American Oil and Gas Reporter - December 2015 - 41

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SpecialReport: Natural Gas White Papers
strengthen the industry's position, prices at most major trading
hubs could remain in the $2.50/MMBtu range for much of the
rest of the decade, even in years in which winter weather is close
to normal. Prices could be much lower in years with mild winters.
A consistent $2.50/MMBtu price may be acceptable to some
producers. The industry's success in lowering development costs
and finding attractive reserves continues to dazzle. A number of
producers with reserves in shale play core areas are able already
to earn attractive margins at Henry Hub-equivalent prices of
$2.50/MMBtu-and not only in the Marcellus Shale, but also in
the Utica, Haynesville, Fayetteville, and Eagle Ford gas window.
Furthermore, if oil prices firm, production of associated gas (which
is relatively insensitive to natural gas prices) could become an
increasingly important supply source.
In two-three years' time, as productivity continues to improve
and additional low-cost targets are identified, the number of opportunities to earn attractive margins at these price levels is likely to increase. This is critical, because in the end, margins determine profitability. While prices in the $3.00-$3.50/MMBtu range
would be welcome, they are not necessarily essential for the industry's longer-term prosperity.
Adjusting To Future Demand

However, there is a risk that a "worst of both" scenario could
develop. Given the industry's demonstrated ability to raise production quickly, prices may seldom rise above $2.50/MMBtu, except for brief periods.
Unless the industry reigns in its tendency to ramp production
too quickly, the market may frequently be oversupplied during
most months of the year, pushing prices significantly lower and
shrinking or altogether eliminating margins. Moreover, when
weather conditions are milder than normal, prices could crater,
putting intense downward pressure on many producers' balance
sheets.
This obviously would be a serious blow for natural gas-heavy
producers, but it could negatively impact oil producers also, since
it would sharply reduce the value of associated gas in a world with
limited upside potential for oil prices. Producing companies could
struggle frequently. Like other capital-intensive industries, profit margins could be modest even in years in which demand was
reasonably strong. In years in which demand falters, cash flows
could dip perilously low.
The potential for this scenario should not be dismissed lightly. Instead, several factors suggest it is actually the most likely
one, absent forceful action by the industry to increase produc-

tion cautiously in step with demand growth.
First, the strongest demand increases will not occur until 201920. In the interim, given the huge backlog of DUC wells, the industry likely will be able to easily adjust to expected increases
in demand by quickly boosting production in the Marcellus and
a number of other plays without appreciable upward price pressure.
Unfortunately, any price increase would reduce coal displacement almost instantly, offsetting increases in core demand. In fact,
EIA predicts that as renewable energy continues to be deployed,
power sector consumption of natural gas could decline sharply
from 2015 levels.
Second, there is substantial reason to expect further breakthroughs over the next few years, with new low-cost supplies
added and productivity continuing to improve. In this regard, Deep
Utica gas could prove to be particularly significant. Some already
contend that it is a potential game-changer, with the potential to
become a second Marcellus.
The list of new development areas/formations also continues
to expand. An excellent example is the previously obscure Memphis formation in Northern Louisiana.
Refracturing, while still at an early stage of development, also
shows considerable promise. Nay-sayers, who claim it is not cost
effective in some instances, are missing the point. As more experience is gained and techniques improve, there almost certainly will be instances in which it is attractive, adding yet another
source of supply that can be brought on rapidly at low cost.
The Bakken, Permian Basin and Eagle Ford also are likely to
become increasingly important sources of low-cost natural gas,
with the Bakken evolving primarily into a gas basin, and the Permian (which yields high percentages of associated gas) becoming the primary focus of U.S. oil drilling.
The lesson of the past few years is clear: As the industry continues to gain experience with shale development, costs are likely to decline and new low-cost sources of supply will become
available. Even if demand increases appreciably between now and
2020, the availability of natural gas with a break-even price below $3/MMBtu is unlikely to be exhausted. Instead, over the next
5-10 years, even steeper increases in demand probably will be
required to keep prices at the level of the current forward curve
on a sustained basis.
Third, natural gas demand is becoming increasingly sensitive
to weather. In the past four years, the market has experienced a
1.5 Tcf swing in demand between cold (2013-14 "polar vortex")
and mild (2012-13) winters. Large swings also are possible in
spring, summer and fall, as was the case this fall.
DECEMBER 2015 41

American Oil and Gas Reporter - December 2015

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