

600

700

800

0

1,000

2,000

3,000

4,000

5,000

6,000

2011 2012 2013 2014 2015F 2016F 2017F

Revenue EBITDA Net profit

262

130 110

366

264

215 208

‐

50

100

150

200

250

300

350

400

2011 2012 2013 2014 2015F 2016F 2017F

Capex

Company Focus

Elnusa

SWOT Analysis

Strengths Weakness Integrated services. ELSA provides a wide range of services on both oil & gas upstream and downstream. We believe this gives ELSA the edge during the contract tender with competitors on its 'one-stop shopping concept' Strong balance sheet. ELSA's strong balance sheet relative to other oil & gas service companies is another competitive advantage as it provides better survival rate vs. leverages Reputable client portfolio. ELSA's key clients are Pertamina and Medco Energy, both largest national state-owned and privately-owned oil & gas operators.

Crude oil price-sensitive business model. ELSA's diversified businesses are sensitive to a single key variable, the crude oil price since it determines clients activity, which third party outsourced to ELSA. Expose to Indonesia's slow developing oil & gas field. Indonesia's slow reform in oil & gas industry are negative to oil & gas services companies on risk on slow new project roll-outs.

Opportunities Threats Overseas projects. ELSA plans to tap overseas oil & gas projects such as India and Myanmar to provide earnings growth driver amid slowing domestic oil & gas activity mainly in exploration stage. Downstream business. ELSA can focus on downstream business if its upstream business continue to be challenging ahead. ELSA's throughput transportation volume growth relatively well in the last three years.

New contract evaporation. Low crude oil price will hinder new contracts as oil & gas contractors will halt their capital expenditure mainly for the new reserves exploration activity. Competition. ELSA has only 2% of market share. Depressed oil & gas service companies will continue to attract new contracts by offering attractive pricing. If the trend goes viral, it could trigger industry price wars, which would be negative for profitability. New management. The management team which previously turned around the company has been replaced. This raises concerns on whether the new team could take the company to the next level amid the currently challenging situation.

Source: DBS Vickers

Company Focus

Elnusa

Company Background Corporate History. ELSA was established in January 1969 as PT Electronika Nusantara, which transformed into PT. Elnusa in 1984 and started to explore oil & gas-related business such as oil & gas data storage and management, oilfield services, and domestic fuel distribution through the establishment of PT Sigma Cipta Utama, PT Elnusa Workover Hydraulic, and PT Elnusa Petrofin. ELSA reinforced its position in the oil & gas industry by establishing PT Elnusa Drilling Services, engaged in integrated drilling services, and acquired PT Purna Bina Nusa, a subsidiary engaged in drilling services, and acquired PT Purna Bina Nusa (now PT Elnusa Fabrikasi Konstruksi) based in Batam. Turnaround story. ELSA's turnaround story was started by its non-core business divestment in 2009-2010 such as Yellow Pages and focus on its oil & gas services business. In 2011-2012, the turnaround programme included overall performance from business aspects, operational and corporate cultures. The corporate strengthening strategy continue in 2014 and covers operational, organisation and internal control function. ELSA also established PT Elnusa Geosains Indonesia and PT Elnusa Oilfield Services as part of the company's risk mitigation.

Three key business segments. ELSA's business is divided by

four key segments; Integrated upstream oil & gas services, Upstream oil & gas support business and Downstream oil & gas services as per 2014 new management policy on business segment regrouping.

Upstream oil & gas services Oilfield maintenance services. Most of the projects in these segments are projects with long-term contracts in various locations, especially in Kalimantan, Java and Sumatera. Key revenue contributors are Hydraulic Work-over and Coiled Tubing business. Utilisation rate on the equipment such as Coiled Tubing and Slickline business is crucial in maintaining revenue growth in this segment, besides the addition of new equipment.

Drilling services. Projects in these segments are medium-term contracts with main revenue contributor Wire-line Logging and Drilling Services businesses. Seismic & data acquisition. Most of the projects in this segments are projects carried over from 2013 with short-term contracts in various project locations mainly in Sumatera and Java. This segment has fallen dramatically since 2013 on the decrease in exploration expenditures and crude oil price.

2. Downstream oil & gas services. These segments are conducted via PT Elnusa Petrofin with the main business of transport. The business is supported by four additional Liquid Fuel Terminals (TBBMs) located in Sulawesi and two TBBMs in East Nusa Tenggara in 2014. 3. Upstream oil & gas support services. The key contributor of this segment is PT Elnusa Fabrikasi & Konstruksi on fabrication services, followed by OCTG on threading service segment.

Sales Trend Profitability Trend


-20.0%

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2013A 2014A 2015F 2016F 2017F

Rp m

Total Revenue Revenue Growth (%) (YoY)

162

212

262

312

362

412

462

512

2013A 2014A 2015F 2016F 2017F

Rp m

Operating EBIT Pre tax Profit Net Profit

Company Focus

Elnusa

Company structure

Source: DBS Vickers, Bloomberg Finance L.P. Management Composition. Despite the board of directors being relatively new, having just been appointed in mid-2014, as part of previous management rotation, the

board of director members have extensive experience in the oil & gas industry with both local and multi-national companies.

Key Management Team

Name Current appointment Experiences

Syamsurizal President Director Appointed as president director since May 2014.

Previously served as director and chief financial officer of PT Medco Energi International (MEDC IJ ) and advisor of board of commissioners of MEDC.

Sabam Hutajulu Director of Finance Appointed as director of finance for the second period since May 2014.

Previously served in board of directors of Zambesi Investment Limited, Hong Kong in 2009-2011.

Held several key positions in oil & gas companies like Petamina Energy Services Ltd, Singapore.

Lusiaga Levi Susila Director of Operation Appointed as Director of Operation since March 2013.

Served several positions in Pertamina, such as GM JOB Pertamina-Lekomaras (2006), Director of Operation of PT Pertamina EP and Primary Staff of Director of Upstream Business of PT Pertamina in 2011 and PT Pertamina EP Director of Operation (2011-2013).

Helmy Said Director of Human Resources Appointed as Director of Human Resources and General Affairs for the second period since May 1994.

Previously he was Expert Staff at Directorate of Investment Planning & Risk Management of PT Pertamina (2011).

Source: Company

Company Focus

Elnusa

Competitive Strengths Extensive service offerings. ELSA offers extensive oil & gas services from seismic survey to drilling, which provide contractors with one-stop shopping convenience, which we believe provide ELSA with a better edge in contract tenders relative to sole-service oil & gas service companies. Strong balance sheet. ELSA is oil & gas services company with strongest balance sheet, net cash position. This arms ELSA with better survivability amid the challenging industry. Reputable clients. ELSA's clients consist of Indonesia's largest oil & gas contractors, both state-owned and privately owned entities such as Pertamina and Medco Energi. Exposure to top reputable contractors guarantee healthy receivables and cash flows. Moreover, this also reflects ELSA's execution track record in offering satisfactory services, and competitive contract pricing. Having reputable clients also implies that ELSA has good receivable quality. Growth Strategies Focus on maintaining stable profitability. ELSA focuses on maintaining its profitability amid its top-line downtrend prospects as seen in its 1H15 performance. ELSA will reduce and control its overhead cost (48% of total COGS) and to continuously employ local engineers vs. expatriates.

Prudent capital allocation. ELSA guarantees that it will only invest in new equipment after considering the economic feasibility of contracts that it could obtain. This is also part of its strategy to maximise its equipment utilisation rate. Key Risks

Softer-than-expected contract re-pricing. If the contract renegotiation process outcome is better than our estimate, ELSA should book better-than-expected top-line and earnings growth outcome relative to our forecast. Better-than-expected upstream oil & gas investment trend and new project roll-outs. If oil & gas investments trend mainly on exploration projects and are better than we expected, ELSA can obtain new contracts and renew its existing contracts with competitive fees. Hence, ELSA's top-line and earnings growth should also be better than our forecast. Successful overseas diversification strategy. We assume only modest contribution from overseas projects on execution risk concerns. However, if ELSA successfully delivers positive results from its overseas projects, it will enable to offset the weak domestic oil & gas project growth.

Company Focus

Elnusa

Key Assumptions

FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Drilling rig revenue (Rpbn) N/A 867.0 964.0 980.3 604.1 516.7

Seismic data collection, 2D & 3D (sqkm)

2,906.6 3,741.1 1,982.0 1,000.0 800.0 500.0

Throughput volume (mn kL)

N/A 10.1 11.9 12.1 12.4 12.6

EBITDA Margin (%) 12.7 14.6 15.8 15.5 16.2 16.3

Capex (Rpbn) 0.0 0.0 0.1 0.1 0.1 0.1 Segmental Breakdown

FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Revenues (Rp m)

Integrated Upstream Oil and Gas Services 2,978 2,543 2,454 1,976 1,379 1,158

Upstream Oil and Gas Support Services

333 242 218 215 205 194

Downstream Oil and Gas Services

1,466 1,327 1,549 1,580 1,483 1,513

0 0 0 0 0 0

Others 0 0 0 0 0 0

Total 4,777 4,112 4,221 3,771 3,067 2,865

Operating profit (Rp )

Integrated Upstream Oil and Gas Services 81 307 186 305 246 171


(4) 112 40 13 13 12


14 (18) (30) 20 21 19

0 0 0 0 0 0

Others 0 0 0 0 0 0

Total 91 402 195 338 279 203 Operating profit M i (%)

Integrated Upstream Oil and Gas Services 2.7 12.1 7.6 15.4 17.8 14.8


(1.1) 46.4 18.3 6.0 6.2 6.3


1.0 (1.3) (2.0) 1.3 1.4 1.3

Total 1.9 9.8 4.6 9.0 9.1 7.1 Source: Company, DBS Vickers

Sensitivity Analysis 2016

Topline growth +/- 1%

Net Profit +/- 4%

EBITDA margin +/- 1% Net Profit +/- 9%

Our per segment assumption is in line with Indonesia's overall oil & gas industry activity

Our per segment assumption is in-line with Indonesia's overall oil & gas industry activity

Downstream business has thin profitability and hence, could not buffer the earnings growth amid ELSA's upstream revenue and earnings downtrend

Company Focus

Elnusa

Income Statement (Rp m)

FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Revenue 4,777 4,112 4,221 3,771 3,067 2,865

Cost of Goods Sold (4,226) (3,465) (3,461) (3,119) (2,561) (2,412)

Gross Profit 551 647 760 652 506 453

Other Opng (Exp)/Inc (239) (277) (200) (259) (217) (206)


Other Non Opg (Exp)/Inc 0 0 0 70 0 0

Associates & JV Inc (24) 1 0 0 0 0

Net Interest (Exp)/Inc (77) (34) 0 (21) (17) (14)


Pre-tax Profit 211 337 560 441 272 233

Tax (75) (95) (142) (134) (82) (71)

Minority Interest (8) (5) (6) 0 0 0

Preference Dividend 0 0 0 0 0 0

Net Profit 128 238 412 308 189 163

Net Profit before Except. 128 238 412 308 189 163

EBITDA 605 599 665 586 497 468

Growth

Revenue Gth (%) 1.3 (13.9) 2.7 (10.7) (18.7) (6.6)

EBITDA Gth (%) 193.4 (0.6) 24.3 (5.8) (24.2) (5.8)

Opg Profit Gth (%) 393.5 18.4 51.3 (29.8) (26.5) (14.5)

Net Profit Gth (%) nm 86.1 73.2 (25.4) (38.5) (14.1)

Margins & Ratio

Gross Margins (%) 11.5 15.7 18.0 17.3 16.5 15.8

Opg Profit Margin (%) 6.5 9.0 13.3 10.4 9.4 8.6

Net Profit Margin (%) 2.7 5.8 9.8 8.2 6.2 5.7

ROAE (%) 6.6 11.1 17.2 11.6 6.7 5.5

ROA (%) 2.9 5.5 9.6 7.1 4.3 3.8

ROCE (%) 6.7 8.5 13.2 8.6 6.2 5.2

Div Payout Ratio (%) 5.6 5.4 28.9 28.9 28.9 28.9

Net Interest Cover (x) 4.1 11.0 NM 18.3 16.8 18.0 Source: Company, DBS Vickers

Margins Trend

5.0%

6.0%

7.0%

8.0%

9.0%

10.0%

11.0%

12.0%

13.0%

14.0%

2013A 2014A 2015F 2016F 2017F


Company Focus

Elnusa

Balance Sheet (Rp m)

FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Net Fixed Assets 1,257 1,049 1,240 1,311 1,317 1,296

Invts in Associates & JVs 0 0 0 0 0 0

Other LT Assets 727 830 769 769 769 769

Cash & ST Invts 928 1,320 1,060 1,258 1,380 1,284

Inventory 93 103 115 103 85 80

Debtors 1,119 958 930 831 676 746

Other Current Assets 171 112 131 131 131 131

Total Assets 4,295 4,371 4,246 4,404 4,359 4,306

ST Debt

434 409 244 195 156 125

Creditor 369 306 305 275 226 132

Other Current Liab 884 845 829 897 845 834

LT Debt 531 496 249 199 159 127

Other LT Liabilities 34 30 36 36 36 36

Shareholder’s Equity 2,017 2,258 2,552 2,770 2,905 3,021

Minority Interests 25 27 31 31 31 31

Total Cap. & Liab. 4,295 4,371 4,246 4,404 4,359 4,306

Non-Cash Wkg. Capital 129 21 42 (106) (179) (9)

Net Cash/(Debt) (37) 415 567 863 1,065 1,031

Debtors Turn (avg days) 88.4 92.2 81.6 85.3 89.7 90.6

Creditors Turn (avg days) 44.3 37.6 33.5 36.2 38.8 29.8

Inventory Turn (avg days) 9.3 10.9 11.9 13.6 14.6 13.7

Asset Turnover (x) 1.1 0.9 1.0 0.9 0.7 0.7

Current Ratio (x) 1.4 1.6 1.6 1.7 1.9 2.1

Quick Ratio (x) 1.2 1.5 1.4 1.5 1.7 1.9

Net Debt/Equity (X) 0.0 CASH CASH CASH CASH CASH

Net Debt/Equity ex MI (X) 0.0 CASH CASH CASH CASH CASH

Capex to Debt (%) 14.2 2.3 60.1 66.9 68.0 79.4 Source: Company, DBS Vickers

Asset Breakdown

Net Fixed Assets -37.4%

Assocs'/JVs -0.0%

Bank, Cash and Liquid

Assets -35.9%

Inventory -3.0%

Debtors -23.7%

Net cash position helps ELSA to survive amid weak oil & gas services demand environment

Company Focus

Elnusa

Cash Flow Statement (Rp m)

FY Dec 2012A 2013A 2014A 2015F 2016F 2017F

Pre-Tax Profit 211 337 560 441 272 233

Dep. & Amort. 293 229 105 193 208 221

Tax Paid (75) (95) (142) (66) (134) (82)

Assoc. & JV Inc/(loss) 24 (1) 0 0 0 0

Chg in Wkg.Cap. 265 79 (24) 80 125 (158)

Other Operating CF (180) 203 (79) 0 0 0

Net Operating CF 537 754 421 649 471 214

Capital Exp.(net) (137) (21) (296) (264) (215) (201)

Other Invts.(net) 27 46 0 0 0 0

Invts in Assoc. & JV 0 0 0 0 0 0

Div from Assoc & JV (24) 1 0 0 0 0

Other Investing CF 47 14 (58) 0 0 0

Net Investing CF (87) 41 (354) (264) (215) (201)

Div Paid (7) (13) (119) (89) (55) (47)

Chg in Gross Debt (67) (60) (412) (99) (79) (63)

Capital Issues 9 15 0 0 0 0

Other Financing CF (169) (467) 192 0 0 0

Net Financing CF (235) (525) (338) (187) (134) (110)

Currency Adjustments 24 122 12 0 0 0

Chg in Cash 239 391 (260) 197 123 (97)

Opg CFPS (Rp) 37.3 92.4 61.0 77.9 47.5 51.0

Free CFPS (Rp) 54.9 100.4 17.1 52.7 35.1 1.8 Source: Company, DBS Vickers

Capital Expenditure

0.0

50.0

100.0

150.0

200.0

250.0

300.0

350.0

2013A 2014A 2015F 2016F 2017F

Capital Expenditure (-)

Rp

Modest capex budget on slow new contract additions

Company Focus

Elnusa

Quarterly / Interim Income Statement (Rp m)

FY Dec 2Q2014 3Q2014 4Q2014 1Q2015 2Q2015 3Q2015

Revenue 1,094 1,008 1,200 925 879 816


Gross Profit 166 161 285 158 138 146

Other Oper. (Exp)/Inc (74) (29) (27) (66) (43) (85)


Other Non Opg (Exp)/Inc 87 0 (87) 0 0 70


Net Interest (Exp)/Inc (2) 4 3 (2) (2) (4)


Pre-tax Profit 177 136 173 89 93 127

Tax (52) (25) (45) (23) (24) (32)

Minority Interest (1) (2) (4) (1) (2) (1)

Net Profit 124 110 124 65 68 94

Net profit bef Except. 124 110 124 65 68 94

EBITDA 179 133 170 91 95 131

Growth

Revenue Gth (%) 19.2 (7.8) 19.0 (23.0) (5.0) (7.1)

EBITDA Gth (%) 131.0 (26.0) 28.6 (46.5) 4.4 37.5

Opg Profit Gth (%) 18.3 44.6 94.3 (64.6) 4.4 (35.9)

Net Profit Gth (%) 129.2 (11.4) 12.9 (47.5) 3.6 38.7

Margins

Gross Margins (%) 15.2 16.0 23.7 17.0 15.7 17.9

Opg Profit Margins (%) 8.4 13.2 21.5 9.9 10.8 7.5

Net Profit Margins (%) 11.3 10.9 10.3 7.0 7.7 11.5

Margins Trend


0%

5%

10%

15%

20%

25%

2Q

20

13

3Q

20

13

4Q

20

13

1Q

20

14

2Q

20

14

3Q

20

14

4Q

20

14

1Q

20

15

2Q

20

15

3Q

20

15


Stable profitability despite downtrend in top-line growth

Company Focus

Elnusa

Valuation We initiate coverage on ELSA with Fully Valued rating and DCF-based target price of Rp205 FY16F PE of 8.0x : Explicit forecast FY15-24E forms the first stage of our

DCF valuation. We assume ELSA's revenue and earnings come only from existing undergoing contracts. Our long-term crude oil benchmark price is US$70 per barrel and we believe there will be minimum new contract rollouts. This allows minimal capex as ELSA requires less new equipment purchase.

For the second stage of the DCF analysis, we employ exit terminal growth rate of 0% as we only assume the renewal contract from existing projects during our forecast life-time.

WACC assumption of 14.2% with cost of equity and debt assumption of 16.0% (risk free rate of 8.0%, risk premium of 7.0% and beta 1.1x) and 5.1% (after-tax) respectively.

Our target price implies FY16F PE of 8.0x, lower with our oil and gas companies multiple. We believe ELSA should de-rate its PE multiple to single digit, and enterprise value (EV) close to its EBITDA on the back of its uncertainties on its upstream projects, in our view. Even we understand that current valuation looks undemanding, ELSA will face headwinds such as uncertainties on existing contracts renewal and new contracts roll out amid current low crude oil price and slow Indonesia oil and gas investment climate reform. We believe PE multiple is fair for ELSA multiple for our sanity check given ELSA's steadier business model; contract-based with steady recurring cash flows, moreover, ELSA will only allocate capex when it can fully secured a new contract only hence, prevent ELSA from balance sheet over-leveraged. ELSA also less exposed to the one-time non-operational items such as operational discontinuation and assets impairment as seen in upstream oil and gas contractors.

DCF Valuation

US$mn FY16F FY17F FY18F FY19F FY20F FY21F FY22F FY23F FY24F FY25F

EBITDA 497 468 466 467 471 487 456 468 487 507

(-) Depreciation (208) (221) (233) (246) (267) (288) (303) (325) (346) (367)

EBIT 289 247 233 221 203 199 153 143 141 140

Tax rate 28% (134) (82) (71) (67) (64) (59) (59) (45) (42) (42)

NOPLAT 155 165 162 154 139 139 94 98 99 98

(+) Depreciation 208 221 233 246 267 288 303 325 346 367

(-) Capex (215) (201) (224) (358) (346) (266) (363) (356) (357) (414)

(+/-) Changes in WC 125 (158) 15 12 22 (16) (66) (23) (3) (98)

(+/-) Other adjustment - - - - - - - - - -

Free Cash Flow for Firm 273 27 186 54 82 145 (31) 44 85 (47)

FCFF PV 336 239 21 125 32 42 65 -12 15 26

NPV 540

Terminal value (87)

Equity 453

Net debt 1,065

Shares out. (mn shares) 7,299

Value per share (Rp/share) 207

Source : DBSVickers

Industry Focus

Oil & Gas

Page 2,

DBSV recommendations are based an Absolute Total Return* Rating system, defined as follows:

STRONG BUY (>20% total return over the next 3 months, with identifiable share price catalysts within this time frame)

BUY (>15% total return over the next 12 months for small caps, >10% for large caps)

HOLD (-10% to +15% total return over the next 12 months for small caps, -10% to +10% for large caps)

FULLY VALUED (negative total return i.e. > -10% over the next 12 months)

SELL (negative total return of > -20% over the next 3 months, with identifiable catalysts within this time frame)

* Share price appreciation + dividends

GENERAL DISCLOSURE/DISCLAIMER This report is prepared by PT. DBS Vickers Securities Indonesia ("DBSVI"). report is solely intended for the clients of DBS Bank Ltd and DBS Vickers Securities (Singapore) Pte Ltd, its respective connected and associated corporations and affiliates (collectively, the “DBS Vickers Group”) only and no part of this document may be (i) copied, photocopied or duplicated in any form or by any means or (ii) redistributed without the prior written consent of DBSVI. The research set out in this report is based on information obtained from sources believed to be reliable, but we (which collectively refers to DBS Bank Ltd., its respective connected and associated corporations, affiliates and their respective directors, officers, employees and agents (collectively, the “DBS Group”)) do not make any representation or warranty as to its accuracy, completeness or correctness. Opinions expressed are subject to change without notice. This document is prepared for general circulation. Any recommendation contained in this document does not have regard to the specific investment objectives, financial situation and the particular needs of any specific addressee. This document is for the information of addressees only and is not to be taken in substitution for the exercise of judgement by addressees, who should obtain separate independent legal or financial advice. The DBS Group accepts no liability whatsoever for any direct, indirect and/or consequential loss (including any claims for loss of profit) arising from any use of and/or reliance upon this document and/or further communication given in relation to this document. This document is not to be construed as an offer or a solicitation of an offer to buy or sell any securities. The DBS Group, along with its affiliates and/or persons associated with any of them may from time to time have interests in the securities mentioned in this document. The DBS Group may have positions in, and may effect transactions in securities mentioned herein and may also perform or seek to perform broking, investment banking and other banking services for these companies. Any valuations, opinions, estimates, forecasts, ratings or risk assessments herein constitutes a judgment as of the date of this report, and there can be no assurance that future results or events will be consistent with any such valuations, opinions, estimates, forecasts, ratings or risk assessments. The information in this document is subject to change without notice, its accuracy is not guaranteed, it may be incomplete or condensed and it may not contain all material information concerning the company (or companies) referred to in this report. The valuations, opinions, estimates, forecasts, ratings or risk assessments described in this report were based upon a number of estimates and assumptions and are inherently subject to significant uncertainties and contingencies. It can be expected that one or more of the estimates on which the valuations, opinions, estimates, forecasts, ratings or risk assessments were based will not materialize or will vary significantly from actual results. Therefore, the inclusion of the valuations, opinions, estimates, forecasts, ratings or risk assessments described herein IS NOT TO BE RELIED UPON as a representation and/or warranty by the DBS Group (and/or any persons associated with the aforesaid entities), that: (a) such valuations, opinions, estimates, forecasts, ratings or risk assessments or their underlying assumptions will be achieved, and (b) there is any assurance that future results or events will be consistent with any such valuations, opinions, estimates, forecasts, ratings

or risk assessments stated therein. Any assumptions made in this report that refers to commodities, are for the purposes of making forecasts for the company (or companies) mentioned herein. They are not to be construed as recommendations to trade in the physical commodity or in the futures contract relating to the commodity referred to in this report. DBS Vickers Securities (USA) Inc ("DBSVUSA")"), a U.S.-registered broker-dealer, does not have its own investment banking or research department, has not participated in any public offering of securities as a manager or co-manager or in any other investment banking transaction in the past twelve months and does not engage in market-making. ANALYST CERTIFICATION The research analyst(s) primarily responsible for the content of this research report, in part or in whole, certifies that the views about the companies and their securities expressed in this report accurately reflect his/her personal views. The analyst(s) also certifies that no part of his/her compensation was, is, or will be, directly, or indirectly, related to specific recommendations or views expressed in this report. As of 15 December 2015, the analyst(s) and his/her spouse and/or relatives who are financially dependent on the analyst(s), do not hold interests in the securities recommended in this report (“interest” includes direct or indirect ownership of securities).

COMPANY-SPECIFIC / REGULATORY DISCLOSURES 1. PT. DBS Vickers Securities Indonesia ("DBSVI") does not have a proprietary position in the securities recommended in this report

as of 15 December 2015.

2. Compensation for investment banking services: DBS Bank Ltd., DBSVS, their subsidiaries and/or other affiliates of DBSVUSA have received compensation, within the past 12 months for investment banking services from Keppel Corporation as of 30 November 2015.

DBSVUSA does not have its own investment banking or research department, nor has it participated in any public offering of

Industry Focus

Oil & Gas

securities as a manager or co-manager or in any other investment banking transaction in the past twelve months. Any US persons wishing to obtain further information, including any clarification on disclosures in this disclaimer, or to effect a transaction in any security discussed in this document should contact DBSVUSA exclusively.

RESTRICTIONS ON DISTRIBUTION

General This report is not directed to, or intended for distribution to or use by, any person or entity who is a citizen or resident of or located in any locality, state, country or other jurisdiction where such distribution, publication, availability or use would be contrary to law or regulation.

Australia This report is being distributed in Australia by DBS Bank Ltd. (“DBS”) or DBS Vickers Securities (Singapore) Pte Ltd (“DBSVS”), both of which are exempted from the requirement to hold an Australian Financial Services Licence under the Corporation Act 2001 (“CA”) in respect of financial services provided to the recipients. Both DBS and DBSVS are regulated by the Monetary Authority of Singapore under the laws of Singapore, which differ from Australian laws. Distribution of this report is intended only for “wholesale investors” within the meaning of the CA.

Hong Kong This report is being distributed in Hong Kong by DBS Vickers (Hong Kong) Limited which is licensed and regulated by the Hong Kong Securities and Futures Commission.

Indonesia This report is being distributed in Indonesia by PT DBS Vickers Securities Indonesia.

Malaysia This report is distributed in Malaysia by AllianceDBS Research Sdn Bhd ("ADBSR"). Recipients of this report, received from ADBSR are to contact the undersigned at 603-2604 3333 in respect of any matters arising from or in connection with this report. In addition to the General Disclosure/Disclaimer found at the preceding page, recipients of this report are advised that ADBSR (the preparer of this report), its holding company Alliance Investment Bank Berhad, their respective connected and associated corporations, affiliates, their directors, officers, employees, agents and parties related or associated with any of them may have positions in, and may effect transactions in the securities mentioned herein and may also perform or seek to perform broking, investment banking/corporate advisory and other services for the subject companies. They may also have received compensation and/or seek to obtain compensation for broking, investment banking/corporate advisory and other services from the subject companies.

Wong Ming Tek, Executive Director, ADBSR

Singapore This report is distributed in Singapore by DBS Bank Ltd (Company Regn. No. 196800306E) or DBSVS (Company Regn No. 198600294G), both of which are Exempt Financial Advisers as defined in the Financial Advisers Act and regulated by the Monetary Authority of Singapore. DBS Bank Ltd and/or DBSVS, may distribute reports produced by its respective foreign entities, affiliates or other foreign research houses pursuant to an arrangement under Regulation 32C of the Financial Advisers Regulations. Where the report is distributed in Singapore to a person who is not an Accredited Investor, Expert Investor or an Institutional Investor, DBS Bank Ltd accepts legal responsibility for the contents of the report to such persons only to the extent required by law. Singapore recipients should contact DBS Bank Ltd at 6327 2288 for matters arising from, or in connection with the report.

Thailand This report is being distributed in Thailand by DBS Vickers Securities (Thailand) Co Ltd. Research reports distributed are only intended for institutional clients only and no other person may act upon it.

United Kingdom

This report is being distributed in the UK by DBS Vickers Securities (UK) Ltd, who is an authorised person in the meaning of the Financial Services and Markets Act and is regulated by The Financial Conduct Authority. Research distributed in the UK is intended only for institutional clients.

Dubai

This research report is being distributed in The Dubai International Financial Centre (“DIFC”) by DBS Bank Ltd., (DIFC Branch) having its office at PO Box 506538, 3rd Floor, Building 3, East Wing, Gate Precinct, Dubai International Financial Centre (DIFC), Dubai, United Arab Emirates. DBS Bank Ltd., (DIFC Branch) is regulated by The Dubai Financial Services Authority. This research report is intended only for professional clients (as defined in the DFSA rulebook) and no other person may act upon it.

United States This report was prepared by DBS Vickers Securities Indonesia (“DBSVI”). DBSVUSA did not participate in its preparation. The research analyst(s) named on this report are not registered as research analysts with FINRA and are not associated persons of DBSVUSA. The research analyst(s) are not subject to FINRA Rule 2241 restrictions on analyst compensation, communications with a subject company, public appearances and trading securities held by a research analyst. This report is being distributed in the United States by DBSVUSA, which accepts responsibility for its contents. This report may only be distributed to Major U.S. Institutional Investors (as defined in SEC Rule 15a-6) and to such other institutional investors and qualified persons as DBSVUSA may authorize. Any U.S. person receiving this report who wishes to effect transactions in any securities referred to herein should contact DBSVUSA directly and not its affiliate.

Other jurisdictions

In any other jurisdictions, except if otherwise restricted by laws or regulations, this report is intended only for qualified, professional, institutional or sophisticated investors as defined in the laws and regulations of such jurisdictions.

PT. DBS Vickers Securities Indonesia

DBS Bank Tower, Ciputra World 1, 32/F Jl. Prof. Dr. Satrio Kav. 3-5, Jakarta 12940, Indonesia

Tel. 6221-3003 4900, Fax: 6221-3003 4943

indonesia industry focus oil & gas - dbs bank price can be varied from our view and forecast....

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