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Tight oil bonanza

US oil production will rise by another 1 million barrels a day in 2014, defying sceptics and suggesting the tight oil surge still has momentum

US OIL output keeps hitting new milestones. In November 2013, the country’s output rose above 8 million barrels a day (b/d), reaching levels not seen since 1987. For the year, production should average more than 7.5 million b/d, or the highest it has been since 1990. Once other liquids such as natural gas liquids (NGLs) and condensate are added, production is well above 11 million b/d. Far from exhausting the potential of shale oil fields, US producers are learning to drill wells more quickly and more cheaply, freeing up capital for more drilling and research into ever more efficient production techniques. As a result, strong growth is widely expected in 2014. On an annual basis, oil output should average 8.5 million b/d in 2014, the US government forecast in December.

Continued growth is mainly expected from the Bakken field in North Dakota and the Eagle Ford formation in southern Texas, the two giants of the unconventional oil business in the US. North Dakota is now comfortably the second-biggest oil-producing state in the US and is on track to surpass the combined output of California and Alaska by late 2014. The surge in production from the Eagle Ford shale, as well as the revitalisation of older producing areas, such as the Permian basin, has put plenty of swagger back into Texas as well. The state’s oil output is now near 2.8 million b/d and exceeds that of Venezuela and a number of other Opec members. This is not to say that oil producers have it easy. Pricing is becoming more difficult as rising domestic output runs up against the limits of refining capacity as US law effectively bars crude oil exports to anywhere but Canada.

Unusually for the fourth quarter, refineries in parts of the US operated at well above 90% of their nameplate capacity, the sort of operating rates normally seen in the summer. Cheap domestic crude and open foreign markets for refined products output explain the high rates of processing. But effectively this means inland oil prices are increasingly pushed down to the level needed to give refiners a strong incentive to maximise processing rates and push fuel into foreign markets. That also means producers have to find outlets for their oil beyond the Midwest and Gulf Coasts, reaching refineries that are less well connected to the shale bounty.

Domestic shipping is increasingly used to move Eagle Ford crude from south Texas to other markets. But as US legislation, in the form of the Jones Act, requires that shipping between American ports be done on a US vessel, freight rates for the tiny Jones Act-friendly fleet of domestic tankers have soared. In late 2013 at least one Jones Act Panamax-size tanker was chartered for six months at an eyewatering $100,000 a day.

As a result of the high costs of shipping and the need to get into refineries cheaply enough to sustain massive exports of refined products even during periods of slack demands, wellhead prices in many parts of the US have fallen to $80 a barrel or less. Producers are mostly determined to continue drilling at planned rates even at these prices, though the long-term sustainability of shale production at $80/b remains open to question given the need for continued capital spending on wells. A number of producers, as well, have indicated that a wellhead price of $70/b would force retrenchment to preserve cash.

Tight oil, in other words, remains a high-cost crude. Even though individual wells are relatively cheap and getting cheaper, high decline rates make for an extremely capital-intensive business.

Lift the export ban

Not surprisingly, the oil industry has tried to put the idea of lifting the ban on crude-oil exports onto the political agenda, with limited success. Although consumers get next to no benefit from the ban – since refined products can be freely exported – politicians are reluctant to tackle the issue, especially with contentious autumnal mid-term elections looming.

After that the lengthy presidential campaign season will begin, which further reduces the likelihood of a serious debate about oil exports until early 2017, when Barack Obama’s successor takes office. In the meantime, producers are banking on high refinery utilisation, capacity expansion and the revamping of plants to handle more light crude oil.

For Eagle Ford producers, more immediate relief will likely come through the commissioning of new condensate splitters on the Gulf Coast, which will allow Eagle Ford condensate to be processed into refined naphtha and other products for export. Kinder Morgan is expected to complete its $370 million, 100,000 b/d Houston, Texas splitter in early 2014, which will process condensate under a long-term contract for BP. Plans call for the facility to have a second 100,000 b/d splitter put into service in 2015. Midstream firms and traders are studying a number of other splitters. They see a huge opportunity to turn low-priced US condensate into high-priced international fuel for a limited capital outlay.

Notwithstanding the difficulties, the US shale basins are hot properties and operators are raising capital spending plans. Marathon Oil alone plans to spend $1 billion in the Bakken in 2014 as it targets a 10,000 barrel of oil equivalent per day (boe/d) increase in output to 50,000 boe/d. Bakken leader Continental Resources aims to spend $3.5 billion on development, most of which will be in the Bakken. Part of their confidence stems from continued technical improvements, which are boosting production and efficiency. Shale pessimists have argued for some time the industry is due to fall off of a production cliff once it exhausts the so-called sweet spots in a field, a term for the most attractive drilling locations. Once the sweet spots are gone, producers will have to turn to less-productive drilling locations and shale output will inevitably fall sharply, the sceptics reason. But far from exhausting the best opportunities producers are converting less-attractive drilling locations into new sweet spots. For instance, improved completion techniques raised initial production rates from the average well in the Bakken field to 465 b/d in the first half of 2013, up from 450 b/d in late 2012, according to IHS, an energy consultancy. And layers of shale below the main Bakken formation, such as the Three Forks shale, are now being probed by operators seeking to prolong the life of their leases.

But beyond pricing, the maturation of shale oil has led to some new thinking about the resource. The Bakken and Eagle Ford shales are clearly world-class discoveries and worthy of the superlatives used in their description. Other plays, such as the Permian basin, where hydraulic fracturing has revitalised production from an area in production for decades, are also exciting. The potential to use hydraulic fracturing in tight sands in existing fields has barely been touched elsewhere. But of the virgin shales, many are falling short of expectations. Chesapeake Energy touted Ohio’s Utica Shale, for instance, as the “next Eagle Ford”.

Yet two years of drilling have been largely disappointing. Instead of gushing light crude, the area seems best for producing wet gas. While still profitable, it is far less of a money-spinner than crude oil since NGLs markets in the US are now largely saturated. Less-than-stellar results from other shales are part of the reason why the US government forecasts a dramatic slowdown in the rate of oil-output growth between 2014 and 2018. Simply put, the Bakken and Eagle Ford phenomena are not being repeated. Without new discoveries or refinements of techniques allowing lesser shale plays to be unlocked, production growth from the US will fade. While the country will continue to produce oil at an elevated level the disruption from the tight oil boom will fade, too.

However the same technological developments that have upended sceptics’ predictions about the Bakken may well come into play on a national level. While the Bakken and Eagle Ford are the only two truly sweet spots at present it is wrong to assume that improved drilling cannot solve the riddles of other fields and prolong the expansion of US oil output beyond what can be foreseen today. Accomplishing that goal, though, may require a recovery in US domestic oil prices. Ironically, the American ban on crude oil exports may play a role here. By keeping domestic crude prices artificially low, the ban punishes risk taking now that the domestic market faces saturation. Oil producers are lifting spending, but they’re focusing it more on proven winners and cutting back on experimental efforts. 

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