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.
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.
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).
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.
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Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b
Headlines of the week
The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.
In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.
As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.
After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.
And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.
So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.
Supermajor Financials: Q2 2019
Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker
Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.
Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.
Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.
Source: U.S. Energy Information Administration
Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)
For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.
Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.