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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Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory
In both 2019 and 2020, project developers in the United States installed more wind power capacity than any other generating technology. According to data recently published by the U.S. Energy Information Administration (EIA) in its Preliminary Monthly Electric Generator Inventory, annual wind turbine capacity additions in the United States set a record in 2020, totaling 14.2 gigawatts (GW) and surpassing the previous record of 13.2 GW added in 2012. After this record year for wind turbine capacity additions, total wind turbine capacity in the United States is now 118 GW.
The impending phaseout of the full value of the U.S. production tax credit (PTC) at the end of 2020 primarily drove investments in wind turbine capacity that year, just as previous tax credit reductions led to significant wind capacity additions in 2012 and 2019. In December 2020, Congress extended the PTC for another year.
Source: U.S. Energy Information Administration, Electric Power Monthly
Texas has the most wind turbine capacity among states: 30.2 GW were installed as of December 2020. In 2020, Texas generated more electricity from wind than the next three highest states (Iowa, Oklahoma, and Kansas) combined. However, Texas generates and consumes more total electricity than any other state, and wind remains slightly less than 20% of the state’s electricity generation mix.
In two other states—Iowa and Kansas—wind is the most prevalent source of in-state electricity generation. In both states, wind surpassed coal as the state’s top electricity generation source in 2019.
Source: U.S. Energy Information Administration, Electric Power Monthly
Nationally, 8.4% of utility-scale electricity generation in 2020 came from wind turbines. Many of the turbines added in late 2020 will contribute to increases in wind-powered electricity generation in 2021. EIA expects wind’s share of electricity generation to increase to 10% in 2021, according to forecasts in EIA’s most recent Short-Term Energy Outlook.
It was a good run while it lasted. Almost exactly a decade ago, the military junta in Myanmar was dissolved, following civilian elections. The country’s figurehead, Aung San Suu Kyi, was released from house arrest to lead, following in the footsteps of her father. Although her reputation has since been tarnished with the Rohingya crisis, she remains beloved by most of her countrymen, and her installation as Myanmar’s de facto leader lead to a golden economic age. Sanctions were eased, trade links were restored, and investment flowed in, not least in the energy sector. Yet the military still remained a powerful force, lurking in the background. In early February, they bared their fangs. Following an election in November 2020 in which Aung San Suu Kyi’s National League for Democracy (NLD) won an outright majority in both houses of Parliament. A coup d’etat was instigated, with the Tatmadaw – the Burmese military – decrying fraud in the election. Key politicians were arrested, and rule returned to the military.
For many Burmese, this was a return to a dark past that many thought was firmly behind them. Widespread protests erupted, quickly turning violent. The Tatmadaw still has an iron grip, but it has created some bizarre situations – ordinary Burmese citizens calling on Facebook and foreign governments to impose sanctions on their country, while the Myanmar ambassador to the United Nations was fired for making an anti-army speech at the UN General Assembly.
The path forward for Myanmar from this point is unclear. The Tatmadaw has declared a state of emergency lasting up to a year, promising new elections by the end of 2021. There is little doubt that the NLD will win yet another supermajority in the election, IF they are fair and free. But that is a big if. Meanwhile, the coup threatens to return Myanmar to the pariah state that it was pre-2010. And threatens to abort all the grand economic progress made since.
In the decade since military rule was abolished, development in Myanmar has been rapid. In the capital city Yangon, glittering new malls have been developed. The Ministry of Energy in 2009 was housed in a crumbling former high school; today, it occupies a sprawling complex in the new administrative capital of Naypyidaw. While not exactly up to the level of the Department of Energy in Washington DC, it is certainly no longer than ministry that was once reputed to take up to three years to process exploration licences for offshore oil and gas blocks.
And it is that very future that is now at stake. Energy has been a great focus for investment in Myanmar, drawn by the rich offshore deposits in the Andaman Sea and the country’s location as a possible pipeline route between the Middle East and inland China. Estimates suggest that – based on pre-coup trends – Myanmar was likely to attract over US$1.1 billion in upstream investment in 2023, more than four times projected for 2021 and almost 20 times higher than 2011. The funds would not only be directed at maintaining production at the current Yadana, Yetagun, Zawtika and Shwe gas fields – where offshore production is mainly exported to Thailand, but also upcoming megaprojects such as Woodside and Total’s A-6 deepwater natural gas and PTTEP’s Aung Sinka Block M3 developments.
The coup now presents foreign investors in Myanmar’s upstream energy sector with a conundrum and reputational risk. Stay, and risk being seen as abetting an undemocratic government? Or leave, and risk being flushing away years of hard work? The home governments of foreign investors such as Total, Chevron, PTTEP, Woodside, Petronas, ONGC, Nippon Oil, Kogas, POSCO, Sumitomo, Mitsui and others have already condemned the coup. For now these companies are hoping that foreign pressure will resolve the situation in a short enough timeframe to allow business to resume. Australia’s Woodside Petroleum has already called the coup a ‘transitionary issue’ claiming that it will not affect its exploration plans, while other operators such as Total and Petronas have focused on the safety of their employees as they ‘monitor the evolving situation’.
But the longer the coup lasts without a resolution satisfactory to the international community and the longer the protests last (and the more deaths that result from that), the more untenable the position of the foreign upstream players will be. Asian investors, especially the Chinese, mainly through CNPC/PetroChina, and the Thais, through PTTEP - will be relatively insulated, but American and European majors face bigger risks. This could jeopardise key projects such as the Myanmar-to-China crude oil and natural gas pipeline project (a 771km connection to Yunnan), two LNG-to-power projects (Thaketa and Thilawa, meant to deal with the country’s chronic blackouts) and the massive Block A-6 gas development in the Shwe Yee Htun field by Woodside which just kicked off a fourth drilling campaign in December.
It is a big unknown. The Tatmadaw has proven to be impervious to foreign criticism in the past, ignoring even the most stringent sanctions thrown their way. In fact, it was a huge surprise that the army even relinquished power back in 2010. But the situation has changed. The Myanmar population is now more connected and more aware, while the army has profited off the opening of the economy. The economic consequences of returning to its darker days might be enough to trigger a resolution. But that’s not a guarantee. What is certain is that the coup will have a lasting effect on energy investment and plans in Myanmar. How long and how deep is a question that only the Tatmadaw can answer.
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The year 2020 was exceptional in many ways, to say the least. All of which, lockdowns and meltdowns, managed to overshadow a changing of the guard in the LNG world. After leapfrogging Indonesia as the world’s largest LNG producer in 2006, Qatar was surpassed by Australia in 2020 when the final figures for 2019 came in. That this happened was no surprise; it was always a foregone conclusion given Australia’s massive LNG projects developed over the last decade. Were it not for the severe delays in completion, Australia would have taken the crown much earlier; in fact, by capacity, Australia already sailed past Qatar in 2018.
But Australia should not rest on its laurels. The last of the LNG mega-projects in Western Australia, Shell’s giant floating Prelude and Inpex’s sprawling Ichthys onshore complex, have been completed. Additional phases will provide incremental new capacity, but no new mega-projects are on the horizon, for now. Meanwhile, after several years of carefully managing its vast capacity, Qatar is now embarking on its own LNG infrastructure investment spree that should see it reclaim its LNG exporter crown in 2030.
Key to this is the vast North Field, the single largest non-associated gas field in the world. Straddling the maritime border between tiny Qatar and its giant neighbour Iran to the north, Qatar Petroleum has taken the final investment decision to develop the North Field East Project (NFE) this month. With a total price tag of US$28.75 billion, development will kick off in 2021 and is expected to start production in late 2025. Completion of the NFE will raise Qatar’s LNG production capacity from a current 77 million tons per annum to 110 mmtpa. This is easily higher than Australia’s current installed capacity of 88 mmtpa, but the difficulty in anticipating future utilisation rates means that Qatar might not retake pole position immediately. But it certainly will by 2030, when the second phase of the project – the North Field South (NFS) – is slated to start production. This would raise Qatar’s installed capacity to 126 mmtpa, cementing its lead further still, with Qatar Petroleum also stating that it is ‘evaluating further LNG capacity expansions’ beyond that ceiling. If it does, then it should be more big leaps, since this tiny country tends to do things in giant steps, rather than small jumps.
Will there be enough buyers for LNG at the time, though? With all the conversation about sustainability and carbon neutrality, does natural gas still have a role to play? Predicting the future is always difficult, but the short answer, based on current trends, it is a simple yes.
Supermajors such as Shell, BP and Total have set carbon neutral targets for their operations by 2050. Under the Paris Agreement, many countries are also aiming to reduce their carbon emissions significantly as well; even the USA, under the new Biden administration, has rejoined the accord. But carbon neutral does not mean zero carbon. It means that the net carbon emissions of a company or of a country is zero. Emissions from one part of the pie can be offset by other parts of the pie, with the challenge being to excise the most polluting portions to make the overall goal of balancing emissions around the target easier. That, in energy terms, means moving away from dirtier power sources such as coal and oil, towards renewables such as solar and wind, as well as offsets such as carbon capture technology or carbon trading/pricing. Natural gas and LNG sit right in the middle of that spectrum: cleaner than conventional coal and oil, but still ubiquitous enough to be commercially viable.
So even in a carbon neutral world, there is a role for LNG to play. And crucially, demand is expected to continue rising. If ‘peak oil’ is now expected to be somewhere in the 2020s, then ‘peak gas’ is much further, post-2040s. In 2010, only 23 countries had access to LNG import facilities, led by Japan. In 2019, 43 countries now import LNG and that number will continue to rise as increased supply liquidity, cheaper pricing and infrastructural improvements take place. China will overtake Japan as the world’s largest LNG importer soon, while India just installed another 5 mmtpa import terminal in Hazira. More densely populated countries are hopping on the LNG bandwagon soon, the Philippines (108 million people), Vietnam (96 million people), to ensure a growing demand base for the fuel. Qatar’s central position in the world, sitting just between Europe and Asia, is a perfect base to service this growing demand.
There is competition, of course. Russia is increasingly moving to LNG as well, alongside its dominant position in piped natural gas. And there is the USA. By 2025, the USA should have 107 mmtpa of LNG capacity from currently sanctioned projects. That will be enough to make the USA the second-largest LNG exporter in the world, overtaking Australia. With a higher potential ceiling, the USA could also overtake Qatar eventually, since its capacity is driven by private enterprise rather than the controlled, centralised approach by Qatar Petroleum. The appearance of US LNG on the market has been a gamechanger; with lower costs, American LNG is highly competitive, having gone as far as Poland and China in a few short years. But while the average US LNG breakeven cost is estimated at around US$6.50-7.50/mmBtu, Qatar’s is even lower at US$4/mmBtu. Advantage: Qatar.
But there is still room for everyone in this growing LNG market. By 2030, global LNG demand is expected to grow to 580 million tons per annum, from a current 360 mmtpa. More LNG from Qatar is not just an opportunity, it is a necessity. Traditional LNG producers such as Malaysia and Indonesia are seeing waning volumes due to field maturity, but there is plenty of new capacity planned: in the USA, in Canada, in Egypt, in Israel, in Mozambique, and, of course, in Qatar. In that sense, it really doesn’t matter which country holds the crown of the world’s largest exporter, because LNG demand is a rising tide, and a rising tide lifts all 😊