OPEC/non-OPEC supply boost likely but keeps oil market on a knife-edge
A fortnight after an unexpected proposal to boost global oil supply by 1 million b/d emerged from a meeting of the Saudi and Russian energy ministers in St. Petersburg, the market has been left hanging in suspense as to whether or not it will be implemented.
The difference between a “yes” and a “no” has so far amounted to a spread of around $4/barrel for Brent futures, between a nervous market driving up prices towards the $80/bbl psychological mark and furiously selling off to pre-empt an increase in supply.
Should a production hike of 1 million b/d be agreed, we estimate a slump of another $4/barrel or so in Brent, cooling it to the low-$70s compared with the 42-month high close of $79.80 notched on May 23.
Between the two diametrically opposite options of raising output by 1 million b/d and keeping the current cuts intact, lies the possibility of agreeing a smaller boost, as we discussed in last weeks viewsletter. The increment would need to be at least more than 500,000 b/d. Anything less would be ineffective in countering the unintended losses from Venezuela and Iran, among others, likely leaving Brent in the mid-$70s, ready to spike again if the supply tightness worsens. As we have said before, even an increase of 1 million b/d is conservative.
Global oil production uncertainties are the highest since the Arab Spring took hold in 2011 and could swing the market into a supply shock that leaves OPEC struggling to plug the gap promptly, or worse, plugging it at all, given the group’s limited spare capacity.
These supply uncertainties arise from accelerating natural declines in conventional oil fields across the globe, amplified by sustained and severe cuts in upstream investment since 2015; delays and teething issues in the few greenfield oil projects coming online; and heightened geopolitical tensions haunting several major oil-producing countries.
Meanwhile, WTI has drifted off again, disconnecting from the global markets. August NYMEX WTI futures closed at a discount of $11.43/barrel to the corresponding ICE Brent contract on June 7, the widest since February 2015. WTI Midland, the price of tight oil in the prolific Permian basin, remains under pressure as surging production has bumped against pipeline takeaway capacity and the forward curve shows a dim view of wellhead prices until September 2019.
WTI Midland is also dragging down NYMEX WTI futures, which represent the value of barrels at the Cushing storage in Oklahoma. Such is the bearish outlook due to the Permian/Cushing bottleneck that not even a third consecutive weekly decline in Cushing stocks reported by the US Energy Information Administration on Wednesday provided any lift.
The drama around Venezuelan output and Iran sanctions has reached a crescendo. We bring you our perspective on the latest twists and what they mean for the ministers meeting in Vienna on June 22.
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Source: U.S. Energy Information Administration, Weekly Petroleum Status Report
For the week ending July 6, 2018, the four-week average of U.S. gross refinery inputs surpassed 18 million barrels per day (b/d) for the first time on record. U.S. refineries are running at record levels in response to robust domestic and international demand for motor gasoline and distillate fuel oil.
Before the most recent increases in refinery runs, the last time the four-week average of U.S. gross refinery inputs approached 18 million b/d was the week of August 25, 2017. Hurricane Harvey made landfall the following week, resulting in widespread refinery closures and shutdowns along the U.S. Gulf Coast.
Despite record-high inputs, refinery utilization as a percentage of capacity has not surpassed the record set in 1998. Rather than higher utilization, refinery runs have increased with increased refinery capacity. U.S. refinery capacity increased by 862,000 barrels per calendar day (b/cd) between January 1, 2011, and January 1, 2018.
The record-high U.S. input levels are driven in large part by refinery operations in the Gulf Coast and Midwest regions, the Petroleum Administration for Defense Districts (PADDs) with the most refinery capacity in the country. The Gulf Coast (PADD 3) has more than half of all U.S. refinery capacity and reached a new record input level the same week as the record-high overall U.S. capacity, with four-week average gross refinery inputs of 9.5 million b/d for the week ending July 6. The Midwest (PADD 2) has the second-highest refinery capacity, and the four-week average gross refinery inputs reached a record-high 4.1 million b/d for the week ending June 1.
U.S. refineries are responding currently to high demand for petroleum products, specifically motor gasoline and distillate. The four-week average of finished motor gasoline product supplied—EIA’s proxy measure of U.S. consumption—typically hits the highest level of the year in August. Weekly data for this summer to date suggest that this year’s peak in finished motor gasoline product supplied is likely to match that of 2016 and 2017, the two highest years on record, at 9.8 million b/d. The four-week average of finished motor gasoline product supplied for the week ending August 3, 2018, was at 9.7 million b/d.
U.S. distillate consumption, again measured as product supplied, is also relatively high, averaging 4.0 million b/d for the past four weeks, 64,000 b/d lower than the five-year average level for this time of year. In addition to relatively strong domestic distillate consumption, U.S. exports of distillate have continued to increase, reaching a four-week average of 1.2 million b/d as of August 3, 2018. For the week ending August 3, 2018, the four-week average of U.S. distillate product supplied plus exports reached 5.2 million b/d.
In its August Short-Term Energy Outlook (STEO), EIA forecasts that U.S. refinery runs will average 16.9 million b/d and 17.0 million b/d in 2018 and 2019, respectively. If achieved, both would be new record highs, surpassing the 2017 annual average of 16.6 million b/d.
Natural gas production in Egypt has been in decline, falling from a 2009 peak of 5.8 billion cubic feet per day (Bcf/d) to 3.9 Bcf/d in 2016, based on estimates in BP’s Statistical Review of World Energy. The startup of a number of natural gas development projects located offshore in the eastern Mediterranean Sea near Egypt’s northern coast has significantly altered the outlook for the region’s natural gas markets. Production from these projects could offset the growing need for natural gas imports to meet domestic demand, according to the Egyptian government.
The West Nile Delta, Nooros, Atoll, and Zohr fields were fast-tracked for development by the Egyptian government and have begun production, providing a substantial increase to Egypt’s natural gas supply. The Zohr field’s estimated recoverable natural gas reserves of up to 22 trillion cubic feet (Tcf) would make it the largest natural gas field in the Mediterranean, based on company reports gathered by IHS Markit. The Zohr field is currently producing 1.1 billion cubic feet (Bcf) per day and is expected to increase to 2.7 Bcf per day by the end of 2019.
Natural gas production in Egypt has declined largely as a result of relatively low investment, according to Business Monitor International research. Meanwhile, domestic demand for energy has grown, driven by economic growth, increased natural gas use for power generation, and energy subsidies. With the exception of small declines in 2013 and 2014, natural gas consumption has increased every year since at least 1990, and it is up 19% from 2009, when domestic production peaked.
Faced with growing demand and declining supply, Egypt had to close its liquefied natural gas (LNG) export terminals to divert supply to domestic consumption. Egypt became a net natural gas importer in 2015, and although LNG exports resumed in 2016, Egypt’s net imports of natural gas continued to increase.
Source: U.S. Energy Information Administration, based on 2017 BP Statistical Review of World Energy
The Middle East Economic Survey (MEES) indicated that Egypt will still need to import small volumes of natural gas in the coming years, particularly for the power sector. MEES reported that the state-owned Egyptian Electricity Holding Company (EEHC) awarded contracts that would add 25 gigawatts (GW) to total generation capacity, 70% of which would come from natural gas-fired projects. Three combined-cycle natural gas turbine power plants with a total capacity of 14.4 GW will collectively require as much as 2.0 Bcf/d of natural gas when they become fully operational in 2020.
A threat. And then a backing off. As the trade war between the US and China escalates, both countries are moving into politically sensitive areas as they ratchet up the scale of the standoff. When the US first introduced tariffs earlier this year, they were limited to washing machines and solar panels. Then as President Trump moved into a broader range of goods, China responded with tariffs that were designed to maximise impact on Trump’s voter base. That meant the agriculture heartlands of the US in the Midwest where soybeans are grown and shipped in record numbers to China last year to feed its massive demand for animal feed and edible oils. Last week, the US imposed tariffs on an additional US$16 billion worth of Chinese imports, targeting technological sectors, and of course, China replied. The list included for the first time US crude exports, demonstrating China’s willingness to hit one of America’s most vibrant industries. And then, a few days later, it backed down, removing crude oil from the list.
Chatter among the industry suggests that Sinopec had lobbied for the removal. Even though growth has slowed down nominally, China’s fuel demand is still growing massively on an absolute level. In a year where Iranian crude exports are being squeezed by new American sanctions, China needs oil. It may have defied a request by the US to completely halt Iranian exports, but it has also promised not to ramp up orders as well. China imported some 650,000 b/d of crude from Iran last year. To replace even some of that will be challenging without tapping into growing American production, particularly since Sinopec and Petrochina are in a tiff with Saudi Aramco over prices, and the government wants to diversify its crude sources away from overreliance on Russia.
So crude was removed from the tariff list. Leaving only refined fuels and petrochemical feedstocks – tiny in demand except for propane, which has become a key feedstock for China’s petrochemicals producers through PDH plants. But since President Trump has mooted more tariffs, this time on US$200 billion worth of imports, China may have backpedalled for strategic reasons this time – Sinopec’s trading arm had suspended all US purchases until the ‘uncertainty passed’- but can still wield its potent weapon in the future. And not just on crude, but tariffs on LNG as well. The latter is more sensitive, given that many of the LNG projects springing up along the Gulf Coast are depending on projected Chinese demand. Cheniere just signed a 25-year LNG deal with CNPC and is hoping for more to come. That hope burns bright for now, but if the trade war continues escalating at its current pace, the forecast could get a lot cloudier. For now, US energy exports have been spared from the wrath of the Middle Kingdom. Enjoy it while it lasts.
Sign-up to NrgEdge for your weekly oil & gas news and analysis