12th April 2019
Oil Drilling Activity
Onshore US drilling activity decreased by 4 with a total active count of 996 rigs; those targeting oil up 2, with the total at 833. Across the three major unconventional oil basins, the oil rig count increased by 1, with Permian up 2, Williston flat and Eagle Ford down 1.
Total US domestic crude output was flat at 12.2 million barrels per day. EIA’s recent short-term energy outlook is projecting US domestic production at 12.4 million barrels per day average for 2019, exiting the year around 12.8 million barrels per day. NGL production will also increase by around 14% to 4.9 million barrels per day average for 2019, with much of the new supply going for export. EIA project the rate of growth in both crude and NGL to slow in 2020, thereby reducing the pressure on oil exporting countries. However, if this were to translate into rising oil prices, one might expect the industry to pick up more rigs and US production rates to resume faster growth.
US crude inventories increased by 7.0 million barrels last week, compared to an expected rise of 2.8 million barrels, following two consecutive weeks of increases. However, supplies of gasoline dropped by 7.7 million barrels, while distillates declined by 100,000 barrels last week.
Filings for US unemployment benefits unexpectedly dropped, falling to the lowest level since October 1969 and suggesting little sign of cooling in a tight labor market. The report comes a day after Federal Reserve officials signaled they are prepared to move interest rates higher or lower as needed, but an unusual mix of risks means they could remain on hold all year.
Carbon Management – The universal role of hydrogen
Last week’s Monitor on Natural Gas and Hydrogen from Nick Fulford got me thinking about how the current hydrogen market could evolve, and what role it could have to deliver the goals of the Paris Agreement.
Today, about 60 million tonnes of hydrogen are used per year in a market estimated to be worth approximately $100 billion. Hydrogen is used for many chemical and other industrial processes, including production of ammonia, methanol, liquid fuels, materials (metals/glass), food, electronics, and used in space and aeronautics. As Nick pointed out, the main production methods are steam methane reforming (SMR), which comprises currently 95% by volume of the market, and 4% by delivered through electrolysis.
Fuels used in SMRs include natural gas and refinery fuel gas (48%), heavy refinery residues and oil (30%), and petroleum coke and coal (18%). SMRs take high temperature (700-1000deg C) steam and reform methane to a hydrogen and carbon monoxide based “syngas” through a catalytic reaction. This syngas then undergoes a further water-gas-shift reaction using a catalyst to produce more hydrogen and carbon dioxide. A pressure swing adsorption system then removes the CO2 to leave a pure hydrogen stream. Reforming of methane typically produces 9-12 tonnes of CO2 for every tonne of hydrogen produced. As an example, the currently growing hydrogen market in US refineries produced approximately 75 MMtpa of higher purity CO2 in 2016. Application of carbon capture, use and storage (CCUS) would produce a low carbon hydrogen, also known as “blue hydrogen”, and result in lower carbon products.
Electrolysis on the other hand splits water into hydrogen and oxygen using electricity. About 50MWh of electricity is typically required to produce 1 tonne of hydrogen. As Nick mentioned in his post, use of renewable energy also provides a route to low carbon hydrogen, also known as “green hydrogen”. The current price difference for electrolysis is estimated to be anywhere from 2 to 7 times greater than an SMR pathway. However, the early deployment of electrolysis means it still has potential for cost reduction through economies of scale and learning curve effects.
As far as the future market is concerned, a study by the Energy Transition Commission found that a 7 to 10 fold increase in global hydrogen production could be needed by mid-century to provide deep de-carbonization of power, heat and transport. Another study by Pöyry found that a decarbonized natural gas pathway for Europe that includes CCUS, biogas and hydrogen, could be over $1 trillion cheaper than an all-electric pathway. Hydrogen can therefore be a cost-effective, universal solution for the energy transition, with pathways for both fossil fuels and renewable energy sources in power, chemicals, heat and transport sectors.
Whatever turns-out to be the most cost effective production route for low carbon hydrogen, it is clear that this clean burning fuel has a major role to play in delivering deep de-carbonization of the future energy and industrial landscape.
Natural Gas – “Cheap” US LNG a poisoned chalice?
Back in 2013, Toshiba took a decision to follow many of its fellow Japanese trading entities into the LNG space, by securing capacity from the US Gulf Coast Freeport LNG terminal, which is due to start deliveries later in 2019. In November 2018, a change of heart saw the announcement of a sale in principle to China’s ENN, a growing LNG buyer in its own right, already very active in the LNG buy/sell and trading space. As is usual with a complex purchase of this sort, involving future commitments based on uncertain commodity prices, the sale of the business itself, for $15 million, was a relatively straightforward transaction. However, calculating the net asset value, or in this, case liabilities associated with its commitments proved more complex. Less than 6 months ago, Toshiba as the seller had agreed to pay the buyer ENN over $800 million to compensate for out-of-the-money LNG contracts that ENN would have taken over. To put this into context, this amounts to just over two years’ worth of tolling fees, payable to Freeport.
Based on recent press reports this week, it appears that the sale of the Toshiba LNG business to ENN is now unlikely to go through. The reasons for this are unclear, but some reports cite regulatory hurdles and US approvals as the reason, while others point to consent not being received from the LNG buyers who had signed up to offtake from the project.
In spite of the unerring interest in US LNG exports, and the announcement of new export projects almost every month, the economics of US LNG exports to both Europe and Asia continue to give rise to uncertainty, especially in the short to medium term. LNG in Asia, the traditional premium market, appears to be dipping below $5/MMBtu, and European gas price indices for May deliveries have weakened considerably over the last month. As a result, liquefying natural gas that is priced at Henry Hub, accounting for losses and fuel gas associated with the process, and then shipping it thousands of miles is an equation that does not add up too well at the moment.
It is interesting to perform some brief analysis on just how out of the money these contracts may be. Taking May 2019 deliveries as an example, NBP is sitting at around $4.80/MMBtu (almost $1.90 lower than the same period last year), whilst HH is hovering around $2.70, leaving an Atlantic basin arbitrage of just $2.10. Taking some of the public domain tolling fees, typically amounting to $3/MMBtu plus 15% for fuel, this amounts to c.$3.45/MMBtu, with shipping (albeit lower today with freight costs under pressure) say in the region of another $0.50/MMBtu. So in terms of whole life costings, deliveries to the UK are in the range of $6.6/MMBtu. This equates to US LNG being $1.80 out of the money, not counting re-gas fees, which can amount to another $0.50/MMBtu on top of this.
From a free cash flow basis, exports from the US to the UK are still positive, but at some point, shutting in US liquefaction and swallowing capacity fees could become the only option for some players. As prices in Europe and Asia come under increasing pressure from the near term excess in LNG supply, it will be interesting to see what effect this has on the appetite for further investments in US export facilities.
Crude Oil – Prices firm on tighten supply
Venezuela pumped 960,000 barrels per day in March, a drop of almost 500,000 bpd from February. The figures have added to a debate within the so-called OPEC+ group of producers on whether to maintain oil supply cuts beyond June. A Russian official indicated this week that Moscow wanted to pump more, although OPEC has been saying the curbs must remain.
Venezuela’s oil output sank to a new long-term low last month due to US sanctions and electrical blackouts, deepening the impact of a global production curb and further tightening crude supplies. Supply cuts by OPEC and partners led by Russia plus involuntary reductions in Venezuela and Iran, have helped drive a 32% rally in crude prices this year.
Brent crude oil spot prices averaged $66 per barrel in March, up $2 per barrel from February 2019. Brent prices for the first quarter of 2019 averaged $63 per barrel, which is $4 per barrel lower than the same period in 2018. Despite lower crude oil prices than last year, Brent prices in March were $9 per barrel higher than in December 2018, marking the largest December-to-March price increase since December 2011 to March 2012. EIA forecasts Brent spot prices will average $65 per barrel in 2019 and $62 per barrel in 2020, compared with an average of $71 per barrel in 2018.
US crude oil production reached a record level of 10.96 million barrels per day in 2018, 1.6 million barrels per day (17%) higher than 2017 levels. In December 2018, monthly US crude oil production reached 11.96 million barrels per day, the highest monthly level of crude oil production in US history. EIA (April 2019) projects that US crude oil production will continue to grow in 2019 and 2020, averaging 12.4 million barrels per day and 13.1 million barrels per day, respectively.
Crude Oil Price
Brent, the global benchmark for oil, increased US$2.04 to US$71.50 a barrel, reflecting a gain of 2.94% on the week.
WTI crude rose US$1.86 to US$64.25 a barrel, up 2.98% on the week.
Total US rig count (including the Gulf of Mexico) stands at 1022, down 3 this week. The horizontal rig count stands at 889, a decrease of 3 this week. US rig activity continues to show constrained growth for 40 of the last 43 weeks and stands just 1% above last year’s total. Crude prices are compelling US shale operators to focus on well productivity (i.e., well completion) and operational efficiency over rig growth.
US Crude Oil Supply and Demand
US crude oil refinery inputs averaged 16.1 million barrels per day, with refineries at 87.5% of their operating capacity last week. This is 251,000 barrels per day more than the previous week’s average.
US gasoline demand over the past four weeks was at 9.4 million barrels, up 1.2% from a year ago. Total commercial petroleum inventories increased by 4.1 million barrels last week.
US crude net imports averaged 4.25 million barrels per day last week, up by 210,000 barrels per day from the previous week. Over the past four weeks, crude oil net imports averaged 3.871 million barrels per day, 38.7% less than the same four-week period last year.
US crude imports averaged 6.6 million barrels per day last week, down by 164,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged 6.7 million barrels per day, 15.5% less than the same four-week period last year.
Crude oil inventories increased 7.0 million barrels from the previous week. The crude stored at Cushing (the main price point for WTI) decreased 1.1 million barrels; total stored is 46.0 million barrels (~51% utilization).
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