In an era of increasing hyperbole, shale energy stands out more and more for its ability to live up to its hype. Development of technologies for hydraulic fracturing, more commonly known as fracking, is poised to make the U.S. the world’s largest oil producer by 2015, according to the International Energy Agency, which recently forecast that the daily domestic production of crude, condensates and natural-gas liquids will peak at 11.6 million barrels per day by 2020. This trend has triggered a flurry of investment in the sectors that handle the logistics required to get this new production to markets. The prospect of a glut of oil from shale deposits has also triggered a debate about whether the U.S. should export crude. After decades of worry about a dependence on foreign imports, now there is suddenly enough oil in the U.S. to overturn 40 years of policy orthodoxy in Washington.
Oil producers want an end to an existing ban on crude oil exports that has been in place since the oil supply shocks of the 1970s. Freedom to sell overseas would benefit any oil producer because having more potential buyers means a chance to sell to the highest bidder. But those with shale deposits in the interior of the country in particular would benefit because much of the existing refinery capacity in the U.S. was built to process domestic crude as well as the imports that were assumed to be necessary to balance supply and demand. What producers of shale oil have to offer is less desirable to domestic refiners. That hurts their prospects for profits.
But even if the supporting evidence these oil producers offer to Washington is backed by valid economics, oil dependence remains a political issue with national security implications. To millions of voters, energy independence means ending a reliance on imports and bilateral relations with Saudi Arabia. It seems unlikely that a nuanced argument about refinery capacities and the various grades of crude oil can stand up to a sound bite to rival “No foreign oil.” It’s also hard to imagine that many politicians would champion the cause on Capitol Hill, making the case to voters. The lobbying effort continues in Washington nonetheless, and should it prove successful, winners would include the Bakken’s biggest leaseholder and producer, Oklahoma City–based Continental Resources. Those who would potentially stand to lose include Californians, says Jonathan Chanis, an oil industry specialist; the managing member of Torrington, Connecticut–based New Tide Asset Management; and adjunct professor at Columbia University’s School of International and Public Affairs.
“If you give domestic sellers the option of selling crude oil internationally, they would have more buyers and the realized price should go up,” says Chanis. “However, there could be negative implications for California. The export ban often slightly lowers the price of crude in California because Alaskan production is essentially captive to that market.”
The present U.S. law on crude oil does allow for exports to Canada, however. This positions Canadian refiners as a potential market and offers U.S. producers far lower shipping costs than they would incur with other international markets, should they open.
Judging from present investment activity, energy producers and the companies that service them do not seem to be banking on changes in U.S. law. Investors are instead spending billions to improve all modes of surface transportation, reviving old refineries and adding capacity to existing ones. A case in point is the U.S. pipeline network, which is operating at full capacity. Presently, there are 26 new pipeline projects under way in Canada and the U.S., according to research from RBN Energy, a Houston–based consultancy. Pipelines are often built and held by master limited partnerships (MLPs), an ownership structure that receives favorable tax treatment but must pay out cash flow to investors, similar to a real estate investment trust. An MLP is suitable for pipelines because usage is set in long-term contracts that provide stable cash flow. For investors, the high yields can be attractive in low-interest-rate environments. Houston–based Buckeye Partners is an example of an MLP popular among institutional investors. The California Public Employees’ Retirement System (CalPERS) is among its major holders and boosted its stake during the third quarter, according to public filings.
Railways are another possible avenue of investment should the crude oil ban be lifted. Producers forgo the stability of long-term obligations to supply a pipeline and pay more per barrel when shipping via rail, but they gain the ability to auction their output to the highest buyers on the spot market. For Texas crudes in the Eagle Ford shale play, Union Pacific has emerged as a major transportation option, with CalPERS and the New York State Common Retirement Fund counted among its major institutional owners. Railroads are also the best choice to move crude from the interior to refineries on the East and West coasts, as most of the country’s pipeline network is north-south oriented.
The U.S. shipping industry is also enjoying a revival, thanks to another combination, which includes another law that crude exporters would like to see repealed. The Merchant Marine Act of 1920, commonly known as the Jones Act, requires any ship movements between domestic ports to use a U.S.-flagged ship built by a U.S.-owned company and crewed by U.S. citizens and permanent residents. These rules, when coupled with U.S. labor laws and environmental and other regulations, amount to a major cost when compared with international shipping options. Jones Act shipping is costlier still at the moment because demand has risen and the supply of suitable tankers and barges has not caught up. On the spot market as of December 9, in the international shipping market a medium-range tanker would cost $14,750 per day to charter, according to New York–based global ship broker Poten & Partners.
The market for Jones Act ships is too illiquid to provide an exact comparison, but a record high of $100,000 per day was touched in June for a ship with less than half the capacity of a medium-range tanker, an indication of the difference in costs. Market reaction includes the IPO of American Petroleum Tankers, which has been controlled by Blackstone Group since the New York–based alternative investment firm bought it for $500 million in 2006. Houston–headquartered Kirby Corp. operates a fleet of smaller transport barges used for inland transportation. Equity owners include the State of Wisconsin Investment Board and the New York State CRF, which according to public filings added to its holdings in the third quarter.
At the downstream level, the refining industry in the U.S. is essentially regional. West Coast refineries typically receive crude from Alaska’s North Slope. Those on the Gulf of Mexico buy imports as well as conventional crude, the blend of Texas and other U.S. crudes that make up the benchmark West Texas Intermediate. Refineries on the East Coast are historically the most dependent on imports and have until now been the least profitable. As of 2010 refineries were being closed or converted to storage terminals, but inexpensive shale oil has drawn new investment. Blackstone and the Washington–based private equity firm Carlyle Group have each bought an East Coast refinery.
Further investment in refinery capacity is more likely to come in the form of upgrading existing operations rather than creating major new ones — and is perhaps a better idea than exporting crude. “[The U.S. is] the Saudi Arabia of petroleum refining,” says Chanis. “The refining sector, especially on the Gulf Coast, is a hidden jewel in America’s economic recovery. We have a competitive advantage that is going to be very hard for other countries to beat because we have very competitively priced oil feedstock, and it is more expensive to build refineries outside the U.S.”
