outperform* - credit suisse
TRANSCRIPT
DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, AND THE STATUS OF NON-US ANALYSTS. US Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.
CREDIT SUISSE SECURITIES RESEARCH & ANALYTICS BEYOND INFORMATION®
Client-Driven Solutions, Insights, and Access
08 September 2015
Europe/France
Equity Research
Integrated Oil & Gas
Total (TOTF.PA) COMMENT
Working to be 'Fit for the Fifties'
■ Maintain Outperform / TP lowered to €48.0 (From €53.5/share) following
downward revisions to our oil price forecast. In the context of a softer macro, our
bottom-up work suggests Total's organic cash flow break-even could fall to
~$60/bbl by 2017 assuming a level of spend that keeps the business healthy,
and even turn 'Fit for the Fifties' in 2018. Ultimately, break-evens can be cyclical
and moving targets. Bottom line, our analysis suggests that its dividend is
secure allowing it to remove the scrip offering in 2017. Over time, maintaining
capital discipline even as FCF rises will be important with share buybacks to
offset current scrip dilution likely having a greater signalling power on the equity.
Before it engages in any form of buybacks to offset scrip dilution, however, the
focus, in our view, will be first to de-lever its balance sheet.
■ Investment Case: The trajectory of upstream volumes is turning positive,
signalling the beginning of a period of strong upstream growth, which we
consider lower risk as the projects that underpin the 2017 target are
currently in production (ramp-up) and development. It is also lower risk given
the diversified nature (unlike CVX's, where a single project risk could
materially dent the outlook). Considering its superior growth profile combined
with its decreasing capital intensity and more aggressive self-help measures,
we expect it to create a business that is more competitive than peers.
■ Catalysts: Total will present its Strategy Update on 23rd
Sept; we could see
an implied cash flow break-even of $60/bbl being targeted with the bull case
of this reaching the $50s. Ultimately, it will be a function of capex intensity
with a range of $18.5-20bn pa from 2017 likely, in our view; a level, which is
sufficient to keep the business healthy in the longer term.
■ Valuation: our TP is based on our DCF and comparative multiples.
Share price performance
35
40
45
50
Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15
Price Price relative
The price relative chart measures performance against the
CAC 40 INDEX which closed at 4541.97 on 04/09/15
On 04/09/15 the spot exchange rate was €1./Eu 1. -
Eu .9/US$1
Performance over 1M 3M 12M Absolute (%) -12.7 -9.3 -22.3 Relative (%) -4.3 -0.3 -14.0
Financial and valuation metrics
Year 12/14A 12/15E 12/16E 12/17E Revenue (US$ m) 213,189 168,108 196,963 237,035 EBIDAX (US$ m) 30,357.0 21,446.2 22,291.6 25,848.1 Adjusted Net Income (US$ m) 12,837.00 9,685.95 9,927.66 11,929.49 CS adj. EPS (US$) 5.62 4.22 4.21 4.90 Prev. EPS (US$) — 4.61 5.38 6.10 ROGIC (%) 8.85 6.54 6.53 7.58 P/E (adj., x) 7.91 10.54 10.57 9.08 P/E rel. (%) 48.1 66.6 74.6 71.3 EV/EBIDAX (x) 3.3 4.9 4.8 4.0
Dividend (12/15E, US$) 2.69 Dividend yield (%) 6.0 Net debt (12/15E, US$ m) 27,432.0 GIC (12/15E, US$) 130,317.0 BV/share (12/15E, US$) 43.4 Current WACC 7.43 EV/GIC (x) 1.1 Number of shares (m) 2,414.36 Free float (%) 100.00
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities (EUROPE) LTD. Estimates.
Rating OUTPERFORM* Price (04 Sep 15, Eu) 39.96 Target price (Eu) (from 53.50) 48.00¹ Market cap. (Eu m) 96,477.68 Enterprise value (US$ m) 134,801.98
*Stock ratings are relative to the coverage universe in each
analyst's or each team's respective sector.
¹Target price is for 12 months.
Research Analysts
Thomas Adolff
44 20 7888 9114
Ilkin Karimli
44 20 7883 0303
Justin Teo
44 20 7888 9484
Specialist Sales: Jason Turner
44 20 7888 1395
08 September 2015
Total (TOTF.PA) 2
Table of contents Total TOTF.PA 3 Financial Details 4 Key charts 5 Key charts – comparing the Majors 6 The supertanker is turning, vol. III 7
Capex intensity falling, but could be re-set further 8 The baseline continues to improve… 12 Future options (beyond 2020) good enough? 14 Doing a SunPower in the Lower 48 17 Disposal target is feasible, potentially conservative 17 Exploration 18 Quick recap of latest guidance 19
08 September 2015
Total (TOTF.PA) 3
Total TOTF.PA Price (04 Sep 15): Eu39.96, Rating: OUTPERFORM, Target Price: Eu(from 53.50) 48.00
Income statement (US$ m) 12/14A 12/15E 12/16E 12/17E
EBITDAX 41,576 27,249 28,387 33,807 Depr & amort (excl. goodwill) (18,895) (12,152) (12,462) (14,376) EBITDA 39,612 25,350 26,488 31,917 Exploration expense (1,964) (1,898) (1,898) (1,891) Goodwill impairment — — — — Other adjustments to EBIT — — — — EBIT 20,717 13,199 14,027 17,541 E&P — — — — R&M — — — — Chemicals — — — — Gas & Power — — — — Others — — — — Net interest income (exp) (494) (842) (919) (926) Net non operating inc (exp) — — — — Share of associates/JVs' equity 4,032 3,260 3,067 3,426 Exceptionals — — — — Profit before tax 24,255 15,617 16,175 20,041 Taxes 11,219 5,803 6,095 7,959 Profit after tax 13,036 9,814 10,080 12,081 Extraordinary gain/(loss) (8,593) (53) — — Non-controlling interest (minority) 199 128 152 152 Preferred dividends — — — — Other analyst adjustments (8,593) (53) — — Adjusted net income 12,837 9,686 9,928 11,929 Reported net income 4,244 9,633 9,928 11,929
Cash flow (US$ m) 12/14A 12/15E 12/16E 12/17E
EBIT (CS) 20,717 13,199 14,027 17,541 Non Cash Items 20,859 14,050 14,360 16,267 Change in working capital 1,011 (583) — — Other operating cash flow (16,979) (6,995) (4,731) (6,318) Cash flow from operations 25,608 19,671 23,656 27,489 CAPEX (27,969) (23,778) (20,495) (19,535) Disposals of PPE — — — — Free cash flow to the firm (2,361) (4,107) 3,161 7,954 Acquisitions (2,540) (2,777) (523) — Divestments 6,190 6,303 400 — Exploration investment — — — — Other investment/(outflows) — — — — Cash flow from investment (24,319) (20,252) (20,618) (19,535) Net share issue/(repurchase) 131 450 — — Dividends paid (7,462) (3,182) (3,213) (7,706) Change in debt — — — — Other financing cash in/(outflows) 2,214 6,976 — — Cash flow from financing activities
(5,117) 4,244 (3,213) (7,706) Effect of exchange rates — — — — Movements in cash/equivalents (3,828) 3,663 (175) 248 Net change in cash (3,828) 3,663 (175) 248
Balance sheet (US$ m) 12/14A 12/15E 12/16E 12/17E
Assets Intangibles & Goodwill 14,682 16,101 16,101 16,101 PPE 106,876 112,990 119,248 122,516 Associates & JV 19,274 19,811 20,885 22,084 Inventory 15,196 17,373 17,373 17,373 Receivables 15,704 14,415 14,415 14,415 Other current assets 47,077 47,587 47,587 47,587 Other non-current assets 10,989 9,452 9,162 8,822 Total assets 229,798 237,729 244,771 248,898 Liabilities & equity Payables (24,150) (22,469) (22,469) (22,469) Net cash/(debt) 31,242 29,871 30,046 29,798 Other current liabilities 29,523 33,059 33,059 33,059 Total current liabilities 53,673 55,528 55,528 55,528 Provisions (incl Pensions) 22,303 21,779 21,779 21,779 Other non-current liabilities 29,049 27,666 27,666 27,666 Total liabilities 136,267 134,844 135,019 134,771 Ordinary equity 90,330 99,705 106,420 110,643 Minority interest 3,201 3,180 3,332 3,484 Total equity 93,531 102,885 109,752 114,127
Key earnings drivers 12/14A 12/15E 12/16E 12/17E
Brent Price 98.9 53.4 58.0 65.0 WTI Price 93.1 48.6 54.0 60.0 Henry Hub 4.37 2.93 3.90 3.50 Oil Production 1,034 1,242 1,298 1,419 Gas Production 6,064 5,977 6,642 7,031
Per share data 12/14A 12/15E 12/16E 12/17E
No. of shares (EOP) 2,283.25 2,294.87 2,359.99 2,435.53 CS adj. EPS (US$) 5.62 4.22 4.21 4.90 Prev. EPS (US$) — 4.61 5.38 6.10 DPS (12/15E, US$) 3.24 2.69 2.74 2.83 Book value per share (US$)
39.6 43.4 45.1 45.4 Operating cash flow per share (US$)
11.22 8.57 10.02 11.29
Key ratios and valuation
12/14A 12/15E 12/16E 12/17E
Margins (%) EBITDAX margin 19.5 16.2 14.4 14.3 EBIT margin 9.7 7.9 7.1 7.4 Net margin 6.0 5.8 5.0 5.0 Valuation metrics (%) Div yield 7.3 6.0 6.2 6.4 FCF yield (%) (2.3) (4.0) 3.0 7.3 EV/EBIDAX (x) 3.3 4.9 4.8 4.0 P/E 7.9 10.5 10.6 9.1 P/B 1.1 1.0 1.0 1.0 ROE analysis (%) ROE 13.5 10.2 9.6 11.0 ROGIC 8.8 6.5 6.5 7.6 Asset turnover 92.8 70.7 80.5 95.2 Interest burden 1.2 1.2 1.2 1.1 Tax burden 0.46 0.37 0.38 0.40 Financial leverage 0.62 0.57 0.54 0.52 Credit ratios Net debt/equity 32.0 26.7 25.2 24.0 Interest coverage ratio 41.9 15.7 15.3 18.9 Dividend payout ratio 57.7 63.7 65.3 57.9
Source: FTI, Company data, Thomson Reuters, Credit Suisse Securities
(EUROPE) LTD. Estimates.
35
40
45
50
Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15
Price Price relative
The price relative chart measures performance against the CAC 40 INDEX which
closed at 4523.08 on 04/09/15
On 04/09/15 the spot exchange rate was €1./Eu 1. - Eu .9/US$1
08 September 2015
Total (TOTF.PA) 4
Financial Details Figure 1: Total – Financial Details Macro overview
2011 2012 2013 2014 2015E 2016E 2017E 2018E 2019E 2020E
Crude Oil prices ($/bbl)
WTI 95.05 94.14 97.93 93.11 48.64 54.00 60.00 65.00 65.00 70.00
Brent 110.95 111.96 108.85 98.94 53.44 58.00 65.00 70.00 70.00 75.00
Natural gas prices ($/mcf)
US Gas NYMEX 4.10 2.80 3.70 4.37 2.93 3.90 3.50 3.60 3.75 3.75
UK Gas 6.74 8.37 9.38 8.91 8.62 8.98 9.06 9.06 9.06 8.77
Euro Gas 11.70 13.85 13.85 12.15 7.06 4.93 6.10 6.48 6.72 7.20
Refining margins ($/bbl)
US Gulf 24.19 29.27 20.77 17.02 19.26 13.13 14.13 14.13 14.13 14.13
CS NWE Indicator Margin 4.74 7.17 4.44 5.31 8.53 6.94 6.40 6.11 5.89 5.69
Asia (Singapore) 13.43 13.53 12.29 10.86 11.14 10.93 10.70 10.50 10.50 10.50
Currency spot rates ($/FX)
US$/EUR 1.39 1.29 1.33 1.33 1.10 1.13 1.15 1.15 1.15 1.20
TOTAL: Key operational data
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Total liquids production (kbd) 1,227 1,219 1,168 1,034 1,242 1,298 1,419 1,516 1,526 1,510
Total gas production (mmcfd) 6,098 5,877 6,183 6,064 5,977 6,642 7,031 7,138 7,291 7,254
Total oil&gas production (kboed) 2,346 2,300 2,299 2,147 2,339 2,517 2,708 2,825 2,863 2,840
TOTAL: P&L overview ($m)
2011 2012 2013 2014 2015E 2016E 2017E 2018E 2019E 2020E
Upstream 22,609 22,028 17,854 17,156 6,372 8,108 11,908 14,945 15,529 16,982
Refining & Chemicals 613 1,510 1,329 2,739 5,544 4,534 4,258 3,992 3,792 3,612
Marketing and Services 1,187 1,362 1,596 1,709 1,899 1,985 2,075 2,159 2,224 2,269
Corporate and Other -506 -541 -493 -887 -616 -600 -700 -700 -700 -510
Adjusted operating income 23,903 24,359 20,286 20,717 13,199 14,027 17,541 20,397 20,846 22,353
Income (loss) from equity interests 2,864 3,068 3,502 4,032 3,260 3,067 3,426 3,671 3,645 3,655
Net financial charge -466 -615 -664 -495 -856 -919 -926 -880 -774 -664
Exceptional items 0 0 0 0 0 0 0 0 0 0
Adjusted pre-tax income 35,741 33,715 29,800 24,255 15,603 16,175 20,041 23,188 23,716 25,343
Taxation -19,395 -17,720 -15,234 -11,219 -5,803 -6,095 -7,959 -9,401 -9,471 -10,089
Att. To: Non-controlling interests (plus IFRIC 21) 398 223 274 199 128 152 152 152 152 152
ADJUSTED NET INCOME TO TOT SHAREHOLDERS 15,948 15,772 14,292 12,837 9,686 9,928 11,929 13,635 14,092 15,102
Adjustment of net operating income 1,478 -2,159 -3,045 -8,786 -218 0 0 0 0 0
Adjustment of non-controlling interests -26 35 -19 193 165 0 0 0 0 0
Reported net income to TOT shareholders 17,400 13,648 11,228 4,244 9,633 9,928 11,929 13,635 14,092 15,102
Adjusted RC EPS (EUR) - fully diluted 5.07 5.41 4.73 4.23 3.83 3.74 4.26 4.87 5.03 5.17
Adjusted EPS (ADR - US$) 7.06 6.96 6.29 5.62 4.25 4.21 4.90 5.60 5.79 6.20
DPS (EUR) 2.28 2.34 2.38 2.44 2.44 2.44 2.46 2.49 2.51 2.54
DPS (ADR - US$) 3.17 3.01 3.16 3.24 2.70 2.75 2.83 2.86 2.89 3.05
TOTAL: Cash Flow overview ($m)
2011 2012 2013 2014 2015E 2016E 2017E 2018E 2019E 2020E
Reported net income to Total shareholders 17,400 13,648 11,228 4,244 9,633 9,928 11,929 13,635 14,092 15,102
Non-controlling interest 424 188 293 6 -37 152 152 152 152 152
DD&A 10,591 11,607 11,183 18,895 12,152 12,462 14,376 15,748 16,245 16,448
Exploration expense 1,419 1,859 2,175 1,964 1,898 1,898 1,891 1,910 1,895 1,896
Other non-cash charges -220 164 1,109 -512 -3,392 -784 -859 -945 -936 -1,279
Sources of funds 29,614 27,466 25,988 24,597 20,254 23,656 27,489 30,501 31,448 32,320
Working capital movements -2,421 1,392 2,525 1,011 -583 0 0 0 0 0
Cash flow from operations 27,193 28,858 28,513 25,608 19,671 23,656 27,489 30,501 31,448 32,320
Capex -21,852 -25,436 -29,957 -27,969 -23,778 -20,495 -19,535 -18,535 -18,935 -19,435
Dividends paid (assumes scrip dividend from 1Q15 & scrapped in 2017) -7,394 -6,793 -7,284 -7,462 -3,182 -3,213 -7,706 -6,937 -7,006 -7,384
Net cash flow from operations -2,053 -3,371 -8,728 -9,823 -7,289 -52 248 5,029 5,507 5,501
Acquisitions -12,309 -4,039 -4,474 -2,540 -2,777 -523 0 0 0 0
Divestments (only assumes agreed sales) 11,940 7,543 6,399 6,190 6,303 400 0 0 0 0
Capital raising / buybacks 670 -47 247 131 450 0 0 0 0 0
Other (including issuance of hybrids, which is treated fully as equity) -2,362 1,109 3,924 2,214 6,976 0 0 0 0 0
Surplus/deficit -4,114 1,195 -2,632 -3,828 3,663 -175 248 5,029 5,507 5,501
Surplus/deficit excluding scrip savings -4,114 1,195 -2,632 -3,828 672 -3,166 248 5,029 5,507 5,501
TOTAL: Balance Sheet overview ($m)
2011 2012 2013 2014 2015E 2016E 2017E 2018E 2019E 2020E
Cash and cash equivalents 18,147 20,409 20,200 25,181 27,322 27,322 27,322 27,322 27,322 27,322
Current financial assets 906 2,061 739 1,293 2,439 2,439 2,439 2,439 2,439 2,439
Other 63,320 66,610 63,664 51,503 49,614 49,614 49,614 49,614 49,614 49,614
Current assets 82,373 89,080 84,603 77,977 79,375 79,375 79,375 79,375 79,375 79,375
Current liabilities 60,357 64,606 61,668 53,673 55,528 55,528 55,528 55,528 55,528 55,528
Intangibles 16,062 16,965 18,395 14,682 16,101 16,101 16,101 16,101 16,101 16,101
PPE 83,400 91,477 104,480 106,876 112,990 119,248 122,516 123,393 124,189 125,279
Equity affiliates 16,814 18,153 20,417 19,274 19,811 20,885 22,084 23,369 24,644 25,923
Other 13,144 10,211 11,328 10,989 9,452 9,162 8,822 8,482 8,142 8,142
Non-current assets 129,420 136,806 154,620 151,821 158,354 165,396 169,523 171,344 173,076 175,445
Non-current liabilities 63,020 65,622 74,176 82,594 79,316 79,491 79,243 74,214 68,708 63,207
NCI 1,749 1,689 3,138 3,201 3,180 3,332 3,484 3,636 3,788 3,940
TOT's shareholder equity 86,667 93,969 100,241 90,330 99,705 106,420 110,643 117,341 124,427 132,145
Total equity 88,416 95,658 103,379 93,531 102,885 109,752 114,127 120,977 128,215 136,085
Total liabilities 123,377 130,228 135,844 136,267 134,844 135,019 134,771 129,742 124,236 118,735
Total assets 211,793 225,886 239,223 229,798 237,729 244,771 248,898 250,719 252,451 254,820
Net debt/equity 26% 22% 24% 32% 27% 25% 24% 18% 13% 8%
Net debt/(net debt plus equity) 20% 18% 19% 24% 21% 20% 19% 16% 12% 8% Source: Company data, Credit Suisse estimates; Note: 2015 has 3 quarterly dividend payments due to processing time for the scrip dividend; the
year the scrip dividend is removed, which we assume in 2017, there will be 5 quarterly dividend payments to make up for the prior timing issue
08 September 2015
Total (TOTF.PA) 5
Key charts Figure 2: Sources and uses of cash flow Figure 3: Production profile (ex Novatek) using capex
shown in Figure 6 (kbd)
-6.0%
-4.0%
-2.0%
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
2015
E
2016
E
2017
E
2018
E
2019
E
2020
EFCF pre-dividend Dividend yield Dividend yield (scrip divi adjusted)
0
500
1000
1500
2000
2500
3000
2014
E
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
2021
E
2022
E
2023
E
2024
E
2025
E
Rest of Base ADCOYEMEN LIBYAFIDed New production pre FIDed production
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
Figure 4: Organic capex profile ($mn) based on the
current set of opportunities
Figure 5: Total's Post vs Pre-FID projects (kbd)
$0
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
20
14
20
15
E
20
16
E
20
17
E
20
18
E
20
19
E
20
20
E
20
21
E
Corporate & Others
Marketing & Services
Refining & Chemicals
Capitalised exploration
pre FIDed capex
FIDed capex
New volumemaintenance spend
Upstream Base
0
200
400
600
800
1000
120020
14E
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
2021
E
2022
E
2023
E
2024
E
2025
E
FIDed New production Libra (ex EWT) Bonga South West
Ikike (OML 99) Elk-Antelope Uganda
Surmont Ph.3
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
Figure 6: Key upstream projects profile @ $60/bbl Figure 7: Key upstream projects profile @ $70/bbl
-$15,000
-$10,000
-$5,000
$0
$5,000
$10,000
$15,000
$20,000
2014
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
2021
E
2022
E
2023
E
2024
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2025
E
CFFO (FIDed projects) CFFO (pre FIDed projects)
Capex (FIDed projects) Capex (pre FIDed projects)
FCF (FIDed projects) FCF (incl pre-FIDed projects)
-$15,000
-$10,000
-$5,000
$0
$5,000
$10,000
$15,000
$20,000
2014
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
2021
E
2022
E
2023
E
2024
E
2025
E
CFFO (FIDed projects) CFFO (pre FIDed projects)
Capex (FIDed projects) Capex (pre FIDed projects)
FCF (FIDed projects) FCF (incl pre-FIDed projects)
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
08 September 2015
Total (TOTF.PA) 6
Key charts – comparing the Majors Figure 8: PSC vs Concession regime exposure (%): PSC
regimes are more value-protective to falling oil prices
Figure 9: Base production risk: Exposure to maturity
and/or higher-risk geography create challenges (2014)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
20
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14
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20
PSC/TSC
Concession
STL BG BP RDS TOT ENIXOM CVXCOP
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
STL ENI TOT BP RDS XOM REP CVX
Europe Libya Algeria Egypt Nigeria Russia Venezuela Yemen
Source: Credit Suisse estimates Source: Company data, Credit Suisse estimates
Figure 10: Exposure to European Gas (% of production) Figure 11: Long-lived (1/3) LNG portfolio (mtpa)
0
10
20
30
40
50
60
70
RDS /BG TOT XOM BP CVX ENI
2015E 2020E
Source: Credit Suisse estimates Source: Credit Suisse estimates; Note: BG includes 3rd
party off-takes
Figure 12: Long-lived (2/3) Heavy Oil (kbd) Figure 13: Long-lived (3/3) Refining (kbd), adjusted for
closure announcements
0
50
100
150
200
250
300
350
400
XOM RDS TOT BP ENI CVX
2015E 2020E
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
XOM RDS BP CVX TOT REPSOl ENI STL OMV Galp
Europe Asia, Oceania, Africa, MidEast Other Americas USA
Source: Credit Suisse estimates Source: Company data, Credit Suisse research
08 September 2015
Total (TOTF.PA) 7
The supertanker is turning, vol. III Investment thesis. The trajectory of upstream volumes is turning positive, signalling the
beginning of a period of strong upstream growth, which we consider lower risk as the
projects that underpin the 2017 target are currently in production (ramp-up) and
development. It is also lower risk given the diversified nature (unlike CVX, where a single
project risk could materially dent the outlook). Considering Total's superior growth profile
combined with its decreasing capital intensity and more aggressive self-help measures,
we expect it to create a business that is more competitive than peers.
Figure 14: Sources and uses of cash flow Figure 15: Key upstream projects profile @ $60/bbl
-6.0%
-4.0%
-2.0%
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
20
15
E
20
16
E
20
17
E
20
18
E
20
19
E
20
20
E
FCF pre-dividend Dividend yield Dividend yield (scrip divi adjusted)
-$15,000
-$10,000
-$5,000
$0
$5,000
$10,000
$15,000
$20,000
2014
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
2021
E
2022
E
2023
E
2024
E
2025
E
CFFO (FIDed projects) CFFO (pre FIDed projects)
Capex (FIDed projects) Capex (pre FIDed projects)
FCF (FIDed projects) FCF (incl pre-FIDed projects)
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
■ Improving cash cycle. Total is entering a period of improving cash cycle and
declining capex over 2015-17 as a large amount of non-productive capital comes into
service. We see Total's capex declining to $20bn pa or less by 2017, which is still a
level of spend that keeps the business healthy over the long run, in our view. This
cash cycle improvement is driven by superior upstream growth that comes with higher
margin and improvements in Downstream.
■ Rising cash flow, but project delivery is key: Improving the cashflow profile should
increase confidence in the dividends. Projects are more complex, the regulatory
environment is more onerous (since Macondo), industry track record on delivery has
been patchy, including some of Total's non-operated projects. Total should be
applauded for the timely delivery (on budget) and ramp-up at CLOV (deepwater
Angola). It is also largely on track on the important Ichthys LNG project as a 'de-facto'
operator. It also has a more diversified profile, which reduces single project risk.
Overall, XOM, TOT and RDS stand out in the industry, in our view; an industry,
however, that generally has a poor track record. Management teams are taking a
closer look at past mistakes.
■ Growing volumes with low decline. Base decline is guided to 3-4%, but over time a
greater number of long life assets come into production. This is important in a capital
intensive industry: with long life production, the decline treadmill is reduced and capex
intensity falls. Overall, we have been of the view that long life assets have value in a
Majors' portfolio and are high multiple assets once onstream, but it is about balance.
■ Rising FCF: This coupled with more aggressive self-help measures, its organic cash
flow break-even after dividend (excluding scrip) could fall to ~$60/bbl by 2017 and
potentially even 'Fit for the Fifties' from 2018, in our view. Over time, maintaining
capital discipline even as FCF rises will be important with buy backs to offset current
scrip dilution likely having a greater signalling power on the equity.
08 September 2015
Total (TOTF.PA) 8
■ Future Opportunity Set: Looking further ahead, Total believes the opportunity set in
the portfolio for the period beyond 2017 is strong and well balanced (eg Yamal LNG,
Kaombo, Egina, Libra, Uganda, Elk-Antelope), while its reserve life (on a 2P basis) is
also already higher than its target (24 years versus >20 years target; ie comfortably
within target). With a disciplined capex budget, it can still be more selective and
monetise tail upstream projects with acquisitions more discretionary/opportunistic. We
do think there are a few portfolio gaps that Total should close, but there is no rush.
Figure 16: Key upstream projects profile @ $70/bbl Figure 17: Key upstream projects profile @ $80/bbl
-$15,000
-$10,000
-$5,000
$0
$5,000
$10,000
$15,000
$20,000
20
14
20
15
E
20
16
E
20
17
E
20
18
E
20
19
E
20
20
E
20
21
E
20
22
E
20
23
E
20
24
E
20
25
E
CFFO (FIDed projects) CFFO (pre FIDed projects)
Capex (FIDed projects) Capex (pre FIDed projects)
FCF (FIDed projects) FCF (incl pre-FIDed projects)
-$15,000
-$10,000
-$5,000
$0
$5,000
$10,000
$15,000
$20,000
20
14
20
15
E
20
16
E
20
17
E
20
18
E
20
19
E
20
20
E
20
21
E
20
22
E
20
23
E
20
24
E
20
25
E
CFFO (FIDed projects)
CFFO (pre FIDed projects)
Capex (FIDed projects)
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
Capex intensity falling, but could be re-set further
The level of organic capex should continue to drop, and our analysis suggests Total could
be spending less than $20bn pa organically from 2017 (Figure 18) and yet keep the
business healthy in the longer term (Figure 19). This gives Total extra fire power to high-
grade its portfolio through select M&A over time and strengthen the optionality in the
period beyond 2020; something we discuss in greater detail in a later section of the note.
Figure 18: Organic capex profile ($mn) Figure 19: Production profile (ex Novatek) using capex
shown in Figure 18 (kbd)
$0
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
2014
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
2021
E
Corporate & Others
Marketing & Services
Refining & Chemicals
Capitalised exploration
pre FIDed capex
FIDed capex
New volumemaintenance spend
Upstream Base
0
500
1000
1500
2000
2500
3000
2014
E
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
2021
E
2022
E
2023
E
2024
E
2025
E
Rest of Base ADCOYEMEN LIBYAFIDed New production pre FIDed production
Source: Company data, Credit Suisse estimates Source: Credit Suisse estimates
It is important to highlight, however, that the industry's capital intensity could fall further;
whilst Total has been relatively good on project delivery (eg CLOV, Usan, Yemen LNG
etc) and we view Total as one of the better operators in the industry, it needs to be put in
08 September 2015
Total (TOTF.PA) 9
context of an industry that has generally done a poor job, and against other industrial
sectors. In the context of the sector, the spread between best and worst in upstream is
much wider than the spread in downstream. Perhaps more 'downstreamers' should be at
the helm, a decision RDS and Total have both recently made and one we welcome.
There is scope to improve design, engineering and construction productivity, where a lot of
fundamental re-thinking is happening in the broader industry; in other words, it is not just
about cost deflation, which is more cyclical. In the words of RDS' CFO during the 2Q15
call, 'of the total cost of any supply chain third party contract for investment, 40% is design
and scope-driven, 40% is logistics and demand management, and 20% is price. And we
are working pretty hard on the first 80%. Because then, quite often, you don’t have to
worry too much about the last 20% because you are both winning: us and the supplier.'
Bottom line, technology advancement, in addition to cost efficiency, capital efficiency and
reliability, is what the industry can control, and technology advancement is what
accommodates the same resource development in a different price environment. The
industry should get better with the learnings from the past 10 years, in our view, but to
think that the current behaviour/thinking is all structural in nature rather than cyclical is
probably optimistic a view to take for investors.
Additionally, companies should also pay more attention on the portfolio of opportunities
and asking the right questions before precious capital is committed, including questions
around reservoirs and opportunities each of them should chase with the technology and
core competencies that companies have to profitably exploit it rather than chasing
everything and anything, which has also been partly an issue for the industry. Total has
managed to avoid many of its peers' expensive failures into US shale. Total has also
placed value in some instances in partnering with companies that have better expertise in
specific themes (eg oil sands, cbm), which not always fully de-risks project risk (eg Santos
overpromising / under-delivering) but sets the right risk management strategy.
Figure 20: Adjusting for Geology, the Offshore E&P
Industry Has Lost Significant Productivity Compared to
the Price of Its Key Product (Oil and Gas)
Figure 21: One Measure of Global Upstream Capex by
Region
.8
1
1.2
1.4
1.6
1.8
2
2.2
2.4
Glo
ba
l T
rend
fro
m J
an
uary
20
03
(Ja
n 2
003
= 1
.00)
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Date
Off-shore E&P Asset Cost Escalation US Producer Price Index
Cost escalation trends are displayed in US dollars.
IPA E&P Projects Cost Index
0
100
200
300
400
500
600
700
2003 2005 2007 2009 2011 2013
North America Asia (incl. Oceana)
Latam (incl. the Caribbean) Europe
FSU MENA
Sub Saharan Africa
Source: IPA Source: Woodmac
Sobering statistics, but it should get better. The rise in energy demand has
necessitated a higher level of industry activity. In our view, if decline rates increased
modestly as reservoirs have matured and if the industry productivity per barrel produced
was constant, then the capex required in 2014 would have needed to be 40-50% higher
per annum than in 2000. Typical inflation would suggest another 50% on top. One can
also point to more challenging geologies being targeted, e.g. the ultra-deepwater and
more costly transport technologies such as LNG. The global rig count outside the U.S. and
Canada has doubled since 2000. With deteriorating geologies, this increase makes sense.
08 September 2015
Total (TOTF.PA) 10
However, industry capex on one measure has tripled since 2003—something else is at
play. When the global market is overheated, as was the case most notably over 2004-09,
projects are also more prone to fail, but that in itself is not the root cause of the failure; an
overheated market renders projects more sensitive to errors. The Majors have flagged
unacceptable upstream costs on more than one occasion.
The world's leading advisory firm on capital projects for the last 30 years has been IPA led
by Ed Merrow, author of Industrial Megaprojects: Concepts, Strategies, and Practices for
Success. They have normalized actual data on 1400+ upstream field developments
across 50+ producers (independents, supermajors, NOCs). The sobering headline of their
work: "The industry has destroyed value versus initial expectations on 75% of all projects
completed in the last decade" on a price normalized basis. In total, the value lost relative
to project planning assumptions has been around 35%. Much of this value destruction
could have been avoided. For shareholders, it shows up in the weak returns on capital that
the sector has delivered.
Root cause of this failure is now being reviewed – long overdue! Issues associated
with poor project outcomes can include amongst many factors, (a) new technology, (b)
basic data problem, (c) remote locations, (d) qualified labour shortage (particularly when
there are competing projects, or when one thinks neighbouring projects will provide the
labour when they start to ramp up; projects often slip), (e) weather problems, (f) lead
sponsor that is new to the area, (g) government involvement, (h) restrictive local content
rules etc. These issues, however, are not very different to other non-petroleum projects,
yet often other industrial sectors do a better job than the oil industry, according to the IPA.
The three big drivers of failures are typically as follows, according to the IPA:
■ Front-end loading (FEL) is the world's best capital investment, and the industry
typically has failed here. This can include (a) inadequate sub-surface definition and
risking, (b) weak project selection (just because a resource has been found does not
mean it needs to be developed) etc. In essence, doing it right across the key areas (1)
the reservoir, (2) the facilities and (3) well construction can enhance cost predictability
and production attainment. There has been a degradation in the quality of engineering;
engineering errors can be costly and dangerous (e.g. CVX's ALNG). The wake-up call
for RDS was likely the massive cost overrun on Sakhalin 2 LNG, where total spend
amounted to $20bn on a gross basis versus a budget of $10bn. Not enough time was
spent at FEL, which led to changes in scope during development.
o This also includes local content, where generally the industry is seen as
more hostile towards it than other industries; undoubtedly in some
instances certain rules are more difficult to meet, especially when
required to secure specific things locally rather than how much, but often
resistance by the industry can be more ideological than logical. When
properly managed, local content can be less expensive and reduces
opposition from local stakeholders (for example, TLW has done a good
job in Ghana and it is benefitting from this).
o It also includes things as simple as making sure that key permits are in
hand before taking FID; permits are a signal that the government (as well
as the local authorities) are on board with the project, and are almost
never withdrawn unless there is a clear violation. Obvious points, but
many projects in the oil industry had an attitude of 'this won't be a
problem' and often the lack of definition around permit requirements was
also associated with cost overruns due to delays, work arounds etc.
■ The level of investment associated at this stage is typically 3-5% of total costs, but
around 30-40% of total project cycle time – a very important stage of investment that
does not cost much money. The discipline needs to be driven from the top (with a
technical authority sitting high in the corporate hierarchy to be able to stop poorly
08 September 2015
Total (TOTF.PA) 11
prepared projects) through the businesses to the projects, which is a greater focus at
RDS (and we are sure at Total as well). This is not just a matter of good corporate
governance, but also project excellence ultimately.
o Projects in the past cycle have also often included costly and
unnecessary features and refinements, often called 'gold-plating'. This
includes things like buying the latest models of equipment (as opposed to
off the shelf equipment), even in producing assets, where sometimes a
refurbishment would do just well. Management teams are taking a harder
look at this as well – as always reactive.
o Companies do have to recognize that there always is a need for bespoke
complex engineering solutions, but in some instances a standardized
approach can help accelerate design; design one, build two equals
staying away from unnecessary over-engineering or creating a gold-
plated solution. The benefits of this approach extend through detailed
design, fabrication, procurement, contracting strategies etc.
For example, RDS' Appomattox is ~70% repetition of Mars B,
while if RDS chose to take FID on Browse FLNG, it would be
80% replication in scope of Prelude FLNG. PBR's approach to
developing the pre-salt also takes a standardised approach (eg
FPSOs), which significantly de-risked the development, but
where it is facing challenges relate to its local content approach.
Choosing projects that look similar have significant saving
potentials.
■ Turnover in the project leadership, which is more frequent in this industry than in
other industrial sectors, and is not necessarily caused by project difficulties, but mostly
due to the needs of the sponsor, reassignment, retirements or voluntary resignation.
These turnovers rarely just involve one person as a project director often has a team
that he/she works with and typically moves the team when reassigned. The turnover of
the project director in E&P projects was associated with the decline in the success rate
from 48% to 7%. In other words, 93% of E&P megaprojects with a turnover of the
project director failed, according to the IPA, and most damaging is the departure when
the project is at an advanced stage of FEL and during project development. Turnover
of directors does not explain all the failures, but typically when project leadership turns
over, FEL tends to be poorer, the team more likely to be inadequately staffed, team
integration likely more absent etc. Unlike normal organizations, projects do not tend to
have an institutional memory – someone leaves, so does a lot of memory.
■ Schedule aggressiveness, which tends to be more aggressive in this industry than
other industrial sectors. For example, schedule aggressiveness can explain the failure
to wait until all permits are in place, but more fundamentally this is associated with
basic data errors for both the reservoir (eg lack of appraisal of the reservoir) and
facilities (the lack of quality and completeness of the understanding of the reservoir
makes it difficult to get the concept and design right from the get go). Failure here, and
it is hard to recover; as the development proceeds, designs keep changing, and
changing one thing often leads to changing everything or many things adding to cost
and time. Often schedule aggressiveness is driven by the desire of the leader to meet
production goals that are the basis of the bonus/compensation.
o Post Mortem Process should play an important role to boost
accountability, in our view. While it's all good to review safety and
delivery of a project on time and on budget, companies should also make
sure that each project is reviewed at a pre-determined interval after
completion (six months, three years, five years) and whether the project
has delivered the expected value; something the bigger oil companies
such as XOM, RDS and TOT already place greater emphasis on, in our
08 September 2015
Total (TOTF.PA) 12
view. The person responsible for the project should be held accountable
for this, which should improve the level of focus and rigor in not just
proposing projects, but when they are developed.
Figure 22: Not Enough Upfront Project Shaping; Poor Portfolio Choices; a Focus on Schedule as Opposed to
Production Delivery or Cost Leads to Poor Outcomes
Source: IPA
We can discuss more, including things such as schedule incentives in lump-sum contracts,
which can lead to an increase in the frequency of production attainment failures, or
engineers proposing and not being challenged for their highly complex and expensive
(gold-plated and not standardized or sometimes off the shelf solutions) designs, but the
crux of the discussion above is, if the industry finally gets it right, which is not all that
straightforward, then there is potential for positive surprises for the next wave of projects.
Bottom line, companies need to focus on successful project delivery from scope
engineering through project planning, execution, and commissioning/operations. There is
lots of room for management teams to take a hard look at what they are doing and to
improve. This is predominantly a human process failure.
The baseline continues to improve…
Global decline in oil production has averaged 4-5mbd over the past decade. In theory, this
decline should accelerate in the current cashflow-constrained environment as certain
activities designed to mitigate declines in more mature areas are likely being cut back, as
was evident in the aftermath of the Great Financial Crisis (GFC) and also commented on
by Total at the turn of the year. But the acceleration in the decline will take time to show up
in the data given the inertia from historical spending. We think the decline should become
more evident as we head into 2016/17, but the situation might play out slightly differently
than last time around; there has been a greater structural re-thinking around managing
businesses since the early part of 2014 and the same level of analysis did not happen in
the immediate aftermath of the GFC. Hence, we do not think that things will be as bad as
they were immediately after the crisis, but broadly speaking declines in mature basins are
a widely shared and price-sensitive part of the equation.
In some instances, improved drilling efficiency allows activity to be kept elevated even if
spend is cut. As far as base portfolio performance is concerned, the European Majors
have surprised on the upside with many stating during their 2Q15 calls that portfolio
decline rates have fallen due to improved field efficiency/platform uptime. BP in the North
Sea is a case in point. Total is positively surprised that portfolio decline rates are falling
(not increasing) to 3% (instead of its previously expected 3-4% range). Generally, as
Total's share of long-lived volumes rises over time even with less spend on mature areas,
which decline as a share of overall production, portfolio decline could end up looking better.
08 September 2015
Total (TOTF.PA) 13
Figure 23: Total: we assume a 4% pa decline on the base
This is ex Novatek ex ADCO and normalizes for Yemen
outages and loss of ADCO in 2014 (kbd)
Figure 24: Our view of Total's share of long-life
production
LHS (kbd); RHS (% of production)
-
500
1,000
1,500
2,000
2,500
3,000
20
11
20
12
20
13
20
14
20
15
E
20
16
E
20
17
E
20
18
E
20
19
E
20
20
E
Core decline Sanctioned growth Volumes with no FID
0%
10%
20%
30%
40%
50%
60%
0
200
400
600
800
1,000
1,200
1,400
1,600
2008
2009
2010
2011
2012
2013
2014
E
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
Africa Heavy oil MidEast
Indonesia Central Asia Shale (US/China)
Russia/Europe Australia LNG % share
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
The macro focuses everyone's mind (now that the base case for most European Majors is
for a more protracted downturn in oil markets) and pushes everyone to perform to its best
and all of a sudden operating efficiency signficantly improves:
■ During periods of low oil prices, companies uncover how inefficient things were before.
It was not for a lack of goodwill on the part of the companies and/or management; we
are sure that they all tried to operate as efficiently as possible, but when money grows
on trees, there is no urgency and it is harder to motivate others (whether inside a
company or the contractors) thereby creating inefficiencies at operations.
■ There can also be misalignment of contractors who are not incentivized to finish jobs
on time or on budget, but rather who were incentivized to prolong their contracts and
increase their day rates. Also mistakes were often made, thereby increasing non-
productive time as a result, which can be costly.
For example, operating costs in the UK North Sea have increased by 20% pa over the
past 10 years or so, according to Wood Group, and up to 40% of the cost increase comes
from increased inefficiencies. Many of the offshore facilities are already operating beyond
the original design life in a harsh environment, where pipes can corrode and sometimes in
need to be replaced. Oil companies have their own processes, controls, own quality
assurance requirements, requests for specific documentations etc, and all this can add
time, cost and complexity. By standardizing the approach, at least 15% of the costs can be
taken out of a typical repair job in a mature region, according to Wood Group.
A more focused mind has yield results:
■ Despite lower spend y/y, BP stated that the portfolio decline rate is likely to be in the 3-
5% range now instead of 4-5%. Integrity work and portfolio simplification is allowing
BP to improve plant efficiency. Generally, BP has consistently improved plant
efficiency in its top four regions since Macondo, while breakdown outages decreased
significantly via investments in turnarounds and defect elimination.
■ Improved production efficiency is a success story at Statoil as well; bringing the
percentage of unplanned losses from 12% in 2012 to 5% in 2014 is outstanding.
Statoil stated recently that it has seen further improvements thus far in 2015 with every
1% point improvement representing 10kbd of extra production.
All put together, this also reduces operating costs. Overall, Total is making good
progress on savings. The target there for 2015 has consistently moved up. Total increased
08 September 2015
Total (TOTF.PA) 14
its 2015 opex savings target earlier this year by 50%, to $1.2bn (from $0.8bn previously)
and more recently stated that it expects at least $1.2bn, which included a recruitment
freeze in Upstream and R&C, and headcount reduction in both mature marketing and
services areas, and corporate functions. It is a process of right-sizing the organisation for a
lower oil price environment.
■ Upstream: Total guides to $800m in savings in 2015 for the Upstream segment and
feels confident about achieving this goal; the run rate year to date suggests that it can
beat its target for 2015. Examples of cost cutting include renegotiation of maintenance
contracts in Congo and Angola, logistics optimisation in Angola, UK contractor
headcount and salaries among others. Moreover, Total continues on its goal to reduce
upstream headcount.
■ Downstream: it launched a new $600m cost reduction plan with the objective of
reducing each of its units to a cash flow breakeven below $20/t. It has also
streamlined its portfolio reducing capacity (its weakest links) in Europe; this is the right
thing to do even if the margin environment is strong right now; if you can't fix a plant to
make it profitable during a down-cycle, it should not form part of a portfolio.
There is potential for more (the current, but somewhat outdated target of $2bn pa or
$1.4bn pa in cash terms by 2017 will likely be exceeded), in particular as oil markets are
seen to be taken a 'bathtub-shaped' recovery with greater uncertainty, allowing the CEO
free hands to implement his vision and measures to create a more efficient and lean
organization.
Future options (beyond 2020) good enough?
Despite Total being reserve (1P reserve life of >13 years and 2P reserves life of >20
years) and resource rich (representing around fifty years), it is about the resource quality
and the aim to continue to improve the quality of the resource base. There is a budget for
bolt-on M&A, which is not that big, but could be bigger if opportunities arise. There is no
rush, however, in our view, and expect Total to be more disciplined and opportunistic.
Figure 25: Total (ex Novatek) production profile (kbd) Figure 26: Total's Post vs Pre-FID projects (kbd)
0
500
1000
1500
2000
2500
3000
20
14
E
20
15
E
20
16
E
20
17
E
20
18
E
20
19
E
20
20
E
20
21
E
20
22
E
20
23
E
20
24
E
20
25
E
Rest of Base ADCO YEMEN
LIBYA FIDed New production pre FIDed production
0
200
400
600
800
1000
1200
20
14
E
20
15
E
20
16
E
20
17
E
20
18
E
20
19
E
20
20
E
20
21
E
20
22
E
20
23
E
20
24
E
20
25
E
FIDed New production Libra (ex EWT) Bonga South West
Ikike (OML 99) Elk-Antelope Uganda
Surmont Ph.3
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates
As far as inorganic opportunities are concerned, the question to ask Total is (a) does the
company want to stay focused and strengthen existing hubs or (b) does it make sense to
be more diversified and create a more flexible capex profile. US shale would form part of
the latter and for being one of the Big 5 with the lowest exposure to shale (perhaps for the
right reasons in the past cycle given all the impairments we have seen recently), it would
make strategic sense to have a better understanding of shale, but also a greater share of
shale in its portfolio could create a more flexibility capex profile.
08 September 2015
Total (TOTF.PA) 15
The next question for (b) is (i) does the company want to go in via a JV (ie a financier) or
(ii) would it buy an operating position? In the case of a small company, it will be both (i)
and (ii) depending on who the company may be partnered with. But we think the smartest
and perhaps the lowest risk approach for Total to getting access to US shale, if this route
is chosen, is to replicate what Total has done with SunPower, which we discuss later.
Figure 27: Total (ex Novatek) portfolio looks competitive
in the context of its peers, most notably versus BP…
Figure 28: …BP's resource base is questionably in quality
and its portfolio is under greater pressure, in our view…
0
500
1000
1500
2000
2500
3000
2014
E
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
2021
E
2022
E
2023
E
2024
E
2025
E
Rest of Base ADCOYEMEN LIBYAFIDed New production pre FIDed production
0
500
1000
1500
2000
2500
3000
2014
2015
E
2016
E
2017
E
2018
E
2019
E
2020
E
2021
E
2022
E
2023
E
2024
E
2025
E
Base FIDed New production pre FIDed production
Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates; Note: ex Rosneft
Based on spending on the observed projects and the base portfolio, there is room for more
spend (and therefore additional project requirements) depending on the level of growth
Total wants to achieve beyond 2017/18 – the period beyond was going to be a low growth
period with Total's aim to achieve a level of top-line growth in line with the market, but
ultimately it is about the value of that growth.
To drive superior cash flow growth, it is about developing projects that sit on the right side
of the cost curve and are superior to the current portfolio's margin generation. Aside from
tie-backs and other types of brownfield projects, the option of greenfield of high quality is
somewhat limited, in our view, but those within the profile are mostly highly competitive
and large in nature that have the potential to keep Total's operations steady or slightly
growing into the early parts of the 2020s. We briefly discuss some of the giant projects
within Total's portfolio to drive the next investment cycle; in some of these developments,
the company could opportunistically increase the equity, in our view.
■ Libra – offshore Brazil, Santos Basin. Total has a 20% stake in the 8-12bn boe
(gross) development, and may get the opportunity to add more in the future. PBR
could sell down to 30% (the minimum level as per regulations in Brazil), from 40%
currently. RDS might also be interested. This field has a competitive break-even (see
chart), and the project will likely take FID in 2016, in our view.
■ Uganda – onshore development. Total has a 33.3% stake in the >1bn boe project.
Progress on the routing of the pipeline (northern route) has been made, but a
constructor for the pipeline still needs to be identified. One of its partners could look to
reduce its shareholding further, and Total together with CNOOC may be interested to
add more, once greater certainty on the timing of FID is reached. In addition, it makes
sense to have a stake in the South Lokichar development in Kenya, where thus far
smaller E&P companies have discovered 0.6bn boe with significant further upside.
■ That said, a potential obstacle may be the pipeline route with Total preferring the
southern route, which is less risky from a security standpoint. The northern route is
preferred by the government to help economic development in that part of the country.
The target for FID for both Uganda and Kenya is late 2016/early 2017, but we assume
it will happen only in early 2018. These barrels are low cost (onshore).
08 September 2015
Total (TOTF.PA) 16
Figure 29: LNG break-even ($/mmbtu)…Yamal LNG,
Ichthys LNG and Elk Antelope screen relatively
attractively amongst the new greenfield projects
Figure 30: Select international non-LNG project break-
evens ($/bbl)…
0
5
10
15
20
25
US$mmBtu
New LNG price range (CS forecast)
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
Blo
ck 3
1 S
outh
East
Blo
ck 3
1 W
est
Blo
ck 1
6 (
Chis
songa &
Cubal)
Angola
15/06 W
est H
ub
Gin
a K
rog
Schie
hallion r
edevelo
pm
ent (Q
uad 2
04
)
Jack/S
t M
alo
Kaskid
a
Angola
15/06 E
ast H
ub
Kaom
bo
Junin
Tubula
r B
ells
Sto
nes
Rosebank
CLO
V (
Blo
ck 1
7)
Bonga N
ort
h
Chirag O
il
Blo
ck 2
1 (
Cam
eia
)
Blo
ck 1
8 W
est
Nene M
arine
TE
N
Lapa
Cara
bobo P
roje
ct 1
Bonga S
outh
West
Sea L
ion P
hase 1
Appom
attox h
ub
Heid
elb
erg
Luciu
s
Uganda -
onshore
Iara
Lib
ra
Edvard
Grieg
Lula
/C
ern
am
bi
South
Lokic
har
- onshore
Jubile
e P
hase 1
and 1
a
Johan S
verd
rup
Sapin
hoa
Source: Credit Suisse estimates Source: Credit Suisse estimates
■ Elk Antelope LNG (Papua New Guinea): Total's base case is for 5.4tcf gross
recoverable resources, which however can rise with further drilling activity (we think
the base case move up to being two trains with each 3.5mtpa in LNG capacity). Total
has a 40.1% gross interest (or ~31% after government back-in rights). This will be a
greenfield project – one of the most competitive ones with likely FID in 2018.
■ LNG from PNG is highly competitive due to its proximity to Asian customers, lower
costs (onshore gas resources) and potentially attractive fiscal regime. The hard work
in establishing a new LNG province (eg. determining fiscal regime, building essential
infrastructure, training labour etc) has been done by PNG LNG (XOM), and Elk-
Antelope (TOT) stands to reap the benefits. The ability of Papua New Guinea to
transport LNG to Japan without travelling through the South China Sea is likely also an
important element to securing off-take agreements from Japan.
■ Bonga South-West – giant Nigerian development. This project, operated by RDS,
has a relatively attractive break-even, particularly as it lies in a wider ring-fence area
and spending can be recovered much faster than if developed as a stand-alone ring-
fenced area. This is potentially a large development with an FPSO in excess of
200kbd. The consortium is spending more time, however, getting the costs right for the
development, and FID may be likely at some point in 2016, in our view, assuming the
fiscal terms (in the absence of a PIB) can be 'grand-fathered' by the president and
certain local content issues resolved. This is almost a 1bn boe (gross) field.
■ GLNG and Santos. There has been discussions of late that Santos could be an
opportunistic target, with numerous investors believing Total would be the most logical
suitor. There are theoretical synergies in PNG if Total had equity in PNG LNG and the
company knows GLNG from their own equity ownership – although unfortunately we
would tend to argue that this knowledge of what is inside the tent might be a deterrent
rather than a positive. Total recently resumed its purchase of Novatek shares taking
its shareholding to 18.64% (end 2Q15) from 18.24% earlier in the year. Its previous
ambition was to get to 19.4% shareholding in Novatek.
■ Kashagan – additional phases longer term. The potential could be considerable,
but for now the focus is on getting the project to first commercial production; at this
stage offshore pipe-laying and welding is one month ahead of schedule (current
timeline is for 4Q16 start-up). Kashagan is located offshore in the north Caspian Sea
08 September 2015
Total (TOTF.PA) 17
in Kazakhstan, and the field’s recoverable reserves are estimated at over 11bn bbl (ie,
additional phases); in addition four satellite fields (Kalamkas More, Aktote, Kairan and
Kashagan SW) may contain another 1.2bn bbl of oil and condensate. The field is
technically challenging, as it is located in shallow water, which freezes for around five
months every year, its carbonate reservoir has very high pressure and the associated
gas has a high concentration of hydrogen sulphide (15%).
■ Absheron – Azerbaijan: if developed, should be focused on delivering gas to Turkey,
and not to Europe, in our view – a different approach to BP's Shah Deniz Phase II.
The development plans are at an early stage, and if pursued, likely to be done in
phases. The Ashberon discovery lies 35km east of the giant Shah Deniz field,
although is thought to be smaller in size, but still large in absolute terms (~5-10tcf of
recoverable gas and >200mbbls of condensate, according to industry estimates).
■ The field will not be easy nor cheap to develop given the extremely deep reservoirs
with high and variable pressures. That said, the know-how from the development of
Shah Deniz should help Total better manage the risk on Ashberon. The field in theory
should be able to produce at or more than 750mmcfd of gas for an extended plateau
based on the recoverable gas resource estimates. Right now, the chance of this
project moving forward is , however, very low, in our view – our base case.
Doing a SunPower in the Lower 48
US shale has changed the dynamics in oil markets. A Supermajor like Total can't get away
with not knowing and fully understanding shale, in our view. As one of the Big 5 Super
Majors, Total is the least exposed to the Lower 48, and the list above misses US LRS
opportunities. At the same time, this also means unlike some of its peers, it has not made
expensive mistakes in the past and taken significant impairment charges in the recent past
(eg RDS, STL) as a result. But in an oil market, which may be structurally changed
because of US shale, a Super Major like Total needs to have a greater presence, in our
view, and a better understanding of this 'new swing producer'. There is no need to rush in
now; if indeed, there is a more prolonged downturn, patience could be rewarding.
There are more unconventional ways to gaining exposure and understanding shale than
outright acquisitions, which can come with risks, especially for European Majors with a
lack of understanding and structurally a higher cost base than the independent peers. We
think an unconventional and rationale approach for Total could be to replicate its approach
taken in the renewables business (eg Sun Power, where it has a ~60% shareholding).
■ A la SunPower: All in one go, back in 2011, Total took a ~60% stake in SunPower – a
leading solar company in the US. Total has a fairly hands-off approach to its
controlling shareholding because part of the magic is that this is a silicon valley high-
tech venture; a similar approach would be taken for a shale US E&P. This means that
Total kept a portion listed/floated because employees are incentivized with shares.
Total has a number of secondees, including until very recently the treasurer. In our
view, 'doing a Sun Power' for a US Shale E&P could work potentially much better than
Total taking over a company or buying own acreage. Additionally, having a better
understanding of shale may also have broader benefits to the rest of the its portfolio.
According to STL, a few development strategies have been adopted offshore.
Disposal target is feasible, potentially conservative
Total targeted $15-20bn in asset sales over 2012-14, and it delivered on that. The assets
sold included peripheral businesses (midstream and downstream), farm-downs of large
equity positions and non-core upstream projects, and admittedly was done in a somewhat
more favourable environment for disposals. The current target for 2015-17 is $10bn.
The rationale behind this program was to balance the cash cycle (at the time of heavy
investment), simplify and rejuvenate the portfolio where possible in strategic alliance, and
08 September 2015
Total (TOTF.PA) 18
balance country exposure. Once the target is met, Total will continue to sell assets and
rotate the portfolio, but it will likely be balanced out (through cycle) by an equal amount
spent on acquisitions. For now, the budgeting to 2017 calls for more disposals than
acquisitions. The target over 2015-17 in terms of disposals is $10bn – a feasible target, in
our view, as Total has many non-oil linked assets it can sell.
Figure 31: Total (completed) disposals 2011-1H15 TOTAL U$bn
2Q15 Totalgaz 0.7
1Q15 Bostik sale to Arkema, 10% stake in OML18 (RDS announced), 10% stake in OML 29 and Nembe Creek Trunk Line (RDS announced), transportation rights in the Ocensa pipeline in ColumbiaFrance, Nigeria 2.7
Total disposals in 2015 3.5
4Q14 Cardinal midstream in US, blocks in Norway and Nigeria (OML 24) and CCP composites business (refining and chemicals) US, Norway, Nigeria 1.3
3Q14 Shah Deniz Azerbaijan 1.7
2Q14 Not disclosed Not disclosed 0.2
1Q14 Angola Block 15/06, partial IPO of GTT Angola, France 1.5
Total disposals in 2014 4.7
4Q13 5% in Ocensa pipeline, 15% of Total E&P Congo Colombia, Congo 0.3
3Q13 TIGF pipeline, E&P assets in Trinidad & Tobago France, Trinidad 2.5
2Q13 25% in Tempa Rossa oil field, GPN subsidiary and 56.86% in Rosier (fertilizer businesses) Italy, France, Belgium, Netherlands 1.4
1Q13 49% interest in Voyager upgrader project Canada 0.6
Other assets 2.2
Total disposals in 2013 6.9
4Q12 Colombian affiliate, upstream assets, 40% stake in Geostock Colombia, UK, Nigeria, Norway, France 1.1
3Q12 Sanofi shares, upstream assets France, UK, Nigeria 1.8
2Q12 Sanofi shares France 1.1
1Q12 Sanofi shares, 6.4% in Gassled, E&P assets in France, 51% in Composites One and 100% of Pec-Rhin France, Norway, US 2.0
Total disposals in 2012 6.0
4Q11 UK marketing assets, two non-operated blocks in Nigeria, Sanofi shares UK, Nigeria, France 1.6
3Q11 48.83% in CEPSA. Chemical assets, 10% in Ocensa pipeline, Sanofi shares Spain, Colombia, France 6.9
2Q11 Interest in Cameroon E&P sub, interest in Joslyn project, Sanofi shares Cameroon, Canada, France 1.8
1Q11 Sanofi-Aventis shares France 0.4
Total disposals in 2011 10.7 Source: Company data, Credit Suisse estimates: Note: there is a difference between announcement and completion date
There are other high multiple options, which over time could be considered for sale, but for
now represent a nice hedge in the low oil price environment, which include Atotek and
Hutchinson, which combined could be worth $10bn to Total with lots of interest for these
assets. This is not part of the $10bn disposal target over 2015-17, but we think non-core.
$5bn to be announced in 2015, and another $5bn over 2016-17. Total plans to sell
$5bn of assets in 2015 (excluding those announced in 2014 and completed in 2015, which
amount to ~$4bn), which is part of a $10bn plan over 2015-17. Recent announcements on
the sale of the Schwedt refinery ($300m plus inventory release), a 20% stake in Laggan-
Tormore ($876m + 2015 capex exceeds consensus of ~$740m) and its Turkish Retail
Network (for ~$356m) are encouraging in terms of valuation. It also recently announced
the sale of gas pipeline assets in the UK North Sea for ~$0.9bn. All these disposals
amount to ~$3bn and should close before the end of the year.
Other assets that Total is marketing (and reported in the press) include a stake in the Port
Arthur refinery in the US, where it wants to bring in a partner to share the capex burden for
potential improvement work. In addition, it continues to market its stake in Usan (Nigeria),
for which there are a number of interested parties. Usan has been producing at plateau for
over two years; a project that was developed by Total and now operated by XOM, where
the reserve base remains unchanged despite years of production as 2P moved towards
3P, in our view. Gearing (ND/EQ) fell to ~26% in 2Q15, from ~28% in 1Q15, which is
below its target of up to 30%, and helped by disposal proceeds.
Exploration
Exploration success is important; success here gives greater optionality, better longer-
term visibility and avoids having to fill any gap inorganically. In other words, it allows a
company to make better project choices over time: high-grading the portfolio through
selective development and to be a more dynamic asset manager. Unlike Eni and Statoil,
Total's exploration strategy over the past four years has been nothing short of disastrous.
08 September 2015
Total (TOTF.PA) 19
Total has cut its exploration budget to $1.9bn in 2015, down from $2.8bn in 2014, and
hired a new Head of Exploration, who will present at the upcoming Strategy Update. Most
companies have been reducing exploration budgets similar to Total (it is the flexible part of
the capex budget) and have reduced the risk profile of their exploration campaign: less
speculative frontier drilling (ie new hydrocarbon provinces) and more drilling in known
hydrocarbon provinces and geologies, and appraising existing discoveries. In addition, in
this environment, companies can add new acreage on low costs with less onerous
commitments, and shoot seismic (very cheap right now).
Figure 32: 3-year average Finding cost per barrel Figure 33: 3-year average reserve replacement ratio (%)
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
20
08
20
09
20
10
20
11
20
12
20
13
20
14
Total (3y avg excl assocs) Sector (3y avg excl assocs)
Total (3y avg incl assocs) Sector (3y avg incl assocs)
0%
20%
40%
60%
80%
100%
120%
140%
20
08
20
09
20
10
20
11
20
12
20
13
20
14
Total (3y avg total proven additions ex associates) Sector (3y avg total proven additions ex associates)
Total (3y avg organic additions ex associates) Sector (3y avg organic additions ex associates)
Source: Company data, Credit Suisse Research Source: Company data, Credit Suisse Research
Total has a big acreage position in Africa; but even there its success ratio has been
lackluster, most notably as the company was either chasing more challenging geologies in
the Transform Margin (Cretaceous turbidites) or found itself in expensive disappointments
in the Kwanza Basin, pre-salt Angola, where the industry had high hopes. In the US GoM,
the results were mixed; Total pursued drilling activities in partnership with CIE.
More recently, Total has farmed into new opportunities in Myanmar, which for us is a
potentially exciting gas province; a known hydrocarbon province, but largely unexplored,
which recently opened up. Companies such as Statoil, Conoco, BG, Woodside, ENI, RDS,
Chevron, Ophir etc have recently been awarded blocks in the shallow and deepwater area
of Myanmar. Total recently farmed into a deep-water opportunity in the Rakhine basin with
a 40% non-operated stake (still subject to government approval) with Woodside the
operator. The consortium has plans to spud the Saung-1 prospect in the fourth quarter of
2015, which targets a multi tcf prospect on trend with the giant producing Shwe field.
Quick recap of latest guidance
Total will present its Strategy Update on 23rd
September. We briefly provide a recap of
what the company has said in the past, including the latest guidance that exists and one
that has been under review for some time with no update earlier in the year.
2017 production. Total has not provided an update for 2017 earlier in 2015, and the
2.8mbd target is likely to be under review. The target assumed 50-100kbd in lost
production from disposals and 100kbd in contingencies; the latter has already been used
up due to outages in Libya and Yemen, and a revised contingency figure could be
included in the upcoming production guidance. The 2.8mbd target previously assumed
50% risking on the ADCO renewal, which Total has since successfully completed (so an
uplift of ~80kbd to what was assumed in the target), but with less investment in
brownfields, a number of outages (Libya, Yemen) coupled with a few project delays (eg
Tempa Rossa), the target may change. Based on the disposals made thus far, we carry
08 September 2015
Total (TOTF.PA) 20
~2.7mbd for 2017. The period beyond 2017, Total previously targeted a growth rate of
~1% pa, which was lowered from the prior expectation of 1-2% (ie more selective growth).
Capex likely to be lowered. Organic capex stood at $26.4bn in 2014 (down from $28bn
in 2013 organically), and the guidance for 2015 stands at $23-24bn, which also reflects
lower exploration spend. The company provided no revised guidance earlier in 2015 for
2017 as it was still under review. Based on observable projects and what we think Total
will sanction, we think the revised target will be $20bn or less (from $24-25bn previously).
It is important to highlight that Total is transitioning out of a capital intensive phase as new
projects come online between now and 2017/18.
Opex savings target should be raised. The current, but somewhat outdated target is
$2bn pa or $1.4bn pa in cash terms by 2017; this was not reviewed in early 2015. In early
2015, Total increased the target for 2015 from $0.8bn to $1.2bn with the increase driven
mostly in the Upstream division. So far, it is ahead of its plan for 2015. Given that oil
markets have proven more challenging than initial expectations and the likelihood for a
more prolonged downturn, there is potential for further cuts exceeding the $2bn pa target
by 2017. For example, it launched a new $600m cost reduction plan in Downstream with
the objective of reducing each of its units to a cash flow breakeven below $20/t.
2017 FCF (pre-dividend) target de-constructed. Previously, once adjusting for inorganic
factors, the cash flow break-even after dividend (without scrip) in 2017 stood at ~$70/bbl
Brent. At the time we wrote that we think Total targets ~$31bn in OCF in 2017 at $70/bbl.
A FCF (pre-dividend) target that looks to be $8.5bn. This likely included $1.5bn in net
proceeds ($2.5bn in disposals against $1bn in acquisitions) and capex of ~$24bn.
Adjusting for the $1.5bn net proceeds, FCF (pre-dividend) would be ~$7bn. When
adjusting for the above (likely higher opex saving targets, lower capex of ~$20bn etc), the
break-even is likely around $60/bbl Brent for 2017 with the next update.
08 September 2015
Total (TOTF.PA) 21
Companies Mentioned (Price as of 04-Sep-2015)
BP (BP.L, 337.9p) CNOOC Ltd (0883.HK, HK$8.8) Chevron Corp. (CVX.N, $76.67) Cobalt International Energy (CIE.N, $7.62) ENI (ENI.MI, €14.45) ExxonMobil Corporation (XOM.N, $72.46) NOVATEK (NVTKq.L, $92.0) Petrobras (PBR.N, $5.16) Royal Dutch Shell plc (RDSa.L, 1605.0p) Santos Ltd (STO.AX, A$4.38) Statoil (STL.OL, Nkr121.0) SunPower Corp. (SPWR.OQ, $22.88) Total (TOTF.PA, €39.96, OUTPERFORM, TP €48.0) Tullow Oil (TLW.L, 200.4p)
Disclosure Appendix
Important Global Disclosures
Thomas Adolff, Justin Teo and Ilkin Karimli each certify, with respect to the companies or securities that the individual analyzes, that (1) the views expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his or her compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report.
3-Year Price and Rating History for Total (TOTF.PA)
TOTF.PA Closing Price Target Price
Date (€) (€) Rating
25-Sep-12 40.74 44.50 N
15-Oct-12 38.50 42.50
01-Nov-12 39.12 43.00
14-Feb-13 37.74 44.00
14-Nov-13 44.02 48.50 O *
06-Dec-13 42.92 R
07-Apr-14 47.91 51.50 O
11-Jul-14 50.77 53.00
22-Oct-14 44.59 51.50
07-Nov-14 46.53 52.50
05-Dec-14 45.18 49.50
27-Jan-15 46.39 47.80
16-Feb-15 47.12 47.10 N
21-Apr-15 48.70 52.25 O
29-Apr-15 48.44 53.50
* Asterisk signifies initiation or assumption of coverage.
N EU T RA L
O U T PERFO RM
REST RICT ED
The analyst(s) responsible for preparing this research report received Compensation that is based upon various factors including Credit Suisse's total revenues, a portion of which are generated by Credit Suisse's investment banking activities
As of December 10, 2012 Analysts’ stock rating are defined as follows:
Outperform (O) : The stock’s total return is expected to outperform the relevant benchmark*over the next 12 months.
Neutral (N) : The stock’s total return is expected to be in line with the relevant benchmark* over the next 12 months.
Underperform (U) : The stock’s total return is expected to underperform the relevant benchmark* over the next 12 months.
*Relevant benchmark by region: As of 10th December 2012, Japanese ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractiv e, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. As of 2nd October 2012, U.S. and Canadian as well as European ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. For Latin Ame rican and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return of the relevant country or regional benchmark; prior to 2nd October 2012 U.S. and Canadian ratings were based on (1) a stock’s absolute total return potential to its current share price and (2) the relative attractiv eness of a stock’s total return potential within an analyst’s coverage universe. For Australian and New Zealand stocks, the expected total return (ETR) calculation includes 12 -month rolling dividend yield. An Outperform rating is assigned where an ETR is greater than or equal to 7.5%; Underperform where an E TR less than or equal to 5%. A Neutral may be assigned where the ETR is between -5% and 15%. The overlapping rating range allows analysts to assign a rating that puts ETR in the context of associated risks. Prior to 18 May 2015, ETR ranges for Outperform and Underperform ratings did not overlap with Neutral thresholds between 15% and 7.5%, which was in operation from 7 July 2011.
08 September 2015
Total (TOTF.PA) 22
Restricted (R) : In certain circumstances, Credit Suisse policy and/or applicable law and regulations preclude certain types of communications, including an investment recommendation, during the course of Credit Suisse's engagement in an investment banking transaction and in certain other circumstances.
Volatility Indicator [V] : A stock is defined as volatile if the stock price has moved up or down by 20% or more in a month in at least 8 of the past 24 months or the analyst expects significant volatility going forward.
Analysts’ sector weightings are distinct from analysts’ stock ratings and are based on the analyst’s expectations for the fundamentals and/or valuation of the sector* relative to the group’s historic fundamentals and/or valuation:
Overweight : The analyst’s expectation for the sector’s fundamentals and/or valuation is favorable over the next 12 months.
Market Weight : The analyst’s expectation for the sector’s fundamentals and/or valuation is neutral over the next 12 months.
Underweight : The analyst’s expectation for the sector’s fundamentals and/or valuation is cautious over the next 12 months.
*An analyst’s coverage sector consists of all companies covered by the analyst within the relevant sector. An analyst may cover multiple sectors.
Credit Suisse's distribution of stock ratings (and banking clients) is:
Global Ratings Distribution
Rating Versus universe (%) Of which banking clients (%)
Outperform/Buy* 54% (31% banking clients)
Neutral/Hold* 31% (42% banking clients)
Underperform/Sell* 12% (33% banking clients)
Restricted 3%
*For purposes of the NYSE and NASD ratings distribution disclosure requirements, our stock ratings of Outperform, Neutral, and Underperform most closely correspond to Buy, Hold, and Sell, respectively; however, the meanings are not the same, as our stock ratings are determined on a relative basis. (Please refer to definitions above.) An investor's decision to buy or sell a security should be based on investment objectives, current holdings, and other individual factors.
Credit Suisse’s policy is to update research reports as it deems appropriate, based on developments with the subject company, the sector or the market that may have a material impact on the research views or opinions stated herein.
Credit Suisse's policy is only to publish investment research that is impartial, independent, clear, fair and not misleading. For more detail please refer to Credit Suisse's Policies for Managing Conflicts of Interest in connection with Investment Research: http://www.csfb.com/research-and-analytics/disclaimer/managing_conflicts_disclaimer.html
Credit Suisse does not provide any tax advice. Any statement herein regarding any US federal tax is not intended or written to be used, and cannot be used, by any taxpayer for the purposes of avoiding any penalties.
Price Target: (12 months) for Total (TOTF.PA)
Method: We set our TP based on our DCF valuation and comparative multiples. We use a 50/50 weighting. Our DCF uses a nominal WACC of
~7.6% derives a value of €46.3/share. Our preferred comparative multiple is EV/DACF. Combining the two methods gives us our TP of €48.0/share, which implies a 2016E EV/DACF of ~6.3x.
Risk: Risks to our TP: Earnings volatility, general market volatility. Total can benefit/suffer from changes to oil and gas prices worldwide. Capital intensity should drop, however, failure here could see Total's valuation fall as the dividend cover sees a slower improvement. Exploration success has the same implication to the upside and downside. It is difficult for a Major to re-rate on exploration success, unless a substantial discovery is made. Exploration success, however, is important as it will allow better project choices over time. Failure here will lead to the potential need for inorganic ways to grow or develop projects with less favourable IRRs in the portfolio.
Please refer to the firm's disclosure website at https://rave.credit-suisse.com/disclosures for the definitions of abbreviations typically used in the target price method and risk sections.
See the Companies Mentioned section for full company names
The subject company (TOTF.PA, 0883.HK, BP.L, CIE.N, CVX.N, ENI.MI, PBR.N, RDSa.L, TLW.L, XOM.N) currently is, or was during the 12-month period preceding the date of distribution of this report, a client of Credit Suisse.
Credit Suisse provided investment banking services to the subject company (TOTF.PA, 0883.HK, BP.L, CIE.N, CVX.N, PBR.N, RDSa.L, XOM.N) within the past 12 months.
Credit Suisse provided non-investment banking services to the subject company (XOM.N) within the past 12 months
Credit Suisse has managed or co-managed a public offering of securities for the subject company (0883.HK, BP.L, RDSa.L, XOM.N) within the past 12 months.
Credit Suisse has received investment banking related compensation from the subject company (TOTF.PA, 0883.HK, BP.L, CIE.N, CVX.N, PBR.N, RDSa.L, XOM.N) within the past 12 months
08 September 2015
Total (TOTF.PA) 23
Credit Suisse expects to receive or intends to seek investment banking related compensation from the subject company (TOTF.PA, 0883.HK, BP.L, CIE.N, CVX.N, ENI.MI, PBR.N, RDSa.L, STO.AX, TLW.L, XOM.N) within the next 3 months.
Credit Suisse has received compensation for products and services other than investment banking services from the subject company (XOM.N) within the past 12 months
As of the date of this report, Credit Suisse makes a market in the following subject companies (CVX.N, SPWR.OQ, XOM.N).
Credit Suisse has a material conflict of interest with the subject company (0883.HK) . Credit Suisse is acting as financial advisor to both CNOOC Ltd. and SINOPEC on the acquisition of Marathon Oil Corporation's 20% interest in Block 32, offshore Angola.
Credit Suisse has a material conflict of interest with the subject company (NVTKq.L) . Pursuant to sectoral sanctions imposed by the Office of Foreign Assets Control (“OFAC”) of the United States Department of the Treasury, U.S. persons are currently prohibited from providing funding for, or otherwise dealing in, new debt of more than 90 days maturity issued by Novatek. This report should not be construed as an inducement to transact in sanctioned securities. Economic sanctions imposed by the United States and European Union prohibit transacting or dealing in new equity of Novatek issued on or after the date when the Company became the target of such sanctions. This report should not be construed as an inducement to transact in any such sanctioned securities.
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Important Regional Disclosures
Singapore recipients should contact Credit Suisse AG, Singapore Branch for any matters arising from this research report.
The analyst(s) involved in the preparation of this report may participate in events hosted by the subject company, including site visits. Credit Suisse does not accept or permit analysts to accept payment or reimbursement for travel expenses associated with these events.
Restrictions on certain Canadian securities are indicated by the following abbreviations: NVS--Non-Voting shares; RVS--Restricted Voting Shares; SVS--Subordinate Voting Shares.
Individuals receiving this report from a Canadian investment dealer that is not affiliated with Credit Suisse should be advised that this report may not contain regulatory disclosures the non-affiliated Canadian investment dealer would be required to make if this were its own report.
For Credit Suisse Securities (Canada), Inc.'s policies and procedures regarding the dissemination of equity research, please visit https://www.credit-suisse.com/sites/disclaimers-ib/en/canada-research-policy.html.
The following disclosed European company/ies have estimates that comply with IFRS: (BP.L, ENI.MI, NVTKq.L, RDSa.L, STL.OL, TLW.L, XOM.N).
Credit Suisse has acted as lead manager or syndicate member in a public offering of securities for the subject company (TOTF.PA, 0883.HK, BP.L, CIE.N, ENI.MI, PBR.N, RDSa.L, SPWR.OQ, STL.OL, XOM.N) within the past 3 years.
As of the date of this report, Credit Suisse acts as a market maker or liquidity provider in the equities securities that are the subject of this report.
Principal is not guaranteed in the case of equities because equity prices are variable.
Commission is the commission rate or the amount agreed with a customer when setting up an account or at any time after that.
To the extent this is a report authored in whole or in part by a non-U.S. analyst and is made available in the U.S., the following are important disclosures regarding any non-U.S. analyst contributors: The non-U.S. research analysts listed below (if any) are not registered/qualified as research analysts with FINRA. The non-U.S. research analysts listed below may not be associated persons of CSSU and therefore may not be subject to the NASD Rule 2711 and NYSE Rule 472 restrictions on communications with a subject company, public appearances and trading securities held by a research analyst account.
Credit Suisse Securities (Europe) Limited ................................................................................................ Thomas Adolff ; Justin Teo ; Ilkin Karimli
For Credit Suisse disclosure information on other companies mentioned in this report, please visit the website at https://rave.credit-suisse.com/disclosures or call +1 (877) 291-2683.
08 September 2015
Total (TOTF.PA) 24
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2015 09 08 Total - Marching towards the Arc de
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