9th November 2018
Oil Drilling Activity
Onshore US drilling activity jumped by 11 with a total active count of 1057 rigs; those targeting oil increased 14, with the total at 886. Across the three major unconventional oil basins, the oil rig count increased 4 and stands at 616, with Permian up 5, Eagle Ford down 2 and Williston up 1.
EIA reported last week’s total US domestic crude output at 11.6 million barrels, an increase of 400,000 barrels per day from the previous week and 2 million barrels a day greater than the same week one year ago. This week’s domestic crude oil production estimate incorporates a re-benchmarking that raised estimated volumes by 415,000 barrels per day, which is about 3.6% of this week’s estimated production total.
In parallel with EIA forecast of increasing US supply in 2019, they have adjusted downwards their expected WTI oil price forecast by US$5/bbl to US$65/bbl for next year.
The US Federal Reserve held interest rates steady Thursday and said ongoing strong job gains and household spending have kept the economy on track. The Fed has raised rates three times this year and is widely expected to do so again in December.
US borrowing costs are rising as the federal government’s fiscal position deteriorates, with yields on 10-year US Treasury notes now above 3.20%, more than double the recent low in 2016, and the highest since 2011.
The federal government ran a budget deficit of US$779 billion in Fiscal Year 2018, according to the Congressional Budget Office. In the last fiscal year, tax revenues rose by just +US$14 billion while net government spending increased by +US$127 billion, according to the Congressional Budget Office. Rising benchmark yields are starting to exert pressure on other borrowers around the world leading to a further tightening of financial conditions.
Natural Gas – US, nil: Rest of Americas, 2 (well, almost ...)
A few weeks ago, there was some discussion in the gas section of this bulletin, about the threats to US LNG exports, mainly focused around the potential for the Chinese tariffs to remain in place longer term, the rising cost of shipping, and of course the potential for Henry Hub (HH) to increase. This week has seen two developments that serve as a reminder that US LNG is only one of a number of potential sources of gas, especially for the growing, but distant, markets in Asia.
This week, it was announced that Toshiba is to sell their US LNG business to ENN of China for US$15m, but will have to pay a further US$821m to ENN to effectively plug the gap between what the LNG is expected to cost, delivered onto the LNG carrier in the US, and the price it will attract in global markets. Of course, every LNG player knows that it is a long-term business, and that you have to have staying power to weather the volatility that can affect profitability, especially given the large capital costs or capacity payments that are required on a multi-year basis. ENN has a growing and long-term interest in LNG, as well as a significant home market demand through which they can naturally hedge some of these risks.
When HH-based LNG exports were first offered for sale early in this decade, oil prices were over a hundred dollars a barrel, and HH was less than US$4/MMBtu. For many Japanese companies, buying LNG-based on HH plus a tolling fee of around US$3/MMBtu and a fuel allowance, there was a very clear cost advantage of US gas versus traditional oil indexed contracts. Some 10 MMtpa was signed up as part of that first LNG marketing phase, but of course, with oil prices having come off, and HH having reduced by a much smaller factor, the situation has now reversed.
One of the disadvantages of all the US LNG terminals that are either in operation or have been fully approved, is the preference to rely on the Panama Canal, to access Pacific markets. Although the capacity for LNG transits via the Panama Canal has increased, with the new LNG coming to market, there will still be bottlenecks. The alternative route is a much longer and costlier voyage via Cape Horn or the Suez Canal. The recent FID by LNG Canada is in part because of the direct access, and much shorter steaming distances to Asia, giving West Coast Canadian LNG a competitive boost compared to the US Gulf Coast or Atlantic coast.
The other route to the Pacific is through Mexico, and specifically via the existing Sempra LNG re-gas terminal near Ensenada, Baja California. Sempra this week signed agreements with Total, Tokyo Gas and Mitsui to underpin LNG sales from a 2.4MMtpa export train, for which they hope to reach FID next year, once the EPC contract has been fully progressed. This model is a throwback to what initially brought the US LNG export market such quick success, with reversals of existing LNG re-gas terminals.
With one export terminal being built to the north, and a another well on its way to FID to the south, the lack of direct US access to the Pacific is starting to look like a potential vulnerability, though of course the Mexican project will rely on gas delivered by pipeline from the US. The other downside is that this could put further upward pressure on HH.
In today’s increasingly dynamic gas world, the "Mexican LNG reversal" is not the only directional switch. Elsewhere, as recently commented on in this bulletin, Argentina is looking to switch from imports to exports, Australia despite being such a large LNG exporter is well on its way to importing LNG in some parts to ease domestic gas shortages, as are Malaysia and Indonesia. Finally, with the market reform processes in Japan and China, we can expect to see two of the global powerhouses in terms of LNG imports, also participate in occasional LNG reloads and exports to seize trading opportunities and manage seasonal demand fluctuations. We are well and truly into a new era of global LNG.
So far, therefore, the score is 2-0 to the rest of the world. Currently, the sole Lower 48 US contender at an advanced stage of planning is Jordan Cove (see illustration), and 2019 could be a decisive year for that project too. Of course, Alaska LNG, while being a somewhat longer-term contender, would be big enough to shift the needle quite substantially.
Crude Oil – Global production pressure crude oil prices
Crude oil prices approached four-year highs in early October because of the uncertainty about the amount of Iranian crude oil coming off the market and whether or not other producers could replace the shortfall. However, increased indications of a global economic slowdown, as well as higher than expected global crude supply, has contributed to rapid price declines.
Crude oil production in Saudi Arabia and Russia reached some of their highest levels in history last month, helping to offset supply losses from Iran and Venezuela. Venezuela's crude oil production declines have slowed, and estimates of its crude oil exports have increased as its domestic refining system is operating at low utilization rates. Libyan production has resumed at a faster rate than expected because of improved security. Libya produced more than 1 million barrels per day for two consecutive months in September and October. The temporary loss of 350,000 barrels per day export capacity at a Norwegian oil terminal this week, due to a collision between a tanker and a military vessel, has had no impact on Brent prices, partly as full export potential is expecting to resume early next week.
OPEC signaled it will consider a return to cutting output next year, potentially making the second production U-turn this year. Amid a summer of rising prices, Saudi Arabia, Russia and other producers had opened the taps. Now, with the US midterm elections over and crude futures falling in the face of another US shale oil surge, the cartel will discuss a change of course this weekend.
US crude output hit an all-time high at 11.6 million barrels per day last week and if confirmed during future revisions, would firmly establish the US as the world's top oil producer. The other producers in the top three, Saudi Arabia and Russia, have been increasing production since June. All three of them are continuing to pump at record levels, that has been part of what is causing oil to move into a bear market.
Even with US sanctions on Iranian oil in place, the perception in the market is that there is more than enough supply to meet demand, as reflected by the front-month January Brent futures contract trading at a discount to February.
This price structure, known as contango, materializes when traders believe supply to be greater than demand and, therefore, have more incentive to store oil, rather than sell it.
Total US rig count (including the Gulf of Mexico) stands at 1081, up 14 this week. The horizontal rig count stands at 935, up 6 this week. US rig activity continues to show constrained growth for 22 of the last 25 weeks and stands 19% above last year’s total.
Crude Oil Price
Brent, the global benchmark for oil, decreased US$2.81 to US$69.72 a barrel, reflecting a loss of 3.87% on the week.
WTI crude fell US$3.61 to US$59.56 a barrel, down 5.71% on the week.
US Crude Oil Supply and Demand
US crude oil refinery inputs averaged 16.4 million barrels per day, with refineries at 90.0% of their operating capacity last week. This is 9,000 barrels per day less than the previous week’s average.
US gasoline demand over the past four weeks was at 9.2 million barrels, down 1.4% from a year ago. Total commercial petroleum inventories increased by 4.8 million barrels last week.
US crude imports averaged 7.5 million barrels per day last week, up by 195,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged 7.5 million barrels per day, 1.2% less than the same four-week period last year.
US crude exports averaged 2.405 million barrels per day last week, a decrease of 80,000 barrels per day from the previous week. Over the last four weeks, crude oil exports averaged 2.213 million barrels per day, 31.6% more than the same four-week period last year.
Crude oil inventories increased 5.8 million barrels from the previous week. The crude stored at Cushing (the main price point for WTI) increased 2.4 million barrels; total stored is 34.3 million barrels (~38% utilization).
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