China could follow the U.S. example and develop its shale gas resources to become self-sufficient in natural gas. By 2035, Russia and the Middle East could see declines in natural gas exports of 6.3 trillion cubic feet (Tcf ) (37%) and 3.4 Tcf (35%), respectively.
At the same time, continued increases in oil production from the “big three” U.S. oil shale plays – the Bakken, Permian, and Eagle Ford – would result in reactions in the oil markets from Saudi Arabia and the Organization for the Petroleum Exporting Countries (OPEC).
A panel of experts at the DUG Permian conference in Fort Worth on April 4 tackled the prospects of “Emerging Resource Plays and the Global Infrastructure Challenges.” Panelists were: Dr. Carmine Difiglio, deputy assistant director for policy analysis, Office of Policy and International Affairs, U.S. Department of Energy; Herve Wilczynski, partner, A.T. Kearney Inc.; Bill Brown, senior analyst, Office of Oil, Gas, and Biofuels Analysis, U.S. Energy Information Administration; and Mike Kelly, vice president and senior E&P analyst, Global Hunter Securities Inc.
“Shale gas, so far, has been a North American story,” Wilcynski told the more than 2,500 participants at the conference. “However, the majority of resources are outside North America. The U.S. might find itself as a pioneer in this field, but the big bang might happen outside the country.”
Shale plays in the U.S., China, and Argentina can disrupt the global balance, which could lead to possible changes in global pricing regimes, he said. China has already committed to 4.7 Tcf/y of pipeline imports and is building 2.2 Tcf/y of LNG import capacity to meet half of its 2020 demand.
“China potentially could do like the U.S. has done and become self-sufficient in natural gas. The Chinese government wants this to happen. There is the political will to increase domestic production by 2.2 Tcf to 3.5 Tcf by 2020. The pacing factor is that the midstream infrastructure is very constrained. The pipeline network in China represents only 16% of the capacity in the U.S.,” he continued.
Argentina is rich in shale gas with the second largest reserves behind China and ahead of the U.S. The situation in Argentina, though, is that the business environment is not conducive to rapid development of shale resources, he added.
There are factors that could impede the growth of shale gas, including subsurface geology, regulations, business environment, above-ground constraints, and reactions from competing sources of natural gas like Qatar and Russia, Wilcynski explained.
Difiglio agreed with the shift in natural gas exports by 2035 with worldwide shale development. Not only will Russia and the Middle East see declines in gas exports with unrestrained shale development, but U.S. exports will decrease to zero, a drop of 5 Tcf since U.S. gas ultimately will be less competitive with other major gas producers.
One of the unique aspects of the shale gas plays worldwide is that the resources are located near demand centers, he emphasized. “Natural gas exports from North Africa and the Caspian Region will also be reduced as gas production shifts to demand centers.”
By 2035 with unrestrained shale development, European shale production would increase 9 Tcf (57%) over the baseline case, Australia up more than 4 Tcf (150%), and China nearly 3 Tcf (81%), Difiglio continued.
Kelly said natural gas production growth in the U.S. is still on the horizon. “There is a 30-year drilling inventory capable of generating 25% or higher internal rates of return at $4.50/Mcf, which should push supply growth higher over the next five years to more than 4.3 Bcf/d. Such growth will keep intermediate gas prices range-bound between $3/Mcf to $4/Mcf.
“We’re not too optimistic on natural gas. We see limited upside there,” he added.
Shale Oil, NGLs Get More Attention
The oil side of the equation is just as impactful as the gas side. “NGLs will show more modest growth with capacity additions in terms of fractionation capacity, gas processing and pipelines,” Kelly explained. “We see long-term NGL prices at 51% of the WTI price versus the 41% we saw in 1Q 2013.”
North American growth in crude oil production could “precipitate a seismic shift in the geopolitical landscape by undermining OPEC as the hegemonic global provider of swing capacity. North American supply growth is for real,” he emphasized, “And the U.S. is leading the charge.
“By 2014-15, this supply is disruptive to the world supply balance by 2.5 MMb/d on the crude side. We see WTI falling to $80 by 2014,” he continued. “There is no shortage of oil resource plays in the U.S.”
Crude oil production in the U.S. is predicted to reach 9.4 MMb/d in 2017, 90% growth from 2008 to 2017. An average price of $72 is needed to generate a 25% IRR. Of the U.S. oil plays, the Eagle Ford, Permian horizontal, Niobrara, Uinta liquids, and Woodbine can be produced for less than the average, he said.
In just five plays – Bakken, Eagle Ford, Permian, Utica, and Niobrara – there is an estimated drilling inventory of 111,760 well locations, which would take 41 years to drill, he added.
The oil rig count is up threefold since 2008, which is being driven primarily by the Bakken and Eagle Ford. Kelly said his company expected a 50% increase in oil production on essentially a flat rig count through 2017. The Bakken, Permian, and Eagle Ford will give most of the growth during the next five years.
“There will be pressure on prices. There will be more production cuts from the Saudis. We will see how it works out,” he emphasized.
U.S. tight oil production leads the annual growth in domestic production of 2.6 MMb/d between 2008 and 2019, Brown said. Production growth is expected to peak in 2020 at 2.8 MMb/d, declining to 2 MMb/d annually by 2040, according to the early release of the Annual Energy Outlook 2013.
Projected U.S. net liquid fuel imports have declined due to increased production and decreased consumption, he continued. That represents a decline of 63% in the projections between the 2005 outlook and the 2013 outlook.
Brown listed several uncertainties that could slow global growth of shale gas and tight oil, including resource quantities and distribution; surface versus mineral rights; taxes, royalties and price regulations; risk appetite of industry participants; infrastructure and technology; and environmental constraints.
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