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The United States continues trend toward exporting more gasoline than it imports


Despite record high gasoline consumption, the United States is on pace to export more gasoline than it imports for the second year in a row. Changes in regional markets, increased demand for exports, and high refinery runs are once again leading to the United States to be a net exporter in 2017.


In 2016, the United States became a net exporter of gasoline for the first time on an annual basis with net gasoline exports of 56,000 barrels per day (b/d). Through September 2017 (the most recently available monthly data), the United States averaged net gasoline exports of 55,000 b/d. The shift toward net exports of gasoline on an annual basis has been a long-running trend.


U.S. gasoline imports and exports are highly seasonal. The United States has typically been a net importer of gasoline in spring and summer months, when domestic consumption increases, and a net exporter in winter months, when demand is lower. However, for every month between April and August 2017, the United States set either record low net imports or record high net exports (Figure 1). Almost year-round net gasoline exports is a major change for U.S. gasoline markets, which is the result of one long-term trend and two more recent trends.

Figure 1. U.S. total motor gasoline trade


Changes in trends of gasoline production and consumption in the Midwest United States, in part, have driven this trend. Historically, the U.S. Gulf Coast (Petroleum Administration for Defense District (PADD) 3) supplied refined products to other regions of the United States where demand exceeded supply, such as the Midwest (PADD 2) and the U.S. East Coast (PADD 1). While the East Coast still relies on supplies from the Gulf Coast and still remains a large net importer of gasoline—619,000 b/d in 2016, the Midwest has reduced its need to draw supplies from the Gulf Coast in recent years. Midwest refineries now are running at higher rates and increased capacity, resulting in more Midwest gasoline demand being met from in-region production. Between 2006 and 2016, Midwest receipts of gasoline from the Gulf Coast declined by 278,000 b/d to 273,000 b/d.


Because of logistical and economic constraints on sending increasing gasoline supplies from the Gulf Coast to other regions, the volumes of gasoline no longer demanded by the Midwest have become available for export. With the Rocky Mountain (PADD 4) and U.S. West Coast (PADD 5) relying largely on in-region or domestic supplies, the balance of U.S. net gasoline imports or exports is between East Coast imports and Gulf Coast exports. Between 2013 and 2016, Gulf Coast gasoline exports increased by 236,000 b/d (54%), while East Coast imports increased by 41,000 b/d (7%), resulting in a shift for the United States as a whole.

Figure 2. PADD total motor gasoline trade


Available Gulf Coast gasoline supplies come at a time when both domestic and nearby fuel markets are experiencing increasing demand for multiple petroleum products, including gasoline. A majority of the growth in U.S. gasoline exports has been to markets in Mexico and Central and South America. In the first half of 2017, Mexico accounted for 53% of the 755,000 b/d of U.S. total motor gasoline exports. Low utilization of Mexican refineries and the ongoing market reforms of Mexico’s retail fuel distribution have resulted in continued increased demand for gasoline supplies from the U.S. Gulf Coast.


At the same time, U.S. domestic gasoline consumption has been increasing to record levels. U.S. gasoline consumption, as measured by product supplied, set a new monthly record high of 9.8 million b/d in August 2017. To meet the combined record domestic gasoline demand and the increased export demand for multiple petroleum products—including gasoline—U.S. refineries have been running at increasingly higher rates. U.S. gross refinery inputs set a record high of 17.8 million b/d for the week ending August 25 and have been higher than the five-year range for a majority of 2017 (Figure 3).

Figure 3. U.S. gross refinery inputs


If the trends of increasing demand from export markets and U.S. refineries producing near record levels of gasoline continues, the United States is likely to become a monthly net exporter of gasoline more consistently.


U.S. average regular gasoline prices fall, diesel prices increase


The U.S. average regular gasoline retail price fell nearly 4 cents from the previous week to $2.53 per gallon on November 27, up 38 cents from the same time last year. The Midwest price fell eight cents to $2.42 per gallon, the Gulf Coast price fell over two cents to $2.26 per gallon, the East Coast and West Coast prices each fell nearly two cents to $2.51 per gallon and $3.04 per gallon, respectively, and the Rocky Mountain price fell less than one cent, remaining at $2.54 per gallon.


The U.S. average diesel fuel price increased over 1 cent to $2.93 per gallon on November 27, 51 cents higher than a year ago. The Rocky Mountain and Gulf Coast prices each increased over two cents to $3.03 per gallon and $2.71 per gallon, respectively, the East Coast and Midwest prices each increased one cent to $2.91 per gallon and $2.88 per gallon, respectively, and the West Coast price increased less than one cent, remaining at $3.38 per gallon.


Propane inventories decline


U.S. propane stocks decreased by 0.6 million barrels last week to 73.2 million barrels as of November 24, 2017, 10.4 million barrels (12.5%) lower than the five-year average inventory level for this same time of year. Gulf Coast, Midwest, and Rocky Mountain/West Coast inventories decreased by 0.5 million barrels, 0.3 million barrels, and 0.2 million barrels, respectively, while East Coast inventories rose by 0.5 million barrels. Propylene non-fuel-use inventories represented 3.5% of total propane inventories.


Residential heating oil and propane prices continue to increase


As of November 27, 2017, residential heating oil prices averaged $2.85 per gallon, over 2 cents per gallon more than last week and almost 45 cents per gallon higher than last year’s price at this time. The average wholesale heating oil price for this week is just under $2.04 per gallon, nearly 1 cent per gallon less than last week but 45 cents per gallon higher than a year ago.


Residential propane prices averaged $2.43 per gallon, almost 2 cents per gallon more than last week and nearly 36 cents per gallon higher than a year ago. Wholesale propane prices averaged $1.12 per gallon, unchanged from last week but 48 cents per gallon higher than last year's price.

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Renewables became the second-most prevalent U.S. electricity source in 2020

In 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.

In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.

Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.

We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.

monthly U.S electricity generation from all sectors, selected sources

Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.

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PRODUCTION DATA ANALYSIS AND NODAL ANALYSIS

Kindly join this webinar on production data and nodal analysis on the 4yh of August 2021 via the link below

https://www.linkedin.com/events/productiondataanalysis-nodalana6810976295401467904/

July, 28 2021
Abu Dhabi Lifts The Tide For OPEC+

The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.

How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.

The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.

The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.

On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.

But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.

For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.

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Market Outlook:

  • Crude price trading range: Brent – US$72-74/b, WTI – US$70-72/b
  • Worries about new Covid-19 infections worldwide dragging down demand just as OPEC+ announced that it would be raising production by 400,000 b/d a month from August onward triggered a slide in Brent and WTI crude prices below US$70/b
  • However, that slide was short lived as near-term demand indications showed the consumption remained relatively resilient, which lifted crude prices back to their previous range in the low US$70/b level, although the longer-term effects of the Covid-19 delta variants are still unknown at this moment
  • Clarity over supply and demand will continue to be lacking given the fragility of the situation, which suggests that crude prices will remain broadly rangebound for now

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