In March 2019, Venezuela's crude oil production (excluding condensate) averaged 840,000 barrels per day (b/d), down from 1.1 million b/d in February, according to estimates in the U.S. Energy Information Administration's (EIA) April 2019 Short-Term Energy Outlook(STEO, Figure 1). This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought Venezuela's state oil company, Petróleos de Venezuela, S.A.'s (PdVSA), operations to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines. Venezuela's production decreased by an average of 33,000 b/d each month in 2018, and the rate of decline accelerated to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years, with average 2018 imports the lowest since 1989. However, there may be upward pressure on the prices of other crude oils imported into the United States.
Venezuela's production is expected to continue decreasing in 2019 and declines may accelerate as sanctions-related deadlines approach. These deadlines include provisions that third-party entities that use the U.S. financial system must cease transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies will likely contribute to a further step-level decrease in production.
Additionally, U.S. sanctions, as outlined in the January 25, 2019, Executive Order 13857, immediately banned exporting petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—from the United States to Venezuela and required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. The imposition of these sanctions has already affected oil trade between the United States and Venezuela in both directions. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States. India, China, and some European countries continued to take Venezuela's crude oil, according to data published by ClipperData Inc., while the destinations of some vessels carrying Venezuelan crude oil remain unknown (Figure 2). Venezuela is likely keeping some crude oil cargoes intended for exports in floating storage until it finds buyers for the cargoes.
A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils produced using complex processing units, or upgraders, to upgrade the crude oil before it is sent via pipeline to domestic refineries or export terminals. These upgraders were shut down in March during the power outages. If the crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, the heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.
In 2019, Venezuela's crude oil production decline has resulted from a combination of disruptions and lost capacity. EIA differentiates among voluntary production reductions; unplanned production outages, or disruptions; and expected declines in production. For the Organization of the Petroleum Exporting Countries (OPEC), voluntary cutbacks count toward spare capacity. EIA defines spare crude oil production capacity as potential oil production that could be brought online within 30 days and sustained for at least 90 days, consistent with sound business practices.
For all countries, involuntary disruptions do not count as spare capacity. Events that could cause a disruption include, but are not limited to, sanctions, armed conflict, labor actions, natural disasters, or unplanned maintenance. In contrast, EIA considers production capacity declines that result from irreparable damage to be lost capacity and not a disruption. EIA no longer counts the lost production because it is very unlikely that it could return within one year and add to global supplies.
Because the power outages in Venezuela resulted from a lack of maintenance of the electricity grid, associated crude oil production declines are considered lost production capacity resulting from mismanagement. As of the April 2019 STEO, EIA includes the portion of Venezuela's production decline that resulted from U.S. sanctions—approximately 100,000 b/d beginning in February—as a disruption (Figure 3). If sanctions persist, the country will likely be unable to restart the disrupted portion of production and the 100,000 b/d will become lost capacity. Although EIA does not forecast unplanned production outages, its forecast for OPEC production totals will reflect declines in Venezuelan production.
As Venezuelan crude oil has come off the global market and as other countries—including the United States—have produced more light, sweet crude oil, the price discount of heavy, sour crudes has narrowed. U.S. refineries are among the most complex in the world, making them well-suited for the physical properties of Venezuelan crude oil (with high sulfur content and heavier API gravity). Heavier, more sour crude oil is typically priced lower than other crude oils because of differences in crude oil quality. Mars—a medium, sour crude oil produced in the U.S. Federal Offshore Gulf of Mexico—traded at a five-year (2014–18) average discount to Light Louisiana Sweet (LLS) of $3.94 per barrel (b). The Mars-LLS discount has narrowed in 2019, averaging $0.62/b in March, and even reached parity on March 27 (Figure 4).
Venezuela's crude oil production is forecasted to continue to fall through at least the end of 2020, reflecting an expectation of further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what is currently included would change this forecast.
U.S. average regular gasoline and diesel fuel prices increase
The U.S. average regular gasoline retail price increased more than 1 cent from a week ago to $2.84 per gallon on April 22, more than 4 cents higher than the same time last year. The Rocky Mountain price increased nearly 12 cents to $2.76 per gallon, the West Coast price rose 5 cents to $3.63 per gallon, and the East Coast price increased nearly 2 cents to $2.73 per gallon. The Midwest price decreased more than 1 cent to $2.72 per gallon, and the Gulf Coast price fell slightly, remaining virtually unchanged at $2.54 per gallon.
The U.S. average diesel fuel price increased nearly 3 cents to $3.15 per gallon on April 22, more than 1 cent higher than the same time last year. The Rocky Mountain price increased 6 cents to $3.14 per gallon, the West Coast price increased nearly 5 cents to $3.70 per gallon, the Midwest price increased more than 3 cents to $3.04 per gallon, and the East Coast and Gulf Coast prices increased 2 cents to $3.17 per gallon and $2.92 per gallon, respectively.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 1.0 million barrels last week to 57.8 million barrels as of April 19, 2019, 10.6 million barrels (22.5%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Midwest inventories increased by 0.6 million barrels, while East Coast and Gulf Coast inventories each increased by 0.3 million barrels. Rocky Mountain/West Coast inventories decreased by 0.2 million barrels. Propylene non-fuel-use inventories represented 10.4% of total propane/propylene inventories.
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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.
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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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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