A study commissioned by the state of Alaska paints a picture of rising costs in North American shale gas plays and higher gas prices in the years ahead that lend support to the case for a gas pipeline from the state's North Slope to serve Lower 48 markets.
The study, which was conducted by Black & Veatch and submitted to the Federal Energy Regulatory Commission late last month, projects that prices at the Henry Hub in 2010 dollars could climb to $8.00/MMBtu by 2020 and $9.00/MMBtu by 2030 in its high-price scenario. The low-price scenario projects $6.00/MMBtu at Henry by 2020 and $6.20/MMBtu by 2030.
"This independent study suggests that projected long-term prices for natural gas will support the construction of a natural gas pipeline to transport available natural gas reserves from Alaska's North Slope to North American markets," Patrick Pope, a lawyer working for Alaska, wrote in a letter to the Commission accompanying the report.
When the Alaska Pipeline Project open season plan was filed early this year by TransCanada Corp. and ExxonMobil Corp., the backers said the projected tariff for the North Slope-to-Alberta option outlined in the plan is $2.80-3.50/MMBtu for transport from a proposed gas treatment plant (GTP) to the Alberta Hub. The projected tariff for the North Slope-to-Valdez, AK, option is $2.45-3.15/MMBtu for transport from the GTP to Valdez.
Citing U.S. Department of Energy statistics, the companies said gas prices at the Alberta Hub for 2020-2030 are projected to be in the $6.25-7.65/MMBtu range, and prices at Henry Hub for the same period are projected to be $6.75-8.15/MMBtu (see Daily GPI, Feb. 1).
The Black & Veatch analysts -- in their report "Growing Shale Resources: Understanding Implications for North American Natural Gas Prices" -- acknowledge a number of uncertainties on both the supply and demand sides that make predictions difficult.
"The combination of these uncertainties results in potentially large variations in the costs, and indirectly in the volumes of natural gas that can be expected to be produced from North American shale gas," the report said.
For one, finding and development (F&D) costs vary widely among shale basins and among producers, they said. "Except for the Barnett [Shale], cumulative production from any given basin is too small to indicate the evolution of future costs. That said, the Barnett's history is indicative and it suggests that costs will rise as a given shale resource is explored."
Factors that have the potential to drive producer costs and/or gas prices higher, according to Black & Veatch, include:
"...[S]ignificant uncertainties remain as to the extent of future production of natural gas from shale plays," the study said.
"This study estimates that the total natural gas production from shale plays may range from 15.5 Bcf/d to 17.0 Bcf/d in 2015 and from 15.4 Bcf/d to 28.3 Bcf/d in 2020, depending on the realized outcomes of the listed uncertainties such as resource availability, F&D costs, natural gas demand and [liquefied natural gas] imports."
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