LNG SHIPPING SECTOR Opportunity knocks

Transcription

1 EQUITY RESEARCH LNG SHIPPING SECTOR Opportunity knocks Based on our bottom-up survey of 1+ liquefaction projects, we expect 215 to be the trough of the LNG shipping cycle. Also, we see a good outlook for the FSRU and FLNG sectors. LNG stocks offer exposure to a crude price rebound case. Shipping - LNG vs (12m) Shipping - LNG Jan Mar May Jul Sep Nov Jan Shipping - LNG Source: Factset Proprietary survey of 1+ LNG liquefaction projects. Our forecasts are based on our survey last summer/autumn of 1+ liquefaction projects (planned and operating). We expect 215 to be the LNG shipping cycle trough and then things to pick up in as the fleet outgrows demand for a fourth consecutive year. We believe that fleet utilisation in 215 will be the lowest since the 29 downturn, but that it should improve considerably in 216 when new liquefaction comes on-line. We expect LNG to become an increasingly large part of global shipping long-term and for investment opportunities (for FLNGs, FSRUs and standard transportation) to materialise. We expect demand growth of 11% for 215 and 16% for 216. We expect traded volumes to grow by 12% for 215, 14% for 216, and 9% for 217. Crossed with distances, this implies demand growth of 11% for 215, 16% for 216, and 7% for 217. We expect fleet growth of 9.6% for 215 and 7.4% for 216. This excludes deliveries from new orders, as on average it takes just over three years from the time of order to delivery. Lower oil price level should favour FLNG over land-based liquefaction. This is due to the c5% cost advantage FLNG enjoys a cost, time-to-market, and flexibility advantage over land-based projects. Hence, it is positive for market opportunities. Partial oil price recovery should improve margins. We believe that the negative impact of the falling oil price is overdone, and we expect a recovery shortly. DNB s view is for the oil price to average USD55/bbl in Q1, USD63/bbl in Q2, USD65/bbl in 215e, USD8/bbl in 216e, and USD84/bbl in 217. Increased oil and gas prices lift the potential margins for FLNG projects, thereby fuelling a rebound case. New opportunities for FSRUs. Over the past four years, the market share of floating regasification units has doubled from 4% to 8% of total regasification capacity, and we expect it to continue to rise. Lower oil and gas prices boost LNG demand, as new LNG importers need a faster, cheaper and more flexible solution. Top LNG picks. Höegh LNG (BUY, TP NOK131) is the FSRU market leader and is set to double its FSRU orderbook by 219e; the stock is trading at a 12% discount to our NAV of NOK94. Golar LNG (BUY, TP USD62) has a first-mover advantage in FLNG, having raised equity for and ordered two FLNG units; we believe the share price (USD3) implies a 3% discount to LNG vessels and a c5% cut in tolling fees for two FLNGs, compared to our expectations. Company Cur Rec Target Price P/E 14e P/E 15e P/E 16e Awilco LNG NOK BUY nm nm 1.9 GasLog USD BUY Golar LNG USD BUY nm 64.1 Golar LNG Partners USD BUY Höegh LNG Holdings NOK BUY nm ANALYSTS Øyvind Berle PhD oyvind.berle@dnb.no Nicolay Dyvik nicolay.dyvik@dnb.no Petter Haugen petter.haugen@dnb.no Please see last pages for important information

2 LNG shipping sector Contents LNG investment case 3 Peer group analysis 5 Supply 6 LNG fleet 6 LNG order book 9 Deliveries 11 Cancellations 12 Contracting 12 Yard overview 13 Scrapping 14 Demand 16 We expect 4% growth in traded volumes in e 16 Volumes traded 17 Transportation demand 2 Development of a spot market 21 Regasification capacity 23 Liquefaction capacity survey 25 Algeria 25 Angola 25 Australia 26 Brunei 28 Cameroon 29 Canada 29 Egypt 32 Equatorial Guinea 32 Indonesia 33 Libya 34 Malaysia 35 Mozambique 36 Nigeria 36 Norway 37 Oman 38 Papua New Guinea 38 Peru 39 Qatar 39 Russia 4 Tanzania 41 Trinidad and Tobago 41 United Arab Emirates (UAE) 42 The US 42 Yemen 48 Market balance 49 Spot rates, TC rates and vessel values 52 FSRU market 54 FLNG market 56 Impact of lower oil price on LNG 57 Appendix: Introduction to gas liquefaction 64 Awilco LNG 64 GasLog 81 Golar LNG 94 Golar LNG Partners 15 Höegh LNG 12 2

3 LNG investment case We expect 215 to be a low year in the LNG cycle before things pick up in , as the fleet outgrows demand for a fourth consecutive year making fleet utilisation in 215 the lowest since the 29 downturn. However, things should improve considerably in 216 when new liquefaction comes on-line and we believe the LNG shipping market will become an increasingly large part of global shipping longer-term and reveal several investment opportunities for FLNGs, FSRUs and standard transportation. We expect traded volumes to grow by 12% in 215, increasing to 14% in 216e, and slowing to 9% in 217e. When crossed with distances, this translates to demand growth of 11% for 215e, increasing to 16% for 216e, and slowing to 7% for 217e. The basis for our forecasts is a survey conducted during summer and autumn 214, where we collected data from more than 1 liquefaction projects, both planned and operating. 215 set to be low year in LNG cycle, before things pick up in We forecast demand growth of 11% for 215, 16% for 216, and 7% for 217 Shorter contracts could reveal more LNG shipping opportunities The LNG shipping market has moved towards shorter contracts over the past decade, as spot 1 as a proportion of total traded volume rose from 5% in 2 to 27% in 213. Also, existing contracts are set to roll off by an average of 9m tonnes per year between 215e and 22e, implying that the share of spot volumes could continue to increase substantially. We find this very interesting as it could lead to a much more flexible and volatile market, providing opportunities for our coverage universe, which is increasingly dependent on shorterterm coverage term coverage for vessels. Order books full until 217e; limited slippage, scrapping; contracting big unknown We forecast fleet growth of 9.5% for 214e (4.% in 213), increasing to 9.6% for 215e, and decreasing to 7.4% for 216e. This does not include deliveries from new ordering as the average time from ordering to delivery is just over three years; hence, supply growth is fairly certain in the LNG market for the next three years. and fleet growth of 9.5% for 214, 9.6% for 215, and 7.4% for 216 At end-november the gross order book was 21m m 3, or 37% of the fleet. We have no reason to expect any significant delays or cancellations in the order book and we include virtually all of it in our delivery estimates. The only adjustment we have made is to move six vessels with delivery in November 214 to January k+ m 3 vessels account for 98% of the order book by capacity and small carriers 2%. There are no orders for vessels of 6k 14k m 3. The order book/fleet ratio is 49% for 14k+ m 3 vessels. The LNG order book is split between China (14%), Japan (11%) and South Korea (75%). Comparing this with deliveries in , we note that China s market share has risen from 4% while South Korea s share has declined from 88% and Japan s from 8%. We forecast deliveries of 1% for 214e, increasing to 12% for 215e, decreasing to 8% for 216e and 7% for 217e. Contracting during 213 was 6.6m m 3, or 13% of the fleet at the beginning of that year. We expect.2m m 3 to be contracted for the remainder (December) of 214e (8.4m m 3 for the full year), 2.5m m 3 for 215e and 3.2m m 3 for 216e, reflecting 15% of the fleet at the start of 214e, 4% in 215e and 5% in 216e. This compares with the 1-year average of 5.1m m 3 (19%) and a 5-year average of 4.4m m 3 (8%). There has been only modest scrapping of LNG vessels over the past few years: 213 saw scrapping of 412k m 3 or.8% of the fleet. We expect.5% annual scrapping for our forecast horizon. In our forecasts we now scrap vessels when they turn 4 years or at the first special or intermediate survey for those vessels already aged 4+ years. Regardless of methodology, with a fleet as young as that of LNG it is hard to see significant scrapping. In October we said shipping did not need lower commodity prices The effect of the lower oil price on LNG share prices is overdone, in our view. Although a lower Asian crude-linked LNG price is negative, it might stimulate more price-sensitive demand. We believe falling oil and gas prices are mostly positive for FSRU, negative for We expect contracting of 2.5m m 3 for 215 and 3.2m m 3 for 216 (5-year average: 4.4m m 3 ) Limited scrapping seen and expected for LNG Impact of lower oil price on LNG share prices is overdone, in our view 1 Here spot relates to contracts with duration of four years or less, this is GIIGNL terminology 3

4 e 215e 216e 217e e 215e 216e 217e % -2% % % 3% Demand growth (%) 3% 4. % 5% 5% 8% 7% 12% 11% 16% 15% 16% Fleet growth (%) 9% 9.5 % 7.3 % 6.3 % 13% 11.2 % 16% 19% 18% 18% 17% 3% 28% e 215e 216e 217e 218e 219e 22e Fleet utilisation (%) 74% 82% 84% 86% 85% 85% 83% 89% 91% 9% 89% 88% 86% LNG spot rates (USD/day) 88% 9% 9% 95% 94% DNB Markets FLNG and LNG shipping short-term, and could stimulate demand longer-term. We believe current land-based and floating LNG projects will be priced as a function of the crude forward curve rather than current gas prices. DNB s view is USD7/bbl crude in 215e, USD8/bbl in 216e, and USD85/bbl in 217, which could fuel a recovery in LNG shipping stocks. New opportunities for FSRUs Regasification capacity remains plentiful in most places but not always in the right places, so floating regasification technology is growing in market share. Over the past four years this has doubled from 4% to 8% of total regasification capacity and we expect this trend to continue. FSRU technology is a clear winner from the lower oil price and spike in LNG demand. Floating regasification technology is increasing its market share Cost advantage spurs FLNG demand at land-based liquefaction s expense A lower oil price should favour FLNG demand over land-based liquefaction due to the c5% cost advantage. Land-based projects are likely to become unprofitable before floating solutions. Also, in a regime where costs will be cut, we believe relatively speaking given inshore FLNG projects are far less complex than land-based facilities that FLNG will enjoy a cost, time-to-market, and flexibility advantage over land-based projects. LNG fleet utilisation Spot rate forecasts 1% 95% 16, 14, 141,772 9% 85% 8% 75% 12, 1, 8, 6, 6,253 11, ,162 82, 82, 68, 55, 7% 4, 2, Utilisation (%) e 215e 216e 217e Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets LNG demand growth LNG fleet growth 35% 3% 3% 25% 2% 25% 2% 15% 15% 1% 5% % 1% 5% -5% % YOY YoY growth Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets 4

5 Fleet (including newbuilds) Multiples Sensitivities Leverage Valuation Misc. DNB Markets Peer group analysis LNG peer group Awilco LNG Golar LNG Golar LNG Partners GasLog Ticker alng glng gmlp glog hlng Currency (Local) Recommodation BUY BUY BUY BUY BUY Price (as of ) (Local) Target (Local) Deviation from target (%) Höegh LNG Average Median EPS (USD/share) Performance (%) EBITDA (USDm) month month year NIBD (USDm) 289 1,563 1,332 2, ,229 1,332 Market cap (USDm) 93 2,817 1,95 1, ,42 1,483 EV (USDm) 382 4,38 3,282 3,728 1,471 2,649 3,282 Current NAV (Local/share) Price/NAV ratio Yield (%, base current price) ChgNAV per +1% values** (Local/share) FALSE % 118 neg EPS sensitivity*** na NIBD/EBITDA ratio Contract coverage (%) EV/EBITDA P/E FALSE 62 FALSE neg. > LNG old steam turbine Number LNG modern steam turbine Number LNG TFDE Number FSRU converted Number FSRU newbild Number FLNG Number 2 Total Number Share LNG (%) Share FSRU (%) Avg. age owned fleet (Years)

6 e 215e 216e 217e 218e 219e 22e # vessels 14k+ m3 DNB Markets Supply We forecast fleet growth of 9.5% for 214e, up from 4.% in 213, increasing to 9.6% for 215e and decreasing to 7.4% for 216e. This does not include deliveries from new ordering as the average time from ordering to delivery is just over three years; hence supply growth is fairly certain in the LNG market next three years. At end-november the gross order book was 21m m 3, or 37% of the fleet. We have no reason to expect any significant delays or cancellations to the order book. The only adjustment we have made is to move six vessels with delivery in November 214 to January k+ m 3 vessels account for 98% of the order book by capacity and small carriers 2%. There are no orders for vessels of 6k 14k m 3. The order book/fleet ratio is 49% for 14k+ m 3 vessels. The LNG order book is split between China (14%), Japan (11%) and South Korea (75%). Comparing this with deliveries during , we note that China s market share has risen from 4% while South Korea s share has declined from 88% and Japan s from 8%. We forecast deliveries of 1% for 214e, increasing to 12% and 215e, decreasing to 8% for 216e and 7% for 217e. Contracting during 213 was 6.6m m 3, or 13% of the fleet at the beginning of that year. We expect.2m m 3 to be contracted for the remainder (December) of 214e (8.4m m 3 for the full year), 2.5m m 3 for 215e and 3.2m m 3 for 216e, reflecting 15% of the fleet at the start of 214e, 4% in 215e and 5% in 216e. This compares with the 1-year average of 5.1m m 3 (19%) and a 5-year average of 4.4m m 3 (8%). There has been only modest scrapping of LNG vessels over the past few years: 213 saw scrapping of 412k m 3 or.8% of the fleet. We expect.5% annual scrapping for our forecast horizon. In our forecasts we now scrap vessels when they turn 4 years or at the first special or intermediate survey for those vessels already aged 4+ years. Regardless of methodology, with a fleet as young as that of LNG it is hard to see significant scrapping. LNG fleet and order book above 14k m Fleet Orderbook Source: Clarksons LNG fleet We forecast fleet growth of 9.5% for 214e, up from 4.% in 213, increasing to 9.6% for 215e and decreasing to 7.4% for 216e. This does not include deliveries from new ordering as the average time from ordering to delivery is just over three years; hence supply growth is fairly certain in the LNG market for the next three years. We expect the LNG fleet to grow from 55.2m m 3 at end-213 to 76.7m m 3 at end-217e. The current fleet is split 69% 14k+ m 3, 29% 1k 14k m 3, 1% 6k 1k m 3, and % below 6k m 3 (by capacity, not units). 6

7 Jan-3 Oct-3 Jul-4 Apr-5 Jan-6 Oct-6 Jul-7 Apr-8 Jan-9 Oct-9 Jul-1 Apr-11 Jan-12 Oct-12 Jul-13 Apr-14 Jan-15 Oct-15 Jul-16 Apr-17 Jan-3 Oct-3 Jul-4 Apr-5 Jan-6 Oct-6 Jul-7 Apr-8 Jan-9 Oct-9 Jul-1 Apr-11 Jan-12 Oct-12 Jul-13 Apr-14 Jan-15 Oct-15 Jul-16 Apr-17 Monthly fleet growth Annual fleet growth YTD14 ROY YTD14 ROY k m k m e 215e 216e 217e k m3 Cumulative share of fleet (%) 17,434 2,225 k m3 22,87 26,82 31,571 4,28 47,229 51,534 53,15 53,87 55,215 6,445 67,189 72,124 76,674 DNB Markets LNG fleet by year built 35, 3, 25, 2, 15, 1, 5, 19 % 1 % 4 % 6 % 8 % 12 % 34 % 1 % 1 % 85 % 9 % 8 % 7 % 6 % 5 % 4 % 3 % 2 % 1 % % Below Cumulative share of fleet Fleet including forecast years (year-end) 9, 8, 7, 6, 5, 4, 3, 2, 1, Source: Clarksons, DNB Markets Delivery year Source: Clarksons, DNB Markets Below 6 LNG fleet and order book by vessel size LNG fleet and order book by shipyard country 1, 9, 8, 7, 6, 5, 4, 3, 2, 1, Below , 9, 8, 7, 6, 5, 4, 3, 2, 1, Other South Korea Japan China Source: Clarksons, DNB Markets Fleet by year of delivery Gross orderbook Source: Clarksons, DNB Markets Fleet by year of delivery Gross orderbook Monthly fleet growth 4.5% 4.% 3.5% 3.% 2.5% 2.% 1.5% 1.%.5%.% -.5% Annualised, smoothed monthly growth versus YOY growth 35% 3% 25% 2% 15% 1% 5% % -5% MOM 3mths MA YOY 3mths MA annualised Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets 7

8 Average age (years) # vessels Jan-7 Aug-7 Mar-8 Oct-8 May-9 Dec-9 Jul-1 Feb-11 Sep-11 Apr-12 Nov-12 Jun-13 Jan-14 Aug-14 Mar-15 Oct-15 May-16 Dec-16 Jul-17 Fleet growth (YOY, %) Share of total fleet and order book (%) YTD14 ROY DNB Markets Monthly fleet growth YOY by vessel size LNG fleet and order book by shipyard country 12% 1% 8% 6% 4% 2% % -2% -4% -6% 12 % 1 % 8 % 6 % 4 % 2 % % Fleet by year of delivery Gross orderbook Source: Clarksons, DNB Markets Below 6 China share Japan share South Korea share Source: Clarksons, DNB Markets Current fleet by vessel size (k m 3 ) Current fleet by engine type 1 % % 22 % 29 % Diesel Electric Motor Ship 2-Stroke Motor Ship 4-Stroke Steam Turbine 6-1 Below 6 12 % 63 % 7 % 3 % Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Average age by engine type, current fleet Fleet by number and capacity by engine type (total fleet) Diesel Electric Motor Ship 2- Stroke Motor Ship 4- Stroke Steam Turbine Not given Total fleet Diesel Electric Motor Ship 2-Stroke Fleet Motor Ship 4-Stroke Orderbook Steam Turbine Not given Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets 8

9 % (basis # vessels) # of vessels k m3 Orderbook/fleet ratio # of vessels DNB Markets Order book/fleet ratio by vessel size, currently Fleet and order book by vessel size (number of vessels) 45, 4, 35, 3, 25, 2, 15, 1, 48 % 18 % 165 % 16 % 14 % 12 % 1 % 8 % 6 % 4 % Fleet 5 4 Orderbook OB/fleet 5, % % Below 6 2 % % In service Vessel size (m3) On order Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Cargo containment system in fleet and orderbook Containment system by vessel age 4% 35% 3% 25% 36% 33% 25% % 15% 12% 13% % 5% % 6% 4% 4% Other/not given Gaztransport Technigaz Moss Other/not given Gaztransport Technigaz Moss Source: Clarksons, DNB Markets % of total fleet % of total orderbook Built 2 or earlier Built Built 211 or later Source: Clarksons, DNB Markets LNG order book At end-november the gross order book was 21m m 3, or 37% of the fleet. We have no reason to expect any significant delays or cancellations to the order book as shown in the chart below, right, we include virtually all of it in our delivery estimates. The only adjustment we have made is to move six vessels with delivery in November 214 to January k+ m 3 vessels account for 98% of the order book by capacity and small carriers 2%. There are no orders for vessels of 6k 14k m 3. The order book/fleet ratio is 49% for 14k+ m 3 vessels and 165% for small LNG carriers (<6k m 3 ). The LNG order book is split between China (14%), Japan (11%) and South Korea (75%). Comparing this with deliveries during , we note that China s market share has increased from 4% while South Korea s share has declined from 88% and Japan s from 8%. 9

10 k m3 k m3 Jan-97 Feb-98 Mar-99 Apr- May-1 Jun-2 Jul-3 Aug-4 Sep-5 Oct-6 Nov-7 Dec-8 Jan-1 Feb-11 Mar-12 Apr-13 May-14 Jan-97 Mar-98 May-99 Jul- Sep-1 Nov-2 Jan-4 Mar-5 May-6 Jul-7 Sep-8 Nov-9 Jan-11 Mar-12 May-13 Fleet growth YoY (%) OB/fleet ratio (%) 14+ fleet growth (%) OB/fleet ratio (%) k m3 k m3 DNB Markets LNG order book at start of year by delivery year 25, Our adjusted order book for future delivery 25 2, 2 15, 15 1, , 5 To be delivered current year next year (Y+1) Y+2 and onwards Order book reported by Clarkson...of which delivery earlier than first forecast month Estimated cancellations of current future order book DNB adjusted orderbook for future delivery Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Order book to fleet ratio and fleet growth, total Order book to fleet ratio and fleet growth, 14k+ m 3 35 % 12 % 45 % 3 % 3 % 25 % 2 % 15 % 1 % 5 % % 1 % 8 % 6 % 4 % 2 % 4 % 35 % 3 % 25 % 2 % 15 % 1 % 5 % 25 % 2 % 15 % 1 % 5 % -5 % % % % Source: Clarksons, DNB Markets Fleet growth YoY (%) OB/fleet ratio (%) Source: Clarksons, DNB Markets Fleet growth YoY (%), 14+ OB/fleet ratio (%) LNG order book by vessel size 8, 7, 6, 5, LNG order book by builder 8, 7, 6, 5, 4, 4, 3, 3, 2, 2, 1, 1, ROY ROY Below 6 China Japan South Korea Other Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets 1

11 Jan-3 Sep-3 May-4 Jan-5 Sep-5 May-6 Jan-7 Sep-7 May-8 Jan-9 Sep-9 May-1 Jan-11 Sep-11 May-12 Jan-13 Sep-13 May-14 YOY change in MA(3) monthly deliveries e 215e 216e 217e Monthly deliveries (k m3) 323 Deliveries (k m3) 2,85 2,791 2,582 1,833 2,539 3,995 4,799 4,434 5,499 5,38 4,929 7,213 7,5 9,122 k m3 k m3 k m3 k m3 DNB Markets Total order book, delivery versus contracting year 9 Total order book, contracting versus delivery year YTD < ROY14 ROY Delivery year < YTD14 Ordering year Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Total order book, shipyard location versus contracting year Total order book, contracting year versus shipyard country China Japan South Korea Builder location Others YTD < < YTD14 Ordering year Others South Korea Japan China Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Deliveries We forecast deliveries of 1% for 214e, increasing to 12% for 215e, decreasing to 8% for 216e and 7% for 217e. Historical deliveries by month Historical and forecast deliveries by year 1,4 1,2 1, % 8% 6% 4% 2% % -2% 1, 9, 8, 7, 6, 5, 4, 3, 2, 1, Below 6 YOY (3mth MA) Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Expected deliveries from new ordering (k m3) Expected deliveries from current OB (k m3) Historical deliveries (k m3) 11

12 Jun-14 Aug-14 Oct-14 Dec-14 Feb-15 Apr-15 Jun-15 Aug-15 Oct-15 Dec-15 Feb-16 Apr-16 Jun-16 Aug-16 Oct-16 Dec-16 Feb-17 Apr-17 Jun-17 Aug-17 Oct-17 Dec-17 Jun-14 Sep-14 Dec-14 Mar-15 Jun-15 Sep-15 Dec-15 Mar-16 Jun-16 Sep-16 Dec-16 Mar-17 Jun-17 Sep-17 Dec-17 Deliveries by month (k m3) 14+ eliveries by month (# vessels) Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Sep-16 Jan-17 May-17 Sep-17 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Sep-16 Jan-17 May-17 Sep-17 Fleet growth (YOY, %) Fleet growth (YOY, %) DNB Markets Fleet growth by month, historical and forecast Fleet growth by month, historical and forecast, only 14k+ m 3 1% 8% 6% 4% 2% % -2% -4% -6% 25% 2% 15% 1% 5% % Below growth in DNB estimates Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Monthly additions from the current order book (k m 3 ) Monthly additions from current order book (no. of 14k+ m 3 ) 1,8 1,6 1,4 1,2 1, Below 6 Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Cancellations Unlike many other shipping segments, there have been limited slippages and cancellations in LNG. At this stage we have no reason to believe any future orders will not be delivered; hence we have not assumed any slippage in our forecast horizon. Contracting Contracting during 213 was 6.6m m 3, or 13% of the fleet at the beginning of that year. We expect.2m m 3 to be contracted for the remainder (December) of 214e (8.4m m 3 for the full year), 2.5m m 3 for 215e and 3.2m m 3 for 216e, reflecting 15% of the fleet at the start of 214e, 4% in 215e and 5% in 216e. This compares with the 1-year average of 5.1m m 3 (19%) and a 5-year average of 4.4m m 3 (8%). As the lead time on new liquefaction capacity is often longer than it takes to build a vessel, our contracting estimates are highly dependent on potential further FIDs taking projects from the FEED phase into under construction ; i.e. if we now underestimate further growth in liquefaction capacity we are highly likely to underestimate future vessel ordering. However, as the average time from ordering to delivery in Japan and South Korea during 213 was c39 months, there are limited possibilities for 217 delivery. Hence, from a fleet supply perspective there is rather good visibility until 218. In this context, note that there are already two vessels in the order book with a 22 delivery date. 12

13 Nov-1 Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov Monthly contracting (k m3) ,437 1,283 1,444 1,518 1,384 1,344 1,215 1, YTD YTD14 New contracting (k m3) Time from ordering to delivery (years) DNB Markets Annual contracting 12 1 Average time from ordering to delivery by building country Below (Annualised) contracting by year Ordering year China P.R. Japan South Korea All builders Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Past four years of contracting by vessel size (k m 3 ) , , ,19 1,214 1, Below 6 Source: Clarksons, DNB Markets Yard overview Over the past 12 months, Daewoo has received the most orders (2,763k m 3 ), followed by Hyundai HI (1,363k m 3 ), and Samsung HI (87k m 3 ). Aggregated, the top 1 yards have 98% of the total order book. Top 1 shipyards ranked by share of current order book Order book by year of delivery (k m3) Order book by year of ordering (k m3) Yard group Country Total ROY < YTD14 Samsung HI South Korea Daewoo South Korea Hyundai HI South Korea Hudong Zhonghua China P.R Hyundai Samho HI South Korea Mitsubishi H.I. Japan Kawasaki H.I. Japan STX SB (Jinhae) South Korea Imabari Shipbuilding Japan Japan Marine United Japan Total top Other yards Top 1 share of total 98 % 1 % 97 % 97 % 1 % 1 % 1 % 97 % Source: Clarksons, DNB Markets 13

14 < < k m3 vessels scrapped # vessels scrapped YTD14 Nov-1 Feb-11 May-11 Aug-11 Nov-11 Feb-12 May-12 Aug-12 Nov-12 Feb-13 May-13 Aug-13 Nov-13 Feb-14 May-14 Aug-14 Nov-14 Scrapping (k m3) Scrapping (% of fleet) Montly scrapping (km 3) DNB Markets Scrapping There has been only modest scrapping of LNG vessels over the past few years: 213 saw scrapping of 412k m 3 or.8% of the fleet. We expect.5% annual scrapping for our forecast horizon. In our forecasts we now scrap vessels when they turn 4 years or at the first special or intermediate survey for those vessels already aged 4+ years. Regardless of methodology, with a fleet as young as that of LNG it is hard to see significant scrapping. Historical scrapping, by size and total as percentage of fleet Past four years of scrapping by vessel size %.8% % %.5% %.3% %.1% 5.% Below 6 Total scrapping (% fleet) >> Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Below 6 Past three years of scrapping, by capacity Past three years of scrapping, by number of vessels 1, 1 % 14 1 % % 8 % 7 % 6 % 5 % 4 % 3 % 2 % 1 % Below % 96 % 94 % 92 % 9 % 88 % 86 % 84 % 82 % Below % Cumulative share - 8 % Cumulative share Age when scrapped (years) Age when scrapped (years) Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets 14

15 % of fleet % 214e 215e 216e 217e Average age when scrapped -.5 % -.4 % -.5 % -.5 % -.5 % -.6 % -.5 % % Scrapping (k m3) % Scrapping as % of fleet %. %. %. %. % DNB Markets Average age of scrapped vessels (k m 3 ) Historical and forecast scrapping by year 5. % % -.2 % % -.4 % % -.6 % -.7 % % -.9 % Below Historical scrapping (k m3) Expected scrapping (k m3) Scrapping Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Renewal survey schedule for current fleet 6% 5% 4% 3.1% 3.3% 3% 2.4% 2%.2% 1.1%.8% 1% 1.4% 1.3%.5%.8% %.2%.%.2%.%.2%.% 215e 216e 217e 218e Source: Clarksons, DNB Markets 3th renewal survey 4th renewal survey 5th renewal survey 6th renewal survey 15

16 e 215e 216e 217e 218e 219e 22e m tonne DNB Markets Demand We expect traded volumes to grow by 12% in 215e, increasing to 14% in 216e and slowing to 9% in 217. When crossed with distances this translate to demand growth of 11% for 215e, increasing to 16% for 216e while slowing to 7% for 217. The basis for our forecasts is a survey conducted during summer and autumn 214 where we collected data from more than 1 liquefaction projects, both planned and operating. YTD (including September) trails at a meagre 1% growth in traded volumes compared with the same period in 213, and we forecast full-year trade of 241m tonnes, about the same as in 213. In general the volumes traded have been stable since 211. Growth in 215e is expected to come mainly from South East Asia (Australia and Papua New Guinea), while in 216e we expect more diversified growth albeit still dominated by Australia. In 216 we also expect the two first trains in Cheniere s Sabine Pass project to be fully operational, adding about 7.5m tonnes. The LNG shipping market has moved towards shorter contracts over the past decade, as spot 2 as a proportion of total traded volume rose from 5% in 2 to 27% in 213. Also, existing contracts are set to roll off by an average of 9m tonnes per year between 215e and 22e, implying that the share of spot volumes could continue to increase substantially. We find this very interesting as it could lead to a much more flexible and volatile market, providing opportunities for our coverage universe, which is increasingly dependent on shorterterm coverage for vessels. Regasification capacity remains plentiful in most places but not always in the right places, so floating regasification technology is growing in market share. Over the past four years this has doubled from 4% to 8% of total regasification capacity and we expect this trend to continue. Total trade West Africa South America S/E Asia North America North Africa N/E Asia Middle east Europe East Africa Australia Source: Poten, DNB Markets We expect 4% growth in traded volumes in e During summer and autumn 214 we collated data on potential future liquefaction capacity. Adding in brownfield expansion of operating liquefaction capacity and capacity from plants under construction (our base case), we estimate the total market will grow from 236m tonnes in 214 to 329m tonnes in 217, or by close to 4%. Looking to 22 we estimate total exports of 372m tonnes. Capacity with a final investment decision adds only 3m tonnes to 217e exports, yet takes trade in 22e to 46m tonnes (c7% higher than in 214). In the chart below we group the volumes we have identified by the status of the plant: 2 Here spot relates to contracts with duration of four years or less, this is GIIGNL terminology 16

17 Global exports (m tonne) DNB Markets 1 Producing. 2 Being built. 3 Has undertaken or is undertaking a FEED study, subdivided as follows: 3.1 Has made a final investment decision. 3.2 Has not made a final investment decision. 4 Most speculative, which we term proposed. The aggregate of 1) and 2) is our base-case scenario. Total trade by liquefaction plant category ) additions from "proposed" projects 3b) additions from projects that has started on the FEED, but no FID 3a) additions from projects that has started on the FEED study and a FID 2) additions from plants currently under construction 1) expansions from currently operating plants Current exports e 215e 216e 217e 218e 219e 22e Source: Poten, DNB Markets Delays are the major uncertainty. We have not included in our base case any (further) delays to projects under construction (brown/greenfield) as they are notoriously difficult to model. This might seem optimistic, but neither have we included any volumes from facilities that are not producing or are being built, regardless of whether a FID has been made. Leaving out the latter is also justified by the recent decrease in the price of oil, which will put cost pressure on many planned shore-based liquefaction plants, potentially cancelling those not yet started. We believe those plants that have started construction, implying a considerable share of sunk cost, we still profitable to finalise. Volumes traded YTD (including September) 214 trails at a meagre 1% growth in traded volumes compared with the same period in 213, and we forecast full-year trade of 241m tonnes, about the same as in 213. In general the volumes traded have been stable since 211, as shown in the charts below. We expect traded volumes to grow by 12% for 215e, increasing to 14% for 216e, and slowing to 9% for

18 Qatar Malaysia Australia Indonesia Papua New Guinea Others Total Q1-Q3 Imports (m tonne) YOY change Japan Korea China Spain India Others Total Q1-Q3 exports (m tonne) YOY change LNG import (m tonne) LNG export (m tonne) DNB Markets Total LNG trade by major importer (top 5) Total LNG trade by major exporter (top 5) Others India 2 Others Papua New Guinea 15 Spain 15 Indonesia 1 China Korea 1 Australia Malaysia 5 Japan 5 Qatar Source: Poten, DNB Markets Source: Poten, DNB Markets On the export side, Papua New Guinea (2%) and Australia (7%) have contributed to the growth YTD 214, while other major exporters have been rather stable. Of the top five importers, Spain increased imports the most (15%, on a gross basis, unadjusted for reexports), and growth was also seen in China (8%) and India (6%). Korea was the main laggard with an 8% YOY decline in Q1 Q Share of total imports (213) YOY growth in LNG imports (% basis Q1 Q3) Others 28% Japan 36% % 8% 15% 6% % 1% 2% 15% 1% 5% India 5% % % -5% YOY change Spain 6% China 8% Korea 17%. -1% Source: Poten, DNB Markets Source: Poten, DNB Markets Share of total exports (213) YOY growth in LNG exports (% basis Q1 Q3) Others 34% Qatar 32% % % 7% % 2% -1% 1% 25% 2% 15% 1% 5% % -5% YOY change Papua New Guinea 7% Indonesia 8% Australia 9% Malaysia 1% Source: Poten, DNB Markets Source: Poten, DNB Markets 18

19 214e 215e 216e 217e 218e 219e 22e Annual increments (m tonne) Annual increments (m tonne) e 215e 216e 217e 218e 219e 22e m tonne DNB Markets Below we show the aggregated historical and estimated volumes traded in our base case by exporting region. We expect total trade of 241m tonnes in 214e (we still do not have actual data for Q4), rising to 269m tonnes in 215e and further to 36m tonnes in 216e and 334m tonnes in 217e. Growth in 215e is expected mainly from South East Asia (Australia and Papua New Guinea), while in 216e we expect more diversified growth albeit still dominated by Australia. In 216 we also expect the two first trains in Cheniere s Sabine Pass project to be fully operational, adding about 7.5m tonnes. Total trade 4 35 West Africa South America S/E Asia North America North Africa 15 N/E Asia 1 5 Middle east Europe East Africa Australia Source: Poten, DNB Markets Annual growth from operating liquefaction capacity by exporter Annual growth from plants under construction by exporter West Africa South America S/E Asia North America North Africa N/E Asia Middle east Europe East Africa e 215e 216e 217e 218e 219e 22e West Africa South America S/E Asia North America North Africa N/E Asia Middle east Europe East Africa Australia 19

20 e 215e 216e 217e 218e 219e 22e Australian exports (m tonne) Australian share of global exports (%) Australia share of global annual additions (%) % % % % % m tonne Volume growth (%) 3% 5% 5% 7% 7% 6% 8% 9% 1% 9% 1% 12% 12% 12% 12% 11% 14% 14% 14% 14% 14% 2% 18% DNB Markets Alternative scenarios Annual volume growth rates in various scenarios 6 25% % 15% % 5% e 215e 216e 217e 218e 219e 22e Base case % -5% 214e 215e 216e 217e 218e 219e 22e Base case Including FEED with FID Including FEED with FID Including all FEED projects, 2 year delays Including all FEED projects, 2 year delays Including all FEED, as planned Including all FEED, as planned Australian LNG exports ( m tonne) and share of exports(%) Australia share of global annual export additions (%) 9 25% 7% 65% 65% 8 7 2% 6% 53% % 5% 45% % 5% 4% 3% 2% 31% % 1% 6% Australia Australian share of global exports (%) % 214e 215e 216e 217e 218e 219e 22e Transportation demand The transition from volume to transportation demand (tonne mile) is pretty straightforward; with the exception of the added volume from the Middle East in (which boosted the average distance significantly) we do not expect the current average of c4,2 nautical miles to change much in the coming years. In the charts below we show our base case and various scenarios in terms of tonne-mile. We expect tonne mile to grow by 11% for 215e, increasing to 16% for 216e and slowing to 7% for

21 % % % 1% bn tonne-mile Demand growth (%) 5% 6% 7% 7% 8% 7% 7% 8% 11% 11% 11% 16% 16% 16% 16% 22% 22% 214e 215e 216e 217e 218e 219e 22e 214e 215e 216e 217e 218e 219e 22e Annual increments (bn tonne-mile) Annual increments (bn tonne-mile) e 215e 216e 217e 218e 219e 22e e 215e 216e 217e 218e 219e 22e bn tonne-mile Nautical miles DNB Markets Tonne mile by exporter West Africa South America S/E Asia North America North Africa N/E Asia Middle east Europe East Africa Average laden distance Average laden distance Annual growth from operating liquefaction capacity by exporter Annual growth from plants under construction by exporter West Africa South America S/E Asia North America North Africa N/E Asia Middle east Europe East Africa West Africa South America S/E Asia North America North Africa N/E Asia Middle east Europe East Africa Tonne mile demand scenarios Annual demand growth rates in various scenarios 25 25% % % 15 1% % e 215e 216e 217e 218e 219e 22e % 214e 215e 216e 217e 218e 219e 22e Base case Base case Including all FEED projects, 2 year delays Including all FEED projects, 2 year delays Including all FEED, as planned Including all FEED, as planned Development of a spot market As shown in the chart below left, the LNG shipping market has moved towards shorter contracts over the past decade, as spot 3 as a proportion of total traded volume rose from 5% 3 Here spot relates to contracts with duration of four years or less, this is GIIGNL terminology 21

22 Current contract volumes by start year Terminaltion of current contract volumes by end-year (m tonne) m tonne traded on <4 years contracts Share of total LNG trade m tonne roll-off from current contracts % roll-off from current contracts DNB Markets in 2 to 27% in 213. Also, existing contracts are set to roll off by an average of 9m tonnes per year between 215e and 22e, implying that the share of spot volumes could continue to increase substantially. We find this very interesting as it could lead to a much more flexible and volatile market, providing opportunities for our coverage universe, which is increasingly dependent on shorter-term coverage for vessels. Also noteworthy is the potential for LNG as a fuel for vessels, which could provide an important new market supporting more spot volumes. This discussion has been ongoing for some years, in particular in light of the introduction of Emission Control Areas. However, such a market is still some way off, is it would require building substantial storage capacity in ports. Spot trade of LNG Roll-off of current contracts 7 3% 16 7% % 2% 15% 1% % 5% 4% 3% 2% % % 2 1% % "Spot" (<4 years) LNG trade % of total trade m tonne roll-off % roll-off from current portfolio Source: GIIGNG, DNB Markets Source: GIIGNG, DNB Markets Current contracts by start year of contract 3 Roll-off of current contracts N/E Asia Middle east 2 N/E Asia Middle east 15 S/E Asia South America 15 S/E Asia South America 1 Europe West africa 1 Europe West africa 5 North africa 5 North africa Source: GIIGNG, DNB Markets Source: GIIGNG, DNB Markets Another relevant factor for the longer term is global energy composition. Over the past five decades, the share of natural gas consumption in the global mix has increased from 16% (1965) to 24% (213). The US shale gas revolution has shed light on what sort of potential there might be to grow this share further as gas is still preferred over other fossil fuels, in particular due to its much lower particle emission than coal (saw its share grow again in the 2s as China joined the global economy). 22

23 m tonne oil equivalent Share of natural gas in the global energy mix (%) DNB Markets Global energy composition Renewables Hydro electric Nuclear Energy Coal Natural Gas Oil Share of natural gas in global energy mix 25% 24% 23% 22% 21% 2% 19% 18% 17% 16% 15% Source: BP Source: BP Global energy mix (1965) Global energy mix (213) % 5% % 7% 2% 4% Oil 33% Oil 41% Natural Gas Natural Gas 38% Coal Nuclear Energy Hydro electric 3% Coal Nuclear Energy Hydro electric Renewables Renewables 16% 24% Source: BP Source: BP Given time, these factors combined mean we consider it likely that LNG shipping will become a deep, liquid and volatile market, clearing its spot rates from gas price arbitrages when shipping capacity is tight. But this is still some way off. Regasification capacity Regasification capacity remains plentiful in most places but not always in the right places, so floating regasification technology is growing in market share. Over the past four years this has doubled from 4% to 8% of total regasification capacity and we expect this trend to continue. 23

24 Receiving capacity (mtpa, liquefied) Share of floating regasification capacity (%) Utilisation of receiving capacity (%) 3% 3% 29% 32% 33% 32% 33% 35% 34% 38% 38% 37% 37% 39% 39% DNB Markets Global regasification capacity Utilisation of regasification capacity 8 9% 45% 7 8% % 6% 5% 4% 3% 2% 4% 35% 3% 1 1% % 25% 2% Floating Shorebased Share of floating 24

25 Liquefaction capacity survey The data in this section comes from a survey we carried out last summer and autumn. We approached most liquefaction plants at an advanced stage and also included certain projects in the planning stage. We spoke to operating managers, IR and external contact managers; in some cases, we also used publicly available sources. All figures are in million tonnes per annum (mtpa) unless otherwise stated. Our aggregated estimate for 213 exports is 237.8m tonnes, which is in line with estimates from gas and energy consultancies and close to the 235.8mtpa estimated in BP s Statistical Review of World Energy. Algeria Existing and planned projects in Algeria Project name Project owner Type Start-up Nominal capacity (mtpa) GL 1Z Complex Sontrach Shore-based GL 2Z Complex Sontrach Shore-based GL 1K Complex Sontrach Shore-based GNL 2K Sontrach Shore-based Arzew GNL 3Z Sontrach Shore-based Algeria has been one of the largest and most dominant LNG exporters for many decades. In 213 it exported c11.22mt of LNG, almost the same as in 24. A lack of foreign investment in its gas sector has forced the country to continue extracting gas from old fields. Most foreign investors abstained due to unattractive fiscal terms. Production at Algerian fields has risen over the past decade, but domestic demand keeps export trains from running at full capacity and they are not targeted to run at full capacity as the infrastructure is old. Another reason behind the available export capacity is reduced take-or-pay volumes contracted to Italy, which receives gas from Algeria through two subsea pipelines so decreased demand from Italy might make room for more seaborne exports from Algeria. The old trains are about to be phased out, with one new train in 214 and another this year. We believe Algeria will remain a significant player, but it is very dependent on future foreign investment in its gas fields. Angola Existing plant in Angola Project name Project owner Type Start-up Nominal capacity (mtpa) Angola LNG T1 Soyo Chevron JV Shore-based Angola exported.4mt in 213 from its new LNG terminal. In 214, it faced a shutdown in April due to a rupture on a flare line. Production is expected to restart in mid-215. The vessels fixed for the project will go spot in other markets in the meantime. Chevron has a c37% stake in the plant, while the Angolan state oil firm Sonangol, Total, BP and ENI own the rest. 25

26 Australia Existing and planned projects in Australia Project name Project owner Type Start-up Nominal capacity (mtpa) North West Shelf Project Train 1 Woodside Shore-based NWS Train 2 Woodside Shore-based NWS Train 3 Woodside Shore-based NWS Train 4 Woodside Shore-based NWS Train 5 Woodside Shore-based Pluto LNG Woodside Shore-based Darwin LNG ConocoPhillips Shore-based Queensland Curtis LNG train 1 BG Group Shore-based Queensland Curtis LNG train 2 BG Group Shore-based 215e 4.25 Arrow Shell-Petrochina JV Shore-based Unknown 18 Australia Pacific LNG Origin-Cphillips-SINOPCE JV Shore-based 215e 9 Gladstone LNG Santos-Petronas-Total-Kogas JV Shore-based 215e 7.8 Gorgon Chevron, JV with Shell and Exxon Mob Shore-based 215e 15.6 Barrow Island expansion Chevron, JV with Shell and Exxon Mob Shore-based 218e 5.2 Wheatstone Chevron (64.14%) in JV Shore-based 216e 8.9 Ichtys Inpex, partnering with TOTAL Shore-based 217e 8.4 Prelude Shell FLNG 217e 3.6 Bonparte GDF Suez FLNG 219e 2.4 Fisherman's landing Liquefied Natural Gas limited Shore-based Unknown 3.8 Browse Woodside FLNG 218e 3.9 Scarborough Esso Australia (ExxonMobil) and BHP FLNG 221e 6.5 Crux LNG Shell (major owner) FLNG 22e Unknown Australia benefits from its close proximity to gas importers Japan, South Korea and Taiwan. It has been an LNG player since 1989, when Woodside started production from its North West Shelf project. During the past decade, there has been a surge in proposed projects, but economic realities mean there are now fewer projects on the drawing board. The main issue for Australia is its inflationary tendencies, driven by high and rising wages. Construction at mega sites (e.g. 15.6mtpa Gorgon) attracts a lot of the capacity, raising the cost of constructing another project simultaneously. The shelving of many large projects (e.g. Fisherman s Landing, Arrow) has been put down to inflationary pressure. Aggregating the projects in the construction/feed phase, Australia has taken huge steps in strengthening its position in LNG. Annual production capacity is expected to reach 8mtpa by 217e (today: 26mtpa) and to surpass 1mtpa by 22e. It is unclear, however, whether this will continue after the plants in the FEED/construction phase come on-stream. There are still large untapped gas resources (from conventional fields and unconventional coal seam gas resources), leading us to believe that the potential is there. That said, for Australia to continue its role as a first mover, it must address its escalating costs. North West Shelf project The last train built to liquefy gas from the North West Shelf was commissioned in 28. Contributing nameplate capacity of 4.4mtpa, it took annual capacity of the site to 16.3mtpa. Woodside does not expect to expand the site during the next few years and does not expect any trains to be decommissioned. Capacity is fully utilised. Pluto LNG This plant (also built and operated by Woodside) is remote and is on the Western Australia Burrup peninsula, utilising gas from the Pluto field. It was commissioned in 212 and is operating at maximum capacity of 4.8mtpa. The liquefied gas is underpinned by a 15-year sales contract with large importers Kansai Electric and Tokyo Gas. Total capital investment amounted to USD14,9m, meaning a cost of USD3,1/mt. This is close to the Australian average, and significantly above that of the North West Shelf project part of the reason for this is unfavourable currency rates. 26

27 Browse FLNG The resources in the Woodside-operated Browse basin have been well known for decades. The Australian operator spent USD2bn studying the feasibility of a land-based terminal, but decided to co-venture with Shell and others to build a floating liquefaction vessel instead. Shell is contributing its experience from the construction of the ground-breaking Prelude project, expected to come on-stream in 217. The Browse FLNG is in the basis of design phase, targeting to reach a FEED phase by mid-215. It expects a final investment decision by mid-216. The total cost for the plant has not been communicated, and annual production capacity is expected to be 3.9mtpa,.3 tonnes more than the Shell Prelude project. Darwin LNG This ConocoPhillips-operated plant at Wickham Point in North Australia has been operating since 26. Annual production capacity is 3.7mtpa. ConocoPhillips is appraising other projects in North Australia, and thus will not consider capacity expansion here near-term. ConocoPhillips operates the plant in a co-venture with Santos, INPEX, Eni, Tokyo Electric and Tokyo Gas. Gas is sold on long term-contracts (until 222) to Tokyo Electric and Tokyo Gas. Production was completed at a lower cost than the country average (cusd5/tonne). Queensland Curtis LNG The first train of this BG-operated plant started up in December 214, with 4.25mtpa capacity, with the second train due to come on-stream during Q3 215, increasing capacity to 8.5mtpa. Total investment for the project is estimated at USD2,4m, or USD2,4 per tonne, slightly below the Australian average. The plant will utilise gas from the BG-owned wells in the Surat Basin, Eastern Australia. Australia Pacific LNG Australia Pacific LNG is operated by Australian integrated energy company Origin and aims to develop LNG from coal seam gas. The gas will be sourced from the Surat and Bowen basins in central Queensland. The plant will have two trains, totalling 9mtpa. The company told us the first train would come on-stream by mid-215 and the second would be commissioned by end-215. Based on a February 213 announcement, the project s total investment is estimated to be USD24,66m. Of the 9mtpa capacity, 8.6mtpa is tied up in long-term agreements with Asian gas giants SINOPEC and Kensai. Origin has allowances to expand capacity, but is not committed to any plans. Gladstone LNG This is another facility to produce LNG from coal seam gas. The plant size when it reaches total capacity should be 7.8mtpa. The plant is scheduled for completion during 215. The project is a co-venture between Santos (which will operate the plant), Petronas, Total and Kogas. Of the 7.8mtpa capacity, 7.2mtpa is tied to long-term agreements with Petronas and Kogas. The capital investment of the project, between the FID and end-215, is expected to be USD18,5m. Gorgon project This mega project on Barrow Island is the largest single resource development ever constructed in Australia. It will be operated by Chevron Australia, in a JV with ExxonMobil. When completed, it will consist of three trains, each contributing 5.2mtpa. The project manager expects to reach total capacity of 15.6mtpa by early 216. Of this, 65% is sold on long-term contracts. The project is in the construction phase the first train arrived at the site in June 214. The company expects the first LNG to be exported by mid-215. The capex for the project has risen, mostly due to inflationary pressure in the LNG industry in Australia. The capital cost is now estimated to be USD54,m, giving a cost per metric tonne of USD3,5, well above the average even in an Australian context. There have been discussions about expanding capacity on Barrow Island, but plans are unlikely to commence before prices come down and other risks have been controlled. Wheatstone Wheatstone is Chevron s other large-scale LNG project, of which it holds 64%. The facility will be at an industrial site close to the city of Onslow on the north western coast of Australia. The plant will consist of two trains each of 4.45mtpa, giving total capacity of 8.9mtpa. A final 27

28 investment decision was reached in September 211, so the plant is in the construction phase. Of Chevron s 64% share, c85% of gas sales have been committed to Asian gas companies, notably TEPCO, Kyushu Electric and Chubu. The estimated capital investment for the project is USD29,m, leaving a slightly lower cost per metric tonne than Gorgon, but still above the USD3, Australian average. If no negative events happen, Chevron anticipates the first LNG exports could occur in 216, and that the plant will ramp up to full capacity by 217. Wheatstone LNG plant under construction Source: LNG World News Ichthys This project was initiated by the Japanese oil and gas giant INPEX, holding a 63% stake in the JV with Total and several minority owners. The Ichthys project will liquefy gas from the Browse basin, offshore Western Australia. The liquefaction capacity will be 8.4mtpa, of which c7% will be exported to Japan. The project is in the construction phase, and the first of the total 2 modules arrived at the site in July 214. The company expects the plant to start production by end-216, reaching full capacity in 217. It will also be able to produce a large amount of LNG, about 1.6m tonnes annually. Prelude Shell owns 67.5% of the world s first floating liquefied natural gas (FLNG) vessel, a 3.6mtpa capacity plant. It is being built at the Samsung Shipyard in South Korea. Shell reached its final investment decision in May 211, and expects production to commission in 217. The project is being built on a USD12,6m budget, leaving it above the Australian average in terms of cost per metric tonne produced. Prelude will operate the Browse basin, close to the city of Broom in north Australia, 2km from the shore. The project was formerly considered too remote to be economically viable, but the technology used to build Prelude might change this. Other projects In addition to the projects listed above, there are several proposed projects for Australia. However, due to escalating costs, they are so uncertain that we have excluded them, preferring to focus on projects that we believe are likely to materialise. Brunei Existing plants in Brunei Project name Project owner Type Start-up Nominal capacity (mtpa) Brunei LNG Sendirian Berhad The Sultan, Shell and Mitsubishi Shore-based

29 Brunei has the advantage of being close to its main customers, Japan and South Korea. The Brunei LNG is operated as a co-venture between the Brunei government (5%), Shell and Mitsubishi (25% each). The plant was established in 1969 and started production in Annual capacity is 6.7mtpa. From our consultation with Shell resources, we believe current capacity is a good indication of future production. There seem to be no expansion plans or reason to believe one or more trains will be de-commissioned. Cameroon Planned projects in Cameroon Project name Project owner Type Start-up Nominal capacity (mtpa) Kribi GDF Suez Shore-based 221e 3.5 The LNG project in Cameroon was initiated by GDF-Suez in a strategic partnership with SNH (Cameroon s national oil and gas company). Contracts with firms operating the upstream business were signed in 211. The project aims to reach a FID in 217. When the project is commissioned, after 22, GDF Suez will operate the plant. Annual capacity will be 3.5m tonnes per annum in its first stage. Canada Planned projects in Canada Project name Project owner Type Start-up Nominal capacity (mtpa) Pacific NorthWest LNG Petronas in JV Shore-based 219e 12 PNWLNG expansion Petronas in JV Shore-based 219e 6 Woodfibre Woodfibre Shore-based 217e 2.1 LNG Canada Project Shell LNG JV Mitsubishi Shore-based 22e 12 LNG Canada P train 3-4 Shell LNG JV Shore-based 222e 12 Kitmat LNG Chevron Shore-based 22e 1 Prince Rupert project BG group Shore-based 22e 14 Prince Rupert train 3 BG Group Shore-based Unknown 7 Goldboro LNG Pieridae Energy Shore-based 219e 1 West Coast Canada LNG Imperial Oil and ExxonM Shore-based 222e 3 Aurora LNG project CNOOC Inpex JV Shore-based 222e 12 Aurora expansion CNOOC Inpex JV Shore-based 221e 12 Sarita Bay LNG Project Steelhead LNG Shore-based Unknown 24 Bear Head LNG Liquefied Natural Gas limited Shore-based 219e 4 Western Canada is abundant with shale gas plays far beyond the country s domestic needs and benefits from shorter sailing distances to Asia than most US plants. However, its infrastructure and extraction technology are at an earlier stage than those south of the border and there is the issue of native land, as pipelines from extraction fields run through native land to reach the large ports of Kitimat and Prince Rupert in North Western British Colombia. In total, 15mtpa of capacity is on the drawing board, scheduled to be completed between now and 225. However, a considerable proportion of this capacity is planned expansion, dependent on the economic viability of the first stage of production. Political institutions have a key role to play in terms of environment policies, export licences, and the financial regime. Project owners constructing liquefaction plants in British Colombia are negotiating the taxation and royalty regime that will apply to LNG producers. The industry is new to British Colombia, and the viability of many large-scale projects will depend heavily on the tax regime. To us the liberal government seems committed to attracting investment in the sector to the extent that it will be willing to reach out to meet the project demands. Regulatory process Canadian firms wanting to export LNG have to apply for an allowance to export from the National Energy Board, which works to secure the domestic supply of gas and to ensure stable prices (in much the same way as the DoE does in the US). 29

30 Canadian gas exporters have historically had two markets for gas: 1) domestic; and 2) the US via pipelines. However, an abundant gas supply from unconventional sources in the US has reduced exports through these pipelines, and Canadian producers are looking for new harbours to source their gas. In addition to receiving an export licence, a liquefaction plant must co-operate with the provincial government, which tracks the construction and operation of a plant. Most planned liquefaction plants will be in British Colombia, but there are also projects proposed for the east coast. The latter will benefit from close proximity to Europe, whereas those in British Colombia should benefit from shorter sailing distances to Asia. A prerequisite for operating in the gas industry in Canada is an environmental assessment. Firms need to apply to two bodies: the Canadian Environmental Assessment Agency and the BC Environmental Assessment (or similar, for other states). A project requires an assessment by the CEAA if it includes one or more activity, such as a marine terminal. There are regulations on environmental issues such as bird life in coastal areas and aboriginal rights. In addition, the EA sets out requirements for communication with local communities. Environmental assessment under the British Columbia Environmental Assessment Office (EAO) is needed for all projects larger than a threshold measured in annual production. This is far below the expected output of most plants on the drawing board. It is in this environmental assessment process that local communities and other public interests can comment. They can do so in the first phase of the process (when the application is being prepared) and during the 9 days when the application is being reviewed. After the second public comment period, the report is assessed, and after another 9 days the provincial ministers use the material provided to decide whether the project should be given the green light. Stylised regulatory process for LNG exports from Canada Liquefaction plants Pacific North West LNG (Petronas) This project is operated by Malaysian state-owned Petronas and several minority owners. It will be on Lelu Island, close to Prince Rupert. It is a greenfield project, involving estimated capex of USD11bn. It is in its FEED stage awaiting FERC approval, and work at this stage involves consulting the local community and securing long-term contracts. In December 214, Petronas decided to defer the project s FID pending on further clarity on substantive items of importance to ensure that critical project components align with economic viability of the Project and competition from other LNG producing countries. The facility is scheduled to come on-stream in 219 with production capacity to handle 12mtpa (two trains, each of 6mtpa). The company has an option for a third 6mtpa train. LNG Canada project (Shell LNG) The proposed LNG Canada project is being developed by renowned gas giants Shell, KOGAS, Mitsubishi and PetroChina (Shell is the majority owner). It will be close to Kitmat, British Columbia. It is conducting technical and environmental studies, involving local 3

31 communities and communicating with Kitselas First Nations. The company told us the project was on schedule, targeting FID during 216. It has to file for the second environmental assessment (EA). The project has four trains on the drawing board, but will go ahead with trains 1 and 2 first. Construction is expected to take c4 5 years and the facility is scheduled to come on-stream by end-22. In 221, LNG Canada expect be able to produce 12mtpa, rising to 24mtpa as soon as the third and the fourth trains come on-stream, if they are deemed economically viable. This decision will depend on market conditions closer to 22. Prince Rupert LNG project This project was initiated by BG-Group, one of the largest players on the global LNG scene. It will be at Ridley Island, near Prince Rupert, and its first phase includes building two trains and an associated port facility. Consulting with company sources, we believe it will be able to reach a FID by mid-216 and see trains coming on-stream in 22. The company expects the project to have combined production capacity of 14mtpa, with the possibility to expand with an additional 7mtpa train. Market conditions at the time will be the main determinant of whether or not to expand. The first phase of the project involves capital investment of USD11,m. Kitimat LNG project This project was initially developed as a co-venture between Chevron and Apache. However, in response to activist investor Jana Partners LLC s recurring proposals for the firm to become more efficient, Apache withdrew from the project at end-july 214. The initial plan was to let Apache be responsible for the downstream activities, and Chevron to be responsible for the 48km pipeline (transporting gas from the basin in North East British Columbia to Kitimat) and the liquefaction plant. Consulting with Chevron, it seemed confident the project would proceed as planned. Chevron does not intend to buy in on Apache s half, but might perform Apache s upstream role. In terms of reaching a final decision, the key issue is securing contracts covering 6 7% of total capacity. Chevron is not able to comment on its marketing efforts, but states the most urgent issue is to agree on a tax- and royalty framework for LNG production in British Colombia. Kitimat LNG will serve as an export facility for gas sources from Horn River and Liard basins in British Colombia. It has received an export permit from the National Energy Board allowing for the export of 1mtpa, and all major environmental approvals are in place. Construction has started, but the FID will not be reached before Chevron is more confident about the broader risk picture. This includes finding a new stakeholder. Kitimat LNG Source: Kitimat LNG 31

32 Goldboro LNG We understand that Goldboro LNG is the only liquefaction plant at an advanced stage outside British Colombia. It aims to reach a final investment decision by early 215, and is now in a FEED phase. Its export application at National Energy Board is under review. The estimated annual project capacity is 1mtpa, and project owner Pieridae Energy expects to start production by 219. The estimated capital cost is CAD5bn 1bn. Other projects in Canada Our research has uncovered several other proposed plants that we believe have a good chance of coming on-stream within the next 1 years, including: 1) the Aurora project, initiated by Asian energy giants Inpex and CNOOC, with proposed capacity of 24mtpa due to come on-stream from 222; 2) the Sarita Bay LNG project, where project-owner Steelhead recently filed the National Energy Board for a licence to export 3mtpa per annum; 3) the long-awaited large-scale West Coast Canada LNG project, a JV between ExxonMobil and Imperial, which might materialise as we reach 225; and 4) the 1.8mtpa Douglas Channel project, the future of which is uncertain formerly liquidated, the project got more likely as AltaGas stepped in with financing solutions for the project in 214. There are several other small projects, such as the 2.1mtpa Woodfibre plant, which could come on stream from 217. Egypt Existing and planned projects in Egypt Project name Project owner Type Start-up Nominal capacity (mtpa) Damietta ENI Shore-based 25 5 Idco BG Group Shore-based Damietta T2 ENI Shore-based 218e 4.8 We have to go back only four years to find the country exporting 1mtpa of LNG. However, the Egyptian state has been on quite a journey since then, which has also affected gas policies. In 213, 2.7mt was exported from Egypt. The main reason for the decline is greater allocation to domestic demand. The Damietta plant has been refused to export Egyptian gas, leading it to look to Israel for gas supplies. It has signed a preliminary non-binding agreement to receive gas from the Tamar field, enough to produce 2.5mt of LNG through its trains. The same strategy is used for the other operating train in Egypt, Idco it signed a non-binding agreement with partners in Israel s Leviathan field to export up to 5.7mtpa of LNG. The Egyptian government believes that domestic demand for gas will continue to outpace inland production and in November 214 a final contract with Höegh LNG was signed for FSRU services to facilitate importing LNG, starting August 215. The country plans to import LNG for at least five years. Equatorial Guinea Existing and planned projects in Equatorial Guinea Project name Project owner Type Start-up Nominal capacity (mtpa) Punta Eur Marathon Shore-based Punta Eur T2 Marathon Shore-based 218e 4.4 BUMI FLNG Bumi FLNG 217e 2.5 EG LNG is the dominant player in Equatorial Guinea s LNG market. It is owned by Marathon (6%), Sonagas (25%), Mitsui & Co (8.5%), and Marubeni Corporation (6.5%). The liquefaction plant in Malabo has capacity of 3.7mtpa. It exported 3.7mt in 213. Because of the plant s young age, we believe it is fair to assume full utilisation going forward. We have been unable to reach the managers at EG LNG, but we consider it fair to assume 95% utilisation from its expected start-up in mid-218e. 32

33 Indonesia Existing and planned projects in Indonesia Project name Project owner Type Start-up Nominal capacity (mtpa) Bontang Badak LNG Shore-based DSLNG Donggi-Senorro Shore-based 215e 2 Abadi FLNG Inpex FLNG 219e 2 Tangguh train 1-2 BP Shore-based Tangguh train 3 BP Shore-based 219e 3.8 The Indonesian gas market is changing rapidly. Formerly a major LNG player, producing about one third of the world s supply of LNG in the 199s, exports from Indonesia are gradually declining. The country is ranked as the fourth-largest LNG exporter worldwide, soon to be passed by the US. This is a result of several trends: 1) declining production at Bontang due to limited resources and reduced gas output, and decommissioning the Arun plant (formerly another major production site) in 214; and 2) increasing demand for gas for domestic use, which is exacerbated by the government wanting to move away from expensive oil imports to reduce the current account deficit. Thus, even as natural gas production has risen by more than 25% since 22, demand has been moving in tandem. Regasification terminals are being built (e.g. on the Arun plant) to transport gas to locations with considerable domestic need. Total domestic demand for gas is 3,55bn BTU per day, or roughly 25mtpa, a figure expected to increase 7% for every year in a 5-year horizon. Most of the gas goes to industrial production (33.4%), followed by electricity generation (26.7%), and fertilisers and petrochemicals (18.5%). As the country transports gas for internal use as liquids, any reduction in imports might not have corrosive effects on the LNG shipping industry. We find it likely that future production from liquefaction facilities will be shared between domestic consumption and exports. The extent to which producers will be constrained from exporting will be determined largely by the Indonesian government. Liquefaction plants in Indonesia Bontang Production from the Bontang plant, operated by state-owned Badak LNG, has been declining since 21. It has production capacity of 22.5mtpa, though this is underutilised due to the aforementioned reasons. We see no reason to assume that the fundamentals will change, and hence end up in a base case of a continued gradual decline in production. The plant is operated by government company Pertamina and has been in operation since This followed the 1972 exploration of significant natural gas reserves in the Muara Badak area, East Kalimantan, along the border with Eastern Malaysia. The plant worked to increase capacity in the 198s 199s and reached its current capacity in November 1999, when the first LNG production from train H was commissioned. In January 213, Pertamina announced that train A would be put idle (LTI long term idle), not likely to be put back in operation. 33

34 Bontang LNG storage tanks and loading jetty Source: Panoramia photo data Tangguh LNG This plant in the Papua Barat area represents BP s main operations in Indonesia and delivers LNG to customers in Asia and the US. Tangguh T1 and Tangguh T2 (combined capacity 7.6mtpa) have been close to fully utilised since their start-up in 29. The company is now working to expand the plant with another 3.8mtpa train (T3) for an estimated investment of USD12bn. In 212, the Indonesian government granted its approval for the development of T3. It is in the FEED stage, with scheduled start-up in 219. However, in 214 the Corruption Eradication Commission announced that the financing for T3 was not in compliance with regulations. The financing scheme was thus rejected due to the possible loss of state revenue. DSLNG (Donggi-Senoro) This is a small liquefaction plant expected to start up later this year. It consists of a single train, intended to monetise the stranded gas of Central Sulawesi, east of the island hosting the Bontang plant. It has a scheduled capacity to produce 2m metric tonnes of liquefied gas annually, sold on long-term contracts to Chubu Electric, Kyushu Electric and KOGAS. It will be operated by Pertamina in a JV with several other gas giants including KOGAS and Mitsubishi Corporation. Abadi FLNG This project is primarily operated by INPEX Masela (6%) in partnership with Shell (3%) and PT EMP Energi Indonesia (1%) and is in the Arafura Sea. In 21, the Indonesian government gave its approval for the Stage 1 development plan for a FLNG facility with capacity to produce 2.5mtpa. To keep the project on schedule, the company is conducting double FEED works with two companies awarded FEED contracts. While one is pursuing normal FEED work, the other is working on the EPC phase. According to a company representative, there are three companies competing for the EPC contract. INPEX emphasised that information on the FID, expected start-up and budgeted capex depend entirely on the FEED process. The project has been subject to delays and cost overruns. Our interpretation of the current information is that production will start in 219. Libya Existing and planned projects in Libya Project name Project owner Type Start-up Nominal capacity (mtpa) Marsa El Brega Sirte Oil Shore-based Marsa El Brega T3 Sirte Oil Shore-based 218e

35 In 1971, Libya became the second country in the world to export LNG. Libyan gas is exported from the Marsa el Braga plant, which has capacity of 3.2mtpa. The trains are in bad shape due to a lack of maintenance following damage in the 211 civil war. Libya also exports gas to southern Europe through pipelines, and due to the high level of uncertainty we do not expect any seaborne exports from Libya in the upcoming years. Malaysia Existing and planned projects in Malaysia Project name Project owner Type Start-up Nominal capacity (mtpa) MLNG Satu Plant Petronas Shore-based MLNG Satu train 9 Petronas Shore-based 216e 3.6 MLNG Dua Plant Petronas Shore-based MLNG Tiga Plant Petronas Shore-based Petronas FLNG Petronas FLNG 215e 1.2 Petronas FLNG 2 Petronas FLNG 218e 1.5 Malaysian exports have been subject to a marginal increase to 24mtpa over the past decade, due to the de-bottlenecking operations at the Dua plant between 24 and 29. We expect capacity to increase as Petronas adds another train to its Satu plant, in addition to two FLNGs planned to come on stream in 215 and 218, respectively. However, we also expect Malaysian imports of LNG to increase going forward. Malaysia comprises the Malaysian peninsular and Borneo. The Malaysian peninsular is home to the capital and many industrial clusters. Borneo is to the east and shares an island with Indonesia s Kalimantan. Borneo has significant gas (Petronas s LNG liquefaction is domiciled there), but on the Malaysian peninsular demand outstrips supply. To meet local demand on the Malaysian peninsula, the gas authorities commissioned a regasification terminal in Melaka, south of the capital Kuala Lumpur. With annual import capacity of 3.8 metric tonnes through two floating devices, Malaysia wanted to ensure the supply of gas for industrial use we believe such trends will continue. Demand for gas in the Malaysian peninsular is likely to increase, as industry will require more gas. However, households in Malaysia will be incentivised to switch away from gas towards cheaper fuels, such as coal, as long as current prices are maintained. In 23 coal represented 16.5% of electricity generation in Malaysia, and had increased to 38.5% in 213. Building on this, we consider it reasonable to assume that both exports and imports will rise in the coming years. Liquefaction plants A JV between Petronas, Shell and Mitsubishi was signed in 1978 to develop the Malaysia LNG. It was to be a 3-train project on the island of Bintulu, capable of producing 6mtpa. The first LNG was sold in November 1979 to Tokyo Gas and Tokyo Electric. Production started in January The second plant of the complex, the Malaysia LNG Dua, was commissioned in 1995, operated by the same JV. Aggregated capacity at the complex, now comprising six trains, reached 15.4mtpa. The third plant, the Malaysia LNG Tiga, was commissioned in 22 and added two trains and c7.4mtpa capacity. The current capacity of c25mtpa was reached after a series of debottlenecking projects were completed. The JV expects production capacity to be expanded when a ninth train comes on stream at the MLNG complex. Petronas reached a final investment decision in March 213, and anticipates the first LNG from the train by 216, adding 3.6mtpa capacity to the complex. In addition, the LNG production capacity of Malaysia will get a lift from Petronas s two FLNG vessels coming on stream. The first has annual production capacity of 1.2m tonnes per year, and is planned to start production over 215. The other has production capacity of 1.5 mtpa, and is planned to be commissioned in

36 Petronas FLNG hull under construction Source: Offshore Energy Today Mozambique Proposed projects in Mozambique Project name Project owner Type Start-up Nominal capacity (mtpa) Mozambique T1 Anadarko Shore-based 218e 5 Mozambique T2 Anadarko Shore-based 218e 5 Mozambique T3 Anadarko Shore-based 221e 5 Mozambique T4 Anadarko Shore-based 221e 5 Mozambique T5 Anadarko Shore-based 223e 5 Mozambique T6 Anadarko Shore-based 223e 5 Mozambique T7 Anadarko Shore-based 225e 5 Mozambique T8 Anadarko Shore-based 225e 5 Mamba ENI Shore-based 22e 5 Area 4 Mamba FLNG 1 ENI FLNG 219e 2.9 Area 4 Mamba FLNG 2 ENI FLNG 22e 2.4 Mozambique has proven gas reserves of 45trn 7trn ft 3, almost all in Area 1 (there are six major areas) and recent government figures suggest total reserves of 17trn 19trn ft 3. Anadarko Petroleum is the largest player, and expects to start exporting LNG in late 218. It has a strategy to build two LNG trains every other year until it has 1 12 trains. However, African gas experts tell us they believe Anadarko needs greater internal competence to execute these plans. We thus expect Mozambique to emerge as a strong market participant, but also that developments could well progress more slowly than expected. Nigeria Proposed and existing plants in Nigeria Project name Project owner Type Start-up Nominal capacity (mtpa) Bonny Islands, train 1 and 2 Nigeria LNG ltd Shore-based Bonny Islands, train 3 Nigeria LNG ltd Shore-based Bonny Islands, train 4&5 Nigeria LNG ltd Shore-based Bonny Islands, train 6 Nigeria LNG ltd Shore-based Bonny Islands, train 7 Nigeria LNG ltd Shore-based 223e 4.1 Progress FLNG NNPC (Nigerian National Petroleum Corporation) FLNG 217e 1.53 Brass LNG T1 NNPC (Nigerian National Petroleum Corporation) Shore-based 222e 5 Brass LNG T2 NNPC (Nigerian National Petroleum Corporation) Shore-based 223e 5 OK LNG NNPC (Nigerian National Petroleum Corporation) Shore-based 223e 12.8 Olokola LNG Plant OKLNG Shore-based 225e

37 Nigeria exported close to 16mt of LNG in 213, an increase of c7mt from 24. The country has increased its efforts to maintaining its market share in the global supply of LNG. It had the same target for 213, but was unable to reach it. There are many proposed projects in Nigeria, totalling possible additional capacity of 34mtpa, but the country faces huge challenges in terms of financing and regulations. Its LNG production is dominated by the Nigerian National Petroleum Corporation. Recent developments have not been positive. The Olokola Project, initiated in 27, was set to be finished in 212, but project partners have been withdrawing from the project in recent years. We also observe large setbacks on the Nigeria LNG train-7 project. The Petroleum Industry Bill, proposed in 28, is expected to change the organisational structure and fiscal terms governing the oil and gas sector. Under the new bill, deepwater projects involving greater capital spending will be less profitable, causing uncertainty and delays for train 7. Victor Eromosele, a former employee of Nigeria LNG, said at the World Petroleum Congress in Moscow in 214 Nigeria should just get serious and fix those two other LNG projects. I mean, they have three LNG projects, get them started and get them running and then compete. Otherwise, the window will soon disappear because by 22, we will find a situation where significant funds have been spent by other countries and those capital expenditures are actually converting to new sources of supply to the market. Norway Existing plants in Norway Project name Project owner Type Start-up Nominal capacity (mtpa) Risavika LNG Skangass Shore-based Statoil Snohvit Shore-based Norwegian LNG production is dominated by Statoil, operating a 4.2mtpa liquefaction plant at Melkøya, in the far north. The plant started operation in 27, but several issues have prevented it from operating at full capacity. We assume, however, that it will reach full capacity in the years ahead, adjusted for regular maintenance. Several expansion plans have been revised, but modest findings of gas reservoirs close to the Snøhvit basin have put these plans on hold. Statoil has communicated that it will rather work to optimise the current facilities. Norway also has a smaller liquefaction plant, in Risavika near Stavanger, where the company Skangas operates its.3mtpa liquefaction plant. Snøhvit LNG plant Source: Statoil 37

38 Oman Existing plants in Oman Project name Project owner Type Start-up Nominal capacity (mtpa) Oman LNG Terminal Oman State, Shell, Total ++ Shore-based Qalhat LNG Terminal Oman State Shore-based There are two LNG plants in operation, the Oman LNG plant and the Qalhat LNG plant. Oman LNG sells some of its capacity in the spot market, while Qalhat LNG has long-term contracts for its production. Last year the two plants exported c8.4mt of LNG combined, which is very close to what the country has achieved historically. We therefore believe that exports of this quantity are a fair estimate going forward. Papua New Guinea Existing and planned projects in Papua New Guinea Project name Project owner Type Start-up Nominal capacity (mtpa) PNG LNG ExxonMobil and Oil Search Shore-based Unknown Total, InterOil, Oil Search ++ Shore-based 22e Unknown Pandora Talisman Energy/Cott Oil and Gas FLNG Unknown 1 Pandora expansion Talisman Energy/Cott Oil and Gas FLNG Unknown 2.5 Located to the north of Australia, Papua New Guinea should be able to benefit from its close proximity to Asia. It is taking baby steps as an LNG exporter, selling its first liquefied gas in 214. The exports will be sourced from the Papua New Guinea LNG project, a co-venture between ExxonMobil and Oil Search, with production capacity of 6.9mtpa. The project was completed ahead of schedule (originally set for October/November), so gas supplies for Q2 Q3 214 were sold on spot. Long-term contracts totalling 6.6mtpa started from Q4. Total investment for the greenfield LNG plant was USD19,m, leaving it at the upper end of the cost ladder. Oil Search is involved in another project in the country, with Total and InterOil, with expected start-up around 22. It is in a very early stage, with the companies drilling for confirmation on gas reserves. The quantity of gas found will determine the plant s size. These plants are in addition to the recently announced FLNG projects initiated by Cott Oil&Gas and Talisman Energy, to extract gas from the Pandora field. Total capacity of the FLNGs will be 3.5mtpa, but it is likely that the smaller vessel (1mtpa production capacity) will be first to come on-stream. LNG liquefaction plant Source: LNG World News 38

39 Peru Existing project in Peru Project name Project owner Type Start-up Nominal capacity (mtpa) Peru LNG Peru LNG (JV Hunt Oil, SJm Repsol and Marubeni) Shore-based The Peru LNG plant has been operating since 21. The shore-based terminal has annual liquefaction capacity of 4.45mtpa and is operated as a co-venture between Hunter Oil Company, SK Energy, Shell and Marubeni. With a total investment of USD3,8m, it is at the low end of the cost ladder. Of the 4.45mtpa per annum capacity, 4.2mtpa is contracted to Shell Trading Middle East until 228. There are no specific plans to add another train to the site. Qatar Existing plants in Qatar Project name Project owner Type Start-up Nominal capacity (mtpa) Qatargas 1 LNG Qatargas Shore-based Qatargas 2 LNG Qatargas Shore-based Qatargas 3 LNG Qatargas Shore-based Qatargas 4 LNG Qatar Petroleum Shore-based Rasgas Train 1-2 Rasgas Shore-based Rasgas Train 3 Rasgas Shore-based Rasgas Train 4 Rasgas Shore-based Rasgas Train 5 Rasgas Shore-based Rasgas Train 6 Rasgas Shore-based Rasgas Train 7 Rasgas Shore-based Adgas LNG ADNOK, Mitsui Shore-based Qatar is roughly equivalent to Estonia in terms of area and population, but no country is comparable to Qatar in terms of LNG exports; it exported c77mt of natural gas in 213. Most of its LNG used to be shipped to the US, but due to the low gas price in the region Qatar has focused more recently on exports to the UK, India, Japan and other Asia countries. Qatar s exports are dominated by Qatargas (42mt in 213) and RasGas (35mt in 213). The latest of the 14 trains came on stream in January 211 with capacity of 7.8mtpa. Historically, most of Qatar s gas sales have been on long-term oil-indexed contracts, but in recent years the country has shifted towards more short-term and spot market sales. New contracts vary with the European short-term gas price, not with the historically used oil index. Despite the high extraction of resources, the reserves should last for many years. Qatar has the third largest reserves of natural gas with 24.7trn m 3 ; only Iran and Russia have larger proven resources. Qatar s natural gas fields are relatively mature, and nobody expects another discovery like that of North Field in However, there are still signs that further commercially viable fields might be found. For instance, in May 213, QP and Wintershall announced the discovery of natural gas in Block 4, on the northern coast of Qatar. This is expected to contain 2.5trn ft 3 of natural gas. There is also the USD1.4bn Barzan Gas project, which is being developed in two phases: Train one came on stream in 214, Train 2 is schedule to follow in 215. Backed by the Qatar National Bank s statement hydrocarbon production will continue plateauing in the medium term, we assume a constant export rate for the country. 39

40 Qatar LNG Train 6 Source: Arabian Oil and Gas Russia Existing and planned projects in Russia Project name Project owner Type Start-up Nominal capacity (mtpa) Sakhalin-2, Train1&2 Gazprom and Shell Shore-based Sakhalin-2, Train3 Gazprom and Shell Shore-based 219e 5 Yamal LNG train 1 Novatek, Total and CNPC Shore-based 217e 5.5 Yamal LNG train 2 Novatek, Total and CNPC Shore-based 218e 5.5 Yamal LNG train 3 Novatek, Total and CNPC Shore-based 219e 5.5 The Sakhalin-2 project on the east coast of Russia has been in operation since 29. With its 9.6mtpa of capacity, the plant accounts for a considerable proportion of the world s supply of gas. The project is a co-venture between Shell and Gazprom. Based on our consultation with industry insiders, we find it reasonable to assume the addition of a third train, adding c5mtpa capacity in No official record of investment cost is publicly available for the existing trains. However, Gazprom reveals it to be in the mid-range of comparable projects somewhat cheaper than most Australian greenfield projects and quite a bit more expensive than brownfield American plants. The harsh and cold surroundings in these regions make it challenging to construct and operate the plant, but liquefying the gas is cheaper than it would be in a warmer climate. The Yamal LNG project, built by Novatek, Total and CNPC, is proceeding as planned with the three trains due to come on-stream in 217, 218 and 219, respectively. Located along the coast north of the Ural Mountains, the environmental challenges are considerable in terms of construction and transport. Each of the three trains is planned to produce 5.5mtpa annually, leading to aggregate capacity of 16.5mtpa by 22. Total capacity has already been secured for long-term contracts, but the EU sanctions in response to Russia s actions in Ukraine might well jeopardise the project. It is not just the project itself that is dependent on a feasible environment to co-operate, but also the infrastructure surrounding the project that will be at stake. Pipelines and ice-breaking vessels due to be built with international companies are vulnerable to any substantial sanctions. Our base case is that the Yamal project will come onstream as planned, but this is highly sensitive to changes or escalations in the conflict. 4

41 Sakhalin 2 loading jetty Source: Gazprom Tanzania Planned projects in Tanzania Project name Project owner Type Start-up Nominal capacity (mtpa) Tanzania LNG T1 BG Group Shore-based 22e 5 Tanzania LNG T2 BG Group Shore-based 221e 5 Tanzania could well emerge as a leading LNG supplier, but it faces many of the same uncertainties as Mozambique. Also, the proven gas reserves are far smaller than in Mozambique. Current reported estimates are c46.5trn ft 3 of natural gas; however, experts say this number could grow to 2trn ft 3 in two years. But developers such as BG Group, Royal Dutch Shell, ExxonMobil and Statoil face significant political risk in the East African country. The dispute is whether Zanzibar (a semi-autonomous government) can sign its own exploration deal and thus secure all the revenues. The Tanzanian government tried to gather all political parties last summer to rewrite parts of the constitution, but the opposition refused to participate. Thus any final investment decision is not expected before the next election, scheduled for October. Experts do not expect any production from Tanzania s gas fields before 222. It is generally perceived as important to be the first of the two East African countries (Tanzania and Mozambique) to emerge as a large-scale LNG exporter. One market player in Mozambique told us there was value in being first on the scene: global customers and banks are willing to make a cluster around the first exporter. It is thus more likely that we will see additional trains emerge in the first-mover country than in the one that falls behind. However, it is often counter-argued there will be enough demand to support LNG development in both. Trinidad and Tobago Existing plants in Trinidad and Tobago Project name Project owner Type Start-up Nominal capacity (mtpa) Atlantic LNG train 1 BP, BG + Shore-based Atlantic LNG train 2 BP, BG + Shore-based Atlantic LNG train 3 BP, BG + Shore-based Atlantic LNG train 4 BP, BG + Shore-based The country accounts for 15mtpa LNG production capacity, all of which is sourced from the Atlantic LNG project, operated by BG and BP. The plant has four trains, with the first commissioned in Long-term contracts for this train will end in 218, and BG said market 41

42 dynamics closer to 218 would determine whether new long-term contracts were signed or other contractual schemes would be preferred. Compared with other projects, Atlantic LNG has proven to be one of the cheapest. Its average investment per tonne of capacity is cusd25. Discussions about capacity expansion have been ongoing for some time, but the scope and timing of expansion is still undecided. United Arab Emirates (UAE) Existing plant in UAE Project name Project owner Type Start-up Nominal capacity (mtpa) Das Island Adgas Shore-based The discovery of Abu Dhabi s giant oil field was in the 195s, and construction of the first LNG train was in the early 197s. Today it has the world s fifth largest reserves, with 6.1trn ft 3 of resources, making it the eighth largest resource holder globally. The UAE exported 5.33mt of LNG in 213. Given the age of the trains, we believe it is reasonable to assume unchanged utilisation in the future; this is supported by UAE having produced extremely stable output of c5.3mt for the past few years. The US Existing and planned plants in the US Project name Project owner Type Start-up Nominal capacity (mtpa) Kenai LNG Plant ConocoPhillips Shore-based Sabine Pass LNG T1-2 Cheniere Shore-based 215e 9 Sabine Pass LNG T3-4 Cheniere Shore-based 218e 9 Sabine Pass LNG T5-6 Cheniere Shore-based 219e 9 Corpus Christi Cheniere Shore-based 218e 8.8 Corpus Christi Cheniere Shore-based 219e 4.7 Elba Island LNG project Shell Shore-based 217e 2.5 Golden Pass Import term. conversion T1 Golden pass Products (Exxon, Qatar) Shore-based 219e 5.2 Golden Pass Import term. conversion T2 Golden pass Products (Exxon, Qatar) Shore-based 22e 5.2 Golden Pass Import term. Conversion T3 Golden pass Products (Exxon, Qatar) Shore-based 22e 5.2 Cameron LNG T1-3 Sempra Energy JV Shore-based 218e 12 Cove Point LNG T1-2 Dominion Resources Shore-based 217e 5.25 Magnolia LNG (4 trains) SK Enginering JV with Liquefied Natural Gas ltd. Shore-based 218e 8 Freeport Freeport JV Shore-based 218e 13.2 Lake Charles project JV BG and Energy Transfer Shore-based 219e 15 Jordan Cove (Oregon) Energy projects development ltd Shore-based 219e 6 Oregon LNG Leucedia National Corporation (holding comp) Shore-based 219e 9.4 Lavaca Bay FLSO Excelerate Energy FLSO 219e 4.4 Cambridge Energy FLNG 1 Cambridge Energy FLNG 218e 4 Cambridge Energy FLNG 2 Cambridge Energy FLNG 218e 4 Texas LNG Texas LNG Shore-based 218e 2 Annova LNG project Anoova LNG Shore-based 219e 2 Alaska LNG Export project Alaska Gasline Devel. Corp, TransCanada, BP, CP, Exxon Shore-based 224e 17.4 Gulf LNG Kinder Morgan Shore-based 219e 1 Originally a major importer of LNG, the US is gradually turning the tables in the global LNG industry driven by the large amount of unconventional gas, and the increased extraction from these sources. The gas has worked its way into US markets, resulting in a low price and excess supply. However, political barriers are an obstacle to the liquefaction process, which is why we see LNG exports from the US growing relatively slowly. At this stage, only one project has undertaken a final investment decision, and an additional five have been awarded the right to export gas to non-fta countries. Only the first four trains of the Cheniere-operated Sabine Pass plant have reached a final investment decision, with most other projects either in the FEED or earlier stages. However, the cost advantage of the US liquefaction plants, in addition to the extensive existing 42

43 infrastructure, leaves us confident that most of the proposed plants will come on-stream. US (mostly brownfield) plants are at about USD7 per tonne produced). It seems reasonable to us to assume that the US will become a major LNG producer within a few years, but that political obstacles must be overcome first. Regulatory process Obtaining export permits Natural gas regulation in the US follows from the Natural Gas Act of 1938, which requires that anyone who wants to import/export natural gas from/to a foreign country must obtain authorisation from the Department of Energy. This, naturally, applies to LNG. Such authorisation can be either short- or long-term (the latter being more than two years). For companies undertaking a final investment decision, it is long-term authorisation that is of interest. Firms can apply only after securing sufficient long-term contracts. Generally, a firm will have to file two applications, one granting an export licence to the countries under a free trade agreement with the US (FTA countries), and one for those not under such a scheme (non-fta). The licence for free trade countries is most easily granted, as permission to export to non-fta countries will be granted only if exports would not be detrimental to the public interest. Factors at play are economic, environmental, and energy security. The DoE has been criticised for following an order of precedence based upon applications filed by December 212. US FTA countries in green Source: Office of the United State Trade Representative Non-FTA countries are vital for LNG producers, as neither of the two major LNG markets is in a free trade agreement with the US. Most notable is Asia, where Japan and South Korea are excluded as export destinations if an LNG producer does not have the licence. Europe is another example. There are binding talks ongoing on free trade agreements in both regions, notably the Trans-Pacific Partnership Agreement and the Transatlantic Trade and Investment Partnership. These negotiations, if successful, will take several years to complete, and it is safe to say that building a LNG plant without holding a non-fta licence is extremely unattractive. Federal Energy Regulatory Commission The Federal Energy Regulatory Commission (FERC) approves proposed liquefaction projects. FERC is an independent agency that regulates the interstate transmission of natural gas, oil and electricity. Firms wanting to build a liquefaction plant apply to FERC for an Order Granting Authority under Section 3 of the Natural Gas Act. From the point of approval, FERC monitors construction and restoration activities to ensure the operating firm complies with the existing permits, plans and regulations. Obtaining approval starts with a request that FERC engages in the pre-filing environmental review process. This opens up for federal and state operating agencies, as well as other 43

44 public stakeholders, to comment on the impact of the project before the application is submitted. This input period ends when the company files a formal application with FERC. The next step is submitting the draft Resource Reports to FERC, so FERC can prepare an Environmental Assessment (EA) or an Environmental Impact Statement (EIS). These reports are prepared to inform the public about the environmental effects, adverse or beneficial, as well as safety impact. Thus a second period of public input begins. The Resource Reports covers up to 13 subjects: General project description. Water use and quality. Fish, wildlife and vegetation. Cultural resources. Socioeconomics. Geological resources. Soil. Land use, recreation and aesthetics. Air and noise quality. Alternatives. Reliability and safety. PCB contamination (commonly not required for LNG projects). Engineering and design material. The EIS or EA is the building block forward in the process. Local communities and other stakeholders can comment on the reports through public meetings and postings. If more issues are identified, they will be addressed before final environmental approval is issued. Gearing up for construction When receiving a final approval from FERC, commonly referred to as an order to proceed, FERC can raise further issues the company must address before construction can begin. Additionally, local regulators might need to be satisfied, e.g. 1) in the ongoing application process for Dominion on its Cove Point LNG in Chesapeake Bay, the company expects to receive FERC approval by the end of the summer, but had to apply to the State of Maryland to issue a wetlands licence; and 2) construction and operations at the Cheniere Sabine Pass LNG sites could start only after obtaining Clean Water Act, Coastal Zone Management Act, and Clean Air Act permits. Political turmoil FERC is a regulatory body, not heavily influenced by politics. There are occasions where senators or congressmen might try to change the filing process in favour of their home project, but the commissions are seldom susceptible to interference. On the other hand, political pressure to change the export licensing application proceedings is quite intense. The DoE is under pressure to find new ways to work the application queue. A group of Republican congressmen, led by Senator John McCain, proposed a bill named the North Atlantic Energy Security Act, aimed at speeding up LNG exports to Europe. The pace of export licensing is far below what many deem optimal, where several firms find their gas flared as a result of excess supply in the US. Entering August 214, the DoE received in excess of 3 applications, but only eight facilities have yet to receive approval. The DoE proposed to change the procedure for export decisions in May 214, including changing the order of precedence (which was set up in December 212). The new rules will eliminate this order of precedence altogether and rather consider the applications in the order of a project s completion of its environmental assessment. 44

45 However, changing the system is not easy, and there are strong powers working against any proposals to liberalise it. The Department of Energy investigated the issue in 213, ordering a two-part report and concluded further research was required. Although the 213 reports generally viewed the upside from LNG exports as outweighing the negative effects, the public hearing after the reports revealed strong opposition. For many, the strongest argument is that the benefits of low energy prices should not be jeopardised. US industrial firms have found a competitive advantage in low energy prices a result of the abundance of shale gas leaving US firms with an energy bill far below that of their European or Asian competitors. This has led to growth in the American manufacturing industry. Another argument of the opposition relates to environmental issues. The fear is that increased exports would boost global energy consumption and hence greenhouse gas emissions. Another concern might be general issues relating to the process of extracting shale gas, known as hydraulic fracturing. This utilises chemical-laced water under high pressure, and has raised concerns about the effects on ground water reservoirs. The process also emits a considerable amount of methane, a more potent heat-trapping gas than carbon dioxide. Stylised proposed changes by DoE (local requirements have a separate process) Liquefaction plants Kenai LNG plant This plant, in Alaska, is operated by ConocoPhillips. It was completed in 1969, and has annual liquefaction capacity of 1.3mtpa. The export operations were resumed in May 214, after several years of solely domestic production. The DoE has allowed it to export 8,mt over the next two years, also to non-fta countries (notably Japan). Sabine Pass terminal Located in Cameron Parish, Louisiana, Cheniere Energy is building a liquefaction terminal at its existing receiving terminal. Loading tanks and berths are in place, in addition to some piping infrastructure. The four trains that have undertaken FIDs are under construction, estimated to be completed by 216 (trains 1 and 2) and 217 (trains 3 and 4). Located along the Gulf Coast, Sabine Pass is close to five of the six major US shale plays, and it is also benefiting from the large number of interstate pipelines built in recent years. FIDs for train 1 and 2 were undertaken in August 212. At maximum capacity, the trains will combined be able to produce 9mtpa of liquefied gas. FIDs for train 3 and 4 were undertaken in May 213. The two trains will operate the same capacity as 1 and 2, and are scheduled to be completed by end-216. Combining the four trains, Sabine Pass plans to have liquefaction capacity of 18mtpa by 217. For trains 5 and 6, Cheniere has secured some commercial contract, but is awaiting greater coverage before undertaking FID. This will likely be made by 215, and it hopes these trains will commence in

46 Sabine Pass liquefaction plant Source: LNG World News Corpus Christi liquefaction project Cheniere has initiated another large-scale project close to Corpus Christi, Texas, the Corpus Christi liquefaction project. It expects to operate three trains, able to produce c13.5mtpa in total. Regarding the first two trains, it hopes to reach a final investment decision early in 215. A decision on the third train will largely depend on market conditions and the first two trains. The company is in the process of obtaining regulatory approval and entering long-term contracts sufficient to underpin the financing of the project. This work should eventually lead to an FID being undertaken. Cheniere hopes to start operations at the plant as early as 218. Elba LNG project This small-scale LNG project was initiated by Shell, and we expect it to contribute c2.5mtpa of export capacity from the US. The first stage of construction will be to build six small-scale modules, each able to produce.25 metric tonnes of liquefied gas annually. The project s first stage is likely to be completed in , but Shell was unable to be more specific. A second phase is under way, with four additional modules to be added, increasing capacity to 2.5mtpa. Cameron LNG This project is along the Calcasieu Ship Channel near Hackberry, Louisiana and is led by Sempra LNG, in co-operation with Mitsui, Mitsubishi and GDF Suez. It is also modifying an existing regasification terminal, enabling it to operate the liquefaction process. The project consists of three liquefaction trains with combined capacity of 12mtpa at estimated capex of USD1bn. The project was awarded a non-fta export allowance in February 214. The final investment decision was reached on 6 August 214, and the firm started the construction phase in October 214. A company representative told us that the scheduled start-up for the three trains was January (T1), June (T2) and December (T3) in 218. We were told it was reasonable to assume production and exports of 6m tonnes during the first year of operation (218) and full utilisation from 219 to 225. The three trains used for liquefaction will be completed by 218, with full commercial operations starting from 219. Capacity is fully contracted going forward, with take-or-pay agreements signed. 46