New base energy news 24 november issue 1298 by khaled al awadi

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,
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NewBase Energy News 24November 2019 - Issue No. 1298 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Acwa, GIC consortium wins Dubai 5th phase solar park deal
Business Arabia + NewBase
A consortium led by Acwa Power and Gulf Investment Corporation has been named the preferred
bidder to build and operate the 900MW 5th phase of the Mohammed bin Rashid Al Maktoum Solar
Park by the Dubai Electricity and Water Authority (Dewa).
The park will generate solar power using photovoltaic (PV) solar panels based on the independent
power producer (IPP) model, said a Wam news agency report.
Dewa has achieved a world record by receiving the lowest bid of $1.6953 cents per kilowatt hour
(kW/h) for this phase. Dewa released the tender for the 5th phase in February 2019, and received
60 requests for qualifications, said Saeed Mohammed Al Tayer, managing director and CEO of
Dewa.
"We are striving to achieve the vision of His Highness Sheikh Mohammed bin Rashid Al Maktoum,
Vice President and Prime Minister of the UAE and Ruler of Dubai, to transform Dubai into a global
hub for clean energy and green economy.

We also support the Dubai Clean Energy Strategy 2050 to provide 75 percent of Dubai’s total
power output from clean energy by 2050 and make Dubai the city with the lowest carbon footprint
in the world.
To achieve this, Dewa launched several leading renewable projects, including the Mohammed bin
Rashid Al Maktoum Solar Park, the largest single-site solar park in the world. Using the IPP
model, it will have a capacity of 5,000MW by 2030 with investments totaling Dh50 billion," said Al
Tayer.
"The 900MW 5th phase of the solar park using PV solar panels based on the IPP model will
become operational in stages starting Q2 of 2021. The project documents, Power Purchase
Agreement (PPA), and financial close agreements will be signed in due course," added Al Tayer.
The projects at the Mohammed bin Rashid Al Maktoum Solar Park, the largest single-site solar
park in the world, are of great interest to international developers and reaffirms investor
confidence in the major projects that are supported by the Government of Dubai.
Dewa has attracted huge investments to the UAE from the private sector and foreign banks,
leading to increased cash flow to the economy of Dubai and the UAE. The Current total production
capacity of solar projects at the solar park is 713MW. Dewa is building three other projects with a
total capacity of 1,250MW. The 900MW 5th phase of the solar park will increase the production
capacity to 2,863MW.

UAE: Abu Dhabi receives bids for planned 2GW solar scheme
The National + NewBase
Abu Dhabi utility firm, Emirates Water and Electricity Company (EWEC), received bids for a
planned 2 gigawatt solar photovoltaic project being developed in the Al Dhafra region of the
emirate.
The company, a subsidiary of Abu Dhabi Power Corporation, tendered financing, construction,
operation and maintenance packages for the solar plant in July, for which 24 firms pre-qualified to
bid. An award is expected in the first quarter of next year, the company said.
An aerial view of the 1.7GW Noor Abu Dhabi project which started commercial operations in June. Wam
"A range of international energy sector experts" and international consortia submitted bids on the
scheme, a company spokesman said, declining to specify a number.
The project, which will be built via an independent power producer (IPP) model, will be spread
across an area of 20 square kilometres and could provide electricity to 110,000 households
across the UAE, according to EWEC. IPPs are typically not owned by the state but build and
operate power plants for the sale of electricity to buyers, which could include a utility, the
government or end users.
No details were available on the number of phases over which the project will be developed or the
potential commercial start date for the plant. The company spokesman said further details will be
made available following the award of the contract next year.
The UAE accounts for 4 per cent of global oil output, much of it from producing fields in Abu
Dhabi. The emirate has begun diversifying its energy mix, adding solar and nuclear sources to its
grid, as it looks to free up its hydrocarbons for the export markets.

The planned 2GW PV
project follows the
start-up in June of the
1.7GW Noor Abu
Dhabi plant. That
project, built at a cost
of Dh3.2 billion, is a
joint venture between
Abu Dhabi Power
Corporation, Japan's
Marubeni and China's
Jinko Solar.
EWEC was created
earlier this year
following a presidential
decree, replacing Abu
Dhabi Water and
Electricity Company as
part of efforts by the
utility regulator, Federal Electricity and Water Authority, to consolidate power and water
generation assets across the emirate.
Bidders on the Dhafra solar scheme were also offered "an optional bid" for battery storage
following "substantial market interest", the company said. The option would allow for an expansion
of storage capacity from the existing six-hour, 108 megawatts available in the Abu Dhabi grid. The
company declined to comment on battery storage capacity that would be built for the scheme.

India Modi makes biggest privatisation push in decade to spur economy
Bloomberg + NewBase
India’s Prime Minister Narendra Modi is putting the flagging economy back on centre stage after
announcing the biggest privatisation drive in more than a decade and making renewed attempts to
ring fence the crisis-ridden shadow banking sector.
The country is in the midst of a deepening slowdown amid waning consumption – the bedrock of
the $2.7tn economy.
And while Modi has targeted transforming India into a $5tn economy by 2025, of late, most of his
attention has been focused on asserting a more muscular foreign policy and placating the Hindu
majority – his main voting base – by scrapping autonomy in India’s lone Muslim-majority state of
Jammu and Kashmir.
On Wednesday, Indian authorities went into overdrive. The government decided to sell its entire
stake in the country’s second-largest state refiner, and its biggest shipping company. It also
approved a proposal to pare stakes below 51% in some companies and pushed for an
introduction of a new industrial code bill.
Meanwhile India’s central bank seized a troubled shadow lender to try and contain defaults from
spreading in Asia’s third-largest economy.
“This is Modi’s renewed attempt to instill confidence in India’s economic potential,” said Priyanka
Kishore, head of India and Southeast Asia Economics at Oxford Economics, Singapore.
She added it was imperative for the Modi government to announce these measures as it attempts
to bridge a widening fiscal deficit following the dismal tax collections and cuts to corporate tax
rates worth $20bn.

Earlier this month Moody’s Investors Service cut the country’s sovereign debt outlook to negative
amid concerns over slowing growth and revenues.
After winning a second consecutive term earlier this year promising rapid economic development,
Modi is realising his popularity and support going forward hinges on passing tough reforms that
unleash growth – and create jobs – in Asia’s third-biggest economy.
The economy expanded 5% in April to June, the slowest in six years and a far cry from 8% seen
just a year ago. Modi is seeking to raise a record Rs1.05tn from asset sales. He has so far has
resisted big-ticket privatisation and restricted sales of its holdings to other state companies,
including the Rs369.2bn ($5.14bn) sale of Hindustan Petroleum Corp to the biggest explorer Oil &
Natural Gas Corp last year.
Now his administration is selling the government’s entire stake in Bharat Petroleum Corp and
Shipping Corp of India Ltd.
“The government’s steep $15bn – 5% of its total revenues – disinvestment target in FY’ 20 may in
our view need to be higher given the recent cut in the corporate tax rate and policymakers’ focus
on macro stability,” said Gautam Chhaochharia, head of India research at UBS Securities India
Pvt Ltd, Mumbai.
The administration’s focus on getting the economy back on track comes as it plans to offer 324
companies including Tesla Incand GlaxoSmithKline Plc incentives to set up factories in a bid to
capitalise from the trade war between China
and the US.
India has jumped 14 places to 63rd in the
World Bank’s annual rankings for ease of
doing business, rolled back a levy on foreign
funds, injected $10bn into sick banks and
relaxed foreign direct investment rules in
coal mining, contract manufacturing and
single-brand retail trading.
The Reserve Bank of India is also poised to
cut rates further after having delivered 135
basis points of rate reductions so far this
year. On Wednesday, it moved to seize
control of a second non-bank lender, Dewan
Housing Finance Corp, stepping up efforts
to contain the economic fallout from the
nation’s shadow banking crisis.
The year-long crisis in the shadow banking sector has snowballed to become a drag on
consumption and pulled down overall growth.
“While the markets will view this as positive, the move also goes to deflect the investor attention
away from the government’s non-economic agenda,” said Prakash Sakpal, Economist with ING
Bank NV in Singapore.
“Despite massive stimulus both the RBI and government has unleashed this year, the economy
continues to be stifled as will be shown by the forthcoming GDP figures.”

U.S Futures markets signal lower natural gas prices in 2020
Source: U.S. Energy Information Administration, based on S&P Global Platts
The current outlook for U.S. natural gas prices at several key regional hubs reflects market
expectations for lower prices in January and February 2020. Two factors account for generally
lower prices: lower natural gas futures prices at the U.S. benchmark Henry Hub location and lower
regional differentials to the Henry Hub (known in natural gas markets as the basis). The Henry
Hub price is lower because of continued production increases.
Note: Futures prices reflect settlements as of November 20, 2019.
Natural gas basis swaps and futures contracts are generally financial instruments that reflect the
difference between the futures price of natural gas at the benchmark Henry Hub in Louisiana and
the forward price of natural gas at another delivery point elsewhere in the country. Large values
often indicate transportation congestion on pipelines between producing regions and demand
markets.
Pacific Northwest: The basis price at the Sumas hub in the U.S. Pacific Northwest was relatively
high in early 2019 following the October 2018 pipeline explosion in British Columbia, Canada, and
the resulting lower natural gas flows to the U.S. Pacific Northwest.
As pipeline flows into the region have recovered, natural gas prices in the Pacific Northwest have
fallen. Trade press reports indicate that in January and February 2020, traders expect the Sumas
price to average $1.25 per million British thermal units (MMBtu) higher than Henry Hub. In
January and February 2019, the Sumas basis averaged $1.53/MMBtu.
Chicago: For January and February 2020, trade press reports indicate that traders anticipate that
the Chicago Citygate basis will be about $0.26/MMBtu higher than at the Henry Hub, similar to the
2019 difference for those same months. EIA expects that large volumes of low-cost natural gas
from the Appalachia Basin will continue to flow into the Midwest. Increased deliveries of natural

gas to the Midwest could limit the Chicago price premium compared with the Henry Hub despite
expected increases in demand for space heating in January and February.
New England: New England’s Algonquin Citygate price is typically significantly higher that the
Henry Hub price throughout winter because of high heating demand and high utilization and
constraints on key natural gas pipelines in the region.
In January and February 2019, spot prices at Algonquin Citygate were $5.30/MMBtu above Henry
Hub. Trade press reports indicate that, in January and February 2020, traders expect that the
Algonquin Citygate price will average $5.10/MMBtu more than the Henry Hub price.
Southern California: Trade press reports indicate that traders expect lower natural gas prices
for Southern California compared with last winter. In January and February 2019, the SoCal
Citygate natural gas price was about $2.70/MMBtu more than at Henry Hub.
In mid-November, the futures price at SoCal Citygate for January and February 2020 has been
trading $1.66/MMBtu higher than the Henry Hub price. In the past year, Southern California
pipeline operators have increased pipeline capacity in the region, and California regulators have
allowed more flexibility in withdrawing natural gas from the Aliso Canyon storage facility that
was curtailed in October 2015 because of leaks.
West Texas: Continued crude oil and natural gas production in the Permian Basin in western
Texas and eastern New Mexico has led to pipeline constraints as production exceeded available
pipeline capacity to deliver the natural gas to markets.
The recent completion of the Gulf Coast Express pipeline added 2 billion cubic feet per day (Bcf/d)
of takeaway capacity in the region, partially alleviating this constraint, but natural gas production in
the region has continued to increase. Trade press reports indicate that traders expect the price at
the West Texas Waha hub in January and February 2020 will be $1.27/MMBtu lower than the
Henry Hub, a narrower basis than the negative $1.57/MMBtu average in

NewBase 24 November 2019 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Crude Oil Price Forecast – Crude Oil Markets Pullback To In The Week
WTI Crude Oil
The West Texas Intermediate Crude Oil market pulled back slightly during the Friday session, as
we continue to see the $60 level offer a bit of resistance. That being said though, the weekly
candlestick is a bit of a hammer and it does suggest that there is a lot of bullish pressure
underneath.
With that being the case, I suspect that if we can break above the $60 level the WTI market is
going to go looking towards the next resistance above, at the $62.50 level. Pullbacks at this point
should be a buying opportunity, down near the 200 day EMA at the $57 level, and of course the
50 day EMA at the $56 level.
Brent
Brent markets have broken down a little bit on Friday, perhaps in a sign of exhaustion as we are
near the 200 day EMA. At this point, it’s likely that the market may need to pullback in order to
build up a bit of momentum, but what should be noted is that the weekly candlestick is a hammer,
and that of course is a very bullish sign.
That doesn’t mean that we break out to the upside right away, because the $65 level of course
has offered resistance, but if we can break above there then we will start to chew through the
“resistance zone” that extends all the way to the $67.50 level above. I like buying pullbacks, and I
believe that in the short term the $60 level should be thought of as a short-term “floor.”
Oil price special
coverage

U.S. oil drillers cut rigs for fifth week in a row: Baker Hughes
U.S. energy firms this week reduced the number of oil rigs operating for a fifth week in a row and
the rig count has dropped 24% year-on-year as producers cut spending on new drilling. Drillers
cut three oil rigs in the week to Nov. 22, bringing the total count down to 671, the lowest since
April 2017, energy services firm Baker Hughes Co said in its closely followed report on Friday.
The oil rig count, an early indicator of
future output, has already declined for
a record 11 months in a row as
independent exploration and
production companies cut spending
on new drilling as shareholders seek
better returns in a low energy price
environment.
“Nearly two-thirds of the rig count
drop over the past 12 months was
due to privately held companies idling
their drilling rigs,” according to a
report this week by energy
information provider Enverus, formerly known as Drillinginfo. “During this period, a net 29% of
private operators, who were drilling at the beginning of this period, have since suspended all of
their U.S. drilling operations,” Everus said. Even though the rig count has declined, oil output
has continued to increase in part because productivity - the amount of oil new wells produce per
rig - has increased to record levels in most U.S. shale basins.
ConocoPhillips unveiled a long-term plan on Tuesday to boost oil and natural gas production by
about 3% per year, restrain annual spending to about $7 billion and return $50 billion to
shareholders over the next decade.
The largest U.S. independent crude producer, which has been divesting assets to focus on shale,
said it will spend about $4 billion per year on shale, running about 20 drilling rigs across four
fields, and boosting shale production from more than 400,000 barrels per day next year to around
900,000 bpd by the end of the decade.
U.S. crude oil output from seven major shale formations is expected to rise about 49,000 bpd in
December to a record 9.13 million bpd, the government said in its latest monthly forecast. U.S.
crude futures traded near a two-month high at around $58 per barrel on Friday, putting the
contract on track for a third week of gains on expectations of an extension to production cuts by
the Organization of the Petroleum Exporting Countries and its allies.
Looking ahead, U.S. crude futures were trading at $56 a barrel in calendar 2020 and $53 in
calendar 2021. U.S. financial services firm Cowen & Co this week said 22 of the exploration and
production (E&P) companies it watches reported spending estimates for 2020.
Cowen said there were 16 decreases, one flat and five increases, implying a 13% year-over-year
decline in 2020, which puts spending on track to decline for a second year in a row. Cowen has
said the producers it watches expected to spend about $80.5 billion in 2019 versus $84.6 billion in
2018. Year-to-date, the total number of oil and gas rigs active in the United States has averaged
958. Most rigs produce both oil and gas.

NewBase Special Coverage
News Agencies News Release 24 August 2019
Satellite Studying Volcanoes Finds Giant Oilfield Methane Plume
The monitoring of pollution from oil and gas fields achieved a major breakthrough after a satellite
company discovered a methane leak in Central Asia equivalent to the fumes of a million cars.
In a study published Friday, Montreal-based GHGSat Inc. said it was searching for emissions at
mud volcanoes when it discovered the giant plume apparently deriving from unlit flaring in the
Korpezhe oil and gas field in western Turkmenistan.
The release, persistent in images captured from early last year through February, was the first
discovery of an unknown industrial methane leak from space, GHGSat President Stephane
Germain said.
The company then tapped U.S., Canada and European diplomatic channels to alert the
Turkmenistan field operator, Germain said in a telephone interview. They didn’t communicate with
the company directly, but more recent images show the emissions had stopped by May.
“This is the equivalent of taking one million passenger vehicles off the road,” Germain said. “This
scientifically provides first detection” by satellite, he said.

Satellite observations of methane plumes in the Korpezhe oil and gas field of western
Turkmenistan . Calls and messages to Turkmenistan’s state gas producer and energy ministry
weren’t immediately answered.
The find demonstrates how satellites can be used “to enable corrective action to fight climate
change,” according to the research published by the American Geophysical Union’s Geophysical
Research Letters journal. It comes at a time when the oil and gas industry faces mounting
pressure to reduce emissions of methane, one of the most harmful greenhouse gases.
Flaring is the burning of unwanted natural gas released from oil fields, converting it into carbon
dioxide and avoiding the release of methane. Often, high winds and equipment malfunctions can
extinguish the flames.
GHGSat was capturing images scaled to 144 square kilometers (55 square miles) in Central Asia
to explore and calibrate emissions detection from naturally occurring mud volcanoes to compare
to land-based measurements. Their satellite couldn’t detect the small quantities from the mud
volcanoes but it did pick up on three unexplained bright spots nearby.
The second source appears to be from a pipeline, potentially due to a valve release, Germain
said. A third smaller one, which also appears to be from an unlit flare, cropped up a few times.

Methane emissions from the oil and gas sector reached close to 80 Mt (or 2.4 billion tonnes of
CO2 equivalent) in 2017. This is equal to 6% of global energy sector GHG emissions.
Emissions remain high despite initial industry-led initiatives and government policies announced
recently. Implementing abatement options quickly and at scale remains a real challenge. Policies
will be critical to achieve the 75% emissions reduction by 2030 demonstrated in the SDS.
Further innovation is needed both to increase understanding of emissions levels and to help
reduce the cost of emissions mitigation strategies such as leak detection and repair
Evaluating emissions trends
The concentration of methane in the atmosphere is currently 2.5 times higher than pre-industrial
levels. Methane has important implications for climate change, particularly in the near term.
Although it has a much shorter atmospheric lifetime than CO2 – around 12 years, compared with
centuries for CO2 – it absorbs much more energy while it exists in the atmosphere (one tonne of
methane absorbs 84 to 87 times more energy than one tonne of CO2 for the first 20 years after
being emitted to the atmosphere.)
The energy sector was responsible for 130 Mt of methane emissions in 2012, (Saunois at al.,
2016). Although emissions occur during coal and biofuel production and consumption, oil and gas
operations are likely the largest source of emissions from the energy sector. Global oil- and gas-
related methane emissions in 2017 were estimated to be 80 Mt.
There is considerable uncertainty about oil and gas methane emissions levels, however, as
estimates are based on sparse and sometimes conflicting data, and there is wide divergence in
estimates at the global, regional and country levels.
Nevertheless, enough is known to conclude that these emissions cannot be ignored and that they
represent a clear risk to the environmental credentials of natural gas.

Technology performance
A wide variety of technologies and measures is available to reduce methane emissions from oil
and gas operations: these are generally well known and well understood.
Devices such as vapour recovery units and plunger lifts can be installed, while existing devices
can be replaced with lower-emitting alternatives such as instrument air systems, pneumatic
pumps and electric motors.
Another cost-effective mitigation option is leak detection and repair (see Innovation section
below), which is critical to detect and mitigate fugitive (or accidental) methane leaks.
Since methane is a valuable product, and in many cases can be sold if it is captured, the IEA
estimates that around 45% of the 80 Mt of methane emissions that occur today could be avoided
with measures that would have no net cost.
In spite of this, methane emissions from oil and gas operations appear to remain stubbornly high.
Trends are diverging strongly from those of the Sustainable Development Scenario (SDS). In the
SDS, all technology options are quickly deployed across the oil and gas value chains – even if
those measures cannot pay for themselves – leading to a 75% fall in emissions from current levels
by 2030.
Industry-led initiatives and policy actions
Multiple international oil companies (IOCs) have set targets to restrict emissions or the emissions
intensity of production. There are also a number of voluntary, industry-led efforts to reduce
methane emissions from oil and gas operations:
• The Methane Guiding Principles (MGP) established in 2017 is a multi-stakeholder
collaborative platform incorporating over 20 institutions from industry, intergovernmental
organisations (including the IEA), academia, and civil society. The principles aim to
advance understanding and best practices for methane emissions reduction and to develop
and implement methane policy and regulation.
• The Oil and Gas Climate Initiative (OGCI) aims to improve methane data collection and
develop and deploy cost-effective methane management technologies; it consists of
thirteen major international oil and gas companies. In 2018, OGCI members announced a
target to reduce the collective average methane intensity of its aggregated upstream gas
and oil operations to below 0.25% by 2025 (from 0.32% today), with an ambition to
ultimately achieve a level of 0.2%.
• The Oil & Gas Methane Partnership (an initiative of the Climate and Clean Air Coalition)
provides protocols for companies to survey and address emissions and a platform for them
to demonstrate results. It consists of group of ten oil and gas companies, governments, UN
Environment, World Bank, and the Environmental Defence Fund.
However, there are limits to what can be achieved by voluntary action because the pool of those
willing to take such action is limited, and because the actions themselves may fall short of what is
desirable from a public policy perspective.
Policies and regulations are therefore essential to bring emissions more into line with the SDS.
Emissions reduction policies are not as ubiquitous as they should be, but some progress has been
made:
• Canada has introduced regulations to cut methane emissions 40-45% by 2025 from the
2012 baseline. The provinces of Alberta, British Columbia and Saskatchewan have

additional regulatory measures in place to address venting and flaring from upstream oil
and gas operations.
• The United States is in a similar position, and several states (including California, Colorado,
Ohio, Pennsylvania, Utah and Wyoming) have their own regulation and standards on
methane emissions that accompany or amplify obligations arising from federal rules. These
vary in scope, but all require mandatory inspection of facilities at varying intervals.
• Many European countries have regulations on reporting and limiting emissions levels. In
Norway, for example, each oil and gas facility estimates and reports methane emissions
annually using a common estimation method that relies on standard emission factors;
methane emissions from venting are taxed.
Recommended actions
Quantitative targets set by IOCs to restrict emissions are a welcome first step to help bring this
subsector closer to SDS alignment.
For companies already claiming low emissions, seeking to continuously reduce emissions is as
valuable as quantitative limits. Third-party verification and transparency on data and methods are
also essential for credible reporting.
In addition, large volumes of methane are emitted from assets not operated by IOCs. A critical
near-term step will be for IOCs to apply their leakage criteria to oil and gas produced from joint
ventures and non-operated assets.
Along with these voluntary efforts, policies and regulations will be central to methane emissions
reductions. Methane emissions reduction commitments can be an important addition to Nationally
Determined Contributions in line with the Paris Agreement.
Although improving data gathering and reporting is a key first step, a lack of detailed information
on emissions levels should not preclude the introduction of emission abatement goals. Policies
should concurrently seek to encourage operators to take advantage of abatement opportunities.
Some of the key considerations and principles that could inform methane emissions reduction
strategies are set out below. They are likely to be most successful if carried out in stages to help
maximise effectiveness and efficiency while shifting emissions trends.
Emphasise data gathering: uncertainty about current emissions levels is high, and reducing
this through direct measurement is critical to improve understanding of the issue, to measure
progress against goals, and to develop and refine objectives and targets. There are large data
gaps that need to be addressed for multiple major gas producing and consuming regions,
including Russia and the Middle East.
Set an overall emissions reduction goal: these can be expressed both in broad,
qualitative terms and as specific, quantitative and time-bound targets.
Foster innovation: the lack of technological innovations to detect emissions and deliver
reliable measurements at low cost is a key technology gap that needs to be a focus of both public
support and private initiatives. Methane management can also be embedded in the oil and gas
industry’s ongoing digitalisation efforts.
Maximise transparency: measurement and analysis protocols (including existing datasets)
could be shared within and among the industry and regulators to facilitate consistent approaches
to quantification and abatement and to help spur implementation.

Ensure widespread engagement during the design of regulations: it is essential to explain why
regulation is required, and then consult on how it is to be achieved, with the aim of securing support and
buy-in from as broad a stakeholder group as possible.
Incentivise collaboration: industry partnerships between international and national oil companies can
provide a powerful impetus for the adoption of best practices in regions where policy and regulatory
frameworks are less developed. Oilfield service companies, technology firms and auditing firms can also be
involved.
Establish enough enforcement: effective enforcement entails deciding how oversight and regulation
should be carried out, determining which institution is to be charged with regulation or enforcement,
providing leadership and resources for that institution, and establishing meaningful disincentives that
support behavioural change, such as penalties for non-compliance.
Incorporate flexibility into measurement and abatement policies: this might be done through
various means, including allowing for adjustments to overall goals over time if interim milestones are either
exceeded or not met.
Focus on outcomes: in deciding the specific practices, standards, technologies, certification systems
and quantitative limits to be introduced, it is important to bear in mind the overarching emissions reduction
goal and to focus on the outcomes to be achieved.
Encourage new corporate thinking on methane emissions reduction: while some companies
view the minimisation of methane emissions as a central pillar of their operations, others appear to attach
much less importance to it.

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
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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 25 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

New base energy news 24 november issue 1298 by khaled al awadi

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