Vol. 36, No. 34
MONDAY, APRIL 17, 2017
Shale-Related Projects Set Record Investment
Level in Southwest Pennsylvania Last Year
The Pittsburgh Regional Alliance
(PRA) said this month that it tracked the
largest-ever amount of capital investment in
the 10-county region surrounding the city in
southwestern Pennsylvania last year, attributing most of the $10.2 billion recorded to
shale gas-related growth.
PRA, the economic development marketing affiliate of the Allegheny Conference on Community Development, tracks
capital investment and economic development deals across the region in an annual
scorecard that serves as an economic indicator and helps guide its own strategies.
Projects announced by Royal Dutch Shell
plc, Tenaska and Energy Transfer Partners LP (ETP) in 2016 helped the region
to a “banner year” in which the investments recorded by PRA since 2007 hit their
highest levels.
Shell’s decision in June to move forward with a $6 billion investment to build
a world-scale ethane cracker in Beaver
County easily topped the list. ETP’s
announcement that it would spend $1.5
billion on a 110-mile natural gas gathering system that would originate in Butler
County and a cryogenic processing facility
in Washington County also pushed up economic commitments in the area. Tenaska
also broke ground last year on a $785 million gas-fired power plant in Westmoreland
County that will generate 925 MW of electricity when it enters service late next year.
“The table is set for the region’s future
by leveraging the combined impact of manufacturing and energy,” said PRA President
David Ruppersberger. (continued on page 22)
NatGas Price Index Reporting Sees Uptick
The number and volume of natural gas
transactions — according to FERC Form
552 submissions from up to 680 respondents — were in decline during 2008 to
2014 and flattened in 2015. However, that
trend has improved somewhat in 2016,
executives with two price reporting agencies (PRA) said in Houston on Tuesday.
Last year was “pretty good” for price
index reporting, NGI Executive Publisher
Dexter Steis said during a forum at the
New Risk in Energy conference. On a deals
basis, reporting to NGI in the day-ahead
market is up by about 3.3%, and the bidweek market is up by almost 1%. Volume
was still a little bit flat, he said citing NGI
internal data for 2016 because the Commission has yet to release its form 552 report
for calendar year 2016.
More overall transacted volumes and
a greater number of transactions have been
part of a tide that has lifted all boats, Steis
said. “So we’ve seen more reportable transactions and then more reported transactions
© COPYRIGHT INTELLIGENCE PRESS 2017 | in the PRAs.”
Since 2008, NGI’s price indexes have
been made more robust by the inclusion
of transaction data from Intercontinental
Exchange (ICE) through a protocol that
maximizes the amount of relevant data
available for use in the NGI indexes while
matching and removing those deal reports
from ICE that are duplicative to what NGI
receives from the companies who report to
NGI directly.
Last November, Platts struck an agreement with ICE and expects to be including
ICE data in its indexes in the coming
months.
Platts’ Mark Callahan, editorial director
for power and generating fuels pricing, said
that while 2012-2014 was “not a great time”
for PRAs, 2015 saw some stabilization. Last
year was a good year with volumes up 5%.
So far this year, Callahan said volumes
reported have been fairly flat compared
with 2016. This has been true of the daily
indexes. For the (continued on page 22)
NATGASINTEL.COM | News This Week
Exco to Sell South Texas Properties to KKR
Affiliate for $300 Million........................................... 3
U.S. Onshore Permitting Still Strong for ‘Usual
Suspects,’ with California, Colorado Coming On.... 4
Former CFTC Head Says Regulatory
Streamlining Ahead: ‘Too Many Regulators’........... 5
NuStar Entering Permian Basin in Nearly $
1.5B Deal................................................................ 6
DCP Joins Kinder in Permian-Focused Gulf
Coast Express Project............................................ 7
FERC Has Environmental Questions on Atlantic
Coast Pipeline......................................................... 7
New York State Deals Another Setback to NatGas
Infrastructure; Denies Northern Access Permits..... 8
PennEast Receives FEIS, Expects Certificate
Order This Summer................................................ 9
Hundreds Comment on Atlantic Coast Pipeline
EIS; Forest Service OKs Appalachian Trail
Crossing................................................................ 10
Enterprise Products Putting 571-Mile NGL
Straw in Permian Basin......................................... 11
Louisiana Lands Another Billion-Dollar Chinese
Petrochemical Facility........................................... 11
EIA Sees Henry Hub Averaging $3.10 This Year,
$3.45 in 2018........................................................ 12
Ultra Raises Nearly $3B in Financing, Emerges
From Chapter 11................................................... 12
Goodrich, Linn Get New Stock Listings;
Bonanza Creek to Exit Chapter 11 Soon.............. 13
Stakeholder Midstream Buys Permian Gas
Gathering System................................................. 14
Raymond James Turns
Bearish on U.S. NatGas
for 2018 and Beyond
Analysts with Raymond James &
Associates Inc. have turned negative on
U.S. natural gas prices beyond 2017, as
faster-than-anticipated growth in supply,
along with surprising gains in renewable
power generation capacity, are expected to
displace more demand than forecast only
four months ago.
In early January analysts had said U.S.
gas prices were poised for the best prices in
2017 since 2014. While they are maintaining
a 2017 forecast of $3.25/Bcf, the 2018 estimate has been slashed to $2.75 from $3.50
and the long-term forecast reduced to $2.75
from $3.00.
(continued on page 2)
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
Raymond James Turns Bearish
(continued from page 1)
“All told, we now expect the 2018 U.S.
gas market to be 1.1 Bcf/d looser (more
bearish) than our previous outlook,” said
analysts led by J. Marshall Adkins, John
Freeman and Pavel Molchanov.
Wells Fargo Securities LLC last month
raised its 2017 price outlook to $3.38/
MMBtu but reduced its outlook for 2018
and beyond to $3.25. BofA Merrill Lynch
Global Research last month kept unchanged
its 2017 average from April through
December at $3.50/MMBtu, while Barclays
reduced its 2017 forecast to $3.02 from
$3.38. The Energy Information Administration (EIA) in March reduced the 2017 spot
price to $3.03/MMBtu, 12% lower than its
February outlook.
The Raymond James team in a note
Monday explained how burgeoning
domestic gas supply growth beginning in
the back half of 2017 and into 2018, coupled
with the outlook for demand drivers and the
rise of renewables, will impact Henry Hub
price forecasts — and not in a good way.
“We anticipate that respectable demand
growth will simply be overwhelmed by a
massive U.S. natural gas supply surge of 5
Bcf/d-plus” on increased pipeline takeaway
from the Marcellus/Utica, growth in oildriven associated gas supply mostly from
the Permian and a modest recovery from the
resurgent Haynesville Shale, analysts said.
Associated gas from onshore oil wells
also is set to accelerate and pressure gas
pricing. In addition, renewables increasingly are cost competitive with gas.
Mexican exports are lower and Canadian imports are higher this year, but the
surge in renewable power “is likely to crush
gas demand growth,” Adkins said. The three
variables make the 2018 gas model almost 2
Bcf/d more bearish than originally forecast.
By the second half of 2017, U.S. gas
supply should begin to accelerate. Compared with the Raymond James forecast
early this year, U.S. dry gas production
growth now is expected to be about 900
MMcf/d higher in 2017 year/year (y/y),
based on revisions by the EIA.
U.S. onshore gas production, which
had been on a downward trend for more
than a year, returned to the upside in January and was set to continuing moving
higher into April, according to EIA.
© COPYRIGHT INTELLIGENCE PRESS 2017 | NGI
INTELLIGENCE
Page 2
Output from Raymond James’ modeled
dry gas plays, the Marcellus, Haynesville,
Fayetteville and Barnett shales, along with
the wet gas Utica and Midcontinent, should
remain muted for the first half of the year,
with slight y/y declines from associated gas
in the Eagle Ford and Bakken shales, Niobrara formation and Permian Basin — until
the second half of this year.
Beyond June, look for gas growth to
pick up the pace, first in dry gas, followed
by associated gas from oil wells.
The mighty Marcellus will carry the
day in growth, up overall y/y at 1 Bcf/d
“in anticipation of a plethora of midstream
capacity planned for 2018,” followed by the
Haynesville Shale rising by 0.2 Bcf/d.
“Taken together, dry gas production
should be up 2 Bcf/d y/y by the end of
2017,” Raymond James analysts said.
Associated gas growth should be
roughly flat y/y because of minor declines
in 1Q2017, but expect growth on that end
into the second half of this year too, rising
1 Bcf/d y/y.
Raymond James anticipates declines in
other gas plays mostly to subside by year’s
end, with growth relatively flat entering
2018.
Next year expect to see a massive 5
Bcf/d-plus in growth, led by the Marcellus,
Utica, Haynesville and associated gas.
“Looking to 2018, we anticipate a pronounced recovery
(continued on page 3)
NATURAL GAS
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Monday, April 17, 2017
in dry gas production, particularly as a
result of increased volumes from the Marcellus/Utica, a continued resurgence in the
Haynesville, and growing associated gas
production from increased activity in major
oil plays (e.g., Permian, Eagle Ford, Niobrara),” Adkins said.
Planned pipeline capacity expansions underway should lead to meaningful
growth from the Marcellus and Utica in
NATURAL GAS
NGI
INTELLIGENCE
2018. In addition, threshold breakevens in
the Marcellus and some areas of the Utica
have fallen below $2.00/MMBtu, which has
incentivized increased drilling and completion activity, as takeaway is accessible.
In the Marcellus alone, Raymond
James model indicates 2.2 Bcf/d of y/y
(November-November) growth in 2018,
contributing 42% of overall dry gas growth
for the year. About 6.5 Bcf/d of planned
Page 3
unrisked 2018 gas pipeline takeaway
capacity also is expected to come online in
Appalachia, further accelerating growth.
In addition, analysts advised to not
underestimate the Haynesville’s gas supply
contribution. A resurgence in the North
Louisiana/East Texas play should drive
“respectable” y/y dry gas volumes in 2018.
“The rig count bottomed at 12 rigs in
April 2016, but in 2018, we anticipate the
rig count to average 42 rigs, up 3.5x times
from the trough,” Adkins said. Enhanced
completions, mostly because of increased
proppant loads, have led to a revival in
single well economics.
“In 2018, we anticipate dry gas volumes in the Haynesville to increase 0.5
Bcf/d y/y to 6.3 Bcf/d,” analysts said.
Meanwhile, associated gas growth
from oily basins should be the final straw,
with more than 1.5 Bcf/d of growth in 2018
y/y, with nearly all of it (1 Bcf/d) from the
Permian.
As the Eagle Ford also begins to
awaken, dry gas output should be up 0.5
Bcf/d y/y in 2018, making up a “sizable”
share of associated growth. 
Exco to Sell South Texas Properties to KKR Affiliate for $300 Million
Exco Resources Inc. announced
Monday that it plans to sell its oil and
natural gas properties in three counties
in South Texas to an affiliate of Kohlberg
Kravis Roberts & Co. LP (KKR) for $300
million.
In a statement Monday, the Dallasbased exploration and production (E&P)
company said it had executed a definitive
agreement with a subsidiary of Venado
© COPYRIGHT INTELLIGENCE PRESS 2017 | Oil and Gas LLC for Exco’s interest in
oil and gas properties and surface acreage
in Dimmit, Frio and Zavala counties. The
properties produced approximately 4,100
boe/d in December 2016, with more than
90% oil.
Exco said it expects the transaction,
which is subject to customary closing conditions and adjustments, to close in June.
“Exco’s planned divestiture of the
NATGASINTEL.COM | South Texas oil and natural gas properties
represents an important step in its portfolio
optimization initiative and will improve its
financial flexibility,” the E&P said, adding
that it “intends to use the proceeds [from the
sale] to fund drilling and development of its
core Haynesville and Bossier shale assets
in North Louisiana and East Texas, and for
other general corporate purposes.”
According to Exco, the borrowing base
under its revolving credit facility will be
$100 million after the transaction closes.
The company’s next borrowing base redetermination is scheduled for November.
Last May, Exco sold some of its noncore undeveloped acreage, as well as interests in four producing wells, for $12 million.
Two months earlier, the E&P slashed its capital expenditures budget for 2016 by more
than two-thirds, while also announcing plans
to spud and complete a handful of wells in
the Haynesville and Bossier shale. Exco
shut down its drilling program in the Eagle
(continued on page 4)
Ford Shale and the
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
Appalachian Basin in November 2015.
According to Exco’s 10-K filing with
the U.S. Securities and Exchange Commission (SEC) on March 16, the company said
it holds 82,100 net acres in East Texas and
North Louisiana prospective to the Haynesville and Bossier shales. It also told the SEC
that it has 49,300 net acres in South Texas
prospective to the Eagle Ford.
In the Appalachian Basin, Exco
reported that it holds 127,000 net acres prospective for the Marcellus Shale and 40,000
net acres in the Utica Shale, predominantly
in the play’s dry gas window.
KKR and Austin-based Venado formed
a partnership, funded by a growth fund from
the former, to consolidate proven assets in
the Eagle Ford Shale in South Texas last
September.
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Page 4
The New York-based equity firm has a
long history of energy investments dating
back to 2009, when it invested $350 million
in privately-held East Resources Inc. (ERI).
The next year, a unit of Royal Dutch Shell
plc purchased nearly all of ERI’s assets,
including KKR’s interest, for $4.7 billion.
KKR formed separate joint ventures
(JV) with RPM Energy LLC, Hilcorp
Energy Co. and El Paso Midstream Group
Inc. in 2010. The firm acquired assets from
ConocoPhillips, Carrizo Oil & Gas Inc. and
Samson Investment Co. and formed a midstream services agreement with Quicksilver
Resources Inc. in separate deals in 2011.
KKR also acquired assets from Chesapeake
Energy Corp. and WPX Energy, and forged
a JV with Comstock Resources Inc., in 2012.
In 2014, KKR partnered with
Riverstone Holdings, another equity giant,
to form Trinity River Energy LLC, with
E&P focused on the Barnett Shale. The next
year, it partnered with Fleur de Lis Energy
LLC to purchase assets from Anadarko
Petroleum Corp., and formed a JV in
Mexico with Monterra Energy.
Veresen Midstream, a 50/50 partnership of Calgary-based Veresen Inc. and
KKR, said it would fund 55-60% of the construction costs of the proposed $715 million
Tower rich natural gas processing plant in
the Montney Shale in December 2015.
Last March, SM Energy Co. closed on
an $800 million gross sale of its non-operated assets in the Eagle Ford, including an
ownership interest in associated midstream
infrastructure, to Venado EF LP, a unit of
Venado. 
NATURAL GAS
U.S. Onshore Permitting Still Strong for ‘Usual
Suspects,’ with California, Colorado Coming On
U.S. land oil and natural gas permitting the first week of April once again got
off to a hot start in Texas, Oklahoma, Wyoming and Louisiana, and while it’s been a
bit sluggish elsewhere, commodity price
stability should result in robust drilling
activity as the year proceeds, Evercore ISI
said Tuesday.
Through April 7, U.S. land permitting stood at 672, and the four-week rolling
average of 725 is “within striking distance”
of the last 12 months’ high of 849 from
mid-March, said Evercore’s James C. West,
senior managing director.
“The usual suspects (Texas, Oklahoma,
Wyoming, and Louisiana) again were off to
© COPYRIGHT INTELLIGENCE PRESS 2017 | extremely hot starts, with Texas poised to
break the 1,000 permit for the third month
in a row,” he said.
West and his team’s April report is a
compilation of monthly permitting numbers
for the United States, onshore and offshore.
All major states and the Bureau of Ocean
Energy Management require permits to be
filed and approved before an exploration
and production (E&P) company may begin
drilling a new well or bypass/sidetrack
an existing well. Most onshore permits
are issued several months before drilling
begins, while offshore permits often are
secured much further in advance.
U.S. land permits outstanding totaled
NATGASINTEL.COM | 3,945 in March, 23% higher month/month
(m/m) than in February and 116% higher
year/year (y/y), and last month saw the
highest permit total since October 2015. It
was the first March-to-March increase since
2013, West said.
Relatively strong permit numbers m/m
also were up in California by 41%, in North
Dakota at 110%, and Oklahoma, which saw
a 37% increase. Declines from February to
March were in Ohio, down 17%, and Utah,
minus 67%).
Texas is Trend-Setter
Fueled by a two-times increase m/m
in the Permian Basin, Texas permitting
jumped 8% in March and rose a whopping 116% y/y. The continuing Texas surge
“served as a strong tailwind for improvement elsewhere,” West said. “With nearly
half of the working U.S. oil rigs, Texas continues to be the single-most important state
in terms of evaluating the magnitude and
direction of U.S. permitting trends...”
States in the “peripheral” unconventional basins — the Niobrara formation,
Woodford and Bakken shales — should
“continue their positive trajectory as
oil prices improve and ‘fringe’ acreage
becomes economical.”
West noted that April traditionally has
been a weak one permit-wise, down m/m
every year since
(continued on page 5)
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Monday, April 17, 2017
2012, with the exception of 2016 when permits rose 15% from March. However, as
commodity prices have stabilized and E&Ps
have provided better visibility for capital
expenditures, permitting momentum should
continue, allowing operators to lock in
incremental production at better economics.
California, Colorado ‘in-the-money’
“A broader base of ‘in-the-money’
drilling prospects, particularly beyond
‘sweet spot’ acreage, could serve to boost
permitting levels outside of the major petrostates,” he said.
By far, California has exhibited the
“greatest sequential and y/y improvement”
in states beyond the Permian. West called
California’s newfound growth “an ode to
revamped drilling programs” by companies
based in the Golden State, including California Resources Corp., Chevron Corp. and
San Joaquin Basin operators.
California and Colorado both look
promising for robust rig growth from here,
West said.
“Absolute permit totals do not tell
the complete story for projected activity
growth, as basin-specific momentum is a
better indicator of the rig count directionality,” he said.
Texas still garners more than half of
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Page 5
the oil rig count, but permitting in the state
exhibited only slightly higher quarter/
quarter and y/y improvement in 1Q2017
compared to the rest of the United States.
“This is indicative not only of the resilience of Texas basins through the downturn
(specifically in the Delaware and Midland
cores), but also that activity growth will
likely moderate in this basin before auxiliary basins hit their stride,” West said.
Meanwhile, Colorado permitting grew
49% from 4Q2016 to 1Q2017, and 1Q2017
was 134% above 1Q2016.
“While more permits are generally observed per incremental rig added
on an absolute basis, Colorado’s recent
momentum should yield steep activity
increases as crude grinds higher and
extended reach drilling improves in the
Wattenberg.”
The Energy Information Administration’s Drilling Productivity Report in
March reported new-well production/rig in
the Denver-Julesburg Basin/Niobrara formation “is among the tops in U.S. land, just
slightly below the 1,442 b/d observed in the
Eagle Ford Shale (and much higher than
the 662 b/d in the Permian),” West said. “In
addition, California has shown unmatched
(and unprecedented) permit growth.”
Meanwhile, in the Gulf of Mexico, 17
new permits were issued in March, up 113%
from February’s eight and 13% higher y/y.
Shallow water permitting held flat at
four m/m, with three sidetracks and one
bypass approved. Seven new midwater
permits were filed versus two in February,
while deepwater permitting improved to
five, with two new wells and three sidetracks approved. Ultra-deepwater permitting notched a single new well permit in
March, flat m/m.
The sharpest decline from the 2014
peak (ex-ultra-deepwater) is in shallow
water permitting, down 82% in 2017 from
year-to-date 2014.
“We believe that offshore drilling
(and jackup utilization) will continue to
languish as long as shallow water permits
remain at historically low levels,” West
said. “Offshore planning from last month
points to modest offshore improvement in
the 2Q2017-3Q2017 timeframe, with four
drilling plans filed for possible tieback
work...
“Overall, we remain cautious in allocating optimism to the offshore space, but
permitting trends have certainly shown
upward momentum over the first quarter of
2017.” 
NATURAL GAS
Former CFTC Head Says Regulatory
Streamlining Ahead: ‘Too Many Regulators’
Commodities and securities regulation under the Trump administration will be
more open to market participants with less
“gotcha stuff” to trip them up, speakers at a
Houston conference heard last week.
Sharon Brown-Hruska, a former
chairman of the Commodity Futures
Trading Commission (CFTC) and currently
a director at NERA Economic Consulting,
was also a member of Trump’s landing
team for the CFTC.
In the months before Trump’s inauguration Hruska was “running around” Washington emphasizing the key priorities of the
incoming administration, she told attendees
at the New Risk in Energy conference last
week.
“First we wanted to embrace legislation and policies that promoted economic
growth and capital formation and increased
competition,” she said of her mandate. “You
© COPYRIGHT INTELLIGENCE PRESS 2017 | heard a lot about putting America first...It’s
a natural message for us within the independent financial agencies to put a focus on
these goals…”
Streamlining regulatory processes and
relying upon fewer regulators is a Trump
priority. “We do believe there are too many
regulators,” Hruska said. “There’s substantial overlap between FERC and SEC [Securities and Exchange Commission] and the
CFTC and the competition regulators.”
There’s no “game plan” yet, she said,
but regulatory reform is coming, with an
eye toward reducing regulatory overlap.
The potential merger of the CFTC and
the SEC was talked about by Hruska and
other speakers at the conference, with no
indication whether the “perennial” idea will
pick up traction.
“We want to sort of unify the approach
and perhaps even look at a regulatory sort
NATGASINTEL.COM | of reshuffling for change at the legislative
level,” Hruska said.
“It’s a perennial question; do we merge
the SEC with the CFTC. [Acting CFTC
Chairman Chris] Giancarlo and [SEC chief
nominee Jay] Clayton, I think, are perfect
leaders of the two most powerful, I think,
administrative agencies to really look at that
and give it an honest appraisal...I believe
that the regulatory program of the CFTC is
substantially different than the SEC. Even
though they both regulate financial instruments, they have fundamentally different
goals and purposes…”
Hruska said the Trump administration would only pursue merging SEC and
CFTC “if it made sense, if there are real
synergies there. And there really, I think,
aren’t that many. I can’t say that they completely dropped the idea, but I know it’s
kind of perennial; it’s (continued on page 6)
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Monday, April 17, 2017
ongoing.”
Speaking at the conference via telephone, Jim Newsome, former CFTC
chairman and a partner with Delta Strategies, said there would be more discipline
among regulators with regard to “gotcha
stuff like record-keeping...It’s “a breath of
fresh air.”
Commenting on the prospect of an
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INTELLIGENCE
Page 6
SEC-CFTC merger, Giancarlo, in recorded
comments to the conference, said a combination would have to enhance the mission
of the agencies. “Synergies would have to
be apparent,” he said, adding that the SEC
is primarily concerned with regulating retail
markets and the CFTC is geared toward the
professional swaps market.
Another potential area of reform,
Hruska said, would be to “put some teeth
into the CFTC’s cost-benefit analysis
requirement, and the same thing for” the
Federal Energy Regulatory Commission.
She said holding regulators to tougher economic standards would likely be a priority
of the administration at independent agencies across the board. “We want to put some
meat behind those bones...Stay tuned.” 
NATURAL GAS
NuStar Entering Permian Basin in Nearly $1.5B Deal
San Antonio-based NuStar Energy
LP has agreed to acquire Permian Basin
crude oil gatherer and transporter Navigator
Energy Services LLC for $1.475 billion.
Already active in the Eagle Ford Shale,
NuStar now would have a long-sought
presence in the Permian, management said
Wednesday.
Navigator’s West Texas assets in the
Midland sub-basin include 500 miles of
crude oil mainline transportation pipelines
with 74,000 b/d, ship-or-pay volume commitments and deliverability
of 412,000 b/d through multiple interconnects.
Navigator also has a
gathering system with more
than 200 connected producer tank batteries capable
of more than 400,000 b/d of
pumping capacity covering
more than 500,000 dedicated
acres. Of its 1 million bbl of
crude storage capacity, about
440,000 bbl is leased to third
parties.
The deal is expected to
close by late May, subject to
conditions, including regulatory approvals.
“We are excited about starting 2017
with a strategic acquisition, and the addition of Navigator’s Permian assets marks
NuStar’s entry into one of the most prolific
basins in the United States,” said NuStar
CEO Bradley C. Barron. “We expect that
the purchase price, when coupled with
modest future growth capex to build out
the system, will result in a high single-digit
multiple as volumes ramp over time.”
NuStar is one of the largest independent liquids terminal and pipeline operators
in the nation with 8,700 miles of pipeline and 79 terminal and storage facilities
that store and distribute crude oil, refined
© COPYRIGHT INTELLIGENCE PRESS 2017 | products and specialty liquids. The partnership’s combined system has 95 million bbl
of storage capacity with operations in the
United States, Canada, Mexico, the Netherlands, including St. Eustatius in the Caribbean, and the United Kingdom.
“It’s been no secret that we’ve been
actively searching for a way to break into
the Permian Basin, which currently represents approximately 40% of all U.S. onshore
rig activity,” Barron said Wednesday during
a conference call to discuss the transaction.
“For the past 18 months or so we’ve actively
looked at opportunities in the Permian, but
for one reason or another they’ve not met
our acquisition criteria or they included
assets that were either too risky or were outside of our core areas of expertise.”
In September 2015 Dallas-based
Navigator began service on its Big Spring
Gateway (BSG) Pipeline System, serving
the Permian Basin and making deliveries into the Sunoco Logistics-owned
West Texas Gulf Pipeline and the Permian
Express 2, with initial capability to transport
up to 40,000 b/d of crude, which increased
to 160,000 b/d by the end of the year.
“We continue to see strong demand for
NATGASINTEL.COM | crude oil transportation and storage solutions with multimarket access,” Navigator
Chief Commercial Officer Matt Vining said
at the time.
The nearly 450-mile BSG System spans
portions of Martin, Howard, Glasscock,
Midland and Mitchell counties in Texas, the
heart of the Permian Basin region.
One year later Navigator said it would
provide crude gathering services to Surge
Operating LLC for an area of mutual
interest spanning 25,000 acres in Howard
County, TX, with a new gathering system.
The Navigator assets
“are located in five of the six
most prolific counties in the
Midland Basin,” Barron said.
“So not only would this be
considered first-tier acreage,
what we’re talking about
here is the core of the core
of the Midland Basin…[W]
e’re very impressed with the
quality of the build. These
are mostly newbuild assets,
and our operations team is
very impressed with their
physical construction…
“The Navigator assets are consistent
with our existing crude oil operations in that
there’s no first purchasing or gas processing
exposure. Additionally, we expect these
assets to provide significant growth prospects through volume ramp from existing
producers with bolt-on acquisitions and
larger takeaway capacity opportunities.
“We will also have opportunities to
expand the system organically and bolt on
future acquisitions and possibly develop
larger takeaway capacity projects, including
a solution that could link the Navigator
system all the way to our docks at Corpus
Christi, TX, by
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NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
way of our existing Eagle Ford operations.”
During the conference call Barron did
not take questions as the company is in a
quiet period for an ongoing equity offering.
To fund part of the purchase, NuStar has
priced an upsized equity offering of 12.5
million common units for $579 million
gross, which is scheduled to close Tuesday..
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Two more capital market transactions are
expected. Bridge financing is in place to
backstop capital markets activity, Barron
said.
The Permian Basin generally and the
Midland sub-basin in particular have drawn
increasing producer and infrastructure
development activity. For example, about
one month ago, EPIC Pipeline Co. LLC
began offering capacity in a proposed crude
oil and condensate pipeline that would
run from the Permian to Corpus Christi,
with multiple receipt points in the western
Permian serving producers in the Delaware
and Midland sub-basins. 
NATURAL GAS
DCP Joins Kinder in Permian-Focused Gulf Coast Express Project
DCP Midstream LP has agreed to participate in developing Kinder Morgan Texas
Pipeline LLC’s (KMTP) proposed Gulf
Coast Express Pipeline Project, the companies said Tuesday.
Gulf Coast Express would provide an
outlet for increased natural gas production
from the Permian Basin to markets along the
Texas Gulf Coast. The project is designed to
transport up to 1.7 million Dth/d of natural
gas through 430 miles of 42-inch diameter
pipeline from the Waha, TX, area to Agua
Dulce, TX. The pipeline is expected to be in
service in the second half of 2019, subject
to shipper commitments.
“We are excited to be partnering with
one of the larger natural gas marketers in
the Permian Basin area, with DCP Midstream currently marketing approximately
600 MMcf/d of natural gas in that region,”
said Kinder Morgan’s Duane Kokinda, president of natural gas midstream. “We believe
DCP’s strong Permian position, when combined with the downstream market connectivity of Kinder Morgan’s Texas Intrastate
network, creates a valuable project for both
producers and markets.”
A nonbinding open season for firm
service on the pipeline is in process. It is
anticipated that DCP would be a partner and
shipper on the pipeline, while KMI would
build and operate it.
DCP is the largest natural gas liquids (NGL) producer and gas processor in
the United States and operates about 1.3
Bcf/d of processing capacity in the targeted Permian supply area. DCP also operates Sand Hills, an NGL pipeline extending
from the Permian to the Mont Belvieu,
TX, market. Sand Hills pipeline is currently being expanded from 280,000 b/d to
365,000 b/d.
“This opportunity presents a welcome
competitive alternative that adds diversity
to the market and is complementary to our
recently announced Sand Hills expansion,”
said DCP CEO Wouter van Kempen. “DCP
has a premier portfolio of integrated assets
in the Permian offering a full range of services and solutions to our customers.”
Gas supply is expected to be sourced
into the project from multiple locations,
including existing receipt points along
Kinder Morgan Inc.’s (KMI) KMTP and El
Paso Natural Gas pipeline systems in the
Permian, a proposed interconnection with
the Trans-Pecos Pipeline, and additional
interconnections to both intrastate and interstate pipeline systems in the Waha area.
Gas deliveries into the Agua Dulce area
would include points into KMTP’s existing
Gulf Coast network, KMI-owned intrastate
affiliates (KM Tejas and KM Border pipelines), the Valley Crossing pipeline, the
NET Mexico header, and multiple other
intrastate and interstate natural gas pipelines, KMI said.
The newly formed partnership isn’t
the only entity targeting the Permian Basin.
NAmerico Energy Holdings LLC’s newly
formed Pecos Trail Pipeline Co. is planning
a 468-mile intrastate gas system originating
in West Texas and terminating at various
points around Corpus Christi, TX. And
Enterprise Products Partners LP plans to tap
the Permian with a pipeline to carry NGLs
to its fractionation and storage complex in
Mont Belvieu.
Earlier this year DCP Midstream LLC
and DCP Midstream Partners LP combined
to create the largest NGL producer and gas
processor in the United States. At the time
expansion projects in the DJ Basin and on
the Sand Hills Pipeline were announced. 
FERC Has Environmental Questions on Atlantic Coast Pipeline
FERC has asked Atlantic Coast Pipeline LLC (ACP) to provide additional information on its proposed natural gas pipeline
within 20 days, after taking note of more
than 100 items or inconsistencies that raised
concerns with federal regulators.
The Federal Energy Regulatory Commission is preparing a final environmental
impact statement (EIS) for the project
[CP15-554], which would transport 1.5
Bcf/d of natural gas from the Marcellus and
Utica shales to satisfy heating and electric
generation demand in the Southeast.
© COPYRIGHT INTELLIGENCE PRESS 2017 | In a 36-page letter to the pipeline’s
backers — Dominion, Duke Energy and
Southern Company Gas — FERC said it
had identified seven geological areas of
concern. Among them, it found numerous
locations along the pipeline’s route that contain known and suspect closed depressions
within the project’s current workspace. The
locations were listed in an updated karst
survey report filed last February.
“It appears that many of these features
could be avoided by small route variations
and/or potential workspace reductions,”
NATGASINTEL.COM | FERC said, adding that ACP and Dominion
should clarify whether they “propose to
incorporate route and/or workspace design
revisions to avoid or minimize impacts to
these features.”
FERC’s letter came after the Commission received hundreds of comments
regarding its draft EIS on the pipeline.
FERC also asked ACP and Dominion
to describe the methods they used to identify orphan oil and natural gas wells along
the pipeline route that are not incorporated
into state databases
(continued on page 8)
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Monday, April 17, 2017
in North Carolina, Virginia and
West Virginia. The agency also
asked how impacts to wells that
may be encountered during construction would be minimized.
Among
its
concerns
regarding water resources, federal regulators said a rare species
report covering the George Washington National Forest (GWNF),
filed last February, had identified 27 waterbodies that would be
crossed by the pipeline — 25 of
which would be affected by pipeline construction, and two by new
permanent access roads.
But two subsequent reports
contained different numbers. The
first, a biological evaluation filed
on March 10, said 30 waterbodies
within the GWNF would be
affected. A revised master waterbody table filed two weeks later
listed 25 pipeline crossings and
12 access road crossings in the
forest.
“Provide an updated waterbody crossing table that accurately
addresses the inconsistencies,”
FERC said. “Note that we will
assume any updated waterbody
table that is filed would replace
waterbody crossing information presented in previously filed
documents...”
Other concerns include temporary workspaces and impacts
to vegetation, wildlife, fisheries,
special status species, land use,
special interest areas, and visual
and cultural resources.
Last week, the U.S. Forest
Service told FERC that a proposal to use horizontal directional drilling to bore the pipeline
under the Appalachian Trail and the Blue
Ridge Parkway was feasible. But the U.S.
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Environmental Protection Agency and
the Department of Interior recommended
that FERC conduct further analysis before
releasing its final EIS. 
NATURAL GAS
New York State Deals Another Setback to NatGas
Infrastructure; Denies Northern Access Permits
In yet another signal of the potential
roadblocks facing the natural gas industry
in New York, the state Department of Environmental Conservation (DEC) late Friday
© COPYRIGHT INTELLIGENCE PRESS 2017 | denied National Fuel Gas Co. (NFG) subsidiaries water quality certification and
other permits for the Northern Access
expansion project.
NATGASINTEL.COM | NFG said National Fuel Gas Supply
Corp. and Empire Pipeline Inc. received
word at 11:22 p.m. EDT on Friday that the
project would not
(continued on page 9)
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
be allowed to go forward. The decision
came after nearly three years of review and
just weeks after NFG’s management anticipated the state’s move by asking FERC to
diminish the DEC’s role in approving the
project.
In a news release on Monday the company made no mention of legal action, but
left the door open saying that NFG remains
committed to the project. The company said
it was still reviewing the agency’s “rationale” for not approving the permits. DEC
determined that construction would negatively affect the environment.
“These construction activities would
certainly have less effect than either
exploding an entire bridge structure and
dropping it into the Cattaraugus Creek or
developing and continuously operating a
massive construction zone in the middle
of the Hudson River for a minimum of five
years,” NFG CEO Ronald Tanski said of
DEC-approved projects for Route 219 and
the Tappan Zee Bridge.
The more than 490,000 Dth/d Northern
Access project would expand the Empire
and National Fuel systems to move gas
from Seneca Resources Corp.-operated
wells in Northwest Pennsylvania to markets
in New York, Canada, the Northeast and
the Midwest. Affiliate Seneca Resources
was relying on the project to help alleviate
capacity constraints. The project would consist of nearly 100 miles of new pipeline in
McKean County, PA, and Allegheny, Cattaraugus, Niagara and Erie Counties NY.
“After an in-depth review of the proposed Northern Access pipeline project
and following three public hearings and
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Page 9
the consideration of over 5,700 comments,
DEC has denied the permit due to the project’s failure to avoid adverse impacts to
wetlands, streams, fish and other wildlife
habitat,” the agency said in a statement.
“We are confident that this decision supports our state’s strict water quality standards that all New Yorkers depend on.”
Friday’s decision would seem to affirm
the growing perception — in the Appalachian Basin at least — that the state, under
Democratic Gov. Andrew M. Cuomo, is a
less than hospitable place for shale gas and
the infrastructure projects necessary for
those volumes to reach more markets. Two
years ago, the state banned high-volume
hydraulic fracturing. Additionally, the DEC
denied a water quality certification required
by the federal Clean Water Act and other
permits last year for the Constitution Pipeline after nearly three years of review.
As the agency continues to defend that
decision in federal court, Millennium Pipeline Co. has filed a preemptive lawsuit to
fight against what it argues are unnecessary permitting delays at the agency for an
8-mile lateral that would supply a natural
gas-fired power plant under construction in
the state.
On edge about those proceedings, NFG
last month filed a request for rehearing at
the Federal Energy Regulatory Commission
asking it to reconsider the Feb. 3 order authorizing the project. The company claims that
the Commission erred by not finding in its
order that DEC stream crossing, water withdrawal and wetlands permits are preempted
by the Natural Gas Act and not required to
begin construction. In a procedural order
posted last week, FERC said it would need
more time to consider the arguments of
NFG and the DEC, which asked the commission to reject the rehearing request in a
strongly worded filing defending its role in
the permitting process.
NFG said Monday that “voluminous”
studies by its subsidiaries and their consultants contradict the DEC’s decision
and show that construction would have
a “temporary and minor” impact on the
environment.
“What is perhaps the most troubling
aspect of this decision is that the NYSDEC
waited literally until the eleventh hour
to issue this denial, even though we had
detailed discussions with NYSDEC staff
over a 34-month period and undertook
detailed engineering and environmental
studies at the agency’s request to support the
stream-crossing techniques that now form
the basis of their denial,” Tanski said. He
added that the agency’s decision “attempts
to set a new standard that cannot possibly be
met by any infrastructure project in the state
that crosses streams or wetlands, whether it
is a road, bridge, water, or an energy infrastructure project.”
Northern Access was initially scheduled to enter service in late 2016, but NFG
said early last year that it would delay the
project until late 2017 on reduced drilling
activity caused by the commodities downturn. The company said in January that it
expected to receive its New York state permits this month after DEC issued notices
of complete applications for them. NFG’s
latest target in-service date for the project
was 1Q2018. 
NATURAL GAS
PennEast Receives FEIS, Expects Certificate Order This Summer
FERC on Friday issued a final environmental impact statement (FEIS) for the
PennEast Pipeline, bringing the project one
step closer to approval.
The FEIS came after nearly three years
of review and input from various stakeholders. Federal Energy Regulatory Commission staff concluded that approval of the
project would result “in some adverse environmental impacts” that could be reduced
to “less than significant levels with the
implementation of PennEast’s proposed
mitigation and the additional measures recommended” in the FEIS.
© COPYRIGHT INTELLIGENCE PRESS 2017 | Earlier this year, the Commission said
it needed more time to consider additional
environmental information and pushed back
the FEIS from Feb. 17 until Friday. With
the impact statement in hand and the water
quality certification required by the federal
Clean Water Act that was issued by Pennsylvania in February, the project has cleared
two major regulatory hurdles. But with only
two of its five seats filled, the Commission
still needs a quorum to issue the certificate
of public convenience and necessity that
would finally approve the pipeline, a FERC
spokesperson said.
NATGASINTEL.COM | “PennEast supports an expeditious
approval of qualified nominees to FERC and
looks forward to receiving a favorable order
from FERC commissioners,” said PennEast
spokeswoman Patricia Kornick. She added
that the project still anticipates receiving its
certificate in the next few months.
While work also still remains with
state regulatory agencies in New Jersey
and Pennsylvania, Kornick said the FEIS
is a “milestone” for the project, which has
faced staunch opposition from environmental groups and others. In a routine step
before the FEIS, (continued on page 10)
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Monday, April 17, 2017
PennEast applied for a freshwater wetlands
impact permit in New Jersey on Thursday
to satisfy Clean Water Act requirements.
The 120-mile greenfield pipeline
would transport 1.11 million Dth/d of Marcellus Shale natural gas to markets in Pennsylvania and New Jersey. It would originate
in Luzerne County, PA, and terminate at
Transcontinental Gas Pipe Line Co.’s interconnection in Mercer County, NJ. The
NGI
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project is 90% subscribed under long-term
contracts with local gas utilities, power generators and other customers.
Despite the uncertainty that remains
about filling FERC’s vacant seats, the project’s backers are still targeting an in-service
date sometime in the second half of next
year.
The project is owned by AGL Resources
Inc. unit Red Oak Enterprise Holdings Inc.
(20%); NJR Pipeline Co. (20%); SJI Midstream LLC (20%), and UGI PennEast LLC
(20%). Spectra Energy Partners LP entered
a deal last month to purchase PSEG Power
LLC’s 10% stake in the pipeline, which
would boost Spectra’s ownership to 20% if
the deal closes this quarter as anticipated.
PSEG would still remain a customer with a
125,000 Dth/d commitment. 
NATURAL GAS
Hundreds Comment on Atlantic Coast Pipeline EIS;
Forest Service OKs Appalachian Trail Crossing
The U.S. Forest Service (USFS) told
FERC that a proposal to use horizontal
directional drilling (HDD) to construct the
Atlantic Coast Pipeline (ACP) — to avoid
impacts to the Appalachian Trail and the
Blue Ridge Parkway — is feasible, and it
would not object to concurrent construction through other forest lands before the
crossing is completed.
Meanwhile, the U.S. Environmental
Protection Agency (EPA) recommended
that FERC conduct further analysis before
releasing its final environmental impact
statement (EIS) for the project [CP15-554].
The Department of Interior (DOI) also
voiced several concerns, including potential disturbance to its stream gauges along
the proposed pipeline’s route.
The comments by the federal agencies were among nearly 800 filed at the
Federal Energy Regulatory Commission
on Thursday — the official last day for
public comments on its draft environmental
impact statement (DEIS) for the project —
and through mid-day on Friday.
In a letter dated last Tuesday, USFS
said it had reviewed Atlantic Coast Pipeline
LLC’s proposal to use HDD as the primary
method to cross the Appalachian Trail and
Blue Ridge Parkway, as well as the company’s contingency method to use direct pipe
installation (DPI) for the crossing.
“ACP’s filings contain sufficient information to assess the feasibility of the proposals. Based on the USFS’ review, the
HDD would be feasible at the proposed
location and the DPI would be a feasible
contingency option,” wrote USFS Forest
Supervisor Clyde Thompson. He added that
USFS had no further questions or requests
regarding the crossing.
© COPYRIGHT INTELLIGENCE PRESS 2017 | In January 2016, USFS denied ACP
a special use permit (SUP) to cross the
Monongahela and George Washington
national forests in West Virginia and Virginia. Thompson said USFS told FERC at
the time that since ACP had not yet submitted any detailed proposals, any SUP
issued to ACP may be conditioned to
require successful completion of HDD at
the crossing — essentially halting any concurrent construction across forest lands
elsewhere.
But Thompson said USFS has since
decided to drop that condition.
“Because ACP subsequently filed
adequate documentation for the USFS to
assess the feasibility of the primary and
contingency proposals, and based on our
independent assessment that the proposals
are feasible, such a condition in the SUP
would no longer be necessary,” Thompson
said. “Thus, the USFS would not prohibit
concurrent construction at other spread on
[National Forest System] lands before the
completion of the [Appalachian Trail and
Blue Ridge Parkway] crossing.”
EPA, DOI voice concerns
In a separate letter, EPA Region 3,
based in Philadelphia, told FERC that its
final EIS for the project would be strengthened if it conducted additional testing and
analysis on geology and soils, streams and
wetlands, and groundwater and drinking
water protection.
Specifically, EPA said the project will
likely encounter “challenging geologic conditions,” and that blasting — coupled with
steep slopes, karst topography, and active
and abandoned mines and quarries along
the project’s route — pose additional challenges to protecting local residents and their
NATGASINTEL.COM | sources for drinking water.
“EPA appreciates the special consideration that crossing karst streams and terrain
has received in the DEIS,” the EPA said.
“In light of the DEIS, which indicates over
50% of karst hazards throughout the 71
miles of karst terrain crossed are identified
as ‘high risk,’ we recommend the final EIS
consider ecological risks to karst systems,
and risk mitigation that includes avoidance
measures.”
EPA also recommended that the
final EIS complete ongoing wetland and
stream surveys, and offered to assist in that
endeavor. Other recommendations included
considering alternative crossings for the
Neuse River; the inclusion of various studies
on the impacts to watersheds and ecosystems; and additional analysis of cumulative
impacts, especially on groundwater, stream
crossings and water withdrawals.
DOI also voiced concerns in another
letter to FERC. Its “greatest concern” is that
the ACP will cross the South River upstream
of Waynesboro, VA, at a point less than
five miles from a former textile plant that
discharged high levels of mercury waste
between 1929 and 1950. DOI said mercury
in the streambed could be disturbed when a
trench for the pipeline crossing is built.
“If the pipeline route were altered again
to where it crossed the South River downstream of this site, or disturbed contaminated areas, the high potential for mercury
release could become a critical environmental issue,” DOI said. “Total mercury
should be quantified upstream and downstream of the crossing point as an essential
element of the water quality monitoring
conducted before and after installation of
the pipeline.”
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Monday, April 17, 2017
DOI added that it was concerned over
potential impacts to eight stream gauges
operated by its U.S. Geological Survey
(USGS) located within one mile of the pipeline route or access roads. The USGS uses
the gauges to measure water quantity and
quality for a variety of purposes.
Other concerns raised by DOI include
alerting towns along the pipeline route of
construction activities upstream of their
public water supply intakes; impacts to
drinking water wells; potential damage to
nearby pipelines and other structures from
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Page 11
blasting; the potential for landslides from
construction in steep-sloped areas; and
potential impacts to aquatic species.
Backed by a joint venture between
Dominion, Duke Energy and Southern
Company Gas, ACP aims to transport 1.5
Bcf/d of natural gas from the Marcellus and
Utica shales to satisfy heating and electric
generation demand in the Southeast. The
project is around 96% subscribed under
long-term commitments.
ACP filed with FERC for a Natural Gas
Act certificate in 2015. Originally it was
targeting a 2018 start-up, but the denial of
an SUP by USFS caused Dominion to push
the in-service date to 2019.
Earlier this month, a bipartisan group of
lawmakers from all three states the pipeline
will traverse sent a letter to FERC, urging
the agency to approve the project. Separately, a labor union also hand-delivered
nearly 1,600 letters of support to the offices
of Virginia’s two senators, both Democrats,
Tim Kaine and Mark Warner. 
NATURAL GAS
Enterprise Products Putting 571-Mile NGL Straw in Permian Basin
Enterprise Products Partners LP said it
will tap the Permian Basin with a new pipeline to carry natural gas liquids (NGL) to its
fractionation and storage complex in Mont
Belvieu, TX.
The 571-mile Shin Oak NGL pipeline
would originate at Enterprise’s Hobbs NGL
fractionation and storage facility in Gaines
County, TX. The 24-inch diameter pipeline
would have an initial capacity of 250,000
b/d, expandable to 600,000 b/d.
“The Permian Basin is currently
the hottest play in North America and is
expected to continue its strong growth for
years to come,” said Jim Teague, CEO of
Enterprise’s general partner.
The project is supported by long-term
customer commitments and is expected to
be in service in the second quarter of 2019,
the company said.
In addition to mixed NGL supplies
aggregated at Hobbs, Shin Oak would provide takeaway capacity for mixed NGLs
extracted at natural gas processing plants
in the Permian region, including two Enterprise facilities that began service in 2016
and the Orla I plant, which is scheduled to
begin operations in the second quarter of
2018. The new pipeline would also increase
the company’s capacity to transport purity
NGL products from Hobbs to Mont Belvieu.
Enterprise is building a ninth fractionator at Mont Belvieu that will increase
NGL fractionation capacity by 85,000 b/d
following its expected completion in the
second quarter of 2018. Mont Belvieu is
pipeline-connected to the expanding U.S.
petrochemical industry on the Gulf Coast,
as well as Enterprise’s liquefied petroleum
gas and ethane deepwater marine export
terminals on the Houston Ship Channel.
“The Shin Oak pipeline project is part
of Enterprise’s larger plans in the Permian
to leverage our integrated midstream assets
to link supplies of cost-advantaged U.S.
hydrocarbons to the largest domestic and
global NGL markets,” Teague said. “This
additional pipeline takeaway capacity to
Mont Belvieu will provide Permian producers the flow assurance they need to continue the unfettered development of their
reserves with confidence.”
Enterprise recently announced plans
to add ethylene infrastructure on the Gulf
Coast with the anticipation of exporting
ethylene in the future. 
Louisiana Lands Another Billion-Dollar Chinese Petrochemical Facility
China’s Wanhua Chemical said it will
develop a $1.12 billion chemical manufacturing complex in Louisiana, noting the
state’s proximity to abundant natural gas
supply as well as waterborne transport.
Wanhua plans to produce methylene
diphenyl diisocyanate (MDI) at the facility,
which would combine a $954 million
investment by Wanhua with a $166 million investment by project partners. Site
selection is to be made later this year. The
company said it had considered locating the
facility in Texas but settled on Louisiana.
The project would be the second-largest
© COPYRIGHT INTELLIGENCE PRESS 2017 | foreign direct investment in Louisiana by
a company based in mainland China following the $1.85 billion methanol complex
under development by Yuhuang Chemical
in St. James Parish.
“Today’s announcement of Wanhua
Chemical’s decision to select Louisiana is
a testament to the strength of Louisiana’s
business climate and unmatched transportation logistics,” said Gov. John Bel Edwards.
“Our highly skilled workforce, our natural
resources and our world-class infrastructure
allow companies like Wanhua to make significant investments in our state and create
NATGASINTEL.COM | great new jobs while strengthening their
competitive edge.”
The facility is expected to be a major
component of Wanhua’s global development of MDI. An intermediate chemical,
MDI is among the fastest-growing categories of chemical production, the company
said. It is used for polyurethane foams and
elastomers, with applications in such consumer areas as appliances, electronics, furniture, textiles and footwear. MDI also is
used in the development of rollers, packing,
vibration insulators and synthetic leather
for various industries. 
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
NATURAL GAS
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EIA Sees Henry Hub Averaging $3.10 This Year, $3.45 in 2018
The Energy Information Administration’s estimated 2017 average Henry Hub
spot price, which had tumbled 12% in the
agency’s March Short-Term Energy Outlook
(STEO), took an upturn in the April report,
rising to $3.10/MMBtu, a 2.2% increase
compared with the previous forecast.
The 2018 Henry Hub spot price is
expected to average $3.45/MMBtu, EIA
said in its latest STEO, which was released
Tuesday. That’s unchanged from the previous STEO forecast. The price increase
next year will come thanks primarily to new
natural gas export capabilities and growing
domestic gas consumption, EIA said.
The front-month natural gas contract
for delivery at Henry Hub increased by 53
cents/MMBtu from March 1, settling at
$3.33/MMBtu on April 6, EIA said. New
York Mercantile Exchange contract values
for July 2017 delivery traded during the fiveday period ending April 6 suggest a price
range from $2.49/MMBtu to $4.59/MMBtu
encompasses the market expectation of
Henry Hub natural gas prices in July 2017 at
the 95% confidence level, EIA said.
“A brief but unseasonably cold period
in the middle of March contributed to an
increase in natural gas futures prices for the
month,” with heating degree days for the
week ending March 16 a full 23% higher
than normal, EIA said. The Henry Hub spot
price averaged $2.88/MMBtu in March,
more than $1/MMBtu above the average of
$1.73/MMBtu in March 2016.
Analysts with Raymond James & Associates Inc. have predicted the reverse of
EIA’s forecast, with 2017 prices higher and
2018 prices lower. The group bases its downward trend on faster-than-anticipated growth
in supply, along with surprising gains in
renewable power generation capacity. This
is expected to displace more demand than
forecast only four months ago. In early January analysts had said U.S. gas prices were
poised for the best prices in 2017 since 2014.
Now, however, while they are maintaining
their 2017 forecast of $3.25/Bcf, the 2018
estimate has been slashed to $2.75 from
$3.50 and the long-term forecast reduced to
$2.75 from $3.00.
Raymond James analysts in a note
Monday said burgeoning domestic gas
supply growth beginning in the back half
of 2017 and into 2018, coupled with the
outlook for demand drivers and the rise of
renewables, will negatively impact Henry
Hub price forecasts.
In a Summer Fuels Outlook released
simultaneously with the April STEO, EIA
said it expects relatively mild summer temperatures to hold total U.S. power generation
to about 2.4% below last summer’s levels.
Gas-fired power generation is expected to
be 9.1% lower than last summer, and coalfired generation is expected to be 4.2% lower
compared with last summer.
“Part of the large decline in natural gasfired generation reflects higher forecast natural gas prices, which encourages generation
from other types of fuels,” EIA said. “Also,
record levels of precipitation along the West
Coast are expected to raise hydroelectric
generation 28% above summer 2016 levels.
“Changes in the mix of electricity generation is also driven in part by changes in
the nation’s electric generating capacity. The
U.S. electric power sector is now expanding
its fleet of generators powered by natural
gas, wind, and solar. Natural gas-fired
generation capacity by the end of August
2017 is scheduled to grow by 10.5 GW, or
2%, from the capacity level last summer. The
electric power sector plans to expand wind
capacity by 9.2 GW (12%) and utility-scale
solar capacity by 7.5 GW (45%) above the
capacity at the end of summer 2016.”
EIA last Thursday reported a storage
build of 2 Bcf for the week ending March 31.
“U.S. working natural gas inventories
on March 31, the traditional end of the withdrawal season, were 15% above the five-year
average but 17% below last year’s recordhigh level at the end of March,” EIA said.
“Winter 2015-2016 and winter 2016-2017
were both unseasonably warm, but natural
gas drawdowns were higher this season
because of lower natural gas production and
higher exports.”
EIA expects exports to increase more
than production this year, which would move
inventories closer to the five-year average by
the time heating seasons begins.
Domestic dry natural gas production is
forecast to average 73.1 Bcf/d this year, a
0.8 Bcf/d increase from the 2016 level. That
increase would reverse a 2016 production
decline, which was the first annual decline
since 2005. Natural gas production in 2018
is forecast to be 4.0 Bcf/d above the 2017
level. 
Ultra Raises Nearly $3B in Financing, Emerges From Chapter 11
Onshore operator Ultra Petroleum
Corp. has completed its in-court restructuring and emerged from voluntary
© COPYRIGHT INTELLIGENCE PRESS 2017 | bankruptcy protection, having raised $2.98
billion in exit financing to fully reimburse
its creditors and preserve some value for
NATGASINTEL.COM | equity holders.
The Houston-based company also won
approval for its
(continued on page 13)
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Monday, April 17, 2017
newly issued common stock to be listed
on the Nasdaq Global Select Market, with
trading to begin on Thursday. It also has
added two members to its board of directors.
“Today is an exciting day for Ultra
Petroleum,” CEO Michael Watford said
Wednesday. “We achieved the goals we
have diligently pursued throughout our
Chapter 11 proceedings: maximizing the
value of the company for the benefit of all
of our stakeholders.
“We are extremely appreciative of the
investors and institutions that supported our
plan with the substantial equity and debt
capital investments reflected in the nearly
$3.0 billion of new financings we closed…”
He also thanked the employees for their
work during the bankruptcy process.
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Ultra last year filed for Chapter 11 in
U.S. Bankruptcy Court for the Southern
District of Texas. Under the reorganization
plan confirmed by the court, the company
completed a $580 million equity rights
offering and an $800 million senior secured
term loan agreement that matures in seven
years. It has $700 million in 6.875% senior
notes due in 2022 and $500 million in
7.125% senior notes due in 2025. A $400
million senior secured revolving credit
agreement also matures in 57 months.
Ultra plans to issue 195 million shares
of common stock under “UPL.” Existing
stock that traded under “UPLMQ” has been
cancelled.
Watford has been retained as chairman
and four board members also are remaining
— W. Charles Helton, Stephen McDaniel,
Roger Brown, and Michael Keeffe. Neal
Goldman and Alan Mintz have joined the
board.
Ultra holds more than 104,000 gross
(68,000 net) acres in and around the Pinedale and Jonah fields in Sublette County,
WY. It also holds 149,000 gross (74,000
net) acres in the Marcellus Shale, with
core acreage in Pennsylvania’s Centre and
Clinton counties, and 9,000 acres in the
Uinta Basin, in Uintah County, UT.
Last month, Ultra announced plans to
spend $500 million on capital expenditures
in 2017, a 46% increase from 2016. It also
said it expects overall production to range
from 290-300 Bcfe in 2017, compared to
the 281.7 Bcfe produced in 2016. 
NATURAL GAS
Goodrich, Linn Get New Stock Listings;
Bonanza Creek to Exit Chapter 11 Soon
Six months after emerging from
bankruptcy protection, common stock in
Goodrich Petroleum Corp. began trading
on the New York Stock Exchange (NYSE)
on Tuesday. Meanwhile, common stock
in Linn Energy Inc., which emerged from
Chapter 11 in late February, began trading
over-the-counter on the OTCQB market on
Monday.
A third exploration and production
company, Bonanza Creek Energy Inc.,
announced that a bankruptcy court has
approved its reorganization plans and
expects to emerge from Chapter 11 before
the end of the month.
Houston-based Goodrich announced
last week that NYSE had approved its
listing under the symbol “GDP,” and that
its common stock would continue trading
on OTCQB until the market closed on
Monday. CEO Robert Turnham said the
NYSE listing “represents an important
corporate milestone since our emergence
[from bankruptcy protection],” adding that
Goodrich expects “the new listing will
enhance trading liquidity and expand the
pool of potential investors.”
Goodrich began trading on OTCQB
after NYSE dropped its listing in January 2016, a consequence of the company
defaulting in 3Q2015. After failing to win
approval of its restructuring plans from
stockholders and noteholders, Goodrich
© COPYRIGHT INTELLIGENCE PRESS 2017 | voluntarily filed for Chapter 11 in U.S.
Bankruptcy Court for the Southern District
of Texas last April. The company had the
same assets when it emerged last October
but with reduced debt, a new board of directors, $40 million in new capital and new
common stock.
Linn, also based in Houston, emerged
from the same bankruptcy court on Feb.
28. The company cited a sustained decline
in commodity prices when it filed as Linn
Energy LLC in May 2016 but was able to
emerge as Linn Energy Inc. after agreeing
to sell its noncore assets in the Williston and
Permian basins, as well as in South Texas
and California. It also agreed to spin off
Berry Petroleum Co. LLC, a company it
acquired in 2013 for $4.3 billion.
Denver-based Bonanza Creek said the
U.S. Bankruptcy Court for the District of
Delaware had approved its reorganization
plans and a rights offering to infuse about
$200 million of new liquidity into the company, which voluntarily filed for Chapter 11
three months earlier.
“The court’s confirmation of our prepackaged plan represents a significant step
toward completing our successful financial
restructuring,” said Bonanza Creek CEO
Richard Carty. “We will emerge as a strong
and deleveraged company with a competitive business plan that will position us well
vis-à-vis our industry peers.”
NATGASINTEL.COM | Bonanza Creek’s prepackaged plan
received unanimous support from its creditors. The plan also incorporates the terms
of the previously announced restructuring
support agreement (RSA) with certain noteholders and one of its crude oil purchase
and sale counterparties, NGL Crude Logistics LLC, and its parent, NGL Energy Partners LP.
The RSA and prepackaged plan allow
Bonanza Creek to equitize $867 million
of its existing unsecured bond obligations
and bolster its liquidity position through a
$200 million rights offering for new equity,
to be backstopped by certain unsecured
noteholders.
Goodrich is focused primarily on oil
and natural gas targets in the Haynesville
Shale in North Louisiana and East Texas,
the oil window in the Eagle Ford Shale in
South Texas, and the Tuscaloosa Marine
Shale in eastern Louisiana and southwestern
Mississippi. Meanwhile, Linn is primarily
focused on stacked plays in Oklahoma —
SCOOP (the South Central Oklahoma Oil
Province) and STACK (the Sooner Trend
of the Anadarko Basin, mostly in Canadian
and Kingfisher counties).
Bonanza Creek operates in the Wattenberg field of Colorado — mostly targeting
the Niobrara and Codell formations — and
in the Cotton Valley Sands formation in
southern Arkansas. 
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
NATURAL GAS
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Stakeholder Midstream Buys Permian Gas Gathering System
San Antonio-based Stakeholder Midstream LLC has acquired the Lovington
Gas Gathering System from Lucid Energy
Group effective April 1.
The system is in the Northwest Shelf
of the Permian Basin in southeastern New
Mexico and serves oil and gas producers in
Lea and Chaves counties. The Lovington
system is composed of 295 miles of gas
gathering lines, 7,400 hp of compression
and a 35 MMcf/d refrigeration plant. Terms
of the sale were not disclosed.
“We see a significant opportunity in the
Northwest Shelf, where there is increasing
activity by producers focused on acreage
that provides not only attractive returns, but
also a lower-cost entry point than some of
the core areas of the Midland and Delaware
basins,” said Stakeholder Co-CEO Rob
Liddell. “The acquisition of the Lovington
system is the first step in developing our
ultimate vision for gas gathering, treating
and processing in the area.”
The acquisition complements Stakeholder’s newly constructed San Andres
Crude Gathering System in Yoakum
County, TX, and Lea County, NM, which
is expected to be fully operational in early
May. It currently consists of 60 miles of
gathering lines and multiple downstream
connections, which would provide access
to the market center in Midland, TX, to
regional refineries, and to long-haul pipelines capable of delivering crude to the Gulf
Coast.
Last year Dallas-based Lucid acquired
Agave Energy Co., which owned and operated natural gas gathering and processing
assets in the Permian’s Delaware sub-basin
in southeastern New Mexico and the Powder
River Basin of eastern Wyoming. 
API Says ‘Keep It in The Ground’ Policies
Would Mean Millions of Jobs Lost by 2040
The U.S. would lose millions of jobs
and trillions in cumulative gross domestic
product (GDP) by the year 2040 if the
nation’s energy policy adhered to actions
championed by the “keep it in the ground”
(KIG) movement, according to a study
commissioned by the American Petroleum
Institute (API).
In a 28-page report, “The Impacts of
Restricting Fossil Fuel Energy Production,”
API contends the United States would lose
5.9 million jobs by 2040 under a KIG scenario, when compared to a reference case
similar to the U.S. Energy Information
Administration’s (EIA) Annual Energy
Outlook (AEO) 2016 Reference Case.
The KIG scenario assumes no new
private, state or federal oil and gas leases;
a complete ban on hydraulic fracturing
(fracking); no new coal mines or expansion
of existing mines; no new energy infrastructure, especially pipelines; restricting
imports and exports to existing trade infrastructure, and no expansion of international
gas pipelines into the U.S.
“U.S. energy leadership is generating
major economic benefits for American
families and businesses,” said Jack Gerard,
CEO of API. “Increased energy production and infrastructure investment could
create hundreds of thousands of additional
jobs. [But] restrictive policies would take
the United States back to an era of energy
dependence — all based on the false idea
that we must choose (continued on page 15)
© COPYRIGHT INTELLIGENCE PRESS 2017 | NATGASINTEL.COM | NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
between energy self-sufficiency and environmental progress.”
API commissioned Vienna, VA-based
OnLocation Inc. to perform the study, using
the National Energy Modeling System
(NEMS) that the EIA uses to compile its
AEO reports.
In addition to the millions in lost jobs,
cumulative GDP (from 2018) would be
$11.8 trillion less by 2040 under the KIG
scenario, compared to the NEMS model.
Annual energy expenditures per household
are also predicted to be $4,552 higher under
KIG.
U.S. crude oil and natural gas liquids
(NGL) production would be an estimated
11.7 million b/d lower, and natural gas production off by 81 Bcf/d, under the KIG scenario. To help offset the drop in domestic
production, net liquid petroleum imports
would be 11.1 million b/d higher under
KIG. Prices for oil and gas would both be
higher compared to the NEMS model —
$40/bbl more for West Texas Intermediate
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(WTI) crude oil, and $21/MMBtu more at
the Henry Hub.
The annual cost of oil and gas imports
would rise to $129 billion in 2040 under the
KIG scenario, compared to net revenue of
$54 billion under the NEMS model. Meanwhile, net annual expenditures for crude
and product imports would increase by
$580 billion in 2040 under KIG, leading to
a cumulative increase in outflows of $7.5
trillion by 2040.
Retail electricity prices would also
be 56.4% higher under KIG, which would
reduce the demand for electricity by 8% in
2040. The only bright spot appears to be a
13.1% reduction in carbon dioxide (CO2)
emissions by 2040 across the nation’s
economy.
“Cutting U.S. oil and natural gas production wouldn’t magically reduce world
energy demand,” Gerard said. “But it could
raise costs significantly for American families and manufacturers, profoundly damage
the U.S. economy, diminish our geopolitical
influence, and severely weaken our energy
security.
“With forward-thinking energy policies, we can ensure the U.S. energy renaissance continues to provide benefits for
American consumers, workers and the
environment.”
According to API, the demand for liquid
fuels remains relatively constant between
the KIG scenario and the NEMS model,
with transportation demand shrinking —
by 0.7 quadrillion Btu (quads), or 2-3% by
2040 — due to higher prices, but industrial
demand is predicted to increase (by 0.5
quads, or 4% by 2040) due to the substitution for natural gas.
Although natural gas demand is predicted to be lower across all sectors of the
economy under the KIG scenario due to
much higher prices, the falloff is especially
pronounced in the power sector, where natural gas demand is reduced by more than 10
quads, or 80%, by 2040. 
NATURAL GAS
NatGas, Oil Consumption Up As U.S. EnergyRelated CO2 Drops 1.7% in 2016, EIA Says
Growth in natural gas-fired power generation was part of an overall reduction in
U.S. energy-related carbon dioxide (CO2)
emissions in 2016, the Energy Information
Administration (EIA) said in a Monday
note.
For 2016, U.S. energy-related CO2
emissions totaled 5,170 million metric
tons, a 1.7% reduction from 2015 levels,
EIA said. Before that, CO2 emissions had
dropped 2.7% from 2014 to 2015.
“These recent decreases are consistent with a decade-long trend, with energyrelated CO2 emissions 14% below the 2005
level in 2016,” the agency said.
The decrease in overall energy-related
CO2 emissions came as consumption of
both oil and natural gas increased, and as
coal consumption decreased “significantly,”
EIA wrote. Emissions levels also changed
based on shifts in consumption, as natural
gas CO2 emissions increased 0.9% and
petroleum CO2 increased 1.1%, while coalrelated CO2 declined 8.6%.
Overall carbon intensity decreased in
2016 as the U.S. economy grew, EIA said.
“Early estimates indicate that gross
© COPYRIGHT INTELLIGENCE PRESS 2017 | domestic product grew at a rate of 1.6%
in 2016, down from 2.6% in 2015. Taken
together with a 1.7% decline in energyrelated CO2, the 1.6% estimate of economic
growth implies a 3.3% decline in the carbon
intensity of the U.S. economy,” EIA said.
“In 2015, carbon intensity of the economy
had decreased by 5.3%.”
In 2016, CO2 from transportation surpassed CO2 from the power sector, a trend
EIA expects to continue in the decades
ahead.
NATGASINTEL.COM | “CO2 emissions from the electric
power sector fell by 4.9% in 2016” amid
“a significant reduction in coal use for electricity” in favor of natural gas and renewables. With the increase in renewables and
the lower emissions from gas-fired power
plants, “data indicate about a 5% decline
in the carbon intensity of the power sector,
a rate that was also realized in 2015. Since
1973, no two consecutive years have seen
a decline of this magnitude, and only one
other year (2009) (continued on page 16)
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
has seen a similar decline.”
EIA said weather played a role in 2016
CO2 emissions as well, with preliminary
data indicating 10% fewer energy-intensive heating degree days and a 13% more
cooling degree days compared to the norm.
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“Heating degree days in 2016 were
the second fewest of any year since at least
1949, consistent with relatively warmer
winter months,” EIA said.
The recent declines in U.S. energyrelated CO2 emissions come as the oil and
gas industry pushes back against “keep it in
the ground” activism. The American Petroleum Institute published a report last week
that found anti-fossil fuel policies could
result in millions of jobs lost by 2040. 
NATURAL GAS
Trump Administration Asks Appellate
Court to Delay Cases Over Methane Rules
The Trump administration has asked an
appellate court to delay a series of lawsuits
over proposed rules governing new sources
of methane emissions from the oil and natural gas industry, in order to give the U.S.
Environmental Protection Agency (EPA)
time to review the rules.
The request for an abeyance last Friday
in U.S. District Court of Appeals for the
District of Columbia Circuit, follows an
executive order (EO) issued by the administration on March 28. The EO includes,
among other things, a directive to the
EPA to immediately review regulations on
energy sources, and then to either suspend,
revise or rescind them.
At issue are three final rules governing
methane emissions that the EPA unveiled
in May 2016 by the Obama administration.
The rules, collectively updates to the New
Source Performance Standards (NSPS),
are designed to reduce methane, volatile
organic compounds (VOC) and toxic air
pollutants. The rules were designed to help
meet a goal by the previous administration
to slash methane emissions from the oil and
gas sector by 40-45% from 2012 levels by
the year 2025.
Acting Assistant Attorney General Jeffrey Wood asked the court to hold the lead
case, American Petroleum Institute (API)
et al v. EPA et al, No. 13-1108, as well as
several consolidated lawsuits, in abeyance
until 30 days after the EPA completed the
review called for in the EO.
“In light of EPA’s pending review of
the 2016 NSPS rule, abeyance of these
consolidated cases until 30 days after EPA’s
review of the rule pursuant to the EO is warranted,” Wood wrote in Friday’s filing. In a
sign the abeyance period could be lengthy,
Wood said the EPA “would be willing to
submit status reports every 60 days during
the abeyance period if that would be helpful
to the court.”
Under the EO, the EPA administrator
has 45 days to submit a review plan to the
White House’s Office of Management and
Budget. A draft report on the EPA’s actions
is due within 120 days of the EO being
enacted, and a final report is due within 180
days.
Last January, the court consolidated
three groups of lawsuits and made the API
case the lead one. The other two were Independent Petroleum Association of America
(IPAA) et al v. EPA et al, No. 15-1040, and
State of North Dakota v. EPA et al, No.
16-1242. Both of those lawsuits also had
additional cases consolidated with them.
Thirteen states — Alabama, Arizona,
Kansas, Kentucky, Louisiana, Michigan,
Montana, Ohio, Oklahoma, South Carolina, West Virginia and Wisconsin — plus
the North Carolina Department of Environmental Quality, are petitioners that oppose
the new rules. API, IPAA, the Western
Energy Alliance and several state oil and
gas, drilling contractor and royalty owner
associations are also opposed.
Meanwhile, at least nine states — California, Connecticut, Illinois, Massachusetts,
New Mexico, New York, Oregon, Rhode
Island and Vermont — joined a coalition
of environmental groups in support of the
rules. The coalition includes the Natural
Resources Defense Council, the Environmental Defense Fund, the Sierra Club, the
Clean Air Council, Earthworks and the
Environmental Integrity Project.
EPA built NSPS upon VOC emission
reduction requirements for new oil and gas
wells that the agency first unveiled in April
2012. Those requirements called for a twophase process to reduce VOCs: requiring
flaring followed by “green completions,”
a term that means deploying equipment to
capture and sell natural gas emissions that
are otherwise lost.
EPA previously said it expected NSPS
to reduce 510,000 short tons of methane in
2025, which is the equivalent of reducing
11 million metric tons of carbon dioxide.
The rules were also expected to reduce
other pollutants, including 210,000 tons of
VOCs and 3,900 tons of air toxics, by 2025.
The Trump administration’s fortunes in
court have been a mixed bag. Earlier this
month, the U.S. Supreme Court agreed to
continue hearing a legal challenge to the
controversial Clean Water Rule, which the
administration, Republicans and several
industries oppose.
Last month, attorneys for the Interior
Department’s Bureau of Land Management
(BLM) asked the U.S. Court of Appeals for
the Tenth Circuit in Denver to abate a case
over a BLM rule governing hydraulic fracturing (fracking) on public and tribal lands
because the agency intends to rescind the
rule. 
Economics, Propane Lobby Stymie NatGas Expansion in North Dakota
In a state in which the Bakken oil boom
produces more than 1.5 Bcf/d of associated
natural gas, most smaller towns still depend
on propane for their thermal energy needs,
and that is likely to continue as economics
© COPYRIGHT INTELLIGENCE PRESS 2017 | and the propane suppliers’ lobby tend to
keep local communities from making the
transformation.
Most efforts in this year’s state legislature to address the situation were soundly
NATGASINTEL.COM | defeated, except for a proposal (HB 1398)
that was passed and is awaiting Gov. Doug
Burgum’s signature. The bill would allow
communities under 2,500 population to get
natural gas service (continued on page 17)
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
— delivered by truck, rail or pipeline —
and have local authorities establish and regulate rates for the service.
Otherwise, proposed incentives and/
or subsidies to help communities get extensions of natural gas distribution pipelines
“have been successfully fought by the propane industry,” said Julie Fedorchak, one of
three members of state Public Service Commission (PSC).
HB 1398 will probably be signed by
the governor, Fedorchak told NGI.
Modeled after an existing policy in
Minnesota, HB 1398 would allow communities to negotiate directly with utility service providers to develop individual plans
for serving a particular community.
“If they can come to terms on what the
service looks like and its cost, then they can
seek a waiver from the PSC to avoid state
rate/regulatory oversight,” Fedorchak said.
“This isn’t a silver bullet for everyone, but
it definitely provides an avenue for communities to get creative and find an alternative
way to get natural gas to their local area.”
HB 1398 is viewed as a bridge or transition to a later time when towns might
be able to find a more permanent solution
through connection to the state’s existing
natural gas network, which is provided
principally through the MDU Resources
Group’s PSC-regulated utility.
North Dakota Pipeline Authority head
Justin Kringstad said he is aware that North
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Dakota’s gas transmission pipelines and
utility local distribution companies are
“continuing to evaluate the prospects of
delivering additional natural gas to unconnected communities in the state.
“The challenge continues to be a given
community’s distance from the existing
pipeline systems and the volume of demand
in the community. In many cases, it may
require a large commercial user around
an unconnected community to justify the
large upfront investment in new pipeline
infrastructure.”
While the U.S. shale gas boom has
spurred many states to seek ways to expand
natural gas service, there are more than 12
million homes that use propane for heating
nationwide, according to statistics from
the U.S. Energy Information Administration (EIA). In North Dakota, more than 360
small communities have no natural gas service while 70, including all of the largest
population areas, have traditional gas utility
service.
North Dakota Propane Gas Association officials said they cannot stop a utility
from moving into communities, but they
are opposed to efforts that create an “unfair
playing field,” although individual manufacturing businesses and the state Association of Rural Electric Cooperatives favor
extensions of natural gas service.
Claiming significant interest in an open
season last year, a unit of Bismarck-based
MDU Resources continues to push forward with plans to build a $60 million
interstate natural gas transmission pipeline
to bring supplies to areas of eastern North
Dakota and western Minnesota. An open
season for the project was completed last
summer. MDU’s WBI Energy Inc. has lined
up binding commitments for its 38-mile,
16-inch diameter Valley Expansion Project.
Eventually, interconnections north and
south of the transmission pipeline could
serve small towns in the far eastern part of
the state with natural gas, Fedorchak said.
“[HB 1398] is really a component of
economic and rural development with no
real added cost to the state,” said Fedorchak,
adding that the PSC has a proposal from
MDU to establish service with Bobcat Co.,
maker and marketer of compact construction, farming and landscaping equipment,
and two other potential large customers in
Gwinner, ND.
“The Bobcat installation is one the
state, overall, has been very interested in
finding a solution for getting it natural gas
service,” Fedorchak said. Not having access
to natural gas is viewed as a “global competitive disadvantage for Bobcat,” she said.
Fedorchak said the PSC will be
reviewing MDU’s proposal in the next
two weeks. The project would get its gas
supplies from an interconnection with the
existing interstate Alliance Pipeline. 
NATURAL GAS
NatGas, Oil Groups Urge Global Sourcing of Steel for Pipelines
A quintet of trade associations representing the majority of U.S. pipeline operators engaged in transporting
natural gas, natural gas liquids,
crude oil, refined petroleum products and carbon dioxide, said
Friday they support President
Trump’s call for the use of American steel pipeline construction,
but warn that there are serious
hurdles to be overcome.
“If these hurdles are not
overcome, government action to
increase domestic steel and pipe
production could have the unintended result of reducing or significantly delaying new pipeline
projects, limiting U.S. pipeline
job growth, and hurting American
© COPYRIGHT INTELLIGENCE PRESS 2017 | consumers,” according to joint comments
filed with the United States Department
NATGASINTEL.COM | of Commerce Office of Policy and Strategic Planning by the American Gas Association (AGA), the Association
of Oil Pipe Lines (AOPL), the
American Petroleum Institute
(API), the Interstate Natural Gas
Association of America (INGAA)
and GPA Midstream Association
(GPA).
Just days after his inauguration, Trump signed memorandums
ordering the Commerce Department to submit a report to him
on ways to streamline the federal
permitting process for domestic
manufacturers within 60 days, and
for Commerce to develop a plan
to maximize the use of American
steel for
(continued on page 18)
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Monday, April 17, 2017
pipeline construction within 180 days.
“We are, and I am, very insistent that
if we’re going to build pipelines in the
United States, the pipes should be made in
the United States,” Trump said at the time.
“[This is] going to put a lot of steel workers
back to work. We will build our own pipeline. We will build our own pipes, like we
used to in the old days.”
The trade associations said in their
comments with the Commerce Department
that they “support President Trump’s objective to grow domestic jobs and boost the
U.S. economy by reinvigorating American
manufacturing...However, a number of hurdles unique to pipeline-grade steel and pipe
manufacturing must be overcome to expand
domestic pipeline production and manufacturing.” Any plan put together by Commerce in response to Trump’s memorandum
“should recognize that global sourcing of
steel is currently essential for the continued
growth of America’s energy pipeline infrastructure and the U.S. economy overall,”
they said.
The associations said they are concerned that domestic sourcing requirements
could undermine the ability to achieve the
positive economic impacts, including job
growth, associated with pipeline manufacturing and construction, and have
the potential to adversely affect maintenance activities and reliability of existing
pipelines.
“An advantage of trade is that it
allows economies to specialize in areas
where they have a competitive advantage.
The specialized steel, pipe, and equipment required to construct and maintain
pipelines necessitates tight controls on
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Page 18
chemical composition, mechanical properties and quality. Manufacturing facilities
need advanced equipment and state-of-theart processes to achieve this result. Current domestic capacity to produce certain
materials and equipment used to construct,
operate, and maintain energy pipelines is
limited,” they said.
“Domestic steel and pipeline manufacturing industries would need time to
boost their capability to meet the unique
demand and support the continued growth
of America’s energy pipeline infrastructure.
The companies that currently supply the
U.S. pipeline industry have spent considerable time and resources perfecting their
processes. New entrants would need to
consider these costs relative to the size of
the niche market for pipeline materials and
equipment.”
The associations believe that several
considerations “are essential” for Commerce’s plan:
•• Consider the constraints for materials
and equipment that cannot be procured
domestically in adequate quantities, at
the necessary technical specifications,
and in time to meet market demand;
•• Consider potential impacts to reliability of existing pipelines if materials and equipment cannot be sourced
within the time necessary to meet
maintenance requirements;
•• Consider the potential for domestic
sourcing requirements to have the unintended consequences of reducing or
delaying investment, and consequently
reducing jobs, in the U.S. energy
industry and in pipeline construction;
•• Consider
the
cost
and
service implications, for industry
and for consumers, of any potential
domestic sourcing requirements;
•• Consider excluding pipeline projects
that already have shipper commitments
and/or pending or issued federal or
state permits, such as interstate projects
with a pending or issued FERC certificate, projects that have been approved
by the state agency responsible for
intrastate transmission and distribution
pipelines, and projects that are subject
to federal or state agency siting or permitting review;
•• Consider the varied operational characteristics, pipe and equipment needs,
and regulatory frameworks of transmission, gathering, and distribution
pipeline systems; and
•• Consider the multiple factors that affect
sourcing decisions made by pipeline
operators and production decisions
made by steel and pipe mills and equipment manufacturers.
While Trump’s memorandum directed
the development of a domestic sourcing
plan “‘to the extent permitted by law,’ neither the presidential memorandum, nor
the Federal Register notice, nor any other
information now available, provides the
legal authority for any such requirement,”
the associations said. “Therefore, to assist
in the development of a plan that complies
fully with the president’s instructions, the
associations request that interested stakeholders are given a meaningful opportunity
to provide advance comment on the possible legal limitations and ramifications of
any plan.” 
NATURAL GAS
Alaska’s Senators Introduce Bill to Reverse
Obama’s Block of Offshore Drilling
Alaska’s two Republican senators have
introduced a bill that calls for conducting
lease sales in the state’s offshore areas of
the Beaufort Sea and Cook Inlet, and would
reverse a decision made during the waning
days of the Obama administration to withdraw leasing areas of the Arctic’s Outer
Continental Shelf (OCS).
Sens. Lisa Murkowski and Dan Sullivan introduced a bill — S 883, also known
as the Offshore Production and Energizing
© COPYRIGHT INTELLIGENCE PRESS 2017 | National Security Alaska Act of 2017, or
OPENS Act — last week. The legislation
was read twice Thursday and referred to the
Senate Committee on Energy and Natural
Resources, which Murkowski chairs.
“After years of regulatory restrictions and burdens imposed by the Obama
administration, this bill charts a much better
course for responsible energy production in
our Beaufort and Chukchi seas that actually
reflects the views of the vast majority of
NATGASINTEL.COM | Alaskans,” Murkowski said in a statement.
“These areas contain prolific resources
that can be safely developed to create jobs,
reduce our deficits, keep energy affordable,
and strengthen national security.”
Sullivan added that the Obama administration “tried to kill responsible resource
development in the Arctic, ignoring the fact
that the rush to the Arctic is on. Oil and gas
will be developed in the region — whether
by our nation or (continued on page 19)
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Monday, April 17, 2017
others. It is imperative that exploration and
development occur with all of the safeguards required by the United States to protect the environment and the people who
live in the region.”
S 883, among other things, directs
the secretary of the Department of Interior
(DOI) to establish a new Nearshore Beaufort
Sea Planning Area in the OCS, consisting
of the portion of the existing Beaufort Planning Area within three nautical miles of the
seaward boundary of Alaska. It also directs
the DOI secretary to conduct one annual
lease sale each in the Nearshore Beaufort
and Cook Inlet planning areas, during fiscal
years (FY) 2018, 2019 and 2020.
The bill also calls for amending the
OCS Lands Act by including the Beaufort,
Chukchi, Cook Inlet and Nearshore Beaufort planning areas to its five-year leasing
programs. At least three lease sales would
be required annually in the Beaufort and
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Chukchi planning areas, and one annual
sale each in the Nearshore Beaufort and
Cook Inlet planning areas.
Last December, President Obama
issued a presidential memorandum withdrawing vast areas of the nation’s OCS
from future oil and gas drilling. He withdrew 115 million acres in the Arctic OCS
and 3.8 million acres in the north and midAtlantic OCS, located off the East Coast.
In their joint statement, Murkowski and
Sullivan contend that the Trump administration has the authority to revoke Obama’s
withdrawals, but decided to introduce a bill
“to set a marker that reflects the views of
the vast majority of Alaskans.” A poll commissioned last year by the Arctic Energy
Center found that 76% of Alaskans support
offshore resource development in the state.
During his presidential campaign,
Trump proposed allowing states to regulate energy development over federal
agencies and opening up more federal lands
to drilling.
The senators added that the Beaufort
and Chukchi seas combined form one of the
most prospective basins in the world, with
an estimated 23.6 billion barrels of oil and
104.4 Tcf of natural gas.
Despite the bounty, Royal Dutch Shell
plc, once the biggest leaseholder in offshore
Alaska, said last May that it will abandon
all but one of its leases in the Chukchi, and
was evaluating its holdings in the Beaufort.
At the time, the international major cited
an “unpredictable” regulatory environment
and disappointing initial drilling results.
Shell, ConocoPhillips, Italy’s Eni SpA
and Iona Energy Inc. together relinquished
about 350 leases, covering 2.2 million acres
of drilling rights, in the Chukchi before a
deadline to do so. 
NATURAL GAS
Jordan Cove LNG Project Eyes Third Offtake Contract,
Selling Equity Interests, Veresen Reports
The backers of the only U.S. West
Coast liquefied natural gas (LNG) project
still alive, Calgary-based Veresen Inc.,
is talking to a third prospective Japanese
buyer and is considering selling up to a 40%
equity interest in the project to offtakers,
including two already signed to term sheets,
according to company officials.
Veresen senior executives outlined
plans for Jordan Cove LNG at the four-day
international Gastech 2017 conference in
Tokyo.
Recently granted a pre-filing status
by FERC, Jordan Cove plans to re-file its
application in the second half of this year.
Its executives’ encouraging words in Japan
came at the same time the global supply of
natural gas is getting even more saturated
and there are more doubts about the viability
of additional long-term LNG contracts.
In Japan, Betsy Spomer, CEO of
Jordan Cove, made clear that the Canadian oil/gas infrastructure company is seriously looking at the equity offering to a
potential Japanese buyer, and to the Tokyobased electric utility joint venture JERA
Co. Inc. and Itochu Corp., who last year
signed long-term capacity agreements. Ideally, Veresen wants to have 6 million tons
© COPYRIGHT INTELLIGENCE PRESS 2017 | of LNG/year under contract before making
a final financing decision on Jordan Cove,
Spomer said.
NATGASINTEL.COM | The fact that Qatar recently announced
it was lifting a long-standing moratorium
on development (continued on page 20)
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Monday, April 17, 2017
of part of the world’s largest gas field and
the prospective deals are looking at shorterterm contracts does not deter Veresen or
Jordan Cove, according to a company
spokesperson.
“There are a bunch of Qatari gas contracts with Japan that are rolling off so
whether it will be added supplies or just
replacement is not clear, and the Japanese
these days are looking very much for diversification of supply sources,” the spokesperson said. “Security of supply is a big
issue, and they don’t have a lot of supply
coming from North America yet, but they
are trying to build that portfolio, and that is
where Jordan Cove comes in.”
NGI
INTELLIGENCE
Page 20
The other advantage for North American supplies is that the Japanese can actually own reserves and have a better grasp
of the value chain, according to the spokesperson. “Ownership of the reserves to the
transportation in the shipping is possible
over here, whereas with Qataris, they are
just a customer.”
Veresen CEO Don Althoff told the
Tokyo conference that in addition to JERA
and Itochu each taking 1.5 million tons
annually of LNG, collectively half of Jordan
Cove’s expected capacity, his company
is talking to a third Japanese buyer to sell
them 1-2 million tons annually. Althoff said
the latest talks are in the advanced stages.
“All buyers are interested in taking
some equity part of the plan,” he said.
JERA reportedly has identified a need
for more LNG starting in 2024, which is
most likely the earliest that Jordan Cove
could come online, given its pre-filing
status at FERC, the Veresen spokesperson
said.
“There have been a couple of things
that have happened on the contracts that
make us more positive on that front, and
on the regulatory front we seemed to have
garnered the support of the White House as
one of three projects they feel have been
mired in red tape, so that is also potentially
helpful.” 
NATURAL GAS
Activist Targets BHP Billiton, Calls For Demerger
of U.S. Petroleum Business, Other Measures
BHP Billiton should jettison its U.S.
petroleum business (offshore and on), which
is undervalued by the market, does not contribute value to the company and does not
mesh with BHP’s traditional mining operations, an activist shareholder said Monday
in a letter to company directors.
“Based on commonly utilized valuation metrics for comparable businesses, the
indicated value for BHP’s U.S. petroleum
business is [approximately] US$22 billion,
which is well in excess of the current analyst consensus valuation for that business,”
said the Elliott Funds, which hold 4.1% of
BHP Billiton plc.
BHP rejected the Elliott proposals.
Elliott said the U.S. business does not
provide “meaningful diversification” to
BHP as a whole and there are no synergies
between the U.S. business and the company’s mining assets. “...[I]ts intrinsic value is
being obscured by bundling it with BHP’s
other assets,” Elliott said.
“We believe that within the confines
of the existing group, BHP’s U.S. onshore
acreage opportunities are extremely limited. BHP has competing capital allocation
alternatives — including its world-beating
mining assets such as those within its iron
ore division, and highly value-accretive
post-unification off-market BHP share buybacks at a 14% discount to market price.
“...BHP’s management simply cannot
justify allocating the capital which the U.S.
onshore assets would need for the U.S.
© COPYRIGHT INTELLIGENCE PRESS 2017 | petroleum business to realize its growth
potential or meaningful corporate expansion activities.”
Demerging and listing the U.S. business separately on the New York Stock
Exchange would unlock the value of the
assets and allow the business to be properly
capitalized, Elliott said.
Elliott is making two other recommendations to BHP management. The
company’s dual-listed structure should be
combined into a single, Australia-headquartered and tax-resident listed company.
It said BHP should adopt “a consistent and
value-optimized capital return policy…”
and cited the company’s misadventure in
U.S. shales.
“BHP is expected to generate [approximately] US$31 billion of excess cash flow
in the next five years, assuming the current
50% payout ratio of net income. Unfortunately, BHP has previously used excess
cash to make value-destructive acquisitions when it acquired certain Fayetteville
[Shale] assets and Petrohawk.”
In early 2011 BHP acquired the Fayetteville Shale assets of Chesapeake Energy
Corp. for $4.75 billion in cash. Later that
year it acquired Petrohawk Energy Corp.
for $12.1 billion. Asset writedowns followed a few years later. BHP, according
to its website, currently holds more than
838,000 net acres in the Eagle Ford Shale,
Permian Basin, and Haynesville Shale, as
well as the Fayetteville.
NATGASINTEL.COM | The company was already active in the
U.S. Gulf of Mexico where it operates two
fields: Shenzi (44% interest) and Neptune
(35%). It holds nonoperating interests in
three other fields: Atlantis (44%), Mad Dog
(23.9%) and Genesis (4.95%).
Instead of such “badly timed acquisitions” as the Fayetteville purchase, the company should return value to shareholders
through buybacks, Elliott said on Monday.
BHP’s offshore U.S. assets should go
as well, Elliott said. “We see the demerger
of BHP’s Gulf of Mexico assets in combination with the U.S. onshore petroleum
assets as providing a standalone U.S. petroleum business with consistent cash flow to
fund its own further expansion, allowing
BHP to increase its focus on its core competencies and also helping the value of
BHP’s remaining core portfolio to positively re-rate.”
BHP last December was high bidder
in a Petroleos Mexicanos (Pemex) auction,
offering $624 million for the first deepwater
partnership ever for Pemex.
In a statement Monday BHP said it
has reviewed the Elliot proposals and has
been in talks with the investor “over many
months.” The costs and associated risks of
what the firm is proposing would outweigh
any potential benefits, BHP said.
“Elliott’s [U.S. petroleum business]
demerger proposal is based on a view that
investors would ascribe a higher value for
these assets in a (continued on page 21)
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
separately listed entity,” BHP said. “There
is no obvious discount in BHP Billiton’s
trading multiples relative to the weighted
average of relevant mining and oil and
gas peers. BHP Billiton has disclosed the
NGI
INTELLIGENCE
Page 21
information the market needs to fully value
the petroleum business.
“BHP Billiton’s approach is to optimise the long term value of the Petroleum
business through operating excellence.”
Elliott manages two funds: Elliott
Associates LP and Elliott International LP,
with assets under management totaling
more than US$32.7 billion. 
NATURAL GAS
West Virginia Severance Tax Collections Trending Higher
West Virginia’s severance tax collections through the first nine months of fiscal
year (FY) 2017 have come in $13 million
above estimates, reversing a downward
trend that began in 2015 when the state was
forced to make spending cuts due in part to
the steep decline of commodity prices at the
time.
Revenue collections released by the
state budget office show that from July 2016
through March, the state generated $200.8
million in severance taxes, well above the
$187.8 million that was projected for the
period. Currently, the state estimates that it
will generate $262.5 million for the entire
fiscal year. In FY2016, severance tax collections came in $195 million below estimates at $276.4 million, reflecting a tough
period for the state’s energy industries.
During a briefing with reporters on
Thursday, Deputy Revenue Secretary Mark
Muchow said increasing natural gas prices
are also lifting the price of coal, with more
of it being burned by power generators in
the competitive market that favors lower
costs. The state collected $40.2 million in
severance taxes during March, compared to
the $27.1 million that was projected for the
month.
The state is still facing an estimated
$123 million revenue shortfall for FY2017.
Lawmakers were at work on a legislative fix
Friday to plug part of that gap with rainy
day funds and money from other accounts
heading into the end of the regular session
at midnight Saturday.
Producers pay 5% for the value of both
coal and natural gas. The legislature eliminated additional volumetric fees last year.
In other news from the Capitol in
Charleston, Gov. Jim Justice signed into
law a bill that exempts some oil and gas
industry storage tanks from a 2014 law
aimed at better protecting public water supplies. The legislature passed a committee
substitute for HB 2811 last month and Justice signed it April 4. The bill exempts more
than 2,000 industry tanks from part of the
Aboveground Storage Tank Act, including
the submittal of spill prevention response
plans and certified inspections.
The aboveground storage act was
prompted by a January 2014 incident in
which thousands of gallons of coal-cleaning
chemicals leaked from a Freedom Industries processing facility on the Elk River, a
waterway from which numerous communities draw their water supplies. 
Ring Drills Seven Horizontal Wells in Permian’s
CBP, Grows Production 10.8% in 1Q2017
Midland, TX-based Ring Energy Inc.
continues to get results from its horizontal
wells in the Permian Basin’s Central Basin
Platform (CBP).
In a 1Q2017 operations update this
week, Ring said it drilled seven new onemile-lateral horizontal wells in its San
Andres asset in the CBP during the quarter.
The exploration and production company
completed five of those wells, which averaged gross 24-hour initial production (IP)
rates of 660 boe/d, with a range of 377 boe/d
to more than 800 boe/d.
Ring, a long-time vertical driller in the
CBP, previously detailed the results from its
initial three-well horizontal program in the
San Andres. This included its Augustus #1H
and Tiberius #1H wells, which produced 602
boe/d and 448 boe/d respectively through 45
days, with production 95% weighted to oil.
On Wednesday, Ring management
said the initial results from the CBP wells
completed during 1Q2017 have exceeded
© COPYRIGHT INTELLIGENCE PRESS 2017 | expectations.
“When we initiated our three-well pilot
horizontal drilling program last year, we had
certain expectations based on the extensive
review and due diligence we performed on
both the current and historical results of
neighboring operators,” said Danny Wilson,
executive vice president of operations.
“As of the end of the first quarter, we
have drilled a total of 10 horizontal San
Andres Wells on our CBP. Of these, two
are 1.5 mile laterals, one is a 1.25 mile lateral and the remaining seven are one mile
laterals. Our original average net estimated ultimate recovery (EUR) target when
starting the program was 55 boe per lateral
foot, with the knowledge and understanding
that some wells will be more productive
than others.
“The initial results on the longer laterals are showing preliminary net EURs of
35-55 boe/foot. Based on a net received oil
price of $45/bbl and a drill and complete
NATGASINTEL.COM | cost of $2.4 million, those wells will yield
over a 90% internal rate of return (IRR) on
the lower end, up to an IRR over 240% on
the higher end.”
Wilson said the one-mile-lateral wells
are on track for EURs between 40 and 100
net boe/foot, yielding a greater than 70%
IRR at $45/bbl and a drill and complete cost
of $2 million.
Ring’s net production for the quarter
totaled 266,000 boe, up 18% year/year and
10.8% sequentially. Average net daily production totaled 3,618 boe/d, compared with
2,370 boe/d in March 2016, the company
said.
CEO Kelly Hoffman said Ring added
10,000 gross acres to its horizontal footprint
in the CBP in 1Q2017, bringing the company’s gross horizontal CBP acreage to more
than 54,000 (30,000 net), including over 500
gross (285 net) horizontal drilling locations.
“We continue to seek out opportunities
that complement (continued on page 22)
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
our existing asset base while optimizing our
current portfolio and growing our production, inventory and reserves,” Hoffman said.
Also during the first quarter, Ring
NGI
INTELLIGENCE
Page 22
drilled two new saltwater disposals in the
CBP and continued to expand its oil, gas and
water infrastructure in the play.
In the Delaware Basin, Ring drilled two
new vertical wells and one new saltwater
disposal well, and recompleted two existing
wells in its Cherry Canyon asset. 
NATURAL GAS
Shale-Related Projects Set Record Investment Level
(continued from page 1)
“Without the natural resource of the shale
gas — for which this region once pioneered
extraction — an ethane cracker would not
have been a consideration.”
While investments in the region reached
a high water mark last year, PRA noted that
there was a drop in the area’s energy sector
deals during the same time. The organization recorded 16, which was down from 31
in 2015. Energy-related manufacturing deals
also dropped by 50% year/year from eight
to four. PRA said the commodities downturn
slowed regional investments, along with the
fact that upstream operations are already
firmly rooted in the state.
Shale gas continued to play a key role
in the regional economy. The 2016 scorecard tracked deals across five key sectors to
record 245 of them, including attractions,
retentions, expansions, and infrastructure
and real estate development projects.
PRA said the total job impact anticipated from those deals is 11,344, or 5,761
new jobs and 5,583 retained jobs. The
greatest total job impact, PRA found, is
expected to be in manufacturing (3,667),
healthcare (2,893) and energy (2,288). 
to shale gas abundance — has made fixed
price deals less attractive compared with
the alternative of just doing index deals.
More independent gas producers —
thank the shales again — means that a
greater share of the producing community
is focusing on just completing wells and
not worried about marketing gas with fixedprice deals, as larger producers with marketing shops might do. Index deals are also
easier for utilities to justify in front of their
state regulatory commissions, Steis added.
And also, banks have left the physical gas
market following the financial collapse and
reforms under the Dodd-Frank Wall Street
Reform and Consumer Protection Act.
Finally, the indexes are victims of their
own success, Steis said. “I think it’s precisely because the indexes are so dependable, reliable and accurate that people do
index deals,” he said. “I’m not sure what
we can really do about that.”
Of those doing fixed price deals, fewer
have been reporting them to publishers,
Leonard said. “If you look over time, the
fraction of companies that actually report
their fixed-price physical gas has been
declining pretty significantly since 2008,”
he said. “In 2008, just under two-thirds
of companies that transacted fixed-price
physical gas made reports to the index publishers. Whereas last year for the first time
it was just under half... basically half...this
is by volume.”
The greatest inhibitor of reporting
fixed-price deals, panelists seemed to
agree, is the perception of regulatory risk,
and sometimes that risk is more than just a
perception.
Prokop said when Deloitte reviews the
price reporting practices of client companies, it finds that many are doing a great job
with great technology and practices. Malicious behavior has not been about in some
time, he said. However, not all companies
are in compliance with regulations developed following the natural gas marketer
meltdown and price reporting scandals of
yesteryear.
Responding to those who say they
don’t want to report, and ask “why should
I report,” NGI’s Steis pointed out that “right
now there’s a voluntary system of price
reporting. But the Energy Policy Act of
2005 gave FERC certain powers to mandate
a system with greater levels of transparency
should they deem it necessary. Right now if
you report, we ask for location, price, volumes, flow dates, trade date, counterparties
optional. So that’s what we receive.
“If it becomes a mandated system, the
question becomes what manner of information would be required to be reported?
Would the Commission require counterparties or profit loss information, trigger deals,
EFPs, index trades? This becomes a slippery regulatory slope.
“So I would thank the folks who are
being good corporate citizens and reporting
under the voluntary system. And I would
ask those who have made the decision to
not report, to re-evaluate.” 
NatGas Price Index Reporting
(continued from page 1)
monthlies, the theme has been similar to
that of the 2012-2014 period, he said. There
are still decreases, but they have been a bit
smaller, he said.
Well over a decade since price reporting
became a headline issue in the natural gas
industry, it’s still around.
“After about 15 years or so, I can’t
believe we’re still talking about price
indices and price creation,” said Deloitte’s
Michael Prokop, moderator of the conference panel. “Back then, when industry realized there was a problem, trading was being
halted or stunted and we got together and
fixed it is what we did...put together best
practices and figured it out and worked very
closely with the regulator…”
About 80% of natural gas transactions
reported to the Federal Energy Regulatory
Commission on Form 552 depend on price
indices, with the remaining 20% or so being
fixed-price and physical basis deals eligible
to be reported to index publishers.
That ratio of index deals to fixed-price
has grown over the last eight years — from
about 3.5 times to a ratio of almost eightto-one, said Cornerstone Research Vice
President Greg Leonard, whose firm publishes an annual report on the Commission’s Form 552 data. “Eight times as many
deals depend on the indices than go into the
indices,” he said.
The migration toward greater reliance
on index deals is due to a constellation of
factors, according to Steis. Lower price
volatility in recent years — thanks largely
© COPYRIGHT INTELLIGENCE PRESS 2017 | NATGASINTEL.COM | NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Monday, April 17, 2017
NATURAL GAS
NGI
INTELLIGENCE
Page 23
PEOPLE
Wayne Christian
Texas Gov. Greg Abbott appointed Railroad Commissioner Wayne Christian to serve as the official representative
of Texas to the Interstate Oil and Gas Compact Commission (IOGCC). Christian was elected to the Railroad
Commission of Texas last year. Christian’s responsibilities
as representative to IOGCC include serving as spokesman
for the group in Texas, meeting with the governor to discuss
current issues, authoring/sponsoring IOGCC resolutions,
voting during business session, participating in committees
and regularly attending meetings. The appointment is for an
indefinite period. 
INDUSTRY BRIEFS
Texas Eastern Transmission | Hilcorp Alaska | Hilcorp Alaska | Drillinginfo |
Yuhuang Chemical | Tennessee Gas Pipeline | Total Petrochemical
Staff of the Federal Energy Regulatory Commission will
prepare an environmental assessment (EA) of the Pomelo
Connector Pipeline Project and the South Texas Expansion
Project, separate but related projects of Texas Eastern Transmission LP (Tetco) intended to support natural gas exports to
Mexico. Comments on the projects [CP15-499] are due at the
Commission by May 8. The 30-inch diameter Pomelo would
run from Tetco’s Petronila Station in Nueces County, TX, to its
Valley Crossing interconnect near Agua Dulce. Valley Crossing
Pipeline LLC, originally a unit of Spectra Energy since merged
with Enbridge Inc., has proposed a Texas pipeline and U.S.Mexico border crossing to serve power generation and other
gas demand in Mexico as well as in Texas [CP17-19].
Hilcorp Alaska Monday morning completed emptying a
natural gas pipeline in Alaska’s Cook Inlet that is suspected
of having a leak. The pipeline is at the Steelhead Platform,
which produces natural gas from the Grayling Gas Sand
Formation in the Trading Bay Unit on the west side of Cook
Inlet. During an investigation prompted by natural gas pipeline
leak discovered earlier this year in the Cook Inlet, a metering
discrepancy was discovered on the pipeline serving the Steelhead Platform, Hilcorp said in a statement. “As a precaution,
we started emptying the A Pipeline of natural gas on Saturday,
and that process was completed early Monday morning,” the
company said. “The line now contains filtered seawater. “We
have decided to leave the line filled with seawater until a later
time when we are able to further investigate and address the
meter discrepancy.” A crude oil pipeline leak also was recently
discovered by Hilcorp in the Cook Inlet.
Hilcorp Alaska said Monday that dive crews were working
to repair a leaking eight-inch diameter natural gas pipeline
in the Middle Ground Shoal area of the Cook Inlet. The
leak point, approximately two inches in length, was noted to
be on the very bottom of the pipeline resting on a boulder
embedded in the seafloor, Hilcorp said. Following completion
of the initial repair, further inspection and work will be done to
permanently repair the affected segment of pipe. The line will
not be returned to service until permanent repairs have been
completed, the line has been pressure tested, and regulators
have approved a re-start, Hilcorp said.
© COPYRIGHT INTELLIGENCE PRESS 2017 | NATGASINTEL.COM | Drillinginfo, a software-as-a-service, or
SaaS analytics provider for the oil and gas industry, is allying
with software platform provider MineralSoft to expand mineral rights management offerings. The joint venture would
allow the Austin, TX-based companies to analyze for mineral
owners in real time computer mapping, royalties, revenue,
expense, volume data and investment performance. No
financial details were disclosed. Drillinginfo in 2016 acquired
GlobalView Software and its flagship product MarketView,
which allows prices to be monitored while trading. It also in
2016 bought production forecasting assets from Ponderosa
Energy, a division of Ponderosa Advisors LLC. In January
Drillinginfo also launched a suite of oilfield services software to
improve real-time interaction between rig and permit reports.
Yuhuang Chemical Inc. (YCI) has completed an $800
million funding agreement for its planned methanol project in
St. James Parish, LA, which is being financed by the Bank
of China and other Chinese banks. Construction has begun
on the world-class methane-to-methanol facility, which is
expected to produce 1.8 million metric tons/year of commercial-grade methanol. YCI’s funding agreement represents the
largest Chinese-invested project in the U.S. Gulf Coast region
and the first U.S. construction project financed entirely by Chinese banks. The project’s three planned phases may exceed
$1.85 billion in investment.
The Federal Energy Regulatory Commission has
approved Tennessee Gas Pipeline Co. LLC (TGP) to begin
tree clearing for and construction of the Connecticut Expansion Project, approved in 2016 [CP14-529]. The project would
extend the existing pipeline in New York and Connecticut while
adding four miles of underground pipeline in Massachusetts.
Nearly two miles of the expansion is to be constructed in Otis
State Forest, adjacent to TGP’s two existing underground gas
pipelines. The forest is protected as conservation land under
Article 97 of the Massachusetts Constitution. The Kinder
Morgan Inc. pipeline recently settled with Massachusetts
authorities allowing the project to proceed.
Total Petrochemical, a joint venture of South Korea’s
Hanwha Group and France’s Total SA, plans to expand
the Desean refining/petrochemicals (continued on page 24)
NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
NATURAL GAS
Monday, April 17, 2017
NGI
INDUSTRY BRIEFS
integrated facility in South Korea to increase ethylene production capacity by 30% to 1.4 million tons/year. Daesan,
one of Total’s six world-class integrated platforms and a
strategic asset for Hanwha, includes a condensate splitter,
steam cracker and polymers, styrene and aromatics units.
“The extension will significantly increase the site’s flexibility,
enabling it to process competitively priced propane feedstock, which is abundantly available, notably due to the shale
gas revolution in the United States,” the company said. The
expansion, expected to be completed by mid-2019, would add
ethylene production for local demand and supply the nearby
fast-growing Chinese market, a significant importer. 
INTELLIGENCE
NGI's Weekly Spot Price Market Summary
Apr 10-13
Location
Range
S. TX Regional Avg.
2.72-3.12
E. TX Regional Avg.
2.75-3.22
W. TX/SE NM Regional Avg.
2.65-2.86
Midwest Regional Avg.
2.69-3.37
Midcontinent Regional Avg.
2.68-2.96
N. LA Regional Avg.
2.75-3.08
S. LA Regional Avg.
2.85-3.18
Southeast Regional Avg.
2.88-3.28
Appalachia Regional Avg.
2.30-3.08
Northeast Regional Avg.
2.40-3.40
Rocky Mtns. Regional Avg.
2.48-2.82
California Regional Avg.
2.78-3.36
National Avg.
2.30-3.40
Henry Hub
2.95-3.18
Page 24
Average
2.92
2.93
2.75
2.99
2.81
2.92
2.99
3.02
2.69
2.92
2.72
3.01
2.89
3.05
Notes: Prices in US$/MMBtu for dry gas. These regional price ranges include prices at citygates
and other market area delivery locations as well as delivered to pipeline prices for gas in producing
areas. The National Average is a simple average of all of the individual regional averages. For more
information see NGI's Price Index Methodology.
Natural Gas Intelligence is published weekly, 50 times a year by Intelligence Press, Inc. (800) 427-5747.
For breaking natural gas and shale news and more detailed pricing data, please visit us at: http://naturalgasintel.com
For a listing of all our premium newsletters and data services, please visit: http://naturalgasintel.com/premiumservices
Editor-in-Chief & Publisher: Ellen Beswick; Executive Publisher: Dexter Steis; Managing Editor: Alex Steis (e-mail:
[email protected]); Senior Editors: Carolyn L. Davis (Houston), Joe Fisher (Houston), David Bradley. Analysts:
Natural Gas Patrick Rau (NYC) and Nathan Harrison. Associate Editors: Charlie Passut, Jamison Cocklin (Pittsburgh), Jeremiah Shelor.
Intelligence Correspondents: Bill Burson (Denver), Richard Nemec (Los Angeles), Gordon Jaremko (Calgary), Dwight Dyer (Mexico City). Monday, Contact us: EDITORIAL: [email protected]; PRICING: [email protected];
April 17, 2017 SUPPORT/SALES: [email protected]; ADVERTISE: [email protected]
Volume 36 No. 34 Intelligence Press, Inc. © Copyright 2017. Contents may not be reproduced, stored in a retrieval system, accessed by computer,
or transmitted by any means without a site license or prior written permission of the publisher.
© COPYRIGHT INTELLIGENCE PRESS 2017 | NATGASINTEL.COM | NATURAL GAS INTEL | FOR A FREE TRIAL VISIT NATGASINTEL.COM
Calendar 1Q17 Earnings Conference Call Dates for Selected Publicly
Traded Oil & Gas, and Related Companies
Last Updated: April 13, 2017
Ticker
Company
SLB
BAS
NEE
HAL
Schlumberger
Basic Energy Services
NextEra
Halliburton
PDS
BHI
RRC
Coverage
Date
Time (ET)
IR Site
Business Specialty
21-Apr
21-Apr
21-Apr
24-Apr
8:30 AM
9:00 AM
9:00 AM
9:00 AM
IR Site
IR Site
IR Site
IR Site
Precision Drilling
Baker Hughes
Range Resources
24-Apr
25-Apr
25-Apr
2:00 PM
8:30 AM
9:00 AM
IR Site
IR Site
IR Site
Oil Services
Oil Services
Power
Oil Services
(Pressure Pumping)
Onshore Drilling
Oil Services
E&P
SLCA
SPN
HES
AEP
MPC
U.S. Silica Holdings
Superior Energy Services
Hess Corporation
American Electric Power Co.
Marathon Petroleum
25-Apr
26-Apr
26-Apr
27-Apr
27-Apr
9:00 AM
9:00 AM
10:00 AM
9:00 AM
9:00 AM
IR Site
IR Site
IR Site
IR Site
IR Site
Proppant
Oil Services
E&P
Power
Oil Refining
NOV
QEP
National Oilwell Varco
QEP Resources
27-Apr
27-Apr
9:00 AM
9:00 AM
IR Site
IR Site
Rig Construction
E&P
FTI
PTEN
TechnipFMC
Patterson UTI
27-Apr
27-Apr
9:00 AM
10:00 AM
IR Site
IR Site
Oil Services
Onshore Drilling
XEL
EQT
ESV
HP
MPLX
NBR
WLL
CRR
EQM
WFT
COG
XOM
Xcel Energy
EQT Corporation
Ensco International
Helmerich & Payne
MPLX LP
Nabors Drilling
Whiting Petroleum
CARBO Ceramics Inc.
EQT Midstream Partners
Weatherford International
Cabot Oil & Gas
ExxonMobil/XTO Energy
27-Apr
27-Apr
27-Apr
27-Apr
27-Apr
27-Apr
27-Apr
27-Apr
27-Apr
28-Apr
28-Apr
28-Apr
10:00 AM
10:30 AM
11:00 AM
11:00 AM
11:00 AM
11:00 AM
11:00 AM
11:30 AM
11:30 AM
8:30 AM
9:30 AM
9:30 AM
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
Power
E&P
Offshore Drilling
Onshore Drilling
Midstream
Onshore Drilling
E&P
Proppant
Midstream
Oil Services
E&P
E&P
CPN
SWN
Calpine
Southwestern Energy
28-Apr
28-Apr
10:00 AM
10:00 AM
IR Site
IR Site
Power
E&P
POR
PEG
NRG
NBL
CNX
EPD
Portland General Electric
Public Service Enterprise Group
NRG Energy
Noble Energy
CONSOL Energy
Enterprise Products Partners
28-Apr
28-Apr
2-May
2-May
2-May
2-May
11:00 AM
11:00 AM
8:00 AM
9:00 AM
10:00 AM
10:00 AM
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
PES
PNW
NBLX
APC
Pioneer Energy Services
Pinnacle West
Noble Midstream Partners
Anadarko Petroleum
2-May
2-May
2-May
3-May
11:00 AM
12:00 PM
2:00 PM
9:00 AM
IR Site
IR Site
IR Site
IR Site
Power
Power
Power
E&P
E&P
Gathering &
Midstream (NGLs)
Drilling
Power
Midstream
E&P
CPE
NI
SR
SM
Callon Petroleum
NiSource
Spire Energy
SM Energy
3-May
3-May
3-May
3-May
9:00 AM
9:00 AM
9:00 AM
10:00 AM
IR Site
IR Site
IR Site
IR Site
E&P
Utilities
Utilities, Pipelines
E&P
DVN
Devon Energy
3-May
11:00 AM
IR Site
E&P
NFX
Newfield Exploration
3-May
11:00 AM
IR Site
E&P
SO
CXO
RIG
WMB
WPZ
Southern Company
Concho Resources
Transocean
Williams Companies
Williams Pipeline Partners
3-May
4-May
4-May
4-May
4-May
1:00 PM
9:00 AM
9:00 AM
9:30 AM
9:30 AM
IR Site
IR Site
IR Site
IR Site
IR Site
ATO
DM
D
Atmos Energy
Dominion Midstream Partners
Dominion Resources
4-May
4-May
4-May
10:00 AM
10:00 AM
10:00 AM
IR Site
IR Site
IR Site
MDU
PXD
WPX
BKH
HK
MUR
OXY
MDU Resources
Pioneer Natural Resources
WPX Energy
Black Hills Corporation
Halcon Resources
Murphy Oil
Occidental Petroleum
4-May
4-May
4-May
4-May
4-May
4-May
4-May
10:00 AM
10:00 AM
10:00 AM
11:00 AM
11:00 AM
11:00 AM
11:00 AM
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
IR Site
Power
E&P
Offshore Drilling
Pipelines, Midstream
Oil & Gas Pipelines,
Midstream (NGLs)
Utilities, Pipelines
Midstream, LNG
Gathering &
Midstream
Pipelines, Utilities
E&P
E&P
E&P, Utilities
E&P
E&P
E&P
Significant Shale/Tight Sands/Resource Basin
Presence
Various
Various
Various
Various
Various
Ardmore-Woodford, Cana-Woodford,
Cleveland/Tonkawa, Cotton Valley, Granite
Wash, Marcellus, Mississippian Lime, Upper
Devonian, Utica
Various
Various
Bakken, Permian, Utica
Bakken, Cana-Woodford, Eagle Ford, Granite
Wash, Haynesville, Niobrara-DJ, Piceance,
Utica
Various
Bakken, Green River, Haynesville, Permian,
Uinta
Various
Various, but Marcellus and Permian are the
largest concentrations
Huron, Marcellus, Upper Devonian, Utica
Various
Various
Bakken, Niobrara-DJ, Permian
Various
Marcellus
Various
Eagle Ford, Haynesville, Marcellus, Utica
Ardmore-Woodford, Bakken, Duvernay,
Haynesville, Marcellus, Montney, Permian,
Fayetteville, Lower Smackover/Brown Dense,
Marcellus, New Brunswick
Eagle Ford, Marcellus, Niobrara-DJ, Permian,
Marcellus, Upper Devonian, Utica
Various
Various
Eaglebine, Green River, Haynesville, NiobraraDJ, Permian, Powder River, Uinta, Utica
Permian
Arkoma-Woodford, Bakken, Eagle Ford,
Eaglebine, Permian, Powder River
Barnett, Cana-Woodford, Eagle Ford, Horn
River, Permian, Powder River, STACK
Arkoma-Woodford, Bakken, Cana-Woodford,
SCOOP, STACK, Uinta
Permian
Various
Eagle Ford, Green River, Marcellus, Piceance,
Uinta
Barnett, Haynesville, Permian,
Marcellus, Utica
Bakken, Powder River
Eagle Ford, Permian
Bakken, Permian, San Juan
Bakken, Piceance, Powder River, San Juan
Bakken, Eaglebine, Tuscaloosa Marine, Utica
Eagle Ford, Duvernay, Montney
Eagle Ford, Permian
Ticker
Company
CLR
Coverage
Date
Time (ET)
IR Site
Business Specialty
Continental Resources
4-May
12:00 PM
IR Site
E&P
CRC
MRO
California Resources Corp
Marathon Oil
4-May
5-May
5:00 PM
9:00 AM
IR Site
IR Site
E&P
E&P
NE
PE
Noble Drilling
Parsley Energy
5-May
5-May
9:00 AM
9:00 AM
IR Site
IR Site
Offshore Drilling
E&P
ERF
EGN
XEC
CRK
Enerplus Resources Fund
Energen
Cimarex Energy
Comstock Resources
5-May
5-May
8-May
8-May
10:00 AM
11:00 AM
11:00 AM
11:00 AM
IR Site
IR Site
IR Site
IR Site
E&P
E&P
E&P
E&P
DUK
EOG
Duke Energy
EOG Resources
9-May
9-May
10:00 AM
10:00 AM
IR Site
IR Site
Utilities
E&P
GDPMQ
PAA
Goodrich Petroleum
Plains All-American Pipeline
9-May
9-May
11:00 AM
11:00 AM
IR Site
IR Site
Oil Pipelines
Significant Shale/Tight Sands/Resource Basin
Presence
Arkoma-Woodford, Bakken, Cana-Woodford,
Niobrara-DJ, SCOOP, STACK
Monterey
Bakken, Cana-Woodford, Cleveland/Tonkawa,
Eagle Ford, Granite Wash, Green River,
SCOOP, STACK
Permian
Bakken, Duvernay, Marcellus
Permian, San Juan
Cana-Woodford, Permian, STACK
Eagle Ford, Haynesville, San Juan, Tuscaloosa
Marine
Bakken, Barnett, Eaglebine, Eagle Ford, Green
River, Haynesville, Horn River, Marcellus,
Marmaton, Mississippian Lime, Niobrara-DJ,
Permian, Powder River, Uinta
Eagle Ford, Haynesville, Tuscaloosa Marine
Bakken, Cleveland/Tonkawa, Eagle Ford,
Monterey, Niobrara-DJ, Permian
*All companies listed are traded on either the New York Stock Exchange, the American Stock Exchange, or NASDAQ. Dates and
times subject to change. Note: NGI will re-run this chart over the next several Monday editions, and will add other conference call
dates as they become available.
Source: Compiled by NGI from Bloomberg and company press releases