U.S. Gulf Coast crude oil imports averaged 1.8 million barrels per day (b/d) in March 2019, the lowest level since March 1986 and significantly lower than the peak of 6.6 million b/d in March 2007. Preliminary weekly data indicate that Gulf Coast crude oil imports have averaged about 1.9 million b/d through April and May (Figure 1). Falling crude oil imports into the U.S. Gulf Coast so far in 2019 are the result of both recent events and continuing longer-term trends. Recently, sanctions on Venezuelan imports and heavy refinery maintenance have reduced imports. At the same time, imports to the Gulf Coast have also decreased because of sharp declines in imports from the Organization of the Petroleum Exporting Countries (OPEC) following an agreement among members to reduce production and because imports are being replaced by increased production of domestic crude oil. Together, these trends have fundamentally changed how the Gulf Coast region is supplied with crude oil. In the past five consecutive months, the U.S. Gulf Coast has exported more crude oil than it imported (net exports), and since 2015, it has consistently received more crude oil from other regions of the United States than it has sent to other regions (net receipts).
Gulf Coast crude oil imports are typically lower in the early months of the year as refineries reduce runs as part of their seasonal maintenance. This year, planned maintenance activity was higher than usual. The four-week average of gross refinery inputs in the Gulf Coast fell from 9.6 million b/d for the week ending January 4, higher than the five-year (2014-18) maximum and 648,000 b/d higher than the five-year average, to a low of about 8.6 million b/d from mid-February until mid-April. Although 8.6 million b/d of gross refinery inputs is more than the Gulf Coast’s five-year average level for the period, eight consecutive weeks of relatively flat refinery runs is longer than normal during refinery maintenance at this time of year. This extended period of lower refinery runs for longer in the early months of 2019 reduced the need for crude oil imports, contributing to the more-than-three-decade-low crude oil imports during this period.
Around the same time, the U.S. government announced additional sanctions on Venezuela that included limitations on crude oil imports from Venezuela. In 2018, 20% of all Gulf Coast crude oil imports were from Venezuela, an annual average of 498,000 b/d. The Gulf Coast was the destination for 98% of all U.S. imports of Venezuelan crude oil in 2018. Because of the imposition of sanctions, refiners in the Gulf Coast sharply reduced imports of Venezuelan crude oil. Between January and March 2019, Gulf Coast imports of crude oil from Venezuela fell by 498,000 b/d to 47,000 b/d in March. As a result of the Gulf Coast reductions, U.S. four-week average imports from Venezuela fell from 603,000 b/d for the week ending January 25 to 12,000 b/d for the week ending May 31 (Figure 2).
An additional change in Gulf Coast crude oil imports occurred following a November 2016 agreement by OPEC members to cut crude oil production. As a result of the production cuts, many OPEC members reduced exports to the United States in favor of growing markets in Asia. One year after the production-cut agreement, crude oil imports from OPEC processed at Gulf Coast refineries had fallen 562,000 b/d from 2.1 million b/d in November 2016 to 1.5 million b/d in November 2017. Imports of crude oil from OPEC members into the Gulf Coast continued to decline, falling to 1.4 million b/d in 2018 and down to 513,000 b/d in March 2019 (Figure 3).
Before the OPEC production cuts in 2016, the Gulf Coast had already started reducing crude oil imports because of rising domestic production and changes in domestic crude oil pipeline infrastructure. Gulf Coast crude oil production increased from 2.7 million b/d in 2008 to 7.9 million b/d in March 2019. Much of this increased crude oil production was of light sweet crude oil that allowed Gulf Coast refineries to reduce imports of light sweet crude oil from foreign sources. Then pipeline infrastructure that once took imported crude oil from the Gulf Coast and delivered it to other regions of the United States was reversed, instead delivering increased domestic crude oil production and imports from Canada to Gulf Coast refineries. By 2015, this reversal meant that the Gulf Coast changed from being a net shipper of crude oil to other U.S. regions to being a net recipient. More recently, as imports have declined and crude oil exports have expanded, the Gulf Coast actually exported more crude oil than it imported for five consecutive months (Figure 4).
Because of all these changes combined, foreign-sourced crude oil receipts at Gulf Coast refineries accounted for an average of 36% of Gulf Coast refinery crude oil inputs in 2018, compared with 73% in 2008. The sources of those imports have also changed, with Canada and Mexico accounting for 54% of all imported crude oil processed in Gulf Coast refineries in March, representing a new high.
U.S. average regular gasoline and diesel prices fall
The U.S. average regular gasoline retail price fell nearly 2 cents from the previous week to $2.81 per gallon on June 3, more than 13 cents lower than the same time last year. The Gulf Coast price fell nearly 5 cents to $2.42 per gallon, the West Coast price fell nearly 4 cents to $3.60 per gallon, and the East Coast price fell more than 3 cents to $2.66 per gallon. The Midwest price rose more than 3 cents to $2.75 per gallon and the Rocky Mountain price increased slightly, remaining at $2.98 per gallon.
The U.S. average diesel fuel price fell nearly 2 cents to $3.14 per gallon on June 3, nearly 15 cents lower than a year ago. The West Coast price fell more than 2 cents to $3.76 per gallon, the Rocky Mountain and Gulf Coast prices each fell nearly 2 cents to $3.16 per gallon and $2.88 per gallon, respectively, and the Midwest and East Coast prices each fell over 1 cent to $3.03 per gallon and $3.15 per gallon, respectively.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 2.5 million barrels last week to 68.3 million barrels as of May 31, 2019, 9.1 million barrels (15.4%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast inventories increased by 1.2 million barrels, and Midwest and East Coast inventories each increased by 0.7 million barrels. Rocky Mountain/West Coast inventories decreased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 7.2% 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.