New base 1186 special 15 july 2018 energy news

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NewBase July 15, 2018 - Issue No. 1186 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Saudi Acwa to co-invest in South Africa as Ramaphosa gets
$10bn in Saudi investment pledge
Saudi renewables developer Acwa Power has signed an agreement with South Africa’s Central
Energy Fund to co-invest in a 100MW concentrated solar power (CSP) project in the country’s
North Cape province.
The Redstone project will move into construction phase later this year and will feature energy
storage technology, allowing energy utilisation even after dark. The facility is expected to dispatch
around 480,000 megawatt hours (MWh) per year, Acwa Power said in a statement on Friday.
“With capital and operating cost of CSP plants with molten salt storage solution reducing at the
same time as demand for cost competitive renewable energy increases in South Africa, our
Redstone CSP plant will be able to deliver stable cost competitive electricity supply to more than
210,000 South African homes during peak demand periods which are during the night,” said Acwa
Power chief executive Paddy Padmanathan.
The investment will be the first in South Africa for Acwa Power, which has primarily invested in the
Middle East and North Africa region, as well as renewables schemes in Jordan. The

announcement follows a pledge by Saudi Arabia to invest around $10 billion in the African nation
following the visit of President Cyril Ramaphosa to Jeddah on Thursday.
South Africa, which derives much of its power-generation requirements from burning coal is also
dependent on oil to meet its energy needs. The biggest supplier of crude to the African nation is
Saudi Arabia, which meets around 47 per cent of its requirement. It also relies on imports from
Oman, Iraq and the UAE, which accounts for 4.5 per cent of the global crude production.
The UAE also announced plans for $10bn worth of investments into Africa's second biggest
economy, official news agency Wam said, without giving further details. President Ramaphosa
visited Abu Dhabi on Friday as part of his Middle East tour.
The African nation is looking to change its energy mix and its the fund, in which Acwa Power will
become an investor, is a key to that strategy. The fund comprises a consortium of companies
dedicated to finding solutions to meet energy requirements of South Africa as well as other
countries in the sub-Saharan African region.
It is pursuing development of hydrocarbons, biomass, wind as well as the other renewable
resources in the region to achieve its objective. The fund also manages the development of oil
and gas assets on behalf of the South African government.
Acwa Power's joint investment in South Africa’s Redstone will see the CSP plant developed using
a central salt receiver technology with 12 hours of thermal storage that will allow the facility to
generate power during peak-demand periods.
The central tower solution for the project, which has also been deployed in Acwa Power’s other
CSP project in Shaikh Mohammed bin Rashid Solar Park in Dubai is expected to generate cost
efficiencies by more than doubling MWh output of electrical energy per rated megawatt capacity.

Salt-based solutions have become a more popular and relatively inexpensive method to store
energy in comparison with other solutions such as photovoltaic or wind-based schemes linked to
utility-scale batteries.
Acwa Power chairman Mohammad Abunayyan said the Riyadh-based developer was looking to
“explore more opportunities” in South Africa to increase production capacity and lower costs.
Saudi Arabia earlier this month increased its stake in Acwa Power through its sovereign wealth
fund, Public Investment Fund, as the world’s largest crude exporter prioritises renewable energy
development to free up more barrels to sell in the global oil markets.
Saudi Arabia is expected to tender over 4GW of solar and wind projects as it continues to diversify
its economy away from oil. The kingdom last year established a renewables department within the
energy ministry, which has largely overseen hydrocarbons, and is expected to tender around $7bn
worth of solar and wind schemes this year.
Acwa Power has taken a leading role in the alternative power generation sector in Saudi Arabia as
well. A consortium led by the company was chosen to develop Saudi Arabia’s first-ever solar
plant, a $302 million facility at Sakaka, being developed on independent power producer model.
The developer is also bidding for the kingdom’s first wind project, a 400MW scheme in the
northern Dumat Al Jandal region.

UAE to invest $10-billion investment in South Africa
https://www.enca.com/money/uae-to-invest-10-billion-investment-in-south-africaSaturd
The United Arab Emirates has announced plans to invest US10 billion in key sectors of South
Africa’s economy, the presidency said on Saturday.
This followed President Cyril Ramaphosa’s first visit to the UAE on Friday, which marked the
beginning of a new chapter in the long-standing relations between South Africa and the UAE, and
constituted a step in further enriching the strong bilateral ties between the two countries, the
presidency said in a statement.
Ramaphosa's visit followed an invitation by UAE President Sheikh Khalifa bin Zayed Al Nahyan.
On the centennial of the birth of Sheikh Zayed bin Sultan Nahyan, founder and first president of
the UAE, and Nelson Mandela, former president of South Africa, the leaders of the UAE and
South Africa pledged to open a new chapter in bilateral relations.
To this end, the leadership of the two countries reaffirmed their deep commitment to further
consolidate their strong bilateral relations across a variety of fields, including trade, transport,
infrastructure development, tourism, mining, investment, and cultural co-operation.
To support these efforts, a business forum was held between the UAE and South Africa, hosted
by Sultan bin Saeed Al Mansoori, Minister of Economy. The UAE announced its plans to invest
US10 billion in key sectors of South Africa’s economy, such as tourism and mining among others,
to support the sustainable development of the country.
The UAE further welcomed South Africa’s positive role in supporting peace and stability on the
African continent and the two sides pledged to work closely together to promote peace, stability,
prosperity, and tolerance in Africa and the Middle East, the presidency said.

Nigeria : A $15 Billion Oil Bet Is Tough Challenge
Bloomberg - Paul Wallace
Aliko Dangote has made a fortune out of cement and food processing. Now, Africa’s richest
person is embarking on a bigger challenge: a $15 billion investment in oil, gas and petrochemicals
that could, if he pulls it off, transform Nigeria’s economy.
The 61-year-old is building one of the world’s biggest oil refineries near Lagos, the commercial
capital. He’s also constructing a fertilizer factory on the same site and plans to boost gas supplies
to the city, Africa’s largest. Once that’s done, he wants to buy enough oil fields to pump one-
quarter of a million barrels of crude a day.
The workaholic, who counts Bill Gates among his friends and is worth $12.2 billion, according to
the Bloomberg Billionaire’s Index, has little experience of any of these businesses. He says his
push into them can help end Nigeria’s reliance, despite its status as an OPEC member, on
imported fuel and increase electricity generation in a country that experiences constant blackouts.
“It will be tough,” said Jeremy Parker, a consultant at London-based CITAC, which analyzes
Africa’s energy sector. “There are many risks. Refining is a competitive and volatile industry.”
Dangote’s executives admit it’s a tall order.
“We are pushing the limits,” Devakumar Edwin, a group executive director at Dangote Industries
Ltd. who has worked with the billionaire for almost 30 years, said in a July 4 interview at the site.
“People still find it difficult to believe we can do it. We believe we can. We are so aggressively
focused.”

Hundreds of Cranes
The refinery and petrochemical plant are the most ambitious part of the plan. Meant to cost $10
billion and process 650,000 barrels of crude daily, the complex will sit an hour’s drive east of
Lagos on a swampy strip of land bounded by the Atlantic and a lagoon. About 7,000 Nigerian,
Chinese, Indian and other workers are rushing to get it ready by early 2020, when it’s scheduled
to start selling gasoline, diesel, aviation fuel and plastics.
Dangote has bought almost 300 cranes and built a jetty for ships bringing in equipment. One
piece, a 94-meter-high (300 feet) column used to distil crude into different products, weighs 2,310
metric tons, equal to 400 elephants.
“It’s a logistics nightmare,” said Edwin. “No roads, no bridges can handle that kind of thing.” The
refinery will produce around 50 million liters (13.2 million gallons) a day of gasoline, which will
easily meet the needs of the continent’s most-populous nation of 200 million people, and one-third
as much diesel.
The company’s been talking to traders including Royal Dutch Shell Plc, Vitol Group and Trafigura
Group Pte about them supplying oil and buying refined products, he said.
Once ready, it will significantly reduce fuel imports not just to Nigeria -- whose decrepit state-
owned refineries operate at a fraction of their capacity -- but to West Africa as well, according to
Salih Yilmaz, an analyst at Bloomberg Intelligence in London.
Political Pressure
“The sheer scale, and the fact it’s Nigeria’s first greenfield refinery in thirty years, will make the
project challenging,” said Johnny Stewart, an analyst at Edinburgh-based oil and gas consultancy

Wood Mackenzie. “We expect the project to come online during 2022 at a higher cost than
currently reported.”
When Nigerian Oil Minister Emmanuel Ibe Kachikwu visited the site last year, he urged the
company to hurry up and said President Muhammadu Buhari would be “absolutely enthused” if it
were completed in time for elections next February.
Dangote’s critics accuse him of benefiting from close tiesto politicians and curbs on imports that
stymie foreign competitors. He admits his businesses, including cement, might not have
succeeded without some protectionism, but says the refinery won’t get any favors from
government, including subsidized crude deliveries.
“Why would we?” said Edwin, the Dangote executive. “It’s a private enterprise. We’ll buy at
international prices.” Analysts say that could affect profits on domestic sales, given Nigeria caps
gasoline prices at the equivalent of $0.40 a liter ($1.51 per gallon), making it one of the
10 cheapest countries in the world to fill up your tank, according to GlobalPetrolPrices.com.
Most private retailers have stopped importing, leaving the job in the hands of the state-owned oil
company, which is making a loss on downstream sales. “The gasoline pricing regime is a key
risk,” said CITAC’s Parker.
Agriculture Investment
The $2.5 billion fertilizer plant, scheduled to be finished at the end of this year, is designed to
churn out 3 million tons of urea a year, almost enough to meet demand from farmers across
Africa. It’s part of Dangote’s move into agriculture, which includes investing almost $5 billion in
rice, sugar and dairy products.
“Why are we still importing most of our food in Nigeria?” said Edwin. “Agricultural activity will grow
and demand for fertilizer will grow.”

U.S continues to export MTBE, to Mexico, Chile, and Venezuela
Source: U.S. Energy Information Administration, Petroleum Supply Monthly
U.S. exports of methyl tert-butyl ether (MTBE), a motor gasoline additive, totaled 38,000 barrels
per day (b/d) in 2017, primarily to Mexico, Chile, and Venezuela. MTBE was once commonly used
in the United States but was phased out in the late 2000s as a result of water contamination
concerns. Since then, fuel ethanol has replaced MTBE as a gasoline additive.
MTBE is a fuel oxygenate that boosts octane ratings and helps achieve more complete
combustion in gasoline engines. Since 2005, most U.S. exports of MTBE have gone to Mexico
and Venezuela, with increasing exports to Chile. In 2017, Mexico accounted for two-thirds (66%)
of U.S. MTBE exports.
Economic instability in Venezuela may
have contributed to the decrease in U.S.
exports of MTBE to that country in recent
years. Overall, MTBE accounts for a small
portion of total U.S. petroleum product
exports, averaging 0.7% of the total in
2017.
MTBE is used as an oxygenate instead of
fuel ethanol in those countries, in part,
because it has lower evaporative
emissions, can be shipped in pipelines
alongside finished petroleum products, and
does not require the kinds of infrastructure
investments specific to ethanol.

Virtually all U.S. MTBE exports originate from the Gulf Coast, where production is concentrated.
MTBE can be blended with motor gasoline blendstock in the United States to produce a finished
product that is subsequently transported to destinations in Mexico.
Source: U.S. Energy Information Administration, Petroleum Supply Monthly
MTBE was once a common fuel additive in the United States. U.S. blending of MTBE into motor
gasoline peaked in 1999 at 260,000 b/d. In that year, the volume of fuel ethanol added to motor
gasoline totaled 38,000 b/d.
However, between 2000 and 2007, 23 states instituted a partial or complete ban on MTBE
blended into motor gasoline because of groundwater contamination concerns. The result was an
eventual phase out as a fuel oxygenate in the United States and a decline in domestic MTBE
consumption that was replaced with ethanol.
In contrast to MTBE, the use of fuel ethanol has been supported by tax subsidies such as
the Volumetric Ethanol Excise Tax Credit and by the Renewable Fuel Standard, which mandates
the use of biofuels in the nation’s transportation supply. As a result, almost all motor gasoline in
the United States contains 10% fuel ethanol blends.

NewBase 15 July June 2018 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil Falters on Specter of Supply Bubble From U.S. Surplus, Libya
Blommberg + Reuters + NewBase
Oil had its worst week since late May as the U.S. considered tapping national crude reserves to
quell rallying gasoline prices amid a restoration of key Libyan supplies that may throw worldwide
supply and demand out of whack.
Futures sank 3.8 percent this week in New York. The Trump administration may draw on the 660
million-barrel Strategic Petroleum Reserve to increase domestic supplies, according to two people
familiar with the situation. Meanwhile, Libya’s state oil producer restarted output from a major field
that had been shut for months. The price slump was truncated on Friday when
Iran disputed Russian claims about OPEC’s agreement to lift production.
“It’s been an avalanche of bearish headlines since Wednesday,” said Bob Yawger, director of
futures at Mizuho Securities USA Inc. in New York. “Libyan crude oil came out of nowhere.
Nobody saw that coming back so fast.”
Oil has retreated since hitting a three-year high at the start of the month. U.S. President Donald
Trump threatened tariffs this week on nearly half of all American imports from China, and China
vowed to retaliate. As crude clawed back some of those losses on Friday, analysts pointed to
doubts that Trump’s aggressive levies will actually go into effect. Some also cited supportive
momentum from bullish equity-market action.
Oil price special
coverage

“The market is realizing that this is more of a negotiating tactic on behalf of the president,” said
Michael Loewen, director and commodities strategist for Scotiabank. “Cooler heads will eventually
prevail in these trade negotiations.”
The U.S. on Friday rejected France’s request for sanctions waivers that would allow French
companies to continue doing business with Iran. The move may indicate the U.S. won’t be as
flexible as Secretary of State Mike Pompeo recently suggested.
“There’s a lot of people in the market who think there’s going to be a number of waivers granted to
ease the supply crunch, and I just don’t see that happening,” said John Kilduff, founding partner
for Again Capital LLC. “I think the administration is going to be playing this hardcore.”
Recovering Prices
West Texas Intermediate crude for August delivery rose 68 cents to settle at $71.01 a barrel on
the New York Mercantile Exchange. Total volume traded was about 20 percent below the 100-day
average.
Brent for September settlement added 88 cents to $75.33 on the London-based ICE Futures
Europe exchange. The global benchmark traded at a $5.38 premium to WTI for the same month.
Front-month Brent flipped to a discount to October futures this week, a structure known as
contango. The pattern normally suggests that immediate supplies are excessive.
Trade Shock
Brent posted its biggest one-day drop in more than two years on Wednesday, after U.S. President
Donald Trump released a list of $200 billion worth of Chinese products that could face additional
tariffs. Risky assets sold off around the world as China vowed to retaliate.
“That brought on concerns that there could be a full-blown trade war brewing between the United
States and pretty much all its trading partners,” said Bart Melek, head commodities strategist of
Toronto Dominion Bank. “The current expected robustness of new oil demand next year could
very well peter out.”
Meanwhile, there are signs supply disruptions that helped oil’s rally earlier this month are easing
in some places.
OPEC member Libya is set to restart production at El-Feel. The country’s National Oil Corp. lifted
force majeure at the field, which will boost output to 72,000 barrels in a matter of days, the
company said in a statement on Thursday.

Oil Explorers in U.S. Heartland Need $69 Crude to Boost Drilling
Oil companies operating in the central U.S. want oil to average $69 a barrel before they’ll
substantially expand drilling, according to the Federal Reserve Bank of Kansas City.
That’s up from $56 a year earlier, according to a survey of firms released Friday by the Kansas
City Fed, which serves all or parts of seven states from Nebraska to New Mexico.
West Texas Intermediate, the U.S. benchmark, has averaged about $66 this year and has risen
17 percent since the end of 2017 amid robust demand and supply disruptions in Canada, Libya,
Venezuela and elsewhere. On Friday, oil settled at $71.01 in New York.
According to the survey, expectations about future drilling and business activity by energy
companies rose in the second quarter even as capital expenditures declined. About 65 percent of
companies said they anticipate a “medium business risk” from higher OPEC production levels.
“Regional energy firms had another good quarter and continue to have strong expectations for
future growth,” Chad Wilkerson, an economist at the Kansas City Fed, said in a statement.
“However, the prices needed for significant expansion to occur have continued to rise.”

U.S. drillers leave oil rig count unchanged -Baker Hughes
Reuters + NewBase
U.S. energy companies left the oil rig count unchanged this week as the rate of growth has slowed
over the past month or so with a decline in crude prices from late May through late June. U.S.
crude prices were on track to fall almost 4 percent this week as escalating U.S.-China trade
tensions threatened to hurt oil demand after last week rising to their highest level since November
2014.
The number of active oil rigs held steady at 863 in the week to July 13, General Electric Co’s
Baker Hughes energy services firm said in its closely followed report on Friday. RIG-OL-USA-BHI
More than half the total oil rigs are in Permian basin in west Texas and eastern New Mexico, the
nation’s biggest shale oil field. Active units there increased by one this week to 475, the most in a
month.
The U.S. rig count, an early indicator of future output, is higher than a year ago when 765 rigs
were active as energy companies have ramped up production in anticipation of higher prices in
2018 than previous years.
So far this year, U.S. oil futures have averaged $65.95 per barrel. That compares with averages of
$50.85 in 2017 and $43.47 in 2016.
Looking ahead, crude futures were trading over $69 for the balance of 2018 and near $65 for
calendar 2019 .
In anticipation of higher prices in 2018 than 2017, U.S. financial services firm Cowen & Co this
week said the exploration and production (E&P) companies they track have provided guidance
indicating a 13 percent increase this year in planned capital spending.
Cowen said those E&Ps expect to spend a total of $81.2 billion in 2018, up from an estimated
$72.1 billion in 2017.
Analysts at Simmons & Co, energy specialists at U.S. investment bank Piper Jaffray, this week
forecast average total oil and natural gas rig count would rise from 876 in 2017 to 1,032 in 2018,
1,092 in 2019 and 1,227 in 2020. Last week, Simmons forecast the count would rise to 1,033 in
2018, 1,092 in 2019 and 1,227 in 2020.
Since 1,054 oil and gas rigs were already in service, drillers would only have to add a handful of
rigs during the rest of the year to hit Simmons’ forecast for 2018.

So far this year, the total number of oil and gas rigs active in the United States has averaged
1,006. That keeps the total count for 2018 on track to be the highest since 2014, which averaged
1,862 rigs. Most rigs produce both oil and gas.
The U.S. Energy Information Administration (EIA) this month projected average annual U.S.
production will rise to a record high 10.8 million barrels per day (bpd) in 2018 and 11.8 million bpd
in 2019 from 9.4 million bpd in 2017.
The current all-time U.S. annual output peak was in 1970 at 9.6 million bpd, according to federal
energy data.

NewBase Special Coverage
News Agencies News Release 15 July 2018
Wind generators’ cost declines reflect technology improvements
and siting decisions
U.S. EIA, based on U.S. DOE, Office of Energy Efficiency and Renewable Energy (EERE), Wind Technology Market Report
Between 2010 and 2016, the capacity-weighted average cost (real 2016$) of U.S. wind
installations declined by one-third, from $2,361 per kilowatt (kW) to $1,587/kW, based on analysis
in the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy’s
(DOE/EERE) Wind Technology Market Report.
The reasons for this decline include improving technology and manufacturing capability and an
increasing concentration of builds in the regions of the United States with the lowest installation
costs.
After many years of declining real project costs, wind reached a low in 2004 at $1,342/kW.
Through the remainder of that decade, costs gradually increased, reaching a peak in 2009 and
2010 of about $2,360/kW.
Contributing factors to the increasing costs through 2010 included increasing labor costs, an
increase in the cost of key manufacturing and construction commodities, and international
currency exchange fluctuations affecting imports of key equipment.

After 2010, installed costs began to decline as some of those pressures lifted. The global
recession of 2008 reduced the cost of key construction and manufacturing commodities. Domestic
manufacturing capacity for wind turbine components increased, and the increasing pace of
installations helped to reduce both turbine manufacturing and installation costs through learning-
by-doing effects, even as higher-performing equipment continued to enter the wind turbine market.
Source: U.S. EIA, based on U.S. DOE, Office of Energy Efficiency and Renewable Energy (EERE), Wind Technology Market Report
Regional variations in wind turbine installation costs also have an effect on reported U.S. average
costs. In 2010, the Interior region of the United States had an average installation cost of
$2,069/kW, compared with $2,247/kW for the rest of the country.
By 2016, the costs in the Interior had dropped 25% from 2010 levels to $1,531/kW, and costs in
the rest of the United States had dropped 10% to $2,025/kW. EIA began collecting capital cost
data for new generators in 2013, and this data closely tracks the estimates from DOE/EERE.Also
in 2010, the share of wind capacity installations was almost evenly split between the Interior and
the rest of the United States, with only 46% of capacity entering service that year in the Interior.
By 2016, almost 90% of incremental capacity was installed in the lower-cost Interior region. This
capacity takes advantage of not only the more favorable wind resources of the region, but also the
easily developed expanses of flat land (allowing for larger project sizes) and transportation access
to the developing concentration of turbine component manufacturing in this region.
The increasing concentration of U.S. wind builds in the low-cost Interior region of the country has
reinforced the overall decline in the average cost of wind construction. Because of the recent
increase in the overall capacity mix in this region, the national rate of decline in wind costs closely
tracks the cost declines for the Interior.
Although other factors have affected overall costs, 2016 average installed costs for wind in the
United States would have been more than 10% higher if total wind installations had remained at
their 2010 geographic market shares.
Wind Energy Costs Set To Continue To Decline, According To Berkeley Lab

Continued technological advancements are expected to continue reducing the cost of wind
energy, according to a new survey of leading wind experts conducted by Lawrence Berkeley
National Laboratory.
According to a new article published in the journal Nature Energy, Expert elicitation survey on
future wind energy costs, the results of a survey of 163 of the world’s foremost wind power experts
were outlined in an effort to better understand the future of wind energy costs and the possible
technological advancement. Specifically, the surveyed experts anticipate wind energy cost
reductions of at least 24% to 30% by 2030, and 35% to 41% by 2050 due to larger and more
efficient wind turbines, lower capital and operating costs, and other advancements, as laid out
below.
The study was led by Ryan Wiser, a senior scientist at Berkeley Lab, and included contributions
from other staff from Berkeley Lab, the National Renewable Energy Laboratory (NREL), the
University of Massachusetts, and participants in the International Energy Agency Wind (IEA) Wind
Technology Collaboration Programme Task 26.
“Wind energy costs have declined dramatically in recent years, leading to substantial growth in
deployment,” explained Wiser. “But we wanted to know about the prospects for continued
technology advancements and cost reductions. Our ‘expert elicitation’ survey complements other
methods for evaluating cost-reduction potential by shedding light on how cost reductions might be
realized and by clarifying the important uncertainties in these estimates.”
The study looked at three wind applications — onshore, fixed-bottom offshore, and floating
offshore. Unsurprisingly, typical onshore projects are expected to remain considerably less

expensive than its offshore brethren, while fixed-bottom offshore will be less expensive than
floating offshore. However, according to the report, and as shown below, there are greater
absolute reductions, as well as more uncertainty, in the levelized cost of energy for offshore wind
as compared with onshore wind.
Despite expected cost reductions, there is still “substantial room for improvement,” and the
experts predicted that there could even be a 10% chance that reductions will be more than 40%
by 2030, and more than 50% by 2050.

The report also identified five key drivers for wind cost reductions: up-front capital cost (CapEx),
ongoing operating costs (OpEx), cost of financing (WACC), performance (capacity factor), and
project design life. We have seen up-front costs for wind projects decline over the last few years,
at the same time as turbine performance has increased, making wind energy ever more cost-
efficient and -effective. The survey reports that the size of wind turbines (capacity factor) will be a
key factor in future declining costs. Average onshore turbine generating capacity is expected to
reach 3.25 MW in 2030, while rotor diameter and hub height will also increase (135 meters and
115 meters respectively in 2030).
“Onshore wind technology is fairly mature, but further advancements are on the horizon — and
not only in reduced up-front costs,” explained Wiser.
“Experts anticipate a wide range of advancements that will increase project performance, extend
project design lives, and lower operational expenses. Offshore wind has even greater
opportunities for cost reduction, though there are larger uncertainties in the degree of that
reduction.
“Though expert surveys are not without weaknesses, these results can inform policy discussions,
R&D decisions, and industry strategy development while improving the representation of wind
energy in energy-sector and integrated-assessment models.”
Technology advances spurring ever-lower wind energy costs
Why is it that wind energy costs keep declining while mainstream electricity generation costs continue
to climb? The answer is continued evolution in wind turbine technology.
Wind energy is now the lowest-cost option for new electricity supply in most Canadian provinces.
Contracts awarded in Hydro-Quebec’s most recent request for wind proposals in 2014 were 6.3
cents per kilowatt-hour; in Ontario, a new low for the province of 6.45 cents was achieved in its
latest procurement in 2016.

In December 2017, however, Alberta’s first competitive renewable energy procurement set a new
Canadian record with an average price of 3.7 cents per kilowatt-hour. Procurements currently
underway in Alberta and Saskatchewan are expected to deliver similar results in 2018.
A November 2017 report by U.S. investment firm Lazard shows that wind energy costs continue to
track lower across the globe. Since 2009, the unsubsidized levelized cost of energy (LCOE) for
onshore utility-scale wind energy has decreased by 67 per cent. Meanwhile, natural gas
generation prices are increasing as carbon costs are included; nuclear generation prices are
forecast to increase in Ontario to recover refurbishment costs; and new hydro mega-projects are
seeing costs climb.
In comparison, wind energy prices continue to decline as the technology continues to improve,
lowering the cost of wind turbines while increasing performance. Today’s larger wind turbines are
more cost-effective and reliable than ever. For example, average rotor sizes have doubled since
the 1980s, with much longer and lighter blades sweeping larger areas, capturing much more
energy. Turbines have taller towers, more reliable drive trains and performance-optimizing control
systems.
According to the U.S. Department of Energy’s Wind Technologies Market Report (August 2016),
between 1998 and 2015:
• the average turbine hub height increased by 47 per cent (to 82 meters);
• the average rotor diameter was scaled up by 113 per cent (to 102 meters); and
• the average electricity-generating capacity of U.S. wind turbines grew by 180 per cent (to 2
megawatts).

Improvements such as these translate into more power at lower prices. The report finds that the
average 2015 capacity factor (percentage of theoretical maximum electricity production on an
annual basis if wind blew at the appropriate speed all the time) among U.S. projects built in 2014
reached 41 per cent, compared to 31 per cent for projects built in the 2004-11 period. Wind
turbine prices in 2015 also were 20 to 40 per cent lower when compared to 2008 prices. Lower
installed costs and higher capacity factors have led to a dramatic decline in the average levelized
long-term price from wind power sales agreements, which have fallen by almost two-thirds in the
United States from 2009 to 2015.
Here in Canada we are benefiting in the same way from wind energy technology advances and
falling costs. In addition to its reliability gains and competitive costs, there is also a growing
understanding that wind energy is
emissions free, that it has no fuel
costs, that it can be built relatively
quickly and scaled to meet needs,
and that it benefits local communities
and our national economy.
These are all reasons why more wind
energy capacity has been built in
Canada over the past decade than
any other form of electricity generation,
and why it is now becoming the
mainstream energy of choice for our
country’s new electricity generation
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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 K. Al Awadi
August 2017

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