Shell’s two drilling vessels and 35 support vessels earmarked for drilling in the Beaufort and Chukchi seas this year are either in Alaska or are on their way to the state, Shell Chief Financial Officer Simon Henry told financial analysts on April 27 during a question and answer session following the company’s presentation on its first quarter 2012 results.
“It’s a huge logistical exercise,” Henry said.
Henry declined to say what size of oil and gas resource the company hopes to find in the Alaska offshore, but he commented that the scale of the company’s Alaska operations provides some indication of Shell’s confidence in the scale of what it might discover.
“We have actually invested around $4 billion to date in Alaska, so you can be fairly sure that we’re looking for something big enough to justify that level of investment and the persistence that we’ve had to show … for the five to six years in which we’ve been preparing to drill,” he said.
Permitting and litigationIn additional to meeting the operational challenges of activating its drilling assets, Shell is addressing two other factors that are also critical to being able to start drilling: obtaining the necessary government permits and dealing with litigation that seeks to block the drilling, Henry said.
From a regulatory perspective, Shell either has obtained or expects to receive in good time all of the permits that it needs to start drilling as planned, Henry said.
However, the company has no control over the various lawsuits targeting its Arctic plans and faces significant uncertainty on the outcome of this litigation, he said. Following past experience of legal actions with unpredictable outcomes being launched shortly before the planned start of drilling, Shell this year has asked the court in Alaska to rule on the validity of the company’s drilling plans, thus enabling the court to deal in a timely manner with litigation that Shell anticipates.
“We are confident that we are ready, willing and able to drill, that we can do so in a very safe and responsible manner, and we look forward to a successful (drilling) campaign this year,” Henry said.
Appeals are currently in progress in the U.S. Court of Appeals for the 9th Circuit against the air quality permits for the Noble Discoverer, the drillship that Shell plans to use in the Chukchi Sea, and against the Bureau of Ocean Energy Management’s approval of Shell’s Chukchi Sea and Beaufort Sea exploration plans. An appeal against the lease sale in which Shell purchased its Chukchi Sea leases has also been filed in the same court.
Shale gasDuring the question and answer session Henry also commented on Shell’s strategy in North America for the development of shale gas, and the potential for Shell monetizing its substantial North American natural gas resources through the manufacture of liquefied natural gas or liquids fuels.
With North American natural gas prices currently hovering around just $2 per thousand cubic feet, Shell is moving its shale development efforts away from dry natural gas plays into what are referred to as liquids-rich shale plays, plays in which perhaps 50 percent of the production consists of natural gas liquids, rather than just the methane that constitutes dry natural gas, Henry said.
Natural gas liquids, with uses such as providing feedstock for the petrochemical industry, are more valuable than dry gas and currently command higher prices in North America.
Shell is operating just under 40 drilling rigs in North America and will probably shift more than half of these into liquids-rich opportunities, Henry said. The company is drilling in some acreage that it has picked up in the Texas Eagle Ford shale and has acreage is several other plays, including the Alberta section of the Bakken, he said.
Appraisal activityBut, although natural gas production from shale has achieved some level of maturity and commercial understanding, Shell views liquids-rich shale development as an exploration or appraisal activity, with Shell’s liquids production potentially coming on line in 2013, Henry said.
There are, for example, significant differences in the production characteristics between different liquids-rich plays and even within a single play, where wells as close as a kilometer apart can give quite different results, Henry said.
“This is an immature activity. It is not as mature as the gas and it’s very difficult for anybody to project specific outcomes based on what we know about reservoirs,” he said. “Almost all of our acreage is what we call emerging or frontier. None of it is mature to the extent of having a high level of production.”
Monetizing gasWith a substantial natural gas resource within its acreage, Shell is also seeking ways of making a profit from producing dry gas. The company is looking at a North American gas portfolio of more than 40 trillion cubic feet “which in a $2 world we’d like to monetize as something other than natural gas,” Henry said.
One possibility is the liquefaction of the gas for export to overseas markets where the price of liquefied natural gas, or LNG, is much higher than gas prices in North America. From this perspective, Shell is focusing on the potential export of LNG from Canada to Asian markets. LNG export from the United States looks possible but access to needed U.S. facilities appears expensive, Henry said.
In the United States Shell is considering the construction of a gas-to-liquids plant, producing materials such as diesel fuel, kerosene and naphtha from gas: The company is looking for a suitable site, either in Texas or Louisiana, with access to the existing support and gas infrastructures. The facility would replicate a major gas-to-liquids plant that Shell operates in Qatar. Shell wants to use its lessons learned in Qatar to reduce the facility costs while improving production efficiency, Henry said.
Although the gas-to-liquids option appears attractive, Shell is still some time away from deciding on whether to pursue this project — if the project does go ahead it will likely be the end of this decade before a gas-to-liquids plant goes into operation. Other possibilities for monetizing gas are the use of natural gas as a transportation fuel and its use as a chemical feedstock. The chemical feedstock option consists essentially of a play involving the use of ethane in Pennsylvania, Henry said.
De-riskingThe conversion of gas to liquids would provide a means of de-risking Shell’s gas portfolio in a world of fluctuating commodity prices by developing an exposure to liquids-related pricing for at least part of the portfolio. On the other hand, a reversion of North American natural gas prices to, say $10 or $11, would become an opportunity cost of liquids production — Shell’s strategy is evolving as the company gains a better understanding of the economics of the different options and the company has not yet determined what proportion of its gas that it might want to convert to liquids, Henry said.
Assuming that Shell can produce its own natural gas at relatively low cost, with no requirement to purchase gas from external sources, gas-to-liquids is a play on long-term oil prices, becoming increasingly viable at higher oil price levels.
“That’s how we think about it,” Henry said.
Chinese shale gasIn response to a question about the potential impact of shale gas development in China on LNG prices, Henry said that an answer to that question would not emerge for another 12 to 14 months.
Shell, working with PetroChina, completed 11 shale gas wells in China last year and hopes to complete about 25 wells this year, he said. The companies are trying to establish the potential for shale gas development in the country.
“We don’t know that yet,” Henry said. “That’s what we’re trying to help establish together with PetroChina, at least in the acreage where we’re working together. … By the beginning of next year we will have a much better feel for what’s the real volume potential and what is the cost of producing that volume.”
Once the economics of Chinese shale gas development become clearer the Chinese government will probably consider a long-term policy to encourage that development, Henry said.
The current Chinese government plan is to grow natural gas’s share in the country’s energy mix from 4 percent of demand in 2010 to 10 percent or more by 2020, Henry said, adding that this policy assumes the use of gas that is imported either by pipeline or as LNG. Chinese LNG prices are typically set on the coast, with inland gas prices then being linked back to those coastal prices, he said.