Refinery cracking margins ease while simple margins are supported by HFO. This is driven by global refinery capacity ramp-ups and lighter crude. FCC light loading likely. Some crude runs cuts also possible for Europe. But this will dramatically reverse later in 2019 as IMO bunker spec changes will disrupt markets as 2020 approaches. Distillate prices will increase and HFO cracks will fall in 2H19 as logistics systems will gear up for the spec change with market structure incentivizing gasoil stock builds and HFO drawdowns. Brent prices have roughly stabilized with the OPEC agreement for now. Brent-Dubai crude differentials are narrower reflecting shifting arbitrage economics due product value shift (strong HFO) and higher freight costs. WTI (Cushing)-Brent differentials will stay relatively wide with rising Cushing stocks until later in 2019.

The latest Chinese economic indicators were mostly negative except for the recovery in infrastructure spending. Manufacturing and consumer confidence remained weak, while total social financing also came in softer than expected. Crude runs grew by 532 thousand barrels per day year-on-year to 12.69 million B/D in October on the back of higher seasonal demand and refining margins. Crude imports jumped by 1.41 MMB/D to a historical high of 10.46 MMB/D in November, mainly due to a surge in crude deliveries to independent refineries as they made a last attempt to use up their import quotas. Downward pressure was continuously felt upon China's oil demand growth in October on the back of moderating fundamentals. Record low passenger car sales growth, increasing discount of gasoil wholesale price over ex-refinery, and moderating growth of aviation passenger turnovers have helped dim the prospect of robust demand growth in 4Q18.

Crude oil storage fell by 1.2 MMB, but a 3 MMB increase is expected for the next week. Cushing saw a stock increase of 1.1 MMB, with a further gain of 0.9 MMB anticipated for the next week. Gasoline storage experienced a build of 2.1 MMB, keeping overall stocks ahead of last year. Another large build is anticipated for the next week. Distillates drew by 1.5 MMB as colder weather prevailed and economic activity remained robust. A small build is expected for the next week. Total U.S. field crude production was reported as 11.6 MMB/D, 0.1 MMB/D lower than last week. The decline is somewhat unusual given the lack of known production outages that week. For the week ahead, we expect U.S. production to remain at 11.6 MMB/D. The balancing item remained firm at a positive 546 MB/D. This is expected to continue to add 400 MB/D to overall crude supply next week. Refinery runs were down slightly from the prior week, likely tempered by soft margins especially for gasoline. For the next week runs are expected to move up slightly to 17.5 MMB/D.

If WTI prices were to drop to $40/Bbl and stay flat for the next two years, we estimate U.S. shale crude production would be 1.4 MMB/D lower in 2019 versus our Reference Case (-0.4 MMB/D Y/Y). If WTI prices stayed at $50/Bbl, shale crude production would be 0.4 MMB/D lower than our Reference Case (+0.7 MMB/D Y/Y). In both scenarios, the 2020 impact is much larger. Still, even at $50/Bbl, we still see growth in U.S. shale as the average full-cycle breakevens of the main shale oil plays is $49/Bbl. However, S&P Global Platts Analytics expects WTI prices to rise by the second half of 2019, on rising seasonal demand, the potential for stronger U.S. enforcement of Iranian sanctions, and impending IMO fuel specification changes. As such, we assume U.S. shale crude and condensate production will continue to grow strongly, even with takeaway capacity constraints flattening production growth through much of 2019.

Crude runs fell back 86 MB/D after having reached their highest level since late August with minimal planned maintenance. Crude imports rose from 3.5 MMB/D to 4 MMB/D and stocks built 5.3 MMBbls. Finished product stocks drew again, this week by 2 MMBbls, with varying draws in all products other than fuel oil. Product stock length continues to lessen, but refining margins remain very weak, with further run restraint needed to induce a sustained recovery. Gasoline cracks appears to have bottomed, while gasoil and fuel oil cracks have continued to soften. Implied marketing margins remain very strong.

Chinese data for retail sales and industrial production in November surprised significantly on the downside – the government has been easing policy, but that has not been sufficient so far to end a slide in economic activity. More easing actions should be forthcoming, as policymakers have not been shy about their willingness to deploy economic stimulus tools at their disposable. U.S. economic growth during the fourth quarter is running stronger than previously projected, as retail sales for November surprised significantly on the upside. The European Central Bank decided to end its quantitative easing financial asset purchases, even though recent economic data have been soft.

The S&P 500 lost 1.3% on the week and closed at the 2,600 level, while financial equity prices remained under pressure. Commodities did poorly, lower by 2.7%, while energy was particularly weak and lower by 6.5%. Palladium remains in a strong uptrend, copper is holding, while aluminum is slightly lower. The U.S. dollar was higher by 1%. Disinflation trends remain a big and growing concern, along with weakness in financial equity indicators. The market remains fragile.

Global equities eased again by 0.9% on the week, though the U.S. S&P 500 fell 1.2%. Among the domestic tracking indices, banking, was again the biggest underperformer, lower by 5.8%, while retail, energy, and housing also lagged and lost about 3%. Internationally, many of the tracking indices did better than the U.S., with emerging Asia gaining 0.4%.

US propane inventories showed the largest draw of the season so far as total demand rose to 2.6 million barrels in the week ended December 7, Energy Information Administration data showed Wednesday. Total US propane stocks fell 3.25 million barrels to 76.6 million barrels during the week, the data showed. Inventories were 2 million barrels above year-ago levels and 6% below the five-year average. Front-month non-LST propane lost 4 cents/gal, or 6%, ending the week at 68.25 cents/gal. EIA reported exports of 607,000 b/d, compared with Platts Analytics’ estimate of 1.3 million b/d based on ship tracking data. The discrepancy implies a true product supplied number closer to 1.3 million b/d. Domestic res/com demand on recent cold weather is contributing to PADD 2 draws and steep declines in PADD 1a inventories. PADD 1a stocks have fallen by 217,000 barrels over the past four weeks, though a build is expected for the current week after the vessel JS Ineos Insight was observed delivering a cargo from Karsto earlier this week.

Chicago ethanol prices climbed at the start of last week, recovering from the 13-year low $1.175 per gallon reported on Nov 29. The cash margins for S&P Global Platts’ model ethanol plant worsened as the cost to manufacture ethanol exceeded the product price. The US exported 171.1 million gallons of fuel grade ethanol in October, a seven-month high. In Brazil, hydrous ex-mill Ribeirao Preto spot prices assessed by S&P Global Platts rose for the second consecutive week. Ethanol producers in the North-Northeast (NNE) region are focusing on hydrous production, which is already triggering higher anhydrous prices. In Europe, T2 ethanol prices rose to a 20-month high due to a shortage of supply.

U.S. ethanol production fell last week by 23 MB/D to 1,046 MB/D as several companies reduced output as a result of weak margins. Inventories slid by 140 thousand barrels to 22.9 million barrels, with most of the decline occurring on the Gulf Coast. East Coast stocks bounced back over 7.0 million barrels, while West Coast stocks climbed to a record high 3.3 million barrels. Ethanol-blended gasoline production increased by 160 MB/D to 9,018 MB/D.

Concern was expressed this weekend over the lack of details on the second Market Facilitation Payment for soybeans. While USDA had promised information over 2 weeks ago, the latest is that Secretary Purdue met with the OMB and President Trump last Friday in an effort to persuade the parties that the second payment is still necessary. Even though a reason for the delay has not been formally announced, it is our interpretation that the OMB is having difficulty substantiating the need for the second payment. Looking over a yearly chart of prompt futures, the high was $10.825 back in early March. If the whole $1.65 is eventually paid, that would mean that selling anything over $9.17 in prompt futures would equate to selling above the high print.

The January NYMEX futures contract settled at $4.124/MMBtu on Thursday, down more than 20 cents from the week before. In spite of strong fundamentals this week, forecasts calling for milder temperatures in the coming weeks are expected to loosen balances and are influencing prices. The remaining NYMEX winter strip (Jan-Mar) fell W/W averaging $0.03/MMBtu less than the average from the week before, and yesterday’s settlement of ~$4.00/MMBtu was the lowest we’ve seen since mid-November. Meanwhile, the summer strip (April-Oct) has averaged about 3 cents higher W/W.

After a period of weakness, the commodity complex has seen a bit of a bounce, driving up the CSP as carbon prices remain volatile, whilst coal has moved out of its bear cycle, in part on the back of restored Rhine river levels. This is as the gas prices have continued to drop, TTF DA falling faster than other hubs. With cold weather until the 15th, NCG is expected to stay high above TTF, whilst PEG is likely to move back below the Dutch hub. Going forward, the generalized warming is expected to bring NBP closer to TTF. NWE remains well supplied, with NCS reacting to the drop in UK LNG sendouts and still limited flows observed on BBL, whilst the IUK remains dormant. This is whilst Russian imports have become even stronger, allowing NWE to maintain storage withdrawals below 70mcm/d and leaving continental NWE with record high storage level for this time of the year.

Falling JKM prices this month through 2020 compared to 2018 levels will usher in a period of weakness. JKM is expected to bottom out in 2020 and 2021. Importantly, this is a period of time where crude prices are expected to increase due to IMO 2020, which should create a disconnect between JKM and Brent. This will be an important development in the commoditization of LNG as long-term contracts linked to oil are expected to be out of the money compared to spot prices. We expect TTF prices to play a greater role in JKM formation, while prices in NW Europe will anchor on coal-switching prices.

Rising domestic gas prices in the US, combined with softening global demand, have resulted in greatly diminished netbacks to U.S. LNG off-takers, which could put pressure on LNG feedgas demand in January and February. Henry Hub has strengthened due to high early-winter demand, combined with unseasonably low underground storage reserves. Platts Analytics models forecast that the current forward curve may be over-valuing the Henry Hub balance of winter contract by upwards of ~17%, assuming that US weighted temperatures fall back within normal bounds.

Spot on-peak energy prices were up y/y in October in all eastern markets and ERCOT due to higher weather-driven loads and gas prices. Our forecast is also up from last month’s runs primarily due to higher fuel price forecasts. Weather-adjusted loads across the Eastern Interconnect and ERCOT increased by 1.2% y/y, driven largely by growth in ERCOT, SPP and PJM. Price support is clearly tied to abnormally low fuel inventory levels which have market participants on edge over a potential pivot to colder conditions during the crucial Jan-Feb time period. Though the weather play seems to be breaking down in the front with milder weather forecast. Outside of the winter, the NYMEX summer 2019 strip has seen increased buying of late. Platts Analytics sees limited potential for a significant supply response. In fact, based on prevailing prices, Platts expects production momentum to slow on a y/y basis throughout 2019, which could lend upward pricing pressure relative to the NYMEX curve at this time next year.

Belgian price risk for the remainder of this winter has fallen sharply over the past week after Engie Electrabel announced the 1GW Doel-4 reactor, offline for the same cement degradation issues as Tihange 2 and 3, would return online as scheduled on Dec.15. With Doel-4 back online, two other reactors remain offline for inspection and repair works, Tihange-2 and Tihange-3, due back on Jun.1 and Mar.2 respectively. This will continue to limit 1Q2019 Belgian nuclear availability to 4GW, down 2GW Y/Y. Meanwhile current spreads indicate the new 1GW link with the UK, NEMO, will add little upside to supply to the Belgian system with the UK-BE Baseload spread for 1Q2019 shrinking and turning positive over the past week.

CIF ARA forward prices shifted notably higher this week across the forward curve, adding to last week’s modest gains. However, with US supply still flowing to the continent and South African supply pushed out of the Pacific Basin due to uncertainties over Chinese imports, additional upside for CIF ARA prices should be limited. On the other hand, continued Chinese import uncertainty and elevated Chinese stockpiles limited price gains for FOB Newcastle this week. Warmer-than-normal temperatures in Northeast Asia appear to be limiting regional demand, adding confidence to our view that FOB Newcastle prices should face downward pressure in CY19.

Battery storage is surging, with more than 25 GW now in RTO/ISO interconnection queues, led by CAISO, SPP and ERCOT. This report analyzes the trends behind growing battery storage deployment, provides a forecast for market penetration through 2022, and also offers a longer-term view of the economic potential for storage. CA will continue to remain the largest market in the medium term, expected to reach 3.5 GW by 2022. Policies in the Northeast will drive ~1 GW of utility-scale battery storage by 2022. Further cost reductions and the federal ITC will help deployment of utility scale solar PV with batteries – challenging natural gas peakers in parts of the U.S. with favorable solar PV conditions. Distributed solar PV with batteries will gain in MA after CA, driven by demand charge management and the new SMART incentive.

CCA Benchmark (V-18 Dec-18) pricing averaged $15.53 in Nov, with monthly pricing flat since Sep at levels near the 2019 floor. The spread between Dec 18 and Dec 19 delivery has retreated somewhat from recent highs in excess of 6%. Trading volumes rose in Nov, with OI climbing. Actual CP2 offsets utilization, to be revealed when the Compliance Report is released this month, will determine the allowance bank carryover to CP3. Generally, near term compliance pressure remains limited, with CA balances not turning negative until after 2020. CARB adopted the final Cap and Trade Amendments on Dec 13th – pricing moved up a bit both the day before and the day after the vote. Linkage with Oregon remains possible, with full cap and trade legislative language for that state now expected next year. Otherwise, the CA Low Carbon Fuel Standard, a key complementary policy to the Cap and Trade, will see the diesel standard resume tightening as of Jan 1st, making for a larger annual deficit – CARB did not provide the promised 30-day notice for this change.

This report includes an updated assessment of Canada’s greenhouse gas (GHG) emissions trends and policies. Official data showed emissions down 1% YOY in 2016 (the last available year). Transport remains the largest contributor, and declining powergen emissions have been negated by increases from upstream oil & gas. Other data sources show similar trends. Canada remains unlikely to meet agreed-upon emissions targets. The Federal Carbon Pricing Framework takes effect in 2019, requiring provincial programs to have a sufficiently high carbon price. Programs in five provinces (ON, SK, NB, MB, PEI) were deemed insufficient, and a Federal backstop program will be imposed that includes a carbon levy on consumed fuels and an intensity program for large facilities. Ongoing lawsuits from SK and ON challenge Federal authority over GHGs and threaten its implementation. Provinces have responded to Federal carbon pricing requirements in a number of ways, including expanding existing taxes, developing new intensity-based programs, and non-pricing initiatives. Provincial emissions profiles will help determine which sectors will be responsible for reductions.

Quite fittingly, EUA prices are ending 2018 with a mid-Dec bull run. Record-high open interest in EUA options expired on Dec 12th, with 70% of calls in-the-money. While this prompted concerns of a sell-off, this has not yet occurred. With 2019 (as well as MSR implementation) just a few weeks away, there is no additional clarity on whether the U.K. will be participating in the EU ETS; a firm answer may not be available until after 2019 has begun. Should the U.K. participate, delays to their EUA auction supply will add additional market tightness. Higher TTF gas prices in 1Q2019 can support coal-gas switching costs, and thus EUAs, as will upcoming lengthy FR nuclear outages. Although a downward correction is possible, fundamentals should support EUA prices as we move into 2019.