Easwaran Kanason

Co - founder of NrgEdge
Last Updated: April 24, 2018
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Business Trends
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Saudi Aramco’s plan to diversify its downstream portfolio reached another milestone last week, as the OPEC giant signed an agreement with India to invest in the planned 1.2 mmb/d Ratnagiri refinery in Maharashtra state. In return, Aramco receives a 50% stake in the refinery – itself a joint venture between Indian Oil, HPCL and BPCL, previewing a possible future where India’s state refiners are merged into one – and assurances that Saudi Arabia crude will always find a home in India. Over the last year, Aramco planned a spat of deals designed to do exactly this – ensure that it has captive demand in key crude markets, particularly in Asia – and of late, the plans have taken a further dimension: expansion into petrochemicals.

In the US, Aramco is now the sole owner of the Port Arthur refinery under Motiva, having cajoled Shell into a divorce of their former joint venture. Post-divorce, Aramco quickly announced up to US$30 billion in investments up to 2023 for America’s largest refining site – which some saw as a move to curry favour with the new Trump administration – and earlier this month, announced it was looking at adding a new 1.5 mtpa ethylene plant using ethane cracked from US shale fields in Texas. At home in Saudi Arabia, Aramco has signed a US$5 billion deal with France’s Total to build a 1.5 mtpa ethylene plant that will be integrated with the existing joint venture 440 kb/d Satorp refinery in Jubail.

Notice a pattern emerging? It becomes more evident when considering Aramco’s latest investments in Asia. Long entrenched in Japan, Aramco has been courting Chinese refiners to ensure continued market share in the most important energy market in the world, fending off competition from Russia, Iraq and Iran. The latest deal revolves around a stake in PetroChina’s 260 kb/d Anning refinery in Yunnan, which has yet to be finalised, along with chatter that China will take a direct stake in Aramco through its planned IPO. But petrochemicals seem to becoming more important for Aramco. Last month, it formally concluded its US$7 billion participation in the US$27 billion RAPID refinery by Petronas in Malaysia, with a significant petrochemical portion of at least 3.6 mtpa. At the same time, there seems to be no movement on Aramco’s planned investment in Indonesian downstream, including a plan to expand Cilacap, none of which include major petrochemical portions.

The plan to own half of Ratnagiri jives in with this approach. The US$44 billion Indian refinery will need crude, and what better way than to partner with the world’s largest oil producer to secure that? In return, Aramco gains access to the world’s fastest growing energy market and Ratnagiri’s massive planned petrochemical capacity of 18 mtpa. With this concluded, Aramco now has downstream refining and petrochemical ‘silos’ in the USA, Middle East, India, China and Southeast Asia; that’s all of the major markets covered. The next step would be to deepen its ties in China, so watch what Saudi Aramco does next.

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January, 24 2020
EIA expects U.S. net natural gas exports to almost double by 2021

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:

  • Pipelines in Central and Southwest Mexico (1.2 Bcf/d La Laguna–Aguascalientes and 0.9 Bcf/d Villa de Reyes–Aguascalientes–Guadalajara)
  • Pipelines in Western Mexico (0.5 Bcf/d Samalayuca–Sásabe)

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:

  • Trains 2 and 3 at Cameron LNG in Louisiana
  • Train 3 at Freeport LNG in Texas
  • Trains 5–10, six Moveable Modular Liquefaction System (MMLS) units, at Elba Island in Georgia

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.

monthly natural gas trade

Source: U.S. Energy Information Administration, Natural Gas Monthly

January, 24 2020
EIA forecasts U.S. crude oil production growth to slow in 2021

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.

Figure 1. U.S. crude oil production

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).

Figure 2. Monthly U.S. crude oil production by region

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).

Figure 3. Cash flow statement items for 46 U.S. oil producers

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).

Figure 4. Selected questions from the Federal Reserve Bank of Dallas' Energy Survey

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.

January, 24 2020