American Oil and Gas Reporter - January 2017 - 45

palachian output stalled in 2016 with low commodity prices. Will
Marcellus/Utica production resume growing in 2017? Will increased productivities per well and per rig continue? What about
the other major shale gas plays? What do you envision in these
basins over the next 12-18 months?
BRAZIEL: It is quite likely that Marcellus/Utica production
will resume its upward trajectory, primarily because of pipeline
capacity out of the region being added over the next couple years.
Local prices for Appalachian gas have been considerably below
prices in most of the rest of North America for the past few years,
mostly because of pipeline capacity constraints. As these constraints are relieved, producers will enjoy higher net backs and
more attractive drilling economics, encouraging them to drill more
wells. The obvious result will be production growth.
In regard to increasing rig and well productivities, we certainly have seen continuous improvement since the start of the shale
revolution. Of course, trees don't grow to the sky, and at some point,
that productivity improvement will slow. But across core parts of
the most rapidly developing basins, there is little evidence of that
slowdown happening yet. And as new shale development regions
open, the industry will again learn how to "break the code" in those
regions, which will initiate new rounds of improving productivity.
We are starting to see some interesting developments in the Haynesville/Cotton Valley region in Northwest Louisiana and East Texas.
But it turns out that some of the most exciting gas developments
actually are in the crude-dominant basins, particularly the Permian and STACK/SCOOP plays in Oklahoma. These plays are throwing off a lot of associated gas, which for most producers has a negative break-even price. That is, the producer can make enough on
crude oil and condensate production to achieve an attractive rate
of return, even if the gas is sold at a price less than zero.
Those economics have the potential to wreak havoc with regional gas markets in Oklahoma and the Permian. Add to that big
new potential plays such as Apache's Alpine High development,
and those markets may become further unsettled.
As to the final part of the question, with all the new pipes being built out of the Marcellus/Utica and favorable production economics in the basins, Appalachia will be responsible for most net
gas production growth over the next five years. But assuming oil
prices continue their gradual recovery, expect to see increasing production out of the Permian, STACK/SCOOP, Bakken and Niobrara
regions. And watch out for the Haynesville/Cotton Valley. That
area was given up for dead, but definitely is coming back to life.
In 2015 and 2016, the Federal Energy Regulatory Commis-

Q: sion approved more than 70 pipeline projects totaling 28 Bcf/d

in capacity and consisting of 1,540 miles of pipeline and 1.7 million compression horsepower. Do you expect a continued high level of investment in pipeline projects in 2017? Where is the next
round of projects planned? How are take-away capacity additions
impacting the market and changing gas flows across the country?
BRAZIEL: We definitely anticipate a high level of pipeline
investment over the next two or three years, with most new capacity being built to move gas out of the Appalachian region, or
to deliver that gas to downstream markets.
Our analysis identifies about 18 Bcf/d of Appalachian takeaway capacity that will ease the constraints out of the region. We
organize those capacity additions into five corridors: six projects
totaling 3.3 Bcf/d to the New England and Mid-Atlantic states,
two projects with a combined 650 million cubic feet a day to Canada, four projects totaling 4.3 Bcf/d to the Midwest through Ohio,

seven projects totaling 4.5 Bcf/d to the Gulf Coast through Ohio,
and four projects totaling 5.2 Bcf/d heading to the Southeast along
the Atlantic Coast. There are other projects planned for the region, but they mostly move gas within Appalachia rather than
adding to take-away capacity out of the region.
While all of the take-away projects are "on the books," not every
single project may materialize as planned. Some may face cancellation, such as Kinder Morgan's Northeast Energy Direct project, while others will deal with long delays, such as those experienced by the Williams Constitution Pipeline. But even if a few
more of these projects are delayed for long periods or cancelled,
there still is more capacity being developed than likely will be
filled in the next five-seven years, which suggests the possibility of an overbuild, at least in the medium term.
Reversing the direction of Northeast natural gas flows is the
most significant transformation in the natural gas market I have
witnessed in my 40-year career. Instead of gas moving north and
east toward the region, gas increasingly is moving south and west
out of the region. As new pipeline capacity continues to open, even
more supply will move directly to the Gulf Coast to meet rapidly increasing LNG and Mexico export demand, or will displace
Gulf Coast supplies that traditionally have served other regions,
such as the Midwest. Either way, we are headed toward a market where the Northeast is a net supply region and the Gulf Coast
is a net demand region-a radical development that has the potential to upend everything we thought we knew about regional price
differentials and forward basis relationships.
Looking at the demand side of the ledger, do you expect any

Q: potential surprises in 2017? U.S. natural gas consumption

grew 5 Tcf annually between 2005 and 2015. Do you envision demand growing at a similar pace over the next decade? Which sectors are most important to sustained demand growth, and what
are the key challenges in attaining that growth? How big a role
will LNG and pipeline exports play over the next few years in expanding the market for U.S. natural gas?
BRAZIEL: The U.S. natural gas market always has the potential to surprise, and most of the time the culprit is weather. Late,
severe winter weather will always strike fear in the heart of the
gas market, and that is still true even at today's high production
levels. But other than that, we do not expect any big surprises in
2017. Slow growth in production is likely to continue during 2017,
along with a relatively balanced market.
Future demand growth will be lumpy, depending on weather and the dynamics for LNG exports. The sectors most important to demand growth clearly are exports and gas-fired power
generation. Both are poised to experience significant growth, which
will be good for natural gas demand and pricing.
LNG and pipeline exports to Mexico will play a huge role over
the next few years, by far the most significant aspect of the U.S.
natural gas market. Because these volumes are expected to flow
on a relatively consistent basis-meaning not so dependent on
weather-these new sources of demand promise to add important
pricing dynamics to the natural gas market.
For example, today, if natural gas prices increase during the
summer, then gas is displaced by coal for power generation, which
acts to mitigate further price increases. But this kind of market
response may not happen in export markets. The big question is
whether high gas prices will curtail LNG exports, or will those
exports (since the volumes are fully committed to overseas buyers) flow anyway, regardless of price? With 10 Bcf/d-12 Bcf/d
of export volumes soon to be part of these markets, that is a wild
card we all will be waiting to see played.
JANUARY 2017 45

American Oil and Gas Reporter - January 2017

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