New base 1058 special 04 august 2017 energy news

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,
or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained in this
publication. However, no warranty is given to the accuracy of its content. Page 1
NewBase August 04 2017 - Issue No. 1054 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: Saipem to set up base in Hamriyah Free Zone &
ready for ME Pipelines projects
Sharjah's Hamriyah Free Zone Authority (HFZA) has signed an investment agreement with
Saipem, a leading Italian oil and gas services company, for the latter to set up a major base in the
zone.
As per the agreement, Saipem will take up a 59,338-sq-m plot of land for the company's
operations in the Middle East and North Africa, said a Wam news agency report.
Saud Salem Al Mazrouei, director of the
Hamriyah Free Zone Authority (HFZA),
and Sharjah Airport Free Zone Authority,
said this investment is the culmination of
the HFZA’s efforts in attracting foreign
investments to the emirate of Sharjah.
He pointed out that the free zone in
Hamriyah is characterised by several
factors that make it attractive to investors.
Saipem's activities cover more than 68
countries and the company employs over
40,000 people worldwide.
Saipem in $900m new deal for Egypt's Zohr Field
Saipem, a world leader in drilling services, and Petrobel have finalised offshore contract variations
worth $900 million for engineering, procurement, construction and installation (EPCI) activities in
relation to the Optimised Ramp Up phase of the supergiant Zohr Field Development Project
situated in the Mediterranean Sea off the Egyptian coast.
Petrobel is a joint venture between Italian Egyptian Oil Company (IEOC), an Eni subsidiary in
Egypt, and Egyptian General Petroleum Corporation (EGPC) and is in charge of the development
of Zohr on behalf of PetroShorouk, a joint venture between Egyptian Natural Gas Holding
Company (Egas) and IEOC.

The current variations to the scope of work include the installation of a 30-inch diameter gas
export pipeline and an 8-inch diameter service pipeline, as well as EPCI work for the field
development in deep water (up to 1700 m) of 4 wells and the installation of umbilicals.
Works were due to commence in July and are scheduled to be completed by the end of 2018.
In order to meet the requirements set
by the client, Saipem will deploy
several vessels from its highly
specialised fleet, including the
Castorone (the latest generation
ultra-deep water pipelayer); the
subsea field development ship
Saipem FDS2; the Saipem 3000 (a
subsea construction vessel) and,
finally, the Castoro 6 and the
trenching barge Castoro 10.
“We are pleased that our activities in
the development of the Zohr field are
in line with the challenging schedule
set by the client,” said Stefano Cao,
Saipem CEO.
“In the execution of this further
phase of the development, we will
deploy our most technologically
advanced vessels and leverage our
proven abilities and skills so that the
achievement of the client’s
requirements is ensured. This
acquisition confirms and
consolidates our presence in the
Eastern Mediterranean Sea and is
yet another milestone for Saipem in
the SURF (subsea, umbilicals, risers,
flowlines) segment of offshore E&C
projects,” he said. - TradeArabia News
Service

South Asia turns LNG hot spot as demand up
Reuters
South Asia, long a backwater for energy markets, is emerging as a hotspot for liquefied natural
gas (LNG), with Pakistan and Bangladesh set to join India as major consumers, helping to ease
global oversupply that has dogged this market for years.
Only India and Pakistan currently import LNG in South Asia, taking in a combined 25 million
tonnes, or 8 per cent of global demand last year. But with a fast growing population, strong
economic growth and soaring energy demand, more import projects are being developed, lead by
Pakistan and Bangladesh.
“Both countries already have extensive gas infrastructure due to legacy production from domestic
gas fields,” said Chong Zhi Xin, principal Asia LNG analyst at energy consultancy Wood
Mackenzie. “As domestic production has failed to keep up with demand, both markets are a
natural fit for LNG imports.”
Pakistan only started importing its first LNG in 2015, and surprised some in the industry by
developing its first terminal within schedule and budget. A second is about to become operational
and a third is expected to be completed next year.

With Bangladesh set to join the club of importers next year, the region could import 80-100 million
tonnes a year by the mid 2020s, analysts said, making it the world’s second biggest import region,
ahead of Europe.
Bangladesh, a country of over 160 million people, could import as much as 2,500 million cubic feet
per day (mmcfd) of LNG, equivalent to around 17.5 million tonnes per year, by 2025, said Nasrul
Hamid, Bangladesh’s state minister for energy and power.
With its own gas reserves depleting and seeking to almost double power capacity to 24,000
megawatt (MW) by 2021, Bangladesh is tapping cheap and plentiful supplies on world markets
and investing heavily in LNG.
Several floating storage and regasification units (FSRU), the first developed by private US
company Excelerate Energy, are due to begin importing cargoes starting in 2018. “We are working
on two FSRU’s from which gas will start flowing (by) next July,” Hamid said.
Both FSRUs will be deployed off Moheshkhali Island in the Bay of Bengal, in the southeast of the
country. They will have a combined capacity of 7.5 million tonnes a year.

Canada:Indian Oil, partners to better locate PNW LNG terminal
Reuters By Nidhi Verma and Neha Dasgupta
Indian Oil Corp Ltd said it is in talks with its partners t o scout for an alternative, cheaper site for
the Pacific Northwest LNG terminal after the recent pullout of the lead developer cast doubt on the
future of the Canadian project.
Malaysia's state-owned Petroliam Nasional Bhd (Petronas) , which held a majority 62 percent
stake in the proposed C$36 billion ($29 billion) Pacific NorthWest LNG Project in British Columbia,
said last week it was abandoning the plan due to weak global prices.

Sanjiv Singh, chairman of Indian Oil, which has a 10 percent stake in the Canadian project, said
the company remained interest in going ahead with at least part of the plan.
"We are very much positive going ahead with the upstream part of it, which is gas production.
Liquefaction and transportation further in the liquid form we are not pursuing, I mean, we don't
want to pursue very aggressively as of now," he told a news conference.
"We are also looking at a different location which might be much less expensive than the earlier
one," Singh said. Indian Oil's head of business development, G.K. Satish, said consortium
partners are talking about alternatives. He declined to comment on write-offs IOC might be taking
in the next quarter for investment in the Canadian LNG project.
Petronas's pullout dealt a blow to the project and its partners which would now have to invest
additional capital to complete the project. Indian Oil is the first partner to suggest the project could
still go ahead, in modified form.
"Cost of liquefaction, transportation and retail outside Canada has gone up. And today we are
finding that it may not be very attractive at the present prices," Singh said. The other partners in
the project are Chinese oil and gas giant Sinopec, with 15 percent, Japex Montney Ltd, with 10
percent, and Petroleum Brunei, with 3 percent.
Petronas may have to write off up to $800 million for work already done on the Canadian project,
analysts say. Japan Petroleum Exploration Co (Japex) said on Wednesday it would take a loss of
about C$102 million ($82 million) due to the scrapping of the project.
Indian Oil Corp planned to lift 1.2 million tonnes of the super-cooled fuel for 20 years from the
British Columbia project for its 5 million tonne a year regasification LNG plant at Ennore in eastern
India. Indian Oil was expecting deliveries from the western Canadian project to begin in 2020.
The company said it also expected a "slight delay" from Cameron LNG project in the United
States and will see deliveries by the end of 2018.
Indian Oil will float a tender to import 2 million barrels of high sulphur U.S. crude in August. It
intends to import high sulphur oil from the United States for as long as benchmark WTI prices are
depressed, Finance Director A.K. Sharma said.
The company's net profit fell 45 percent in its fiscal first quarter of 2017, beating analysts'
estimates, although higher inventory losses and lower refining margins weighed on profitability.
Net profit was 45.49 billion rupees ($714.83 million) in the quarter ended on June 30, compared
with 82.69 billion rupees a year earlier, the country's top refiner said. Analysts on average had
expected a net profit of 30.63 billion rupees for the first quarter, Thomson Reuters data showed.
India's top refiner suffered an inventory loss - due to sudden changes in oil and refined product
prices - of 40.4 billion rupees in the June quarter compared to a gain of 74.8 billion rupees a year
ago, Sharma said.
The company's quarterly average gross refining margins, or profit earned on each barrel of crude
processed, fell to $4.32 per barrel, compared with $9.98 per barrel in the same period last year.
IOC's shares closed 4.6 percent up and was the top percentage gainer on the broader Nifty 50
index.

Indonesia Asks Chevron, Conoco to Consider Extending Oil Licenses
By Irina Slav for Oilprice.com
The Indonesian government has approached Chevron and Conoco with an offer to consider
extending their licenses, which expire in a few years, as part of efforts to boost domestic crude oil
production.
Chevron has been present in Indonesia since 1924 and is currently responsible for 40 percent of
the country’s oil output, which makes it the biggest single producer of crude. The Energy and
Mineral Resources Minister of Indonesia has asked the company to consider how it is going to
proceed with its local operations beyond 2021, when its license expires.
ConocoPhillips, which suspended operation at
its South Jambi gas field two years ago, has
been asked to consider extending its license
for the field. At the moment, Conoco is not
producing any oil and gas in Indonesia
following field depletion and is considering
options. Jakarta has also asked Exxon to
consider building a refinery in Indonesia or
relocating a facility from Singapore as
Indonesian fuel demand grows.
According to Bloomberg, Jakarta’s approach to
the majors aims to secure early agreements on their operation licenses, to show prospective
foreign investors that Indonesia is investor-friendly. The need to reassure investors comes from a
long row with miner Freeport-McMoRan: Jakarta wants Freeport and other miners to process
copper and other metals locally, and miners have not been too willing to start investing in
processing facilities. To force them, the government has threatened to revoke their licenses.
Yet Jakarta needs foreign investments in oil and gas, as well as in mining. Earlier this year, media
reported that the country was ambitiously planning to bring in $200 billion in new oil investments
as local production declines and demand grows. As part of the plan, Bloomberg reports, Jakarta
will allow foreign energy companies to bid for 14 oil and gas blocks, all untapped, sweetening the
deal with incentives such as tax-free imports of equipment and technology.
Over the next seven years, Jakarta plans to increase local oil refining capacity to half a million
barrels daily, but even so, it may need to import up to 50 percent of the fuels it needs. To date,
Indonesia produces around 800,000 bpd of crude and imports another 500,000 bpd, plus 800,000
bpd of refined products.

US:How the Shale Race May Be Harming the U.S. Oil Trove
By Giacomo Tognini
The frantic shale race may be causing some long-term damage to assets in the Permian and
other major U.S. oil fields.
As production from wells rapidly declines, drillers are rushing to add new ones at a faster pace in
order to keep increasing output. The problem is that drilling multiple wells closer together is
contributing to the drop in established ones, and sometimes causing harm that can’t be fixed.
Output from legacy wells -- a term that in the fast-pace shale world includes those that are just a
month old -- is dropping by 350,000 barrels a day every month and has fallen steeply since 2012,
according to data from the U.S. Energy Information Administration.
Unlike offshore wells in the Gulf of Mexico, which can produce for decades, shale wells can peak
within months and sometimes cease after two years. Eager explorers may undercut the life of
wells by over-drilling, said Russell Clark, investment manager at Horseman Capital Management
Ltd. So-called frack hits occur when drilling in one well interferes with another, causing a pressure
transfer that can disrupt or stop production.
"New well production is increasingly cannibalizing legacy production," Clark wrote in a report. "The
decline rate looks to be accelerating." It’s a trend particularly acute in the prolific Permian basin in
West Texas and New Mexico.

Companies such as ConocoPhillips say it’s up to producers to give wells drilled in the area their
best chance to succeed.
"You can drill too fast in these unconventional plays," said Alan Hirshberg, executive vice
president of production drilling at ConocoPhillips, in a conference call last week. "We get
ultimately much better recoveries and avoid causing damage to an area that you can’t go back
and fix very easily."
The oil downturn has forced producers to find creative solutions to keep drilling in a world of lower
prices. Some of those cost-cutting strategies, such as packing wells more densely and closer
together, are now causing major headaches.
Another risk from the boom is that shale producers have been spending more than they make for
a decade, aided by a flow of money from investors. But that has encouraged companies to focus
on ramping up production at the expense of profitability, according to a report released last week
by Wood Mackenzie Ltd.
That could worsen a global supply glut and push down oil prices, leading to an outflow of finance
that may jeopardize the entire industry.
"At some point debt investors start to worry they will not get their capital back and cut lending to
the industry," Clark said. "Even a small reduction in capital would likely lead to a steep fall in U.S.
production."

NewBase August 04 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices dip on high OPEC supplies, rising U.S. production
Reuters + NewBase
Oil markets were little changed on Friday, with U.S. crude remaining below $50 per barrel,
restrained by rising output from the United States as well as producer club OPEC.
U.S. West Texas Intermediate (WTI) crude futures CLc1 were at $48.95 per barrel at 0707 GMT,
down 8 cents, or 0.1 percent, from their last close and set to drop 1.5 percent for the week.
Brent crude futures LCOc1, the international benchmark for oil prices, were at $51.92 a barrel,
down 9 cents, or 0.2 percent, from their last close and set to drop 1 percent for the week.
Traders said prices were pressured by rising output, although strong demand prevented bigger
drops. "Developments this week have seen some pessimism return to markets," National Australia
Bank said in its August outlook.
"We forecast Brent to trade at around $53 per barrel in Q4 2017," it said.
Barclays bank said "we expect a downward (price) correction during this quarter," but see Brent at
an average of $54 per barrel during the fourth quarter.
Crude oil exports by the Organization of the Petroleum Exporting Countries (OPEC) rose to a
record high in July, according to a report by Thomson Reuters Oil Research this week. July's
26.11 million barrels per day (bpd) in exports marked a rise of 370,000 bpd, most of which came
from Nigeria, which posted a rise of 260,000 bpd in shipments.
The rise came despite the group's pledge to restrict output by 1.8 million bpd until March 2018
together with some non-OPEC producers, including Russia.
Oil price special
coverage

But output in Russia is also high. Russia's largest oil producer Rosneft (ROSN.MM) said on Friday
its crude oil output grew by 11.1 percent year-on-year in the second quarter of 2017 to 56.08
million tonnes.
Average daily oil production, however, declined by 1.2 percent in the second quarter compared to
the first quarter and stood at 4.57 million bpd, the company said, citing "the limitations for the
Russian oil producers related to the agreements with the OPEC+ countries".
In the United States, oil production has hit 9.43 million bpd, the highest since August 2015 and up
12 percent from its most recent low in June last year. Preventing prices from falling further is
strong demand. U.S. gasoline demand rose to a record 9.842 million bpd last week, according to
government data this week.
"Gasoline demand is now +0.1 percent (year-on-year). This is reasonably encouraging given it
had been flat or negative since late November 2016," U.S. investment bank Jefferies said.
"Gasoline inventories in the U.S. fell for the seventh consecutive week ... and are now only 6.3
million barrels above the 5-year average," it said.
Oil Two-Minute Auction
Iraq’s state oil marketing company, known as SOMO, conducted its first-ever auction in April,
when it sold two million barrels of Basrah Light grade for June loading. The company has sold
another four million barrels each of Basrah Light and Basrah Heavy since, with its most-recent
sale attracting 17 bidders and 25 bids in a two-minute window. The September-loading heavy
cargo was sold at $1.37 a barrel more than its official price, a bigger premium than for an August
shipment.
The relatively higher price signaled healthy demand for the variety as Saudi Arabia, the world’s
biggest oil exporter, focuses on curbing medium-heavy crudes as part of a pact with other
producers to rein in the global glut. It also contributed to a rise in Iraqi official prices against
competing Saudi Arabian grades, according to a Bloomberg survey of five traders who participate
in the Middle East oil market.
“Middle Eastern producers have traditionally referenced Saudi Arabia’s official prices when setting
their monthly offer prices,” said Driscoll, who has spent more than 30 years in the petroleum

trading industry in Singapore. “As Saudi Arabia now tries to rein in a global oil glut with its own
independent strategy, other producers may be more inclined to find alternative ways to value their
barrels.”
Through its sale on the DME, SOMO received an independent assessment of the value of its
crude, which it can use to set its official selling price, he said.
Last month, SOMO reduced its official selling price for Basrah Light by a smaller margin than
Saudi Arabia cut its similar-quality Arab Medium. Iraq also increased the cost of Basrah Heavy by
more than Arab Heavy was raised. The spread between Basrah Light and Arab Medium has
widened to its highest level since September 2012, while the discount of Basrah Heavy to Arab
Heavy has narrowed to the smallest in six months.
Shipping Restrictions
Still, it’s not always viable for producers to sell their supplies via auctions. Some cargoes from
Kuwait, for example, are restricted in terms of where they can be shipped. That means buyers
would be limited in their ability to transport the crude. Some suppliers could also have
requirements related to credit and legal terms that participants cannot meet. Additionally, sellers
may not have the option to auction because they have already committed all their volumes under
long-term contracts.
Under the DME’s guidelines, sellers provide details on the type of crude, quantity, delivery and
other specifications such as the floor price, date and duration of the auction. Buyers who’ve
registered with the exchange can participate. While the process -- conducted via an electronic
platform -- doesn’t reveal the identity of those participating, their real-time price offers are
available for everyone to see and outbid.
“The auction will accomplish in a few minutes what could take hours or even days during a
traditional tender process, and potentially reach a much wider base of counterparties and a fair
access to spot cargoes to all term lifters and customers,” said Mayssam Hamadeh, head of
marketing at DME. “Additionally, the audit trail provided by an electronic auction process is
increasingly important to many companies.”
Better Value
Auction sales also help producers unload cargoes relatively quickly if they become available
because of unexpected incidents such as refinery outages. Offering crude via auctions is also part
of their effort to enhance their trading expertise and become more nimble as competition
increases in an oversupplied market. National oil companies such as SOMO and Kuwait
Petroleum Corp. are entering into partnerships with international trading houses.
Brent crude, the benchmark for more than half the world’s crude, was trading at $52.54 a barrel in
London by 6:36 p.m. Singapore time. West Texas Intermediate, the U.S. marker, was at $49.76 in
New York. Both are still more than 50 percent below their 2014 peaks as the market oversupply
persists.
“Traditional marketing approaches from the Middle East is going to start to evolve into a more
trading practice,” said Richard Gorry, managing director at industry consultant JBC Energy GmbH.
“With producers now looking to auction off more cargoes into a trader market, they feel that they
may better understand the value of their crude oil.”

Supply Situation
U.S. crude stockpiles fell by 1.53 million barrels to 481.9 million, the lowest level since December,
the EIA data showed. Analysts surveyed by Bloomberg had estimated a 3.1-million-barrel draw.
Crude production increased by 20,000 barrels a day to 9.43 million.
Gasoline supplies dropped 2.52 million barrels to 227.7 million, a seventh weekly decline.
Demand for the motor fuel jumped by 21,000 barrels a day to 9.84 million, a record-high. U.S.
gross refinery inputs also a hit a record-high level in the week ended July 28.
"The market has been laser-focused on crude stocks and gasoline demand," Andrew Lebow,
senior partner at Commodity Research Group, said by telephone. "What’s amazing is that
gasoline stocks are drawing despite the fact that we’re running.
Crude Oil Price Forecast August 4, 2017, Technical Analysis
ByChristopher Lewis
WTI Crude Oil
The WTI Crude Oil market initially tried to rally on Thursday, but found significant resistance at the
$50 level again, and has rolled over as we approach to that level. I believe that the sellers are
coming back into the marketplace, and we will more than likely see oil drop from here. I have a
target of $47.50 underneath, and less we break above the $50.25 level above, which will see the
markets continue to go higher.
I believe that the market is more bearish though, because quite frankly, the higher oil goes – the
more likely we are to see increased American production. If the US dollar strengthens after the
jobs report today, that could also put bearish pressure on oil.
Brent
Brent markets reached towards the highs again at the $53 level, but then fell just as the WTI
market did. I believe that if we drop from here, we should probably go looking towards the $51
level next. A breakdown below there should have the market looking for the $50 handle, and I
believe that could be our target.
The market should continue to see bearish pressure in general, as the oversupply issues
continue. I think that the crude oil markets are towards the top of the longer-term consolidation
that we have been in for some time now, so it makes sense that the sellers would return.
Keep in mind that the US dollar will be volatile today during the economic announcements coming
out, so we could get choppy behavior. However, unless we can break above the $53 level, I don’t
have any interest in buying this contract as I think it is getting a bit heavy. Either way, I expect
there to be plenty of opportunities to go back and forth during the day with the economic releases.

NewBase Special Coverage
News Agencies News Release August 04 2017
New U.S. DOE Report Shows How Utilities Can Avoid Risky
Investments ( Guidelines for GCC )
By: Silvio Marcacci - a Communications Director at Energy Innovation, where he leads all public relations and communications efforts.
It’s no secret rising demand for clean electricity has upended America’s utility sector, making
building new fossil fuel generation a difficult proposition. But a related challenge caused by this
trend is challenging utilities – the need for flexible planning and procurement to avoid risky
investments.
Utilities previously accustomed to a business model of making capital investments and paying
them off over decades with stable economic and policy considerations, must now build in
adaptivity and frequent updates to their planning process to avoid “driving blind” on procurement.
The pace of change in today’s energy markets demands it.
A new study commissioned by the U.S. Department of Energy and conducted by Lawrence
Berkeley National Laboratory outlines this imperative. The study finds shifting state policies,
evolving customer demand, and difficulty siting coal generation forced dramatic differences
between the resources Western U.S. utilities envisioned in their Integrated Resource Plans (IRPs)
and the resources they actually procured.
From 2003 to 2014, 12 utilities across the Western Interconnection added natural gas and wind
instead of coal, adding three times more wind capacity than originally planned for in their IRPs .
While these utility IRPs accurately forecast demand across their service territories (estimated ~20
gigawatts [GW], installed ~18 GW), their procured supplies widely diverged from forecast
additions. By 2015, the utilities expected to meet new demand with 20% coal, 35% natural gas,
and 15% wind, with 25% undefined – but actual procurements totaled approximately 50% wind
and 50% natural gas.

Chart via Lawrence Berkeley National Laboratory
Total incremental actual (procured) and planned nameplate capacity by resource and split by
contracts and self-builds for 12 Load Serving Entities in the West
Long-term planning runs into unprecedented change
IRPs evolved to expand utility planning and review processes to provide more information to
regulators and better understand power supply, demand, and cost uncertainty. But renewable
energy cost declines have been consistently underestimated, while policy uncertainty and siting
difficulties changed in unforeseen ways between the Bush and Obama administrations, making
predicting the future harder than ever for utilities.
For the 12 utilities covered in DOE’s research, long-held assumptions changed dramatically in a
decade – state renewable portfolio standards required cleaner electricity supplies, long-term
industrial customer demand changed, and building new coal generation became difficult because
of environmental and permitting challenges. To fill this gap, the utilities bet on natural gas
generation self-builds, along with wind energy power purchase agreements (PPAs) and self-
builds.
The long-term trend from coal to clean isn’t news. Coal fell to 30% of America’s power mix in 2016
from 42% in 2011, typically replaced by some combination of natural gas and renewables
(wind roughly doubledover this span).

U.S Energy Information Adminstration
US utility-scale electric capacity additions and retirements 2002-2016
The new lesson is that in an energy landscape defined by uncertainty, IRPs must account for
multiple scenarios to evaluate potential changes and plan for a wide range of outcomes to meet
shifting regulatory goals and customer demand. Predicting the future is nearly impossible, but the
more potential market and policy changes integrated into an IRP, the more clarity it provides
utilities and regulators.
Risky Bets Won’t Always Pay Off
The 12 utility IRPs largely predicted natural gas prices would fall toward the end of their forecast,
and encouraged more natural gas self-builds than planned starting around 2007. But more than
80% of the new natural gas capacity deployed was built before prices actually dropped in 2009 –
meaning utilities placed their bets without knowing actual prices.
In this case the utilities bet right, but building long-term generation on a hunch natural gas prices
would remain low was risky at best. While fracking made natural gas cheap by the time the plants
came online, historic fuel price volatility created a high degree of uncertainty and could easily
convert large investments like these into stranded assets.
The utility IRPs bet wrong on renewables, but wind energy filled the gaps left by expensive coal,
through far larger wind contracts and slightly greater wind self-builds than planned. Three utilities
in the study (Idaho Power, PacifiCorp, and PGE) wound up with greater demand than expected,
and for all three, “much larger than anticipated procurement of wind is a common trait.” Idaho and
PGE procured 2-3 times more wind than planned, and PacifiCorp didn’t plan for any wind, but
wind made up more than half its added generation.

As cost and policy dynamics changed for these utilities, wind energy became the easiest and
often cheapest option to supply customers .
Rather than locking themselves into long-term infrastructure investments that may not remain
profitable years later, the utilities met demand through a mix of PPAs with wind developers or by
building their own wind farms.
Forward-looking utilities are moving in this direction – New Mexico utility PNM’s latest
IRPannounced it will stop burning coal by 2031 in favor of renewables and natural gas to lower
costs, and Ohio-based AEP is building a $4.5 billion wind farm because it says wind carries far
less risk than fossil fuel generation.
Utility investments based on inflexible long-term plans meet unexpected trends
The key problems utilities faced in DOE’s study are occurring across America. Once-
reliable industrial customer demand forecasts are shifting as costs decline for demand-side
energy management and renewable energy technology. Environmental concerns and policy
uncertainty slow generation siting and contractual obligations. Rising renewable portfolio
standards require more clean electricity. None of these trends were mainstream forecasts in the
early 2000s.
Image via Lawrence Berkeley National Laboratory

Projected RPS demand by US region 2016-2030
These trends aren’t unnoticed – Utility Dive’s 2017 State of the Electric Utility Survey found utilities
most confident in the growth of large-scale renewables and distributed energy resources – but
according to DOE’s research, being hemmed in by long-term or inflexible IRPs fails to “create
useful information for the procurement process.”
So what’s a utility executive or state regulator to do?
DOE’s research shows “most information produced in the planning phase is generally discounted
from the procurement phase.” To overcome this challenge, DOE suggests utilities focus on
demand forecasts and least-cost/risk portfolios during their IRP processes, and rely “extensively
on the most recent information available” when making procurement decisions. In addition, DOE
recommends state regulators avoid making IRPs more complex in response to technological
changes and carefully define the links between IRPs and procurement.
Energy Innovation analysts recommend IRPs use (or at least analyze) the most recent publicly
available data to determine cost or deployment projections for evolving technologies, require data
representative of current information to triangulate projections with multiple sources, and increase
flexibility through an iterative approach to improving and revising projections. IRPs should also
include a range of demand and procurement forecasts with a wide range of cost assumptions
under different policy settings, i.e. what mix of renewable energy would be needed to meet a high
RPS target or what mix of peaking generation or transmission would be needed for reliability in a
high-renewables scenario.
By combining flexible planning with current and accurate data, utilities can take advantage of the
dynamic energy landscape to provide reliable electricity supply from the low-carbon generation
sources customers increasingly want, without risking long-term stranded assets.

iea has released its Natural Gas Information 2017
Production
In 20161, 3,613 Billion cubic metres (Bcm) of natural gas were produced globally, a 0.8% increase
compared to 2015. Natural gas production has risen every year since the economic crisis of 2009;
however the increase in 2016 (+29.1 Bcm) is the smallest in this period.
Out of the additional 29.1 Bcm produced in 2016, 23.1 Bcm were produced in countries that do
not be- long to the OECD or non-OECD Europe/Eurasia, highlighting the importance of new
producers in the market.
The share of these countries in the global production more than doubled since 1990, rising from
16.8% to 39.5%. However, the trend in production varies across different countries in the OECD
and non-OECD Europe/Eurasia.

In the OECD, overall, natural gas production rose by 0.4% (fr the fall in the United States (-17.3
Bcm) and OECD Europe (-3.1 Bcm).
In non-OECD Europe/Eurasia, the growth in Russia (+5.9 Bcm) and Uzbekistan (+1.1 Bcm) offset
the falls in Turkmenistan (-3.9 Bcm), Romania (-1.2 Bcm) and Kazakhstan (-0.9 Bcm). In 2016,
this entire region produced 874 Bcm, the same volume as in 2015. This stabilization, with growth
elsewhere, resulted in a decrease of 0.2 percentage points in the region’s share of the global
supply (24.2% in 2016).
The production in the members of the Gas Exporting Countries Forum (GECF)2 increased by
1.5%. Most of the additional volumes were produced in Algeria (+10.0%), the Russian Federation
(+0.9%) and Iran (+3.0%), which increased their production by 8.4 Bcm, 5.9 Bcm and 5.5 Bcm.
Overall GECF produced 1 330 Bcm (36.8%. of global supply), slightly above the OECD (36.3%).
In other non-OECD countries outside the GECF, production increased by 0.4%, up to 973 Bcm.
Saudi Arabia, the People’s Republic of China, Indonesia, Argentina, Malaysia and Peru
experienced the biggest increases. The share of global production of these countries has grown
from 19.8% in 1990 to 26.9%.

Analysis of individual countries’ production shows a range of factors implying changes in 2016.
Within the OECD:
• Australia continued the growth shown last year. In 2016, more LNG projects were
commissioned and this new export capacity enhanced production, which increased by 21.0
Bcm in 2016. Australia was the 10th largest natural gas producer in the world in 2016.
• After the sustained growth of the last few years in the United States (production increased
by 47.8 Bcm and 33.1 Bcm in 2014 and 2015 respectively) natural gas production fell in
2016 (-17.3 Bcm). This is the first annual decrease since the beginning of the shale gas
revolution.
• In the United Kingdom and Norway, production remained almost stable in 2016 with a small
increase of +0.2 Bcm in both countries.
• In the Netherlands, the cap in gas production established by the government at the major
Groning- en gas field in response to the risk of earth quakes continued in 2016, resulting in
a new decrease in their L-gas production (-4.1 Bcm).
• The gas output in Mexico continued falling due to the decline in associated gas from legacy
oil and gas fields (-4.9 Bcm).

• In Ireland, where almost all the gas consumed used to be imported from the UK, the
production jumped to 3.0 Bcm (almost 60% of the natural gas consumed in the country)
after natural gas extraction from the Corrib Gas field began at the end of 2015 and
continued through 2016.
Among non-OECD countries:
• Algeria led the increase outside the OECD, sup- plying to the market 8.4 Bcm more than in
2015. In 2016 it produced 92.4 Bcm, the highest in its history, and became the eighth
largest producer.
• In Iran production has grown every year in the last two decades. Since 2006, it grew at an
average rate of 5.7% per year. In 2016, the increase rate was smaller (3.0%). This country
is the world's third largest natural gas producer since 2014.
• China, which surpassed Norway as the sixth largest producer in 2013, continues to
increase its production but at a slowest rate than in the early 2000s. For the last 10 years,
production has grown at an average rate of 8.9% per year but in 2015 and 2016 the
increases were smaller, of 3.4% and 1.7% respectively.
• Qatar, the fifth largest producer of natural gas, showed a small increase of 0.8% in
2016 (+1.3 Bcm).
• Turkmenistan’s production decreased for the first time since 2009 by 4.7% (-3.9 Bcm).
• Nigeria’s production also fell in 2016 (-5.7% and -2.5 Bcm).
The top five natural gas-producing countries (United States, Russia, Iran, Canada and Qatar)
together represented 53.2% of the world’s production.
Imports
Imports by pipeline to OECD Europe rose by 17.7 Bcm in 2016, consolidating the region’s position
as the world’s largest importer. OECD Europe represented over 50% of the pipeline trade in the
World.
This increase was mostly due to increases in imports in two of the main producers in the area: the
UK (+21.5% to balance the increase in demand) and the Netherlands (+13.3%, mainly due to the
decrease in production).
In addition, pipeline imports to Italy, the third largest consumer in the region after Germany and
the UK, also increased (+6.1%) to meet the growing demand. The additional pipeline imports into
Europe were sourced mainly with Algerian and Russian gas (+11.1 Bcm and +20.3 Bcm).
With the growth in consumption and production in most of the European countries declining or
remaining stable, the region became more dependent on imports from countries outside the
OECD. In 2016 for the first time, countries in OECD Europe produced less than 50% of the gas
they consumed.
OECD Americas also increased their pipeline imports for second year in a row (+17.6 Bcm). This
was largely due to the decline in Mexican production and a small increase in demand, resulting
in a need to import by pipeline from the United States (+28.1%). Pipeline imports to the United
States from Canada also increased (+10.9%).

Compared to the situation in OECD Europe, the increase in pipeline trade in OECD Americas is
purely between members of the OECD. In addition, Chile exported by pipeline re-gasified LNG to
Argentina for the first time in 2016, after the works to enable reverse flows in the interconnector
were finished.
Outside the OECD there are different trends across the regions. While in Africa and non- OECD
Asia ( excluding China ) imports by pipeline remained stable, in non- OECD Europe/Eurasia they
fell by 7.1 Bcm, especially in Ukraine where due to the severe economic recession, it fell by
33.7%.
Pipeline imports decreased slightly in the Middle East driven by the 19.8% fall in Iran where
production grew more than consumption, decreasing its dependency on imports. Similarly, in non-
OECD Americas the decrease in Brazil (-20.2%) drove the decline in the region. Finally, the
largest growth for the pipeline imports of a single country was in the People’s Republic of China,
where an estimated additional 8.3 Bcm were imported in 2016 (+25%) to supply its increasing
demand.
Within the OECD, LNG imports remained fairly constant in 2016. There were small decreases in
OECD Americas (-1.4 Bcm) and OECD Europe (-0.5 Bcm), and an increase in OECD Asia
Oceania (+2.8 Bcm) after the substantial fall in 2015.
Mexico and the UK, which saw big increases in pipeline imports, drove the decline of LNG
imports in the OECD Americas and OECD Europe respectively. On the other hand, both Japan
and Korea increased their imports by almost 2% receiving from Australia 10.2 Bcm more than in
2015.

Despite the decrease in imports from Qatar (-7.1 Bcm), it is still the main supplier of LNG
for the OECD, with a 24.1% of the total share. However, Qatar is no longer the main supplier of
OECD Asia Oceania after being surpassed by Australia, the second largest source of LNG for the
total OECD.
Australia also supplied, for the first time, to OECD Americas (Mexico), showing its increasing
relevance in the global LNG market. In addition, many other new routes appeared in the LNG
trade in 2016. In particular, the United States, which became a net exporter of LNG in 2016,
supplied a total of 5.3 Bcm to more than 13 different destinations.
In 2016, non-OECD countries continued importing more LNG than previous years and they
accounted for one third of the global LNG imports. Since 2006, when OECD countries represented
90.3% of the total market, non-OECD LNG imports increased at an average rate of 18.3% per
year.
This growth was mainly pushed by Asia, in particular by China and India. In 2016, these two
countries imported 5.9 Bcm and 4.8 Bcm of LNG more than in 2015 and they were the third and
fourth largest LNG importers of the world respectively (the People’s Republic of China was 9th
and India 7th in 2010).

LNG imports also increased in Africa and the Middle East, mainly in Egypt (+3 Bcm), Jordan (+1.2
Bcm) and the United Arab Emirates (+0.5 Bcm). In contrast to OECD countries, imports from
Qatar to non-OECD countries increased by an estimated 8.1 Bcm in 2016.
In non-OECD Americas, LNG imports fell in Brazil and Argentina (-4.2 Bcm and -0.9 Bcm
respectively) driving the imports of the region down by 37.1%.
Demand
In 2016, global demand for natural gas increased by 2.7% compared to 2015, rising up to 3 648
Billion cubic metres.
In 2016, OECD natural gas demand was 3.1% higher than in the previous year. In OECD Europe,
where consumption rose by 6.4%, the increase was concentrated in the largest consumers of
the region: the UK (+9.6 Bcm), France (+5.1 Bcm), Germany (+4.8 Bcm), and Italy (+3.4 Bcm).
Despite the lack of published disaggregated annual demand data, the main factor for this increase
in Europe was gas-fired power generation, especially in the UK, where the Carbon Price Floor

contributed to the coal-to-gas switch, and in France to compensate the drop in nuclear power
generation. On the other hand, Turkish natural gas demand decreased by 3.3% (-1.6 Bcm) in
2016 following a decrease in 2015 as a consequence of the national policies to decrease Turkish
dependency on imports.
An increase was also registered in OECD Americas, 1.1% in the entire region, mainly driven by
the growth in the United States (+ 11.6 Bcm), where power generated from natural gas also
increased (+3.4% electricity generated from natural gas, based on annual electricity data). In
OECD Asia Oceania natural gas demand raised again (+10.5 Bcm) after the decrease in 2015.
In non-OECD countries, natural gas demand increased as well (+2.3%). Non-OECD countries
consumed more than the OECD since 2008, but 2016 is the second year when the growth rate is
smaller outside than inside the OECD, closing the gap between the two regions.
Different trends characterized the demand growth since 1990 across regions: OECD Americas,
OECD Europe, OECD Asia/Oceania, non-OECD Europe/Eurasia and the rest of the World
(special case for China):
• In OECD Americas consumption grew steadily between 1990 and 2000 when it
stabilized around 800 Bcm for 10 years. In 2010 demand growth re- sumed until 2016,
when it hit the record of 975 Bcm.

• In OECD Europe, the increase was sustained until the year 2005, when it stabilized
between 540 Bcm and 560 Bcm until 2008. Then, it fell reaching 458 Bcm in 2014.
Despite growth in the last three years, it is still far from the levels previous to the economic
crisis in 2009. Currently, demand levels are similar to 2002. In addition to economic driv-
ers, improvements in energy efficiency in major gas consuming sectors, such as space
heating also contributed to slower demand growth.
• In OECD Asia/Oceania, demand also increased steadily until 2007 when it remained
almost constant for three years before growing again in 2010 (driven by demand growth in
Korea) and 2011 (driven by the decrease in nuclear power generation after the
Fukushima accident in Japan). Since then, it oscillated around 225 Bcm.
• In non-OECD Europe/Eurasia, the natural gas consumption remained fairly constant after
1994.
• Finally, in the rest of the World, natural gas consumption showed a strong average
growth rate of 6.1% per year in the last 20 years. This trend has been even stronger in
China, where the average increase rate was of 12.8% per year in the same period.

At a country level, significant increases in natural gas demand were registered in 2016 for the
People’s Republic of China (+8.0% reaching 207 Bcm) and Russia (+2.5% and +11.0 Bcm).
Additional noteworthy increases were also observed in Iran (+4.2 Bcm), India (+4.0 Bcm), the
United Arab Emirates (+3.3 Bcm) and Egypt (+3.3 Bcm).
On the other hand, natural gas demand decreased in Brazil (-5.7 Bcm), Kazakhstan (-2.4 Bcm),
Ukraine (-1.7 Bcm) and Uzbekistan (-0.9 Bcm).
Detailed demand data by sector, available to 2015, show non-OECD demand increasing, mainly
in the largest natural gas-consuming sector, the heat and power generation (+1.6%, equivalent to
13.1 Bcm). This was the case in the People’s Republic of China (+23.8%), Iran (+16.4%) and
Saudi Arabia (+21.8%). This growth offset the decrease in the Russian Federation (-8.9%) driven
by the shorter heating season in 2015. In addition, natural gas is becoming more relevant in the
heat and power generation sector and it is replacing coal and oil in some countries.
In the OECD, natural gas demand for power generation increased more significantly than in non-
OECD countries in 2015 (+7.3%). Mainly pushed by low prices that allowed natural gas to
compete with coal fired generation in the United States, it increased by 16.6% (+41.4 Bcm). This
growth was much slower in Europe (+1.6% and 2.1 Bcm). In OECD Asia/Oceania, it decreased, in
particular in Japan (-6.8%), where the gas-fired power generation fell in 2015 for the first time
since the Fukushima accident
in 2011.
Other major natural gas
consuming sectors showed
different behaviours in 2015
in the OECD and non- OECD
countries.
In 2015 the industry sector
showed a decrease in natural
gas consumption in both
OECD and non-OECD
countries. This decrease was
mainly driven by the chemical
sector in the OECD. In the
residential and commercial
sectors demand figures
showed opposite trends in
the OECD, where it declined,
and in non- OECD, where it
grew. Consumption in the oil
and gas extraction increased
globally and it fell significantly
only in Egypt and Thailand, where natural gas production decreased compared to 2014.
Regarding road transport, the increase is mainly outside the OECD, with China and Iran leading it
(they represent 39.5% and 15% of the global natural gas consumption for road transport
respectively).
The trends also differ among OECD regions. Whereas in OECD America the consumption in the
residential sector decreased substantially (-1.3 Bcm in Canada and -13.1 Bcm in United States), it
increased in OECD Europe, mainly driven by the largest countries like Germany (+1.7 Bcm), Italy
(+2.2 Bcm), Turkey (+1.7 Bcm) and the UK (+1.3 Bcm). A similar trend is observed in the

commercial sector where OECD Eu- rope registered an increase of 3.2 Bcm and in OECD
Americas it fell by 8.3 Bcm.
The chemical and petrochemical sector saw an overall decrease in natural gas consumption,
however the trend is very different for the energy use (-5.4 Bcm) and the non-energy use (+0.9
Bcm). In the United States, the biggest consumer of natural gas for the chemical and
petrochemical sectors, natural gas burned to support its activity decreased (-2.5 Bcm) while the
natural gas used as a feedstock in this sector increased (+0.8 Bcm).
Similarly, in Russia and India, the energy use consumption of natural gas in the chemical and
petrochemical sectors remained constant but the non-energy use increased by 1.7 Bcm and 1.8
Bcm respectively. On the contrary, in China energy use fell by 3.3 Bcm and non- energy use by
2.5 Bcm, resulting in the biggest decrease at a country level.
Prices
In 2016, natural gas import prices by pipeline fell by 28.2% for European Union members, while in
the United States they fell by 23.0%. As such, the gap between these two prices continued closing
in 2016, showing a stronger convergence than in the previous year. However, the price for the

American market remained much lower than the European one, at 2.14 US dollars/MBtu vs. 4.93
US dollars/MBtu.
LNG import prices showed a similar
pattern, with a general decrease
observed in all regions, notably in
the US (-44.7%). After converging
in 2014, LNG prices in Europe and
the US remained in line in 2016
again whilst in Japan and Korea the
gap between their LNG import
prices and those for the US and
Europe continued to narrow. This
convergence is partially driven by
the increase in global liquefaction
capacity, especially in Australia.
The LNG price for the American
market was below that of the
European one but much higher than
the pipeline import price, at 3.99 US
dollars/MBtu. The price in Europe
was of 4.78 US dollars/MBtu,
slightly lower than the price of
pipeline imports, showing the
competitive- ness of LNG as a source of imports for Europe. In Japan and Korea, the two largest
LNG importers, the weighted average price was higher, 7.04 US dollars/MBtu.
The LNG market continued its globalization in 2016, with 18 countries with liquefaction capacity
operating and 40 countries with regasification capacity. Colombia, Jamaica, Finland and Poland
commissioned their first re-gasification LNG terminal.

Type: Statistics Publications and CD-ROMs
431 pages
ISBN PRINT 978-92-64-27814-1 / PDF 978-92-64-27815-8
Subject: Natural Gas ; Statistics ;
Available for pre-ordering. The PDF file will be available mid-August, the print version and CD-
ROM early September.
Natural Gas Information is a detailed
reference work on gas supply and demand
covering not only the OECD countries but
also the rest of the world; this publication
contains essential information on LNG and
pipeline trade, gas reserves, storage
capacity and prices. The main part of the
book concentrates on OECD countries,
showing a detailed supply and demand
balance for each country and for the three
OECD regions: Americas, Asia-Oceania
and Europe, as well as a breakdown of gas
consumption by end user. Import and export
data are reported by source and
destination.
Natural Gas Information is one of a
series of annual IEA statistical
publications on major energy
sources; other reports are Coal
Information, Electricity
Information, Oil
Information and Renewables
Information.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Your partner in Energy Services
NewBase energy news is produced daily (Sunday to Thursday) and
sponsored by Hawk Energy Service – Dubai, UAE.
For additional free subscription emails please contact Hawk Energy
Khaled Malallah Al Awadi,
Energy Consultant
MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
ASME member since 1995
Hawk Energy member 2010
Mobile: +97150-4822502
khdmohd@hawkenergy.net
khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 27 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 2017 K. Al Awadi

New base 1058 special 04 august 2017 energy news

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Similar to New base 1058 special 04 august 2017 energy news

Similar to New base 1058 special 04 august 2017 energy news (20)

More from Khaled Al Awadi

More from Khaled Al Awadi (20)

Recently uploaded

Recently uploaded (20)

New base 1058 special 04 august 2017 energy news