Natural Gas

Overweight Crude Oil And E&P Are Joined At The Hip Crude Oil And E&P Are Joined At The Hip S&P oil & gas exploration & production (E&P) stocks have closely tracked crude oil prices, but recently a wide gap has opened and we reckon that it will likely narrow via a catch up phase in the former (top panel). Even natural gas prices have come out of hibernation and caught a bid of late and similarly suggest that relative share prices are uncharacteristically depressed by steeply deviating from the underlying commodities (second panel). There is so much pessimism ingrained in the E&P space with net EPS revisions sinking to “as bad as it gets” warning that even a modest rise in oil prices can serve as a catalyst to raise the profile of this unloved corner of the deep cyclical universe (bottom panel). Bottom Line: Continue to overweight the S&P oil & gas exploration & production index. Please refer to the following Weekly Report for more details. The ticker symbols for the stocks in this index are: S5OILP – COP, PXD, DVN, HES, APA, MRO, XEC, COG, CXO, EOG, FANG, NBL.

Dear Client, This is our last publication of 2018. We wish all our clients a Merry Christmas and a Happy New year! We will be back on January 3, 2019. Thank you, The Commodity & Energy Strategy Team!   Because they missed the first wave of North American Liquified Natural Gas (LNG) investments, Canadian gas producers will continue to endure low prices – compared to their U.S. counterparts – for the next three to five years. To become attractive to investors, proposed Canadian LNG projects will have to wait for demand to catch up to supply coming from the first wave of investment in 2010 – 2015.1 The good news is demand – mainly from Europe and Asia – is projected to outpace gas liquefaction capacity by 2023 – 2024.2 We believe this will create the necessary conditions to incentivize the second wave of LNG investment. To preserve its strong natural gas sector, Canada will have to become a leading LNG exporter, or risk seeing production decline. Highlights Energy: Overweight. The 2H18 OPEC 2.0 production surge undertaken to cover the re-imposition of U.S. sanctions against Iranian oil exports still is being absorbed in key refining centers. We expect to see inventories begin to draw heavily in January, given the transit from the Persian Gulf to the U.S. Gulf, where inventory levels are reported weekly, takes roughly 50 days per the U.S. EIA (Chart of the Week). Chart 1 Base Metals: Neutral. Asian copper concentrate treatment and refining charges (TC/RCs) appear to be headed lower next year. According to Metal Bulletin’s Fastmarkets, a deal agreed by Antofagasta and Jiangxi Copper setting TC/RCs at $80.80/MT / 8.08 cents/lb is setting next year’s levels. This will be the “the lowest benchmark since 2013,” coming in $1.45/MT under this year’s levels. Precious Metals: Neutral. Gold prices have rallied, as markets appear to be discounting fewer rate hikes by the Fed next year.3 We expect at least three rate hikes in 2019. Ags/Softs: Underweight. The USDA will release the second and final installment of farm assistance totaling $4.7 billion, to cover losses arising from the Sino – U.S. tit-for-tat tariffs and lost trade. This brings the total U.S. payout to $9.6 billion, according to agriculture.com. Feature U.S. LNG companies have the first-mover advantage in the North American LNG market.4 Because of this, these firms have a decided advantage in attracting capital investments and securing shorter- and long-term contracts to absorb their output. We believe the upcoming second wave of North American LNG investment – likely to get rolling in early 2019 – might be the last opportunity for Canadian producers to secure a position in the global gas market. If they miss this wave, Canadian natural gas production likely will plateau at close to current levels and begin to decline as early as 2019 (Chart 2).5 Chart 2 Currently, ~ 51% of Canadian natural gas production is exported to the U.S., but the shale revolution south of the border threatens every single cubic-foot of exports. U.S. gas supply is projected to increase by 20%, while its domestic demand by only 5%. This means the U.S.’s supply-surplus is poised to increase by 4.25 Bcf/d by 2023. Most of the American surplus will be exported via the LNG facilities that received final-investment decisions (FID) during the first wave of investment, and the rest via pipelines to Mexico and Canada. By 2020 the U.S. will have ~ 9.5 Bcf/d of liquefaction capacity and 3.4 Bcf/d of additional pipeline capacity destined to Mexico and Canada (Table 1). Table 1U.S. LNG Capacity To Reach 9.5 Bcf/d In The Early 2020s Canada's Last LNG Opportunity Canada's Last LNG Opportunity Canadian Gas Market Balance The U.S. natural gas market is the most important factor driving the evolution of Canadian natural gas production. Canadian natgas exports to the U.S. are expected to decrease from 8.2 Bcf/d to ~ 5 Bcf/d by 2040, according to EIA data. Moreover, Eastern Canada’s imports of natural gas from Northeast U.S. are projected to increase by 2.2 Bcf/d, due to the region’s proximity to the super-giant Marcellus and Utica gas fields in the Appalachian Basin. This trend has already started (Chart 3). Chart 3 Our base case projections for Canadian natural gas includes five new projects reaching FID in 2019-2020, with a combined capacity of 6.4 Bcf/d by 2024: Woodfibre LNG (prob > 80%): Small-scale project with capacity close to 0.3 Bcf/d located near Squamish, BC. This involves a 47-kilometer expansion of the existing FortisBC pipeline, transporting gas from the Western Canadian Sedimentary Basin. Goldboro LNG (prob > 80%): Although the project is placed in proximity to the Maritimes & Northeast Pipeline, the ~0.5 Bcf/d import capacity of this pipe would not sustain the 1.3 Bcf/d facility’s export capacity suggesting a required expansion, or new infrastructure to source its gas from the Marcellus Basin or Canada West. Bear Head LNG (prob > 80%): This project in Richmond County, NS must decide on whether to source 1.6 Bcf/d from the U.S. or Western Canada. Kitimat LNG (prob > 50%): This 1.3Bcf/d terminal in Bish Cove, BC will source its gas from the Horn River and Liard Basins via the proposed 480-kilmeter Pacific Trail Pipeline. Kwispaa LNG (prob > 50%): Formally known as Sarita LNG, the 1.9 Bcf/d project in Sarita Bay, BC would rely on gas supply from northeastern BC and/or Alberta. On the back of these expansions, we expect a short-term gas supply-surplus in Canada from 2019 to 2022, followed by balanced market, as LNG export capacity rises sufficiently to support Western Canadian gas production growth and pipeline-export declines (Chart 4). Chart 4 If there are no new Canadian LNG projects receiving FID decisions in the next two years, the domestic market will become over-supplied. This would depress the Canadian benchmark price at the AECO-C hub, and curtail investment in the energy sector. Should this scenario play out, we would expect future Canadian natural gas production to ~ 14.3 Bcf/d by 2040 (Chart 2). Bottom Line: Next year will be crucial for the medium- and long-term Canadian natgas outlook. Any delays in the construction of projects in the development pipeline would depress AECO-C prices and increase uncertainty for future investments in the Western Canadian Select Basin. Can Canada Compete With The U.S.? Canadian LNG projects are in direct competition with those in the U.S. to attract investment for the next wave of needed liquefaction capacity. We believe the Canadian LNG sector offers several advantages, which could favor its development versus the U.S. There are three major points of comparison: Proximity to key demand markets: One crucial advantage of Canadian LNG is its proximity to Asian markets, which will be the principal driver of LNG demand growth (Chart 5). In fact, a voyage from the Canadian Westcoast to Ningbo, China, takes on average 28 days less than from the GOM (Table 2). Moreover, the Canadian Energy Research Institute (CERI) estimates shipping from Eastern and Western Canada offers cost advantage over most liquefaction facilities around the world (Chart 6). Lastly, U.S. GOM exports to China are constrained by the Panama Canal and are expected to reach full transit capacity in early 2020s.6 This would increase U.S. voyage time by close to 14 days. Chart 5 Table 2BC’s LNG Voyage Time To Asia Is Advantageous Canada's Last LNG Opportunity Canada's Last LNG Opportunity Chart 6 Proximity to cheap and abundant feedstock gas: British Colombia’s integrated LNG projects are close to the growing Montney, Horn River and Liard production basins (Map 1).7 Natural gas reserves in these basins are estimated at ~ 41 Tcf, and are located within 400 miles of pipeline infrastructure.8 Moreover, prices have historically been lower compared to Henry Hub, and this is especially true today (Chart 7). We believe AECO-C prices will have to remain at a discount to U.S. prices over the next two years to incentivize LNG investments or disincentivizes production. Chart Chart 7AECO-C's Discount To Henry Hub Widens AECO-C's Discount To Henry Hub Widens AECO-C's Discount To Henry Hub Widens Capital Costs and pipeline systems: Canadian LNG projects have competitive capital costs (Chart 8). However, Canada lacks a developed pipeline system from the Montney, Horn River and Liard basins to the west coast. Each proposed LNG project includes a dedicated pipeline. According to CERI, the cost of building a new pipeline in BC is higher than average due to the mountainous terrain. The U.S. has the advantage in regard to its developed pipeline system connected to the Henry Hub. This allows LNG projects to access an abundant and reliable feedstock by investing in short connection pipelines to the Hub. This makes the U.S. slightly more attractive in terms of capital costs. Chart 8 Bottom Line: Canada offers a competitive alternative to U.S. LNG projects. Western Canadian gas offers the most cost-effective solution to fill the rising Asian gas demand. Short- And Medium-Term Price Outlook We expect Canadian natural gas prices – i.e. the AECO-C benchmark – to modestly pick up and the U.S. Henry Hub prices to remain flat over the coming winter. Going into the winter heating season in November, Canadian gas storage levels were 15.5% lower than last year. Environment Canada continues to project a “normal” winter, which should not pressure prices in any direction. The Enbridge pipeline segment north of Prince George, BC is back at 85% utilization rate from reduced levels of 50-80% following the explosion in early October. As exports pick up, this will alleviate some of the downward pressure on Canadian prices. Over the medium term, however, we believe there is limited upside to Canadian gas prices. British Columbia pipelines to the U.S. already are close to full capacity, and no new projects are under construction (Chart 9). The province’s gas production is poised to grow by 1.56 Bcf/d from the prolific Montney and Horn River plays over the next 5 years. Given the lack of LNG export capacity until at least 2022, the excess capacity will have to find its way through Alberta – where the AECO-C benchmark is determined – increasing the available supply and pushing its price down. Chart 9 Domestic Canadian markets are unlikely to absorb this new supply. Higher-than-expected U.S. production from the Utica and Marcellus plays in the Appalachian Basin will satisfy a growing proportion of Eastern Canadian natural gas consumption, increasing the competition for Western Canadian gas. Reversals of pipeline flows within existing systems so as to import greater volumes from U.S. is evidence of this trend (Chart 10). Furthermore, according to the EIA, close to 1.3 Bcf/d additional pipeline capacity from Northeast U.S. to Canada will be built in the next 2 years. Chart 10 In the U.S., Henry Hub price volatility picked up as the U.S. market experienced an early-season freeze at the start of the November – March heating season, which was accompanied by record low working gas inventories (Chart 11). The April-October 2018 re-fill season paled in comparison to last winter’s withdrawal (Chart 12). Expressed in Days-Forward-Cover (DFC), this year’s October seasonal inventory peak was 16% lower than the historical average and 10% lower than the 5-year average. This was most recently followed by warmer-than-expected temperatures that subsequently crashed prices (Chart 13). Chart 11 Chart 12 Chart 13Weather-Related Natgas Volatility Weather-Related Natgas Volatility Weather-Related Natgas Volatility U.S. natgas prices remain vulnerable to weather shocks. We expect a premium on prices to remain throughout most of the winter season, keeping prices above $3.00/MMbtu. Still, upside price movements remain capped by higher-than-expected production (Chart 14, panel 1). U.S. production reached 90.7 Bcf/d in November 2018, according to EIA data, and is projected to reach 93.5 Bcf/d by the end of next year. This is an 8.4% revision to the EIA June 2018 projections. Moreover, our higher 2019 shale production estimates vs. the EIA estimates will support additional associated gas production. Chart 14 ​​​​​​​ Similarly, domestic demand and net exports are surging, and we expect these trends, especially regarding the U.S. natural gas exports, to continue next year (Chart 14, panel 2 & 3). This implies fundamentals will be fairly balanced in 1H19. The wildcard will be weather. The latest NOAA weather projections show extremely warm weather for the next 6-10 days, and warmer-than-normal temperature for the next two months. This keeps us Neutral.   Hugo Bélanger, Senior Analyst Commodity & Energy Strategy HugoB@bcaresearch.com Robert P. Ryan, Senior Vice President Commodity & Energy Strategy rryan@bcaresearch.com Footnotes 1      According to NEB, since 2010, 43 projects have been proposed. Of those, 35% have been cancelled and 20 were approved and working toward receiving FID. 2      Please see BCA Research’s Commodity & Energy Strategy Weekly Report “U.S. Set To Disrupt Global LNG Market,” published October 4, 2018. Available at ces.bcaresearch.com. 3      Please see “Druckenmiller Urges Fed to Pause Tightening `Blitz’ in WSJ Op-Ed,” published by bloomberg.com on December 17, 2018. 4      The U.S. already has more than 3 Bcf/d of liquefaction capacity. The experience/expertise acquired from these projects will facilitate the construction and permitting of new projects, reducing time delays and uncertainty. Brownfield expansions benefit from economies of scale (e.g. additional trains can share jetty, land, storage, pipeline and permitting). Lastly, the well-developed pipeline system reduces the need to built long direct pipelines to LNG projects, which speeds up the construction. For more details, please see Canadian Energy Research Institute, “Competitive Analysis Of Canadian LNG,” July 2018. 5      The largest LNG project in Canada clearing the FID hurdle is LNG Canada, the 1.8 Bcf/d project in Kitimat, BC, being developed by Shell. It is expected to cost $40 billion, and to be on line in 2023, with the possibility to double capacity eventually. 6      Please see Oxford Institute For Energy Studies, “Panama Canal and LNG: Congestion Ahead?” April 2018. 7      Please see National Energy Board, “Canada’s Role in the Global LNG Market: Energy Market Assessment,” July 2017. 8      Marketable reserves are estimated at 532 Tcf. Please see BC Oil and Gas Commission, “British Columbia’s Oil and Gas Reserves and Production Report,” December 2017. Investment Views and Themes Recommendations Strategic Recommendations Commodity Prices and Plays Reference Table TRADE RECOMMENDATION PERFORMANCE IN 3Q18 Image Trades Closed in 2018 Summary of Trades Closed in 2017 Image

Highlights This Special Report was written with our colleagues in BCA Research's Geopolitical Strategy, led by Marko Papic. In it, we explore the evolution of Russia's role in European natural gas markets vis-a-vis the fast-growing U.S. natural gas production and Liquefied Natural Gas (LNG) export capabilities. So what? Rise of U.S. LNG exports to Europe will benefit gas producers and LNG merchants with access to U.S. supplies. Russia will grow ever-more dependent on China, while retaining a market share in Europe. Why? Exports of U.S. LNG to Europe are set to surge over the next decade. Russia will not be completely displaced, as American LNG fills the gap in European natural gas production. But U.S. LNG will lead to the end of oil-indexing of long-term natural gas contracts, hurting Russian state coffers on the margin... ... And forcing Russia further into the arms of China. Also... A tighter Trans-Atlantic partnership - soon to involve a deep energy relationship - and a budding Sino-Russian alliance will further divide the world into two camps, producing a Bifurcated Capitalism that may define this century. Feature Russia's obituaries have been written and re-written many times since the end of the Cold War. And yet, Moscow continues to play an outsized role in global affairs that is belied by quantitative measures of its power (Chart 1). Chart 1From Bipolarity To Multipolarity From Bipolarity To Multipolarity From Bipolarity To Multipolarity How so? The fall of the Soviet Union was precipitated by the country's sclerotic managed economy, its failure to escape the middle income trap, and its disastrous military campaign in Afghanistan. But before it died, the Soviet Union sowed the seeds for its resurrection. The $100-130 billion (in 2018 USD) spent on building a natural gas pipeline infrastructure into Western Europe was the elixir that revived Russian power. Just as Russia emerged from its lost decade in the 1990s, it caught a break. Western Europe's natural gas demand rose. At the same time, China's epic industrialization created a once-in-a-century commodity bull market (Chart 2). With demand for its resources buoyed on both sides of the Eurasian landmass, Russia once again saw revenue fill its coffers (Chart 3). With material wealth came the ability to rebuild its hard power and put up a fight against an expansionary Western alliance encroaching on its sphere of influence. Chart 2Chinese Industrialization... Chinese Industrialization... Chinese Industrialization... Chart 3...Filled Russian Coffers ...Filled Russian Coffers ...Filled Russian Coffers Is there an existential risk to Russia's business model looming in the form of surging U.S. liquefied natural gas (LNG) export capability (Chart 4)? Not yet. Thanks to a massive drop in European domestic production, U.S. LNG exports will fill a growing supply gap, but will not replace Russia's natural gas exports in the medium term. All the same, the once-lucrative European market no longer holds as much promise as it once did with the arrival of the U.S. LNG supplies. Chart 4U.S. LNG Exports Will Surge American Pipes, Russian Gripes? American Pipes, Russian Gripes? In order for Russian natural gas exports to Europe to be permanently displaced, Europe would have to build out new LNG capacity beyond 2020, restart domestic production by incentivizing shale development, or turn to alternative energy sources with large base-load potential, such as nuclear power. None of these are on the horizon. With ~15% of its government revenue sourced from natural gas sales, Russia is as much of a one-trick pony as there is in macroeconomics. While we do not foresee that pony heading off to the glue factory, Russia will face some considerable risks in the future, starting with the shift away from the rigid oil-indexed contracts it favors (which lock the price of natural gas to that of oil). As such, the risk to Russia is not that it loses market share in Europe's energy market, but that this market share yields much smaller income in the future, as gas-on-gas pricing competition increases. The U.S. Shale Revolution Goes Global Our commodity team has presented a compelling case for why investors should expect an increase in U.S. LNG exports beyond the current EIA forecast.1 Increasing volumes of associated natural gas production in the Permian Basin in west Texas, which will have to be transported from the basin so as not to curtail oil production, will drive a large part of the expected growth in LNG exports. Our commodity team expects that a major LNG export center will be developed in south Texas, in Corpus Christi, over the next five years, just as the U.S. surpasses 10 Bcf/d of exports in the middle of the next decade.2 At the same time, global LNG demand is expected to rise at an impressive 1.7% annual rate to 2040 (Chart 5). A few key markets will lead this trend (Chart 6). Based on BCA Commodity & Energy Strategy calculations, world LNG export capacity is expected to go from 48 Bcf/d in 2017 to 61 Bcf/d by 2022 (Chart 7). The majority of the new capacity (53%) will come from the U.S., while 18% will come from Australia and 15% from Russia. Chart 5Global LNG Demand Growth Likely Outpaces Current Expectations American Pipes, Russian Gripes? American Pipes, Russian Gripes? Chart 6Supply - Demand Imbalances Will Fuel LNG Demand Globally American Pipes, Russian Gripes? American Pipes, Russian Gripes? Chart 7LNG Export Capacity Growth American Pipes, Russian Gripes? American Pipes, Russian Gripes? The pickup in Australian export capacity is already impressive. While being a relatively small natural gas producer - the eighth largest, accounting for 3% of world output - it has already become the second largest LNG exporting country in the world with over 7.5 Bcf/d of exports. The bulk of new liquefaction facilities will be operational in 2019. Most of Australia's LNG trade lies with Asia, given its geography. The U.S., whose LNG export terminals will be located in the Gulf of Mexico, only has 3 Bcf/d of liquefaction capacity today. Most of its LNG exports also go to Asia (Table 1), but that may change as the current capacity expansion will see exports rise to just over 9 Bcf/d in 2020.3 Furthermore, American gas will compete with surging Australian LNG exports and a build-up of Russian pipeline export capacity to China, which is set to start delivering gas to the country in 2019. Table 1U.S. LNG Exports By Country American Pipes, Russian Gripes? American Pipes, Russian Gripes? Europe, on the other hand, has massive regasification capacity slack and thus requires only minimal capex to begin importing large volumes of U.S. LNG. Europe has 23 Bcf/d regasification capacity, with a very low utilization rate of just 27%. This means that it has ~ 16 Bcf/d capacity available, more than enough to absorb all of expectant U.S. ~ 6-7 Bcf/d exports in the next couple of years.4 Bottom Line: The U.S. shale revolution is going global, with U.S. LNG exports set to surge over the next 5-10 years. While some of that capacity will find its way to Asia, those markets will also be flooded with Australian LNG and Russian piped natural gas. Europe, on the other hand, is filing just a quarter of its LNG import capacity, making a Trans-Atlantic gas alliance a match made in heaven. From Cold War To Gas War? If half of the currently proposed, pre-FID, LNG export projects were built in the U.S., American capacity would grow to potentially ~26 Bcf/d by 2030. Europe would need only one or two extra LNG import terminals to build over the next two decades to absorb this volume, as its current capacity is able to import nearly every molecule coming out of North America (Chart 8). Chart 8Europe Has Plenty Of Regasification Capacity American Pipes, Russian Gripes? American Pipes, Russian Gripes? Will this new U.S. LNG displace Europe's imports of Russian natural gas? The short answer is no. By 2030, Europe's supply-gap (i.e. domestic supply minus domestic consumption) is estimated to reach 36 Bcf/d. The U.S. could cover a large part of this gap if only half of the proposed pre-FID projects are constructed. However, if Europe's demand remains stable over this period, Europe will still import roughly 20 Bcf/d of Russian natural gas, which in 2017 amounted to 35% of Europe's natural gas consumption. If the U.S. fills 100% of the increase in Europe's supply-gap, it means new Russian natural gas production (the IEA and BP expect Russian production to keep increasing until 2030) will not be sent to Europe. Hence, even if it does not displace old Russian exports, it will limit Russia's ability to export its new natural gas. Europe's demand for natural gas is not likely to be stable. Despite sclerotic growth and generally weak population growth, European governments have tried to incentivize natural gas consumption due to its low emission of CO2 (Table 2). As such, investors should expect further displacement of coal and nuclear power generation in favor of natural gas. Table 2Natgas Emits Less CO2 American Pipes, Russian Gripes? American Pipes, Russian Gripes? Thus, U.S. exports will simply replace Europe's domestic production, which is facing considerable declines. The U.K. North Sea production will decrease 5% annually due to the lack of capex and the large number of fields reaching a mature state. Meanwhile, the Netherlands is phasing-out its Groningen field by 2030. Finally, Norwegian gas production is likely to stagnate after reaching record levels in 2017. The second reason that Europe will not be able to sever its relationship with Russia is that its LNG import terminals are largely located in countries that are not massively dependent on Russian imports (Map 1). The two major LNG terminals serving Central and Eastern Europe are the Swinoujscie terminal in Poland - finished in 2015 - and the Adria project in Croatia, to be completed in 2020. Map 1European Natural Gas Geography American Pipes, Russian Gripes? American Pipes, Russian Gripes? The Polish LNG terminal will do little to alleviate the dependency of countries further East - Belarus, Ukraine, Bulgaria, Hungary, and Slovakia - from Russia as it currently satisfies only one third of Poland's natural gas needs, and is projected to reach 50% by 2022 once the expansion is completed. This could significantly cut Russian exports to Poland, but not completely end them.5 The Croatian LNG terminal will likely make a very small dent in the overall reliance of the Balkans on Russian natural gas, as once it satisfied Croatian demand, little will be left over for the rest of the region. Beyond these two terminals, Europe will have to invest in pipeline infrastructure in order to reverse the flow of pipelines currently taking gas from the East to the West. At some point in the distant future, we could see a scenario where American natural gas flows even through Cold War era, Soviet-built pipelines deep into Central and Eastern Europe. But given the steep declines in West European natural gas production, this day will come after 2030. Bottom Line: Dreams of displacing Russian natural gas in Europe with American are overstated. European imports of U.S. LNG are likely to skyrocket, but that will merely replace the massive decline in West European and North Sea production. What does that mean for geopolitics? It means that Russia will continue to have a role to play in Europe, but its share of European imports will decline. As such, Europe will have options. If it builds more LNG import terminals, it could expand those options beyond American LNG imports. However, Russian geopolitical influence will not be displaced completely. Russian Coffers Will Take A Hit Although Russian natural gas will continue to course through Europe's veins, its state coffers are nonetheless going to take a hit. European governments are actively diversifying away from Russia via U.S. LNG imports, and buyers generally are shortening the tenor of contracts as they seek more flexible pricing.6 The growth in the global LNG market, fueled by surging U.S. production, will ultimately allow Asian and European markets to diversify away from oil-indexed pricing - which tends to be priced higher than gas-on-gas pricing - and expand access to U.S. supplies.7 The EU has co-financed or committed to co-finance LNG infrastructure projects valued at ~ 640mm euros to secure U.S. LNG. Ultimately, as more and more U.S. LNG moves toward Europe, markets will move toward short- and long-term contracts priced in USD/MMBtu (indexed to Henry Hub, LA, prices), much like Brent crude oil priced in USD/bbl. European markets have already seen this shift, as illustrated in Chart 9. Chart 9European Gas-On-Gas Pricing Is Rising American Pipes, Russian Gripes? American Pipes, Russian Gripes? The totality of U.S. export prices is determined by gas-on-gas pricing - i.e., gas priced in USD/MMBtu as a function of gas supply-demand fundamentals. These contracts are without the restrictions found in many oil-indexed contracts. In the U.S., the presence of a deep futures market delivering natural gas to Henry Hub, LA, allows flexible long-term financing and short- and long-term contracting that can be hedged by buyers and sellers. According to Royal Dutch Shell, the spot LNG market doubled from 2010 to 2017, accounting for ~ 25% of all transactions, most of it due to the prodigious increase in U.S. LNG supply. While in Europe the share of LNG spot and short-term deals is small relative to the overall market, it is growing (Chart 10). With U.S. LNG volumes becoming increasingly available in Europe, market participants will be inclined to turn to the LNG spot market to buy or sell outside contracted volumes. This will deepen the development of European natgas markets: in any fully developed market, spot trading is followed by forward contracting, then futures trading using contracts settling against a spot price.8 Chart 10Expect More LNG Spot Trading American Pipes, Russian Gripes? American Pipes, Russian Gripes? Russia is a low-cost gas producer in Europe and will be committed to maintaining its market in Europe. However, with U.S. LNG export capacity potentially reaching ~14 Bcf/d by 2025, from ~3 Bcf/d today, it is entirely likely that Russia will find itself in a price war defending existing market share in Europe at lower prices. Its preferred way of doing business, via oil price indexed contracts, will be challenged overnight by a surge in U.S. LNG imports. Bottom line: The EU and its member states are actively diversifying gas supply sources away from Russia via U.S. LNG purchases. This will lower the marginal price of all gas bought and sold in Europe, all else equal, resulting in lower margins for all sellers of gas and better prices for consumers. Ultimately, the European natural gas market will resemble every other fully developed commodity market, operating on razor-thin margins. This means whatever rents were available in this market will be dissipated as competition increases. Investment And Geopolitical Implications The immediate investment implication of these developments is that gas producers and LNG merchants with access to U.S. shale-gas supplies, processing trading, and risk-management capabilities should be favored in this evolving market. Beyond the short term, however, we expect several ongoing geopolitical developments to be ossified by the flood of American LNG steaming towards European shores: Sino-Russian alliance deepens: As Russian natural gas exports to Europe stagnate, its pipeline infrastructure build-out will increase its exports to China to 3.8 Bcf/d by 2019. China will become the growth market for Russian energy producers, deepening the move between the two former Cold War foes to stabilize their relationship. Although it may seem obvious that Russia would retain leverage in such a relationship - given that it can "turn off the lights" to Beijing at whim - we actually think that Beijing will hold all the cards.9 Europe will have an incentive to keep diversifying its natural gas supplies. Meanwhile, Chinese demand is likely to keep growing. As such, China will become Russia's main option for revenue growth. And as the old adage goes, the customer is always right. Trans-Atlantic alliance deepens: Despite the fears that the "Trump Doctrine" would lead to American isolationism - fears that we shared in 2017 - the growing U.S.-European LNG connection will ensure that the Trans-Atlantic alliance - forged 70 years ago in blood - will be saved via brisk energy trade.10 A growing European energy deficit with the U.S. will also resolve - or at least alleviate - the main source of marital problems in the relationship: Europe's trade surplus. Bifurcation of capitalism: A key theme of BCA's Geopolitical Strategy is that the age of globalization will yield to the world's segmentation into spheres of influence.11 A deepening Trans-Atlantic alliance, when combined with a budding Sino-Russian relationship, will lead to a Bifurcated Capitalism system where the Trans-Atlantic West faces off against the Eurasian East. What would such a Bifurcated Capitalism mean for investors? Time will tell. But it may mean that thirty years of global capitalism (1985 to roughly today) may give way to something more common in human history: a world dissected into spheres of influence where flows of capital, goods, and people within spheres are relatively smooth and unencumbered, yet flows between the spheres are heavily impeded. Marko Papic, Senior Vice President Chief Geopolitical Strategist marko@bcaresearch.com Hugo Bélanger, Senior Analyst Commodity & Energy Strategy HugoB@bcaresearch.com Robert P. Ryan, Senior Vice President Commodity & Energy Strategy rryan@bcaresearch.com Pavel Bilyk, Research Associate Commodity & Energy Strategy pavelb@bcaresearch.com 1 Please see "U.S. Set To Disrupt Global LNG Market," published by BCA Research's Commodity & Energy Strategy October 4, 2018. It is available at ces.bcaresearch.com. 2 Please see "The Price of Permian Gas Pipeline Limits," by Stephen Rassenfoss, in the Journal of Petroleum Technology, published July 19, 2018. 3 Following a two-year pause in project Final Investment Decisions (FIDs) from 2016 to 2017, potential FIDs in 2018 and 2019 could increase the U.S. capacity to ~ 14 Bcf/d by 2025. This will make the U.S. the second-largest exporter of LNG in the world, surpassing Australia. This new wave of investment is yet to be finalized. Therefore, final decisions in 2H18 and 2019 will be crucial to determine the medium-term potential of U.S. LNG. 4 Cheniere Energy, the largest U.S. LNG exporter, expects ~ 50% of its exports to go to Europe, according to S&P Global Platts. Please see "US LNG vs Pipeline Gas: European Market Share War?" published April 2017 by Platts. 5 Additionally, if the Baltic Pipe Project, moving gas from Norway to Poland, reaches FID in 2019, this would help Poland diversify its energy supply from Russia, as the country would cover close to all its domestic demand via its production + LNG and new pipeline imports. 6 Please see "US and Russia step up fight to supply Europe's gas," published by the Financial Times August 3, 2017. See also "Russia's gas still a potent weapon," also published by the FT, re the so-called collateral damage suffered by Europe when Russia cut off gas supplies to Ukraine in January 2009. 7 For the EU, supply diversification is a particularly important goal. On July 25, 2018, the European Commission and the U.S. issued a joint statement, in which the EU agreed to import more LNG from the U.S. "to diversify and render its energy supply more secure. The EU and the U.S. will therefore work to facilitate trade in liquefied natural gas," according to a press release issued August 9, 2018, by the Commission. Re Japan's diversification strategy, please see "Feature: US LNG sources fit with Japan's desire for route diversity: minister," published by S&P Global Platts September 27, 2018. 8 Please see Darrell Duffie, Futures Markets (1988), Prentice-Hall; and Jeffrey C. Williams, The Economic Function of Futures Markets (1986), Cambridge University Press. Longer-term deals already are being signed under flexible Henry Hub futures-based indexing terms in the U.S. This is occurring because the U.S. LNG market is able to tap into futures liquidity that supports hedging by natgas producers and consumers. Please see "Vitol-Cheniere Pact Shows Long-Term LNG Deals Aren't Dead," published by bloomberg.com September 17, 2018. 9 Please see BCA Geopolitical Strategy Special Report, "The Embrace Of The Dragon And The Bear," dated April 11, 2014, available at gps.bcaresearch.com. 10 Please see BCA Geopolitical Strategy Weekly Report, "The Trump Doctrine," dated February 1, 2017, available at gps.bcaresearch.com. 11 Please see BCA Geopolitical Strategy Monthly Report, "Multipolarity And Investing," dated April 9, 2014, and Special Report, "The Apex Of Globalization - All Downhill From Here," dated November 12, 2014, available at gps.bcaresearch.com.

Highlights Chart of the WeekIncreasing Gas-On-Gas Pricing Will Disrupt Global LNG Markets U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market Growth in the global Liquefied Natural Gas (LNG) market will be fuelled by surging U.S. natural gas production, which will allow consumers in Asian and European markets to diversify away from oil-indexed pricing - with its attendant geopolitical risks - and falling European gas production. As a result, markets will move toward short- and long-term contracts priced in USD/MMBtu (Chart of the Week). This will favor gas producers and LNG merchants with access to U.S. shale-gas supplies, where production is growing at double-digit p.a. rates (Chart 2). Well-developed trading and risk-management markets in the U.S. - centered on Henry Hub, LA - will incentivize consumers to shorten the tenor of oil-indexed contracts, replacing them with hedgeable futures-based contracts. These markets allow producers and merchants to offer short- and long-term contracts that meet consumer preferences. As the global LNG market grows, shipping companies, along with producers and merchants with worldwide trading and transport capabilities - or access to such capabilities - will grow market share at the expense of exporters tied to the more rigid oil-indexing regime (Chart 3). Energy: Overweight. We remain long call spreads along the Brent forward curve over February - August; these positions are up an average 88.4% since inception, basis Tuesday's close. The long S&P GSCI position we recommended in December is up 21.8%, on the back of higher oil prices and backwardated crude-oil forward curves. Base Metals: Neutral. Copper is holding on to recent gains - up ~ 11% from its mid-August trough, following oil higher. Precious Metals: Neutral. Gold hovers around $1,200/oz, following the Fed's meeting last week, which resulted in a 25bp increase in fed funds to 2.25%. Ags/Softs: Underweight. The trade agreement to be signed by U.S. officials at the end of November with their counterparts in Mexico and Canada removes some of the uncertainty weighing on ag markets. Upward revisions to 2017 carry-out estimates by the USDA continue to pressure corn and beans. Chart 2Surging Production, Market Depth Favor U.S. Gas Producers And Merchants U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market Chart 3Growing LNG Imports Will Favor Shippers, Producers And Merchants U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market Feature Surging U.S. natural gas production will continue to find its way to global LNG markets over the next decade. The persistence of oil-indexing in Asian LNG contracts will fuel the growth of U.S. exports, given the arbitrage between cheaper natural gas - priced basis supply-demand fundamentals for gas - and more expensive oil-indexed contracts.1 Added to this cost advantage, U.S. exports can be linked to hedgeable futures prices, using NYMEX Henry Hub, LA, contracts. These stability-of-supply and pricing advantages also allow LNG buyers in Asia and Europe to diversify away from oil-production disruption risks, which can send prices sharply higher, and being overly reliant on Russian imports. Chart 4U.S. LNG Exports Will Surge U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market This will give global consumers an incentive to continue shortening the tenor of more rigid oil-indexed LNG contracts, and to replace them with hedgeable contracts referencing Henry Hub, LA, futures contracts priced in USD/MMBtu. While a fairly stout increase of U.S. LNG exports already is expected by the EIA and IEA, we believe this dynamic likely results in export volumes that are higher than the ~ 10 Bcf/d expected by 2023, and close to 15 Bcf/d toward the end of the 2020s (Chart 4).2 Increasing volumes of associated natural gas production in the Permian Basin in west Texas, which will have to be transported from the basin so that it does not curtail oil production, will drive a large part of this growth. We expect a significant LNG export center to be developed in South Texas in Corpus Christi over the next five years or so, just as the U.S. surpasses 10 Bcf/d of exports in the middle of the next decade.3 Flexible pricing of LNG contracts basis Henry Hub already is supporting the buildout of Gulf Coast exports via take-or-cancel contracts. These contracts are replacing the more restrictive take-or-pay contracts still used in Asia.4 This will continue to evolve, allowing supply development to be hedged via Henry Hub natgas futures. Consumers ultimately benefit from cheaper supplies and hedgeable risks. This is not to say other benchmarks will fall away. There is always room for regional benchmarks - even oil-based benchmarks such as the Japan Crude Cocktail (JCC), or the spot- and swaps-market reference Japan/Korea Marker (JKM).5 The global crude oil market accommodates such regional benchmarks: WTI crude oil futures are the benchmark for oil markets in the Americas, while Brent crude oil futures serve as the benchmark for global markets. Crude oils with different chemical properties can be priced relative to these benchmarks for delivery anywhere in the world. The global LNG market could retain an Asian benchmark, but a lot of work needs to be done in terms of building the supporting infrastructure - pipelines, regasification facilities, deep futures markets, etc. - to make that happen.6 We are inclined to believe the build-out of U.S. LNG export capacity will occur before these pieces fall into place: Scale has never been an issue in the U.S. oil and gas patch. Global Supply - Demand Overview Chart 5Global LNG Demand Growth Likely Outpaces Current Expectations U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market Global LNG demand is expected to rise at an impressive 1.7% p.a. out to 2040 (Chart 5). However, local supply and demand levels are increasingly unbalanced, implying that cross-border pipeline and LNG imports will need to increase as gas demand rises.7 A few key markets lead this trend, as seen in Chart 6, which illustrates the supply-gap in major consuming countries. Supply gaps are poised to grow in Emerging Asia and Europe, due to elevated demand growth in the former and lack of supply growth in the latter. World LNG demand grew by 10% last year, with Europe and Emerging Asia accounting for more than 95% of this increase. However, last year's stellar growth numbers should not be considered as the baseline growth forecast.8 The latest projections show demand increasing by 21 Bcf/d by 2025 - taking LNG imports from 38 Bcf/d at present to 58 Bcf/d by then. This implies a lower annualized growth rate of 5.5%. Chart 6Supply - Demand Imbalances Will Fuel LNG Demand Globally U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market LNG Supply On Growth Trajectory World LNG export capacity is expected to go from 48 Bcf/d in 2017 to 61 Bcf/d by 2022 (Chart 7), with 53% of the additional capacity coming from the U.S., 18% from Australia, and 15% from Russia.9 Chart 7LNG Export Capacity Growth U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market Our baseline forecast for the LNG market foresees a short-term supply surplus in 2020 (Chart 8), followed by a catch-up in demand and new waves of projects between 2024 and 2030. Among the supply-side developments we are following: Chart 8New LNG Projects In The Pipeline U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market The Australian LNG market has undergone massive change in the last five years. While being a relatively small natural gas producer (8th largest producer, accounting for ~ 3% of world output), in 2015, the country became the second largest LNG exporting country in the world with now over 7.5 Bcf/d of exports. The bulk of new liquefaction facilities will be operational in 2019 with the completion of new trains at the Wheatstone, Prelude Floating and Ichthys LNG facilities.10 This will bring Australian total LNG export capacity to over 10 Bcf/d. Importantly, most of Australia's LNG trade is with Emerging Asian countries. This region still relies mostly on oil-linked, long-term, and fixed-destination contracts. Absent the OPEC market-share war of 2014 - 2016, when oil prices collapsed, Australia's LNG prices are subject to oil price risks and volatility (Chart 9). Chart 9Asian Oil-Indexed Contracts Trade Above Spot LNG U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market The U.S. currently has ~ 3 Bcf/d liquefaction capacity and is increasingly exporting to Asian countries (Table 1). The present wave of projects under-construction will push capacity to ~ 9 Bcf/d in 2020. Following a two year pause in project Final Investment Decisions (FIDs) from 2016 to 2017, potential FIDs in 2018 and 2019 could increase the U.S. capacity to ~ 14 Bcf/d by 2025. This will make the U.S. the second-largest exporter of LNG in the world, surpassing Australia. This new wave of investment is yet to be finalized; therefore, final investment decisions in 2H18 and 2019 will be crucial to determine the medium-term potential of U.S. LNG. If a majority of these projects goes through, U.S. capacity risks being overbuilt for the next decade (Chart 10). Table 1U.S. LNG Exports By Country U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market Chart 10U.S. LNG Capacity Risks Becoming Overbuilt U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market Importantly, U.S. LNG exports already have had a massive impact on the global LNG market. The totality of U.S. export prices are determined by gas-on-gas pricing - i.e., gas priced in USD/MMBtu as a function of gas supply-demand fundamentals. Just as importantly, these contracts are without destination restrictions found in many oil-indexed contacts. In the U.S., the presence of a deep futures market allows flexible long-term contracting.11 According to Royal Dutch Shell, the spot LNG market doubled from 2010 to 2017, accounting for ~ 25% of all transactions, most of it due to the prodigious increase in U.S. LNG supply.12 An overbuilt U.S. market would increase spot LNG trading. Our own calculations based on EIA data indicate the U.S. could have too much capacity relative to demand in 2018 - 19, but goes into balance in 2020 - 2022.13 Russia's natural gas production is projected to increase from 66.7 Bcf/d in 2017 to 70.1 Bcf/d in 2023. However, the bulk of this increase will cover new pipeline exports. The country's LNG capacity is expected to grow by ~ 2.5 Bcf/d with the completion of trains at the Yamal, Vysotsk and Portovaya export facilities. Despite its low LNG capacity, Russia remains a key player in the LNG market. Its rising pipeline capacity connected to China - the fastest growing market in the world - competes directly with global LNG supplies. For Russia, the rise of natural gas availability on a global basis - in the form of LNG - shakes its foreign relationships and policies to the core. In loosening the once-tight relationship between buyers and sellers, the rise of spot LNG supplies will favor consumers and energy security, and foster the development of longer-term contracting.14 Global LNG Demand Could Outpace Supply By our reckoning, some 62% of additional global gas demand of 160 Bcf/d will be covered by rising domestic production, 12% by rising trans-national pipeline capacity, and the remaining 26% by LNG imports.15 Longer-term, we expect LNG and natural gas demand to keep rising as industry demand expands and major coal consumers build up their natural gas and renewables usage. As a result, LNG consumption will increase at a rate of ~ 3% p.a. until 2040, as overall gas demand grows ~ 1.7%.16 Key demand-side developments: Table 2Natgas Emits Less CO2 U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market China's environmental reforms, supply-side industrial policies and continued economic growth will be the engine of global natural gas and LNG growth in the next decade. The Middle Kingdom's natural gas demand grew 15% to 23 Bcf/d in 2017, of which 54% came from additional LNG. This short-term growth surge required spot and short-term LNG imports, which pushed up North Asian LNG spot prices. Despite our expectation that China will continue leading global LNG growth, we believe 2017 to be an outlier. Two factors contributed to the rise in spot prices: To tackle its massive pollution without significantly altering economic development and growth, China's environmental policies favor natural gas as a bridge to a low-carbon economy, since natgas contains half the carbon content of coal (Table 2). China's supply-side reforms and winter capacity cut led to a spike in spot LNG demand, which had to be covered in global LNG markets. China has an extremely low level of storage to deal with seasonal natgas consumption fluctuations; this forces the country to rely on spot LNG to meet short-term peaks in gas demand (Chart 11). Chart 11China's Minimal Natgas Storage Forces It To Rely On Spot Markets U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market While these factors still dominate Chinese markets, new Russian pipeline capacity is expected to start delivering gas in 2019, the ~ 247 bcf of additional domestic storage capacity and the rise in spot LNG supply will mitigate the effect. In addition, China is limited in its regasification capacity. Data re projects under construction and demand forecasts indicate the average utilization would rise to ~ 90% in 2020. Winter usage would push this to ~ 100% rapidly, constraining its ability to meet winter demand with spot LNG. As a result, we expect Asian spot LNG prices to rise above contracted oil-indexed prices next winter, but less so in 2020 and 2021. Longer term, China's gas consumption is expected to grow 4.6% p.a., outpacing the 4.0% p.a. domestic production growth. Some 23% of the gap will come from Russian and Turkmenistan pipeline imports. Europe's supply-gap rose in the past 3 years, and is expected to continue to widen. Unlike the rest of the world, this gap is growing because of supply depletion instead of strong demand growth. In fact, demand is expected to remain flat, based on the IEA's forecast of Europe's long-term growth. On the other hand, total European gas supply has decreased by 16% since 2010, and is expected to continue decreasing at a similar pace, reaching 21 Bcf/d in 2023 from 25 Bcf/d in 2017. These declines in European natgas supply are due to: The phase-out by 2030 of Netherlands' Groningen field. Continued concerns about the impact of natural gas production on earthquakes in nearby communities pushed the Dutch government to adopt, in March 2018, a plan to gradually stop gas extraction at the Groningen field. Production has been decreasing since 2013 and is expected to decrease by around three quarters between now and end-2023. U.K. natural gas production will decrease by 5% p.a. due to the lack of capex and the large number of fields reaching a mature state. Stagnation in Norway's gas production following its record production level in 2017. Europe's regasification capacity has considerable slack, which will allow it to expand its import volumes. Europe currently has 23 Bcf/d regas capacity, with a very low 27% utilization in 2017. This means it has ~16 Bcf/d capacity available. With the U.S. is expected to raise its exports by ~ 6 - 7 Bcf/d in the next couple of years, Europe could potentially absorb the entire U.S. LNG exports if it desires to diversify its source of energy supply. Pressure Builds For Competitive LNG Markets Chart 12Expect More LNG Spot Trading U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market The movement toward an integrated global market - similar in structure to current oil markets - will be driven by sharply increased U.S. LNG exports, and more competitive pricing of LNG as a function of gas supply-demand fundamentals. This latter effort likely will find support from Japanese and EU regulators. In addition, U.S. exporters already are using futures-based pricing - using Henry Hub contracts - which provide greater flexibility for producers, consumers and merchants to hedge their risk. Either Asian markets will develop viable regional benchmarks, or the global market will increasingly adopt Henry Hub indexing. Again, this is a typical commodity-market evolution: wheat can be priced for delivery anywhere on the planet using Chicago Board of Trade indexing. Asia lacks an integrated pipeline network. Market-based pricing of gas as gas - i.e., based on regional supply-demand gas fundamentals - also has not fully developed. LNG-on-LNG competition is considered a way to promote market-based pricing. Thus, the rise in spot and short-term contracts priced on the basis of natural gas fundamentals in the region already visible in the data likely will continue (Chart 12). In addition, if we see the oil price spike we expect in 1Q19 - driven by the loss of Iranian exports due to U.S. sanctions, continuing losses in Venezuelan exports due to economic collapse, and still-strong global oil demand - LNG priced on gas fundamentals will become even more attractive.17 LNG consumers' exposure to oil prices - via oil-indexed supply contracts - is a disadvantage to consumers with super-abundant natural gas supplies (Chart 13).18 That said, the U.S. export capacity remains limited, thus it cannot completely substitute for the global trade being done basis oil-indexed LNG contracts. Still, higher oil prices will incentivize a shift to contracts with prices determined by natgas fundamentals, which favors continued growth in U.S. exports. If anything, it will push for a faster-than-expected expansion of U.S. LNG export capacity. Chart 13LNG Buyers Will Resist Oil-Indexed Exposure BCA Ensemble Forecast Lifts Brent To $95/bbl, As Market Tightens BCA Ensemble Forecast Lifts Brent To $95/bbl, As Market Tightens Bottom Line: Growth in global LNG markets likely will be faster than expected, as the U.S. develops its export capacity and continues to offer futures-based pricing. This will further reduce the attractiveness of rigid oil-indexed contracts. Gas producers and LNG merchants with access to U.S. shale-gas supplies, possessing trading and risk-management capabilities that allow them to offer flexible contracts globally, are favored in this quickly evolving market. Hugo Bélanger, Senior Analyst HugoB@bcaresearch.com Pavel Bilyk, Research Associate pavelb@bcaresearch.com Robert P. Ryan, Senior Vice President Commodity & Energy Strategy rryan@bcaresearch.com 1 The LNG cost structure is complex. A recent paper from the Oxford Institute For Energy Studies estimates U.S. breakeven costs for new LNG projects are roughly $7/MMBtu delivered, or ~ $4/MMBtu over current Henry Hub, LA, spot prices. This includes liquefaction costs, and transportation costs from the U.S. Gulf to Asia of ~ $1.50/MMBtu, and ~ $0.70/MMBtu from the U.S. Gulf to northwest Europe. Regasification charges and entry fees likely add ~ $0.70 to $1/MMBtu. Please see "The LNG Shipping Forecast: costs rebounding, outlook uncertain," published by the Oxford Institute For Energy Studies, March 2018. Transport costs are variable, and are only one part of the LNG pricing equation. The benefits of diversifying supplies cannot be overlooked, nor can the benefit of gas-on-gas pricing in a high-priced crude oil market. See also see "US powerhouse in the making," published June 14, 2018, by petroleum-economist.com. 2 Please see the International Energy Agency's Gas 2018 report published in March, particularly the discussion of supply beginning on p. 67. 3 Please see "The Price of Permian gas Pipeline Limits," by Stephen Rassenfoss, in the Journal of Petroleum Technology, published July 19, 2018. 4 Take-or-cancel contracts employ option-like features - e.g., cancelation payments that function as an option premium - that give buyer and seller flexibility in cancelling a contract or delivery in a manner that allows the seller to cover fixed costs, not unlike a tolling contact. This is possible because of the hedging latitude provided by the NYMEX natural gas futures market, which has Henry Hub, LA, as its delivery point. Please see "The Shift Away from Take-or-Pay Contracts in LNG," published by the Atlanta-based law firm King & Spalding on its Energy Law Exchange blog September 13, 2017. 5 Platts' JKM spot assessment for November was $11.35/MMBtu, which was down 6% from October assessments. Please see "Platts JKM: Asia November LNG spot prices fall on thin demand," published by S&P Global Platts September 21, 2018. The NYMEX JKM forward curve peaks at $13.50/MMBtu for January 2019 deliveries, and backwardates thereafter. 6 Big LNG consumers' antitrust regulators are increasing pressure on overly restrictive contracts, which could open these markets to further competition over the next three years. Japan's Fair Trade Commission (JFTC) in 2017 concluded a review of term LNG contracts, which raised the possibility heretofore standard term contract features - e.g., limits on destinations and diversions, and take-or-pay provisions - could run counter to its antimonopoly laws. Japan is the largest importer of LNG in the world, taking ~ 11 Bcf/d. Meanwhile, in June of this year, the European Commission opened an investigation into long-term LNG contracts between its member states and Qatar Petroleum. Akin Gump Strauss Hauer & Feld, the Washington, D.C., law firm, expects a ruling on destination and profit-sharing clauses that severely limit re-trading of LNG by purchasers. Akin Gump expects a ruling in the course of the next 3 years. While Japan's FTC did not specify remedies, it is possible buyers gain rights to re-sell and re-direct cargoes, following these reviews. This would make markets more competitive, although indexing the price of LNG to oil-based formulas likely will hinder this process. Please see "Revisiting LNG Resale Restrictions - Implications of Recent EU Decisions," published on the firm's website August 2, 2018. 7 Natural gas demand grew by 16% since 2010, according to the BP 2018 Statistical Review of World Energy, and is expected to grow by a cumulative 47% (1.6% p.a.) by 2040. 8 Many idiosyncratic factors helped Chinese LNG imports reach such an exceptional growth rate, mostly weather-related: China's environmental policy is resulting in widespread substitution of coal for natural gas for space-heating purposes, which, in colder-than-expected winters, results in surging demand. We do not believe this will be a long-term seasonal influence: Physical facilities are being built out to accommodate higher supply and demand. 9 World liquefaction capacity will rise to ~ 61 Bcf/d in 2022, based on our calculations of projects under construction. The bulk of additional capacity will come from the U.S., Australia and Russia. 10 Capacity of 0.6, 0.5 and 1.2 Bcf/d, respectively. 11 Please see U.S. Department of Energy, office of Oil & Natural Gas, LNG Monthly. 12 Like most globally traded commodities, LNG can be traded in USD/MMBtu. The global financial and clearing system already is set up to accommodate commodity transactions denominated in USD, therefore we do not see any impediments to extending it further into the LNG market. 13 Please see Chart 10 footnote for details. 14 We will be exploring the geopolitical dimension of LNG next week in a Special Report written with our colleagues in BCA Research's Geopolitical Strategy. Please see Meghan L. O'Sullivan, Windfall: How the new energy abundance upends global politics and Strengthens America's Power (New York: Simon & Schuster, 2012). 15 From 2017 to 2040, based on BP projections. The bulk of additional pipeline capacity will come from Russia with 12 Bcf/d destined to China and Europe expected to come on line in 2019. 16 Please see the International Energy Agency's GAS 2018 report published in March, BP's BP Statistical Review Of World Energy 2018 report published in June, Shell's Shell LNG Outlook 2018 report published in February, and U.S. the Energy Information Administration's International Energy Outlook 2017 report published in September. 17 Please see our most recent assessment of global oil fundamentals, published September 27, 2018, entitled "Risks From Unplanned Oil-Outage Rising; OPEC 2.0's Spare Capacity Is Suspect," and our updated forecast, "Odds Of Oil-Price Spike In 1h19 rise; 2019 Brent Forecast Lifted $15 To $95/bbl," published September 20, 2018. 18 Asia LNG prices are usually linked to the JCC according to predetermined formulae. However, the exact formula remains opaque and varies with each contract. Based on our calculations, we concluded that since 2010, the average formula uses a slope of ~14% on JCC prices lagged 4 months, with very low s-curve components and a constant. Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Commodity Prices and Plays Reference Table U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market Trades Closed in 2018 Summary of Trades Closed in 2017 U.S. Set To Disrupt Global LNG Market U.S. Set To Disrupt Global LNG Market

The old cyclical market axiom that "nothing cures low prices like low prices" has never held
truer than in today's oil market.