Sunday, 16 June 2019

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S&P Global Platts Energy Market Recap for the Week Ending March 12, 2019


2019 Scenario Planning Service Annual Guidebook

Platts Analytics’ Scenario Planning Service (SPS) recently released its 2019 SPS Annual Guidebook, forecasting all aspects of the energy market out to 2040. This comprehensive report provides detailed assumptions and data on long-term supply, demand, and price of oil, gas, and coal, as well as outlooks of technology and policy drivers. Two of the most important messages in the SPS Annual Guidebook are to not underestimate energy demand and to be cautious about the impact of new technology deployment. While this cross-commodity outlook sees cost declines, technological enhancements, and policy developments increasing the penetration rate for both renewables and electric vehicles, peak demand for oil, and fossil fuels as a whole, is closer to 2040 than 2020. As well as providing a detailed most likely forecast of the energy markets, the SPS Annual Guidebook presents high and low price scenarios for oil, gas, and coal, to provide a range of potential outcomes depending on certain factors. The Guidebook also compares forecasted global CO2 emissions with 2 degree (Celsius) warming targets, which are looking increasingly difficult to meet.


European Oil Market Forecast

Brent prices to rise into the $70s later in the year. Crude differentials for light vs. medium/heavy will widen late in the year. Refining margins are starting to recover with modest gasoline improvement. Further margin strengthening should continue but the gasoline season will generally be lackluster, lower than last year, though stronger than the current forward curve. Diesel cracks will likely ease a bit before strengthening rapidly in 2H19 to well above the current forward curve. HSFO cracks will stay firm thru the summer as IMO 2020 demand impacts will not kick in until roughly September, then HSFO cracks will plunge.

Independents versus Majors: Diverging approaches to US shale. Will it matter?

Until recently, US shale oil development was dominated by independent operators while the majors continued to focus on deepwater and other developments. However, the game has started to change. Majors have made large acquisitions and have started to successfully compete with the independents. They now account for around 13% of total US shale oil production, and if their aggressive plans materialize, by 2024 their share could significantly increase to over 20%. The independents will not stand still. However, they have a big challenge to maintain their current share of production. In 2019 alone, their stated 15% production growth target will be hard to achieve in view of the announced 12% decrease in Capex. Having higher well efficiencies and dipping into the large DUC inventory is the most likely way to reach the target set by the independents. We forecast strong US shale oil production growth in 2019, despite the slowdown in 1H due to takeaway capacity constraints in the Permian. Much of the growth will come from the majors. This equates to a 1.2 MMB/D year-on-year increase for an average of 7.4 MMB/D in 2019 for US shale crude and condensate production.

Enbridge’s Line 3 project delay impacts Western Canada and Cushing

Enbridge’s Line 3 expansion has been delayed until 2H 2020, resulting in material revisions to our Western Canadian and Cushing balances. Inventories at Cushing built during February, and are expected to continuing building in March. The rail arb between Western Canada and the Gulf Coast reopened during February, and the rail arb from the Bakken to the Atlantic Coast widened. Exports increased in February, and are expected to decline in March as refinery maintenance starts to roll off. Please note: The EIA’s official monthly data for December will not publish until March 8, so the December numbers are still in prelim.

Demand has peaked, finished product draws ending

Aggregate demand fell 333 MB/D, while the 4-week average lost 71 MB/D. Seasonal demand has now peaked, and the demand uplift fell short of expectations. Even so, steady draws in finished products leave stock levels near seasonal means, but irregular seasonal builds will soon commence. Crude stocks built 1.8 MMBbls, which was a reversal from the week before. Refining margins continue to recover from very weak levels. The implied marketing margin eased again, with gasoline remaining above its statistical high, but gasoil/diesel below.

DOE Weekly Analysis

Total commercial stocks were almost flat as product stock draws were near-fully compensated for by an unexpected crude stock build, driven by a very large “adjustment” factor (the largest YTD). For next week, we forecast a significant crude stock build as still-low refinery runs won’t keep pace with strong domestic crude production. We also forecast significant product stock draws, as demand increases seasonally while products supply remains relatively low.

Significant production growth in 4Q18 but slowdown in activity planned for 2019

US shale crude and condensate production grew 8% Q/Q (+540 MB/D), while the horizontal oil rig count was basically flat at around 775 rigs. For the year, US shale crude and condensate production grew significantly (+32%, 1,500 MB/D year-on-year) and averaged 6,200 MB/D. Most operators signaled lower Capex and production guidance for 2019 in view of the reduction in oil prices during 4Q18 and the desire to stay within cash flow. Independents are planning less activity, but the majors are increasing spending modestly. Overall, Capex is down 9% in 2019. Still, production growth is expected to be strong at +18%. This is in line with our forecast which calls for a 20% year-on-year increase in production. Rig count for 2019 expected to go down 8% from an average of 740 rigs in 2018. Production growth will be supported by a draw down in DUCs. Overall drilling and completion costs increased by around 6% in 2018. Most costs increased but proppant costs decreased because of an oversupply of sand resulting from too many new local mines. The use of local sand also continued to increase, mainly in the Permian with some companies using up to 75% local sand.

Aramco Pricing for April: pricing higher to Asia, lower to Europe, US still priced at a large premium

Saudi Arabia released its pricing for April this week. Asian prices were generally raised a bit more than expected or justified based on Dubai structure. Europe pricing was lowered in agreement with a wider discount for Urals vs. Dated Brent, while US pricing was left basically unchanged. US pricing remains set at a large premium to competing domestic crudes, which sharply reduces its attractiveness to US refiners. Saudi production has fallen from 10.7 MMB/D in Dec to an estimated 9.8 MMB/D in March. Platts Analytics assumes a slight rise to 10.1 MMB/D in April and May. Pricing adjustments are not seen pushing volumes higher, but if refiners need to increase liftings due to fundamental demand, then the volumes are available, but at a price. Saudi seeks still higher prices as current prices continue to draw foreign exchange reserves and a fiscal deficit remains that needs to be filled by drawdowns, or debt issuance.

Significant snowfall impacts on gasoline demand in Northeast for this week, yet very limited one on jet and diesel demand

March 3rd had multiple weather events including a snowstorm that swept across the Northeast and catastrophic tornadoes in Alabama. The main impact of the tornado in Alabama was in Lee County where 23 people were killed including 3 children. The snowfall in the Northeast was minimal in most states but significant in a few. The amount of potential demand impacted from the states hit by the snowstorm was 1387 MB/D although in most cases the major city centers that comprise that number were minimally hit. Major cities like Philadelphia got 1 inch while New York City got 2-5 inches. The states hit the hardest were Massachusetts, Rhode Island and Connecticut which got between 6 and 17 inches.


US ends 2018 on solid note, but starts 2019 inauspiciously; Asian trade data weaken

US GDP growth during the fourth quarter was better-than-expected, and the pace of economic expansion in 2018 was the strongest since the mid-2000s. But reported growth for the first quarter is likely to be sub-par, as consumer spending is starting 2019 below the fourth quarter 2018 level; recent export confidence data do not bode well for the outlook, either. In Asia, Chinese manufacturing confidence figures were mixed in February. There were increasing indications that China’s industrial slump is negatively impacting other export-oriented Asian economies.

Financial stresses build slightly, but energy holds up

The S&P 500 failed to hold the 2,800 level and fell back 2.2%. Credit metrics deteriorated and implied inflation fell back. It is too soon to say if this is merely consolidation or something more. Commodities lost 0.6%, but energy gained 0.6%. The U.S. dollar strengthened 0.9%, and while implied inflation fell back, oil was higher as it now appears to be trading more on fundamentals and less on overall credit markets. The leveraged loan indicators continue to show lessening stress, while the St Louis financial stress indicator extended its improvement.


Propane stocks above year-ago levels exiting winter demand season

US propane/propylene stocks declined by 2.0 million barrels to 51.4 million barrels during the week ended March 1, according to EIA data. Total stocks are 10.3 million barrels above year-ago levels after the supply surplus to last year fell by 414,000 barrels week-over-week. Inventory declines were most concentrated in PADD 1 and PADD 2, which drew 683,000 barrels and 1.8 million barrels over the week, respectively. The total draw from the week prior was partially offset by an increase of 378,000 barrels in PADD 3. Total domestic demand was flat to the previous week at 1.6 million b/d, although below-normal temperatures in PADD 1 and PADD 2 may have contributed to elevated draws in the two regions. Population-weighted temperatures averaged 2 degrees and 9 degrees Fahrenheit below normal in the Northeast and Midcon Markets through March 1, respectively. Imports were lower week-over-week, averaging 153,000 b/d, or 29,000 b/d below the week prior. EIA reported exports were down an average 41,000 b/d from the previous week to 841,000 b/d. Platts Analytics estimates exports for the current week, through March 8, are averaging higher at 916,000 b/d. Front-month non-LST propane lost 0.125 cents/gal on Thursday settling at 68.38 cents/gal.


US ethanol production down despite higher annual production capacity; prices expected to continue rising

Chicago ethanol assessments remained in the $1.30-$1.35/gal range for most of February, preserving the gains made in late January during the polar vortex. Ethanol production in Brazil’s key Center-South region reached 30.4 billion liters in the current season through February 15, up 19.5% year-on-year. CropEnergies will resume ethanol production in its plant in Wilton, U.K. in March. Senator Chuck Grassley, one of Congress’s staunchest biofuels supporters, proposed legislation to reinstate the now-expired $1 per gallon biodiesel blending credit.

The biofuels industry awaits EPA’s proposed rule on E15

The EPA has not yet proposed the long-awaited rules on E15 or RIN reform, which had been on the agency’s Regulatory Agenda with a February 2019 target date. 2019 D6 RIN prices fell every day last week, dropping from 23.5¢ on Monday to 21.0¢ by the weekend. After surging to near record high, hydrous ethanol prices in Brazil's key Center-South region weakened Friday with minimal trading activity due to the Carnival holiday.

US ethanol stocks near a record high

US ethanol inventories soared last week to a near-record 24.3 million barrels. Midwest inventories increased to 8.8 million barrels, the third highest level ever reported. Total stocks are currently up 1.1 million barrels year-on-year, putting downside pressure on prices. Domestic ethanol production fell by 4 MB/D to 1,024 MB/D. Ethanol-blended gasoline production rose by 115 MB/D to 8,863 MB/D.


Rising OPEC fiscal breakeven prices mean more pressure to maintain production cuts

Platts Analytics estimates OPEC budget breakeven prices now stand above $90/Bbl Brent, up from $86/Bbl in 2018 and $80/Bbl in 2017. Saudi Arabia will require $92/Bbl Brent to balance its budget this year, up from $78/Bbl in 2017, largely due to sharply higher government spending. Given rising fiscal requirements and the need to fund longer-term economic reforms under Vision 2030, it is understandable that Saudi oil policy now appears to be focused on near-term revenue maximization and production restraint, as we have seen with the announcement to lower production below 10 MMB/D in March. Russia’s breakeven price is lower at $60/Bbl Brent, but we expect continued cooperation with OPEC for now. The economic benefits from production cut agreements in 2016 and 2018 far outweighed Russia’s own voluntary loss of supply volumes, while the geopolitical advantages of cooperation with US ally Saudi Arabia likely remain appealing to the Kremlin. Elsewhere in OPEC, we are most concerned by fiscal stress in Nigeria ($109/Bbl breakeven price) and Iraq ($83/Bbl). US sanctions raised Iran’s breakeven price to $112/Bbl Brent in 2019, and Venezuela’s to $161/Bbl.


March 2019 WASDE Preview

With the “final” 2018/’19 production numbers in the delayed January Crop Production report now a known, focus shifts to tweaks on the demand side of the ledgers in advance of the first acreage survey in the Prospective Plantings report in a few weeks’ time. March WASDE’s are typically a non-event although last year’s report gave a short-lived boost to corn prices. The “problem” this year is that the focal point of demand has very little in the form of positive news for any of the major grains and oilseeds. Expected cuts in demand may be offset somewhat by what is shaping up to be late start for planting in major growing areas west of the Mississippi River. Never one to jump on the “delayed planting” bandwagon, Platts Analytics is certainly not oblivious to the record snowfall and frozen tundra like conditions currently seen in many parts of the Belt. Underneath some of the record snowfall amounts sits a frost line 21” deep in the central part of Iowa as compared to 2” last year according to the NWS in Des Moines. Throughout the state of Iowa there is not one county that has above freezing soil temp at the 4” depth level while many in the northern part of the state are registering soil temperatures in the mid-20’s, almost certainly the same for those in southern Minnesota and parts west. May not be a story yet, but a weather shift needs to occur in fairly short order to prevent delayed plantings.


US Gas Weekly Report

Henry Hub cash prices averaged $3.23/MMBtu for the week ended March 6 — an increase of ~17% week-on-week. Weather and low storage levels were largely behind the increase in price, as US temperatures fell ~19% week-on-week. Of note, prices spiked to an impressive $4.12/MMBtu for flow date March 5, the highest levels since last December. Since then, prices have come back down and have averaged roughly $3.0/MMBtu. Henry Hub summer 2019 prices have responded to market expectations for end March dipping below 1.1 Tcf. Currently, summer prices are trading at the upper-end of their heating season range ($2.60 to $2.95/MMBtu), while rallying over 9% in the past month. Total supply for the week-ended March 7 grew by 0.7 Bcf/d relative to the prior week. Higher LNG sendout (0.5 Bcf/d) and Canadian imports (0.7 Bcf/d) week-on-week helped to offset a 0.5 Bcf/d decline in domestic production. Domestic production losses on a week-on-week basis were largely driven by the Northeast, which fell by ~0.5 Bcf/d. Regional production averaged 30.5 Bcf/d for the week and is ~1.2 Bcf/d off the record daily high of 31.7 Bcf/d realized in early December.

Don't be fooled: Why another summer ending inventory of 3.2 Tcf is more bullish than last year

US natural gas inventories appear destined to exit this coming summer and enter the winter of 2019-2020 with roughly 3.1-3.2 Tcf in storage, due to sustained cold weather in recent weeks. This same scenario played out last summer, yet the market is on the verge of surviving one of the lowest beginning of winter inventory levels in over 10 years. Next winter, however, could be different. For one, the 8.2 Bcf/d of winter-over-winter production growth available to the market this year that dwarfed demand gains will be just 3 Bcf/d next winter, thanks to flagging Northeast production. As well, up to 4 Bcf/d of incremental LNG export capacity is slated to enter service before next winter. This structural growth in demand will outpace production gains, leaving the US market much tighter in the winter of 2019-2020. The lack of a supply overhang will place a greater reliance on storage to balance the market, presenting upside risk to the Henry Hub summer and winter 2019-20 strips.


With an early start to spring, gas pricing risks breaking through key support levels

European gas fundamentals could not be any more different compared to those last year. Continued strong LNG deliveries and weak demand on mild weather saw February storage withdrawals at their lowest since 2011; a trend which continued into March. This contrasts with record withdrawals in Feb-17, escalating into “the Beast” at the start of Mar-17. We’re now being reminded on almost a daily basis of just how dramatic the W-18 market shift has been 1st March saw a new 7 year high daily European LNG sendout. Saturday 2nd March saw 89mcm/d of NW European injections, a level never seen before 24th March in previous years (compared to withdrawals remaining above 550mcm/d for five consecutive days going into March 2018).


Emerging Africa presents real risks in shoulder seasons to existing suppliers

The current fall in JKM pricing is not necessarily a case of massive oversupply, but more a case of massive undersupply of storage. When demand in East Asia is not there, the market is prone to price collapse to incentivize new demand, as storage space can be hard to find. In the competition to satisfy marginal demand, a big lesson is being felt by the US - distance wins. We have emphasized for a long time that new US production is at a disadvantage versus nearly all other producers due to their distance from Asian buyers and to a large extent European ones as well – despite Henry Hub remaining at sub-$3/MMBtu levels.


Ramp-down flexibility of French nuclear fleet potentially supportive of summer prices

After a relatively flat profile observed throughout Feb, French nuclear output went through a D/D drop of more than 10GW in the first weekend of Mar, the largest of at least the past seven years. This is part of a pattern of renewed flexibility from the French nuclear fleet, evident through ramp-down rates in the current quarter. Summer ramp-up rates have increased in the past couple of years, suggesting a progressive loss of flexibility overall, but if the above pattern holds during the summer it could offer a relevant support to prices all else being equal.


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