American Oil and Gas Reporter - December 2015 - 39

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SpecialReport: Natural Gas White Papers
FIGURE 3
Potential Growth in U.S. Natural Gas Demand (2016-20)
Replacing Lost
Canadian Imports

25.0

Mexican Exports

20.0
Lease and Plant Fuel

Bcf/d

15.0
Industrial

10.0

Natural Gas Vehicles

Power Sector

5.0

Liquefied Natural Gas

0.0
2016

2017

2018

2019

2020

Source: EBW Analytics

5-10 percent by late winter/early spring.
It should be noted that contrary to market expectations, mild
winter weather is not a lock. Instead, depending on developments
in the Pacific Ocean, there is still a substantial possibility of much
colder-than-normal weather by February (Figures 2A & 2B).
If this occurs, it could add as much as 125 Bcf of demand, mitigating the impact of mild early winter temperatures. End-of-winter storage could fall below 1.800 Tcf. At least for a few weeks,
cash market prices might climb above $2.50, temporarily pushing March-October 2016 contracts to an average of $2.65$2.85/MMBtu.
Increasing Core Demand

The bigger and better news is that beginning in 2017, core U.S.
demand for natural gas is likely to increase. The extent of this
growth will depend heavily on the completion of six LNG export projects-Sabine Pass trains 1-4, Freeport trains 1-3, Cove
Point, Cameron trains 1-2, Sabine Pass trains 5-6, and Corpus
Christi trains 1-3-and these terminals' ability to compete in a global LNG market that is expected to be significantly oversupplied
for several years.
With exports to Mexico and industrial demand continuing to
rise, the success of U.S. LNG export projects would increase core

daily U.S. gas demand significantly over the next four or five years
(Figure 3).
If U.S. producers show restraint in increasing production, the
excess supply that has plagued the U.S. market since 2012 could
finally begin to be sopped up. That said, it is critical for producers to be realistic regarding how strongly natural gas prices may
rebound in 2016 or subsequent years.
Unless producers immediately institute steep drilling cuts, Henry Hub prices are likely to average less than $2.50 between January and October, even if cold weather arrives in February. This
is partly because of the huge backlog of DUC wells in the Marcellus Shale.
Near term, some experts believe that if prices in the Marcellus were to increase to even $2.25/MMBtu (versus a 2015 Dominion North average of less than $1.40/MMBtu), the expanding take-away capacity in the Northeast would fill quickly, potentially increasing production by 8 Bcf/d.
At $2.50/MMBtu, production in the Haynesville and Fayetteville also would likely respond in short order, preventing
NYMEX futures prices from rising above $2.50/MMBtu for an
extended period. If mild weather continues through spring, prices
could be much weaker.
Just as importantly, however, absent taking specific steps to
DECEMBER 2015 39

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