New base 10 may 2018 energy news issue 1169 by khaled al awadi

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NewBase Energy News 10 May 2018 - Issue No. 1169 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: Abu Dhabi is currently building the world’s largest solar P
Gulf News - Fareed Rahman, Senior Reporter
The Chairman of Department of Energy — Abu Dhabi, Awaidha Murshed Al Marar, on Wednesday
said the newly created department will focus on finding the right mix of energy that fits Abu Dhabi’s
interests, including special emphasis on solar and other sources of energy.
“Right now, the energy mix is heavily loaded with gas sources but we are expanding tremendously
on utilising the solar and our target is to heavily focus on solar mix. We will also be looking at other
alternative sources of energy,” Al Marar said while speaking to reporters at the launch of a new
strategy for the department.
Abu Dhabi is currently building the world’s largest solar plant in Sweihan at an estimated cost of
$870 million as it works towards generating more clean energy. The project is being undertaken by
Department of Energy in cooperation with Japanese company Marubeni, and Chinese manufacturer
JinkoSolar. Abu Dhabi has set a target of 7 per cent of renewable energy by 2020.
Al Marar also said they are upgrading desalination plants and raising their efficiency. In a month’s
time, they would be launching one of the biggest desalination plants in the world with a capacity of
200 million gallons per day, he said without giving further details.
Department of Energy was created earlier this year with Abu Dhabi Water and Electricity Authority
(ADWEA) and the Regulation and Supervision Bureau becoming part of it.

JinkoSolar Holding Co., Ltd. (NYSE: JKS) (the “Company,” or “JinkoSolar”), a global leader in the
solar PV industry, today announced that the world record breaking 1177 MW Sweihan project, co-
developed by JinkoSolar, Marubeni, and the Abu Dhabi Electricity and Water Authority (“ADEWA”)
， was named Large Scale Solar Project of the Year by the Middle East Solar Industry Association
(MESIA).
The award is one of Middle East’s highest solar honors, furthering affirming the milestone nature of
the Sweihan project. With the winner selected by a panel of nine judges from across the industry,
the award recognizes large scale solar projects in Middle East region that are impact and innovative.
When the Sweihan project is completed, at 1177 MW, it will be the world’s largest PV plant.
Beyond just size of the installation, the project also broke a world record in PV electricity generation
cost. At the time when the bid was announcement, the JinkoSolar-Marubeni bid of 0.0242 USD/kwh
was the lowest the world had ever seen.
The Sweihan project achieved such a large scale and competitive generation cost largely due to the
utilization of JinkoSolar high efficiency monocrystalline solar modules. Given the limitation on the
plot size, the use of JinkoSolar monocrystalline modules allowed for the maximization of output,
enabling the world record scale.
The high efficiency of the modules also allowed for decreases in balance of system cost, enabling
the world record low tender price.
“We’ve always known that Sweihan project is undoubtedly not just a milestone for JinkoSolar,
Marubeni, and ADEWA, but also a great big leap for the global solar power development. The
recognition from MESIA further affirms the ground-breaking significance of the Sweihan project”
noted Mr. Xiande Li, JinkoSolar Chairman.
“Fueled by the success of the Sweihan project, we will continue to seek to produce cutting-edge
high efficiency modules, fulfilling our vision of optimizing the world’s energy structure and blazing
new trails in solar power” Mr. Li further explained.
DEALS

UAE – ADNOC a M.E. Oil Giant Prepares for a Post-Petro World
Bloomberg - Anthony Dipaola
Behind the 65-story glass tower that houses the shiny new headquarters of Abu Dhabi National Oil
Co. sits a remnant of the Middle Eastern emirate’s not-so-distant past: the squat, sand-colored
building that the government-owned energy giant once called home.
The stark contrast between the old and new buildings
provides a hint of the changes afoot in energy-rich Abu
Dhabi. The tiny, but stratospherically wealthy, emirate is
trying to forge an economy for a post-oil world and needs
to wring more profits from its petroleum industry to
finance the makeover.
A similar shift is taking place in neighboring Saudi Arabia,
where Adnoc’s larger rival, Saudi Aramco, plans to sell
shares for the first time. With a projected $2 trillion
valuation, Aramco is set to have the world’s biggest initial
public offering.
Adnoc also wants to secure an economic future for its
government owner after the hydrocarbons run out, but it’s
treading a different path. “Adnoc has always been seen
as a stodgy, slow-moving company,” says Robin Mills,
chief executive officer of consultant Qamar Energy. “Now
they’re striving to set up a strategy and actually
implement it. It’s still a work in progress.”
“You can no longer be dependent on only oil prices,” says
Al Jaber.
The man in charge of revamping Adnoc and managing its 50,000 employees is Sultan Al Jaber,
who became CEO in 2016. His effort has an existential urgency, because Abu Dhabi—like Saudi
Arabia—offers something the world apparently has too much of: oil. The boom first fell in 2014,
when the price of crude plunged by more than half, breaking a string of $100-per-barrel years that
had engorged budgets and bred complacency across the Gulf.
Since 2017, the United Arab Emirates, of which Abu Dhabi is the capital, has taken part in
the Organization of Petroleum Exporting Countries program to constrain output to prop up prices.
Now—even as it’s limiting Adnoc’s revenue to satisfy OPEC—it’s also revamping the national oil
giant and pitching the company to foreign investors to tap the capital and technology needed for its
transformation.
“What became evident in 2014 and 2015 was the fact that the energy market is no longer what it
used to be,” Al Jaber says. “You can no longer be dependent on only oil prices. Adnoc had to come
to terms with the realities on the ground.”
Since its founding in 1971, Adnoc has been synonymous with the oil wealth that thrust the U.A.E.
into modernity. It’s the company that made possible Abu Dhabi’s glittering cityscape. It helped keep
the lights on for Dubai, too: Abu Dhabi bailed out its flashier neighbor after the 2008 financial crisis,
and an Abu Dhabi-owned pipeline supplies the natural gas Dubai needs every day to keep its
shopping malls and hotels bright and cool.

For much of its five-decade history, Adnoc has sold crude to the mostly Western companies that
help pump it, or to traders that flipped their cargo for profit in Asia or the Mediterranean. Refiners in
those countries turned that oil into gasoline and diesel or feedstock for chemical plants to produce
plastics and other petroleum derivatives.
But talk in the global energy markets has moved from peak oil—concern that reserves were doomed
to run out—to peak demand—forecasts of continuing oversupply. Oil producers are being buffeted
by declining prices and uncertainty over the future direction of their business.
So Abu Dhabi has decided to build a hedge against the shifting energy market by pushing Adnoc to
get involved in the entire supply chain, alongside the oil majors and traders. The hope is that by
dangling access to the emirate’s oil reserves—the U.A.E. has about 6 percent of the world’s crude—
Adnoc can bring in the funds and expertise that will help contribute to the broader national economy.
“Abu Dhabi is reinvesting for development and to expand the economy,” says Hootan Yazhari, Bank
of America Merrill Lynch’s chief Middle East markets analyst. “The question of whether there is
urgency to do this depends on your view of oil. By 2030, oil is unlikely to be where it is today.”
In an effort to ensure Adnoc has long-term buyers for all its oil, Abu Dhabi over the past two years
let Chinese and Indian companies participate in its main oilfield concessions for the first time,
alongside historic allies such as Exxon Mobil, Total, and BP. On the downstream side of the energy
business, it wants to eke out more dollars per barrel of crude by turning its oil into refined fuels and
products such as plastics and chemicals.
The company is also looking to make its first foreign investments in similar plants abroad where
local demand is growing fastest. To finance that expansion and entice lenders and investors to the
emirate, Adnoc in 2017 sold bonds for the first time as well as a sliver of equity—a 10 percent
stake—in its gas station unit.

All of this invites the inevitable comparison with Aramco. Saudi Arabia’s Crown Prince Mohammed
bin Salman is determined, like Abu Dhabi’s Sheikh Mohammed bin Zayed, to maximize his country’s
oil-related income and use proceeds from asset sales to build new industries and help workers
develop more sophisticated skills. But while the strategy is the same, the tactics and timelines differ.
Adnoc’s “not going in the same direction as Saudi Aramco,” Bank of America’s Yazhari says. “Abu
Dhabi doesn’t have an immediate need to list Adnoc given its healthy economic balances. What
they need to focus on is increasing access to investors. By listing smaller units, they can boost
liquidity and trading on the domestic stock market, and that can help the country.”
Instead of selling equity at the holding company level as Aramco plans to, Adnoc raised $851 million
from the sale of the minority stake in the service station business. Adnoc’s code name for the IPO
was “Project First,” because, as Al Jaber says, it will be “the first of many.” While selling shares in
Adnoc itself isn’t planned, almost every other financial move is being entertained.
“Whether it is a financial restructuring, whether it’s a bond issue, whether it’s a private placement,
whether it is attracting strategic investors, whether it is us going through an IPO, we are looking at
everything,” Al Jaber says. “We have some real substantial deals that are taking place this year.”
Value of Adnoc’s five-year capital-expenditure plan: $110 billion
Adnoc’s outreach program shifts into high gear on May 13, when it will host international oil majors,
bankers, and investors to its Downstream Investment Forum to sample opportunities available in
the emirate. Also on the schedule is a trip to Ruwais, where Adnoc’s 817,000-barrel-a-day oil-
processing complex pumps out gasoline for local drivers, as well as diesel and jet fuel destined for
Europe and other markets.
Ruwais, where the vast desert of the Empty Quarter meets the waters of the Gulf, will soon become
an oil-processing and petrochemicals hub. Adnoc aims to build a 600,000-barrel-a-day refinery, plus
petrochemical plants that would let it triple production capacity. It plans to finance the construction
and operation of all those by wooing investors and, potentially, selling a stake in its refining business
to a partner.

“We’re going to be announcing a series
of projects,” Al Jaber says. “We are
going to invest heavily in Ruwais,” as
part of a five-year capital-expenditure
plan of about $110 billion.
Whether investors will bite is another
question. U.S. shale oil and gas and
other new supplies are intensifying
competition for Middle Eastern
producers, which are shackled by
OPEC’s production limits. And entering
competitive downstream businesses
could mean large expenses and small
profits if the oil majors also add capacity.
“It’s not really going to revolutionize their
export revenue, but it provides some
hedging against the oil price risk,” says
Hamed Ghoddusi, of the School of
Business at the Stevens Institute of
Technology and the author of a recent
paper on OPEC members pushing into
downstream.
Back at Adnoc’s gleaming headquarters,
the company has installed a wall of LED
panels, which provide a supercomputer-
powered overview of its many
operations. Alongside the bar charts
showing oil output and revenue is a
gauge that stands out: “Emiratization of the workforce”—a nod to Abu Dhabi’s long-term ambition
to make Adnoc a spearhead of both economic and societal reform for the entire U.A.E. Key to that
will be weaning itself off expatriate labor and having Emiratis account for a greater share—Adnoc
won’t say how large—of the company’s workforce.
Creating a commercially minded and internationally competitive local workforce is difficult in a
country where the citizens are accustomed to generous government handouts. One of the biggest
challenges Al Jaber has faced so far has been shaking up a bureaucratic corporate culture—
streamlining it into a more entrepreneurial organization, according to Haif Zamzam, a former Boston
Consulting Group adviser, who joined Adnoc’s strategy department. “In the past we would take on
nearly zero risk. There was absolutely no room for error,” Zamzam says. “Now we’re introducing the
idea of taking calculated risks.”
While young Emiratis have voiced strong support for Al Jaber’s changes, the process hasn’t been
without its critics. Two points of contention: Al Jaber’s unprecedented job cuts and other cost-saving
measures and the introduction of performance reviews.
Abu Dhabi’s Crown Prince Mohammed has deployed himself more than once to show support for
Adnoc’s changes, posting photos of himself and Al Jaber on Twitter and state media. In February
the crown prince and Al Jaber had lunch together at the Abu Dhabi branch of London restaurant
Zuma with about a dozen members of Adnoc’s Future Leaders Program, underscoring the kind of
technologically savvy workforce the emirate wants to develop.

Saudi's SABIC eyes 50 percent stake in ONGC's west India
Reuters + NewBase
Saudi Basic Industries Corp (SABIC) 2010.SE, the world’s No.4 petrochemical company, wants to
buy about half of the $4.6-billion Indian petchem project backed by Oil and Natural Gas Corp
(ONGC), two sources familiar with the matter said.
ONGC (ONGC.NS) is a majority shareholder in ONGC Petro Additions Ltd (OPaL), which operates
India’s biggest petrochemical plant in western Gujarat state. “They (SABIC} want to have a
significant stake in OPaL, around 50 percent,” said one of the sources.
Previously, ONGC had held talks about selling a stake in the project with Saudi Aramco and
Petrochemical Industries Co, a unit of Kuwait Petroleum Corp, a second source said. “SABIC is the
latest entrant. Recently SABIC has held talks with ONGC officials about a stake purchase,” the
second source said.
ONGC and SABIC did not respond to Reuters’ requests for comment.
India and Saudi Arabia want to strengthen their trade ties. Saudi Aramco recently signed an initial
deal with India to buy a 50 percent stake in a planned 1.2 million barrels per day west coast refinery
and petrochemical project.
To expand its footprint in the world’s third-biggest oil importer, Saudi Arabia is also scouting for a
stake in existing major refineries, its energy minister Khalid al-Falih has said. The first source said
OPaL made an operating profit for the first time in 2017/18, increasing its appeal to prospective
investors. “There are enough green shoots in the company,” the source said.
India’s per capita consumption of synthetic polymers, used to make various grades of plastics, is
just 10 kg (22 lbs) a year, compared with a global average of about 32 kg.
The country’s per capita consumption of petrochemicals will rise with its expanding middle class,
growing income levels and increasing urbanisation, Prime Minister Narendra Modi said in March
last year. The second source said OPaL operated the project at about 65 percent capacity in the
March quarter and it aimed to operate the plant at about 80 percent capacity in 2018/19.

China: The Real Oil Action Is in China, Forget Iran
Surging products exports and declining domestic fields are driving an imports boom.
By David Fickling
Forget Iran, shale and Opec. The real action in the oil market is happening on the other side of the
globe.
China overtook the U.S. as the world’s largest oil importer last year, and for 2018, it’s hoping to beat
that achievement. April imports of 39.46 million metric tons reported late Tuesday came off the back
of a string of blockbuster months. Until the start of this year, China had never imported much more
than 37 million tons in any single month. So far in 2018, only February, shortened by the Lunar New
Year holiday, failed to exceed that amount.
It wasn’t meant to be like this.
Organization of the Petroleum Exporting Countries and the International Energy Agency expect
China’s demand growth to start slowing toward an annual pace of 300,000 additional barrels a day
over the next few years as the nation switches from its headlong pace of industrialization and the
rise of electric vehicles crimps gasoline demand.
Opec revised its numbers upward for 2017, and the same may happen this year. The 5.1-million-
ton increase in China’s April crude imports compared to a year earlier on its own represents growth
of about 1.2 million barrels a day.
A few things might help account for this. China’s domestic oilfields are struggling to keep up with
demand as wells get tapped out and the government pushes the big three state-owned firms to
instead produce more gas. As a result, the country is leaning more heavily on imports — so even a
slower pace of domestic demand growth can have an outsized impact on global markets.

Another factor is that much of this crude isn’t ultimately being consumed in China. Exports of refined
products have been surging as authorities relax quotas on the trade, with Morgan Stanley analyst
Andy Meng estimating that the volume of products permitted under export quotas granted in 2018
already exceeds the total for the whole of last year. In that sense, this isn’t so much a story of
China’s booming domestic demand as the perennial habit of its manufacturing sector to go over-
capacity.
Filling Up
China has turned a major net exporter of petroleum products over the past three years
Source: China Customs General Administration, Bloomberg, Bloomberg Opinion calculations
The 26 million tons of net product exports over the past 12 months would be enough to turn a
country that was until a few years ago one of the larger importers of refined petroleum into a major
exporter on a par with South Korea, Kuwait and India.
Even China’s teapot refineries — non-state-owned plants mainly in Shandong province, which are
traditionally operating less than half the time — have been seeing operating rates nudging close to
levels where they should be able to make a profit.
Shorter Tea Break
The operating rate of China's teapot refineries has been nudging close to profitable 75 percent-plus levels
Source: Sublime China Information Group, Bloomberg

The sanguine response of oil prices to news of President Donald Trump’s decision to withdraw from
the 2015 accord on Iran’s nuclear program has been explained by the fact that the decision was
widely expected, and that crude tends to find a way round such restrictions.
The strength of Chinese demand — in particular, whether the current strong figures play out over
the course of the year or represent a short-term stock build — could prove a decisive factor on that
front.
The yuan-denominated crude contract recently launched in Shanghai may be one of the easiest
ways for Iran to get past U.S. sanctions, which are typically enforced when banks attempt to clear
dollar-denominated trades in New York. Beijing has been shifting its oil purchases away from the
Arabian Gulf and toward Russia, the U.S., Brazil, Angola and Malaysia in recent years, but a sudden
lack of Western buyers would be the perfect opportunity for Chinese refiners to get back into the
market for Tehran’s crude.
Yawning Gulf
China has been reducing its crude imports from the Arabian Gulf, and increasing elsewhere else
Source: China Customs General Administration, Bloomberg, Bloomberg Opinion calculations
Note: Shows change in oil imports between calendar 2017 and calendar 2016.
Looking at supply is crucial for understanding crude, but it’s not everything. Right now, the strength
of China’s demand may be the most underappreciated story in the market.

NewBase May 10 - 2018 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices hit highest in years as markets adjust to sanctions on Iran
Reuters + Bloomberg + NewBase
Oil prices clocked up more multi-year highs on Thursday as traders adjusted to the prospects of
renewed U.S. sanctions against major crude exporter Iran amid an already tightening market.
The United States plans to impose new sanctions against Iran, which produces around 4 percent of
global oil supplies, after abandoning an agreement reached in late 2015 which limited Tehran’s
nuclear ambitions in exchange for removing U.S.-Europe sanctions.
Oil prices rose sharply in response to the announced measures.
Brent crude futures, the international benchmark for oil prices, hit their strongest since November
2014 above $77.80 per barrel at 0421 GMT on Thursday. U.S. West Texas Intermediate (WTI)
crude futures also marked a November-2014 high, at $71.75 a barrel at that time.
In China, which is Iran’s single biggest buyer of oil, Shanghai crude futures posted their biggest
intra-day rally since their launch in March, rising more than 4 percent to a dollar-denominated record
Oil price special
coverage

of around $73.40 per barrel. Analysts had little hope that opposition to the U.S. action would prevent
sanctions from going ahead. “Europe and China will not fight against the U.S. sanctions. They will
grumble and accept it. There is no one who will realistically choose Iran over the U.S.,” said energy
consultancy FGE.
“We believe the previous 1 million bpd limit for exports (imposed during previous sanctions) will be
reimposed. As before, it may take several rounds of reductions to reach target levels,” FGE’s
founder and chairman Fereidun Fesharaki wrote in a note.
“Oil prices will certainly move up, and $90-100 per barrel prices may again be on the cards,”
Fesharaki said.
U.S. bank Goldman Sachs said renewed sanctions and risks to supplies elsewhere, especially in
Venezuela, meant there was a high possibility of higher prices than the bank’s summer Brent price
forecast of $82.50 per barrel.
The threat of new sanctions come amid an oil market that has already been tightening due to strong
demand, especially in Asia, and as top exporter Saudi Arabia and top producer Russia have led
efforts since 2017 to withhold oil supplies to prop up prices.
U.S. crude inventories fell by 2.2 million barrels in the week to May 4, to 433.76 million barrels,
according to the Energy Information Administration (EIA), slightly above the 420 million barrels five-
year average level.
One factor that could prevent markets from tightening further is soaring U.S. oil output. “Higher
prices are more than likely to be capped as...U.S. shale producers turn the taps back on the longer
prices remain above break-evens,” said Kerry Craig, global market strategist at J.P. Morgan Asset
Management.
Weekly U.S. crude oil production hit another record last week, climbing to 10.7 million barrels per
day (bpd). That’s up 27 percent since mid-2016 and means U.S. output is creeping ever closer to
that of top producer Russia, which pumps around 11 million bpd.

Impacts on U.S. Gas Market While It's Down
President Donald Trump’s decision to scrap the Iran nuclear deal and restore sanctions was great
for oil bulls. But for natural gas drillers in America’s hottest shale play, it could be a disaster in the
making.
The highest oil prices in more than three years are poised to boost output from areas like West
Texas’ Permian Basin, the most prolific U.S. reservoir of the fuel. That would add to the supply of
gas that’s produced alongside crude there, making an existing glut even bigger.
A surge in oil drilling would deliver another blow to a gas market that’s already America’s worst. The
Permian boom has filled pipelines to capacity, trapping gas in the region and making prices there
the cheapest of any major U.S. hub. West Texas gas prices could drop to zero on some days,
according to Tudor Pickering Holt & Co., forcing explorers to shut production or burn off excess
supplies in a process known as flaring.
Gas is “getting incredibly cheap again versus oil and refined products,” John Kilduff, founding
partner at Again Capital LLC in New York, said by phone. Producers “are just going to try to give it
away.”
Gas at West Texas’ Waha hub traded at $2.06 per million British thermal units Tuesday, compared
with $2.7161 at the Henry Hub in Louisiana, the benchmark for futures traded on the New York
Mercantile Exchange. Waha gas is down 48 percent this year.
In the Permian alone, gas flaring is likely to jump as much as five-fold in the next year, Matthew
Portillo, managing director of exploration and production research at Tudor Pickering, said by
phone. But state regulators typically won’t allow that to continue indefinitely, and limits to flaring
could ultimately curtail oil and gas production gains, he said.
“Permian growth may actually be limited by the ability to flare gas,” Portillo said. “Basically, the pipes
don’t point in the right direction. And the pipes that are available are getting full.”

Gas traded on the New York Mercantile Exchange, meanwhile, may be relatively unscathed by the
Iran decision. Portillo predicts futures will drop to $2.25 to $2.50 per million Btu by the third quarter,
but then rise as high as $2.75 next year on slowing production and rising demand from exports.
But for gas drillers in the Permian, restored Iran sanctions signal a tough road ahead as surging
supply overwhelms pipeline capacity.
“Over the next 12-24 months, a large gap is likely to develop in global oil supplies, pushing global
prices up sharply,” Andy Weissman, chief executive officer of the Washington-based energy
analysis company EBW Analytics Group, wrote in a note to clients. “For natural gas producers, this
is a distressing development.”
Shale Drillers Face New Test of Will as Crude Crosses $70 Mark
With benchmark U.S. crude prices crossing the $70 a barrel threshold on Monday, the shale drillers
who helped upend global markets now face a new challenge: Do they stick with promises of fiscal
discipline and avoid new production? Or is it time to turn on the taps and reap the benefits of the
highest crude prices in more than three years.
In quarterly earnings reports over the last two weeks, producers have modestly upped forecasts for
oil and gas output but also mostly kept drilling budgets flat, holding out hope they won’t completely
undermine the rally. What they do they do now? Here are three ways the industry could react:
1. Drill, Baby, Drill? Historically, shale drillers have ramped up output in response to the market, and
there’s little reason to believe this time will be different, said Ashley Petersen, lead oil analyst at
Stratas Advisors in New York. “It signals to drill. that’s for sure," she said in a phone interview. “It
definitely signals to them, take advantage of prices while you can." Companies are also adding on

new hedging contracts, locking in payments for future barrels that will sustain production even if
prices slide again.
2. Stay the Course? For months, investors have urged exploration and production to rein in
unprofitable spending. That pressure’s likely to remain, keeping a lid on any increases to drilling
budgets, analysts at Houston investment bank Tudor Pickering Holt & Co. said in a note to clients
recently. “Expect little change to messaging or 2018 plans as operators continue to view the rally in
crude as a boon to cash flow rather than an opportunity to accelerate growth," the bank advised.
Instead, additional share buybacks and debt reduction are likely to be the top priorities, added RBC
Capital Markets analyst Scott Hanold in another note.
The caution is made more likely by the logistical hurdles mounting in the Permian basin, the top
U.S. shale play. Shortages of labor, equipment and pipeline capacity had crude from the West Texas
region selling at a $12 a barrel discount this past week to oil received at the U.S. distribution hub in
Cushing, Oklahoma. That’s meant producers aren’t reaping the full benefit of $70 oil anyway, said
Antoine Halff, former chief oil analyst for the International Energy Agency. Add in the increasing size
and complexity of shale projects, which lengthens the time for oil to come to market, and “I wouldn’t
necessary conclude that this will trigger a huge rebound in supply," said Halff, now a Columbia
University scholar.
3. Let the Price Wars Begin: After years of watching fees shrink during the industry’s downturn,
oilfield service companies -- the businesses that frack wells, truck in sand and do other contract
work for the shale patch -- are likely to demand a bigger slice of the pie. “Seventy dollars is a very
strong signal of psychological recovery," said Petersen of Stratas Advisors. For service companies,
“now is the time to start aggressively renegotiating pricing contracts that they had set when prices
were a lot lower." Higher fees could cut into explorer profits, however, making it harder to keep those
aforementioned investors happy.

NewBase Special Coverage
News Agencies News Release May 10-2018
The USA electricity sources between Solar, biomass, Gas & Nuclear
Source: U.S. Energy Information Administration, Electric Power Monthly
Electricity generation from solar resources in the United States reached 77 million megawatt hours
(MWh) in 2017, surpassing for the first-time annual generation from biomass resources, which
generated 64 million MWh in 2017.
Among renewable sources, only hydro and wind generated more electricity in 2017, at 300 million
MWh and 254 million MWh, respectively. Biomass generating capacity has remained relatively
unchanged in recent years, while solar generating capacity has consistently grown.

Annual growth in solar generation often lags annual capacity additions because generating capacity
tends to be added late in the year. For example, in 2016, 29% of total utility-scale solar generating
capacity additions occurred in December, leaving few days for an installed project to contribute to
total annual generation despite being counted in annual generating capacity additions.
In 2017, December solar additions accounted for 21% of the annual total. Overall, solar technologies
operate at lower annual capacity factors and experience more seasonal variation than biomass
technologies.
Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory
Biomass electricity generation comes from multiple fuel sources, such as wood solids (68% of total
biomass electricity generation in 2017), landfill gas (17%), municipal solid waste (11%), and other
biogenic and nonbiogenic materials (4%).These shares of biomass generation have remained
relatively constant in recent years.
Solar can be divided into three types: solar thermal, which converts sunlight to steam to produce
power; large-scale solar photovoltaic (PV), which uses PV cells to directly produce electricity from
sunlight; and small-scale solar, which are PV installations of 1 megawatt or smaller.
Generation from solar thermal sources has remained relatively flat in recent years, at about 3 million
MWh. The most recent addition of solar thermal capacity was the Crescent Dunes Solar Energy
plant installed in Nevada in 2015, and currently no solar thermal generators are under construction
in the United States.
Solar photovoltaic systems, however, have consistently grown in recent years. In 2014, large-scale
solar PV systems generated 15 million MWh, and small-scale PV systems generated 11 million
MWh. By 2017, annual electricity from those sources had increased to 50 million MWh and 24 million

MWh, respectively. By the end of 2018, EIA expects an additional 5,067 MW of large-scale PV to
come online, according to EIA’s Preliminary Monthly Electric Generator Inventory. Information about
planned small-scale PV systems (one megawatt and below) is not collected in that survey.
Future of U.S. nuclear power fleet depends mostly on natural gas prices, carbon policies
Existing U.S. nuclear power generating plants operate under increasingly competitive market
conditions brought on by relatively low natural gas prices, increasing electricity generation from
renewable energy sources, and limited growth in electric power demand. Several sensitivity cases
prepared for EIA’s Annual Energy Outlook 2018(AEO2018) show the potential effects on the U.S.
nuclear power fleet of different assumptions for natural gas prices, potential carbon policies, and
nuclear power plant operating costs.
Currently, 60 nuclear power plants operate in the United States with a combined electricity
generating capacity of 99 gigawatts (GW). Nine plants with a combined 11 GW of capacity have
announced plans to retire by 2025. Based on assumptions in the AEO2018 Reference case, which
reflects current laws and regulations, EIA expects additional unplanned retirements will reduce total
U.S. nuclear generating capacity from 99 GW in 2017 to 79 GW by 2050.

Higher or lower natural gas prices. About half of the existing nuclear fleet operates in deregulated
wholesale electricity (i.e., merchant) markets, where natural gas-fired generators can and
sometimes do set the marginal price for electricity. For this reason, changes in natural gas prices
affect electric power markets. cases with different assumptions for oil and natural gas resources
and technology result in higher and lower natural gas prices.
In the High Oil and Gas Resource and Technology case, lower natural gas prices lead to more
nuclear retirements, and total nuclear capacity falls to 55 GW by 2050 in this case. Conversely, in
the Low Oil and Gas Resource and Technology case, higher natural gas prices lead to fewer nuclear
retirements, but nuclear capacity still falls to 83 GW in 2050. In all three of these cases, no additional
nuclear plants come online beyond the units currently under construction in Georgia (Vogtle Units
3 and 4), but in some locations nuclear power plant capacity increases because of uprates.
Higher or lower nuclear operating costs. Operating costs have played a major role in recent
retirement decisions. At least five currently operating nuclear plants have requested state-level price
support to continue operating. In two sensitivity cases, assumed operating costs were raised or
lowered by 20%.
On their own, changes in operating costs have a relatively minor effect on changes in nuclear
capacity. With higher operating costs, nuclear capacity falls to 66 GW by 2050; with lower operating
costs, nuclear capacity falls to 84 GW—levels that are 13 GW lower than and 5 GW higher than
Reference case capacity in 2050, respectively.
Natural gas and renewables make up most of 2018 electric capacity additions
EIA expects nearly 32 gigawatts (GW) of new electric generating capacity will come online in the
United States in 2018, more than in any year over the past decade. Although renewables such as
wind and solar accounted for 98% of the 2 GW added so far, this year (based on data for January
and February), EIA expects about 21 GW of natural gas-fired generators will come online in 2018.

If these generators come online based on their reported timelines, 2018 will be the first year since
2013 in which renewables did not make up a majority of added capacity.
In 2017, renewables accounted for 55% of the 21 GW of U.S. capacity additions, the fourth
consecutive year in which renewables made up more than half. As of February 2018, renewables
accounted for 22% of total currently operating U.S. electricity generating capacity. Generators’
planned online dates for the remainder of 2018 are based on data reported to EIA in the Preliminary
Monthly Electric Generator Inventory.
The newly added generating capacity in January and February 2018 included 2,029 megawatts
(MW) of renewables, 27 MW of fossil fueled generators, and 28 MW of other technologies, mostly
consisting of energy storage batteries.
In February 2018, for the first time in decades, all of the new generating capacity coming online
within a month were non-fossil-fueled. Of the 475 MW of capacity that came online in February,
81% was wind, 16% was solar photovoltaic, and the remaining 3% was hydro and biomass.
Natural gas. About half of the 21 GW of natural gas-fired generation capacity EIA expects to come
online by the end of 2018 are combined-cycle units to be added to the PJM Regional Transmission
Organization, which spans parts of several Mid-Atlantic and Midwestern states.
In the PJM region, Pennsylvania plans to add 5.2 GW; Maryland will add 1.9 GW, and Virginia will
add 1.9 GW. Most of the new capacity is being added on the eastern side of the PJM region along
the Transcontinental, the Dominion Transmission, and the Texas Eastern Transmission pipelines.
Wind. Most of the 1,196 MW of new wind capacity that came online in January and February 2018
was added in states that already have significant wind capacity such as Texas, Oklahoma, and

Iowa. In Texas, two utility-scale batteries totaling 20 MW were collocated at wind facilities. EIA
expects five gigawatts of capacity to come online by the end of 2018. Of those 5 GW, 2 GW are in
Texas, the state with the most wind capacity currently.
Solar. About 90% of Florida’s solar capacity has come online since 2016. In January 2018, Florida
Power & Light (FPL) completed four solar photovoltaic projects totaling 300 MW. FPL plans for
another four projects totaling 300 MW to have come online by March 2018.
Upon completion, these eight projects will account for 54% of Florida’s utility-scale solar capacity.
By the end of 2018, 4 GW of solar PV are expected to come online in the United States. More than
half of the 2018 solar PV additions will be added in California, North Carolina, and Texas
Source: U.S. Energy Information Administration, Annual Energy Outlook 2018
Combined effects of higher and lower natural gas prices and operating costs. Four cases combine
the assumptions above so that higher and lower natural gas prices are combined with higher and
lower nuclear operating costs.
Nuclear capacity increases the most in the case that combines high natural gas prices and lower
nuclear operating costs, resulting in 134 GW of nuclear capacity by 2050, or 35 GW higher than
current levels. Conversely, the combination of low natural gas prices and higher nuclear operating
costs reduces the nuclear fleet to 18 GW, or about 18% of the current nuclear power fleet.

Source: U.S. Energy Information Administration, Annual Energy Outlook 2018
Effects of various carbon fees. Potential policies that would subject fossil fuel-fired power plants,
such as those fueled by coal, natural gas, and petroleum, to fees based on their carbon dioxide
(CO2) emissions would result in higher wholesale electricity prices, and in turn, would allow nuclear
power plants—which do not generate CO2 emissions—to become more economically competitive.
Two cases implement fees of $15 per ton of CO2 and $25 per ton of CO2 (in 2017 dollars) starting
in 2020, increasing by 5% in each subsequent year in real dollar terms. In both cases, much of the
existing nuclear fleet remains competitive, and additional nuclear plants are constructed so that
capacity in 2050 is higher than current levels. With a $15 per ton CO2 fee, nuclear capacity
increases to 106 GW in 2050; at $25 per ton, capacity increases to 145 GW in 2050.
The full analysis on the AEO2018 Nuclear Power Outlook provides additional detail on the current
electricity market environment, recent and announced plant retirements, certain state policies
supporting nuclear power, and implications for the electricity generating mix across the sensitivity
cases discussed above.

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base, most of the experience were spent as the Gas Operations Manager in
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transportation, operation & maintenance agreements along with many MOUs for the local
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and Energy program broadcasted internationally, via GCC leading satellite Channels.

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