World production of crude and liquids has been revised slightly downward from EIA’s May Short-Term Energy Outlook (STEO) for both 2017 and 2018. The Organization of the Petroleum Exporting Countries (OPEC) met on May 25, 2017, and announced an extension to production cuts that were originally set to end this month. The agreed-upon OPEC crude oil production target remains at 32.5 million barrels per day (b/d) through the end of the first quarter of 2018. EIA now forecasts OPEC members’ crude oil production to average 32.3 million b/d in 2017 and 32.8 million b/d in 2018, about 0.2 million b/d and 0.4 million b/d, respectively, lower than previously forecast. However, continuing production growth in many non-OPEC countries is expected to moderate the pace of global liquid fuels inventory draws in 2017 and lead to a small inventory build in 2018.
EIA now forecasts OPEC crude oil and other liquids production to average 39.6 million b/d from the third quarter of 2017 through the first quarter of 2018 (340,000 b/d lower than previously forecast). Non-OPEC production averages 59.6 million b/d over this period, up from 58.3 million b/d over the same period a year earlier. Considering both OPEC and non-OPEC production forecasts and the outlook for demand growth, EIA now expects an average global inventory draw of 100,000 b/d through the first quarter of 2018. The largest draws are expected in the third quarter of 2017, when global crude oil and other liquids inventories are forecast to fall by an average of 430,000 b/d
Inventory draws of this magnitude suggest the possibility of some upward pressure on crude oil prices over the coming months. The third quarter 2017 Brent spot price forecast is $54/b in EIA’s June STEO, up from $52/b in the May STEO. However, because U.S. tight oil production is relatively responsive to changes in oil prices, and given an estimated six-month lag between a change in oil prices and realized production, higher crude oil prices in mid-2017 have the potential to raise U.S. supply in 2018.
The largest global inventory increase in the forecast occurs in the second quarter of 2018, when Brazilian and OPEC production are expected to realize quarterly increases of 570,000 b/d and 220,000 b/d, respectively. The expectation of supply growth in 2018 could contribute to oil price weakness in late 2017 and early 2018; the June STEO’s Brent spot price forecast for the first quarter of 2018 is $52/b, $3/b lower than in the previous forecast. The current forecast assumes OPEC cuts will be extended beyond March 2018, but that non-compliance, which begins to grow late in 2017, increases somewhat in the second half of 2018. Although this forecast reflects the assumption of only partial OPEC compliance with a second production-cut extension in 2018, any extension provides some support for crude oil prices, even if only temporarily, and partially offsets downward price pressure from growing inventories.
The June STEO forecasts a 2017 average spot price for Brent crude oil of $53/b, unchanged from the previous STEO, along with a $56/b price forecast for 2018, $1/b lower than expected last month. WTI prices are forecast to average $2/b less than Brent in both 2017 and 2018 (Figure 2). As always, all oil price forecasts are subject to considerable uncertainty. For example, NYMEX contract values for September 2017 delivery that traded during the five-day period ending June 1 suggest that a range of $39/b to $64/b encompasses the market expectation for WTI prices in September 2017 at the 95% confidence level; also, as shown in the figure, the range encompassing current market expectations at this confidence level widens for longer time horizons.
U.S. crude oil production increases through the forecast, averaging 9.3 million b/d in 2017 and 10.0 million b/d in 2018. The 2018 forecast exceeds the previous record production level of 9.6 million b/d set in 1970. Growth in U.S. production of crude oil and hydrocarbon gas liquids has been the largest contributor to the 820,000 b/d of non-OPEC liquids supply growth from January through May 2017. Continued increases in drilling activity in U.S. shale basins, particularly in Texas, support production increases throughout the forecast. The largest expansion for U.S. production occurs in the fourth quarter of 2017, which averages a quarter-over-quarter rise of 330,000 b/d.
U.S. average regular gasoline price increases, diesel retail price drops
The U.S. average regular gasoline retail price rose slightly from the previous week, remaining virtually unchanged at $2.41 per gallon on May 29, up three cents from the same time last year. The Midwest and Gulf Coast prices each rose two cents to $2.32 per gallon and $2.17 per gallon, respectively, while the Rocky Mountain and East Coast prices each increased one cent to $2.43 per gallon per gallon and $2.35 per gallon, respectively. The West Coast price dropped two cents to $2.94 per gallon.
The U.S. average diesel fuel price fell one cent to $2.56 per gallon on May 29, 16 cents higher than a year ago. The West Coast, East Coast, Midwest, and Gulf Coast prices each dropped one cent to $2.84 per gallon, $2.60 per gallon, $2.51 per gallon, and $2.42 per gallon, respectively, while the Rocky Mountain price increased less than a penny, remaining at $2.66 per gallon.
Propane inventories gain
U.S. propane stocks increased by 3.3 million barrels last week to 50.4 million barrels as of June 2, 2017, 26.9 million barrels (34.8%) lower than a year ago. Gulf Coast, Midwest, Rocky Mountain/West Coast, and East Coast inventories increased by 2.3 million barrels, 0.5 million barrels, 0.3 million barrels, and 0.1 million barrels, respectively. Propylene non-fuel-use inventories represented 5.5% of total propane inventories.
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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 😊
Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.
EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.
Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021
EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.
EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.