The United States exported 7.3 million barrels per day (b/d) of crude oil and petroleum products in the first half of 2018, when exports of crude oil and hydrocarbon gas liquids (HGL) set record monthly highs. Crude oil surpassed HGLs to become the largest U.S. petroleum export, with 1.8 million b/d of exports in the first half of 2018. U.S. exports of crude oil, HGLs, and motor gasoline grew in the first half of 2018 compared with the same period in 2017, while distillate exports decreased 84,000 b/d (Figure 1).
U.S. crude oil exports increased by 787,000 b/d (almost 80%) from the first half of 2017 to the first half of 2018 and set a new monthly record of at 2.2 million b/d in June. Destinations in Asia and Oceania were the largest recipients of U.S. crude oil exports in the first half of 2018, and U.S. crude oil exports to China more than doubled—increasing by 193,000 b/d—from the first half of 2017. U.S. crude oil exports to South Korea and India also increased significantly during this period, up 81,000 b/d and 72,000 b/d, respectively.
Europe was the second-largest market for U.S. crude oil exports, receiving 555,000 b/d in the first half of 2018. U.S. crude oil export volumes to Europe are more equally distributed than in other regions. Italy, the United Kingdom, and the Netherlands, each received more than 120,000 b/d in the first half of 2018. Canada was the only major U.S. crude oil export destination where exports decreased somewhat, down 13,000 b/d in the first half of 2018 compared with the same period in 2017 (Figure 2).
HGLs were the second-largest petroleum export from the United States in the first half of 2018 at 1.6 million b/d. Destinations in Asia and Oceania were also the primary recipients of U.S. HGLs at 618,000 b/d in the first half of 2018. The region’s main importers were Japan, South Korea, China, and India, many of which have expanded petrochemical facilities that import U.S. HGLs as a feedstock. The second-largest regional destinations for U.S. HGL exports in the first half of 2018 were Canada and Mexico in North America, which received a combined 453,000 b/d in the first half of 2018 (Figure 3). U.S. HGL exports also set a new monthly record in the first half of 2018 at 1.7 million b/d in May 2018.
In the first half of 2018, the United States exported 1.3 million b/d of distillate, primarily to destinations in Central and South America, with Brazil and Chile as the two largest destinations, receiving 131,000 b/d and 114,000 b/d, respectively. The decline in U.S. distillate exports in the first half of 2018 compared with the first half of 2017 is mostly the result of lower exports to a number of destinations in Central and South America and in Europe. However, U.S. distillate exports are typically higher in summer months, most of which occur in the second half of the year. The largest single destination for U.S. distillate exports in the first half of 2018 was Mexico at 289,000 b/d (Figure 4). Despite being the third-largest U.S. petroleum export, U.S. distillate exports go to the largest number of destinations—as 49 different destinations received at least 1,000 b/d in the first half of 2018.
The United States exported 913,000 b/d of motor gasoline in the first half of 2018, an increase of 144,000 b/d compared with the same period in 2017. Mexico accounted for more than half of U.S. motor gasoline exports in the first half of 2018, the largest single-destination concentration for any U.S. petroleum export (Figure 5). Years of under investment in Mexico’s refineries, combined with a mismatch between the type of crude oil produced locally and the type of crude oil Mexico’s refineries were designed to process, has resulted in low refinery utilization rates. Low refinery utilization has resulted in increased imports of motor gasoline and other petroleum products, from the United States. Mexico’s gasoline consumption ranges from 780,000 b/d to 800,000 b/d based on recent history. In the first half of 2018, U.S. gasoline exports to Mexico accounted for more than 60% of the gasoline consumed in Mexico.
U.S. average regular gasoline price decreases, diesel price increases
The U.S. average regular gasoline retail price decreased less than 1 cent from last week to $2.82 per gallon on September 3, 2018, up 15 cents from the same time last year. West Coast prices increased nearly two cents to $3.33 per gallon, and East Coast and Rocky Mountain prices each rose over one cent to $2.78 per gallon and $3.01 per gallon, respectively. Midwest prices fell nearly three cents to $2.73 per gallon and Gulf Coast prices decreased two cents to $2.55 per gallon.
The U.S. average diesel fuel price increased over 2 cents from last week to $3.25 per gallon on September 3, 2018, 49 cents higher than a year ago. Midwest prices increased nearly four cents to $3.19 per gallon, Gulf Coast prices rose over three cents to $3.04 per gallon, West Coast prices increased more than two cents to $3.74 per gallon, and East Coast prices increased over one cent to $3.24 per gallon. Rocky Mountain prices were unchanged, remaining at $3.36 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 2.0 million barrels last week to 73.4 million barrels as of August 31, 2018, 9.7 million barrels (11.7%) lower than the five-year (2013-2017) average inventory level for this same time of year. Midwest, Gulf Coast, and East Coast inventories increased by 1.2 million barrels, 0.5 million barrels, and 0.3 million barrels, respectively, while Rocky Mountain/West Coast inventories fell slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 3.9% of total propane/propylene inventories.
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Nagman has diversified into dealing with Flow meters or Instruments viz Electro-Magnetic Flow Meters, Coriolis Mass Flow Meter, Positive Displacement Flow Meter, Vortex Flow Meter, Turbine Flow Meter, Ultrasonic Flow Meter.
Electro-Magnetic Flow Meter:
Size : DN 3 to DN 3000 mm
Flow Velocity : 0.5 m/s to 15 m/s
Accuracy : ±0.5%, ±0.2% of Reading
Coriolis Mass Flow Meter:
Size : DN8~DN300
Flow Range : 8 to 2500000 Kg/hr (for liquids)
4 to 2500000 Kg/hr (for gases)
Accuracy : 0.1% 0.2% 0.5% of Normal Flow Range
Positive Displacement Flow Meter:
Size : DN 15 ~ DN 400
Max. Flow Range : 0.3 m3/hr to 1800 m3/hr
(Will vary based on the measured media & temperature)
Accuracy : 0.1% 0.2% 0.5%
Vortex Flow Meter:
Size : DN 25 to DN 300
Flow Range : 1.3 m3/hr to 2000 m3/hr (Water)
8.0 m3/hr to 10000 m3/hr (Air)
Accuracy : ±1.0% of Reading
Turbine Flow Meter:
Size : DN 4 to DN 200
Flow Range : 0.02 m3 /hr to 680 m3 /hr
Accuracy : 1.0% or 0.5% of Rate
Ultrasonic Flow Meter:
Type : Hand held Ultrasonic Flow meter with S2, M2, L2 Sensors
Accuracy : ±1% of Reading at rates > 0.2 mps
Measuring Range : DN 15 – DN 6000
In its Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that U.S. natural gas exports will exceed natural gas imports by an average 7.3 billion cubic feet per day (Bcf/d) in 2020 (2.0 Bcf/d higher than in 2019) and 8.9 Bcf/d in 2021. Growth in U.S. net exports is led primarily by increases in liquefied natural gas (LNG) exports and pipeline exports to Mexico. Net natural gas exports more than doubled in 2019, compared with 2018, and EIA expects that they will almost double again by 2021 from 2019 levels.
The United States trades natural gas by pipeline with Canada and Mexico and as LNG with dozens of countries. Historically, the United States has imported more natural gas than it exports by pipeline from Canada. In contrast, the United States has been a net exporter of natural gas by pipeline to Mexico. The United States has been a net exporter of LNG since 2016 and delivers LNG to more than 30 countries.
In 2019, growth in demand for U.S. natural gas exports exceeded growth in natural gas consumption in the U.S. electric power sector. Natural gas deliveries to U.S. LNG export facilities and by pipeline to Mexico accounted for 12% of dry natural gas production in 2019. EIA forecasts these deliveries to account for an increasingly larger share through 2021 as new LNG facilities are placed in service and new pipelines in Mexico that connect to U.S. export pipelines begin operations.
Net U.S. natural gas imports from Canada have steadily declined in the past four years as new supplies from Appalachia into the Midwestern states have displaced some pipeline imports from Canada. U.S. pipeline exports to Canada have increased since 2018 when the NEXUS pipeline and Phase 2 of the Rover pipeline entered service. Overall, EIA projects the United States will remain a net natural gas importer from Canada through 2050.
U.S. pipeline exports to Mexico increased following expansions of cross-border pipeline capacity, averaging 5.1 Bcf/d from January through October 2019, 0.5 Bcf/d more than the 2018 annual average, according to EIA’s Natural Gas Monthly. The increase in exports was primarily the result of increased flows on the newly commissioned Sur de Texas–Tuxpan pipeline in Mexico, which transports natural gas from Texas to the southern Mexican state of Veracruz. Several new pipelines in Mexico that were scheduled to come online in 2019 were delayed are expected to enter service in 2020:
U.S. LNG exports averaged 5 Bcf/d in 2019, 2 Bcf/d more than in 2018, as a result of several new facilities that placed their first trains in service. This year, several new liquefaction units (referred to as trains) are scheduled to be placed in service:
In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction capacity to 10.2 Bcf/d (baseload) and 10.8 Bcf/d (peak). EIA expects LNG exports to continue to grow and average 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021, as facilities gradually ramp up to full production.
Source: U.S. Energy Information Administration, Natural Gas Monthly
In the January 2020 update of its Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that U.S. crude oil production will average 13.3 million barrels per day (b/d) in 2020, a 9% increase from 2019 production levels, and 13.7 million b/d in 2021, a 3% increase from 2020. Slowing crude oil production growth results from a decline in drilling rigs during the past year that EIA expects will continue through most of 2020. Despite the decline in rigs, EIA forecasts production will continue to grow as rig efficiency and well-level productivity rise, offsetting the decline in the number of rigs until drilling activity accelerates in 2021.
EIA’s U.S. crude oil production forecast is based on the West Texas Intermediate (WTI) price forecast in the January 2020 STEO, which rises from an average of $57 per barrel (b) in 2019 to an average of $59/b in 2020 and $62/b in 2021. The price forecast is highly uncertain, and any significant divergence of actual prices from the projected price path could change the pace of drilling and new well completion, which would in turn affect production.
Crude oil production in the Lower 48 states has a relatively short investment and production cycle. Changes in Lower 48 crude oil production typically follow changes in crude oil prices and rig counts with about a four- to six-month lag. Because EIA forecasts WTI prices will decline during the first half of 2020 but begin increasing in the second half of the year and into 2021, forecast U.S. crude oil production grows slowly month over month until the end of 2020. In contrast, crude oil production in Alaska and the Federal Offshore Gulf of Mexico (GOM) is driven by long-term investment that is typically less sensitive to short-term price movements.
In 2019, Lower 48 production reached its largest annual average volume of 9.9 million b/d, and EIA expects it to increase further by an average of 1.0 million b/d in 2020 and 0.4 million b/d in 2021. EIA forecasts the GOM region will grow by 0.1 million b/d in 2020 to 2.0 million b/d and to remain relatively flat in 2021 because several projects expected to come online in 2021 will not start producing until late in the year and will be offset by declines from other producing fields. Alaska’s crude oil production will remain relatively unchanged at about 0.5 million b/d in 2020 and in 2021.
The Permian region remains the most prolific growth region in the United States. Favorable geology combined with technological improvements have contributed to the Permian region’s high returns on investment and years of remaining oil production growth potential. EIA forecasts that Permian production will average 5.2 million b/d in 2020, an increase of 0.8 million b/d from 2019 production levels. For 2021, the Permian will produce an average of 5.6 million b/d. EIA forecasts that the Bakken region in North Dakota will be the second-largest growth area in 2020 and 2021, growing by about 0.1 million b/d in each year (Figure 2).
EIA expects crude oil prices higher than $60/b in 2021 will contribute to rising crude oil production because producers will be able to fund drilling programs through cash flow and other funding sources, despite a somewhat more restrictive capital market. Financial statements of 46 publically-traded U.S. oil producers reveal that these companies generated sufficient cash from operating activities to fund investment and grow production with WTI prices in the $55/b–$60/b range. The 46 selected companies produced more than 30% of total U.S. liquids production in the third quarter of 2019. The four-quarter moving average free cash flow for these companies ranged between $1.7 billion and $3.5 billion from the fourth quarter of 2017 through the second quarter of 2019. The third quarter of 2019—the latest quarter for which data are available—had less cash from operations than investing activities, but this figure was skewed by the large, one-time acquisition cost of Anadarko Petroleum by Occidental, valued at $55 billion (Figure 3).
Results for these 46 publicly traded companies do not represent all U.S. oil producers because private companies that do not publish financial statements are not included in EIA’s analysis. The Federal Reserve Bank of Dallas Energy Survey sheds some light on the financial position of a broader set of companies. Released quarterly, the bank’s survey asks oil companies about business activity and employment and asks a few special questions that change each quarter. The number of companies that participate varies each quarter, but generally the survey includes about 100 exploration and production companies. In the most recent survey (from the fourth quarter of 2019), 75% of survey respondents said they can cover their capital expenditures through cash flow from operations at a WTI price of less than $60/b. In addition, 40% of survey respondents plan to increase capital expenditures in 2020 compared with 2019, while 24% of respondents expect to spend about the same (Figure 4).
Since about 2017, large, globally integrated oil companies have acquired more acreage in Lower 48 regions, particularly in the Permian. These companies have announced investment plans to make Lower 48 production an increasing portion of their portfolios. These companies can typically fund their investment programs through cash flow from operations and are generally less susceptible to tighter capital markets than smaller oil companies. The financial results of the public companies shown in Figure 3 and the Federal Reserve survey support EIA’s production forecast and suggest that U.S. crude oil production can continue to grow under EIA’s price forecast for 2020 and 2021 because many companies are less dependent on debt or equity to fund investment.
U.S. average regular gasoline and diesel prices decline
The U.S. average regular gasoline retail price fell more than 3 cents from the previous week to $2.54 per gallon on January 20, 29 cents higher than the same time last year. The Midwest price fell over 5 cents to $2.39 per gallon, the Gulf Coast price fell nearly 5 cents to $2.23 per gallon, the Rocky Mountain price fell more than 3 cents to $2.57 per gallon, the East Coast price fell more than 2 cents to $2.50 per gallon, and the West Coast price fell nearly 2 cents to $3.18 per gallon.
The U.S. average diesel fuel price fell nearly 3 cents from the previous week to $3.04 per gallon on January 20, 7 cents higher than a year ago. The Rocky Mountain price fell nearly 6 cents to $3.01 per gallon, the East Coast price fell nearly 4 cents to $3.08 per gallon, the Midwest price declined almost 3 cents to $2.94 per gallon, the West Coast price fell nearly 2 cents to $3.57 per gallon, and the Gulf Coast price dropped more than 1 cent to $2.80 per gallon.
Propane/propylene inventories decline
U.S. propane/propylene stocks decreased by 1.4 million barrels last week to 86.5 million barrels as of January 17, 2020, 17.1 million barrels (24.6%) greater than the five-year (2015-19) average inventory levels for this same time of year. Midwest, East Coast, Gulf Coast, and Rocky Mountain/West Coast inventories decreased by 0.7 million barrels, 0.4 million barrels, 0.2 million barrels, and 0.1 million barrels, respectively. Propylene non-fuel-use inventories represented 6.9% of total propane/propylene inventories.
Residential heating fuel prices decrease
As of January 20, 2020, residential heating oil prices averaged nearly $3.07 per gallon, 3 cents per gallon below last week’s price and 10 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged almost $1.96 per gallon, more than 7 cents per gallon below last week’s price and more than 7 cents per gallon lower than a year ago.
Residential propane prices averaged almost $2.01 per gallon, less than 1 cent per gallon below last week’s price and more than 42 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.60 per gallon, nearly 4 cents per gallon lower than last week’s price and 20 cents per gallon below last year’s price.