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Dan Tsubouchi

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Produced by: Dan Tsubouchi

December 15, 2019

Supplemental Documents

U.S. Energy Information Administration | Short-Term Energy Outlook December 2019 1

December 2019

Short-Term Energy Outlook (STEO)

Forecast highlights

Global liquid fuels

Brent crude oil spot prices averaged $63 per barrel (b) in November, up $3/b from October. EIA forecasts Brent spot prices will average $61/b in 2020, down from a 2019 average of $64/b. EIA forecasts that West Texas Intermediate (WTI) prices will average $5.50/b less than Brent prices in 2020. EIA expects crude oil prices will be lower on average in 2020 than in 2019 because of forecast rising global oil inventories, particularly in the first half of next year.

On December 6, the Organization of the Petroleum Exporting Countries (OPEC) and a group of other oil producers announced they were deepening production cuts originally announced in December 2018. The group is now targeting production that is 1.7 million barrels per day (b/d) lower than in October 2018, compared with the former target reduction of 1.2 million b/d. OPEC announced that the cuts would be in effect through the end of March 2020. However, EIA assumes that OPEC will limit production through all of 2020, amid a forecast of rising oil inventories. EIA forecasts OPEC crude oil production will average 29.3 million b/d in 2020, down by 0.5 million b/d from 2019.

Beginning on January 1, 2020, the International Maritime Organization (IMO) is set to enact Annex VI of the International Convention for the Prevention of Pollution from Ships (MARPOL Convention), which lowers the maximum sulfur content of marine fuel oil used in ocean-going vessels from 3.5% of weight to 0.5%. EIA expects that starting in the fourth quarter of 2019, this regulation will encourage global refiners to increase refinery runs and maximize upgrading of high-sulfur heavy fuel oil into low-sulfur distillate fuel to create compliant bunker fuels. EIA forecasts that U.S. refinery runs will rise by 3% from 2019 to a record level of 17.5 million b/d in 2020, resulting in refinery utilization rates that average 93% in 2020. EIA expects one of the most significant effects of the regulation to be on diesel wholesale margins, which rise from an average of 45 cents per gallon (gal) in 2019 to a forecasted peak of 61 cents/gal in the first quarter of 2020 and an average of 57 cents/gal in 2020.

EIA data show that the United States exported 90,000 b/d more total crude oil and petroleum products in September than it imported. This is the first month recorded in U.S. data that the United States exported more crude oil and petroleum products


than it imported. U.S. imports and exports records of crude oil and petroleum products started on an annual basis in 1949 and on a monthly basis in 1973. EIA expects total crude oil and petroleum net exports to average 570,000 b/d in 2020 compared with average net imports of 490,000 b/d in 2019.

EIA expects U.S. crude oil production to average 13.2 million b/d in 2020, an increase of 0.9 million b/d from the 2019 level. Expected 2020 growth is slower than 2018 growth of 1.6 million b/d and 2019 growth of 1.3 million b/d. Slowing crude oil production growth results from a decline in drilling rigs over the past year that EIA expects to continue into 2020. Despite the decline in rigs, EIA forecasts production will continue to grow as rig efficiency and well-level productivity rises, offsetting the decline in the number of rigs.

EIA estimates that propane inventories in the Midwest—Petroleum Administration for Defense District (PADD) 2—were 22.0 million barrels at the end of November, 17% lower than the five-year (2014–18) average for the end of November. Colder-than-normal temperatures and strong grain drying demand in November contributed to large draws on Midwest propane inventories. Also, Western Canadian rail shipments of propane to the Midwest have declined since the opening of a new propane export terminal in Western Canada in May. EIA forecasts Midwest inventories at the end of March will be 32% lower than the five-year (2015–19) average and the lowest for that time of year since 2014.

Natural gas

EIA estimates that the U.S. total working gas inventories were 3,616 billion cubic feet (Bcf) at the end of November. This level was about equal to the five-year (2014–18) average and 19% higher than a year ago. EIA expects storage withdrawals to total 1.9 trillion cubic feet (Tcf) from the end of October to the end of March, which is less than the five-year average winter withdrawal. A withdrawal of this amount would leave the end-of-March inventories at almost 1.9 Tcf, which would be 8% higher than the five-year (2015–19) average.

The U.S. benchmark Henry Hub natural gas spot price averaged $2.64 per million British thermal units (MMBtu) in November, up 31 cents/MMBtu from October. Prices increased as a result of November temperatures that were colder than the 10-year (2009–18) average. EIA forecasts the Henry Hub spot price to average $2.45/MMBtu in 2020, down 14 cents/MMBtu from the 2019 average.

EIA forecasts that annual U.S. dry natural gas production will average 92.1 billion cubic feet per day (Bcf/d) in 2019, up 10% from 2018. EIA expects that natural gas production will grow much less in 2020 because of the lag between changes in price and changes in future drilling activity. Low prices in the third quarter of 2019 will reduce natural gas-directed drilling in the first half of 2020. EIA forecasts natural gas production in 2020 will average 95.1 Bcf/d.


Electricity, coal, renewables, and emissions

EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants will rise from 34% in 2018 to 37% in 2019 and to 39% in 2020. EIA forecasts the share of U.S. electric generation from coal to average 25% in 2019 and 22% in 2020, down from 28% in 2018. EIA’s forecast nuclear share of U.S. generation remains at about 20% in 2019 and in 2020. Hydropower averages a 7% share of total U.S. generation in the forecast for 2019 and 2020, similar to 2018. Wind, solar, and other nonhydropower renewables provided 9% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.

EIA expects U.S. coal production in 2019 to total 697 million short tons (MMst), which would be an 8% decline from the 2018 level. In 2020, EIA expects a further decrease in total U.S. coal production of 14%, to an annual total of 601 MMst, reflecting continued idling and closures of mines as a result of declining domestic demand.

EIA expects U.S. coal exports to total 93 MMst in 2019, and then decline by 8 MMst to 85 MMst in 2020. U.S. coking coal currently faces challenges from a global oversupply of steel, particularly in the fourth quarter of 2019. Steam coal exports have been dampened by high stockpiles in Europe and India, a top destination for U.S. shipments.

EIA expects U.S. electric power sector generation from renewables other than hydropower—principally wind and solar—to grow from 411 billion kilowatthours (kWh) in 2019 to 471 billion kWh in 2020. In EIA’s forecast, Texas accounts for 20% of the U.S. nonhydropower renewables generation in 2019 and 22% in 2020. California’s forecast share of nonhydropower renewables generation falls from 15% in 2019 to 14% in 2020. EIA expects that the Midwest and Central power regions will see shares in the 16% to 18% range for 2019 and 2020.

EIA forecasts that, after rising by 2.9% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.4% in 2019 and by 2.2% in 2020, partly as a result of lower forecast energy consumption. For 2019, EIA estimates there was less demand for space cooling because of cooler summer months, with an estimated 5% decline in U.S. cooling degree days from 2018, when temperatures were significantly higher than the previous 10-year (2008–17) average. In addition, EIA also expects U.S. CO2 emissions in 2019 to decline because the forecast share of electricity generated from natural gas and renewables will increase, and the share generated from coal, which is a more carbon-intensive energy source, will decrease.


Petroleum and natural gas markets review Crude oil

Prices: The front-month futures price for Brent crude oil settled at $63.39 per barrel (b) on December 5, 2019, an increase of $1.70/b from November 1. The front-month futures price for West Texas Intermediate (WTI) crude oil for delivery at Cushing, Oklahoma, increased by $2.23/b during the same period, settling at $58.43/b on December 5 (Figure 1).

The increase in crude oil prices over the past month likely reflected modest upward pressures from both demand-side factors and supply-side factors. On the demand side, economic data from the world’s two largest economies—the United States and China—reduced market perceptions of an upcoming slowdown in economic activity. The U.S. Bureau of Economic Analysis released its second estimate of third-quarter 2019 gross domestic product (GDP). This estimate indicated that real U.S. GDP increased at an annual rate of 2.1% in the third quarter, a faster rate than previously estimated and an increase from growth of 2.0% in the second quarter. For China, the Caixin/Markit manufacturing purchasing managers’ index (PMI) for November was 51.8, up from 51.7 in October and the highest level since 2016. Any reading higher than 50 indicates an expected expansion in manufacturing activity.

Concurrently, the S&P 500 equity index closed at a record 3,153.6 on November 27—the day the U.S. GDP estimate was released—an increase of 2.8% from the beginning of the month. The S&P 500 subsequently declined in late November and early December as trade tensions between the United States and China were back in news headlines. Overall, the S&P 500 index was up 2.4% in November.

On the supply side, markets adjusted expectations ahead of the December 6 meeting between the Organization of the Petroleum Exporting Countries (OPEC) and partner countries. Expectations that OPEC and its partners would extend or possibly deepen the cuts, as noted in


press reports, helped support crude oil prices. Ultimately, the group decided to deepen existing production cuts by 0.5 million b/d, but the cuts were not extended and continue to run through the end of March 2020.

EIA assumes the production cuts from OPEC and Russia will remain in place through the end of the forecast period in 2020. With production restraint from most OPEC members, continuing sanctions on Iran, and ongoing declines in Venezuela’s crude oil production, EIA expects OPEC production to fall in 2020. However, EIA forecasts that increased non-OPEC production will more than offset those declines and that global liquid fuels supply will rise by 1.5 million barrels per day (b/d) in 2020. EIA forecasts global fuels demand will rise by 1.4 million b/d next year and that Brent prices will average $61/b in 2020, down from $64/b in 2019. EIA expects the downward price pressures to be concentrated in the first half of 2020, when global oil inventories are forecast to rise. Prices will begin to rise in the second half of next year based on this STEO’s forecast of global oil inventory draws over that period.

Brent and copper-to-gold ratio: The price of copper—a commodity heavily used in construction and industrial production and, therefore, often positively correlated with economic expansion—has increased since reaching its year-to-date low in September relative to the price of gold. Gold is typically assumed to be a safe haven asset and its price tends to increase in times of economic uncertainty. Taken together, the ratio of these two commodity prices can indicate market sentiment on global economic growth.

As of December 5, copper-to-gold ratio increased to 0.93 (indexed to July 1, 2019) compared with a ratio of 0.84 on September 3, the lowest ratio in 2019 (Figure 2). The upward trend may reflect some improvement in the macroeconomic climate, which may have also contributed some support to the Brent price during the past two months. Supply issues can also affect commodity prices, as the September price spike in Brent after the attack on Saudi Arabia indicates. Part of the strength in copper prices also likely reflects the recent strikes, work slowdowns, and port closures in Chile, which produced 29% of the world’s copper in 2018.


Crude oil trade flows: Increasing U.S. crude oil exports and sanctions on Iranian crude oil sales have contributed to a significant shift in the waterborne oil trade in the Mediterranean and Red Seas, where traffic on the interconnecting Suez Canal has inverted. Ships transiting the Canal—through which 6% of all crude oil passed in 2018—had typically traveled northbound from the Red Sea into the Mediterranean, and northbound crude oil cargoes typically outnumbered their southbound counterparts by a ratio of about 2.8 to 1 between 2015 and 2018. This mismatch largely reflected the deep linkages between European buyers and major east-of-Suez producers such as Iraq, Saudi Arabia, and Iran, which supplied an average of 10%, 9%, and 15%, respectively, of crude oil imports to European countries in the Organization of Economic Cooperation and Development (OECD) between 2015 and 2018, according to data from the International Energy Agency (IEA). This group of Middle Eastern producers typically ship their Europe-bound crude oil cargoes to the Red Sea, where they then either navigate the Suez Canal or offload their cargoes onto the north-bound SUMED pipeline—though the attractiveness of the latter option has declined following the widening of the Canal in 2015. Since late 2018, however, northbound crude oil volumes on the Suez Canal have fallen in both absolute and relative terms, with the ratio of northbound to southbound October 2019 shipments falling to 0.4 to 1 for crude oil (Figure 3).

This reversal has likely been driven by two related factors. First, the increase in U.S. crude oil exports—which do not have to transit the Suez—has displaced some supplies from the former Soviet Union (FSU), primarily Russia, and the Middle East. According to the IEA, while the share of OECD Europe crude oil imports supplied by the FSU, Saudi Arabia, Iran, and Iraq fell from a combined 2015 to 2018 average of 68% to 62% in August 2019 (the latest date for which information is available), the U.S. share increased from 3% to 8% during the same period (Figure 4). Consequently, some Russian exporters have opted to send their cargoes south and east into the faster-growing Asian markets, increasing the number of southbound transits, while Middle Eastern exporters are also sending more cargoes to Asia, decreasing the number of northbound transits. Second, the volume of northbound cargoes has also been affected by U.S. sanctions on


Iran that were reimposed in November 2018. By limiting the ability of Iranian cargoes to reach OECD Europe, the sanctions have contributed to the collapse in Iranian exports to the region from an annual average 536,000 b/d in 2018 to 25,000 b/d in August 2019.

These trends could continue in 2020 based on EIA’s supply forecasts and the International Maritime Organization (IMO) 2020 regulations. EIA expects U.S. crude oil production to provide about two-thirds of total global liquids growth next year, but OPEC production is forecast to decline. In addition, U.S. crude oil tends to be light, sweet grades, which will likely see an increase in global demand because of the IMO 2020 regulations.

Petroleum products

Gasoline prices: The front-month futures price of reformulated blendstock for oxygenate blending (RBOB, the petroleum component of gasoline used in many parts of the country) settled at $1.62 per gallon (gal) on December 5, down 3 cents/gal since November 1 (Figure 5). The RBOB–Brent crack spread (the difference between the price of RBOB and the price of Brent crude oil) decreased by 8 cents/gal to settle at 11 cents/gal during the same period.


The RBOB–Brent crack spread for November remained relatively stable, within a range of 8 cents/gal, and averaged 5 cents less than October and 3 cents/gal less than the five-year (2014–18) monthly average. One factor likely contributing downward pressure on the spread was an inventory build of 12.6 million barrels in November, which increased inventory levels to higher than the five-year monthly average after falling lower than the five-year average in October. Higher production and lower consumption in November compared with October contributed to the stock build.

Ultra-low sulfur diesel prices: The ultra-low sulfur diesel (ULSD) front-month futures price settled at $1.93/gal on December 5, unchanged from November 1. The ULSD–Brent crack spread (the difference between the price of ULSD and the price of Brent crude oil) decreased 4 cents/gal to settle at 42 cents/gal during the same period (Figure 6).


Although the average ULSD–Brent crack spread in November declined from the October level, it remained higher than the five-year average. Higher U.S. distillate fuel production and imports helped to moderate crack spreads in November. Distillate production increased from October as refineries came back from maintenance and increased throughput, but production remained lower than the five-year average. An increase in distillate imports and a decrease in exports resulted in net imports rising to higher than the five-year range. If confirmed in the monthly data, this level of net distillate imports would be the highest for November since 2012.

Distillate consumption also reached what would be a record high for November if confirmed by monthly data. Colder-than-normal temperatures and a late harvest contributed to distillate consumption in November of 4.2 million barrels per day. Despite the increases in production and net imports, the increase in distillate consumption led to a smaller-than-normal inventory build for November. EIA estimates the end of November inventory at 120 million barrels, the lowest level for November in seven years. EIA expects that the lower inventory levels combined with the upcoming International Maritime Organization (IMO) 2020 change to marine fuel sulfur specifications will contribute to higher ULSD-Brent crack spreads during the next several months.

Midwest crack spreads: Product market dynamics in the Midwest are creating different trends in gasoline and ULSD crack spreads for the Chicago area compared with New York Harbor and the Gulf Coast. In late November, refinery utilization rates in the Midwest (PADD 2), reached 94.4%, the highest across U.S. regions. Although total motor gasoline inventories in the Midwest ended November 1% higher than the five-year average, distillate inventories were 11% lower than the five-year average, likely a result of higher demand.

Because the Midwest has the largest regional consumption of distillate in the United States and the largest distillate consumption for farming end-use, factors specific to the farming sector likely contributed to the elevated consumption levels in the region. According to data from the U.S. Department of Agriculture and trade press reports, heavy rainfall and flooding delayed the crop harvest in the Midwest from October to November. Crack spreads responded by remaining high for ULSD and decreasing for gasoline. The average monthly Chicago ULSD-WTI crack spread in November decreased 1 cent/gal from October, and the Chicago RBOB-WTI crack spread decreased 12 cents/gal (Figure 7).


Residual fuel oil sulfur spread: The price spread between low- and high-sulfur residual fuel continued to widen in November (Figure 8), likely related to the upcoming IMO 2020 change in marine fuel sulfur specifications. Prices for high-sulfur residual fuel oil have been falling for most of the year, but prices for low-sulfur residual fuel oil have remained mostly flat, increasing the price differential between the two fuels. The price for high-sulfur (3%) residual fuel oil in New York Harbor (NYH) has fallen by $23.23 per barrel (b) from this time last year to $40.82/b in November 2019. During the same time period, the price for low-sulfur (0.3%) residual fuel oil in NYH has decreased $0.61/b to $76.91/b in November 2019. This difference in price performance indicates that the increase in the price differential between NYH low-sulfur and high-sulfur residual fuel oil of $22.62/b has been driven by the decrease in the high-sulfur residual fuel oil price.


EIA forecasts that demand for high-sulfur residual fuel oil in the bunkering market will shift to low-sulfur alternatives as a result of the IMO specification change. To prepare for this demand shift, ship operators have started to replace their high-sulfur fuel oil stores with low-sulfur fuels, which has contributed to the increase in the differential between low- and high-sulfur residual fuel oil.

Natural Gas

Prices: The front-month natural gas futures contract for January delivery at the Henry Hub settled at $2.43 per million British thermal units (MMBtu) on December 5, down 29 cents/MMBtu from November 1 (Figure 9). Forecasts for colder weather in early November—seen in Figure 9 as the sharp, green peak in the difference between normal and current heating degree days (HDD) in November 2019—had supported a sharp increase in futures prices from $2.24/MMBtu on October 21 to a peak of $2.86/MMBtu on November 5. For the rest of the month, prices declined in tandem with generally milder weather forecasts. The decline would have been more substantial, but the front-month natural gas futures price gained 6 cents/MMBtu with the change from December to January delivery on November 27.

Inventories: A similar increase in HDD occurred in November 2018, but the corresponding Henry Hub front-month futures price rose significantly more than in 2019. Natural gas inventory during November 2018 declined to more than 700 billion cubic feet lower than the five-year (2013–17) average (Figure 10), which likely contributed to the larger price response. Increasing production contributed to substantial inventory builds following the 2018 winter season, sending the total to near the five-year (2014–18) average in November 2019. The higher inventory level likely dampened the increases in the front-month futures price increases during November 2019. EIA estimates that natural gas production will remain at or lower than the November 2019 level through the end of 2020.


Notable forecast changes

EIA revised historical global (outside of the United States) liquid fuels consumption data back to 2000. These revisions were most significant for countries in Africa and the Middle East. Based on these changes, EIA estimates that global liquid fuels consumption in 2017, the most recent year for which EIA has a complete set of consumption data, averaged 98.6 million barrels per day (b/d), 250,000 b/d lower than previously estimated. The lower 2017 consumption levels result in lower estimated and forecast consumption from 2018 through 2020.

For more information, see the detailed table of STEO forecast changes.

For ore information, see the detailed STEO table of forecast changes.

This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and analytical agency within the U.S. Department of Energy. By law, EIA's data, analyses, and forecasts are independent of approval by any other officer or employee of the United States Government. The views in this report therefore should not be construed as representing those of the U.S. Department of Energy or other federal agencies.

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2018 2019 2020Supply (million barrels per day) Crude Oil Supply Domestic Production (a) ................................................... 10.27 10.54 11.25 11.89 11.81 12.10 12.23 12.87 13.12 13.22 13.14 13.23 10.99 12.25 13.18 Alaska ........................................................................... 0.51 0.48 0.43 0.49 0.49 0.47 0.43 0.49 0.51 0.49 0.45 0.49 0.48 0.47 0.48 Federal Gulf of Mexico (b) ............................................. 1.68 1.60 1.87 1.87 1.85 1.93 1.81 2.00 2.04 2.03 1.94 1.96 1.76 1.90 1.99 Lower 48 States (excl GOM) ......................................... 8.07 8.46 8.94 9.53 9.47 9.70 9.99 10.37 10.57 10.71 10.75 10.78 8.75 9.89 10.70 Crude Oil Net Imports (c) ................................................. 6.03 6.10 5.78 4.98 4.25 4.14 3.95 3.42 4.06 4.46 4.17 4.07 5.72 3.94 4.19 SPR Net Withdrawals ...................................................... -0.03 0.06 0.00 0.12 0.00 0.05 0.00 0.11 0.01 0.01 0.00 0.03 0.04 0.04 0.01 Commercial Inventory Net Withdrawals ............................ -0.04 0.11 -0.02 -0.28 -0.19 -0.05 0.41 -0.19 -0.39 0.02 0.22 -0.12 -0.06 0.00 -0.07 Crude Oil Adjustment (d) .................................................. 0.18 0.33 0.32 0.29 0.33 0.53 0.38 0.34 0.19 0.19 0.21 0.15 0.28 0.39 0.19 Total Crude Oil Input to Refineries ...................................... 16.42 17.13 17.33 16.99 16.20 16.76 16.97 16.55 16.97 17.89 17.75 17.37 16.97 16.62 17.49 Other Supply Refinery Processing Gain ................................................. 1.10 1.13 1.17 1.16 1.06 1.07 1.07 1.17 1.19 1.24 1.24 1.25 1.14 1.09 1.23 Natural Gas Plant Liquids Production ............................... 4.04 4.33 4.56 4.54 4.66 4.81 4.80 5.25 5.23 5.35 5.42 5.54 4.37 4.88 5.39 Renewables and Oxygenate Production (e) ...................... 1.21 1.23 1.25 1.22 1.18 1.23 1.20 1.18 1.16 1.20 1.19 1.21 1.23 1.20 1.19 Fuel Ethanol Production ................................................ 1.05 1.04 1.06 1.04 1.01 1.05 1.02 1.01 1.01 1.03 1.02 1.04 1.05 1.02 1.03 Petroleum Products Adjustment (f) ................................... 0.21 0.21 0.21 0.22 0.20 0.18 0.19 0.22 0.22 0.23 0.23 0.23 0.21 0.20 0.23 Product Net Imports (c) .................................................... -3.03 -3.44 -3.12 -3.92 -3.35 -3.10 -3.20 -4.11 -4.74 -4.82 -4.53 -4.95 -3.38 -3.44 -4.76 Hydrocarbon Gas Liquids .............................................. -1.20 -1.53 -1.47 -1.42 -1.33 -1.65 -1.66 -2.01 -2.01 -2.08 -2.05 -2.15 -1.40 -1.67 -2.07 Unfinished Oils .............................................................. 0.40 0.35 0.35 0.30 0.21 0.47 0.47 0.25 0.44 0.56 0.52 0.38 0.35 0.35 0.48 Other HC/Oxygenates ................................................... -0.18 -0.15 -0.13 -0.15 -0.13 -0.13 -0.13 -0.10 -0.10 -0.10 -0.10 -0.11 -0.15 -0.12 -0.10 Motor Gasoline Blend Comp. ........................................ 0.50 0.78 0.67 0.37 0.43 0.79 0.70 0.37 0.42 0.65 0.50 0.45 0.58 0.57 0.50 Finished Motor Gasoline ............................................... -0.92 -0.71 -0.70 -1.00 -0.82 -0.63 -0.62 -0.86 -1.12 -1.02 -0.87 -1.12 -0.83 -0.73 -1.03 Jet Fuel ......................................................................... -0.11 -0.10 -0.06 -0.13 -0.08 -0.01 -0.05 -0.07 -0.08 -0.10 -0.11 -0.11 -0.10 -0.05 -0.10 Distillate Fuel Oil ........................................................... -0.81 -1.33 -1.13 -1.18 -0.91 -1.29 -1.30 -1.05 -1.33 -1.70 -1.54 -1.28 -1.11 -1.14 -1.46 Residual Fuel Oil ........................................................... -0.09 -0.13 -0.11 -0.11 -0.08 -0.15 -0.08 0.01 -0.04 -0.14 -0.05 -0.09 -0.11 -0.07 -0.08 Other Oils (g) ................................................................ -0.61 -0.60 -0.54 -0.62 -0.64 -0.50 -0.52 -0.66 -0.93 -0.90 -0.83 -0.92 -0.59 -0.58 -0.89 Product Inventory Net Withdrawals .................................. 0.40 -0.22 -0.68 0.38 0.35 -0.62 -0.35 0.76 0.39 -0.51 -0.31 0.36 -0.03 0.04 -0.02 Total Supply ........................................................................ 20.35 20.36 20.71 20.59 20.30 20.32 20.68 21.02 20.43 20.59 20.99 21.01 20.50 20.58 20.75

Consumption (million barrels per day) Hydrocarbon Gas Liquids ................................................. 3.26 2.69 2.89 3.19 3.48 2.79 2.95 3.50 3.59 3.10 3.21 3.55 3.01 3.18 3.36 Unfinished Oils ................................................................. 0.14 -0.02 -0.09 0.03 -0.03 0.09 0.04 0.03 0.00 0.00 0.00 0.00 0.01 0.03 0.00 Motor Gasoline ................................................................ 9.02 9.51 9.53 9.25 8.96 9.48 9.49 9.28 8.97 9.49 9.50 9.33 9.33 9.30 9.32 Fuel Ethanol blended into Motor Gasoline ..................... 0.91 0.95 0.96 0.94 0.91 0.97 0.95 0.94 0.90 0.96 0.95 0.95 0.94 0.94 0.94 Jet Fuel ............................................................................ 1.62 1.72 1.78 1.70 1.65 1.78 1.79 1.80 1.70 1.79 1.83 1.78 1.71 1.75 1.77 Distillate Fuel Oil .............................................................. 4.23 4.10 4.06 4.19 4.28 4.01 3.94 4.20 4.22 4.05 4.07 4.23 4.15 4.11 4.14 Residual Fuel Oil .............................................................. 0.29 0.33 0.33 0.33 0.27 0.23 0.32 0.34 0.28 0.23 0.30 0.27 0.32 0.29 0.27 Other Oils (g) ................................................................... 1.78 2.03 2.22 1.90 1.68 1.95 2.14 1.87 1.67 1.92 2.08 1.86 1.98 1.91 1.89 Total Consumption .............................................................. 20.35 20.36 20.71 20.59 20.29 20.32 20.68 21.02 20.43 20.59 20.99 21.01 20.50 20.58 20.75

Total Petroleum and Other Liquids Net Imports ............. 3.00 2.66 2.66 1.06 0.89 1.04 0.75 -0.69 -0.68 -0.36 -0.36 -0.88 2.34 0.49 -0.57

End-of-period Inventories (million barrels) Commercial Inventory Crude Oil (excluding SPR) ............................................... 424.9 415.2 416.7 442.5 459.3 464.0 426.5 444.0 479.9 478.3 458.1 469.3 442.5 444.0 469.3 Hydrocarbon Gas Liquids ................................................. 138.6 180.9 225.3 189.0 163.0 228.9 267.1 213.1 169.1 218.0 254.0 210.0 189.0 213.1 210.0 Unfinished Oils ................................................................. 98.1 92.2 91.9 85.9 92.0 95.9 92.2 84.7 93.1 92.4 90.0 83.2 85.9 84.7 83.2 Other HC/Oxygenates ...................................................... 31.1 28.7 30.5 31.4 32.8 30.7 29.7 27.7 29.7 28.8 28.0 28.5 31.4 27.7 28.5 Total Motor Gasoline ........................................................ 239.7 240.7 240.0 246.5 236.1 229.7 231.9 237.6 233.9 228.6 224.1 237.0 246.5 237.6 237.0 Finished Motor Gasoline ............................................... 22.9 24.6 24.7 25.8 21.7 21.0 23.0 25.6 24.0 22.7 23.8 24.1 25.8 25.6 24.1 Motor Gasoline Blend Comp. ........................................ 216.8 216.2 215.2 220.7 214.4 208.8 208.9 212.0 209.9 205.9 200.3 212.9 220.7 212.0 212.9 Jet Fuel ............................................................................ 40.3 40.9 46.8 41.6 41.6 40.6 44.4 38.7 39.4 41.3 43.1 41.4 41.6 38.7 41.4 Distillate Fuel Oil .............................................................. 130.5 120.5 137.2 140.2 132.4 130.8 131.7 128.5 120.9 124.0 129.4 133.9 140.2 128.5 133.9 Residual Fuel Oil .............................................................. 35.0 30.0 28.7 28.3 28.7 30.3 29.9 28.6 31.0 31.2 29.4 28.8 28.3 28.6 28.8 Other Oils (g) ................................................................... 60.3 60.0 56.1 58.7 63.2 59.1 51.2 49.5 55.5 54.5 49.0 51.4 58.7 49.5 51.4 Total Commercial Inventory ................................................. 1,199 1,209 1,273 1,264 1,249 1,310 1,305 1,252 1,253 1,297 1,305 1,283 1,264 1,252 1,283 Crude Oil in SPR ................................................................. 665 660 660 649 649 645 645 635 634 634 633 630 649 635 630

(e) Renewables and oxygenate production includes pentanes plus, oxygenates (excluding fuel ethanol), and renewable fuels.

Table 4a. U.S. Petroleum and Other Liquids Supply, Consumption, and InventoriesU.S. Energy Information Administration | Short-Term Energy Outlook - December 2019

2018 2019 2020 Year

- = no data available(a) Includes lease condensate.(b) Crude oil production from U.S. Federal leases in the Gulf of Mexico (GOM).(c) Net imports equals gross imports minus gross exports.(d) Crude oil adjustment balances supply and consumption and was previously referred to as "Unaccounted for Crude Oil."

Petroleum Supply Annual , DOE/EIA-0340/2; and Weekly Petroleum Status Report , DOE/EIA-0208. Minor discrepancies with published historical data are due to independent rounding. Projections: EIA Regional Short-Term Energy Model.

(f) Petroleum products adjustment includes hydrogen/oxygenates/renewables/other hydrocarbons, motor gasoline blend components, and finished motor gasoline.(g) "Other Oils" inludes aviation gasoline blend components, finished aviation gasoline, kerosene, petrochemical feedstocks, special naphthas, lubricants, waxes, petroleum coke, asphalt and road oil, still gas, and miscellaneous products.Notes: The approximate break between historical and forecast values is shown with historical data printed in bold; estimates and forecasts in italics.SPR: Strategic Petroleum ReserveHC: HydrocarbonsHistorical data: Latest data available from Energy Information Administration databases supporting the following reports: Petroleum Supply Monthly , DOE/EIA-0109;

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2018 2019 2020Supply (billion cubic feet per day) Total Marketed Production .............. 86.04 87.82 90.98 94.75 96.08 97.44 99.79 102.59 102.20 102.18 102.53 102.40 89.93 98.99 102.33 Alaska .......................................... 1.00 0.92 0.86 0.96 0.96 0.93 0.79 0.93 1.00 0.85 0.78 0.94 0.94 0.90 0.90 Federal GOM (a) ......................... 2.52 2.45 2.91 2.80 2.80 2.75 2.50 2.89 2.84 2.75 2.59 2.54 2.67 2.73 2.68 Lower 48 States (excl GOM) ...... 82.53 84.45 87.21 90.99 92.32 93.76 96.49 98.77 98.36 98.57 99.16 98.91 86.32 95.36 98.75 Total Dry Gas Production ............... 80.18 81.84 84.79 88.30 89.32 90.50 92.89 95.42 95.01 94.94 95.21 95.04 83.80 92.05 95.05 LNG Gross Imports ........................ 0.33 0.10 0.15 0.26 0.28 0.03 0.06 0.21 0.32 0.10 0.18 0.20 0.21 0.15 0.20 LNG Gross Exports ........................ 2.64 2.79 2.95 3.48 4.01 4.55 4.96 6.11 6.25 5.76 6.58 7.35 2.97 4.91 6.49 Pipeline Gross Imports ................... 8.65 7.57 7.43 7.19 8.35 6.73 7.10 7.52 8.00 6.52 6.47 7.33 7.70 7.42 7.08 Pipeline Gross Exports ................... 7.00 6.14 7.04 7.47 7.86 7.18 7.79 7.47 8.88 8.08 8.20 7.88 6.92 7.57 8.26 Supplemental Gaseous Fuels ........ 0.18 0.19 0.19 0.20 0.20 0.16 0.15 0.19 0.19 0.19 0.19 0.19 0.19 0.17 0.19 Net Inventory Withdrawals ............. 18.32 -8.85 -8.23 2.58 16.93 -14.18 -10.40 1.95 15.12 -12.11 -9.00 3.53 0.89 -1.49 -0.63Total Supply ....................................... 98.03 71.91 74.35 87.57 103.21 71.52 77.04 91.71 103.50 75.80 78.28 91.05 82.91 85.82 87.14Balancing Item (b) ............................. 0.12 -0.97 -0.40 -0.81 0.12 -0.78 -0.30 0.80 1.04 -1.09 -0.77 0.97 -0.51 -0.04 0.04Total Primary Supply ......................... 98.15 70.94 73.95 86.76 103.32 70.74 76.74 92.51 104.54 74.71 77.51 92.02 82.40 85.78 87.18

Consumption (billion cubic feet per day) Residential ...................................... 25.89 8.01 3.46 17.60 27.15 7.34 3.53 18.56 26.87 7.66 3.78 16.92 13.69 14.09 13.79 Commercial .................................... 15.52 6.68 4.64 11.77 16.19 6.36 4.68 11.87 15.72 6.63 4.87 10.69 9.63 9.75 9.47 Industrial ......................................... 24.53 22.06 21.56 23.67 25.12 21.74 21.31 24.89 26.09 23.06 22.33 25.40 22.95 23.26 24.22 Electric Power (c) ........................... 24.81 27.52 37.38 26.23 26.84 28.14 39.75 29.18 27.57 29.81 38.82 30.90 29.01 31.01 31.79 Lease and Plant Fuel ..................... 4.41 4.51 4.67 4.86 4.93 5.00 5.12 5.26 5.24 5.24 5.26 5.25 4.61 5.08 5.25 Pipeline and Distribution Use ......... 2.85 2.02 2.11 2.49 2.96 2.03 2.20 2.60 2.89 2.15 2.30 2.71 2.36 2.45 2.51 Vehicle Use .................................... 0.14 0.14 0.14 0.14 0.13 0.13 0.14 0.15 0.15 0.15 0.15 0.15 0.14 0.14 0.15Total Consumption ............................ 98.15 70.94 73.95 86.76 103.32 70.74 76.74 92.51 104.54 74.71 77.51 92.02 82.40 85.78 87.18

End-of-period Inventories (billion cubic feet) Working Gas Inventory ................... 1,390 2,195 2,950 2,708 1,185 2,461 3,415 3,235 1,859 2,961 3,789 3,464 2,708 3,235 3,464 East Region (d) ........................... 229 465 778 659 216 537 845 808 382 694 984 847 659 808 847 Midwest Region (d) ..................... 261 459 846 777 242 579 990 875 384 717 1,063 957 777 875 957 South Central Region (d) ............ 613 845 845 879 519 917 1,049 1,105 780 1,099 1,214 1,190 879 1,105 1,190 Mountain Region (d) .................... 87 140 179 141 63 135 200 164 100 144 188 156 141 164 156 Pacific Region (d) ........................ 169 253 263 214 115 259 294 247 176 269 303 278 214 247 278 Alaska .......................................... 31 33 38 37 30 33 37 37 37 37 37 37 37 37 37

Table 5a. U.S. Natural Gas Supply, Consumption, and InventoriesU.S. Energy Information Administration | Short-Term Energy Outlook - December 2019

2018 2019 2020 Year

LNG: liquefied natural gas.Historical data: Latest data available from Energy Information Administration databases supporting the following reports: Natural Gas Monthly , DOE/EIA-0130; and Electric Power Monthly , DOE/EIA-0226.Minor discrepancies with published historical data are due to independent rounding. Projections: EIA Regional Short-Term Energy Model.

- = no data available(a) Marketed production from U.S. Federal leases in the Gulf of Mexico.(b) The balancing item represents the difference between the sum of the components of natural gas supply and the sum of components of natural gas demand.(c) Natural gas used for electricity generation and (a limited amount of) useful thermal output by electric utilities and independent power producers.(d) For a list of States in each inventory region refer to Weekly Natural Gas Storage Report, Notes and Definitions (http://ir.eia.gov/ngs/notes.html) .Notes: The approximate break between historical and forecast values is shown with historical data printed in bold; estimates and forecasts in italics.

Current Forecast: December 10, 2019; Previous Forecast: November 13, 2019

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2017 2018 2019 2020 2017-2018 2018-2019 2019-2020U.S. Energy Supply U.S. Crude Oil Production (million barrels per day) Current 10.27 10.54 11.25 11.89 11.81 12.10 12.23 12.87 13.12 13.22 13.14 13.23 9.35 10.99 12.25 13.18 17.5% 11.5% 7.5% Previous 10.27 10.54 11.25 11.89 11.81 12.10 12.24 13.01 13.23 13.32 13.27 13.35 9.35 10.99 12.29 13.29 17.5% 11.8% 8.1% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -1.0% -0.9% -0.8% -1.0% -0.9% 0.0% 0.0% -0.3% -0.9% U.S. Dry Natural Gas Production (billion cubic feet per day) Current 80.18 81.84 84.79 88.30 89.32 90.50 92.89 95.42 95.01 94.94 95.21 95.04 74.81 83.80 92.05 95.05 12.0% 9.8% 3.3% Previous 80.18 81.84 84.79 88.30 89.29 90.48 93.02 95.66 94.83 94.91 95.15 94.89 74.81 83.80 92.13 94.95 12.0% 9.9% 3.1% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -0.3% 0.2% 0.0% 0.1% 0.2% 0.0% 0.0% -0.1% 0.1% U.S. Coal Production (million short tons) Current 187.6 180.8 194.7 192.4 170.3 174.9 178.9 172.9 165.6 133.7 160.4 141.4 774.6 755.5 697.0 601.1 -2.5% -7.7% -13.8% Previous 187.6 180.8 194.7 192.4 170.3 173.9 178.9 174.9 172.2 131.7 157.2 146.1 774.6 755.5 697.9 607.1 -2.5% -7.6% -13.0% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.6% 0.0% -1.1% -3.8% 1.5% 2.0% -3.2% 0.0% 0.0% -0.1% -1.0%U.S. Energy Consumption U.S. Petroleum and Other Liquid Fuels Consumption (million barrels per day) Current 20.35 20.36 20.71 20.59 20.29 20.32 20.68 21.02 20.43 20.59 20.99 21.01 19.96 20.50 20.58 20.75 2.7% 0.4% 0.8% Previous 20.35 20.36 20.71 20.59 20.29 20.32 20.76 20.94 20.43 20.55 21.00 21.01 19.96 20.50 20.58 20.75 2.7% 0.4% 0.8% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.4% 0.4% 0.0% 0.2% -0.1% 0.0% 0.0% 0.0% 0.0% 0.0% U.S. Natural Gas Consumption (billion cubic feet per day) Current 98.15 70.94 73.95 86.76 103.32 70.74 76.74 92.51 104.54 74.71 77.51 92.02 74.37 82.40 85.78 87.18 10.8% 4.1% 1.6% Previous 98.31 71.01 74.30 86.59 103.12 70.41 76.33 90.80 102.40 74.00 78.14 91.30 74.37 82.50 85.10 86.45 10.9% 3.2% 1.6% Percent Change -0.2% -0.1% -0.5% 0.2% 0.2% 0.5% 0.5% 1.9% 2.1% 1.0% -0.8% 0.8% 0.0% -0.1% 0.8% 0.8% U.S. Electricity Retail Sales (billion kilowatthours) Current 934 920 1,094 912 911 876 1,072 913 921 877 1,052 883 311 322 315 311 3.7% -2.2% -1.1% Previous 934 920 1,094 912 911 876 1,075 908 921 877 1,054 889 311 322 315 312 3.7% -2.3% -0.9% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.2% 0.6% 0.0% 0.0% -0.2% -0.6% 0.0% 0.0% 0.1% -0.2% U.S. Total Energy Consumption (quadrillion Btu) Current 26.43 24.01 25.15 25.60 26.53 23.44 24.87 25.63 26.42 23.35 24.56 25.11 97.71 101.19 100.47 99.44 3.6% -0.7% -1.0% Previous 26.39 23.98 25.12 25.54 26.46 23.39 24.88 25.42 26.31 23.25 24.49 25.07 97.69 101.03 100.15 99.12 3.4% -0.9% -1.0% Percent Change 0.2% 0.1% 0.1% 0.3% 0.3% 0.2% 0.0% 0.8% 0.4% 0.5% 0.3% 0.1% 0.0% 0.2% 0.3% 0.3%U.S. Macroeconomic and Weather U.S. Real Gross Domestic Product (billion chained 2012 dollars) Current 18,438 18,598 18,733 18,784 18,927 19,022 19,113 19,181 19,276 19,389 19,485 19,573 18,108 18,638 19,061 19,431 2.9% 2.3% 1.9% Previous 18,438 18,598 18,733 18,784 18,927 19,022 19,095 19,196 19,289 19,393 19,496 19,588 18,108 18,638 19,060 19,441 2.9% 2.3% 2.0% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% -0.1% -0.1% 0.0% -0.1% -0.1% 0.0% 0.0% 0.0% -0.1% U.S. Manufacturing Production Index (index 2012 = 100) Current 104.8 105.5 106.6 107.0 106.5 105.7 106.0 105.5 105.6 105.6 106.1 106.4 103.2 106.0 105.9 105.9 2.7% 0.0% 0.0% Previous 104.8 105.5 106.6 107.0 106.5 105.7 106.1 106.4 107.0 107.3 107.7 108.1 103.2 106.0 106.2 107.5 2.7% 0.2% 1.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -0.1% -0.8% -1.3% -1.6% -1.5% -1.5% 0.0% 0.0% -0.2% -1.5% U.S. Heating Degree Days Current 2,130 522 48 1,578 2,210 481 56 1,594 2,113 476 72 1,521 3,828 4,278 4,341 4,183 11.8% 1.5% -3.6% Previous 2,130 522 48 1,578 2,210 481 56 1,542 2,113 476 72 1,521 3,828 4,278 4,289 4,183 11.8% 0.3% -2.5% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 3.3% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.2% 0.0% U.S. Cooling Degree Days Current 51 477 959 98 46 398 953 117 44 407 859 93 1,428 1,586 1,514 1,402 11.0% -4.6% -7.4% Previous 51 477 959 98 46 398 953 118 44 407 859 93 1,428 1,586 1,515 1,402 11.0% -4.5% -7.5% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.7% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% 0.0%Source: Energy Information Administration, Short-Term Energy Outlook (http://www.eia.gov/outlooks/steo/)

STEO Current/Previous Forecast Comparisons: U.S. Energy Supply and Demand Summary

Year Growth Rate2018 2019 2020


Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2017 2018 2019 2020 2017-2018 2018-2019 2019-2020U.S. Petroleum WTI spot ($/barrel) Current 62.90 68.07 69.69 59.59 54.82 59.94 56.35 55.75 53.84 52.19 55.47 58.50 50.79 65.06 56.74 55.01 28.1% -12.8% -3.0% Previous 62.90 68.07 69.69 59.59 54.82 59.94 56.35 54.62 52.84 51.53 55.47 58.50 50.79 65.06 56.45 54.60 28.1% -13.2% -3.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.1% 1.9% 1.3% 0.0% 0.0% 0.0% 0.0% 0.5% 0.7% Refiner composite crude oil acquisition cost ($/barrel) Current 61.94 67.27 69.08 59.39 56.93 63.55 58.13 55.36 51.90 50.22 53.54 56.57 50.68 64.48 58.51 53.06 27.2% -9.3% -9.3% Previous 61.94 67.27 69.08 59.39 56.93 63.55 57.43 54.16 50.90 49.55 53.54 56.57 50.68 64.48 58.02 52.65 27.2% -10.0% -9.2% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.2% 2.2% 2.0% 1.3% 0.0% 0.0% 0.0% 0.0% 0.9% 0.8% Brent spot average ($/barrel) Current 66.84 74.53 75.02 68.29 63.14 69.07 61.90 61.56 59.34 57.69 60.97 64.00 54.15 71.19 63.93 60.51 31.5% -10.2% -5.3% Previous 66.84 74.53 75.02 68.29 63.14 69.07 61.90 60.21 58.34 57.03 60.97 64.00 54.15 71.19 63.59 60.10 31.5% -10.7% -5.5% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.2% 1.7% 1.2% 0.0% 0.0% 0.0% 0.0% 0.5% 0.7% Gasoline, regular-grade retail including taxes ($/gallon) Current 2.58 2.85 2.84 2.63 2.36 2.79 2.65 2.59 2.48 2.60 2.62 2.52 2.42 2.73 2.60 2.56 12.8% -4.6% -1.7% Previous 2.58 2.85 2.84 2.63 2.36 2.79 2.65 2.59 2.53 2.66 2.69 2.58 2.42 2.73 2.60 2.62 12.8% -4.5% 0.5% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -2.3% -2.0% -2.4% -2.4% 0.0% 0.0% 0.0% -2.3% Diesel, retail including taxes ($/gallon) Current 3.02 3.20 3.24 3.27 3.02 3.12 3.02 3.08 3.12 3.03 3.06 3.14 2.65 3.18 3.06 3.09 19.9% -3.9% 0.9% Previous 3.02 3.20 3.24 3.27 3.02 3.12 3.02 3.06 3.03 2.98 3.04 3.13 2.65 3.18 3.06 3.04 19.9% -3.9% -0.5% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.4% 2.9% 1.8% 0.8% 0.4% 0.0% 0.0% 0.1% 1.5% Heating Oil, residential retail including taxes ($/gallon) Current 2.87 2.98 3.25 3.16 3.00 3.05 2.90 3.09 3.14 2.97 2.90 3.06 2.51 3.01 3.03 3.07 20.1% 0.6% 1.4% Previous 2.87 2.98 3.25 3.16 3.00 3.05 2.90 3.03 3.08 2.94 2.90 3.08 2.51 3.01 3.01 3.05 20.1% -0.1% 1.4% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.9% 1.8% 1.0% -0.2% -0.7% 0.0% 0.0% 0.7% 0.7%U.S. Natural Gas Henry Hub spot ($ per million Btu) Current 3.02 2.85 2.93 3.80 2.92 2.56 2.38 2.52 2.62 2.34 2.35 2.51 2.99 3.15 2.59 2.45 5.5% -17.7% -5.4% Previous 3.02 2.85 2.93 3.80 2.92 2.56 2.38 2.60 2.73 2.35 2.35 2.52 2.99 3.15 2.61 2.48 5.5% -17.0% -4.9% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -2.9% -3.8% -0.4% -0.1% -0.4% 0.0% 0.0% -0.7% -1.3% Residential Retail ($ per thousand cubic feet) Current 9.36 11.90 17.85 9.95 9.47 12.48 18.10 11.17 9.78 12.27 16.73 10.20 10.86 10.46 10.97 10.73 -3.7% 4.8% -2.2% Previous 9.36 11.90 17.85 9.95 9.47 12.48 17.89 10.87 9.66 12.26 16.72 10.18 10.86 10.46 10.85 10.66 -3.7% 3.7% -1.7% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.2% 2.7% 1.2% 0.1% 0.0% 0.2% 0.0% 0.0% 1.1% 0.6%U.S. Electric Utilities Fuel Costs ($ per million Btu) Coal Current 2.06 2.05 2.05 2.07 2.08 2.05 2.04 2.10 2.11 2.11 2.09 2.09 2.06 2.06 2.07 2.10 0.0% 0.5% 1.6% Previous 2.06 2.06 2.06 2.08 2.08 2.05 2.07 2.09 2.11 2.11 2.09 2.09 2.06 2.06 2.07 2.10 0.2% 0.6% 1.1% Percent Change -0.2% -0.3% -0.2% -0.3% 0.0% 0.2% -1.5% 0.1% 0.3% 0.2% 0.2% 0.0% 0.0% -0.3% -0.3% 0.2% Natural Gas Current 3.97 3.11 3.21 4.07 3.71 2.73 2.49 2.72 3.04 2.44 2.36 2.65 3.37 3.55 2.86 2.59 5.2% -19.3% -9.3% Previous 3.96 3.09 3.23 4.06 3.71 2.73 2.42 2.79 3.21 2.46 2.33 2.66 3.37 3.54 2.85 2.62 5.0% -19.4% -8.1% Percent Change 0.4% 0.6% -0.6% 0.4% 0.0% 0.1% 2.9% -2.2% -5.4% -1.1% 1.3% -0.4% 0.0% 0.1% 0.3% -1.0% Residual Fuel Oil Current 11.54 13.00 14.02 14.47 12.21 13.39 12.99 11.91 12.15 12.31 11.67 11.92 11.01 12.92 12.63 12.03 17.3% -2.2% -4.8% Previous 11.47 13.02 14.02 14.49 12.22 13.39 12.21 11.76 11.92 12.16 11.66 11.99 11.01 12.95 12.38 11.92 17.5% -4.4% -3.7% Percent Change 0.6% -0.1% 0.0% -0.1% -0.1% 0.0% 6.4% 1.2% 1.9% 1.2% 0.1% -0.5% 0.0% -0.2% 2.1% 0.9%U.S. Residential Retail Electricity (cents per kilowatthour) Current 12.56 13.01 13.14 12.71 12.67 13.32 13.20 12.68 12.65 13.37 13.36 12.95 12.89 12.87 12.97 13.09 -0.1% 0.8% 0.9% Previous 12.59 13.03 13.15 12.75 12.66 13.31 13.21 12.76 12.66 13.39 13.39 13.00 12.89 12.89 12.99 13.11 0.0% 0.8% 1.0% Percent Change -0.2% -0.1% -0.1% -0.3% 0.1% 0.0% -0.1% -0.6% -0.1% -0.2% -0.2% -0.4% 0.0% -0.2% -0.1% -0.2%

Source: Energy Information Administration, Short-Term Energy Outlook (http://www.eia.gov/outlooks/steo/)

STEO Current/Previous Forecast Comparisons: Energy Prices

2018 2019 2020 Year Growth Rate

Prices are not adjusted for inflation.


Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2017 2018 2019 2020 2017-2018 2018-2019 2019-2020World Crude Oil and Liquid Fuels Supply (million barrels per day) OECD (Organization for Economic Cooperation and Development) Supply Current 29.23 29.40 30.59 31.48 31.08 31.32 31.49 33.06 33.49 33.78 33.62 34.05 27.66 30.18 31.74 33.73 9.1% 5.2% 6.3% Previous 29.20 29.35 30.50 31.41 31.02 31.25 31.47 33.17 33.56 33.85 33.78 34.19 27.65 30.12 31.73 33.85 8.9% 5.4% 6.7% Percent Change 0.1% 0.2% 0.3% 0.2% 0.2% 0.2% 0.0% -0.3% -0.2% -0.2% -0.5% -0.4% 0.0% 0.2% 0.0% -0.3% OPEC (Organization of the Petroleum Exporting Countries) Supply Current 37.46 37.07 37.38 37.36 36.05 35.50 34.55 34.82 34.28 34.30 34.47 34.34 37.37 37.32 35.23 34.35 -0.1% -5.6% -2.5% Previous 37.46 37.07 37.38 37.36 36.05 35.48 34.56 34.83 34.53 34.55 34.72 34.45 37.37 37.32 35.22 34.56 -0.1% -5.6% -1.9% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% -0.7% -0.7% -0.7% -0.3% 0.0% 0.0% 0.0% -0.6% Non-OPEC Supply Current 61.94 62.82 64.23 65.14 64.44 65.01 65.78 67.17 66.91 68.11 68.32 68.42 60.75 63.54 65.61 67.94 4.6% 3.3% 3.6% Previous 61.94 62.81 64.17 65.10 64.42 64.97 65.90 67.27 66.95 68.19 68.47 68.45 60.75 63.52 65.65 68.02 4.6% 3.4% 3.6% Percent Change 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% -0.2% -0.1% -0.1% -0.1% -0.2% 0.0% 0.0% 0.0% -0.1% -0.1% Total World Supply Current 99.39 99.89 101.61 102.50 100.49 100.51 100.33 101.99 101.20 102.40 102.78 102.75 98.11 100.86 100.83 102.29 2.8% 0.0% 1.4% Previous 99.40 99.88 101.55 102.47 100.47 100.45 100.46 102.10 101.48 102.73 103.19 102.90 98.11 100.83 100.87 102.58 2.8% 0.0% 1.7% Percent Change 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% -0.1% -0.1% -0.3% -0.3% -0.4% -0.1% 0.0% 0.0% 0.0% -0.3%World Crude Oil and Liquid Fuels Consumption (million barrels per day) OECD (Organization for Economic Cooperation and Development) Consumption Current 47.79 47.06 48.06 47.56 47.25 46.62 47.77 48.11 47.46 46.88 48.00 48.20 47.39 47.62 47.44 47.64 0.5% -0.4% 0.4% Previous 47.79 47.06 48.05 47.57 47.24 46.62 47.85 48.10 47.45 46.83 48.01 48.19 47.42 47.62 47.45 47.62 0.4% -0.3% 0.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.2% 0.0% 0.0% 0.1% 0.0% 0.0% -0.1% 0.0% 0.0% 0.0% Non-OECD Consumption Current 51.52 52.59 52.51 52.79 52.57 53.45 53.54 53.51 53.67 54.69 54.70 54.95 51.18 52.36 53.27 54.50 2.3% 1.7% 2.3% Previous 51.70 52.77 52.68 52.96 52.69 53.57 53.75 53.77 53.81 54.84 54.85 55.11 51.40 52.53 53.45 54.65 2.2% 1.7% 2.3% Percent Change -0.4% -0.3% -0.3% -0.3% -0.2% -0.2% -0.4% -0.5% -0.3% -0.3% -0.3% -0.3% -0.4% -0.3% -0.3% -0.3% China Consumption Current 13.95 14.14 13.88 14.10 14.38 14.67 14.39 14.61 14.98 15.17 14.88 15.12 13.57 14.02 14.51 15.04 3.3% 3.5% 3.6% Previous 13.95 14.15 13.88 14.10 14.38 14.68 14.40 14.62 14.96 15.16 14.87 15.10 13.57 14.02 14.52 15.02 3.3% 3.6% 3.5% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.0% 0.0% 0.0% 0.1% Total World Consumption Current 99.31 99.65 100.57 100.35 99.82 100.08 101.32 101.62 101.14 101.57 102.70 103.16 98.57 99.97 100.72 102.14 1.4% 0.7% 1.4% Previous 99.50 99.83 100.73 100.53 99.92 100.19 101.61 101.87 101.26 101.66 102.86 103.30 98.83 100.15 100.90 102.27 1.3% 0.8% 1.4% Percent Change -0.2% -0.2% -0.2% -0.2% -0.1% -0.1% -0.3% -0.2% -0.1% -0.1% -0.2% -0.1% -0.3% -0.2% -0.2% -0.1%Closing Stocks (million barrels) OECD Commercial Inventory Current 2,803 2,800 2,852 2,860 2,867 2,924 2,952 2,932 2,934 2,989 2,997 2,971 2,850 2,860 2,932 2,971 0.4% 2.5% 1.3% Previous 2,797 2,794 2,847 2,855 2,860 2,920 2,908 2,900 2,907 2,967 2,987 2,959 2,845 2,855 2,900 2,959 0.3% 1.6% 2.0% Percent Change 0.2% 0.2% 0.2% 0.2% 0.2% 0.1% 1.5% 1.1% 0.9% 0.7% 0.3% 0.4% 0.2% 0.2% 1.1% 0.4%OPEC Surplus Production Capacity and World Macroeconomic OPEC Surplus Crude OIl Production Capacity (million barrels per day) Current 1.86 1.78 1.34 1.00 2.08 2.18 1.96 1.65 2.39 2.32 2.15 2.25 2.03 1.49 1.96 2.28 -26.7% 31.8% 15.9% Previous 1.86 1.78 1.34 1.00 2.08 2.19 1.95 1.65 2.19 2.12 1.95 2.19 2.03 1.49 1.97 2.11 -26.7% 32.0% 7.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% -0.7% 0.4% 0.0% 9.1% 9.4% 10.2% 3.1% 0.0% 0.0% -0.1% 7.9% World Oil-Consumption-Weighted GDP Growth (annualized percent change) Current 3.32 3.24 2.91 2.60 2.16 1.95 1.86 1.93 1.48 2.55 2.67 2.84 3.20 3.01 1.97 2.39 Previous 3.32 3.23 2.90 2.60 2.18 1.97 1.85 1.92 1.46 2.55 2.71 2.87 3.21 3.01 1.98 2.40Source: Energy Information Administration, Short-Term Energy Outlook (http://www.eia.gov/outlooks/steo/)

STEO Current/Previous Forecast Comparisons: International Crude Oil and Liquid Fuels



Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2017 2018 2019 2020 2017-2018 2018-2019 2019-2020U.S. Supply (million barrels per day) U.S. Crude Oil Production Current 10.27 10.54 11.25 11.89 11.81 12.10 12.23 12.87 13.12 13.22 13.14 13.23 9.35 10.99 12.25 13.18 17.5% 11.5% 7.5% Previous 10.27 10.54 11.25 11.89 11.81 12.10 12.24 13.01 13.23 13.32 13.27 13.35 9.35 10.99 12.29 13.29 17.5% 11.8% 8.1% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -1.0% -0.9% -0.8% -1.0% -0.9% 0.0% 0.0% -0.3% -0.9% U.S. Natural Gas Plant Liquids Production Current 4.04 4.33 4.56 4.54 4.66 4.81 4.80 5.25 5.23 5.35 5.42 5.54 3.78 4.37 4.88 5.39 15.5% 11.7% 10.4% Previous 4.04 4.33 4.56 4.54 4.66 4.81 4.80 5.29 5.27 5.37 5.50 5.60 3.78 4.37 4.89 5.44 15.5% 11.9% 11.1% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -0.7% -0.7% -0.4% -1.5% -1.0% 0.0% 0.0% -0.2% -0.9% U.S. Ethanol Production Current 1.05 1.04 1.06 1.04 1.01 1.05 1.02 1.01 1.01 1.03 1.02 1.04 1.04 1.05 1.02 1.03 1.0% -2.6% 0.5% Previous 1.05 1.04 1.06 1.04 1.01 1.05 1.02 1.03 1.02 1.04 1.03 1.04 1.04 1.05 1.03 1.03 1.0% -2.2% 0.6% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -1.8% -0.7% -0.6% -0.7% -0.2% 0.0% 0.0% -0.5% -0.6% U.S. Total Petroleum and Other Liquid Fuel Net Imports Current 3.00 2.66 2.66 1.06 0.89 1.04 0.75 -0.69 -0.68 -0.36 -0.36 -0.88 3.77 2.34 0.49 -0.57 -37.9% -78.9% -215.1% Previous 3.00 2.66 2.66 1.06 0.89 1.04 0.73 -0.57 -0.85 -0.56 -0.49 -1.11 3.77 2.34 0.52 -0.75 -37.9% -77.7% -244.1% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.2% 21.5% -19.1% -36.4% -27.8% -20.5% 0.0% 0.0% -5.2% -24.3%U.S. Consumption (million barrels per day) U.S. Gasoline Current 9.02 9.51 9.53 9.25 8.96 9.48 9.49 9.28 8.97 9.49 9.50 9.33 9.33 9.33 9.30 9.32 0.0% -0.3% 0.2% Previous 9.02 9.51 9.53 9.25 8.96 9.48 9.55 9.31 8.95 9.47 9.50 9.32 9.33 9.33 9.33 9.31 0.0% 0.0% -0.2% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.6% -0.3% 0.2% 0.2% 0.0% 0.1% 0.0% 0.0% -0.2% 0.1% U.S. Distillate Current 4.23 4.10 4.06 4.19 4.28 4.01 3.94 4.20 4.22 4.05 4.07 4.23 3.93 4.15 4.11 4.14 5.4% -0.9% 0.8% Previous 4.23 4.10 4.06 4.19 4.28 4.01 3.93 4.19 4.23 4.05 4.07 4.25 3.93 4.15 4.10 4.15 5.4% -1.1% 1.2% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.4% 0.4% -0.3% 0.2% -0.1% -0.4% 0.0% 0.0% 0.2% -0.2% U.S. Jet Fuel Current 1.62 1.72 1.78 1.70 1.65 1.78 1.79 1.80 1.70 1.79 1.83 1.78 1.68 1.71 1.75 1.77 1.5% 2.8% 1.2% Previous 1.62 1.72 1.78 1.70 1.65 1.78 1.79 1.79 1.71 1.79 1.83 1.77 1.68 1.71 1.75 1.77 1.5% 2.6% 1.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% 0.6% -0.3% 0.1% 0.1% 0.2% 0.0% 0.0% 0.1% 0.0% U.S. Hydrocarbon Gas Liquids Current 3.26 2.69 2.89 3.19 3.48 2.79 2.95 3.50 3.59 3.10 3.21 3.55 2.64 3.01 3.18 3.36 13.8% 5.8% 5.7% Previous 3.26 2.69 2.89 3.19 3.48 2.79 2.98 3.48 3.63 3.12 3.27 3.58 2.64 3.01 3.18 3.40 13.8% 5.9% 6.8% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -1.1% 0.5% -1.1% -0.5% -1.8% -1.0% 0.0% 0.0% -0.1% -1.1% U.S. Total Petroleum and Other Liquid Fuels Current 20.35 20.36 20.71 20.59 20.29 20.32 20.68 21.02 20.43 20.59 20.99 21.01 19.96 20.50 20.58 20.75 2.7% 0.4% 0.8% Previous 20.35 20.36 20.71 20.59 20.29 20.32 20.76 20.94 20.43 20.55 21.00 21.01 19.96 20.50 20.58 20.75 2.7% 0.4% 0.8% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.4% 0.4% 0.0% 0.2% -0.1% 0.0% 0.0% 0.0% 0.0% 0.0%U.S. Closing Stocks (million barrels) U.S. Crude Oil Current 424.9 415.2 416.7 442.5 459.3 464.0 426.5 444.0 479.9 478.3 458.1 469.3 421.6 442.5 444.0 469.3 4.9% 0.3% 5.7% Previous 424.9 415.2 416.7 442.5 459.3 464.0 424.3 448.1 484.8 482.0 470.2 477.9 421.6 442.5 448.1 477.9 4.9% 1.3% 6.7% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.5% -0.9% -1.0% -0.8% -2.6% -1.8% 0.0% 0.0% -0.9% -1.8% U.S. Total Gasoline Current 239.7 240.7 240.0 246.5 236.1 229.7 231.9 237.6 233.9 228.6 224.1 237.0 236.8 246.5 237.6 237.0 4.1% -3.6% -0.3% Previous 239.7 240.7 240.0 246.5 236.1 229.7 229.3 234.3 233.0 228.3 224.0 236.3 236.8 246.5 234.3 236.3 4.1% -5.0% 0.9% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.1% 1.4% 0.4% 0.1% 0.0% 0.3% 0.0% 0.0% 1.4% 0.3% U.S. Distillate Fuel Oil Current 130.5 120.5 137.2 140.2 132.4 130.8 131.7 128.5 120.9 124.0 129.4 133.9 145.6 140.2 128.5 133.9 -3.8% -8.3% 4.2% Previous 130.5 120.5 137.2 140.2 132.4 130.8 129.0 133.7 124.4 126.5 131.3 135.6 145.6 140.2 133.7 135.6 -3.8% -4.6% 1.4% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.1% -3.9% -2.8% -2.0% -1.5% -1.3% 0.0% 0.0% -3.9% -1.3%Source: Energy Information Administration, Short-Term Energy Outlook (http://www.eia.gov/outlooks/steo/)

STEO Current/Previous Forecast Comparisons: U.S. Petroleum and Other Liquid Fuels



Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2017 2018 2019 2020 2017-2018 2018-2019 2019-2020U.S. Supply (billion cubic feet per day) U.S. Total Marketed Production Current 86.04 87.82 90.98 94.75 96.08 97.44 99.79 102.59 102.20 102.18 102.53 102.40 80.01 89.93 98.99 102.33 12.4% 10.1% 3.4% Previous 86.04 87.82 90.98 94.75 96.05 97.42 99.86 102.76 101.92 102.05 102.37 102.14 80.01 89.93 99.04 102.12 12.4% 10.1% 3.1% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -0.2% 0.3% 0.1% 0.2% 0.3% 0.0% 0.0% -0.1% 0.2% U.S. Federal GOM Marketed Production Current 2.52 2.45 2.91 2.80 2.80 2.75 2.50 2.89 2.84 2.75 2.59 2.54 2.91 2.67 2.73 2.68 -8.0% 2.3% -1.9% Previous 2.52 2.45 2.91 2.80 2.80 2.75 2.53 2.75 2.73 2.63 2.48 2.42 2.91 2.67 2.71 2.56 -8.0% 1.3% -5.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -1.3% 5.0% 4.2% 4.5% 4.7% 4.9% 0.0% 0.0% 1.0% 4.6% U.S. Lower 48 ex GOM Marketed Production Current 82.53 84.45 87.21 90.99 92.32 93.76 96.49 98.77 98.36 98.57 99.16 98.91 76.16 86.32 95.36 98.75 13.3% 10.5% 3.6% Previous 82.53 84.45 87.21 90.99 92.29 93.74 96.52 99.07 98.19 98.56 99.11 98.77 76.16 86.32 95.43 98.66 13.3% 10.5% 3.4% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.3% 0.2% 0.0% 0.1% 0.1% 0.0% 0.0% -0.1% 0.1% U.S. Pipeline Gross Imports Current 8.6 7.6 7.4 7.2 8.4 6.7 7.1 7.5 8.0 6.5 6.5 7.3 8.1 7.7 7.4 7.1 -4.8% -3.7% -4.6% Previous 8.6 7.6 7.4 7.2 8.4 6.7 7.1 7.4 8.0 6.5 6.5 7.3 8.1 7.7 7.4 7.1 -4.8% -4.1% -4.2% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.6% 1.4% 0.3% 0.0% 0.0% 0.0% 0.0% 0.0% 0.5% 0.1% U.S. LNG Gross Imports Current 0.33 0.10 0.15 0.26 0.28 0.03 0.06 0.21 0.32 0.10 0.18 0.20 0.21 0.21 0.15 0.20 -2.0% -30.1% 35.7% Previous 0.33 0.10 0.15 0.26 0.28 0.03 0.09 0.21 0.32 0.10 0.18 0.20 0.21 0.21 0.15 0.20 -2.0% -26.7% 29.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -31.4% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -4.7% 0.0% U.S. Gross Exports Current 9.64 8.93 9.99 10.95 11.87 11.73 12.75 13.58 15.13 13.84 14.78 15.23 8.64 9.88 12.49 14.75 14.4% 26.3% 18.1% Previous 9.64 8.93 9.99 10.95 11.87 11.73 12.62 13.11 14.92 13.87 14.67 15.12 8.64 9.88 12.34 14.65 14.4% 24.8% 18.7% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.1% 3.5% 1.4% -0.2% 0.7% 0.7% 0.0% 0.0% 1.2% 0.7%U.S. Consumption (billion cubic feet per day) U.S. Residential Current 25.89 8.01 3.46 17.60 27.15 7.34 3.53 18.56 26.87 7.66 3.78 16.92 12.09 13.69 14.09 13.79 13.2% 2.9% -2.2% Previous 25.89 8.01 3.46 17.60 27.15 7.34 3.46 18.28 26.87 7.66 3.74 17.01 12.09 13.69 14.00 13.80 13.2% 2.3% -1.4% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.2% 1.5% 0.0% 0.0% 0.9% -0.6% 0.0% 0.0% 0.6% -0.1% U.S. Commercial Current 15.52 6.68 4.64 11.77 16.19 6.36 4.68 11.87 15.72 6.63 4.87 10.69 8.67 9.63 9.75 9.47 11.1% 1.3% -2.9% Previous 15.52 6.68 4.64 11.77 16.19 6.36 4.73 11.66 15.72 6.62 4.87 10.70 8.67 9.63 9.71 9.47 11.1% 0.8% -2.5% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.9% 1.8% 0.0% 0.1% 0.0% -0.1% 0.0% 0.0% 0.4% 0.0% U.S. Industrial Current 24.53 22.06 21.56 23.67 25.12 21.74 21.31 24.89 26.09 23.06 22.33 25.40 21.78 22.95 23.26 24.22 5.4% 1.3% 4.1% Previous 24.53 22.06 21.56 23.67 25.12 21.74 21.29 24.16 25.63 22.65 21.91 25.00 21.78 22.95 23.07 23.79 5.4% 0.5% 3.1% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 3.0% 1.8% 1.8% 1.9% 1.6% 0.0% 0.0% 0.8% 1.8% U.S. Electric Power Sector Current 24.81 27.52 37.38 26.23 26.84 28.14 39.75 29.18 27.57 29.81 38.82 30.90 25.39 29.01 31.01 31.79 14.3% 6.9% 2.5% Previous 24.81 27.52 37.38 26.23 26.84 28.14 39.70 28.84 25.86 29.45 39.80 30.39 25.39 29.01 30.91 31.39 14.3% 6.5% 1.6% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 1.2% 6.6% 1.2% -2.5% 1.7% 0.0% 0.0% 0.3% 1.3% U.S. Total Consumption Current 98.15 70.94 73.95 86.76 103.32 70.74 76.74 92.51 104.54 74.71 77.51 92.02 74.37 82.40 85.78 87.18 10.8% 4.1% 1.6% Previous 98.31 71.01 74.30 86.59 103.12 70.41 76.33 90.80 102.40 74.00 78.14 91.30 74.37 82.50 85.10 86.45 10.9% 3.2% 1.6% Percent Change -0.2% -0.1% -0.5% 0.2% 0.2% 0.5% 0.5% 1.9% 2.1% 1.0% -0.8% 0.8% 0.0% -0.1% 0.8% 0.8%U.S. Working Gas in Storage (billion cubic feet) Current 1,390 2,195 2,950 2,708 1,185 2,461 3,415 3,235 1,859 2,961 3,789 3,464 3,033 2,708 3,235 3,464 -10.7% 19.4% 7.1% Previous 1,390 2,195 2,950 2,708 1,185 2,460 3,397 3,269 1,882 2,977 3,695 3,401 3,033 2,708 3,269 3,401 -10.7% 20.7% 4.1% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.5% -1.0% -1.2% -0.5% 2.5% 1.8% 0.0% 0.0% -1.0% 1.8%U.S. Balancing Item (billion cubic feet per day) (Consumption - Supply) Current 0.12 -0.97 -0.40 -0.81 0.12 -0.78 -0.30 0.80 1.04 -1.09 -0.77 0.97 -0.99 -0.51 -0.04 0.04 Previous 0.28 -0.90 -0.05 -0.98 -0.07 -1.09 -1.19 -0.97 -1.24 -1.83 -1.39 0.62 -0.99 -0.41 -0.84 -0.96Source: Energy Information Administration, Short-Term Energy Outlook (http://www.eia.gov/outlooks/steo/)

STEO Current/Previous Forecast Comparisons: U.S. Natural Gas



Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2017 2018 2019 2020 2017-2018 2018-2019 2019-2020U.S. Electricity Generation, Electric Power Sector (billion kilowatthours) U.S. Total Generation Current 963 971 1,132 945 955 936 1,130 966 957 934 1,098 929 3,877 4,011 3,987 3,917 3.4% -0.6% -1.7% Previous 963 971 1,132 945 955 936 1,133 954 955 932 1,100 934 3,877 4,011 3,978 3,922 3.4% -0.8% -1.4% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.2% 1.3% 0.2% 0.2% -0.2% -0.6% 0.0% 0.0% 0.2% -0.1% U.S. Coal Current 280 258 325 275 258 209 279 256 232 189 248 177 1,198 1,139 1,002 847 -4.9% -12.0% -15.5% Previous 280 258 325 275 258 209 284 242 244 187 242 187 1,198 1,139 993 860 -4.9% -12.8% -13.4% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -1.7% 5.5% -4.8% 1.1% 2.3% -5.2% 0.0% 0.0% 0.9% -1.6% U.S. Natural gas Current 291 320 440 315 317 331 474 349 328 352 466 368 1,197 1,365 1,471 1,515 14.1% 7.7% 3.0% Previous 291 320 440 315 317 331 471 347 312 346 476 364 1,197 1,365 1,466 1,499 14.1% 7.3% 2.2% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.6% 0.6% 5.2% 1.7% -2.1% 1.1% 0.0% 0.0% 0.4% 1.1% U.S. Petroleum Current 9.2 4.7 5.4 4.7 4.9 4.2 4.8 4.2 4.7 4.2 4.5 4.5 20.0 23.9 18.0 17.9 19.4% -24.7% -0.8% Previous 9.2 4.7 5.4 4.7 4.9 4.2 5.3 4.3 4.6 4.2 5.0 4.5 20.0 23.9 18.6 18.3 19.4% -22.2% -1.7% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -9.8% -1.7% 2.7% 0.3% -10.5% -1.0% 0.0% 0.0% -3.2% -2.4% U.S. Nuclear Current 206 196 209 195 203 197 210 196 206 186 205 201 805 807 806 797 0.3% -0.2% -1.0% Previous 206 196 209 195 203 197 210 198 206 186 204 200 805 807 807 796 0.3% 0.0% -1.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.2% -1.0% -0.1% 0.1% 0.2% 0.2% 0.0% 0.0% -0.2% 0.1% U.S. Conventional Hydroelectric Current 76 86 66 64 71 82 61 59 71 73 60 59 299 291 273 263 -2.5% -6.4% -3.6% Previous 76 86 66 64 71 82 65 61 74 79 61 60 299 291 279 275 -2.5% -4.3% -1.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -6.7% -2.8% -4.3% -8.0% -1.9% -2.5% 0.0% 0.0% -2.2% -4.4% U.S. Other Renewables Current 99 105 84 91 99 111 100 101 113 128 114 118 354 379 411 471 7.0% 8.5% 14.7% Previous 99 105 84 91 99 111 97 101 112 128 110 116 354 379 408 466 7.0% 7.5% 14.4% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 3.5% 0.3% 0.4% 0.0% 3.2% 1.3% 0.0% 0.0% 0.9% 1.2%U.S. Electricity Sales (billion kilowatthours) U.S. Residential Current 370 329 436 334 361 309 434 342 370 312 422 324 115 123 121 119 6.5% -1.6% -1.3% Previous 370 329 436 334 361 309 434 337 369 311 421 326 115 123 120 119 6.5% -1.9% -1.0% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% 1.5% 0.1% 0.2% 0.3% -0.6% 0.0% 0.0% 0.3% 0.0% U.S. Commercial Current 326 339 388 329 320 328 382 331 324 329 376 323 113 115 114 113 2.1% -1.5% -0.7% Previous 326 339 388 329 320 328 383 330 324 329 377 325 113 115 114 113 2.1% -1.4% -0.5% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.4% 0.3% 0.0% 0.0% -0.3% -0.6% 0.0% 0.0% -0.1% -0.2% U.S. Industrial Current 237 250 267 247 228 237 255 238 225 234 251 234 82 84 79.88 79 1.8% -4.4% -1.5% Previous 237 250 267 247 228 237 255 239 225 234 254 236 82 84 80 79 1.8% -4.3% -1.1% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -0.4% -0.1% -0.2% -1.0% -0.6% 0.0% 0.0% -0.1% -0.5% U.S. Total Current 934 920 1,094 912 911 876 1,072 913 921 877 1,052 883 311 322 315 311 3.7% -2.2% -1.1% Previous 934 920 1,094 912 911 876 1,075 908 921 877 1,054 889 311 322 315 312 3.7% -2.3% -0.9% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.2% 0.6% 0.0% 0.0% -0.2% -0.6% 0.0% 0.0% 0.1% -0.2%Source: Energy Information Administration, Short-Term Energy Outlook (http://www.eia.gov/outlooks/steo/)

STEO Current/Previous Forecast Comparisons: U.S. Electricity



Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2017 2018 2019 2020 2017-2018 2018-2019 2019-2020U.S. Coal (million short tons) U.S. Production Current 187.6 180.8 194.7 192.4 170.3 174.9 178.9 172.9 165.6 133.7 160.4 141.4 775 755.5 697 601 -2.5% -7.7% -13.8% Previous 187.6 180.8 194.7 192.4 170.3 173.9 178.9 174.9 172.2 131.7 157.2 146.1 775 756 698 607 -2.5% -7.6% -13.0% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.6% 0.0% -1.1% -3.8% 1.5% 2.0% -3.2% 0.0% 0.0% -0.1% -1.0% U.S. Exports Current 27.2 30.9 29.1 28.5 25.2 25.3 21.9 20.5 24.2 20.8 20.4 19.8 97.0 115.6 92.9 85.1 19.3% -19.6% -8.4% Previous 27.2 30.9 29.1 28.5 25.2 25.3 21.9 20.5 23.9 20.3 19.8 19.4 97.0 115.6 93.0 83.5 19.3% -19.6% -10.2% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.1% -0.1% 0.9% 2.4% 2.7% 1.9% 0.0% 0.0% 0.0% 1.9% U.S. Imports Current 1.4 1.5 1.4 1.6 1.7 1.6 1.7 1.7 1.3 1.3 1.5 1.4 7.8 6.0 6.7 5.6 -23.4% 12.9% -17.1% Previous 1.4 1.5 1.4 1.6 1.7 1.6 1.5 1.5 1.2 1.3 1.5 1.4 7.8 6.0 6.3 5.4 -23.4% 6.0% -14.0% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 10.1% 17.1% 7.7% 2.8% 0.9% 0.4% 0.0% 0.0% 6.5% 2.7% U.S. Electric Power Demand Current 155.4 144.1 181.7 156.0 145.3 118.0 156.6 141.2 130.5 108.1 140.5 102.1 665 637 561 481 -4.2% -11.9% -14.3% Previous 154.8 144.2 181.6 155.9 145.0 117.7 158.6 136.9 137.2 106.7 138.0 107.1 665 636 558 489 -4.3% -12.3% -12.4% Percent Change 0.4% 0.0% 0.1% 0.0% 0.2% 0.3% -1.3% 3.2% -4.9% 1.4% 1.8% -4.7% 0.0% 0.1% 0.5% -1.6% U.S. Secondary Stocks Current 131.1 126.2 105.8 108.4 102.2 123.2 110.7 123.4 124.1 120.7 113.3 121.0 143.0 108.4 123.4 121.0 -24.2% 13.9% -2.0% Previous 131.2 126.3 105.9 108.1 102.2 122.0 110.7 118.3 119.2 115.9 108.6 116.5 143.0 108.1 118.3 116.5 -24.4% 9.4% -1.5% Percent Change -0.1% -0.1% -0.1% 0.2% 0.0% 1.0% 0.0% 4.3% 4.1% 4.1% 4.3% 3.9% 0.0% 0.2% 4.3% 3.9%U.S. Carbon Dioxide Emissions Petroleum Current 582.9 590.2 599.9 600.3 574.7 586.7 596.5 599.3 577.8 581.6 597.0 600.1 2,329 2,373 2,357 2,356 1.9% -0.7% 0.0% Previous 583.0 590.3 600.0 600.4 574.8 586.8 599.8 599.2 578.1 580.5 596.8 600.0 2,329 2,374 2,361 2,355 1.9% -0.5% -0.2% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% -0.6% 0.0% -0.1% 0.2% 0.0% 0.0% 0.0% 0.0% -0.1% 0.0% Coal Current 307.7 287.3 355.4 309.8 289.6 239.1 315.8 288.4 266.1 223.7 280.9 215.5 1316.0 1260.3 1132.8 986.3 -4.2% -10.1% -12.9% Previous 306.6 287.4 355.3 309.7 289.1 238.5 319.2 280.1 277.7 220.7 276.0 224.0 1316.0 1259.0 1126.9 998.4 -4.3% -10.5% -11.4% Percent Change 0.4% 0.0% 0.0% 0.0% 0.2% 0.2% -1.1% 3.0% -4.2% 1.4% 1.8% -3.8% 0.0% 0.1% 0.5% -1.2% Natural Gas Current 481.5 350.4 369.3 434.4 506.7 349.8 384.7 461.4 518.4 369.3 387.1 460.7 1475.0 1635.5 1702.6 1735.6 10.9% 4.1% 1.9% Previous 477.4 348.4 369.2 430.0 502.6 345.9 382.3 450.9 504.6 363.4 388.2 453.4 1473.9 1625.0 1681.7 1709.6 10.2% 3.5% 1.7% Percent Change 0.9% 0.6% 0.0% 1.0% 0.8% 1.1% 0.6% 2.3% 2.7% 1.6% -0.3% 1.6% 0.1% 0.7% 1.2% 1.5% Total Fossil Fuel Current 1372.1 1227.9 1324.6 1344.5 1371.0 1175.6 1297.0 1349.2 1362.3 1174.7 1265.0 1276.4 5,120 5,269 5,193 5,078 2.9% -1.4% -2.2% Previous 1367.0 1226.1 1324.4 1340.1 1366.5 1171.3 1301.4 1330.2 1360.4 1164.6 1261.1 1277.4 5,118 5,258 5,169 5,063 2.7% -1.7% -2.1% Percent Change 0.4% 0.1% 0.0% 0.3% 0.3% 0.4% -0.3% 1.4% 0.1% 0.9% 0.3% -0.1% 0.0% 0.2% 0.5% 0.3%Source: Energy Information Administration, Short-Term Energy Outlook (http://www.eia.gov/outlooks/steo/)

STEO Current/Previous Forecast Comparisons: U.S. Coal and Carbon Dioxide Emissions



Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2017 2018 2019 2020 2017-2018 2018-2019 2019-2020U.S. Renewable Energy Consumption, All Sectors (quadrillion btu) U.S. Wind Power Current 0.692 0.691 0.505 0.621 0.683 0.724 0.609 0.702 0.789 0.834 0.676 0.836 2.341 2.509 2.719 3.135 7.2% 8.3% 15.3% Previous 0.720 0.688 0.493 0.630 0.683 0.737 0.584 0.701 0.786 0.832 0.647 0.815 2.341 2.530 2.706 3.079 8.1% 6.9% 13.8% Percent Change -3.8% 0.4% 2.4% -1.3% 0.0% -1.8% 4.3% 0.2% 0.5% 0.2% 4.5% 2.6% 0.0% -0.8% 0.5% 1.8% U.S. Wood Biomass Current 0.589 0.581 0.599 0.590 0.578 0.568 0.578 0.549 0.541 0.539 0.557 0.530 2.285 2.359 2.272 2.166 3.2% -3.7% -4.6% Previous 0.587 0.584 0.596 0.590 0.577 0.570 0.562 0.544 0.536 0.537 0.552 0.530 2.285 2.357 2.254 2.156 3.1% -4.4% -4.4% Percent Change 0.4% -0.4% 0.6% -0.1% 0.1% -0.5% 2.8% 0.8% 0.9% 0.3% 1.0% -0.1% 0.0% 0.1% 0.8% 0.5% U.S. Solar Power Current 0.178 0.285 0.277 0.177 0.197 0.315 0.319 0.209 0.242 0.383 0.405 0.260 0.777 0.917 1.041 1.290 18.0% 13.6% 23.9% Previous 0.182 0.292 0.286 0.182 0.200 0.320 0.322 0.212 0.243 0.385 0.405 0.264 0.777 0.942 1.055 1.297 21.3% 12.0% 23.0% Percent Change -2.2% -2.5% -3.1% -2.8% -1.5% -1.7% -0.9% -1.1% -0.4% -0.6% 0.0% -1.5% 0.0% -2.7% -1.3% -0.6% U.S. Ethanol Current 0.283 0.300 0.305 0.301 0.285 0.305 0.302 0.301 0.284 0.303 0.304 0.302 1.192 1.188 1.192 1.193 -0.4% 0.3% 0.1% Previous 0.283 0.300 0.305 0.301 0.285 0.305 0.302 0.296 0.282 0.302 0.304 0.301 1.192 1.188 1.187 1.190 -0.4% -0.1% 0.3% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 1.6% 0.6% 0.2% -0.1% 0.2% 0.0% 0.0% 0.4% 0.2% U.S. Biodiesel Current 0.053 0.071 0.072 0.063 0.058 0.071 0.070 0.081 0.077 0.086 0.076 0.082 0.280 0.260 0.281 0.321 -7.4% 8.0% 14.2% Previous 0.053 0.071 0.072 0.063 0.058 0.071 0.073 0.085 0.074 0.084 0.076 0.082 0.280 0.260 0.287 0.316 -7.3% 10.4% 10.0% Percent Change 0.0% 0.0% 0.0% -0.2% 0.0% 0.0% -3.5% -4.5% 3.6% 2.2% 0.9% -0.4% 0.0% 0.0% -2.2% 1.5%U.S. Renewable Electric Power Sector Generation Capacity (MW) Wind Power Current 88,700 89,149 89,858 94,330 96,499 98,050 99,404 106,636 108,250 109,454 111,646 124,241 87,488 94,330 106,636 124,241 7.8% 13.0% 16.5% Previous 88,643 89,092 89,801 94,273 96,442 97,993 100,101 106,433 108,042 109,246 111,134 122,404 87,488 94,273 106,433 122,404 7.8% 12.9% 15.0% Percent Change 0.1% 0.1% 0.1% 0.1% 0.1% 0.1% -0.7% 0.2% 0.2% 0.2% 0.5% 1.5% 0.0% 0.1% 0.2% 1.5% Wood Biomass Current 3,039 3,039 3,020 2,965 2,835 2,820 2,731 2,847 2,847 2,847 2,847 2,889 3,079 2,965 2,847 2,889 -3.7% -4.0% 1.5% Previous 3,039 3,039 3,020 2,965 2,835 2,820 2,731 2,847 2,847 2,847 2,847 2,889 3,079 2,965 2,847 2,889 -3.7% -4.0% 1.5% Percent Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Solar Power Current 28,024 28,882 29,412 31,560 32,664 33,125 33,758 37,533 39,259 41,729 43,161 50,666 26,432 31,560 37,533 50,666 19.4% 18.9% 35.0% Previous 28,011 28,868 29,399 31,531 32,610 33,069 34,497 37,471 39,090 41,791 43,071 50,044 26,432 31,531 37,471 50,044 19.3% 18.8% 33.6% Percent Change 0.0% 0.0% 0.0% 0.1% 0.2% 0.2% -2.1% 0.2% 0.4% -0.1% 0.2% 1.2% 0.0% 0.1% 0.2% 1.2%Source: Energy Information Administration, Short-Term Energy Outlook (http://www.eia.gov/outlooks/steo/)

STEO Current/Previous Forecast Comparisons: U.S. Renewable Energy Consumption and Capacity


Chevron Announces $20 Billion Capital and Exploratory Budget for 2020

Disciplined capital allocation prioritizes high return, lower risk investments Third consecutive year of flat capital spending Capital allocation decisions and lower price outlook expected to result in non-cash after tax charges in fourth quarter

2019

SAN RAMON, Calif., Dec. 10, 2019 – Chevron Corporation today announced a 2020 organic capital and exploratory spending program of $20 billion. The 2020 budget supports a robust portfolio of upstream and downstream investments, highlighted by Chevron’s world-class Permian Basin position, the company’s major capital project at TCO in Kazakhstan, and an advantaged queue of deepwater opportunities in the Gulf of Mexico.

“We are positioning Chevron to win in any environment by ratably investing in the highest return, lowest risk projects in our portfolio. This will be the third consecutive year with organic capital spending held flat at $20 billion, continuing our capital discipline through the cycle. Our emphasis on short cycle investments is expected to deliver improved returns on capital and stronger free cash flow over the long-term,” said Chevron Chairman and CEO Michael Wirth.

As a result of Chevron’s disciplined approach to capital allocation and a downward revision in its longer-term commodity price outlook, the company will reduce funding to various gas-related opportunities including Appalachia shale, Kitimat LNG, and other international projects. Chevron is evaluating its strategic alternatives for these assets, including divestment. In addition, the revised oil price outlook resulted in an impairment at Big Foot. Combined, these actions are estimated to result in non-cash, after tax impairment charges of $10 billion to $11 billion in its fourth quarter 2019 results, more than half related to the Appalachia shale.

“We believe the best use of our capital is investing in our most advantaged assets,” Wirth continued. “With capital discipline and a conservative outlook comes the responsibility to make the tough choices necessary to deliver higher cash returns to our shareholders over the long term.”

Details of the 2020 Capital and Exploratory Spending Program include: Chevron 2020 Planned Capital & Exploratory Expenditures $ Billions U.S. Upstream 7.6 International Upstream 9.1

Total Upstream 16.8 U.S. Downstream 1.6 International Downstream 1.2

Total Downstream 2.8 Other 0.4 TOTAL (Including Chevron’s Share of Expenditures by Affiliated Companies) 20.0 Expenditures by Affiliated Companies 6.2

Cash Expenditures by Chevron Consolidated Companies 13.8 Upstream

In the upstream business, approximately $11 billion is forecasted to sustain and grow currently producing assets, including about $4 billion for Permian unconventional development and about $1 billion for other international unconventional development. Approximately $5 billion of the upstream program is planned for major capital projects underway, of which about 75 percent is associated with the Future Growth Project and Wellhead Pressure Management Project (FGP / WPMP) at the Tengiz field in Kazakhstan. Global exploration funding is expected to be about $1 billion.

Downstream

Approximately $2.8 billion of planned capital spending is associated with the company’s downstream businesses that refine, market, and transport fuels, and manufacture and distribute lubricants, additives and petrochemicals.

https://www.chevron.com/stories/chevron‐announces‐20‐billion‐capital‐and‐exploratory‐budget‐for‐2020

The Disclaimer: The SAF Energy Blog is intended to provide general information only and is written for an institutional or sophisticated investor audience. It is not a recommendation of, or solicitation for the purchase of securities, an offer of securities, or intended as investment research or advice. The information presented, while obtained from sources we believe reliable as of the publishing date, is not guaranteed against errors or omissions and no representation or warranty, express or implied, is made as to their accuracy, completeness or correctness. This publication is proprietary and intended for the sole use of direct recipients from Dan Tsubouchi and SAF Group. The SAF Energy Blog is not to be copied, transmitted, or forwarded without the prior written permission Dan Tsubouchi and SAF Group. Please advise if you have received The SAF Energy Blog from a source other than Dan Tsubouchi and SAF Group

Chevron Lowers Long Term Gas Prices, Hits Both Short Cycle Dry

Marcellus Shale And Long Cycle Greenfield Kitimat LNG

Posted: Friday December 13, 2019. 1:00pm MT No one outside Chevron really knows the reasons driving downward revision of longer term commodity prices that led to the $10 to $11b impairment charge, reduced capex and move to divest Appalachia shale gas and Kitimat LNG. We think the takeaways come from what we believe is the likely linkage between short cycle shale gas and long cycle greenfield LNG – it’s a view for lower longer term Asian landed LNG prices. US natural gas prices and values are increasingly linked to LNG prices. Kitimat moves from one of two LNG projects in Chevron’s 12 major capital projects. Kitimat LNG is a greenfield LNG project, albeit with the chance to be close to brownfield capital, but close to brownfield capital costs likely doesn’t cut it in a lower Asian LNG price outlook. Future growth in US natural gas supply essentially has to be exported primarily thru the Gulf Coast, which makes US gas supply a price taker. And that price goes down with every $ reduction in Asian LNG prices basically flowing thru to the natural gas supply netback ie. LNG shipping and liquefaction costs don’t really change. A materially reduced gas supply netback hits the economics harder for the pure dry gas plays like Appalachia whose returns are based on natural gas price as opposed to associated natural gas from oil wells in Texas/Oklahoma whose returns are driven by the oil price. Even if we are right that it’s a view of lower Asian landed LNG prices, we don’t believe this impacts the expectation for LNG Canada Phase 2 to FID and for LNG Canada’s ~3.6 bcf/d to be the big plus to western Canada natural gas. But, post 2025 western Canada natural gas will be hurt by the chance for 2.4 bcf/d Kitimat LNG to go ahead is extremely low unless a new owner is found quickly and can link construction to LNG Canada to get as low as capital costs as possible. The biggest impact on western Canada natural gas in the near term would be if Appalachia shale gas can’t compete against associated natural gas for Gulf Coast LNG and it forces more Appalachia gas to Eastern Canada and US Midwest. So we think there is a linkage – a view of lower Asian landed LNG prices. Chevron downward revision in its longer-term commodity price outlook led to massive impairment, reduced capex and potential divestment of Appalachia and Kitimat LNG. There is no question Chevron surprised investors with its Tues release [LINK] that included Chevron writing “As a result of Chevron’s disciplined approach to capital allocation and a downward revision in its longer-term commodity price outlook, the company will reduce funding to various gas-related opportunities including Appalachia shale, Kitimat LNG, and other international projects. Chevron is evaluating its strategic alternatives for these assets, including divestment. In addition, the revised oil price outlook resulted in an impairment at Big Foot. Combined, these actions are estimated to result in non-cash, after tax impairment charges of $10 billion to $11 billion in its fourth quarter 2019 results, more than half related to the Appalachia shale. “We believe the best use of our capital is investing in our most advantaged assets,” Wirth continued. “With capital discipline and a conservative outlook comes the responsibility to make the tough choices necessary to deliver higher cash returns to our shareholders over the long term.”

A big negative shift in their views on longer term natural gas price and related natural gas asset views since their March Security Analyst meeting. The Chevron announcement caught the US analysts by surprise and understandably so since Chevron went thru positive views on the Appalachia and Kitimat in their analyst meeting. For the Appalachia, mgmt. said “We're actively developing attractive shale and tight assets in Argentina, Canada and Appalachia”, ““a growing source of new production is the other shale and tight assets, including Vaca Muerta, Kaybob Duvernay and Appalachia, shown in dark blue”, and “the Marcellus and Utica Shale in Appalachia is predominantly a gas play and with low development costs and improved infrastructure in the region, realizations have strengthened and returns are competitive.” For Kitimat LNG, its one of the two LNG projects that were both in the design stage (along with Gorgon Stage 2) on the list of 12 Upstream Major Capital Projects that were driving Chevron’s mid to long term production growth, and “We also have the unconventional gas plays up in Western Canada with Kitimat that offers some opportunity. We've been working hard to get the development cost of the plant proper to a point, where it's competitive with US Gulf Coast delivered into Asia Pacific.” There was also no change to their Appalachia and Kitimat LNG views in their Nov investor update. The other reason why we expect the US analysts were surprised was that there were no hints or anything in Chevron’s recent 90-slide Chevron 2019 Investor Presentation November 2019 [LINK] that may have pointed to a big negative shift on natural gas or on the Appalachia and Kitimat LNG compared to the March analyst day. For Kitimat LNG, it was still one of the two LNG projects

https://www.chevron.com/stories/chevron-announces-20-billion-capital-and-exploratory-budget-for-2020

https://chevroncorp.gcs-web.com/static-files/67bad561-a933-4784-8203-307c8da70ea6


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on their 12 major capital project list. Appalachia slides were also the same. We even looked at their bubble map of core vs non core assets (slide 12 below) to see if any of the unnamed bubbles in the core side of assets had shifted over to the non-core side. The bubbles representing Chevron core and non-core assets were identical in classification in the March and November slide decks. There were no shifting of bubble (assets).

Excerpt Chevron 2019 Investor Presentation November 2019

Source: Chevron November 2019 Investor Presentation How does a downward revision in Chevron’s longer term natural gas view impact both short cycle Appalachia and long cycle Kitimat LNG? Chevron’s downward revision of their longer term commodity price view led to over $5 billion asset impairment on short cycle Appalachia shale gas. Only those within Chevron likely know the full reasons because Chevron did not disclose their longer term price assumptions or how these longer term views impacted both short cycle Appalachia and long cycle Kitimat LNG. We could go thru pages on our case for linkage, but here are three main points as to why these diverse assets are no longer advantaged gas assets that can attract capital within Chevron. (i) Kitimat LNG is a long cycle greenfield LNG project that we thought could get close to brownfield costs if it linked construction LNG Canada. Chevron’s Appalachia is short cycle, but is primarily dry natural gas so the economics stand on the natural gas whereas the economics of associated natural gas from oil wells in the Permian or Eagle Ford or SCOOP/STACK is primarily driven by the oil component. (ii) The vast majority of any increasing US natural gas supply has to be exported via LNG primarily from the US Gulf Coast and compete in Asia or Europe against LNG or pipeline gas. At the same time, US natural gas has significantly surprised to the upside since Feb/March. The EIA’s Short Term Energy Outlook Dec 2019 forecast for US natural gas supply is approx. 3 bcf/d higher for 2019 and 2020 than forecast in Feb/March ie. more US natural gas than expected only increases the reminder that most of future US natural gas growth has to be exported. (iii) A lower mid to long term landed Asian LNG price. Our Oct 7 SAF Group 2020 Energy Market Outlook webcast [LINK] said we expected lower “mid term Asian LNG price of +/--$8”, which would link back to a HH price to a $2.50 --$3.25. We believe for capital allocation Chevron could be looking to stress test against Asian landed LNG prices even lower than our +/-$8, possibly in the $7 range. We don’t think they would be looking at a long term $6 Asian landed LNG price because, if they did, they probably wouldn’t be looking at any LNG. Since their March analyst meeting, a number of significant LNG or LNG alternative supply projects to Asian/Europe LNG markets have been confirmed or about to be confirmed – Qatar brownfield LNG expansions to add 6.5 bcf/d, Exxon’s 2 bcf/d initial phase for its greenfield Mozambique LNG to FID in

http://www.safgroup.ca/research/trends-in-the-market/


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Energy Blog

early 2020, Total’s June FID for greenfield phase 1 Mozambique 1.7 bcf/d LNG, Total’s Nov announcement looking to FID brownfield Mozambique LNG phase 2 to add another 1.7 bcf/d, Gazprom’s Dec 1 start up of Power of Siberia 3.6 bcf/d gas pipeline to China, and final approvals to complete the Gazprom’s 5.3 bcf/d Nord Stream 2 pipeline to Germany expected on stream in mid 2020, plus a number of other items. (iv) Appalachia dry shale gas is disadvantaged vs associated natural gas from oil wells in Texas/Oklahoma or dry shale gas in the Haynesville. Associated natural gas from Texas/Oklahoma oil wells is almost like a by product, doesn’t drive the economics of the oil wells, and can therefore withstand lower gas prices. Plus there is a massive increase in Permian natural gas pipelines to bring associated natural gas to the Gulf Coast with the Sept start up of the 2 bcf/d Gulf Coast Express, 2.1 bcf/d Permian Highway pipeline to startup in late 2020, and 2 bcf/d Whistler gas pipeline to start up in Q3/2021. And the dry Haynesville is right at US Gulf Coast export points.

New And Upcoming Permian Natural Gas Pipelines To Gulf Coast Export Points

Source: RBN Energy If Asian landed LNG prices are ~$7, it makes it extremely difficult for greenfield LNG projects like Kitimat LNG. Our outlook webcast highlighted how our view of lower mid term Asian LNG prices put an increasing necessity for LNG projects to minimize capital costs. And if Chevron has a sensitivity for capital allocation less than ~$8, it makes low capital costs even more critical. (i) Kitimat LNG. We have been saying that Chevron would need to get as close to brownfield capital costs as possible to go FID and, to do so, it would have to FID on Kitimat LNG years earlier than expected (ie. in 2020) to take advantage of a continuous LNG construction cycle on the BC coast. We detailed our thesis in our July 19, 2019 blog “Chevron’s Kitimat LNG Expansion Plan Points To A LNG Canada Phase 2 FID in 2020 and A Continuous BC LNG 2020’s Runway of ~6 bcf/d” [LINK]. The key being to keep the BC LNG service contractors after LNG Canada and to also line up the in demand Asian fabricators. However, if Asian LNG prices are ~$7 for a capital allocation decision, close to brownfield capital costs are likely not enough. Plus Chevron’s key working interest natural gas that would supply to Kitimat is from the shale gas play in the Horn River and not from associated natural gas from liquids rich Montney wells that have their economics driven by condensate and not the associated natural gas. (ii) Other greenfield LNG. There is no change to our view that the key will be to get brownfield capital costs, but a lower Asian LNG price means that it will be very difficult for future greenfield LNG projects to go FID unless they can meet a capital allocation decision under ~$7 Asian landed LNG prices. The other linked disadvantage of greenfield projects is that there is a longer time to first LNG sales. (iii) Brownfield LNG. A lower Asian landed LNG price will impact the returns of brownfield LNG projects, but these projects have two key advantages that should keep them as FID likely. The brownfield phases (ie. an LNG Canada Phase 2) have superior returns than the initial greenfield phase 1 that must carry all the costs of infrastructure. Whereas

http://www.safgroup.ca/research/trends-in-the-market/


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Energy Blog

the brownfield phase only picks up the new capital costs related to a new train or two, but a lesser relative capital cost for any infrastructure expansion instead of starting from scratch. The superior returns in a Phase 2 are normally counted on to enhance the overall returns. The reality is that most LNG projects wouldn’t be going ahead if there is only a phase 1. The other big advantage is time to first LNG sales. The cycle times are much shorter and therefore there is less risk to returns with getting cash flow year quicker. (iv) The wave of LNG FIDs in 2019 also likely made it even tougher for Chevron to be close to brownfield capital costs. All of these FIDS are signing up LNG service contractors and Asian fabricators, which likely caused Chevron to re-evaluate their capital cost/time for Kitimat LNG. We don’t know the nature of LNG Canada’s contract with LNG service contractors and Asian fabricators, but we would be surprised if their contract for phase 1 didn’t include some sort of option/retainer for a continuous schedule or near term slot for phase 2. We expect all greenfield LNG projects have these option/retainers. Its why we see announcements like Total talk about phase 2 FID less 6 months after phase 1 FID. But it also means that a greenfield Kitimat LNG has to fight for slots with the new wave of greenfield plus their phase 2 brownfields. Every $ of lower Asian landed LNG prices will squeeze netbacks for source US natural gas supply. We believe there is an increasing linkage of US natural gas markets to global LNG prices especially as most US natural gas growth will have to find its way to export markets. And if so, it means that all US gas is moving to primarily compete in the Gulf Coast export market. Every dollar change in assumption for long term Asian landed LNG prices has a material impact on netbacks for the natural gas supply for US Gulf Coast LNG exports. From the perspective of natural gas being supplied to a non fully integrated LNG project because US natural gas has to find export markets, US natural gas supply is forced to be a price taker for LNG transportation costs to Asia and Gulf Coast liquefaction costs ie. every $1 drop in Asian LNG prices basically flows thru to the gas supply netback. It seems like most estimates for LNG shipping costs to Asia via the Panama Canal are in the ~$1.75 to $2 range. Most estimates of liquefaction costs look at from the perspective of the LNG project operator for capital and operating costs. We think a reasonable range is $2.75 to $3. On the low end, we looked at the US Dept of Energy LNG Monthly report for Nov 2019 [LINK] that includes the weighted average export price by export terminal. Importantly, the DOE notes that “Domestically-Produced LNG Delivered –Volume (Bcf) and Weighted Average price ($/MMBtu) by Export Terminal per month 2019 –YTD” schedule that shows the volume and export price by LNG terminal. The DOE notes that “*Beginning with July 2019 data, with the exception of some commissioning cargos as indicated in Table 2(a), all average export cargo prices include liquefaction fees”. We graphed the July/Aug/Sept average export price including liquefaction fees and plotted average HH gas prices to give an approximate “actual” for liquefaction cost of ~$2.75. For the high end, we used Cheniere’s recent June long term Apache supply deal that included a liquefaction fee of ~$3. If we assume shipping and liquefaction is $4.50 to $5, it shows how slim the netbacks are for US gas supply landed at the Gulf Coast export facility ie. at Asian $7, its only $2 to $2.50 landed in the Gulf Coast prior to the transportation costs to get the natural gas from the field to the Gulf Coast. This is why the Appalachia dry shale is disadvantaged vs associated natural gas from oil wells in the Permian, Eagle Ford and Oklahoma where the primary driver of returns is oil price. It is also why Haynesville dry shale has an advantage in closeness to the Gulf Coast.

https://www.energy.gov/sites/prod/files/2019/11/f68/LNG%20Monthly%202019.pdf


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Energy Blog

Henry Hub and Weighted Average Price Incl Liquefaction Cost For US LNG Exports ($/mmbtu)

Source: US Department of Energy, Bloomberg Shouldn’t impact LNG Canada potential to add ~3.6 bcf/d demand, but is a negative to western Canada natural gas. (i) This should not impact the key mid term upside for western Canada natural gas – LNG Canada Phase 1 and 2 will create demand for ~3.6 bcf/d of western Canada natural gas or approx. 20% of total western Canada gas supply. We don’t believe this points to any lessening of our expectation for LNG Canada Phase 2 FID assuming LNG Canada is part of a continuous construction cycle with Phase 1. Phase 2 has superior economics to Phase 1 and will enhance the overall return for LNG Canada. If anything, the rash of LNG FIDs places an even higher probability for LNG Canada Phase 2 FID years sooner than expected to ensure a continuous construction cycle with LNG Canada, much like we are seeing play out with Total’s Mozambique LNG phase 2. Shell’s Oct 2018 “LNG Canada Final Investment Decision” [LINK] for Phase 1 (trains 1 and 2) “estimated integrated project IRR ~13%” “at LNG price of $8.5/mmbtu (Tokyo DES, real terms 2018)”, and also said Phase 2 would increase the IRRs saying there was “upside with trains 3 & 4”. (ii) Not moving on Kitimat LNG would not impact western Canada natural gas supply/demand until post 2025 as it would eliminate ~2.4 bcf/d of demand for western Canada natural supply post 2025. This would also impact valuations prior to 2025. Chevron has put the for sale sign up for Kitimat. But we believe Kitimat LNG is unlikely to go ahead unless it (Woodside and whoever buys Chevron’s interest) can commit to FID soon enough to be part of a continuous construction cycle with LNG Canada Phase 1 and 2 so it can minimize capital costs for a greenfield LNG project. (iii) Reinforces our view that any large greenfield BC LNG project is highly unlikely to proceed in the next few years unless it can get in the queue within the next year or two to tie up LNG contractor services and Asian fabricators following LNG Canada. (iv) We don’t believe this points to any impact on the ability of liquids rich Montney as supply for LNG Canada. The liquids rich Montney has a similar advantage as associated natural gas in the Permian – its economics are driven by liquids (condensate in Montney’s case) and not by the natural gas. But ultimately a lower long term Asian landed LNG price flows back into a lower netback for the source gas ie. more of a cap. (v) This flow back into a lower netback will disadvantage western Canada dry gas wells that rely on the natural gas to drive the well economics vs liquids rich Montney well economics that are driven by condensate. (vi) The near term impact on western Canada natural gas will come if Marcellus dry gas isn’t competitive in the US Gulf Coast as it will force even more Appalachia natural gas into markets like Eastern Canada and Midwest US increasing competition for western Canada natural gas.

https://www.shell.com/investors/news-and-media-releases/investor-presentations/2018-investor-presentations/shell-gives-green-light-to-invest-in-lng-canada-webcast/_jcr_content/par/textimage_a5ec.stream/1538482386925/9ccced0b76145d965a12fdbcdb59135a6520a650/lng-canada-fid-webcast-01102018.pdf

Bloomberg @The Terminal

CNOOC Swaps LNG Cargoes for Dec.‐Jan. Amid High Inventories 2019‐12‐10 01:47:19.102 GMT By Stephen Stapczynski (Bloomberg) ‐‐ China National Offshore Oil Corp. swapped multiple LNG cargoes for Dec. to Jan. delivery in return for later supply, according to traders with knowledge of the matter. * CNOOC swapped the prompt cargoes earlier this month in order to manage inventories, which were at high levels ** Cargoes were swapped with other buyers in North Asia * Stockpiles are now manageable and CNOOC isn’t currently seeking to swap more prompt cargoes * NOTE: Traders told Bloomberg in November that some North Asian buyers were seeking to swap cargoes for later supply as they struggle with high inventories and weaker demand due to milder temperatures ** READ: Nov. 25, Traders See Asia LNG Price Weakness Dragging Into New Year To contact the reporter on this story: Stephen Stapczynski in Singapore at [email protected] To contact the editors responsible for this story: Ramsey Al‐Rikabi at [email protected] Rob Verdonck

China Sets Up National Pipeline Company in Major Energy Revamp 2019‐12‐09 05:24:00.283 GMT By Alfred Cang and Jasmine Ng (Bloomberg) ‐‐ China announced the creation of its long‐ planned national oil and gas pipeline company, officially kicking off one of its biggest energy revamps aimed at helping supply keep pace with swelling demand. The move marks a “key step” in China’s efforts to deepen reforms of its oil and gas sector, the official Xinhua News Agency said Monday. The government will merge the networks operated by its three state‐owned giants under a single company, an important step toward removing barriers that have hampered domestic production, and which dovetails with efforts to use more gas instead of coal. Click here for a QuickTake Q&A explaining China’s national pipeline plan A main development to watch is the valuation of assets, said Neil Beveridge, an analyst at Sanford C. Bernstein & Co. It may take six to nine months for that detail to emerge, based on a similar reform of telecom carriers in 2015 that created China Tower Corp., Beveridge said.

The pipeline company’s creation has been considered since at least 2014 and is part of President Xi Jinping’s drive to streamline industrial capacity among state‐owned enterprises. The government is seeking to spur wider natural gas distribution and upstream exploration by shifting ownership from competing producers into a single operator, which can make decisions based

on overall national energy needs. The reform is also designed to help smaller private or foreign firms, which have found access to infrastructure blocked or prohibitively expensive. With the assets stripped from the hands of the big three state firms, other companies can gain access and move supply to where it’s needed. Sector Overhaul The plan follows other Chinese reforms aimed at a more level playing field for private and state‐owned enterprises. As well, the nation has been accelerating the overhaul of its energy sector in recent years, including changes to its gas pricing policy and merging power giants. Media representatives of the new pipeline operator didn’t respond to an email seeking comment. The State‐owned Assets Supervision & Administration Commission, which oversees centrally owned enterprises, didn’t respond to a faxed request for comment. Nobody answered calls to the media departments of the three companies involved ‐‐ China National Petroleum Corp., Sinopec Group and China National Offshore Oil Corp. Policy makers have also embarked on a campaign targeting pollution, replacing coal with gas for industrial and residential uses. That’s boosted demand for the cleaner‐burning fuel faster than pipelines can support it, giving China added urgency to push forward the latest reform. Shareholding Structure The change will mainly affect PetroChina Co., the listed unit of CNPC, which controls about 70% of the nation’s networks. Its shares in Hong Kong sank to their lowest since 2004 last week amid concern the company’s earnings and cash flow would be diluted as it loses one of its most prized assets. The stock rose as much as 2.8% Monday following a gain in oil prices last week. CNPC may take a 30% stake in the pipeline company, while Sinopec holds 20% and CNOOC 10%, Economic Information Daily and 21st Century Business Herald reported. SASAC will own the remaining 40%, they said, citing unidentified sources. Zhang Wei, general manager of CNPC, will likely be appointed as chairman of the pipeline company, according to local media. ‐‐With assistance from Ramsey Al‐Rikabi, Jing Yang and Aaron Clark. To contact the reporters on this story: Alfred Cang in Singapore at [email protected]; Jasmine Ng in Singapore at [email protected] To contact the editors responsible for this story: Ramsey Al‐Rikabi at [email protected] Jason Rogers

Release Date: 12/132019 Director Lynn Helms

Page 1 of 9

Director’s Cut October 2019 Production

Oil Production

September 43,319,393 barrels = 1,443,980 barrels/day (Final) October 47,051,671 barrels = 1,517,796 barrels/day (Preliminary All-time high)

1,461,438 barrels/day or 96% from Bakken and Three Forks 56,358 barrels/day or 4% from legacy conventional pools

Revenue Forecast

= 1,400,000 barrels/day

Crude Price1 ($/barrel)

North Dakota Light Sweet WTI ND Market est September 46.88 54.01 50.44 October 41.86 57.12 49.49 November 46.07 56.80 51.43 Today 47.75 59.18 53.47 All-time high $136.29/barrel (7/3/2008) $145.29/barrel (7/3/2008) Revenue Forecast

= $48.50

Gas Production & Capture

September 88,391,725 MCF = 2,946,391 MCF/day 82% Capture 72,884,618 MCF = 2,429,487 MCF/day October 95,189,103 MCF = 3,070,616 MCF/day (All Time High) 82 % Capture 78,256,540 MCF = 2,524,405 MCF/day (All Time High)

Wells

August September October November Revenue Forecast Permitted - 92 drilling

1 seismic 126 drilling 0 seismic

79 drilling 1 seismic

-

Completed 102 (Final) 112 (Revised) 91 (Preliminary) - 90 Inactive2 - 2,104 1,683 - - Waiting on Completion1

916 885

Producing - 16,115 16,157 (Preliminary) 14,622 wells or 90% from unconventional Bakken – Three Forks 1,535 wells or 10% from legacy conventional pools

1 Pricing Source: Flint Hills Resources 2 Includes all well types on IA and AB statuses: IA = Inactive shut in >3 months and <12 months; AB = Abandoned (Shut in >12 months)

Rig Count September 61 October 59 November 55 Today 53 Federal Surface 4 All-time high 218 (5/29/2012)


Page 2 of 9

Fort Berthold Reservation Activity

Total Fee Land Trust Land Oil Production 368,834 108,896 259,938 Drilling Rigs 17 5 12 Active Wells 2,316 606 1,710 Waiting on completion 102 Approved Drilling Permits 409 69 340 Potential Future Wells 4,236 1,158 3,078

Drilling and Completions Activity

The drilling rig count was very stable around 65 for the first half of the year. Operators have shifted to incremental increases and decreases based on oil price, capital availability, and gas capture. Operators have implemented plans to use fewer rigs second half of 2019 based on oil price, capital availability, and infrastructure constraints. The number of well completions has become variable again due to weather, gas capture, oil price and workforce. 95% of drilling now targets the Bakken and Three Forks formations. Lower crude oil price, gas capture, workforce, and competition with the Permian and Anadarko shale oil plays for capital continue to limit drilling rig count. Utilization rate for rigs capable of 20,000+ feet is 50-60% and for shallow well rigs (7,000 feet or less) 35-45%. Drilling permit activity is normal. Operators continue to maintain a permit inventory that will accommodate varying oil prices for the next 12 months.

Crude Oil Markets OPEC and Russia have agreed to increased production restrictions of 500,000 barrels per day through march 2020. Futures markets and EIA continue to anticipate crude oil oversupply through year end 2020.

Crude oil take away capacity including rail deliveries to coastal refineries is adequate, but Washington state Senate Bill 5579 threatens to disrupt 150,000-200,000 barrels per day.


Page 3 of 9

Seismic

Seismic activity is very slow.

Active Surveys Recording NDIC Reclamation Projects Remediating Suspended Permitted 3 0 2 0 1 3

Gas Capture

US natural gas storage is unchanged at the five-year average while crude oil inventories are well above the long-term average and stable, indicating little potential for price increases in the future. North Dakota shallow gas exploration could be economic at future gas prices but is not at the current price. The price of natural gas delivered to Northern Border at Watford City is down $0.55 at $1.73/MCF. This results in a current oil to gas price ratio of 31 to 1. The statewide gas flared volume from September to October increased 29,453 MCF to 546,358 MCF per day and percent flared was unchanged at 18% with a Bakken capture percentage of 81%. The historical high flared percent was 36% in 09/2011. Gas Capture Details: Statewide………………. 82% Statewide Bakken……... 81% Non-FBIR Bakken…….. 85% FBIR Bakken………….. 70% Trust FBIR Bakken... 68% Fee FBIR…………… 74%

The Commission established the following gas capture goals: 74% October 1, 2014 - December 31, 2014 77% January 1, 2015 - March 31, 2016 80% April 1, 2016 - October 31, 2016 85% November 1, 2016 - October 31, 2018 88% November 1, 2018 - October 31, 2020 91% November 1, 2020

https://bismarcktribune.com/bakken/north‐dakota‐oil‐production‐tops‐million‐barrels‐per‐day/article_e6729471‐91cd‐

5bd8‐b1a8‐bc47e42955eb.html#tracking‐source=home‐top‐story‐1

North Dakota oil production tops 1.5 million barrels per day

Amy R. Sisk 1 hr ago North Dakota oil production has hit a new milestone: 1.5 million barrels per day.

“It should be a very happy holiday for the state of North Dakota,” Mineral Resources Director Lynn Helms said Friday upon releasing the latest oil figures, which reflect production during the month of October.

The record number, nearly 1.52 million barrels per day, comes after oil production dropped to 1.44 million barrels per day in September amid rainy weather that shuttered roads in western North Dakota and slowed down activity in the oil patch.

Helms said he anticipates production will continue to increase in the Bakken for the foreseeable future, as OPEC and Russia agreed this month to curb their oil outputs in an effort to reduce an abundant global supply and bolster prices.

“It should result in small increments of production growth through the year 2020,” Helms said of the impact of the other nation’s cuts in North Dakota.

Events overseas also led to ripple effects this fall within the transportation of Bakken oil. Attacks on Saudi Arabian oil facilities disrupted imports of crude to East Coast refineries, North Dakota Pipeline Authority Director Justin Krinstad said.

“Those East Coast refineries, they really only have two options for crude sourcing: that’s either waterborne barrels coming from foreign sources or it’s crude-by-rail coming into the region,” he said.

With oil imports temporarily curbed from Saudi Arabia, refiners sought out more Bakken crude. In September, for the first time since January 2017, more oil-by-rail shipments from North Dakota went to the East Coast than the West Coast, which usually dominates the market share for oil transported by train out of the Bakken.

Kringstad said he anticipates that shift to be short-lived, as it didn’t take long for Saudi Arabia to ramp up its oil output following the attacks.

This week marked a significant development for the transportation of natural gas out of North Dakota. Oneok's Elk Creek Pipeline began operating, carrying up to 240,000 barrels per day of natural gas liquids from the Bakken to Kansas. NGLs include ethane, propane and butane, which are components of natural gas that exist in liquid form under certain temperatures and pressures.

The startup of that pipeline offers relief to existing and new natural gas processing plants, which have not been able to operate at full capacity.

“You can have all the processing capacity in the world, but if you don’t have an outlet at the tailgate of that facility for those NGLs, that plant will become congested and it will not be able to operate at its stated capacity,” Kringstad said.

Helms said the demand for space on the Elk Creek Pipeline is so high that he anticipates it will be full in a matter of weeks.

“There’s already plans in the works for an expansion,” he said.

Reach Amy R. Sisk at 701-250-8252 or [email protected].

MONTHLY UPDATE OCTOBER 2019 PRODUCTION & TRANSPORTATION

North Dakota Oil Production Month Monthly Total, BBL Average, BOPD

Sep. 2019 - Final 43,319,393 1,443,980 Oct. 2019 - Prelim. 47,051,671 1,517,796

North Dakota Natural Gas Production Month Monthly Total, MCF Average, MCFD

Aug. 2019 - Final 88,391,725 2,946,391 Sep. 2019 - Prelim. 95,189,103 3,070,616

Estimated Williston Basin Oil Transportation, Oct. 2019

CCURRENT DDRILLING AACTIVITY: NORTH DAKOTA1 53 Rigs

EASTERN MONTANA2 2 Rigs

SOUTH DAKOTA2 0 Rigs

SOURCE (DEC. 13, 2019): 1. ND Oil & Gas Division

2. Baker Hughes

PRICES: Crude (WTI): $59.39

Crude (Brent): $64.65

NYMEX Gas: $2.31

SOURCE: BLOOMBERG (DEC. 13, 2019)

GAS STATS** 83% CAPTURED & SOLD 14% FLARED DUE TO CHALLENGES OR CONSTRAINTS ON EXISTING GATHERING SYSTEMS 3% FLARED FROM WELL WITH ZERO SALES *OCT. 2019 NON-CONF DATA

Estimated North Dakota Rail Export Volumes

Estimated Williston Basin Oil Transportation

Williston Basin Truck/Rail Imports and Exports with Canada

Data for imports/exports chart is provided by the US International Trade Commission and represents traffic across US/Canada border in the Williston Basin area.

New Gas Sales Wells per Month

https://news.ihsmarkit.com/press‐release/energy/base‐decline‐rate‐oil‐and‐gas‐output‐permian‐basin‐has‐increased‐dramatically‐b

“Base Decline” Rate of Oil and Gas Output in Permian Basin has Increased Dramatically Because of Recent Growth; Operators Must Drill More Wells to Maintain Production Levels, IHS Markit Says Productionfromexistingwellsdeclinedby34%in2018.Byend2019,basedeclinesinPermianwillriseto40%

Thursday, December 12, 2019 7:35 am EST Permian Basin oil and gas operators will have to drill substantially more wells to maintain current production levels & even more to grow production, owing to the high level of recent growth, according to IHS Markit (NYSE: INFO). HOUSTON--(BUSINESS WIRE)--Oil and gas operators in the Permian Basin, the most prolific hydrocarbon resource basin in North America, will have to drill substantially more wells just to maintain current production levels and even more to grow production, owing to the high level of recent growth, according to an analysis by IHS Markit (NYSE: INFO), a world leader in critical information, analytics and solutions.

Data from the new IHS Markit Automated Well Forecasting Technology showed that the base decline rate of the more than 150,000 producing oil and gas wells in the Permian Basin has “increased dramatically” since 2010. The surge in shale drilling and output in recent years has been accelerating that inherent production decline because newer, younger wells decline much faster than older wells.

“Base decline” is calculated by identifying the actual or forecasted production of all the wells onstream at the start of the year, then tracking their cumulative decline by the end of the year. Understanding those base declines is critical for engineers/operators who must determine what level of drilling and production targets must be achieved for their company to grow production, and hopefully, maintain performance and provide returns to investors.

"Base decline is the volume that oil and gas producers need to add from new wells just to stay where they are—it is the speed of the treadmill,” said Raoul LeBlanc, vice president of Unconventional Oil and Gas at IHS Markit. “Because of the large increases of recent years, the base decline production rate for the Permian Basin has increased dramatically, and we expect those declines to continue to accelerate. As a result, it is going to be challenging, especially for some companies with cash constraints, just to keep production flat.”

The new IHS Markit production outlook expects total U.S. oil production growth to flatten by 2021 due to a major slowdown in growth from U.S. shale.The new IHS Markit outlook for oil market fundamentals for 2019-2021 expects total U.S. production growth to be 440,000 barrels per day in 2020 before essentially flattening out in 2021. Modest growth is expected to resume in 2022. But those volumes would still be in stark contrast to the boom levels of recent years, LeBlanc said.

The Permian provides the comparison between traditional wells and shale wells. At the start of 2010, IHS Markit noted that production for the Permian Basin was approximately 880,000 barrels per day, with virtually all production coming from conventional operations. By the end of 2010, that group of wells produced 767,000 barrels per day—a decline of 110,000 barrels per day, or 13% of production.

Fast forward to 2019 when most wells drilled in the Permian Basin were shale wells (hydraulically fractured), which decline much faster, and the situation became even more dramatic. In 2019 Permian Basin production started the year at 3.8 million barrels per day, a million barrels per day higher than the year before. IHS Markit expects that base production will decline by approximately 1.5 million barrels of oil per day by the end of 2019–a staggering 40% base decline rate.

“Unless intentionally choked back, new, individual unconventional wells decline very rapidly, often 65% to 85% in the first year, so companies with many young wells in their inventory see significant declines in production compared to companies with a balance of younger and older wells,” LeBlanc said. “However, these high initial decline rates of individual shale wells become shallower over time, with older wells showing annual declines of 20% or less. So, the key here is that older wells in an operator’s inventory help offset the rapid declines of newer wells.”

Because of these older wells, base declines can also decelerate if the weighted average age of the wells in the production base rises. Just as a production base with mostly young wells exhibits high decline rates, the older the production base, the more stable it is, IHS Markit said.

Companies with the highest growth in recent years have the steepest base decline rates, and vice versa. The challenge of base declines is, therefore, different for each operator, depending on multiple factors, but especially on the decisions the firm has made concerning production growth and capital allocation, IHS Markit said.

“Now that capital markets have closed for many companies and investors are requiring returns, a critical objective for these companies is to slow production growth, significantly moderating their base declines,” LeBlanc said.

The enhanced Permian Basin reserves-decline analysis is derived from the IHS Markit Automated Well Forecasting Technology and is currently delivered to customers through its Performance Evaluator™ analytics platform. To speak with Raoul LeBlanc, or for more information on the Permian analysis, please contact Melissa Manning.

AboutIHSMarkit(www.ihsmarkit.com)

SAF Created Transcript Excerpt From Wood Mackenzie Dec 11 webcast “Nuances in the Water Type

Curve” https://readytalk.webcasts.com/viewer/event.jsp?ei=1273297&tp_key=7410f54856

Wood Mackenzie comments on slide 18 below. SAF transcript of the his quote “we have seen very often

a lot of your operators, operators are saying they are going to drill 8 benches and might have up to 52

wells in a section, we don’t believe that that is going to be true and there have been several articles now

as well that have been published as well and we believe that only going to be 4 to 5 benches could be

drilled out especially in the Permian basin, especially in the Delaware with a total wells of 20 to 24 wells.

we see that the drilling inventories about half what many companies are forecasting”

https://www.wsj.com/articles/shale‐slowdown‐takes‐economic‐toll‐11576405800?mod=hp_lead_pos2

ShaleSlowdownTakesEconomicTollU.S. regions that benefited as fracking boomed are seeing declines in economic activity as producers reduce employment, spending Many shale companies have struggled to generate returns for shareholders, and they are now slashing spending. PHOTO: DYLAN COLE FOR THE WALL STREET JOURNAL

By

RebeccaElliottUpdated Dec. 15, 2019 7:17 am ET

MIDLAND, Texas—America’s hottest oil-drilling regions—such as this one at the heart of the

Permian Basin—are seeing their economies soften as shale producers slash spending, leading to

emptier hotels, choosier employers and less overtime for workers.

Early this year, demand for the tubing, bolts and valves used in fracking was so high that Homer

Daniels’s oil-field equipment company, RK Supply, in the Midland area was on track to easily beat

its annual revenue forecast. But by August, Mr. Daniels had to impose a hiring freeze as

customers delayed projects.

“It affects everybody’s bottom lines,” Mr. Daniels said.

Fracking has made the U.S. the world’s top oil producer, buoyed the national economy and helped

the country become a net exporter of crude and petroleum products for the first time in decades.

But the rapid production growth of recent years is waning as shale companies, many of which

have struggled to make money, focus on profits over expansion to satisfy unhappy investors.

“The boom time is done at this point, unless oil prices go up significantly,” said Michael Plante,

senior economist at the Federal Reserve Bank of Dallas

Already, that shift is taking an economic toll. National nonresidential fixed investment—which

tracks spending on software, research and development, equipment and structures—fell at an

annualized rate of 2.66% in the third quarter and 1.01% in the second quarter, due in large part

to declines in oil and gas spending, according to the Dallas Fed.

Spending is expected to decline further next year. North American shale investment, or spending

on drilling and fracking, is forecast to fall about 6% this year, then tumble another 14% in 2020,

adjusted for inflation, according to energy analytics firm Rystad Energy.

Companies also are trimming jobs, leading to a 5% decline in seasonally adjusted oil-field service

employment in the 12 months ended in October, according to Bureau of Labor Statistics data.

The changes are evident in the Permian, the region straddling Texas and New Mexico that has

been the heart of the fracking boom. Trucks carrying sand, water and crude still clog the

highways, new homes continue to be built, and regional unemployment was 2.4% in October, up

from a recent low of 1.9% in April but below the national average of 3.3%, not seasonally

adjusted, according to the Texas Workforce Commission.In Texas, the nation’s top oil-producing

state, energy industry employment has dropped at an annualized rate of 2.1% in the year to date

through September, Dallas Fed data show. Such granular figures weren’t available in other oil-

producing states, but BLS data show that in North Dakota, seasonally adjusted employment in

mining and logging, which includes the oil-and-gas industry, fell about 9% from January through

October. Employment has been steadier in Colorado and New Mexico.

Still, oil-and-gas workers have begun to see their hours cut, and hotel occupancy in Midland has

fallen 14% through the first 10 months of the year from a year earlier, according to hospitality

benchmarking firm STR Inc. Occupancy had tightened during the boom, leading to high prices

and a building frenzy throughout the Permian. The average cost of a room in Midland was about

55% higher last year than in 2017, STR data show.

For Jose Urteaga, a supervisor for a bulk fuel supplier, the softness has meant that his company

doesn’t have to worry as much about employee turnover.

“In the past, we were just getting every warm body we could,” Mr. Urteaga said at a recent

cookout in Midland. “Because it’s leveled off some, we’re able to check references, make sure

guys have the experience they’re putting on their résumés.”

The slowdown is unusual because it hasn’t been driven by a sharp decline in crude prices, which

have hovered around $57 a barrel this year. Rather, U.S. oil producers are paring growth and

spending largely because many have struggled mightily to generate returns for shareholders and

are facing tightening access to capital. Including reinvested dividends, a broad index of U.S. oil-

and-gas companies’ share prices has fallen about 47% in the past three years as the S&P 500

index soared roughly 49%, according to FactSet.

“Investors are playing a large role here, and that’s the biggest driver of this cycle,” said Chris

Wright, chief executive of Denver-based Liberty Oilfield Services Inc., which specializes in

hydraulic fracturing. Companies such as Liberty that provide services or parts to shale producers

have been among the hardest-hit by the pullback.

In Hobbs, N.M., just 5 miles from the Texas border, Kevin Mattingly, who owns Shiloh Machine, is

seeing customers that used to consistently pay him within 60 days wait 90 or 100 days to do so.

Meanwhile, the pile of tubing and other tools that companies have asked the machinist to repair

is dwindling.

“There is a crunch on our cash,” Mr. Mattingly said. He recently asked employees to stop working

overtime, a key source of income in oil boomtowns, where costs run high and housing can be

difficult to find.

On the Texas side of the Permian, Scott Chaffin is planning to go back to school in January for

welding, after seeing his weekly hours at a pipe-inspection company fall to about 50, from more

than 80 earlier this year.

“You’ve got to pay attention a lot more to your spending,” said Mr. Chaffin, 34 years old, who has

cut back on expenses such as new clothes and eating out.

http://www.bst‐tsb.gc.ca/eng/enquetes‐investigations/rail/2019/R19W0320/R19W0320.html

Rail transportation safety investigation R19W0320 Tableofcontents

Main‐tracktrainderailmentCanadian Pacific Railway Mile 48.8, Sutherland Subdivision Near Guernsey, Saskatchewan 9 December 2019

TheoccurrenceOn 09 December 2019, a Canadian Pacific (CP) crude oil unit train 516-398 was proceeding eastward at about 45 mph on the CP Sutherland Subdivision. The speed limit in this section of the subdivision is 45 mph. The train originated at Rosyth, Alberta, and was destined for Stroud, Oklahoma, USA. The train crew was composed of a locomotive engineer and a conductor. Both were qualified for their positions and fit for duty.

WhatweknowPlease note that the following information is preliminary and subject to change as the TSB continues its investigation.

At 0010 Central Standard Time, the train experienced a train-initiated emergency brake application at Mile 48.85, near Guernsey, Saskatchewan. Initial site examination determined that the covered hopper car in position 2 and the following 33 tank cars had derailed. The derailed tank cars consisted of a mix of 9 Class 117R and 24 CPC-1232 Class 111 tank cars. There were no injuries reported. The temperature at the time was about −19°C.

The head-end 23 tank cars derailed east of the crossing and came to rest in various positions in a large pile over a distance of approximately 500 feet. About 20 of the 23 tank cars sustained breaches, released product and became engulfed in a large pool fire which burned for approximately 24 hours.

Preliminary examination of the 23 cars suggests that about 19 of the cars lost their entire loads releasing an estimated 1.5 million litres of product to either the ground or atmosphere. A more precise determination of the tank car damage and the amount of product released will be made as product is recovered and the investigation progresses. No waterways appear to be affected.

The tail end 10 cars derailed west of the crossing, sustained minimal damage and remained intact with no loss of product.

OngoingworkThe TSB has deployed 6 investigators to the occurrence site. Work on-site is progressing. All 33 tank cars will be examined in order to evaluate tank car performance.

Mechanical and track components recovered from the derailment will be examined and any components of interest will be sent to the TSB Engineering Laboratory in Ottawa for detailed analysis.

Mediamaterials

Deploymentnotice2019-12-09 TTSB deploys a team of investigators to a train derailment near Lanigan, Saskatchewan

Winnipeg, Manitoba, 9 December 2019 – The Transportation Safety Board of Canada (TSB) is deploying a team of investigators to the site of a derailment involving a Canadian Pacific Railway train near Lanigan, Saskatchewan. The TSB will gather information and assess the occurrence.

Investigationinformation

Mapshowingthelocationoftheoccurrence

Investigator‐in‐charge

Rob Johnston has been with the Transportation Safety Board of Canada (TSB) since 2001. He was hired as a Senior Regional Investigator (Rail/Pipeline) in Winnipeg where he worked until 2004, when he assumed the position of Senior Investigator, Standards and Training Officer at TSB Head Office in Gatineau, Quebec. He became Manager of Central Regional Operations in November 2009, and has also served as Acting Director of Investigations – Rail/Pipeline for various periods since 2010.

He now manages a staff of six rail/pipeline investigators in Winnipeg, Toronto, and Ottawa, and is responsible for all activities related to rail investigations in TSB’s Central Region, which extends from Cornwall, Ontario, to near the Alberta–Saskatchewan border.

During his time at the TSB, Mr. Johnston has been involved in over 70 TSB accident investigations either as an Investigator-in- Charge (IIC) or as an investigation team member providing technical expertise.

Before joining the TSB, Mr. Johnston worked for Canadian Pacific Railway (CP) in Winnipeg from 1984 until 2001, where he was a member of the Train Accident Prevention group and worked in a failure analysis laboratory. He was a member of CP’s hazardous materials emergency response team for 14 years and has acquired an extensive background in mechanical operations, failure analysis, and dangerous goods.

https://www.cbc.ca/news/canada/saskatoon/saskatchewan‐rail‐tank‐car‐cp‐1.5395111

U.S. rail carrier reportedly cracked down on same retrofitted tank type involved in fiery Sask. derailment

Same type of retrofitted 117R cars were involved in a previous derailment last year in Iowa Guy Quenneville ꞏ CBC News ꞏ Posted: Dec 13, 2019 11:27 AM CT | Last Updated: 8 hours ago

An oil-carrying rail car tank that ruptured after Canadian National Railway unit train 516-398 derailed west of Guersney, Sask., and ignited a large blaze Monday. (Albert Couillard/Radio Canada) 18 comments Transport Canada says "only the most crash-resistant tank cars available" are allowed to haul crude oil on Canadian rail lines.

But the Canadian Pacific Railway train that derailed on a remote patch of Saskatchewan farmland Monday, leaking an estimated 1.5 million litres of oil and igniting a large blaze, was pulling retrofitted steel tank cars that are not the thickest available.

The same retrofitted tank type has reportedly been cracked down upon by a major rail carrier of crude oil in the United States, following a June 2018 derailment in Iowa that leaked 870,645 litres of oil into a waterway.

CP has confirmed that the train that derailed west of Guernsey, Sask., this week was hauling a mix of jacketed CPC-1232 cars and TC-117R cars.

Another damaged tank from the scene of Monday's derailment. (Albert Couillard/Radio Canada) TC-117R cars are retrofitted to meet the same standards as brand new TC-117s, which are meant to be less prone to rupturing during crashes.

"The features [for new and retrofitted 117 cars] are the same and include thermal protection, top fitting protection, new bottom outlet valves, full head shield protection and a jacket," a spokesperson for Transport Canada said earlier this week.

'Not quite brand new' But Ian Naish, a former director of rail investigations for the Transportation Safety Board of Canada, said the shells on retrofitted 117R cars are slightly thinner than those on new 117 cars: 7/16th of an inch thick, versus 9/16th of an inch thick.

"They are almost equivalent," Naish said. "[They] are not quite brand new but better than what was there before."

Naish was referring to the TC-111 cars that were involved in the July 2013 Lac-Mégantic, Que., rail disaster that killed 47 people.

In the wake of the crash, Transport Canada called for the TC-117 rail cars to become the new standard for transporting flammable liquids.

On Thursday, Transport Canada confirmed retrofitted TC-117 cars like the ones on the CP train have the same protective features as brand new TC-117 cars. But they are not as thick as new ones, a former TSB investigator said. (Transport Canada/CBC) The agency also ordered that CPC-1232 tank cars that do not feature jackets for thermal protection be phased out by November 2018.

19 tanks lost entire loads of oil The Transportation Safety Board of Canada is investigating Monday's CP derailment. According to an update provided by the TSB Wednesday, 33 cars went off the tracks. Nine of them were the retrofitted 117R type, while the remaining 24 were jacketed CPC-1232 cars.

The TSB said about 20 of the tanks ruptured and released oil, with 19 of the cars losing their entire loads.

The TSB did not specify which tank type suffered the worst damage but engineers will be examining all damaged tanks closely.

"We'd have to see what happened to the actual cars that ruptured or released product," Naish, the former TSB investigator, said. "But if the tank car shells were an issue, obviously the 7/16ths-of-inch shells aren't very good. And maybe the 9/16ths would have been better."

Heavy equipment works in the background behind a row of damaged rail thank cars. (Albert Couillard/Radio Canada) CP has previously said it does not own the rail cars involved in Monday's derailment but has declined to say who does.

U.S. rail carrier banned 117R cars Retrofitted TC-117R rail car tanks were on the train hauling Canadian oil that derailed in Iowa in June 2018, according to Reuters. The railway involved, the BNSF Railway Company, then moved to ban the use of 117R cars on its lines.

"BNSF continues to handle all car types allowed under federal regulation for crude but we are working with our individual customers to facilitate getting the newest and safest tank cars in service sooner on our railroad," BNSF spokesperson Amy Casas told CBC.

"That refers to the transition to the [new] 117s," she added for clarification.

No one was injured in Monday's Saskatchewan derailment, nor was it the largest release of oil in the province's history, according to the Saskatchewan government.

But it's unclear if it represents the largest release of oil carried by rail in the province.

Canadian Pacific Railways says it does not own the tank cars it was hauling. It's unclear who does. (Albert Couillard/Radio Canada) The estimated amount released onto the farmland near Guernsey, 1.5 million litres, is more than six times the amount that spilled into the North Saskatchewan River in 2016 after a Husky Energy pipeline leaked near Maidstone, Sask.

The TSB has said Monday's leak did not affect any waterways but said its definition of waterways does not include the water table.

Melanie Loessl, whose pasture land is located right near the derailment site, said she is worried about any potential impacts to her drinking water.

Emily Eaton, an associate professor at the University of Regina's department of geography and environmental studies, said spills on land, as opposed to water, are easier to contain.

1

https://pm.gc.ca/en/mandate‐letters/minister‐transport‐mandate‐letter

MinisterofTransportMandateLetter

Dear Mr. Garneau:

Thank you for agreeing to serve Canadians as Minister of Transport.

On Election Day, Canadians chose to continue moving forward. From coast to coast to coast, people chose to invest in their families and communities, create good middle class jobs and fight climate change while keeping our economy strong and growing. Canadians sent the message that they want us to work together to make progress on the issues that matter most, from making their lives more affordable and strengthening the healthcare system, to protecting the environment, keeping our communities safe and moving forward on reconciliation with Indigenous Peoples. People expect Parliamentarians to work together to deliver these results, and that’s exactly what this team will do.

It is more important than ever for Canadians to unite and build a stronger, more inclusive and more resilient country. The Government of Canada is the central institution to promote that unity of purpose and, as a Minister in that Government, you have a personal duty and responsibility to fulfill that objective.

That starts with a commitment to govern in a positive, open and collaborative way. Our platform, Forward: A Real Plan for the Middle Class, is the starting point for our Government. I expect us to work with Parliament to deliver on our commitments. Other issues and ideas will arise or will come from Canadians, Parliament, stakeholders and the public service. It is my expectation that you will engage constructively and thoughtfully and add priorities to the Government’s agenda when appropriate. Where legislation is required, you will need to work with the Leader of the Government in the House of Commons and the Cabinet Committee on Operations to prioritize within the minority Parliament.

We will continue to deliver real results and effective government to Canadians. This includes: tracking and publicly reporting on the progress of our commitments; assessing the effectiveness of our work; aligning our resources with priorities; and adapting to events as they unfold, in order to get the results Canadians rightly demand of us.

Many of our most important commitments require partnership with provincial, territorial and municipal governments and Indigenous partners, communities and governments. Even where disagreements may occur, we will remember that our mandate comes from citizens who are served by all orders of government and it is in everyone’s interest that we work together to find common ground. The Deputy Prime Minister and Minister of Intergovernmental Affairs is the Government-wide lead on all relations with the provinces and territories.

There remains no more important relationship to me and to Canada than the one with Indigenous Peoples. We made significant progress in our last mandate on supporting self-determination, improving service delivery and advancing reconciliation. I am directing every single Minister to determine what they can do in their specific portfolio to accelerate and build on the progress we have made with First Nations, Inuit and Métis Peoples.

I also expect us to continue to raise the bar on openness, effectiveness and transparency in government. This means a government that is open by default. It means better digital capacity and services for Canadians. It means a strong and resilient public service. It also means humility and continuing to acknowledge mistakes when we make them. Canadians do not expect us to be perfect; they expect us to be diligent, honest, open and sincere in our efforts to serve the public interest.

As Minister, you are accountable for your style of leadership and your ability to work constructively in Parliament. I expect that you will collaborate closely with your Cabinet and Caucus colleagues. You will also

2

meaningfully engage with the Government Caucus and Opposition Members of Parliament, the increasingly non-partisan Senate, and Parliamentary Committees.

It is also your responsibility to substantively engage with Canadians, civil society and stakeholders, including businesses of all sizes, organized labour, the broader public sector and the not-for-profit and charitable sectors. You must be proactive in ensuring that a broad array of voices provides you with advice, in both official languages, from every region of the country.

We are committed to evidence-based decision-making that takes into consideration the impacts of policies on all Canadians and fully defends the Canadian Charter of Rights and Freedoms. You will apply Gender-based Analysis Plus (GBA+) in the decisions that you make.

Canada’s media and your engagement with them in a professional and timely manner are essential. The Parliamentary Press Gallery, indeed all journalists in Canada and abroad, ask necessary questions and contribute in an important way to the democratic process.

You will do your part to continue our Government’s commitment to transparent, merit-based appointments, to help ensure that people of all gender identities, Indigenous Peoples, racialized people, persons with disabilities and minority groups are reflected in positions of leadership.

As Minister of Transport, you will continue to ensure that Canada’s transportation system supports the Government’s ambitious economic growth and job creation agenda. Canadians require a transportation system that is safe and reliable, that facilitates trade and the movement of people and goods and that is more environmentally sustainable.

I will expect you to work with your colleagues and through established legislative, regulatory and Cabinet processes to deliver on your top priorities. In particular, you will:

Continue the implementation of the Transportation 2030 strategic plan:

o Work with the Minister of Infrastructure and Communities to invest in Canada’s trade corridors to increase global market access for Canadian goods;

o In your capacity as Minister responsible for VIA Rail, work with the Minister of Infrastructure and Communities to create high frequency rail for the Toronto-Quebec City corridor;

o Work with the Minister of Employment, Workforce Development and Disability Inclusion to make the transportation system more accessible for persons with disabilities;

o Complete the transfer of the Canadian Air Transport Security Authority to an independent not-for-profit entity that will improve the passenger experience, including a clear service standard to limit the amount of time travellers wait in airport security checkpoints;

o Implement measures to strengthen the transparency, accountability and efficiency of Canadian airports;

o Continue to improve the safety of Canada’s transportation sector through a review and modernization of relevant legislation and regulations;

o Work with the Minister of Innovation, Science and Industry, the Minister of Natural Resources and the Minister of Environment and Climate Change to advance toward our zero-emission vehicles targets of 10 per cent of light-duty vehicles sales per year by 2025, 30 per cent by 2030 and 100 per cent by 2040; and

o Work with the Minister of Fisheries, Oceans and the Canadian Coast Guard to implement the Oceans Protection Plan to deliver 24/7 emergency response for incident management, to increase

3

on-scene environmental response capacity, and to develop near real-time information on marine traffic with Indigenous and coastal communities.

Work with partners to begin a process to design and introduce programs that support making Canada’s major ports among the most efficient and cleanest in the world. This work will require you to:

o Support efforts that develop marine infrastructure and convert ships from burning heavy oil and diesel toward more environmentally friendly fuels, like liquefied natural gas; and

o Complete the Ports Modernization Review with an aim to update governance structures that promote investment in Canadian ports.

Work with VIA Rail to make opportunities to travel to Canada’s National Parks more accessible and affordable.

These priorities draw heavily from our election platform commitments. As mentioned, you are encouraged to seek opportunities to work across Parliament in the fulfillment of these commitments and to identify additional priorities.

I expect you to work closely with your Deputy Minister and their senior officials to ensure that the ongoing work of your department is undertaken in a professional manner and that decisions are made in the public interest. Your Deputy Minister will brief you on the many daily decisions necessary to ensure the achievement of your priorities, the effective running of the government and better services for Canadians. It is my expectation that you will apply our values and principles to these decisions so that they are dealt with in a timely and responsible manner and in a way that is consistent with the overall direction of our Government.

Our ability, as a government, to implement our priorities depends on consideration of the professional, non-partisan advice of public servants. Each and every time a government employee comes to work, they do so in service to Canada, with a goal of improving our country and the lives of all Canadians. I expect you to establish a collaborative working relationship with your Deputy Minister, whose role, and the role of public servants under their direction, is to support you in the performance of your responsibilities.

We have committed to an open, honest government that is accountable to Canadians, lives up to the highest ethical standards and applies the utmost care and prudence in the handling of public funds. I expect you to embody these values in your work and observe the highest ethical standards in everything you do. I want Canadians to look on their own government with pride and trust.

As Minister, you must ensure that you are aware of and fully compliant with the Conflict of Interest Act and Treasury Board policies and guidelines. You will be provided with a copy of Open and Accountable Government to assist you as you undertake your responsibilities. I ask that you carefully read it, including elements that have been added to strengthen it, and ensure that your staff does so as well. I expect that in staffing your offices you will hire people who reflect the diversity of Canada, and that you will uphold principles of gender equality, disability equality, pay equity and inclusion.

Give particular attention to the Ethical Guidelines set out in Annex A of that document, which apply to you and your staff. As noted in the Guidelines, you must uphold the highest standards of honesty and impartiality, and both the performance of your official duties and the arrangement of your private affairs should bear the closest public scrutiny. This is an obligation that is not fully discharged by simply acting within the law.

I will note that you are responsible for ensuring that your Minister’s Office meets the highest standards of professionalism and that it is a safe, respectful, rewarding and welcoming place for your staff to work.

I know I can count on you to fulfill the important responsibilities entrusted in you. It is incumbent on you to turn to me and the Deputy Prime Minister early and often to support you in your role as Minister.

Sincerely,

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Rt. Hon. Justin Trudeau, P.C., M.P. Prime Minister of Canada

*This Ministerial Mandate Letter was signed by the Prime Minister in the Minister’s first official language.

Oil Market Highlights

OPEC Monthly Oil Market Report – December 2019 v


Crude Oil Price Movements

The OPEC Reference Basket (ORB) price rose by $3.03, or 5.1%, month-on-month (m-o-m) in November settling at $62.94/b. In November, ICE Brent averaged $3.08, or 5.2%, higher m-o-m at $62.71/b, while NYMEX WTI rose by $3.06, or 5.7%, m-o-m averaging $57.07/b. Year-to-date (y-t-d), ICE Brent averaged $8.79, or 12.1%, lower at $64.08/b, while NYMEX WTI declined by $9.48, or 14.3%, to $56.79/b, both compared to the same period a year earlier. The backwardation price structures of both ICE Brent and DME Oman steepened further in November, particularly in prompt forward months, while the NYMEX WTI market structure slipped into backwardation for most of the month. Hedge funds and other money managers raised their speculative net long positions, reflecting a more positive outlook for the global oil market.

World Economy

The global economic growth forecast remains at 3.0% for both 2019 and 2020. US growth remains at 2.3% for 2019 and 1.8% for 2020. Euro-zone growth remains at 1.2% for 2019 and 1.0% for 2020. Japan’s growth forecast is unchanged at 0.9% for 2019, but revised up to 0.6% for 2020, considering a forecast positive net effect from the announced fiscal stimulus. China’s growth forecast is unchanged, standing at 6.2% for 2019 and 5.9% for 2020. India’s growth forecast is revised down to 5.5% for 2019 and to 6.4% for 2020, after less-than-expected growth in the first three quarters of 2019. Both Brazil’s and Russia’s forecasts are revised up slightly, after both economies continued accelerating in 3Q19. Brazil’s 2019 growth forecast is revised up to 1.0% for 2019 and to 1.7% for 2020. Similarly, Russia’s forecast is revised up to 1.1% for 2019 and 1.3% for 2020.

World Oil Demand

World oil demand growth is expected at 0.98 mb/d in 2019, unchanged from last month’s report. In the OECD region, OECD Americas is estimated to lead oil demand growth as a result of steady light distillate requirements. China is assessed to lead demand growth globally, as well as within non-OECD countries, in response to steady petrochemical feedstock demand for transportation fuels. In 2020, world oil demand is forecast to increase by 1.08 mb/d, also in line with last month projections. Oil demand growth is forecast to originate largely from Other Asia, followed by China. OECD countries are projected to consume an additional 0.07 mb/d as compared to the current year, while non-OECD countries are expected to remain the driver for oil demand growth in 2020, adding an estimated 1.01 mb/d.

World Oil Supply

Non-OPEC oil supply growth forecast for 2019 remains at 1.82 mb/d, unchanged from last month’s report. The US liquids supply growth also remains unchanged at 1.62 mb/d, the an upward revision in 3Q19 is now offset by a lower estimate for 4Q19. Similarly, the non-OPEC oil supply growth forecast for 2020 remains unchanged from last month’s forecast at 2.17 mb/d. An upward revision in the UK’s oil supply forecast is offset by a downward revision in Russia. The 2020 non-OPEC supply forecast remains subject to some uncertainties, including the degree of spending discipline by US independent oil companies. For 2019, the US, Brazil and Canada remain to be the key drivers for growth, and this will continue in 2020 with the addition of Norway. OPEC NGLs production in 2019 is estimated to have grown by 0.04 mb/d to average 4.80 mb/d and in 2020 is forecast to grow to average 4.83 mb/d. In November, OPEC crude oil production dropped by 193 tb/d m-o-m to average 29.55 mb/d, according to secondary sources.


vi OPEC Monthly Oil Market Report – December 2019

Product Markets and Refining Operations

Product markets in November lost solid ground as refinery intakes recovered, following peak refinery maintenance which led to higher product availability and contributed to a trend reversal of refinery margins in all main trading hubs. Higher feedstock prices and weaker fuel oil cracks affected by high freight rates weighed further on product markets, particularly in Asia, where refining economics fell sharply to a multi-year record low and entered negative territory.

Tanker Market

Dirty tanker spot freight rates in November remained at robust levels relative to their performance seen for most of this year, although down from the record highs of the previous month. Indeed, October’s announcement of sanctions on two subsidiaries of a China’s shipping giant, Cosco, surprised the market at a time of seasonal uplift in demand for longer-haul voyages and reduced tonnage availability due to IMO preparations, leading to panic fixing and a sharp spike in rates. As the panic subsided in November and as the market regained balance, rates retreated but remained close to the elevated levels seen in the same month last year. Clean tanker rates also enjoyed a similar upward trend and even managed to retain gains to stand well above the levels achieved this time last year.

Stock Movements

Preliminary data for October showed that total OECD commercial oil stocks fell by 5.1 mb m-o-m to stand at 2,933 mb, which is 82.5 mb higher than the same time one year ago, and 32.8 mb above the latest five-year average. Within the components, crude stocks rose by 18.9 mb m-o-m to stand at 18.3 mb above the latest five-year average, while product stocks decreased by 23.9 mb m-o-m to stand at 14.5 mb above the latest five-year average. In terms of days of forward cover, OECD commercial stocks rose by 0.6 days m-o-m in October to stand at 61.2 days, which is 1.8 days above the same period in 2018, but 0.2 days below the latest five-year average.

Balance of Supply and Demand

Demand for OPEC crude in 2019 was unchanged from the previous report to stand at 30.7 mb/d, which is 0.9 mb/d lower than the 2018 level. Demand for OPEC crude in 2020 also remained unchanged from the previous report to stand at 29.6 mb/d, which is around 1.1 mb/d lower than the 2019 level.

Feature Article

OPEC Monthly Oil Market Report – December 2019 vii

Feature Article

Review of 2019 and outlook for 2020

Global economic growth slowed in 2019, impacted by a variety of challenges. Trade issues not only led to reduction in global final consumption but also caused investment growth to decelerate. On the positive side, global trade slowdown has likely bottomed out, and now the negative trend in industrial production seen in 2019 is expected to reverse in 2020. As a result, global economic growth is forecast at 3.0% for both 2019 and 2020.

Recent progress on various trade agreements such as the conclusion of the Regional Comprehensive Economic Partnership of Asian-Pacific nations may provide the base to re-energize the momentum in global trade, although challenges remain, particularly regarding ongoing trade talks between the US and its trade partners, particularly China.

While global monetary policies continue to be accommodative, high debt levels in many major economies represent some risk. Additional challenges are posed by fiscal issues in few EU Member Countries, Brexit, and Japan’s ongoing slowdown. Fiscal imbalances in emerging and developing economies may also have a negative effect on global economic growth, while recent social unrest in some economies may add more downward pressure.

Graph 1: 2020 real GDP growth for selected countries

Global oil demand is projected to rise by 0.98 mb/d in 2019, mainly due to cooling macro-economic indicators in major economies. Oil demand in the OECD is projected to grow by a marginal 0.02 mb/d in 2019, due to slower-than-expected demand in the Americas and Asia Pacific. Weaker-than-expected diesel requirements in the US amid the slower pace in manufacturing and construction activity have limited demand growth in the current year. In Asia Pacific, significant petrochemical plant turnarounds reduced demand for petrochemical feedstock in 1H19. In non-OECD oil demand in 2019 is anticipated to rise by 0.96 mb/d, primarily as a result of slower-than-expected demand in India due to reduced industrial and transportation fuel requirements in 2Q19 and 3Q19. In 2020, global oil demand is expected to grow by 1.08 mb/d, with the OECD growing by 0.07 mb/d. OECD Americas is anticipated to be the only OECD region in positive demand growth territory next year, supported mainly by petrochemical capacity additions. In the non-OECD region, oil demand growth is projected to be around 1.01 mb/d, with growth projected to improve in Other Asia, Latin America and the Middle East. Indeed, the transportation and petrochemical sectors are expected to continue leading oil demand growth in 2020.

On the supply side, non-OPEC oil supply growth in 2019 has been lower than initial market expectations, now standing at 1.82 mb/d compared to the initial projection of 2.10 mb/d in July 2018. Weaker-than-expected growth in Canada, Brazil, Norway, Kazakhstan, China and Russia has been the key contributor to the downward revision, despite the better-than-expected performance of US liquids supply. US oil output is leading this growth with 1.62 mb/d in 2019. In 2020, non-OPEC supply is expected to see a continued slowdown in growth on the back of decreased investment and lower drilling activities in US tight oil. Non-OPEC supply is now forecast to grow by 2.17 mb/d in 2020, representing a downward revision of around 0.27 mb/d from initial forecasts in July 2019 on the back of downward revisions in US oil supply. Nevertheless,

Graph 2: World oil demand and non-OPEC supply revisions from initial forecast in 2019 and 2020

incremental production from the US tight plays, particularly in the Permian Basin, as well as from offshore fields in Norway, Brazil, Australia and possibly Guyana, will contribute to the non-OPEC supply in 2020.

Evidently, significant and successful effort of countries participating in the Declaration of Cooperation (DoC) have helped the global oil market to remain relatively balanced in 2019. Going forward, countries participating in the DoC reaffirmed their continuing commitment to oil market stability as they have decided this month to adjust production further by another 500 tb/d, adding to the previous adjustment of 1.2 mb/d, and now totalling to 1.7 mb/d as of January 2020. This is to stabilize the market in the interests of both consumers and producers, as well as the wellbeing of the global economy.

1.0

1.7

1.3

6.4

5.9

1.0

0.6

1.8

1.4

3.0

-0.2

1.0

1.1

5.5

6.2

1.20.9

2.3

1.6

3.0

OPEC

Brazil

Russia

India

China

Euro-zone

Japan

US

OECD

World

2019*

2020*

Note: * 2019 = Estimate and 2020 = Forecast.Source: OPEC Secretariat.

Percentage

0.5

1.0

1.5

2.0

2.5

Jul 19 Aug 19 Sep 19 Oct 19 Nov 19 Dec 19

mb/d

World oil demand: 2019 World oil demand: 2020

Non-OPEC supply: 2019 Non-OPEC supply: 2020

Source: OPEC Secretariat.

World Oil Demand

OPEC Monthly Oil Market Report – December 2019 31

World Oil Demand

Global oil demand in 2019 is now anticipated to rise by 0.98 mb/d, unchanged from the previous month’s report. Total global oil consumption is expected to average 99.80 mb/d. In the OECD, oil demand growth was left unchanged as compared to last month’s MOMR with OECD Americas projected to lead growth in 2019 as the ramping-up of production in ethane crackers should provide solid support to demand for NGLs/LPG. On the other hand, OECD Europe and Asia Pacific are projected to decline y-o-y in line with slower-than-expected industrial activity and significant petrochemical plant turnarounds. In the non-OECD region, oil demand growth was kept in line with last month’s projections. China is anticipated to lead demand growth globally in 2019, rising by 0.35 mb/d, followed by Other Asia, which is expected to add 0.30 mb/d y-o-y. Additionally, oil demand growth in Latin America and the Middle East is projected to improve from 2018 levels to increase by 0.04 mb/d and 0.06 mb/d y-o-y, respectively.

World oil demand in 2020 is anticipated to increase by 1.08 mb/d to average 100.88 mb/d, also untouched as compared to last month’s MOMR. In the OECD region, oil demand is projected to increase by 0.07 mb/d, with OECD Americas being in positive territory, driven largely by steady light distillate demand. In the non-OECD region, growth is anticipated to be around 1.01 mb/d with Other Aisa regaining its leading position in terms of oil demand growth, followed by China. Higher oil requirements in other regions such as Latin America and the Middle East are also projected in 2020 as compared to the current year.

World oil demand in 2019 and 2020

Table 4 - 1: World oil demand in 2019*, mb/d

2018 1Q19 2Q19 3Q19 4Q19 2019 Growth %

Americas 25.55 25.22 25.38 26.03 26.02 25.66 0.12 0.46

of which US 20.79 20.67 20.66 21.25 21.02 20.90 0.12 0.57Europe 14.31 13.99 14.23 14.68 14.30 14.30 0.00 -0.03

Asia Pacific 8.08 8.45 7.64 7.73 8.12 7.99 -0.09 -1.14

Total OECD 47.93 47.65 47.26 48.44 48.44 47.95 0.02 0.04

Other Asia 13.64 13.91 13.96 13.66 14.21 13.93 0.30 2.18

of which India 4.73 5.03 4.75 4.49 5.14 4.85 0.12 2.57Latin America 6.53 6.36 6.58 6.83 6.49 6.57 0.04 0.62

Middle East 8.12 8.25 7.90 8.64 7.95 8.18 0.06 0.78

Africa 4.33 4.45 4.42 4.36 4.50 4.43 0.10 2.31

Total DCs 32.62 32.97 32.87 33.49 33.14 33.12 0.50 1.53

FSU 4.82 4.75 4.74 5.02 5.11 4.91 0.09 1.82

Other Europe 0.74 0.75 0.71 0.75 0.84 0.76 0.02 2.69

China 12.71 12.63 13.19 12.98 13.43 13.06 0.35 2.73

Total "Other regions" 18.27 18.13 18.64 18.75 19.38 18.73 0.45 2.49

Total world 98.82 98.76 98.76 100.69 100.95 99.80 0.98 0.99

Previous estimate 98.82 98.76 98.76 100.69 100.95 99.80 0.98 0.99

Revision 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00


Change 2019/18

Totals may not add up due to independent rounding.Note: * 2019 = Estimate.

World Oil Demand

32 OPEC Monthly Oil Market Report – December 2019

Table 4 - 2: World oil demand in 2020*, mb/d

OECD

OECD Americas

US

US oil demand growth returned to positive territory in September 2019, according to the latest monthly data from the Energy Information Administration (EIA) and following y-o-y declines in August 2019. September 2019 oil requirements grew by 0.14 mb/d y-o-y, mainly supported by demand growth for petroleum products at the light end of the barrel, LPG/NGLs.

Table 4 - 3: US oil demand, tb/d

2019 1Q20 2Q20 3Q20 4Q20 2020 Growth %

Americas 25.66 25.43 25.56 26.19 26.18 25.84 0.18 0.69

of which US 20.90 20.85 20.80 21.37 21.17 21.05 0.15 0.71Europe 14.30 13.94 14.20 14.66 14.28 14.27 -0.03 -0.21

Asia Pacific 7.99 8.37 7.56 7.66 8.05 7.91 -0.08 -0.99

Total OECD 47.95 47.73 47.31 48.51 48.51 48.02 0.07 0.14

Other Asia 13.93 14.27 14.32 14.04 14.60 14.31 0.37 2.66

of which India 4.85 5.20 4.90 4.65 5.32 5.02 0.16 3.39Latin America 6.57 6.44 6.66 6.91 6.56 6.64 0.07 1.14

Middle East 8.18 8.30 7.95 8.72 8.04 8.25 0.07 0.86

Africa 4.43 4.53 4.52 4.46 4.59 4.52 0.09 2.00

Total DCs 33.12 33.54 33.44 34.12 33.79 33.73 0.60 1.82

FSU 4.91 4.83 4.81 5.11 5.19 4.99 0.08 1.65

Other Europe 0.76 0.76 0.72 0.76 0.85 0.77 0.01 1.54

China 13.06 12.91 13.50 13.28 13.77 13.37 0.31 2.37


Total world 99.80 99.78 99.79 101.78 102.12 100.88 1.08 1.08


Revision 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Source: OPEC Secretariat. Totals may not add up due to independent rounding.

Change 2020/19

Note: * 2019 = Estimate and 2020 = Forecast.

Sep 19 Sep 18 tb/d %

LPG 2,829 2,724 105 3.9

Naphtha 225 251 -26 -10.4

Gasoline 9,169 9,153 16 0.2

Jet/kerosene 1,695 1,704 -9 -0.5

Diesel oil 3,915 4,022 -107 -2.7

Fuel oil 270 349 -79 -22.6

Other products 2,409 2,171 238 11.0

Total 20,512 20,374 138 0.7

Change 2019/18

Sources: US EIA and OPEC Secretariat.

World Oil Demand


Gasoline demand remained weak despite a low historical base for the same month in 2018, yet it was in line with shrinking light vehicle sales and amid slightly growing mileage – the latter data was, however, largely survey dependent and hence had a lower degree of accuracy. Gasoline demand seems to be underperforming in 2019, as fuel substitution, fuel efficiencies and changing driving patterns have resulted in substantially lower required volumes and declines in growth by approximately 0.2 mb/d as compared to historical norms. With the driving season over, gasoline demand growth was not a main factor behind US oil demand growth in 2019.

Graph 4 - 1: OECD Americas oil demand, y-o-y change

Graph 4 - 2: US gasoline demand, y-o-y change

Diesel, jet/kerosene and residual fuel oil demand continued to decline during September 2019 y-o-y. Data for nine months in 2019 show US oil demand slightly lower as compared to the same period last year.

NGL/LPG requirements, as feedstock for the petrochemical industry, and jet/kerosene are the petroleum product categories with rising demand; the overall losses result from shrinking requirements for all other petroleum categories.

October 2019 demand estimates, which are based on preliminary weekly data, show an increase of around 2.4% y-o-y, with NGL/LPG, jet/kerosene and distillate requirements rising but being partly offset by disappointing gasoline and residual fuel oil demand.

For November 2019, month-to date data imply similar growth of around 2.9% y-o-y. These preliminary data imply that US oil demand will most likely be solid throughout the remainder of 2019, with industrial and, to some extent, also transportation fuels dominating the implied growth share.

The US is projected to again remain the main contributor to 2020 OECD oil demand growth, with the overall risks being balanced to the upside and downside. Anticipated economic growth is the fundamental indicator pointing to the upside, while fuel substitution, vehicle efficiencies, as well as trade-related disputes with China and other entities are factors that may push oil demand to the downside.

Canada

In Canada, September 2019 came up increasing y-o-y. Gains in LPG and jet kerosene demand have been partly offset by declines in required naphtha and gasoline. The prospects for 2020 Canadian oil demand are positive, mainly as a result of a growing economy; some existing downside risks relate to vehicle efficiencies and fuel substitution.

-0.2

0.0

0.2

0.4

0.6

0.8

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

1Q

20*

2Q

20*

3Q

20*

4Q

20*

mb/d

Note: * 4Q19-4Q20 = Forecast.Source: OPEC Secretariat.

-400

-300

-200

-100

0

100

200

300

Se

p 1

8

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

tb/d


World Oil Demand


Mexico

Mexican oil demand shrank for another month in October 2019, dropping by 5.1% y-o-y, for the fifth month in the current year and the second consecutive month. The bulk of oil demand losses during October 2019 originated in diesel, gasoline and residual fuel oil requirements, as a result of weaker economic growth and increasing fuel substitution. The risks for 2020 Mexican oil demand are skewed to the downside, to a large extent, as a result of anticipated fuel substitution in the industrial and transportation sectors.

In 2019, OECD Americas oil demand is expected to grow by 0.12 mb/d as compared to 2018. 2020 OECD Americas oil demand is projected to increase by 0.18 mb/d y-o-y.

OECD Europe

September 2019 data showed growing European oil demand growth y-o-y following declines during August 2019. During September 2019, the oil requirements for some main oil consuming countries in the region France, Turkey, and the Netherlands were growing y-o-y; oil demand declines in Germany, the UK, Spain and other countries have partly offset overall oil demand growth in the region.

Graph 4 - 3: OECD Europe’s oil demand, y-o-y change

Graph 4 - 4: UK diesel demand, y-o-y change

Y-t-d in 2019, OECD Europe oil demand is expected to grow by 0.6% y-o-y; gains originate in additional gasoline, jet/kerosene and diesel requirements in the transportation, industrial and residential sectors, while y-t-d demand for LPG, naphtha and residual fuel fell as compared to the same period of last year. Y-t-d, the momentum in auto sales shows declines as compared to the same period during last year, yet following solid increases in previous years.

Early indications for October 2019 showed gains in oil demand of approximately 0.06 mb/d, 0.07 mb/d and 0.01 mb/d in Germany, France and Italy, respectively, while oil requirements in the UK fell y-o-y by 0.02 mb/d.

-0.1

0.0

0.1

0.2

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

1Q

20*

2Q

20*

3Q

20*

4Q

20*

mb/d


-75

-50

-25

0

25

50

75

100

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

tb/d

Sources: Joint Organisations Data Initiative, UK Department forBusiness, Energy & Industrial Strategy and OPEC Secretariat.

World Oil Demand


Table 4 - 4: Europe Big 4* oil demand, tb/d

The outlook for European oil demand during 2020 points to mild declines y-o-y with risks being skewed to the downside. 2020 European oil demand faces many uncertainties, which concern the region’s high historical oil demand baseline, fuel efficiencies and substitution, as well as challenges in relation to unsolved debt and other geopolitical issues.

OECD Europe oil demand is projected to flatten in 2019, while 2020 oil demand in the region is anticipated to decline by 0.03 mb/d as compared to 2019.

OECD Asia Pacific

Japan

Preliminary October 2019 data imply that oil demand in Japan dropped by 0.28 mb/d y-o-y for the fourth consecutive month and saw its ninth monthly y-o-y decline so far in 2019.

Table 4 - 5: Japan’s domestic sales, tb/d

All main product categories were in negative territory y-o-y, notably for LPG, naphtha, gasoline and jet/kerosene. Declines have also been eminent in crude and residual fuel oil for the power generation sector, mainly as a result of fuel substitution programs.

Oct 19 Oct 18 tb/d %

LPG 493 399 94 23.5

Naphtha 542 575 -33 -5.7

Gasoline 1,135 1,131 4 0.3

Jet/kerosene 863 870 -7 -0.8

Diesel oil 3,503 3,397 106 3.1

Fuel oil 199 220 -21 -9.8

Other products 658 675 -17 -2.6

Total 7,392 7,267 125 1.7

Sources: JODI, UK Department for Business, Energy & Industrial Strategy, Unione Petrolifera and OPEC Secretariat.

Change 2019/18

Note: * Germany, France, Italy and the UK.


LPG 282 328 -46 -14.0

Naphtha 727 796 -69 -8.7

Gasoline 799 834 -35 -4.2

Jet/kerosene 360 432 -72 -16.6

Diesel oil 754 774 -20 -2.6

Fuel oil 246 277 -31 -11.2


Total 3,499 3,779 -280 -7.4

Change 2019/18

Sources: JODI, Ministry of Energy and Trade and Industry of Japan and OPEC Secretariat.

World Oil Demand


Graph 4 - 5: OECD Asia Pacific oil demand, y-o-y change

Graph 4 - 6: Japan’s LPG and naphtha demand, y-o-y change

Declining overall Japanese oil demand y-t-d in 2019 stems largely from developments related to the country’s main economic indicators and is expected to continue during 2020, with forecasts being skewed further to the downside; efficiencies and fuel substitution are the dominating factors towards the downside, while oil use in the industrial sector may soften expected overall losses.

South Korea

In South Korea, September 2019 oil demand declined for the first time during the last three months. LPG usage in the industrial and transportation sectors took the lion’s share of gains, while declining oil requirements in all other main petroleum product categories more than offset gains.

The outlook for South Korean oil demand during 2020 is positive with risks skewed to the upside, in line with anticipated economic growth, expansions in the country’s petrochemical industry and the low 2019 baseline.

Australia

With available data up to September 2019, y-t-d oil demand in Australia appears flat, showing practically the same levels as compared to the same period last year.

New Zealand

In New Zealand, the smallest oil consuming country in the region, oil demand grew y-t-d by 3.4% y-o-y, with gasoline and diesel being the products with the largest requirement growth.

OECD Asia Pacific oil demand is estimated to decline by 0.09 mb/d in 2019 and expected to fall by 0.08 mb/d y-o-y in 2020.

Non-OECD

China

Chinese oil demand rose in October 2019 by around 0.35 mb/d y-o-y after rising by around 0.22 mb/d y-o-y in September 2019.

Total petroleum product demand reached around 13.2 mb/d in October. Oil demand growth was determined by rising jet/kerosene, naphtha and diesel.

-0.3

-0.2

-0.1

0.0

0.1

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

1Q

20*

2Q

20*

3Q

20*

4Q

20*

mb/d


-100

0

100

200

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

tb/d

LPG Naphtha

Sources: Ministryof Economy Trade and Industry of Japan, Joint Organisations Data Initiative and OPEC Secretariat.

World Oil Demand


Jet/kerosene added around 0.11 mb/d y-o-y in October in line with positive air traffic data. Air passenger traffic increased more than 5.0% during the Golden Week, which is in comparison to a nearly 9% increase during the same month last year, depicting slower consumer spending.

Naphtha demand growth hovered around 0.06 mb/d y-o-y in October 2019 amid solid naphtha margins mainly during the first half of the month. Naphtha performance has been very steady with an average increase of 5.5% y-o-y so far in 2019.

Diesel oil gained momentum in October after more than 20 months of consecutive declines, adding around 0.07 mb/d y-o-y.

Graph 4 - 7: Changes in China’s apparent oil demand, y-o-y change

The product was supported by increases in mining and coal production, which boosted trucking activity as a result.

Gasoline demand declined for the second consecutive month amid continued weakness in vehicle sales data. Vehicle sales decreased by more than 4% y-o-y during the month of October, according to the China Passenger Car Association. Those declines came in line with dropping sales of sedans and minivans, which shed around 11% and 13% y-o-y respectively and despite positive gains for Sport Utility Vehicles (SUVs), which added around 2.0% y-o-y and Multipurpose Vehicles (MPVs), which added more than 9% y-o-y. Gasoline consumption dropped by 0.02 mb/d y-o-y in October 2019.

Graph 4 - 8: China’s gasoline and diesel demand growth, y-o-y change

The overall 2019 and 2020 outlooks are unchanged since last month’s MOMR. In 2019, oil demand growth is projected to be slightly slower than 2018 as economic activities cooled down as compared to last year. Vehicle sales and slower manufacturing activity have also impacted petroleum product demand during the current year. In 2020, oil demand is projected to slow further in China as compared to the current year largely in line with lower economic projections as compared to the current year. Additionally, a continuation of fuel quality programs targeting fewer emissions as well as on going fuel substitution with natural gas and coal are assumed in the 2020 projections.

China’s oil demand is anticipated to grow by 0.35 mb/d in 2019 and by 0.31 mb/d in 2020.

Other Asia

India

In October 2019, Indian oil demand declined by 0.07 mb/d y-o-y. Middle and heavy distillates lost ground primarily in light of the extended effects of the heavy monsoon season, which is limiting demand for transportation and industrial fuels.

0.2

0.3

0.4

0.5

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

1Q

20*

2Q

20*

3Q

20*

4Q

20*

mb/d


-300

-200

-100

0

100

200O

ct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

tb/d

Gasoline Diesel

Sources: Facts Global Energy, China OGP (Xinhua News Agency), Argus Global Markets, JODI, National Bureau of Statistics, Chinaand OPEC Secretariat.

World Oil Demand


Table 4 - 6: India’s oil demand, tb/d

On the other hand, LPG requirements increased by more than 0.12 mb/d y-o-y due to the government’s policy to support LPG household consumption as an alternative to other fuels.

Additionally, gasoline consumption picked up during the month of October, adding around 0.06 mb/d y-o-y, despite dwindling y-t-d vehicle sales data. However, in October, vehicle sales reversed this trend and improved slightly, with sales of passenger vehicles adding around 0.3% y-o-y despite weak overall auto sales in 2019. Diesel demand plummeted by as much as 0.11 y-o-y in October, dropping for the third consecutive month, mainly as a result of the extended monsoon season, which limited demand in the industrial and transportation sector in addition to a significant slowdown in commercial vehicle sales in 2019.

Graph 4 - 9: Other Asia’s oil demand, y-o-y change

Graph 4 - 10: India’s gasoline demand, y-o-y change

Jet/kerosene declined by 0.04 mb/d y-o-y as demand for jet fuel was outweighed by declines in household kerosene requirements for cooking.

Y-t-d, Indian oil demand growth remains well below last year’s average level during the same period, by 0.16 mb/d, mainly as a result of slower road construction activity, which curtailed demand for asphalt during 2Q19 as well as the heavy monsoon season, which impacted demand growth for various petroleum products during 3Q19.

Thailand

Rising Thailand’s diesel and gasoline requirements in 2019, with data up to September, have been marginally counterbalanced by declining naphtha and residual fuel oil demand, mainly as a result of slower-than-expected manufacturing activity.

Oil demand growth has been stable in 2019, adding 0.02 mb/d so far this year.


LPG 939 821 118 14.3

Naphtha 263 318 -55 -17.2

Gasoline 720 662 59 8.9

Jet/kerosene 267 302 -36 -11.8

Diesel oil 1,402 1,513 -111 -7.3

Fuel oil 279 329 -51 -15.3

Other products 594 584 10 1.7

Total 4,464 4,530 -66 -1.4

Sources: JODI, Petroleum Planning and Analysis Cell of India and OPEC Secretariat.

Change 2019/18

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

1Q

20*

2Q

20*

3Q

20*

4Q

20*

mb/d


0

10

20

30

40

50

60

70

80

90

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

tb/d

Sources: OPEC Secretariat, and Petroleum Planning and Analysis Cell of India.

World Oil Demand


Indonesia

In Indonesia, in cumulative terms, oil demand has grown by around 0.04 mb/d in 2019 with data up to September amid rising industrial and transportation fuels. Demand in all of the main petroleum categories was in positive territory with the exception of jet/kerosene and residual fuel oil.

With a few monthly data points still remaining in 2019, oil demand in Other Asia is anticipated to post positive gains but remains lower than last year’s growth levels. Going forward, oil demand is expected to find some support from year’s end petrochemical feedstock demand as well as a possible rebound in Indian demand after slow 3Q data largely due to the heavy monsoon season. In 2020, anticipated improvements in economic conditions are projected to support middle distillate demand, particularly in manufacturing and industrial activity, whereas the transportation sector is projected to provide support for gasoline and jet fuel requirements in 2020.

Oil demand in the region is projected to rise by 0.30 mb/d in 2019 and by around 0.37 mb/d in 2020.

Latin America

Brazil

Oil demand in Brazil increased by a solid 0.13 mb/d y-o-y in October 2019. Total oil demand in the country hovered around 2.88 mb/d in October.

Table 4 - 7: Brazil’s oil demand*, tb/d

Most products, particularly diesel and gasoline, registered gains with the exception of jet/kerosene. Gasoline consumption increased for the fourth consecutive month and for the fifth time this year, adding nearly 0.06 mb/d y-o-y in October, the highest monthly gain in 2019. This is despite higher retail prices as compared to ethanol, which theoretically reduces gasoline advantage to ethanol as prices remained favouring ethanol. However, the exceptionally low base line of total gasoline demand during the same month last year and the higher base for ethanol has positively affected demand growth for gasoline. Total demand for gasoline reached 0.68 mb/d in October.

Ethanol, in contrast, was flat y-o-y as total demand for the product reached nearly 0.42 mb/d, the second highest on record. Diesel gained momentum during the month of October, increasing by 0.07 mb/d y-o-y. This increase occurred in line with higher industrial output in various sectors. Brazil’s manufacturing PMI, as reported by IHS Markit, registered 52.2 points, remaining in positive territory for the third consecutive month and for the tenth time so far in 2019.


LPG 234 229 5 2.2

Naphtha 147 146 1 0.7

Gasoline 675 620 55 8.8

Jet/kerosene 118 123 -5 -4.3

Diesel oil 1,099 1,026 72 7.1

Fuel oil 66 65 1 1.1


Total 2,875 2,748 127 4.6

Change 2019/18

Sources: JODI, Agencia Nacional do Petroleo, Gas Natural e Biocombustiveis and OPEC Secretariat.Note: * = Inland deliveries.

World Oil Demand


Graph 4 - 11: Latin America’s oil demand, y-o-y change

Graph 4 - 12: Brazil’s gasoline demand, y-o-y change

Argentina

In Argentina, demand has increased for the second consecutive month as all petroleum products recorded steady gains. Oil demand increased by 0.03 mb/d y-o-y during the month of September 2019, registering the second highest level of monthly growth in 2019.This is despite economic woes within the country. On a cumulative basis, 2019 oil demand growth recorded declines y-o-y of around 0.04 mb/d. Product categories showing positive demand growth figures were naphtha and jet/kerosene, while gasoline, LPG, diesel and residual fuel oil incurred declines.

Ecuador

In Ecuador, oil demand decreased during October, dropping by 0.03 mb/d y-o-y. Those declines were led by dropping demand for diesel, gasoline and residual fuel oil, while jet/kerosene and LPG were the only products in positive territory.

For the rest of 2019 and 2020, expectations for oil demand growth in Latin America are similar to last month’s projections with a better economic outlook in 2020 as compared to 2019, supporting better oil demand growth projections. Oil demand growth should be supported by demand for transportation fuels as well as industrial fuels. Most of the gains in oil demand growth are anticipated to come from Brazil as it remains the region’s largest consumer of petroleum products.

Oil demand growth in the region is projected to increase by 0.04 mb/d in 2019 and by 0.07 tb/d in 2020.

Middle East

Saudi Arabia

In the Middle East, oil demand requirements registered solid gains during the month of October with oil demand in Saudi Arabia increasing sharply for the fourth straight month. Oil demand has now improved in six out of ten months in 2019 in Saudi Arabia, impacting total Middle East oil demand positively, mainly in 2H19. The improvement in oil requirements in Saudi Arabia stems primarily from continued increases in the consumption of industrial fuels direct crude for burning and diesel.

Looking at the product mix, in addition to industrial fuels, jet/kerosene and gasoline were also in the positive, while residual fuel oil declined y-o-y. Direct crude for burning and diesel were supported by additional power generation consumption and a progressing construction sector as the recovering economy was encouraged by the low base line of comparison during the same month last year.

-0.1

0.0

0.1

0.2

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

1Q

20*

2Q

20*

3Q

20*

4Q

20*

mb/d


-150

-100

-50

0

50

100

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

tb/d

Sources: Agencia Nacional do Petroleo, Gas e Biocombustiveis of Brazil, Joint Organisations Data Initiative and OPEC Secretariat.

World Oil Demand


Graph 4 - 13: Middle East oil demand, y-o-y change Graph 4 - 14: Saudi Arabia’s crude direct use, y-o-y change

In cumulative terms, with data up to October, oil demand in Saudi Arabia has increased, only to reach a growth level of around 0.04 mb/d as compared to the same period in 2018. The improvement in power generation and desalination plant fuels led to a decent increase in the overall consumption of the country. However, this level of growth remains lower than the historical oil demand growth average of around 0.12 tb/d seen in the periods prior to 2016. Replacing direct crude for power generation with natural gas in addition to the economic reforms within the country have contributed to the slower-than-expected oil demand picture over the recent past.

Iraq

In October 2019, oil demand growth in Iraq flipped into positive territory after six months of declines, as data indicated a steady increase of around 0.03 mb/d from the levels seen in October 2018.

Total product consumption is assumed at 0.76 mb/d. All product categories saw positive performances apart from residual fuel oil, which declined mainly as a result of displacement with other fuels. Residual fuel oil dropped by 0.05 mb/d y-o-y.

Graph 4 - 15: Iraq’s crude direct use, y-o-y change

Other countries in the region

Oil demand increased in Kuwait, particularly in relation to petrochemical feedstock as well as transportation fuels. Oil demand increased by a solid 0.13 mb/d in September 2019, as compared to the same month in 2018.

A similar trend was observed in the UAE, where gains were recorded across the barrel.

For the rest of 2019 and 2020, Middle East oil demand growth is expected to be challenged by many aspects, mostly related to geopolitical issues and economic transformation policies, including subsidy reduction programs. Oil demand is anticipated to rise in Saudi Arabia, Iraq, the UAE and Kuwait in 2020. Transportation fuels, particularly gasoline, and industrial fuels, predominantly diesel and residual fuel oil, are projected to play a significant part in the total oil demand growth of the region. Oil demand growth in the Middle East is anticipated to increase by 0.06 mb/d in 2019 and by 0.07 mb/d in 2020.

-0.2

-0.1

0.0

0.1

0.2

0.3

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

1Q

20*

2Q

20*

3Q

20*

4Q

20*

mb/d


-150

-100

-50

0

50

100

150

200

250

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

tb/d

Sources: Joint Organisations Data Initiative, direct communication and OPEC Secretariat.

-200

-150

-100

-50

0

50

100

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

tb/d

Sources: Joint Organisations Data Initiative, direct communication and OPEC Secretariat.

World Oil Supply


World Oil Supply

The non-OPEC oil supply growth estimate for 2019 remained unchanged at 1.82 mb/d, for an annual average of 64.30 mb/d. The downward revisions to production data from the UK, other OECD Europe, India and Indonesia were fully offset by upward production adjustments in Thailand and Russia. US liquids output in 3Q19 was revised up due to higher-than-expected output in September. In contrast, the supply forecast for 4Q19 was revised down by 75 tb/d. Hence, the expected y-o-y growth of 1.62 mb/d remained unchanged. The US, Brazil, China, Canada, Australia and the UK are forecast to be the key drivers of growth in 2019, while Mexico and Norway are expected to experience the largest declines.

The non-OPEC oil supply growth forecast for 2020 also remained unchanged from last month’s assessment and will grow by 2.17 mb/d for an average of 66.46 mb/d. The upward revision in the UK oil supply forecast was offset by a downward revision in Russia’s supply. The US, Brazil, Norway, Canada, Australia, Russia and Kazakhstan are expected to be the main growth drivers for next year, while Mexico, Indonesia, Egypt and Colombia are forecast to see the largest declines. The 2020 non-OPEC supply forecast remains subject to many uncertainties, mainly the trend of investment discipline by US independents, the timing of debottlenecking of pipeline constraints in Canada, drilling and completion activity in the US, and Mexico’s efforts to overcome natural decline.

OPEC NGL production in 2019 is expected to grow by 0.04 mb/d to average 4.80 mb/d. In 2020, OPEC NGLs are forecast to grow by 0.03 mb/d y-o-y to average 4.83 mb/d.

In November, OPEC crude oil production fell by 193 tb/d m-o-m to average 29.55 mb/d, according to secondary sources. Non-OPEC supply, including OPEC NGLs, rose by 0.61 mb/d m-o-m, to average 70.22 mb/d, up by 1.28 mb/d y-o-y.

As a result, preliminary data indicates that global oil supply increased in November by 0.41 mb/d m-o-m to average 99.78 mb/d.

Table 5 - 1: Non-OPEC supply forecast comparison in 2019–2020*, mb/d

Change Change2019 2019/18 2020 2020/19

OECD Americas 25.65 1.57 27.13 1.48

OECD Europe 3.73 -0.11 3.93 0.19

OECD Asia Pacific 0.48 0.07 0.55 0.07

Total OECD 29.87 1.54 31.61 1.74

Other Asia 3.43 -0.13 3.39 -0.04

Latin America 5.39 0.20 5.64 0.25

Middle East 3.21 0.00 3.25 0.04

Africa 1.54 0.04 1.57 0.03

Total DCs 13.57 0.11 13.85 0.27

FSU 14.35 0.06 14.44 0.09

Other Europe 0.12 0.00 0.12 -0.01

China 4.10 0.09 4.12 0.02

Non-OPEC production 62.02 1.79 64.13 2.11

Processing gains 2.28 0.03 2.33 0.05

Non-OPEC supply 64.30 1.82 66.46 2.17


Region

World Oil Supply


Monthly main revisions to the non-OPEC supply growth forecast

Non-OPEC supply in 2019 is estimated to grow by 1.82 mb/d, unchanged for the second consecutive month despite having few upward and downward revisions in supply from the previous assessment, and is expected to average 64.30 mb/d for the year.

The US supply growth estimate remained unchanged at annual growth of 1.62 mb/d compared to last month’s assessment, despite the upward revision in 3Q19 following higher than expected output in September. The supply forecast for 4Q19 was revised down by 75 tb/d to average 18.87 mb/d.

Canada’s oil production growth also remained unchanged at 0.10 mb/d on a yearly basis, as actual production levels in 3Q19 were revised up by 17 tb/d, while 4Q19 was revised down by 30 tb/d due to expected lower output resulting from ongoing production curtailments in Alberta.

The UK oil supply estimate for 4Q19 was revised down by 64 tb/d, following lower-than-expected oil output in October. Estimated annual growth was revised down by 0.02 mb/d to average 0.05 mb/d.

Despite downward revisions in actual oil production data of India and Indonesia by 5 tb/d and 6 tb/d, respectively, in 3Q19, annual growth remained unchanged in these two countries.

Finally, following higher-than-expected oil output in October and November in Russia, production in 4Q19 was revised up by 70 tb/d to average 11.41 mb/d. This led to an upward revision in annual growth for Russia by 0.02 mb/d to average 0.08 mb/d for 2019 (Graph 5 - 1).

Graph 5 - 1: Monthly oil market report Dec 19/Nov 19 revisions in 2019* annual supply changes

Graph 5 - 2: Monthly oil market report Dec 19/Nov 19 revisions in 2020* annual supply changes

Non-OPEC supply in 2020 is forecast to grow by 2.17 mb/d, unchanged from the previous month’s assessment, and is expected to average 66.46 mb/d for the year.

The upward revision in the UK by 14 tb/d offset by downward revision of 18 tb/d in Russia (Graph 5 - 2).

-14

-2

-1

-1

3

18

-20 0 20

UK

Indonesia

India

Canada

Thailand

Russia

tb/d

Note: * 2019 = Estimate.Source: OPEC Secretariat.

-18

-3

1

1

2

14

-20 -10 0 10 20

Russia

Thailand

Canada

India

Indonesia

UK

tb/d

Note: * 2020 = Forecast.Source: OPEC Secretariat.

World Oil Supply


Graph 5 - 3: Non-OPEC quarterly liquids supply and Dated Brent

Graph 5 - 4: Non-OPEC quarterly oil supply

Non-OPEC oil supply in 2019 and 2020

Table 5 - 2: Non-OPEC oil supply in 2019*, mb/d

30

40

50

60

70

80

52

56

60

64

68

721

Q

2Q

3Q

4Q

1Q

2Q

3Q

4Q

*

1Q

*

2Q

*

3Q

*

4Q

*

2018 2019 2020

US$/bmb/d

Non-OPEC supply (LHS) Brent Dated (RHS)


61

.27

61

.66

62

.81 64

.12

63

.80

63

.81

64

.25

65

.31

65

.82

66

.09

66

.46

67

.49

58

60

62

64

66

68

1Q

2Q

3Q

4Q

1Q

2Q

3Q

4Q

*

1Q

*

2Q

*

3Q

*

4Q

*

2018 2019 2020

mb/d


2018 1Q19 2Q19 3Q19 4Q19 2019 Growth %

Americas 24.08 25.07 25.59 25.71 26.22 25.65 1.57 6.53

of which US 16.71 17.78 18.29 18.38 18.87 18.33 1.62 9.69Europe 3.84 3.84 3.61 3.59 3.88 3.73 -0.11 -2.77

Asia Pacific 0.41 0.43 0.48 0.51 0.51 0.48 0.07 18.11

Total OECD 28.33 29.34 29.68 29.81 30.62 29.87 1.54 5.43

Other Asia 3.56 3.51 3.46 3.32 3.42 3.43 -0.13 -3.58

Latin America 5.19 5.17 5.25 5.53 5.60 5.39 0.20 3.79

Middle East 3.21 3.22 3.22 3.22 3.20 3.21 0.00 0.09

Africa 1.50 1.51 1.51 1.53 1.61 1.54 0.04 2.40

Total DCs 13.46 13.41 13.44 13.60 13.83 13.57 0.11 0.81

FSU 14.29 14.55 14.16 14.34 14.37 14.35 0.06 0.44

of which Russia 11.35 11.53 11.36 11.42 11.41 11.43 0.08 0.73Other Europe 0.12 0.12 0.12 0.12 0.12 0.12 0.00 -2.34

China 4.02 4.10 4.13 4.10 4.09 4.10 0.09 2.17


Total non-OPEC

production 60.22 61.52 61.53 61.98 63.03 62.02 1.79 2.98

Processing gains 2.25 2.28 2.28 2.28 2.28 2.28 0.03 1.24

Total non-OPEC supply 62.47 63.80 63.81 64.25 65.31 64.30 1.82 2.92


Revision 0.00 0.00 0.00 0.07 -0.08 0.00 0.00 0.00


Change 2019/18

Totals may not add up due to independent rounding.Note: * 2019 = Estimate.

World Oil Supply


Graph 5 - 5: Annual supply changes for selected countries in 2019*

Graph 5 - 6: Annual supply changes for selected countries in 2020*

Table 5 - 3: Non-OPEC oil supply in 2020*, mb/d

-0.15

-0.14

-0.04

0.06

0.07

0.08

0.09

0.10

0.19

1.62

-0.5 0.0 0.5 1.0 1.5 2.0

Mexico

Norway

Malaysia

UK

Australia

Russia

China

Canada

Brazil

US

mb/d

Non-OPEC supply growth

2019/181.82 mb/d

Note: * 2019 = Estimate.Source: OPEC Secretariat.

-0.13

-0.03

-0.03

-0.03

0.07

0.07

0.10

0.21

0.29

1.50

-0.5 0.0 0.5 1.0 1.5 2.0

Mexico

Indonesia

Thailand

Egypt

Russia

Australia

Canada

Norway

Brazil

US

mb/d

Non-OPEC supply growth

2020/192.17 mb/d

Note: * 2020 = Forecast.Source: OPEC Secretariat.

2019 1Q20 2Q20 3Q20 4Q20 2020 Growth %

Americas 25.65 26.64 26.92 27.34 27.62 27.13 1.48 5.76

of which US 18.33 19.23 19.82 20.03 20.25 19.84 1.50 8.21Europe 3.73 3.95 3.81 3.83 4.11 3.93 0.19 5.16

Asia Pacific 0.48 0.54 0.53 0.57 0.57 0.55 0.07 14.89

Total OECD 29.87 31.13 31.26 31.73 32.30 31.61 1.74 5.83

Other Asia 3.43 3.38 3.39 3.39 3.39 3.39 -0.04 -1.22

Latin America 5.39 5.62 5.59 5.60 5.74 5.64 0.25 4.61

Middle East 3.21 3.21 3.25 3.26 3.28 3.25 0.04 1.11

Africa 1.54 1.58 1.57 1.57 1.56 1.57 0.03 2.02

Total DCs 13.57 13.78 13.80 13.82 13.98 13.85 0.27 2.01

FSU 14.35 14.32 14.44 14.36 14.64 14.44 0.09 0.60

of which Russia 11.43 11.34 11.50 11.51 11.64 11.50 0.07 0.61Other Europe 0.12 0.12 0.12 0.12 0.11 0.12 -0.01 -4.32

China 4.10 4.12 4.13 4.10 4.13 4.12 0.02 0.46


Total non-OPEC

production 62.02 63.49 63.75 64.12 65.15 64.13 2.11 3.41

Processing gains 2.28 2.33 2.33 2.33 2.33 2.33 0.05 2.37

Total non-OPEC supply 64.30 65.82 66.09 66.46 67.49 66.46 2.17 3.37


Revision 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Note: * 2019 = Estimate and 2020 = Forecast. Totals may not add up due to independent rounding.Source: OPEC Secretariat.

Change 2020/19

World Oil Supply


OECD

Following robust growth of 2.62 mb/d in 2018, OECD oil supply in 2019 is estimated to grow by 1.54 mb/d y-o-y and average 29.87 mb/d, unchanged from last month's assessment. OECD Americas and Asia Pacific are forecast to grow by 1.57 mb/d and 0.07 mb/d, respectively, while OECD Europe was revised down by 18 tb/d and now is forecast to decline by 0.11 mb/d.

For 2020, yearly growth was revised up by 19 tb/d to 1.74 mb/d and average 31.61 mb/d. OECD Americas, Europe and Asia Pacific are forecast to grow by 1.48 mb/d, 0.19 mb/d and 0.07 mb/d, respectively.

OECD Americas

US

US liquids output in September (excluding processing gains) showed an increase of 0.28 mb/d m-o-m to average 18.82 mb/d, up by 1.36 mb/d y-o-y, while crude oil output increased by 0.07 mb/d m-o-m to average 12.46 mb/d, higher by 965 tb/d y-o-y. Production of NGLs in September was up by 0.26 mb/d m-o-m to average 4.99 mb/d, higher by 0.35 mb/d y-o-y. Preliminary indications show that the output of other non-conventional liquids, mainly ethanol, was down in September by 45 tb/d m-o-m to average 1.37 mb/d, but was higher by 41 tb/d compared to a year ago.

The EIA’s latest US monthly production information for September 2019 showed a mild increase of 66 tb/d for crude oil production (including lease condensate) to average 12.46 mb/d, compared to the previous month’s robust increase of 574 tb/d (revised down by 25 tb/d by the EIA). Onshore Lower 48 production in September grew by 109 tb/d m-o-m, primarily due to increasing production from Texas and New Mexico (totalling 93 tb/d).

Crude oil output increased on the West Coast (PADD 5), mainly in Alaska (+67 tb/d); in the Rocky Mountains (PADD 4), mainly in Wyoming (+10 tb/d); in the Midwest (PADD 2), primarily in Oklahoma (+43 tb/d); and on the East Coast (PADD 1), primarily in West Virginia. On the Gulf Coast (PADD 3), total production – despite increasing output in onshore fields, particularly in Texas and New Mexico – declined by 114 tb/d m-o-m in the GoM to average 1,895 tb/d.

Table 5 - 4: US crude oil production by state, tb/d Graph 5 - 7: US monthly crude oil production in 2017-2019 vs. weekly forecast in 2019

US crude oil production in 2019 is likely to grow by 1.20 mb/d y-o-y to average 12.19 mb/d. The share of tight crude, out of the forecast growth of 1.20 mb/d in 2019, is estimated at 1.16 mb/d, to average 7.67 mb/d; and for the GoM, it is 0.13 mb/d, averaging 1.89 mb/d. Conventional crude (non-shale), including Alaska’s production, is projected to decline by 0.10 mb/d, to average 2.63 mb/d.

ChangeState Aug 19 Sep 19 Sep 19/Aug 19

Alaska 382 449 67Colorado 521 514 -7Oklahoma 562 605 43New Mexico 935 956 21North Dakota 1,440 1,400 -40Federal Offshore -

Gulf of Mexico (GoM) 2,009 1,895 -114Texas 5,155 5,227 72

Total US crude oil

production 12,397 12,463 66


9.97

12.04

12.4612.84

8

9

10

11

12

13

14

Ja

n

Fe

b

Ma

r

Ap

r

Ma

y

Ju

n

Ju

l

Au

g

Se

p

Oct

Nov

Dec

mb/d

Monthly data 2017 Monthly data 2018

Monthly data 2019 Weekly data 2019*

Note: * 2019 = Estimate.Sources: US EIA and OPEC Secretariat.

World Oil Supply


US crude oil production in 2020 is forecast to grow by 1.02 mb/d y-o-y to average 13.20 mb/d. Judging by the current trend of decline in the US oil rig count and discipline in E&P spending by independents, US crude oil output, particularly from tight oil regions, will definitely be affected. Although the backlog of more than 6,000 drilled but uncompleted horizontal wells in tight oil regions provides support because of lower costs, crude production – despite the opening of new pipelines in the Permian Basin – is forecast to increase y-o-y by 0.89 mb/d from onshore fields to average 11.18 mb/d, and 0.13 mb/d from offshore fields in GoM to average 2.02 mb/d. Tight crude growth is forecast to slow to 0.97 mb/d for next year and average 8.64 mb/d. With regard to non-tight crude, Lower 48 onshore crude oil output is forecast to decline by around 0.09 mb/d to average 2.54 mb/d.

Graph 5 - 8: US monthly liquids supply by key component

Graph 5 - 9: US total liquids supply quarterly

US liquids supply in 2019 is estimated to average 18.33 mb/d, representing y-o-y growth of 1.62 mb/d, unchanged from the previous month’s assessment. Although the US liquids supply has been revised up by 75 tb/d in 3Q19, however this was offset by a downward revision to 4Q19.

Graph 5 - 10: US monthly crude oil supply Graph 5 - 11: US monthly total liquids supply

Besides expected y-o-y growth of 1.20 mb/d for crude oil, NGL production – mainly from unconventional sources of rich gas – is expected to grow by 0.42 mb/d to average 4.80 mb/d, while other liquids output, mainly biofuels, is estimated to remain unchanged from last year at 1.35 mb/d.

18.82

14

15

16

17

18

19

20

0

2

4

6

8

10

Se

p 1

8

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

mb/dmb/d

Tight crude Gulf of Mexico crude

Unconventional NGL Total supply

Source: US EIA and OPEC Secretariat.

15

.60

16

.24

17

.20

17

.78

17

.78

18

.29

18

.38

18

.87

19

.23

19

.82

20

.03

20

.25

16.71

18.33

19.84

10

12

14

16

18

20

22

1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q* 1Q* 2Q* 3Q* 4Q*

2018 2019 2020

mb/d

US quarterly production Annual average

Note: * 4Q19-4Q20 = Forecast.Sources: US EIA and OPEC Secretariat.

10.02

12.0411.86

12.70

12.7013.72

9

10

11

12

13

14

Ja

n

Fe

b

Ma

r

Ap

r

Ma

y

Ju

n

Ju

l

Au

g

Se

p

Oct

Nov

Dec

mb/d

2018 2019* 2020*


17.87

19.05

20.31

14

16

18

20

22

Ja

n

Fe

b

Ma

r

Ap

r

Ma

y

Ju

n

Ju

l

Au

g

Se

p

Oct

Nov

Dec

mb/d

2018 2019* 2020*


World Oil Supply


Table 5 - 5: US liquids production breakdown, mb/d

US tight crude output in September 2019 increased by an estimated 86 tb/d m-o-m to average 7.96 mb/d, an increase of 0.98 mb/d y-o-y according to preliminary estimates. The main m-o-m growth in US tight crude output from shale and tight formations through horizontal wells came from the Permian Midland as well as the Delaware basins in Texas, adding a total of 95 tb/d to average 3.86 mb/d.

Graph 5 - 12: US tight crude output breakdown Graph 5 - 13: US liquids production breakdown

Tight crude output in Eagle Ford declined by 7 tb/d to average 1.22 mb/d in September. Tight crude output from Bakken shale in North Dakota declined by 40 tb/d m-o-m, due to heavy seasonal rains and disruptions to completion operations, to average 1.41 mb/d. While production from Niobrara shale in Colorado fell to an average 0.53 mb/d, production from other tight plays, particularly in Oklahoma and Wyoming, rose by 43 tb/d in September m-o-m to average 0.94 mb/d.

For 2020, US tight crude and unconventional NGLs are forecast to continue to dominate non-OPEC supply growth. Due to ongoing spending discipline by independent companies as well as lower drilling activity, a slowdown in y-o-y growth is anticipated compared to 2019. This could lead producers to try to maintain production growth by completing drilled horizontal wells, but not drilled but uncompleted wells, in all tight oil regions to reduce costs.

Change Change Change2017 2018 2018/17 2019* 2019/18 2020* 2020/19

Tight crude 4.96 6.51 1.55 7.67 1.16 8.64 0.97Gulf of Mexico crude 1.68 1.76 0.08 1.89 0.13 2.02 0.13Conventional crude oil 2.71 2.72 0.01 2.63 -0.10 2.54 -0.09

Unconventional NGLs 3.02 3.60 0.57 3.98 0.40 4.43 0.45Conventional NGLs 0.76 0.77 0.01 0.81 0.02 0.83 0.02

Biofuels + Other liquids 1.27 1.35 0.08 1.35 0.00 1.37 0.02

US total supply 14.40 16.71 2.31 18.33 1.62 19.84 1.50

Note: * 2019 = Estimate and 2020 = Forecast.Sources: US EIA, Rystad Energy and OPEC Secretariat.

0

2

4

6

8

Se

p 1

7

Nov 1

7

Ja

n 1

8

Ma

r 1

8

Ma

y 1

8

Ju

l 18

Se

p 1

8

Nov 1

8

Ja

n 1

9

Ma

r 1

9

Ma

y 1

9

Ju

l 19

Se

p 1

9

mb/d

Permian Eagle Ford Bakken Niobrara Others

Souces: US EIA, Rystad Energy and OPEC Secretariat.

Sep 19Total = 7,955

0

5

10

15

20

25

200

6

200

7

200

8

200

9

201

0

201

1

201

2

201

3

201

4

201

5

201

6

201

7

201

8

201

9*

202

0*

mb/d

Tight crude Unconventional NGLs

Biofuels + Other liquids Conventional crude oil

Gulf of Mexico crude Conventional NGLs

Note: * 2019 = Estimate and 2020 = Forecast.Sources: US EIA, Rystad Energy and OPEC Secretariat.

World Oil Supply


Table 5 - 6: US tight oil production growth, mb/d

US rigs, wells and drilled-but-uncompleted wells (DUCs)

The overall US rig count declined by 276 units, or 26%, y-o-y to 799 rigs in the week ending 6 December. Out of the active 799 rigs, 777 were onshore and 22 were offshore. US oil rigs dropped by 214 units, or 24%, y-o-y to average 663 oil rigs (Graph 5 - 14).

US gas rigs dropped by 65 units, or 33%, y-o-y to 133 rigs. Total horizontal rigs (oil and gas) decreased by 238 units, or 26%, y-o-y to stand at 695 horizontal rigs.

With regard to drilling and completion (D&C) in all US shale plays, 951 wells were spudded in September 2019, down by 63 wells m-o-m, while 962 wells were completed in the same month, 193 fewer wells than completed in August. The number of completed wells in 3Q19 was down by 30 wells q-o-q to 3,179 wells (Graph 5 - 15).

Graph 5 - 14: US weekly oil rig count Graph 5 - 15: Spudded, completed and started wells in the US shale plays

The number of drilled horizontal oil wells in 3Q19 declined by around 6%, or 196 wells, to total 2,997 wells. By comparison, 14,236 horizontal oil wells were drilled in the US in 2014, while in 2018 the number declined to 11,814 wells. A total of 12,417 wells were completed in 2014, while in 2018 the total declined to 10,476 wells, although the productivity of these wells was higher than the wells completed in 2014 due to upgraded completion metrics. The total number of completed wells in the first three quarters of 2019 reached 8,893 wells, an increase of 1,124 wells y-o-y.

Shale play

tb/d Production

Y-o-y change Production

Y-o-y change Production

Y-o-y change

Permian tight 2.81 0.97 3.66 0.85 4.31 0.65Bakken shale 1.25 0.20 1.40 0.15 1.56 0.16Eagle Ford shale 1.18 0.09 1.22 0.04 1.26 0.04Niobrara shale 0.46 0.12 0.52 0.06 0.57 0.05Other tight plays 0.80 0.17 0.87 0.07 0.93 0.06

Total 6.51 1.55 7.67 1.16 8.64 0.97


2018 2019* 2020*

663

799

600

700

800

900

1,000

1,100

2 N

ov 1

8

30 N

ov 1

8

28 D

ec 1

8

25 J

an

19

22 F

eb 1

9

22 M

ar

19

18 A

pr

19

17 M

ay 1

9

14 J

un

19

12 J

ul 1

9

9 A

ug 1

9

6 S

ep 1

9

4 O

ct

19

1 N

ov 1

9

27 N

ov 1

9

Rigs

Week

US rig count: oil US rig count: total

Sources: Baker Hughes and OPEC Secretariat.

600

800

1,000

1,200

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Wells

Spudded wells Completed wells

Started wells

Sources: Rystad Energy and OPEC Secretariat.

World Oil Supply


In Graph 5 - 16, the US tight oil horizontal DUCs count development shows that the DUCs count has been decreasing in recent months.

Total DUCs count in March 2019 peaked at 6,404. Since then 289 DUCs have been taken from inventories across all regions, bringing the number to 6,115 in September.

Graph 5 - 16: US horizontal DUCs count by shale play

Canada

Canada’s liquids supply in August 2019 rose by 0.05 mb/d m-o-m to average 5.46 mb/d, according to official data, which is 0.08 mb/d lower than a year earlier. Non-conventional oil production increased by 20 tb/d m-o-m to average 3.04 mb/d in August, lower by 0.08 mb/d y-o-y, while conventional oil output declined by 30 tb/d m-o-m to average 1.22 mb/d.

Graph 5 - 17: Canada quarterly oil production Graph 5 - 18: Canada monthly production development by type

Alberta’s provincial government has exempted increases in conventional crude oil production from curtailment limits. With regard to the oil sands breakdown, while synthetic crude declined by 0.04 mb/d m-o-m, mainly attributed to the start of upgrader maintenance, production of bitumen rose by 0.06 mb/d to average 1.83 mb/d in August.

NGLs output in August also increased by 0.04 mb/d to average 1.15 mb/d. Synthetic crude production in September is estimated to have declined by 0.24 mb/d to average 0.97 mb/d, mainly due to the lower rate in Horizon and other upgraders. The preliminary 3Q19 production data at 5.40 mb/d shows that Canada’s liquids supply has gradually increased by 0.02 mb/d in every quarter since 1Q19.

Canada’s oil supply growth estimation in 2019 and forecast for 2020 remain unchanged at 0.10 mb/d, for each year.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Se

p 1

7

Nov 1

7

Ja

n 1

8

Ma

r 1

8

Ma

y 1

8

Ju

l 18

Se

p 1

8

Nov 1

8

Ja

n 1

9

Ma

r 1

9

Ma

y 1

9

Ju

l 19

Se

p 1

9

Wells

Permian Midland Permian DelawareEagle Ford BakkenNiobrara Others

Sources: Rystad Energy and OPEC Secretariat.

Sep 19Total = 6,115

5.54

5.36

5.62

4.6

4.8

5.0

5.2

5.4

5.6

5.8

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

1Q

20*

2Q

20*

3Q

20*

4Q

20*

mb/d

Note: 4Q19-4Q20 = Forecast.Sources OPEC Secretariat.

1.22

1.15

1.21

1.83

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

Au

g 1

8

Se

p 1

8

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

mb/d

Conventional crude NGLs

Synthetic crude Bitumen

Sources: National Energy Board and OPEC Secretariat.

World Oil Supply


Mexico

Mexico’s average liquids output in October 2019 fell by 0.02 mb/d m-o-m and averaged 1.92 mb/d, down by 0.07 mb/d y-o-y. Crude oil production declined by 28 tb/d m-o-m, due to planned maintenance at Ku-Maloob-Zaap (KMZ), to an average of 1.66 mb/d, and was down by 92 tb/d y-o-y. NGL output was up by 9 tb/d m-o-m to average 259 tb/d.

According to preliminary production data for November, output has increased m-o-m possibly due to the production start-up of the first project of 17 PEMEX priority fields – the 70 tb/d Xikin field - which should help to limit the estimated heavy annual decline. Oil output has increased since June 2019, mainly in Ku-Maloob-Zaap and other regions. Mexico’s liquids supply in 3Q19 increased q-o-q with an average of 1.93 mb/d. Mexico’s supply growth in 2019 is estimated to contract by 0.15 mb/d, y-o-y.

Graph 5 - 19: Mexico’s quarterly liquids supply Graph 5 - 20: Mexico’s monthly liquids and crude production by type

Half of the declines for 2020 are forecast from the Cantarell, Abkatún-Pol-Chuc and Tsimin-Xux projects. Part of the total annual decline will be offset by the new incremental production capacity that is coming on line next year, although this capacity is not so remarkable.

Overall, Mexico’s oil supply in 2020 will decline further by 0.13 mb/d to average 1.80 mb/d. This forecast is subject to change due to uncertainty regarding the implementation of new projects.

OECD Europe OECD Europe’s preliminary oil supply in October rose by 0.19 mb/d m-o-m, due to higher output in Norway, to average 3.69 mb/d, lower by 0.21 mb/d y-o-y.

For 2019, OECD Europe’s oil supply is forecast to see a contraction of 0.11 mb/d to average 3.73 mb/d, revised down by 0.02 mb/d following the lower UK supply forecast for 4Q19. The projected annual growth of 0.06 mb/d for the UK is expected to be offset by production declines in other countries, particularly Norway. North Sea oil production is forecast to see a gradual ramp-up from 4Q19 onward, owing to the start-up of Norway’s giant Johan Sverdrup field. Therefore, for 2020, total growth of 0.19 mb/d y-o-y and an average oil supply of 3.93 mb/d is forecast.

Graph 5 - 21: OECD Europe quarterly liquids supply

-237-212

-149

-7

-37-105

-144

-214

-300

-250

-200

-150

-100

-50

0

0

500

1,000

1,500

2,000

2,500

1Q 2Q 3Q 4Q

2019/18 (RHS) 2020/19 (RHS)2018 2019*2020*


Y-o-y change (tb/d)Production (tb/d)

1,750

1,800

1,850

1,900

1,950

2,000

2,050

0

200

400

600

800

1,000

1,200

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

tb/dtb/d

Heavy Light Extralight

NGL Total liquids

Sources: PEMEX and OPEC Secretariat.

3.2

3.4

3.6

3.8

4.0

4.2

1Q 2Q 3Q 4Q

mb/d

2018 2019* 2020*


World Oil Supply


While Norway’s output is forecast to grow by 0.21 mb/d, the UK’s and Denmark’s production is projected to decline by 0.01 mb/d each, while oil production in other OECD Europe will grow by 0.01 mb/d to average 0.73 mb/d.

Norway

Norwegian liquids supply in October rose by 0.27 mb/d m-o-m to average 1.83 mb/d. Average daily liquids production in October included 1.52 mb/d of crude oil and 0.31 mb/d of NGLs (including 30 tb/d of condensate).

According to the Norwegian Petroleum Directorate (NPD), oil production in October 2019 was 4.5% higher than the NPD's forecast, and 3.2% below the forecast so far this year. The main reason for the higher output in October was due to the early start-up of production in Johan Sverdrup, which was one month ahead of schedule. Moreover, liquids output for October 2019 was expected to rise as fields returned from maintenance, mainly in Ekofisk and in Gullfaks.

Despite lower NGLs output from the Troll field due to storage constraints, Norway’s NGLs output in October was boosted by 49 tb/d m-o-m to average 309 tb/d, following higher winter gas production.

Graph 5 - 22: Norway monthly liquids output

Following a deep y-o-y contraction in Norway oil supply growth in 2019, liquids supply is expected to grow by 0.21 mb/d to average 1.93 mb/d, which is still lower than the level of average liquids output in 2017 at 1.97 mb/d.

Johan Sverdrup is forecast to account for 50% of the new production. In addition, 20% of the new production will come from the ramp-up of the Valhall and Oseberg projects and the start-up of Njord, Yme and Martin Linge. Maintenance is scheduled for 2Q20 and again for 4Q20.

Graph 5 - 23: Norway’s quarterly liquids supply

1.861.83

1.3

1.4

1.5

1.6

1.7

1.8

1.9

2.0

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

mb/d

Sources: Norwegian Petroleum DirectorateOPEC Secretariat.

-18

3

-22

2

-14

9

12

12

1

27

1

24

8

21

2

-300

-200

-100

0

100

200

300

1,500

1,600

1,700

1,800

1,900

2,000

2,100

2,200

1Q 2Q 3Q 4Q

2019/18 (RHS) 2020/19 (RHS)2018 2019*2020*



World Oil Supply


UK

UK crude oil output in October 2019 declined m-o-m by 0.08 mb/d to an average of 1.05 mb/d, lower by 0.11 mb/d, y-o-y.

Crude oil and NGLs output declined by 69 tb/d and 8 tb/d in October to average 1.00 mb/d and 79 tb/d, respectively.

For crude, two separate outages were reported from Buzzard, the UK’s largest field. However, production is expected to recover in November.

For 2019, UK liquids supply growth is forecast at a slower pace compared to a year ago, at 0.06 mb/d y-o-y, to average 1.18 mb/d, revised down by 0.01 mb/d due to a downward revision in the 4Q19 supply forecast by 54 tb/d.

Graph 5 - 24: UK monthly liquids output

For 2020, despite the expected growth from new projects – Mariner, Clair, Lancaster and the start-up of Liberator – UK oil supply is forecast to see an overall contraction of 0.01 mb/d in 2020 to average 1.17 mb/d. The main projects in decline include Buzzard, Elgin/Franklin, Golden Eagle Area, Western Isles, Greater Catcher and ETAP. These will account for more than 40% of total UK declines in 2020. Maintenance is expected to occur in 2Q20 and 3Q20, with production resuming in 4Q20.

Graph 5 - 25: UK quarterly liquids supply

Developing Countries (DCs)

Total developing countries’ (DCs) oil supply for 2019 remained unchanged from last month’s assessment to average 13.57 mb/d, representing y-o-y growth of 0.11 mb/d. Latin America is forecast to see y-o-y growth of 0.20 mb/d, driven by new production ramp-ups in Brazil. In Africa, the anticipated y-o-y growth of 0.04 mb/d will come mainly from Ghana and the Sudans (including South Sudan and Sudan). Oil supply in the Middle East is expected to remain unchanged y-o-y at 3.21 mb/d. As before, Other Asia will see an annual contraction of 0.13 mb/d.

For 2020, oil supply in DCs is expected to increase by 0.27 mb/d to average 13.85 mb/d, also unchanged from the last monthly assessment. The key driver remains Latin America with y-o-y forecast growth of 0.25 mb/d due to projects being ramped up in Brazil. While production is forecast to increase in the Middle East and Africa by 0.04 mb/d and 0.03 mb/d, respectively, to average 3.25 mb/d and 1.57 mb/d, production in Other Asia, despite projected growth in India and Malaysia, is forecast to decline by 0.04 mb/d to average 3.39 mb/d.

1.16

1.05

0.9

1.0

1.1

1.2

1.3

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

mb/d

Sources: Oil and Gas Authority and OPEC Secretariat.

116

66 55-7

-16

-59

-21

40

-100

-50

0

50

100

150

800

900

1,000

1,100

1,200

1,300

1Q 2Q 3Q 4Q

2019/18 (RHS) 2020/19 (RHS)2018 2019*2020*



World Oil Supply


Table 5 - 7: Developing countries’ liquids supply, mb/d

Latin America

Brazil

Brazil’s crude oil output in October 2019 rose by 36 tb/d m-o-m to average 2.96 mb/d, a robust y-o-y growth of 0.35 mb/d according to the Agência Nacional do Petróleo, mainly due to higher output from two FPSOs operating in the Lula Field. Production of NGLs and biofuels was steady in October at 0.11 mb/d and 0.63 mb/d, respectively.

Brazil’s total liquids supply in October rose by 0.03 mb/d to average 3.70 mb/d, higher by 0.37 mb/d y-o-y. With new project ramp-ups, particularly in the Lula and Búzios fields, Brazil’s liquids supply in 2019 is forecast to average 3.49 mb/d (including biofuels), representing y-o-y growth of 0.19 mb/d.

Graph 5 - 26: Brazil’s crude oil and liquids supply Graph 5 - 27: Brazil’s quarterly liquids supply

The supply forecast for 2020 shows y-o-y growth of 0.29 mb/d for an average of 3.78 mb/d, unchanged from last month’s assessment. More than 80% of the estimated addition from new projects is expected to come from the Búzios (x-Franco), Lara and Lula fields. Mature fields such as Parque das Baleia, Marlim Sul (South), Roncador, Mero (Libra NW), and Marlim Leste account for more than 50% of the estimated 0.12 mb/d total decline in Brazil’s supply during 2020. Annual maintenance is expected to slow growth in 2Q20 and in 3Q20.

FSU

FSU oil supply in 2019 is forecast to increase by 0.06 mb/d y-o-y to average 14.35 mb/d, revised up by 18 tb/d from last month’s assessment due to the upward revision of 70 tb/d in Russia’s supply forecast for 4Q19. In Russia and Kazakhstan, oil supply is expected to increase by 0.08 mb/d and 0.01 mb/d y-o-y to average 11.43 mb/d and 1.82 mb/d, respectively, while oil output is likely to decline in Azerbaijan and FSU Others by 0.02 mb/d and 0.01 mb/d, respectively.

For 2020, the FSU oil supply forecast is revised down by 0.01 mb/d and is now expected to grow by 0.09 mb/d y-o-y, to average 14.44 mb/d.

Change1Q 2Q 3Q 4Q Yearly Y-o-y

2018 13.44 13.51 13.39 13.51 13.46 0.072019* 13.41 13.44 13.60 13.83 13.57 0.112020* 13.78 13.80 13.82 13.98 13.85 0.27


2.96

3.70

2.4

2.6

2.8

3.0

3.2

3.4

3.6

3.8

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

mb/d

Crude oil output Liquids supply

Sources: National Agency of Petroleum, Natural Gas and Biofuels; and OPEC Secretariat.

3.34

3.73

3.85

3.0

3.2

3.4

3.6

3.8

4.0

1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q* 1Q* 2Q* 3Q* 4Q*

2018 2019 2020

mb/d

Note: * 4Q19-4Q20 = Forecast.Sources: National Agency of Petroleum, Natural Gas and Biofuels; and OPEC Secretariat.

World Oil Supply


Russia

Preliminary data for Russian liquids supply in November 2019 shows an increase of 0.02 mb/d m-o-m to average 11.45 mb/d, down by 0.12 mb/d y-o-y. Part of the higher production in recent months is due to rising condensate output from gas fields, which usually see a production increase before winter.

Graph 5 - 28: Russia's monthly liquids supply Graph 5 - 29: Russia’s quarterly liquids output

Russia’s annual oil supply growth in 2019 is revised up by 18 tb/d following output in 4Q19 that was higher by 70 tb/d than expected in our forecast. Production is now estimated to grow by 0.08 mb/d y-o-y to average 11.41 mb/d.

Caspian

Kazakhstan

Kazakhstan’s liquids output in October recovered by 0.07 mb/d m-o-m to average 1.84 mb/d, higher y-o-y by 0.13 mb/d. Crude oil production in October increased by 62 tb/d to average 1.57 mb/d. NGL output also was up by 4 tb/d to average 271 tb/d, the same as a year ago.

Our forecast for November was estimated at 1.87 mb/d but it seems that the unplanned production shut-in that began in the middle of the month in the Kashagan field will result in lower output than expected in the forecast.

Kazakhstan’s oil supply in the current year will grow by 0.01 mb/d to average 1.82 mb/d.

For 2020, Kazakhstan plans to start production from a satellite oil field, Kalamkas-Sea, as well as ramp up production in the Kashagan field.

Graph 5 - 30: Kazakhstan’s quarterly liquids output

11.45

11.17

11.35

11.44

10.8

11.0

11.2

11.4

11.6

11.8

Ju

l 17

Se

p 1

7

Nov 1

7

Ja

n 1

8

Ma

r 1

8

Ma

y 1

8

Ju

l 18

Se

p 1

8

Nov 1

8

Ja

n 1

9

Ma

r 1

9

Ma

y 1

9

Ju

l 19

Se

p 1

9

Nov 1

9

mb/d

Sources: Nefte Compass and OPEC Secretariat.

Avg. 18

Avg. Jan-Nov 19

Avg. 17

10.9

11.0

11.1

11.2

11.3

11.4

11.5

11.6

11.7

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

mb/d

Note: * 4Q19 = Forecast.Sources: Nefte Compass and OPEC Secretariat.

1.811.82

1.4

1.5

1.6

1.7

1.8

1.9

2.0

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

mb/d

Note: * 4Q19 = Forecast.Sources: Nefte Compass and OPEC Secretariat.

World Oil Supply


Azerbaijan

Azerbaijan’s liquids output in October was down by 36 tb/d m-o-m to average 0.75 mb/d, due to shut-in production in the West Chirag platform. Oil production in 3Q19 was higher by 0.02 mb/d q-o-q to average 0.79 mb/d, and showed a y-o-y decline of 0.01 mb/d.

Azerbaijan’s November total liquids output is expected to recover by 0.04 mb/d to average 0.79 mb/d.

For 2019, oil supply in Azerbaijan is expected to decline by 0.02 mb/d to average 0.79 mb/d, unchanged from last month’s assessment.

Graph 5 - 31: Azerbaijan’s quarterly liquids supply

China

China’s liquids production in October 2019 declined by 10 tb/d m-o-m to an average 4.08 mb/d, up by 47 tb/d y-o-y, according to official data.

Crude oil output in October decreased by 12 tb/d to an average of 3.79 mb/d, which was only 5 tb/d higher y-o-y. Domestic crude oil output by CNPC will support the country’s oil production during winter. Nevertheless, our forecast shows that oil supply in 4Q19 will fall by 0.01 mb/d to average 4.09 mb/d. Production from Shaanxi and Xinjiang are showing m-o-m growth, while oil production at several mature fields is declining.

Graph 5 - 32: China’s monthly liquids output Graph 5 - 33: China’s quarterly liquids output

China’s liquids production in 2019 is expected to grow by 0.09 mb/d to average 4.10 mb/d, unchanged from last month.

However for 2020, oil production growth is forecast to slow to 0.02 mb/d, for an average of 4.12 mb/d, due to a lack of new oil prospects and rising exploration costs. Future oil production will depend on foreign investor spending in the upstream sector amid the US-China trade dispute.

0.81

0.79

0.72

0.74

0.76

0.78

0.80

0.82

0.84

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

mb/d

Note: * 4Q19 = Forecast.Sources: JODI and OPEC Secretariat.

0.01

4.19

4.08

3.9

4.0

4.1

4.2

4.3

Oct

18

Nov 1

8

Dec 1

8

Ja

n 1

9

Fe

b 1

9

Ma

r 1

9

Ap

r 1

9

Ma

y 1

9

Ju

n 1

9

Ju

l 19

Au

g 1

9

Se

p 1

9

Oct

19

mb/d

Sources: China National Petroleum Corporation and OPEC Secretariat.

4.02

4.104.12

3.8

3.9

4.0

4.1

4.2

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19*

1Q

20*

2Q

20*

3Q

20*

4Q

20*

mb/d

Note: * 4Q19-4Q20 = Forecast.Sources: China National Petroleum Corporation and OPEC Secretariat.

World Oil Supply


OPEC NGLs and non-conventional oils

OPEC NGLs and non-conventional liquids in 2019 are forecast to grow by 0.04 mb/d to average 4.80 mb/d, unchanged from last month’s assessment, following growth of 0.12 mb/d in 2018.

NGL output in October recovered by 0.19 mb/d m-o-m to average 4.75 mb/d. Preliminary production data for November 2019 shows an increase of 0.06 mb/d to average 4.81 mb/d compared to a month earlier, an increase of 0.09 mb/d y-o-y.

For 2020, the preliminary forecast indicates growth of 0.03 mb/d to average 4.83 mb/d.

Graph 5 - 34: OPEC NGL and non-conventional liquids output

Table 5 - 8: OPEC NGL + non-conventional oils, mb/d

4.76 4.80 4.83

4.2

4.5

4.8

5.1

1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q

2018 2019* 2020*

mb/d

OPEC non-conventional

OPEC NGL

OPEC NGL and non-conventionalannual average

Note: * 2019 = Estimate and 2020 = Forecast.Sources: OPEC Secretariat.

Change Change2018 2019 19/18 1Q20 2Q20 3Q20 4Q20 2020 20/19

Total OPEC 4.76 4.80 0.04 4.83 4.83 4.83 4.83 4.83 0.03

Note: 2019 = Estimate and 2020 = Forecast.Source: OPEC Secretariat.

World Oil Supply


OPEC crude oil production

According to secondary sources, total OPEC-14 preliminary crude oil production averaged 29.55 mb/d in November, lower by 193 tb/d m-o-m. Crude oil output increased mostly in Ecuador, Kuwait and Libya, while production decreased in Saudi Arabia, Angola, Iraq and Iran I.R.

Table 5 - 9: OPEC crude oil production based on secondary sources, tb/d

Table 5 - 10: OPEC crude oil production based on direct communication, tb/d

2017 2018 1Q19 2Q19 3Q19 Sep 19 Oct 19 Nov 19 Nov/Oct

Algeria 1,047 1,042 1,026 1,019 1,021 1,020 1,019 1,027 7Angola 1,634 1,505 1,443 1,420 1,390 1,404 1,358 1,284 -75Congo 252 317 326 332 325 334 324 311 -13Ecuador 530 519 526 530 544 550 457 530 73Equatorial

Guinea 133 125 115 114 119 122 126 134 8Gabon 200 187 209 212 204 197 207 184 -23Iran, I.R. 3,813 3,553 2,726 2,404 2,189 2,163 2,147 2,102 -45Iraq 4,446 4,550 4,635 4,699 4,750 4,732 4,698 4,639 -59Kuwait 2,708 2,745 2,715 2,693 2,655 2,658 2,648 2,705 58Libya 811 951 965 1,154 1,103 1,162 1,166 1,188 23Nigeria 1,658 1,718 1,736 1,786 1,844 1,851 1,804 1,798 -6Saudi Arabia 9,954 10,311 10,019 9,769 9,452 8,796 10,001 9,850 -151UAE 2,916 2,986 3,068 3,067 3,082 3,083 3,105 3,102 -3Venezuela 1,911 1,354 975 776 714 644 685 697 12

Total OPEC 32,014 31,864 30,484 29,974 29,392 28,716 29,744 29,551 -193

Notes: Totals may not add up due to independent rounding.Source: OPEC Secretariat.

2017 2018 1Q19 2Q19 3Q19 Sep 19 Oct 19 Nov 19 Nov/Oct

Algeria 1,059 1,040 1,027 1,017 1,025 1,024 1,023 1,026 3Angola 1,632 1,473 1,421 1,424 1,318 1,369 1,391 1,273 -118Congo 263 323 345 340 334 327 316 385 69Ecuador 531 517 529 531 546 547 467 546 79Equatorial

Guinea 129 120 108 114 109 109 119 90 -29Gabon 210 193 214 225 220 216 212 .. ..Iran, I.R. 3,867 .. .. .. .. .. .. .. ..Iraq 4,469 4,410 4,540 4,565 4,630 4,620 4,576 4,595 19Kuwait 2,704 2,737 2,712 2,681 2,636 2,650 2,633 2,706 73Libya .. .. .. .. .. .. .. .. ..Nigeria 1,536 1,602 1,689 1,721 1,794 1,796 1,780 .. ..Saudi Arabia 9,959 10,317 10,053 9,752 9,503 9,129 10,303 9,890 -412UAE 2,967 3,008 3,055 3,050 3,068 3,070 3,070 3,065 -5Venezuela 2,035 1,510 1,289 1,045 864 749 761 912 151

Total OPEC .. .. .. .. .. .. .. .. ..

Notes: .. Not availab le. Totals may not add up due to independent rounding.Source: OPEC Secretariat.

Stock Movements


Stock Movements

Preliminary data for October showed that total OECD commercial oil stocks fell by 5.1 mb m-o-m to stand at 2,933 mb, which was 83 mb higher than the same time one year ago and 33 mb above the latest five-year average. Within the components, crude stocks rose by 18.9 mb, while product stocks fell by 23.9 mb, m-o-m. OECD crude stocks stood at 18 mb above the latest five-year average, while product stocks indicated a surplus of 15 mb. In terms of days of forward cover, OECD commercial stocks rose by 0.6 days m-o-m in October to stand at 61.2 days, which was 1.8 days above the same period in 2018, but 0.2 days below the latest five-year average.

Preliminary data for November showed that US total commercial oil stocks fell by 15.6 mb m-o-m to stand at 1,263.8 mb, which was 1.6 mb above the same period a year ago, and 3.9 mb higher than the latest five-year average. Within the components, crude stocks rose slightly by 0.3 mb, while product stocks fell by 15.9 mb, m-o-m.

OECD

Preliminary data for October showed that total OECD commercial oil stocks fell by 5.1 mb m-o-m to stand at 2,933 mb, which was 82.5 mb higher than the same time one year ago and 32.8 mb above the latest five-year average.

Within the components, crude stocks rose by 18.9 mb, while product stocks fell by 23.9 mb, m-o-m. It should be noted that the overhang of total OECD commercial oil stocks has been reduced by around 267 mb since the ‘Declaration of Cooperation’ began at the beginning of 2017.

Within the regions, OECD Americas and OECD Europe witnessed stock draws from the previous month, while OECD Asia Pacific saw a stock build.

Graph 9 - 1: OECD commercial oil stocks

OECD commercial crude stocks rose by 18.9 mb m-o-m in October, ending the month at 1,471 mb, which was 34.7 mb higher than the same time a year ago and 18.3 mb higher than the latest five-year average. Compared to the previous month, OECD Americas rose by 20.3 mb, while crude stocks in OECD Europe and OECD Asia Pacific fell by 0.4 mb and 1.1 mb, respectively.

In contrast, OECD total product inventories fell by 23.9 mb m-o-m in October to stand at 1,462 mb, which was 47.8 mb above the same time a year ago and 14.5 mb above the latest five-year average. Within the OECD regions, product stocks in OECD Asia Pacific rose by 2.9 mb, while OECD Americas and Europe stocks fell by 26.4 mb and 0.3 mb, m-o-m, respectively.

In terms of days of forward cover, OECD commercial stocks rose by 0.6 days m-o-m in October to stand at 61.2 days, which was 1.8 days above the same period in 2018, but 0.2 days below the latest five-year average. Within the regions, OECD Americas was 0.9 days below the latest five-year average to stand at 60.4 days in October. OECD Europe’s stocks were 1.6 days higher than the latest five-year average to finish the month at 70.4 days. OECD Asia Pacific stocks were 1.7 days below the latest five-year average to stand at 48.8 days.

2,500

2,600

2,700

2,800

2,900

3,000

3,100

2,500

2,600

2,700

2,800

2,900

3,000

3,100

Ja

n

Fe

b

Ma

r

Ap

r

Ma

y

Ju

n

Ju

l

Au

g

Se

p

Oct

Nov

Dec

mbmb

2017 2018 2019

Historical range2014-18

Sources: Argus Media, Euroilstock, IEA, METI, OPEC Secretariat and US EIA.

Avg. 2014-18

Stock Movements


Table 9 - 1: OECD’s commercial stocks, mb

OECD Americas

OECD Americas total commercial stocks fell by 6.1 mb m-o-m in October to settle at 1,548 mb, which was 13.1 mb above a year ago and 22.5 mb above the latest five-year average. Within the components, crude stocks rose by 20.3 mb, while products stocks fell by 26.4 mb, m-o-m.

Commercial crude oil stocks in OECD Americas rose by 20.3 mb m-o-m in October to stand at 818 mb, which was 17.5 mb higher than the same time a year ago and 27.6 mb higher than the latest five-year average. This build can be attributed to lower refinery runs in the US.

In contrast, total product stocks in OECD Americas fell by 26.4 mb m-o-m in October to stand at 730 mb, which was 4.4 mb lower than the same time one year ago and 5.1 mb less than the latest five-year average. Higher consumption in the region was behind the product stock draw.

OECD Europe

OECD Europe’s total commercial stocks fell by 0.7 mb m-o-m in October, ending the month at 978 mb, which was 66.8 mb higher than the same time a year ago and 34.6 mb higher than the latest five-year average. Crude and product stocks fell by 0.4 mb and 0.3 mb, m-o-m, respectively.

OECD Europe’s commercial crude stocks fell by 0.4 mb m-o-m in October, ending the month at 441 mb, which was 26.7 mb above a year earlier and 30.8 mb higher than the latest five-year average. The drop was driven by higher refinery throughput in the EU-16 countries, which rose by 30 tb/d to stand at 9.91 mb/d.

OECD Europe’s commercial product stocks also fell by 0.3 mb m-o-m to end October at 537 mb, which was 40.1 mb higher than the same time a year ago and 3.8 mb above the latest five-year average. The drop came on the back of relatively higher consumption in the region.

OECD Asia Pacific

OECD Asia Pacific’s total commercial oil stocks rose by 1.8 mb m-o-m in October to stand at 407 mb, which was 2.6 mb higher than a year ago, yet 24.3 mb below the latest five-year average. Within the components, crude stocks fell by 1.1 mb, while product stock rose by 2.9 mb, m-o-m.

OECD Asia Pacific’s crude inventories fell by 1.1 mb m-o-m to end October at 213 mb, which was 9.5 mb lower than one year ago and 40.1 mb below the latest five-year average.

In contrast, OECD Asia Pacific’s total product inventories rose by 2.9 mb m-o-m to end October at 195 mb, which was 12.1 mb higher than the same time a year ago and 15.9 mb above the latest five-year average.

ChangeAug 19 Sep 19 Oct 19 Oct 19/Sep 19 Oct 18

Crude oil 1,466 1,453 1,471 18.9 1,437

Products 1,511 1,486 1,462 -23.9 1,414

Total 2,977 2,938 2,933 -5.1 2,851

Days of forward cover 61.6 60.7 61.2 0.6 59.5

Note: Totals may not add up due to independent rounding.Sources: Argus Media, Euroilstock, IEA, METI, OPEC Secretariat and US EIA.

Stock Movements


US

Preliminary data for November showed that US total commercial oil stocks fell by 15.6 mb m-o-m to stand at 1,263.8 mb, which was 1.6 mb, or 0.1%, above the same period a year ago, and 3.9 mb, or 0.3%, higher than the latest five-year average. Within the components, crude stocks rose slightly by 0.3 mb, while product stocks fell by 15.9 mb, m-o-m.

US commercial crude stocks rose in November to stand at 447.1 mb, which was 2.3 mb, or 0.5%, below the same time last year, but 5.9 mb, or 1.3%, above the latest five-year average. The build could have been driven by higher supply as refinery throughput rose to a level of 16.77 mb/d. Inventories in Cushing, Oklahoma, fell by almost 4.0 mb to end November at 43.8 mb.

In contrast, total product stocks in October fell by 15.9 mb m-o-m to stand at 816.7 mb, which was 3.9 mb, or 0.5%, above the level seen at the same time in 2018, but 2.0 mb, or 0.2%, below the latest five-year average. Within the components, gasoline, distillate and residual fuel oil saw stock builds, while jet fuel, propylene and other unfinished oil registered stock draws.

Graph 9 - 2: US weekly commercial crude oil inventories

Gasoline stocks rose in November by 12.1 mb m-o-m to settle at 229.4 mb, which was 0.9 mb, or 0.4%, lower than levels seen at the same time last year, but 3.1 mb, or 1.4%, higher than the latest five-year average. This monthly increase came mainly on the back of lower demand, which fell by 281 tb/d to average 9.18 mb/d.

Distillate stocks also rose by 0.3 mb m-o-m in November to end the month at 119.5 mb, which was 7.1 mb, or 5.6%, lower than the same period a year ago, and 21.5 mb, or 15.2%, below the latest five-year average. The stock build could be mainly attributed to lower demand, which decreased by around 50 tb/d to average 4.20 mb/d.

Residual fuel stocks rose by 0.7 mb m-o-m to end November at 29.5 mb, which was 0.3 mb, or 0.9%, less than the same time a year ago and 6.5 mb, or 18.1%, lower than the latest five-year average.

In contrast, jet fuel stocks fell by 1.1 mb m-o-m to stand at 38.3 mb in November, which was 1.0 mb, or 2.5%, less than the same time a year ago and 1.6 mb, or 4.0%, lower than the latest five-year average.

Graph 9 - 3: US weekly distillate inventories

300

350

400

450

500

550

300

350

400

450

500

550

1 11 21 31 41 51

mbmb

2017 2018

2019 Average 2014-18



Week

100

110

120

130

140

150

160

170

180

100

110

120

130

140

150

160

170

180

1 11 21 31 41 51

mbmb

2017 2018

2019 Average 2014-18



Week

Stock Movements


Table 9 - 2: US commercial petroleum stocks, mb

Japan

In Japan, total commercial oil stocks rose by 1.8 mb m-o-m in October to settle at 138.5 mb, which was 14.5 mb, or 9.5%, lower than one year ago and 22.7 mb, or 14.1%, below the latest five-year average. Within the components, crude stocks fell by 1.1 mb, while products stocks rose by 2.9 mb, m-o-m.

Japanese commercial crude oil stocks fell by 1.1 mb m-o-m in October to stand at 74.1 mb, which was 14.6 mb, or 16.4%, above the same period a year ago and 19.6 mb, or 20.9%, below the latest five-year average. The drop was driven mainly by slightly lower crude imports to average 2.76 mb/d. However, lower refinery throughput limited a further drop in crude oil stocks.

By contrast, Japan’s total product inventories rose by 2.9 mb m-o-m to end October at 64.4 mb, which was 0.1 mb higher than the same month last year, but 3.1 mb, or 4.6%, below the latest five-year average. All product categories experienced stock builds.

Graph 9 - 4: Japan’s commercial oil stocks

Gasoline stocks rose by 0.6 mb m-o-m to stand at 10.2 mb in October, which was 0.2 mb, or 2.4%, lower than a year ago, yet 0.1 mb higher than the latest five-year average. The build was mainly driven by lower domestic sales, which declined by 9.5% from the previous month. Lower gasoline output, which decreased by 3.6%, limited a further build in gasoline stocks.

Distillate stocks rose by 1.3 mb m-o-m, reversing the drop of last month, to stand at 31.4 mb in October. This was 0.2 mb, or 0.7%, higher than the same time a year ago, yet 1.7 mb, or 5.1%, lower than the latest five-year average. Within the distillate components, jet fuel and kerosene stocks rose by 3.4% and 9.3% m-o-m, respectively. The builds in both products were driven by higher output combined with lower domestic sales. In contrast, gas oil stocks fell by 3.9% m-o-m in October.

Total residual fuel oil stocks rose by 0.5 mb m-o-m in October to stand at 13.3 mb, which was unchanged from the same period a year ago, but was 0.9 mb, or 6.4%, lower than the latest five-year average. Within the components, fuel oil A and fuel B.C stocks rose by 7.0% and 2.2% m-o-m, respectively, on the back of lower production.

ChangeSep 19 Oct 19 Nov 19 Nov 19/Oct 19 Nov 18

Crude oil 426.5 446.8 447.1 0.3 449.4

Gasoline 231.9 217.2 229.4 12.1 230.2

Distillate fuel 131.7 119.1 119.5 0.3 126.5

Residual fuel oil 29.9 28.8 29.5 0.7 29.8

Jet fuel 44.4 39.4 38.3 -1.1 39.3

Total products 878.1 832.6 816.7 -15.9 812.8

Total 1,304.5 1,279.4 1,263.8 -15.6 1,262.2

SPR 644.8 641.0 635.2 -5.8 649.6


120

130

140

150

160

170

180

120

130

140

150

160

170

180

Ja

n

Fe

b

Ma

r

Ap

r

Ma

y

Ju

n

Ju

l

Au

g

Se

p

Oct

Nov

Dec

mbmb

2017 2018 2019


Sources: Ministry of Economic, Trade and Industry of Japanand OPEC Secretariat.

Avg. 2014-18

Stock Movements


Table 9 - 3: Japan’s commercial oil stocks*, mb

EU plus Norway

Preliminary data for October showed that total European commercial oil stocks fell slightly by 0.7 mb m-o-m to stand at 1,091.4 mb, which was 47.1 mb, or 4.5%, above the same time a year ago, and 3.3 mb, or 0.3%, above than the latest five-year average. Within the components, crude and product stocks fell by 0.4 mb and 0.3 mb, m-o-m, respectively.

European crude inventories fell in October to stand at 477.5 mb, which was 5.4 mb, or 1.1%, higher than the same period a year ago, and 1.5 mb, or 0.3%, higher than the latest five-year average. The drop was driven by higher refinery throughput in the EU-16 countries, which rose by 30 tb/d to stand at 9.91 mb/d.

Graph 9 - 5: EU-15 plus Norway’s total oil stocks

European total product stocks fell by 0.3 mb m-o-m, ending October at 613.9 mb, which was 41.6 mb, or 7.3%, higher than the same time a year ago, and 1.7 mb, or 0.3%, higher than the latest five-year average. The fall in product stocks could be attributed to relatively higher demand in the region. Within products, residual fuel experienced a stock build, while distillates, gasoline and naphtha witnessed stock draws in October versus the previous month.

Distillate stocks fell by 0.1 mb m-o-m in October for the second consecutive month to stand at 415.3 mb, which was 36.6 mb, or 9.7%, higher than the same time last year and 6.3 mb, or 1.5%, above the latest five-year average.

Gasoline stocks fell by 0.2 mb m-o-m in October for the second consecutive month to stand at 109.5 mb, which was 3.9 mb, or 3.7%, higher than the same time a year ago, and 0.5 mb, or 0.5%, above the latest five-year average.

Naphtha stocks fell by 0.4 mb in October, ending the month at 27.7 mb, which was 2.0 mb, or 6.9%, below last year’s October level, yet 1.7 mb, or 6.7%, higher than the latest five-year average.

In contrast, residual fuel stocks rose in October by 0.3 mb m-o-m to stand at 61.4 mb, which was 3.2 mb, or 5.4%, higher than the same time one year ago, but 6.8 mb, or 10.0%, below the latest five-year average.


Crude oil 81.0 75.1 74.1 -1.1 88.6

Gasoline 10.1 9.6 10.2 0.6 10.5

Naphtha 11.4 9.0 9.5 0.4 9.4

Middle distillates 31.4 30.1 31.4 1.3 31.2

Residual fuel oil 12.3 12.8 13.3 0.5 13.3

Total products 65.1 61.5 64.4 2.9 64.3

Total** 146.1 136.7 138.5 1.8 153.0

Note: * At the end of the month. ** Includes crude oil and main products only.Sources: Ministry of Economy, Trade and Industry of Japan and OPEC Secretariat.

1,040

1,060

1,080

1,100

1,120

1,140

1,160

1,180

1,200

1,040

1,060

1,080

1,100

1,120

1,140

1,160

1,180

1,200

Ja

n

Fe

b

Ma

r

Ap

r

Ma

y

Ju

n

Ju

l

Au

g

Se

p

Oct

Nov

Dec

mbmb

2017 2018 2019


Sources: Argus, Euroilstock and OPEC Secretariat.

Avg. 2014-18

Stock Movements


Table 9 - 4: EU-15 plus Norway’s total oil stocks, mb

Singapore, Amsterdam-Rotterdam-Antwerp (ARA) and Fujairah

Singapore

At the end of October, total product stocks in Singapore rose by 2.2 mb m-o-m, reversing the drop of last month, to stand at 44.6 mb, which was 7.4 mb, or 19.9%, above the same period a year ago. Within products, light distillates and fuel oil experienced stock builds, while middle distillates registered a stock draw when compared to the previous month.

Light distillate and fuel oil stocks rose in October by 1.6 mb and 2.2 mb, m-o-m, respectively. At 11.7 mb, light distillates stood at 0.5 mb, or 4.1%, lower than the same time one year ago. Fuel oil stocks ended October at 21.7 mb, which was 6.2 mb, or 40%, higher than last year’s October level.

In contrast, middle distillate stocks fell by 1.6 mb m-o-m to end October at 11.2 mb, which was 1.7 mb, or 17.9%, higher the same period a year ago. This drop may have been driven by higher exports from the hub.

ARA

Total product stocks in ARA fell by 2.9 mb m-o-m in October to settle at 40.6 mb, which was 0.2 mb, or 0.5%, higher than the same time a year ago. Within products, naphtha and jet oil experienced stock builds, while gasoline, gasoil and fuel oil stocks registered stock draws when compared to the previous month.

Naphtha and jet oil stocks rose by 0.5 mb and 0.6 mb m-o-m in October to stand at 2.2 mb and 5.7 mb, respectively. Naphtha stocks were unchanged from last year’s level at the same time. Jet oil stocks were 0.8 mb, or 16.3%, higher than last year’s level.

Gasoline and gasoil stocks fell by 1.3 mb and 1.4 mb m-o-m in October to stand at 6.8 mb and 19.3 mb, respectively. Gasoline stocks were 1.6 mb, or 19%, lower than last year’s level at the same time. Gasoil stocks were 0.5 mb, or 2.7%, higher than last year’s level.

Fuel oil stocks fell by 1.3 mb in October m-o-m to stand at 6.6 mb, which was 0.5 mb, or 8.2%, higher than the same time a year ago.


Crude oil 479.2 477.9 477.5 -0.4 472.1

Gasoline 109.8 109.7 109.5 -0.2 105.6

Naphtha 29.0 28.2 27.7 -0.4 29.8

Middle distillates 417.2 415.4 415.3 -0.1 378.7

Fuel oils 61.0 61.1 61.4 0.3 58.3

Total products 617.1 614.3 613.9 -0.3 572.3

Total 1,096.2 1,092.1 1,091.4 -0.7 1,044.3

Sources: Argus, Euroilstock and OPEC Secretariat.

Stock Movements


Fujairah

During the week ending 2 December 2019, total oil product stocks in Fujairah fell by 2.45 mb w-o-w to stand at 20.82 mb, according to data from FEDCom and S&P Global Platts. At this level, total oil stocks were 2.50 mb higher than the same time a year ago. Within products, light and heavy distillates witnessed stock draws, while middle distillates registered stock builds when compared with the previous week’s data.

Light distillate stocks fell by 0.25 mb w-o-w to stand at 4.66 mb, which was 5.35 mb lower than a year ago at the same time.

Heavy distillate stocks fell by 2.55 mb to stand at 12.79 mb, which was 6.79 mb higher than the same level one year ago.

In contrast, middle distillates rose by 0.35 mb w-o-w to stand at 3.37 mb, which was 1.06 mb higher than the same week in 2018.

https://www.iea.org/reports/oil‐market‐report‐december‐2019

Oil Market Report - December 2019 Flagship report — December 2019 CiteSharePurchase Oil Market Report - December 2019

The IEA Oil Market Report (OMR) is one of the world's most authoritative and timely sources of data, forecasts and analysis on the global oil market – including detailed statistics and commentary on oil supply, demand, inventories, prices and refining activity, as well as oil trade for IEA and selected non-IEA countries. About this report

Global oil demand increased by 900 kb/d y-o-y in 3Q19, the strongest annual growth in a year. Nearly three-quarters of the growth occurred in China. Indian demand rose 135 kb/d, but OECD deliveries fell for the fourth straight quarter and are expected to decline 75 kb/d overall in 2019. For 2019 and 2020 we have left unchanged our global oil demand growth forecasts at 1 mb/d and 1.2 mb/d, respectively.

Faced with potential oversupply in early 2020, OPEC+ countries agreed to deepen existing cuts to 2.1 mb/d in 1Q20. This implies a reduction in supply of 500 kb/d from current levels. Despite the additional curbs and a reduction in our forecast of 2020 non-OPEC supply growth to 2.1 mb/d, global oil inventories could build by 0.7 mb/d in 1Q20. In November, global oil supplies held steady at 101.36 mb/d, down 1.2 mb/d y-o-y.

The sharp drop in refining margins in November in all markets revealed the delicate balancing act between global crude oil and product markets. Labour strikes in November in several countries were factors in the downward revision to our 4Q19 throughput forecast, now expected to be flat y-o-y. In 2020, refining throughput growth is also revised down to 1 mb/d, after a 0.2 mb/d decline in 2019.

OECD commercial stocks drew 32.5 mb in October to 2 904 mb. They were 2.9 mb below the five-year average and covered 60.6 days, one day below the average. Preliminary data for November showed total inventories falling in all regions, by 23.5 mb. Short-term floating storage of crude oil fell 2.1 mb in November to 62 mb. The number of Iranian VLCCs used for floating storage decreased by one to 26.

ICE Brent futures rose above $64/bbl following the OPEC+ meetings. Physical markets appear to have tightened with steeper backwardation for both North Sea Dated and Dubai, and rising differentials for many crudes, particularly sweet grades. Product cracks eased, with the exception of naphtha which was boosted by petrochemical demand. HSFO cracks continued to be pressured by the IMO regulations and fell to record lows. Highlights For the last several months in this Report we have suggested that in early 2020 the oil market is likely to see a significant surplus of supply over demand. On 6 December, countries participating in the OPEC+ agreement took a step to address this imbalance by deepening their cuts from 1.2 mb/d to 1.7 mb/d. Saudi Arabia once again showed its willingness to shoulder a greater burden by volunteering an additional reduction of 0.4 mb/d to take the total cut to 2.1 mb/d, effective 1

January. The voluntary cut by the Saudis has already been partially delivered but the overall effectiveness of the OPEC+ agreement depends on the willingness of all its parties to fully comply, including those whose compliance so far has been less rigorous. This revised deal excludes from the production ceiling 1.5 mb/d of condensate output by non-OPEC producers. Russia, in particular, now has 0.8 mb/d of supply that can legitimately be increased.

If all the countries comply with their new allocations and Saudi Arabia delivers the rest of its voluntary cut of 0.4 mb/d, the fall in production volume versus today will be about 0.5 mb/d. In this Report we have reduced our forecast for non-OPEC production growth next year from 2.3 mb/d to 2.1 mb/d to take account of lower output from participants in the OPEC+ deal and a weaker growth outlook for Brazil, Ghana and the United States. Even so, with our demand outlook unchanged, there could still be a surplus of 0.7 mb/d in the market in 1Q20.

In the meantime, the market has done its own sums and the reaction to oil’s new deal has so far been muted: Brent crude oil was priced at $63/bbl on the eve of the OPEC+ meetings and as we publish this Report the price is $64/bbl.

On a historic note, in September, the United States momentarily became a net oil exporter to the tune of 89 kb/d. This is a major milestone on its path to becoming a sustained net exporter, which is likely to be late in 2020 or early in 2021. However, this does not mean that energy independence has been achieved: the United States remains a major crude oil importer. In September, it received 6.5 mb/d of crude oil, with the largest volume coming from Canada and, with exports of 3.1 mb/d, it remained a significant net importer of 3.4 mb/d. Quality issues and greater market competition indicate that the United States will remain a major crude importer. This exposure to international markets highlights the need to insure against disruptions by maintaining emergency stocks, as reconfirmed in the communique issued at the conclusion of the biannual IEA Ministerial Meeting held last week in Paris.

Finally, to all our readers, a happy holiday season and we look forward to seeing you again in 2020. Oil’s new deal

IEA REPORT WRAP: Oil Surplus to Persist; Demand Estimate Steady 2019‐12‐12 09:45:59.289 GMT By Stephen Voss (Bloomberg) ‐‐ Summary including stories from IEA’s monthly Oil Market Report that was published at 10am Paris time Thursday: * IEA says OPEC+ supply cuts won’t prevent surplus in 2020 ** Demand 2020 forecast was little changed at 101.5m b/d ** Demand growth in 2020 est. 1.2% y/y or 1.2m b/d ** Non‐OPEC supply 2020 revised down to 67m b/d from 67.1m ** Global inventories may still build in 1Q 2020 ** Call on OPEC crude for all of 2020 pegged at 29m b/d, which is 660k b/d below recent production levels ** Click here for summary of key IEA supply/demand forecasts * OPEC crude output fell m/m by 300k b/d in November to 29.66m b/d ** See Table ** Biggest m/m change was Saudi Arabia ‐300k b/d * OPEC output fell last month led by Saudi, Angola: IEA ** November compliance with promised cutbacks was 154% for 11 OPEC members and 61% among non‐OPEC nations participating in the OPEC+ deal: IEA * OECD oil demand is set to decline in 2019 * Russia, Oman win from condensate exclusion from quotas * Crude, condensate stockpiles fell globally in 3Q * U.S. output growth forecast cut by IEA on spending curbs * Refinery margins fell across the board in November * Refining runs won’t get anticipated IMO boost * Table: IEA world oil supply and demand forecasts by quarter * NOTE: OPEC and its non‐OPEC allies agreed last week to deepen their production cuts, starting Jan. 1, to 1.7m b/d, with Saudi Arabia pledging additional voluntary cuts of 400k b/d on top of that * NOTE: Next OPEC ministerial conference is March 5 * NOTE: OPEC published its own monthly report on Wednesday and the U.S. EIA’s monthly Short‐Term Energy Outlook was published Tuesday ‐‐With assistance from Brian Wingfield, Jack Wittels, Mark Evans, Grant Smith, Christopher Sell, Olga Tanas, Rachel Graham, Alex Longley and Amanda Jordan. To contact the reporter on this story: Stephen Voss in London at [email protected] To contact the editors responsible for this story: Stephen Voss at [email protected] Brian Wingfield, Helen Robertson

IEA World Oil Supply/Demand Key Forecasts 2019‐12‐12 09:00:00.26 GMT By Mark Evans (Bloomberg) ‐‐ World oil demand 2020 fcast was unrevised at 101.5m b/d in Paris‐based Intl Energy Agency’s latest monthly report. * 2019 world demand was 100.25m b/d * Demand growth in 2020 est. 1.2% y/y or 1.2m b/d * Non‐OPEC supply 2020 was 67m b/d * Call on OPEC crude 2020 was 29m b/d * Call on OPEC crude 2019 was revised to 29.9 m b/d from 30m b/d ** OPEC crude production in Nov. fell by 300k b/d on the month to 29.66m b/d * Detailed table: FIFW NSN Q2E3XUT1UM0X <GO> * NOTE: Fcasts based off IEA’s table providing one decimal point To contact the reporter on this story: Mark Evans in London at [email protected] To contact the editor responsible for this story: Joshua Robinson at [email protected] OPEC+ Oil Supply Cuts Won’t Prevent Surplus in 2020, IEA Says 2019‐12‐12 09:00:00.62 GMT By Grant Smith (Bloomberg) ‐‐ Global oil markets still face a surplus next year even if OPEC and its partners deliver newly‐announced production cuts in full, the International Energy Agency said. Oil inventories may accumulate by 700,000 barrels a day in the first quarter even if the Organization of Petroleum Exporting Countries and its allies implement the entire cutback of 2.1 million barrels a day agreed last week, the IEA said in a monthly report. Supplies outside the group, led by U.S. shale, continue to grow much faster than world demand. While crude prices climbed to a 12‐week high in New York after OPEC+ surprised traders with their latest intervention, they remain below $60 a barrel amid concern that the additional output curbs still won’t be enough. The U.S. briefly became a net exporter of oil three months ago, underscoring the challenge OPEC faces from America’s shale boom.

“The market has done its own sums and the reaction to oil’s new deal has so far been muted,” said the Paris‐based agency, which advises most of the world’s major economies. The extra OPEC+ curbs would translate into an actual reduction from current levels of 532,000 barrels a day, the IEA said. Implementing that fully may be a tall order, as some producers like Iraq and Nigeria have barely made the cutbacks they promised to enact this year. A change to the terms of the OPEC+ agreement, which now exempts light oil known as condensate produced by the non‐OPEC members, could also undermine the coalition’s efforts. Condensate production in those countries, such as Russia and Azerbaijan, has the potential to increased from its current level of about 1.5 million barrels a day, according to the IEA. Saudi Arabia, OPEC’s biggest member, has already made considerable progress in fulfilling its output commitments, including additional voluntary reductions announced at the close of the OPEC meeting on Dec. 6. The kingdom pumped 9.9 million barrels a day in November, the IEA estimated. “The overall effectiveness of the OPEC+ agreement depends on the willingness of all its parties to fully comply, including those whose compliance so far has been less rigorous,” the agency said. OPEC and its partners are getting some solace from a recent recovery in oil demand. Global consumption increased at the strongest rate in a year during the third quarter, expanding by 900,000 barrels a day, according to the report. That’s almost twice the pace seen in the second quarter.

Demand is set to accelerate further in 2020, when it will expand by 1.2 million barrels a day ‐‐ about 1.2% ‐‐ to average 101.5 million barrels a day, the IEA predicts. OPEC may also be reassured that supply from some of its rivals, such as the U.S., Brazil and Ghana, is increasing less quickly than the IEA previously forecast. The agency lowered its projections for non‐OPEC production growth in 2020 by about 200,000 barrels a day. Yet supplies outside OPEC will nonetheless expand much more vigorously than world demand, swelling by 2.1 million barrels a day next year as a new tide of American shale‐oil is joined by offshore projects once considered unviable in an era of constrained prices, from Brazil, Norway and Guyana. As a result, the surplus in global markets may swell to as much as 1 million barrels a day during the second quarter, the agency said. That poses a considerable challenge for the cartel and its allies, who will meet again in early March to consider their next move. To contact the reporter on this story: Grant Smith in London at [email protected] To contact the editors responsible for this story: James Herron at [email protected] Christopher Sell OPEC Output Fell Last Month Led by Saudi Arabia and Angola: IEA 2019‐12‐12 09:00:00.27 GMT By Amanda Jordan (Bloomberg) ‐‐ OPEC’s November crude output dropped 300k b/d from October to 29.66m b/d, the International Energy Agency said in its monthly report. * Saudi Arabia cut output by 300k b/d to 9.9m b/d ‐‐ 410k b/d below its supply cap ‐‐ having raised production the previous month to replenish stockpiles following the Abqaiq attack * Angola’s production declined 90k b/d to 1.28m b/d, a 13‐year low, because of maintenance at the Girassol field and losses at aging deposits ** Angola has been running far below its OPEC supply quota * Elsewhere in Africa, Libya held production steady at 1.16m b/d, Algerian output edged up to 1.03m b/d and Nigeria slipped 30k b/d to 1.77m b/d ‐‐ still up 160k b/d from a year earlier * In the Middle East, Kuwait pumped 2.69m b/d, up 60k b/d vs October, while output from the U.A.E. held steady at 3.09m b/d * Iraq’s production slid 40k b/d to 4.65m b/d ‐‐ still 140k b/d above target ‐‐ as it suspended some output from state‐ controlled oil fields * Iranian production, still crippled by sanctions, dropped to 2.13m b/d, the lowest since June 1988 * Venezuela, also struggling under sanctions, raised output by 80k b/d to 780k b/d, but the recovery may “prove fleeting”

* Overall, the 11 OPEC members restricting supply produced 440k b/d below target during November, representing 154% compliance To contact the reporter on this story: Amanda Jordan in London at [email protected] To contact the editors responsible for this story: James Herron at [email protected] Rachel Graham, Helen Robertson OECD Nations’ Oil Demand is Set to Decline in 2019, IEA Says 2019‐12‐12 09:00:00.44 GMT By Alex Longley (Bloomberg) ‐‐ OECD oil demand has declined y/y for the past four consecutive quarters and is set to fall for 2019 as a whole, the IEA says in its monthly oil market report. * OECD oil demand to drop 70k b/d this year * Seen rising by 590k b/d y/y in current quarter * Consumption in those regions since 4Q last year as follows: *T ================================================================ Quarter | Y/y demand change ================================================================ 4Q18 |‐450k b/d 1Q19 |‐380k b/d 2Q19 |‐330k b/d 3Q19 |‐190k b/d 4Q19 |590k b/d *T To contact the reporter on this story: Alex Longley in London at [email protected] To contact the editors responsible for this story: Alaric Nightingale at [email protected] Rachel Graham Russia, Oman Win From Condensate Exclusion from OPEC+ Quota: IEA 2019‐12‐12 09:00:00.10 GMT By Olga Tanas (Bloomberg) ‐‐ Exclusion of condensates from non‐OPEC oil‐ output targets gives Russia “scope to further ramp up” production of gas condensate from about 830,000 b/d currently, International Energy Agency says in its monthly oil market report. * Oman, which under existing deal had to restrict crude output to counter increasing condensate supply, will also benefit ** Condensate production was 157,000 b/d in October, up 44,000 b/d from a year ago

* Azerbaijan produced 89,000 b/d of condensate in November, up 20,000 b/d from a year ago as BP boosts Shah Deniz supplies * Kazakhstan produces “roughly” 300,000 b/d of condensate, mainly from the Karachaganak field * All non‐OPEC participants of the output‐cuts agreement produce about 1.5m b/d of oil classed as condensate * IEA sees Russia’s oil production falling 0.4% to 11.53m b/d in 2020 from 11.58m b/d this year * READ: Russia Says Its New Crude‐Only OPEC+ Target Isn’t a Loophole ‐‐With assistance from Dina Khrennikova. To contact the reporter on this story: Olga Tanas in Moscow at [email protected] To contact the editors responsible for this story: James Herron at [email protected] Christopher Sell, Helen Robertson Global Crude, Condensate Stocks Fell by 2.2M B/D in 3Q: IEA 2019‐12‐12 09:00:00.43 GMT By Brian Wingfield (Bloomberg) ‐‐ “Global balances based on crude and condensate production and refining intake and direct use imply 2.2m b/d of stock draw” in 3Q, the IEA said in its monthly Oil Market Report. * OECD crude inventories fell by 600k b/d, offset by implied build in Chinese stocks ** “The rest of the non‐OECD accounted for a 2m b/d draw” ** IEA sees crude/condensate surplus of 200k in 4Q ** Crude market to be in deficit of 300k b/d on average in 2019 * Revised data show global oil deficit of 900k b/d in 3Q, following five quarters of stock builds; largest quarterly draw since 2Q 2017 * Refined product balances grew in 3Q even as refinery runs fell y/y ** Product surplus at 200k b/d in 3Q, following deficit of 700k in 2Q ** Balance expected to be flat in 4Q, at surplus of 100k b/d on average in 2019 To contact the reporter on this story: Brian Wingfield in London at [email protected] To contact the editors responsible for this story: Alaric Nightingale at [email protected] Helen Robertson, John Deane

U.S. Oil Output Growth Forecast Cut Back on Spending Curbs: IEA 2019‐12‐12 09:00:00.11 GMT By Christopher Sell (Bloomberg) ‐‐ The IEA reduced its forecast for U.S. oil supply growth in 2020 by 110k b/d vs last month as operators continued to scale back, according to the agency’s monthly report. * U.S. oil‐production growth is expected to slow to 1.1m b/d in 2020 from 1.6m b/d this year * “Several companies that have already provided guidance for 2020 point to further declines in spending compared with 2019. Many independent players have slashed their original ambitions and are now expecting a slower pace of growth” * Oil companies laid off a further 21 rigs in November, leaving 663 in operation at the start of December, down 214 y/y * Nevertheless, Pioneer and EOG still planning for “strong” U.S. supply growth in 2020, while Exxon and Chevron continue to step up operations in the Permian ** As such, U.S crude output is expected to increase by 760k b/d; NGLs will add a further 360k b/d To contact the reporter on this story: Christopher Sell in London at [email protected] To contact the editors responsible for this story: James Herron at [email protected] Amanda Jordan, John Deane Refinery Margins Fell Across the Board in November: IEA 2019‐12‐12 09:00:00.53 GMT By Jack Wittels (Bloomberg) ‐‐ Refining margins fell m/m in all regions in November as higher crude prices pressured light product cracks and exaggerated high‐sulfur fuel oil discounts, the IEA said in monthly Oil Market Report. * Singapore Dubai margins turned negative in 2H of November, hit by lower HSFO cracks ** NOTE: HSFO values are already under pressure as the IMO 2020 deadline of Jan. 1 approaches ** Higher than usual tanker rates mean Singapore margins still have a freight penalty * U.S. Midwest margins were the most resilient on a regional basis, though still fell m/m * Margins in the U.S. Gulf Coast, northwest Europe and the Mediterranean also all fell m/m * Assessments for 0.5% sulfur bunker fuel published by several agencies indicate wide premiums to HSFO, with cracks closer to middle distillates To contact the reporter on this story:

Jack Wittels in London at [email protected] To contact the editors responsible for this story: Alaric Nightingale at [email protected] Brian Wingfield

Global Refining Runs Won’t Get Anticipated IMO Boost: IEA 2019‐12‐12 09:00:00.52 GMT By Rachel Graham (Bloomberg) ‐‐ Strike‐related outages in OECD nations will curb refinery runs in 4Q, with global throughput now set to fall from 3Q, the IEA said in its monthly report. * Global runs forecast to fall to 82.2m b/d in 1Q from 82.6m b/d in 4Q ** Both figures are below 3Q levels ** IEA said it had expected an increase in runs due to the IMO switch * Agency also cuts 2020 crude throughput forecast to 83.2m b/d To contact the reporter on this story: Rachel Graham in London at [email protected] To contact the editors responsible for this story: Alaric Nightingale at [email protected] Helen Robertson, Amanda Jordan

https://tass.com/economy/1098459 11 DEC, 10:36

Cleansing Druzhba pipeline from contaminated oil will go

into 2020, says Polish operator The Druzhba oil pipeline provides oil supplies to Belarusian refineries and its transit to Europe © Egor Aleev/TASS, archive

WARSAW, December 11. / TASS /. The cleansing of the Polish oil transfer system from polluted

oil arriving in Poland this spring will go into 2020, said Igor Vasilevsky, the head of the company

operator of the Polish section of the Druzhba PERN oil pipeline on Wednesday.

"Polish and German refineries have their own production systems. They respond restraintly to our

requests to collect more contaminated oil. They are based on our supplies, and we must constantly

sell them. There are storage facilities with and without contaminated oil. Companies decide which

ones to take from," said Vasilevsky, emphasizing that the refinery has high quality requirements.

"With this development of events, we will process contaminated oil for the whole of 2020. It all

depends on customers," he said.

Transneft announced that the full amount of compensation will be known in 2020, because its

storage facilities are also contaminated with chlorine. On the other hand, refineries will not be able

to name the final amount until all contaminated oil is processed. Today, any calculations involve

the risk of error. After processing the last batch, it will be known what needs to be replaced and

what needs to be repaired. We expect a long conversation with the Russians," said he.

The Druzhba oil pipeline provides oil supplies to Belarusian refineries and its transit to Europe. The

oil pollution in Druzhba organochlorine, detected in April, led to the suspension of pumping of

Russian oil to Ukraine, Poland, Germany, Hungary and Slovakia.

Each year, PERN, which operates as the operator of the Polish section of the pipeline, pumps about

50 million tons of oil from Russia into the national system, managing a 2.6 thousand km oil

pipeline network, and also has storage facilities with a volume of 3.5 million cubic meters and an

oil port in Gdansk with a capacity of 40 million tons of oil per year. PERN supplies two refineries

in Poland - in Plock (Orlen) and Gdansk (Lotos), as well as two refineries in Germany - in the areas

of Schwedt and Spergau.

The Druzhba oil pipeline supplies oil to Belarusian refineries and provides its transit to Europe.

PERN pumps around 50 mln tonnes of oil from Russia to the national system annually, managing a

chain of oil pipelines stretching 2,600 kilometers. It supplies two refineries in Poland - Orlan in

Plock and Lotos in Gdansk, as well as to two refineries in Germany - in Schwedt and Spergau.

In mid-April, Belneftekhim reported a sharp deterioration in the quality of the Russian oil running

through the pipeline. As a result, several states stopped receiving and refining the Russian oil.

Poland suspended the pumping on April 24. Oil supplies to the republic via Druzhba were halted

for 46 days. On June 9, supplies were resumed.

https://www.spglobal.com/platts/en/market‐insights/latest‐news/shipping/121119‐imo‐2020‐fuel‐switch‐prompts‐

bulkers‐to‐load‐less‐cargo‐to‐enable‐higher‐bunker‐intake

11 Dec 2019 | 07:22 UTC

IMO2020fuelswitchpromptsbulkerstoloadlesscargotoenablehigherbunkerintake AuthorShriramSivaramakrishnan

Singapore — The IMO 2020 sulfur regulations that take effect in three weeks' time are starting to redefine the choice of bunkering ports and impact the cargo-carrying capacity of dry bulk ships, according to freight market participants.

A large number of dry bulk carriers trading in the Asia-Pacific have already made the switch to 0.5% sulfur marine fuel to comply with the new IMO requirement.

The move is starting to result in many changes, such as dry bulk shipowner-operators preferring straight run 0.5% sulfur fuel, also known as low sulfur fuel oil or LSFO, over blended fuel grades to ensure the safety of their ships and for operational ease.

"If we go to a place where we know we can get straight run LSFO, we try to maximize and take as much of it as possible," said a ship-operating source, adding this would reduce the amount of cargo that would be loaded on the ship by 500-1,000 mt to enable the higher intake of bunker fuel.

BUNKERING DELAYS

Dry bulk shipowners are now planning the purchase of bunkers well in advance for procuring 0.5% sulfur grade; unlike in the past, when 3.5% sulfur bunker fuel was bought promptly.

"Not only do we need to plan in advance for stemming [supplying] bunkers, but there is also time involved in waiting to complete the bunkering," a shipowner said.

"We are having to book bunkers about two-three weeks in advance to ensure availability and bunker suppliers would give a small, two-three day laycan," the shipowner added.

Most of the time, it is highly unlikely that a vessel would call at the bunkering port within the laycan.

"So the bunker supplier will supply when he is ready and there have been instances of ships waiting, even in Singapore, for two days to get the bunkers," the shipowner said.

QUALITY CONCERNS

Spirited debate over the use of straight run LSFO versus blended grades is continuing as the market settles into the new IMO sulfur regulation regime.

"There is a bit of panic about the quality of blended LSFO that is available at the major bunkering ports," a second ship-operating source said.

This is causing stress among ship-operators. "There does seem to be a lot of blended fuel oil around which we as operators would not be comfortable using as we are unsure if there are going to be quality claims and how that is going to be handled," the second ship-operator said.

According to the shipowner, a lot of the blended 0.5% LSFO stems being offered to ships is "borderline" regarding sulfur limits.

"The answers on what to do with off-spec bunkers are still gray," the shipowner added.

A source with a ship-operator cited a bunker testing report showing an LSFO stem supplied in China that was far below the 0.5% sulfur cap, whereas another stem supplied at an Asian port was just marginally below the same limit.

The viscosity of the LSFO supplied, too, is causing concerns for shipowners. Many stems supplied have had issues with low viscosity. The preference is for LSFO with a viscosity of at least 100 CST.

Higher viscosity usually reflects a better calorific value and is apt for current ship engines. Lower viscosity can cause incomplete combustion and can affect the performance of the ship's engine.

Market sources said most of the LSFO available in Singapore was of the blended variety, with very little coming directly from refineries. It was also heard that a few oil majors were holding straight run LSFO that was only being sold to their close clients and made available to their own ships.

MORE BUNKER, LESS CARGO

Another issue vexing shipowners and operators is the availability of compliant fuel in ports with lower bunker sales volumes. The uncertainty over the availability of LSFO at these ports, along with the lack of clean barges, is resulting in longer waiting times for taking bunkers.

To mitigate this issue, shipowners are trying to carry as much LSFO on board as is possible given the design of the ship.

On the Indonesia-India coal route, a shipowner would typically take bunkers in Singapore, which would be just enough to ballast to South Africa after completing the cargo discharge in either east or west coast India.

But currently, shipowners-operators are trying to bunker their ships to the maximum possible volume when it passes through ports that have LSFO, and load less cargo to accommodate the extra bunker fuel on board.

The dip in cargo volume loaded on the ship also increases the freight rate slightly, a ship chartering source with a commodity trader said.

-- Shriram Sivaramakrishnan, [email protected]

-- Edited by Wendy Wells, [email protected]

Excerpt https://www.rev.com/blog/impeachment‐hearing‐day‐5‐transcript‐fiona‐hill‐and‐david‐holmes‐testimony

Impeachment Hearing Day 5 Transcript – Fiona Hill and David Holmes Testimony

Rev Nov 21, 2019

P O L I T I C A L T R A N S C R I P T S

Mr. Conaway: (02:14:07) So is it appropriate for the RT to be used to affect public policy on our nation? As an example, there’ve been a long series of advertisements, or programs on RT going against fracking, that to saying that’s bad and trying to affect public policy in the United States. Is that appropriate use? Or is that should be, should Americans be paying attention to that?

Fiona Hill: (02:14:30) In the tense that Americans should be paying attention that RT and other outlets are used to propagate this kind of information, absolutely. I wasn’t quite sure what you meant about should be paying attention-

Mr. Conaway: (02:14:40) Just that the fracking is a controversial issue within our nation. If we did away with fracking, the United States would not be in a position today to dominate the oil production within the world and would play into strengthening Putin’s hands with respect to the oil-

Fiona Hill: (02:14:52) That’s correct. And actually I’d like to point out that in November 2011, I actually sat next to Vladimir Putin at a conference in which he made precisely that point. It was the first time that he had actually done so to a group of American journalists and experts who were brought to something called the Valdai Discussion Club. So he started in 2011 making it very clear that he saw American fracking as a great threat to Russian interests. We were all struck by how much he stressed this issue and it’s since 2011, and since that particular juncture, that Putin has made a big deal of this.

PRESS RELEASE

S&P Dow Jones Indices Announces Changes to the S&P/TSX Composite Index

Toronto, Ontario, December 13, 2019 – S&P Dow Jones Indices (“S&P DJI”) today announces the rebalancing results for the S&P/TSX Composite Index. The following changes will be effective prior to the open of trading on Monday, December 23, 2019.

S&P/TSX COMPOSITE INDEX – December 23, 2019

COMPANY GICS SECTOR GICS SUB-INDUSTRY

ADDED Corus Entertainment Inc B Nvtg (TSX:CJR.B)

Communication Services Broadcasting

ADDED CT REIT (TSX:CRT.UN) Real Estate Retail REITs

ADDED Jamieson Wellness Inc. (TSX:JWEL)

Consumer Staples Personal Products

ADDED Lightspeed POS Inc. SV (TSX:LSPD)

Information Technology Application Software

ADDED Real Matters Inc. (TSX:REAL) Consumer Discretionary Internet & Direct Marketing Retail

DELETED Gran Tierra Energy Inc (TSX:GTE) Energy Oil & Gas Exploration & Production

DELETED Turquoise Hill Resources Ltd (TSX:TRQ) Materials Diversified Metals & Mining

For more information about S&P Dow Jones Indices, please visit www.spdji.com

ABOUT S&P DOW JONES INDICES

S&P Dow Jones Indices is the largest global resource for essential index-based concepts, data and research, and home to iconic financial market indicators, such as the S&P 500® and the Dow Jones Industrial Average®. More assets are invested in products based on our indices than products based on indices from any other provider in the world. Since Charles Dow invented the first index in 1884, S&P DJI has become home to over 1,000,000 indices across the spectrum of asset classes that have helped define the way investors measure and trade the markets.

S&P Dow Jones Indices is a division of S&P Global (NYSE: SPGI), which provides essential intelligence for individuals, companies, and governments to make decisions with confidence. For more information, visit www.spdji.com.

FOR MORE INFORMATION:

S&P Dow Jones Indices [email protected]

13

https://pm.gc.ca/en/mandate‐letters/minister‐finance‐mandate‐letter

MinisterofFinanceMandateLetter

Dear Mr. Morneau:

Thank you for agreeing to serve Canadians as Minister of Finance.

On Election Day, Canadians chose to continue moving forward. From coast to coast to coast, people chose to invest in their families and communities, create good middle class jobs and fight climate change while keeping our economy strong and growing. Canadians sent the message that they want us to work together to make progress on the issues that matter most, from making their lives more affordable and strengthening the healthcare system, to protecting the environment, keeping our communities safe and moving forward on reconciliation with Indigenous Peoples. People expect Parliamentarians to work together to deliver these results, and that’s exactly what this team will do.

It is more important than ever for Canadians to unite and build a stronger, more inclusive and more resilient country. The Government of Canada is the central institution to promote that unity of purpose and, as a Minister in that Government, you have a personal duty and responsibility to fulfill that objective.

That starts with a commitment to govern in a positive, open and collaborative way. Our platform, Forward: A Real Plan for the Middle Class, is the starting point for our Government. I expect us to work with Parliament to deliver on our commitments. Other issues and ideas will arise or will come from Canadians, Parliament, stakeholders and the public service. It is my expectation that you will engage constructively and thoughtfully and add priorities to the Government’s agenda when appropriate. Where legislation is required, you will need to work with the Leader of the Government in the House of Commons and the Cabinet Committee on Operations to prioritize within the minority Parliament.

We will continue to deliver real results and effective government to Canadians. This includes: tracking and publicly reporting on the progress of our commitments; assessing the effectiveness of our work; aligning our resources with priorities; and adapting to events as they unfold, in order to get the results Canadians rightly demand of us.

Many of our most important commitments require partnership with provincial, territorial and municipal governments and Indigenous partners, communities and governments. Even where disagreements may occur, we will remember that our mandate comes from citizens who are served by all orders of government and it is in everyone’s interest that we work together to find common ground. The Deputy Prime Minister and Minister of Intergovernmental Affairs is the Government-wide lead on all relations with the provinces and territories.

There remains no more important relationship to me and to Canada than the one with Indigenous Peoples. We made significant progress in our last mandate on supporting self-determination, improving service delivery and advancing reconciliation. I am directing every single Minister to determine what they can do in their specific portfolio to accelerate and build on the progress we have made with First Nations, Inuit and Métis Peoples.

I also expect us to continue to raise the bar on openness, effectiveness and transparency in government. This means a government that is open by default.It means better digital capacity and services for Canadians. It means a strong and resilient public service. It also means humility and continuing to acknowledge mistakes when we

14

make them. Canadians do not expect us to be perfect; they expect us to be diligent, honest, open and sincere in our efforts to serve the public interest.

As Minister, you are accountable for your style of leadership and your ability to work constructively in Parliament.I expect that you will collaborate closely with your Cabinet and Caucus colleagues. You will also meaningfully engage with the Government Caucus and Opposition Members of Parliament, the increasingly non-partisan Senate, and Parliamentary Committees.

It is also your responsibility to substantively engage with Canadians, civil society and stakeholders, including businesses of all sizes, organized labour, the broader public sector and the not-for-profit and charitable sectors. You must be proactive in ensuring that a broad array of voices provides you with advice, in both official languages, from every region of the country.

We are committed to evidence-based decision-making that takes into consideration the impacts of policies on all Canadians and fully defends the Canadian Charter of Rights and Freedoms. You will apply Gender-based Analysis Plus (GBA+) in the decisions that you make.

Canada’s media and your engagement with them in a professional and timely manner are essential. The Parliamentary Press Gallery, indeed all journalists in Canada and abroad, ask necessary questions and contribute in an important way to the democratic process.

You will do your part to continue our Government’s commitment to transparent, merit-based appointments, to help ensure that people of all gender identities, Indigenous Peoples, racialized people, persons with disabilities and minority groups are reflected in positions of leadership.

As Minister of Finance, you will continue to lead the Government’s work to grow the economy in a way that works for all Canadians, with continued focus on strengthening the middle class and helping those people working hard to join it. This includes immediately launching a Budget 2020 process that works with Parliament to begin the implementation of our election platform. You will support the Minister of Middle Class Prosperity and Associate Minister of Finance with her new mandate. You will also be working with me in supporting our broad agenda, and so I would ask you and your department to actively support the implementation of mandate commitments across the Ministry.

I will expect you to work with your colleagues and through established legislative, regulatory and Cabinet processes to deliver on your top priorities. In particular, you will:

Maintain four key principles for the implementation of our fiscal plan:

1. Continue to reduce the Government’s debt as a function of our economy;

2. Continue to build confidence in Canada’s economy by preserving our AAA credit rating;

3. Continue to invest in people and in the things that give people a better quality of life; and

4. Preserve fiscal firepower in the event that we need to respond to an economic downturn.

As our top Parliamentary priority, introduce legislation to cut taxes for the middle class and those working hard to join it. You will develop a new Basic Personal Amount (BPA) of $15,000. Higher income individuals should not benefit from this tax cut but will still receive the existing BPA tax credit.

Cut tax rates by 50 per cent for companies that develop and manufacture zero-emissions technology. Eligible sectors should include but not be limited to: manufacturing related to renewable energy, renewable fuels production, zero-emission vehicles, carbon sequestration and removal technology, batteries for use in zero-emission vehicles, and grid storage and electric vehicle charging systems.

15

Continue to work with the Minister for Women and Gender Equality and Rural Economic Development and the Minister of Diversity and Inclusion and Youth to improve the quality and scope of Gender-based Analysis Plus (GBA+) in future budgets.

Work with the Deputy Prime Minister and Minister of Intergovernmental Affairs to support the Minister of Health to strengthen Medicare, renewing our health agreements with the provinces and territories in four priority areas:

o Ensure that every Canadian has access to a family doctor or primary health care team;

o Set national standards for access to mental health services so Canadians can get fast access to the support they need when they need it;

o Continue to make home care and palliative care more available across the country; and

o Continue to implement national universal pharmacare, including the establishment of the Canada Drug Agency, a national formulary and a rare disease drug strategy to help Canadian families save money on high-cost drugs.

Ensure that all proceeds that the federal government receives from the Trans Mountain Expansion project, including incremental corporate income tax revenue, dividends and capital gains on sale, are invested in nature-based climate solutions and clean energy projects.

Undertake a new comprehensive review of government spending that provides transparent and public reporting to Canadians of the results and analysis.

Undertake a review of tax expenditures to ensure that wealthy Canadians do not benefit from unfair tax breaks. Ensure that this process provides transparent and public reporting to Canadians of the results and analysis.

Modernize anti-avoidance rules to stop large multinational companies from being able to shop for lower tax rates by constructing complex schemes between countries.

Close corporate tax loopholes that allow companies to excessively deduct debt to artificially reduce the tax that they pay.

Introduce a new 10 per cent tax on luxury boats, cars and personal aircraft over $100,000.

Ensure that multinational tech giants pay appropriate corporate tax on the revenue that they generate within Canada.

Work with the Organisation for Economic Co-operation and Development to ensure that international digital corporations whose products are consumed in Canada collect and remit the same level of sales tax as Canadian digital corporations.

Work with the Minister of Families, Children and Social Development who is the Minister responsible for the Canada Mortgage and Housing Corporation (CMHC) to limit housing speculation by developing a framework and introducing a 1 per cent annual vacancy and speculation tax on applicable residential properties owned by non-resident non-Canadians. This would involve working with provinces, territories, municipalities and law enforcement to track housing ownership and speculation.

In the upcoming review of the Canada Pension Plan (CPP), work with the Minister of Seniors and the provinces and territories to increase survivor benefits under the CPP and the Quebec Pension Plan by 25 per cent.

Support the Minister of Employment, Workforce Development and Disability Inclusion in implementing the Canada Training Benefit.

16

Finalize a report, which will include a list of federal fossil fuel subsidies including the description of the subsidies, annual costs and analysis of the subsidies. This report will be made public once a peer review is finalized.

Work in collaboration with provinces to ensure that the CPP enhancement is completed.

Support the Minister of Innovation, Science and Industry in concluding consultations with provinces and territories on the creation of a pan-Canadian public registry for beneficial ownership and in preparing legislation reflecting the outcome of those consultations.

Finalize amendments to the Income Tax Act to limit the benefit of the employee stock option deduction for high-income individuals employed at large, long-established mature firms.

Review and consider recommendations from financial agencies related to making the borrower stress test more dynamic.

Support the Minister of Crown-Indigenous Relations and the Minister of Indigenous Services in developing a new fiscal relationship with Indigenous Peoples.

Work with the Minister of Agriculture and Agri-Food on tax measures to facilitate the intergenerational transfer of farms.

Support the Minister of Infrastructure and Communities in ensuring that the Canada Infrastructure Bank has the support it needs for its core purpose of attracting private sector and institutional investment to expand the scope of public infrastructure investment in Canada.

Complete implementation of the new financial consumer protection framework.

Support the Minister of Innovation, Science and Industry in developing enhanced consumer protections, including the creation of a new Canadian Consumer Advocate.

These priorities draw heavily from our election platform commitments. As mentioned, you are encouraged to seek opportunities to work across Parliament in the fulfillment of these commitments and to identify additional priorities.

I expect you to work closely with your Deputy Minister and their senior officials to ensure that the ongoing work of your department is undertaken in a professional manner and that decisions are made in the public interest. Your Deputy Minister will brief you on the many daily decisions necessary to ensure the achievement of your priorities, the effective running of the government and better services for Canadians. It is my expectation that you will apply our values and principles to these decisions so that they are dealt with in a timely and responsible manner and in a way that is consistent with the overall direction of our Government.

Our ability, as a government, to implement our priorities depends on consideration of the professional, non-partisan advice of public servants. Each and every time a government employee comes to work, they do so in service to Canada, with a goal of improving our country and the lives of all Canadians. I expect you to establish a collaborative working relationship with your Deputy Minister, whose role, and the role of public servants under their direction, is to support you in the performance of your responsibilities.

We have committed to an open, honest government that is accountable to Canadians, lives up to the highest ethical standards and applies the utmost care and prudence in the handling of public funds. I expect you to embody these values in your work and observe the highest ethical standards in everything you do. I want Canadians to look on their own government with pride and trust.

As Minister, you must ensure that you are aware of and fully compliant with the Conflict of Interest Act and Treasury Board policies and guidelines. You will be provided with a copy of Open and Accountable Government to assist you as you undertake your responsibilities. I ask that you carefully read it, including

17

elements that have been added to strengthen it, and ensure that your staff does so as well. I expect that in staffing your offices you will hire people who reflect the diversity of Canada, and that you will uphold principles of gender equality, disability equality, pay equity and inclusion.

Give particular attention to the Ethical Guidelines set out in Annex A of that document, which apply to you and your staff. As noted in the Guidelines, you must uphold the highest standards of honesty and impartiality, and both the performance of your official duties and the arrangement of your private affairs should bear the closest public scrutiny. This is an obligation that is not fully discharged by simply acting within the law.

I will note that you are responsible for ensuring that your Minister’s Office meets the highest standards of professionalism and that it is a safe, respectful, rewarding and welcoming place for your staff to work.

I know I can count on you to fulfill the important responsibilities entrusted in you. It is incumbent on you to turn to me and the Deputy Prime Minister early and often to support you in your role as Minister.

Sincerely,

Rt. Hon. Justin Trudeau, P.C., M.P. Prime Minister of Canada

CHOOSE FORWARD : A RESPONSIBLE FISCAL PLAN 76

CHAPTER SEVEN

Fiscal Plan


We know that a country can’t cut its way to prosperity. Cuts don’t help people. Austerity

interests of wealthy people ahead of the middle class is not how you keep a country like Canada moving forward.

government was raise taxes on the wealthiest one percent, so that we could cut taxes for the

families with the high cost of raising their kids.

Not only because it makes good economic sense, but because it’s the right thing to do. Our invest-ments in young people and families are helping to

kids a good start in life.

Our investments in seniors are helping more people

historic investments in infrastructure are helping

climate tomorrow.

-omy was slowing down – and people were feeling it. Especially those whose real needs didn’t line

like people living in poverty, Indigenous Peoples, women, young people, racialized people, people

Because we believe that everyone deserves a real

more Canadians get ahead, but further progress is needed. With an economy that is strong and

to the size of our economy, Canada now has the best balance sheet in the G7. And together, we’ve

prepared for whatever challenges come our way. In 2019, there are events taking place around

economic uncertainty, and we need to be ready to respond.


compared to other G7 countries. Our net debt-to-

less than a third of where the United States is right now.

-

Place To Invest.

countries in the G7, only Germany can boast of a similarly strong record.

-ings agencies have in Canada’s economic strength.

people already understand: that even though there is more work to be done, our economy is strong and growing.

The last four years have shown what can happen

that make their lives easier: more money for

people living in poverty.

While others seek to move our country backward – balancing the books at all costs, on the backs of hard-working Canadians – we will move forward with the investments that we know make a

Moving Forward. Even though Canada’s economy is doing well, we need to be ready to respond to whatever challeng-es might arise, with the right tools at our disposal so that we can react quickly and appropriately when we need to.

is sustainable over the long term – and gives us the room we need to invest for long-term growth.


More Fairneeded to invest in people and keep our economy strong and growing, we will move forward with a transparent and publicly reported review of several

taxes more fair. This includes taking steps to crack down on corporate tax evasion and avoidance, and

more. We will:

• undertake a new comprehensive review of government spending and tax expenditures, to

from unfair tax breaks (a similar review, which

middle class);

•

complex schemes between countries;

•

including the United States;

• crack down on corporate tax loopholes that allow companies to excessively deduct debt to

• introduce a new 10 per cent tax on luxury cars,

• corporate tax on the revenue they generate in Canada. We will also work to achieve the

whose products are consumed in Canada collect

home prices, we will also put in place a consistent

by non-Canadians who don’t live in Canada.

New Revenue 7,192

New Investment

More Fair

undertake a new comprehensive review of pgovernment spending and tax expenditures, to g p g p

from unfair tax breaks (a similar review, which

middle class);

e, and p

more. We will:introduce a new 10 per cent tax on luxury cars,p y

crack down on corporate tax loopholes thatp pallow companies to excessively deduct debt top y

complex schemes between countries; home prices, we will also put in place a consistentp p p

by non-Canadians who don’t live in Canada.


followed through on that promise.to changes to personal or corporate income taxes.

New tax expenditure and government spending review 2,000

Cracking down on corporate tax loopholes

their fair share

217 229

10% luxury tax

Self-Financing EI Measures

-

Cracking down on corporate tax loopholes

10% luxury tax

Dan.Tsubouchi

Highlight


Helping Canadians keep more of what they earn

-11

More help for families with kids under one 777

172

the North 22 22 22

22

they need -

20

Strengthening public health care

Pediatric cancer research - - -

Canada Entrepeneur Account 100 100 100

Reducing fees for SMEs

E-payroll system 100 - -

100 100

Tourism Community Infrastructure Fund

Canada Water Agency and other measures 70 70 70

to the agricultural sector

-

Increasing the Disaster Management Assistance Fund - 100 100 100

New rebate for used ZEVs 22 17


Learn to Camp

Tackling gun crime

Free legal aid to survivors of sexual assault and - 10 10 10

- 122 127

100 100

of veterans

- 197 199

Helping spouses of CAF and RCMP who relocate

Addressing veterans’ homelessness

91 100 100

More support for arts and culture -

Training for teachers (immersion and second-language) 100 100

- - -

Enhancing support to UN peacekeeping, -

Playing a bigger role in the training and support of -

Establishing the Centre for Peace, Order and Good Government -

-

permanent residence 101 110

Monies to be reinvested in related measures 72

https://pitchbook.com/news/articles/stephen‐schwarzman‐doesnt‐stop P L A Y B O OK 4 Q 2 0 1 9

Stephen Schwarzman doesn't stop: An exclusive Q&A with Blackstone's chief By Eliza Haverstock December 6, 2019

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This story is featured in the 4Q 2019 issue of the PitchBook Private Market PlayBook. It took a few mistakes before Stephen A. Schwarzman skyrocketed. Once, a single miscalculation rippled its way through an entire deal book. Decades later, he invested $330.0 million in a company that collapsed within months—which resulted in a 100% loss. These career‐defining moments now bedeck the pages of Schwarzman's memoir "What It Takes: Lessons in the Pursuit of Excellence," published by Simon & Schuster in September 2019. It traces the story of his meteoric rise from mowing lawns in a Philadelphia suburb to becoming king of a global alternative investment empire worth $554 billion. Among his many titles: CEO, entrepreneur, philanthropist, presidential adviser and multibillionaire. Yet with all this success, Schwarzman still sees Blackstone—the firm he created in 1985—as a "work in progress," his job much the same as it ever was. And at 72, he says he has no plans of slowing down. PitchBook spoke with Schwarzman about his perspectives on the changing private equity landscape, what he describes as Blackstone's "revolution" in the industry and what's next for the legendary dealmaker. (Hint: It's not retirement.) The following interview has been edited and condensed for clarity. PitchBook: You talked a lot in your book about creating Blackstone and the defining inflection points in that journey. What was the moment when you and co‐founder Pete Peterson realized you were creating something big?

Stephen Schwarzman: I guess it was the moment when we got our circle, or commitment, from Prudential Insurance. We were basically fundraising and getting close to failing. We had $75 million from two commitments, but they were contingent upon us getting to $500 million— and we were trying to raise a billion. We were about out of names. We got to Prudential, and we're having a lunch, and I did the exact same presentation I gave to everybody else, which had resulted in only those two commitments. The chief investment officer was listening, and he said, "Sounds great. I'll give you $100 million." At that point, Prudential was the No. 1 investor in terms of size and reputation in the world of private equity. I knew that if we had their prestige and knowledge base as our lead investor, the rest of the world would follow. So, that was the moment. PB: What emotions did you have at that moment? SS: I think it was something approximating stunned amazement. PB: You rose very quickly in the ranks at Lehman Brothers, becoming a managing director at 31. How did your expertise in M&A inform your transition to private equity entrepreneurship? SS: I was used to the concept of buying or selling something. Lehman, at that point, was the most active in mergers and acquisitions of any firm. Goldman Sachs had accumulated more in terms of aggregate principal deal value—they did bigger deals across the board—but Lehman did more total deals. It was an enormous amount of activity. So, you could learn how deals were put together, what valuations were. Negotiating wasn't a periodic activity—it was almost an everyday activity. Getting business was something you had to do. So, being out and about and able to convince people to trust you with something of enormous consequence to them were skills similar to what you would need in private equity. PB: Blackstone has evolved a lot since its creation. How have you and the firm changed your perspectives on producing returns, from financial engineering in the beginning to a focus more on operational improvements and growth initiatives today? SS: From the 1980s to now, it's been sort of a revolution. Nowadays, you would never buy anything without developing a significant transformation plan beforehand, so

owning large‐scale assets isn't the type of adventure that it was in the 1980s and 90s. Now we're quite sure in terms of what needs to happen and be done at every different phase of the company's management. We own now about 200 businesses, and this is just in private equity. Private equity is only 25% of Blackstone. Real estate represents a bigger proportion of our business. We also have a huge credit business and a very good‐sized hedge fund business. When you have responsibility for hundreds of billions of dollars in assets, you have to have systems. You have to have in‐house experts. It's not like a small partnership of 10 or 15 people trying to make its way. We do group buying, and because of the total scale of the firm, I'm sure we're one of the 10 largest purchasers of supplies of all types. So, when you combine your companies doing something like that, you get enormous cost advantages. We did the same thing with healthcare costs here at the firm. It's a different type of approach than a medium size or small private equity business has. PB: You talked a little bit about the different strategies that Blackstone has pursued, such as credit and real estate. What strategy are you most excited about looking forward? SS: We're the largest owner of real estate in the world. I've been excited since 1991 about that area, and it's proven to be a really great thing. We now are so broad in terms of our presence around the world. Today, we like warehouses, because the digital economy needs warehouses for delivery of their products to customers. Digital sales are going up faster than brick‐andmortar retailing, so warehouses turned out to be a terrific focus. Certain kinds of residential real estate have turned out to be very good, such as apartment buildings and single‐family homes. We sold almost all of our shopping malls, so we didn't get hurt like many other real estate investors did. We used to be the biggest hotel owner in the world, and that turned out to be an extremely good focus, but as the economy was peaking, we sold those assets. We go in and out of asset classes and different parts of the world. It's always interesting. PB: One aspect of leveraged buyouts that you didn't delve into in your memoir is the cost‐cutting layoffs that often ensue after a financial sponsor takes the reins. A new report from economists including Josh Lerner and Steve Davis found average job losses of 4.4% in the two years after a company is bought by PE firms. How do you respond to criticism about this?

SS: I'd say the flaw in that analysis was that it was looking at only two years. The cycle in private equity, depending on what kind of company you buy, is a function of what happens with the jobs. If you're buying a very healthy company that's expanding nicely, I think the study showed that those companies grow employees 10% to 13% in their first two years. Something like that. On the other hand, say you're buying a carveout of a company, in other words, a part of a very big company. Or say you're buying a company that's done quite poorly—because people don't always sell wonderful companies—and that company needs to be restructured. But the seller, for whatever their reasons, doesn't want to do that. To make those companies healthy, there needs to be some changes of various types. You know that when you buy that business. The personnel cuts for those companies are larger. And they were using a control group—I have no idea what control group they were using. What happens with those companies is once you start getting them in shape, you put them in a growth mode. In growth mode, you end up hiring more people. The average life of a private equity deal isn't just two years. In two years, you haven't established enough growth because just reducing people count does not add a lot of value. My experience has been that there's always situations in which you get a company that has more jobs at the end of five years than you started with after the first year or two. Because that's how you make money. You should be matching the life of the investment, not cutting off the whole improvement, which is why you buy the company in the first place. I think the methodology that was chosen is unfortunate. … I don't think, at the end of the day, private equity net fires anybody. Because if you have a holding period of three years, and they're growing in years three, four and five, you didn't net fire anyone in a given year. PB: After many public private equity firms converted to C‐Corps, we've seen their market caps skyrocket. Are the public markets finally valuing Blackstone and its competitors correctly? SS: It's certainly been modified. I saw no reason why those historic valuations of 11x earnings made any sense. I was pretty straightforward about indicating that. Now we're being valued on a much more sensible basis.

The way you value companies is, what do you think the growth rate is? What's the yield? We were always significantly undervalued in part because the structure we were using, a master limited partnership, basically eliminated two‐thirds of the typically eligible buyers from owning us. By changing to a corporate form, a much, much bigger group of potential owners could buy us. We used to visit these people, and they'd say, "Geez, you've got this marvelous company, but we can't buy you." So, if we went to a mutual fund company, usually there was one manager that could buy us and seven that wouldn't. But now all seven can. In a way, it's the law of supply and demand—that's how we've made ourselves available to a much larger group. And that's working out with a much higher valuation. PB: I'd also like to hear your thoughts on longer holding times for portfolio companies. We've seen a lot of firms including Blackstone raise long‐dated or permanent capital funds. Do you think this will become a larger part of the industry? SS: I think the longer holds will slowly grow as a percentage of the industry. The compensation structure now in the industry, from the perspective of the investors, is based in part on high rates of return. Longer holds typically have somewhat lower rates of return, which makes it harder to attract that capital. It may be smarter to invest on that kind of basis, but it's harder if the people who are giving you the money are incented in a slightly different direction. We pioneered this type of investment. It's increasing in popularity. It's a smart type of investing to do, and we're optimistic about it. But it won't challenge, in terms of aggregate scale, the more traditional private equity structure. PB: In your memoir, you wrote that your mother had what it took to become the CEO of a major corporation, if only she had lived in another time. Private equity still has very few female executives, even compared with other segments in finance. What do you think needs to change in the private equity industry to encourage more female leaders? SS: Well, that's a good question. What it was, interestingly, was you had very few women who ever applied to go into private equity. For some reason, they thought this industry was a difficult place to work. It's hard to hire people when they don't apply. So, what we did about three or four years ago, is we said, OK, let's find out why women aren't applying. Let's go to campuses and explain what we do. Let's start an intern program, where women can apply and just get an introduction into what we do. In our

entry‐level classes now, we've gone from 15% women to 40%. And we still have women applying at disproportionately low rates. I think we've made some very forward‐looking approaches to trying to rebalance Blackstone's next set of employees, and we've been unbelievably successful doing that. PB: What was the worst investment you've ever made, and what did you learn from it? SS: The worst investment we ever made was called Edgecomb Steel, a steel distribution business, and it's in the book. We lost 100% of our money. It was our third deal. It resulted in changing everything we did, in terms of how we looked at a potential investment, the kind of processes that we had, the focus on downside risk and how to construct an investment committee process where everybody participates. We get the virtue of everybody's thoughts. That was a seminal moment in the firm's history. PB: You've found incredible success in your career. What more would you like to accomplish? SS: Well, I don't approach the world that way. For me, every day is a new day, and there are two things that could happen: You could do something that's really terrific, or you can stop something from becoming a mess. Both of those require enormous immediacy and focus. I don't look backward. I don't feel that Blackstone is some kind of success. I view it as a work in progress that can always go wrong. The job of myself and the other senior people here at the firm is to make sure that things don't go wrong and that things go right for our investors and the people who work here, as well as for society. There are always going to be wonderful things that happen in the future, and our job is to help figure them out and make sure we have the resources to execute that. So, I don't know. I think my job sort of is the same as it ever was. I want to make sure Blackstone's lifespan is a lot longer than my own personal lifespan, because I'm getting a bit older apparently, and the firm is just getting better and better. Featured image of Stephen Schwarzman at the 2018 Annual Meeting of the World Economic Forum via Boris Baldinger/World Economic Forum/CC BY‐NC‐SA 2.0

Excerpt from Review of Tom Peters “in search of excellence”

https://www.businessballs.com/strategy‐innovation/tom‐peters‐in‐search‐of‐excellence/

tom peters - in search of excellence

Tom Peters and Robert H Waterman Jr - In Search Of Excellence summary The seminal management book In Search of Excellence, by Tom Peters and Robert Waterman, was published in 1982, and remains one of the one of the biggest selling and widely read business books ever. Peters and Waterman found eight common themes which they argued were responsible for the success of the chosen corporations, which have become pointers for managers ever since. In Search of Excellence didn't start out as a book, as Tom Peters explained when interviewed in 2001 to mark the 20th anniversary of In Search of Excellence: Peters and Waterman were both consultants on the margins of McKinsey, based in the San Francisco office. In 1977 McKinsey director Ron Daniel launched two projects; the first and major one, the Business Strategy project, was allocated to top consultants at McKinsey's New York corporate HQ and was given star billing. Nothing came of it. The second 'weak-sister' project (as Peters called it) concerned Organisation - structure and people. The Organisation project was seen as less important, and was allocated to Peters and Waterman at San Francisco. Peters travelled the world on an infinite budget, with licence to talk to as many interesting business people he could find about teams and organisations in business. He had no particular aim or theory in mind. In 1979 McKinsey's Munich office requested Peters to present his findings to Siemens, which provided the spur for Peters to create a 700-slide two-day presentation. Word of the meeting reached the US and Peters was invited to present also to PepsiCo, but unlike the hyper-organised Siemens, the PepsiCo management required a tighter format than 700 slides, so Peters produced the eight themes.

The platform for Peters and Waterman onto which the In Search Of Excellence research and theorising was built, was the McKinsey 7-S model:

McKinsey 7-S model elements 1. structure 2. strategy 3. systems 4. style of management 5. skills - corporate strengths 6. staff 7. shared values

Peters and Waterman examined 43 of Fortune 500's top performing companies. They started with a list of 62 of the best performing McKinsey clients and then applied performance measures to weed out what they thought to be the weaker companies. General Electric was one of the casualties which failed to make the cut. Peters says that one of his personal drivers in carrying out his research was to prove that certain established methods - particularly heavily systemised philosophies and practices - were wrong, notably those used by Xerox, and advocated by Peter Drucker and Robert McNamara. Peters says that he wanted - with a passion - to prove how crucial people are to business success , and to release business from the 'tyranny of the bean counters'.

As Peters explained in 2001: 'Start with Taylorism, add a layer of Druckerism and a dose of McNamaraism, and by the late 1970's you had the great American corporation that was being run by bean counters...'

Contrast this with what Peters says became the essential message of In Search of Excellence, simply:

People Customers Action

Peters says that In Search of Excellence turned these 'soft' factors into hard ones, when previously the only 'hard factors were considered to be the 'numbers'.

Peters also said in 2001 that other than certain wrong companies highlighted - Atari and Wang for instance - In Search of Excellence 'absolutely nailed the eight points of the compass for business at that time' (1982), but that its central flaw was in suggesting that these points would apply for ever, when they most certainly have not.

Peters said finally in his 2001 interview that were he to write In Search of Excellence today, he would not tamper with any of the eight themes, but he would add to them: capabilities concerning ideas, liberation, and speed.

Here is a summary of the 'In Search of Excellence' eight themes, which also form the eight chapters of the book.

In Search of Excellence - the eight themes 1. A bias for action, active decision making - 'getting on with it'. 2. Close to the customer - learning from the people served by the business. 3. Autonomy and entrepreneurship - fostering innovation and nurturing 'champions'. 4. Productivity through people - treating rank and file employees as a source of quality. 5. Hands-on, value-driven - management philosophy that guides everyday practice -

management showing its commitment. 6. Stick to the knitting - stay with the business that you know. 7. Simple form, lean staff - some of the best companies have minimal HQ staff. 8. Simultaneous loose-tight properties - autonomy in shop-floor activities plus centralised

values.