26th April 2019
Oil Drilling Activity
Onshore US drilling activity decreased by 20 with a total active count of 966 rigs; those targeting oil down 20, with the total at 805. Across the three major unconventional oil basins, the oil rig count decreased by 9, with Permian, Williston and Eagle Ford each down 3.
Total US domestic crude output increased by 100,000 barrels per day; US crude oil production continues to remain at or below 12.2 million barrels per day for the past ten weeks. After near continuous additions since November 2016, EIA’s drilled but uncompleted (DUC) well count declined in March, but still represents a healthy 8,500 wells to bring on line as needed to help sustain 12+ million barrels per day. US crude inventories showed a significate increase of 5.5 million barrels last week, compared to an expected drop of 0.5 million barrels. US production and inventory changes are expected to help offset supply declines elsewhere in the world.
Filings for US unemployment benefits rose the most since late 2017, while still remaining in the range of what is considered a tight labor market. Jobless claims rose 37,000 to 230,000 in the week ended April 20. US first quarter activity showed surprising strength; the economy expanded at a 3.2% annual pace in the first three months of 2019.
Carbon Management - Carbon offsets for oil and gas emissions reductions
Oil and gas companies working to lower their Greenhouse Gas emissions have a variety of reduction options, or ‘carbon solutions’ at their disposal, including indirect options such as switching to renewable power and paying for external reductions that reduce or “offset” an organization’s net emissions.
It is generally recognized that a quality carbon offset needs to be real (actually exist), verified (a third party has provided independent review as to the amount of Greenhouse Gas emissions being abated), and permanent (the GHG emissions abated are not just temporary). However, the tricky part for any industrial offset project that makes an economic return is that an offset must also be additional (it would not have been done otherwise). This is why most renewable energy projects (wind, solar, biomass, hydroelectric and geothermal) are in the voluntary offset market, small in scale and usually are located in developing countries. They are therefore generally not required by current regulation, not common practice, and/or face economic, investment or technological barriers.
Instead, a more common approach for large-scale carbon offsets are land-based offsets generated from land use, land use change, and forestry offsets. Just over a week ago, Eni, the Italian oil and gas company, made a bold move by committing to a €3bn plan to eliminate all (net) upstream operational CO2 emissions by 2030, in part by planting 20 million acres of forest in Africa that would capture 20 million tonnes of CO2 per year. This is the largest forestry offset commitment to date from a major oil and gas company; however, it is part of their corporate carbon management plan that also includes energy efficiency, flaring and fugitive’s reduction, and incorporation of renewable energy.
Some may call to question the moral ethics of oil and gas companies buying offsets as a legitimate way to achieve their Greenhouse Gas reduction goals, branding them a ‘continued license to pollute’ and ‘allowing more bad behavior rather than less’. However, these views fail to see that when used as part of a wider Carbon Management plan in addition to direct reductions, and used for residual emissions that cannot be effectively reduced with available technologies, then why not consider them a responsible solution for society to meet our de-carbonization goals?
Natural Gas – The final disconnect?
The way in which fuels are measured has a lot to answer for. When we talk about oil, we usually refer to it as $/Bbl, for gas it is sometimes $/MMBtu or pence per therm, or even Euros per kWh, and for liquid fuels it can be $/gallon, $ per tonne or a whole range of other units. In this confusing array of different units, it is sometimes easy to forget that the amount of fuel you are buying is much less important than the amount of energy. With the effect of the Trump administration’s tightening of sanctions in Iran, we are now seeing some very substantial disconnects in the energy market, predominantly between oil derived products, and natural gas.
Nowhere is this more evident than in the LNG market. Two thirds of the LNG delivered into Asian markets is governed by long-term take or pay contracts linked to oil. The origin of this practice was that allowing for regasification, if you multiply the price of oil in $/Bbl by about 14.5%, you arrive at a gas price that is equivalent, in energy terms. However, one by one, gas markets have slowly developed pricing characteristics that are governed more by the supply and availability of pipeline gas and LNG, than whether or not it is priced at parity with oil.
In the 1980s, various FERC orders changed the face of gas pricing in the US, and in the 1990s, the Gas Act of 1992 paved the way for a similar wholesale gas price in the UK. With the first, second, and third directives in Europe, that market, too, has almost completely disengaged from oil price indexation, leaving only Asia as the bastion of oil-linked gas. Back in 2012, with oil prices still high, but with LNG spot prices starting to disengage, it looked as though Asia would follow Europe with the mass renegotiation of long-term supply contracts. With the fall in oil prices, the advent of Henry Hub linked gas, and other factors, the pressure eased off once again, and for the last couple of years, gas-on-gas competition has generated prices very similar to those derived from oil.
However, the last few months has shown once again, that gas prices determined through typical market economics of supply and demand, and those simply linked with oil, can be very different. LNG month ahead prices in the $5 range in both Europe and Asia this last few weeks, with oil prices now breaking through $70/Bbl mark are once again putting considerable strain in both buyers and sellers of long-term gas. Now, with oil tightening up again following the latest US sanctions, the position is becoming even more unsustainable. Once the current oil prices filter through to delivered LNG, buyers will be looking at prices approximately double those of cargoes priced on gas indices. For a typical 160,000 cubic metre delivery, amounting to some 3.4 million MMBtus, we are talking the difference between an $18 million invoice, and a $36 million invoice.... a tough dilemma for any buyer to manage. In today’s market, where an LNG carrier can be organized through the briefest of phone calls or text message, buyers will be finding every means possible to hold back long-term take or pay gas, in preference to spot cargoes.
When we last faced this issue, many predicted that the swathe of contract renegotiations and arbitrations that took place in Europe, would simply relocate to Asia. That has not yet come about, partly because of the much greater sense of long-term relationships between LNG buyers and sellers. At some point, though, it would seem that those relationships could be eclipsed by the attraction of millions of dollars of saving.
Crude Oil – Ouch…..US rig Y-o-Y growth turns negative!
The United States demanded that buyers of Iranian oil stop purchases by May 1 or face sanctions, a move to choke off Tehran’s oil revenues that sent crude prices higher on fears of a potential supply shortage.
Do not expect Iran to be entirely eliminated from the oil market overnight, but the decision to allow waivers on Iran oil sanctions to expire will likely cause around 700,000 to 800,000 barrels a day to come off the market in the near term. Given the expected loss of oil in the market, producers must be willing to return almost all the amount they decided to cut in December if they want to eliminate the effects.
Venezuela's production is expected to continue decreasing in 2019 and declines may accelerate as sanctions-related deadlines approach. These deadlines include provisions that third-party entities that use the US financial system must cease transactions with PdVSA by April 28 and that US companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27.
The declines in Venezuelan production should have limited effects on the United States, as US imports of Venezuelan crude oil have decreased over the last several years, with average 2018 imports the lowest since 1989.
The IEA notes that markets are now adequately supplied, and that global spare production capacity remains at comfortable levels. Total oil supplies from the United States are expected to grow by 1.6 million barrels per day this year. Furthermore, as infrastructure bottlenecks in the United States are easing, oil exports are now abler to keep pace with production trends.
Crude Oil Price
Brent, the global benchmark for oil, increased $1.43 to $73.31 a barrel, reflecting a gain of 1.99% on the week.
WTI crude rose $0.35 to $64.24 a barrel, up 0.55% on the week.
Total US rig count (including the Gulf of Mexico) stands at 991, down 21 this week. The horizontal rig count stands at 873, a decrease of 13 this week. US rig activity continue to show constrained growth for 42 of the last 45 weeks and dropped below (-2.8%) last year’s total. Crude prices are swaying US shale operators to focus on well productivity (i.e., well completion) and operational efficiency over rig growth.
US Crude Oil Supply and Demand
Crude oil inventories increased 5.5 million barrels from the previous week. The crude stored at Cushing (the main price point for WTI) increased 0.5 million barrels; total stored is 44.9 million barrels (~50% utilization).
US crude oil refinery inputs averaged 16.6 million barrels per day, with refineries at 90.1% of their operating capacity last week. This is 505,000 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 0.9% from a year ago. Total commercial petroleum inventories increased by 8.8 million barrels last week.
US crude net imports averaged 4.468 million barrels per day last week, up by 877,000 barrels per day from the previous week. Over the past four weeks, crude oil net imports averaged 4.087 million barrels per day, 35.9% less than the same four-week period last year.
US crude imports averaged 7.1 million barrels per day last week, up by 1,157,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged 6.6 million barrels per day, 19.6% less than the same four-week period last year.
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