Two years almost to the day after Alaska Sen. Lisa Murkowski, chair of the Senate Energy and Natural Resources Committee, issued her white paper promoting exports,
“Renovating the Architecture of U.S. Energy Exports,” she got her wish. On Dec. 31, 2015, a tanker departed NuStar Energy LP’s dock at Corpus Christi, Texas, loaded with Eagle Ford crude oil produced by ConocoPhillips.
A few days later, Enterprise Products Partners shipped a second cargo of Texas crude out of its facilities on the Houston Ship Channel. The buyer in both cases was global commodity trading giant Vitol Group, which planned to move the oil by pipeline to two reﬁneries it operates in Europe under a joint venture it arranged last year with The Carlyle Group.
The total volume shipped by the two vessels amounted to about 930,000 barrels (bbl), according to Genscape estimates.
By any stretch of the imagination, it was not a lot. U.S. production in November was about 8.7 million barrels per day (MMbbl/d) in the Lower 48 alone, and 9.3 MMbbl/d in total.
But lifting the 40-year-old ban was a huge step forward—one of the most signiﬁcant policy changes beneﬁting the U.S. oil industry in years, with long-term ramiﬁcations. Pressure to do this built up over the past two years as U.S. light, tight oil production soared, storage tanks ﬁlled and study after study said exports would be good for the economy. Crude was at record levels at the key Cushing, Okla., storage and trading hub in February.
The dog caught the car
Despite that, many pundits warned that nothing would happen until after the presidential election. Now that the dog has caught the car, what will he do with it?
Lifting the ban has already brought West Texas Intermediate (WTI) prices back in line with Brent and other world market prices, as experts predicted, narrowing the usually wider spread. In fact, for the ﬁrst time in years, WTI traded at a premium to Brent early this year. This phenomenon increases the value of every barrel we can produce—an incentive to produce even more, were it not for the oil price crash that has altered the equation in other ways. In the meantime, experts say, transportation costs will hamper the economics of U.S. oil exports versus competing sources of crude.
Still, the fact that the ban is dead is good news, if not now, then especially in the longer term. Experts say as much as 1 MMbbl/d could be available for export if the economics justify it.
“For producers, this is tremendous,” Continental Resources Inc. Chairman and CEO Harold Hamm said. “First of all, this gives us a future—without it we were all about dead. We didn’t have enough reﬁning capacity here for all the sweet crude we were producing. Now, you’re not just going to be shipping it to the coasts, you’re going to go beyond the coasts.”
Continental has been shipping its Bakken crude west via the BNSF Railway to Tesoro’s reﬁnery at Anacortes, Wash., and it “certainly intends to be exporting by the end of the year, or as soon as practical,” Hamm said.
Not surprisingly, he said the company is considering exports to Asian buyers where it already has relationships.
The U.S doubled its oil production from 2008 to 2014, and Hamm believes it has the capacity to double it again and go up to 20 MMbbl/d.
“You get into a rare league then. How many 20-million-a-day producers do you know? This is a real transformation of the world’s oil supply: We have the highest-quality oil, and this ends OPEC dominance once and for all.”
The differential between WTI and Brent was as wide as $42 per bbl at one time, and Hamm had said that once the ban was lifted, that would go away. “In the ﬁrst 11 hours of trading, it did,” he said. “It was history. So that was an immediate beneﬁt. And we said gasoline prices at the pump would go down, and that’s exactly what’s happened.”
ConocoPhillips said its Dec. 31 export cargo through NuStar’s facility was not the result of a premeditated effort to be the ﬁrst U.S. producer off the launch pad, although the company certainly is proud to have been able to react quickly to the ban’s demise.
Was ConocoPhillips’ ﬁrst export cargo a one-off to test the system’s logistics, to open negotiations with a willing buyer, Vitol, or was it the start of a broader effort to export its crude?
The best buyer
“We market our crude oil to opportunities as they manifest themselves,” said ConocoPhillips senior economist Helen Currie. “Our marketing organization is always seeking the best buyer, so I can’t deﬁnitively say we will have more [export cargoes] or not this year; that will depend entirely on the market.”
The opportunity the company seized in December was not contrived or planned, but rather was the result of a market opportunity that appeared concurrently with the lifting of the ban. “We were not seeking an export-speciﬁc buyer, because we did not know when the ban would be changed,” Currie said.
“It just so happens that we were originally transacting for a stream of processed crude condensate when the ban was lifted, and we were then able to send unprocessed crude instead. We were definitely grateful for the opportunity, but it was a fortuitous set of circumstances.”
Although observers are positive about the benefits of exports, many take a somewhat cautious tone for now in light of low global oil prices and slackening demand in Asia.
“In general, any incremental exports of light crude from the U.S., or even heavier crudes, say, from California, should in theory help producers in a fairly difﬁcult supply situation globally,” said Ed Morse, Citigroup’s global head of commodities research.
Here’s what he expects, “in no particular order:”
• Exports of light crude to Mexico for use in Mexican reﬁneries, to enable them to have a higher yield of light-end production.
• Exports of light crude through Mexico to the Pacific Port of Salinas Cruz, to be blended into Mexican heavier crude oils, for re-export to the U.S. West Coast and even onward to the Pacific Basin.
• Traders buying U.S. crudes and shipping them to Venezuela, to “blend up” heavier Venezuelan crude for external sales to Europe, and perhaps even as far east as India.
“So, in general, even as WTI/LLS [Light Louisiana Sweet] and Brent have tightened their price relationship, there are opportunities still for growing volumes of U.S. crude oil, including condensates, to reach foreign markets,” he said.
It is too soon to gauge the potential value of crude oil exports from U.S. coasts; after all, exporting is a ﬂedgling industry, and companies negotiating to ship crude abroad remain tightlipped for competitive reasons.
In the infrastructure sector, companies are consulting, studying and gearing up. It’s important to note that along with lifting the ban, Congress also overturned the Jones Act requirement that only U.S.-ﬂagged ships be used to export Alaskan oil from the West Coast.
There is talk that the Louisiana Offshore Oil Port could be reconﬁgured to add more crude storage for traders and new export facilities for light, shale crudes. Currently, it handles heavier crudes coming from Gulf of Mexico ﬁelds.
Enterprise Products, NuStar and other midstream players with facilities along the Gulf Coast are adding docks, storage tanks and pipelines to facilitate handling of onshore crudes for export. Private-equity provider ArcLight Capital Partners LLC and Freepoint Commodities LLC teamed up recently to buy an idled reﬁnery and storage complex in St. Croix, U.S. Virgin Islands, to revitalize it as an oil hub. Sinopec Ltd. has already contracted for some of the storage capacity.
At ﬁrst, exports will be a trickle, but eventually a global market will emerge, Hamm predicted. He cited the case of U.S. propane exports, which were small and not proﬁtable at ﬁrst. Today that market has grown to 500,000 bbl/d of exports.
“We’ve identiﬁed 3.2 MMbbl/d of world reﬁnery capacity that was at risk (or already partially closed) due to the lack of supply of the type of light oil needed. This Bakken oil is light and sweet and has so many middle distillates. It’s very high quality, so you just need to export it, one deal at a time,” Hamm said.
Barclays analyst Michael Cohen said certain regions will be more welcoming than others, such as Mexico and Latin America. Europe may become a more prominent destination as North Sea crude production declines, but the U.S. would face steep competition for that market from exporters in the Middle East, Africa, the Caspian and Russia.
“Though energy security concerns may compel some countries, such as Poland and the Baltic states, to seek U.S. crudes, the U.S. crude footprint in Europe is likely to remain limited to special market circumstances, due to high cost and the need for higher distillate cuts,” Cohen said in a report.
In any case, lifting the export ban on U.S. crude is expected to increase U.S. trade in oil, said Anas Alhajji, energy economist with NGP Energy Capital Management LLC, “but the U.S. will export light sweet crude and import heavier and more sour crudes. This should beneﬁt U.S. producers greatly in the long run, especially when we move from global competition in crude to global competition in products.”
Others take a cautious view.
“The realization that crude exports are now happening is an interesting footnote for 2016 markets, but likely just that,” said Greg Haas, Stratas Advisors’ director, integrated oil and gas research. “It marks the end of a 40-year market distortion. But I don’t think exports will be a big 2016 driver, given low oil prices and the overhang in crude oil supply around the world that we see lasting for months.”
Haas thinks exports of 500,000 bbl/d are a reasonable expectation as an annual average. Condensate and limited crude exports, meanwhile, have already increased steadily from 50,000 bbl/d in 2013 to 485,000 bbl/d last year.
“I think the U.S. oil industry should replicate the story of the U.S. LNG industry: convert import facilities to export facilities—or make them bidirectional.”
Haas said he believes it would take signiﬁcant crude import declines, or drastic production declines in the U.S., to wear off the record-breaking crude supply overhang in the U.S. in 2015.
“With global benchmark crude prices lower than U.S. WTI, and off-shore crude storage costs around the world reportedly priced at a higher rate than onshore crude storage, (which is still available in the U.S.), we think the industry will continue stockpiling crude into the U.S. in 2016,” he said.
“Those will be barrels produced by U.S. operators more intent on holding or growing production rather than cutting growth, or they will be barrels imported for reﬁning here or brought onshore to hide out the market with lower U.S. onshore storage costs here.”
Haas said that despite ﬂashy announcements of now-legal exports, U.S. midstream operators “can likely beneﬁt more from offering onshore storage at stronger rates to crude producers and importers, rather than trying to do a few tanker loads of premium-priced U.S. light crude exported into a glutted and discounted global market.”
Ironically, the arbitration to Europe looks closed as long as LLS crude trades for a higher price than Brent. On Dec. 28, spot prices for the Brent benchmark closed at $35.03/bbl—that was $1.78 per bbl below the inland U.S. WTI crude benchmark that closed at $36.81 per bbl that day. WTI was trading at a premium to Brent through August 2017 for the ﬁrst time since the shale boom began, Reuters said.
“Excluding transport costs, the WTI premium to Brent incentivizes light sweet crude producers to ship oil cargoes to the U.S.,” it said.
“It’s tempting to think that the overturn of the U.S. export prohibition has created a run on U.S. crude barrels and crude prices. But while exports of unprocessed crude and condensate are now possible, we don’t see them as voluminously probable,” Haas said. “We believe differentials would need to widen to cover the costs of transport between U.S. and global markets.”
Market dynamics such as current crude differentials—and onshore storage capacity in the U.S.—still promote imports of lower-cost light crude oil into the U.S., rather than exports of higher-cost domestic crude offshore, he said.
The U.S. likely will continue to be a net importer of crude for the foreseeable future, but if reﬁneries around the world need additional light crude, now they have a new supply source to consider. Diversity of supply and open, transparent markets are key goals for producers and consumers alike.
It is ironic, however, that just as a 40-year-old barrier was lifted to open up new market outlets to U.S. producers burdened by low cash ﬂows, they face a new hurdle—oil prices crashing through 12-year lows. Why ship more oil into a market that is already struggling with a glut of supply and tepid demand, and what’s more, the pending arrival of up to 200,000 bbl/d or more from sanctions-free Iran this year?
The International Energy Agency (IEA) projects that 2016 could end up being the third consecutive year that the global supply surplus is over 1 MMbbl/d more than demand, despite the fact that it projects a 600,000 bbl/d decrease in non-OPEC oil production this year.
With the ban lifted, a more truly global market has emerged with increased efﬁciency, but the strength of that market will dictate the extent to which U.S. barrels ﬁnd their way abroad. The IEA said oil demand grew in 2015 by about 1.8 MMbbl/d, a solid number by historical standards. But growth this year is projected to be less robust, at 1.1- to 1.3 MMbbl/d, it said.
The Chinese driver
Chinese demand ﬂuctuations are the main driver, and although its economy is slowing during its transition to a consumer- and service-led market from one based mostly on manufacturing, demand there is still growing, albeit on a more gradual curve.
“Iranian increases of 500,000 bbl/d are largely offset by second-tier declines and leakage into Iraq … resulting in only a small increase from the current OPEC production rate of 31.7 MMbbl/d,” Tudor, Pickering, Holt & Co. said in a report.
“By second-half 2017, further market tightness requires an additional OPEC production increase of 1.2 MMbbl/d, led by Saudi Arabia. We assume Iran, Iraq and Libya also contribute to the 2017 production increase.”
Exports of U.S. oil will no doubt stimulate production (absent oil price signals), but it remains to be seen by how much. That will depend on the global market’s appetite for U.S. barrels. Before the price crash of 2014-2015, several studies estimated U.S. production would hit 10 MMbbl/d in 2016.
Hamm estimated daily U.S. output could increase by as much as 1.2 MMbbl/d by 2025. A study by Columbia University’s Center on Global Energy Policy and the Rhodium Group estimated an increase of 1 MMbbl/d, as did IHS in its base-case scenario. Consulting ﬁrm ICF said production could increase from 100,000 bbl/d to 400,000 bbl/d annually to 2025. Goldman Sachs estimated production would go up by 1.5 MMbbl/d in 2020, in its base case.
IHS noted that U.S. reﬁning capacity will be saturated by 9 to 10 MMbbl/d of production, creating a bigger need to export—a supply push for exports instead of a demand pull. The U.S. EIA, however, projects that domestic production of about 9.4 MMbbl/d in 2015 will fall to an average 8.7 MMbbl/d in 2016 and ﬂatline through 2017, perhaps offsetting the needs of foreign buyers.
The Brookings Institution said daily U.S. production by 2020 will be anywhere from 1.3 MMbbl to 2.9 MMbbl more than it would have been under the ban.
Before the crash
But keep in mind, all of these projections were made during the heat of the push for lifting the ban—and well before the oil price crash that has decimated the domestic rig ﬂeet, causing producers to cut their 2016 budgets in half.
Given the forward price deck that Stratas uses—where Brent’s premium to WTI only gets above $4 in 2020—Haas said he doesn’t see a lot of arbitrage potential to export light U.S. crude in the years ahead.
Tudor, Pickering, Holt & Co. said it still anticipates tightening global supply and demand fundamentals starting in the second quarter of this year, with tightness continuing into 2017, and especially as more global megaprojects are delayed or deferred, setting up the possibility of a much tighter supply- demand balance in a couple of years.
Meanwhile, Tudor stands by its projection of $80 per bbl by the end of 2016. Like others, it projects global demand to increase by about 1 MMbbl this year and again in 2017, “consistent with the long-term average growth rate.”
“Regardless of who loads that next ship, all U.S. producers will beneﬁt,” said ConocoPhillips’ Currie. “It’s a wonderful uplift to the economy that creates more jobs and is generally going to be a widespread beneﬁt. As long as U.S. production is higher than it would have been without the ban being lifted, it’s also good for U.S. consumers.
“We still hold the view that the world market will want our U.S. oil.”
2022-05-02 - BP’s Starlee Sykes provided an inside look during an OTC keynote presentation on how the operator is optimizing all four of its producing hubs in the Gulf of Mexico as part of its net-zero goals.
2022-02-28 - Two of the gas fields, Samna and Umm Khansar, are “non-conventional” or shale, according to Saudi Arabia Energy Minister Prince Abdulaziz bin Salman.
2022-02-28 - Monthly gross natural gas production, meanwhile, rose 100 MMcf/d to a record 108.3 Bcf/d in the U.S. Lower 48 states in December, the EIA said in its monthly production report.
2022-02-28 - In this digitalization transformation era, Petrobras’ "innovation machine" aids in assembling a team to create new technologies, strong business strategies and increasing efficiencies.
2022-03-01 - Experts with Project Canary and MiQ share insights and strategies on emissions monitoring technology, certification and leak prevention.