U.S. Energy Renaissance

Just how fast can oil production grow in the supply renaissance now taking hold in the U.S. industry as a result of technology advances in horizontal drilling and hydraulic fracturing? The answer, according to a report by Houston-based energy experts Simmons & Co. International: gains of as much as 319,000 to 938,000 barrels per day per annum, with the high case taking U.S. volumes by yearend 2015 to levels exceeding 10 million barrels per day (MMbbl/d)—a level last seen in 1970.

Even the firm’s low-case scenario bumps volumes up to almost 7.6 MMbbl/d, or roughly 1.3 million higher than the 2011 year-end level of 6.2 MMbbl/d.

The bookends Simmons puts on its underlying oil price assumptions are $100 per barrel in its high case and $70 in the low case, with the base case at the $85 midpoint. Each case assumes a natural gas price of $3.50 per thousand cubic feet (Mcf).

From a 2011 exit rate of 6.2 MMbbl/d, the three scenarios laid out are: an average 319,000 bbl/d per annum growth rate in the low case, taking production to 7.6 MMbbl/d at year-end 2015; 627,000 bbl/d per annum growth in the base case, taking volumes to 8.8 million daily; and 938,000 bbl/d growth in the high case, with output rising to 10.1 MMbbl/d. The projections do not include any estimates for natural gas liquids.

This “significant and sustainable growth” foreseen in North American oil production represents a transformation from an earlier profile of “seemingly intractable stagnation and decline,” says study lead author Jeff A. Dietert. However, U.S. onshore production would likely lapse into stagnation, it says, if oil were to fall to the $70/bbl low-case scenario.

Although its low-case projections indicate a 5% compound annual growth rate through 2015, a slowdown in the underlying pace of growth is obscured by two factors: a 2013 jump in volumes due to the delayed effect of 2012 drilling activity, and an increase in Gulf of Mexico volumes as longer lead-time projects (Jack/St. Malo, Lucius, etc.) come on in 2014 and make full-year contributions in 2015. Adjusting for these two factors results in “a far more intuitive conclusion—at $70/bbl oil prices, U.S. onshore production stagnates” by 2014-2015.

From a global perspective, the rapid gains projected in U.S. oil production under the higher price scenarios are needed to offset what has been disappointing growth in non-OPEC production, excluding North America. “Non-OPEC supply projections in every single region aside from North America have been revised lower throughout 2011-2012,” the report’s authors say, noting that total non-OPEC supply growth is estimated to be about 400,000 bbl/d in both years.

“No individual regions outside of the U.S. and Canada grew by more than about 100,000 bbl/d,” and production growth in the U.S. and Canada during 2013 is expected merely to offset declines in other non-OPEC regions. These challenges in growing global non-OPEC production “suggest WTI (West Texas Intermediate) prices above $70/bbl may be necessary to sustain growth.”

For the oilfield service segment, prospects have improved even in the short few weeks since the report went to press. With oil prices moving higher following indications of potential stimulus in Europe, as well as a stronger euro/weaker dollar, “we’re now part way between our base case and high case, which would be supportive of oil-directed drilling activity,” says Dietert, co-head of equity research at Simmons.

Under its base case, the U.S. Lower 48 oil rig count (excluding Gulf of Mexico) is projected to be down 1% in 2013 before rising 4% in 2013 and 11% in 2014. The recent upgrade moves Simmons part way towards its high case, calling for a 9% rise in the oil rig count in 2013 and 15% increases in each of 2014 and 2015. Latest exploration and production spending data show a further slide in gas-directed drilling, “but oil-directed drilling is holding,” observes Dietert.

In addition to increases in the U.S. rig count, factors driving higher U.S. volumes include improved estimated ultimate recoveries (EURs) and initial production (IP) rates. These are assumed to improve by 5% per annum in the base case and 10% in the high case.

Forecast gains range from 319,000 to as much as 938,000 barrels per day per annum; year-end 2015 oil production would return to the 1970 level of 10 million barrels per day in the high case.

Infrastructure, refinery implications

On the infrastructure front, Simmons’ base-case scenario foresees major pipeline projects providing sufficient capacity to deliver crude to market through 2015, although conditions by basin will obviously differ. For example, Bakken oil supply is expected to continue to outstrip pipeline capacity through 2014 in all cases, with rail required to move excess production.

While sufficient rail-loading capacity additions are foreseen, various bottlenecks in the system (railcar availability, rail congestion, unloading facilities, etc.) mean Bakken discounts are likely to remain wide through 2014 (i.e., prevent Bakken prices from clearing at destination prices less rail transportation). Meanwhile, additional rail-unloading facilities are planned along the Gulf, East and West coasts.

In the Permian, pipeline additions appear sufficient to meet production growth through 2015, as the Basin Pipeline expansion and Longhorn reversal are due to come online in 2013 and help relieve near-term bottlenecks. In the Eagle Ford, infrastructure looks to be more than adequate, with over 1 MMbbl/d of pipeline capacity scheduled to have come on over the summer of 2012.

At Cushing, Oklahoma, the bottleneck should be eliminated in 2013 with both the Seaway Phase 2 and Keystone XL Southern leg due online. However, greater market balance may return in 2014 with Flanagan South carrying crude into Cushing; and a bottleneck could resurface in 2015 with greater volumes due to come into Cushing via various projects (e.g., Keystone XL Northern line, Pony Express, Oneok Bakken Express).

What is the upshot of this extensive infrastructure buildout? For one, domestic refiners will have far greater access to an expanded menu of U.S. and Canadian crudes, at better prices, as imports of foreign oil are backed out by the homegrown grades. From 1980-2006, the trend in refiners’ crude feedstock was towards heavier and more sour crudes from overseas. However, this trend has recently reverted towards higher quality, light sweet crudes, and this shift is expected to gain further momentum.

Eagle Ford production will increase availability of domestic light crudes. Permian output will boost domestic light grades and potentially sour crudes. Cushing pipeline capacity will carry domestic light crudes and Canadian heavy crudes. And, via rail, Bakken production is expected to displace foreign grades at coastal locations, including Brent and Bonnie Light on the East Coast.

With U.S. law preventing the export of domestic crudes, imported oils will be squeezed. In the Gulf Coast, imports have fallen from 5.4 MMbbl/d in 2010 to 4.9 million daily in 2011 and, based on latest data, 4.6 MMbbl/d year-to-date in 2012. Of this amount, imports of light crude account for about 700,000 bbl/d, and by 2013 this category is expected to be eliminated entirely.

Looking at oil imports into the U.S. as a whole, running at about 8.5 MMbbl/d year-to-date based on latest data, the base-case forecast is for a drop to 6 million daily by year-end 2015—another stride forward in the drive to energy independence!

Moreover, with Louisiana Light Sweet (LLS) prices no longer bid in tandem with Brent to levels needed to attract foreign supplies, LLS is expected to slip from its current premium to a discount to Brent of $2 to $6 per barrel. With lower LLS prices, combined with a growing menu of domestic light crudes competing for market share with international medium and heavy sour crudes, markedly lower feedstock costs for refiners should “result in U.S. refineries becoming among the most competitive refineries on a global basis.”