American Oil and Gas Reporter - April 2018 - 75

EMPOWERING THE FUTURE
10-12 percent of gas feedstock to process natural gas into LNG,
we forecast that U.S. supply to LNG export facilities will be 7
Bcf/d by December 2019, accounting for 8 percent of the total
U.S. dry production.
At the same time, pipeline exports to Mexico are expected to
grow from 4.2 Bcf/d in 2017 to 5 Bcf/d in 2019. That number
could wind up closer to 5.5 Bcf/d, depending how quickly
pipelines and gas-fired power generation facilities are constructed
to remove constraints on the Mexican side of the border.
At any rate, by the end of 2019, EIA forecasts a total of 12
Bcf/d between LNG and Mexican pipeline exports. That equates
to nearly 4.4 Tcf a year in demand for natural gas produced in
the United States.
Fortunately, there are a lot of options for supplying LNG
exports, and most of that supply already is contracted by the liquefaction facilities. The molecules that will be converted to LNG
primarily will come from production basins in Appalachia, the
Permian, and the Gulf Coast. Cheniere even signed an agreement
last year for supply from the Montney Shale in Canada.
To meet the demand, EIA forecasts dry natural gas
production increasing to an average of 82.7 Bcf/d in 2019, or
3 percent higher than in February 2018. Strong production
growth is forecast in the Marcellus/Utica, with 4.5 Bcf/d of
production flowing south to the Gulf Coast, primarily to
supply LNG export facilities as more (north-to-south) pipeline
reversals are completed. There certainly will be changes in
basis differentials, but more needs to be done to accommodate
flows from supply centers in the north to accommodate LNG
demand centers in the south.
Strong growth in associated gas production also is expected
in the Permian Basin, with Permian producers targeting LNG
exports and exports to Mexico to market their production.
However, the existing networks of interstate and intrastate
pipelines in Texas will require major expansions, in addition to
expansions already in progress. Four new pipelines with more
than 8 Bcf/d of capacity have been proposed to move Permian
gas from the Waha Hub in Pecos County to Gulf Coast markets,
primarily to supply liquefaction terminals:
* Kinder Morgan's Gulf Coast Express (2 Bcf/d with an inservice date of October 2019);
* Tellurian's Permian Global Access Pipeline (2 Bcf/d with
an announced in-service date of December 2018);
* NAmerico Energy Holdings' Pecos Trail Pipeline (1.85
Bcf/d with an announced in-service date of July 2019); and
* Boardwalk's Permian 2 Katy (2 Bcf/d with an announced
in-service date of December 2019).
An interesting point here is that the Henry Hub traditionally
has been a financial center for gas trading contracts with
minimal physical exchange of gas. However, more recently,
because of pipeline reversals that allow Marcellus/Utica gas to
flow south to Gulf Coast demand centers, physical gas flows
through Henry Hub have been increasing and this is expected
to continue with higher LNG export demand.

Finally, what are EIA's projections regarding adQ: ditional
U.S. LNG export capacity beyond 2019?

How does EIA summarize the opportunity for U.S. LNG
in the 2020-30 timeframe? How much new U.S. export
capacity could be added in that decade? How much
new demand for domestic natural gas could those yetto-be-built facilities represent?
ZARETSKAYA: There is no shortage of approved LNG
export projects as well as projects undergoing review by the
U.S. Department of Energy and Federal Energy Regulatory
Commission. In fact, export capacity from the proposed U.S.
facilities far exceeds anticipated global demand through 2030.
EIA projects about 5 Bcf/d of additional LNG exports by
2030, representing the so-called second wave of U.S. LNG
facility construction. Adding another 5 Bcf/d to the 9.6 Bcf/d of
first-wave LNG projects would grow U.S. LNG export capacity
to 14.6 Bcf/d (5.3 Tcf/year) by 2030. That would be equivalent
to nearly one-fifth of total U.S. gas demand in 2017.
This year, it is likely that a final investment decision will be
made for the third train at Cheniere Energy's Corpus Christi
facility. It is more than 60 percent contracted, and Cheniere is
actively moving forward with its development. Beyond that,
there are four new (Magnolia, Golden Pass, Lake Charles and
Delfin) and one other expansion (Sabine Pass train six) projects
that have been fully approved by both FERC and DOE for
exports to non-Free Trade Agreement destination countries.
Combined, these projects have 8.6 Bcf/d in capacity.
But even though the projects have been approved, that does
not necessarily mean they will move forward anytime soon. In
fact, both Lake Charles and Golden Pass look increasingly less
likely by 2025, and may be delayed or cancelled as project
sponsors have re-prioritized these projects. Market economics
will decide which projects ultimately get built.
LNG buyers are looking selectively for flexibility in contracts,
including shorter contract terms, flexible volumes without destination restrictions, and a price indexation that reflects the fundamentals of the regional LNG markets. To that end, several
countries in Asia, including Japan, China and Singapore, are
actively developing natural gas trading hubs with the goal of
setting up liquid and transparent regional gas pricing benchmarks.
Beyond 2020 and the first wave of U.S. LNG projects, there are
a lot of sellers pursuing a limited number of highly selective
buyers, and only the most cost-competitive projects will move
forward. There is very strong competition between proposed
projects, and some projects-particularly in Qatar and Russia-
have the advantage of the lowest global upstream costs.
No seller is able to obtain project financing without a longterm contract. Therefore, the focus is shifting toward equity financing, but only a few large integrated oil and gas companies
will be able to carry the financing of capital-intensive LNG
projects on their balance sheets.
r
APRIL 2018 75



American Oil and Gas Reporter - April 2018

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