New base energy news 27 august 2018 no 1196 by khaled al awadi-compressed

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NewBase Energy News 27 August 2018 - Issue No. 1196 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
UAE's ADNOC in advanced talks to sell refinery stakes: sources
Reuters - Clara Denina, Stephen Jewkes, Dasha Afanasieva
State-owned Abu Dhabi National Oil Co (ADNOC) is in advanced talks with more than one potential
buyer, including Italy’s ENI, as it prepares to sell minority stakes in its refining business, two sources
familiar with the matter said.
ADNOC began a wide-ranging shake-up in 2016 to tackle competition from new producers such as
U.S. shale firms. It listed 10 percent of its fuel distribution business last year and aims to expand its
downstream business abroad.
The company also started a sale process for a stake in its $20 billion refining business, which the
sources said it was likely to split between two or more parties.
One said that ADNOC would favor companies it already has partnerships with, including ENI and
Austrian oil and gas group OMV.
OMV works with ADNOC on a number of projects, including a 40-year agreement for a 20 percent
stake in the SARB and Umm Lulu offshore oil concession. ENI has a 10 percent stake in its Umm
Shaif and Nasr offshore oil concession and a 5 percent stake in Lower Zakum.
“This strategy would give ADNOC the chance to bring in these companies’ money and expertise
without having a dominant partner,” the source said.

An ENI spokesman said the company does not comment on market rumors. OMV was not
immediately available to comment.
A second round of offers is expected to be presented as soon as next week, when the Gulf returns
from a religious holiday, both sources said.
“ADNOC is looking for long term strategic partners that will contribute real value, such as: know
how, differentiated technology, smart capital and market access,” an ADNOC spokesman said.
Such partners would help the company grow in “strategic destinations,” he said, adding that ADNOC
has received “significant interest” from both new and existing partners.
ADNOC has partnerships with France’s Total and PetroChina, among others.
ENI, the biggest foreign oil producer in Africa, is looking to build its presence in the Middle East to
diversify risk and take advantage of business opportunities in the oil-rich region.
One of the sources said it is using U.S. investment bank Morgan Stanley to help with the offer for
ADNOC’s stake.
Morgan Stanley declined to comment.
Reporting by Clara Denina, Stephen Jewkes and Dasha Afanasieva; additional reporting by Rania
El Gamal in Dhahran; Editing by Elaine Hardcastle and Rosalba O'Brien

GCC: Coal seen as cost-competitive alternative to gas
Oman Observer - Conrad Prabhu
MUSCAT, AUG 25 – Competing demands on natural gas as a fuel resource for power generation,
on the one hand, and as feedstock for industrial investments, on the other, are among the factors
underpinning the Gulf region’s nascent embrace of coal as an alternative resource, according to an
Omani scholar.
Dr Aisha al Sarihi (pictured), a specialist in energy and climate affairs, says that coal is also seen
as a cost-competitive alternative to gas and other power sources as some
Gulf states move to conserve natural gas for industrial and other value-
generating investments.
Her comments are set out in an insightful paper titled, ‘Why Oil and Gas-
Rich Gulf Arab States are Turning to Coal?’ published by the prominent
think-tank, The Arab Gulf States Institute in Washington (AGSIW).
Although blessed with a nearly a third of proven world crude oil and around
a fifth of global natural gas reserves, some GCC states in this resource-
rich region are switching to coal to augment electricity generation,
according to Dr Aisha.
Dubai, for instance, is making headway in the construction of the Gulf’s first coal-fired power plant
— the 2,400 MW Hassyan project — in Saih Shuaib. The Emirate is also weighing plans for a
second coal-powered scheme as part of the Dubai Clean Energy Strategy 2050.
Likewise, the Sultanate of Oman has already launched a competitive bid process for the
development of the nation’s first coal-based power plant — a 1,200 MW capacity scheme — planned
in the Special Economic Zone at Duqm.
“Securing enough energy to meet surging domestic demand and maintaining energy export levels
over the long term while also pursuing ambitious economic diversification strategies present a triple
policy challenge to the hydrocarbon-dependent economies of the Gulf states, especially with the
drop in oil prices since mid-2014,” said Dr Aisha, a visiting scholar at the Arab Gulf States Institute
in Washington, in her paper.
According to the expert, the GCC states
are experiencing an “extraordinary surge
in energy consumption”, with their overall
energy demand rising on average some 5
per cent per annum during the 2000s.
“Between 2003 and 2013, regional
electricity consumption increased at an
average rate of 6-7 per cent per annum —
faster than anywhere else in the world.
Nearly 50 per cent of all electricity
produced in the Gulf states goes to the
residential sector, with air-conditioning
accounting for a considerable portion of
demand.
Given the highly subsidised power sector,
per capita electricity consumption in the

Gulf countries is also substantial: more than 10,000 kilowatt-hours per person in 2014,” she pointed
out.
“Consequently, gas demand across the Gulf states has grown two-and-a-half fold since 2000, with
almost two-thirds of this growth coming from power generation alone,” she stated.
This burgeoning gas demand, Dr Aisha points out, threatens to come in the way of the GCC states’
ambitions to pursue economic diversification, notably through investments in gas-based industrial
and petrochemical projects.
“Against this background, it makes sense for the Gulf states to free up natural gas either for export
or industrial expansion. Therefore, the provision of additional energy becomes ever more important.
Indeed, considering this triple energy-policy challenge, all of the Gulf Arab states are now pursuing
fuel-mix diversification strategies, including the development of renewable energy, nuclear power,
and most recently coal,” she noted.
Coal’s appeal to some Gulf states, over alternatives like renewables and nuclear power, is linked to
its cost-competitiveness relative to these alternatives, according to the scholar. The average
Levelised Cost of Electricity (LCOE) places coal-based generation ($0.05 per kWh) significantly
lower than the corresponding average for alternatives like gas-based power generation ($0.02 –
0.05 per kWh), solar ($0.11 – 0.47 per kWh) or nuclear (around $0.15 per kWh).
“It is even cheaper than the lowest recorded cost of utility-scale solar photovoltaic (PV), which was
$0.06 per kWh in Dubai in 2014. Further, it takes less time to construct coal-fired plants, which
means that gas or diesel can be freed up and used very quickly for other purposes such as industrial
expansion or sales in the international market,” Dr Aisha stated.
On the flipside, the paper looks at the implications of the transition to coal-power for climate change
and global warming. The characterisation of coal-based technology as “clean” is still unclear, the
author points out. She stresses, in this regard, an emphasis on energy efficiency and further reform
of fossil fuel subsidies to help conserve natural gas as a valuable resource.

On planning - Oman plans 1,200MW clean-coal power project
The Sultanate is firming up plans for the development of the nation’s first Independent Power Project
(IPP) based on clean-coal technology — adding to a diversifying energy mix that will include solar
photovoltaic (PV) based renewables and potentially waste-to-energy schemes as well.
On Sunday, the Oman Power and Water Procurement Company (OPWP) — the sole procurer of new
power generation and water desalination capacity under the Sector Law — issued a Request for
Qualifications (RfQ) inviting international developers to submit their technical qualifications as the first
step in a competitive tender for the development of the landmark project at Duqm in Wusta Governorate.
The maiden coal-based scheme will have a capacity of around 1,200 megawatts (MW), OPWP said.
The move underscores an energetic effort by Oman’s authorities to end the dominance of natural gas
as the principal fuel source for power generation and water desalination in the Sultanate.
By offsetting gas consumption via investments in renewable and alternative energy sources, the
government aims to divert any gas volumes saved in the process into value-adding manufacturing and
petrochemicals based activities.
The launch of the competitive process for the development of a coal-based IPP comes on the back of a
techno-feasibility study conducted by Finland-based international consulting and engineering services
firm Pöyry on OPWP’s behalf. Pöyry’s remit was to evaluate the feasibility of establishing a first-ever
privately funded, coal-based IPP in the Sultanate.
At a press briefing hosted by OPWP late last year, Yaqoob Saif Hamood al Kiyumi, CEO, confirmed that
the techno-feasibility study had been completed and its findings placed before the government for its
consideration.
Importantly, the proposed scheme will be executed on a Build-Own- Operate (BOO) basis, mirroring the
methodology currently in place for the execution of conventional natural gas-based power projects.
Duqm has long been seen as ideally positioned to host a coal-based power plant Duqm because of its
enabling characteristics. This includes the presence of a modern port, adjoining Special Economic Zone,
and ample land for future expansions, if any.
Further, with plans for an interconnection between the Main Interconnected System (MIS) serving North
Oman and the Dhofar Power System in the south, Duqm will be eventually incorporated into a national
interconnected system, it is pointed out. OPWP has set last June 7, 2018 as the deadline for the receipt

Indian coal imports surge despite rising prices, today at 120 $/T
The National + AFP + NewBase
India's coal imports appear headed for another strong month in August, raising the question as to
why the usually cost-sensitive market hasn't scaled back purchases given a surge in prices to the
highest in nearly seven years.
Total coal imports may reach 17.7 million tonnes in August, according to vessel-tracking and port
data compiled by Thomson Reuters.
This figure may be revised as it becomes clearer when ships will arrive and discharge their cargoes,
but the August imports are likely to be more or less in line with the 17.4 million tonnes imported in
July, which was the strongest monthly outcome so far in 2018.
But no matter what the exact level of imports turns out to be, India's coal imports have been
exceptionally strong and are on track to rise for the first year in three in 2018.
This is despite prices for thermal coal rising to the highest in six and a half years, with the Australian
benchmark Newcastle cargoes trading above $120 a tonne recently, taking the year-to-date gain to
around 18 per cent.
The gain in prices has been largely driven by strong Chinese imports, partly because of output
restrictions at domestic mines and partly because of high demand caused by a recent heatwave.
Previously Indian coal imports, especially for thermal grades used to generate electricity, have been
thought to be sensitive to price, and likely to decline if prices moved rapidly higher, as they have
done this year. But Indian imports have been on an upward trend in recent months, despite the
rising prices.
An easy answer as to why is to point to the recent difficulties state miner Coal India has experienced
in transporting the polluting fuel from pits to power plants. But as Tim Buckley, director of energy
finance studies at the Institute for Energy Economics and Financial Analysis (IEEFA), pointed out
in a recent note, there is more to the situation.

Data from India's Central Electricity Authority show that coal imports for what are termed on-grid
power plants, ie those that supply power to the network, are actually declining, falling 14 per cent in
the June quarter. So, as far as thermal coal imports for the power sector are concerned, the price
signal is working insofar as they are declining as prices rise.
However, as Mr Buckley notes, a large part of India's coal imports are used by consumers other
than on-grid power plants.
There is a about 30 gigawatts (GW) of coal-fired generation capacity that is used by captive power
plants, Mr Buckley said in a recent paper sent to Reuters. These users include aluminium smelters,
cement makers and other industrial users, and they are more reliant on coal imports as their demand
isn't prioritised by Coal India, effectively meaning they are last in line for domestic supplies.
If this 30 GW was run at 61 per cent capacity, it would need about 96 million tonnes of thermal coal
a year, Mr Buckley said, a figure that represents about two-thirds of current thermal coal imports.
Given these consumers have to run their captive power plants in order to produce their goods, they
have no option but to turn to imports when Coal India can't meet their needs. Thus, it appears that
as much as two-thirds of India's current coal import demand is from buyers that aren't price sensitive.
This likely means that coal imports will remain robust, at least for as long as Coal India is struggling
to meet the needs of the various consumers of the fuel.
This dynamic of captive
power-plant users
importing coal also
appears to be shifting the
buying patterns of India. In
the first seven months of
the year, India's coal
imports totalled 112.5
million tonnes, with
Indonesia the largest
supplier at 43.4 million.
However, Indonesia's
share of imports is
declining, running at 38.6
per cent of the total so far
in 2018, down from 43.8
per cent for the whole of
2017.
In contrast, South Africa's share of Indian imports in the first seven months of 2018 rose to 18.1 per
cent, from 17.1 per cent for 2017, while that of the United States rose to 9.6 per cent from 7.1 per
cent. South Africa and the United States supply higher grades of coal with greater energy content
than Indonesia.
It makes sense for captive-power plant buyers in India to seek higher quality coal as it maximises
the output from their plants. Australia's share of India's imports is also up, rising to 23.9 per cent in
the first seven months of 2018 from 22.6 percent in 2017.
However, virtually all of Australia's exports are coking coal, used in steel-making, and the increase
is likely a reflection of rising domestic steel production, as well as the paucity of Indian supplies of
this higher-grade type of coal.

Norway: Big Oil's Exit Turns Into Revival for Aging North Sea
Bloomberg - Mikael Holter
BP, Shell, Exxon, Total have all taken steps back from Norway
Back in 2015, Royal Dutch Shell Plc and BP Plc cast doubt over the future of aging oil fields offshore
Norway. A crash in crude prices and high operating costs threatened to shut them early, leaving
millions of barrels in the ground.
Two of the fields, Draugen and Valhall, have since fallen into the hands of smaller, local companies,
and they’re now expected to keep producing well into the 2040s.
The recovery in oil prices is certainly helping. But the turnaround also shows how the changing
make-up of Norway’s oil industry is putting assets in the hands of new companies willing to invest
billions of dollars in projects discarded by the majors. Oil and gas fields that got a new operator
since 2010 have had a higher reserve growth compared to the average in Norway, according to
Oslo-based consulting firm Rystad Energy AS.
New Kids on the Block
Norwegian oil and gas fields with new operators see higher reserve growth
Sources: Rystad Energy and Norwegian Petroleum Directorate
Notes: Figures cover fields that got a new operator since 2010; the national average reserve growth
is weighted according to field size

The shift, evident also in the neighboring U.K., will be a key topic of discussion at the ONS
Conference, which kicks off in Stavanger on Monday.
The fierce competition between projects in the global oil majors’ portfolios got even more intense
after crude fell in 2015. That meant even profitable fields got bumped down their priority list, making
them available for smaller companies that also had more time and capacity to take a deeper look at
how to improve returns.
"If you have a global portfolio, you need some form of mechanism to allocate your capital," Karl
Johnny Hersvik, Chief Executive Officer of Aker BP, said in a interview last month. "If you only have
one portfolio with a few assets to look after, you’re more focused on each individual asset."
While Big Oil’s retreat is creating some concerns in Norway’s largest industry and in government
offices, the positive aspects “very clearly” outweigh the negative, said Norway’s Petroleum and
Energy Minister Terje Soviknes.
“We’re getting players that have the ability and willingness to bet on the Norwegian shelf,” he said
in an interview this month. “It doesn’t help to have the big ones as operators on the Norwegian shelf
if the capital is going to other projects anyway.”
Price Pressure
The collapse in crude prices forced the biggest companies to narrow their focus on higher-return
projects, such as U.S. shale or liquefied natural gas ventures. This meant that Norway, with its aging
North Sea province and disappointing Arctic exploration, fell off their radar.
Through mergers or asset sales, BP, Shell, Exxon Mobil Corp. and Total SA have all taken a step
back from Norway’s offshore, leaving smaller and more specialized companies in charge, often
backed by private equity.

A landmark transaction was the 2016 merger of BP’s Norwegian unit with Det Norske Oljeselskap
ASA, creating Aker BP ASA. The company plans to more than double its output, to 330,000 barrels
of oil equivalent a day in 2023, potentially making it the third-biggest producer in Norway after state-
controlled Equinor ASA and Petoro AS. Part of this new output will come from Valhall, where Aker
BP aims to produce 500 million barrels, an additional to the 1 billion already sold.
Exxon sold its operated fields to a unit of Norway’s private-equity firm HitecVision AS, which then
agreed to merge with Eni SpA’s Norwegian subsidiary. Eni retains 70 percent of the new company,
Var Energi AS, which plans to invest $8 billion over the next five years, including on Exxon’s former
fields, Ringhorne and Balder, which have been in production since 1999.
In a 4.52 billion krone ($540 million) deal, Shell is set to transfer operatorship of Draugen to OKEA
AS, a private equity-backed company which prides itself on its focus on smaller fields. It plans to
produce from Draugen into the 2040s, beyond the 2036 target that Shell warned it might not meet.
Neptune Energy Group Holdings Ltd., another PE-backed company, has made Norway a priority
after buying Engie SA’s fossil-fuel unit and Verbundnetz Gas AG’s local subsidiary.
“We may not have seen the level of investment in existing fields and legacy producers like Valhall
and Balder and Ringhorne without these deals,” said Neivan Boroujerdi, an analyst at consultant
Wood Mackenzie Ltd. “These are good examples of getting assets into the right hands.”
Capex Rebound
Spending in Norway’s oil industry is expected to rise this year for the first time since 2014, and will
get a further boost next year, according to the latest figures from the country’s statistics office.
Norway’s recovery wouldn’t have been as dynamic without the new entrants, said both the
Petroleum Minister and Rystad analyst Simon Sjothun.
Highlighting the success of the new entrants, BP’s decision to keep its exposure through its 30
percent stake in Aker BP has paid off: the shares it got in the new company have more than tripled
in value since the deal. Brokers from UBS to Exane BNP Paribas compared Eni’s deal with Hitec to
Aker BP immediately after it was announced, suggesting the Italian major might be seeking to
replicate the success.
Yet it’s not all rosy. Even if the super-majors stay invested in Norway through minority stakes in
companies and fields, losing the focus of their top managers and engineers could leave Norway
with limited access to the industry’s deepest pool of talent, Sjothun said.
Smaller companies also means less financial muscle when the time will come to decommission
offshore installations. Norway has already taken steps to ensure taxpayers aren’t left with the bill by
warning Big Oil it can’t escape responsibility even by leaving.

U.S:Permian region is expected to drive U.S. crude oil production
growth through 2019 .. by:U.S. EIA, Short-Term Energy Outlook, August 2018
EIA’s August Short-Term Energy Outlook (STEO) forecasts that U.S. crude oil production will
average 10.7 million barrels per day (b/d) in 2018 and 11.7 million b/d in 2019. If realized, both of
these forecast levels would surpass the previous record of 9.6 million b/d set in 1970.
This national increase is almost entirely driven by tight oil. In particular, the Permian region in
western Texas and eastern New Mexico is expected to account for more than half of the growth in
crude oil production through 2019.
EIA expects Permian regional production to average 3.3 million b/d in 2018 and 3.9 million b/d in
2019. Although favorable geology combined with technological and operational improvements have
contributed to the Permian region becoming one of the more economically favorable regions for
crude oil production in the United States, recent pipeline capacity constraints have dampened
wellhead prices for the region’s oil producers. Lower wellhead prices in the region are contributing
to slower growth in Permian crude oil production in 2019 compared with 2018.
EIA forecasts Federal Offshore Gulf of Mexico (GOM) production to grow by 158,000 b/d in 2019 to
average 1.9 million b/d, making this region the second-largest contributor to STEO’s forecast growth
from 2018 to 2019.
The forecast growth is driven by the ramping up of 2 new fields that started producing in 2017, the
anticipation of 10 new fields starting up in 2018, and 6 new fields coming online in 2019. These 18
fields are expected to contribute 480,000 b/d of the total 1.9 million b/d of GOM production in 2019.

EIA expects the Bakken region to hit record-high production in 2018, averaging 1.3 million b/d and
growing to 1.4 million b/d in 2019. Although the Bakken region is geographically large, spanning
approximately 200,000 square miles in North Dakota and Montana, it contains fewer identified
producing formations and is significantly more affected by winter weather than the Permian. The
recent production growth in the Bakken has been supported by the removal of pipeline capacity
constraints that affected the region before 2017.
EIA forecasts production in the Eagle Ford region in Texas to increase by about 105,000 b/d from
2018 to 2019 to average 1.5 million b/d. The Eagle Ford region covers a smaller geographic area
with fewer prolific formations and fewer opportunities to drill compared with the Permian region.
However, the Eagle Ford region does not have the same pipeline capacity constraints as the
Permian region. EIA anticipates that producers may move away from the Permian in mid-to-late
2018 and in 2019 into the Eagle Ford while the Permian region pipeline transport is constrained.
EIA expects Niobrara and Anadarko regional production to average 670,000 b/d and 550,000 b/d,
respectively, in 2019. EIA forecasts that drilling activity will continue increasing in both of these
regions through 2019, although at a slightly slower rate than in 2017 and 2018.
EIA expects production in Alaska to remain steady, averaging 480,000 b/d in 2018 and 2019. In the
rest of the United States, EIA expects production to decline slightly (by 81,000 b/d) as a result of
drilling activity that is insufficient to offset declining output from currently producing wells. If crude
oil prices continue to increase, these areas could become more profitable, spurring the pace of
drilling.

NewBase August 27 - 2018 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil slightly dips, but stable as trade row weighs, Iran to cut supply
Reuters+ Bloomberg + NewBase
Oil prices fell on Monday on concerns the U.S.-China trade dispute will erode global economic
growth, although looming U.S. sanctions against Iran’s oil sector kept crude from falling further,
traders said.
International Brent crude oil futures LCOc1 were at $75.63 per barrel at 0654 GMT, down 19 cents
from their last close. U.S. West Texas Intermediate (WTI) crude futures CLc1 were down 30 cents
at $68.42 a barrel.
Trading activity was limited due to a public holiday in Britain, traders said.
“Falling U.S. rig counts and last week’s decline in U.S. inventories are supporting oil prices amid a
protracted U.S.-China trade war that could dampen global growth and weigh on oil demand,” said
Stephen Innes, Head of Trading for Asia-Pacific at futures brokerage OANDA in Singapore.
Oil price special
coverage

U.S. energy companies cut nine oil drilling rigs last week, dropping to 860, the biggest reduction
since May 2016, energy services firm Baker Hughes said on Friday.
“Despite growing concerns about potential oversupply, the markets will continue to get a fillip from
U.S. sanctions against Iran,” Innes added.
Washington will target Iran’s oil exports with sanctions from November.
OPEC-member Iran has exported around 2.5 million barrels per day of crude oil so far this year.
Most analysts expect this figure to fall by at least 1 million bpd once sanctions kick in.
U.S. Rigs Decline at Fastest Pace Since 2016
Oil held gains above $68 a barrel as drilling-rig data signaled slowing growth in American crude
production and as the U.S. and Mexican governments neared a breakthrough on a trade standoff.
Futures in New York were little changed, following a 1.3 percent gain on Friday. Working oil rigs in
the U.S. fell by nine to 860 last week, the biggest drop since May 2016, according to Baker Hughes
data released Friday. Meanwhile, America and Mexico are poised to resolve their bilateral
differences over the North American Free Trade Agreement as soon as Monday after breakthroughs
on issues including automobiles and energy.
Oil in New York has traded below $70 as a trade war between the U.S. and China, coupled with the
threat of contagion from the Turkish currency crisis, has weighed on prices. Still, slowing U.S. output

growth and pipeline bottlenecks are adding to supply risks as the Trump administration is set to
impose sanctions on crude exports from Iran in early November.
“Falling U.S. rig counts and last week’s decline in U.S. inventories are supporting oil prices amid a
protracted U.S.-China trade war that could dampen global growth and weigh on oil demand,” said
Stephen Innes, head of trading for the Asia Pacific region at Oanda Corp. “Despite growing concerns
about a potential oversupply, the markets will continue to get a fillip from U.S. sanctions against
Iran.”
West Texas Intermediate crude for October delivery traded at $68.61 a barrel on the New York
Mercantile Exchange, down 11 cents, at 10:04 a.m. in Tokyo. The contract rose 89 cents to $68.72
on Friday. Total volume traded was about 63 percent below the 100-day average.
Brent for October settlement traded at $75.76 a barrel on the London-based ICE Futures Europe
exchange, down 6 cents. Prices on Friday added 1.5 percent to $75.82. The global benchmark
crude traded at $7.14 premium to WTI.

NewBase Special Coverage
News Agencies News Release August 16-2018
U.S. natural gas pipeline exports increase with commissioning of
new pipelines in Mexico by: U.S. EIA, Natural Gas Monthly, and Federal Energy Regulatory
Commission
U.S. natural gas pipeline exports to Mexico have been increasing following expansions of cross-
border pipeline capacity. These exports averaged 4.2 billion cubic feet per day (Bcf/d) in 2017 and
4.4 Bcf/d through the first five months of 2018. Based on data compiled by Genscape, natural gas
exports to Mexico by pipeline exceeded 5 billion cubic feet per day (Bcf/d) for the first time in July
2018, after the commissioning of several key pipelines in Mexico.
By the end of 2018, an additional four of six major pipelines identified as strategic in Mexico’s five-
year natural gas infrastructure expansion plan are scheduled to begin commercial operations.
These newly commissioned pipelines will transport U.S. natural gas farther into Mexico’s central
and southern regions and provide an additional outlet for constrained Permian production in western
Texas. Natural gas exports from the United States will help meet growing demand from Mexico’s
natural gas-fired power generation and industrial sectors, offsetting declines in Mexico’s domestic
production.

Currently, about three-quarters of U.S. natural gas pipeline exports to Mexico flow from southern
Texas. Exports from southern Texas averaged 3.2 Bcf/d in 2017 and 3.3 Bcf/d through the first five
months of 2018. This natural gas is sourced primarily from the Eagle Ford Basin in Texas and
transported on an existing pipeline network to serve industrial and power sector customers in
northeastern Mexico.
Source: U.S. Energy Information Administration, Natural Gas Monthly, and Federal Energy Regulatory Commission
Exports from western Texas, however, have been limited, despite a significant increase in cross-
border pipeline capacity from 2015 to 2017. Exports from western Texas averaged only 0.4 Bcf/d in
2017 and 0.5 Bcf/d in January–May 2018.
Significant delays in construction of the connecting pipelines on the Mexican side of the border have
led to relatively low utilization of cross-border pipeline capacity from western Texas. Some pipelines
in Mexico have been delayed by more than a year from their original expected in-service dates, in
part because of disputes contesting pipeline routes.
Several key pipelines in Mexico were placed in service earlier in 2018. La Laguna-Aguascalientes
(1.2 Bcf/d) and Villa de Reyes-Aguascalientes-Guadalajara (0.9 Bcf/d) are scheduled to begin
commercial operations in November 2018 after the interconnect at El Encino-La Laguna is
completed in October. These pipelines will transport natural gas from western Texas into central
and western Mexico through the Ojinaga-El Encino and Tarahumara pipelines.
Natural gas from these pipelines may displace some imports of liquefied natural gas (LNG) at
Manzanillo LNG terminal and will serve markets in Guadalajara, Mexico’s second-largest city.

Samalayuca-Sásabe (0.5 Bcf/d capacity) is scheduled to begin commercial operation in November
2018 and will primarily serve new natural gas-fired power plants in western Mexico.
Source: U.S. Energy Information Administration, based on Mexico's Secretaría de Energía Status of Pipelines (in Spanish), IHS Markit,
Genscape, and trade press
Note: Click to enlarge.
Additional export capacity from southern Texas totaling 3.0 Bcf/d will begin commercial operations
later this year. The U.S. Valley Crossing (also called Nueces-Brownsville) pipeline (2.6 Bcf/d
capacity) will connect to Mexico’s Sur de Texas-Tuxpan underwater pipeline. Both pipelines are
expected to be placed in service in October 2018.
However, pipelines at the other end of this underwater pipeline have been delayed. The Tuxpan-
Tula pipeline (0.9 Bcf/d capacity), which connects Sur de Texas-Tuxpan to markets in central
Mexico, is delayed and is not expected to begin commercial operation until 2020. Another pipeline
near Mexico City—Tula-Villa de Reyes (0.9 Bcf/d)—has been delayed until 2019. Until these
pipelines begin commercial operations, the high-demand market around Mexico City is expected to
continue to be served by existing pipeline infrastructure transporting natural gas from southern
Texas.
Principal contributor: Victoria Zaretskaya

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khdmohd@hawkenergy.net
khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 28 years of experience in
the Oil & Gas sector. Currently working as Technical Affairs Specialist for
Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy
consultation for the GCC area via Hawk Energy Service as a UAE operations
base , Most of the experience were spent as the Gas Operations Manager in
Emarat , responsible for Emarat Gas Pipeline Network Facility & gas
compressor stations . Through the years, he has developed great experiences
in the designing & constructing of gas pipelines, gas metering & regulating
stations and in the engineering of supply routes. Many years were spent drafting, & compiling gas
transportation, operation & maintenance agreements along with many MOUs for the local
authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE
and Energy program broadcasted internationally, via GCC leading satellite Channels.
NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE
NewBase August 2018 K. Al Awadi

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New base energy news 27 august 2018 no 1196 by khaled al awadi-compressed

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