Remember the shale gale and Saudi America? The scale of those outlandish delusions has now dwindled to plays in a few counties in West Texas and southeastern New Mexico. Saudi Permian.
It’s a race to the bottom as investors double down on the tight oil companies that can still tell a growth story. Permian-weighted E&P companies are the temporary darlings of Wall Street as other tight oil plays have lost their luster.
A Silly Price Rally: Catch-22
We are in the middle of a truly silly price rally. Other rallies of 2015 and 2016 took place despite substantial production surpluses and too much inventory. Then, there was some hope that higher prices might result if over-production could be brought under control. Now, the world’s production and consumption are near balance but oil prices remain mired in the $40 to $50 per barrel range.
This current rally will end badly because there is something more fundamental keeping prices low. Despite repeated assurances from IEA and EIA that demand growth is strong, it is not strong enough to draw down outsized global inventories.
Hope for an OPEC production freeze at next month’s meeting in Algiers is the main factor driving this rally. The problem is that the world liquids market is as close to balance as it ever gets—over-supply has been less than 0.5 million barrels per day for the last two months. Oil prices were more than $100 per barrel at similar or greater production surpluses in 2013 and 2014.
In 2015, when the average production surplus was 2 million barrels per day, it was a different story. Over-production is not the problem now as it was then. If OPEC freezes production, it won’t make any difference.
Inventories exceed all historical levels. The world remains over-supplied because there is too much oil in inventory.
As long as oil prices are are range-bound between about $40 and $50 per barrel, it makes more sense to store oil than to sell it. The carrying cost of storage is less than what can be made by rolling futures contracts over each month. Inventories will stay high until prices break out of their current range but outsized inventories make that impossible. Catch-22.
Four Oil-Price Cycles in 2015 and 2016
There have been four oil-price cycles in 2015 and 2016–the first three each lasted approximately 6 months. Each new cycle began with high price volatility that fell as price peaked. We are currently in the upward arc of Cycle 4.
The oil-price volatility index has fallen to levels similar to when prices peaked during the last cycle suggesting that current WTI futures prices just above $48 per barrel may already be near the peak for this cycle. Prices may increase into the low-$50 per barrel range as they did in June before falling again.
The latest cycle began when NYMEX futures prices fell below $40 per barrel in early August. In the succeeding two weeks, they have climbed to more than $48. A factor beyond a possible OPEC freeze is the weakened U.S. dollar because of expectations that the Federal Reserve Bank will not raise interest rates at least until December. The value of the dollar against other major currencies has fallen 3% over the last month (36% annualized). WTI futures prices have increased 22% since August 1.
A third factor driving the current price rally is long-term concern about supply because of under-investment in oil development projects and exploration since the oil-price collapse. Recentstatements by the International Energy Agency that demand may outpace supply in the next few years underscored that anxiety.
Figure 3 shows that oil prices appear to be range-bound between about $40 support and $51 per barrel resistance levels. The upper boundary is largely controlled by record-breaking volumes of U.S. and world crude oil inventories and the fact that producers add rigs and production with each upward swing in oil prices.
The 200-day moving average of NYMEX futures prices suggests similar range boundaries of about $38 and $52 per barrel.
This market looks for any excuse to raise prices. Every price upswing is seen by some as the beginning of a return to oil prices above $70 per barrel. We seem to selectively forget that the staggering inventory levels of crude oil make this impossible until those volumes are drawn down substantially. Oops.
U.S. crude oil inventories fell 2.5 million barrels this week but have increased a net 1.6 million barrels over the last month during what is supposed to be de-stocking season.
Storage volumes are 57 million barrels more than at this time in 2015 and are 143 million barrels higher than the 5-year average. This is definitely not a basis for a sustainable oil-price rally. Until inventories are drawn down by at least another 125 million barrels, a recovery to somewhere approaching mid-cycle 2014 levels of about $80 per barrel is technically impossible.
The Permian Basin Dominates Rig Count Increases
Five new horizontal rigs were added last week to drill tight oil objectives in the Permian basin and 12 rigs were added the previous week. Only 1 rig was added in the Bakken play after losing 2 rigs a week ago. No rigs were added in the Eagle Ford after losing 1 rig the previous week. More capital is being spent in the Permian basin than in all the other plays put together.
Overall, 67 tight oil rigs have been added since early June. Forty eight of those are in the Permian basin, 5 in the Bakken and 6 in the Eagle Ford play. Four rigs were added in the Niobrara, 3 in the Granite Wash and 1 in Other. Rig count increases began as oil prices peaked above $50 per barrel in early June and continued through the slump toward $40 prices before the latest upward swing to $48 per barrel.
Weekly changes in the Permian basin rig count are the leading indicator of capital flows and expenditures. Permian rig count is more responsive to capital flows than the other tight oil plays because there is more money available for Permian-weighted companies.
In late July, I wrote, “When prices fall and oil-price volatility increases, the floodgates of capital open. Every genius-investor wants to buy low and sell high. Rig count rises with fresh capital, production increases and oil prices fall.”
In fact, the Permian basin accounts for 64% of the total U.S. horizontal tight oil rig count.
This is curious because Permian production from the Bone Spring, Wolfcamp and Trend-Spraberry horizontal plays represents only 21% of total tight oil production.
It is even more curious because Permian basin tight oil proven reserves rank 42nd in the world just behind Denmark and Trinidad and Tobago based on the latest EIA data.
Some will argue about potential and possible Permian resources and reserves preferring Pioneer CEO Scott Sheffield’s view of things to reality. I won’t debate them but the point is that Saudi Permian is a stretch based on any reality-based interpretation of existing data.
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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.