LNG SECTOR REPORT The recovery is happening

Transcription

1 EQUITY RESEARCH 8 September 216 Research report prepared by DNB Markets, a division of DNB Bank ASA LNG SECTOR REPORT The recovery is happening We have only made marginal adjustments to our LNG outlook, as our proprietary liquefaction survey, covering all existing plants, confirms strong demand growth in spite of weak LNG prices. We argue that further declines in the LNG price should now be protected by the price of coal, which should give confidence in the longer-term viability of the LNG market. We also reiterate our view that the FSRU concept has structurally benefitted from more affordable energy prices and that FLNG technology, sourcing from stranded gas, is likely to prove itself sustainable despite the lower energy price regime. Shipping - LNG 1 9 Shipping - LNG Sep Nov Jan Mar May Jul Sep Shipping - LNG Source: Factset Rates troughed this summer and high season is coming. Current LNG carrier spot rates of USD38,5/day are 33% higher than the lows experienced in January and the combination of improving LNG spot prices in Asia, widening arbitrages, and continued strong growth in liquefaction coupled with an upcoming high season (from October to December trade normally increases some 1 15%) makes us optimistic about the nearterm rate environment; our H2 spot rate forecast is ~USD43,/day. 39% volume growth from 215 to 218e, but the fleet is also growing. We estimate the LNG trade to grow from 246m tonnes in 215 to 342m tonnes in 218 (up from 34m tonnes in our previous sector report in January), or by 39%. The fleet is expected to add 28% more transportation capacity in the same period. Looking to 22, we estimate total exports of 391m tonnes (up from 39m), adding another 14% to our expected 218e exports. The current orderbook for that period implies c5% fleet growth. FSRUs are needed; 15 3 awards expected in the next five years. Over the past five years FSRUs have doubled their market share from 4% to 8% of total regasification capacity and we expect this trend to continue as lower gas prices make it much more competitive versus gas-fired power plants for emerging economies. Although visibility on future growth in this space is limited, we believe that up to 15 3 FSRU projects could be awarded within the next five years. Fed by stranded gas, FLNG technology is still likely to be profitable, although coal prices will be increasingly relevant to LNG price formation going forward at the expense of oil as the marginal consumption is set to be electricity production and the alternative is coal-fired power plants. Golar has recently stated it is confident that it would conclude 5 projects within the next 5 years. Following a recent change of analyst, we have made some changes. We reiterate our BUY recommendation on Golar LNG, while we have raised our target price to USD31 (21.3). We reiterate HOLD on Golar LNG Partners while we have raised our target price to USD19 (16.2). We reiterate BUY on GasLog and a USD16.2 target price. We have initiated coverage on Höegh LNG Partners, with a USD22 target price, and we reiterate BUY on Höegh LNG Holding, while cutting our target price to NOK18 (127). ANALYSTS Nicolay Dyvik nicolay.dyvik@dnb.no Petter Haugen petter.haugen@dnb.no Jørgen Lian jorgen.lian@dnb.no Ola Jahnsen ola.jahnsen@dnb.n Company Cur Rec Target Price P/E 16e P/E 17e P/E 18e Please see the last two pages for GasLog USD BUY important information. This research Golar LNG USD BUY nm nm nm report was not produced in the US. Golar LNG Partners USD HOLD Analysts employed by non-us Höegh LNG Holding NOK BUY affiliates are not registered/ Höegh LNG Partners USD BUY qualified research analysts with Source: DNB Markets FINRA in the United States.

2 8 September 216 Contents Our LNG case a graphical representation 3 Forecast changes 4 Peer group analysis 5 Demand 6 We expect 39% growth in traded volumes in e 6 Volumes traded 8 Transportation demand 11 Creation of a spot market 13 Regasification capacity 15 Total gas trade, including piped gas 15 Supply 17 LNG fleet 17 LNG order book 2 Deliveries 23 Cancellations 24 Contracting 24 Yard overview 24 Scrapping 25 Market balance 27 Coal provides a floor to LNG prices 3 Spot rates, TC rates and vessel values 33 USD15, 2,/day premium for TFDE vessels 33 FSRU market 36 FSRU descriptions 37 FLNG market 44 Appendix: Introduction to the LNG market 46 Appendix: Liquefaction capacity survey 48 Algeria 48 Angola 48 Australia 49 Brunei 52 Cameroon 52 Canada 53 Egypt 56 Equatorial Guinea 56 Indonesia 57 Libya 59 Malaysia 59 Mozambique 6 Nigeria 61 Norway 61 Oman 62 Papua New Guinea 62 Peru 63 Qatar 64 Russia 65 Tanzania 66 Trinidad and Tobago 66 United Arab Emirates (UAE) 67 The US 68 Yemen 75 2

3 Commercial breakeven land-based facilities (USD/mmBTU) e 217e 218e Seasonality (time of export) Fleet utilisation (%) 74 % 77 % 79 % 84 % 83 % 81 % 86 % 86 % 86 % 85 % 89 % 91 % 91 % 89 % 96 % 94 % e 217e 218e Spot rate 16cbm (USD/day) Annual growth in the LNG trade (m tonne) DNB Markets 8 September 216 Our LNG case a graphical representation Rates are up 33% since mid-january and strong near-term growth in liquefaction capacity 41, 39, 37, 35, 38, , 31, 29, 27, 29, , -1-4 Source: Fearnleys, DNB Markets Source: Poten, DNB Markets (forecasts) coupled with seasonally higher demand, makes us optimistic on near term-rate development. Our view of a recovery in the longer term remains intact. 115 % 1 % 11 % 95 % 15 % 9 % 85 % 1 % 8 % 95 % 75 % 9 % jan feb mar apr may jun jul aug sep oct nov dec 7 % Average seasonality volume Average seasonality tonne-mile Utilisation (%) Source: Poten, DNB Markets Source: DNB Markets We remain optimistic on FSRUs (immature but strongly growing market, benefiting incumbents such as Höegh LNG and Golar LNG)... and FLNG technologies (with a clear cost advantage over land-based facilities and considerable barriers to entry) FLNG Cumulative gas production (mtpa) Source: EIA Source: DNB Markets, Golar LNG, Goldman Sachs 3

4 -1% YOY increase in transported volumes 2% 1% 11% 12% 13% YOY increase in ton-mile demand 1% 11% 11% 13% 13% 12% 15% 15% 14%.5%.5 % 1.% 1.2% 1.6 % 1.4% 6.2 % 2.1 % 7.4 % 7.1 % 6.4 % 7.3 % 2.9 % 9.3 % 8.6 % 1.3 % USD/day 4, 37, 7% 8% 8% 62, 62, 9% 9% 72, 72, 1% 11% 11% DNB Markets 8 September 216 Forecast changes Estimate revisions, spot rates Estimate revisions, deliveries 8, 12% 7, 6, 5, 1% 8% 4, 6% 3, 2, 1, 4% 2% 216e 217e 218e % e 217e 218e 16 m3 TFDE (USD/day), old 16 m3 TFDE (USD/day), new Source: Fearnleys, DNB Markets Source: DNB Markets, Clarksons Deliveries, old Deliveries, new Estimate revisions, scrapping Estimate revisions, fleet growth 3.5% 12. % 3.% 1. % 2.5% 8. % 2.% 1.5% 6. % 1.% 4. %.5% 2. %.% e 217e 218e. % e 217e 218e Scrapping, old Scrapping, new Fleet growth, old Fleet growth, new Source: DNB Markets, Clarksons Source: DNB Markets, Clarksons Estimate revisions, volumes traded Estimate revisions, tonne-mile demand 16% 16% 14% 14% 12% 12% 1% 8% 6% 4% 1% 8% 6% 4% 2% 2% % % e 217e 218e -2% e 217e 218e Volume growth, old Volume growth, new Demand growth, old Demand growth, new Source: DNB Markets Source: DNB Markets 4

5 Fleet (including newbuilds) Multiples Sensitivities Leverage Valuation Misc. DNB Markets 8 September 216 Peer group analysis LNG peer group Flex LNG Golar LNG Golar LNG Partners GasLog Ticker flng glng gmlp glog hlng Currency (Local) Recommodation HOLD 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) 6 3,2 1,35 2, ,513 1,35 Market cap (USDm) 143 1, EV (USDm) 149 4,684 2,68 3,171 1,427 2,3 2,68 Current NAV (Local/share) Price/NAV ratio Yield (%, base current price) ChgNAV per +1% values** (Local/share) % EPS sensitivity*** na na NIBD/EBITDA ratio Contract coverage (%) EV/EBITDA P/E neg. neg neg. > LNG old steam turbine Number LNG modern steam turbine Number LNG TFDE Number FSRU converted Number FSRU newbild Number FLNG Number Total Number Share LNG (%) Share FSRU (%) Avg. age owned fleet (Years) Source: DNB Markets 5

6 e 215e 216e 217e 218e e 215e 216e 217e 218e Total trade (m tonne) YOY growth (%) DNB Markets 8 September 216 Demand We estimate that the trade will grow from 246m tonnes in 215 to 342m tonnes in 218 (up from 34m tonnes in our previous sector report in January), or by 39%. Looking to 22 we estimate total exports of 391m tonnes (up from 39m), adding another 14% to our expected 218e exports. This translates into transportation demand growth of 11% for 216e, 12% for 217e and 14% for 218e, which compares to 13%, 15% and 11%, respectively, previously. Only marginal changes to our LNG trade forecasts In 216 we estimate Australia to be the largest contributor of additional volumes, adding 15m tonnes on our estimates. These comprise an additional 4.8m tonnes from Australia Pacific LNG, 4.1m tonnes from Gladstone and 3.3m tonnes from Gorgon. We expect another 3.1m tonnes from the continued ramp-up of the two trains in the Queensland Curtis facility. In the US, we expect the two first trains in Cheniere s Sabine Pass to add 5.1m tonnes. We estimate growth remain dominated by Australia also in 217, which we believe will add 16.9m tonnes (Gorgon +9.1m tonne, Australia Pacific +3.6m, Gladstone +1.8m), while the US looks set to contribute 8.9m tonnes (only Sabine Pass). For 218e, we expect growth from the US of 14m tonnes (Cove Point LNG +5m tonne, Cameron LNG +4m, Sabine Pass +3.9m) and Australia of 16m tonnes (Wheatstone +6.8m, Ichtys +4.5m, Gorgon +3.3m). The basis of our LNG demand forecasts is a survey carried out this summer. Here we have collected data from more than 1 liquefaction projects, both planned and operating, which we believe include all liquefaction plants globally. It is attached here as an appendix. The LNG shipping market has moved towards shorter contracts over the past decade, as short-term contracts as a proportion of total traded volume rose from 5% in 2 to 28% in 215. Also, existing contracts are set to roll off by an average of 9m tonnes per year between 216e 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. 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 five years this has doubled from 4% to 8% of total regasification capacity and we expect this trend to continue. Total LNG trade and annual volume growth Volume versus tonne-mile growth % 2 % 15 % 1 % 5 % % -5 % 35 % 3 % 25 % 2 % 15 % 1 % 5 % % -5 % 15 % 11 % 6 % 22 % 19 % 7 % 8 % 31 % 15 % -1 %-1 %-1 % -1 % 13 % 15 % 11 % Total trade (m tonne) YOY total trade YOY total trade YOY tonne-mile Source: Poten, BP, DNB Markets (forecast) Source: Poten, DNB Markets (forecast) We expect 39% growth in traded volumes in e The data below is based on a survey that we believe covered all liquefaction plants globally, see appendix. Adding in brownfield expansion of operating liquefaction capacity and capacity from plants under construction (our base case), we estimate that the total market will grow from 246m tonnes in 215 to 342m tonnes in 218 (up from 34m tonnes in our previous sector 6

7 Global exports (m tonne) DNB Markets 8 September 216 report in January), or by 39%. Looking to 22 we estimate total exports of 391m tonnes (up from 39m), adding another 14% to our expected 218e exports. In the chart below we group the volumes we have identified by the status of the plant; the sum of 1 and 2 below constitute our base case. 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 b) 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 217e 218e 219e 22e 221e Source: Poten, DNB Markets Potential delays of liquefaction capacity remain a 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. However, we still believe the plants that have started construction, implying a considerable share of sunk cost, will still be profitable to finalise despite the decline in energy prices during the past years. In the chart below we show changes made; the revisions made to 217e are predominantly due to delays at the Chevron s Wheatstone LNG in Australia, while delays in the Woodfibre project in Canada (-2m tonnes for 219) and for train 5 and 6 at Sabine Pass are the main reasons for the negative revisions to exports. 7

8 e 217e 218e 219e 22e m tonne Change in expected LNG export (m tonne) Net change in estimates (%) DNB Markets 8 September 216 Changes to our forecast LNG trade 8 1. % e 217e 218e 219e 22e.5 %. % -.5 % -1. % -1.5 % -2. % -2.5 % West Africa South America S/E Asia North America North Africa N/E Asia Middle east Europe East Africa Net change in estimates Source: DNB Markets Volumes traded We estimate total trade of 246.2m tonnes in 215e (up from the 242.2m tonnes in our previous update), rising to 27m tonnes for 216e, and further to 39m tonnes for 217e. For 216, we estimate Australia to be the largest contributor of additional volumes, adding 15m tonnes on our estimates. These comprise an additional 4.8m tonnes from Australia Pacific LNG, 4.1m tonnes from Gladstone and 3.3m tonnes from Gorgon. We expect another 3.1m tonnes from the continued ramp-up of the two trains in the Queensland Curtis facility. In the US, we expect the two first trains in Cheniere s Sabine Pass to add 5.1m tonnes. For 217e, we believe growth will remain dominated by Australia, which we believe will add 16.9m tonnes (Gorgon +9.1m tonnes, Australia Pacific +3.6m, Gladstone +1.8m), while the US looks set to contribute 8.9m tonnes (only Sabine Pass). For 218e, we expect growth from the US of 14m tonnes (Cove Point LNG +5m tonne, Cameron LNG +4m, Sabine Pass +3.9m) and Australia of 16m tonnes (Wheatstone +6.8m, Ichtys +4.5m, Gorgon +3.3m). Below we show the aggregated historical and estimated volumes traded in our base case by exporting region. On our estimates (collecting data on the export side), the trade saw a 1.8% (4m tonne) increase in 215. In the BP statistical review, which adjusts data so that imports and exports harmonise, trade grew by 1.1%. Total trade by exporting region West Africa South America S/E Asia North America 2 North Africa 15 N/E Asia 1 Middle east 5 Europe East Africa Source: Poten, BP, DNB Markets (forecast) 8

9 m tonne Volume growth (%) 5 % 8 % 1 % 1 % 1 % 12 % 12 % 13 % 12 % 14 % 216e 217e 218e 219e 22e 216e 217e 218e 219e 22e Annual change in production from existing plants (m tonne) Annual increments m tonne) Annual change in exports (m tonne) DNB Markets 8 September 216 Annual change in exports by country Source: DNB Markets e 217e 218e 219e 22e Other Yemen USA Papua New Guinea Indonesia Australia Angola Algeria Total Annual growth from operating liquefaction capacity by exporting region Annual growth from plants under construction by exporting region 3. West Africa 35. West Africa 25. South America 3. South America 2. S/E Asia 25. S/E Asia 15. North America 2. North America 1. North Africa 15. North Africa 5. N/E Asia 1. N/E Asia. -5. Middle east Europe East Africa 5.. Middle east Europe East Africa Source: DNB Markets Source: DNB Markets Alternative scenario Annual volume growth rates in various scenarios % 4 14 % 12 % 35 1 % 8 % 3 6 % 25 4 % 2 % e 217e 218e 219e 22e % 216e 217e 218e 219e 22e Base case Including all FEED, as planned Base case Including all FEED, as planned Source: DNB Markets Source: DNB Markets 9

10 LNG import (m tonne) LNG export (m tonne) e 217e 218e 219e 22e Australian exports (m tonne) Australian share of global exports (%) Australia share of global annual additions (%) 25 % 4 % 54 % 6 % DNB Markets 8 September 216 Australian LNG exports (m tonnes) and share of exports (%) Australia share of global annual export additions (%) 9 25 % 1% % 15 % 1 % 5 % 9% 8% 7% 6% 5% 4% 3% % 2% 1% Source: DNB Markets Australia Australian share of global exports (%) % Source: DNB Markets 216e 217e 218e 219e Total LNG trade by major importer (top 5) Total LNG trade by major exporter (top 5) Others India 2 Others Indonesia 15 Spain 15 Papua New Guinea 1 China Korea 1 Australia Malaysia 5 Japan 5 Qatar Source: Poten, BP, DNB Markets Source: Poten, BP, DNB Markets Share of total imports (215) Share of total exports (215) Others 36 % Japan 33 % Others 33 % Qatar 31 % India 6 % Source: Poten, DNB Markets Spain 5 % China 7 % Korea 13 % Indonesia 7 % Papua New Guinea 8 % Source: Poten, DNB Markets Australia 11 % Malaysia 1 % The two largest Asian importers are down YTD: Japanese imports are down 7% YOY while South Korean imports are down 5%. On a positive note, both India (data only until May) and China have increased their imports YTD by 42% and 15%, respectively. If one assumes YTD growth for each country to be representative for the full-year growth, total imports in 216 for the four countries will grow by 1% compared with 215 as the strong growth in India and 1

11 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Indian LNG import (m tonne) -28 % -28 % -21 % -6 % -13 % 1 % -6 % -6 % 9 % 6 % 12 % 12 % 3 % 31 % China LNG import (m tonne) -29 % -2 % -17 % -9 % -11 % -7 % 5 % 3 % 4 % 11 % 39 % 12 % 16 % 16 % 12 % 53 % 61 % 28 % 26 % 22 % 27 % 28 % -1 % -6 % -5 % -1 % -1 % -3 % -7 % -5 % Annual growth (%) % 1 % % Imports (m tonne, assuming YTD growth for remainder of 216) 42 % DNB Markets 8 September 216 China more than compensated for the decline in Japan and South Korea despite the higher base in the latter two. Growth in LNG imports for major Asian importers LNG imports for major Asian importers; 216 annualised basis YTD growth 5 % 9. 4 % 3 % % 5. 1 % 4. % -1 % % YTD YTD216 India China Japan South Korea India China Japan South Korea Source: Bloomberg, UN Comtrade, DNB Markets Source: Bloomberg, UN Comtrade, DNB Markets Indian LNG import by month Indian LNG import by month % % % 5 % 4 % 3 % 2 % 1 % % -1 % -2 % -3 % % 2 % 1 % % -1 % -2 % -3 %.7-4 %.7-4 % Source: Poten, BP, DNB Markets Source: Poten, BP, DNB Markets 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 4,1 4,2 nautical miles to change much in the coming years. We could see upside potential for trade demand if a significant part of US volumes were contracted to Asian buyers (similar to what we have seen in LPG trade). Another potential upside factor would be if added volumes from Australia in the remainder of 216 and 217 (partially) were to find their way to the European market. In the charts below, we show our base case and various scenarios for tonne-mile. We now estimate growth of 11% for 216e, 12% for 217e and 14% for 218e, which compares to 13%, 15% and 11%, respectively, previously. 11

12 bn tonne-mile Demand growth (%) 5 % 8 % 11 % 11 % 12 % 12 % 11 % 14 % 15 % 16 % 216e 217e 218e 219e 22e 216e 217e 218e 219e 22e Annual increments (bn tonne-mile) Annual increments (bn tonne-mile) e 216e 217e 218e 219e 22e e 216e 217e 218e 219e 22e bn tonne-mile Nautical miles DNB Markets 8 September 216 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 Source: DNB Markets Source: 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 West Africa South America S/E Asia North America North Africa N/E Asia Middle east Europe East Africa Source: DNB Markets Source: DNB Markets Tonne-mile demand scenarios Annual demand growth rates in various scenarios % % % 14 6 % % % 216e 217e 218e 219e 22e 9 216e 217e 218e 219e 22e Base case Including all FEED, as planned Base case Including all FEED, as planned Source: DNB Markets Source: DNB Markets 12

13 Current contract volumes by start year (m tonne) Termination 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 8 September 216 Creation 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 1 as a proportion of total traded volume rose from 5% in 2 to 28% in 215 (though down from 29% in 214). Also, existing contracts are set to roll off by an average of 9m tonnes per year between 216e 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, as it would require building substantial storage capacity in ports. Spot trade of LNG Roll-off of current contracts 8 3 % 25 8 % % 2 % 15 % % 6 % 5 % 4 % 3 % % 5 % 5 2 % 1 % % % m tonne roll-off "Spot" (<4 years) LNG trade % of total trade Accumulated roll-off from current portfolio (%) Source: GIIGNG, DNB Markets Source: GIIGNG, DNB Markets Current contracts by start year of contract 35 Roll-off of current contracts Other N/E Asia 3 25 Other N/E Asia 2 15 Middle east S/E Asia South America 2 15 Middle east S/E Asia South America 1 5 Europe West africa North africa 1 5 Europe West africa North africa Source: GIIGNG, DNB Markets Source: GIIGNG, DNB Markets Also relevant 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% (214). The US shale gas revolution has shed light on what sort of potential there might be to grow this further as gas is still preferred over other fossil fuels, in particular due to its much lower particle emissions than coal (saw its share grow again in the 2s as China joined the global economy). 1 Here spot relates to contracts with duration of four years or less, this is GIIGNL terminology 13

14 m tonne oil equivalent Share of natural gas in the global energy mix (%) DNB Markets 8 September 216 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 (214) % 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 we believe that this is still some way off. 14

15 Utilisation of regas capacity (%) Spare import capacity (mtpa) Receiving capacity (mtpa, liquefied) Share of floating regasification capacity (%) Utilisation of receiving capacity (%) 29 % 29 % 28 % 3 % 31 % 32 % 32 % 32 % 32 % 34 % 33 % 33 % 36 % 35 % 36 % 36 % DNB Markets 8 September 216 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. We expand upon the FRSU market in a sub-section below. Global regasification capacity Utilisation of regasification capacity 8 9% 38 % % 7% 6% 5% 4% 3% 2% 36 % 34 % 32 % 3 % 28 % 26 % 1 1% % 24 % 22 % 2 % Source: GIIGNL, DNB Markets Utilisation of regasification capacity by country Source: GIIGNL, DNB Markets Spare regasification capacity 14 % 12 % 128 % % 4. 8 % 6 % 4 % 2 % 72 % 58 % 5 % 44 % 32 % % Taiwan India Turkey Others China World. USA Japan Korea Others Spain World Source: GIIGNL, DNB Markets Source: GIIGNL, DNB Markets Total gas trade, including piped gas Over the period gas production has had a compounded annual growth rate of 2.5%, resulting in a 42% increase in volume. As the trade in gas has grown by 4.6% CAGR in the same period, the share of gas traded has increased from 22% to around 3%. However, since 21 the production has continued with annual growth of 2.% while the trade has been lagged; the trade/production ratio hence topped out at 31% in 211 and came down to 29% for 215. Looking to the global composition of gas trade split by pipeline or LNG transport can nuance the situation further. Even though the total share of gas trade has been rather stable around 3% in recent years, the composition has changed. LNG trade has grown by a CAGR of 3.2% since 21, clearly outpacing production growth of 2.%, while pipeline trade only achieved.8% over the same period. Over the full period LNG trade has grown 137% which compares with a 71% increase in piped gas. The share of cross-regional trade, when adding both piped gas and LNG increased from 55% in 21 to a high of 7% in 211, but then declined to 63% in 215. This latter development 15

16 Bcm Share of total gas trade (%) Average laden distance (nautical miles) % 17 % 17 % 18 % 19 % 19 % 19 % 19 % 21 % 21 % 21 % 21 % 21 % 19 % 2 % 6 % 6 % 6 % Bcm 7 % 7 % 7 % 8 % 7 % 8 % 9 % 1 % 1 % 1 % 1 % 22 % 23 % 1 % 2, % 2,538 2,632 2, % 2, % 26 % 2, % 2, % 3,72 2,983 3,29 3,3 3,363 3, % 3,463 3,539 3 % 31 % 31 % 3 % 29 % 29 % DNB Markets 8 September 216 simply implies that more gas is staying in the same region it is produced though the drop in the cross-trade is more significant than the decrease in the average distance. Looking ahead, we do believe that the LNG trade will continue to grow faster than piped gas and generally also that the share of traded gas versus production will continue to grow. Global gas production and percentage traded Global gas trade by mode of transport 4, 4 % 35 % 3,5 3, 2,5 38 % 36 % 34 % 32 % 3 % 25 % 2, 3 % 1,5 1, 5 28 % 26 % 24 % 22 % 2 % 15 % 2 % 1 % Gas production Gas traded as % of production Piped trade as % of production LNG trade as % of production Source: BP, DNB Markets Source: BP, DNB Markets Regional LNG gas trade profile Share of cross-regional LNG trade and average traded distance 4 75 % 75 % 4, % 65 % 6 % 55 % 7 % 65 % 6 % 55 % 4,2 4, 3,8 3,6 3,4 3,2 5 % 5 % 3, Source: BP, DNB Markets Intra-region Inter-region Cross-regional trade ( %) Source: BP, DNB Markets Cross-regional trade ( %) Avg distances (nm) 16

17 e 217e 218e 219e 22e 221e 222e e 217e 218e # vessels 14k+ m3 % 3 % 4 % 9 % 9 % 7 % 9 % 7 % 6 % 14 % 13 % 16 % 18 % 18 % 18 % 29 % DNB Markets 8 September 216 Supply Fleet growth in 215 was 7.1%, and YTD annualised growth is 6.2% as per August 216. For the full year and onward, we forecast 9.3% for 216e (8.6% previously), 7.3% for 217e (8.5%) and 6.4% for 218e (6.%). This does not include deliveries from new ordering, as the average time from ordering to delivery is about three years; hence supply growth is fairly certain in the LNG market for the next three years. The gross order book was 21.5m m 3 at the end of August this year, or 32% of the fleet (down from 37% at the beginning of the year). 14k+ m 3 vessels account for 99% of the order book by capacity, and small carriers 1%. There are no orders for vessels of 6k 14k m 3. The order book/fleet ratio is 43% for 14k+ m 3 vessels and 52% for small LNG carriers (<6k m 3 ). The LNG order book is split between China (9%), Japan (2%), and South Korea (71%). Comparing this with deliveries in , we see that China s market share has increased from 5% and Japan s is up from 8%, while South Korea s has decreased from 87%. We forecast deliveries of 11% for 216e, declining to 9% for 217e and 9% for 218e. Unlike many other shipping segments, there have been limited slippage and very few cancellations of LNG vessels, but in 215 we estimate 22% slippage. While we have no explicit reasons to expect any significant delays or cancellations to the order book, we do highlight that in the current order book compiled by Clarksons there is 1.9m m 3 scheduled for delivery this September; this represents more than four times the average amount delivered monthly last year (.4m m 3 ), and we do believe some of these contracts could be delayed further. Contracting during 215 was 5.m m 3 (about half of 214 s ordering of 1.9m m 3 ) or 8% of the fleet at the beginning of that year. For 216e, we have lowered our estimates on the back of weaker market expectations and predict a total of 1.m m 3 (from 2.5m m 3 ) to be contracted, of which.7m m 3 is already in the order book. For e we expect.8m m 3 (2.7m m 3 ) and.9m m 3 (2.9m m 3 ) respectively. This level of contracting corresponds to 1% annual contracting for the period e. There has been only modest scrapping of LNG vessels over the past few years: 214 saw scrapping of 269k m 3 and k m 3, representing.5% of fleet capacity both years. We expect this to increase to 1.6% (previously 1.%) in 216e, 2.1% (1.4%) in 217e, and 2.9% (1.2%) in 218e. No. of vessels above 14m 3 by (expected) delivery year Historical and expected fleet growth % % 25 % 2 % 15 % 1 % 5 % % -5 % Fleet Orderbook Deliveries Scrapping Conventional fleet growth Source: Clarksons, DNB Markets Source: Clarksons (historical), DNB Markets (forecast) LNG fleet We forecast 9.3% fleet growth for 216e (up from 8.6% in our previous report), 7.3% for 217e (previously 8.5%) and 6.4% for 218e (6.%). This does not include deliveries from 17

18 Jan-3 Nov-3 Sep-4 Jul-5 May-6 Mar-7 Jan-8 Nov-8 Sep-9 Jul-1 May-11 Mar-12 Jan-13 Nov-13 Sep-14 Jul-15 May-16 Mar-17 Jan-18 Nov-18 Jan-3 Nov-3 Sep-4 Jul-5 May-6 Mar-7 Jan-8 Nov-8 Sep-9 Jul-1 May-11 Mar-12 Jan-13 Nov-13 Sep-14 Jul-15 May-16 Mar-17 Jan-18 Nov-18 Monthly fleet growth Annual fleet growth YTD16 ROY YTD16 ROY k m k m e 217e 218e k m3 Cumulative share of fleet (%) 17,434 2,225 k m3 22,87 26,82 31,442 4,286 47,235 51,54 53,21 53,93 55,221 6,266 64,573 7,584 75,732 8,615 DNB Markets 8 September 216 new ordering, as the average time from ordering to delivery is about 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 64.6m m 3 at end-215 to 8.6m m 3 at end-218e. The current fleet is split 73% 14k+ m 3, 25% 1k 14k m 3, 1% 6k 1k m 3, and 1% below 6k m 3 (by capacity, not units). LNG fleet by year built 25, 2, 15, 1, 5, 16 % 9 % 1 % 1 % 2 % 3 % 4 % 75 % 1 % 1 % 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 Below 6 Source: Clarksons (historical), DNB Markets (forecast) LNG fleet and order book by vessel size LNG fleet and order book by shipyard country 9, 8, 9, 8, Other 7, 6, 5, 4, 3, 2, Below , 6, 5, 4, 3, 2, South Korea Japan China 1, 1, 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 5.% Annualised, smoothed monthly growth versus YOY growth 35% 4.% 3.% 2.% 1.%.% -1.% 3% 25% 2% 15% 1% 5% % -5% MOM 3mths MA YOY 3mths MA annualised Source: Clarksons (historical), DNB Markets (forecast) Source: Clarksons (historical), DNB Markets (forecast) 18

19 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 Feb-18 Sep-18 Fleet growth (YOY, %) Share of total fleet and order book (%) YTD16 ROY DNB Markets 8 September 216 Monthly fleet growth YOY by vessel size LNG fleet and order book by shipyard country 12% 1% 8% 6% 4% 2% % -2% -4% -6% 1 % 9 % 8 % 7 % 6 % 5 % 4 % 3 % 2 % 1 % % Fleet by year of delivery Gross orderbook Below 6 Source: Clarksons (historical), DNB Markets (forecast) 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 % 1 % 22 % 3 % Diesel Electric Motor Ship 2-Stroke Motor Ship 4-Stroke Steam Turbine 6-1 Below 6 54 % 76 % 12 % Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets 4 % 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 19

20 % (basis # vessels) # of vessels k m3 Orderbook/fleet ratio # of vessels DNB Markets 8 September 216 Order book/fleet ratio by vessel size, currently Fleet and order book by vessel size (number of vessels) 5, 7 % 12 45, 4, 35, 3, 25, 2, 15, 1, 5, 46 % 64 % 6 % 5 % 4 % 3 % 2 % 1 % % % Below 6 % Vessel size (m3) Fleet Orderbook OB/fleet In service On order Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Cargo containment system in fleet and order book 45 % 43 % 4 % 38 % 34 % 35 % 3 % 26 % 25 % 22 % 2 % 16 % 15 % 13 % 1 % 6 % 5 % % Other/not given Gaztransport Technigaz Moss % of total fleet % of total orderbook Source: Clarksons, DNB Markets Containment system by vessel age Other/not given Gaztransport Technigaz Moss Built 2 or earlier Built Built 211 or later Source: Clarksons, DNB Markets LNG order book The gross order book was 21.5m m 3 end of August this year, or 32% of the fleet (down from 37% at the beginning of the year). While we have no explicit reasons to expect any significant delays or cancellations to the order book, we do highlight that in the current order book compiled by Clarksons there is 1.9m m 3 scheduled for delivery this September; this represents more than four times the average amount delivered monthly last year (.4m m 3 ), and we do see the risk of some of these vessels being delayed further. 14k+ m 3 vessels account for 99% of the order book by capacity, and small carriers 1%. There are no orders for vessels of 6k 14k m 3. The order book/fleet ratio is 43% for 14k+ m 3 vessels and 52% for small LNG carriers (<6k m 3 ). The LNG order book is split between China (9%), Japan (2%), and South Korea (71%). Comparing this with deliveries in , we see that China s market share has increased from 5% and Japan s is up from 8%, while South Korea s has decreased from 87%. 2

21 k m3 k m3 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 Jul-14 Sep-15 Jan-97 Apr-98 Jul-99 Oct- Jan-2 Apr-3 Jul-4 Oct-5 Jan-7 Apr-8 Jul-9 Oct-1 Jan-12 Apr-13 Jul-14 Oct-15 Fleet growth YoY (%) OB/fleet ratio (%) 14+ fleet growth (%) OB/fleet ratio (%) k m3 k m3 DNB Markets 8 September 216 LNG order book at start of year by delivery year 3, Our adjusted order book for future delivery 25 25, 2, 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 (historical), DNB Markets (forecast) Order book to fleet ratio and fleet growth, total Order book to fleet ratio and fleet growth, 14k+ m 3 35 % 3 % 25 % 2 % 15 % 1 % 5 % % -5 % 12 % 1 % 8 % 6 % 4 % 2 % % 45 % 4 % 35 % 3 % 25 % 2 % 15 % 1 % 5 % % 1 % 9 % 8 % 7 % 6 % 5 % 4 % 3 % 2 % 1 % % 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 21

22 k m3 k m3 k m3 k m3 DNB Markets 8 September 216 Total order book, delivery versus contracting year 8 Total order book, contracting versus delivery year YTD < ROY16 ROY Delivery year < YTD16 Ordering year Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Total order book, shipyard location versus contracting year 16 Total order book, contracting year versus shipyard country China Japan South Korea Builder location Others YTD < < YTD16 Ordering year Others South Korea Japan China Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets 22

23 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 Mar-18 Jun-18 Sep-18 Dec-18 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 Mar-18 Jun-18 Sep-18 Dec-18 Deliveries by month (k m3) 14+ deliveries 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-18 May-18 Sep e 217e 218e 1 % 4 % 5 % 9 % 8 % 1 % 14 % 13 % 11 % 9 % 9 % 16 % 18 % 18 % 18 % Fleet growth (YOY, %) 29 % 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 Monthly deliveries (k m3) YOY change in MA(3) monthly deliveries e 217e 218e 323 Deliveries (k m3) 2,85 2,791 2,582 1,833 2,539 3,994 4,799 4,434 5,314 4,714 7,213 7,37 6,62 7,76 9,127 DNB Markets 8 September 216 Deliveries We forecast deliveries of 11% for 216e, declining to 9% for 217e and 9% for 218e. 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 Expected deliveries from new ordering (k m3) Expected deliveries from current OB (k m3) Historical deliveries (k m3) Source: Clarksons (historical), DNB Markets (forecast) Fleet growth by year, historical and forecast Fleet growth by month, historical and forecast, only 14k+ m 3 35 % 18% 3 % 16% 25 % 14% 2 % 15 % 1 % 12% 1% 8% 6% 5 % 4% % 2% % Deliveries as % of fleet start of year Source: Clarksons (historical), DNB Markets (forecast) Source: Clarksons (historical), DNB Markets (forecast) Monthly additions from the current order book (k m 3 ) Monthly additions from current order book (no. of 14k+ m 3 ) 3, 2,5 2, 1,5 1, Below 6 Source: Clarksons (historical), DNB Markets (forecast) Source: Clarksons (historical), DNB Markets (forecast) 23

24 Aug-12 Oct-12 Dec-12 Feb-13 Apr-13 Jun-13 Aug-13 Oct-13 Dec-13 Feb-14 Apr-14 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 Monthly contracting (k m3) ,83 1,14 1, ,491,549 1,44 1,421 3, YTD YTD16 New contracting (k m3) Time from ordering to delivery (years) DNB Markets 8 September 216 Cancellations Unlike many other shipping segments, there have been limited slippages and very few cancellations of LNG vessels, though for 215 we saw 22% slippage. It is also relevant to mention that 11 vessels are now in the orderbook for September delivery; some of these are likely to be postponed further, possibly into 217. The record in terms of monthly deliveries was set in January 215 when seven vessels were delivered. All in all, we opt to assume neither cancellations nor further slippage, but regard that as a conservative approach. Contracting Contracting during 215 was 5.m m 3 (about half of 214 s ordering of 1.9m m 3 ) or 8% of the fleet at the beginning of that year. For 216e, we have lowered our estimates on the back of weaker market expectations and predict a total of 1.m m 3 (from 2.5m m 3 ) to be contracted, of which.7m m 3 is already in the order book. For e we expect.8m m 3 (2.7m m 3 ) and.9m m 3 (2.9m m 3 ), respectively. This level of contracting corresponds to 1% annual contracting for the period e. 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 ) , , Below 6 Source: Clarksons, DNB Markets Yard overview Over the past 12 months, MHI Nagasaki has received most orders (54k m 3 ), followed by Imabari SB Saijo (534k m 3 ) and Daewoo (DSME) (52.2k m 3 ). Aggregated, the top 1 yards have 86% of the total order book. 24

25 YTD16 Aug-12 Nov-12 Feb-13 May-13 Aug-13 Nov-13 Feb-14 May-14 Aug-14 Nov-14 Feb-15 May-15 Aug-15 Nov-15 Feb-16 May-16 Aug-16 Scrapping (k m3) Scrapping (% of fleet) Montly scrapping (km 3) DNB Markets 8 September 216 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 < YTD16 Daewoo (DSME) South Korea Samsung HI South Korea MHI Nagasaki Japan Hudong Zhonghua China P.R Kawasaki HI Sakaide Japan Imabari SB Saijo Japan JMU Tsu Shipyard Japan Hyundai Samho HI South Korea Jiangsu New YZJ China P.R CMHI (Jiangsu) China P.R Total top Other yards Top 1 share of total 86 % 71 % 85 % 93 % 9 % 87 % 81 % 87 % 92 % Source: Clarksons, DNB Markets Scrapping There has been only modest scrapping of LNG vessels over the past few years: 214 saw scrapping of 269k m 3 and k m 3, representing.5% of fleet capacity both years. We expect this to increase to 1.6% (previously 1.%) in 216e, 2.1% (1.4%) in 217e, and 2.9% (1.2%) in 218e. These are the vessels that are turning 22.5 years or older, and given the rather weak rate outlook in combination with inferior fuel economics for the older steam turbine vessels, we expect those to be scrapped at the first special or intermediate survey. Also relevant in this context is the roll-off from the long-term purchase contracts of LNG; in a chart below we show how this accelerates over the next years and both in 218e and 219e close to 6% of contracts are rolling off. We believe the vessels employed on these contracts will have a hard time to get alternative employment and hence these are likely scrapping candidates. 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 25

26 % of fleet e 217e 218e -2.9 % Average age when scrapped -2.1 % Scrapping (k m3) -1.6 % -.5 % %. %. %. % -.1 % -.3 % -.4 % -.5 % -.8 % -.5 % -.5 % Scrapping as % of fleet. % < < k m3 vessels scrapped # vessels scrapped DNB Markets 8 September 216 Past three years of scrapping, by capacity Past three years of scrapping, by number of vessels 9 1 % 12 1 % % 8 % 7 % 6 % 5 % 4 % 3 % 2 % 1 % % Below Cumulative share % 8 % 7 % 6 % 5 % 4 % 3 % 2 % 1 % % Below Cumulative share Age when scrapped (years) Age when scrapped (years) Source: Clarksons, DNB Markets Source: Clarksons, DNB Markets Average age of scrapped vessels (k m 3 ) 5 Historical and forecast scrapping by year. % % -1. % 4-1, -1.5 % 35-1,5-2. % , -2,5-2.5 % -3. % -3.5 % Below Historical scrapping (k m3) Expected scrapping (k m3) Scrapping Source: Clarksons, DNB Markets Source: Clarksons (historical), DNB Markets (forecast) Renewal survey schedule for current fleet Share of long-term LNG contracts rolling off 9% 8% 8% 7% 6% 5% 3.8% 3.9% 3th renewal survey 4th renewal survey 7% 6% 5% 4% 6% 6% 7% 4% 3% 2% 2.2% 2.9% 1.1% 2.9% 5th renewal survey 6th renewal survey 3% 2% 1% 1% 2% 2% 1% % 1.2%.8% 1.7% 1.1%.%.2%.6%.%.4%.4% 217e 218e 219e 22e % Roll-off per annum (%) Source: Clarksons, DNB Markets Source: Clarksons (historical), DNB Markets (forecast) 26

27 e 217e 218e Fleet utilisation (%) 74% 77% 79% 81% 84% 83% 86% 86% 86% 85% 89% 91% 91% 89% 96% 94% Spot rate (USD/day, 14-16k m3 vessel) 36,349 37, 22, USD/day 54,64 68,646 62, 47, 72, 57, 92,433 1,74 128,481 DNB Markets 8 September 216 Market balance We forecast average rates of USD37k/day for 216 (16m 3 TFDE vessels), increasing to USD62k/day in 217 and further to USD72k/day in 218 as we expect fleet utilisation to improve from 77% in 215e to 85% in 218e. For 216, when we expect rates to improve in H2, this is a reduction from USD4k/day, while our previous estimates were the same for 217e and 218e. Below we show the historical and forecast utilisation of the LNG fleet together with a scatter chart of fleet utilisation and spot rates between 21 and 215. Spot rates, historical and forecast 14, 12, 1, 8, 6, 4, 2, e 217e 218e 16 TFDE 14 MST Source: Fearnleys, DNB Markets Utilisation of LNG fleet Spot rate model fit (21 213) 1% 14, 95% 12, 9% 1, 85% 8, 8% 75% 6, 4, y = e x R² = % 2, Utilisation (%) 7% 75% 8% 85% 9% 95% 1% Fleet utilisation Source: Poten, DNB Markets Source: Fearnleys, Poten, DNB Markets How we derived our model First, variables exogenous to the model are shown in purple, while endogenous variables or assumptions we made are shown in dark green. For future periods, we derived our own trade forecasts as discussed above. Scrapping estimates are based on a scrapping age of 22.5 years (down from 3 years in our previous update), or at the earliest intermediate or special survey thereafter. Future contracting is a simple assumption based on: 1) yard capacity; and 2) our assessment of future transportation demand. 27

28 8 September 216 Our shipping LNG model, overview Tonne-miles by country-tocountry trade in the following regions West Africa Europe East Africa LNG transport demand N/E Asia North Africa North America S/E Asia South America Scrapping LNG fleet Spot rates New orders Deliveries Current order book Cancellations LNG transport capacity Utilisation of fleet Vessel speed Inefficiencies Port operations Source: DNB Markets Both the scrapping and contracting methodology in our LNG balance differ from the other segments we model, as there is no consistent data on earnings in this segment prior to 21, making it difficult to understand how earnings affect scrapping and contracting. Deliveries are estimated using the current order book taken from Clarksons, adjusted for our assumed cancellations (we assume all vessels ordered before 27 still in the order book will be cancelled, but that does not affect the LNG order book), and deliveries from our estimated new ordering (the latter with a 36-month time lag from the date of ordering). Our notation on transport capacity is m 3 -mile/month (cubic meters per month). We have also included an inefficiencies dimension, where we categorise dead-freight and port congestion, which we know are significant factors in the market balance but we have no data to rely upon for either historical or estimating purposes. Hence this is flat in the model at 5% for it not to affect the changes in the market balance, but at the same time allow us to easily include improvements to the model in the future. Those following our research know that we normally include vessel speed as an endogenous variable in our fundamental modelling. However, for LNG we have modelled it on an exogenous basis, taking it from typical design speed of 19 knots in 23 down to 16.5 knots in 28 where we expect it to stay throughout our forecast horizon. The reason for this is simply the lack of reliable historical data. We have extracted speed data on a vessel by vessel basis since March 214 and it has been rather constant at knots. From the aggregated time series we do have access to (going back to May 28), we cannot see the 28

29 8 September 216 normal decline in speed that we observe in all other segments. Hence, we conclude that speed came down prior to 28. The historical demand data is predominantly based on data provided by Poten and Partners on a country-by-country basis by month. The trade data is then crossed with a distance matrix to derive a transportation (laden) demand estimate. We assume 5% ballasting when calculating total transportation demand. Transportation demand estimates are based on collected data from multiple sources with information about liquefaction capacity. We assume that each exporter follows the trade pattern from 215. Our shipping LNG model SUPPLY e 217e 218e 219e 22e Fleet, start of year (k m3) 15,349 17,434 2,225 22,87 26,82 31,442 4,286 47,235 51,54 53,21 53,93 55,221 6,266 64,573 7,584 75,732 8,615 82,994 Gross OB with delivery current year as start of year Not delivered* Historical deliveries (k m3) % not delivered of historical OB for current year* % 6% 1% 19% 3% -26% 11% 27% 3% 22% 2% Order book Order book as % of fleet start of year 17.6% 19.% 32.4% 22.1% 9.6% 2.8%.7% 6.5% 9.9% 1.% 11.3% Assumed not delivered** Deliveries from current order book (k m3) % not delivered of remaining OB % % % % % New orders placed, historical New orders placed, future Total ordering (k m3) Ordering as % of fleet start of year 14% 63% 34% 3% 16% 3% 2% 1% 16% 12% 12% 2% 8% 1% 1% 1% 1% 1% Delivery of new orders placed, future Total deliveries (k m3) Deliveries as % of fleet start of year 14% 16% 13% 18% 18% 29% 18% 9% 4% 1% 5% 1% 8% 11% 9% 9% 4% 2% Historical scrapping (k m3) Forecasted scrapping (k m3) Total scrapping (k m3) Scrapping as % of fleet start of year.%.%.%.%.1%.5%.%.3%.4%.5%.8%.5%.5% 1.6% 2.1% 2.9% 1.3%.6% Misc./Net additions Fleet, end of year (k m3) 17,434 2,225 22,87 26,82 31,442 4,286 47,235 51,54 53,21 53,93 55,221 6,266 64,573 7,584 75,732 8,615 82,994 83,887 YoY growth 16% 13% 18% 17% 28% 17% 9% 3% % 4. % 9.1 % 7.1 % 9.3 % 7.3 % 6.4 % 3. % 1.1 % Fleet average normal speed, laden (knot) Fleet potential transport capacity (bn m3-mile/year) Time used for port operations (%) 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% Port operations (bn m3-mile/year) Commercial waiting time, share of fleet (%) 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% 5.% Commercial waiting time (bn m3-mile/year) Bunker price (USD/ton) Net transport capacity (bn m3-mile/year) YoY growth 14% 9% 13% 13% 2% 24% 12% 5% 2% 1% 7% 9% 8% 9% 9% 3% 2% DEMAND e 217e 218e 219e 22e Seaborne volumes per main export region Middle east North America S/E Asia N/E Asia Others Total trade (m tonne) YOY total trade 13% 5% 7% 12% 9% 1% 6% 23% 8% % -2% % 2% 1% 12% 13% 8% 5% Total laden tonne-mile (bn) Average laden distance (nm) YOY change in avg distance % 3% -4% 6% 7% 4% -1% 6% 6% -2% 1% -1% -1% 1% % 1% 1% 3% Total m3-mile demand (bn) YOY tonne-mile 15% 11% 6% 22% 19% 7% 8% 31% 15% -1% -1% -1% 1% 11% 12% 14% 8% 5% Utilisation (%) 89% 86% 84% 91% 96% 86% 74% 86% 94% 91% 89% 83% 77% 79% 81% 85% 89% 92% Spot rates (USD/day) 16 TFDE 68,646 36,349 37, 62, 72, 14 MST 54,64 92, ,481 1,74 22, 47, 57, Source: Clarksons, Poten, BP, DNB Markets (forecast) 29

30 USD/mmBtu Apr-12 Jul-12 Oct-12 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Apr-12 Jul-12 Oct-12 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 USD/mmBtu LNG discount to oil (%) DNB Markets 8 September 216 LNG prices The LNG price in Asia followed the oil price after it started to decline in H2 214, but from March this year the Asian LNG price has traded at an average 33% discount to the crude price, which is about double the normal discount (which is 16% from 212 to YTD). Spot LNG in Asia versus Brent, both USD/mmBtu LNG discount to Brent 4% 3% 2% 1% % -1% -2% -3% -4% -5% LNG des Northeast Asia (ANEA) half-month 1 (USD/mmBtu) Brent (USD/mmBtu) Source: Argus, Bloomberg, DNB Markets Source: Argus, Bloomberg, DNB Markets LNG discount to oil (%) Average We have no explicit forecast for LNG prices, while DNB s oil analyst expects oil to trade in the range of USD6 8/bbl in the years ahead, which implies an LNG price of USD1 13/mmBtu if at parity to crude. As this view on oil prices is above the current forward curve for oil, it also implies a higher LNG price in Asia than implied by the current forward curve for oil. Forward prices for LNG US FOB (indicative) NBP Japan oil-linked Source: Argus, 6 September 216 Coal provides a floor to LNG prices LNG prices in Asia followed the oil price after it started to decline in H2 214, but from March this year the Asian LNG price has traded at an average 33% discount to the crude price, which is about double the normal discount (which is 16% from 212 to YTD). Conventional economics state that, in the long run, the prices of all energy carriers are correlated as the different carriers are substitutes in consumption. If no constraints are applied, the pricing mechanism will be dominated by the energy content in each carrier adjusted for the cost of utilising that energy in end consumption, including processing and transportation costs. A good example of this is found in the US market in the early 2s; in the chart below we show a selection of prices for different energy carriers, all in USD/mmBtu in the US. Up until the start of the shale gas revolution (say, 26) the prices of all carriers, apart from coal, were 3

31 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Last Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Last USD/GJ USD/GJ Jun-1 Dec-1 Jun-2 Dec-2 Jun-3 Dec-3 Jun-4 Dec-4 Jun-5 Dec-5 Jun-6 Dec-6 Jun-7 Dec-7 Jun-8 Dec-8 Jun-9 Dec-9 Jun-1 Dec-1 Jun-11 Dec-11 Jun-12 Dec-12 Jun-13 Dec-13 Jun-14 Dec-14 Jun-15 Dec-15 USD/Mmbtu DNB Markets 8 September 216 tightly correlated. However, the strong growth in gas supplies starting in 26 led to a decoupling of the price of natural gas (methane) versus the other gaseous and liquid energy carriers, which didn t stop until the gas price was at parity with coal (in 211), a relationship which has more or less stayed in place since then. The prices for different energy carriers in the US, all in USD/mmBtu Methane Ethane Propane Butane WTI LLS Coal Source: Bloomberg, EIA, BP, DNB Markets Recently the same development has been seen in both European and Asian markets. In the charts below, we show the price of coal and gas delivered in Europe (left) and Asia (right) converted to USD/GJ (1 GJ (gigajoule) =.95 mmbtu). The spread between the price of gas and the price of coal is down from USD12/GJ to USD2/GJ in Asia from 213 to now, while in Europe the spread is down from USD7/GJ to USD1/GJ (see charts below). European coal (ARA) and gas (NBP) prices in USD/GJ Asian coal (China) and gas (LNG spot) prices in USD/GJ Gas/LNG Coal Gas/LNG Coal Source: Bloomberg, DNB Markets Source: Argus, Bloomberg, DNB Markets And adjusting further the prices for different efficiencies in power plants, the two prices seem aligned in both places. This leads us to believe that the LNG spot price now has downside protection from further declines given by the price of coal. We argue that investors should take confidence in LNG carrier rates having managed to appreciate while LNG prices have averaged multiyear lows YTD. Also, a premium of LNG versus coal is easily justified from an environmental point of view as both particulate and greenhouse gas emissions are considerably lower from gas compared to coal. The 1:2 CO 2 emission ratio (gas emits half the amount of CO 2 per energy unit) should also support gas prices if any sort of carbon pricing were to be put in place. 31

32 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Last Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Last USD/MWh USD/MWh DNB Markets 8 September 216 Implied price for electricity by energy carrier, Europe Implied price for electricity by energy carrier, Asia Gas (52% efficiency) Coal (39% efficiency) Gas (52% efficiency) Coal (33% efficiency) Source: Bloomberg, DNB Markets Source: Argus, Bloomberg, DNB Markets This said, in a longer-term perspective we believe competition between gas and coal will grow, while in the shorter term there are still many contracts which tie LNG to the price of oil and if LNG can be bought at a considerable discount to the oil link, it is likely that those contracts would be limited to their minimum volume and the additional volume to be bought spot, hence the oil price would still impact the willingness to pay for spot LNG. LNG prices in consuming countries have traditionally been directly linked to oil prices, as gas markets, due to pipeline economics, were highly regionalised and no global gas price existed. In the infancy of the LNG market, this was a rational approach both for producers and consumers as: 1) consumers used oil products for stationary use (power plants); and 2) producers could extract and sell gas at approximately the same energy value as liquids. However, with the significant growth in LNG used for electricity production globally in recent decades, we believe its competition versus coal, and not oil, will intensify in the years to come as this is where marginal substitution is happening: i.e. while the use of oil in stationaries was the price-setting mechanism previously, the substitution of coal-fired power production with gas-fired power production is likely to impact the pricing of LNG going forward. 32

33 Jan-11 May-11 Sep-11 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 Oct-98 Oct-99 Oct- Oct-1 Oct-2 Oct-3 Oct-4 Oct-5 Oct-6 Oct-7 Oct-8 Oct-9 Oct-1 Oct-11 Oct-12 Oct-13 Oct-14 Oct-15 1 year TC rate 16k* cbm (USD/day) Newbuilding price LNG (USD m) Oct-1 Feb-11 Jun-11 Oct-11 Feb-12 Jun-12 Oct-12 Feb-13 Jun-13 Oct-13 Feb-14 Jun-14 Oct-14 Feb-15 Jun-15 Oct-15 Feb-16 Jun-16 LNG spot rate (USD/day) USD/day DNB Markets 8 September 216 Spot rates, TC rates and vessel values Newbuild prices have been in the narrow range of USD185m 187m (for 147k m 3 ) since 21 and the latest quote for a 174k m 3 vessel is USD198.5m, down from USD24m at the start of the year. In our sector report from January we pointed to downside risk and given the very weak order intake for yards from all shipping segments, we continue to see the risk for further depreciation. LNG spot rates (14k m 3 vessel until 214, 16k m 3 TFDE from 214 to YTD 216) Spot rate, annual averages (216 is YTD including January) 16, 14, 128,481 14, 12, 1, 8, 6, 12, 1, 8, 6, 54,64 92,433 1,74 68,646 4, 2, Source: Fearnleys 4, 2, Source: Fearnleys 36,349 31, YTD year TC rates 14/16k m 3 18, 16, 14, 12, 1, 8, 6, 4, 2, Newbuild prices Clarksons Fearnleys (*: 14k cbm until 214) 147k cbm Newbuilding Prices 174k cbm Newbuilding Prices Source: Fearnleys, Clarkson Source: Clarkson USD15, 2,/day premium for TFDE vessels Our spot rate forecasts given are based on the marginal vessel employed, which we now believe will change from vessels with steam turbine technology to TFDE vessels. Hence, we expect increased discrimination against the older and less efficient technology in the next few years, which could give a boost to state-of-the-art TFDE vessels. 59% of the fleet is using turbine propulsion. On the back of the better fuel economics in the tri-fuel part of the fleet (not accounting for any differences in cargo intake, i.e. larger vessels should enjoy higher dayrates), we believe realised TFDE fixtures will be about USD15, 2,/day higher than for modern steam turbine vessels. This is based on ship-owners getting the fuel benefit (cusd1,/day for TFDE versus modern steam turbine powered vessels) and 25 5% of estimated USD2,/day cargo intake savings. 33

34 Dayrate (assumed at parity, USD/day) Bunker consumption (tonne HFOequivalent/day) Bunker consumption (HFO-equivalent, tonne/day) # vessels above 14k m3 # vessels above 14k m3 Share diesel electric DNB Markets 8 September k+ m 3 fleet and order book by propulsion technology Accumulated share of TFDE vessels in the fleet % 45 % 4 % 35 % 3 % 25 % 2 % 15 % 1 % 5 % % Fleet Steam turbine Motor Ship 2-Stroke Source: Clarkson, DNB Markets Diesel Electric Motor Ship 4-Stroke Orderbook Fleet Orderbook Other Diesel Electric Share diesel electric Source: Clarkson, DNB Markets In the table below we quantify the savings assuming a speed of 18 knots laden, 16 knots in ballast, doing a 4,nm round voyage, including loading/unloading days. We have highlighted current levels with oil in the USD4s/bbl and LNG carrier spot rates in the USD3,/day, with savings for TFDE vessels in the region of USD25,/day (25%). These savings are set to increase towards USD3 4,/day using DNB s USD6 8/bbl oil price forecast for 218e and our USD72,/day modern LNG carrier forecast. For older turbine powered vessels, the comparable figures are USD4,/day to USD65,/day in 218e, reflecting low 4s% savings. Fuel consumption curve (tonne/day) Fuel consumption regression (modern turbine, tonne/day) Knots y = 2.294e.112x R² = Consumption (HFO/24 hours) TFDE Modern steam Old steam Expon. (Consumption (HFO/24 hours)) Source: DNB Markets Source: DNB Markets Daily savings TFDE vessel (16k cbm) versus modern turbine powered vessel (14k cbm) (USD/day) Oil price (USD/barrel) Bunker (HFO-equivalent, USD/ton Bunker (Gas, USD/mmBTU) , 15,9 21,348 26,796 32,244 37,692 43,14 2, 17,329 22,777 28,225 33,673 39,12 44,568 3, 18,757 24,25 29,653 35,11 4,549 45,997 4, 2,186 25,634 31,82 36,53 41,978 47,425 5, 21,615 27,62 32,51 37,958 43,46 48,854 6, 23,43 28,491 33,939 39,387 44,835 5,283 7, 24,472 29,92 35,367 4,815 46,263 51,711 8, 25,9 31,348 36,796 42,244 47,692 53,14 9, 27,329 32,777 38,225 43,673 49,12 54,568 Source: DNB Markets 34

35 Dayrate (assumed at parity, USD/day) Dayrate (assumed at parity, USD/day) Dayrate (assumed at parity, USD/day) DNB Markets 8 September 216 Daily savings TFDE vessel (16k cbm) versus old turbine powered vessel (13k cbm) (USD/day) Oil price (USD/barrel) Bunker (HFO-equivalent, USD/ton Bunker (Gas, USD/mmBTU) , 25,927 34,889 43,851 52,813 61,775 7,737 2, 28,235 37,197 46,159 55,121 64,82 73,44 3, 3,543 39,55 48,466 57,428 66,39 75,352 4, 32,85 41,812 5,774 59,736 68,698 77,66 5, 35,158 44,12 53,82 62,44 71,5 79,967 6, 37,466 46,428 55,389 64,351 73,313 82,275 7, 39,773 48,735 57,697 66,659 75,621 84,583 8, 42,81 51,43 6,5 68,967 77,929 86,89 9, 44,389 53,351 62,313 71,274 8,236 89,198 Source: DNB Markets Daily savings TFDE vessel (16k cbm) versus modern turbine powered vessel (14k cbm) (%) Oil price (USD/barrel) Bunker (HFO-equivalent, USD/ton Bunker (Gas, USD/mmBTU) , 25 % 3 % 35 % 38 % 42 % 44 % 2, 23 % 28 % 32 % 36 % 39 % 42 % 3, 22 % 27 % 3 % 34 % 37 % 39 % 4, 21 % 25 % 29 % 32 % 35 % 37 % 5, 21 % 24 % 28 % 31 % 33 % 36 % 6, 2 % 24 % 27 % 29 % 32 % 34 % 7, 2 % 23 % 26 % 28 % 31 % 33 % 8, 19 % 22 % 25 % 27 % 3 % 32 % 9, 19 % 22 % 24 % 27 % 29 % 31 % Source: DNB Markets Daily savings TFDE vessel (16k cbm) versus old turbine powered vessel (13k cbm) Oil price (USD/barrel) Bunker (HFO-equivalent, USD/ton Bunker (Gas, USD/mmBTU) , 4 % 49 % 57 % 63 % 68 % 73 % 2, 38 % 46 % 53 % 59 % 64 % 68 % 3, 36 % 44 % 5 % 55 % 6 % 64 % 4, 35 % 42 % 47 % 52 % 57 % 61 % 5, 34 % 4 % 45 % 5 % 54 % 58 % 6, 33 % 38 % 43 % 48 % 52 % 56 % 7, 32 % 37 % 42 % 46 % 5 % 54 % 8, 31 % 36 % 41 % 45 % 48 % 52 % 9, 31 % 35 % 4 % 43 % 47 % 5 % Source: DNB Markets Daily savings TFDE vessel (16k cbm) versus modern turbine powered vessel (14k cbm) (USD/day), excluding size savings Oil price (USD/barrel) Bunker (HFO-equivalent, USD/ton Bunker (Gas, USD/mmBTU) Difference 5,92 9,837 13,772 17,77 21,642 25,577 Source: DNB Markets Daily savings TFDE vessel (16k cbm) versus old turbine powered vessel (14k cbm) (USD/day), excluding size savings Oil price (USD/barrel) Bunker (HFO-equivalent, USD/ton Bunker (Gas, USD/mmBTU) Difference 9,5 15,84 21,118 27,151 33,185 39,219 Source: DNB Markets 35

36 8 September 216 FSRU market We continue to consider floating storage and regasification terminals (FSRUs) to be an attractive sub-sector of LNG shipping. While the segment s fleet totals 25 vessels on-water and four on order, we expect solid growth and continued attractive rates. Since 28 about 4% of the total growth in regasification capacity is in the FSRU segment and we expect this to grow further as FSRUs generally are cheaper, more flexible, less environmentally challenging and have shorter time to market compared with land-based facilities. We estimate that a 12% ROIC (unleveraged) is feasible for modern FSRU projects mid-term for 1-year contracts, with lower returns for longer durations (ROIC 11% for 2 years). FSRU project rates suggest annual EBITDA of cusd38m 4m, or cusd12k 13k/day for a newbuild FSRU on a 1-year charter. Also, additional capex for mooring arrangements and equipment is often paid through higher dayrates. To compare FSRU projects and earnings, capex is highly relevant on a like-for-like basis. Solid growth in number of new projects expected. Although visibility on future growth in this space is limited, we believe that up to 15 3 FSRU projects could be awarded within the next five years. To understand the sample space: the 96m tonnes of added liquefaction capacity we expect until 218 could translate to 15 3 FSRUs (assuming 3 6mtpa capacity for each) and on top of that we expect 26m tonnes to roll off contracts, adding potential for another 4 9 FSRUs. The upper limit of 39 units implied by this corresponds well to the talk of about 4 FSRU projects currently discussed in the market place. At its Q2 update Höegh LNG management guided for total market growth of 4 units in 216. Given that two contracts are awarded YTD, this implies another two awards during the remainder of 216. High barriers to entry. There are only five FSRU operators so far: Exmar Group/ Excelerate, Golar LNG and Höegh LNG (all of which have vessels on-water), as well as GDF (which leases two from Höegh LNG and has one under construction with MOL), and BW Gas (which has ordered two units to be delivered in 216). An FSRU project is in reality infrastructure, where the FSRU service provider operates the asset over the life of the project. The up-time of the installation is important in a chain perspective, as LNG is to a large degree used for power generation. Power plant outages are costly, and the cost of the FSRU component in the value chain is limited; hence the incentive for a charterer to choose a high-quality, solvent, provider. Most FSRU tender projects require pre-qualifications with regard to technical solutions and experience in the sector. Fairly low contract risk, FSRUs can be used for new contracts. Most FSRU contracts are with government-backed utilities or strong long-term industrial players. We believe these have an inherent incentive to keep the FSRU on contract, given the critical role the asset plays in the value chain. FSRUs can be redeployed to new contracts as the LNG is uniform. Some modifications might be needed to fit local demand, and not all are good matches in terms of size, regasification capacity, and operating conditions. Most of the FSRU fleet can also be operated as LNG carriers. What is an FSRU? The industry standard for the receiving end of the LNG transportation system is land-based regasification facilities. However, in the past decade floating regasification facilities have been commissioned, known as floating storage and regasification units (FSRUs). These are in essence LNG vessels equipped with heat exchangers and gas transfer systems, albeit with more complex power systems, fire extinguishing systems, and regasification equipment. The first was Excelerate Energy s facility in the Gulf of Mexico, which started operation in 25. Several advantages of FSRUs over land-based installations The advantages of FSRUs over land-based installations include: They are mobile, and can be moved if demand changes or when demand is seasonal. They do not have to be built locally, reducing construction costs and risks. They have shorter construction times, typically <3 months for a newbuild versus 5 7 years for a land-based facility. If the vessel is under construction, even shorter lead-times are possible. 36

37 8 September 216 They are less capital-intensive. The delivered cost of a newbuild FSRU is from cusd285m, plus extra for higher send-out capacities, trading capacity, moorings, piping and installation. They can be located offshore, to limit political opposition to construction and lack of available land. They have flexibility/scalability capacity can be deployed by using several FSRUs. For developing countries in particular, FSRU installations require less local competency, and can be completed more quickly. The expected cost of a moored FSRU is about half (or less) that of a comparable onshore facility, although onshore facilities are normally larger. An industry rule of thumb is that land-based facilities cost upwards of USD1bn. The typical regasification cost for LNG is USD.3.4/mmBTU, which includes storage of the LNG at the receiving facility. About 95% of all regasified volume is processed at land-based facilities, and 5% on floating storage and regasification units (FSRUs). To illustrate, an FSRU with regasification capacity of 5kcbf/day (3.7mtpa) would cost USD.3/tonne including fuel costs at 1% utilisation at USD13,/day. FSRU order book and fleet The segment s order book is eight newbuilds, according to Clarkson. The FSRU fleet including combined LNG carriers/fsrus (shuttle re-gas vessels, SRVs) is 24 vessels. Exmar Group/Excelerate started off the FSRU segment in 25, followed by Golar LNG in 27. Golar LNG s business started out as converted LNG carriers. FSRU orderbook Name Owner Builder Order date Delivery Months from date ordering to delivery Price (m USD) GNL del Plata Mitsui O.S.K. Lines Daewoo (DSME) 6-jan jun N/B Daewoo (DSME) Geoje 2489 BW Gas Daewoo (DSME) 25-sep nov N/B Hyundai HI (Ulsan) Ulsan 2552 Hoegh LNG Hyundai HI (Ulsan) 6-nov mar N/B Hyundai HI (Ulsan) Ulsan 2854 Gazprom Hyundai HI (Ulsan) 1-mai nov N/B Samsung HI Geoje 2118 BW Gas Samsung HI 29-nov nov N/B Samsung HI Geoje 2189 Golar LNG Samsung HI 17-jul des N/B Zhoushan/Exmar Exmar Offshore Zhoushan Wison 11-feb feb Penco-Lirquen (Octopus) FSRU Hoegh LNG Hyundai HI (Ulsan) 1-jun mar Source: Clarksons FSRU descriptions Hough Grace The FSRU construction charter was awarded in November 214. The vessel was built by Hyundai Heavy Industries Co., Ltd in South Korea and delivered on 31 March 216. It is owned and operated by Höegh LNG and chartered to Sociedad Portuaria El Cayao S.A. E.S.P. (SPEC) on a 5-year contract. The vessel will be based in Colombia at the Cartagena LNG import terminal, but is currently operating as a LNGC. The vessel has a throughput capacity of 4. Mtpa and a storage capacity of 17,m 3. The Höegh Grace is powered by a Wärtsila-Hyundai dual fuel diesel electric (DFDE) propulsion engine and has a Mark III Membrane containment system. It is expected that the vessel will be operational in Colombia in November 216 and the gas produced is expected to go towards the power market in Colombia. Höegh Independence Höegh LNG was awarded the FSRU contract on 2 March 212 and the Höegh Independence was finished and delivered in May 214. It was built by Hyundai Heavy Industries Co., Ltd in South Korea and started operating in December the same year. The vessel is currently anchored in the Port of Klaipeda where it is charted by Klaipedos Nafta on a 1-year contract. Höegh Independence started operations on 3 December 214 and has a throughput capacity of roughly 3.1 Mtpa and a storage capacity of 17,m 3. It is powered by a Wärtsila-Hyundai 37

38 8 September 216 dual fuel diesel electric (DFDE) propulsion engine and uses a Mark III Membrane containment system. The vessel is both owned and operated by Höegh LNG. Höegh Gallant On 12 May 214, Höegh LNG was awarded the FSRU contract and the Höegh Gallant was finished and delivered in November 214 after being built by Hyundai Heavy Industries Co., Ltd in South Korea. It has been operational since late April 215 on a 5 year charter with the Egyptian Natural Gas Holding Company (EGAS). On 13 August 215, Höegh LNG sold the ship to Höegh LNG Partners LP. The vessel is located in Ain Sokhna, Egypt and has a throughput and storage capacity of 4.2 Mtpa and 17,m 3, respectively. Although the Höegh Gallant was sold to Höegh LNG Partners LP, it is still operated by Höegh LNG. The ship is powered by a Wärtsila-Hyundai dual fuel diesel electric (DFDE) propulsion engine and uses an open-loop system, which uses the heat from pumping sea water to vaporise the liquid natural gas in the regasification process. Similar to the Independence, the ship uses a Mark III Membrane containment system. The gas produced is used to secure gas supply for households in Egypt. GDF Suez Cape Ann The ship was built and delivered in June 21. It is owned by Höegh LNG Partners (5%) and MOL (48.5%) and Tokyo LNG Tanker Co. Ltd (1.5%). It is chartered to Engie ex. GDF Suez on a 2-year contract with an option for 5 or 1 more years since 3 November 213. It was built by Hyundai Heavy Industries Co., Ltd in South Korea. The vessel will be employed as China s first FSRU stationed in Tianjin, China with seasonal deployment under a subcontract with China National Offshore Oil Corporation Gas & Power Ltd (CNOOC). It is currently located in Tianjin, however, according to CNOOC s general manager, they will postpone startup of the LNG terminals until after 22. It is therefore uncertain where or how the vessel will be used. The GDF Suez Cape Ann has a throughput capacity of roughly 6 Mtpa and a storage capacity of 145,m 3. Like the Höegh Grace and Gallant, the GDF Suez Cape Ann is powered by a Wärtsila-Hyundai dual fuel diesel electric (DFDE) propulsion engine, while it is also using a Mark III Membrane containment system. During the regasification process the ship uses a closed-loop system which utilises the heat from steam boilers to vaporise the liquid natural gas. The GDF Suez Cape Ann is equipped with a reinforced membrane-type cargo containment system that facilitates offshore loading operations. PGN FSRU Lampung The PGN FSRU Lampung is owned by Höegh LNG Partners LP and operated by Höegh LNG, and is located offshore in the Lampung province on the southeast coast of Sumatra, Indonesia and currently moored at an offshore purpose-built mooring system owned by PT PNG LNG. The vessel was built by Hyundai Heavy Industries Co., Ltd in South Korea and delivered to charterer PGN LNG in late April 214 and is currently on a 2-year contract with a possible 5 or 1-year extension. Operations started in July 214 and throughput capacity is roughly 2.9 Mtpa with a storage capacity of 17,m 3. Like Höegh s other FSRUs the PGN FSRU Lampung is powered by a Wärtsila-Hyundai dual fuel diesel electric (DFDE) propulsion engine. The vessel is also equipped for mooring to a tower yoke, which is a cost effective and reliable solution for permanently mooring in shallow water. Similar to the Höegh Gallant, the PGN FSRU Lampung uses an open-loop system to vaporise the liquid natural gas in the regasification process. Its cargo-containment system is of reinforced membrane, which facilitates offshore loading operations. GDF Suez Neptune The GDF Suez Neptune is the first of two ships in the Neptune project and was delivered on 3 November 29 from Samsung Heavy Industries and has, since then, been chartered to Engie ex. GDF Suez on a 2-year contract with a possible extension of years. The vessel is owned by Höegh LNG Partners (5%), MOL (48.5 %), and Tokyo LNG Tanker Co. Ltd (1.5%). The past year it has been operating as an LNGC between France and Spain. Throughput capacity is approximately 6 Mtpa and storage capacity of 145,m 3. The engine is powered by a steam turbine and uses a closed-loop system in the regasification process. Like the GDF Suez Cape Ann, the PGN FSRU Lampung, and the Höegh Gallant, the GDF Suez Neptune has a reinforced Mark III membrane-type cargo containment system that eases 38

39 8 September 216 offshore loading operations. The vessel is equipped with a submerged turret loading (STL) offshore mooring system, and can also be moored to a jetty. It also has a STL buoy system, and has also been retrofitted with high-pressure gas manifold on the side, which can be connected to loading arms on a jetty. In the regasification process it uses a close-loop system, which uses the heat from the steam boilers to vaporise the liquefied natural gas. Penco-Lirquen (Octopus) FSRU, Hull 2865 This is a new project that is expected to start operations in December 218. The vessel is owned by Höegh LNG and will be chartered to Octopus LNG SpA on a 2 year contract. It is being built by Hyundai Heavy Industries Co., Ltd in South Korea. It is expected that the ship will be employed in Penco-Lirquen in Chile where it will utilise its throughput capacity of approximately 4. Mtpa, or 5 million cubic feet per day. However, at commencement it will only deliver 25 million cubic feet per day. The vessel will have a storage capacity of 15,9m 3. It is expected that this vessel will use the Mark III containment system. Hyundai Ulsan, HN 2552 This is also a new vessel. It is expected to be delivered in Q1 217 and is owned by Höegh LNG. It is being built by Hyundai Heavy Industries Co., Ltd in South Korea, and will have a storage capacity of 17,m 3 and a throughput capacity of roughly 6 Mtpa. As of now, information about where this FSRU will be employed is not publicly known. Like many of Höegh s vessels, it expected that this ship will use a Mark III containment system. GNL Del Plata The vessel is owned by Mitsui OSK Lines and is currently being built by Daewoo Shipbuilding & Marine Engineering (DSME) in South Korea with expected delivery in mid-217. Once completed and delivered it will be the largest FSRU in the world in terms of storage, with a capacity of 263,m 3. In addition, it is expected that the vessel will be able to produce up to 4 Mtpa once it replaces the GDF Suez Neptune off Uruguay in November 216. The ship is chartered by the Uruguayan joint venture Gas Sayago for 2 years and will be located at Punta Sayago near the Uruguayan capital Montevideo. Although Uruguay does not have sufficient domestic gas demand to support a terminal, it can be used to supply the country s first gas-fired power station, while also exporting gas through pipeline to Argentina. GNL Del Plata is equipped with a GT NO 96 cargo containment system. Excellence The vessel was built by Daewoo Shipbuilding & Marine Engineering (DSME) in South Korea and has operated since 5 April 25. It is chartered by IEC and Israel Natural Gas Lines for 15 years. It is currently located at the Hadera Deepwater LNG Terminal in Israel. The project was implemented in under one year and a STL buoy system was re-located from the Gulf of Mexico to Israel offshore. The vessel has a throughput capacity of approximately 5.5 Mtpa and a storage capacity of 138,m 3. The Excellence s energy is powered by a steam turbine. Exquisite The Exquisite was built by Daewoo Shipbuilding & Marine Engineering (DSME) in South Korea and delivered to its owner Exmar in October 29. It has been chartered by Engro Corporation and is currently operating at the Port Qasim LNG terminal in Karachi, Pakistan. The vessel has a storage capacity of 151,m 3 and a throughput capacity of 5.5 Mtpa. The ship is powered by a steam turbine and is equipped with a GT NO 96 containment system. The gas produced by the Exquisite is used to remedy the large energy crisis in Pakistan. In 215 Pakistan started using LNG to fire up its power plants, trying to reduce its reliance on importing furnace oil and diesel, making the Exquisite an important asset. Expedient Expedient is owned by Excelerate energy and built by Daewoo Shipbuilding & Marine Engineering (DSME) in South Korea. The vessel has been chartered to Yacimientos Petrolíferos Fiscales (YPF). It was delivered in April 21 and is currently located at the GNL Escobar import terminal in Argentina, where it in November 215 replaced Excelerate Energy s Exemplar after being employed in Israel since September 214. The vessel has a throughput capacity of approximately 5.5 Mtpa and a storage capacity of 151,m 3. The 39

40 8 September 216 engine is powered by a steam turbine and is using the containment system Membrane GT NO 96. Exemplar The vessel Exemplar is currently employed at the Bahia Blanca Gasport LNG terminal. It was built by Daewoo Shipbuilding & Marine Engineering (DSME) in South Korea and is owned by Excelerate Energy. The vessel is operated by Exmar, and chartered to YPF. It has a storage capacity of 151,m 3 and is able to regasify approximately 5.5 Mtpa, or 69 Mmcf per day. The ship uses a Membrane GT NO 96 containment system while its engine is powered by a steam turbine. Experience The Experience was delivered on 6 May 214 and is being chartered by the Brazilian energy company, Petrobras, on a 15 year charter. The ship was built by Daewoo Shipbuilding & Marine Engineering s (DSME) at the Okpo Shipyard in South Korea and operations started in May 214. The vessel is currently employed at Pecém Regasification Terminal, where it utilises its market-leading send out capacity of approximately 8 Mtpa, or 1 Bcf of gas per day. The Experience also has storage capacity of 173 4m 3, while the engine is powered by a dual fuel diesel electric (DFDE) propulsion engine. The ship uses the GT NO 96 containment system of reinforced membrane, which facilitates offshore loading operations. Excelsior The vessel is owned by JV Exmar (5%) and Teekay LNG Partners L.P (5%) and was delivered in January 25 to Excelerate energy on a 2 year charter running until 225 with a 1 year option. It was built by Daewoo Shipbuilding & Marine Engineering s (DSME) at the Okpo Shipyard in South Korea. The Excelsior was the world s first vessel of its kind, changing the future of the LNG industry. It is currently employed in Brazil with the end user being Petrobras. The Excelsior has a throughput capacity of approximately 5.5Mtpa, or 69 million cubic feet per day, and a storage capacity of 138,m 3. This makes it one of the smaller FSRU vessels in the market in terms of storage capacity. Like many of the other vessels either owned or chartered by Excelerate Energy, the Excelsior is powered by a steam turbine, while it is using the containment system Membrane GT NO 96. Excelerate The vessel is owned in JV by Exmar (5%) and Excelerate Energy (5%) and was delivered in October 26. It is on a 2 year charter with Excelerate Energy with a 1 year option to extend. The vessel was built by Daewoo Shipbuilding & Marine Engineering s (DSME) at the Okpo Shipyard in South Korea and started operations in late October 26, only a few days after being delivered. The vessel is used on spot trade and is currently located in the United Arab Emirates after being employed in Pecem, Brazil and Cape Town, South Africa for some time earlier this year. In July last year it took part in providing Pakistan its first ship to ship transfer in Karachi. Like the Excelsior, the Excelerate has a throughput capacity of 5.5 Mtpa, or 69 million cubic feet per day, while it is able to store 138,m 3 of gas. The Excelerate is equipped with a Membrane GT NO 96 cargo containment system. Explorer The vessel was delivered in March 28 after being converted into an FSRU from a LNG carrier by built by Daewoo Shipbuilding & Marine Engineering s (DSME) at the Okpo Shipyard in South Korea. The vessel is owned in a joint venture between Exmar (5%) and Excelerate Energy (5%), while Excelerate Energy is also chartering the ship on a 25 year contract. The end user is Dubai Supply Authority (DUSUP) which operates the LNG terminal in Jebel Ali where the Explorer is currently employed. Dubai Supply Authority (DUSUP) and Excelerate Energy signed a long-term time charter party agreement in 214 for the vessel to replace the existing FSRU, as the demand for gas in Dubai has increased. Under the agreement, Excelerate upgraded the Explorer FSRU. The Explorer entered dry-dock in October 215 and the modifications was completed in December 215. The vessel has the largest throughput capacity in the FSRU industry with approximately 8 Mtpa, or 1 billion cubic feet per day. Despite of its large throughput capacity, the vessel is only able to store 15,9m 3 in its tanks. The Excelerate is equipped with a Membrane GT NO 96 cargo containment system. 4

41 8 September 216 Express The Express was built in 28 by Daewoo Shipbuilding & Marine Engineering s (DSME) at the Okpo Shipyard in South Korea and delivered on 11 May 29. It is owned in JV by Exmar (5%) and Excelerate Energy (5%). The vessel is chartered for 25 years by Excelerate Energy with the end user being Yacimientos Petrolíferos Fiscales (YPF) and the Bahia Blanca Gasport in Argentina. However, according to its last reported position, the vessel is now located outside of Hadera, Israel and has been for some time. The Express has a throughput capacity of 5.5 Mtpa, or 69 million cubic per day. It has a storage capacity of 15 9 m 3 while it is using the Membrane GT NO 96 containment system to store the gas. Like many of Excelator s ships, the Express is power by a steam turbine. N/B Zhoushan/Exmar This is a vessel that is under construction today. Although there is very little public information on this vessel, we know that Exmar is registered as the owner with Exmar shipping management as the manager. Its expected storage capacity is only m 3 and the ship is being built by Zhoushan Wison in China. Golar Spirit Golar Spirit is the world s first FSRU conversion project which was awarded to Golar in April 27 by PetroBras, the majority state-owned oil and gas company of Brazil. The Golar Spirit was the first LNG carrier built in Japan, and was from 1996 to 26 contracted for LNG shipment between Indonesia and South Korea. The decision to convert the vessel was taken in 25 and the vessel was converted in 28 at Keppel Shipyard in Singapore. Golar Spirit now gives PetroBras the ability to receive LNG from standard LNG Carriers and provide natural gas for domestic consumption. The vessel was delivered at Pecém in Brazil 22 July 28 and operations started in January 29. The contract between the two parties runs for 1 years until 218 with an option to prolong. The vessel holds a vaporisation system of direct stream in a closed loop, LNG storage capacity of 129,m 3 and vessel throughput capacity of 2.5bcm/y, which equates around 1.9mtpa. LNG transfer is executed over the jetty via loading arms fixed on the jetty and Gas transfer via high-pressure loading arms fixed on the jetty and the vessel has a Moss tank containment system. Golar Winter The Golar Winter was built in 24, and selected for conversion in 26. The decision to convert Golar Spirit was taken without a contract on the vessel. However, for Golar Winter negotiations with Petrobras resulted in a charter arrangement signed in April 27, before conversion started in September 28 at Keppel Shipyard in Singapore and the vessel was delivered in April 29 to Guanabara Bay, Rio de Janeiro. The original contact stated that Petrobras will charter the vessel for 1 years with the option of another 5 years. However, in conjunction with Petrobras wanting some modifications made to Golar Winter in 212, the option was executed and another 5 year option added to the now 15 year contract running till 224. The vessel has an LNG storage capacity of 138,m 3 with a Steam turbine in closed or open loop. Regasification capacity is 5.1 bcm/y or around 3.9mtpa and tank containment system is GTT NO96. LNG and Gas transfer is done via loading arms and high pressure loading arms, respectively, fixed on the jetty. Golar Freeze The Golar Freeze was built in 1997 and converted to a FSRU by Keppel Shipyard, Singapore in early 21. The Dubai Supply Authority (DUSUP) took charter on the vessel for 1 years till 22, with an option for a further 5 years. Golar Freeze was delivered in April 21 to Jebel Ali in Dubai, where it is permanently moored and operations started in Q4 21. The Golar Freeze is used by DUSUP to import gas to supply Dubai with electricity. The vessel holds a steam turbine and uses a vaporisation system of two-stage propane and seawater in open loop. LNG transfer is done side by side to the jetty via loading arms on the FSRU, while gas transfer through high pressure loading arms fixed to the jetty. Golar freeze s throughput capacity is 4. bcm/y or around 3.8mtpa, and vessel storage capacity is 125,m 3. The FSRU has a Moss tank containment system. 41

42 8 September 216 Nusantara Regas Satu The Nusantara Regas Satu was built in 1997 and later converted to a FSRU in 212 at the Jurong Shipyard in Singapore. It was delivered to its location in West java, Indonesia in May 212. The vessel is chartered by PT Nusantara Regas which holds a contract of 11 years lasting until 222 with the option to extend to 225. Golar LNG was awarded the FSRU contract in October 21; before the conversion. The FSRU holds a steam turbine and vaporisation system of open loop. Vessel storage capacity is 17,m 3 and throughput capacity is 7.5 bcm/y which equals around 5.8mtpa. PT Nusantara Regas buys gas from Mahakam PSC and sells the gas to Perusahaan Gas Negara (PGN), an Indonesian government-owned corporation which has monopoly on electricity distribution in Indonesia. Golar Igloo In August 213 Golar LNG was awarded with the 5 year FSRU time charter contract of Kuwait National Petroleum Company (KNPC). The vessel is located at the LPG plant Mina Al-Ahmadi in Kuwait, and contract commencement was in March 213. The Golar Igloo was built by Samsung Heavy Industries in South Korea and construction was finished in 214 and delivered to Golar in February 214.With tri-fuel diesel electric propulsion and open loop mode vaporisation system the vessel has a storage capacity of 17,m 3 and throughput capacity of 7.5 bcm/y (c5.8mtpa). Cargo containment system is TZ Mk.III. Golar Igloo is scheduled to operate during a nine month window that runs between 1 March and 3 November and has the ability to operate as a traditional LNG carrier the outstanding three months. Golar Eskimo The vessel was built in 214 by Samsung Heavy Industries in South Korea and commenced services in Q2 215 under a 1 year time charter contract with Hashemite Kingdom of Jordan (Jordan). The FSRU contract was awarded to Golar LNG in July 213 and the vessel was delivered to Golar in December 214 and arrived in Jordan end-may 215. Golar Eskimo is connected to the port of Aqaba and connects to the Jordan gas Transmission Pipeline that delivers natural gas to power plants in Jordan. The FSRU holds a tri-fuelled diesel electric propulsion and vaporisation system of open loop. Vessel storage capacity is 16,m 3, throughput capacity is 7.5bcm/y (c5.8mtpa) and the vessel holds a TZ Mark III containment system. Golar reported in June 215 that Golar Eskimo had, since commencement, produced at close to peak capacity. Golar Tundra In November 215, Golar executed an agreement with West African Gas Limited (WAGL) for the Golar Tundra to operate in a 5-year time charter, with the option to extend the charter for another 5 years. Golar originally expected the contract to commence Q2 216, depending on when the vessel would meet certain delivery criteria. In a more recent report Golar Partners stated that Golar Tundra will not commence its contract until after the end of Q2. Golar Tundra is constructed with tri-fuel diesel electric propulsion and open loop vaporisation system. Vessel storage capacity is 17,m 3 and throughput capacity is 7.5bcm/y (c5.8mtpa). N/B Samsung H.I./Golar In July 215, Golar LNG entered into a shipbuilding contract with Samsung for the construction of a new FSRU, expected to be delivered Q The vessel will be a sister vessel to the Golar Tundra, with vessel storage capacity of 17,m 3. BW Singapore Samsung Heavy Industries finished building the BW Singapore in 215 before BW Group was awarded the 5 year FSRU time charter contract with Egyptian Natural Gas Holding Co. (EGAS) in July 215. BW Singapore achieved a record fast-track FSRU project implementation with 5 months from project inception to fist gas sent out 1 November 215. The FSRU is permanently moored alongside a jetty in the Port of Ain Sokhna, Egypt. BW Singapore was constructed with dual fuel diesel electric propulsion and open loop vaporisers. Vessel storage capacity is 17,15m 3 and the maximum LNG throughput capacity is 4.5mtpa. BW Singapore receives an LNG cargo every 5 to 6 days and will primarily be used to supply natural gas to the local fertiliser industry. 42

43 8 September 216 BW Integrity August 216 BW Group was selected as FSRU supplier by Pakistan GasPort Limited (PGPL) with its BW Integrity scheduled to be delivered in November 216 to BW group. The FSRU is a sister vessel of BW Singapore and holds similar specifications; storage capacity of 17.15m 3, maximum LNG throughput capacity of 4.5mtpa, dual-fuel diesel engine and openloop regasification system. The contract runs for 15 years and the project is expected to be commissioned by 3 June 217 at Port Qasim, Karachi. The project will ensure fuel for new power plants being constructed in Pakistan. BW Group also has an order with DSME for another FSRU expected to be delivered in November 219. FSRU Toscana FSRU Toscana was converted from LNG carrier Golar Frost after it was acquired by OLT in July 28. The vessel is operated by ECOS (JV between Exmar Ship management and Fratelli Cosulich SPA) and NERI and permanently anchored offshore outside Livorno, Italy. The FSRU holds a steam turbine engine, a vessel storage capacity of 137,5m 3 and a Moss tank containment system. The LNG throughput capacity is 3.75bcm/y (2.9mtpa). The FSRU has been designed to remain on location for 2 years without the need for dry-docking. N/B Hyundai HI Ulsan 2854 Gazprom ordered in 215 an FSRU of max capacity 174,1cbm/y from Hyundai Heavy Industries. The vessel will be delivered in November 217 and supply natural gas to the Kiliningrad Region of Russia. Depending on demand the vessel will be deployed as FSRU, an LNG-delivery shuttle or a conventional LNG carrier. It will be the world s first ice-class FSRU, meaning it will be fitted with anti-ice equipment, allowing it to operate in temperatures down to -3 C. The vessel s containment system will be GTT Mk.III Flex and it will have tri-fuel diesel electric propulsion. 43

44 8 September 216 FLNG market Floating LNG production units began operating in 211 and another two units were ordered in 212, and interest by companies and investors has since grown. The order book is seven vessels. We expect interest to continue to grow, in particular from owners of stranded gas, as the technology becomes proven and the cost and location benefits are realised. We expect FLNG production to be among the lowest cost providers of LNG liquefaction services, which should support contract awards. There are considerable differences between FLNG orders, e.g. the unit ordered by Shell is a fully fledged offshore LNG production unit, including facilities for 3.6mtpa of LNG, 1.3mtpa of condensates, and.4mtpa of LPG while Exmar s FLNG barges are expected to produce about.5.6mtpa. Concepts The FLNGs scheduled for completion differ in many respects: 1) the intended ownership of gas versus pure timecharter rate profile for the ship-owner; 2) whether the vessel has offshore capabilities or will simply be an inshore moored barge; 3) to what extent the vessel can clean gas or accept only pipeline quality gas; 4) whether the vessel can handle heavier gas components, i.e. condensates and LNG; 5) the vessel s storage capability; 6) newbuild versus conversion; and 7) the vessel s production cost. Construction The technical complexity of the FLNGs being built varies greatly. Fully fledged projects are built as barges, where the components of a land-based site are adjusted to fit on to a floating device. Smaller projects are either built on barges, or by converting an existing LNG carrier or carrier design. One advantage of conversion over newbuild is cost efficiency. One drawback is that the topside will be constrained by the existing hull, reducing flexibility in construction and output capacity when completed. Conversion of one LNG carrier is being done by Keppel Corporation, on contract for Golar LNG. Similar conversions turned out to be successful for the regasification terminals, which were also rebuilds of LNG carriers. Capabilities The FLNGs being constructed will be utilised differently. Shell s Prelude will be able to extract and process condensate and LNG in addition to the LNG output. The annual output of condensate and LNG is as much as 1.3mtpa and.4mtpa, respectively, and industry sources indicate that the total profitability of the project depends on the sales of these liquids. The Petronas FLNG will have the ability to produce and store condensate. As for Höegh LNG, the company started out along the same lines, designing fully fledged offshore FLNG vessels with cleaning capabilities. However, it has changed the concept, and increasingly sees more market opportunities in the lower-hanging fruit segments, i.e. inshore production barges or vessels for benign met-ocean areas. This will limit the potential use of the vessel, but should keep down cost and complexity. Flex LNG focuses on the smaller end of FLNGs, with intended production volumes of.5 1.2mtpa. Cost The differences in the complexity of the FLNGs obviously results in quite considerable cost differences. Fully fledged units in particular Prelude have seen considerable cost overruns and may now be in excess of USD3,/tonne annual LNG production capacity. The cost guidance for the in-shore FLNG concepts Golar LNG we estimate ~USD5/tonne annual LNG production capacity. This cost-base compares with upward trending liquefaction cost for land-based facilities. While the large Qatari Qatargas and Rasgas LNG projects could be realised at a cost of cusd4/tonne annual production capacity, the figures for recent projects such as Australia Pluto LNG, Gladstone LNG and Queensland Curtis have been triple this at USD1,2/tonne, while there have been extreme cases of Gorgon at USD1,8/tonne and Snøhvit LNG at USD2,/tonne. 44

45 Cost (USD/tonne per annum) Commercial breakeven (USD/mmBTU) DNB Markets 8 September 216 Total delivered gas price required for economic breakeven (USD/mmBTU) Greater Gorgon APLNG Gladstone LNG Brass LNG Queensland Curtis LNG 15 Greater Sunrise LNG Elk/Antelope Evans Shoal LNG Canada Angola LNG Wheatstone LNG 14 PNG LNG Nigeria Train 7 WCC LNG Browse LNG Ichtys Leviathan LNG Prelude 13 Cove Point LNG Kitimat LNG Shtokman Pacific Northwest LNG Sabine Pass Mozambique LNG Freeport LNG Tanzania LNG Yamal LNG Prince Rupert LNG 12 Cameron LNG Lake Charles LNG 11 1 Sakhalin LNG 9 FLNG Cumulative gas production (mtpa) Source: DNB Markets, Golar LNG, Goldman Sachs Note: Non-producing and recent LNG assets, North American projects in bold Abadi LNG LNG liquefaction facility capex (USD/tonne annual capacity) cost versus start-up year 2 Snøhvit 18 Gorgon 16 Ichtys Kenai Brunei MLNG Angola Pluto Donggi NWS NLNG exp Sabine Pass NLNG Yemen Peru ELNG 1 Darwin Lavaca Barge QG1 Atlantic 1 MLNG Exp Oman QG2 QG3 MLNG T9 RG3 Atlantic 2&3 ELNG 2 FLNG QC APLNG Gladstone PNG Start-up year Source: DNB Markets, Höegh LNG, IHS Cera Marginal price of gas for FLNG projects likely lower than Henry Hub The pricing of stranded gas (the most likely source of demand for FLNG services) is likely to be lower than HH pricing. In our view, a lower marginal cost of stranded gas than HH would allow pricing in Asia equivalent to the price difference plus transportation (and possibly from cheaper liquefaction), implying improved profitability for the upstream gas owner and hence greater willingness to pay for liquefaction services. 45

46 8 September 216 Appendix: Introduction to the LNG market The LNG value chain can be described in five steps, of which the three discussed in this report are directly relevant to companies in the LNG shipping sector. LNG value chain Natural gas extraction Liquefaction Shipping Regasification Consumption Source: DNB Markets Gas extraction. Natural gas extracted from the ground, both as associated gas to oil production and as non-associated gas from conventional fields, and various nonconventional sources, in particular from coal-beds and shale. Liquefaction. LNG is created by cooling natural gas to minus 161 degrees Celsius, turning the gas to liquid. By volume, LNG shrinks to about 1/6 th of its gaseous state. This process is technically challenging and energy-intensive (requires about 1/1 th of the energy of compressed gas), and requires significant capex to create capacity. However, the process makes it possible to transport the gas. In addition to the cooling, the gas needs to be prepared: water, gases such as CO 2 and H 2S, and trace amounts of mercury need to be removed. LNG liquefaction can be done on-board a purpose-built vessel (FLNG), ranging from barges purpose-built for handling pre-treated gas in inshore locations to fullfledged offshore FPSOs with gas stream processing and condensate and LPG treatment. Shipping. A modern tri-fuel LNG carrier tends to be 155, 175,m 3, up from c13,m 3 ten years ago. Two other classes exist, the Q-flex (21,m 3 ) and Q-max (26,m 3 ), but these are operated only from Qatar by Nakilat for Rasgas and Qatargas. A new standard LNG carrier costs about USD19m 195m yard price, cusd21m delivered. Regasification. LNG is reheated and returned to its gaseous state. This can be done in a land-based facility or on-board a vessel. For the latter, the vessel might transport the gas itself (SRV the way this market started out) or be permanently moored (FSRU which has become industry standard). Consumption. Natural gas delivered as LNG is primarily used for power generation. Traditionally, natural gas was difficult to transport due to its low-energy density, limiting trade to regional markets. It is not economical to transport gas by pipeline over distances of more than 3, 4,km overland or c1,2km over water. The emergence of LNG liquefaction and regasification capacity has allowed global trade of natural gas and arbitrage between regional gas markets. LNG contract terms have by convention been 2+ years, where dedicated vessels have been contracted for the purpose. The past five years have seen shorter contracts (1 4 years), with some down to a few months. We estimate that 25% of all cargoes go on vessels chartered for less than four years. However, there is still no well-functioning spot market as the number of trades is too low c5% of the fleet is trading in single voyage trades, hence this market is highly sensitive to small changes in vessels made available versus additional cargo volumes. LNG liquefaction industry trends Moving forward, the output of LNG is likely to grow substantially. Below we give an overview of the technical and engineering trends in the LNG market. Train size The size of shore-based trains has increased with a typical capacity of a land-based liquefaction train is now 4.5mtpa. This is larger than trains produced in the 198s, which was closer to 1mtpa. An executive industry professional tells us that it would be technically feasible to build a train with capacity of 13mtpa. However, this is not economically lucrative, because we will see very limited competition in the supply of these huge trains, which will lead to inflationary prices. Also, the construction of a 13mtpa train would lead to a skewed risk allocation towards 46

47 8 September 216 a single production line. Building on this, our impression is that the future capacity of the trains is expected to be somewhat stable, at close to 5mtpa. In terms of production flexibility, several firms are investigating whether it makes sense to build five 1mtpa trains instead of one 5mtpa train. For instance, we see many players who target building trains of.5 1.2mtpa with Black & Veatch technology, which have a hydrocarbon-based cooling process. A key benefit of having multiple trains instead of one large train is that maintenance can be done on one while the others are running. With one large train, all production must be shut down to start maintenance. Energy production and consumption Energy demand at liquefaction plants generally stems from the large amount of compressors involved in the process. At shore-based terminals, it is common to use large gas turbines to run the plants. On an FLNG operating offshore, you rather use smaller aero-derivative turbines for cost and weight reasons. Energy use for cooling the gas will vary with the location of the unit. For land-based terminals in warm areas, the process of cooling the gas occupies about 1%+ of total expenses. This figure is closer to 6 7% in Arctic areas. For the Sakhalin and Snøhvit LNG production sites, this is a cost advantage, as the energy consumption is reduced. For cooling the gas at FLNGs, most of the units currently in construction will take advantage of cold sea water to cool and prepare the liquefaction process. Investment cost per mtpa of capacity The cost of the land-based plants is dependent on the inflationary pressures in the region of the proposed plant, the complexity of the regulatory process, the existing infrastructure and other factors. Investment cost varies dramatically between regions. This is seen particularly in the difference between US brownfield plants (investment cost of <USD1,/tonne of annual capacity) and greenfield sites in Australia (new projects have reportedly passed USD3,/tonne). Small-scale FLNG costs have been estimated to <USD5/tonne for Golar conversions, and up to USD8 9/tonne for more complex FLNG newbuilds. 47

48 8 September 216 Appendix: Liquefaction capacity survey Below we give an overview of global liquefaction capacity, with data collected during summer 216. Most liquefaction plants we approached are already producing or are at an advanced stage of construction, and the base case for our trade forecast (see earlier) uses producing facilities and projects under construction (i.e. those that have undertaken a FID and started work on the ground). The data is predominantly collected from our talks with operating managers, IR, and external contact managers, and in some cases we have used publicly available sources. All figures are million tonnes per annum (mtpa) unless otherwise stated. Data was collected from companies that we estimate had 215 combined exports of 246m tonnes, which is similar to the total 215 export estimates from GIIGNL (245.2mt) and IGU (244.8mt); hence we believe this survey covers all existing liquefaction facilities globally. Algeria Existing and planned projects in Algeria Project name Project owner Type Start-up Nominal capacity (mtpa) GL1Z Complex Arzew Sonatrach Shore-based GL2Z Complex Arzew Sonatrach Shore-based GL1K Complex Skikda Sonatrach Shore-based GL1K Complex Rebuild Sonatrach Shore-based GNL3Z Arzew Sonatrach Shore-based Source: DNB Markets Algeria is one of the world s largest LNG exporters, exporting c12.1mt in 215 (12.8mt in 214). In our 215 report we expected a rise in exports that year due to the introduction of its new LNG production train in November 214. However, we actually saw a.7mt decrease. Algerian LNG exports are still suffering from low utilisation, and a lack of foreign investment in its gas sector means it continues to extract gas from old fields. Most foreign investors have steered clear, owing to unattractive fiscal terms and security concerns. Production at Algerian fields has risen over the past decade, but domestic demand keeps export trains from running at full capacity, and full capacity is not expected given the dated infrastructure. We believe Algeria will remain a significant player in the future with the rebuilding of the GL1K complex. However, this is dependent on the LNG plant receiving sufficient gas to export at capacity. Thus, we have trimmed our estimates to what we expect will be produced in the coming years. Angola Existing plant in Angola Project name Project owner Type Start-up Nominal capacity (mtpa) Angola LNG T1 Soyo Chevron JV Shore-based Source: DNB Markets Angola exported.33mt in 214 from its new LNG terminal, which started in June 213. In 214 it faced a shutdown due to a rupture on a flare line, as well as several fires, leaks, and mechanical problems. These issues caused the plant to run at about half capacity until the shutdown, delivering only four cargoes in 214. In 215 Chevron reported that the plant was expected to re-start production by end-215, with full production expected in 216 onwards. However, it remained offline until June 216 when it had its first export after the closure. According to the company, the ramp-up schedule after the restart will be based on performance. At full capacity it expects 7 cargoes to be exported each year. Chevron has a c37% stake in the plant; Angolan state oil firm Sonangol, Total, BP, and ENI own the rest. 48

49 8 September 216 Australia Existing and planned projects in Australia Project name Project owner Type Start-up Nominal capacity (mtpa) North West Shelf Project T1 Woodside, Shell, BHP, BP, Chevron Shore-based NWS T2 Woodside, Shell, BHP, BP, Chevron Shore-based NWS T3 Woodside, Shell, BHP, BP, Chevron Shore-based NWS T4 Woodside, Shell, BHP, BP, Chevron Shore-based NWS T5 Woodside, Shell, BHP, BP, Chevron Shore-based Pluto LNG T1 Woodside, Kansai, Tokyo Gas Shore-based Darwin LNG T1 Woodside, ENI, Santos, INPEX++ Shore-based Queensland Curtis LNG T1 BG Group, CNOOC Shore-based Queensland Curtis LNG T2 BG Group, CNOOC Shore-based Australia Pacific LNG T1 T2 Origin, ConocoPhillips, Sinopec Shore-based Gladstone LNG T1 T2 Santos, Petronas, Total, KOGAS Shore-based Gorgon T1 T3 Chevron, Shell, Exxon Mob++ Shore-based Gorgon T4 Chevron, Shell, Exxon Mob++ Shore-based Unknown 5.2 Wheatstone T1 T2 Chevron, KUFPEC, Woodside, Kyushu++ Shore-based 217e 8.9 Ichthys T1 T2 INPEX, TOTAL Shore-based 217e 8.4 Prelude Shell, INPEX, CPC, KOGAS FLNG 218e 3.6 Bonaparte Engie Shore-based 221e 2.4 Fisherman's landing T1 T2 Liquefied Natural Gas limited Shore-based Unknown 3.8 Browse Woodside, Shell, BP++ FLNG Unknown 11.7 Scarborough Esso Australia (ExxonMobil) and BHP FLNG Unknown 6.5 Crux Arrow T1 T4 Source: DNB Markets Shell, Nexus, Osaka Gas, Shell, PetroChina FLNG Shore-based Australia has been an LNG player since 1989 when Woodside started production on its North West Shelf project, benefiting from its close proximity to large Asian gas importers such as Japan, South Korea, and Taiwan. During the past decade, we have seen a surge in proposed projects, but economic realities hit home and many proposed projects are unlikely to be realised near-term. In June, LNG exports from Australia hit a new high at 3.6mt exported. The main issue is inflation, driven by high and rising wages. Construction at mega sites (e.g. 15.6mtpa Gorgon) are magnets for labour and equipment, inflating the cost of constructing another project at the same time. The shelving of many large projects (e.g. Browse, Fisherman s Landing, Arrow) was due to inflationary pressure and unfavourable market conditions. Costs are increasingly important given the sharp decline in LNG prices, and the companies we talked to reported that they are highly selective on FIDs. Aggregating the projects in the FEED/construction phase, Australia has taken huge steps in strengthening its position in LNG. In 215 and early 216 Gladstone LNG, Australia Pacific LNG, and Gorgon came online, adding more than 32mt of potential LNG capacity in Australia. We expect annual weighted production capacity to reach 76mtpa by end-217e (end mtpa), and the country looks set to overtake Qatar as the world s largest exporter of LNG in the next five years. It is unclear, however, whether this rapid growth will continue after the plants in the FEED/construction phase come online. There are still large untapped gas resources (from conventional fields and unconventional coal seam gas resources). That said, to maintain its position as a main LNG player, the country must address escalating costs to stay competitive. Liquefaction plants in Australia North West Shelf project The last train (4.6mtpa) built to liquefy gas from the North West Shelf was commissioned in 28, reaching total annual capacity of 16.3mtpa. In 215 capacity was raised to 16.9mtpa; it is now fully utilised and Woodside does not expect to expand the site in the next few years or decommission any trains. There is normally major maintenance for each train every four years (T1 was down for a month in 214). Compared with 214 (15.5mtpa), production fell slightly to 15.3mtpa in 215. According to the company, this was due to higher ambient Unknown Unknown Unknown 18 49

50 8 September 216 temperatures, cyclone activity, and lower reliability. However, exports increased.1mtpa versus 214. Pluto LNG This plant (also built and operated by Woodside) in Western Australia utilises gas from the Pluto field. Commissioned in 212, it is operating at maximum capacity of 4.7mtpa. However, nameplate capacity is 4.3mtpa, taking into account planned turnaround and maintenance. Production in 215 was 4.34mt, which is.31mt lower than in 214 due to maintenance in Q2. The liquefied gas is underpinned by a 15-year sales contract with large importers Kansai Electric and Tokyo Gas. Total capex was USD14.9bn, implying a cost of USD3,1/mt. This is close to the Australian average and significantly above that of the North West Shelf project. Browse FLNG We have paid close attention to Browse FLNG, as resources in the Woodside-operated Browse basin have been known for decades and USD2bn was spent studying the feasibility of a landbased terminal. However, the co-venture with Shell on the Prelude project (which we expected to come on-stream in 218) seems to have stalled. Browse FLNG completed the FEED phase in March; however, with its JV participants, Woodside has postponed the project awaiting a more favourable economic environment. The project s total cost has not been given, but annual production capacity was expected to be 11.7mtpa (subject to the number of FLNG vessels). Darwin LNG This ConocoPhillips-operated plant at Wickham Point in North Australia has been operating since 26 with production capacity of 3.5mtpa. 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 significantly lower cost (cusd5/tonne) than the country average. The plant is normally down for a month s maintenance every other year; the last time was in 214 so we expect maintenance again this year. In 214 Darwin LNG exported 3.1mt, primarily to Japan, while in 215 this rose to 3.5mt after reaching its highest production to date of 3.8mt. Queensland Curtis LNG The first cargo from this BG-operated plant was loaded in late December 214 and sent to China. The plant reportedly reached over 9% utilisation within a month of starting after BG initially said it would take six months to ramp up. The train has nameplate capacity of 4.3mtpa, but production is expected to be close to 4mtpa according to BG. The second train (4.3mtpa capacity with 4mpta production expected) shipped its first cargo (to CNOOC s regasification facility in China) last July. Even though train 1 ramped-up production quickly, train 2 took a little longer to reach plateau. Now that both trains have reached plateau they should produce enough to load 1 vessels monthly (mainly sold on long-term contracts to CNOOC and Tokyo Gas). Total investment for the project in was estimated at USD2.4bn, or USD2,4/tonne, slightly below the country average. The plant uses gas from the BG-owned wells in the Surat Basin, Eastern Australia. According to our estimates QCLNG exported c4.9mtpa of LNG in 215, which is slightly above 5% utilisation. We expect this to increase closer to plateau now that both trains have reached capacity. Australia Pacific LNG Australia Pacific LNG s upstream production is operated by Origin, while the downstream LNG facility is operated by ConocoPhillips. It aims to develop LNG from coal seam gas, sourced from the Surat and Bowen basins in Queensland. The plant will have two trains, totalling 9mtpa. The first cargo left the LNG facility on Curtis Island on 9 January, slightly later than the guided Q4 215 in last year s report. In June, APLNG started shipment to Kansai Electric Power, with which it has a 2-year sales and purchase agreement. This was its 27 th shipment. According to earlier estimates, steady production is to be reached by Q3 216 with the second train coming online in H2 216 with first cargo by year-end. A company representative told us it expects 217 production to run at full tilt, subject to the commissioning remaining on track. The total investment is estimated to be cusd24bn. Of the 5

51 8 September 216 9mtpa capacity, 8.6mtpa is tied up in long-term agreements with Sinopec and Kansai Electric. Although Origin has allowances to expand capacity, it has not yet committed to any plans. Gladstone LNG This is a two-train facility producing LNG from coal seam gas. At full capacity the plant should be able to produce 7.8mt of LNG per year. In line with estimates in last year s report (August 215), the first shipment of LNG from Curtis Island was 16 October 215, headed for South Korea. In 215, Gladstone LNG produced.544mt and ramp-up was expected to be completed by Q The first LNG from train 2 was at end-may and expected ramp-up is 2 3 years. The unusually slow production ramp-up for the second train is reportedly due to the owner securing sufficient offtake agreements. The project is a co-venture between Santos (operations), Petronas, Total, and KOGAS. Of the 7.8mtpa capacity, 7.2mtpa is tied to longterm agreements with Petronas and KOGAS. Capex has been estimated to USD18.5bn. Gorgon LNG This Barrow Island mega project is the largest single resource development ever constructed in Australia. It is operated by Chevron Australia, in a JV with ExxonMobil and Shell. When completed, there will be three, potentially four, trains of 5.2mtpa. After several delays, first export from train 1 occurred in March, but was shut down in mid-june due to minor repairs and maintenance. Operations resumed in late July and it is still expected that train 1 will reach full production late this year. The second train is expected to commence operations in Q4 this year, while needing an additional six months to ramp up to full production. The third train is targeted to come online in Q2 217 and reach full production six months later. Given the ramp-up schedule, we do not expect production at full capacity until 218. The capital cost is estimated to be USD54bn, giving a cost per metric tonne of USD3,5, well above the average even for Australia. In May Chevron received environmental approval from Australia for the potential expansion of a fourth train. However, this is still in an early planning stage. Wheatstone LNG Wheatstone is Chevron s other large-scale LNG project in Australia, of which it holds 64%. The facility is based at an industrial site close to Onslow in North West Australia. The plant will consist of two 4.45mtpa trains, with total capacity of 8.9mtpa. A FID was reached in 211 and in July this year Chevron reported that drilling was completed, but expected start-up has been postponed to mid-217 (from late 216) and train 2 in January 218. Of Chevron s 64% share, c85% of gas sales have been committed to Asian gas companies, notably TEPCO, Kyushu Electric, and Chubu Electric. The originally estimated project capex was USD29bn, but due to delays it could increase to USD33bn, leaving the cost per metric tonne higher than both Gorgon and the Australian average. The delay to expected first production has been partly due to the decision to build part of the project in Malaysia, but all modules required for train 1 are now onsite so we expect first production by mid-217. Wheatstone LNG plant under construction Source: LNG World News 51

52 8 September 216 Ichthys This project was initiated by the Japanese oil and gas giant INPEX, with 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. Liquefaction capacity will be 8.4mtpa, of which c7% will be exported to Japan. The project is in the construction phase, reportedly being 81% complete as of April 216. INPEX initially targeted the first LNG by end-216, but the project has been delayed and is now expected in Q3 217, with train 2 coming online in February 218, according to company representatives. Given the needed ramp-up period for both trains, and the time between each train going into operation, we do not see a full-year of production until 219. As well as LNG, we expect that Ichthys to be able to produce c1.6m tonnes of LPG annually. Prelude Shell owns 67.5% of the world s first FLNG vessel, a 3.6mtpa capacity plant. It is being built at the Samsung Shipyard in South Korea, with capex of USD12.6bn including costs for condensates and LPG production capacity. According to company representatives, Prelude is on schedule to start operating by mid-218 and will work in the Browse basin, close to 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 seems to have changed this. Other projects There are several other proposed projects in Australia, but due to a combination of escalating costs and falling LNG prices, they are too uncertain to cover in-depth as of now. We have excluded them and prefer 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 of Brunei, Shell and Mitsubishi Shore-based Source: DNB Markets Brunei has the advantage of being close to its main customers, Japan and South Korea. The Brunei LNG is a co-venture between the Brunei government (5%), and Shell and Mitsubishi (25% each). The plant was established in 1969 and started production in Annual capacity is 7.2mtpa and exports reportedly increased by.4mt to 6.6mt in 215, on the back of lower contracted volumes (5.2mt). There seem to be no expansion plans or reason to believe one or more of the five trains will be decommissioned. Cameroon Planned projects in Cameroon Project name Project owner Type Start-up Nominal capacity (mtpa) Kribi Hilli FLNG Source: DNB Markets Engie (New GDF Suez) SNH and Perenco Shore-based FLNG In late 214 it was announced that the former LNG carrier Golar Hilli would be converted into an FLNG, and positioned offshore Cameroon; this was confirmed in June 215. The natural gas will be sourced from the offshore Kribi fields, and is expected to be exported at 1.2mt per annum, utilising c5% of capacity. In November, Gazprom agreed to an offtake agreement of 1.2mt with Perenco for Hilli FLNG, while in July this year Engie announced it had decided to put the Kribi onshore project on hold due to unfavourable market conditions. 221e 217e

53 8 September 216 Canada Planned projects in Canada Project name Project owner Type Start-up Nominal capacity (mtpa) PNWLNG T1 T2 Petronas, Sinopec, JAPEX++ Shore-based 22e 12 PNWLNG T3 Petronas, Sinopec, JAPEX++ Shore-based Unknown 6 Woodfibre LNG T1 T2 Pacific Oil and Gas Shore-based 22e 2.1 LNG Canada T1 T2 Shell, PetroChina, KOGAS++ Shore-based 222e 12 LNG Canada T3 T4 Shell, PetroChina, KOGAS++ Shore-based 223e 12 Kitimat LNG T1 T2 Chevron, Woodside Shore-based 221e 1 Prince Rupert LNG T1 T2 BG group Shore-based 221e 14 Prince Rupert LNG T3 BG Group Shore-based Unknown 7 Goldboro LNG T1 T2 Pieridae Energy Shore-based 221e 1 WCC LNG T1 T5 Imperial Oil, ExxonMobil Shore-based 225e 3 Aurora LNG T1 T2 Inpex, CNOOC, JGC Shore-based 223e 12 Aurora LNG T3 T4 Inpex, CNOOC, JGC Shore-based 228e 12 Sarita Bay LNG T1 T4 Steelhead LNG Shore-based 223e 24 Bear Head LNG T1 T4 Liquefied Natural Gas limited Shore-based 22e 8 Bear Head LNG T5 T6 Liquefied Natural Gas limited Shore-based 224e 4 Canaport LNG Repsol, Irving Oil Shore-based 222e 5 Saguenay LNG T1 T2 GNL Quebec Shore-based 221e 11 Grassy Point LNG Woodside Shore-based 221e 2 Discovery LNG T1 T4 Quicksilver Resources Shore-based 221e 2 Orca FLNG V1 V6 Orca LNG FLNG 22e 24 Stolt LNGaz T1 T2 Stolt-Nielsen, Sun LNG++ Shore-based 218e 1 New Times FLNG New Times Energy FLNG 219e 12 Source: DNB Markets Western Canada is abundant with shale gas that exceeds 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 in the US 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. The fact that all projects in Canada except the Canaport LNG are greenfield puts them at a cost disadvantage relative to most US brownfield projects. In total, more than 2mtpa of proposed 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. Given that current prices are putting pressure on LNG exports from Canada, only one project has reached a conditional FID, the Pacific Northwest LNG. In a recent report, the IEA predicts Canada will not have any LNG export projects online by 22. Political institutions have a key role to play in terms of environment policies, export licences, and financial policies. Project owners constructing liquefaction plants in British Colombia have negotiated the tax and royalty rules that will apply to LNG producers. The British Colombia government recently reached a Project Development Agreement (PDA) with the PNWLNG project, hoping to provide enough fiscal certainty for the consortium to reach a final FID. The industry is new to the area and the viability of many large-scale projects depends heavily on the tax policy. We believe the liberal government seems committed to attracting investment in the sector to the extent that it is willing to help to meet the project demands, as proven in the recent PDA with PNWLNG and the passing of the Liquefied Natural Gas Project Agreements Act. Regulatory process Canadian firms wanting to export LNG have to apply for an allowance to export from the National Energy Board (NEB), which works to secure the domestic supply of gas and to ensure stable prices (in much the same way the DOE does in the US). Canadian gas exporters have historically had two markets for gas: 1) domestic; and 2) the US via pipelines. However, abundant gas supply from unconventional sources in the US has reduced exports through these pipelines. Canada is thus looking for new harbours from which to export its gas. 53

54 8 September 216 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 are expected to be in British Columbia (closer to Asia markets), but there are also projects proposed on the east coast (closer to European markets). 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 (CEAA) and the British Colombia 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. Also, the environmental assessment 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 make their feelings known. They 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 a project should get the green light. Regulatory process for LNG exports from Canada Source: DNB Markets Liquefaction plants in Canada Pacific North West LNG (PNWLNG) This greenfield project (estimated capex of USD11bn and USD92/tonne for the first phase) is operated by Malaysian state-owned Petronas and several minority owners. It will be on Lelu Island, close to Prince Rupert. In mid-june last year, PNWLNG announced it had reached a positive conditional FID, subject to 1) approval of the PDA by the Legislative Assembly of British Columbia; and 2) a positive regulatory decision on the environmental assessment by the Canadian government. In late July the British Columbia legislature passed the Liquefied Natural Gas Project Agreements Act and removed one of the final conditions. In March this year the CEAA suspended its review of the project asking PNWLNG to submit more information on the proposal, but it was resumed in June. Subject to a positive regulatory decision on the environmental assessment, PNWLNG expects construction to take about four years. This would imply start-up of the first 6mtpa train in mid-22. The company also has an option for a third 6mtpa train. LNG Canada project The proposed LNG Canada project (close to Kitimat, British Columbia) is being developed by Shell (majority owner), KOGAS, Mitsubishi, and PetroChina. It recently made significant regulatory progress with the CEAA approving the environmental assessment and the BCEAO issuing an Environmental Assessment Certificate in June last year. The companies involved were expected to reach FID by mid-216, but after two delays in 216 it seems that the decision has been postponed indefinitely. If FID is made in the future, construction is expected to take c4 5 years with the project coming on-stream shortly after completion. 54

55 8 September 216 Prince Rupert LNG project This project at Ridley Island, near Prince Rupert, was initiated by the BG Group. The first phase includes two trains and an associated port facility, and it is expected by operators to have 14mpta production capacity, with the possibility of an additional 7mtpa train (market conditions will determine as to whether this happens). The first phase of the project has capex of USD16bn, including pipeline costs. BG Group reported last autumn that it had paused the project due to shifting market conditions and would delay FID until 217. This implies that LNG cannot be expected until 221 at the earliest. However, the project could be at risk after Shell s takeover of BG Group. Last year, Shell said it would look at the LNG Canada and Prince Rupert LNG projects to ascertain whether there was reason to prefer one over the other. At this moment, however, it seems as though both projects are on hold. 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 in July 214. The initial plan was for Apache to be responsible for downstream activities, and Chevron for the 48km pipeline (transporting gas from the basin in North East British Columbia to Kitimat) and the liquefaction plant. In April 215 Woodside finalised the transaction to acquire Apache s 5% interest in the project, and in May the same year it transferred its role as upstream operator to Chevron. According to Chevron, major environmental and LNG export permits and First Nations benefits agreements are in place. However, progress has slowed down awaiting better market conditions and searching for ways to lower productions costs. The key issue is securing contracts covering at least 6 7% of total capacity, which is often a requirement to obtain financing. An FID is not expected by operators until late-216 with operations starting in 221 at the earliest. Kitimat LNG Source: Kitimat LNG Goldboro LNG Goldboro LNG is one of the most advanced projects outside British Columbia. The natural gas supply feeding the project is to be delivered via the existing Maritimes & Northeast Pipeline. It is still in a FEED phase and FID was recently postponed to late 216. In May 215 Pieridae Energy received approval from the DOE to export gas to end use in Canada and countries with which the US has a free-trade agreement. In February this year it also received approval to export to non-fta countries. Estimated annual project capacity is 1mtpa, and project owner Pieridae Energy now expects to start production in 221. Estimated capex is 55

56 8 September 216 CAD5bn 1bn. Goldboro has signed a 2-year contract with German utility E.on to purchase 5mtpa, equal to half of total annual production capacity. Bear Head LNG Led by Liquefied Natural Gas Limited, this is the only project in eastern Canada with all the necessary federal, provincial, and local regulatory approval in place for construction. The NEB filing is under review. The FEED phase was initiated in 215 with a target FID for the potential 12mtpa project in 216 and construction to commence shortly thereafter. However, as of July, the FID had been postponed until the project could secure substantial offtake to cover financing. Subject to a positive FID in 216, the initial two trains are expected to come online from 22. Other projects in Canada Our research has uncovered several other proposed plants, in British Columbia and Eastern Canada, including: 1) Aurora, initiated by INPEX and CNOOC, with total proposed capacity of 24mtpa due to come online from 223; 2) Sarita Bay LNG, where project-owner Steelhead recently said it was in the feasibility stage for the potential 3mtpa project, scheduled for startup in 223 at the earliest; and 3) the long-awaited large-scale West Coast Canada LNG, a JV between ExxonMobil and Imperial, which might materialise as we reach 225. There are several other small projects, such as the 2.1mtpa Woodfibre plant and the StoltLNGaz, which could come online from 218. The Douglas Channel LNG project has been scrapped due to lack of customers, so has been removed from our report. Egypt Existing and planned projects in Egypt Project name Project owner Type Start-up Nominal capacity (mtpa) Damietta ENI Shore-based 25 5 Idku BG Group Shore-based Source: DNB Markets We have to go back only five years to find the country exporting 1mtpa of LNG, but given recent strife gas exports have been hit and, consequently, no LNG was exported in 215. The main reason was greater allocation to domestic demand. The Damietta plant has not been allowed to export Egyptian gas and is idle, leading Egypt to look to Israel and Cyprus for gas supplies. In July this year it has been reported that a deal between Israel and Egypt could be on the rise to address the energy challenges in Egypt. Oil Minister Sherif Ismail said last year he expected Egypt to stop importing LNG by 22, and if no deal with external suppliers is made, it is not likely to see exports from Egypt before 22. The same can be said for the other operating plant in Egypt, Idku. However, Eni has discovered a new field offshore that could hold up to 3Tcf, which could free up gas and restart exports from Egypt. The Egyptian government believes that domestic demand for gas will continue to outpace inland production and in April 215 the FSRU unit Höegh Gallant commenced commercial operations in Egypt. In August 215 Egypt signed a five-year lease agreement with BW Gas for a second FSRU, the newly completed FSRU BW Singapore, to be delivered to the Ain Sokhna Port by end-september. On 28 June Egypt launched a tender for a third ship, supporting the notion that Egypt has become a net-importer. The gas will be pumped into the national grid, to answer the increasing need of energy. Equatorial Guinea Existing and planned projects in Equatorial Guinea Project name Project owner Type Start-up Nominal capacity (mtpa) Punta Europa T1 Marathon Shore-based Punta Europa T2 Marathon Shore-based 22e 4.4 Fortuna FLNG Ophir FLNG 219e 2.2 Source: DNB Markets 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 annual production capacity of 3.7mtpa, and reportedly had full utilisation in exporting c3.7mtpa in each year. The potential start-up of a second train at 56

57 8 September 216 Punta Europa is subject to gas field developments in the country, and thus speculative. The Fortuna FLNG project was recently announced, and is a conversion of the former LNG carrier Golar Gandria into an FLNG unit. The FLNG was scheduled to be delivered to Ophir in H1 219, but has been postponed to 22, with operations commencing shortly thereafter. Indonesia Existing and planned projects in Indonesia Project name Project owner Type Start-up Nominal capacity (mtpa) Bontang T1 T8 Badak LNG Shore-based DSLNG T1 Donggi-Senorro Shore-based Abadi FLNG INPEX, Shell Shore-based Tangguh T1 T2 BP Shore-based Tangguh T3 Sengkang LNG T1 T4 Source: DNB Markets BP EWC Shore-based Shore-based The Indonesian gas market is changing rapidly from a major LNG player (one third of LNG supply in the 199s) to the fifth-largest LNG exporter (soon to be passed by the US). This is a result of several trends: 1) declining production at Bontang due to reduced gas output; 2) recently expired export contracts that have not been extended; 3) conversion of the Arun plant (formerly another major production site) into an import terminal earlier this year; and 4) increasing domestic demand. The latest reports indicate that domestic allocation has risen further with industrial clients unable to absorb the allocated LNG which may lead to a larger drop in exports than initially expected. Regasification terminals are being built (e.g. the Arun plant) to transport gas to domestic demand hotspots. The country also has plans to operate several FSRU facilities, although the Lampung FSRU moored offshore Sumatra was idle in 215, as domestic electricity demand growth was slower than expected. Total natural gas consumption was 39.7bn cubic metres in 215, down from 4.9bn cubic metres in 214. The main drivers of gas demand are power generation and the industrial sector. As the country transports gas for internal use as liquids, any reduction in exports might not have such a corrosive effect on the LNG shipping industry. We consider it likely that future production from liquefaction facilities will be shared between domestic consumption and exports. There is also a clause in the Production Sharing Contracts (PSCs) in Indonesia that at least 25% of production shall be supplied to the domestic market. New projects such as DSLNG and Tangguh T3 are expected by operators to commit 4% of production to the domestic market. There are also reports that up to 6 uncommitted LNG cargoes from the two plants could flood the spot market due to expiring long-term contracts. Liquefaction plants in Indonesia Bontang Production from the Bontang plant, operated by state-owned Badak LNG, has been on a declining path since 21. The plant has production capacity of 22.5mtpa, though this is underutilised for the aforementioned reasons. We see no reason to assume that the fundamentals will change, so our base case is for a continued gradual decline in production and that more cargoes will be sold on the spot market. The plant is operated by the government-owned company Pertamina and has been in operation since The plant worked to increase capacity in the s and reached its current capacity in 1999, when the first LNG production from train H was commissioned. It is expected that Bontang exports around 145 cargoes in e 216e

58 8 September 216 Bontang LNG storage tanks and loading jetty Source: Panoramia photo data Tangguh LNG The Tangguh LNG plant in the Papua Barat area is BP s main operation 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 working to expand the plant by another 3.8mtpa train (T3) with an estimated investment of USD12bn, which was given government approval in 212. FID was taken on 1 July and start-up is expected in % of annual production is sold to the Indonesian State Electricity Company, with the remainder under contract with Kansai Electric Power Company. DSLNG (Donggi-Senoro) This USD2.8bn single train liquefaction plant shipped its first cargo in early August last year to the recently converted Arun LNG receiving terminal in Indonesia. It has the 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 others including KOGAS and Mitsubishi Corporation. A representative from one of the companies told us that the feed gas would be supplied from Senoro Upstream (31mmcfd) and Mantindok Upstream (15mmcfd); however, Mantindok Upstream has not been completed yet. According to the representative, the LNG plant only needs a gas supply of 335mmscfd to be able to export cargoes each year. Gas supply is at 347mmscfd, meaning DSLNG should now able to produce at its plateau capacity. Abadi FLNG The project is operated by INPEX (65%) in partnership with Shell (35%), and is being evaluated as part of the plan to develop the Abadi gas field in the Masela block. In 21 the Indonesian government gave approval for the Stage 1 development plan for a FLNG facility with capacity to produce 2mtpa. However, in March this year it was decided by the Indonesian government that the project would be moved onshore. As of July neither INPEX nor Shell had communicated its future project plans now that FLNG seems to be off the table. The project has already been severely delayed and potential start-up is now unknown (originally 226). Sengkang LNG The Sengkang LNG was initially scheduled to commence operations in 29 but has been hit by significant delays. Hong Kong based Energy World Corporation is the operator, and said it expected the first train (.5mtpa) to be commissioned before end-215 and later mid-216. However, expected start-up is now late 216. Dependent on sufficient gas supply, three additional trains of similar capacity are expected to be added at three- and six-month intervals after the first train begins production. 58

59 8 September 216 Libya Existing and planned projects in Libya Project name Project owner Type Start-up Nominal capacity (mtpa) Marsa El Brega Sirte Oil Shore-based Source: DNB Markets In 1971 Libya became the third country to export LNG, from the Marsa el Brega plant with nominal capacity of 3.2mtpa. The trains are in bad shape due to a lack of maintenance following the 211 civil war. Previously there was talk of adding a new train to the plant, to get production capacity back to the original 3.2mtpa nameplate capacity. However, given the current situation this is not likely in the foreseeable future. Prior to the 211 shutdown, Libya shipped small amounts of LNG to Spain, and now exports gas to southern Europe through the Greenstream subsea pipeline, running from Mellitah in Libya to Sicily. Due to the high level of uncertainty we do not expect any seaborne exports from Libya in the coming years. Malaysia Existing and planned projects in Malaysia Project name Project owner Type Start-up Nominal capacity (mtpa) MLNG Satu T1 T3 Petronas Shore-based MLNG Satu T4 Petronas Shore-based 216e 3.6 MLNG Dua T1 T3 Petronas Shore-based MLNG Tiga T1 T2 Petronas Shore-based Petronas FLNG Sarawak Petronas FLNG 216e 1.2 Petronas FLNG Sabah Petronas FLNG 22e 1.5 Source: DNB Markets Malaysian LNG exports have been flat around 25mtpa in the past couple of years, but we expect capacity to increase as Petronas adds a fourth train to its Satu plant, which is expected to come online in Q In addition, two FLNGs are expected to commence operations in 216 and 22 (originally 218). Although Malaysian gas imports were relatively constant between 214 and 215, we believe that Malaysia will increase its imports in years to come. To meet local demand, gas authorities commissioned a regasification terminal in Melaka with annual import capacity of 3.8mtpa through two floating devices. Malaysia wants to ensure the supply of gas for industrial use and we believe this trend will continue. In 23 coal represented 16.5% of electricity generation in Malaysia, and had risen to 38.5% in 213. Considering this we find it reasonable to assume that both exports and imports will rise in the coming years. Liquefaction plants in Malaysia MLNG complex A JV between Petronas, Shell and Mitsubishi was signed in 1978 to develop Malaysia LNG (MLNG) on Bintulu Island capable of producing 6mtpa. The first LNG was sold in November 1979 with production starting in January The second plant (MLNG Dua) was commissioned in 1995 and operated by the same JV. The third plant (MLNG 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. The JV expects production capacity to be expanded with a ninth train at the MLNG complex. Petronas reached a final investment decision in March 213 with expected production by mid However, this is now postponed to early 217 adding 3.6mtpa capacity to the complex. In 215 the MLNG complex exported 25.1mt compared with the 25.8mt in 214. Petronas FLNGs In addition to MLNG, the LNG production capacity of Malaysia should get a lift from Petronas s two FLNG vessels coming on stream. Petronas reported last year that the first FLNG (1.2mtpa) was planned to set sail by end-215 and be ready for production at the Kanowit gas field offshore Sarawak in Q However, recent reports indicate that the vessel arrived in Sarawak in late June this year and will commence operations within a few 59

60 8 September 216 months. The second FLNG (1.5mtpa) has also been delayed and is now set for commissioning in 22 (originally 218) at the Rotan gas field offshore Sabah. Petronas s FLNG close to completion Source: Offshore Energy Today Mozambique Proposed projects in Mozambique Project name Project owner Type Start-up Nominal capacity (mtpa) Mozambique T1 Anadarko Shore-based 221e 6 Mozambique T2 Anadarko Shore-based 222e 6 Mozambique T3 Anadarko Shore-based 223e 6 Mozambique T4 Anadarko Shore-based 223e 6 Mozambique T5 Anadarko Shore-based 224e 6 Mozambique T6 Anadarko Shore-based 225e 6 Mozambique T7 Anadarko Shore-based 226e 6 Mozambique T8 Anadarko Shore-based 226e 6 Area 4 Mamba T1 T2 ENI Shore-based 222e 1 Area 4 Coral FLNG ENI FLNG 221e 3.4 Area 4 Mamba FLNG ENI FLNG 222e 2.4 Source: DNB Markets Mozambique has proven gas reserves of over 1trn ft 3, with about 7trn ft 3 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 221. The initial strategy was to build ten trains with 5mtpa capacity. Now, however, it is planning two LNG trains of 6mtpa each to begin with and then potentially expand capacity further. The African government is struggling with a debt crisis, which together with the drop in oil price has made the project uncertain at best. However, in a recent statement Anadarko emphasised it was still strongly committed to the project and was working with the government to move the project forward. We thus expect Mozambique to emerge as a strong market participant, but that things could progress more slowly than expected. The project has been delayed significantly from the initial schedule. Another significant project developer in Mozambique is the Italian company ENI, which aims to build several liquefaction plants close to Area 4 of the Rovuma basin. The first project that is expected by operators to commence operations is the Coral FLNG. Company representatives told us they were in the final stages of making FID, with first LNG targeted in 221. For the initial development of the Mamba field they said an onshore plant comprising two trains was planned, with an FID in 217. For Mamba, they will also consider an FLNG. 6

61 8 September 216 Nigeria Proposed and existing plants in Nigeria Project name Project owner Type Start-up Nominal capacity (mtpa) Bonny Islands T1 T2 NLNG (Nigeria LNG ltd) Shore-based Bonny Islands T3 NLNG (Nigeria LNG ltd) Shore-based Bonny Islands T4 T5 NLNG (Nigeria LNG ltd) Shore-based Bonny Islands T6 NLNG (Nigeria LNG ltd) Shore-based Bonny Islands T7 NLNG (Nigeria LNG ltd) Shore-based 223e 4.1 Brass LNG T1 NNPC (Nigerian National Petroleum Corporation) Shore-based 222e 4.5 Brass LNG T2 NNPC (Nigerian National Petroleum Corporation) Shore-based 223e 4.5 Olokola LNG T1 T2 NNPC (Nigerian National Petroleum Corporation) Shore-based 223e 12.6 Source: DNB Markets Nigeria exported c19.5mt in 215, up c.3mt from 214. In 215 it enjoyed more stable feed gas supply versus 213, when the country declared several forces majeures, and thus managed to increase production slightly versus 214. There are many proposed projects in Nigeria, totalling possible additional capacity of c26mtpa, but the country faces huge financing and regulatory challenges. Its LNG production is dominated by the Nigerian National Petroleum Corporation, which has a policy to keep the country s share of the global LNG market at 1%. Recent events have not been positive. The Olokola project (initiated in 27) was set to be finished in 212, but project partners such as Chevron and BG have been withdrawing from the project in recent years due to a lack of progress. We have also observed some large setbacks on the Nigeria LNG train-7 project, with Mr Babs Omotowa (CEO of NLNG) saying in 215 that it needed at least two more years to reach an FID. The Brass LNG project s technical partner ConocoPhillips decided to exit in 214; and, according to the Minister of State for Petroleum Resources, Total is now considering doing the same. The partners had to change technology for the project, as Conoco Phillips owns and licences The Optimised Cascade technology initially intended to be adopted. The Petroleum Industry Bill, initially proposed in 28, is expected by operators to change the organisational structure and fiscal terms governing the oil and gas sector. Given the uncertainty surrounding the Petroleum Industry Bill and its effect on the fiscal regime, as well as the highly competitive global LNG supply market, it is not seen as likely that any new Nigerian LNG projects will materialise until well into the 22s. Norway Existing plants in Norway Project name Project owner Type Start-up Nominal capacity (mtpa) Risavika LNG Skangas Shore-based Snøhvit Statoil Shore-based Source: DNB Markets Norwegian LNG production is dominated by Statoil, operating a 4.2mtpa liquefaction plant at Melkøya, in the far north. The plant started operations in 27, but several issues have prevented it from operating at full capacity. After several measures were taken to increase plant efficiency and regularity, production rose by 22% in 214 and another 13% in 215 (c4.28mt) versus previous years, reaching full production capacity in 215. Several expansion plans have been proposed, but modest findings of gas reservoirs close to the Snøhvit basin put the plans on hold. Statoil has said it would rather work to optimise the current facilities. Norway also has a smaller liquefaction plant, in Risavika near Stavanger, where Skangas operates its.3mtpa liquefaction plant. Exports from here head mainly to the Lysekil-terminal in Sweden, just north of Gothenburg. The plant produced.274mt in 215 (.287mt in 214). 61

62 8 September 216 Snøhvit LNG plant Source: Ramirent Oman Existing plants in Oman Project name Project owner Type Start-up Nominal capacity (mtpa) Qalhat LNG Terminal T1 T2 Oman State, Shell, Total ++ Shore-based Qalhat LNG Terminal T3 Oman State, Oman LNG ++ Shore-based Source: DNB Markets There are two LNG plants in operation, both in the Port of Qalhat. Previously they were operated by Oman LNG and Qalhat LNG, but in September 213 the companies merged to make a fully integrated entity called Oman LNG. In 215 the two plants exported c7.78mt of LNG combined, down c1% YOY and well below combined nameplate capacity. Exports are delivered on long-term contracts to clients such as KOGAS, UFG, and Osaka Gas. Similar to, but not as imminent as in Egypt, Omani exports of LNG could run the risk of being limited by increasing domestic demand and thus shortage of feed gas. The latter might be counteracted by BP Oman s development of the Khazzan tight gas project in the south of Block 61, where first gas is expected in 217. One solution under consideration that could be back on the table now that the sanctions against Iran have been lifted, is a subsea pipeline between Oman and Iran. The pipeline could secure Oman gas supply both for domestic use and LNG production. Papua New Guinea Existing and planned projects in Papua New Guinea Project name Project owner Type Start-up Nominal capacity (mtpa) PNG LNG T1 T2 PNG LNG T3 ExxonMobil, Oil Search ++ ExxonMobil, Oil Search ++ Shore-based Shore-based Elk-Antelope LNG T1 T2 Total, InterOil, Oil Search ++ Shore-based 222e 8 Pandora Talisman Energy, Cott Oil and Gas FLNG Unknown 1 Pandora expansion Talisman Energy, Cott Oil and Gas FLNG Unknown 2.5 Source: DNB Markets To the north of Australia, Papua New Guinea should be able to benefit from its close proximity to Asia. It is taking small steps as an LNG exporter with its first LNG sales in 214. Exports are sourced from the PNG LNG project, a co-venture between ExxonMobil and Oil Search with production capacity of 6.9mtpa. In 215, PNG LNG exported 7.18mt, mostly shipped to China, Japan, and Taiwan and the 6.6mt being sold through long-term contracts. Total investment for the greenfield LNG plant was USD19bn, leaving it at the high end of the cost ladder. This plant is set to be expanded with a third train with an FID targeted by end e

63 8 September 216 Oil Search is also involved in the Elk-Antelope LNG project (expected start-up around 222). It is very early stage and the quantity of gas found will determine the plant s size, but it is considered increasingly likely that volumes are enough for two trains (total capacity 8mtpa). Costs are estimated to be much lower than for the PNG LNG. These plants are in addition to the FLNG projects initiated by Cott Oil and Gas and Talisman Energy, to extract gas from the Pandora field. Total capacity of the FLNGs will be 3.5mtpa, but a smaller vessel (1mtpa) is likely to come on-stream first. Cott Oil and Gas representatives told us it had not decided on a timeline and was still looking at alternatives. As with other potential projects, much depends on the market. PNG LNG liquefaction plant Source: GAS TODAY Peru Existing project in Peru Project name Project owner Type Start-up Nominal capacity (mtpa) Peru LNG Peru LNG (JV Hunt Oil, SK Energy, Shell, Marubeni) Shore-based Source: DNB Markets The Peru LNG plant has been operating since 21. The shore-based terminal has liquefaction capacity of 4.45mtpa and is operated as a co-venture between Hunt Oil Company, SK Energy, Shell, and Marubeni. With total investment of USD3.8bn it is at the low end of the cost ladder in terms of cost per tonne of production capacity. Of the 4.45mtpa of nominal capacity, 4.2mtpa is contracted to Shell Trading Middle East until 228. In 215, Peru LNG exported around 3.6mt of LNG (4.2mt in 214), with exports heading mainly to Mexico (68.63%), but also Spain (19.89%), Japan, and France. The significant drop between 214 and 215 was due to major maintenance of plant and upstream equipment, plus the transportation pipeline. There are no specific plans to add another train to the site, and we believe LNG exports will be steady at around 4.2mtpa in the coming years. 63

64 8 September 216 Qatar Existing plants in Qatar Project name Project owner Type Start-up Nominal capacity (mtpa) Qatargas 1 LNG T1 T3 Qatargas Shore-based Qatargas 2 LNG T1 T2 Qatargas Shore-based Qatargas 3 LNG T1 Qatargas Shore-based Qatargas 4 LNG T1 Qatar Petroleum Shore-based Rasgas 1 LNG T1 T2 Rasgas Shore-based Rasgas 2 LNG T1 Rasgas Shore-based Rasgas 2 LNG T2 Rasgas Shore-based Rasgas 2 LNG T3 Rasgas Shore-based Rasgas 3 LNG T1 Rasgas Shore-based Rasgas 3 LNG T2 Rasgas Shore-based Source: DNB Markets Despite its small size, no country is comparable to Qatar in terms of LNG exports; it exported c78.4mt of natural gas in 215 (76.5mt in 214). After an unusual decline in 214, due to maintenance at its Ras Laffan facilities, Qatar is back on an increasing trend. Most of its LNG used to be shipped to the US, but given the low US gas price no cargoes were sent to the US In 215 and more than 65% of the country s exports head to Asia, specifically Japan, South Korea, and India. Qatar s exports are dominated by Qatargas and RasGas, and the latest of the 14 trains came on stream in January 211 (7.8mtpa). It is known for its mega-trains, as six of the 14 trains can produce a minimum of 7.8mtpa of LNG. Most of Qatar s gas sales are still on long-term oil-indexed sales and purchase agreements (SPAs), but in recent years have shifted slightly towards short-term and spot market sales. As short-term sales have increased, flexibility to take advantage of its beneficial location between Europe and Asia has improved. This flexibility enabled Qatari LNG exporters to profit from the relatively high spot price in Asian countries, by directing gas intended for Europe to Asia. Despite the high extraction of resources, the reserves should last for many years. Qatar has the third largest proven reserves of natural gas with 24.5trn cbm; only Iran and Russia have larger proven resources. With the government having imposed a moratorium on further development of the North Field and suspended development of new LNG plants, new shortterm production capacity is likely to come only from debottlenecking existing trains. Having enjoyed full utilisation of nominal production capacity in recent years, we expect exports from Qatar to be stable going forward. As mentioned earlier in the survey, however, we expect that Qatar to be surpassed in terms of production capacity in the near future now that Australia is rapidly increasing its production capacity with several projects coming online before 22e. Qatar LNG ship loading Source: Bloomberg/Qatar Petroleum 64

65 8 September 216 Russia Existing and planned projects in Russia Project name Project owner Type Start-up Nominal capacity (mtpa) Sakhalin-2 T1 T2 Gazprom and Shell Shore-based Sakhalin-2 T3 Gazprom and Shell Shore-based 221e 5 Yamal LNG T1 Novatek, Total and CNPC Shore-based 217e 5.5 Yamal LNG T2 Novatek, Total and CNPC Shore-based 218e 5.5 Yamal LNG T3 Gydan LNG T1 Gydan LNG T2 Gydan LNG T3 Baltic LNG T1 T2 Pechora LNG T1 T2 Vladivostok LNG T1 T3 Sakhalin-1 LNG T1 Source: DNB Markets Liquefaction plants in Russia Novatek, Total and CNPC Novatek Novatek Novatek Gazprom Alltech Gazprom Rosneft, Exxon++ Shore-based Shore-based Shore-based Shore-based Shore-based Shore-based Shore-based Shore-based Sakhalin-2 LNG The Sakhalin-2 project on the east coast of Russia has been in operation since 29, and is a co-venture between Gazprom and Shell. Exports in 215 totalled c1.82mt, a slight increase from the 1.7mt in 214, and well above the stated nominal capacity. All of the exports are for Asia with c15% sold in the spot market. The company expects 216 production to be roughly flat YOY. An agreement has been reached between Gazprom and Shell to add a third train to the Sakhalin-2 plant. The project has entered the FEED stage and Gazprom told us that FID was targeted by late-216, but the decision will be made by the SEIC shareholders once the FEED phase is completed. Expected start-up is in 221. The development of this project is subject to securing the required feed gas volumes. The investment cost of the existing trains is not publicly available. However, Gazprom reveals that costs were in the mid-range of comparable projects somewhat cheaper than most Australian greenfield projects and slightly more expensive than brownfield American plants. While the harsh and cold surroundings make it challenging to construct and operate the plant, liquefying gas is cheaper than it would be in a warmer climate. Yamal LNG Novatek told us that construction of Yamal LNG is on track with 95% of production capacity being pre-sold and LNG from the first train expected in late-217e. New trains are expected to be added 12 months apart, with each train needing 4 6 months to ramp-up to full production. Located along the Russian north coast, the environmental challenges are considerable in terms of construction and transportation. According to the company, each of the three trains is planned to produce 5.5mtpa annually, leading to aggregate capacity of 16.5mtpa by 22. Almost all of the gas has reportedly been sold on long-term contracts to clients such as Engie, CNPC, and Gazprom. According to Reuters, the company circumvented western sanctions by signing loan agreements worth USD12bn with Chinese banks in April, reaching its financing need of USD18bn 19bn. Also, Novatek signed an agreement with China s Silk Road Fund in December 215 to sell a 9.9% stake in the project. Other LNG projects Other projects proposed in Russia include Arctic LNG, Vladivostok LNG, Baltic LNG, Sakhalin-1 LNG, and Pechora LNG. Although some of these projects are fairly advanced, they lack any firm commitment, and some are even on hold. We have chosen to focus on the projects likely to materialise in the coming years. 219e 221e 222e 223e 22e 223e 22e 22e

66 8 September 216 Sakhalin-2 tanker loading unit Source: Gazprom Tanzania Planned projects in Tanzania Project name Project owner Type Start-up Nominal capacity (mtpa) Tanzania LNG T1 BG Group Shore-based 222e 5 Tanzania LNG T2 BG Group Shore-based 223e 5 Source: DNB Markets Tanzania could well emerge as a leading LNG supplier. It faces many of the same uncertainties as Mozambique, but its proven gas reserves are far smaller. Reported estimates are c55trn ft 3 of natural gas; however, experts say this could grow to 2trn ft 3 in the next few years. But developers such as BG Group, Royal Dutch Shell, ExxonMobil, and Statoil face significant political risks. In last year s report we addressed whether Zanzibar (semiautonomous government) could sign its own exploration deal and thus secure all the revenue. In June this year Shell appealed to the Tanzania tribunal, having been landed with a USD52m capital gains bill relating to the BG takeover. Legislation on investment and profit-sharing is crucial for this to proceed. The Tanzanian government tried to get all political parties to rewrite parts of the constitution last summer, but the opposition refused to participate. In our August report last year we said FID was not expected before the election in October 215, and since then market sources have talked about a potential FID not before 218 or even 219. The market expects no production from Tanzania s gas fields before 222. It is considered important for Tanzania and Mozambique to become the first large-scale LNG exporter in this region. One company in Mozambique told us that being first had value, as global customers and banks would be more willing to make a cluster around the first exporter. We believe it is more likely that we will see additional trains emerge in the country that starts LNG production first. With bureaucratic issues delaying project progress, we believe Tanzania might fall behind. However, it is often counter-argued that there will be enough demand to support LNG development in both countries. In January this year the land for the project was acquired and is now being transferred to the project owners. According to Reuters, the acquiring of the plant site has been one reason for the delay. Trinidad and Tobago Existing plants in Trinidad and Tobago Project name Project owner Type Start-up Nominal capacity (mtpa) Atlantic LNG T1 BP, BG + Shore-based Atlantic LNG T2 BP, BG + Shore-based Atlantic LNG T3 BP, BG + Shore-based Atlantic LNG T4 BP, BG + Shore-based Source: DNB Markets 66

67 8 September 216 The country has 14.8mtpa of 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 dynamics closer to 218 would determine whether new long-term contracts are signed or other contractual schemes are preferred. Exports from Trinidad and Tobago declined from 13.1mt in 214 to 12.6mt in 215, due mainly to an underinvestment by upstream producers in recent years that led to curtailments. In our report last year we estimated gas curtailments as large as 2% in H1 215, which also affected output at downstream plants. However, according to news reports, curtailment is expected by end-217 when an additional 8 MMcfd is due to come onstream from the Loran-Manatee field. We note that upstream projects such as BG Group s Starfish delivered first gas in late 214, which is also expected to serve as feed gas for the Atlantic LNG plant. Other short-term upstream projects include BP s Juniper, which is expected to deliver first gas in mid-217. Compared with other projects, Atlantic LNG has proven to be one of the cheapest. Its average investment per tonne of capacity is cusd25. United Arab Emirates (UAE) Existing plant in UAE Project name Project owner Type Start-up Nominal capacity (mtpa) Das Island Adgas Shore-based Source: DNB Markets Abu Dhabi s giant oil field was discovered in the 195s with construction of the first LNG train in the early 197s. It has the world s sixth largest natural gas reserves with 6.1trn cbm of proven resources, c3.3% of the world s total. The three-train LNG plant is on Das Island in the Persian Gulf and is operated by Adgas with ADNOC, Mitsui, BP, and Total as shareholders. In 215 c5.7mt was exported, versus c5.9mt in 214, which marked a 3.5% decrease. The main client is the Tokyo Electrical Power Company (TEPCO) with which it has a 25-year contract for up to 4.9mtpa expiring in 219. The remaining production is sold in the spot market. Last year we expected 215 exports to decline YOY, reflecting 1) two of three trains reportedly being shut down for maintenance from 15 March to 19 April; and 2) expiry of a short-term volume contract with TEPCO in 215 for an additional.9mt, agreed upon after the Fukushima disaster. These estimates seem to have been fairly accurate, but the drop in production was smaller than expected, Future LNG exports from UAE are dependent on: 1) the TEPCO contract expiring in 219 being extended or replaced; and 2) coping with surging domestic demand for gas without limiting exports. There is also a long-term likelihood of trains being decommissioned due to age. 67

68 8 September 216 The US Existing and planned plants in the US Project name Project owner Type Start-up Nominal capacity (mtpa) Kenai LNG T1 ConocoPhillips Shore-based Sabine Pass LNG T1 2 Cheniere Shore-based Sabine Pass LNG T3 4 Cheniere Shore-based 217e 9 Sabine Pass LNG T5 6 Cheniere Shore-based 218e 9 Corpus Christi LNG T1 T2 Cheniere Shore-based 219e 9 Corpus Christi LNG T3 Corpus Christi LNG T4 Corpus Christi LNG T5 Cheniere Cheniere Cheniere Shore-based Shore-based Shore-based Elba Island LNG T1 T1 Kinder Morgan Shore-based 218e 2.5 Golden Pass T1 Golden Pass Products Shore-based 221e 5.2 Golden Pass T2 Golden Pass Products Shore-based 222e 5.2 Golden Pass T3 Golden Pass Products Shore-based 222e 5.2 Cameron LNG T1 3 Cameron LNG T4 T5 Sempra, Engie, Mitsui, Mitsubishi, NYK Sempra, Engie, Mitsui, Mitsubishi, NYK Shore-based Shore-based Cove Point LNG T1 Dominion Resources Shore-based 217e 5.25 Magnolia LNG T1 T4 Liquefied Natural Gas Limited Shore-based 218e 8 Freeport LNG T1 T2 Freeport LNG T3 Freeport LNG T4 Freeport LNG Freeport LNG Freeport LNG Shore-based Shore-based Shore-based Lake Charles LNG T1 T3 Energy Transfer Shore-based 22e 15 Jordan Cove LNG T1 T4 Veresen Shore-based 22e 6 Oregon LNG T1 T2 Leucedia National Corporation Shore-based 22e 9 Lavaca Bay FLSO Excelerate Energy FLSO 22e 4 Cambridge Energy FLNG V1 Cambridge Energy FLNG 22e 4 Cambridge Energy FLNG V2 Cambridge Energy FLNG 221e 4 Texas LNG Brownsville T1 Texas LNG Shore-based 221e 2 Texas LNG Brownsville T2 Texas LNG Shore-based 223e 2 Annova LNG T1 T6 Exelon Shore-based 221e 6 Alaska LNG T1 T3 TransCanada, BP, CP, Exxon Shore-based 224e 2 Gulf LNG T1 T2 Kinder Morgan Shore-based 22e 1 Calcasieu Pass T1 T1 Venture Global Shore-based 219e 1 Louisiana LNG T1 T2 Parallax, Cheniere Shore-based 221e 5.2 Live Oak LNG T1 T2 Parallax, Cheniere Shore-based 221e 5.2 Port Arthur LNG T1 T2 Sempra Shore-based 221e 1 Rio Grande LNG T1 T3 NextDecade Shore-based 22e 13.5 Rio Grande LNG T4 T6 NextDecade Shore-based 222e 13.5 Pelican Island LNG NextDecade Shore-based 221e 6 Delfin FLNG V1 V4 Fairwood Peninsula Energy FLNG 22e 8 Jacksonville LNG T1 Eagle LNG Partners Shore-based 219e.18 Jacksonville LNG T2 Eagle LNG Partners Shore-based 22e.18 Jacksonville LNG T3 Eagle LNG Partners Shore-based 221e.18 Downeast LNG T1 Kestrel Energy Shore-based 221e 3 Gulf Coast LNG T1 T3 Gulf Coast LNG Export Shore-based 221e 18 Monkey Island LNG T1 T6 SCT&E LNG Shore-based 224e 12 G2 Cameron Parish LNG G2 LNG Shore-based 221e 14 Plaquemines LNG T1 T1 Venture Global Shore-based 22e 1 Plaquemines LNG T11 T2 Venture Global Shore-based 223e 1 Alaska-Japan LNG T1 Resources Energy Shore-based 22e 1 Source: DNB Markets 22e 221e 222e 218e 219e 218e 219e 22e Originally a major importer of LNG, the US is gradually turning the tables on the global LNG industry driven by its increasing amount of unconventional gas. 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. Five projects have a FID and are under construction: Cameron LNG (T1 T3), Freeport LNG (T1 T3), Sabine Pass LNG (T1 T5), Cove Point LNG (T1), and most recently Cheniere s Corpus Christi LNG (T1 T3). Several other US projects are expected to reach an FID in , subject to regulatory approval and obtaining adequate financing. 68

69 8 September 216 In recent years there has been a surge in proposed LNG export projects in the US. Project sponsors were looking to achieve high returns by taking advantage of the low US natural gas prices and previously high oil-linked LNG prices in Asia and Europe. The outlook for most early-stage US LNG export projects has worsened due to: 1) the relatively low Henry Hub Natural Gas Spot Price forecast by most experts; 2) LNG prices in other countries falling significantly due to the oil price crash and competition from other energy sources; and 3) demand growth being lower than expected, leading to expected oversupply in the market for the coming years. However, most planned US projects are to some extent brownfield, utilising existing infrastructure, implying they are significantly cheaper to build than similar greenfield projects in Canada or Australia. Although, as we have seen lately, many projects have either been postponed, put on hold, or cancelled due to an unfavourable economic environment, we believe that the US will become a major LNG producer within a few years. Regulatory process Obtaining export permits Natural gas regulations in the US follow the Natural Gas Act, which requires that anyone who wants to import/export natural gas from/to a foreign country must obtain authorisation from the Department of Energy (DOE). 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 only apply after securing sufficient long-term contracts for gas supply and/or sales. 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 easily granted, as permission to export to non-fta countries is granted only if exports are not detrimental to the public interest. Issues considered are economic, environmental, and energy security. The DOE has been criticised for its order of precedence based on applications filed by December 212, as the DOE considered applications in the order that they were filed. However, in August 214 the DOE changed its order of precedence. It will now wait for FERC/MARAD to complete the environmental review as required under the National Environmental Policy Act of 197 (NEPA) before acting on applications to export LNG to non-fta countries. US FTA countries Source: fedex.com 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 notably Asia, Japan and South Korea are excluded as export destinations if an LNG producer does not have a licence. Europe is another example. There are binding talks ongoing about free-trade agreements in both regions, notably the Trans-Pacific Partnership Agreement and the Transatlantic Trade and Investment 69

70 8 September 216 Partnership. These negotiations, if successful, will take several years to complete, and we consider it safe to say that building an 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. The 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 the 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 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 public stakeholders, to comment on the effect of the project before the application is submitted. This input period ends when the company files a formal application with the 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 effects. 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 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 the final environmental approval is issued. Gearing up for construction After receiving final approval from FERC, so-called order to proceed, the FERC can still raise further issues the company must address before construction can begin. Additionally, local regulators might need to be satisfied, e.g. 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. Under the new order of precedence at the DOE, projects that have not received conditional authorisation before changes to procedures were made will have to apply for export permission to non-fta countries once the FERC process is complete. Political turmoil The FERC is a regulatory body and thus not heavily influenced by politics. There are occasions, however, when senators or congressmen might try to change the filing process in favour of their home project, but the commissions are rarely influenced by this. 7

71 8 September 216 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, even after the measures taken last year to streamline the process. Senator John Hoeven cosponsored the bipartisan bill called the LNG Permitting Certainty and Transparency Act earlier this year, which was approved by the US Senate Energy Committee. The core provision of the bill is to force the DOE to make a decision on non-fta export licences within 45 days of FERC approval. This could shorten the regulatory process significantly for some projects. For example, Cheniere s Corpus Christi received final authorisation from FERC in late December 214 but had to wait until mid-may 215 to be granted non-fta export approval. 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. However, changing the system is not easy, and there are strong powers working against any proposals to liberalise it. The DOE investigated the issue in 213, ordering a two-part report and concluded further research was required. Although the 213 reports were generally viewed as positive for LNG exports, 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 over European and Asian competitors. This has led to growth in the American manufacturing industry. Another argument 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 changes by the DOE last year (local requirements have separate process) Federal Energy Regulatory Commission Department of Energy Pre-filing process Public comments Submitting draft resource reports FTA licence granted Local requirements EA or EIS prepared Public comments Order to proceed Non-FTA decided on basis of EA or EIS issued by FERC Non-FTA licence Clean Air Act Coastal Zone Management Others Source: DNB Markets Liquefaction plants in the US Kenai LNG plant The Kenai plant in Alaska, operated by ConocoPhillips, was completed in 1969 and has liquefaction capacity of 1.3mtpa. Export operations 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 (starting 214), also to non-fta countries (notably Japan). After lingering talks of the plant being decommissioned, Kenai LNG received approval from DOE in February to produce up to 4 Bcf of LNG over the next two years. Sabine Pass terminal Cheniere Energy is building a liquefaction terminal at its existing receiving terminal in Cameron Parish, Louisiana. Located along the Gulf Coast, Sabine Pass is close to five of the six major US shale plays, and it also benefits from the large number of interstate pipelines built in recent years. Although construction of Train 1 is now complete, well ahead of the guaranteed contractual schedule and within budget, first LNG was delayed one quarter and occurred in February this year. The second train produced first LNG late July this year with 71

72 8 September 216 ramp up over the next 3 4 months and substantial completion by September. The remaining three trains that have undertaken FIDs are under construction. FIDs for train three and four (both 4.5mtpa) were undertaken in May 213. Combining the four trains, Sabine Pass will have a liquefaction capacity of 18mtpa by end-217. The FID for train number five was made in June 215, and construction commenced shortly thereafter. Train five (4.5mtpa) is not expected to commence operations before Q A FID for the sixth train (4.5mtpa), which was expected by end-215 in last year s report, has yet not been reached, but the permitting process was completed simultaneously with the process for train five. Cheniere Partners have received the FERC authorisation to site, construct and operate train six, and the authorisation from the DOE to export LNG to non-fta countries. Commencing construction on train six is expected by Cheniere upon entering into acceptable commercial arrangements and obtaining adequate financing. Cheniere has entered into long-term (2 years) take-or-pay SPAs for about 2mtpa of the capacity, to clients such as BG Group, Gas Natural Fenosa, KOGAS, Total, GAIL, and Centrica. Sabine Pass liquefaction plant Source: World Maritime 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 five trains able to produce 22.5mtpa in total. Cheniere and partners reached a positive FID for the two first trains in May 215, which are now under construction. In our August 215 report the company expected a FID for the third train by end-215, while Cheniere now says it expects a FID upon the final execution of commercial arrangements. For the fourth and fifth trains it initiated the permit process in early June 215 by requesting the FERC s permission to engage in the pre-filing process. Cheniere expects the first train (4.5mtpa) to commence operations in February 219, ramping up to reach full production by mid-219. The second train (4.5mtpa) is targeted for substantial completion by June 219. Subject to a positive FID, the third train (4.5mtpa) is expected to reach completion in 22. Cheniere has entered into long-term take-or-pay SPAs for about 9mtpa, with clients such as Pertamina, Endesa, Woodside, Central El Campesino, and Gas Natural Fenosa. Elba LNG project This small-scale LNG project was initiated by Shell and Kinder Morgan, and we expect it to contribute c2.5mtpa of export capacity from the US. On 15 July 215 it was announced that Kinder Morgan purchased 1% of Shell s equity interest in the project, giving it full ownership. The first stage of construction will be to build six Moveable Modular Liquefaction System (MMLS) units, each able to produce.25mtpa. In last year s report FID and commencement of operations were expected in late 215. However, as of July, FID had not been made even though the project received FERC approval in June. Initial production is 72