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Venezuela's crude oil production is declining amid economic instability


Venezuela's crude oil production has been on a downward trend for two decades, but has experienced significant decreases over the past two years. Crude oil production in Venezuela fell from an annual average of 3.2 million barrels per day (b/d) in 1997 to an average of 2.4 million b/d in 2015 (Figure 1). More recently, Venezuela's crude production fell from a monthly average of 2.3 million b/d in January 2016 to 1.6 million b/d in January 2018. A combination of relatively low global crude oil prices and mismanagement of Venezuela’s oil industry has led to the accelerated decline in production. Venezuela's economy is extremely dependent on oil revenue, so the production declines are having a negative impact on the country's finances as well.

Figure 1. Venezuela average annual crude oil production


Several indicators suggest that Venezuela's crude oil production will likely continue to decline in the near future. The number of active rigs has fallen from about 70 in the first quarter of 2016 to an average of 43 in the fourth quarter of 2017 (Figure 2). In addition, recent reports indicate that financial difficulties, such as missed payments to oil service companies, a lack of working upgraders, a lack of knowledgeable managers and workers, and declines in oil industry capital expenditures, have also contributed to production declines.

Figure 2. Venezuela monthly rig count


The United States is the largest importer of Venezuela's crude oil, receiving an average of 618,000 b/d in 2017, or about 41% of total Venezuelan exports. China and India received approximately 386,000 b/d and 332,000 b/d, respectively, in 2017. The remaining 186,000 b/d of exports during the year went to countries including Sweden, the United Kingdom, Germany, Cuba, Singapore, and others (Figure 3).

Figure 3. Venezuela monthly crude oil exports


Venezuela produces extra-heavy crude oil in the Orincoco Oil Belt area and relies extensively on imports of lighter liquids (diluents) to blend with this crude oil to make it marketable. Financial difficulties have recently prevented the state-owned oil company, Petroleos de Venezuela SA (PdVSA), from importing the necessary volumes of diluent on several occasions to sustain production and exports.


In 2017, refiners in the United States and Asia reported crude oil quality issueswith imported crude oil from Venezuela, resulting in requests for discounts or discontinuation of purchases. Venezuela's crude oil exports to the United States fell from 840,000 b/d in December 2015 to 437,000 b/d in December 2017 (the latest month for which EIA import data are available). As recently as September 2017, Venezuela was the third-largest supplier of U.S. crude oil imports after Canada and Saudi Arabia, occupying a top-three spot since 2015. In December 2017, Venezuela fell behind Canada, Saudi Arabia, Mexico, and Iraq based on average imported volumes of crude oil during the month.


The fall in exports to the United States is especially harmful to Venezuela's economy because U.S. refiners are among the few customers that still remit cash payments to Venezuela. Some volumes shipped to China, for example, are sent as loan repayments. In January 2018, Venezuela exported about 360,000 b/d of crude oil to China, based on tanker tracking data. Venezuela's exports to India—also a cash remitting customer—have fallen to the lowest levels in about five years. In January, only about 220,000 b/d of Venezuelan crude oil was destined for India, about 20% lower than the level in January 2017, according to crude oil shipping data. This level includes volumes sent to Essar’s Vadinar refinery in India to service debt that Venezuela owes to Russian oil company Rosneft (Rosneft co-owns the Vadinar refinery).


Although the Venezuelan government has not published any economic data in more than two years, Venezuela's National Assembly reported in mid-March that inflation was more than 6,000% between February 2017 and February 2018. The International Monetary Fund projects that inflation will reach 13,000% in 2018 and that Venezuela's economy will contract 15%, resulting in a cumulative GDP decline of nearly 50% from 2013 through the end of 2018.


Venezuela also has high levels of debt with a variety of creditors. During the last quarter of 2017, when Venezuela was late making some bond payments, the main rating agencies declared the country in selective default . Venezuela has more than $8 billion in bond payments coming due in 2018. Given the country's precarious financial situation, a general default is possible. In addition to about $64 billion worth of debt in traded bonds, Venezuela owes $26 billion to creditors and $24 billion in commercial loans, according to Torino Capital, although some estimates place Venezuelan debt as high as $150 billion.


Venezuela's crude oil production is projected to continue to fall through at least the end of 2019, reflecting that crude oil production losses are increasingly widespread and affecting joint ventures. These projections reflect that crude oil production losses are increasingly widespread and affecting joint ventures. With the reduced capital expenditures, foreign partners are limiting activities in the Venezuelan oil sector. Venezuela's economy is heavily dependent on the oil industry, and production declines result in reduced oil export revenues. Venezuela's economy contracted by nearly 9% in 2017, based on estimates from Oxford Economics.


U.S. average regular gasoline and diesel prices increase


The U.S. average regular gasoline retail price rose 5 cents from the previous week to $2.65 per gallon on March 26, 2018, up 33 cents from the same time last year. Rocky Mountain prices increased nearly nine cents to $2.53 per gallon, Gulf Coast prices increased nearly eight cents to $2.38 per gallon, West Coast and East Coast prices each increased nearly six cents to $3.27 per gallon and $2.59 per gallon, respectively, and Midwest prices increased two cents to $2.52 per gallon.


The U.S. average diesel fuel price rose nearly 4 cents to $3.01 per gallon on March 26, 2018, 48 cents higher than a year ago. Rocky Mountain prices rose nearly seven cents to $2.99 per gallon, West Coast prices increased over five cents to $3.44 per gallon, Gulf Coast and Midwest prices each increased nearly four cents to $2.82 per gallon and $2.93 per gallon, respectively, and East Coast prices increased nearly three cents to $3.04 per gallon.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 1.2 million barrels last week to 35.6 million barrels as of March 23, 2018, 9.7 million barrels (21.4%) lower than the five-year average inventory level for this same time of year. East Coast and Midwest inventories each decreased by 0.5 million barrels, while Gulf Coast inventories decreased by 0.2 million barrels. Rocky Mountain/West Coast inventories rose slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 8.2% of total propane/propylene inventories.


Residential heating oil prices increase, propane prices decrease


As of March 26, 2018, residential heating oil prices averaged almost $3.10 per gallon, nearly 4 cents per gallon higher than last week and 51 cents per gallon higher than last year's price at this time. The average wholesale heating oil price for this week averaged almost $2.12 per gallon, nearly 11 cents per gallon higher than last week and 52 cents per gallon higher than a year ago.


Residential propane prices averaged $2.48 per gallon, almost one cent per gallon lower than last week but nine cents per gallon higher than a year ago. Wholesale propane prices averaged $0.88 per gallon, 1 cent per gallon higher than last week and nearly 21 cents per gallon higher than last year's price. This is the last data collection for the 2017-2018 State Heating Oil and Propane Program (SHOPP) heating season. Data collection will resume on October 1, 2018 for publication on Wednesday, October 3, 2018.


For questions about This Week in Petroleum, contact the Petroleum Markets Team at 202-586-4522.

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Latest issue of GEO ExPro magazine covers Europe and Frontier Exploration, Modelling and Mapping, and Geochemistry.

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January, 20 2020
Your Weekly Update: 13 - 17 January 2020

Market Watch   

Headline crude prices for the week beginning 13 January 2020 – Brent: US$64/b; WTI: US$59/b

  • Tensions in the Persian Gulf have abated, but not disappeared, as both the US and Iran stepped back from going to war; the buck, so far, has stopped with Tehran’s retaliation to the US assassination of its top general with a barrage of missile strikes at US bases in Iraq
  • The underlying situation is still fragile, with the Iranian population swinging from supporting the government to protesting its accidental downing of a commercial Ukraine Airlines plane; with the risk of war easing, crude prices have fallen back to their pre-crisis levels
  • However, American and foreign oil companies have pulled their staff from crude fields in northern Iraq and Kurdistan, including Chevron, as the oil industry in Iraq monitors the risk – and consequences – of military action
  • In precaution, oil tankers have begun boosting their rates once again to haul crude through the Persian Gulf, with quoted rates now at their highest level since the 2019 attacks on ships passing through the narrow straight
  • Although political tensions remain fresh, Saudi Arabia said that OPEC and the OPEC+ club were instead focused on using their window of production cuts to reduce excess oil stockpiles to levels ‘within the contours of 2010-2014’
  • In the US, not only is shale output staying strong, but production in the US Gulf of Mexico also made history, exceeding 2 mmb/d for the first time ever in 2019, beating the previous high recorded in 2018
  • Worries about the health of global oil demand persist… although the US and China signed a Phase 1 trade deal, the agreement is more about halting escalation of the trade war than repairing inflicted damage; a slowdown in Chinese economic growth could lead to oil demand growth halving in 2020 in China according to CNPC
  • The US active rig count fell for a second consecutive week, losing 15 rigs – 11 oil and 4 gas – for the 17th weekly decline of the past 20 weeks; losses in the Permian were once again high, shedding a total of 6 rigs
  • Crude oil prices should remain rangebound with Brent at US$63-65/b and WTI at US$57-59/b, as the market retreats back to its ever-present worries about demand while geopolitical risk premiums scale back


Headlines of the week

Upstream

  • Guyana’s success is now extending to its neighbours, with Total and Apache announcing a ‘significant’ oil discovery at their Maka Central-1 well in Suriname’s Block 58, which lies adjacent to the prolific Stabroek Block
  • BP has agreed to sell its operating interest in the UK North Sea’s Andrew assets – including the Andrew platform as well as the Andrew, Arundel, Cyrus, Farragon, and Kinnoull fields – along with its 27.5% non-operating interest in the Shearwater field to Premier Oil for some US$625 million
  • Liberia will kick start its next offshore licensing round in April 2020, offering nine blocks in the Harper basin, one of the few offshore regions in West Africa that remains unexplored and undrilled
  • Equinor has extended the life of its Statfjord assets beyond 2030, with plans to commission up to 100 new wells over the next decade, deferring decommissioning with a goal of maintaining current output levels beyond 2025
  • After Murphy Oil, Petrofac and ExxonMobil, Repsol is the latest major considering an upstream exit from Malaysia, covering assets that include six development blocks and the major Kinabalu oilfield in Sabah
  • Senegal’s government has approved Woodside’s offshore Sangomar Field Development, which will involve the drilling of 23 subsea wells and a FPSO with the capacity to process up to 100,000 b/d of crude
  • Equinor has announced plans to reduce greenhouse gas emissions from its offshore fields and onshore plants in Norway by 40% by 2030, 70% by 2040 and to near zero by 2050 from 2019 levels

Midstream/Downstream

  • Shell is reportedly seeking buyers for its 144 kb/d Anacortes refinery in Washington state, which would be its third North American sale in two years after divesting its Martinez refinery in California and Sarnia refinery in Ontario
  • Shell has announced plans to increase its share of the Mexican fuel market to 15%, which would require considerable growth in its network of 200 fuel stations in 12 states that currently represent 1% of the market
  • Occidental Petroleum plans to reduce its holdings in Western Midstream Partners – acquired as part of its controversial takeover of Anadarko – to less than 50%, potentially removing up to US$7.8 billion of debt

Natural Gas/LNG

  • Sempra Energy and Saudi Aramco have signed an agreement that will see the Saudi giant play a bigger part in the planned 22 million tpa Port Arthurt LNG project, following an existing agreement to purchase 5 mtpa signed in May 2019
  • Kuwait Petroleum Corp has agreed to purchase 3 million tpa of LNG from Qatar Petroleum for 15 years beginning 2022, with Kuwait remaining one of the few countries in the Middle East that remain neutral to the Saudi-Qatar standoff
  • ExxonMobil has signed an agreement with midstream company Outrigger Energy II to build a 250 mmscf/d cryogenic gas processing, gathering and pipeline system in the Bakken’s Williston Basin in North Dakota
  • The Larak gas field in Sarawak has achieved first gas, operated by SapuraOMV Upstream as part of the SK408 PSC that includes the Gorek and Bakong fields, with output planned to be processed into LNG at Petronas’ Bintulu complex
  • Russia’s TurkStream natural gas pipeline – connecting Russia, Turkey, Bulgaria and eventually Serbia and Hungary - has officially begun operations, delivering up to 13 bcm of Russian gas that can be rerouted from the Ukraine route
January, 17 2020
EIA forecasts slower growth in natural gas-fired generation while renewable energy rises

annual U.S. electric power sector generation by energy source

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

In its latest Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that generation from natural gas-fired power plants in the electric power sector will grow by 1.3% in 2020. This growth rate would be the slowest growth rate in natural gas generation since 2017. EIA forecasts that generation from nonhydropower renewable energy sources, such as solar and wind, will grow by 15% in 2020—the fastest rate in four years. Forecast generation from coal-fired power plants declines by 13% in 2020.

During the past decade, the electric power sector has been retiring coal-fired generation plants while adding more natural gas generating capacity. In 2019, EIA estimates that 12.7 gigawatts (GW) of coal-fired capacity in the United States was retired, equivalent to 5% of the total existing coal-fired capacity at the beginning of the year. An additional 5.8 GW of U.S. coal capacity is scheduled to retire in 2020, contributing to a forecast 13% decline in coal-fired generation this year. In contrast, EIA estimates that the electric power sector has added or plans to add 11.4 GW of capacity at natural gas combined-cycle power plants in 2019 and 2020.

Generating capacity fueled by renewable energy sources, especially solar and wind, has increased steadily in recent years. EIA expects the U.S. electric power sector will add 19.3 GW of new utility-scale solar capacity in 2019 and 2020, a 65% increase from 2018 capacity levels. EIA expects a 32% increase of new wind capacity—or nearly 30 GW—to be installed in 2019 and 2020. Much of this new renewables capacity comes online at the end of the year, which affects generation trends in the following year.

Forecast generation mix varies in each of the 11 STEO electricity supply regions. A large proportion of the retired coal-fired capacity is located in the mid-Atlantic area, where PJM manages the dispatch of electricity. EIA forecasts that coal generation in the mid-Atlantic will decline by 37 billion kilowatthours (kWh) in 2020. Some of this decline is offset by more generation from mid-Atlantic natural gas-fired power plants; EIA expects generation from these plants to grow by 23 billion kWh.

forecast annual change in electric power sector generation by fuel

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2020

In the Midwest, where the Midcontinent ISO (MISO) manages electricity, EIA expects coal generation to fall in 2020 by 33 billion kWh. This decline is offset by an increase in natural gas electricity generation (12 billion kWh) and by nonhydropower renewable energy sources (13 billion kWh). The regional increase in renewables is primarily a result of new wind generating capacity.

The electric power sector in the area of Texas managed by the Electric Reliability Council of Texas (ERCOT) is planning to see large increases in generating capacity from both wind and solar. EIA expects this new capacity will increase generation from nonhydropower renewable energy sources by 24 billion kWh this year. EIA expects the increased ERCOT renewable generation will lead to a regional decline of natural gas-fired generation and coal generation of 14 billion kWh for each fuel source in 2020.

EIA expects these trends to continue into 2021. EIA forecasts U.S. generation from nonhydropower renewable energy sources will grow by 17% next year as the electric power sector continues expanding solar and wind capacity. This increase in renewables, along with forecast increases in natural gas fuel costs, contributes to EIA’s forecast of a 2.3% decline in natural gas-fired generation in 2021. U.S. coal generation in 2021 is forecast to fall by 3.2%.

January, 17 2020