Natural Gas

Special Report

Highlights We expect limited upside to gas prices from current levels as the comeback of US Liquefied Natural Gas (LNG) exports will add to an already oversupplied market. In the short term, prices will remain below full-cycle costs. This will limit investment in LNG and the infrastructure required to get it to market in future. European storage will peak below maximum capacity. Gas forwards are pricing a rapid drawdown over the winter. Whether this occurs depends critically on winter demand in the northern hemisphere and a continued recovery in world economic activity. In the US, declining production in the prolific natural-gas shales and rising LNG exports will help balance its domestic gas markets: Rig counts in the Appalachian basin are at multiyear lows, which is weighing on output. Collapsing oil production in major shale-oil basins is dramatically reducing associated gas output, which represents more than 16% of total gas production. Still, a second wave of COVID-19 that results in another round of widespread lockdowns could send natgas prices back below $2/MMBtu as storage fills. Over the next few months, the balance of risk in natgas markets – especially in the US – remains to the downside, though highly uncertain. We are staying on the sidelines for now.  Over the medium term, global demand for LNG will catch up with supply by 2024, supported by additional coal-to-gas switching and slower supply growth. Feature The mounting probability inventories will fill up to maximum capacity before this coming winter’s heating season has pushed major European and Asian benchmarks below US LNG’s variable costs. Global natural gas markets have been severely hit by the COVID-19 pandemic. Natgas prices in Asia, Europe, and the US were amongst the worst performing commodities during the crisis (Chart 1). This reflects weak fundamentals – i.e. a significant global supply surplus – which gas markets faced even before the exogenous shock. The mounting probability inventories will fill up to maximum capacity before this coming winter’s heating season has pushed major European and Asian benchmarks below US LNG’s variable costs. This development renders shipments of US gas overseas uneconomical. The cancellation of US cargoes is acting as the primary balancing factor and will allow inventories to stay below full capacity – assuming global economic activity continues to accelerate in 2H20. Henry Hub prices surged by 34% since the beginning of the month on the back of higher gas demand – from warmer-than-normal weather and rebounding global economic activity – depressed US LNG exports, and prolonged maintenance at Australia’s Gorgon plant. Chart 1Global Gas Benchmarks Collapsed In 1H20 Chart 2Relative Prices Will Favor Additional US LNG Exports As storage-related fears abate, LNG economics is turning favorable for cargoes to be delivered in 4Q20 and 1Q21. This will allow exports of US gas to Europe and Asia to resume as regional demand rises. This improvement is already apparent in relative futures curves (Chart 2). Still, we expect only limited price gains from current levels, especially in the US. The resurgence in US LNG exports will add to the global supply surplus and cap the upside. Relative prices will remain below LNG offtakers' (exporters) full-cycle costs, limiting additional investments in LNG projects over the medium term. We expect demand to catch up to supply by 2024. Gas Fundamentals Worsened In 2019 Global gas demand increased by 2% y/y in 2019, led by growth in the US and China as coal-to-gas switching intensified amid the low-price environment (Chart 3). However, this rate of growth is a marked slowdown relative to the average 3.5% y/y growth from 2016-2018. It was also slower than the strong global supply growth – up 3.4% y/y – and LNG export growth – up 12.7% y/y. Chart 3US, China Supported Gas Demand Growth In 2019 The US was the largest contributor to both new gas and LNG supply, accounting for 65% of the world’s incremental gas production (Chart 4). The liquefaction capacity addition from the first wave of investments – i.e. projects that received a final investment decision (FID) before 2017 – is now mostly operational. Chart 4US Dominated Natgas Supply And LNG Growth In 2019 US LNG capacity stands at ~10 Bcf/d and serves as a needed pressure valve to its oversupplied domestic market – a consequence of rapid shale production growth – forcing the excess gas to Europe and Asia. However, the economic slowdown in Asia in 2H19 meant the region could no longer adequately absorb these new volumes. As a result, global gas markets moved to a supply-surplus. Relative gas price spreads began trending downward and moved in favor of exports to Europe over Asia.1 Europe plays a growing role as a market of last resort for global natural gas – particularly US LNG – due to its well-developed storage infrastructure, regasification units, and pipeline networks. Around 80% of LNG exports from newly added terminals were absorbed by European markets, and most of that went into storage. Around 40% of the global natural gas supply increase last year ended up in storage, according to the IEA (Chart 5). Moreover, milder-than-expected weather last year exacerbated these trends and forced global prices to converge closer to Henry Hub. Chart 5European Storage Absorbed ~ 40% Of Global Gas Supply Growth By the end of 2019, gas storage in Europe was drastically higher than its 5-year average for that period (Chart 6). Chart 6Elevated US And Europe Gas Storage European Storage Will Stay Below Capacity-Testing Levels Cargo cancellations for September have been markedly lower, a sign of improving – though still oversupplied – fundamentals. Global gas markets confronted the COVID-19 pandemic from a fragile starting point. The shock reinforced the imbalances that began in 2019 and completely erased US LNG’s competitiveness in European and Asian markets. As demand fell in response to lockdowns – down 2.8% in the US and 7% in Europe y/y in Jan-May by IEA’s reckoning – storage in Europe was projected to reach full capacity by end-August.2 Consequently, in June, natural gas prices plunged to a more than two-decade low to incentivize supply and demand adjustments. Around 100 LNG cargoes from the US were cancelled for delivery in June and July, based on EIA estimates (Chart 7). US LNG supply is now the main balancing factor in global gas markets: It is a high-cost source of supply when delivered to Europe or Asia and is contracted under more flexible agreements facilitating cargo cancellations. Over the short term, the number of vessels cancelled each month is an important indicator of storage availability in Europe. The decision to cancel a cargo is complex but mainly depends on whether the spreads between US Henry Hub (HH) and Dutch Title Transfer Facility (TTF) or Japan Korea Marker (JKM) prices cover the exporter's variable costs. Based on a Cheniere-type contract,3 this implies the spread must be higher than 115% of Henry Hub prices plus shipping and regasification costs (Chart 2). Chart 7US LNG Vessel Cancellations Balance Global Gas Markets The spread failed to cover variable costs for most of 2020 and even moved to a premium – i.e. HH above TTF – in July. Moreover, because most contracts have a 40-day to 70-day notice period for cancellation, the supply of US LNG only reacted to the rapid drop in demand with a lag, aggravating the supply surplus and flooding European inventories. The resulting supply adjustments, combined with stronger-than-expected demand in Europe, have slowed the storage injections rates in August and pushed prices higher.4 Cancellations for September have been markedly lower, a sign of improving – though still oversupplied – fundamentals. Forward curve behavior suggests market participants expect US LNG shut-ins, combined with robust demand recovery in Asia and Europe, to move price spreads above variable costs by November this year (Chart 8). This is mostly a consequence of rising Asian LNG prices. We expect this will incentivize added exports of US LNG over the coming months which will move Henry Hub prices slightly higher over the winter. Chart 8Relative Price Spreads Cover LNG Variable Costs, But Not Total Costs In fact, some cargoes are reportedly already selling their gas in forward Asian markets and taking longer routes or reducing their travel speed to remain at sea for longer and profit from these higher deferred prices.5 Still, the increase in US prices will be limited given that relative prices need to remain wide enough to cover LNG variable costs. While global prices will move up gradually over the winter, we believe their upside is bounded by the supply surplus, especially as US exports normalize. At current storage levels, a resurgence of lockdowns in the US or Europe would have drastic consequences, sending prices back below $2/MMBtu. On the demand side, low prices will favor additional coal-to-gas switching as economies recover in 2H20 (Chart 9). Current forward TTF prices are signaling deep drawdowns in European storage this winter as demand in the region increases (Chart 10). Chart 9Cheap Gas Favors Coal-To-Gas Switching Chart 10TTF Forwards Signaling Strong Inventory Draws This Winter In Chart 11, we simulated the remaining of the filling season based on previous monthly seasonal injection rates for Europe. This suggests storage remains at risk of being maxed out by October. However, we believe – in agreement with current forward curves – that the pickup in demand from recovering economic activity, coal-to-gas switching, and lower US exports will further diminish injection rates in Aug-Sep-Oct relative to historical rates (Chart 12). This will allow inventory to reach its seasonal peak slightly below capacity-testing levels. Chart 11Euopean Storage Remains A Significant Downside Risk Chart 12Low US LNG Exports, Warmer Weather Drastically Reduced Injections In July Moreover, flows from Europe to Ukraine should continue freeing up capacity in core EU storage facilities (Chart 13).6 Chart 13Filling Ukrainian Storage Acts As A Safety Valve Chart 14Lower US Gas Supply Slows Inventory Builds In the US, the multi-year-low active gas rigs in the Appalachian basin are starting to weigh on production. Moreover, collapsing oil production in major shale-oil basins is bringing associated gas – which is now more than 16% of total gas production – down rapidly (Chart 14). This contributes to the slowdown in domestic storage injection and to the recent Henry Hub price gains. Still, at current storage levels, a resurgence of lockdowns in the US or Europe would have drastic consequences, sending prices back below $2/MMBtu (Chart 15). Consequently, we believe short-term downside risks from lockdowns are too elevated to try to profit from the limited price increase expected this winter. Chart 15Renewed Lockdowns In Europe Would Push Storage to Capacity   Rising US-Russia Competition Keeps Prices Lower For Longer Global gas markets will stay oversupplied over the medium term. This will keep relative prices between the US and Europe/Asia below LNG exports’ full-cycle costs. In 2019, a record volume of liquefaction capacity reached FID globally (Chart 16). By 2025, global LNG capacity is expected to reach ~73Bcf/d, a ~ 15Bcf/d increase from current levels. Despite the COVID-19 shock, most projects under construction in the US remain on track to be completed as previously scheduled in 2020.7 Global gas markets will stay oversupplied over the medium term. This will keep relative prices between the US and Europe/Asia below LNG exports’ full-cycle costs – i.e. below variable costs plus a fixed contracted liquefaction capacity fee estimated at ~$3/MMBtu. Chart 16Record FID Risks Keeping Markets Oversupplied Mounting competition – especially from Russia – in both Europe and Asia will hold down prices over the coming years. In Europe, the completion of the Nord Stream 2 pipeline would add 5.3Bcf/d of cheap Russian gas supply and could keep prices ~ $1/MMBtu lower than otherwise.8 These new volumes would be absorbed by higher European consumption – fueled by low prices – and lower US LNG exports – from weak relative prices. Geopolitics is a major factor driving Russian behavior and hence oversupply: The US and Russia will vie with each other for market share in Europe. As gas markets further liberalize globally, Europe will be increasingly essential for US LNG as its destination of last resort in times of low demand elsewhere. If Russia floods this market with gas, it reduces Europe’s ability to absorb US gas, which will lead to lower Henry Hub prices. It will shut in US supply in times of low demand, making investments there riskier. While US administrations of either party almost always attempt to engage Russia at the beginning of a four-year term, the US foreign policy establishment no longer believes that engagement with Russia is beneficial (Chart 17). This is apparent under the Russia-friendly Trump administration but will be especially relevant if the Democratic Party wins the White House in November. Democrats blame Russia for undermining and ultimately reversing the Obama administration’s policies by betraying the US-Russia diplomatic “reset” and interfering in the 2016 election. Chart 17Russian Geopolitical Risk Set To Increase Even If Trump Re-Elected Hence the US will continue to impose sanctions on Russia and probably on a range of companies involved in Nord Stream 2 and Turkstream. If both pipelines are completed, then Washington will ask Europe to compensate for its Russia dealings in other ways. Meanwhile Russia will use a combination of commercial and strategic measures to woo Germany and the Europeans so that they do not commit to preferential bilateral deals with the United States. Because the US and Russia are engaged in a great power struggle – rather than healthy trade competition – they will attempt to achieve their aims through means other than price and volume. Punitive measures will create volatility by occasionally removing supplies but probably cannot change the backdrop of oversupply. The gist is that US-Russia relations will remain antagonistic and Europe will benefit from the oversupply except during times of surprise sanctions and strategic blows. In China, we expect imports of US LNG to increase. However, rising Russian LNG and pipeline supplies, increasing domestic gas output, and a persistent global oversupply of gas will limit the incentives for Chinese buyers to sign long-term agreements with US exporters at a price above full-cycle costs – i.e. ~ $7/MMBtu.9 The ongoing US-China trade conflict will encourage China to use US LNG imports as a negotiating lever. This has large implications for the US gas market, as LNG capacity represents ~ 11% of its domestic supply – based on 1H20 production levels. Low demand growth for its gas in Europe or Asia will keep Henry Hub prices low to limit supply growth from shale gas and limit investment in additional liquefaction capacity. Here too geopolitics will undermine Henry Hub prices: China is strengthening economic ties with its strategic partner, Russia, and the ongoing US-China trade conflict will encourage China to use US LNG imports as a negotiating lever. A Biden administration would approach China differently from the Trump administration but it would still have to face fundamental trade tensions due to China’s mercantilism and the US attempt to contain China’s technological rise. China is crucial for global LNG demand growth, but trade tensions will reignite even under Biden and spill over into China’s demand for US commodities. China has substitutes for American LNG. If trade tensions affect China’s imports of US LNG then they will lead to lower Henry Hub prices and possibly to vessel cancellations, especially if European storage once again proves unable to absorb these exports during the injection season. The Biden administration will not ultimately be China-friendly, looking beyond any diplomatic “reset” in its first year, and thus the risk of China diversifying away from US LNG is real. Global natgas prices are moving up, ahead of this winter, but gains will be limited by the persistent oversupply. There are currently more than 6Bcf/d of approved, not yet FID, projects in the US. We do not expect much of this capacity to move forward until LNG economics turn favorable and buyers’ willingness to sign long-term contracts comes back. Large projects expected to start closer to 2025 – e.g. Shell’s LNG Canada and Total’s Mozambique LNG – could be delayed to the second half of the decade. On the demand side, persistent low prices will reinforce two ongoing trends. First, this will favor additional coal-to-gas switching in most regions, helping demand to catch up to supply by 2024 and eventually forcing European and Asian prices significantly higher in anticipation of tighter fundamentals. Second, low spot LNG prices in Asia and the availability of flexible supply will accelerate the shift to a merchant/trading market.10 The movement toward shorter and non-indexed-oil contracts continued in 2019, with spot and short term contracts reaching 34% of total LNG flows in 2019, up 32% vs. 2018 (Chart 18). The COVID-19 shock augmented the incentive to switch to non-oil-indexed contracts given the steep discount it created in LNG spot market prices versus oil-indexed contracts. Based on our Brent price forecasts, we expect this divergence to persist in 2021 (Chart 19). Chart 18Shorter, Gas-On-Gas Contracts Will Increase In Asia Chart 19Spot Prices Will Decouple From Oil-Indexed Again In 2021 The convergence in regional prices that began in 2019 is disrupting the standard LNG model based on significant regional price spreads. Low and uniform prices reduce the arbitrage of moving gas overseas. Companies will need to start using sophisticated financial instruments and will increasingly resort to spot and futures markets, like in oil markets.11 Crucially, our expectation that demand will catch up to supply assumes government policies aimed at reducing carbon emissions continue being implemented in major consuming countries. Future gas consumption is a function of economic – i.e. price incentives – and policy variables. A reversal in China’s environmental policies could drastically slow gas demand growth and remains a risk to our view. At present China’s policy setting aims for growth recovery at all costs, but the driver of Xi Jinping’s green policy is the middle class demand for healthier air and environment (Chart 20). Hence the slog to diversify away from coal will resume over the medium and long run. Bottom Line: The large collapse in prices will remain bearish for US LNG over the short term as global gas markets remain firmly oversupplied and storage levels hew dangerously close to maximum capacity. Global natgas prices are moving up, ahead of this winter, but gains will be limited by the persistent oversupply. Relative prices will be capped close to variable costs. These unfavorable conditions for additional investments in LNG projects could create a supply deficit later in the decade. Chart 20China"s Green Policy Is Driven By Its Growing Middle Class   Hugo Bélanger Associate Editor Commodity & Energy Strategy HugoB@bcaresearch.com         Footnotes 1     These destination adjustments in response to price incentives are possible because of the flexibility in US long-term LNG agreements. These contracts, for the most part, have no predetermined destination clause. 2     For instance see "NWE gas storage sites could be 'almost' full by end-August: Platts Analytics" published by S&P Global Platts on May 21, 2020. 3    There exists two main types of LNG contracts in the US: (1) Tolling agreements in which the LNG exporter needs to secure the feedgas, transport the gas to the liquefaction facility, and ship it to the buyer. In this model, the LNG operator charges a fixed fee – usually in the range of $2.25 to $3.5/MMBtu, paid regardless of whether they use their contracted LNG space to liquefy the gas. The ownership of the gas remains in the hand of the offtaker. (2) Chienere-type agreements – or a hybrid merchant-tolling structure – in which the LNG operator secures the feedgas and transports it to its liquefaction facilities. It takes ownership of the gas until it is liquefied and sold to the exporter responsible for shipping the gas to the final buyer – the pricing scheme is usually ~115% of Henry Hub gas prices + a fixed liquefaction fee. In the US, the Cove Point, Freeport, Cameron, and Elba terminals mostly use the tolling model, while all of Cheniere’s installations – i.e. Sabine Pass and Corpus Christi – are operating under Cheniere-type models. In our analysis we use the Cheniere-type as it is slightly more flexible and seems more vulnerable to cargo cancellations – subject to a penalty, or fixed fee, to ensure a reliable cash flow to Cheniere. Moreover, it is difficult to estimate how much of the shipping cost are truly variable, some offtakers have long-term shipping contracts to diminish total variable costs. Please see “Steady as She Goes, Part 5 - How Global Prices Drive U.S. LNG Cargo Destinations,” published by RBN Energy on August 1, 2020 for a detailed discussion of LNG exporters’ costs. 4    Maintenance delays at Australia’s Gorgon LNG plant also contributed to the price increase, especially in Asia. Please see "Chevron says expects to restart Train 2 of Gorgon LNG plant in early September" published by reuters.com on July 28, 2020 for more details. 5    Please see "Buyers of U.S. LNG cancel September cargoes but pace slows, sources say," published by reuters.com on July 21, 2020. 6    Since May this year, the Ukrainian storage and gas pipeline managing company UkrTransGaz started offering discounts on transportation fees and other arrangements to incentivize European traders to storage gas at their facilities. Natgas stored by non-resident in customs warehouses with UkrTransGaz are more than four times higher than last year. Please see “European gas storage: backhaul helps open the Ukrainian safety valve,” published by Oxford Institute For Energy Studies in May 2020. 7     A few projects reported lockdown-related delays of up to 4 months. 8    Please see "Nord Stream 2 and the battle for gas market share in Europe" published by Wood Mackenzie on July 24, 2020. 9    Please see “No Upside: The U.S. LNG Buildout Faces Price Resistance From China,” published by The Institute for Energy Economics and Financial Analysis (IEEFA), July 2020. 10   We highlighted in our October 4, 2018 report titled "US Set To Disrupt Global LNG Market" that the large LNG supply expansion in the US would incentivize consumers to shorten the tenor of oil-indexed contracts, replacing them with hedgeable futures-based contracts. 11    Please see “Covid-19 And The Energy Transition,” published by Oxford Institute For Energy Studies in July 2020. Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Trade Recommendation Performance In 2020 Q2 Commodity Prices and Plays Reference Table Trades Closed in 2020 Summary of Closed Trades

Special Report

Highlights Theoretically the US could employ a “Reverse Kissinger” strategy – befriend Russia to isolate China or at least prevent the budding Russo-Chinese alliance.  But Trump has made no headway in relations with Russia. Meanwhile Democrats now see engagement with Putin as a failure and will pursue a more aggressive policy. Competition in Europe’s natural gas market underscores the broader Russo-American geopolitical confrontation. Russia will likely succeed in preserving its share in the European natural gas market in the medium term, but not in the long run. We remain overweight Russian equities and bonds relative to EM benchmarks, but will downgrade if Biden’s election becomes a foregone conclusion. Feature Investors do not need to wait for the US election verdict to assess the general trajectory of US-Russia relations. Some points are clear regardless of whether President Trump or former Vice President Joe Biden prevails: US-Russia engagement had mostly but not entirely failed between the fall of the Soviet Union in 1991 and President Trump’s election in 2016.   President Trump could not break free of the constraints of office and his administration has remained adversarial toward Russia despite his preference for deeper engagement. Whether Democrats or Republicans take the White House in 2021, the result will be confrontation with Russia over the four-year term and likely beyond. The geopolitical risk premium in the Russian ruble will rise relative to its current level. A Trump victory would reduce this risk, but only temporarily.   The Failure Of Engagement Russia’s rise from the ashes of the Soviet Union can be illustrated by our Geopolitical Power Index – it shows Russia’s rise relative to the US in terms of demographic, economic, technological, commercial, and military variables that make a nation strong (Chart 1). Chart 1Russia Rose From Soviet Ashes, But Still Lags US Russia is a shadow of its Soviet self and lags far behind the US in raw capability. But its recovery from the chaos of the 1998 financial crisis, fueled by a global commodity bull market, has consisted of a systematic removal of domestic political constraints. It is politically unified under the personal rule of Putin, has reformed its economy and modernized its military, and has successfully pushed back against the US and the West in its sphere of influence. Russia punches above its economic weight in the world by means of its military, which it has wielded opportunistically in Georgia, Ukraine, Syria, and Libya (Chart 2). Neither the US nor any other power was willing to fill the power vacuum in these locations. A Trump victory only temporarily reduces the rise in Russian geopolitical risk. The US and Russia have a fundamentally antagonistic relationship over influence in Europe and occasionally the Far East. They have little need to trade with each other. They are both large, independent commodity exporters and advanced weapon-makers separated by vast distances. Russia is threatened by the US’s military and technological superiority, its economic strength and newfound status as an energy exporter (see energy section), and its ability to undermine Russian legitimacy in the former Soviet sphere by promoting democracy.  Russia’s advantage is that the US is internally divided by political factions. Putin’s popular approval has benefited from his restoration of domestic order and Russia’s standing as a great power. Successive American presidents have floundered under domestic partisanship and polarization (Chart 3).   Chart 2Russia’s Military Punches Above Its Economic Weight Chart 3Russia Is Politically Unified, The US is Internally Divided   Attempts to “reset” relations have failed.1 The Barack Obama administration’s 2009-11 Reset, announced by Biden, saw several concrete compromises, including the New START treaty and Russia’s joining the WTO. But the Bolotnaya Square protests in 2011-12, at the height of the Arab Spring, rekindled Moscow’s fear that the US aimed to foment “color revolutions” not only in Russia’s periphery but even in Russia itself. Faced with losing its control over Ukraine’s geopolitical orientation, Russia invaded parts of Ukraine and seized Crimea, the first military annexation of territory in Europe since World War II. The US and Europe applied extensive sanctions that last to this day and drag on Russian growth.2  True, Moscow cooperated on the 2015 nuclear deal with Iran. Russia does not want Iran to get nuclear weapons. Yet this is not imminent. And Russia gained global oil market share when the US walked away from the deal and restarted sanctions (Chart 4). Either way, Iran survives as a Russian ally capable of exerting influence across the Middle East.   President Trump launched another attempt at engagement with Russia. If there is a strategic basis for this policy – i.e. if it is not just based in Trump’s personal proclivities – then it is the idea of a “Reverse Kissinger” maneuver. During the Cold War, the US befriended Maoist China in order to isolate the Soviet Union. Today, with China posing the clear threat to US hegemony, the US could try to befriend Russia to isolate China or at least prevent the budding Russo-Chinese alliance.  The difference is that in 1972, American and Chinese interests were complementary. China wished to stabilize its borders and the US offered geopolitical relief as well as technology and knowhow. Today American and Russian interests are not complementary other than the political convenience of demonizing each other (Chart 5). The US offers Russia limited investment capital; Russia does not offer cheap labor or a vast consumer market. Chart 4Russia’s Oil Market Share Benefitted From Iran Sanctions Chart 5US-Russo Interests Are Not Complementary   The Trump administration’s attempt to engage Putin has failed. Putin’s declaration of a global oil market share war this year drove American shale oil companies into bankruptcy during an election year. Barring an “October surprise” engineered by Putin to get Trump reelected, their “alliance” is at best rhetorical and at worst a mirage. Putin might favor Trump because he sharpens US internal divisions, or because he has an isolationist foreign policy preference, but Putin’s actions so far in 2020 suggest a deeper strategic reality: Russia seeks to foment political turmoil in the US, not solidify either of the parties in power, as the latter could backfire against Russia. What Comes After Engagement? Russia lacks the power to create a new world order, but it will continue to leverage its relative power to exercise a veto over affairs in the current global order, in which US influence is weakening. It can hasten the West’s decline by sowing divisions within the West. Chart 6COVID-19 Dented Support For Trump And Putin What happens when US polarization falls and a new political consensus takes shape? This would pose a major threat to Putin’s strategic options. Thus it is relevant if Joe Biden wins the 2020 election with a strong majority and a full Democratic sweep of government. Presidents Trump and Putin, and their political parties, are among the worst performers amid the COVID-19 pandemic and recession (Chart 6). The implication is that Trump will lose the election and Putin will resort to time-tried techniques of confrontation with the West to restore his domestic support. Democrats will pursue a more aggressive policy toward Russia. The Democrats harbor a deep vendetta against Russia over its interference in the 2016 election and will go on the offensive to prevent Russia from trying to undermine their grip on power again. They will also seek to deter Russia from further undermining American strategic interests. Biden will try to revive NATO, expand US troop presence in eastern Europe, and promote democracy and human rights in Russia’s periphery, using the Internet to launch a disinformation campaign against Putin’s regime. Cyber warfare will escalate.  A “Reverse Kissinger” is not achievable until Russia feels threatened by China. The silver lining for Russia is economic: Biden’s policies will help to weaken the dollar and cultivate a global growth recovery. Biden will be less inclined to start disruptive Trump-style trade war with China that could permanently damage China’s potential growth or global growth. Chinese imports are essential to propping up Russia’s sluggish economy. In enabling commodity prices to recover, and reducing global policy uncertainty, Biden would inadvertently aid Russian recovery (Chart 7). Chart 7The Silver Lining Of A Biden Presidency For Russia Is A Weaker Dollar Ultimately Russia is insecure because the US threatens to undermine its economy and political legitimacy both at home and in its strategic buffers. Putin has re-centralized control while shutting out foreign influence. This approach is not changing anytime soon given the recent constitutional changes to prolong Putin’s rule till 2036. Preliminary reports claim that, with 65% of the public voting, these changes were ratified by 76% of the population.3  What changed is that the US is no longer as optimistic about engaging Russia. If anything, its internal divisions will encourage it to go on the offensive. Sanctions may well be expanded before they are eased, the Ukraine conflict could revive rather than simmer down, and new fronts in the conflict could widen, particularly in cyberspace. This is particularly the case if Biden wins the White House in November. The structural, geopolitical risk premium of US-Russia conflict is priced into Russian assets, but there is room for a cyclical increase if Biden is elected. Our market-based Russian geopolitical risk indicators – which define geopolitical risk as excessive ruble weakness relative to its macro context – show that Russian risk is elevated because of COVID-19, but dropping. The US election should reverse this trend, unless Trump wins (Chart 8). Chart 8Russian Geopolitical Risk Set To Increase Even If Trump Re-Elected Alternative measures of political risk that utilize non-market variables support our qualitative assessment, such as the indicator provided by GeoQuant. The implication is that Russian political risk is higher than the market is pricing (Chart 9). Chart 9Market Is Underpricing Russian Political Risk Kissinger Reversed? Not Yet. If Trump wins, could he not engineer a major détente with Russia? In 2018 the US shifted its national defense strategy to emphasize that “the central challenge to US prosperity and security is the reemergence of long-term, strategic competition,” arguing specifically that “it is increasingly clear that China and Russia want to shape a world consistent with their authoritarian model.4”  Yet US geopolitical power has declined such that taking an offensive approach to Russia and China simultaneously is not practicable.  If the US pursues the Reverse Kissinger strategy, then it will have to make major concessions to Putin’s Russia. It would need to provide substantial sanctions relief, accept the Crimean annexation, allow a high degree of Russian influence in Donbass (Ukraine), abandon hopes of retribution for the 2016 election interference, ask for a return to the 2015 nuclear deal on Iran at best, and settle for arms control agreements that do not cover new technologies. It is not clear that President Trump would concede this much in a second term, though in most cases he would have the power to do so. Yet Moscow cannot downgrade its cooperation with Beijing by much, since US-Russia détente never lasts long and China weighs more heavily in its economic calculus than the West’s sanctions. Chart 10US-Russo Struggle Is Subordinate To US-Sino Conflict The Democrats, by contrast, are not prepared to make these concessions, particularly on 2016. They are more willing to pursue a gradualist approach in dealing with China, which they believe is less urgent due to shared economic interests.5  If the US confronts Russia, then Russia will draw closer to China. The informal alliance between these two powers is well advanced. A closer association provides China with a better position in waging its long-term geopolitical competition with the United States.  Ultimately US grand strategy and public opinion will drive American presidents to take a harder line on China because it rivals the US in economic resilience and technology over the long run (Chart 10). The conflict with Moscow will eventually be subordinate to the US-China struggle. But a “Reverse Kissinger” is not achievable until Russia feels threatened by China, either through its own weakness or Chinese strength. A much stronger trans-Atlantic alliance, or much greater Chinese influence over East Asia and/or the Middle East, could trigger a shift in Russian strategy. We are not there yet. Russia’s cooperation with China will deepen, strengthening China’s hand and making it all the more imperative for the United States to solidify the trans-Atlantic alliance with Europe. Otherwise the risk of a precipitous decline in American power will threaten global stability.  Bottom Line: US-Russian antagonism will continue for the foreseeable future. Russian geopolitical risk is underpriced, particularly if Biden wins the election. A Trump victory would offer only a temporary reprieve.  Direct Competition In Energy Russia can offer low cost natural gas alongside an existing and projected (under construction) network of pipelines into Europe. This capability will help it to sustain and marginally increase its market share in Europe relative to the US in the medium term. In turn, this will help Russia secure vital revenues for its macro stability.  Natural gas exports to Europe represent 2.5% of GDP or 9% of total exports. A Biden presidency is negative for Russian assets, but Russia has room to ease policy. In the long run, however, US LNG will challenge Russia’s share in the European natural gas market. On the whole, the US sees Russia as an economic competitor in the European natural gas market and it will continue to disrupt Russian natural gas exports to Europe through sanctions and/or by other means. A resulting market share war between the US and Russia will lead to low natural gas prices benefitting the consumer, Europe. Competition in Europe’s natural gas market underscores the broader geopolitical confrontation between the US and Russia. The following factors will shape heightened competition: Escalating Competition For European Natural Gas Market Europe will remain a major market for natural gas. The combination of falling domestic production, steady consumption growth and the ongoing structural shift to cleaner sources of energy will require greater imports of natural gas (Chart 11). Critically, Europe’s natural gas consumption might rise faster than its GDP making this market attractive to energy producers. According to the IEA, Europe’s consumption of natural gas will continue to grow at a steady rate over the next 5 years. In a nutshell, European policymakers are promoting cleaner energy such as natural gas over coal and nuclear energy. This push will facilitate rising demand for natural gas.  Yet, European natural gas production is expected to drop by 40%, driven by field closures in the Netherlands and the UK.  As such, the diverging gap between falling production and steady consumption opens up a space for both Russian and US natural gas exports into the continent. Russia Natural Gas Strategy: Russia and its largest natural gas producer, Gazprom, are aiming to increase their share in the European market from their current 36% to 40% (Chart 12). Chart 11Europe's Nat Gas Imports Will Continue Growing... Chart 12...Allowing Russia To Grab Market Share   Table 1Russia’s Pipeline Export Capacity More specifically, Russia’s latest 2035 strategy (known as ES-2035) reaffirms its two-pronged strategy: (i) continue to provide low-cost natural gas to Europe and Asia through pipelines and (ii) developing LNG export capacity for exports to the Far East. Pipelines: Russia’s export capacity to Europe is set to increase to 190 Bcm/y by 2022 excluding existing transit routes passing through Ukraine (Table 1). Two new sources of pipeline routes will be the Nord Stream2, coming online by the end of this year, and Turk Stream, expected to come online by 2022. These pipelines will have an export capacity of 55 Bcm/y and 31.5/y Bcm, respectively (Map 1).   Map 1Russia’s Latest Pipelines Bypass Ukraine Chart 13Russian Natural Gas Exports To Non-CIS Countries Meanwhile, pipeline capacity through Ukraine will remain 140 Bcm/y. Ultimately, Russia has been determined to diversify its natural gas transit routes despite pressures from the US.6 In addition, Gazprom natural gas production for transport via pipeline is expected to increase by 35% to 983 Bcm in the next 15 years. The European market is essential to Russia’s export revenues, as it currently represents 56% of Russia’s total gas export volumes compared with 83% total export to non-CIS countries (Chart 13). Lastly, regarding natural gas pricing, Gazprom will continue to move away from oil-indexed long-term contracts to shorter-term spot market contracts. This change of tack will cause deflation in Gazprom’s export prices to Europe but will preserve Russia’s market share in its strategic European market.   LNG: Russia will continue to be one the top four LNG producers alongside Qatar, Australia and the US. According to the latest estimates by the IEA, Russian exports of LNG, currently at 39 Bcm, are set to expand by 20% by 2025. The development of the Yamal peninsula into a major natural gas and LNG hub will allow Russia to produce close to 110 Bcm of LNG by 2035, which will constitute 16% of its overall current gas production. This will lead to continued LNG exports to various markets, particularly Europe, which consumes 50% of Russia’s LNG exports. Imported technology from Europe and external financing from China have allowed Novatek, Russia’s second largest natural gas producer, to become the leader in production and exports of LNG. Russia is also investing heavily in liquefaction. It is now fifth globally in liquefaction capacity. There are currently $21 billion in pre-final investment decision (FID) from the LNG Artic 2 in the Yamal that will increase its liquefaction capacity by over 200% by 2026.  Lastly, it is estimated that 70-80% of total commodity exporters’ costs are sourced locally and are in rubles due to the import substitution policy adopted by Moscow in 2015. This will alleviate cost pressures arising from a potentially weaker ruble in exploiting the Yamal reserves. US Needs To Find A Market For Its LNG: US produces 920 bcm/y of natural gas but consumes only 830 bcm/y. The rest is available for export. The need to export rising excess of natural gas output puts the US in direct competition with other natural gas exporters such as Russia. Chart 14US LNG Exports To Europe To Rise In the medium term, an oversupplied market alongside the COVID-19-induced demand shock in Europe will reduce European natural gas demand, hurting both the US and Russia. US LNG might lose market share in the European market to Russia due to falling production arising from capex cuts and bankruptcies in the US natural gas sector.7 Yet, in the long run, Europe’s geopolitical ties with the US and strategic interest in diversifying away from Russia make US LNG an obvious area of cooperation. The Trump-Juncker agreement in July 2018 led to a 300% increase in US LNG exports to Europe before the COVID-19 pandemic (Chart 14). Since coming into effect, the agreement also resulted in a doubling of EU utilization of LNG regasification capacity, from 30% to close to 60% in early 2020 and is expected to continue expanding in the years to come. Bottom Line: Russia will likely succeed in at least preserving its share in the European natural gas market in the medium term, but will be challenged by US LNG in the long run. Macro And Financial Market Implications For Russia Chart 15Russia: Low Public Debt Burden Heightened confrontation with the US and new sanctions on Russia will materialize if Biden wins the presidency. All else constant, this is unfavourable for Russian asset prices. It should be noted, however, that years of fiscal conservativism, tight monetary policy, a prudent and pro-active bank regulatory stance as well as some success in import substitution have given Russia the capacity to offset negative external shocks by easing macro policy: Russia has one of the lowest public debt-to-GDP ratios among the largest countries in the world. Its total public debt stands at 13.5% of GDP (Chart 15). Its external public debt is at a mere 4% of GDP. As in many other countries, Russia’s fiscal deficit is widening sharply due to the pandemic and low oil prices. However, we expect the primary and overall fiscal deficits will be only 4.25% and 5% of GDP in 2020, respectively. So far, at 3.5% of GDP, the announced fiscal stimulus in response to the pandemic has been small by global standards. Russia has room to boost fiscal expenditure substantially this year and in the coming years to offset negative external shocks. The Central Bank still has room to reduce interest rates further. The real policy rate is 2.5% compared with 1% for EM ex-China, Korea and Taiwan (Chart 16, top panel). Russia’s local currency government bond yields offer value: their real yield is 2.5% compared with the EM GBI benchmark real yield of 1.5% (Chart 16, bottom panel). The Central Bank of the Russian Federation will refrain from QE-type policies (i.e., public debt monetization). This is a plus for the ruble relative to other EM currencies where central banks are engaged in QEs. Bank lending rates remain extremely elevated in Russia and local currency credit penetration is reasonably low (Chart 17). Companies and banks’ external indebtedness has declined from $1,200 bn in 2014 to $900 bn currently. Chart 16Russian Real Rates Offer Value Chart 17Russia: Real Lending Rates Are Too Elevated!   Authorities have cleaned up the banking system. The number of banks has dropped from 1000 in 2010 to 430. Banks have written down and provisioned for a large amount of loans. All of these reduce Russia’s vulnerability to negative shocks. Finally, pressured by US and EU sanctions, Russia has been moderately successful in import substitution as we discussed in a previous report. The nation has expanded its productive capacity, especially in agriculture and some other industries. As a result, it now has more room to deploy fiscal and monetary stimulus to boost demand that will be satisfied by domestic rather than foreign output. In short, fiscal and monetary stimulus will not cause the currency to plunge. On the negative side, the outlook for productivity growth remains lukewarm. Russia’s long-term economic outlook will be characterized by relative stability but low growth, as has been the case in recent years. Combining our geopolitical and macro analysis, two conclusions stand out. First, we remain overweight Russian equities as well as both local currency and US dollar bonds relative to their EM benchmarks. If Trump stages a comeback over the next four months, which is not impossible, then the geopolitical risk premium will continue to fall. Trump would offer a reprieve in tensions for a year or two.  Second, the US election threatens this view because Joe Biden is currently heavily favoured to beat Trump and if he does, he is likely to impose fresh sanctions on Russia, possibly as early as 2021. Therefore, if Biden’s election becomes a foregone conclusion, we will downgrade Russian assets. Matt Gertken  Vice President Geopolitical Strategist  mattg@bcaresearch.com Andrija Vesic Associate Editor andrijav@bcaresearch.com   Footnotes 1  Michael McFaul, From Cold War To Hot Peace: The Inside Story of Russia and America (London: Penguin, 2018). 2  International Monetary Fund, “Russian Federation: 2019 Article IV Consultation,” IMF Country Report 19/260 (August 2019). 3  Ann M. Simmons and Georgi Kantchev, “Russians Vote for Overhaul That Could Keep Putin in Power Until 2036,” Wall Street Journal, July 1, 2020.  4  “Summary of the 2018 National Defense Strategy of the United States of America: Sharpening The American Military’s Competitive Edge,” Department of Defense, 2018. 5  Victoria Nuland, “Pinning Down Putin: How A Confident America Should Deal With Russia,” Foreign Affairs, July/August 2020. 6  The US has tried to stop Russia’s expansion of pipelines into Europe in the past. Evidenced from both Kennedy and Reagan administration policies directed towards the building of the Friendship oil pipeline in the 1960s and the Brotherhood gas pipeline in the 1980s, respectively. In response, Russia began developing its own technological capacity through import substitution, hurting western firms in the process. 7  "U.S. natural gas giant Chesapeake Energy goes bankrupt,” CBC, June 29, 2020.

Highlights US dry gas production – the gas traded on futures exchanges and consumed by firms and households – is expected to fall ~ 2.5% this year to 89.7 bcf/d.  Consumption will be down ~ 4% to 74.3 bcf/d.  High carryout stocks from a warmer-than-normal winter mean US natgas storage will be at a record 4 TCF by November.  This is close to demonstrated peak capacity of 4.3 TCF. We expect US benchmark Henry Hub futures prices to average $2.00/MMBtu in 2H20, assuming a normal winter (Chart of the Week).  This is slightly lower than current futures’ levels.  A deeper round of demand destruction from a second wave of COVID-19 remains a risk to commodities generally.  Our base case assumes accommodative policy globally will spur a recovery in gas demand next year.  This will push benchmark US prices into the $2.25-$2.50/MMBtu range, which also is below the level futures currently are trading. Weather-related risk is peaking right now.  The early start to the hurricane season will keep demand for storage gas elevated into October.  Local-distribution companies will be planning for normal winter temperatures, which would be colder than last year. Feature Our modeling, shown in the Chart of the Week, leads us to expect natgas futures to average $1.92/MMBtu and $2.22/MMBtu this year and next, respectively. US natgas prices will recover slowly in 2H20 and pick up steam in 2021 as demand recovers and LNG export growth resumes. However, we do not expect prices to rally to the extent futures currently are pricing in, nor as much as the US EIA expects. The NYMEX benchmark natgas futures, which call for delivery of pipeline quality dry gas at Henry Hub, LA, were on track to average close to $2.00/MMBtu this year and $2.64/MMBtu next year earlier this week.1 The EIA, for its part, is forecasting $2.04/MMBtu and $3.08/MMBtu for 2020 and 2021, respectively. Our modeling, shown in the Chart of the Week, leads us to expect natgas futures to average $1.92/MMBtu and $2.22/MMBtu this year and next, respectively. Our natgas price models use the EIA’s fundamental inputs – supply, demand and working gas storage levels – and temperature and financial variables to explain and forecast prices, including 10-year average heating-degree days, and US Treasury rates. Chart of the WeekUS Natgas Prices Recover Slowly On the supply side, the rate of growth in US natgas production started rolling over in 4Q19, well before COVID-19 was even an issue for the market. A warmer-than-normal winter last year weakened prices sufficiently to cause natgas production in the US shales to roll over from a high of 86 billion cubic feet per day (bcf/d) in 4Q19, to 84 bcf/d in the first five months of 2020. Shales account for ~ 90% of total US gas production. In and of itself, this is a relatively small impact, reflecting more the unintended inventory accumulation following last winter. Shale-Gas Production Rolls Over The decade-long shale-gas production surge led by the Marcellus formation in the US Appalachian Mountain region and, more recently, the Permian basin in Texas, which together account for ~ 60% of US gas production, ended – for the time being – in 4Q19 (Chart 2). Total natgas production in the Lower 48 states rose 11% in 2019 to 95.6 bcf/d, and is expected to fall ~ 2% this year to 93.7 bcf/d. Chart 2Shale-Gas Production Rolled Over Following A Warm 2019-20 Winter Natgas production is sensitive to the level of US short-term rates. The financial variables in our model indicate natgas production is sensitive to the level of US short-term rates, which the Fed has been maintaining at low levels since the Global Financial Crisis (GFC) to battle disinflation. Natgas is a derived demand – it is used to heat buildings and generate electricity, e.g. – so anything that lifts demand will benefit supply (Chart 3). In our modeling, we find natgas production is an explanatory variable for natgas consumption, but not vice versa, suggesting that the supply side is aggressively pricing to meet demand, and increase market share at the expense of coal-fired generation (Chart 4). Chart 3US Natgas Production, Consumption Are Sensitive to US Treasurys Chart 4Low Rates Accelerate Coal's Market Share Loss To Natgas Shale-gas production also is being weakened in the US by the collapse in oil prices, particularly in the Permian basin, where associated natural gas output has been surging (Chart 5).2 Close to 500 Bcf of natural gas was flared in the Bakken and Permian plays.3 This means the collapse in crude-oil prices on net is lowering CO2 emissions associated with flaring in Texas and North Dakota.4 Chart 5Associated Gas Production Falls As Crude Oil Prices Weaken Chart 6Warm Winter Destroys Natgas Demand Gas Consumption Growth Slows The US EIA expects working gas in storage to reach 4 TCF, a record, by the start of the heating season in November. Gas consumption was hammered by a much warmer-than-average winter last year (Chart 6). This left the level of working gas in storage at ~ 2 TCF by the end of March 2020, when the heating season ended (Chart 7). Natgas working storage has continued to increase every month since, and now stands just below 3 TCF, according to the EIA’s latest estimate. The US EIA expects working gas in storage to reach 4 TCF, a record, by the start of the heating season in November. The latest estimate of demonstrated peak storage capacity is 4.26 TCF, which raises the possibility a warm winter this year could lead to a full-storage event.5 Should this happen, markets would begin pricing the probability – not the possibility – of negative natural gas prices in more than just local markets lacking pipeline takeaway capacity or sufficient storage to accommodate local supply and demand imbalances. Chart 7US Working Gas In Storage Continues To Build Toward 4 TCF Negative natgas prices would further exacerbate the risk of more sharp curtailments in oil and gas capex – in addition to the $400 billion projected by the International Energy Agency (IEA) last month, which would cut shale-oil and -gas capex by 50%.6 This could set up a huge rally in hydrocarbons generally, oil and gas in particular, should it occur. Beware Disorderly Gas Markets As US natgas working storage fills going into the winter heating season, markets will once again be watching to see if the CFTC and CME are capable of maintaining orderly terminations of trading under physical-market stress, which a full-storage event certainly qualifies as. At the end of April, we noted the disorderly termination of trading in WTI futures delivering in May to Cushing, OK, was among the proximate causes of futures falling to -$40.32/bbl – that’s $40.32/bbl below $0.00/bbl – prior to the contract going off the board. Partly, we contend, this was the result of a failure of the US Commodity Futures Trading Commission (CFTC) and the CME Group, which operates WTI crude oil and Henry Hub natgas futures markets, to ensure only bona fide hedgers with the capacity to make or take delivery of the physical commodity being traded via futures contracts were left in the market as these contracts went to delivery. As US natgas working storage fills going into the winter heating season, markets will once again be watching to see if the CFTC and CME are capable of maintaining orderly terminations of trading under physical-market stress, which a full-storage event certainly qualifies as. Another failure to ensure an orderly termination of trading would add another impediment to sourcing capital for oil and gas producers – many producers chose to or are forced to hedge – which would exacerbate a tightening of supply in the medium term (2 to 3 years hence). Bottom Line: We expect natgas futures delivering to Henry Hub, LA, to average $1.92/MMBtu and $2.22/MMBtu this year and next, respectively, based on our proprietary models using fundamental and financial explanatory variables. Upside risks to the forecast are a stronger-than-expected demand recovery, which sees residential, commercial, industrial and electric-generation demand reviving sharply. A global pick-up that increased demand for LNG also would rally US gas prices sharply. To the downside, another round of demand destruction from a second wave of the COVID-19 pandemic would press prices lower. As US working gas in storage increases, the risks of a full-storage event rises. This will force market participants to price in a higher probability of negative prices, which also would have a deleterious impact on capex and, thus, future supplies.   Robert P. Ryan Chief Commodity & Energy Strategist rryan@bcaresearch.com Hugo Bélanger Associate Editor Commodity & Energy Strategy HugoB@bcaresearch.com Fernando Crupi Research Associate Commodity & Energy Strategy FernandoC@bcaresearch.com     Commodities Round-Up Energy: Overweight US shale E&P companies are bringing back some of their shut-in production as WTI prices remain above $35/bbl. According to Rystad Energy, more than 300k b/d of previously shut-in production is already coming back online as of June. Nonetheless, rig count remains at its lowest level since 2009 and prices are not high enough to incentivize additional drilling. Our estimates suggest the return of shut-in production will pale compared to the drop in production from natural decline rates over the coming months. Base Metals: Neutral In its June Global Economic Prospects, the World Bank revised its emerging market and developing economies real GDP growth estimates for 2020 to -2.5%, a 6.6pp downward revision from its January 2020 projections. On the other hand, China’s credit numbers continue to move up, reaching 30% of nominal GDP in May (Chart 8). Going forward, the recovery in base metals hinges on the speed at which the stimulus reaches the real economy. On average, it takes somewhere between 4 to 9 months for metals to react to surges in China’s TSF. Precious Metals: Neutral Gold prices traded between $1,675/oz and $1,760/oz since April. Our fair-value model suggests prices could trade slightly below this range (Chart 9). However, risks of renewed US-China tensions are rising rapidly, which could keep gold well-bid. BCA Research’s China Investment strategists believe these risks will reach new height over the summer as pressure on Trump’s election campaign intensifies.7 Mounting geopolitical risks could hurt risk assets and benefit gold as a hedge against equity volatility. Ags/Softs:  Underweight July Ethanol futures have shown substantial strength in the past two months, but the outlook remains gloomy. With over 30% of US fuel ethanol plants being idled during the pandemic, as prices and margins increase, an increase in supply is likely.  Gasoline demand might have less room to grow as most individuals keep working from home. Supporting this is EIA’s STEO outlook which sees the ethanol market oversupplied in 2020, with consumption expected to average 800k b/d in 2020 and production to average 880k b/d. Chart 8Chinese Credit Growth To Rise Chart 9Gold Slightly Above Fair Value     Footnotes 1     Pipeline-quality dry natural gas has had all impurities (metals, sulfur compounds, etc.) and non-methane liquids removed so that its heat content is ~ 1,010 BTUs per cubic foot. The NYMEX futures taken to delivery at Henry Hub, LA, require physical gas to meet the specifications “set forth in the FERC-approved tariff of Sabine Pipe Line Company.” 2     TThe correlation between US natgas and oil prices declined substantially since 2009. Our model, based on WTI prices and 10-year US treasury yields only, suggests Henry Hub prices’ elasticity to changes in oil prices dropped by more than 50% post-GFC. On the other hand, US yields are now much closely related to natural gas prices. The disconnection between Henry Hub and WTI prices is largely a result of the large increase in shale gas and associated gas production. Strong oil prices –which are determined globally – incentivized higher output by US E&Ps. This led to a surge in the volume of associated gas in an already saturated domestic gas market. 3    Please see Lingering Oil-Demand Weakness Will Fade, which we published November 21, 2019, and discusses flaring in the Permian and Bakken basins. 4    Please see "U.S. oil fields flared and vented more natural gas again in 2019: data" published by reuters.com February 3, 2020. 5    Please see Underground Natural Gas Working Storage Capacity published by the EIA May 29, 2020, for additional detail. 6    Please see The Covid-19 crisis is causing the biggest fall in global energy investment in history, published by the IEA May 27, 2020. The Agency notes, “… after the Covid-19 crisis brought large swathes of the world economy to a standstill in a matter of months, global investment is now expected to plummet by 20%, or almost $400 billion, compared with last year.” Oil and gas investment is projected to fall more than 30%. 7     Please see BCA Research's China Investment Strategy Report entitled Watch Out For A Second Wave (Of US-China Frictions) published June 10, 2010, available at cis.bcaresearch.com.   Investment Views and Themes Recommendations Strategic Recommendations Tactical Trades Trade Recommendation Performance In 2020 Q1 Commodity Prices and Plays Reference Table Trades Closed In 2020 Summary of Closed Trades  

Overweight 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). 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 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 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). 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). 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. Table 2BC’s LNG Voyage Time To Asia Is Advantageous 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 7AECO-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. 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. 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. 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 13Weather-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. ​​​​​​​ 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 Trades Closed in 2018 Summary of Trades Closed in 2017

Special Report

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 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... Chart 3...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 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 Chart 6Supply - Demand Imbalances Will Fuel LNG Demand Globally Chart 7LNG Export Capacity Growth 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 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 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 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 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 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 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.