When the U.S. lifted its crude oil export restrictions in December 2016, it completely changed the landscape for the global tanker industry, creating a major new source of seaborne cargo. Tanker operators’ focus on U.S. crude has become increasingly intense ever since, particularly in light of OPEC cuts, renewed sanctions targeting Iran and rising geopolitical tensions near the Strait of Hormuz.
The big question now is: Will the heightened U.S. role in tanker markets always be a plus, or is there downside ahead?
To the extent U.S. crude replaces Middle Eastern supply among Asian buyers, it’s positive for the rates of very large crude carriers (VLCCs), ships that carry two million barrels of crude oil each.
Because VLCCs cannot fit in the Panama Canal locks, they take the long way from the U.S. to Asia, via the Cape of Good Hope. It is 6,608 nautical miles between Ras Tanura, Saudi Arabia, and Chiba, Japan; from Houston to Chiba, it’s 15,887 nautical miles. Because U.S. crude is transported 2.4 times the distance to Asia as Middle Eastern crude, it effectively creates demand for 2.4 times as many VLCCs when measured in ton-miles (volume multiplied by distance), all else being equal.
The positive effect on average VLCC voyage distance (and thus, demand) has been a welcome relief for tanker owners. “U.S. exports ramped up faster than expected, partially offsetting the weakness from lower OPEC production,” said Randy Giveans, shipping analyst at Jefferies, in a new industry report. “As U.S. exports ramped up in May and June, VLCC rates surprised to the upside.”
During the Marine Money Week conference in New York on June 17-19, Petter Haugen, equity research analyst at Kepler Cheuvreux, maintained, “OPEC cuts are simply subsidizing U.S. shale and moving incremental production two to three times further apart from consumption.”
U.S. crude production is an increasingly important indicator to watch for publicly listed VLCC owners such as Euronav (NYSE: EURN), DHT (NYSE: DHT), Frontline (NYSE: FRO) and International Seaways (NYSE: INSW). The concern is that U.S. production may not be able to keep up its growth pace – leaving less crude available for export.
“With a declining rig count, [U.S.] oil production should continue to grow, albeit at a slower pace, reducing previously expected export growth and subsequent tanker demand,” warned Ben Nolan, shipping analyst at Stifel, in a new shipping outlook report.
So far, so good
Driven by the fracking and shale-oil revolution in drilling technology, U.S. production surged from 5 million barrels per day (b/d) in 2008 to 9.4 million b/d in 2015.
After falling back to 8.8 million b/d in 2016, U.S. production rose to 9.4 million b/d in 2017 then jumped to 11 million b/d in 2018. The Energy Information Administration (EIA) currently predicts production of 12.4 million b/d this year and 13.3 million b/d next year, driven by output increases in the Permian Basin in Texas and New Mexico.
In 2017, the first year in which shipments were allowed to countries other than Canada, U.S. crude exports averaged 1.2 million b/d. Last year, outbound volumes rose to 2 million b/d. So far this year, they’re averaging 2.9 million b/d, hitting an all-time high of 3.3 million b/d in June (based on preliminary estimates).
U.S. crude export volume averaged 12 percent of total production in 2017. Last year, 18 percent of U.S. production was exported; so far this year, the export share is 25 percent.
If the U.S. continues to export a quarter of its crude production, and the EIA production estimates prove correct, the country’s exports would be about 3.1 million b/d this year and 3.3 million b/d next year.
Whether U.S. crude exports can maintain current momentum depends upon the answer to three questions: Will there be enough terminal capacity to load the crude? Will there be enough pipeline capacity to get the crude from the Permian Basin to the coast for loading? And will U.S. crude production growth be maintained?
Export terminals on the drawing board
The U.S. Gulf currently has only one terminal that allows for direct docking by VLCCs – the Louisiana Offshore Oil Port (LOOP). LOOP is primarily contracted for crude imports, but it has also been handling a limited amount of exports since February 2018.
Outside of LOOP, VLCCs are being loaded through a process called ‘reverse lightering.’ The crude is initially loaded aboard smaller tankers in the Aframax category (with a capacity of 750,000 barrels of crude oil each), then a ship-to-ship transfer is used in deeper waters offshore to fill the VLCC. The reverse lightering process can add two to three days to the transportation time and cost shippers an extra $1 million.
The good news for both crude oil shippers and VLCC owners is that developers are investing in more facilities that can directly handle VLCCs – and in the meantime, the need to reverse lighter does not seem to be dissuading shippers.
During a conference call with Stifel in December 2018, consultancy East Daley cited plans for the development of up to 10 VLCC loading facilities with almost 8.2 million b/d in combined capacity. Although only some of them are expected to be built, it should be enough to provide cost savings to crude exporters through averting the reverse-lightering process.
Proposed projects include both land-based terminals and offshore facilities fed by pipeline. Most are centered around Corpus Christi, which is the best-connected with the Permian Basin and has higher water depth offshore.
Insufficient water depth is the reason for the current inability to handle VLCCs along the U.S. Gulf Coast. According to East Daley, water depth drops to 90 feet, a safe depth for a VLCC port, around 15 miles off the coast of Corpus Christi. Off Houston, the water depth doesn’t drop off to 90 feet for 50 miles. The shallower it is further out from shore, the more expensive it is to dredge a channel to accommodate a land-based loading site or to lay pipeline in the case of an offshore loading platform.
More pipeline capacity from the Permian
The next potential export constraint is pipeline capacity from the production field to the coast. The good news for tanker operators and crude exporters is that a large amount of new pipeline capacity is about to come onstream.
Nolan noted that around 2.2 million b/d in pipeline capacity from the Permian Basin to the Gulf has been announced or is under construction, including Cactus II, Gray Oak, Epic, and Bridge Tex Expansion II. Of that, around 1.8 million b/d should come online by the end of this year, mostly in the fourth quarter. The remainder should enter service by mid-2020.
Nolan said that by “removing the bottleneck,” the new pipeline capacity should increase U.S. exports, a positive for tanker demand measured in ton-miles.
Another positive pipeline-related development for U.S. exports involves Capline, the largest pipeline connecting the Gulf Coast to the Midwest. It flows south to north, and is fed by imports through the LOOP facility, but its direction is being reversed. In February, owner Plains All American Pipeline LP (NYSE: PAA) confirmed a target of the third quarter of 2020 for the reversal, which should lead to a substantial increase in U.S. exports through LOOP.
Uncertainty over U.S. crude production
With pipeline and terminal trends in favor of tanker owners, that leaves the most important question: What’s next for U.S. crude production?
Concern has been rising. According to Baker Hughes, the number of active U.S. oil rigs had fallen to 779 as of July 19, the lowest total since February 2018 and down 12 percent from the number of active rigs in November 2018.
A major challenge faced by exploration and production [E&P] companies is a loss of access to capital-market funding. Investors are demanding that these companies focus more on debt reduction, dividends and share buybacks, not speculative growth.
According to Dealogic, a company that provides transaction statistics, equity proceeds of U.S.-listed E&P companies fell by almost 60 percent in 2018 compared to the previous year.
Texas-based data analytics company DrillingInfo said in a new report that the U.S. energy industry raised 36 percent less from equity and debt offerings in the second quarter of this year than in the same period last year. According to Drillinginfo analyst Andrew Dittmar, “Wall Street emphatically closed the door on fresh external capital for upstream companies. That is consistent with calls for E&Ps to live within cash flow.”
Commenting on the falling rig count, Nolan of Stifel said that “capital discipline by E&P companies means that [production] growth is slower than expected.”
Concern over U.S. production could offer one reason why some U.S.-listed tanker stocks have pulled back as the price of crude has come down. The lower the price of crude, the more likely that U.S. production will not grow as fast. The slower U.S. production grows, the less potentially available for export on long-haul routes to Asia, and the less positive the ton-mile demand effect is for tanker rates.
